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