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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, 2003
OR
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the Transition Period from _____________ to ______________
Commission file number 1-3480
MDU Resources Group, Inc.
(Exact name of registrant as specified in its charter)
Delaware 41-0423660
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
Schuchart Building
918 East Divide Avenue
P.O. Box 5650
Bismarck, North Dakota 58506-5650
(Address of principal executive offices)
(Zip Code)
(701) 222-7900
(Registrant's telephone number, including area code)
Indicate by check mark whether the registrant (1) has filed all
reports required to be filed by Section 13 or 15(d) of the
Securities Exchange Act of 1934 during the preceding 12 months (or
for such shorter period that the registrant was required to file
such reports), and (2) has been subject to such filing requirements
for the past 90 days. Yes X. No.
Indicate by check mark whether the registrant is an accelerated
filer (as defined in Rule 12b-2 of the Exchange Act). Yes X. No.
Indicate the number of shares outstanding of each of the
issuer's classes of common stock, as of November 6, 2003:
113,234,956 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 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.
In addition to the risk factors and cautionary statements included
in this Form 10-Q at Item 2 -- Management's Discussion and Analysis
of Financial Condition and Results of Operations - Risk Factors and
Cautionary Statements that May Affect Future Results, the following
are some other factors that should be considered for a better
understanding of MDU Resources Group, Inc.'s (Company) financial
condition. These other factors may impact the Company's financial
results in future periods.
- Acquisition and disposal of assets or facilities
- Changes in operation and construction of plant facilities
- Changes in present or prospective generation
- Changes in anticipated tourism levels
- The availability of economic expansion or development
opportunities
- Population growth rates and demographic patterns
- Market demand for energy from plants or facilities
- Changes in tax rates or policies
- Unanticipated project delays or changes in project costs
- Unanticipated changes in operating expenses or capital
expenditures
- Labor negotiations or disputes
- Inflation rates
- Inability of the various contract counterparties to meet their
contractual obligations
- Changes in accounting principles and/or the application of such
principles to the Company
- Changes in technology and legal proceedings
- The ability to effectively integrate the operations of acquired
companies
- Variations in weather
- Unanticipated increases in competition
- Changes in currency exchange rates
- Changes in governmental regulation
- Fluctuations in natural gas and crude oil prices
- Decline in general economic environment
The Company is a diversified natural resource company which was
incorporated under the laws of the state of Delaware in 1924. Its
principal executive offices are at the Schuchart Building, 918 East
Divide Avenue, P.O. Box 5650, Bismarck, North Dakota 58506-5650,
telephone (701) 222-7900.
Montana-Dakota Utilities Co. (Montana-Dakota), a public utility
division of the Company, through the electric and natural gas
distribution segments, generates, transmits and distributes
electricity and distributes natural gas in the northern Great
Plains. Great Plains Natural Gas Co. (Great Plains), another public
utility division of the Company, distributes natural gas in
southeastern North Dakota and western Minnesota. These operations
also supply related value-added products and services in the
northern Great Plains.
The Company, through its wholly owned subsidiary, Centennial
Energy Holdings, Inc. (Centennial), owns WBI Holdings, Inc. (WBI
Holdings), Knife River Corporation (Knife River), Utility Services,
Inc. (Utility Services), Centennial Energy Resources LLC (Centennial
Resources) and Centennial Holdings Capital LLC (Centennial Capital).
WBI Holdings is comprised of the pipeline and energy
services and the natural gas and oil production segments.
The pipeline and energy services segment provides natural
gas transportation, underground storage and gathering
services through regulated and nonregulated pipeline
systems primarily in the Rocky Mountain and northern Great
Plains regions of the United States. The pipeline and
energy services segment also provides energy-related
management services, including cable and pipeline
magnetization and locating. The natural gas and oil
production segment is engaged in natural gas and oil
acquisition, exploration and production activities
primarily in the Rocky Mountain region of the United States
and in and around the Gulf of Mexico.
Knife River mines aggregates and markets crushed stone,
sand, gravel and other related construction materials,
including ready-mixed concrete, cement, asphalt and other
value-added products, as well as performs integrated
construction services, in the north central and western
United States and in the states of Alaska, Hawaii and
Texas.
Utility Services is a diversified infrastructure company
specializing in electric, gas and telecommunication utility
construction, as well as industrial and commercial
electrical, exterior lighting and traffic signalization
throughout most of the United States. Utility Services also
provides related specialty equipment manufacturing, sales
and rental services.
Centennial Resources owns electric generating facilities in
the United States and has an investment in an electric
generating facility in Brazil. Electric capacity and energy
produced at these facilities are sold under long-term
contracts to nonaffiliated entities. Centennial Resources
includes investments in potential new growth opportunities
that are not directly being pursued by the other business
units, as well as projects outside the United States which
are consistent with the Company's philosophy, growth
strategy and areas of expertise. These activities are
reflected in independent power production and other.
Centennial Capital insures and reinsures various types of
risks as a captive insurer for certain of the Company's
subsidiaries. The function of the captive program is to
fund the deductible layers of the insured companies' general
liability and automobile liability coverages. Centennial
Capital also owns certain real and personal property and
contract rights. These activities are reflected in
independent power production and other.
On August 14, 2003, the Company's Board of Directors
approved a three-for-two common stock split. For more
information on the common stock split see Note 3 of Notes to
Consolidated Financial Statements.
INDEX
Part I -- Financial Information
Consolidated Statements of Income --
Three and Nine Months Ended September 30, 2003 and 2002
Consolidated Balance Sheets --
September 30, 2003 and 2002, and December 31, 2002
Consolidated Statements of Cash Flows --
Nine Months Ended September 30, 2003 and 2002
Notes to Consolidated Financial Statements
Management's Discussion and Analysis of Financial
Condition and Results of Operations
Quantitative and Qualitative Disclosures About Market Risk
Controls and Procedures
Part II -- Other Information
Signatures
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,
2003 2002 2003 2002
(In thousands, except per share amounts)
Operating revenues:
Electric, natural gas distribution
and pipeline and energy services $130,818 $ 79,581 $ 454,862 $ 317,684
Utility services, natural gas and oil
production, construction materials
and mining and other 585,281 532,817 1,277,209 1,156,866
716,099 612,398 1,732,071 1,474,550
Operating expenses:
Fuel and purchased power 16,158 14,500 44,827 41,568
Purchased natural gas sold 19,888 4,644 123,619 60,120
Operation and maintenance:
Electric, natural gas distribution
and pipeline and energy services 33,375 29,719 104,852 95,080
Utility services, natural gas and oil
production, construction materials
and mining and other 461,100 415,953 1,015,483 928,482
Depreciation, depletion and
amortization 47,749 40,589 138,725 114,536
Taxes, other than income 22,163 16,822 61,266 47,601
600,433 522,227 1,488,772 1,287,387
Operating income 115,666 90,171 243,299 187,163
Other income -- net 2,491 6,910 11,124 11,729
Interest expense 13,604 11,731 39,283 33,253
Income before income taxes 104,553 85,350 215,140 165,639
Income taxes 39,032 31,419 78,449 63,133
Income before cumulative effect of
accounting change 65,521 53,931 136,691 102,506
Cumulative effect of accounting
change (Note 8) --- --- (7,589) ---
Net income 65,521 53,931 129,102 102,506
Dividends on preferred stocks 172 189 547 567
Earnings on common stock $ 65,349 $ 53,742 $ 128,555 $ 101,939
Earnings per common share -- basic:
Earnings before cumulative effect
of accounting change $ .58 $ .51 $ 1.23 $ .97
Cumulative effect of accounting
change --- --- (.07) ---
Earnings per common share -- basic $ .58 $ .51 $ 1.16 $ .97
Earnings per common share -- diluted:
Earnings before cumulative effect of
accounting change $ .58 $ .50 $ 1.22 $ .96
Cumulative effect of accounting change --- --- (.07) ---
Earnings per common share -- diluted $ .58 $ .50 $ 1.15 $ .96
Dividends per common share $ .1700 $ .1600 $ .4900 $ .4666
Weighted average common shares
outstanding -- basic 112,359 106,385 111,100 105,432
Weighted average common shares
outstanding -- diluted 113,368 107,017 111,921 106,134
Pro forma amounts assuming retroactive
application of accounting change:
Net income $ 65,521 $ 53,332 $ 136,691 $ 100,713
Earnings per common share -- basic $ .58 $ .50 $ 1.23 $ .95
Earnings per common share -- diluted $ .58 $ .50 $ 1.22 $ .94
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,
2003 2002 2002
(In thousands, except shares
and per share amount)
ASSETS
Current assets:
Cash and cash equivalents $ 91,900 $ 42,806 $ 67,556
Receivables, net 410,666 363,568 325,395
Inventories 127,717 102,130 93,123
Deferred income taxes 1,950 15,020 8,877
Prepayments and other current assets 47,202 39,482 42,597
679,435 563,006 537,548
Investments 40,626 43,339 42,864
Property, plant and equipment 3,312,747 2,844,935 2,961,808
Less accumulated depreciation,
depletion and amortization 1,198,382 1,042,938 1,079,110
2,114,365 1,801,997 1,882,698
Deferred charges and other assets:
Goodwill 199,209 185,205 190,999
Other intangible assets, net 193,010 172,123 176,164
Other 106,723 103,959 106,976
498,942 461,287 474,139
$3,333,368 $2,869,629 $2,937,249
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Short-term borrowings $ --- $ 10,000 $ 20,000
Long-term debt and preferred
stock due within one year 7,892 22,606 22,183
Accounts payable 183,506 148,312 132,120
Taxes payable 27,852 17,960 13,108
Dividends payable 19,436 17,335 17,959
Other accrued liabilities 113,463 104,720 94,275
352,149 320,933 299,645
Long-term debt 988,804 832,533 819,558
Deferred credits and other liabilities:
Deferred income taxes 403,540 360,872 374,097
Other liabilities 170,138 139,021 144,004
573,678 499,893 518,101
Preferred stock subject to mandatory
redemption (Note 8) --- 1,300 1,200
Commitments and contingencies
Stockholders' equity:
Preferred stocks 15,000 15,000 15,000
Common stockholders' equity:
Common stock (Note 3)
Shares issued -- $1.00 par value
113,583,312 at September 30, 2003,
71,681,396 at September 30, 2002
and 74,282,038
at December 31, 2002 113,583 71,681 74,282
Other paid-in capital 752,276 690,139 748,095
Retained earnings 548,506 446,820 474,798
Accumulated other comprehensive
loss (7,002) (5,044) (9,804)
Treasury stock at cost - 359,281
shares at September 30, 2003 and
239,521 shares at September 30,
2002 and December 31, 2002 (3,626) (3,626) (3,626)
Total common stockholders' equity 1,403,737 1,199,970 1,283,745
Total stockholders' equity 1,418,737 1,214,970 1,298,745
$3,333,368 $2,869,629 $2,937,249
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,
2003 2002
(In thousands)
Operating activities:
Net income $129,102 $102,506
Cumulative effect of accounting change 7,589 ---
Adjustments to reconcile net income to net cash provided
by operating activities:
Depreciation, depletion and amortization 138,725 114,536
Deferred income taxes and investment tax credit 24,426 12,686
Changes in current assets and liabilities, net of
acquisitions:
Receivables (63,511) (64,437)
Inventories (25,233) (4,585)
Other current assets (8,364) (2,743)
Accounts payable 36,838 27,941
Other current liabilities 33,046 14,142
Other noncurrent changes 5,587 1,594
Net cash provided by operating activities 278,205 201,640
Investing activities:
Capital expenditures (212,361) (212,584)
Acquisitions, net of cash acquired (132,070) (14,802)
Net proceeds from sale or disposition of property 8,273 5,699
Investments 4,298 (2,827)
Proceeds from notes receivable 7,812 4,000
Net cash used in investing activities (324,048) (220,514)
Financing activities:
Net change in short-term borrowings (20,000) 10,000
Issuance of long-term debt 243,063 68,039
Repayment of long-term debt (99,307) (8,043)
Proceeds from issuance of common stock, net 366 200
Dividends paid (53,935) (50,327)
Net cash provided by financing activities 70,187 19,869
Increase in cash and cash equivalents 24,344 995
Cash and cash equivalents -- beginning of year 67,556 41,811
Cash and cash equivalents -- end of period $ 91,900 $ 42,806
The accompanying notes are an integral part of these consolidated statements.
MDU RESOURCES GROUP, INC.
NOTES TO CONSOLIDATED
FINANCIAL STATEMENTS
September 30, 2003 and 2002
(Unaudited)
1. Basis of presentation
The accompanying consolidated interim financial statements
were prepared in conformity with the basis of presentation
reflected in the consolidated financial statements included in
the Annual Report to Stockholders for the year ended
December 31, 2002 (2002 Annual Report), and the standards of
accounting measurement set forth in Accounting Principles Board
(APB) Opinion No. 28 and any amendments thereto adopted by the
Financial Accounting Standards Board (FASB). Interim financial
statements do not include all disclosures provided in annual
financial statements and, accordingly, these financial
statements should be read in conjunction with those appearing
in the Company's 2002 Annual Report. The information is
unaudited but includes all adjustments that are, in the opinion
of management, necessary for a fair presentation of the
accompanying consolidated interim financial statements.
2. Seasonality of operations
Some of the Company's operations are highly seasonal and
revenues from, and certain expenses for, such operations may
fluctuate significantly among quarterly periods. Accordingly,
the interim results for particular businesses, and for the
Company as a whole, may not be indicative of results for the
full fiscal year.
3. Common stock split
On August 14, 2003, the Company's Board of Directors
approved a three-for-two common stock split to be effected in
the form of a 50 percent common stock dividend. The additional
shares of common stock were distributed on October 29, 2003, to
common stockholders of record on October 10, 2003. All common
stock information appearing in the accompanying consolidated
financial statements has been restated to give retroactive
effect to the stock split. Additionally, preference share
purchase rights have been appropriately adjusted to reflect the
effects of the split.
4. Allowance for doubtful accounts
The Company's allowance for doubtful accounts as of
September 30, 2003 and 2002, and December 31, 2002, was $8.3
million, $8.0 million and $8.2 million, respectively.
5. Earnings per common share
Basic earnings per common share were computed by dividing
earnings on common stock by the weighted average number of
shares of common stock outstanding during the applicable
period. Diluted earnings per common share were computed by
dividing earnings on common stock by the total of the weighted
average number of shares of common stock outstanding during the
applicable period, plus the effect of outstanding stock
options, restricted stock grants and performance share awards.
For the three months and nine months ended September 30, 2003,
209,805 shares with an average exercise price of $24.56
attributable to outstanding stock options, were excluded from
the calculation of diluted earnings per share because their
effect was antidilutive. For the three months and nine months
ended September 30, 2002, 3,915,975 shares and 3,891,225
shares, respectively, with an average exercise price of $20.04
and $20.07, respectively, attributable to outstanding stock
options were excluded from the calculation of diluted earnings
per share because their effect was antidilutive. Common stock
outstanding includes issued shares less shares held in
treasury.
6. Cash flow information
Cash expenditures for interest and income taxes were as
follows:
Nine Months Ended
September 30,
2003 2002
(In thousands)
Interest, net of amount capitalized $ 31,871 $ 27,434
Income taxes $ 35,341 $ 42,421
7. Reclassifications
Certain reclassifications have been made in the financial
statements for the prior period to conform to the current
presentation. Such reclassifications had no effect on net
income or stockholders' equity as previously reported.
8. New accounting standards
The Company has stock option plans for directors, key
employees and employees. In the third quarter of 2003, the
Company adopted the fair value recognition provisions of
Statement of Financial Accounting Standards (SFAS) No. 123
"Accounting for Stock-Based Compensation," and began expensing
the fair market value of stock options for all awards granted
on or after January 1, 2003. Compensation expense recognized
for awards granted on or after January 1, 2003, for the three
months and nine months ended September 30, 2003, was $53,000
(after tax).
As permitted by SFAS No. 148, "Accounting for Stock-Based
Compensation - Transition and Disclosure - an amendment of SFAS
No. 123," the Company accounts for stock options granted prior
to January 1, 2003, under APB Opinion No. 25, " Accounting for
Stock Issued to Employees." No compensation expense has been
recognized for stock options granted prior to January 1, 2003,
as the options granted had an exercise price equal to the
market value of the underlying common stock on the date of the
grant.
Since the Company adopted SFAS No. 123 effective January
1, 2003, for newly granted options only, the following table
illustrates the effect on earnings and earnings per common
share as if the Company had applied SFAS No. 123 and recognized
compensation expense for all outstanding and unvested stock
options based on the fair value at the date of grant:
Three Months Ended
September 30,
2003 2002
(In thousands, except
per share amounts)
Earnings on common stock, as reported $ 65,349 $ 53,742
Stock-based compensation expense included
in reported earnings, net of related
tax effects 53 ---
Total stock-based compensation
expense determined under fair value
method for all awards, net of related
tax effects (618) (809)
Pro forma earnings on common stock $ 64,784 $ 52,933
Earnings per common share -- basic --
as reported:
Earnings before cumulative effect of
accounting change $ .58 $ .51
Cumulative effect of accounting change --- ---
Earnings per common share -- basic $ .58 $ .51
Earnings per common share -- basic --
pro forma:
Earnings before cumulative effect of
accounting change $ .58 $ .50
Cumulative effect of accounting change --- ---
Earnings per common share -- basic $ .58 $ .50
Earnings per common share -- diluted --
as reported:
Earnings before cumulative effect of
accounting change $ .58 $ .50
Cumulative effect of accounting change --- ---
Earnings per common share -- diluted $ .58 $ .50
Earnings per common share -- diluted --
pro forma:
Earnings before cumulative effect of
accounting change $ .57 $ .49
Cumulative effect of accounting change --- ---
Earnings per common share -- diluted $ .57 $ .49
Nine Months Ended
September 30,
2003 2002
(In thousands, except
per share amounts)
Earnings on common stock, as reported $128,555 $101,939
Stock-based compensation expense included
in reported earnings, net of related
tax effects 53 ---
Total stock-based compensation
expense determined under fair value
method for all awards, net of related
tax effects (1,925) (2,409)
Pro forma earnings on common stock $126,683 $ 99,530
Earnings per common share -- basic --
as reported:
Earnings before cumulative effect of
accounting change $ 1.23 $ .97
Cumulative effect of accounting change (.07) ---
Earnings per common share -- basic $ 1.16 $ .97
Earnings per common share -- basic --
pro forma:
Earnings before cumulative effect of
accounting change $ 1.21 $ .94
Cumulative effect of accounting change (.07) ---
Earnings per common share -- basic $ 1.14 $ .94
Earnings per common share -- diluted --
as reported:
Earnings before cumulative effect of
accounting change $ 1.22 $ .96
Cumulative effect of accounting change (.07) ---
Earnings per common share -- diluted $ 1.15 $ .96
Earnings per common share -- diluted --
pro forma:
Earnings before cumulative effect of
accounting change $ 1.20 $ .94
Cumulative effect of accounting change (.07) ---
Earnings per common share -- diluted $ 1.13 $ .94
In June 2001, the FASB approved SFAS No. 141, "Business
Combinations," which requires the purchase method of accounting
for business combinations initiated after June 30, 2001 and
eliminates the pooling-of-interests method. In June 2001, the
FASB also approved SFAS No. 142, "Goodwill and Other Intangible
Assets," which discontinues the practice of amortizing goodwill
and indefinite lived intangible assets and initiates an annual
review for impairment. Intangible assets with a determinable
useful life will continue to be amortized over that period.
The amortization provisions apply to goodwill and intangible
assets acquired after June 30, 2001. SFAS No. 141 and SFAS No.
142 clarify that more assets should be distinguished and
classified between tangible and intangible. The Company did
not change or reclassify contractual mineral rights included in
property, plant and equipment related to its natural gas and
oil production business upon adoption of SFAS No. 142. The
Company has included such mineral rights as part of property,
plant and equipment under the full cost method of accounting
for natural gas and oil properties. An issue has arisen within
the natural gas and oil industry as to whether contractual
mineral rights under SFAS No. 142 should be classified as
intangible rather than as part of property, plant and
equipment. This accounting matter is anticipated to be
addressed by the FASB's Emerging Issues Task Force. The
resolution of this matter may result in certain
reclassifications of amounts in the Company's Consolidated
Balance Sheets, as well as changes to the Company's Notes to
Consolidated Financial Statements in the future. The
applicable provisions of SFAS No. 141 and SFAS No. 142 only
affect the balance sheet and associated footnote disclosure, so
any reclassifications that might be required in the future will
not affect the Company's cash flows or results of operations.
The Company believes that the resolution of this matter will
not have a material effect on the Company's financial position
because the mineral rights acquired by its natural gas and oil
production business after the June 30, 2001, effective date of
SFAS No. 142 are not material.
In June 2001, the FASB approved SFAS No. 143, "Accounting
for Asset Retirement Obligations." SFAS No. 143 requires
entities to record the fair value of a liability for an asset
retirement obligation in the period in which it is incurred.
When the liability is initially recorded, the entity
capitalizes a cost by increasing the carrying amount of the
related long-lived asset. Over time, the liability is accreted
to its present value each period, and the capitalized cost is
depreciated over the useful life of the related asset. Upon
settlement of the liability, an entity either settles the
obligation for the recorded amount or incurs a gain or loss
upon settlement. SFAS No. 143 is effective for fiscal years
beginning after June 15, 2002. For more information on the
adoption of SFAS No. 143, see Note 13.
In April 2002, the FASB approved SFAS No. 145, "Rescission
of FASB Statements No. 4, 44 and 64, Amendment of FASB
Statement No. 13, and Technical Corrections." FASB No. 4
required all gains or losses from extinguishment of debt to be
classified as extraordinary items net of income taxes. SFAS
No. 145 requires that gains and losses from extinguishment of
debt be evaluated under the provisions of APB Opinion No. 30,
and be classified as ordinary items unless they are unusual or
infrequent or meet the specific criteria for treatment as an
extraordinary item. SFAS No. 145 is effective for fiscal years
beginning after May 15, 2002. The adoption of SFAS No. 145 did
not have a material effect on the Company's financial position
or results of operations.
In November 2002, the FASB issued FASB Interpretation
No. 45, "Guarantor's Accounting and Disclosure Requirements for
Guarantees, Including Indirect Guarantees of Indebtedness of
Others" (FIN 45). FIN 45 clarifies the disclosures to be made
by a guarantor in its interim and annual financial statements
about its obligations under certain guarantees that it has
issued. FIN 45 also requires a guarantor to recognize, at the
inception of a guarantee, a liability for the fair value of the
obligation undertaken in issuing certain types of guarantees.
Certain types of guarantees are not subject to the initial
recognition and measurement provisions of FIN 45 but are
subject to its disclosure requirements. The initial
recognition and initial measurement provisions of FIN 45 are
applicable on a prospective basis to guarantees issued or
modified after December 31, 2002, regardless of the guarantor's
fiscal year-end. The guarantor's previous accounting for
guarantees issued prior to the date of the initial application
of FIN 45 is not required to be revised or restated. The
disclosure requirements in FIN 45 are effective for financial
statements of interim or annual periods ended after December
15, 2002. The Company is applying the initial recognition and
initial measurement provisions of FIN 45 to guarantees issued
or modified after December 31, 2002. For more information on
the Company's guarantees and the disclosure requirements of FIN
45, as applicable to the Company, see Note 18.
In January 2003, the FASB issued FASB Interpretation
No. 46, "Consolidation of Variable Interest Entities" (FIN 46).
FIN 46 clarifies the application of Accounting Research
Bulletin No. 51, "Consolidated Financial Statements" to certain
entities in which equity investors do not have the
characteristics of a controlling financial interest or do not
have sufficient equity at risk for the entity to finance its
activities without additional subordinated support from other
parties. FIN 46 requires existing unconsolidated variable
interest entities to be consolidated by their primary
beneficiaries if the entities do not effectively disperse risks
among parties involved. All companies with variable interests
in variable interest entities created after January 31, 2003,
were required to apply the provisions of FIN 46 to those
entities immediately. Although the Company has not created any
variable interest entities after January 31, 2003, the Company
will apply the provisions of FIN 46 to variable interest
entities if and when they are created.
FIN 46 was effective for the first fiscal year or interim
period beginning after June 15, 2003, for variable interest
entities created before February 1, 2003. However, in October
2003, the FASB issued FASB Staff Position No. FIN 46-6 which
defers the required effective date until the end of the first
interim or annual period ending after December 15, 2003, for
interests held in a variable interest entity or potential
variable interest entity that was created before February 1,
2003, provided that financial statements have not been issued
reporting that variable interest entity in accordance with FIN
46. The deferral of the effective date of FIN 46 did not have
an effect on the Company's financial position or results of
operations.
The Company evaluated the provisions of FIN 46 for
entities created before February 1, 2003. Based on this
evaluation, the Company determined that MPX Holdings, Ltda.
(MPX) is a variable interest entity. MPX was formed in August
2001, as a result of MDU Brasil Ltda. (MDU Brasil), an indirect
wholly owned Brazilian subsidiary of the Company, entering into
a joint venture agreement with a Brazilian firm. MDU Brasil
has a 49 percent interest in MPX. Although the Company has
determined that MPX is a variable interest entity, MDU Brasil
is not considered the primary beneficiary of MPX because MDU
Brasil does not absorb a majority of MPX's expected losses or
receive a majority of MPX's expected residual returns.
Therefore, MDU Brasil does not have a controlling financial
interest in MPX and is not required to consolidate MPX in its
financial statements. MPX is being accounted for under the
equity method of accounting. For more information on the
equity method investment, see Note 10. The adoption of FIN 46
did not have a material effect on the Company's financial
position or results of operations.
In April 2003, the FASB issued SFAS No. 149, "Amendment of
Statement 133 on Derivative Instruments and Hedging
Activities." SFAS No. 149 provides clarification on the
financial accounting and reporting of derivative instruments,
including certain derivative instruments embedded in other
contracts, and hedging activities; and requires contracts with
similar characteristics to be accounted for on a comparable
basis. SFAS No. 149 is generally effective for contracts
entered into or modified after June 30, 2003, and for hedging
relationships designated after June 30, 2003. The adoption of
SFAS No. 149 did not have a material effect on the Company's
financial position or results of operations.
In May 2003, the FASB issued SFAS No. 150, "Accounting for
Certain Financial Instruments with Characteristics of Both
Liabilities and Equity." SFAS No. 150 establishes standards
for how an issuer classifies and measures certain financial
instruments with characteristics of both liabilities and
equity. It requires that an issuer classify a financial
instrument that is within the scope of SFAS No. 150 as a
liability (or an asset in some circumstances). SFAS No. 150 is
effective for financial instruments entered into or modified
after May 31, 2003, and otherwise is effective at the beginning
of the first interim period beginning after June 15, 2003. The
Company will apply SFAS No. 150 to any financial instruments
entered into or modified after May 31, 2003. Beginning with
the third quarter of 2003, the Company reported its preferred
stock subject to mandatory redemption as a liability in
accordance with SFAS No. 150. The transition to SFAS No. 150
did not have a material effect on the Company's financial
position or results of operations.
9. Comprehensive income
Comprehensive income is the sum of net income as reported
and other comprehensive income (loss). The Company's other
comprehensive income (loss) resulted from gains (losses) on
derivative instruments qualifying as hedges, a minimum pension
liability adjustment and foreign currency translation
adjustments.
The Company's comprehensive income, and the components of
other comprehensive income (loss), and their related tax
effects, were as follows:
Three Months Ended
September 30,
2003 2002
(In thousands)
Net income $ 65,521 $ 53,931
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 $1,545 and
$806 in 2003 and 2002, respectively 2,416 (1,234)
Less: Reclassification adjustment for
gain (loss) on derivative instruments
included in net income, net of
tax of $2,839 and $789 in
2003 and 2002, respectively (4,522) 1,208
Net unrealized gain (loss) on derivative
instruments qualifying as hedges 6,938 (2,442)
Foreign currency translation adjustment 1,698 ---
8,636 (2,442)
Comprehensive income $ 74,157 $ 51,489
Nine Months Ended
September 30,
2003 2002
(In thousands)
Net income $129,102 $102,506
Other comprehensive income (loss) --
Net unrealized gain (loss) on derivative
instruments qualifying as hedges:
Net unrealized loss on derivative
instruments arising during the
period, net of tax of $983 and
$723 in 2003 and 2002, respectively (1,537) (1,107)
Less: Reclassification adjustment for
gain (loss) on derivative instruments
included in net income, net of
tax of $2,171 and $1,185 in
2003 and 2002, respectively (3,397) 1,815
Net unrealized gain (loss) on derivative
instruments qualifying as hedges 1,860 (2,922)
Minimum pension liability adjustment,
net of tax of $2,781 in 2002 --- (4,340)
Foreign currency translation adjustment 942 ---
2,802 (7,262)
Comprehensive income $131,904 $ 95,244
10. Equity method investment
In August 2001, MDU Brasil entered into a joint venture
agreement with a Brazilian firm under which the parties formed
MPX. MDU Brasil has a 49 percent interest in MPX which is
being accounted for under the equity method of accounting, as
discussed in Note 8. MPX, through a wholly owned subsidiary,
owns a 220-megawatt natural gas-fired power plant (Project) in
the Brazilian state of Ceara. MPX has assets at September 30,
2003, of approximately $101.6 million. Petrobras, the
Brazilian state-controlled energy company, has agreed to
purchase all of the capacity and market all of the Project's
energy. The power purchase agreement with Petrobras expires in
May 2008. Petrobras also is under contract for five years to
supply natural gas to the Project. This natural gas supply
contract is renewable for an additional 13 years. The
functional currency for the Project is the Brazilian real. The
power purchase agreement with Petrobras contains an embedded
derivative, which derives its value from an annual adjustment
factor, which largely indexes the contract capacity payments to
the U.S. dollar. For the three and nine months ended September
30, 2003, the Company's 49 percent share of the loss from the
embedded derivative in the power purchase agreement was $3.0
million (after tax) and $9.0 million (after tax), respectively.
The Company's 49 percent share of the foreign currency loss
resulting from devaluation of the Brazilian real totaled
$476,000 (after tax) for the three months ended September 30,
2003. The Company's 49 percent share of the foreign currency
gain resulting from the revaluation of the Brazilian real
totaled $2.6 million for the nine months ended September 30,
2003.
The Company's investment in the Project has been accounted
for under the equity method of accounting, and the Company's
share of net income, including the previously mentioned foreign
currency gain and loss and the loss from the embedded
derivative in the power purchase agreement, for the three
months and nine months ended September 30, 2003, of $130,000
and $1.9 million, respectively, was included in other income -
net. At September 30, 2003 and 2002, and December 31, 2002,
the Company's investment in the Project was approximately $20.6
million, $27.8 million and $27.8 million, respectively.
11. Goodwill and other intangible assets
The changes in the carrying amount of goodwill were as
follows:
Net
Goodwill
Acquired
Balance and Other Balance
as of Changes as of
Nine Months Ended January 1, During September 30,
September 30, 2003 2003 the Year* 2003
(In thousands)
Electric $ --- $ --- $ ---
Natural gas
distribution --- --- ---
Utility services 62,487 127 62,614
Pipeline and energy
services 9,494 --- 9,494
Natural gas and oil
production --- --- ---
Construction materials
and mining 111,887 8,083 119,970
Independent power
production and other 7,131 --- 7,131
Total $ 190,999 $ 8,210 $ 199,209
Net
Goodwill
Acquired
Balance and Other Balance
as of Changes as of
Nine Months Ended January 1, During September 30,
September 30, 2002 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
Independent power
production and other --- --- ---
Total $ 173,997 $ 11,208 $ 185,205
Net
Goodwill
Acquired
Balance and Other Balance
as of Changes as of
Year Ended January 1, During December 31,
December 31, 2002 2002 the Year* 2002
(In thousands)
Electric $ --- $ --- $ ---
Natural gas
distribution --- --- ---
Utility services 61,909 578 62,487
Pipeline and energy
services 9,336 158 9,494
Natural gas and oil
production --- --- ---
Construction materials
and mining 102,752 9,135 111,887
Independent power
production and other --- 7,131 7,131
Total $ 173,997 $ 17,002 $ 190,999
_________________
* Includes purchase price adjustments related to acquisitions
acquired in a prior period.
Other intangible assets were as follows:
September 30, September 30, December 31,
2003 2002 2002
(In thousands)
Amortizable intangible
assets:
Leasehold rights $184,079 $170,496 $172,496
Accumulated amortization (11,096) (6,141) (7,494)
172,983 164,355 165,002
Noncompete agreements 12,075 12,090 12,075
Accumulated amortization (9,621) (9,234) (9,366)
2,454 2,856 2,709
Other 17,736 5,149 7,224
Accumulated amortization (1,766) (237) (374)
15,970 4,912 6,850
Unamortizable intangible
assets 1,603 --- 1,603
Total $193,010 $172,123 $176,164
The unamortizable intangible assets were recognized in
accordance with SFAS No. 87, "Employers' Accounting for
Pensions" which requires that if an additional minimum
liability is recognized an equal amount shall be recognized as
an intangible asset, provided that the asset recognized shall
not exceed the amount of unrecognized prior service cost. The
unamortizable intangible asset will be eliminated or adjusted
as necessary upon a new determination of the amount of
additional liability.
Amortization expense for amortizable intangible assets for
the three months and nine months ended September 30, 2003, was
$1.7 million and $4.5 million, respectively. Amortization
expense for amortizable intangible assets for the three months
and nine months ended September 30, 2002, and for the year
ended December 31, 2002, was $727,000, $1.4 million and $3.4
million, respectively. Estimated amortization expense for
amortizable intangible assets is $5.9 million in 2003, $6.2
million in 2004, $6.4 million in 2005, $5.2 million in 2006,
$5.1 million in 2007 and $167.1 million thereafter.
For more information on goodwill and other intangible
assets, see Note 8.
12. Derivative instruments
From time to time, the Company utilizes derivative
instruments as part of an overall energy price, foreign
currency and interest rate risk management program to
efficiently manage and minimize commodity price, foreign
currency and interest rate risk. The following information
should be read in conjunction with Notes 1 and 5 in the
Company's Notes to Consolidated Financial Statements in the
2002 Annual Report.
As of September 30, 2003, a subsidiary of the Company held
derivative instruments designated as cash flow hedging
instruments.
Hedging activities
A subsidiary of the Company utilizes natural gas and oil
price swap and collar agreements to manage a portion of the
market risk associated with fluctuations in the price of
natural gas and oil on the subsidiary's forecasted sales of
natural gas and oil production.
For the three months and nine months ended September 30,
2003 and 2002, the amount of hedge ineffectiveness recognized,
which was included in operating revenues, was immaterial. For
the three months and nine months ended September 30, 2003 and
2002, the subsidiary did not exclude any components of the
derivative instruments' gain or loss from the assessment of
hedge effectiveness and there were no reclassifications into
earnings as a result of the discontinuance of hedges.
Gains and losses on derivative instruments that are
reclassified from accumulated other comprehensive income (loss)
to current-period earnings are included in the line item in
which the hedged item is recorded. As of September 30, 2003,
the maximum term of the subsidiary's swap and collar
agreements, in which the subsidiary of the Company is hedging
its exposure to the variability in future cash flows for
forecasted transactions, is 15 months. The subsidiary of the
Company estimates that over the next twelve months net losses
of approximately $2.7 million (after tax) will be reclassified
from accumulated other comprehensive loss into earnings,
subject to changes in natural gas and oil market prices, as the
hedged transactions affect earnings.
13. Asset retirement obligations
The Company adopted SFAS No. 143 on January 1, 2003. The
Company recorded obligations related to the plugging and
abandonment of natural gas and oil wells; decommissioning of
certain electric generating facilities; reclamation of certain
aggregate properties and certain other obligations associated
with leased properties. Removal costs associated with certain
natural gas distribution, transmission, storage and gathering
facilities have not been recognized as these facilities have
been determined to have indeterminate useful lives.
Upon adoption of SFAS No. 143, the Company recorded an
additional discounted liability of $22.5 million and a
regulatory asset of $493,000, increased net property, plant and
equipment by $9.6 million and recognized a one-time cumulative
effect charge of $7.6 million (net of deferred income tax
benefits of $4.8 million). The Company believes that any
expenses under SFAS No. 143 as they relate to regulated
operations will be recovered in rates over time and
accordingly, deferred such expenses as a regulatory asset upon
adoption. The Company will continue to defer those SFAS No.
143 expenses that it believes will be recovered in rates over
time. In addition to the $22.5 million liability recorded upon
the adoption of SFAS No. 143, the Company had previously
recorded a $7.5 million liability related to retirement
obligations.
A reconciliation of the Company's liability was as
follows:
For the Nine
Months Ended
September 30, 2003
(In thousands)
January 1, 2003 $ 29,997
Liabilities incurred 1,216
Liabilities acquired 626
Liabilities settled (607)
Accretion expense 1,426
$ 32,658
This liability is included in other liabilities. If SFAS
No. 143 had been in effect during 2002, the Company's liability
would have been approximately $27.0 million and $28.6 million
at January 1, 2002, and September 30, 2002, respectively.
The fair value of assets that are legally restricted for
purposes of settling asset retirement obligations at
September 30, 2003, was $5.1 million.
14. Long-term debt
In 2003, Centennial borrowed an additional $39 million
under its long-term master shelf agreement. Under the terms of
Centennial's master shelf agreement, $384.6 million was
outstanding at September 30, 2003. Williston Basin Interstate
Pipeline Company (Williston Basin), an indirect wholly owned
subsidiary of the Company, borrowed an additional $25 million
in 2003 under its long-term master shelf agreement. Under the
terms of Williston Basin's master shelf agreement, $55.0
million was outstanding at September 30, 2003. In addition,
Centennial entered into a $125 million note purchase agreement
on June 27, 2003. The $125 million in proceeds was used to pay
down Centennial commercial paper program borrowings.
Borrowings outstanding that were classified as long-term debt
under the Company's and Centennial's commercial paper programs
totaled $126.6 million at September 30, 2003, compared to
$151.9 million at December 31, 2002.
15. Business segment data
The Company's reportable segments are those that are based
on the Company's method of internal reporting, which generally
segregates the strategic business units due to differences in
products, services and regulation. The Company has six
reportable segments consisting of electric, natural gas
distribution, utility services, pipeline and energy services,
natural gas and oil production, and construction materials and
mining. During the fourth quarter of 2002, the Company
separated independent power production and other operations
from its reportable segments. The independent power production
and other operations do not individually meet the criteria to
be considered a reportable segment. All prior period
information has been restated to reflect this change.
The vast majority of the Company's operations are located
within the United States. The Company also has investments in
foreign countries, which consist largely of an investment in a
natural gas-fired electric generation station in Brazil, as
discussed in Note 10. The electric segment generates,
transmits and distributes electricity and the natural gas
distribution segment distributes natural gas. These operations
also supply related value-added products and services in the
northern Great Plains. The utility services segment consists
of a diversified infrastructure company specializing in
electric, gas and telecommunication utility construction, as
well as industrial and commercial electrical, exterior lighting
and traffic signalization throughout most of the United States.
Utility services also provides related specialty equipment
manufacturing, sales and rental services. The pipeline and
energy services segment provides natural gas transportation,
underground storage and gathering services through regulated
and nonregulated pipeline systems primarily in the Rocky
Mountain and northern Great Plains regions of the United
States. The pipeline and energy services segment also provides
energy-related management services, including cable and
pipeline magnetization and locating. The natural gas and oil
production segment is engaged in natural gas and oil
acquisition, exploration and production activities primarily in
the Rocky Mountain region of the United States and in and
around the Gulf of Mexico. The construction materials and
mining segment mines aggregates and markets crushed stone,
sand, gravel and related construction materials, including
ready-mixed concrete, cement, asphalt and other value-added
products, as well as performs integrated construction services,
in the north central and western United States and in the
states of Alaska, Hawaii and Texas. The independent power
production and other operations include electric generating
facilities in the United States and Brazil and investments in
potential new growth opportunities that are not directly being
pursued by the Company's other businesses.
The information below follows the same accounting policies
as described in Note 1 of the Company's 2002 Annual Report.
Information on the Company's businesses was as follows:
Inter-
External segment Earnings
Operating Operating on Common
Revenues Revenues Stock
(In thousands)
Three Months Ended
September 30, 2003
Electric $ 47,935 $ --- $ 6,279
Natural gas distribution 27,710 --- (2,524)
Pipeline and energy
services 55,173 6,230 4,662
130,818 6,230 8,417
Utility services 116,091 --- 1,669
Natural gas and oil
production 33,381 31,518 16,530
Construction materials
and mining 426,470 --- 36,135
Independent power
production and other 9,339 740 2,598
585,281 32,258 56,932
Intersegment eliminations --- (38,488) ---
Total $ 716,099 $ --- $ 65,349
Three Months Ended
September 30, 2002
Electric $ 41,515 $ --- $ 4,463
Natural gas distribution 16,821 --- (2,646)
Pipeline and energy
services 21,245 6,324 5,846
79,581 6,324 7,663
Utility services 113,419 --- 1,628
Natural gas and oil
production 40,785 1,383 6,953
Construction materials
and mining 378,613 --- 33,400
Independent power
production and other --- 847 4,098
532,817 2,230 46,079
Intersegment eliminations --- (8,554) ---
Total $ 612,398 $ --- $ 53,742
Inter-
External segment Earnings
Operating Operating on Common
Revenues Revenues Stock
(In thousands)
Nine Months Ended
September 30, 2003
Electric $ 131,655 $ --- $ 12,862
Natural gas distribution 181,104 --- 430
Pipeline and energy
services 142,103 36,656 14,056
454,862 36,656 27,348
Utility services 328,682 --- 4,294
Natural gas and oil
production 111,246 87,334 46,062
Construction materials
and mining 811,352 --- 41,498
Independent power
production and other 25,929 2,221 9,353
1,277,209 89,555 101,207
Intersegment eliminations --- (126,211) ---
Total $1,732,071 $ --- $ 128,555
Nine Months Ended
September 30, 2002
Electric $ 117,877 $ --- $ 9,627
Natural gas distribution 122,652 --- 1,057
Pipeline and energy
services 77,155 36,647 13,361
317,684 36,647 24,045
Utility services 338,051 --- 3,811
Natural gas and oil
production 117,293 31,046 37,363
Construction materials
and mining 701,522 --- 34,560
Independent power
production and other --- 2,541 2,160
1,156,866 33,587 77,894
Intersegment eliminations --- (70,234) ---
Total $1,474,550 $ --- $ 101,939
Earnings from electric, natural gas distribution and
pipeline and energy services are substantially all from
regulated operations. Earnings from utility services, natural
gas and oil production, construction materials and mining, and
independent power production and other are all from
nonregulated operations.
16. Acquisitions
During the first nine months of 2003, the Company acquired
a number of businesses, none of which was individually
material, including construction materials and mining
businesses in Montana, North Dakota and Texas and a wind-
powered electric generation facility in California. The total
purchase consideration for these businesses and adjustments
with respect to certain other acquisitions acquired in 2002,
including the Company's common stock and cash, was $172.2
million.
The above 2003 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, results of operations or cash
flows.
17. Regulatory matters and revenues subject to refund
On May 30, 2003, Montana-Dakota filed an application with
the North Dakota Public Service Commission (NDPSC) for an
electric rate increase. Montana-Dakota requested a total of
$7.8 million annually or 9.1 percent above current rates. The
application included an interim request of $2.4 million
effective July 1, 2003, related to the recovery of costs for
additional investments and costs incurred for new generation
resources. On July 23, 2003, Montana-Dakota and the NDPSC
Staff filed a Settlement Agreement with the NDPSC agreeing on
the issues of rate of return, capital structure and cost of
capital components. On August 4, 2003, Montana-Dakota
requested that the NDPSC hold its interim rate request in
abeyance until the issuance of a final order or until Montana-
Dakota renews the motion for interim relief. A final order
from the NDPSC is due January 30, 2004.
In December 2002, Montana-Dakota filed an application with
the South Dakota Public Utilities Commission (SDPUC) for a
natural gas rate increase. Montana-Dakota requested a total of
$2.2 million annually or 5.8 percent above current rates. On
October 27, 2003, Montana-Dakota and the SDPUC Staff filed a
Settlement Stipulation with the SDPUC agreeing to an increase
of $1.3 million annually. The Settlement Stipulation must be
approved by the SDPUC before it can become effective and a
final order from the SDPUC is expected in late 2003.
In October 2002, Great Plains filed an application with
the Minnesota Public Utilities Commission (MPUC) for a natural
gas rate increase. Great Plains requested a total of $1.6
million annually or 6.9 percent above current rates. In
December 2002, the MPUC issued an Order setting interim rates
that approved an interim increase of $1.4 million annually
effective December 6, 2002. Great Plains began collecting such
rates effective December 6, 2002, subject to refund until the
MPUC issues a final order. On May 13, 2003, Great Plains and
the Minnesota Department of Commerce (DOC), the only intervener
in the proceeding, filed a Stipulation with the MPUC agreeing
to an increase of $1.1 million annually. A hearing before the
MPUC on the Stipulation was held on June 13, 2003, at which
time the MPUC took under advisement the Stipulation agreed upon
by Great Plains and the DOC. On October 9, 2003, the MPUC
issued a Final Order authorizing an increase of $1.1 million
annually as outlined in the Stipulation and requiring Great
Plains to file a compliance filing with the MPUC. On
November 10, 2003, Great Plains filed a compliance filing with
the MPUC. Great Plains is awaiting a decision from the MPUC on
the implementation date of the final rates changes.
Reserves have been provided for a portion of the revenues
that have been collected subject to refund for certain of the
above proceedings. The Company believes that such reserves are
adequate based on its assessment of the ultimate outcome of the
proceedings.
In December 1999, Williston Basin filed a general natural
gas rate change application with the Federal Energy Regulatory
Commission (FERC). Williston Basin began collecting such rates
effective June 1, 2000, subject to refund. In May 2001, the
Administrative Law Judge (ALJ) issued an Initial Decision on
Williston Basin's natural gas rate change application. The
Initial Decision addressed numerous issues relating to the rate
change application, including matters relating to allowable
levels of rate base, return on common equity, and cost of
service, as well as volumes established for purposes of cost
recovery, and cost allocation and rate design. On July 3,
2003, the FERC issued its Order on Initial Decision. The Order
affirmed the ALJ's Initial Decision on many of the issues
including rate base and certain cost of service items as well
as volumes to be used for purposes of cost recovery, and cost
allocation and rate design. However, there are other issues as
to which FERC differed with the ALJ including return on common
equity and the correct level of corporate overhead expense. On
August 4, 2003, Williston Basin requested rehearing of a number
of issues including determinations associated with cost of
service, throughput, and cost allocation and rate design, as
discussed in the FERC's Order. On September 3, 2003, the FERC
issued an order granting Williston Basin's request for
rehearing of the July 3, 2003, Order on Initial Decision. The
FERC also indicated in its September 3, 2003, order that it
anticipates issuing a decision on the merits of the rehearing
request by November 17, 2003.
Reserves have been provided for a portion of the revenues
that have been collected subject to refund with respect to
Williston Basin's pending regulatory proceeding. Williston
Basin believes that such reserves are adequate based on its
assessment of the ultimate outcome of the proceeding.
18. Contingencies
Litigation
In January 2002, Fidelity Oil Co. (FOC), one of the
Company's natural gas and oil production subsidiaries, entered
into a compromise agreement with the former operator of certain
of FOC's oil production properties in southeastern Montana.
The compromise agreement resolved litigation involving the
interpretation and application of contractual provisions
regarding net proceeds interests paid by the former operator to
FOC for a number of years prior to 1998. The terms of the
compromise agreement are confidential. As a result of the
compromise agreement, the natural gas and oil production
segment reflected a gain in its financial results for the first
quarter of 2002 of approximately $16.6 million after tax. As
part of the settlement, FOC gave the former operator a full and
complete release, and FOC is not asserting any such claim
against the former operator for periods after 1997.
In July 1996, Jack J. Grynberg (Grynberg) filed suit in
United States District Court for the District of Columbia (U.S.
District Court) against Williston Basin and over 70 other
natural gas pipeline companies. Grynberg, acting on behalf of
the United States under the Federal False Claims Act, alleged
improper measurement of the heating content and volume of
natural gas purchased by the defendants resulting in the
underpayment of royalties to the United States. In March 1997,
the U.S. District Court dismissed the suit without prejudice
and the dismissal was affirmed by the United States Court of
Appeals for the D.C. Circuit in October 1998. In June 1997,
Grynberg filed a similar Federal False Claims Act suit against
Williston Basin and Montana-Dakota and filed over 70 other
separate similar suits against natural gas transmission
companies and producers, gatherers, and processors of natural
gas. In April 1999, the United States Department of Justice
decided not to intervene in these cases. In response to a
motion filed by Grynberg, the Judicial Panel on Multidistrict
Litigation consolidated all of these cases in the Federal
District Court of Wyoming (Federal District Court). Oral
argument on motions to dismiss was held before the Federal
District Court in March 2000. In May 2001, the Federal
District Court denied Williston Basin's and Montana-Dakota's
motion to dismiss.
The matter is currently in the discovery stage. Grynberg
has not specified the amount he seeks to recover. Williston
Basin and Montana-Dakota are unable to estimate their potential
exposure and will be unable to do so until discovery is
completed. Williston Basin and Montana-Dakota believe that the
Grynberg case will ultimately be dismissed because Grynberg is
not, as is required by the Federal False Claims Act, the
original source of the information underlying the action.
Failing this, Williston Basin and Montana-Dakota believe
Grynberg will not recover damages from Williston Basin and
Montana-Dakota because insufficient facts exist to support the
allegations. Williston Basin and Montana-Dakota intend to
vigorously contest this suit.
The Company is also involved in other legal actions in the
ordinary course of its business. Although the outcomes of any
such legal actions cannot be predicted, management believes
that the outcomes with respect to these other legal proceedings
will not have a material adverse effect upon the Company's
financial position or results of operations.
Environmental matters
In December 2000, Morse Bros., Inc. (MBI), an indirect
wholly owned subsidiary of the Company, was named by the United
States Environmental Protection Agency (EPA) as a Potentially
Responsible Party in connection with the cleanup of a
commercial property site, acquired by MBI in 1999, and part of
the Portland, Oregon, Harbor Superfund Site. Sixty-eight other
parties were also named in this administrative action. The EPA
wants responsible parties to share in the cleanup of sediment
contamination in the Willamette River. To date, costs of the
overall remedial investigation of the harbor site for both the
EPA and the Oregon State Department of Environmental Quality
(DEQ) are being recorded, and initially paid, through an
administrative consent order by the Lower Willamette Group
(LWG), a group of ten entities which does not include MBI. The
LWG estimates the overall remedial investigation and
feasibility study will cost approximately $10 million. It is
not possible to estimate the cost of a corrective action plan
until the remedial investigation and feasibility study has been
completed, the EPA has decided on a strategy, and a record of
decision has been published. While the remedial investigation
and feasibility study for the harbor site has commenced, it is
expected to take several years to complete. The development of
a proposed plan and record of decision on the harbor site is
not anticipated to occur until 2006, after which a cleanup plan
will be undertaken.
Based upon a review of the Portland Harbor sediment
contamination evaluation by the DEQ and other information
available, MBI does not believe it is a Responsible Party. In
addition, MBI has notified Georgia-Pacific West, Inc., the
seller of the commercial property site to MBI, that it intends
to seek indemnity for any and all liabilities incurred in
relation to the above matters, pursuant to the terms of their
sale agreement.
The Company believes it is not probable that it will incur
any material environmental remediation costs or damages in
relation to the above administrative action.
Guarantees
Centennial has unconditionally guaranteed a portion of
certain bank borrowings of MPX and a foreign currency swap
agreement of MPX in connection with the Company's equity method
investment in the natural gas-fired electric generation station
in Brazil, as discussed in Note 10. The Company, through MDU
Brasil, owns 49 percent of MPX. At September 30, 2003, the
amount of the obligation of the foreign currency swap
agreement, which expires in 2003, was $47,000. At
September 30, 2003, the aggregate amount of borrowings
outstanding subject to these guarantees was $64.4 million and
the scheduled repayment of these borrowings was $19.1 million
in 2006 and $45.3 million in 2008. Centennial guarantees of
approximately $19.1 million will terminate upon MPX meeting
certain financial covenants. The individual investor, who
through EBX Empreendimentos Ltda. (EBX), a Brazilian company,
owns 51 percent of MPX, has also guaranteed a portion of these
loans. Centennial and the individual investor have entered
into reimbursement agreements under which they have agreed to
reimburse each other to the extent they may be required to make
any guarantee payments in excess of their proportionate
ownership share in MPX. These guarantees are not reflected on
the Consolidated Balance Sheets.
In addition, WBI Holdings has guaranteed certain of its
subsidiary's natural gas and oil price collar agreement
obligations. The amount of the subsidiary's obligations at
September 30, 2003, was $2.2 million. There is no fixed
maximum amount guaranteed in relation to the natural gas and
oil price collar agreements; however, the amount of hedging
activity entered into by the subsidiary is limited by corporate
policy. The guarantees of the natural gas and oil price collar
agreements at September 30, 2003, expire in December 2003;
however, the subsidiary continues to enter into additional
hedging activities, and, as a result, WBI Holdings from time to
time may issue additional guarantees on these hedging
obligations. The amounts outstanding under the natural gas and
oil price collar agreements were reflected on the Consolidated
Balance Sheets. In the event the above subsidiary defaults
under its obligations, WBI Holdings would be required to make
payments under its guarantees.
Certain subsidiaries of the Company have outstanding
guarantees to third parties that guarantee the performance of
other subsidiaries of the Company that are related to natural
gas transportation and sales agreements, electric power supply
agreements, insurance policies and certain other guarantees.
At September 30, 2003, the fixed maximum amounts guaranteed
under these agreements aggregated $43.7 million. The amounts
of scheduled expiration of the maximum amounts guaranteed under
these agreements aggregate $6.5 million in 2003; $12.5 million
in 2004; $5.0 million in 2005; $3.3 million in 2006; $900,000
in 2009; $12.0 million in 2012; $500,000, which is subject to
expiration 30 days after the receipt of written notice and $3.0
million, which has no scheduled maturity date. The amount
outstanding by subsidiaries of the Company under the above
guarantees was $202,000 and was reflected on the Consolidated
Balance Sheets at September 30, 2003. In the event of default
under these guarantee obligations, the subsidiary issuing the
guarantee for that particular obligation would be required to
make payments under its guarantee.
Fidelity Exploration & Production Company (Fidelity), an
indirect wholly owned subsidiary of the Company, and WBI
Holdings have outstanding guarantees to Williston Basin. These
guarantees are related to natural gas transportation and
storage agreements that guarantee the performance of
Prairielands Energy Marketing, Inc. (Prairielands), an indirect
wholly owned subsidiary of the Company. At September 30, 2003,
the fixed maximum amounts guaranteed under these agreements
aggregated $22.0 million. Scheduled expiration of the maximum
amounts guaranteed under these agreements aggregate $2.0
million in 2005 and $20.0 million in 2009. In the event of
Prairielands' default in its payment obligations, the
subsidiary issuing the guarantee for that particular obligation
would be required to make payments under its guarantee. The
amount outstanding by Prairielands under the above guarantees
was $650,000, which was not reflected on the Consolidated
Balance Sheets at September 30, 2003, because these
intercompany transactions are eliminated in consolidation.
In addition, Centennial has issued guarantees related to
the Company's purchase of maintenance items to third parties
for which no fixed maximum amounts have been specified. These
guarantees have no scheduled maturity date. In the event a
subsidiary of the Company defaults under its obligation in
relation to the purchase of certain maintenance items,
Centennial would be required to make payments under these
guarantees. Any amounts outstanding by subsidiaries of the
Company for these maintenance items were reflected on the
Consolidated Balance Sheets at September 30, 2003.
As of September 30, 2003, Centennial was contingently
liable for performance of certain of its subsidiaries under
approximately $325 million of surety bonds. These bonds are
principally for construction contracts and reclamation
obligations of these subsidiaries, entered into in the normal
course of business. Centennial indemnifies the respective
surety bond companies against any exposure under the bonds. A
large portion of these contingent commitments are expected to
expire within the next twelve months; however, Centennial will
likely continue to enter into surety bonds for its subsidiaries
in the future. The surety bonds were not reflected on the
Consolidated Balance Sheets.
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
The Company has six reportable segments consisting of electric,
natural gas distribution, utility services, pipeline and energy
services, natural gas and oil production, and construction materials
and mining. During the fourth quarter of 2002, the Company
separated independent power production and other operations from its
reportable segments. The independent power production and other
operations do not individually meet the criteria to be considered a
reportable segment. All prior period information has been restated
to reflect this change.
The electric and natural gas distribution segments include the
electric and natural gas distribution operations of Montana-Dakota
and the natural gas distribution operations of Great Plains Natural
Gas Co. The utility services segment includes all the operations of
Utility Services, Inc. The pipeline and energy services segment
includes WBI Holdings' natural gas transportation, underground
storage, gathering services, and energy related management services.
The natural gas and oil production segment includes the natural gas
and oil acquisition, exploration and production operations of WBI
Holdings. The construction materials and mining segment includes
the results of Knife River's operations, while independent power
production and other operations include electric generating
facilities in the United States and Brazil and investments in
potential new growth opportunities that are not directly being
pursued by the Company's other businesses.
Earnings from electric, natural gas distribution and pipeline
and energy services are substantially all from regulated operations.
Earnings from utility services, natural gas and oil production,
construction materials and mining, and independent power production
and other are all from nonregulated operations.
On August 14, 2003, the Company's Board of Directors approved a
three-for-two common stock split. For more information on the
common stock split see Note 3 of Notes to Consolidated Financial
Statements.
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 businesses.
Three Months Nine Months
Ended Ended
September 30, September 30,
2003 2002 2003 2002
Electric $ 6.3 $ 4.5 $ 12.9 $ 9.6
Natural gas distribution (2.5) (2.6) .4 1.0
Utility services 1.7 1.6 4.3 3.8
Pipeline and energy services 4.6 5.8 14.1 13.3
Natural gas and oil production 16.5 6.9 46.1 37.4
Construction materials and mining 36.1 33.4 41.5 34.6
Independent power production
and other 2.6 4.1 9.3 2.2
Earnings on common stock $ 65.3 $ 53.7 $128.6 $101.9
Earnings per common
share - basic $ .58 $ .51 $ 1.16 $ .97
Earnings per common
share - diluted $ .58 $ .50 $ 1.15 $ .96
Return on average common equity
for the 12 months ended 13.4% 11.5%
________________________________
Three Months Ended September 30, 2003 and 2002
Consolidated earnings for the quarter ended September 30, 2003,
increased $11.6 million from the comparable period a year ago due to
higher earnings at the natural gas and oil production, construction
materials and mining, electric, natural gas distribution and utility
services businesses. Decreased earnings at the independent power
production and other and pipeline and energy services businesses
slightly offset the earnings increase.
Nine Months Ended September 30, 2003 and 2002
Consolidated earnings for the nine months ended September 30,
2003, increased $26.7 million from the comparable period a year ago
due to higher earnings at the natural gas and oil production,
independent power production and other, construction materials and
mining, electric, pipeline and energy services, and utility services
businesses. Decreased earnings at the natural gas distribution
business slightly offset the earnings increase.
________________________________
Financial and operating data
The following tables (dollars in millions, where applicable)
are key financial and operating statistics for each of the Company's
businesses.
Electric
Three Months Nine Months
Ended Ended
September 30, September 30,
2003 2002 2003 2002
Operating revenues:
Retail sales $ 40.0 $ 37.1 $ 110.7 $ 103.3
Sales for resale and other 7.9 4.4 21.0 14.6
47.9 41.5 131.7 117.9
Operating expenses:
Fuel and purchased power 16.1 14.5 44.8 41.6
Operation and maintenance 12.6 10.8 38.9 33.7
Depreciation, depletion and
amortization 5.1 4.8 15.0 14.6
Taxes, other than income 1.9 1.8 5.8 5.6
35.7 31.9 104.5 95.5
Operating income $ 12.2 $ 9.6 $ 27.2 $ 22.4
Retail sales (million kWh) 630.2 609.9 1,760.0 1,669.6
Sales for resale (million kWh) 212.7 153.6 587.1 580.0
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,
2003 2002 2003 2002
Operating revenues:
Sales $ 26.8 $ 16.0 $ 178.1 $ 119.9
Transportation and other .9 .8 3.0 2.8
27.7 16.8 181.1 122.7
Operating expenses:
Purchased natural gas sold 18.1 8.6 136.6 82.4
Operation and maintenance 9.7 8.5 31.4 27.0
Depreciation, depletion and
amortization 2.4 2.4 7.6 7.2
Taxes, other than income 1.3 1.2 3.9 3.8
31.5 20.7 179.5 120.4
Operating income (loss) $ (3.8) $ (3.9)$ 1.6 $ 2.3
Volumes (MMdk):
Sales 3.1 3.1 25.9 26.2
Transportation 2.8 2.5 8.8 8.9
Total throughput 5.9 5.6 34.7 35.1
Degree days (% of normal)* 92% 82% 100% 104%
Average cost of natural gas,
including transportation
thereon, per dk $ 5.80 $ 2.73 $ 5.27 $ 3.14
_____________________
* Degree days are a measure of the daily temperature-related demand
for energy for heating.
Utility Services
Three Months Nine Months
Ended Ended
September 30, September 30,
2003 2002 2003 2002
Operating revenues $116.1 $113.4 $ 328.7 $ 338.1
Operating expenses:
Operation and maintenance 106.5 104.3 300.4 311.7
Depreciation, depletion
and amortization 2.6 2.4 7.7 6.8
Taxes, other than income 3.6 3.1 11.4 10.8
112.7 109.8 319.5 329.3
Operating income $ 3.4 $ 3.6 $ 9.2 $ 8.8
Pipeline and Energy Services
Three Months Nine Months
Ended Ended
September 30, September 30,
2003 2002 2003 2002
Operating revenues:
Pipeline $ 24.2 $ 26.4 $ 74.7 $ 71.4
Energy services 37.2 1.2 104.1 42.4
61.4 27.6 178.8 113.8
Operating expenses:
Purchased natural gas sold 36.5 .7 101.3 36.8
Operation and maintenance 11.0 10.4 34.8 34.4
Depreciation, depletion
and amortization 3.8 3.7 11.2 11.0
Taxes, other than income 1.4 1.3 4.3 4.4
52.7 16.1 151.6 86.6
Operating income $ 8.7 $ 11.5 $ 27.2 $ 27.2
Transportation volumes (MMdk):
Montana-Dakota 9.2 9.4 25.6 24.6
Other 13.7 20.5 44.3 52.4
22.9 29.9 69.9 77.0
Gathering volumes (MMdk) 18.8 18.8 56.4 52.4
Natural Gas and Oil Production
Three Months Nine Months
Ended Ended
September 30, September 30,
2003 2002 2003 2002
Operating revenues:
Natural gas $ 52.7 $ 30.2 $160.5 $ 87.8
Oil 12.2 11.9 37.9 33.1
Other --- .1 .2 27.4*
64.9 42.2 198.6 148.3
Operating expenses:
Purchased natural gas sold --- --- .1 ---
Operation and maintenance:
Lease operating costs 8.4 7.5 22.9 20.2
Gathering and transportation 4.0 3.1 11.1 8.9
Other 3.7 4.1 12.5 12.7
Depreciation, depletion
and amortization 15.3 12.3 44.6 35.2
Taxes, other than income:
Production and property
taxes 5.4 2.9 16.0 8.2
Other .1 .2 .4 .6
36.9 30.1 107.6 85.8
Operating income $ 28.0 $ 12.1 $ 91.0 $ 62.5
Production:
Natural gas (MMcf) 13,470 12,219 40,367 34,571
Oil (000's of barrels) 453 486 1,380 1,469
Average realized prices
(including hedges):
Natural gas (per Mcf) $ 3.91 $ 2.48 $ 3.98 $ 2.54
Oil (per barrel) $26.86 $24.44 $27.48 $ 22.54
Average realized prices
(excluding hedges):
Natural gas (per Mcf) $ 4.26 $ 2.13 $ 4.42 $ 2.34
Oil (per barrel) $27.78 $25.63 $28.64 $ 22.68
Production costs, including
taxes, per net equivalent Mcf $ 1.10 $ .89 $ 1.03 $ .86
_____________________
* Includes the effects of a compromise agreement gain of $27.4
million ($16.6 million after tax).
Construction Materials and Mining
Three Months Nine Months
Ended Ended
September 30, September 30,
2003 2002 2003 2002
Operating revenues $426.5 $378.6 $811.3 $ 701.5
Operating expenses:
Operation and maintenance 338.3 299.1 668.9 581.7
Depreciation, depletion
and amortization 16.4 14.9 46.6 39.5
Taxes, other than income 8.5 6.3 19.5 14.2
363.2 320.3 735.0 635.4
Operating income $ 63.3 $ 58.3 $ 76.3 $ 66.1
Sales (000's):
Aggregates (tons) 14,119 13,155 28,738 25,600
Asphalt (tons) 3,647 3,745 5,510 5,732
Ready-mixed concrete
(cubic yards) 1,161 951 2,588 2,145
Independent Power Production and Other
Three Months Nine Months
Ended Ended
September 30, September 30,
2003 2002 2003 2002
Operating revenues $ 10.1 $ .8 $ 28.1 $ 2.5
Operating expenses:
Operation and maintenance 4.1 1.7 11.3 4.4
Depreciation, depletion and
amortization 2.1 .1 6.0 .2
6.2 1.8 17.3 4.6
Operating income (loss) $ 3.9* $ (1.0) $ 10.8*$ (2.1)
Net generation capacity - kW** 279,600 --- 279,600 ---
Electricity produced and sold
(thousand kWh)** 103,816 --- 242,410 ---
_____________________
* Reflects international operations for 2003 and domestic
operations acquired on November 1, 2002 and January 31, 2003.
** Reflects domestic independent power production operations.
NOTE: The earnings from the Company's equity method investment in
Brazil were included in other income - net and, thus, are not
reflected in the above table.
Amounts presented in the preceding tables for operating
revenues, purchased natural gas sold and operation and maintenance
expense will not agree with the Consolidated Statements of Income
due to the elimination of intersegment transactions. The amounts
(dollars in millions) relating to the elimination of intersegment
transactions are as follows:
Three Months Nine Months
Ended Ended
September 30, September 30,
2003 2002 2003 2002
Operating revenues $ 38.5 $ 8.5 $ 126.2 $ 70.2
Purchased natural gas sold $ 34.7 $ 4.7 $ 114.4 $ 59.1
Operation and maintenance $ 3.8 $ 3.8 $ 11.8 $ 11.1
For further information on intersegment eliminations, see Note
15 of Notes to Consolidated Financial Statements.
Three Months Ended September 30, 2003 and 2002
Electric
Electric earnings increased as a result of higher sales for
resale revenues due to higher average realized prices of 46 percent
and higher volumes of 39 percent, both resulting from stronger
sales for resale markets. Also contributing to the earnings
increase were higher retail sales prices and higher retail sales
volumes, primarily to residential and small commercial customers.
Partially offsetting the earnings increase was higher operation and
maintenance expense, primarily due to higher pension, medical, and
payroll costs, and higher power plant maintenance costs.
Natural Gas Distribution
Normal seasonal losses at the natural gas distribution business
decreased slightly as a result of higher retail sales rates, the
result of increases in Minnesota, Montana, North Dakota and Wyoming.
Largely offsetting the earnings increase was higher operation and
maintenance expense, primarily due to higher pension, medical and
payroll costs. The pass-through of higher natural gas prices is
reflected in the increase in both sales revenues and purchased
natural gas sold. For further information on the retail rate
increases, see Note 17 of Notes to Consolidated Financial Statements
in this Form 10-Q and Note 17 of Notes to Consolidated Financial
Statements in the Company's Quarterly Report on Form 10-Q for the
quarter ended March 31, 2003.
Utility Services
Utility services earnings increased slightly as a result of
higher inside electrical margins in the Northwest and Central
regions and higher line construction margins in the Northwest and
Rocky Mountain regions, all at existing operations. Earnings from a
company acquired since the comparable period last year also added to
the earnings increase. Largely offsetting the earnings increase
were lower line construction margins at existing operations in the
Southwest and Central regions and higher selling, general and
administrative expenses. Lower margins are a reflection of the
continuing effects of the soft economy in this sector and the
downturn in the telecommunications market.
Pipeline and Energy Services
Earnings at the pipeline and energy services business decreased
as a result of lower transportation volumes, largely resulting from
lower volumes transported to storage, and higher operation and
maintenance costs due in part to higher compressor-related materials
costs and property insurance costs. Partially offsetting the
earnings decrease were higher transportation reservation fees
resulting from an increase in firm services, lower financing-related
costs and higher transportation and gathering rates. The increase
in energy services revenues and the related increase in purchased
natural gas sold include the effect of increases in natural gas
prices since the comparable period last year.
Natural Gas and Oil Production
Natural gas and oil production earnings increased due to higher
realized natural gas prices of 58 percent, higher natural gas
production of 10 percent, largely resulting from enhanced natural
gas production in the Rocky Mountain area, and higher average
realized oil prices of 10 percent. Partially offsetting the
earnings increase were increased depreciation, depletion and
amortization expense due to higher natural gas production volumes
and higher rates and increased operation and maintenance expense,
primarily higher lease operating expenses due in part to increased
natural gas production. Decreased oil production of 7 percent also
partially offset the earnings increase.
Construction Materials and Mining
Construction materials and mining earnings increased due to
earnings from companies acquired since the comparable period last
year. Increased ready-mixed concrete volumes and margins and higher
aggregate volumes, all at existing operations, also added to the
increase in earnings. Partially offsetting the earnings increase
were higher selling, general and administrative costs, lower asphalt
volumes and margins, due in part to higher asphalt oil costs, and
higher depreciation, depletion and amortization expense due to
higher property, plant and equipment balances.
Independent Power Production and Other
Earnings for the independent power production business
decreased due to lower net income at the Brazilian operations and
higher interest expense resulting from higher debt balances related
to domestic businesses acquired since the comparable period last
year. Lower net income of $3.6 million from the Company's share of
its equity investment in Brazil was due primarily to the effects of
foreign currency exchange fluctuations, including their effect on
the value of the embedded derivative in the electric power contract,
offset in part by higher margins due to higher capacity revenues
resulting from all four units being in operation compared to only
two operational units (effective July 2002) for the same period in
2002. Partially offsetting the earnings decrease were earnings from
domestic businesses acquired since the comparable period last year.
Nine Months Ended September 30, 2003 and 2002
Electric
Electric earnings increased as a result of higher retail sales
revenues, due in part to higher retail sales volumes, largely to
residential, commercial and large industrial customers. Higher
average sales for resale prices of 48 percent and higher sales for
resale volumes, both due to stronger sales for resale markets, also
added to the increase in earnings. Partially offsetting the
earnings increase was higher operation and maintenance expense,
largely higher payroll costs, higher costs related to planned
maintenance outages at two generating stations, and higher pension
and medical costs. Increased fuel and purchased power costs also
partially offset the earnings increase.
Natural Gas Distribution
Earnings at the natural gas distribution business decreased as
a result of higher operation and maintenance expense, primarily due
to higher payroll, pension and medical costs, and decreased returns
on natural gas held in storage. Partially offsetting the earnings
decline were higher retail sales rates, the result of increases in
Minnesota, Montana, North Dakota and Wyoming, as previously
discussed. The pass-through of higher natural gas prices is
reflected in the increase in both sales revenues and purchased
natural gas sold.
Utility Services
Utility services earnings increased as a result of the absence
in 2003 of a 2002 write-off of receivables of $1.4 million (after
tax) associated with a company in the telecommunications industry
and the absence in 2003 of a 2002 unfavorable settlement of a
billing dispute of $724,000 (after tax) in the Central Region.
Higher line construction margins in the Northwest and Rocky Mountain
regions and higher equipment sale margins also added to the increase
in earnings. Partially offsetting the earnings increase were lower
line construction margins in the Southwest and Central regions,
lower margins in the telecommunications industry in the Rocky
Mountain region and lower inside electrical margins in the Northwest
and Central regions. Lower margins are a reflection of the
continuing effects of the soft economy in this sector and the
downturn in the telecommunications market.
Pipeline and Energy Services
Earnings at the pipeline and energy services business increased
as a result of higher gathering volumes of 8 percent, lower
financing-related costs and increased storage revenues. Partially
offsetting the earnings increase was higher operation and
maintenance costs, primarily higher payroll and property insurance
costs. The increase in energy services revenues and the related
increase in purchased natural gas sold include the effect of
increases in natural gas prices since the comparable period last
year.
Natural Gas and Oil Production
Natural gas and oil production earnings increased due to higher
realized natural gas prices of 57 percent, higher natural gas
production of 17 percent, largely resulting from enhanced natural
gas production in the Rocky Mountain area, and higher average
realized oil prices of 22 percent. Largely offsetting the earnings
increase were the 2002 compromise agreement gain of $27.4 million
($16.6 million after tax) which was included in 2002 operating
revenues, and the $12.7 million ($7.7 million after tax) noncash
transition charge in 2003, reflecting the cumulative effect of an
accounting change, as discussed in Note 18 and Note 8 of Notes to
Consolidated Financial Statements, respectively. Also partially
offsetting the earnings increase were increased depreciation,
depletion and amortization expense due to higher natural gas
production volumes and higher rates, and increased operation and
maintenance expense, primarily higher lease operating expenses
resulting largely from the expansion of coalbed natural gas
production. Decreased oil production of 6 percent, higher interest
expense, due primarily to higher average debt balances, and higher
general and administrative costs, also partially offset the earnings
increase.
Construction Materials and Mining
Construction materials and mining earnings increased due to
increased aggregate volumes and margins, increased ready-mix
concrete volumes and margins, and higher construction activity
primarily due to a large harbor-deepening project in southern
California, all at existing operations. Earnings from companies
acquired since the comparable period last year also added to the
earnings increase. Partially offsetting the increase in earnings
were higher selling, general and administrative costs and lower
asphalt volumes and margins due in part to higher asphalt oil costs.
Higher depreciation, depletion and amortization expense primarily
due to higher aggregate volumes produced and higher property, plant
and equipment balances also partially offset the earnings increase.
Independent Power Production and Other
Earnings for the independent power production business
increased largely from the domestic businesses acquired since the
comparable period last year, partially offset by higher interest
expense, resulting from higher average debt balances relating to
these acquisitions. Partially offsetting the earnings increase was
lower net income of $477,000 from the Company's share of its equity
investment in Brazil due primarily to the mark-to-market loss on an
embedded derivative in the electric power contract and higher
interest expense due to a full nine months of debt in 2003, offset
by higher margins due to higher capacity revenues, as previously
discussed.
Risk Factors and Cautionary Statements that May Affect Future
Results
The Company is including the following factors and cautionary
statements in this Form 10-Q to make applicable and to take
advantage of the safe harbor provisions of the Private Securities
Litigation Reform Act of 1995 for any forward-looking statements
made by, or on behalf of, the Company. Forward-looking statements
include statements concerning plans, objectives, goals, strategies,
future events or performance, and underlying assumptions (many of
which are based, in turn, upon further assumptions) and other
statements that are other than statements of historical facts. From
time to time, the Company may publish or otherwise make available
forward-looking statements of this nature, including statements
contained within Prospective Information. All these subsequent
forward-looking statements, whether written or oral and whether made
by or on behalf of the Company, are also expressly qualified by
these factors and cautionary statements.
Forward-looking statements involve risks and uncertainties,
which could cause actual results or outcomes to differ materially
from those expressed. The Company's expectations, beliefs and
projections are expressed in good faith and are believed by the
Company to have a reasonable basis, including without limitation
management's examination of historical operating trends, data
contained in the Company's records and other data available from
third parties. Nonetheless, the Company's expectations, beliefs or
projections may not be achieved or accomplished.
Any forward-looking statement contained in this document speaks
only as of the date on which the 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 the 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 the factors, nor
can it assess the effect of each factor on the Company's business or
the extent to which any factor, or combination of factors, may cause
actual results to differ materially from those contained in any
forward-looking statement.
Following are some specific factors that should be considered
for a better understanding of the Company's financial condition.
These factors and the other matters discussed herein are important
factors that could cause actual results or outcomes for the Company
to differ materially from those discussed in the forward-looking
statements included elsewhere in this document.
Economic Risks
The recent events leading to the current adverse economic
environment may have a general negative impact on the Company's
future revenues and may result in a goodwill impairment for
Innovatum, Inc., an indirect wholly owned subsidiary of the Company
(Innovatum).
In response to the occurrence of several recent events,
including the September 11, 2001, terrorist attack on the United
States, the ongoing war against terrorism by the United States and
the bankruptcy of several large energy and telecommunications
companies and other large enterprises, the financial markets have
been highly volatile. An adverse economy could negatively affect
the level of governmental expenditures on public projects and the
timing of these projects which, in turn, would negatively affect the
demand for the Company's products and services.
Innovatum, which specializes in cable and pipeline
magnetization and locating, is subject to the economic conditions
within the telecommunications and energy industries. Innovatum
could face a future goodwill impairment if there is a continued
downturn in these sectors. At September 30, 2003, the goodwill
amount at Innovatum was approximately $8.3 million. The
determination of whether an impairment will occur is dependent on a
number of factors, including the level of spending in the
telecommunications and energy industries, the success of a newly
developed hand-held locating device at Innovatum, rapid changes in
technology, competitors and potential new customers.
The Company relies on financing sources and capital markets. The
Company's inability to access financing may impair the Company's
ability to execute its business plans, make capital expenditures or
pursue acquisitions that the Company may otherwise rely on for
future growth.
The Company relies on access to both short-term borrowings,
including the issuance of commercial paper, and long-term capital
markets as a source of liquidity for capital requirements not
satisfied by the cash flow from operations. If the Company is not
able to access capital at competitive rates, the ability to
implement its business plans may be adversely affected. Market
disruptions or a downgrade of the Company's credit ratings may
increase the cost of borrowing or adversely affect its ability to
access one or more financial markets. Such disruptions could
include:
- A severe prolonged economic downturn
- The bankruptcy of unrelated industry leaders in the same line
of business
- Capital market conditions generally
- Volatility in commodity prices
- Terrorist attacks
- Global events
The Company's natural gas and oil production business is dependent
on factors, including commodity prices, which cannot be predicted or
controlled.
These factors include: price fluctuations in natural gas and
crude oil prices; availability of economic supplies of natural gas;
drilling successes in natural gas and oil operations; the ability to
contract for or to secure necessary drilling rig contracts and to
retain employees to drill for and develop reserves; the ability to
acquire natural gas and oil properties; and other risks incidental
to the operations of natural gas and oil wells.
Environmental and Regulatory Risks
Some of the Company's operations are subject to extensive
environmental laws and regulations that may increase its costs of
operations, impact or limit its business plans, or expose the
Company to environmental liabilities. One of the Company's
subsidiaries has been sued in connection with its coalbed natural
gas development activities.
The Company is subject to extensive environmental laws and
regulations affecting many aspects of its present and future
operations including air quality, water quality, waste management
and other environmental considerations. These laws and regulations
can result in increased capital, operating and other costs, as a
result of compliance, remediation, containment and monitoring
obligations, particularly with regard to laws relating to power
plant emissions and coalbed natural gas development. These laws and
regulations generally require the Company to obtain and comply with
a wide variety of environmental licenses, permits, inspections and
other approvals. Both public officials and private individuals may
seek to enforce applicable environmental laws and regulations. The
Company cannot predict the outcome (financial or operational) of any
related litigation that may arise.
Existing environmental regulations may be revised and new
regulations seeking to protect the environment may be adopted or
become applicable to the Company. Revised or additional
regulations, which result in increased compliance costs or
additional operating restrictions, particularly if those costs are
not fully recoverable from customers, could have a material effect
on the Company's results of operations.
Fidelity has been named as a defendant in, and/or certain of
its operations are the subject of, several lawsuits filed in
connection with its coalbed natural gas development in the Powder
River Basin in Montana and Wyoming. If the plaintiffs are
successful in these lawsuits, the ultimate outcome of the actions
could have a material effect on Fidelity's existing coalbed natural
gas operations and/or its future development of its coalbed natural
gas properties.
The Company is subject to extensive government regulations that may
have a negative impact on its business and its results of
operations.
The Company is subject to regulation by federal, state and
local regulatory agencies with respect to, among other things,
allowed rates of return, financings, industry rate structures, and
recovery of purchased power and purchased gas costs. These
governmental regulations significantly influence the Company's
operating environment and may affect its ability to recover costs
from its customers. The Company is unable to predict the impact on
operating results from the future regulatory activities of any of
these agencies.
Changes in regulations or the imposition of additional
regulations could have an adverse impact on the Company's results of
operations.
Risks Relating to the Company's Independent Power Production
Business
The operation of power generation facilities involves many
risks, including start up risks, breakdown or failure of equipment,
competition, inability to obtain required governmental permits and
approvals and inability to negotiate acceptable acquisition,
construction, fuel supply, off-take or other material agreements, as
well as the risk of performance below expected levels of output or
efficiency.
The Company is finalizing plans for the construction of a 113-
megawatt coal-fired development project in Hardin, Montana. Based
on demand and power pricing in the Northwest, the plant will be
built on a merchant basis. Unanticipated events could delay
completion of construction, start-up and/or operation of the
project. Changes in the market price for power from the Company's
projections could also negatively impact earnings to be derived from
the project.
Risks Relating to Foreign Operations
The value of the Company's investment in foreign operations may
diminish due to political, regulatory and economic conditions and
changes in currency exchange rates in countries where the Company
does business.
The Company is subject to political, regulatory and economic
conditions and changes in currency exchange rates in foreign
countries where the Company does business. Significant changes in
the political, regulatory or economic environment in these countries
could negatively affect the value of the Company's investments
located in these countries. Also, since the Company is unable to
predict the fluctuations in the foreign currency exchange rates,
these fluctuations may have an adverse impact on the Company's
results of operations.
The Company's 49 percent equity method investment in a 220-
megawatt natural gas-fired electric generation project in Brazil
includes a power purchase agreement that contains an embedded
derivative. This embedded derivative derives its value from an
annual adjustment factor that largely indexes the contract capacity
payments to the U.S. dollar. In addition, from time to time, other
derivative instruments may be utilized. The valuation of these
financial instruments, including the embedded derivative, can
involve judgments, uncertainties and the use of estimates. As a
result, changes in the underlying assumptions could affect the
reported fair value of these instruments. These instruments could
recognize financial losses as a result of volatility in the
underlying fair values, or if a counterparty fails to perform.
Other Risks
Competition is increasing in all of the Company's businesses.
All of the Company's businesses are subject to increased
competition. The independent power industry includes numerous
strong and capable competitors, many of which have greater resources
and more experience in the operation, acquisition and development of
power generation facilities. Utility services' competition is based
primarily on price and reputation for quality, safety and
reliability. The construction materials products are marketed under
highly competitive conditions and are subject to such competitive
forces as price, service, delivery time and proximity to the
customer. The electric utility and natural gas industries are also
experiencing increased competitive pressures as a result of consumer
demands, technological advances, deregulation, greater availability
of natural gas-fired generation and other factors. Pipeline and
energy services competes with several pipelines for access to
natural gas supplies and gathering, transportation and storage
business. The natural gas and oil production business is subject to
competition in the acquisition and development of natural gas and
oil properties as well as in the sale of its production.
Weather conditions can adversely affect the Company's operations and
revenues.
The Company's results of operations can be affected by changes
in the weather. Weather conditions directly influence the demand
for electricity and natural gas, affect the wind-powered generation
at the independent power production business, affect the price of
energy commodities, affect the ability to perform services at the
utility services and construction materials and mining businesses
and affect ongoing operation and maintenance activities for the
pipeline and energy services and natural gas and oil production
businesses. In addition, severe weather can be destructive, causing
outages and/or property damage, which could require additional costs
to be incurred. As a result, adverse weather conditions could
negatively affect the Company's results of operations and financial
condition.
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 businesses. Many of these highlighted points are
forward-looking statements. There is no assurance that the
Company's projections, including estimates for growth and increases
in revenues and earnings, will in fact be achieved. Reference
should be made to assumptions contained in this section as well as
the various important factors listed under the heading Risk Factors
and Cautionary Statements that May Affect Future Results and the
other factors listed in the Introduction. 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 common share for 2003, diluted, before the
cumulative effect of the change in accounting for asset retirement
obligations as required by the adoption of SFAS No. 143, are
projected in the range of $1.46 to $1.63. Including the $7.6
million after-tax cumulative effect of the accounting change, 2003
earnings per common share, diluted, are projected to be in the range
of $1.40 to $1.57.
- - Earnings per common share for 2004, diluted, are projected in
the range of $1.50 to $1.63.
- - The Company will consider issuing equity from time to time to
keep debt at the nonregulated businesses at no more than 40 percent
of total capitalization.
- - Excluding unidentified future acquisitions, the Company
anticipates investing approximately $375 million in capital
expenditures during 2004.
- - The Company's long-term compound annual growth goals on
earnings per share from operations are in the range of 6 percent to
9 percent.
Electric
- - Montana-Dakota has obtained and holds valid and existing
franchises authorizing it to conduct its electric operations in all
of the municipalities it serves where such franchises are required.
As franchises expire, Montana-Dakota may face increasing competition
in its service areas, particularly its service to smaller towns,
from rural electric cooperatives. Montana-Dakota intends to protect
its service area and seek renewal of all expiring franchises and
will continue to take steps to effectively operate in an
increasingly competitive environment.
- - Montana-Dakota filed an application with the NDPSC seeking an
increase in electric retail rates of 9.1 percent above current
rates. While Montana-Dakota believes that it should be authorized
to increase retail rates in the amount requested, there is no
assurance that the increase ultimately allowed will be for the full
amount requested in the jurisdiction. For further information on
the electric rate increase application, see Note 17 of Notes to
Consolidated Financial Statements.
- - In August 2003, an electric rate case was filed with the
Montana Public Service Commission (MTPSC) requesting an increase of
$3.3 million annually, or 10.7 percent. This case was recently
withdrawn due to concerns expressed by the MTPSC and the Montana
Consumer Council related to the case test period. It is the
Company's intent to file a new case.
- - Regulatory approval has been received from the North Dakota
Public Service Commission and the South Dakota Public Utilities
Commission on the Company's plans to purchase energy from a 20-
megawatt wind energy farm in North Dakota. This wind energy farm is
expected to be on line early to mid 2004.
- - The Company expects to build or acquire an additional 80
megawatts of capacity in the 2007 through 2009 timeframe. The costs
of these projects are expected to be recovered in rates and will be
used to meet the utility's need for additional generating capacity.
- - The Company is working with the state of North Dakota to
determine the feasibility of constructing a 250-megawatt to 500-
megawatt lignite-fired power plant in western North Dakota. The
next preliminary decision on this matter is expected later this
year.
- - Montana-Dakota has joined with two electric generators in
appealing a finding by the North Dakota Department of Health
(Department) in September 2003 that the Department may unilaterally
revise operating permits previously issued to electric generating
plants. Although it is doubtful that any revision of Montana-
Dakota's operating permits by the Department would reduce the amount
of electricity its plants could generate, the finding, if allowed to
stand, could increase costs for sulfur dioxide removal and/or limit
Montana-Dakota's ability to modify or expand operations at its North
Dakota generation sites. Montana-Dakota and the other electric
generators filed their appeal of the order on October 8, 2003, in
the Burleigh County District Court in Bismarck, North Dakota.
In a related case, the Dakota Resource Council filed an action in
Federal District Court in Denver, Colorado on September 30, 2003,
to require the Environmental Protection Agency (EPA) to enforce
certain air quality standards in North Dakota. If successful, the
action could require the curtailment of discharges of sulfur
dioxide into the atmosphere by existing electric generating
facilities and could preclude or hinder the construction of future
generating facilities in North Dakota. The Company is currently
assessing the merits of this lawsuit and may file a motion to
intervene.
The Company cannot predict the outcome of these matters or their
ultimate impact on its operations.
Natural gas distribution
- - Montana-Dakota and Great Plains have obtained and hold valid
and existing franchises authorizing them to conduct their natural
gas operations in all of the municipalities they serve where such
franchises are required. As franchises expire, Montana-Dakota and
Great Plains may face increasing competition in their service areas.
Montana-Dakota and Great Plains intend to protect their service
areas and seek renewal of all expiring franchises and will continue
to take steps to effectively operate in an increasingly competitive
environment.
- - Annual natural gas throughput for 2003 and 2004 is expected to
be approximately 52 million decatherms per year.
- - Montana-Dakota filed an application with the SDPUC seeking an
increase in natural gas retail rates of $2.2 million annually or 5.8
percent above current rates. On October 27, 2003, Montana-Dakota
and the SDPUC staff filed a Settlement Stipulation with the SDPUC
agreeing to an increase of $1.3 million annually. Great Plains
filed an application with the MPUC seeking an increase in natural
gas retail rates of $1.6 million or 6.9 percent above current rates.
On October 9, 2003, the MPUC issued a Final Order authorizing an
increase of $1.1 million annually. For further information on the
natural gas rate increase applications, see Note 17 of Notes to
Consolidated Financial Statements.
Utility services
- - Revenues for this segment are expected to be in the range of
$425 million to $475 million in 2003 and $450 million to $500
million in 2004.
- - This segment anticipates margins in 2003 to decrease from 2002
levels; however, margins are anticipated to increase in 2004 as
compared to projected 2003 levels.
Pipeline and energy services
- - In 2003, natural gas throughput from this segment, including
both transportation and gathering, is expected to be comparable to
2002 record levels. In 2004, total throughput is expected to
increase approximately 25 percent over projected 2003 levels largely
due to the Grasslands Pipeline being in service. Transportation
rates are expected to decline due to the estimated effects of a FERC
rate order received in July 2003.
- - Pipeline construction began in mid-August on the 253-mile
Grasslands Pipeline project. The in-service date for this project
is expected to be in the late-November to December 1, 2003,
timeframe.
- - Innovatum could face a future goodwill impairment based on
certain economic conditions, as previously discussed in Risk Factors
and Cautionary Statements that May Affect Future Results. Innovatum
recently developed a hand-held locating device that can detect both
magnetic and plastic materials. One of the possible uses for this
product would be in the detection of unexploded ordnance (land
mines). Innovatum is in the preliminary stages of working with and
demonstrating the device to a Department of Defense contractor and
has met with individuals from the Department of Defense. This
potential new market may mitigate the possibility of a goodwill
impairment.
Natural gas and oil production
- - In 2003, this segment expects a combined natural gas and oil
production increase of approximately 10 percent to 12 percent over
record 2002 levels. In 2004, the Company expects a combined
production increase of approximately 10 percent over projected 2003
levels. Currently, this segment's gross daily operated natural gas
production is approximately 130,000 to 140,000 Mcf per day.
- - This segment continues to expand its operated production.
Natural gas production from operated properties was 73 percent and
67 percent of total production for the nine months ended September
30, 2003 and 2002, respectively.
- - This segment expects to drill more than 400 wells in 2003 and
approximately 400 wells in 2004.
- - This segment had approximately 185 wells in process related to
its coalbed natural gas development in the Powder River Basin in
Montana and Wyoming that were not producing natural gas or water at
September 30, 2003, but may begin producing either natural gas or
water in the future.
- - Estimates for average natural gas prices in the Rocky Mountain
region for November and December 2003, reflected in the Company's
2003 earnings guidance, are in the range of $3.50 to $4.00 per Mcf.
The Company's estimates for natural gas prices on the NYMEX for
November and December 2003, reflected in the Company's 2003 earnings
guidance, are in the range of $4.25 to $4.75 per Mcf. During 2002,
more than half of this segment's natural gas production was priced
using Rocky Mountain or other non-NYMEX prices.
- - For 2004, the Company's estimate for natural gas prices in the
Rocky Mountain region are in the range of $3.00 to $3.50 per Mcf,
and estimates for natural gas prices on the NYMEX are in the range
of $4.00 to $4.25 per Mcf.
- - Estimates of NYMEX crude oil prices for October through
December 2003, reflected in the Company's 2003 earnings guidance,
are in the range of $22 to $27 per barrel.
- - Estimates of NYMEX crude oil prices for 2004 are projected in
the range of $24 to $28 per barrel.
- - The Company has hedged a portion of its 2003 production
primarily using collars that establish both a floor and a cap. The
Company has entered into agreements representing approximately 45
percent to 50 percent of 2003 estimated annual natural gas
production. The agreements are at various indices and range from a
low CIG index of $2.94 to a high Ventura index of $4.76 per Mcf.
CIG is an index pricing point related to Colorado Interstate Gas
Co.'s system and Ventura is an index pricing point related to
Northern Natural Gas Co.'s system.
- - The Company has hedged a portion of its 2003 oil production.
The Company has entered into agreements at NYMEX prices with floors
of $24.50 and caps as high as $28.12, representing approximately 30
percent to 35 percent of 2003 estimated annual oil production.
- - The Company has hedged a portion of its 2004 estimated annual
natural gas production. The Company has entered into agreements
representing approximately 10 percent to 15 percent of 2004
estimated annual natural gas production. The agreements are at
various indices and range from a low CIG index of $3.75 to a high
NYMEX index of $5.20 per Mcf.
- - Fidelity has been named as a defendant in, and/or certain of
its operations are the subject of, several lawsuits filed in
connection with its coalbed natural gas development in the Powder
River Basin in Montana and Wyoming.
In one such case, the United States District Court in Billings,
Montana (U.S. District Court) held that water produced in
association with coalbed natural gas and discharged into rivers
and streams was not a pollutant under the Federal Clean Water Act
and that state statutes exempt such unaltered groundwater from
Montana Pollution Discharge Elimination System permit
requirements. On April 10, 2003, the United States Circuit Court
of Appeals for the Ninth Circuit (Circuit Court) reversed the U.S.
District Court's decision. Fidelity filed a petition for a writ
of certiorari with the United States Supreme Court (Supreme Court)
on August 8, 2003. The Supreme Court denied Fidelity's petition
for certiorari on October 20, 2003. The Supreme Court's decision
has the effect of remanding the case to the U.S. District Court
for trial on the remaining issues. Fidelity believes the ultimate
outcome of the proceeding will not have a material effect on its
existing coalbed natural gas operations or on the future
development of its coalbed natural gas properties. In the event a
penalty is ultimately imposed in that proceeding, Fidelity
believes it will be minimal because any unpermitted discharges
were of small amounts, were for a short duration and are now fully
permitted.
Fidelity believes the ultimate outcome of other lawsuits filed in
connection with its coalbed natural gas development could have a
material effect on its existing coalbed natural gas operations
and/or its future development of its coalbed natural gas
properties.
For further information on these proceedings, see Risk Factors and
Cautionary Statements that May Affect Future Results in this Form
10-Q.
Construction materials and mining
- - Excluding the effects of unidentified future acquisitions,
aggregate and ready-mixed concrete volumes in 2003 are expected to
increase over record levels achieved in 2002, while asphalt volumes
are expected to be comparable to 2002 levels. Ready-mixed concrete
and aggregate volumes in 2004 are expected to be comparable to
projected 2003 levels, while asphalt volumes are expected to
increase over those projected for 2003.
- - Revenues for this segment in 2003 are expected to increase by
approximately 10 percent to 15 percent as compared to 2002 record
levels. Revenues in 2004 are expected to increase by approximately
5 percent to 10 percent over projected 2003 levels.
- - Four of the five labor contracts that Knife River was
negotiating, as reported in Items 1 and 2 - Business and Properties
- General in the Company's 2002 Form 10-K, have been ratified and
the one remaining contract is being negotiated. The Company
considers its relations with its employees to be satisfactory.
Independent power production and other
- - Earnings projections in 2003 and 2004 for independent power
production and other operations include the estimated results from
the wind-powered electric generation facility in California, the
natural gas-fired generating facilities in Colorado, and the
Company's 49-percent ownership in a 220-megawatt natural gas-fired
generation project in Brazil. Earnings are expected to be in the
range of $9 million to $14 million in 2003 and $18 million to $23
million in 2004.
- - The Company is finalizing plans for the construction of a 113-
megawatt coal-fired development project in Hardin, Montana, as
previously discussed in Risk Factors and Cautionary Statements that
May Affect Future Results. Efforts will continue towards securing a
contract for the off-take of the plant. The Company is optimistic
that this plant will be under contract by the time of plant
completion. The projected plant on-line date for this project is
late 2005.
New Accounting Standards
In the third quarter of 2003, the Company adopted the fair
value recognition provisions of Statement of Financial Accounting
Standards (SFAS) No. 123 "Accounting for Stock-Based Compensation,"
and began expensing the fair market value of stock options for all
awards granted on or after January 1, 2003. Compensation expense
recognized for awards granted on or after January 1, 2003, for the
three months and nine months ended September 30, 2003, was $53,000
(after tax).
In June 2001, the FASB approved SFAS No. 141, "Business
Combinations," which requires the purchase method of accounting for
business combinations initiated after June 30, 2001 and eliminates
the pooling-of-interests method. In June 2001, the FASB also
approved SFAS No. 142, "Goodwill and Other Intangible Assets," which
discontinues the practice of amortizing goodwill and indefinite
lived intangible assets and initiates an annual review for
impairment. Intangible assets with a determinable useful life will
continue to be amortized over that period. The amortization
provisions apply to goodwill and intangible assets acquired after
June 30, 2001. SFAS No. 141 and SFAS No. 142 clarify that more
assets should be distinguished and classified between tangible and
intangible. The Company did not change or reclassify contractual
mineral rights included in property, plant and equipment related to
its natural gas and oil production business upon adoption of SFAS
No. 142. The Company has included such mineral rights as part of
property, plant and equipment under the full cost method of
accounting for natural gas and oil properties. An issue has arisen
within the natural gas and oil industry as to whether contractual
mineral rights under SFAS No. 142 should be classified as intangible
rather than as part of property, plant and equipment. This
accounting matter is anticipated to be addressed by the FASB's
Emerging Issues Task Force. The resolution of this matter may
result in certain reclassifications of amounts in the Company's
Consolidated Balance Sheets, as well as changes to the Company's
Notes to Consolidated Financial Statements in the future. The
applicable provisions of SFAS No. 141 and SFAS No. 142 only affect
the balance sheet and associated footnote disclosure, so any
reclassifications that might be required in the future will not
affect the Company's cash flows or results of operations. The
Company believes that the resolution of this matter will not have a
material effect on the Company's financial position because the
mineral rights acquired by its natural gas and oil production
business after the June 30, 2001, effective date of SFAS No. 142 are
not material.
In June 2001, the FASB approved SFAS No. 143, "Accounting for
Asset Retirement Obligations." Upon adoption of SFAS No. 143, the
Company recorded an additional discounted liability of $22.5 million
and a regulatory asset of $493,000, increased net property, plant
and equipment by $9.6 million and recognized a one-time cumulative
effect charge of $7.6 million (net of deferred tax benefit of $4.8
million).
In April 2002, the FASB approved SFAS No. 145, "Rescission of
FASB Statements No. 4, 44 and 64, Amendment of FASB Statement No.
13, and Technical Corrections." The adoption of SFAS No. 145 did
not have a material effect on the Company's financial position or
results of operations.
In November 2002, the FASB issued FASB Interpretation No. 45,
"Guarantor's Accounting and Disclosure Requirements for Guarantees,
Including indirect Guarantees of Indebtedness of Others" (FIN 45).
The Company is applying the initial recognition and initial
measurement provisions of FIN 45 to guarantees issued or modified
after December 31, 2002.
In January 2003, the FASB issued FASB Interpretation No. 46,
"Consolidation of Variable Interest Entities" (FIN 46). FIN 46 was
effective for the first fiscal year or interim period beginning
after June 15, 2003, for variable interest entities created before
February 1, 2003. However, in October 2003, the FASB issued FASB
Staff Position No. FIN 46-6 which defers the required effective date
until the end of the first interim or annual period ending after
December 15, 2003, for interests held in a variable interest entity
or potential variable interest entity that was created before
February 1, 2003, provided that financial statements have not been
issued reporting that variable interest entity in accordance with
FIN 46. The deferral of the effective date of FIN 46 did not have
an effect on the Company's financial position or results of
operations. The adoption of FIN 46 did not have a material effect
on the Company's financial position or results of operations.
In April 2003, the FASB issued SFAS No. 149, "Amendment of
Statement 133 on Derivative Instruments and Hedging Activities."
SFAS No. 149 is generally effective for contracts entered into or
modified after June 30, 2003, and for hedging relationships
designated after June 30, 2003. The adoption of SFAS No. 149 did
not have a material effect on the Company's financial position or
results of operations.
In May 2003, the FASB issued SFAS No. 150, "Accounting for
Certain Financial Instruments with Characteristics of Both
Liabilities and Equity." The Company will apply SFAS No. 150 to any
financial instruments entered into or modified after May 31, 2003.
Beginning with the third quarter of 2003, the Company reported its
preferred stock subject to mandatory redemption as a liability in
accordance with SFAS No. 150. The transition to SFAS No. 150 did
not have a material effect on the Company's financial position or
results of operations.
For further information on SFAS No. 123, SFAS No. 143, SFAS No.
145, FIN 45, FIN 46, SFAS No. 149 and SFAS No. 150, see Note 8 of
Notes to Consolidated Financial Statements.
Critical Accounting Policies
The Company's critical accounting policies include impairment
of long-lived assets and intangibles, impairment testing of natural
gas and oil properties, revenue recognition, derivatives, purchase
accounting, accounting for the effects of regulation and use of
estimates. There are no material changes in the Company's critical
accounting policies from those reported in the Company's Annual
Report on Form 10-K for the year ended December 31, 2002. For more
information on critical accounting policies, see Part II, Item 7 in
the Company's Annual Report on Form 10-K for the year ended December
31, 2002.
Liquidity and Capital Commitments
Cash flows
Operating activities --
Cash flows provided by operating activities in the first nine
months of 2003 increased $76.6 million from the comparable 2002
period, the result of an increase in cash from net income of $26.6
million and higher depreciation, depletion and amortization expense
of $24.2 million, resulting largely from increased property, plant
and equipment balances and higher mineral production volumes.
Higher deferred income taxes and investment tax credits of $11.7
million and the cumulative effect of an accounting change of $7.6
million also added to the increase in cash flows provided by
operating activities.
Investing activities --
Cash flows used in investing activities in the first nine
months of 2003 increased $103.5 million compared to the comparable
2002 period, the result of an increase in net capital expenditures
(capital expenditures; acquisitions, net of cash acquired; and net
proceeds from the sale or disposition of property) of $114.4
million, slightly offset by an increase in investments of $7.1
million and proceeds from notes receivable of $3.8 million. Net
capital expenditures exclude the noncash transactions related to
acquisitions, including the issuance of the Company's equity
securities. The noncash transactions were $40.1 million and $46.0
million for the first nine months of 2003 and 2002, respectively.
Financing activities --
Cash flows provided by financing activities in the first nine
months of 2003 increased $50.3 million compared to the comparable
2002 period, due to an increase in the issuance of long-term debt of
$175.0 million. The increase in the repayment of long-term debt of
$91.3 million and the net decrease of short-term borrowings of $30.0
million, partially offset the increase in cash provided by financing
activities.
Defined benefit pension plans
The Company has qualified noncontributory defined benefit
pension plans (Pension Plans) for certain employees. Plan assets
consist of investments in equity and fixed income securities.
Various actuarial assumptions are used in calculating the benefit
expense (income) and liability (asset) related to the Pension Plans.
Actuarial assumptions include assumptions about the discount rate,
expected return on plan assets and rate of future compensation
increases as determined by the Company within certain guidelines.
Pretax pension income reflected in the years ended December 31, 2002
and 2001 was $2.4 million and $4.4 million, respectively. The
Company's pension expense is expected to be less than $1.0 million
in 2003 and is currently projected to be approximately $4.0 million
to $5.0 million in 2004. Persistent declines in the equity markets
and a reduction in the Company's assumed discount rate for Pension
Plans have combined to largely produce the increase in these costs.
Funding for the Pension Plans is actuarially determined. The
minimum required contributions for 2002 and 2001 were approximately
$1.2 million and $440,000, respectively. The minimum required
contribution for 2003 is approximately $1.6 million and is currently
projected to be approximately $2.5 million to $3.0 million for 2004.
For further information on the Company's Pension Plans, see Part II,
Item 7 in the Company's Annual Report on Form 10-K for the year
ended December 31, 2002.
Capital expenditures
Net capital expenditures, including the issuance of the
Company's equity securities, for the first nine months of 2003 were
$376.3 million and are estimated to be approximately $510 million
for the year 2003. Estimated capital expenditures include those
for:
- Completed acquisitions
- System upgrades, including a 40-megawatt natural gas-fired
peaking unit
- Routine replacements
- Service extensions
- Routine equipment maintenance and replacements
- Land and building improvements
- Pipeline and gathering expansion projects, including a 253-mile
pipeline, as previously discussed
- The further enhancement of natural gas and oil production and
reserve growth
- Power generation opportunities, including certain construction
costs for a 113-megawatt coal-fired development project, as
previously discussed
- Other growth opportunities
Approximately 34 percent of estimated 2003 net capital
expenditures are for completed acquisitions. The Company continues
to evaluate potential future acquisitions and other growth
opportunities; however, they are dependent upon the availability of
economic opportunities and, as a result, actual acquisitions and
capital expenditures may vary significantly from the estimated 2003
capital expenditures referred to above. It is anticipated that the
funds required for capital expenditures will be met from various
sources. These sources include internally generated funds,
commercial paper credit facilities at Centennial and MDU Resources,
as described below, and through the issuance of long-term debt and
the Company's equity securities.
The estimated 2003 capital expenditures referred to above
include completed 2003 acquisitions involving construction materials
and mining businesses in Montana, North Dakota and Texas and a wind-
powered electric generation facility in California. Pro forma
financial amounts reflecting the effects of the above acquisitions
are not presented as such acquisitions were not material to the
Company's financial position or results of operations.
Capital resources
Certain debt instruments of the Company and its subsidiaries,
including those discussed below, contain restrictive covenants, all
of which the Company and its subsidiaries were in compliance with at
September 30, 2003.
MDU Resources Group, Inc.
The Company has a revolving credit agreement with various banks
totaling $90 million at September 30, 2003. There were no amounts
outstanding under the credit agreement at September 30, 2003. The
credit agreement supports the Company's $75 million commercial paper
program. Under the Company's commercial paper program, $50.0
million was outstanding at September 30, 2003. The commercial paper
borrowings are classified as long-term debt as the Company intends
to refinance these borrowings on a long-term basis through continued
commercial paper borrowings and as further supported by the credit
agreement, which expires on July 18, 2006.
The Company's goal is to maintain acceptable credit ratings in
order to access the capital markets through the issuance of
commercial paper. If the Company were to experience a minor
downgrade of its credit ratings, it would not anticipate any change
in its ability to access the capital markets. However, in such
event, the Company would expect a nominal basis point increase in
overall interest rates with respect to its cost of borrowings. If
the Company were to experience a significant downgrade of its credit
ratings, which it does not currently anticipate, it may need to
borrow under its credit agreement.
To the extent the Company needs to borrow under its credit
agreement, it would be expected to incur increased annualized
interest expense on its variable rate debt of approximately $75,000
(after tax) based on September 30, 2003, variable rate borrowings.
Based on the Company's overall interest rate exposure at September
30, 2003, this change would not have a material effect on the
Company's results of operations or cash flows.
Prior to the maturity of the credit agreement, the Company
plans to negotiate the extension or replacement of this agreement
that provides credit support to access the capital markets. In the
event the Company was unable to successfully negotiate the credit
agreement, or in the event the fees on this facility became too
expensive, which it does not currently anticipate, the Company would
seek alternative funding. One source of alternative funding might
involve the securitization of certain Company assets.
In order to borrow under the Company's credit agreement, the
Company must be in compliance with the applicable covenants and
certain other conditions. The significant covenants include maximum
leverage ratios, minimum interest coverage ratio, limitation on sale
of assets and limitation on investments. The Company was in
compliance with these covenants and met the required conditions at
September 30, 2003. In the event the Company does not comply with
the applicable covenants and other conditions, alternative sources
of funding may need to be pursued, as previously described.
Currently, there are no credit facilities that contain cross-
default provisions between the Company and any of its subsidiaries.
The Company's issuance of first mortgage debt is subject to
certain restrictions imposed under the terms and conditions of its
Indenture of Mortgage. Generally, those restrictions require the
Company to pledge $1.43 of unfunded property to the trustee for each
dollar of indebtedness incurred under the Indenture and that annual
earnings (pretax and before interest charges), as defined in the
Indenture, equal at least two times its annualized first mortgage
bond interest costs. Under the more restrictive of the two tests,
as of September 30, 2003, the Company could have issued
approximately $338 million of additional first mortgage bonds.
The Company's coverage of fixed charges including preferred
dividends was 4.9 times and 4.8 times for the twelve months ended
September 30, 2003 and December 31, 2002, respectively.
Additionally, the Company's first mortgage bond interest coverage
was 8.6 times and 7.7 times for the twelve months ended September
30, 2003 and December 31, 2002, respectively. Common stockholders'
equity as a percent of total capitalization was 58 percent and 60
percent at September 30, 2003 and December 31, 2002, respectively.
Centennial Energy Holdings, Inc.
Centennial has two revolving credit agreements with various
banks that support $275 million of Centennial's $350 million
commercial paper program. There were no outstanding borrowings
under the Centennial credit agreements at September 30, 2003. Under
the Centennial commercial paper program, $76.6 million was
outstanding at September 30, 2003. The Centennial commercial paper
borrowings are classified as long-term debt as Centennial intends to
refinance these borrowings on a long-term basis through continued
Centennial commercial paper borrowings and as further supported by
the Centennial credit agreements. The Centennial credit agreements
are for $137.5 million each. One of these agreements expires on
September 3, 2004, and allows for subsequent borrowings up to a term
of one year. The other agreement expires on September 5, 2006.
Centennial intends to negotiate the extension or replacement of
these agreements prior to their maturities.
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, $384.6 million was outstanding at
September 30, 2003. To meet potential future financing needs,
Centennial may pursue other financing arrangements, including
private and/or public financing.
Centennial's goal is to maintain acceptable credit ratings in
order to access the capital markets through the issuance of
commercial paper. If Centennial were to experience a minor
downgrade of its credit ratings, it would not anticipate any change
in its ability to access the capital markets. However, in such
event, Centennial would expect a nominal basis point increase in
overall interest rates with respect to its cost of borrowings. If
Centennial were to experience a significant downgrade of its credit
ratings, which it does not currently anticipate, it may need to
borrow under its committed bank lines.
To the extent Centennial needs to borrow under its committed
bank lines, it would be expected to incur increased annualized
interest expense on its variable rate debt of approximately $115,000
(after tax) based on September 30, 2003, variable rate borrowings.
Based on Centennial's overall interest rate exposure at September
30, 2003, this change would not have a material effect on the
Company's results of operations or cash flows.
Prior to the maturity of the Centennial credit agreements,
Centennial plans to negotiate the extension or replacement of these
agreements that provide credit support to access the capital
markets. In the event Centennial was unable to successfully
negotiate these agreements, or in the event the fees on such
facilities became too expensive, which Centennial does not currently
anticipate, it would seek alternative funding. One source of
alternative funding might involve the securitization of certain
Centennial assets.
In order to borrow under Centennial's credit agreements and the
Centennial uncommitted long-term master shelf agreement, Centennial
and certain of its subsidiaries must be in compliance with the
applicable covenants and certain other conditions. The significant
covenants include maximum capitalization ratios, minimum interest
coverage ratios, minimum consolidated net worth, limitation on
priority debt, limitation on sale of assets and limitation on loans
and investments. Centennial and such subsidiaries were in
compliance with these covenants and met the required conditions at
September 30, 2003. In the event Centennial or such subsidiaries do
not comply with the applicable covenants and other conditions,
alternative sources of funding may need to be pursued as previously
described.
Certain of Centennial's financing agreements contain cross-
default provisions. These provisions state that if Centennial or
any subsidiary of Centennial fails to make any payment with respect
to any indebtedness or contingent obligation, in excess of a
specified amount, under any agreement that causes such indebtedness
to be due prior to its stated maturity or the contingent obligation
to become payable, the applicable agreements will be in default.
Certain of Centennial's financing agreements and Centennial's
practice limit the amount of subsidiary indebtedness.
Williston Basin Interstate Pipeline Company
Williston Basin has an uncommitted long-term master shelf
agreement that allows for borrowings of up to $100 million. Under
the terms of the master shelf agreement, $55.0 million was
outstanding at September 30, 2003.
In order to borrow under Williston Basin's uncommitted long-
term master shelf agreement, it must be in compliance with the
applicable covenants and certain other conditions. The significant
covenants include limitation on consolidated indebtedness,
limitation on priority debt, limitation on sale of assets and
limitation on investments. Williston Basin was in compliance with
these covenants and met the required conditions at September 30,
2003. In the event Williston Basin does not comply with the
applicable covenants and other conditions, alternative sources of
funding may need to be pursued.
Contractual obligations and commercial commitments
There are no material changes in the Company's contractual
obligations on operating leases and purchase commitments from those
reported in the Company's Annual Report on Form 10-K for the year
ended December 31, 2002.
The Company's contractual obligations on long-term debt at
September 30, 2003, increased $155.1 million or 18 percent from
December 31, 2002, primarily due to acquisitions and other corporate
purposes. At September 30, 2003, the Company's commitments under
these obligations for the twelve months ended September 30, were as
follows:
2004 2005 2006 2007 2008 Thereafter Total
(In millions)
Long-term debt $7.9 $91.7 $212.1 $120.7 $130.2 $434.1 $996.7
For more information on contractual obligations and commercial
commitments, see Part II, Item 7 in the Company's Annual Report on
Form 10-K for the year ended December 31, 2002.
Centennial has financial guarantees outstanding at September
30, 2003. These guarantees pertain to Centennial's guarantee of
certain obligations in connection with the natural gas-fired
electric generation station in Brazil and as of September 30, 2003,
are approximately $64.5 million. As of September 30, 2003, with
respect to these guarantees, there was approximately $47,000
outstanding through 2003, $19.1 million outstanding through 2006 and
$45.3 million outstanding through 2008. These guarantees are not
reflected on the Consolidated Balance Sheets. For more information
on these guarantees, see Note 18 of Notes to Consolidated Financial
Statements.
As of September 30, 2003, Centennial was contingently liable
for performance of certain of its subsidiaries under approximately
$325 million of surety bonds. These bonds are principally for
construction contracts and reclamation obligations of these
subsidiaries, entered into in the normal course of business.
Centennial indemnifies the respective surety bond companies against
any exposure under the bonds. A large portion of these contingent
commitments are expected to expire within the next twelve months;
however, Centennial will likely continue to enter into surety bonds
for its subsidiaries in the future. The surety bonds were not
reflected on the Consolidated Balance Sheets.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The Company is exposed to the impact of market fluctuations
associated with commodity prices, interest rates and foreign
currency. The Company has policies and procedures to assist in
controlling these market risks and utilizes derivatives to manage a
portion of its risk.
Commodity price risk --
A subsidiary of the Company utilizes natural gas and oil price
swap and collar agreements to manage a portion of the market risk
associated with fluctuations in the price of natural gas and oil on
the subsidiary's forecasted sales of natural gas and oil production.
For more information on commodity price risk, see Part II, Item 7A
in the Company's Annual Report on Form 10-K for the year ended
December 31, 2002, and Note 12 of Notes to Consolidated Financial
Statements in this Form 10-Q.
The following table summarizes hedge agreements entered into by
a subsidiary of the Company, as of September 30, 2003. These
agreements call for the subsidiary to receive fixed prices and pay
variable prices.
(Notional amount and fair value in thousands)
Weighted
Average Notional
Fixed Price Amount
(Per MMBtu) (In MMBtu's) Fair Value
Natural gas swap
agreements maturing
in 2003 $ 4.14 559 $ (209)
Natural gas swap
agreements maturing
in 2004 $ 4.96 3,660 $ 762
Weighted
Average
Floor/Ceiling Notional
Price Amount
(Per MMBtu) (In MMBtu's) Fair Value
Natural gas collar
agreements maturing
in 2003 $3.33/$3.89 5,637 $ (4,075)
Natural gas collar
agreements maturing
in 2004 $4.04/$4.48 3,111 $ (597)
Weighted
Average
Floor/Ceiling Notional
Price Amount
(Per barrel) (In barrels) Fair Value
Oil collar agreements
maturing in 2003 $24.50/$27.62 161 $ (277)
Interest rate risk --
There are no material changes to interest rate risk faced by
the Company from those reported in the Company's Annual Report on
Form 10-K for the year ended December 31, 2002. For more
information on interest rate risk, see Part II, Item 7A in the
Company's Annual Report on Form 10-K for the year ended December 31,
2002.
Foreign currency risk --
MDU Brasil has a 49 percent equity investment in a 220-megawatt
natural gas-fired electric generation project (Project) in Brazil,
which has a portion of its borrowings and payables denominated in
U.S. dollars. MDU Brasil has exposure to currency exchange risk as
a result of fluctuations in currency exchange rates between the U.S.
dollar and the Brazilian real. The functional currency for the
Project is the Brazilian real. For further information on this
investment, see Note 10 of Notes to Consolidated Financial
Statements.
MDU Brasil's equity income from this Brazilian investment is
impacted by fluctuations in currency exchange rates on transactions
denominated in a currency other than the Brazilian real, including
the effects of changes in currency exchange rates with respect to
the Project's U.S. dollar denominated obligations, excluding a U.S.
dollar denominated loan from Centennial Energy Resources
International Inc. (Centennial International), an indirect wholly
owned subsidiary of the Company, as discussed below. At September
30, 2003, these U.S. dollar denominated obligations approximated
$71.8 million. If, for example, the value of the Brazilian real
decreased in relation to the U.S. dollar by 10 percent, MDU Brasil,
with respect to its interest in the Project, would record a foreign
currency transaction loss in net income of approximately $3.2
million (after tax) based on the above U.S. dollar denominated
obligations at September 30, 2003. The Project also had US$7.4
million of Brazilian real denominated obligations at September 30,
2003.
Adjustments attributable to the translation from the Brazilian
real to the U.S. dollar for assets, liabilities, revenues and
expenses were recorded in accumulated other comprehensive income
(loss) at September 30, 2003. Foreign currency translation
adjustments on the Project's U.S. dollar denominated borrowings
payable to the subsidiary of $20.0 million at September 30, 2003,
are recorded in accumulated other comprehensive income (loss).
The investment of Centennial International in this Project at
September 30, 2003, was $20.6 million. Centennial has guaranteed
Project obligations and loans of approximately $64.5 million as of
September 30, 2003.
A portion of the Project's foreign currency exchange risk is
being managed through contractual provisions, which are largely
indexed to the U.S. dollar, contained in the Project's power
purchase agreement with Petrobras. In addition, the Project is
utilizing foreign currency derivatives. At September 30, 2003, the
Project had foreign currency forward contracts with a notional
amount of approximately $2.3 million at a weighted average rate of
R$3.115, which expired on October 15, 2003, and approximately $4.5
million at a weighted average rate of R$3.125, which expire on
November 17, 2003. The Company's 49 percent share of the fair value
of these forward contracts at September 30, 2003, was approximately
$162,000.
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-15(e) and 15d-15(e) 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 the period covered by this report, and, they have concluded that,
as of this period, such controls and procedures were effective to
accomplish those tasks.
Changes in internal controls
The Company maintains a system of internal accounting controls
that are designed to provide reasonable assurance that the Company's
transactions are properly authorized, the Company's assets are
safeguarded against unauthorized or improper use, and the Company's
transactions are properly recorded and reported to permit
preparation of the Company's financial statements in conformity with
generally accepted accounting principles in the United States of
America. There were no changes in the Company's internal control
over financial reporting that occurred during the period covered by
this report that have materially affected, or are reasonable likely
to materially affect, the Company's internal control over financial
reporting.
PART II -- OTHER INFORMATION
ITEM 2. CHANGES IN SECURITIES AND USE OF PROCEEDS
Between July 1, 2003 and September 30, 2003, and prior to the
common stock split, the Company issued 1,234,357 shares of Common
Stock, $1.00 par value, and the Preference Share Purchase Rights
appurtenant thereto, as part of the consideration paid by the
Company for all of the issued and outstanding capital stock with
respect to a business acquired during this period and as a final
adjustment with respect to an acquisition in a prior period. The
Common Stock and Rights issued by the Company in these transactions
were issued in a private transaction exempt from registration under
the Securities Act of 1933 pursuant to Section 4(2) thereof, Rule
506 promulgated thereunder, or both. The classes of persons to whom
these securities were sold were either accredited investors or other
persons to whom such securities were permitted to be offered under
the applicable exemption.
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
a) Exhibits
12 Computation of Ratio of Earnings to Fixed Charges and
Combined Fixed Charges and Preferred Stock Dividends
31(a) Certification of Chief Executive Officer filed pursuant
to Section 302 of the Sarbanes - Oxley Act of 2002
31(b) Certification of Chief Financial Officer filed pursuant
to Section 302 of the Sarbanes - Oxley Act of 2002
32 Certification of Chief Executive Officer and Chief
Financial Officer furnished pursuant to 18 U.S.C. Section
1350, as adopted pursuant to Section 906 of the
Sarbanes - Oxley Act of 2002
b) Reports on Form 8-K
Form 8-K was filed on September 10, 2003. Under Item 5 -- Other
Events and Regulation FD Disclosure and Item 7 -- Financial
Statements and Exhibits, the Company reported the press release
issued September 9, 2003, regarding earnings guidance for 2003
and 2004.
Form 8-K was filed on July 24, 2003. Under Item 7 -- Financial
Statements, Pro Forma Financial Information and Exhibits and Item
9 -- Regulation FD Disclosure, the Company reported the press
release issued July 24, 2003, regarding earnings for the quarter
ended June 30, 2003.
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of
1934, the registrant has duly caused this report to be signed on its
behalf by the undersigned thereunto duly authorized.
MDU RESOURCES GROUP, INC.
DATE: November 13, 2003 BY: /s/ Warren L. Robinson
Warren L. Robinson
Executive Vice President,
Treasurer and Chief
Financial Officer
BY: /s/ Vernon A. Raile
Vernon A. Raile
Senior Vice President and
Chief Accounting Officer
EXHIBIT INDEX
Exhibit No.
12 Computation of Ratio of Earnings to Fixed Charges
and Combined Fixed Charges and Preferred Stock
Dividends
31(a) Certification of Chief Executive Officer filed pursuant to
Section 302 of the Sarbanes - Oxley Act of 2002
31(b) Certification of Chief Financial Officer filed pursuant to
Section 302 of the Sarbanes - Oxley Act of 2002
32 Certification of Chief Executive Officer and Chief Financial
Officer furnished pursuant to 18 U.S.C. Section 1350, as
adopted pursuant to Section 906 of the Sarbanes - Oxley Act
of 2002