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 JUNE 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 August 6, 2003: 75,476,937
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 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
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 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.
INDEX
Part I -- Financial Information
Consolidated Statements of Income --
Three and Six Months Ended June 30, 2003 and 2002
Consolidated Balance Sheets --
June 30, 2003 and 2002, and December 31, 2002
Consolidated Statements of Cash Flows --
Six Months Ended June 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 Six Months
Ended Ended
June 30, June 30,
2003 2002 2003 2002
(In thousands, except per share amounts)
Operating revenues:
Electric, natural gas distribution and
pipeline and energy services $128,175 $106,522 $324,045 $238,104
Utility services, natural gas and oil
production, construction materials
and mining and other 420,044 373,696 691,928 624,049
548,219 480,218 1,015,973 862,153
Operating expenses:
Fuel and purchased power 13,262 13,124 28,669 27,068
Purchased natural gas sold 27,625 19,781 103,731 55,476
Operation and maintenance:
Electric, natural gas distribution and
pipeline and energy services 34,313 31,516 71,478 65,360
Utility services, natural gas and oil
production, construction materials
and mining and other 332,003 310,860 554,383 512,530
Depreciation, depletion and amortization 46,911 37,845 90,976 73,948
Taxes, other than income 19,420 15,897 39,103 30,779
473,534 429,023 888,340 765,161
Operating income 74,685 51,195 127,633 96,992
Other income -- net 4,949 1,230 8,632 4,819
Interest expense 12,820 10,977 25,679 21,522
Income before income taxes 66,814 41,448 110,586 80,289
Income taxes 23,341 16,595 39,416 31,714
Income before cumulative effect of
accounting change 43,473 24,853 71,170 48,575
Cumulative effect of accounting
change (Note 8) --- --- (7,589) ---
Net income 43,473 24,853 63,581 48,575
Dividends on preferred stocks 188 189 375 378
Earnings on common stock $ 43,285 $ 24,664 $ 63,206 $ 48,197
Earnings per common share -- basic:
Earnings before cumulative effect of
accounting change $ .59 $ .35 $ .96 $ .69
Cumulative effect of accounting change --- --- (.10) ---
Earnings per common share -- basic $ .59 $ .35 $ .86 $ .69
Earnings per common share -- diluted:
Earnings before cumulative effect of
accounting change $ .58 $ .35 $ .95 $ .68
Cumulative effect of accounting change --- --- (.10) ---
Earnings per common share -- diluted $ .58 $ .35 $ .85 $ .68
Dividends per common share $ .24 $ .23 $ .48 $ .46
Weighted average common shares
outstanding -- basic 73,734 70,456 73,641 69,965
Weighted average common shares
outstanding -- diluted 74,355 71,027 74,189 70,502
Pro forma amounts assuming retroactive
application of accounting change:
Net income $ 43,473 $ 24,255 $ 71,170 $ 47,381
Earnings per common share -- basic $ .59 $ .34 $ .96 $ .67
Earnings per common share -- diluted $ .58 $ .34 $ .95 $ .67
The accompanying notes are an integral part of these consolidated statements.
MDU RESOURCES GROUP, INC.
CONSOLIDATED BALANCE SHEETS
(Unaudited)
June 30, June 30, December 31,
2003 2002 2002
(In thousands, except shares
and per share amounts)
ASSETS
Current assets:
Cash and cash equivalents $ 66,342 $ 48,350 $ 67,556
Receivables, net 348,209 312,115 325,395
Inventories 97,490 83,565 93,123
Deferred income taxes 7,585 16,534 8,877
Prepayments and other current assets 54,929 71,728 42,597
574,555 532,292 537,548
Investments 42,112 36,910 42,864
Property, plant and equipment 3,198,873 2,748,707 2,961,808
Less accumulated depreciation,
depletion and amortization 1,165,575 1,003,978 1,079,110
2,033,298 1,744,729 1,882,698
Deferred charges and other assets:
Goodwill 196,394 182,021 190,999
Other intangible assets, net 187,949 172,973 176,164
Other 103,352 105,854 106,976
487,695 460,848 474,139
$3,137,660 $2,774,779 $2,937,249
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Short-term borrowings $ 5,500 $ 4,500 $ 20,000
Long-term debt and preferred
stock due within one year 17,938 15,442 22,183
Accounts payable 163,033 124,560 132,120
Taxes payable 12,999 11,747 13,108
Dividends payable 18,005 16,617 17,959
Other accrued liabilities 104,667 91,395 94,275
322,142 264,261 299,645
Long-term debt 938,609 834,900 819,558
Deferred credits and other liabilities:
Deferred income taxes 379,608 355,720 374,097
Other liabilities 168,466 139,125 144,004
548,074 494,845 518,101
Preferred stock subject to mandatory
redemption 1,200 1,300 1,200
Commitments and contingencies
Stockholders' equity:
Preferred stocks 15,000 15,000 15,000
Common stockholders' equity:
Common stock (Shares issued --
$1.00 par value, 74,479,251
at June 30, 2003, 71,664,751 at
June 30, 2002 and 74,282,038 at
December 31, 2002) 74,479 71,665 74,282
Other paid-in capital 755,017 688,812 748,095
Retained earnings 502,403 410,224 474,798
Accumulated other comprehensive
loss (15,638) (2,602) (9,804)
Treasury stock at cost - 239,521
shares (3,626) (3,626) (3,626)
Total common stockholders' equity 1,312,635 1,164,473 1,283,745
Total stockholders' equity 1,327,635 1,179,473 1,298,745
$3,137,660 $2,774,779 $2,937,249
The accompanying notes are an integral part of these consolidated statements.
MDU RESOURCES GROUP, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Six Months Ended
June 30,
2003 2002
(In thousands)
Operating activities:
Net income $ 63,581 $ 48,575
Cumulative effect of accounting change 7,589 ---
Adjustments to reconcile net income to net cash provided
by operating activities:
Depreciation, depletion and amortization 90,976 73,948
Deferred income taxes and investment tax credit 11,547 4,870
Changes in current assets and liabilities, net of
acquisitions:
Receivables (20,044) (17,220)
Inventories (1,399) 14,325
Other current assets (17,284) (31,198)
Accounts payable 24,399 9,898
Other current liabilities 3,024 (4,804)
Other noncurrent changes 3,247 552
Net cash provided by operating activities 165,636 98,946
Investing activities:
Capital expenditures (130,780) (114,020)
Acquisitions, net of cash acquired (115,246) (14,963)
Net proceeds from sale or disposition of property 6,984 4,402
Investments 752 1,288
Proceeds from notes receivable 7,812 4,000
Net cash used in investing activities (230,478) (119,293)
Financing activities:
Net change in short-term borrowings (14,500) 4,500
Issuance of long-term debt 214,084 78,237
Repayment of long-term debt (100,168) (23,037)
Proceeds from issuance of common stock, net 188 178
Dividends paid (35,976) (32,992)
Net cash provided by financing activities 63,628 26,886
Increase (decrease) in cash and cash equivalents (1,214) 6,539
Cash and cash equivalents -- beginning of year 67,556 41,811
Cash and cash equivalents -- end of period $ 66,342 $ 48,350
The accompanying notes are an integral part of these consolidated statements.
MDU RESOURCES GROUP, INC.
NOTES TO CONSOLIDATED
FINANCIAL STATEMENTS
June 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 which are, in the
opinion of management, necessary for a fair presentation of the
accompanying consolidated interim financial statements.
2. Seasonality of operations
Some of the Company's operations are highly seasonal and
revenues from, and certain expenses for, such operations may
fluctuate significantly among quarterly periods. Accordingly,
the interim results for particular segments, and for the
Company as a whole, may not be indicative of results for the
full fiscal year.
3. Allowance for doubtful accounts
The Company's allowance for doubtful accounts as of
June 30, 2003 and 2002, and December 31, 2002, was $8.3
million, $8.4 million and $8.2 million, respectively.
4. Earnings per common share
Basic earnings per common share were computed by dividing
earnings on common stock by the weighted average number of
shares of common stock outstanding during the year. Diluted
earnings per common share were computed by dividing earnings on
common stock by the total of the weighted average number of
shares of common stock outstanding during the year, plus the
effect of outstanding stock options, restricted stock grants
and performance share awards. For the three months and six
months ended June 30, 2003, 139,870 shares and 2,333,480
shares, respectively, with an average exercise price of $36.85
and $30.16, respectively, 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 six months ended June 30, 2002, 150,630 shares and
2,567,050 shares, respectively, with an average exercise price
of $36.86 and $30.15, respectively, attributable to outstanding
stock options were excluded from the calculation of diluted
earnings per share because their effect was antidilutive.
Common stock outstanding includes issued shares less shares
held in treasury.
5. Stock-based compensation
The Company has stock option plans for directors, key
employees and employees and accounts for these option plans in
accordance with APB Opinion No. 25 under which no compensation
cost has been recognized.
The following table illustrates the effect on earnings and
earnings per common share as if the Company had applied
Statement of Financial Accounting Standards (SFAS) No. 123,
"Accounting for Stock-Based Compensation" to its stock-based
compensation:
Three Months Ended
June 30,
2003 2002
(In thousands, except
per share amounts)
Earnings on common stock, as reported $ 43,285 $ 24,664
Total stock-based compensation
expense determined under fair value
method for all awards, net of related
tax effects (717) (912)
Pro forma earnings on common stock $ 42,568 $ 23,752
Earnings per common share -- basic --
as reported:
Earnings before cumulative effect of
accounting change $ .59 $ .35
Cumulative effect of accounting change --- ---
Earnings per common share -- basic $ .59 $ .35
Earnings per common share -- basic --
pro forma:
Earnings before cumulative effect of
accounting change $ .58 $ .34
Cumulative effect of accounting change --- ---
Earnings per common share -- basic $ .58 $ .34
Earnings per common share -- diluted --
as reported:
Earnings before cumulative effect of
accounting change $ .58 $ .35
Cumulative effect of accounting change --- ---
Earnings per common share -- diluted $ .58 $ .35
Earnings per common share -- diluted --
pro forma:
Earnings before cumulative effect of
accounting change $ .57 $ .33
Cumulative effect of accounting change --- ---
Earnings per common share -- diluted $ .57 $ .33
Six Months Ended
June 30,
2003 2002
(In thousands, except
per share amounts)
Earnings on common stock, as reported $ 63,206 $ 48,197
Total stock-based compensation
expense determined under fair value
method for all awards, net of related
tax effects (1,307) (1,600)
Pro forma earnings on common stock $ 61,899 $ 46,597
Earnings per common share -- basic --
as reported:
Earnings before cumulative effect of
accounting change $ .96 $ .69
Cumulative effect of accounting change (.10) ---
Earnings per common share -- basic $ .86 $ .69
Earnings per common share -- basic --
pro forma:
Earnings before cumulative effect of
accounting change $ .94 $ .67
Cumulative effect of accounting change (.10) ---
Earnings per common share -- basic $ .84 $ .67
Earnings per common share -- diluted --
as reported:
Earnings before cumulative effect of
accounting change $ .95 $ .68
Cumulative effect of accounting change (.10) ---
Earnings per common share -- diluted $ .85 $ .68
Earnings per common share -- diluted --
pro forma:
Earnings before cumulative effect of
accounting change $ .94 $ .66
Cumulative effect of accounting change (.10) ---
Earnings per common share -- diluted $ .84 $ .66
6. Cash flow information
Cash expenditures for interest and income taxes were as
follows:
Six Months Ended
June 30,
2003 2002
(In thousands)
Interest, net of amount capitalized $ 23,316 $ 19,236
Income taxes $ 31,263 $ 40,589
7. Reclassifications
Certain reclassifications have been made in the financial
statements for the prior period to conform to the current
presentation. Such reclassifications had no effect on net
income or stockholders' equity as previously reported.
8. New accounting standards
In June 2001, the FASB approved SFAS No. 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. The SEC has recently
questioned under SFAS No. 142 whether contractual mineral
rights should be classified as intangible rather than as part
of property, plant and equipment and has referred this
accounting matter to the Emerging Issues Task Force and is
continuing its dialog with the FASB Staff. The resolution of
this matter may result in certain reclassifications to 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 impact balance sheet and associated footnote
disclosure, so any reclassifications that might be required
in the future will not impact 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 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 shall not be revised or restated. The disclosure
requirements in FIN 45 are effective for financial statements
of interim or annual periods ended after December 15, 2002.
The Company will apply the initial recognition and initial
measurement provisions of FIN 45 to guarantees issued or
modified after December 31, 2002. For more information on the
Company's guarantees and the disclosure requirements of FIN 45,
as applicable to the Company, see Note 18.
In January 2003, the FASB issued FASB Interpretation
No. 46, "Consolidation of Variable Interest Entities" (FIN 46).
FIN 46 clarifies the application of Accounting Research
Bulletin No. 51, "Consolidated Financial Statements" to certain
entities in which equity investors do not have the
characteristics of a controlling financial interest or do not
have sufficient equity at risk for the entity to finance its
activities without additional subordinated support from other
parties. FIN 46 requires existing unconsolidated variable
interest entities to be consolidated by their primary
beneficiaries if the entities do not effectively disperse risks
among parties involved. All companies with variable interests
in variable interest entities created after January 31, 2003,
shall apply the provisions of FIN 46 to those entities
immediately. FIN 46 is effective for the first fiscal year or
interim period beginning after June 15, 2003, for variable
interest entities created before February 1, 2003. The Company
will prospectively apply the provisions of FIN 46 that were
effective January 31, 2003.
The Company 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 Company does
not expect SFAS No. 149 to have a material effect on its
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. The Company is
currently evaluating the effect of SFAS No. 150 for financial
instruments entered into on or before May 31, 2003, on its
financial position and 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 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 loss, and their related tax effects, were
as follows:
Three Months Ended
June 30,
2003 2002
(In thousands)
Net income $ 43,473 $ 24,853
Other comprehensive 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 $2,241 and
$1,110 in 2003 and 2002, respectively (3,587) 1,700
Less: Reclassification adjustment for
gain (loss) on derivative instruments
included in net income, net of
tax of $1,871 and $58 in
2003 and 2002, respectively (2,926) 90
Net unrealized gain (loss) on derivative
instruments qualifying as hedges (661) 1,610
Minimum pension liability adjustment,
net of tax of $2,781 in 2002 --- (4,340)
Foreign currency translation adjustment (475) ---
(1,136) (2,730)
Comprehensive income $ 42,337 $ 22,123
Six Months Ended
June 30,
2003 2002
(In thousands)
Net income $ 63,581 $ 48,575
Other comprehensive loss --
Net unrealized loss on derivative
instruments qualifying as hedges:
Net unrealized gain (loss) on derivative
instruments arising during the
period, net of tax of $4,635 and
$574 in 2003 and 2002, respectively (7,331) 880
Less: Reclassification adjustment for
gain (loss) on derivative instruments
included in net income, net of
tax of $1,440 and $888 in
2003 and 2002, respectively (2,252) 1,360
Net unrealized loss on derivative
instruments qualifying as hedges (5,079) (480)
Minimum pension liability adjustment,
net of tax of $2,781 in 2002 --- (4,340)
Foreign currency translation adjustment (755) ---
(5,834) (4,820)
Comprehensive income $ 57,747 $ 43,755
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 a
variable interest entity, as discussed in Note 8. However, MDU
Brasil does not have a controlling financial interest in MPX
and is not required to consolidate MPX in its financial
statements. Therefore, MPX is being accounted for under the
equity method of accounting. 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
June 30, 2003, of approximately $95 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 and is renewable for an additional 13 years. The
functional currency for the Project is the Brazilian real. The
power purchase agreement with Petrobras contains an embedded
derivative, which derives its value from an annual adjustment
factor, which largely indexes the contract capacity payments to
the U.S. dollar. For the three and six months ended June 30,
2003, the Company's 49 percent share of the loss from the
embedded derivative in the power purchase agreement was $4.5
million (after tax) and $6.0 million (after tax), respectively.
In addition, the Company's 49 percent share of the foreign
currency gains resulting from revaluation of the Brazilian real
totaled $2.2 million (after tax) and $3.1 million (after tax)
for the three months and six months ended June 30, 2003,
respectively.
The Company's investment in the Project has been
accounted for under the equity method of accounting, and the
Company's share of net income, including the previously
mentioned foreign currency gain and loss from the embedded
derivative in the power purchase agreement, for the three
months and six months ended June 30, 2003, of $1.3 million and
$1.8 million, respectively, was included in other income - net.
At June 30, 2003 and 2002, and December 31, 2002, the Company's
investment in the Project was approximately $20.6 million,
$23.8 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
Six Months January 1, During June 30,
Ended June 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 5,268 117,155
Independent power
production and other 7,131 --- 7,131
Total $ 190,999 $ 5,395 $ 196,394
Net
Goodwill
Acquired
Balance and Other Balance
as of Changes as of
Six Months January 1, During June 30,
Ended June 30, 2002 2002 the Year* 2002
(In thousands)
Electric $ --- $ --- $ ---
Natural gas
distribution --- --- ---
Utility services 61,909 (738) 61,171
Pipeline and energy
services 9,336 158 9,494
Natural gas and oil
production --- --- ---
Construction materials
and mining 102,752 8,604 111,356
Independent power
production and other --- --- ---
Total $ 173,997 $ 8,024 $ 182,021
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:
June 30, June 30, December 31,
2003 2002 2002
(In thousands)
Amortizable intangible
assets:
Leasehold rights $176,583 $170,496 $172,496
Accumulated amortization (9,211) (5,451) (7,494)
167,372 165,045 165,002
Noncompete agreements 12,075 12,090 12,075
Accumulated amortization (9,552) (9,096) (9,366)
2,523 2,994 2,709
Other 17,719 5,149 7,224
Accumulated amortization (1,268) (215) (374)
16,451 4,934 6,850
Unamortizable intangible
assets 1,603 --- 1,603
Total $187,949 $172,973 $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 six months ended June 30, 2003, was $1.6
million and $2.8 million, respectively. Amortization expense
for amortizable intangible assets for the three months and six
months ended June 30, 2002, and for the year ended December 31,
2002, was $472,000, $703,000 and $3.4 million, respectively.
Estimated amortization expense for amortizable intangible
assets is $6.0 million in 2003, $6.1 million in 2004, $6.2
million in 2005, $5.1 million in 2006, $5.0 million in 2007 and
$160.7 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 June 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 six months ended June 30, 2003
and 2002, the amount of hedge ineffectiveness recognized, which
was included in operating revenues, was immaterial. For the
three months and six months ended June 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 June 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 18 months. The subsidiary of the Company
estimates that over the next twelve months net losses of
approximately $9.2 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 Six
Months Ended
June 30, 2003
(In thousands)
January 1, 2003 $ 29,997
Liabilities incurred 548
Liabilities acquired 626
Liabilities settled (263)
Accretion expense 948
$ 31,856
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 $28.1 million
at January 1, 2002, and June 30, 2002, respectively.
The fair value of assets that are legally restricted for
purposes of settling asset retirement obligations at June 30,
2003, was $5.3 million.
14. Long-term debt
Centennial borrowed an additional $39 million in the first
quarter of 2003 under its long-term master shelf agreement.
Under the terms of the master shelf agreement, $394.6 million
was outstanding at June 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
$108.1 million at June 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 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 June 30, 2003
Electric $ 38,049 $ --- $ 1,766
Natural gas distribution 42,409 --- (1,291)
Pipeline and energy
services 47,717 8,508 5,083
128,175 8,508 5,558
Utility services 108,928 --- 1,515
Natural gas and oil
production 36,746 27,912 17,866
Construction materials
and mining 264,129 --- 12,803
Independent power
production and other 10,241 740 5,543
420,044 28,652 37,727
Intersegment eliminations --- (37,160) ---
Total $ 548,219 $ --- $ 43,285
Three Months
Ended June 30, 2002
Electric $ 36,292 $ --- $ 1,673
Natural gas distribution 34,120 --- (815)
Pipeline and energy
services 36,110 8,420 4,610
106,522 8,420 5,468
Utility services 116,344 --- 834
Natural gas and oil
production 27,775 15,989 9,341
Construction materials
and mining 229,577 --- 10,881
Independent power
production and other --- 847 (1,860)
373,696 16,836 19,196
Intersegment eliminations --- (25,256) ---
Total $ 480,218 $ --- $ 24,664
Inter-
External segment Earnings
Operating Operating on Common
Revenues Revenues Stock
(In thousands)
Six Months
Ended June 30, 2003
Electric $ 83,720 $ --- $ 6,583
Natural gas distribution 153,397 --- 2,954
Pipeline and energy
services 86,928 30,427 9,394
324,045 30,427 18,931
Utility services 212,591 --- 2,625
Natural gas and oil
production 77,865 55,816 29,532
Construction materials
and mining 384,882 --- 5,363
Independent power
production and other 16,590 1,481 6,755
691,928 57,297 44,275
Intersegment eliminations --- (87,724) ---
Total $1,015,973 $ --- $ 63,206
Six Months
Ended June 30, 2002
Electric $ 76,362 $ --- $ 5,164
Natural gas distribution 105,832 --- 3,701
Pipeline and energy
services 55,910 30,323 7,514
238,104 30,323 16,379
Utility services 224,631 --- 2,184
Natural gas and oil
production 76,509 29,663 30,411
Construction materials
and mining 322,909 --- 1,160
Independent power
production and other --- 1,694 (1,937)
624,049 31,357 31,818
Intersegment eliminations --- (61,680) ---
Total $ 862,153 $ --- $ 48,197
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 six months of 2003, the Company acquired
a number of businesses, none of which was individually
material, including construction materials and mining
businesses in Montana and North Dakota 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 $120.1 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. The NDPSC has not acted on the interim request. 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. A
final order from the SDPUC was due June 30, 2003. However, on
June 13, 2003, Montana-Dakota and the SDPUC Staff filed a
motion to continue and reschedule the hearing and further
suspend rates. On July 1, 2003, the SDPUC granted the motion
to continue and reschedule the hearing and further suspend
rates. 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. The due date for a final order
from the MPUC was extended and is now due October 22, 2003.
Reserves have been provided for a portion of the revenues
that have been collected subject to refund for certain of the
above proceedings. The Company believes that such reserves are
adequate based on its assessment of the ultimate outcome of the
proceedings.
In December 1999, Williston Basin Interstate Pipeline
Company (Williston Basin), an indirect wholly owned subsidiary
of the Company, filed a general natural gas rate change
application with the Federal Energy Regulatory Commission
(FERC). Williston Basin began collecting such rates effective
June 1, 2000, subject to refund. In May 2001, the
Administrative Law Judge (ALJ) issued an Initial Decision on
Williston Basin's natural gas rate change application. The
Initial Decision addressed numerous issues relating to the rate
change application, including matters relating to allowable
levels of rate base, return on common equity, and cost of
service, as well as volumes established for purposes of cost
recovery, and cost allocation and rate design. On July 3,
2003, the FERC issued its Order on Initial Decision. The Order
affirms 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 differs 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. Williston Basin is unable to
predict the timing of a decision by the FERC on the issues
raised in the rehearing request.
Reserves have been provided for a portion of the revenues
that have been collected subject to refund with respect to
Williston Basin's pending regulatory proceeding. Williston
Basin believes that such reserves are adequate based on its
assessment of the ultimate outcome of the proceeding.
18. Contingencies
Litigation
In January 2002, Fidelity Oil Co. (FOC), one of the
Company's natural gas and oil production subsidiaries, entered
into a compromise agreement with the former operator of certain
of FOC's oil production properties in southeastern Montana.
The compromise agreement resolved litigation involving the
interpretation and application of contractual provisions
regarding net proceeds interests paid by the former operator to
FOC for a number of years prior to 1998. The terms of the
compromise agreement are confidential. As a result of the
compromise agreement, the natural gas and oil production
segment reflected a gain in its financial results for the first
quarter of 2002 of approximately $16.6 million after tax. As
part of the settlement, FOC gave the former operator a full and
complete release, and FOC is not asserting any such claim
against the former operator for periods after 1997.
In July 1996, Jack J. Grynberg (Grynberg) filed suit in
United States District Court for the District of Columbia (U.S.
District Court) against Williston Basin and over 70 other
natural gas pipeline companies. Grynberg, acting on behalf of
the United States under the Federal False Claims Act, alleged
improper measurement of the heating content and volume of
natural gas purchased by the defendants resulting in the
underpayment of royalties to the United States. In March 1997,
the U.S. District Court dismissed the suit without prejudice
and the dismissal was affirmed by the United States Court of
Appeals for the D.C. Circuit in October 1998. In June 1997,
Grynberg filed a similar Federal False Claims Act suit against
Williston Basin and Montana-Dakota and filed over 70 other
separate similar suits against natural gas transmission
companies and producers, gatherers, and processors of natural
gas. In April 1999, the United States Department of Justice
decided not to intervene in these cases. In response to a
motion filed by Grynberg, the Judicial Panel on Multidistrict
Litigation consolidated all of these cases in the Federal
District Court of Wyoming (Federal District Court). Oral
argument on motions to dismiss was held before the Federal
District Court in March 2000. In May 2001, the Federal
District Court denied Williston Basin's and Montana-Dakota's
motion to dismiss. The matter is currently in the discovery
stage. Grynberg has not specified the amount he seeks to
recover. Williston Basin and Montana-Dakota are unable to
estimate their potential exposure and will be unable to do so
until discovery is completed. Williston Basin and Montana-
Dakota believe that the Grynberg case will ultimately be
dismissed because Grynberg is not, as is required by the
Federal False Claims Act, the original source of the
information underlying the action. Failing this, Williston
Basin and Montana-Dakota believe Grynberg will not recover
damages from Williston Basin and Montana-Dakota because
insufficient facts exist to support the allegations. Williston
Basin and Montana-Dakota intend to vigorously contest this
suit.
The Quinque Operating Company (Quinque), on behalf of
itself and subclasses of gas producers, royalty owners and
state taxing authorities, instituted a legal proceeding in
State District Court for Stevens County, Kansas, (State
District Court) against over 200 natural gas transmission
companies and producers, gatherers, and processors of natural
gas, including Williston Basin and Montana-Dakota. The
complaint, which was served on Williston Basin and Montana-
Dakota in September 1999, contains allegations of improper
measurement of the heating content and volume of all natural
gas measured by the defendants other than natural gas produced
from federal lands. The plaintiffs have not specified the
amount they seek to recover. In September 2002, the plaintiffs
moved for certification of the case as a class action and on
April 10, 2003, the State District Court denied the motion. On
May 12, 2003, the plaintiffs filed a motion to file an amended
class action petition. Neither Williston Basin nor Montana-
Dakota were named as defendants in the amended class action
petition. The motion to amend the class petition was granted
by the State District Court on July 28, 2003, and as a result
Williston Basin and Montana-Dakota are no longer defendants in
this proceeding.
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 June 30, 2003, the amount
of the obligation of the foreign currency swap agreement, which
expires in 2003, was $30,000. At June 30, 2003, the aggregate
amount of borrowings outstanding subject to these guarantees
was $57.1 million and the scheduled repayment of these
borrowings was $2.1 million in 2003, $12.3 million in 2004 and
$42.7 million in 2006. 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.
These guarantees are not reflected on the Consolidated Balance
Sheets.
On June 17, 2003, MPX entered into a five-year credit
agreement with the U.S. Export-Import Bank under which MPX
borrowed $50.6 million. MPX received the proceeds of this loan
on July 10, 2003, and used the funds to pay outstanding bank
borrowings. Centennial and EBX have jointly and severally
guaranteed repayment of this loan. Following this refinancing,
guarantees with respect to approximately $26.4 million will
terminate upon MPX meeting certain financial covenants under
the prior financing agreements.
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.
In addition, Centennial has unconditionally guaranteed
borrowings under a $10 million credit agreement by a subsidiary
of the Company. The proceeds from these borrowings were used
in connection with the Company's investment in international
projects. The amount outstanding under this agreement at
June 30, 2003, was $5.5 million, which amount is reflected on
the Consolidated Balance Sheets. On June 30, 2003, Centennial
International extended this agreement through September 30,
2003. This agreement was terminated on July 11, 2003. In the
event this subsidiary of the Company had defaulted under its
obligation, Centennial would have been required to make
payments under its guarantee.
In addition, WBI Holdings has guaranteed certain of its
subsidiary's natural gas and oil price swap and collar
agreement obligations. The amount of the subsidiary's
obligations at June 30, 2003, was $6.5 million. There is no
fixed maximum amount guaranteed in relation to the natural gas
and oil price swap and collar agreements; however, the amount
of hedging activity entered into by the subsidiary is limited
by corporate policy. The guarantees of the natural gas and oil
price swap and collar agreements at June 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 will issue additional guarantees on these
hedging obligations. The amounts outstanding under the natural
gas and oil price swap and collar agreements were reflected on
the Consolidated Balance Sheets. In the event the above
subsidiary defaults under its obligations, WBI Holdings would
be required to make payments under its guarantees.
Certain subsidiaries of the Company have outstanding
guarantees to third parties that guarantee the performance of
other subsidiaries of the Company that are related to natural
gas transportation and sales agreements, electric power supply
agreements and certain other guarantees. At June 30, 2003, the
fixed maximum amounts guaranteed under these agreements
aggregated $38.2 million. The amounts of scheduled expiration
of the maximum amounts guaranteed under these agreements
aggregate $8.6 million in 2003; $7.6 million in 2004; $5.0
million in 2005; $12.0 million in 2012; $2.0 million, which is
subject to expiration 30 days after the receipt of written
notice and $3.0 million, which has no scheduled maturity date.
In the event of default under these guarantee obligations, the
subsidiary issuing the guarantee for that particular obligation
would be required to make payments under its guarantee. The
amount outstanding by subsidiaries of the Company under the
above guarantees was $165,000 and was reflected on the
Consolidated Balance Sheets at June 30, 2003.
WBI Holdings and Fidelity Exploration & Production Company
(Fidelity), an indirect wholly owned subsidiary of the Company,
have outstanding guarantees to Williston Basin. These
guarantees are related to natural gas transportation and
storage agreements and guarantee the performance of
Prairielands Energy Marketing, Inc. (Prairielands), an indirect
wholly owned subsidiary of the Company. At June 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 $622,000, which was not reflected on the Consolidated
Balance Sheets at June 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 maintenance were reflected on the Consolidated
Balance Sheets at June 30, 2003.
As of June 30, 2003, Centennial was contingently liable
for performance of certain of its subsidiaries under
approximately $302 million of surety bonds. These bonds are
principally for construction contracts and reclamation
obligations of these subsidiaries, entered into in the normal
course of business. Centennial indemnifies the respective
surety bond companies against any exposure under the bonds. A
large portion of these contingent commitments expire in 2003,
however Centennial will likely continue to enter into surety
bonds for its subsidiaries in the future. The surety bonds
were not reflected on the Consolidated Balance Sheets.
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
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.
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 Six Months
Ended Ended
June 30, June 30,
2003 2002 2003 2002
Electric $ 1.8 $ 1.7 $ 6.6 $ 5.2
Natural gas distribution (1.3) (.8) 2.9 3.7
Utility services 1.5 .8 2.6 2.2
Pipeline and energy services 5.1 4.7 9.4 7.5
Natural gas and oil production 17.9 9.3 29.5 30.4
Construction materials and mining 12.8 10.9 5.4 1.1
Independent power production
and other 5.5 (1.9) 6.8 (1.9)
Earnings on common stock $43.3 $ 24.7 $ 63.2 $ 48.2
Earnings per common
share - basic $ .59 $ .35 $ .86 $ .69
Earnings per common
share - diluted $ .58 $ .35 $ .85 $ .68
Return on average common equity
for the 12 months ended 13.0% 11.5%
________________________________
Three Months Ended June 30, 2003 and 2002
Consolidated earnings for the quarter ended June 30, 2003,
increased $18.6 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,
utility services, pipeline and energy services and electric
businesses. A higher seasonal loss at the natural gas distribution
business slightly offset the earnings increase.
Six Months Ended June 30, 2003 and 2002
Consolidated earnings for the six months ended June 30, 2003,
increased $15.0 million from the comparable period a year ago due to
higher earnings at the independent power production and other,
construction materials and mining, pipeline and energy services,
electric and utility services businesses. Decreased earnings at the
natural gas and oil production and natural gas distribution
businesses 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
business segments.
Electric
Three Months Six Months
Ended Ended
June 30, June 30,
2003 2002 2003 2002
Operating revenues:
Retail sales $ 33.5 $ 31.3 $ 70.6 $ 66.2
Sales for resale and other 4.6 5.0 13.1 10.2
38.1 36.3 83.7 76.4
Operating expenses:
Fuel and purchased power 13.3 13.1 28.7 27.1
Operation and maintenance 12.9 11.5 26.2 22.9
Depreciation, depletion and
amortization 5.0 4.9 9.9 9.8
Taxes, other than income 1.8 1.8 3.9 3.8
33.0 31.3 68.7 63.6
Operating income $ 5.1 $ 5.0 $ 15.0 $ 12.8
Retail sales (million kWh) 529.8 500.9 1,129.9 1,059.7
Sales for resale (million kWh) 122.9 199.8 374.3 426.4
Average cost of fuel and
purchased power per kWh $ .020 $ .018 $ .018 $ .017
Natural Gas Distribution
Three Months Six Months
Ended Ended
June 30, June 30,
2003 2002 2003 2002
Operating revenues:
Sales $ 41.4 $ 33.2 $ 151.4 $ 103.9
Transportation and other 1.0 .9 2.0 2.0
42.4 34.1 153.4 105.9
Operating expenses:
Purchased natural gas sold 30.4 22.7 118.5 73.8
Operation and maintenance 10.0 8.8 21.6 18.5
Depreciation, depletion and
amortization 2.5 2.4 5.1 4.8
Taxes, other than income 1.3 1.3 2.7 2.6
44.2 35.2 147.9 99.7
Operating income (loss) $ (1.8) $ (1.1) $ 5.5 $ 6.2
Volumes (MMdk):
Sales 5.3 6.6 22.8 23.1
Transportation 3.0 2.7 6.1 6.4
Total throughput 8.3 9.3 28.9 29.5
Degree days (% of normal)* 91% 122% 100% 104%
Average cost of natural gas,
including transportation
thereon, per dk $ 5.69 $ 3.47 $ 5.20 $ 3.20
_____________________
* Degree days are a measure of the daily temperature-related demand
for energy for heating.
Utility Services
Three Months Six Months
Ended Ended
June 30, June 30,
2003 2002 2003 2002
Operating revenues $108.9 $116.3 $ 212.6 $ 224.6
Operating expenses:
Operation and maintenance 99.8 108.5 194.0 207.4
Depreciation, depletion
and amortization 2.7 2.3 5.1 4.4
Taxes, other than income 3.3 3.5 7.7 7.7
105.8 114.3 206.8 219.5
Operating income $ 3.1 $ 2.0 $ 5.8 $ 5.1
Pipeline and Energy Services
Three Months Six Months
Ended Ended
June 30, June 30,
2003 2002 2003 2002
Operating revenues:
Pipeline $ 25.1 $ 23.7 $ 50.5 $ 44.9
Energy services 31.1 20.8 66.8 41.3
56.2 44.5 117.3 86.2
Operating expenses:
Purchased natural gas sold 30.3 18.7 64.8 36.1
Operation and maintenance 11.4 11.2 23.7 24.0
Depreciation, depletion
and amortization 3.7 3.6 7.4 7.3
Taxes, other than income 1.4 1.4 2.9 3.1
46.8 34.9 98.8 70.5
Operating income $ 9.4 $ 9.6 $ 18.5 $ 15.7
Transportation volumes (MMdk):
Montana-Dakota 8.0 7.4 16.4 15.2
Other 18.1 21.3 30.6 31.9
26.1 28.7 47.0 47.1
Gathering volumes (MMdk) 18.6 16.7 37.5 33.6
Natural Gas and Oil Production
Three Months Six Months
Ended Ended
June 30, June 30,
2003 2002 2003 2002
Operating revenues:
Natural gas $ 52.6 $ 32.1 $ 107.8 $ 57.6
Oil 12.0 11.7 25.8 21.2
Other .1 --- .1 27.4*
64.7 43.8 133.7 106.2
Operating expenses:
Purchased natural gas sold --- --- .1 ---
Operation and maintenance:
Lease operating costs,
including gathering 10.1 9.4 21.5 18.6
Other 3.9 4.3 8.9 8.6
Depreciation, depletion
and amortization 15.2 11.3 29.4 22.9
Taxes, other than income:
Production and property
taxes 5.0 2.9 10.6 5.3
Other .2 .3 .3 .4
34.4 28.2 70.8 55.8
Operating income $ 30.3 $ 15.6 $ 62.9 $ 50.4
Production:
Natural gas (MMcf) 13,258 10,949 26,897 22,352
Oil (000's of barrels) 453 502 927 983
Average realized prices
(including hedges):
Natural gas (per Mcf) $ 3.97 $ 2.93 $ 4.01 $ 2.57
Oil (per barrel) $26.52 $23.20 $ 27.79 $ 21.60
Average realized prices
(excluding hedges):
Natural gas (per Mcf) $ 4.31 $ 2.78 $ 4.50 $ 2.46
Oil (per barrel) $26.98 $23.34 $ 29.06 $ 21.21
Production costs, including
taxes, per net equivalent Mcf $ .95 $ .88 $ .99 $ .85
_____________________
* Includes the effects of a compromise agreement gain of $27.4
million ($16.6 million after tax).
Construction Materials and Mining
Three Months Six Months
Ended Ended
June 30, June 30,
2003 2002 2003 2002
Operating revenues $264.1 $229.6 $ 384.9 $ 322.9
Operating expenses:
Operation and maintenance 219.2 190.8 330.7 282.5
Depreciation, depletion
and amortization 15.6 13.2 30.2 24.6
Taxes, other than income 6.4 4.7 11.0 7.9
241.2 208.7 371.9 315.0
Operating income $ 22.9 $ 20.9 $ 13.0 $ 7.9
Sales (000's):
Aggregates (tons) 9,592 8,869 14,619 12,445
Asphalt (tons) 1,701 1,820 1,863 1,987
Ready-mixed concrete
(cubic yards) 912 793 1,427 1,194
Independent Power Production and Other
Three Months Six Months
Ended Ended
June 30, June 30,
2003 2002 2003 2002
Operating revenues $ 11.0 $ .9 $ 18.1 $ 1.7
Operating expenses:
Operation and maintenance 3.1 1.6 7.3 2.7
Depreciation, depletion and
amortization 2.2 .1 3.9 .1
5.3 1.7 11.2 2.8
Operating income (loss) $ 5.7* $ (.8) $ 6.9* $ (1.1)
Net generation capacity - kW** 279,600 --- 279,600 ---
Electricity produced and sold
(thousand kWh)** 89,694 --- 138,594 ---
_____________________
* 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 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 Six Months
Ended Ended
June 30, June 30,
2003 2002 2003 2002
Operating revenues $ 37.2 $ 25.3 $ 87.7 $ 61.7
Purchased natural gas sold $ 33.1 $ 21.6 $ 79.7 $ 54.4
Operation and maintenance $ 4.1 $ 3.7 $ 8.0 $ 7.3
For further information on intersegment eliminations, see Note
15 of Notes to Consolidated Financial Statements.
Three Months Ended June 30, 2003 and 2002
Electric
Electric earnings increased slightly as a result of higher
average sales for resale prices of 34 percent, due to stronger sales
for resale markets, and higher retail sales revenues, due in part to
higher retail sales volumes of 6 percent, primarily to commercial
and large industrial customers. Partially offsetting the earnings
increase were higher operation and maintenance expense, decreased
sales for resale volumes of 38 percent and increased purchased power
costs, all primarily related to planned maintenance outages at two
generating stations.
Natural Gas Distribution
Normal seasonal losses at the natural gas distribution business
increased as a result of higher operation and maintenance expense,
primarily due to higher employee benefit-related, payroll and
insurance costs, along with decreased retail sales volumes. Retail
sales volumes were 18 percent lower due to weather that was 31
percent warmer than the second quarter of the prior year. Partially
offsetting the earnings decline were higher retail sales rates, the
result of rate increases in Minnesota, Montana, North Dakota and
Wyoming. The pass-through of higher natural gas prices resulted in
the increase in sales revenues and purchased natural gas sold. For
further information on the retail rate increases, see 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 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 region and lower
selling, general and administrative expenses also added to the
increase in earnings. Partially offsetting the earnings increase
were lower margins in the Rocky Mountain region, lower line
construction margins in the Southwest and Central regions and lower
inside electrical margins in the Northwest and Central regions,
reflecting the continuing effects of the soft economy 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 12 percent, mainly from
increased gathering in the Powder River Basin. Also adding to the
earnings increase were higher transportation revenues, primarily
higher reservation fees resulting from an increase in firm services,
offset in part by lower transportation volumes, largely the result
of lower volumes transported to storage. Partially offsetting the
earnings increase were higher operation and maintenance costs. The
increase in energy services revenue and the related increase in
purchased natural gas sold were due largely to an increase 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 35 percent, higher natural gas
production of 21 percent, largely from operated properties in the
Rocky Mountain area, and higher average realized oil prices of 14
percent. Partially offsetting the earnings increase were higher
depreciation, depletion and amortization expense due to higher
natural gas production volumes and higher rates, decreased oil
production of 10 percent and higher interest expense, due primarily
to higher average debt balances.
Construction Materials and Mining
Construction materials and mining earnings increased due to
increased aggregate volumes, higher construction activity, primarily
due to a large harbor-deepening project in southern California, and
higher ready-mixed concrete and cement volumes, 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 depreciation,
depletion and amortization expense, due to higher aggregate volumes
produced and higher property, plant and equipment balances,
increased selling, general and administrative costs, higher asphalt
oil and fuel costs and lower asphalt volumes at existing operations.
Independent Power Production and Other
Earnings for the independent power production business
increased largely from domestic businesses acquired since the
comparable period last year, partially offset by higher interest
expense, resulting from higher average debt balances relating to
these acquisitions. The Brazilian operations also contributed to
the earnings increase. The Company's $1.3 million (after tax) share
of net income from its equity investment in Brazil was due to higher
margins and foreign currency gains, partially offset by the mark-to-
market loss on an embedded derivative in the electric power contract
and higher plant financing costs.
Six Months Ended June 30, 2003 and 2002
Electric
Electric earnings increased as a result of higher average sales
for resale prices of 46 percent, due to stronger sales for resale
markets, and higher retail sales revenues, primarily due to higher
retail sales volumes of 7 percent, largely to commercial,
residential and large industrial customers. Partially offsetting
the earnings increase was higher operation and maintenance expense,
largely higher payroll costs and higher costs related to planned
maintenance outages at two generating stations. Increased purchased
power costs and decreased sales for resale volumes of 12 percent,
both primarily related to planned maintenance outages at two
generating stations, 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 and employee benefit-related costs, and decreased
returns on natural gas held in storage. Partially offsetting the
earnings decline were higher retail sales rates, the result of rate
increases in Minnesota, Montana, North Dakota and Wyoming, as
previously discussed. The pass-through of higher natural gas prices
largely resulted in the increase in 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 and an unfavorable
settlement of a billing dispute, as previously discussed. Higher
line construction margins in the Northwest region, lower selling,
general and administrative expenses and higher equipment sale
margins also added to the increase in earnings. Partially
offsetting the earnings increase were lower inside electrical
margins in the Central and Northwest regions, lower margins in the
Rocky Mountain region and lower line construction margins in the
Southwest and Central regions. Lower margins are a reflection of
the continuing effects of the soft economy 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 12 percent and higher
transportation revenues, primarily higher reservation fees resulting
from an increase in firm services, offset in part by lower
transportation volumes, largely lower volumes transported to
storage. Higher storage revenues also added to the earnings
increase. Partially offsetting the earnings increase was higher
interest expense due to higher average debt balances. The increase
in energy services revenue and the related increase in purchased
natural gas sold were largely due to an increase in natural gas
prices since the comparable period last year.
Natural Gas and Oil Production
Natural gas and oil production earnings decreased largely due
to the 2002 compromise agreement gain of $27.4 million ($16.6
million after tax), included in 2002 operating revenues, and the
$12.7 million ($7.7 million after tax) noncash transition charge in
2003, reflecting the cumulative effect of an accounting change, as
discussed in Note 18 and Note 8 of Notes to Consolidated Financial
Statements, respectively. Also contributing to the earnings decline
were increased depreciation, depletion and amortization expense due
to higher natural gas production volumes and higher rates.
Increased operation and maintenance expense, primarily higher lease
operating expenses resulting largely from the expansion of coalbed
natural gas production, and higher interest expense, due primarily
to higher average debt balances, contributed to the decrease in
earnings. Higher general and administrative costs and decreased oil
production of 6 percent, also contributed to the earnings decline.
Largely offsetting the decrease in earnings were higher realized
natural gas prices of 56 percent, higher natural gas production of
20 percent, largely from operated properties in the Rocky Mountain
area, and higher average realized oil prices of 29 percent.
Construction Materials and Mining
Construction materials and mining earnings increased due to
increased aggregate volumes and margins, higher construction
activity due to a large harbor-deepening project in southern
California, and increased ready-mixed concrete and cement volumes,
all at existing operations. Partially offsetting the increase in
earnings were higher selling, general and administrative costs,
higher depreciation, depletion and amortization expense due to
higher aggregate volumes produced and higher property, plant and
equipment balances, and higher asphalt oil and fuel costs.
Independent Power Production and Other
Earnings for the independent power production business
increased largely from domestic businesses acquired since the
comparable period last year, partially offset by higher interest
expense, resulting from higher average debt balances relating to
these acquisitions. The Brazilian operations also contributed to
the earnings increase. The Company's $1.8 million (after tax) share
of net income from its equity investment in Brazil was due to higher
margins and foreign currency gains, partially offset by the mark-to-
market loss on an embedded derivative in the electric power contract
and higher plant financing costs.
Risk Factors and Cautionary Statements that May Affect Future Results
The Company is including the following factors and cautionary
statements in this Form 10-Q to make applicable and to take
advantage of the safe harbor provisions of the Private Securities
Litigation Reform Act of 1995 for any forward-looking statements
made by, or on behalf of, the Company. Forward-looking statements
include statements concerning plans, objectives, goals, strategies,
future events or performance, and underlying assumptions (many of
which are based, in turn, upon further assumptions) and other
statements that are other than statements of historical facts. From
time to time, the Company may publish or otherwise make available
forward-looking statements of this nature, including statements
contained within Prospective Information. All such subsequent
forward-looking statements, whether written or oral and whether made
by or on behalf of the Company, are also expressly qualified by
these factors and cautionary statements.
Forward-looking statements involve risks and uncertainties,
which could cause actual results or outcomes to differ materially
from those expressed. The Company's expectations, beliefs and
projections are expressed in good faith and are believed by the
Company to have a reasonable basis, including without limitation
management's examination of historical operating trends, data
contained in the Company's records and other data available from
third parties. Nonetheless, the Company's expectations, beliefs or
projections may not be achieved or accomplished.
Any forward-looking statement contained in this document speaks
only as of the date on which such statement is made, and the Company
undertakes no obligation to update any forward-looking statement or
statements to reflect events or circumstances that occur after the
date on which such statement is made or to reflect the occurrence of
unanticipated events. New factors emerge from time to time, and it
is not possible for management to predict all of such factors, nor
can it assess the effect of each such factor on the Company's
business or the extent to which any such factor, or combination of
factors, may cause actual results to differ materially from those
contained in any forward-looking statement.
Following are some specific factors that should be considered
for a better understanding of the Company's financial condition.
These factors and the other matters discussed herein are important
factors that could cause actual results or outcomes for the Company
to differ materially from those discussed in the forward-looking
statements included elsewhere in this document.
Economic Risks
The recent events leading to the current adverse economic
environment may have a general negative impact on the Company's
future revenues and may result in a goodwill impairment for
Innovatum, Inc., an indirect wholly owned subsidiary of the Company
(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 June 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, rapid changes in technology, competitors and
potential new customers.
The Company relies on financing sources and capital markets.
The Company's inability to access financing may impair its ability
to execute the Company's business plans, make capital expenditures
or pursue acquisitions that the Company may otherwise rely on for
future growth.
The Company relies on access to both short-term borrowings,
including the issuance of commercial paper, and long-term capital
markets as a 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 several lawsuits
filed in connection with its coalbed natural gas development in the
Powder River Basin in Montana and Wyoming. If the plaintiffs are
successful in these lawsuits, the ultimate outcome of the actions
could have a material effect on Fidelity's future development of its
coalbed natural gas properties.
The Company is subject to extensive government regulations that
may have a negative impact on its business and its results of
operations.
The Company is subject to regulation by federal, state and
local regulatory agencies with respect to, among other things,
allowed rates of return, financings, industry rate structures, and
recovery of purchased power and purchased gas costs. These
governmental regulations significantly influence the Company's
operating environment and may affect its ability to recover costs
from its customers. The Company is unable to predict the impact on
operating results from the future regulatory activities of any of
these agencies.
Changes in regulations or the imposition of additional
regulations could have an adverse impact on the Company's results of
operations.
Risks Relating to the Company's Independent Power Production Business
There are risks involved with the growth strategies of the
Company's independent power production business. If the Company is
unable to access markets previously unavailable to a proposed 113-
megawatt coal-fired electric generation station in Montana, it may
not complete construction or commence operation of that facility,
which may result in an asset impairment.
The operation of power generation facilities involves many
risks, including start up risks, breakdown or failure of equipment,
competition, inability to obtain required governmental permits and
approvals and inability to negotiate acceptable acquisition,
construction, fuel supply or other material agreements, as well as
the risk of performance below expected levels of output or
efficiency.
The Company's plans to construct a 113-megawatt coal-fired
electric generation station in Montana are pending. The Company
purchased plant equipment and obtained all permits necessary to
begin construction. NorthWestern Energy terminated the power
purchase agreement for the energy from this plant in July 2002;
however, the Company is in the process of accessing markets
previously unavailable to this project and plans to resume
construction in the near future to the extent access to such markets
is secured. The Company has suspended construction activities
except for those items of a critical nature. At June 30, 2003, the
Company's investment in this project was approximately $29.6
million. If it is not economically feasible for the Company to
construct and operate this facility or if alternate markets cannot
be identified, an asset impairment may occur.
Risks Relating to Foreign Operations
The value of the Company's investment in foreign operations may
diminish due to political, regulatory and economic conditions and
changes in currency exchange rates in countries where the Company
does business.
The Company is subject to political, regulatory and economic
conditions and changes in currency exchange rates in foreign
countries where the Company does business. Significant changes in
the political, regulatory or economic environment in these countries
could negatively affect the value of the Company's investments
located in these countries. Also, since the Company is unable to
predict the fluctuations in the foreign currency exchange rates,
these fluctuations may have an adverse impact on the Company's
results of operations.
The Company's 49 percent equity method investment in a 220-
megawatt natural gas-fired electric generation project in Brazil
includes a power purchase agreement that contains an embedded
derivative. This embedded derivative derives its value from an
annual adjustment factor that largely indexes the contract capacity
payments to the U.S. dollar. In addition, from time to time, other
derivative instruments may be utilized. The valuation of these
financial instruments, including the embedded derivative, can
involve judgments, uncertainties and the use of estimates. As a
result, changes in the underlying assumptions could affect the
reported fair value of these instruments. These instruments could
recognize financial losses as a result of volatility in the
underlying fair values, or if a counterparty fails to perform.
Other Risks
Competition is increasing in all of the Company's businesses.
All of the Company's 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.
Weather conditions can adversely affect the Company's operations and
revenues.
The Company's results of operations can be affected by changes
in the weather. Weather conditions directly influence the demand
for electricity and natural gas, affect the price of energy
commodities, 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. Changes
in such assumptions and factors could cause actual future results to
differ materially from targeted growth, revenue and earnings
projections.
MDU Resources Group, Inc.
- - 2003 earnings per common share, diluted, before the cumulative
effect of the change in accounting for asset retirement obligations
as required by the adoption of SFAS No. 143, are projected in the
range of $2.20 to $2.45. 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 $2.10 to $2.35.
- - The Company expects the percentage of 2003 earnings per common
share, diluted, after the cumulative effect of an accounting change
by quarter to be in the following approximate ranges:
- Third Quarter - 35 percent to 40 percent
- Fourth Quarter - 22 percent to 27 percent
- - 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.
- - The Company's long-term compound annual growth goals on
earnings per share from operations are in the range of 6 percent to
9 percent.
Electric
- - Montana-Dakota has obtained and holds valid and existing
franchises authorizing it to conduct its electric operations in all
of the municipalities it serves where such franchises are required.
As franchises expire, Montana-Dakota may face increasing competition
in its service areas, particularly its service to smaller towns,
from rural electric cooperatives. Montana-Dakota intends to protect
its service area and seek renewal of all expiring franchises and
will continue to take steps to effectively operate in an
increasingly competitive environment.
- - A new 40-megawatt, natural gas-fueled combustion turbine near
Glendive, Montana, became operational in late May. The new plant
will help the utility provide peak period electrical energy to
customers on its integrated system in North Dakota, South Dakota and
Montana. In addition, the added capacity will allow the company to
meet its peak load obligation with the regional power pool. The
costs of this project are expected to be recovered in rates.
- - 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 respective amount requested, there
is no assurance that the increases 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.
- - Regulatory approval has been received from the NDPSC and the
SDPUC 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 by late 2003 or early 2004.
- - The Company expects to build an additional 80-megawatts of
peaking capacity by 2007. The costs of these projects are expected
to be recovered in rates and will be used to meet Montana-Dakota'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 in late 2003.
Natural gas distribution
- - Montana-Dakota and Great Plains have obtained and hold valid
and existing franchises authorizing them to conduct their natural
gas operations in all of the municipalities they serve where such
franchises are required. As franchises expire, Montana-Dakota and
Great Plains may face increasing competition in their service areas.
Montana-Dakota and Great Plains intend to protect their service
areas and seek renewal of all expiring franchises and will continue
to take steps to effectively operate in an increasingly competitive
environment.
- - Annual natural gas throughput for 2003 is expected to be
approximately 52 million decatherms.
- - Montana-Dakota filed an application with the SDPUC seeking an
increase in natural gas retail rates of 5.8 percent above current
rates. Great Plains filed an application with the MPUC seeking an
increase in natural gas retail rates of 6.9 percent above current
rates. While Montana-Dakota and Great Plains believe that they
should be authorized to increase retail rates in the respective
amounts requested, there is no assurance that the increases
ultimately allowed will be for the full amounts requested in each
jurisdiction. For further information on the natural gas rate
increase applications, see Note 17 of Notes to Consolidated
Financial Statements.
Utility services
- - 2003 revenues for this segment are expected to be in the range
of $425 million to $475 million.
- - This segment anticipates margins in 2003 to decrease slightly
from 2002 levels. During 2002, a number of factors affected
earnings, including the write-off of certain receivables and
restructuring of the engineering function which amounts totaled
approximately $5.2 million after-tax.
- - This segment's work backlog as of June 30, 2003, was
approximately $150 million.
Pipeline and energy services
- - In 2003, natural gas throughput from this segment, including
both transportation and gathering, is expected to increase slightly
over the 2002 record levels.
- - Pipeline construction has begun in Wyoming on the 253-mile
Grasslands Pipeline project with construction expected to start soon
in North Dakota and Montana. Construction has begun on both a new
compressor station in western North Dakota and an addition to an
existing station in Montana, related to this project. The estimated
in-service date is November 1, 2003.
- - Innovatum could face a future goodwill impairment based on
certain economic conditions, as previously discussed in Risk Factors
and Cautionary Statements that May Affect Future Results.
Natural gas and oil production
- - In 2003, this segment expects a combined natural gas and oil
production increase of approximately 15 percent over 2002 record
levels. Currently, this segment's gross daily operated natural gas
production is approximately 130,000 Mcf per day.
- - This segment continues to expand its operated production.
Natural gas production from operated properties was 73 percent and
66 percent for the six months ended June 30, 2003 and 2002,
respectively.
- - This segment expects to drill more than 400 wells in 2003. At
June 30, 2003, 158 wells had been drilled.
- - This segment had approximately 150 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
June 30, 2003, but may begin producing either natural gas or water
in the future.
- - Estimates for natural gas prices in the Rocky Mountain region
for August through December 2003, reflected in the Company's 2003
earnings guidance, are in the range of $3.00 to $3.50 per Mcf. The
Company's estimates for natural gas prices on the NYMEX for August
through 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.
- - Estimates of NYMEX crude oil prices for July through December
2003, reflected in the Company's 2003 earnings guidance, are in the
range of $22 to $27 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 begun hedging 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 several lawsuits
filed in connection with its coalbed natural gas development in the
Powder River Basin in Montana and Wyoming.
In one such case, the United States District Court in Billings,
Montana (Federal District Court) held that water produced in
association with coalbed natural gas and discharged into rivers
and streams was not a pollutant under the Federal Clean Water Act
and that state statutes exempt such unaltered groundwater from
Montana Pollution Discharge Elimination System permit
requirements. On April 10, 2003, the United States Circuit Court
of Appeals for the Ninth Circuit (Circuit Court) reversed the
Federal District Court's decision. Fidelity filed a petition for
a writ of certiorari with the United States Supreme Court on
August 8, 2003. Fidelity believes the ultimate outcome of the
proceeding will not have a material effect on its existing coalbed
natural gas operations or future development of its coalbed
natural gas properties. In the event a penalty is ultimately
imposed in that proceeding, Fidelity believes it will be minimal
because any unpermitted discharges were of small amounts, were for
a short duration, were quickly remediated and are now fully
permitted.
Fidelity believes the ultimate outcome of other lawsuits filed in
connection with its coalbed natural gas development would not have
a material effect on its existing coalbed natural gas operations,
but could have a material effect on Fidelity's future development
of its coalbed natural gas properties.
For further information on these proceedings, see Risk Factors and
Cautionary Statements that May Affect Future Results in this Form
10-Q.
Construction materials and mining
- - Excluding the effects of potential future acquisitions,
aggregate and ready-mixed concrete volumes are expected to increase
over record levels achieved in 2002, while asphalt volumes are
expected to be comparable to 2002 levels.
- - Revenues for this segment in 2003 are expected to increase by
approximately 10 percent as compared to 2002 record levels.
- - As of mid-July 2003, this segment had $497 million in work
backlog.
- - On July 11, 2003, this segment completed the acquisition of a
privately held construction materials and services company serving
East Central Texas. The company supplies and places ready-mixed
concrete, asphalt, crushed stone and sand and gravel for highways,
subdivisions and a variety of other projects in 27 central Texas
counties. In 2002, the acquired company had annual revenues of
about $87 million. The acquisition is expected to be accretive to
earnings per share.
- - 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
- - 2003 earnings projections for independent power production and other
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.
- - The Company's plans to construct a 113-megawatt coal-fired
electric generation station in Montana are pending, as previously
discussed in Risk Factors and Cautionary Statements that May Affect
Future Results.
New Accounting Standards
In June 2001, the FASB approved SFAS No. 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. The SEC has recently
questioned under SFAS No. 142 whether contractual mineral rights
should be classified as intangible rather than as part of property,
plant and equipment and has referred this accounting matter to the
Emerging Issues Task Force and is continuing its dialog with the
FASB staff. The resolution of this matter may result in certain
reclassifications to the Company's Consolidated Balance Sheet, 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 impact balance sheet and associated footnote
disclosure, so any reclassifications that might be required in the
future will not impact 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 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 a discounted liability of $22.5 million and a
regulatory asset of $493,000, increased net property, plant and
equipment by $9.6 million and recognized a one-time cumulative
effect charge of $7.6 million (net of deferred tax benefit of $4.8
million).
In April 2002, the FASB approved SFAS No. 145, "Rescission of
FASB Statements No. 4, 44 and 64, Amendment of FASB Statement No.
13, and Technical Corrections." The adoption of SFAS No. 145 did
not have a material effect on the Company's financial position or
results of operations.
In November 2002, the FASB issued FASB Interpretation No. 45,
"Guarantor's Accounting and Disclosure Requirements for Guarantees,
Including indirect Guarantees of Indebtedness of Others" (FIN 45).
The Company will apply the initial recognition and initial
measurement provisions of FIN 45 to guarantees issued or modified
after December 31, 2002.
In January 2003, the FASB issued FASB Interpretation No. 46,
"Consolidation of Variable Interest Entities" (FIN 46). FIN 46 is
effective for the first fiscal year or interim period beginning
after June 15, 2003, for variable interest entities created before
February 1, 2003. The Company will prospectively apply the
provisions of FIN 46 that were effective January 31, 2003. The
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 Company does not expect SFAS
No. 149 to have a material effect on its 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.
The Company is currently evaluating the effect of SFAS No. 150 for
financial instruments entered into on or before May 31, 2003, on its
financial position and results of operations.
For further information on 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 six
months of 2003 increased $66.7 million from the comparable 2002
period, the result of an increase in cash from working capital items
of $17.7 million and higher depreciation, depletion and amortization
expense of $17.0 million, resulting largely from increased property,
plant and equipment balances and higher production volumes. An
increase in net income of $15.0 million and the cumulative effect of
an accounting change of $7.6 million also added to the increase of
cash flows provided by operating activities.
Investing activities --
Cash flows used in investing activities in the first six months
of 2003 increased $111.2 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 $114.5
million, slightly offset by an increase in proceeds from notes
receivable of $3.8 million. Net capital expenditures exclude the
noncash transactions related to acquisitions, including the issuance
of the Company's equity securities. The noncash transactions were
$4.9 million and $41.8 million for the first six months of 2003 and
2002, respectively.
Financing activities --
Cash flows provided by financing activities in the first six
months of 2003 increased $36.7 million compared to the comparable
2002 period, due to an increase in the issuance of long-term debt of
$135.8 million. The increase in the repayment of long-term debt of
$77.1 million and the net decrease of short-term borrowings of $19.0
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). There are no material changes in the
Company's Pension Plans from those reported in the Company's Annual
Report on Form 10-K for the year ended December 31, 2002. For
further information on the Company's Pension Plans, see Part II,
Item 7 in the Company's Annual Report on Form 10-K for the year
ended December 31, 2002.
Capital expenditures
Net capital expenditures, including the issuance of the
Company's equity securities, for the first six months of 2003 were
$243.9 million and are estimated to be approximately $525 million
for the year 2003. Estimated capital expenditures include those
for:
- Completed acquisitions
- System upgrades, including a 40-megawatt natural gas-fired
peaking unit, as previously discussed
- Routine replacements
- Service extensions
- Routine equipment maintenance and replacements
- Land and building improvements
- Pipeline and gathering expansion projects, including a 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 electric generation station,
as previously discussed
- Other growth opportunities
Approximately 35 percent of estimated 2003 net capital
expenditures are for completed acquisitions. The Company continues
to evaluate potential future acquisitions and other growth
opportunities; however, they are dependent upon the availability of
economic opportunities and, as a result, actual acquisitions and
capital expenditures may vary significantly from the estimated 2003
capital expenditures referred to above. It is anticipated that the
funds required for capital expenditures will be met from various
sources. These sources include internally generated funds,
commercial paper credit facilities at Centennial and MDU Resources,
as described below, and through the issuance of long-term debt and
the Company's equity securities.
The estimated 2003 capital expenditures referred to above
include completed 2003 acquisitions involving a wind-powered
electric generation facility in California and construction
materials and mining businesses in Montana, North Dakota and Texas.
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
June 30, 2003.
MDU Resources Group, Inc.
The Company has unsecured short-term bank lines of credit from
various banks totaling $21 million and a revolving credit agreement
with various banks totaling $50 million at June 30, 2003. The bank
lines of credit provide for commitment fees at varying rates. There
were no amounts outstanding under the bank lines of credit or the
credit agreement at June 30, 2003. The bank lines of credit and the
credit agreement support the Company's $75 million commercial paper
program. Under the Company's commercial paper program, $30.0
million was outstanding at June 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. On July 18, 2003, the Company increased the credit
agreement to $90 million and extended the maturity date of this
agreement to 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 and/or bank lines of credit.
To the extent the Company needs to borrow under its credit
agreement and/or bank lines of credit, it would be expected to incur
increased annualized interest expense on its variable rate debt of
approximately $45,000 (after tax) based on June 30, 2003, variable
rate borrowings. Based on the Company's overall interest rate
exposure at June 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 and the bank
lines of credit, the Company plans to negotiate the extension or
replacement of these agreements that provide credit support to
access the capital markets. In the event the Company was unable to
successfully negotiate the credit agreement and/or the bank lines of
credit, or in the event the fees on such facilities became too
expensive, which it does not currently anticipate, the Company would
seek alternative funding. One source of alternative funding might
involve the securitization of certain Company assets.
In order to borrow under the Company's credit agreement, the
Company must be in compliance with the applicable covenants and
certain other conditions. The significant covenants include maximum
leverage ratios, minimum interest coverage ratio, limitation on sale
of assets and limitation on investments. The Company was in
compliance with these covenants and met the required conditions at
June 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 June 30, 2003, the Company could have issued approximately
$339 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
June 30, 2003 and December 31, 2002, respectively. Additionally,
the Company's first mortgage bond interest coverage was 8.1 times
and 7.7 times for the twelve months ended June 30, 2003 and December
31, 2002, respectively. Common stockholders' equity as a percent of
total capitalization was 58 percent and 60 percent at June 30, 2003
and December 31, 2002, respectively.
Centennial Energy Holdings, Inc.
Centennial has a revolving credit agreement with various banks
that supports $330 million of Centennial's $350 million commercial
paper program. There were no outstanding borrowings under the
Centennial credit agreement at June 30, 2003. Under the Centennial
commercial paper program, $78.1 million was outstanding at June 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
agreement, which allows for subsequent borrowings up to a term of
one year. Centennial intends to renew the Centennial credit
agreement, which expires September 26, 2003.
Centennial has an uncommitted long-term master shelf agreement
that allows for borrowings of up to $400 million. Under the terms
of the master shelf agreement, $394.6 million was outstanding at
June 30, 2003. To meet potential future financing needs, Centennial
may pursue other financing arrangements, including private and/or
public financing.
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.
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 $117,000
(after tax) based on June 30, 2003, variable rate borrowings. Based
on Centennial's overall interest rate exposure at June 30, 2003,
this change would not have a material effect on the Company's
results of operations or cash flows.
On an annual basis, Centennial negotiates the extension or
replacement of the Centennial credit agreement that provides credit
support to access the capital markets. In the event Centennial was
unable to successfully negotiate the credit agreement, or in the
event the fees on such facility became too expensive, which
Centennial does not currently anticipate, it would seek alternative
funding. One source of alternative funding might involve the
securitization of certain Centennial assets.
In order to borrow under Centennial's credit agreement and the
Centennial uncommitted long-term master shelf agreement, Centennial
and certain of its subsidiaries must be in compliance with the
applicable covenants and certain other conditions. The significant
covenants include maximum capitalization ratios, minimum interest
coverage ratios, minimum consolidated net worth, limitation on
priority debt, limitation on sale of assets and limitation on loans
and investments. Centennial and such subsidiaries were in
compliance with these covenants and met the required conditions at
June 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.
Centennial Energy Resources International Inc
Centennial Energy Resources International Inc (Centennial
International), an indirect wholly owned subsidiary of the Company,
had a short-term credit agreement that allowed for borrowings of
up to $10 million. Under this agreement, $5.5 million was
outstanding at June 30, 2003. On June 30, 2003, Centennial
International extended this agreement through September 30, 2003,
and lowered the amount of allowed borrowings from $25 million to $10
million. This agreement was terminated on July 11, 2003.
Centennial had guaranteed this short-term credit agreement.
Williston Basin Interstate Pipeline Company
Williston Basin has an uncommitted long-term master shelf
agreement that allows for borrowings of up to $100 million. Under
the terms of the master shelf agreement, $30.0 million was
outstanding at June 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 June 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 June
30, 2003, increased $114.8 million or 14 percent from December 31,
2002, primarily due to acquisitions and other corporate purposes.
At June 30, 2003, the Company's commitments under these obligations
for the twelve months ended June 30, were as follows:
2004 2005 2006 2007 2008 Thereafter Total
(In millions)
Long-term debt $34.9 $196.8 $25.5 $180.7 $110.1 $408.5 $956.5
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 June 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 June 30, 2003, are
approximately $57.1 million. As of June 30, 2003, with respect to
these guarantees, there was approximately $2.1 million outstanding
through 2003, $12.3 million outstanding through 2004 and $42.7
million outstanding through 2006. These guarantees are not
reflected on the Consolidated Balance Sheets.
On June 17, 2003, MPX entered into a five-year credit agreement
with the U.S. Export-Import Bank under which MPX borrowed $50.6
million. MPX received the proceeds of this loan on July 10, 2003,
and used the funds to pay outstanding bank borrowings. Centennial
and EBX have jointly and severally guaranteed repayment of this
loan. Following this refinancing, guarantees with respect to
approximately $26.4 million will terminate upon MPX meeting certain
financial covenants under the prior financing agreements.
For more information on these guarantees, see Note 18 of Notes
to Consolidated Financial Statements.
As of June 30, 2003, Centennial was contingently liable for
performance of certain of its subsidiaries under approximately $302
million of surety bonds. These bonds are principally for
construction contracts and reclamation obligations of these
subsidiaries, entered into in the normal course of business.
Centennial indemnifies the respective surety bond companies against
any exposure under the bonds. A large portion of these contingent
commitments expire in 2003, however Centennial will likely continue
to enter into surety bonds for its subsidiaries in the future. The
surety bonds were not reflected on the Consolidated Balance Sheets.
ITEM 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 June 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 $ 4.20 1,631 $ (896)
Natural gas swap
agreements maturing
in 2004 $ 4.96 3,660 $ (316)
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 11,275 $(13,023)
Natural gas collar
agreements maturing
in 2004 $4.04/$4.48 3,111 $ (745)
Weighted
Average
Floor/Ceiling Notional
Price Amount
(Per barrel) (In barrels) Fair Value
Oil collar agreements
maturing in 2003 $24.50/$27.62 322 $ (657)
Interest rate risk --
There are no material changes to interest rate risk faced by
the Company from those reported in the Company's Annual Report on
Form 10-K for the year ended December 31, 2002. For more
information on interest rate risk, see Part II, Item 7A in the
Company's Annual Report on Form 10-K for the year ended December 31,
2002.
Foreign currency risk --
MDU Brasil has a 49 percent equity investment in a 220-megawatt
natural gas-fired electric generation project (Project) in Brazil,
which has a portion of its borrowings and payables denominated in
U.S. dollars. MDU Brasil has exposure to currency exchange risk as
a result of fluctuations in currency exchange rates between the U.S.
dollar and the Brazilian real. The functional currency for the
Project is the Brazilian real. For further information on this
investment, see Note 10 of Notes to Consolidated Financial
Statements.
MDU Brasil's equity income from this Brazilian investment is
impacted by fluctuations in currency exchange rates on transactions
denominated in a currency other than the Brazilian real, including
the effects of changes in currency exchange rates with respect to
the Project's U.S. dollar denominated obligations, excluding a U.S.
dollar denominated loan from Centennial International as discussed
below. At June 30, 2003, these U.S. dollar denominated obligations
approximated $71.2 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 based on the above U.S. dollar
denominated obligations at June 30, 2003. The Project also had
US$11.4 million of Brazilian real denominated obligations at
June 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 June 30, 2003. Foreign currency translation adjustments
on the Project's U.S. dollar denominated borrowings payable to the
subsidiary of $20.0 million at June 30, 2003, are recorded in
accumulated other comprehensive income (loss).
Centennial International's investment in this Project at June
30, 2003, was $20.6 million. Centennial has guaranteed Project
obligations and loans of approximately $57.1 million as of June 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, a portion of the
Project's foreign currency risk on interest payments on U.S. dollar
denominated obligations is being managed through the utilization of
foreign currency hedging. At June 30, 2003, the Project had foreign
currency forward contracts with a notional amount of approximately
$2.0 million at a weighted average rate of R$3.006, which expired on
July 15, 2003, and approximately $2.3 million at a weighted average
rate of R$3.115, which expire on October 15, 2003. The Company's 49
percent share of the fair value of these forward contracts at June
30, 2003, was approximately $82,000.
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 1. LEGAL PROCEEDINGS
On July 28, 2003, the motion to amend the class petition in the
Quinque legal proceeding was granted by the State District Court for
Stevens County, Kansas, and as a result Williston Basin and Montana-
Dakota are no longer defendants in this proceeding.
For more information on the above legal action see Note 18 of
Notes to Consolidated Financial Statements.
ITEM 2. CHANGES IN SECURITIES AND USE OF PROCEEDS
Between April 1, 2003 and June 30, 2003, the Company issued
133,996 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. The Common Stock and Rights issued by the Company in
this transaction were issued in a private transaction exempt from
registration under the Securities Act of 1933 pursuant to Section
4(2) thereof, Rule 506 promulgated thereunder, or both. The classes
of persons to whom these securities were sold were either accredited
investors or other persons to whom such securities were permitted to
be offered under the applicable exemption.
ITEM 5. OTHER INFORMATION
a) Reference is made to Part I, Items 1 and 2 - Business and
Properties - Natural Gas and Oil Production - Operating Information
and Part II, Item 7 - Management's Discussion and Analysis of
Financial Condition and Results of Operations - Financial and
Operating Data - Natural Gas and Oil Production in the Company's
Annual Report on Form 10-K for the year ended December 31, 2002.
Supplemental information on average realized prices (excluding
hedges) related to natural gas and oil interests for 2002, 2001 and
2000, are as follows:
2002 2001 2000
Average realized prices
(excluding hedges):
Natural gas (per Mcf) $ 2.54 $ 3.74 $ 3.35
Oil (per barrel) $ 23.26 $ 23.72 $ 28.17
b) Reference is made to Part I, Items 1 and 2 - Business and
Properties - Construction Materials and Mining - Consolidated
Construction Materials and Mining - Reserve Information in the
Company's Annual Report on Form 10-K for the year ended December 31,
2002.
Reserve estimates are calculated based on the best available
data. These data are collected from drill holes and other
subsurface investigations as well as investigations of surface
features like mine highwalls and other exposures of the aggregate
reserves. Mine plans, production history and geologic data are also
utilized to estimate reserve quantities.
Estimates are based on analyses of the data described above by
experienced mining engineers, operating personnel and consulting
geologists. Property setbacks and other regulatory restrictions and
limitations are identified to determine the total area available for
mining. Data described above are used to calculate the thickness of
aggregate materials to be recovered. Topography associated with
alluvial sand and gravel deposits is typically flat and volumes of
these materials are calculated by simply applying the thickness of
the resource over the areas available for mining. Volumes are then
converted to tons by using an appropriate conversion factor.
Typically, 1.5 tons per cubic yard in the ground is used for sand
and gravel deposits.
Topography associated with the hard rock reserves is typically
much more diverse. Therefore, using available data, a final
topography map is created and computer software is utilized to
compute the volumes between the existing and final topographies.
Volumes are then converted to tons by using an appropriate
conversion factor. Typically, 2 tons per cubic yard in the ground
is used for hard rock quarries.
Estimated reserves are probable reserves as defined in
Securities Act Industry Guide 7. Remaining reserves are based on
estimates of volumes that can be economically extracted and sold to
meet current market and product applications. The reserve estimates
include only salable tonnage and thus exclude waste materials that
are generated in the crushing and processing phases of the
operation. Approximately 928 million tons of the 1.1 billion tons
of aggregate reserves are permitted reserves. The remaining
reserves are on properties that the Company expects will be
permitted for mining under current regulatory requirements. Some
sites have leases that expire prior to the exhaustion of the
estimated reserves. The estimated reserve life (years remaining)
anticipates that leases will be renewed to allow sufficient time to
fully recover these reserves. The data used to calculate the
remaining reserves may require revisions in the future to account
for changes in customer requirements and unknown geological
occurrences. The years remaining were calculated by dividing
remaining reserves by current year sales. Actual useful lives of
these reserves will be subject to, among other things, fluctuations
in customer demand, customer specifications, geological conditions
and changes in mining plans.
The following table sets forth details applicable to the
Company's aggregate reserves under ownership or lease and production
as of and for the years ended December 31, 2002, 2001 and 2000.
Number Number
of Sites of Sites Estimated
Production (Crushed Stone) (Sand & Gravel) Tons Sold (000's) Reserves Lease Reserve
Area owned leased owned leased 2000 2001 2002 (000's tons) Expiration Life (yrs)
Central MN --- --- 47 54 --- 3,860 6,236 105,078 2003-2014 17
Portland, OR 1 3 2 2 4,064 3,951 4,186 263,028 2005-2014 63
Northern CA --- --- 6 1 2,333 2,797 3,430 61,130 2046 18
Southwest OR 3 5 6 2 2,111 2,710 2,812 104,082 2003-2031 37
Eugene, OR 2 3 6 3 1,953 1,418 2,724 203,178 2003-2010 75
Hawaii --- 6 --- --- 1,065 1,528 2,688 73,680 2006-2038 27
Central MT --- --- 4 2 1,751 1,951 2,463 42,376 2003-2006 17
Anchorage, AK --- --- 1 --- 1,318 1,991 1,719 26,360 N/A 15
Northwest MT --- --- 7 2 542 1,197 1,260 24,214 2010-2020 19
Southern CA 2 --- --- --- 380 101 1,247 98,270 2035 79
Bend, OR --- 2 2 1 942 836 1,030 67,820 2010-2012 66
Northern MN 2 --- 20 28 --- --- 559 38,632 2004-2020 69
Casper, WY --- --- --- 1 --- 67 61 2,172 2006 36
Sales from
other sources 1,856 5,158 4,663 ---
18,315 27,565 35,078 1,110,020
c) Reference is made to Part I, Items 1 and 2 - Business and
Properties - Construction Materials and Mining - Consolidated
Construction Materials and Mining - Reserve Information in the
Company's Annual Report on Form 10-K for the year ended December 31,
2002.
As of December 31, 2002, Knife River had under ownership or
lease, recoverable lignite deposits of approximately 37.8 million
tons.
The sale of the Company's coal operations in 2001 included
active coal mines in North Dakota and Montana, coal sales
agreements, reserves and mining equipment, and certain development
rights at the Company's former Gascoyne Mine site in North Dakota.
The Company retained ownership of lignite deposits and leases at its
former Gascoyne Mine site in North Dakota, which were not part of
the sale of the coal operations. The Gascoyne Mine site was closed
in 1995 due to the cancellation of the coal sale contract. These
lignite deposits are currently not being mined and are not
associated with an operating mine. These lignite deposits are of a
high moisture content and it is not economical to mine and ship the
lignite to other distant markets. However, should a power plant be
constructed near the area, the Company may have the opportunity to
participate in supplying lignite to fuel a plant.
d) Reference is made to Part II, Item 7 - Management's
Discussion and Analysis of Financial Condition and Results of
Operations - Financial and Operating Data - Natural Gas and Oil
Production in the Company's Annual Report on Form 10-K for the
year ended December 31, 2002.
The following table includes revised key financial statistics
for the Company's natural gas and oil production segment:
Natural Gas and Oil Production
Years ended December 31,
2002 2001 2000
(In millions)
Operating revenues:
Natural gas $ 131.0 $ 153.2 $ 84.6
Oil 42.1 47.7 40.7
Other 30.5* 8.9 13.0
203.6 209.8 138.3
Operating expenses:
Purchased natural gas sold .1 2.8 3.4
Operation and maintenance:
Lease operating costs,
including gathering 39.8 33.6 21.1
Other 15.8 16.8 10.2
Depreciation, depletion and
amortization 48.7 41.7 27.0
Taxes, other than income:
Production and property
taxes 12.7 10.8 10.0
Other .9 .2 .1
118.0 105.9 71.8
Operating income $ 85.6 $ 103.9 $ 66.5
_____________________________
*Includes the effects of a nonrecurring compromise agreement of
$27.4 million ($16.6 million after tax) in the first quarter of
2002.
e) Reference is made to Part II, Item 8 - Financial Statements and
Supplementary Data in the Company's Annual Report on Form 10-K for
the year ended December 31, 2002, which incorporates by reference
the second table on page 78 of the Company's 2002 Annual Report to
shareholders under "Supplementary Financial Information - Natural
Gas and Oil Activities."
The following revised table reflects income resulting from the
Company's operations of natural gas and oil producing activities,
excluding corporate overhead and financing costs:
Years ended December 31, 2002* 2001 2000
(In thousands)
Revenues $200,607 $201,117 $125,391
Production costs 52,520 44,435 31,093
Depreciation, depletion and
amortization 48,064 41,223 26,739
Pretax income 100,023 115,459 67,559
Income tax expense 36,886 45,245 25,835
Results of operations for
producing activities $ 63,137 $ 70,214 $ 41,724
* Includes the compromise agreement as discussed in Note 17 of
Notes to Consolidated Financial Statements in the Company's Annual
Report on Form 10-K for the year ended December 31, 2002.
f) Reference is made to Part II, Item 8 - Financial Statements and
Supplementary Data in the Company's Annual Report on Form 10-K for
the year ended December 31, 2002, which incorporates by reference
the first table on page 79 of the Company's 2002 Annual Report to
shareholders under "Supplementary Financial Information - Natural
Gas and Oil Activities."
The following revised table reflects the standardized measure
of the Company's estimated discounted future net cash flows of total
proved reserves associated with its various natural gas and oil
interests at December 31:
2002 2001 2000
(In thousands)
Future cash inflows $1,726,000 $ 974,200 $3,069,100
Future production costs 513,200 361,600 661,400
Future development costs 61,200 64,600 58,200
Future net cash flows before
income taxes 1,151,600 548,000 2,349,500
Future income tax expense 324,000 112,000 827,000
Future net cash flows 827,600 436,000 1,522,500
10% annual discount for estimated
timing of cash flows 321,300 174,000 601,200
Discounted future net cash flows
relating to proved natural gas
and oil reserves $ 506,300 $ 262,000 $ 921,300
g) Reference is made to Part II, Item 8 - Financial Statements and
Supplementary Data in the Company's Annual Report on Form 10-K for
the year ended December 31, 2002, which incorporates by reference
the second table on page 79 of the Company's 2002 Annual Report to
shareholders under "Supplementary Financial Information - Natural
Gas and Oil Activities."
The following revised table reflects the sources of change in
the standardized measure of discounted future net cash flows by
year:
2002 2001 2000
(In thousands)
Beginning of year $ 262,000 $921,300 $229,100
Net revenues from production (112,900) (153,500) (94,300)
Change in net realization 296,100 (1,119,700) 861,700
Extensions, discoveries and
improved recovery, net of
future production-related costs 117,000 40,200 273,200
Purchases of proved reserves 3,700 2,600 93,200
Sales of reserves in place (8,900) --- (1,500)
Changes in estimated future
development costs (1,100) (6,700) (700)
Development costs incurred during
the current year 19,400 31,600 24,200
Accretion of discount 27,300 122,700 26,600
Net change in income taxes (124,700) 436,500 (412,300)
Revisions of previous quantity
estimates 30,000 (11,700) (79,200)
Other (1,600) (1,300) 1,300
Net change 244,300 (659,300) 692,200
End of year $ 506,300 $262,000 $921,300
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
a) Exhibits
10(a) Directors' Compensation Policy, as amended
10(b) Non-Employee Director Stock Compensation Plan, as amended
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 April 22, 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 April 22, 2003, regarding earnings for the quarter
ended March 31, 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: August 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.
10(a) Directors' Compensation Policy, as amended
10(b) Non-Employee Director Stock Compensation Plan, as amended
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