UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
X QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2004
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 April 28, 2004: 116,775,456 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 the financial condition of MDU Resources Group,
Inc. (Company). These other factors may impact the Company's
financial results in future periods.
- Acquisition, disposal and impairment of assets or facilities
- Changes in operation, performance and construction of plant
facilities or other assets
- 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, and/or available supplies of, energy
products
- Changes in tax rates or policies
- Unanticipated project delays or changes in project costs
- Unanticipated changes in operating expenses or capital
expenditures
- Labor negotiations or disputes
- Inflation rates
- Inability of the various contract counterparties to meet their
contractual obligations
- Changes in accounting principles and/or the application of such
principles to the Company
- Changes in technology
- Changes in legal proceedings
- The ability to effectively integrate the operations of acquired
companies
- Fluctuations in natural gas and crude oil prices
- Decline in general economic environment
- Changes in governmental regulation
- Changes in currency exchange rates
- Unanticipated increases in competition
- Variations in weather
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, development and production
activities, primarily in the Rocky Mountain region of the
United States and in and around the Gulf of Mexico.
Knife River mines aggregates and markets crushed stone,
sand, gravel and related construction materials, including
ready-mixed concrete, cement, asphalt and other value-added
products, as well as performs integrated construction
services, in the central and western United States and in
the states of Alaska and Hawaii.
Utility Services specializes in electrical line
construction, pipeline construction, inside electrical
wiring and cabling and the manufacture and distribution of
specialty equipment.
Centennial Resources owns electric generating facilities in
the United States and has investments in electric generating
facilities in Brazil and in The Republic of Trinidad and
Tobago (Trinidad and Tobago). Electric capacity and energy
produced at these facilities are primarily sold under long-
term contracts to nonaffiliated entities. Centennial
Resources also includes investments in opportunities that
are not directly being pursued by the Company's other
businesses, 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 various types of risks as a
captive insurer for certain of the Company's subsidiaries.
The function of the captive insurer is to fund the
deductible layers of the insured companies' general
liability and automobile liability coverages. Centennial
Capital also owns certain real and personal property and
contract rights. These activities are reflected in
independent power production and other.
On August 14, 2003, the Company's Board of Directors approved a
three-for-two common stock split. For more information on the
common stock split see Note 3 of Notes to Consolidated Financial
Statements.
INDEX
Part I -- Financial Information
Consolidated Statements of Income --
Three Months Ended March 31, 2004 and 2003
Consolidated Balance Sheets --
March 31, 2004 and 2003, and December 31, 2003
Consolidated Statements of Cash Flows --
Three Months Ended March 31, 2004 and 2003
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
Legal Proceedings
Changes in Securities and Use of Proceeds
Submission of Matters to a Vote of Security Holders
Exhibits and Reports on Form 8-K
Signatures
Exhibit Index
Exhibits
PART I -- FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
MDU RESOURCES GROUP, INC.
CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
Three Months Ended
March 31,
2004 2003
(In thousands, except
per share amounts)
Operating revenues:
Electric, natural gas distribution and
pipeline and energy services $231,848 $195,870
Utility services, natural gas and oil production,
construction materials and mining and other 283,611 271,883
515,459 467,753
Operating expenses:
Fuel and purchased power 16,725 15,407
Purchased natural gas sold 94,744 76,106
Operation and maintenance:
Electric, natural gas distribution and
pipeline and energy services 42,199 37,167
Utility services, natural gas and oil production,
construction materials and mining and other 246,372 222,378
Depreciation, depletion and amortization 49,511 44,065
Taxes, other than income 21,885 19,683
471,436 414,806
Operating income 44,023 52,947
Other income -- net 4,793 3,685
Interest expense 13,846 12,859
Income before income taxes 34,970 43,773
Income taxes 11,390 16,076
Income before cumulative effect of accounting change 23,580 27,697
Cumulative effect of accounting change (Note 14) --- (7,589)
Net income 23,580 20,108
Dividends on preferred stocks 172 187
Earnings on common stock $ 23,408 $ 19,921
Earnings per common share -- basic:
Earnings before cumulative effect of
accounting change $ .20 $ .25
Cumulative effect of accounting change --- (.07)
Earnings per common share -- basic $ .20 $ .18
Earnings per common share -- diluted:
Earnings before cumulative effect of
accounting change $ .20 $ .25
Cumulative effect of accounting change --- (.07)
Earnings per common share -- diluted $ .20 $ .18
Dividends per common share $ .17 $ .16
Weighted average common shares outstanding -- basic 114,658 110,318
Weighted average common shares outstanding -- diluted 115,709 111,094
Pro forma amounts assuming retroactive
application of accounting change:
Net income $ 23,580 $ 27,697
Earnings per common share -- basic $ .20 $ .25
Earnings per common share -- diluted $ .20 $ .25
The accompanying notes are an integral part of these consolidated financial
statements.
MDU RESOURCES GROUP, INC.
CONSOLIDATED BALANCE SHEETS
(Unaudited)
March 31, March 31, December 31,
2004 2003 2003
(In thousands, except shares
and per share amounts)
ASSETS
Current assets:
Cash and cash equivalents $ 113,183 $ 75,843 $ 86,341
Receivables, net 336,615 312,472 357,677
Inventories 108,694 89,893 114,051
Deferred income taxes 5,942 11,205 3,104
Prepayments and other current assets 61,586 42,424 52,367
626,020 531,837 613,540
Investments 68,680 42,777 44,975
Property, plant and equipment 3,470,472 3,127,926 3,397,619
Less accumulated depreciation,
depletion and amortization 1,212,923 1,064,362 1,175,326
2,257,549 2,063,564 2,222,293
Deferred charges and other assets:
Goodwill 198,737 190,908 199,427
Other intangible assets, net 193,995 185,273 193,454
Other 110,478 105,198 106,903
503,210 481,379 499,784
$3,455,459 $3,119,557 $3,380,592
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Short-term borrowings $ --- $ 12,500 $ ---
Long-term debt and preferred
stock due within one year 50,572 22,947 27,646
Accounts payable 135,015 137,370 150,316
Taxes payable 24,282 23,936 15,358
Dividends payable 20,024 17,971 19,442
Other accrued liabilities 128,435 108,620 101,299
358,328 323,344 314,061
Long-term debt 878,541 895,505 939,450
Deferred credits and other liabilities:
Deferred income taxes 459,111 369,010 444,779
Other liabilities 234,775 232,110 231,666
693,886 601,120 676,445
Preferred stock subject to mandatory
redemption --- 1,200 ---
Commitments and contingencies
Stockholders' equity:
Preferred stocks 15,000 15,000 15,000
Common stockholders' equity:
Common stock (Note 3)
Shares issued -- $1.00 par value
117,151,449 at March 31, 2004,
74,337,088 at March 31, 2003 and
113,716,632 at December 31, 2003 117,151 74,337 113,717
Other paid-in capital 831,677 750,244 757,787
Retained earnings 578,788 476,935 575,287
Accumulated other comprehensive loss (13,542) (14,502) (7,529)
Treasury stock at cost -
390,658 shares at March 31, 2004,
239,521 shares at March 31, 2003
and 359,281 shares at
December 31, 2003 (4,370) (3,626) (3,626)
Total common stockholders' equity 1,509,704 1,283,388 1,435,636
Total stockholders' equity 1,524,704 1,298,388 1,450,636
$3,455,459 $3,119,557 $3,380,592
The accompanying notes are an integral part of these consolidated financial
statements.
MDU RESOURCES GROUP, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Three Months Ended
March 31,
2004 2003
(In thousands)
Operating activities:
Net income $ 23,580 $ 20,108
Cumulative effect of accounting change --- 7,589
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation, depletion and amortization 49,511 44,065
Deferred income taxes 4,194 988
Changes in current assets and liabilities, net
of acquisitions:
Receivables 27,468 14,411
Inventories 8,942 3,826
Other current assets (11,087) (5,187)
Accounts payable (17,781) (657)
Other current liabilities 23,321 19,839
Other noncurrent changes (4,089) 5,081
Net cash provided by operating activities 104,059 110,063
Investing activities:
Capital expenditures (53,538) (63,735)
Acquisitions, net of cash acquired (5,167) (100,842)
Net proceeds from sale or disposition of property 4,614 3,644
Investments (21,548) 87
Proceeds from notes receivable 2,000 7,812
Net cash used in investing activities (73,639) (153,034)
Financing activities:
Net change in short-term borrowings --- (7,500)
Issuance of long-term debt 4,253 89,000
Repayment of long-term debt (42,467) (12,290)
Proceeds from issuance of common stock, net 54,078 19
Dividends paid (19,442) (17,971)
Net cash provided by (used in) financing activities (3,578) 51,258
Increase in cash and cash equivalents 26,842 8,287
Cash and cash equivalents -- beginning of year 86,341 67,556
Cash and cash equivalents -- end of period $113,183 $ 75,843
The accompanying notes are an integral part of these consolidated financial
statements.
MDU RESOURCES GROUP, INC.
NOTES TO CONSOLIDATED
FINANCIAL STATEMENTS
March 31, 2004 and 2003
(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, 2003
(2003 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 2003 Annual Report. The information is
unaudited but includes all adjustments that are, in the opinion
of management, necessary for a fair presentation of the
accompanying consolidated interim financial statements.
2. Seasonality of operations
Some of the Company's operations are highly seasonal and
revenues from, and certain expenses for, such operations may
fluctuate significantly among quarterly periods. Accordingly,
the interim results for particular businesses, and for the
Company as a whole, may not be indicative of results for the
full fiscal year.
3. Common stock split
On August 14, 2003, the Company's Board of Directors approved a
three-for-two common stock split to be effected in the form of
a 50 percent common stock dividend. The additional shares of
common stock were distributed on October 29, 2003, to common
stockholders of record on October 10, 2003. Common stock
information appearing in the accompanying consolidated
financial statements has been restated to give retroactive
effect to the stock split. Additionally, preference share
purchase rights have been appropriately adjusted to reflect the
effects of the split.
4. Allowance for doubtful accounts
The Company's allowance for doubtful accounts as of March 31,
2004 and 2003, and December 31, 2003, was $8.2 million,
$8.5 million and $8.1 million, respectively.
5. Earnings per common share
Basic earnings per common share were computed by dividing
earnings on common stock by the weighted average number of
shares of common stock outstanding during the applicable
period. Diluted earnings per common share were computed by
dividing earnings on common stock by the total of the weighted
average number of shares of common stock outstanding during the
applicable period, plus the effect of outstanding stock
options, restricted stock grants and performance share awards.
For the three months ended March 31, 2004 and 2003, 209,805
shares and 3,571,770 shares, respectively, with an average
exercise price of $24.56 and $20.07, respectively, attributable
to the exercise of outstanding stock options, were excluded
from the calculation of diluted earnings per share because
their effect was antidilutive. For the three months ended
March 31, 2004 and 2003, no adjustments were made to reported
earnings in the computation of earnings per share. Common
stock outstanding includes issued shares less shares held in
treasury.
6. Stock-based compensation
The Company has stock option plans for directors, key employees
and employees. In the third quarter of 2003, the Company
adopted the fair value recognition provisions of Statement of
Financial Accounting Standards (SFAS) No. 123, "Accounting for
Stock-Based Compensation," and began expensing the fair market
value of stock options for all awards granted on or after
January 1, 2003. Compensation expense recognized for awards
granted on or after January 1, 2003, for the three months ended
March 31, 2004, was $3,000 (after tax).
As permitted by SFAS No. 148, "Accounting for Stock-Based
Compensation - Transition and Disclosure - an amendment of SFAS
No. 123," the Company accounts for stock options granted prior
to January 1, 2003, under APB Opinion No. 25, "Accounting for
Stock Issued to Employees." No compensation expense has been
recognized for stock options granted prior to January 1, 2003,
as the options granted had an exercise price equal to the
market value of the underlying common stock on the date of the
grant.
Since the Company adopted SFAS No. 123 effective January 1,
2003, for newly granted options only, the following table
illustrates the effect on earnings and earnings per common
share for the three months ended March 31, 2004 and 2003, as if
the Company had applied SFAS No. 123 and recognized
compensation expense for all outstanding and unvested stock
options based on the fair value at the date of grant:
Three Months Ended
March 31,
2004 2003
(In thousands, except
per share amounts)
Earnings on common stock, as
reported $ 23,408 $ 19,921
Stock-based compensation expense
included in reported earnings,
net of related tax effects 3 ---
Total stock-based compensation
expense determined under fair
value method for all awards,
net of related tax effects (92) (590)
Pro forma earnings on common stock $ 23,319 $ 19,331
Earnings per common share -- basic --
as reported:
Earnings before cumulative effect
of accounting change $ .20 $ .25
Cumulative effect of accounting
change --- (.07)
Earnings per common share -- basic $ .20 $ .18
Earnings per common share -- basic --
pro forma:
Earnings before cumulative effect
of accounting change $ .20 $ .24
Cumulative effect of accounting
change --- (.07)
Earnings per common share -- basic $ .20 $ .17
Earnings per common share -- diluted
-- as reported:
Earnings before cumulative effect
of accounting change $ .20 $ .25
Cumulative effect of accounting
change --- (.07)
Earnings per common share --
diluted $ .20 $ .18
Earnings per common share -- diluted
-- pro forma:
Earnings before cumulative effect
of accounting change $ .20 $ .24
Cumulative effect of accounting
change --- (.07)
Earnings per common share --
diluted $ .20 $ .17
7. Cash flow information
Cash expenditures for interest and income taxes were as
follows:
Three Months Ended
March 31,
2004 2003
(In thousands)
Interest, net of amount capitalized $ 8,520 $8,667
Income taxes (refunded) paid, net $(1,267) $ 563
8. Reclassifications
Certain reclassifications have been made in the financial
statements for the prior year to conform to the current
presentation. Such reclassifications had no effect on net
income or stockholders' equity as previously reported.
9. New accounting standards
In December 2003, the FASB issued FASB Interpretation No. 46
(revised December 2003), "Consolidation of Variable Interest
Entities" (FIN 46 (revised)), which replaced FASB
Interpretation No. 46, "Consolidation of Variable Interest
Entities" (FIN 46). FIN 46 (revised) 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. An enterprise shall consolidate a
variable interest entity if that enterprise is the primary
beneficiary. An enterprise is considered the primary
beneficiary if it has a variable interest that will absorb a
majority of the entity's expected losses, receive a majority of
the entity's expected residual returns or both. FIN 46
(revised) shall be applied to all entities subject to FIN 46
(revised) no later than the end of the first reporting period
that ends after March 15, 2004.
The Company evaluated the provisions of FIN 46 (revised) and
determined that the Company does not have any controlling
financial interests in any variable interest entities and,
therefore, is not required to consolidate any variable interest
entities in its financial statements. The adoption of FIN 46
(revised) did not have an effect on the Company's financial
position or results of operations.
In January 2004, the FASB issued FASB Staff Position No. FAS
106-1, "Accounting and Disclosure Requirements Related to the
Medicare Prescription Drug, Improvement and Modernization Act
of 2003." FASB Staff Position No. FAS 106-1 permits a sponsor
of a postretirement health care plan that provides a
prescription drug benefit to make a one-time election to defer
accounting for the effects of the Medicare Prescription Drug,
Improvement and Modernization Act of 2003 (2003 Medicare Act).
SFAS No. 106, "Employers' Accounting for Postretirement
Benefits Other than Pensions," requires enacted changes in
relevant laws to be considered in current period measurements
of postretirement benefit costs and accumulated postretirement
benefit obligation. The Company provides prescription drug
benefits to certain eligible employees and has elected the one-
time deferral of accounting for the effects of the 2003
Medicare Act. These consolidated financial statements and
accompanying notes do not reflect the effects of the 2003
Medicare Act on the postretirement benefit plans. The Company
is currently analyzing the 2003 Medicare Act, along with
proposed authoritative guidance, to determine if its benefit
plans need to be amended and how to record the effects of the
2003 Medicare Act. Final guidance on the accounting for the
federal subsidy provided by the 2003 Medicare Act is pending
and that guidance, when issued, could require the Company to
change certain previously reported postretirement benefit
information.
SFAS No. 142, "Goodwill and Other Intangible Assets,"
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, "Business
Combinations," and SFAS No. 142 clarify that more assets should
be distinguished and classified between tangible and
intangible. The Company did not change or reclassify
contractual mineral rights included in property, plant and
equipment related to its natural gas and oil production
business upon adoption of SFAS No. 142. The Company has
included such mineral rights as part of property, plant and
equipment under the full-cost method of accounting for natural
gas and oil properties. An issue has arisen within the natural
gas and oil industry as to whether contractual mineral rights
under SFAS No. 142 should be classified as intangible rather
than as part of property, plant and equipment. This accounting
matter is anticipated to be addressed by the FASB's Emerging
Issues Task Force during 2004. The resolution of this matter
may result in certain reclassifications of amounts in the
Consolidated Balance Sheets, as well as changes to Notes to
Consolidated Financial Statements in the future. The
applicable provisions of SFAS No. 141 and SFAS No. 142 only
affect the balance sheet and associated footnote disclosure, so
any reclassifications that might be required in the future will
not affect the Company's cash flows or results of operations.
The Company believes that the resolution of this matter will
not have a material effect on the Company's financial position
because the mineral rights acquired by its natural gas and oil
production business after the June 30, 2001, effective date of
SFAS No. 142 were not material.
In April 2004, the FASB issued FASB Staff Position Nos. FAS 141-
1 and FAS 142-1, "Interaction of FASB Statements No. 141,
'Business Combinations,' and No. 142, 'Goodwill and Other
Intangible Assets,' and EITF Issue No. 04-2, 'Whether Mineral
Rights are Tangible or Intangible Assets,'" (FAS 141-1 and FAS
142-1). FAS 141-1 and FAS 142-1 amend SFAS No. 141 and SFAS
No. 142 to clarify that certain mineral rights held by mining
entities that are not within the scope of SFAS No. 19,
"Financial Accounting and Reporting by Oil and Gas Producing
Companies," be classified as tangible assets rather than
intangible assets. FAS 141-1 and FAS 142-1 shall be applied to
the first reporting period beginning after April 29, 2004. The
Company has included such mineral rights at its construction
materials and mining business in other intangible assets, net
as of March 31, 2004. FAS 141-1 and FAS 142-1 will require
reclassification of the Company's leasehold rights at its
construction materials and mining operations from other
intangible assets, net to property, plant and equipment, as
well as changes to Notes to Consolidated Financial Statements.
FAS 141-1 and FAS 142-1 will only affect the balance sheet and
associated footnote disclosure, so the reclassifications will
not affect the Company's cash flows or results of operations.
The Company's leasehold rights, net of accumulated amortization
(included in other intangible assets, net on the Consolidated
Balance Sheets), are $174.2 million at March 31, 2004, $164.2
million at March 31, 2003, and $174.6 million at December 31,
2003.
10. Comprehensive income
Comprehensive income is the sum of net income as reported and
other comprehensive income (loss). The Company's other
comprehensive loss resulted from losses on derivative
instruments qualifying as hedges and foreign currency
translation adjustments.
Comprehensive income, and the components of other comprehensive
loss and related tax effects, were as follows:
Three Months Ended
March 31,
2004 2003
(In thousands)
Net income $ 23,580 $ 20,108
Other comprehensive loss:
Net unrealized loss on
derivative instruments qualifying
as hedges:
Net unrealized loss on
derivative instruments arising
during the period, net of tax of
$3,636 and $3,541 in 2004 and 2003,
respectively (5,687) (5,538)
Less: Reclassification adjustment
for loss on derivative instruments
included in net income, net of tax
of $470 and $716 in 2004 and
2003, respectively (735) (1,120)
Net unrealized loss on
derivative instruments qualifying
as hedges (4,952) (4,418)
Foreign currency translation
adjustment (1,061) (280)
(6,013) (4,698)
Comprehensive income $ 17,567 $ 15,410
11. Equity method investments
The Company has a number of equity method investments,
including MPX Participacoes, Ltda. (MPX) and Carib Power
Management LLC (Carib Power).
MPX was formed in August 2001 when MDU Brasil Ltda. (MDU
Brasil), an indirect wholly owned Brazilian subsidiary of the
Company, entered into a joint venture agreement with a
Brazilian firm. MDU Brasil has a 49 percent interest in MPX.
MPX, through a wholly owned subsidiary, owns a 220-megawatt
natural gas-fired electric generating facility (Brazil
Generating Facility) in the Brazilian state of Ceara.
Petrobras, the Brazilian state-controlled energy company, has
agreed to purchase all of the capacity and market all of the
Brazil Generating Facility's energy. The power purchase
agreement with Petrobras expires in May 2008. Petrobras also
is under contract to supply natural gas to the Brazil
Generating Facility during the term of the power purchase
agreement. This natural gas supply contract is renewable by a
wholly owned subsidiary of MPX for an additional 13 years. The
Brazil Generating Facility generates energy based upon economic
dispatch and available gas supplies. Under current conditions,
including, in particular, existing constraints in the region's
gas supply infrastructure, the Company does not expect the
facility to generate a significant amount of energy at least
through 2006.
The functional currency for the Brazil Generating Facility 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. The
Company's 49 percent share of the loss from the change in the
fair value of the embedded derivative in the power purchase
agreement was $29,000 and $1.5 million (after tax) for the
three months ended March 31, 2004 and 2003, respectively. The
Company's 49 percent share of the foreign currency loss
resulting from the devaluation of the Brazilian real was
$159,000 (after tax) for the three months ended March 31, 2004.
The Company's 49 percent share of the foreign currency gain
resulting from revaluation of the Brazilian real was $902,000
(after tax) for the three months ended March 31, 2003.
In February 2004, Centennial Energy Resources International,
Inc. (Centennial International), an indirect wholly owned
subsidiary of the Company, acquired 49.9 percent of Carib
Power. Carib Power, through a wholly owned subsidiary, owns a
225-megawatt natural gas-fired electric generating facility
located in Trinidad and Tobago (Trinidad and Tobago Generating
Facility). The functional currency for the Trinidad and Tobago
Generating Facility is the U.S. dollar.
At March 31, 2004, total assets and long-term debt of MPX and
Carib Power were $204.6 million and $161.3 million,
respectively. The Company's investment in the Brazil and
Trinidad and Tobago Generating Facilities was approximately
$39.3 million, including undistributed earnings of $7.6 million
at March 31, 2004. The Company's investment in the Brazil
Generating Facility was approximately $20.5 million at
March 31, 2003, and $25.2 million, including undistributed
earnings of $4.6 million at December 31, 2003.
The Company's share of income from its equity method
investments, including MPX and Carib Power, was $3.4 million
and $1.0 million for the three months ended March 31, 2004 and
2003, respectively, and was included in other income - net.
12. Goodwill and other intangible assets
The changes in the carrying amount of goodwill were as follows:
Balance Goodwill Balance
as of Acquired as of
Three Months January 1, During March 31,
Ended March 31, 2004 2004 the Year* 2004
(In thousands)
Electric $ --- $ --- $ ---
Natural gas
distribution --- --- ---
Utility services 62,604 --- 62,604
Pipeline and energy
services 9,494 --- 9,494
Natural gas and oil
production --- --- ---
Construction materials
and mining 120,198 (690) 119,508
Independent power
production and other 7,131 --- 7,131
Total $ 199,427 $ (690) $ 198,737
Balance Goodwill Balance
as of Acquired as of
Three Months January 1, During March 31,
Ended March 31, 2003 2003 the Year* 2003
(In thousands)
Electric $ --- $ --- $ ---
Natural gas
distribution --- --- ---
Utility services 62,487 83 62,570
Pipeline and energy
services 9,494 --- 9,494
Natural gas and oil
production --- --- ---
Construction materials
and mining 111,887 (174) 111,713
Independent power
production and other 7,131 --- 7,131
Total $ 190,999 $ (91) $ 190,908
Balance Goodwill Balance
as of Acquired as of
Year Ended January 1, During December 31,
December 31, 2003 2003 the Year* 2003
(In thousands)
Electric $ --- $ --- $ ---
Natural gas
distribution --- --- ---
Utility services 62,487 117 62,604
Pipeline and energy
services 9,494 --- 9,494
Natural gas and oil
production --- --- ---
Construction materials
and mining 111,887 8,311 120,198
Independent power
production and other 7,131 --- 7,131
Total $ 190,999 $ 8,428 $ 199,427
__________________
* Includes purchase price adjustments related to acquisitions
acquired in a prior period.
Other intangible assets were as follows:
March 31, March 31, December 31,
2004 2003 2003
(In thousands)
Amortizable intangible assets:
Leasehold rights $ 186,445 $172,464 $186,419
Accumulated amortization (12,273) (8,274) (11,779)
174,172 164,190 174,640
Noncompete agreements 10,275 12,075 12,075
Accumulated amortization (7,957) (9,477) (9,690)
2,318 2,598 2,385
Other 19,308 17,733 17,734
Accumulated amortization (2,763) (713) (2,265)
16,545 17,020 15,469
Unamortizable intangible
assets 960 1,465 960
Total $ 193,995 $185,273 $193,454
Acquired aggregate reserves at our construction materials and
mining business are classified based on type of ownership.
Owned mineral rights are classified as property, plant and
equipment, whereas leased mineral rights are classified as
leasehold rights in other intangible assets, net.
The unamortizable intangible assets were recognized in
accordance with SFAS No. 87, "Employers' Accounting for
Pensions," which requires that if an additional minimum
liability is recognized an equal amount shall be recognized as
an intangible asset, provided that the asset recognized shall
not exceed the amount of unrecognized prior service cost. The
unamortizable intangible asset will be eliminated or adjusted
as necessary upon a new determination of the amount of
additional liability.
Amortization expense for amortizable intangible assets for the
three months ended March 31, 2004 and 2003, and for the year
ended December 31, 2003, was $1.1 million, $1.2 million and
$5.9 million, respectively. Estimated amortization expense for
amortizable intangible assets is $6.7 million in 2004,
$5.9 million in 2005, $5.6 million in 2006, $5.0 million in
2007, $5.1 million in 2008 and $165.8 million thereafter.
13. 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 2003 Annual Report.
As of March 31, 2004, Fidelity Exploration & Production Company
(Fidelity), an indirect wholly owned subsidiary of the Company,
held derivative instruments designated as cash flow hedging
instruments.
Hedging activities
Fidelity 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. Each of the natural gas and oil price swap and
collar agreements was designated as a hedge of the forecasted
sale of natural gas and oil production.
For the three months ended March 31, 2004 and 2003, the amount
of hedge ineffectiveness recognized, which was included in
operating revenues, was immaterial. For the three months ended
March 31, 2004 and 2003, the subsidiary did not exclude any
components of the derivative instruments' gain or loss from the
assessment of hedge effectiveness and there were no
reclassifications into earnings as a result of the
discontinuance of hedges.
Gains and losses on derivative instruments that are
reclassified from accumulated other comprehensive income (loss)
to current-period earnings are included in the line item in
which the hedged item is recorded. As of March 31, 2004, 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 21 months. The subsidiary of the Company
estimates that over the next 12 months net losses of
approximately $7.3 million 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.
14. Asset retirement obligations
The Company adopted SFAS No. 143, "Accounting for Asset
Retirement Obligations," 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.
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. The independent power production and other operations
do not individually meet the criteria to be considered a
reportable segment.
The vast majority of the Company's operations are located
within the United States. The Company also has investments in
foreign countries, which largely consist of investments in
natural gas-fired electric generating facilities in Brazil and
in Trinidad and Tobago, as discussed in Note 11. 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 specializes in electrical line construction, pipeline
construction, inside electrical wiring and cabling and the
manufacture and distribution of specialty equipment. 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, development and production
activities, primarily in the Rocky Mountain region of the
United States and in and around the Gulf of Mexico. The
construction materials and mining segment mines aggregates and
markets crushed stone, sand, gravel and related construction
materials, including ready-mixed concrete, cement, asphalt and
other value-added products, as well as performs integrated
construction services, in the central and western United States
and in the states of Alaska and Hawaii. The independent power
production and other operations own electric generating
facilities in the United States and have investments in
electric generating facilities in Brazil and in Trinidad and
Tobago. Electric capacity and energy produced at these
facilities are primarily sold under long-term contracts to
nonaffiliated entities. These operations also include
investments in 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 2003 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 March 31, 2004
Electric $ 46,989 $ --- $ 3,408
Natural gas distribution 128,320 --- 2,323
Pipeline and energy
services 56,539 27,613 2,683
231,848 27,613 8,414
Utility services 100,251 --- (1,901)
Natural gas and oil
production 37,507 43,462 25,260
Construction materials
and mining 139,446 --- (11,881)
Independent power
production and other 6,407 919 3,516
283,611 44,381 14,994
Intersegment eliminations --- (71,994) ---
Total $ 515,459 $ --- $ 23,408
Inter-
External segment Earnings
Operating Operating on Common
Revenues Revenues Stock
(In thousands)
Three Months
Ended March 31, 2003
Electric $ 45,671 $ --- $ 4,817
Natural gas distribution 110,987 --- 4,245
Pipeline and energy
services 39,212 21,919 4,311
195,870 21,919 13,373
Utility services 103,663 --- 1,110
Natural gas and oil
production 41,118 27,905 11,666
Construction materials
and mining 120,753 --- (7,440)
Independent power
production and other 6,349 740 1,212
271,883 28,645 6,548
Intersegment eliminations --- (50,564) ---
Total $ 467,753 $ --- $ 19,921
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 three months of 2004, the Company acquired a
number of businesses, none of which was individually material,
including construction materials and mining businesses in Iowa
and Minnesota. The total purchase consideration for these
businesses and purchase price adjustments with respect to
certain other acquisitions acquired prior to 2004, including the
Company's common stock and cash, was $24.8 million.
The above acquisitions were accounted for under the purchase
method of accounting and, accordingly, the acquired assets and
liabilities assumed have been preliminarily recorded at their
respective fair values as of the date of acquisition. Final
fair market values are pending the completion of the review of
the relevant assets, liabilities and issues identified as of the
acquisition date. The results of operations of the acquired
businesses are included in the financial statements since the
date of each acquisition. Pro forma financial amounts
reflecting the effects of the above acquisitions are not
presented, as such acquisitions were not material to the
Company's financial position or results of operations.
17. Employee benefit plans
The Company has noncontributory defined benefit pension plans
and other postretirement benefit plans for certain eligible
employees. Components of net periodic benefit cost (income)
for the Company's pension and other postretirement benefit
plans were as follows:
Other
Pension Postretirement
Three Months Benefits Benefits
Ended March 31 2004 2003 2004 2003
(In thousands)
Components of net periodic
benefit cost (income):
Service cost $ 1,849 $ 1,432 $ 583 $ 442
Interest cost 3,941 3,794 1,324 1,247
Expected return on
assets (5,087) (5,225) (993) (981)
Amortization of prior
service cost 278 285 --- ---
Recognized net actuarial
(gain) loss 247 (68) (55) (130)
Amortization of net
transition obligation
(asset) (63) (237) 526 538
Net periodic benefit cost
(income) 1,165 (19) 1,385 1,116
Less amount capitalized 74 (11) 102 80
Net periodic benefit cost
(income) $ 1,091 $ (8) $1,283 $1,036
As of March 31, 2004, approximately $400,000 has been
contributed to the defined benefit pension plans and
approximately $1.2 million has been contributed to the
postretirement benefit plans. The Company presently
anticipates contributing an additional $1.2 million to its
pension plans in 2004 for a total of $1.6 million for the year.
The Company presently anticipates contributing an additional
$3.8 million to its postretirement benefit plans for a total of
$5.0 million for the year.
In addition to the qualified plan defined pension benefits
reflected in the table above, the Company also has an unfunded,
nonqualified benefit plan for executive officers and certain
key management employees that provides for defined benefit
payments upon the employee's retirement or to their
beneficiaries upon death for a 15-year period or as an
equivalent life annuity. The Company's net periodic benefit
cost for this plan for the three months ended March 31, 2004
and 2003, was $1.5 million and $1.2 million, respectively.
18. Regulatory matters and revenues subject to refund
On April 1, 2004, Montana-Dakota filed an application with the
Montana Public Service Commission (MTPSC) for a natural gas
rate increase. Montana-Dakota requested a total of $1.5
million annually or 1.8 percent above current rates. Montana-
Dakota requested an interim increase of $500,000 annually to be
effective within 30 days of the filing of the natural gas rate
increase. A final order from the MTPSC is due January 1, 2005.
On March 3, 2004, Montana-Dakota filed an application with the
North Dakota Public Service Commission (NDPSC) for a natural
gas rate increase. Montana-Dakota requested a total of $3.3
million annually or 2.8 percent above current rates. The
natural gas rate increase application included an interim
increase of $1.9 million annually to be effective within 60
days of the filing of the natural gas rate increase. On April
26, 2004, Montana-Dakota filed an amendment to its request for
interim rate increase requesting an interim increase of $1.7
million annually. On April 27, 2004, the NDPSC issued an Order
approving Montana-Dakota's interim rate increase of $1.7
million annually effective for service rendered on or after May
3, 2004. Montana-Dakota began collecting such rates effective
May 3, 2004, subject to refund until the NDPSC issues a final
order. A final order from the NDPSC is due October 3, 2004.
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. In July 2003, the FERC issued
its Order on Initial Decision. The Order on Initial Decision
affirmed the ALJ's Initial Decision on many of the issues
including rate base and certain cost of service items as well
as volumes to be used for purposes of cost recovery, and cost
allocation and rate design. However, there are other issues as
to which the FERC differed with the ALJ including return on
common equity and the correct level of corporate overhead
expense. In August 2003, Williston Basin requested rehearing
of a number of issues including determinations associated with
cost of service, throughput, and cost allocation and rate
design, as discussed in the FERC's Order on Initial Decision.
In September 2003, the FERC issued an Order granting Williston
Basin's request for rehearing of the July 2003, Order on
Initial Decision. The Company is awaiting a decision from the
FERC on the merits of the Company's rehearing request but is
unable to predict the timing of the FERC's decision.
Reserves have been provided for a portion of the revenues that
have been collected subject to refund with respect to Williston
Basin's pending regulatory proceeding. Williston Basin
believes that such reserves are adequate based on its
assessment of the ultimate outcome of the proceeding.
19. Contingencies
Litigation
In June 1997, Jack J. Grynberg (Grynberg) filed a Federal False
Claims Act Suit against Williston Basin and Montana-Dakota and
filed over 70 similar suits against natural gas transmission
companies and producers, gatherers, and processors of natural
gas. 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 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.
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 believe the
claims of Grynberg are without merit and intend to vigorously
contest this suit. Williston Basin and Montana-Dakota believe
it is not probable that Grynberg will ultimately succeed given
the current status of the litigation.
Fidelity has been named as a defendant in, and/or certain of
its operations are the subject of, 13 lawsuits filed in
connection with its coalbed natural gas development in the
Powder River Basin in Montana and Wyoming. These lawsuits were
filed in federal and state courts in Montana between June 2000
and April 2004 by a number of environmental organizations,
including the Northern Plains Resource Council and the Montana
Environmental Information Center as well as the Tongue River
Water Users' Association and the Northern Cheyenne Tribe.
Portions of two of the lawsuits have been transferred to
Federal District Court in Wyoming. The lawsuits involve
allegations that Fidelity and/or various government agencies
are in violation of state and/or federal law, including the
Federal Clean Water Act and the National Environmental Policy
Act. The lawsuits seek injunctive relief, invalidation of
various permits and unspecified damages. Fidelity is unable to
quantify the damages sought in any of these cases, and will be
unable to do so until after completion of discovery in the
separate cases. Fidelity is vigorously defending all coalbed-
related lawsuits in which it is involved. If the plaintiffs
are successful in these lawsuits, the ultimate outcome of the
actions could have a material effect on Fidelity's existing
coalbed natural gas operations and/or the future development of
its coalbed natural gas properties.
Montana-Dakota has joined with two electric generators in
appealing a finding by the North Dakota Department of Health
(Department) in September 2003 that the Department may
unilaterally revise operating permits previously issued to
electric generating plants. Although it is doubtful that any
revision of Montana-Dakota's operating permits by the
Department would reduce the amount of electricity its plants
could generate, the finding, if allowed to stand, could
increase costs for sulfur dioxide removal and/or limit Montana-
Dakota's ability to modify or expand operations at its North
Dakota generation sites. Montana-Dakota and the other electric
generators filed their appeal of the order in October 2003, in
the Burleigh County District Court in Bismarck, North Dakota.
Proceedings have been stayed pending discussions with the
United States Environmental Protection Agency (EPA), the
Department and the other electric generators.
In a related case, the Dakota Resource Council filed an action
in Federal District Court in Denver, Colorado, in September
2003, to require the EPA to enforce certain air quality
standards in North Dakota. If successful, the action could
require the curtailment of discharges of sulfur dioxide into
the atmosphere by existing electric generating facilities and
could preclude or hinder the construction of future generating
facilities in North Dakota. The Company has filed a Motion to
Intervene in the lawsuit and has joined in a brief supporting a
Motion to Dismiss filed by the EPA. The EPA Motion to Dismiss
was granted on April 1, 2004.
The Company cannot predict the outcome of the Department or
Dakota Resource Council matters or their ultimate impact on its
operations.
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 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 10 entities which does not include MBI. The
LWG estimates the overall remedial investigation and
feasibility study will cost approximately $10 million. It is
not possible to estimate the cost of a corrective action plan
until the remedial investigation and feasibility study has been
completed, the EPA has decided on a strategy, and a record of
decision has been published. While the remedial investigation
and feasibility study for the harbor site has commenced, it is
expected to take several years to complete. The development of
a proposed plan and record of decision on the harbor site is
not anticipated to occur until 2006, after which a cleanup plan
will be undertaken.
Based upon a review of the Portland Harbor sediment
contamination evaluation by the DEQ and other information
available, MBI does not believe it is a Responsible Party. In
addition, MBI has notified Georgia-Pacific West, Inc., the
seller of the commercial property site to MBI, that it intends
to seek indemnity for any and all liabilities incurred in
relation to the above matters, pursuant to the terms of their
sale agreement.
The Company believes it is not probable that it will incur any
material environmental remediation costs or damages in relation
to the above administrative action.
Guarantees
Centennial has unconditionally guaranteed a portion of certain
bank borrowings of MPX in connection with the Company's equity
method investment in the natural gas-fired electric generating
facility in Brazil, as discussed in Note 11. The Company,
through MDU Brasil, owns 49 percent of MPX. The main business
purpose of Centennial extending the guarantee to MPX's
creditors is to enable MPX to obtain lower borrowing costs. At
March 31, 2004, the aggregate amount of borrowings outstanding
subject to these guarantees was $40.0 million and the scheduled
repayment of these borrowings is $5.4 million in 2004, $10.7
million in 2005, $10.7 million in 2006, $10.7 million in 2007
and $2.5 million in 2008. The individual investor (who through
EBX Empreendimentos Ltda. (EBX), a Brazilian company, owns 51
percent of MPX) has also guaranteed these loans. In the event
MPX defaults under its obligation, Centennial and the
individual investor would be required to make payments under
their guarantees. Centennial and the individual investor have
entered into reimbursement agreements under which they have
agreed to reimburse each other to the extent they may be
required to make any guarantee payments in excess of their
proportionate ownership share in MPX. These guarantees are not
reflected on the Consolidated Balance Sheets.
In addition, WBI Holdings has guaranteed certain of its
subsidiary's natural gas and oil price swap and collar
agreement obligations. The amount of the subsidiary's
obligation at March 31, 2004, was $5.0 million. There is no
fixed maximum amount guaranteed in relation to the natural gas
and oil price collar agreements, as the amount of the
obligation is dependent upon natural gas and oil commodity
prices. The amount of hedging activity entered into by the
subsidiary is limited by corporate policy. The guarantees of
the natural gas and oil price swap and collar agreements at
March 31, 2004, expire in 2004 and 2005; however, the
subsidiary continues to enter into additional hedging
activities and, as a result, WBI Holdings from time to time may
issue additional guarantees on these hedging obligations. At
March 31, 2004, the amount outstanding was 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. These guarantees are related to
natural gas transportation and sales agreements, electric power
supply agreements, insurance policies and certain other
guarantees. At March 31, 2004, the fixed maximum amounts
guaranteed under these agreements aggregated $53.2 million.
The amounts of scheduled expiration of the maximum amounts
guaranteed under these agreements aggregate $7.5 million in
2004; $24.9 million in 2005; $3.8 million in 2006; $545,000 in
2007; $911,000 in 2009; $12.0 million in 2012; $500,000, which
is subject to expiration 30 days after the receipt of written
notice; and $3.0 million, which has no scheduled maturity date.
The amount outstanding by subsidiaries of the Company under the
above guarantees was $355,000 and was reflected on the
Consolidated Balance Sheets at March 31, 2004. In the event of
default under these guarantee obligations, the subsidiary
issuing the guarantee for that particular obligation would be
required to make payments under its guarantee.
Fidelity and WBI Holdings have outstanding guarantees to
Williston Basin. These guarantees are related to natural gas
transportation and storage agreements that guarantee the
performance of Prairielands Energy Marketing, Inc.
(Prairielands), an indirect wholly owned subsidiary of the
Company. At March 31, 2004, the fixed maximum amounts
guaranteed under these agreements aggregated $22.9 million.
Scheduled expiration of the maximum amounts guaranteed under
these agreements aggregate $2.9 million in 2005 and $20.0
million in 2009. In the event of Prairielands' default in its
payment obligations, the entity 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 $1.3 million, which was not reflected
on the Consolidated Balance Sheets at March 31, 2004, because
these intercompany transactions are eliminated in
consolidation.
In addition, Centennial has issued guarantees related to the
Company's purchase of maintenance items to third parties for
which no fixed maximum amounts have been specified. These
guarantees have no scheduled maturity date. In the event a
subsidiary of the Company defaults under its obligation in
relation to the purchase of certain maintenance items,
Centennial would be required to make payments under these
guarantees. Any amounts outstanding by subsidiaries of the
Company for these maintenance items were reflected on the
Consolidated Balance Sheets at March 31, 2004.
As of March 31, 2004, Centennial was contingently liable for
performance of certain of its subsidiaries under approximately
$277 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. The purpose of
Centennial's indemnification is to allow the subsidiaries to
obtain bonding at competitive rates. In the event a subsidiary
of the Company does not fulfill its obligations in relation to
its bonded contract or obligation, Centennial may be required
to make payments under its indemnification. A large portion of
these contingent commitments are expected to expire within the
next 12 months; however, Centennial will likely continue to
enter into surety bonds for its subsidiaries in the future.
The surety bonds were not reflected on the Consolidated Balance
Sheets.
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
Overview
This subsection of Item 2 -- Management's Discussion and Analysis of
Financial Condition and Results of Operations (Management's
Discussion and Analysis) is a brief overview of the important
factors that management focuses on in evaluating the Company's
businesses, the Company's financial condition and operating
performance, the Company's overall business strategy and the
earnings of the Company for the period covered by this report. This
subsection is not intended to be a substitute for reading the entire
Management's Discussion and Analysis section. Reference is made to
the various important factors listed under the heading Risk Factors
and Cautionary Statements that May Affect Future Results, as well as
other factors that are listed in the Introduction in relation to any
forward-looking statement.
Business and Strategy Overview
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. The independent power production and other operations
do not individually meet the criteria to be considered a reportable
segment.
The electric segment includes the electric generation, transmission
and distribution operations of Montana-Dakota. The natural gas
distribution segment includes the natural gas distribution
operations of Montana-Dakota and 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, development and production operations
of WBI Holdings. The construction materials and mining segment
includes the results of Knife River's operations. Independent power
production and other operations own electric generating facilities
in the United States and have investments in electric generating
facilities in Brazil and Trinidad and Tobago and investments in
opportunities that are not directly being pursued by the Company's
other businesses.
Earnings from electric, natural gas distribution, and pipeline and
energy services are substantially all from regulated operations.
Earnings from utility services, natural gas and oil production,
construction materials and mining, and independent power production
and other are all from nonregulated operations.
On August 14, 2003, the Company's Board of Directors approved a
three-for-two common stock split. For more information on the
common stock split, see Note 3 of Notes to Consolidated Financial
Statements.
The Company's strategy is to pursue growth opportunities by
expanding upon its expertise in energy and transportation
infrastructure industries, focusing on acquiring and developing well-
managed companies and projects that enhance shareholder value and
are accretive to earnings per share and returns on invested
capital.
The Company's long-term compound annual growth goals on earnings per
share from operations are in the range of 6 percent to 9 percent.
In addition, earnings per share for 2004, diluted, are projected in
the range of $1.60 to $1.75. Contributing to the anticipated growth
goals and/or earnings per share projections are a number of items
including:
- An expected return in 2004 at the electric business that is
anticipated to be generally consistent with overall authorized
levels.
- Anticipated natural gas rate increases that offset higher
expected operating costs at the natural gas distribution business.
- Anticipated increased margins in 2004 compared to 2003 at the
utility services business.
- An expected increase of total natural gas throughput of
approximately 20 percent to 25 percent over 2003 levels at the
pipeline and energy services business, largely due to the Grasslands
Pipeline, which began providing natural gas transmission service on
December 23, 2003.
- An expected decline in transportation rates in 2004 from 2003
levels due to the estimated effects of a FERC rate order received in
July 2003.
- An expected combined natural gas and oil production increase of
approximately 10 percent in 2004 compared to 2003.
- Natural gas prices in the Rocky Mountain region for May through
December 2004, reflected in the Company's 2004 earnings guidance,
are in the range of $3.75 to $4.25 per Mcf. The Company's estimates
for natural gas prices on the NYMEX for May through December 2004,
reflected in the Company's 2004 earnings guidance, are in the range
of $4.75 to $5.25 per Mcf.
- NYMEX crude oil prices for April through December 2004,
reflected in the Company's 2004 earnings guidance, are in the range
of $28 to $32 per barrel.
- The Company has hedged a portion of its 2004 natural gas
production. The Company has entered into agreements representing
approximately 30 percent to 35 percent of 2004 estimated annual
natural gas production. The agreements are at various indices and
range from a low CIG index of $3.75 to a high NYMEX index of $6.11
per Mcf. CIG is an index pricing point related to Colorado
Interstate Gas Co.'s system.
- The Company has hedged a portion of its 2004 oil production.
The Company has entered into agreements at NYMEX prices with a low
of $28.84 and a high of $30.28, representing approximately 30
percent to 35 percent of 2004 estimated annual oil production.
- An expected increase in 2004 revenues of approximately 10
percent to 15 percent over 2003 levels at the construction materials
and mining business.
- Anticipated earnings in the range of $18 million to $23 million
in 2004 at the independent power production and other businesses.
The Company has capabilities to fund its growth and operations
through various sources, including internally generated funds,
commercial paper credit facilities and through the issuance of long-
term debt and the Company's equity securities. Net capital
expenditures are estimated to be approximately $415 million for
2004.
The Company faces certain challenges and risks as it pursues its
growth strategies, including, but not limited to the following:
- The natural gas and oil production business experiences
fluctuations in average natural gas and oil prices. These prices
are volatile and subject to significant change at any time. The
Company hedges a portion of its natural gas and oil production in
order to mitigate price volatility.
- The uncertain economic environment and the depressed
telecommunications market have been challenging, particularly for
the Company's utility services business which has been subjected to
lower margins and decreased workloads. These economic factors have
also negatively affected the Company's energy services business.
- Fidelity continues to seek additional reserve and production
growth through acquisition, exploration, development and production
of natural gas and oil resources, including the development and
production of its coalbed natural gas properties. Future growth is
dependent upon success in these endeavors. Fidelity has been named
as a defendant in, and/or certain of its operations are the subject
of, 13 lawsuits filed in connection with its coalbed natural gas
development in the Powder River Basin in Montana and Wyoming. If
the plaintiffs are successful in these lawsuits, the ultimate
outcome of the actions could have a material effect on Fidelity's
existing coalbed natural gas operations and/or the future
development of its coalbed natural gas properties.
For further information on certain factors that should be considered
for a better understanding of the Company's financial condition, see
the various important factors listed under the heading Risk Factors
and Cautionary Statements that May Affect Future Results, as well as
other factors that are listed in the Introduction.
For information pertinent to various commitments and contingencies,
see Notes to Consolidated Financial Statements.
Earnings Overview
The following table (dollars in millions, where applicable)
summarizes the contribution to consolidated earnings by each of the
Company's businesses.
Three Months
Ended
March 31,
2004 2003
Electric $ 3.4 $ 4.8
Natural gas distribution 2.3 4.2
Utility services (1.9) 1.1
Pipeline and energy services 2.7 4.3
Natural gas and oil production 25.3 11.7
Construction materials and mining (11.9) (7.4)
Independent power production and other 3.5 1.2
Earnings on common stock $ 23.4 $ 19.9
Earnings per common share - basic $ .20 $ .18
Earnings per common share - diluted $ .20 $ .18
Return on average common equity
for the 12 months ended 12.7% 11.8%
________________________________
Three Months Ended March 31, 2004 and 2003
Consolidated earnings for the quarter ended March 31, 2004,
increased $3.5 million from the comparable prior period due to
higher earnings at the natural gas and oil production and
independent power production and other businesses. Decreased
earnings at the other businesses partially offset the earnings
increase.
Natural gas and oil production earnings increased due to the absence
in 2004 of a $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 14 of Notes to Consolidated
Financial Statements. Also adding to the increase in earnings were
higher average natural gas and oil prices and increased natural gas
production. Higher depreciation, depletion and amortization expense
partially offset the increase in earnings.
Earnings increased at the independent power production and other
businesses due to higher income from the Company's share of its
equity method investment in Brazil, the result of significantly
lower financing costs, combined with the effects of changes in the
value of the embedded derivative in the power purchase agreement,
partially offset by foreign currency changes.
The construction materials and mining business experienced higher
losses as a result of normal seasonal losses from businesses
acquired since the prior period and lower earnings compared to the
prior period in connection with work on a large harbor-deepening
project that is substantially complete.
Utility services experienced a $1.9 million loss compared to $1.1
million of earnings for the comparable prior period due to decreased
margins and workloads.
Earnings decreased at the natural gas distribution business due to
higher operation and maintenance expense and lower retail sales
volumes, partially offset by higher retail sales prices due to a
rate increase effective in South Dakota.
Pipeline and energy services earnings decreased due to higher
operating expenses and lower storage revenues. Partially offsetting
this decrease were higher natural gas transportation volumes as a
result of the Grasslands Pipeline, offset in part by a decrease in
revenues from lower transportation reservation fees unrelated to the
Grasslands Pipeline.
Electric earnings decreased as a result of higher operation and
maintenance expense and lower retail sales prices due to the
seasonal effects of a new rate design for retail customers in North
Dakota, partially offset by higher average sales for resale margins.
Financial and operating data
The following tables (dollars in millions, where applicable) are key
financial and operating statistics for each of the Company's
businesses.
Electric
Three Months
Ended
March 31,
2004 2003
Operating revenues $ 47.0 $ 45.7
Operating expenses:
Fuel and purchased power 16.7 15.4
Operation and maintenance 15.0 13.4
Depreciation, depletion and amortization 5.0 5.0
Taxes, other than income 2.3 2.0
39.0 35.8
Operating income $ 8.0 $ 9.9
Retail sales (million kWh) 621.1 600.1
Sales for resale (million kWh) 227.3 251.4
Average cost of fuel and purchased
power per kWh $ .019 $ .017
Natural Gas Distribution
Three Months
Ended
March 31,
2004 2003
Operating revenues:
Sales $ 127.0 $ 110.0
Transportation and other 1.3 1.0
128.3 111.0
Operating expenses:
Purchased natural gas sold 105.6 88.2
Operation and maintenance 13.8 11.6
Depreciation, depletion and amortization 2.3 2.5
Taxes, other than income 1.6 1.4
123.3 103.7
Operating income $ 5.0 $ 7.3
Volumes (MMdk):
Sales 16.3 17.5
Transportation 3.8 3.1
Total throughput 20.1 20.6
Degree days (% of normal)* 96% 102%
Average cost of natural gas, including
transportation thereon, per dk $ 6.46 $ 5.05
_____________________
* Degree days are a measure of the daily temperature-related demand
for energy for heating.
Utility Services
Three Months
Ended
March 31,
2004 2003
Operating revenues $ 100.3 $ 103.7
Operating expenses:
Operation and maintenance 95.5 94.2
Depreciation, depletion and amortization 2.6 2.5
Taxes, other than income 4.8 4.4
102.9 101.1
Operating income (loss) $ (2.6) $ 2.6
Pipeline and Energy Services
Three Months
Ended
March 31,
2004 2003
Operating revenues:
Pipeline $ 23.1 $ 25.4
Energy services 61.1 35.7
84.2 61.1
Operating expenses:
Purchased natural gas sold 57.3 34.5
Operation and maintenance 13.4 12.3
Depreciation, depletion and amortization 4.7 3.7
Taxes, other than income 1.9 1.5
77.3 52.0
Operating income $ 6.9 $ 9.1
Transportation volumes (MMdk):
Montana-Dakota 8.3 8.4
Other 14.1 12.5
22.4 20.9
Gathering volumes (MMdk) 19.5 18.9
Natural Gas and Oil Production
Three Months
Ended
March 31,
2004 2003
Operating revenues:
Natural gas $ 66.4 $ 55.2
Oil 14.2 13.7
Other .4 .1
81.0 69.0
Operating expenses:
Purchased natural gas sold .4 ---
Operation and maintenance:
Lease operating costs 8.2 8.1
Gathering and transportation 2.5 3.3
Other 6.0 5.0
Depreciation, depletion and
amortization 16.6 14.2
Taxes, other than income:
Production and property taxes 4.7 5.5
Other .1 .2
38.5 36.3
Operating income $ 42.5 $ 32.7
Production:
Natural gas (MMcf) 14,506 13,639
Oil (000's of barrels) 457 474
Average realized prices (including hedges):
Natural gas (per Mcf) $ 4.57 $ 4.05
Oil (per barrel) $ 31.16 $ 29.00
Average realized prices (excluding hedges):
Natural gas (per Mcf) $ 4.68 $ 4.69
Oil (per barrel) $ 32.34 $ 31.05
Production costs, including
taxes, per net equivalent Mcf:
Lease operating costs $ .48 $ .49
Gathering and transportation .14 .20
Production and property taxes .27 .34
$ .89 $ 1.03
Construction Materials and Mining
Three Months
Ended
March 31,
2004 2003
Operating revenues $ 139.4 $ 120.8
Operating expenses:
Operation and maintenance 133.0 111.5
Depreciation, depletion and amortization 16.2 14.6
Taxes, other than income 6.5 4.7
155.7 130.8
Operating loss $ (16.3) $ (10.0)
Sales (000's):
Aggregates (tons) 4,807 5,027
Asphalt (tons) 302 162
Ready-mixed concrete (cubic yards) 574 515
Independent Power Production and Other
Three Months
Ended
March 31,
2004 2003
Operating revenues $ 7.3 $ 7.1
Operating expenses:
Operation and maintenance 4.7 4.2
Depreciation, depletion and amortization 2.1 1.6
6.8 5.8
Operating income $ .5 $ 1.3
Net generation capacity - kW* 279,600 279,600
Electricity produced and sold (thousand kWh)* 31,355 48,900
_____________________
* Reflects domestic independent power production operations.
NOTE: The earnings from the Company's equity method investments in
Brazil and Trinidad and Tobago were included in other income - net
and, thus, are not reflected in the above table.
Amounts presented in the preceding tables for operating revenues,
purchased natural gas sold and operation and maintenance expense
will not agree with the Consolidated Statements of Income due to
the elimination of intersegment transactions. The amounts (dollars
in millions) relating to the elimination of intersegment
transactions were as follows:
Three Months
Ended
March 31,
2004 2003
Operating revenues $ 72.0 $ 50.6
Purchased natural gas sold 68.5 46.6
Operation and maintenance 3.5 4.0
For further information on intersegment eliminations, see Note 15
of Notes to Consolidated Financial Statements.
Three Months Ended March 31, 2004 and 2003
Electric
Electric earnings decreased as a result of higher operation and
maintenance expense, including increased payroll, pension and other
benefit-related costs. Also contributing to the earnings decrease
were increased fuel and purchased power costs, lower retail sales
prices due to the seasonal effects of a new rate design for retail
customers in North Dakota, and lower sales for resale volumes of 10
percent resulting from less energy being available due to higher
retail demand. Partially offsetting the decrease in earnings were
higher average sales for resale margins and higher retail sales
volumes to all customer classes.
Natural Gas Distribution
Earnings at the natural gas distribution business decreased due to
higher operation and maintenance expense, including increased
payroll, pension and other benefit-related costs; lower retail sales
volumes of 7 percent due to weather that was 5 percent warmer than
the prior period; and decreased service and repair margins.
Partially offsetting the earnings decrease were higher retail sales
prices due to a rate increase effective in South Dakota.
Utility Services
Utility services experienced a $1.9 million loss for the first
quarter, compared to $1.1 million in earnings for the comparable
prior period. Decreased inside electrical margins in the Central
and Northwest regions, combined with decreased line construction
margins and workload in the Central and Rocky Mountain regions, more
than offset increased line construction margins in the Northwest and
Southwest regions.
Pipeline and Energy Services
Earnings at the pipeline and energy services business decreased as a
result of higher operating expenses, which were partially the result
of increased costs associated with the expansion of pipeline and
gathering operations, and lower storage service revenues. Partially
offsetting the decrease in earnings was an increase in natural gas
transportation volumes as a result of the Grasslands Pipeline, which
began providing natural gas transmission service late in 2003,
offset in part by a decrease in revenues from lower transportation
reservation fees unrelated to the Grasslands Pipeline resulting from
a decrease in the level of firm services provided. The increase in
energy services revenues and the related increase in purchased
natural gas sold includes the effect of increases in natural gas
prices and volumes since the comparable prior period.
Natural Gas and Oil Production
Natural gas and oil production earnings increased due to the absence
in 2004 of a 2003 noncash transition charge, as previously
discussed, and higher average realized natural gas prices of 13
percent due in part to the Company's ability to access higher-priced
markets for its natural gas production through the recently
constructed Grasslands Pipeline. Higher natural gas production of 6
percent and higher average realized oil prices of 7 percent, also
added to the increase in earnings. Partially offsetting the
earnings increase was higher depreciation, depletion and
amortization expense due to higher rates and higher nataral gas
production volumes.
Construction Materials and Mining
The construction materials and mining business experienced higher
losses as a result of normal seasonal losses from businesses
acquired since the prior period; lower aggregate margins and volumes
at existing operations largely related to lower construction
activity compared to the prior period in connection with work on a
large harbor-deepening project in southern California that is
substantially complete; and higher selling, general and
administrative expenses. Improved asphalt margins slightly offset
the seasonal loss.
Independent Power Production and Other
Earnings for the independent power production and other businesses
increased largely due to higher net income of $2.6 million from the
Company's share of its equity investment in Brazil. The higher net
income was due primarily to lower financing costs, largely the
result of obtaining low-cost, long-term financing for the operation
in mid-2003, combined with the effects of changes in the value of
the embedded derivative in the power purchase agreement, partially
offset by foreign currency changes.
Risk Factors and Cautionary Statements that May Affect Future
Results
The Company is including the following factors and cautionary
statements in this Form 10-Q to make applicable and to take
advantage of the safe harbor provisions of the Private Securities
Litigation Reform Act of 1995 for any forward-looking statements
made by, or on behalf of, the Company. Forward-looking statements
include statements concerning plans, objectives, goals, strategies,
future events or performance, and underlying assumptions (many of
which are based, in turn, upon further assumptions) and other
statements that are other than statements of historical facts. From
time to time, the Company may publish or otherwise make available
forward-looking statements of this nature, including statements
contained within Prospective Information. All these subsequent
forward-looking statements, whether written or oral and whether made
by or on behalf of the Company, are also expressly qualified by
these factors and cautionary statements.
Forward-looking statements involve risks and uncertainties, which
could cause actual results or outcomes to differ materially from
those expressed. The Company's expectations, beliefs and
projections are expressed in good faith and are believed by the
Company to have a reasonable basis, including without limitation,
management's examination of historical operating trends, data
contained in the Company's records and other data available from
third parties. Nonetheless, the Company's expectations, beliefs or
projections may not be achieved or accomplished.
Any forward-looking statement contained in this document speaks only
as of the date on which the statement is made, and the Company
undertakes no obligation to update any forward-looking statement or
statements to reflect events or circumstances that occur after the
date on which the statement is made or to reflect the occurrence of
unanticipated events. New factors emerge from time to time, and it
is not possible for management to predict all of the factors, nor
can it assess the effect of each factor on the Company's business or
the extent to which any factor, or combination of factors, may cause
actual results to differ materially from those contained in any
forward-looking statement.
Following are some specific factors that should be considered for a
better understanding of the Company's financial condition. These
factors and the other matters discussed herein are important factors
that could cause actual results or outcomes for the Company to
differ materially from those discussed in the forward-looking
statements included elsewhere in this document.
Economic Risks
The 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. Significant changes
in these factors could negatively affect the results of operations
and financial condition of the Company's natural gas and oil
production business.
The construction and operation of power generation facilities may
involve unanticipated changes or delays which could negatively
impact the Company's business and its results of operations.
The construction and operation of power generation facilities
involves many risks, including start-up risks, breakdown or failure
of equipment, competition, inability to obtain required governmental
permits and approvals, and inability to negotiate acceptable
acquisition, construction, fuel supply, off-take, transmission or
other material agreements, as well as the risk of performance below
expected levels of output or efficiency. Such unanticipated events
could negatively impact the Company's business and its results of
operations.
The uncertain economic environment and depressed telecommunications
market may have a general negative impact on the Company's future
revenues and may result in a goodwill impairment for Innovatum, Inc.
(Innovatum), an indirect wholly owned subsidiary of the Company.
In response to 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 volatile. A soft economy could
negatively affect the level of public and private expenditures on
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 has also
developed a hand-held locating device that can detect both magnetic
and plastic materials. Innovatum could face a future goodwill
impairment if there is a continued downturn in the telecommunications
and energy industries or if it cannot find a successful market for the
hand-held locating device. At March 31, 2004, the goodwill amount at
Innovatum was approximately $8.3 million. The determination of whether
an impairment will occur is dependent on a number of factors, including
the level of spending in the telecommunications and energy industries,
the success of the hand-held locating device at Innovatum, rapid
changes in technology, competitors and potential new customers.
The Company relies on financing sources and capital markets. If the
Company was unable to obtain financing in the future, the Company's
ability to execute its business plans, make capital expenditures or
pursue acquisitions that the Company may otherwise rely on for
future growth could be impaired.
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 its 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
Environmental and Regulatory Risks
Some of the Company's operations are subject to extensive
environmental laws and regulations that may increase costs of
operations, impact or limit business plans, or expose the Company to
environmental liabilities. One of the Company's subsidiaries is
subject to litigation 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. Public officials and entities, as well as private
individuals and organizations, may seek to enforce applicable
environmental laws and regulations. The Company cannot predict the
outcome (financial or operational) of any related litigation that
may arise.
Existing environmental regulations may be revised and new
regulations seeking to protect the environment may be adopted or
become applicable to the Company. Revised or additional
regulations, which result in increased compliance costs or
additional operating restrictions, particularly if those costs are
not fully recoverable from customers, could have a material effect
on the Company's results of operations.
Fidelity has been named as a defendant in, and/or certain of its
operations are the subject of, 13 lawsuits filed in connection with
its coalbed natural gas development in the Powder River Basin in
Montana and Wyoming. If the plaintiffs are successful in these
lawsuits, the ultimate outcome of the actions could have a material
effect on Fidelity's existing coalbed natural gas operations and/or
the 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 Foreign Operations
The value of the Company's investments in foreign operations may
diminish due to political, regulatory and economic conditions and
changes in currency exchange rates in countries where the Company
does business.
The Company is subject to political, regulatory and economic
conditions and changes in currency exchange rates in foreign
countries where the Company does business. Significant changes in
the political, regulatory or economic environment in these countries
could negatively affect the value of the Company's investments
located in these countries. Also, since the Company is unable to
predict the fluctuations in the foreign currency exchange rates,
these fluctuations may have an adverse impact on the Company's
results of operations.
The Company's 49 percent equity method investment in a 220-megawatt
natural gas-fired electric generation project in Brazil includes a
power purchase agreement that contains an embedded derivative. This
embedded derivative derives its value from an annual adjustment
factor that largely indexes the contract capacity payments to the
U.S. dollar. In addition, from time to time, other derivative
instruments may be utilized. The valuation of these financial
instruments, including the embedded derivative, can involve
judgments, uncertainties and the use of estimates. As a result,
changes in the underlying assumptions could affect the reported fair
value of these instruments. These instruments could recognize
financial losses as a result of volatility in the underlying fair
values, or if a counterparty fails to perform.
Other Risks
Competition is increasing in all of the Company's businesses.
All of the Company's businesses are subject to increased
competition. The independent power industry includes numerous
strong and capable competitors, many of which have greater resources
and more experience in the operation, acquisition and development of
power generation facilities. Utility services' competition is based
primarily on price and reputation for quality, safety and
reliability. The construction materials products are marketed under
highly competitive conditions and are subject to such competitive
forces as price, service, delivery time and proximity to the
customer. The electric utility and natural gas industries are also
experiencing increased competitive pressures as a result of consumer
demands, technological advances, deregulation, greater availability
of natural gas-fired generation and other factors. Pipeline and
energy services competes with several pipelines for access to
natural gas supplies and gathering, transportation and storage
business. The natural gas and oil production business is subject to
competition in the acquisition and development of natural gas and
oil properties as well as in the sale of its production output. The
increase in competition could negatively affect the Company's
results of operations and financial condition.
Weather conditions can adversely affect the Company's operations and
revenues.
The Company's results of operations can be affected by changes in
the weather. Weather conditions directly influence the demand for
electricity and natural gas, affect the wind-powered operation at
the independent power production business, affect the price of
energy commodities, affect the ability to perform services at the
utility services and construction materials and mining businesses
and affect ongoing operation and maintenance activities for the
pipeline and energy services and natural gas and oil production
businesses. In addition, severe weather can be destructive, causing
outages and/or property damage, which could require additional costs
to be incurred. As a result, adverse weather conditions could
negatively affect the Company's results of operations and financial
condition.
Prospective Information
The following information includes highlights of the key growth
strategies, projections and certain assumptions for the Company and
its subsidiaries over the next few years and other matters for each
of the Company's businesses. Many of these highlighted points are
forward-looking statements. There is no assurance that the
Company's projections, including estimates for growth and increases
in revenues and earnings, will in fact be achieved. Reference is
made to assumptions contained in this section, as well as the
various important factors listed under the heading Risk Factors and
Cautionary Statements that May Affect Future Results, and other
factors that are listed in the Introduction. Changes in such
assumptions and factors could cause actual future results to differ
materially from targeted growth, revenue and earnings projections.
MDU Resources Group, Inc.
- - Earnings per common share for 2004, diluted, are projected in
the range of $1.60 to $1.75, an increase from prior guidance of
$1.55 to $1.68.
- - The Company expects the percentage of 2004 earnings per common
share, diluted, by quarter to be in the following approximate
ranges:
- Second quarter - 22 percent to 27 percent
- Third quarter - 37 percent to 42 percent
- Fourth quarter - 24 percent to 29 percent
- - The Company's long-term compound annual growth goals on
earnings per share from operations are in the range of 6 percent to
9 percent.
- - The Company will consider issuing equity from time to time to
keep debt at the nonregulated businesses at no more than 40 percent
of total capitalization.
- - The Company had formed an alliance with several electric cooperatives
in the region to evaluate potential utility opportunities presented
by the bankruptcy of NorthWestern Corporation (NorthWestern).
NorthWestern filed for Chapter 11 bankruptcy protection on
September 14, 2003. On May 4, 2004, the alliance announced that
it was ceasing its efforts to acquire the assets of NorthWestern.
The alliance has been dissolved.
Electric
- - Montana-Dakota has obtained and holds valid and existing
franchises authorizing it to conduct its electric operations in all
of the municipalities it serves where such franchises are required.
As franchises expire, Montana-Dakota may face increasing competition
in its service areas, particularly its service to smaller towns,
from rural electric cooperatives. Montana-Dakota intends to protect
its service area and seek renewal of all expiring franchises and
will continue to take steps to effectively operate in an
increasingly competitive environment.
- - The expected return for this segment in 2004 is anticipated to
be generally consistent with overall authorized levels.
- - Regulatory approval has been received from the NDPSC and the
South Dakota Public Utilities Commission to include renewable energy
in the fuel adjustment clause. The Company has plans to purchase
energy from a 20-megawatt wind energy farm in North Dakota.
However, wind development is currently stalled nationwide awaiting
federal reauthorization of the production tax credits. This segment
does not anticipate the project being constructed until the tax
credits are extended.
- - The Company continues to evaluate potential needs for future
generation. The Company expects to build or acquire an additional
175-megawatts to 200-megawatts of capacity over the next 10 years to
replace expiring contracts and meet system growth requirements. The
Company is working with the state of North Dakota to determine the
feasibility of constructing a lignite-fired power plant in western
North Dakota. This segment also announced its involvement in a
coalition with four other utilities to study the feasibility of
building a coal-based facility, possibly combined with a wind energy
facility, at potential sites in North Dakota, South Dakota and Iowa.
The costs of building and/or acquiring the additional generating
capacity needed by the utility are expected to be recovered in
rates.
- - On January 9, 2004, Montana-Dakota entered into a firm capacity
contract with a Midwest utility to purchase 5 megawatts of capacity
during the period May 1, 2004 to October 31, 2004, 15 megawatts
during the period May 1, 2005 to October 31, 2005 and 25 megawatts
during the period May 1, 2006 to October 31, 2006. In addition, on
January 9, 2004, Montana-Dakota entered into a firm power contract
with the same Midwest utility to purchase 70 megawatts of power
during the period November 1, 2006 to December 31, 2006, 80
megawatts during the period January 1, 2007 to December 31, 2007, 90
megawatts during the period January 1, 2008 to December 31, 2008 and
100 megawatts during the period January 1, 2009 to December 31,
2010. All capacity and power purchases from these contracts are
contingent upon the parties securing transmission service for the
delivery of capacity and power to Montana-Dakota's customer load.
Transmission service has not yet been secured.
Natural gas distribution
- - Montana-Dakota and Great Plains have obtained and hold valid
and existing franchises authorizing them to conduct their natural
gas operations in all of the municipalities they serve where such
franchises are required. As franchises expire, Montana-Dakota and
Great Plains may face increasing competition in their service areas.
Montana-Dakota and Great Plains intend to protect their service
areas and seek renewal of all expiring franchises and will continue
to take steps to effectively operate in an increasingly competitive
environment.
- - Annual natural gas throughput for 2004 is expected to be
approximately 52 million decatherms.
- - The Company expects to seek natural gas rate increases from
time to time to offset higher expected operating costs.
- - Montana-Dakota filed applications with the MTPSC and the NDPSC
seeking increases in natural gas retail rates of $1.5 million
annually or 1.8 percent above current rates and $3.3 million
annually or 2.8 percent above current rates, respectively. While
Montana-Dakota believes that it should be authorized to increase
retail rates in the amounts requested, there is no assurance that
the increases ultimately allowed will be for the full amount
requested in each jurisdiction. For further information on the
natural gas rate increase applications, see Note 18 of Notes to
Consolidated Financial Statements.
Utility services
- - Revenues for this segment are expected to be in the range of
$440 million to $490 million in 2004.
- - This segment anticipates margins to increase in 2004 as
compared to 2003 levels.
- - This segment's work backlog as of March 31, 2004, was
approximately $174 million compared to $158 million at March 31,
2003.
Pipeline and energy services
- - In 2004, total natural gas throughput is expected to increase
approximately 20 percent to 25 percent over 2003 levels largely due
to the Grasslands Pipeline, which began providing natural gas
transmission service on December 23, 2003.
- - Firm capacity for the Grasslands Pipeline is currently 90
million cubic feet per day with expansion possible to 200 million
cubic feet per day.
- - Transportation rates are expected to decline in 2004 from 2003
levels due to the estimated effects of a FERC rate order received in
July 2003.
- - Innovatum could face a future goodwill impairment based on
certain economic conditions, as previously discussed in Risk Factors
and Cautionary Statements that May Affect Future Results. Innovatum
recently developed a hand-held locating device that can detect both
magnetic and plastic materials. One of the possible uses for this
product would be in the detection of unexploded ordnance. Innovatum
is in the preliminary stages of working with and demonstrating the
device to a Department of Defense contractor and has met with
individuals from the Department of Defense.
Natural gas and oil production
- - In 2004, this segment expects a combined production increase of
approximately 10 percent over 2003 levels. Currently, this
segment's gross operated natural gas production is approximately
140,000 Mcf to 150,000 Mcf per day.
- - Natural gas production from operated properties was 74 percent
of total natural gas production for the three months ended March 31,
2004.
- - This segment expects to drill more than 400 wells in 2004.
- - Natural gas prices in the Rocky Mountain region for May through
December 2004, reflected in the Company's 2004 earnings guidance,
are in the range of $3.75 to $4.25 per Mcf. The Company's estimates
for natural gas prices on the NYMEX for May through December 2004,
reflected in the Company's 2004 earnings guidance, are in the range
of $4.75 to $5.25 per Mcf. During 2003, more than two-thirds of
this segment's natural gas production was priced using Rocky
Mountain or other non-NYMEX prices.
- - NYMEX crude oil prices for April through December 2004,
reflected in the Company's 2004 earnings guidance, are in the range
of $28 to $32 per barrel.
- - The Company has hedged a portion of its 2004 natural gas
production. The Company has entered into agreements representing
approximately 30 percent to 35 percent of 2004 estimated annual
natural gas production. The agreements are at various indices and
range from a low CIG index of $3.75 to a high NYMEX index of $6.11
per Mcf. CIG is an index pricing point related to Colorado
Interstate Gas Co.'s system.
- - The Company has hedged a portion of its 2004 oil production.
The Company has entered into agreements at NYMEX prices with a low
of $28.84 and a high of $30.28, representing approximately 30
percent to 35 percent of 2004 estimated annual oil production.
- - The Company has hedged approximately 15 percent to 20 percent
of its 2005 estimated annual natural gas production and 10 percent
to 15 percent of its 2005 estimated annual oil production. The
Company will continue to evaluate additional hedging opportunities.
Construction materials and mining
- - Aggregate volumes in 2004 are expected to be comparable to 2003
levels. Ready-mixed concrete volumes are expected to increase by 15
percent to 20 percent, while asphalt volumes are expected to
increase 10 percent to 15 percent over 2003.
- - Revenues in 2004 are expected to increase by approximately 10
percent to 15 percent over 2003 levels.
- - The Company is confident that the replacement funding
legislation for the Transportation Equity Act for the 21st Century
(TEA-21) will be at funding levels equal to or higher than the
funding under TEA-21.
- - As of mid-April, this segment had $460 million in work backlog
compared to $325 million in mid-April of 2003.
- - On May 3, 2004, this segment acquired a construction materials
and services provider in Idaho. This company has annual revenues of
approximately $35 million.
- - Three of the four labor contracts that Knife River was
negotiating, as reported in Items 1 and 2 -- Business and Properties
- General in the Company's 2003 Form 10-K, have been ratified and
one remains in negotiations. The Company considers its relations
with its employees to be satisfactory.
Independent power production and other
- - Earnings projections for independent power production and other
operations are expected to be in the range of $18 million to $23
million in 2004.
- - The Company has begun construction of a 116-megawatt coal-fired
electric generating project near Hardin, Montana. The Company has
entered into a power sales agreement with Powerex Corp., a
subsidiary of BC Hydro. The power sales agreement is for three
years with a two-year extension option and provides for capacity and
energy payments for the entire output of the plant. The projected
on-line date for this plant is late 2005.
- - On April 16, 2004, Centennial Energy acquired an independent
power production operating and development company in Lafayette,
Colorado.
New Accounting Standards
In December 2003, the FASB issued FASB Interpretation No. 46
(revised December 2003), "Consolidation of Variable Interest
Entities" (FIN 46 (revised)), which replaced FASB Interpretation No.
46, "Consolidation of Variable Interest Entities" (FIN 46). FIN 46
(revised) shall be applied to all entities subject to FIN 46
(revised) no later than the end of the first reporting period that
ends after March 15, 2004. The adoption of FIN 46 (revised) did not
have an effect on the Company's financial position or results of
operations.
In January 2004, the FASB issued FASB Staff Position No. FAS 106-1,
"Accounting and Disclosure Requirements Related to the Medicare
Prescription Drug, Improvement and Modernization Act of 2003." FASB
Staff Position No. FAS 106-1 permits a sponsor of a postretirement
health care plan that provides a prescription drug benefit to make a
one-time election to defer accounting for the effects of the
Medicare Prescription Drug, Improvement and Modernization Act of
2003 (2003 Medicare Act). The Company provides prescription drug
benefits to certain eligible employees and has elected the one-time
deferral of accounting for the effects of the 2003 Medicare Act.
The Company is currently analyzing the 2003 Medicare Act, along with
proposed authoritative guidance, to determine if its benefit plans
need to be amended and how to record the effects of the 2003
Medicare Act.
SFAS No. 142, "Goodwill and Other Intangible Assets," 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,
"Business Combinations," and SFAS No. 142 clarify that more assets
should be distinguished and classified between tangible and
intangible. An issue has arisen within the natural gas and oil
industry as to whether contractual mineral rights under SFAS No. 142
should be classified as intangible rather than as part of property,
plant and equipment. The Company believes that the resolution of
this matter will not have a material effect on the Company's
financial position because the mineral rights acquired by its
natural gas and oil production business after the June 30, 2001,
effective date of SFAS No. 142 were not material.
In April 2004, the FASB issued FASB Staff Position Nos. FAS 141-1
and FAS 142-1, "Interaction of FASB Statements No. 141, 'Business
Combinations,' and No. 142, 'Goodwill and Other Intangible Assets,'
and EITF Issue No. 04-2, 'Whether Mineral Rights are Tangible or
Intangible Assets,'" (FAS 141-1 and FAS 142-1). FAS 141-1 and FAS
142-1 will require reclassification of the Company's leasehold
rights at its construction materials and mining operations from
other intangible assets, net to property, plant and equipment, as
well as changes to Notes to Consolidated Financial Statements.
FAS 141-1 and FAS 142-1 will only affect the balance sheet and
associated footnote disclosure, so the reclassifications will
not affect the Company's cash flows or results of operations.
The Company's leasehold rights, net of accumulated amortization
(included in other intangible assets, net on the Consolidated
Balance Sheets), are $174.2 million at March 31, 2004, $164.2
million at March 31, 2003, and $174.6 million at December 31, 2003.
For further information on FIN 46 (revised), FASB Staff Position No.
FAS 106-1, SFAS No. 142 and 141, and FASB Staff Position Nos. FAS
141-1 and FAS 142-1, see Note 9 of Notes to Consolidated Financial
Statements.
Critical Accounting Policies Involving Significant Estimates
The Company's critical accounting policies involving significant
estimates include impairment testing of long-lived assets and
intangibles, impairment testing of natural gas and oil production
properties, revenue recognition, purchase accounting, asset
retirement obligations, and pension and other postretirement
benefits. There were no material changes in the Company's critical
accounting policies involving significant estimates from those
reported in the Company's Annual Report on Form 10-K for the year
ended December 31, 2003. For more information on critical
accounting policies involving significant estimates, see Part II,
Item 7 in the Company's Annual Report on Form 10-K for the year
ended December 31, 2003.
Liquidity and Capital Commitments
Cash flows
Operating activities --
Cash flows provided by operating activities in the first quarter of
2004 decreased $6.0 million from the comparable 2003 period due in
part to a decrease in cash provided by working capital and other
items of $10.5 million, partially offset by higher depreciation,
depletion and amortization expense of $5.4 million, resulting
largely from increased property, plant and equipment balances and
higher mineral production rates and volumes.
Investing activities --
Cash flows used in investing activities in the first quarter of 2004
decreased $79.4 million from the comparable 2003 period, the result
of a decrease in net capital expenditures (capital expenditures;
acquisitions, net of cash acquired; and net proceeds from the sale
or disposition of property) of $106.8 million, offset by an increase
in investments of $21.6 million and a decrease in proceeds from
notes receivable of $5.8 million. Net capital expenditures exclude
the noncash transactions related to acquisitions, including the
issuance of the Company's equity securities. The noncash
transactions were $19.5 million and $1.1 million for the first
quarter of 2004 and 2003, respectively.
Financing activities --
Cash flows provided by financing activities in the first quarter of
2004 decreased $54.8 million, primarily the result of a decrease in
the issuance of long-term debt of $84.7 million and an increase in
the repayment of long-term debt of $30.2 million. An increase in
the issuance of common stock of $54.1 million, primarily due to net
proceeds received from an underwritten public offering, partially
offset the decrease in cash provided by financing activities.
Defined benefit pension plans
The Company has qualified noncontributory defined benefit pension
plans (Pension Plans) for certain employees. Plan assets consist of
investments in equity and fixed income securities. Various
actuarial assumptions are used in calculating the benefit expense
(income) and liability (asset) related to the Pension Plans.
Actuarial assumptions include assumptions about the discount rate,
expected return on plan assets and rate of future compensation
increases as determined by the Company within certain guidelines.
At December 31, 2003, certain Pension Plans' accumulated benefit
obligations exceeded these plans' assets by approximately
$4.3 million. Pretax pension expense (income) reflected in the
years ended December 31, 2003, 2002 and 2001, was $153,000, ($2.4)
million and ($4.4) million, respectively. The Company's pension
expense is currently projected to be approximately $4.0 million to
$5.0 million in 2004. A reduction in the Company's assumed discount
rate for Pension Plans along with declines in the equity markets
experienced in 2002 and 2001 have combined to largely produce the
increase in these costs. Funding for the Pension Plans is
actuarially determined. The minimum required contributions for
2003, 2002 and 2001 were approximately $1.6 million, $1.2 million
and $442,000, respectively. For further information on the
Company's Pension Plans, see Note 17 of Notes to Consolidated
Financial Statements.
Capital expenditures
Net capital expenditures, including the issuance of the Company's
equity securities in connection with acquisitions, for the first
three months of 2004 were $73.6 million and are estimated to be
approximately $415 million for the year 2004. Estimated capital
expenditures include those for:
- Completed acquisitions
- System upgrades
- Routine replacements
- Service extensions
- Routine equipment maintenance and replacements
- Land and building improvements
- Pipeline and gathering expansion projects
- The further enhancement of natural gas and oil production and
reserve growth
- Power generation opportunities, including certain construction
costs for a 116-megawatt coal-fired development project, as
previously discussed
- Other growth opportunities
Approximately 14 percent of estimated 2004 net capital expenditures
are for completed acquisitions. The Company continues to evaluate
potential future acquisitions and other growth opportunities;
however, they are dependent upon the availability of economic
opportunities and, as a result, capital expenditures may vary
significantly from the estimated 2004 capital expenditures referred
to above. It is anticipated that all of the funds required for
capital expenditures will be met from various sources. These
sources include internally generated funds; commercial paper credit
facilities at Centennial and MDU Resources Group, Inc., as described
below; and through the issuance of long-term debt and the Company's
equity securities.
The estimated 2004 capital expenditures referred to above include
completed 2004 acquisitions involving construction materials and
mining businesses in Idaho, Iowa and Minnesota and an operating and
an independent power production development company in Colorado.
Pro forma financial amounts reflecting the effects of the above
acquisitions are not presented as such acquisitions were not
material to the Company's financial position or results of
operations.
Capital resources
Certain debt instruments of the Company and its subsidiaries,
including those discussed below, contain restrictive covenants, all
of which the Company and its subsidiaries were in compliance with at
March 31, 2004.
MDU Resources Group, Inc.
The Company has a revolving credit agreement with various banks
totaling $90 million at March 31, 2004. There were no amounts
outstanding under the credit agreement at March 31, 2004. The
credit agreement supports the Company's $75 million commercial paper
program. There were no amounts outstanding under the Company's
commercial paper program at March 31, 2004. The credit agreement
expires on July 18, 2006.
The Company's goal is to maintain acceptable credit ratings in order
to access the capital markets through the issuance of commercial
paper. If the Company were to experience a minor downgrade of its
credit ratings, it would not anticipate any change in its ability to
access the capital markets. However, in such event, the Company
would expect a nominal basis point increase in overall interest
rates with respect to its cost of borrowings. If the Company were
to experience a significant downgrade of its credit ratings, which
it does not currently anticipate, it may need to borrow under its
credit agreement.
To the extent the Company needs to borrow under its credit
agreement, it would be expected to incur increased annualized
interest expense on its variable rate debt. This was not applicable
at March 31, 2004, as there were no variable rate borrowings at such
time.
Prior to the maturity of the credit agreement, the Company plans to
negotiate the extension or replacement of this agreement that
provides credit support to access the capital markets. In the event
the Company was unable to successfully negotiate the credit
agreement, or in the event the fees on this facility became too
expensive, which it does not currently anticipate, the Company would
seek alternative funding. One source of alternative funding might
involve the securitization of certain Company assets.
In order to borrow under the Company's credit agreement, the Company
must be in compliance with the applicable covenants and certain
other conditions. The significant covenants include maximum
leverage ratios, minimum interest coverage ratio, limitation on sale
of assets and limitation on investments. The Company was in
compliance with these covenants and met the required conditions at
March 31, 2004. In the event the Company does not comply with the
applicable covenants and other conditions, alternative sources of
funding may need to be pursued, as previously described.
There are no credit facilities that contain cross-default provisions
between the Company and any of its subsidiaries.
On February 10, 2004, the Company issued 2.3 million shares of its
common stock and appurtenant preference share purchase rights to the
public at a price per share of $23.32 in an underwritten public
offering and received net proceeds from the offering of
approximately $51.5 million, after deducting underwriting discounts
and commissions and offering expenses payable by the Company.
Approximately $24 million of the net proceeds was used to repay
outstanding indebtedness. The remainder of the net proceeds of the
sale of these shares was added to the Company's general funds and
may be used for the repayment of outstanding debt obligations, for
corporate development purposes (including the acquisition of other
businesses and/or business assets), and for other general corporate
purposes.
The Company's issuance of first mortgage debt is subject to certain
restrictions imposed under the terms and conditions of its Indenture
of Mortgage. Generally, those restrictions require the Company to
fund $1.43 of unfunded property or use $1.00 of refunded bonds for
each dollar of indebtedness incurred under the Indenture and, in
some cases, to certify to the trustee that annual earnings (pretax
and before interest charges), as defined in the Indenture, equal at
least two times its annualized first mortgage bond interest costs.
Under the more restrictive of the tests, as of March 31, 2004, the
Company could have issued approximately $314 million of additional
first mortgage bonds.
The Company's coverage of fixed charges including preferred
dividends was 4.7 times for the twelve months ended March 31, 2004
and December 31, 2003. Additionally, the Company's first mortgage
bond interest coverage was 7.1 times and 7.4 times for the twelve
months ended March 31, 2004 and December 31, 2003, respectively.
Common stockholders' equity as a percent of total capitalization was
63 percent and 60 percent at March 31, 2004 and December 31, 2003,
respectively.
Centennial Energy Holdings, Inc.
Centennial has two revolving credit agreements with various banks
that support $275 million of Centennial's $350 million commercial
paper program. There were no outstanding borrowings under the
Centennial credit agreements at March 31, 2004. Under the
Centennial commercial paper program, $36.8 million was outstanding
at March 31, 2004. The Centennial commercial paper borrowings are
classified as long-term debt as Centennial intends to refinance
these borrowings on a long-term basis through continued Centennial
commercial paper borrowings and as further supported by the
Centennial credit agreements. The Centennial credit agreements are
for $137.5 million each. One of these agreements expires on
September 3, 2004, and allows for subsequent borrowings up to a term
of one year. The other agreement expires on September 5, 2006.
Centennial intends to negotiate the extension or replacement of
these agreements prior to their maturities.
Centennial has an uncommitted long-term master shelf agreement
that allows for borrowings of up to $400 million. Under the terms
of the master shelf agreement, $384.0 million was outstanding at
March 31, 2004. To meet potential future financing needs,
Centennial may pursue other financing arrangements, including
private and/or public financing.
Centennial's goal is to maintain acceptable credit ratings in order
to access the capital markets through the issuance of commercial
paper. If Centennial were to experience a minor downgrade of its
credit ratings, it would not anticipate any change in its ability to
access the capital markets. However, in such event, Centennial
would expect a nominal basis point increase in overall interest
rates with respect to its cost of borrowings. If Centennial were to
experience a significant downgrade of its credit ratings, which it
does not currently anticipate, it may need to borrow under its
committed bank lines.
To the extent Centennial needs to borrow under its committed bank
lines, it would be expected to incur increased annualized interest
expense on its variable rate debt of approximately $55,000 (after
tax) based on March 31, 2004, variable rate borrowings. Based on
Centennial's overall interest rate exposure at March 31, 2004, this
change would not have a material effect on the Company's results of
operations or cash flows.
Prior to the maturity of the Centennial credit agreements,
Centennial plans to negotiate the extension or replacement of these
agreements that provide credit support to access the capital
markets. In the event Centennial was unable to successfully
negotiate these agreements, or in the event the fees on such
facilities became too expensive, which Centennial does not currently
anticipate, it would seek alternative funding. One source of
alternative funding might involve the securitization of certain
Centennial assets.
In order to borrow under Centennial's credit agreements and the
Centennial uncommitted long-term master shelf agreement, Centennial
and certain of its subsidiaries must be in compliance with the
applicable covenants and certain other conditions. The significant
covenants include maximum capitalization ratios, minimum interest
coverage ratios, minimum consolidated net worth, limitation on
priority debt, limitation on sale of assets and limitation on loans
and investments. Centennial and such subsidiaries were in
compliance with these covenants and met the required conditions at
March 31, 2004. In the event Centennial or such subsidiaries do not
comply with the applicable covenants and other conditions,
alternative sources of funding may need to be pursued as previously
described.
Certain of Centennial's financing agreements contain cross-default
provisions. These provisions state that if Centennial or any
subsidiary of Centennial fails to make any payment with respect to
any indebtedness or contingent obligation, in excess of a specified
amount, under any agreement that causes such indebtedness to be due
prior to its stated maturity or the contingent obligation to become
payable, the applicable agreements will be in default. Certain of
Centennial's financing agreements and Centennial's practice limit
the amount of subsidiary indebtedness.
Williston Basin Interstate Pipeline Company
Williston Basin has an uncommitted long-term master shelf agreement
that allows for borrowings of up to $100 million. Under the terms
of the master shelf agreement, $55.0 million was outstanding at
March 31, 2004.
In order to borrow under Williston Basin's uncommitted long-term
master shelf agreement, it must be in compliance with the applicable
covenants and certain other conditions. The significant covenants
include limitation on consolidated indebtedness, limitation on
priority debt, limitation on sale of assets and limitation on
investments. Williston Basin was in compliance with these covenants
and met the required conditions at March 31, 2004. In the event
Williston Basin does not comply with the applicable covenants and
other conditions, alternative sources of funding may need to be
pursued.
Off balance sheet arrangements
Centennial has unconditionally guaranteed a portion of certain bank
borrowings of MPX in connection with the Company's equity method
investment in the natural gas-fired electric generating facility in
Brazil, as discussed in Note 11 of Notes to Consolidated Financial
Statements. The Company, through MDU Brasil, owns 49 percent of
MPX. The main business purpose of Centennial extending the
guarantee to MPX's creditors is to enable MPX to obtain lower
borrowing costs. At March 31, 2004, the aggregate amount of
borrowings outstanding subject to these guarantees was $40.0 million
and the scheduled repayment of these borrowings is $5.4 million in
2004, $10.7 million in 2005, $10.7 million in 2006, $10.7 million in
2007 and $2.5 million in 2008. The individual investor (who through
EBX, a Brazilian company, owns 51 percent of MPX) has also
guaranteed these loans. In the event MPX defaults under its
obligation, Centennial and the individual investor would be required
to make payments under their guarantees. Centennial and the
individual investor have entered into reimbursement agreements under
which they have agreed to reimburse each other to the extent they
may be required to make any guarantee payments in excess of their
proportionate ownership share in MPX. These guarantees are not
reflected on the Consolidated Balance Sheets.
As of March 31, 2004, Centennial was contingently liable for
performance of certain of its subsidiaries under approximately $277
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. The purpose of Centennial's
indemnification is to allow the subsidiaries to obtain bonding at
competitive rates. In the event a subsidiary of the Company does
not fulfill its obligations in relation to its bonded contract or
obligation, Centennial may be required to make payments under its
indemnification. A large portion of these contingent commitments
are expected to expire within the next 12 months; however,
Centennial will likely continue to enter into surety bonds for its
subsidiaries in the future. The surety bonds were not reflected on
the Consolidated Balance Sheets.
Contractual obligations and commercial commitments
There were no material changes in the Company's contractual
obligations on long-term debt, operating leases and purchase
commitments from those reported in the Company's Annual Report on
Form 10-K for the year ended December 31, 2003. For more
information on contractual obligations and commercial commitments,
see Part II, Item 7 in the Company's Annual Report on Form 10-K for
the year ended December 31, 2003.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The Company is exposed to the impact of market fluctuations
associated with commodity prices, interest rates and foreign
currency. The Company has policies and procedures to assist in
controlling these market risks and utilizes derivatives to manage a
portion of its risk.
Commodity price risk --
Fidelity 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 its forecasted
sales of natural gas and oil production. For more information on
commodity price risk, see Part II, Item 7A in the Company's Annual
Report on Form 10-K for the year ended December 31, 2003, and Note
13 of Notes to Consolidated Financial Statements.
The following table summarizes hedge agreements entered into by
Fidelity as of March 31, 2004. These agreements call for Fidelity
to receive fixed prices and pay variable prices.
(Notional amount and fair value in thousands)
Weighted
Average Notional
Fixed Price Amount
(Per MMBtu) (In MMBtu's) Fair Value
Natural gas swap
agreements maturing
in 2004 $ 5.14 8,250 $ (5,096)
Natural gas swap
agreements maturing
in 2005 $ 5.08 3,650 $ (1,316)
Weighted
Average
Floor/Ceiling Notional
Price Amount
(Per MMBtu) (In MMBtu's) Fair Value
Natural gas collar
agreements maturing
in 2004 $4.62/$5.28 7,276 $ (4,648)
Natural gas collar
agreement maturing
in 2005 $4.75/$5.25 1,825 $ (824)
Weighted
Average Notional
Fixed Price Amount
(Per barrel) (In barrels) Fair Value
Oil swap agreements
maturing in 2004 $ 29.59 413 $ (1,678)
Oil swap agreement
maturing in 2005 $ 30.70 183 $ (23)
Interest rate risk --
There were no material changes to interest rate risk faced by the
Company from those reported in the Company's Annual Report on Form
10-K for the year ended December 31, 2003. For more information on
interest rate risk, see Part II, Item 7A in the Company's Annual
Report on Form 10-K for the year ended December 31, 2003.
Foreign currency risk --
MDU Brasil has a 49 percent equity investment in a 220-megawatt
natural gas-fired electric generating facility in Brazil, which has
a portion of its borrowings and payables denominated in U.S.
dollars. MDU Brasil has exposure to currency exchange risk as a
result of fluctuations in currency exchange rates between the U.S.
dollar and the Brazilian real. The functional currency for the
Brazil Generating Facility is the Brazilian real. For further
information on this investment, see Note 11 of Notes to Consolidated
Financial Statements.
MDU Brasil's equity income from this Brazilian investment is
impacted by fluctuations in currency exchange rates on transactions
denominated in a currency other than the Brazilian real, including
the effects of changes in currency exchange rates with respect to
the Brazil Generating Facility's U.S. dollar denominated obligations
(including a U.S. dollar denominated loan from Centennial
International). At March 31, 2004, these U.S. dollar denominated
obligations approximated $85.9 million. If, for example, the value
of the Brazilian real decreased in relation to the U.S. dollar by 10
percent, MDU Brasil, with respect to its interest in the Brazil
Generating Facility, would record a foreign currency loss in net
income of approximately $3.8 million (after tax) based on the above
U.S. dollar denominated obligations at March 31, 2004.
The investment of Centennial International in the Brazil Generating
Facility at March 31, 2004, was approximately $27.3 million.
A portion of the Brazil Generating Facility's foreign currency
exchange risk is being managed through contractual provisions, which
are largely indexed to the U.S. dollar, contained in the Brazil
Generating Facility's power purchase agreement with Petrobras. The
Brazil Generating Facility has also historically used derivative
instruments to manage a portion of its foreign currency risk and may
utilize such instruments in the future.
ITEM 4. CONTROLS AND PROCEDURES
The following information includes the evaluation of disclosure
controls and procedures by the Company's chief executive officer and
the chief financial officer, along with any significant changes in
internal controls of the Company.
Evaluation of disclosure controls and procedures
The term "disclosure controls and procedures" is defined in Rules
13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934
(Exchange Act). These rules refer to the controls and other
procedures of a company that are designed to ensure that information
required to be disclosed by a company in the reports it files under
the Exchange Act is recorded, processed, summarized and reported
within required time periods. The Company's chief executive officer
and chief financial officer have evaluated the effectiveness of the
Company's disclosure controls and procedures and they have concluded
that, as of the end of the period covered by this report, such
controls and procedures were effective to accomplish those tasks.
Changes in internal controls
The Company maintains a system of internal accounting controls
designed to provide reasonable assurance that the Company's
transactions are properly authorized, the Company's assets are
safeguarded against unauthorized or improper use, and the Company's
transactions are properly recorded and reported to permit
preparation of the Company's financial statements in conformity with
generally accepted accounting principles in the United States of
America. There were no changes in the Company's internal control
over financial reporting that occurred during the period covered by
this report that have materially affected, or are reasonably likely
to materially affect, the Company's internal control over financial
reporting.
PART II -- OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
In February and April 2004, two additional lawsuits were filed in
connection with Fidelity's coalbed natural gas development in the
Powder River Basin in Montana and Wyoming.
On April 1, 2004, the EPA Motion to Dismiss was granted in the
Dakota Resource Council case filed in Federal District Court in
Denver, Colorado.
For more information on the above legal actions, see Note 19 of
Notes to Consolidated Financial Statements, which is incorporated by
reference.
ITEM 2. CHANGES IN SECURITIES AND USE OF PROCEEDS
Between January 1, 2004 and March 31, 2004, the Company issued
973,895 shares of Common Stock, $1.00 par value, and the Preference
Share Purchase Rights appurtenant thereto, as part of the
consideration paid by the Company for all of the issued and
outstanding capital stock with respect to businesses acquired during
this period and as a final purchase price adjustment with respect to
an acquisition in a prior period. The Common Stock and Rights
issued by the Company in these transactions were issued in a private
transaction exempt from registration under the Securities Act of
1933 pursuant to Section 4(2) thereof, Rule 506 promulgated
thereunder, or both. The classes of persons to whom these
securities were sold were either accredited investors or other
persons to whom such securities were permitted to be offered under
the applicable exemption.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
The Company's Annual Meeting of Stockholders was held on April 27,
2004. Two proposals were submitted to stockholders as described in
the Company's Proxy Statement dated March 12, 2004, and were voted
upon and approved by stockholders at the meeting. The table below
briefly describes the proposals and the results of the stockholder
votes.
Shares
Shares Against or Broker
For Withheld Abstentions Non-Votes
Proposal to elect four directors:
For terms expiring in 2007 --
Dennis W. Johnson 100,356,868 3,135,314 --- ---
John L. Olson 100,333,699 3,158,483 --- ---
Martin A. White 101,921,227 1,570,955 --- ---
John K. Wilson 100,304,976 3,187,206 --- ---
Proposal to amend the
Non-Employee Director Stock
Compensation Plan 54,918,021 24,225,587 1,377,878 22,970,696
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
a) Exhibits
12 Computation of Ratio of Earnings to Fixed Charges and
Combined Fixed Charges and Preferred Stock Dividends
31(a) Certification of Chief Executive Officer filed pursuant
to Section 302 of the Sarbanes-Oxley Act of 2002
31(b) Certification of Chief Financial Officer filed pursuant
to Section 302 of the Sarbanes-Oxley Act of 2002
32 Certification of Chief Executive Officer and Chief
Financial Officer furnished pursuant to 18 U.S.C. Section
1350, as adopted pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002
b) Reports on Form 8-K
Form 8-K was filed on February 5, 2004. Under Item 5 -- Other
Events and Regulation FD Disclosure and Item 7 -- Financial
Statements and Exhibits, the Company reported the press release
issued February 5, 2004, regarding an Underwriting Agreement,
with respect to the issuance and sale by the Company and the
purchase by the Underwriters of 2,000,000 shares of the Company's
Common Stock. Pursuant to the Underwriting Agreement, the
Underwriters were granted a 30-day over-allotment option to
purchase up to an additional 300,000 shares of common stock from
the Company.
Form 8-K was filed on January 22, 2004. Under Item 5 -- Other
Events and Regulation FD Disclosure, Item 7 -- Financial
Statements, Pro Forma Financial Information and Exhibits and Item
12 -- Results of Operations and Financial Condition, the Company
reported the press release issued January 22, 2004, regarding
earnings for 2003.
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of
1934, the registrant has duly caused this report to be signed on its
behalf by the undersigned thereunto duly authorized.
MDU RESOURCES GROUP, INC.
DATE: May 7, 2004 BY: /s/ Warren L. Robinson
Warren L. Robinson
Executive Vice President
and Chief Financial
Officer
BY: /s/ Vernon A. Raile
Vernon A. Raile
Senior Vice President
and Chief Accounting
Officer
EXHIBIT INDEX
Exhibit No.
12 Computation of Ratio of Earnings to Fixed Charges
and Combined Fixed Charges and Preferred Stock
Dividends
31(a) Certification of Chief Executive Officer filed pursuant to
Section 302 of the Sarbanes-Oxley Act of 2002
31(b) Certification of Chief Financial Officer filed pursuant to
Section 302 of the Sarbanes-Oxley Act of 2002
32 Certification of Chief Executive Officer and Chief Financial
Officer furnished pursuant to 18 U.S.C. Section 1350, as
adopted pursuant to Section 906 of the Sarbanes-Oxley Act of
2002