UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
X QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
FOR THE QUARTERLY PERIOD ENDED September 30, 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 October 29, 2004: 118,097,432
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 and services
- Cyclical nature of large construction projects at certain
operations
- 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
- 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, The Republic of Trinidad and Tobago
(Trinidad and Tobago) and the United States. Electric
capacity and energy produced at the power plants are sold
primarily under long-term contracts to nonaffiliated
entities. Centennial Resources also provides analysis,
design, construction, refurbishment, and operation and
maintenance services to independent power producers. These
operations also include investments not directly being
pursued by the Company's other businesses. These activities
are reflected in this Form 10-Q under 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 this
Form 10-Q under independent power production and other.
INDEX
Part I -- Financial Information
Consolidated Statements of Income --
Three and Nine Months Ended September 30, 2004 and 2003
Consolidated Balance Sheets --
September 30, 2004 and 2003, and December 31, 2003
Consolidated Statements of Cash Flows --
Nine Months Ended September 30, 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
Unregistered Sales of Equity Securities and Use of Proceeds
Exhibits
Signatures
Exhibit Index
Exhibits
PART I -- FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
MDU RESOURCES GROUP, INC.
CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
Three Months Nine Months
Ended Ended
September 30, September 30,
2004 2003 2004 2003
(In thousands, except per share amounts)
Operating revenues:
Electric, natural gas distribution
and pipeline and energy services $149,623 $130,818 $ 540,837 $ 454,862
Utility services, natural gas and
oil production, construction
materials and mining and other 654,975 585,281 1,432,521 1,277,209
804,598 716,099 1,973,358 1,732,071
Operating expenses:
Fuel and purchased power 15,995 16,158 49,090 44,827
Purchased natural gas sold 24,305 19,888 158,583 123,619
Operation and maintenance:
Electric, natural gas distribution
and pipeline and energy services 37,307 33,375 117,834 104,852
Utility services, natural gas and
oil production, construction
materials and mining and other 527,669 461,100 1,171,126 1,015,483
Depreciation, depletion and
amortization 53,115 47,749 154,413 138,725
Taxes, other than income 25,525 22,163 72,876 61,266
Asset impairments (Notes 11 and 12) 6,106 --- 6,106 ---
690,022 600,433 1,730,028 1,488,772
Operating income 114,576 115,666 243,330 243,299
Other income -- net 10,927 2,491 25,290 11,124
Interest expense 14,285 13,604 43,784 39,283
Income before income taxes 111,218 104,553 224,836 215,140
Income taxes 39,499 39,032 70,907 78,449
Income before cumulative effect of
accounting change 71,719 65,521 153,929 136,691
Cumulative effect of accounting
change (Note 14) --- --- --- (7,589)
Net income 71,719 65,521 153,929 129,102
Dividends on preferred stocks 171 172 514 547
Earnings on common stock $ 71,548 $ 65,349 $ 153,415 $ 128,555
Earnings per common share -- basic:
Earnings before cumulative effect
of accounting change $ .61 $ .58 $ 1.32 $ 1.23
Cumulative effect of accounting
change --- --- --- (.07)
Earnings per common share -- basic $ .61 $ .58 $ 1.32 $ 1.16
Earnings per common share -- diluted:
Earnings before cumulative effect of
accounting change $ .60 $ .58 $ 1.31 $ 1.22
Cumulative effect of accounting
change --- --- --- (.07)
Earnings per common share --
diluted $ .60 $ .58 $ 1.31 $ 1.15
Dividends per common share $ .18 $ .17 $ .52 $ .49
Weighted average common shares
outstanding -- basic 117,109 112,359 116,112 111,100
Weighted average common shares
outstanding -- diluted 118,278 113,368 117,225 111,921
Pro forma amounts assuming retroactive
application of accounting change:
Net income $ 71,719 $ 65,521 $ 153,929 $ 136,691
Earnings per common share -- basic $ .61 $ .58 $ 1.32 $ 1.23
Earnings per common share --
diluted $ .60 $ .58 $ 1.31 $ 1.22
The accompanying notes are an integral part of these consolidated financial
statements.
MDU RESOURCES GROUP, INC.
CONSOLIDATED BALANCE SHEETS
(Unaudited)
September 30, September 30, December 31,
2004 2003 2003
(In thousands, except shares
and per share amounts)
ASSETS
Current assets:
Cash and cash equivalents $ 145,001 $ 91,900 $ 86,341
Receivables, net 465,748 410,666 357,677
Inventories 152,043 127,717 114,051
Deferred income taxes 4,244 1,950 3,104
Prepayments and other current assets 51,824 47,202 52,367
818,860 679,435 613,540
Investments 113,056 40,626 44,975
Property, plant and equipment 3,825,010 3,496,826 3,584,038
Less accumulated depreciation,
depletion and amortization 1,313,695 1,144,577 1,187,105
2,511,315 2,352,249 2,396,933
Deferred charges and other assets:
Goodwill 199,467 199,209 199,427
Other intangible assets, net 23,331 20,027 18,814
Other 88,451 106,723 106,903
311,249 325,959 325,144
$3,754,480 $3,398,269 $3,380,592
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Long-term debt due within one year $ 86,792 $ 7,892 $ 27,646
Accounts payable 183,451 183,506 150,316
Taxes payable 51,891 27,852 15,358
Dividends payable 21,414 19,436 19,442
Other accrued liabilities 159,071 113,463 101,299
502,619 352,149 314,061
Long-term debt 912,440 988,804 939,450
Deferred credits and other liabilities:
Deferred income taxes 475,354 403,540 444,779
Other liabilities 237,184 235,039 231,666
712,538 638,579 676,445
Commitments and contingencies
Stockholders' equity:
Preferred stocks 15,000 15,000 15,000
Common stockholders' equity:
Common stock
Shares issued -- $1.00 par value
118,395,863 at September 30,
2004, 113,583,312 at September 30,
2003 and 113,716,632 at
December 31, 2003 118,396 113,583 113,717
Other paid-in capital 854,519 752,276 757,787
Retained earnings 667,474 548,506 575,287
Accumulated other comprehensive loss (24,880) (7,002) (7,529)
Treasury stock at cost - 359,281
shares (3,626) (3,626) (3,626)
Total common stockholders' equity 1,611,883 1,403,737 1,435,636
Total stockholders' equity 1,626,883 1,418,737 1,450,636
$3,754,480 $3,398,269 $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)
Nine Months Ended
September 30,
2004 2003
(In thousands)
Operating activities:
Net income $ 153,929 $ 129,102
Cumulative effect of accounting change --- 7,589
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation, depletion and amortization 154,413 138,725
Earnings, net of distributions, from equity
method investments (17,203) (1,902)
Deferred income taxes 21,512 24,426
Asset impairments 6,106 ---
Changes in current assets and liabilities, net
of acquisitions:
Receivables (88,507) (63,354)
Inventories (32,066) (25,233)
Other current assets (1,021) (8,364)
Accounts payable 28,783 36,838
Other current liabilities 64,050 33,046
Other noncurrent changes 8,507 7,332
Net cash provided by operating activities 298,503 278,205
Investing activities:
Capital expenditures (225,165) (212,361)
Acquisitions, net of cash acquired (33,147) (132,070)
Net proceeds from sale or disposition of property 11,680 8,273
Investments (52,313) 4,298
Proceeds from notes receivable 22,000 7,812
Net cash used in investing activities (276,945) (324,048)
Financing activities:
Net change in short-term borrowings --- (20,000)
Issuance of long-term debt 72,215 243,063
Repayment of long-term debt (41,041) (99,307)
Proceeds from issuance of common stock, net 65,533 366
Dividends paid (59,605) (53,935)
Net cash provided by financing activities 37,102 70,187
Increase in cash and cash equivalents 58,660 24,344
Cash and cash equivalents -- beginning of year 86,341 67,556
Cash and cash equivalents -- end of period $ 145,001 $ 91,900
The accompanying notes are an integral part of these consolidated financial
statements.
MDU RESOURCES GROUP, INC.
NOTES TO CONSOLIDATED
FINANCIAL STATEMENTS
September 30, 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. Allowance for doubtful accounts
The Company's allowance for doubtful accounts as of
September 30, 2004 and 2003, and December 31, 2003, was
$7.5 million, $8.3 million and $8.1 million, respectively.
4. Earnings per common share
Basic earnings per common share were computed by dividing
earnings on common stock by the weighted average number of
shares of common stock outstanding during the 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 and nine months ended September 30, 2004, 36,000
and 205,305 shares, respectively, with an average exercise
price of $25.70 and $24.54, 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 and nine months ended
September 30, 2003, 209,805 shares with an average exercise
price of $24.56 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 and nine months ended September 30, 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.
5. 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 and nine
months ended September 30, 2004, was $3,000 and $8,000,
respectively (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
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 and nine months ended September 30, 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
September 30,
2004 2003
(In thousands, except
per share amounts)
Earnings on common stock, as
reported $ 71,548 $ 65,349
Stock-based compensation expense
included in reported earnings,
net of related tax effects 3 53
Total stock-based compensation
expense determined under fair
value method for all awards,
net of related tax effects (79) (618)
Pro forma earnings on common stock $ 71,472 $ 64,784
Earnings per common share -- basic --
as reported $ .61 $ .58
Earnings per common share -- basic --
pro forma $ .61 $ .58
Earnings per common share -- diluted --
as reported $ .60 $ .58
Earnings per common share -- diluted --
pro forma $ .60 $ .57
Nine Months Ended
September 30,
2004 2003
(In thousands, except
per share amounts)
Earnings on common stock, as
reported $153,415 $128,555
Stock-based compensation expense
included in reported earnings,
net of related tax effects 8 53
Total stock-based compensation
expense determined under fair
value method for all awards,
net of related tax effects (251) (1,925)
Pro forma earnings on common stock $153,172 $126,683
Earnings per common share -- basic --
as reported:
Earnings before cumulative effect
of accounting change $ 1.32 $ 1.23
Cumulative effect of accounting
change --- (.07)
Earnings per common share -- basic $ 1.32 $ 1.16
Earnings per common share -- basic --
pro forma:
Earnings before cumulative effect
of accounting change $ 1.32 $ 1.21
Cumulative effect of accounting
change --- (.07)
Earnings per common share -- basic $ 1.32 $ 1.14
Earnings per common share -- diluted
-- as reported:
Earnings before cumulative effect
of accounting change $ 1.31 $ 1.22
Cumulative effect of accounting
change --- (.07)
Earnings per common share --
diluted $ 1.31 $ 1.15
Earnings per common share -- diluted
-- pro forma:
Earnings before cumulative effect
of accounting change $ 1.31 $ 1.20
Cumulative effect of accounting
change --- (.07)
Earnings per common share --
diluted $ 1.31 $ 1.13
6. Cash flow information
Cash expenditures for interest and income taxes were as
follows:
Nine Months Ended
September 30,
2004 2003
(In thousands)
Interest, net of amount capitalized $35,334 $31,871
Income taxes paid, net $22,671 $35,341
7. 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.
8. 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" (FSP No. FAS 106-1). FSP 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).
In May 2004, the FASB issued FASB Staff Position No. FAS 106-2,
"Accounting and Disclosure Requirements Related to the Medicare
Prescription Drug, Improvement and Modernization Act of 2003
(FSP No. FAS 106-2). FSP No. FAS 106-2 requires (a) that the
effects of the federal subsidy be considered an actuarial gain
and recognized in the same manner as other actuarial gains and
losses and (b) certain disclosures for employers that sponsor
postretirement health care plans that provide prescription drug
benefits.
The Company provides prescription drug benefits to certain
eligible employees. The Company elected the one-time deferral
of accounting for the effects of the 2003 Medicare Act in the
quarter ended March 31, 2004, the first period in which the
plan's accounting for the effects of the 2003 Medicare Act
normally would have been reflected in the Company's financial
statements.
During the second quarter of 2004, the Company adopted FSP No.
FAS 106-2 retroactive to the beginning of the year. The
Company and its actuarial advisors determined that benefits
provided to certain participants are expected to be at least
actuarially equivalent to Medicare Part D (the federal
prescription drug benefit), and, accordingly, the Company
expects to be entitled to a federal subsidy. The expected
federal subsidy reduced the accumulated postretirement benefit
obligation (APBO) at January 1, 2004, by approximately $3.2
million, and net periodic benefit cost for 2004 by
approximately $285,000 (as compared with the amount calculated
without considering the effects of the subsidy). In addition,
the Company expects a reduction in future participation in the
postretirement plans, which further reduced the APBO at January
1, 2004, by approximately $12.7 million and net periodic
benefit cost for 2004 by approximately $1.3 million.
See Note 17 for the components of net periodic benefit cost.
The net periodic benefit cost for the three and nine months
ended September 30, 2004, was reduced by approximately $384,000
and $1.2 million, respectively, to reflect 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. 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 had 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. In September
2004, the FASB Staff issued FASB Staff Position No. FAS 142-2,
"Application of FASB Statement No. 142, Goodwill and Other
Intangible Assets, to Oil- and Gas-Producing Entities," (FSP
No. 142-2). FSP No. 142-2 indicates that the exception in SFAS
No. 142 does not change the accounting prescribed in SFAS No.
19, "Financial Accounting and Reporting by Oil and Gas
Producing Companies," including the balance sheet
classification of drilling and mineral rights of oil and gas
producing entities and, as a result, the contractual mineral
rights should continue to be classified as part of property,
plant and equipment. FSP No. 142-2 did not have an effect on
the Company's financial position, results of operations or cash
flows.
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,'" (FSP Nos. FAS 141-1
and FAS 142-1). FSP Nos. 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 be classified as tangible assets rather than intangible
assets. The Company adopted FSP Nos. FAS 141-1 and FAS 142-1
in the second quarter of 2004. FSP Nos. FAS 141-1 and FAS 142-
1 required 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.
FSP Nos. FAS 141-1 and FAS 142-1 affected the asset
classification in the consolidated balance sheet and associated
footnote disclosure only, so the reclassifications did not
affect the Company's stockholders' equity, cash flows or
results of operations.
In September 2004, the Securities and Exchange Commission
issued Staff Accounting Bulletin No. 106 (SAB 106) which is an
interpretation regarding the application of FASB Statement No.
143, "Accounting for Asset Retirement Obligations" (SFAS No.
143) by oil and gas producing companies following the full cost
accounting method. SAB 106 clarifies that the future cash
outflows associated with settling asset retirement obligations
that have been accrued on the balance sheet should be excluded
from the computation of the present value of estimated future
net revenues for purposes of the full cost ceiling calculation.
SAB 106 also states that a company is expected to disclose in
the financial statement footnotes and Management's Discussion
and Analysis how the company's calculation of the ceiling test
and depreciation, depletion and amortization are affected by
the adoption of SFAS No. 143. SAB 106 shall be applied to all
entities subject to SAB 106 as of the beginning of the first
quarter beginning after October 4, 2004.
The adoption of SAB 106 is not expected to have a material
effect on the Company's financial position or results of
operations.
9. Comprehensive income
Comprehensive income is the sum of net income as reported and
other comprehensive income (loss). The Company's other
comprehensive income (loss) resulted from gains (losses) on
derivative instruments qualifying as hedges and foreign
currency translation adjustments. For more information on
derivative instruments, see Note 13 of Notes to Consolidated
Financial Statements.
Comprehensive income, and the components of other comprehensive
income (loss) and related tax effects, was as follows:
Three Months Ended
September 30,
2004 2003
(In thousands)
Net income $ 71,719 $ 65,521
Other comprehensive income (loss):
Net unrealized gain (loss) on
derivative instruments qualifying
as hedges:
Net unrealized gain (loss) on
derivative instruments arising
during the period, net of tax of
$7,255 and $1,545 in 2004 and 2003,
respectively (11,768) 2,416
Less: Reclassification adjustment
for gain (loss) on derivative
instruments included in net income,
net of tax of $2,166 and $2,839 in
2004 and 2003, respectively (3,388) (4,522)
Net unrealized gain (loss) on
derivative instruments qualifying
as hedges (8,380) 6,938
Foreign currency translation
adjustment 919 1,698
(7,461) 8,636
Comprehensive income $ 64,258 $ 74,157
Nine Months Ended
September 30,
2004 2003
(In thousands)
Net income $153,929 $129,102
Other comprehensive income (loss):
Net unrealized gain (loss) on
derivative instruments qualifying
as hedges:
Net unrealized gain (loss) on
derivative instruments arising
during the period, net of tax of
$12,069 and $983 in 2004 and 2003,
respectively (19,297) (1,537)
Less: Reclassification adjustment
for gain (loss) on derivative
instruments included in net income,
net of tax of $1,576 and $2,171 in
2004 and 2003, respectively (2,465) (3,397)
Net unrealized gain (loss) on
derivative instruments qualifying
as hedges (16,832) 1,860
Foreign currency translation
adjustment (519) 942
(17,351) 2,802
Comprehensive income $136,578 $131,904
10. Equity method investments
The Company has a number of equity method investments,
including MPX Participacoes, Ltda. (MPX), Carib Power
Management LLC (Carib Power) and Hartwell Energy Limited
Partnership (Hartwell). The Company assesses its equity method
investments for impairment whenever events or changes in
circumstances indicate that such carrying values may not be
recoverable. None of the Company's equity method investments
have been impaired and, accordingly, no impairment losses have
been recorded in the accompanying consolidated financial
statements or related equity method investment balances.
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 and operates 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 electric power sales
contract with Petrobras for 110 megawatts expires in November
2007 and the portion of the contract for the remaining 110
megawatts expires in May 2008. Petrobras also is under
contract to supply natural gas to the Brazil Generating
Facility during the term of the electric power sales contract.
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 electric power sales contract 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 electric power
sales contract was $690,000 (after tax) for the three months
ended September 30, 2004. The Company's 49 percent share of
the gain from the change in the fair value of the embedded
derivative in the electric power sales contract was $3.4
million (after tax) for the nine months ended September 30,
2004. The Company's 49 percent share of the loss from the
change in the fair value of the embedded derivative in the
electric power sales contract was $3.0 million (after tax) and
$9.0 million (after tax) for the three and nine months ended
September 30, 2003, respectively. The Company's 49 percent
share of the foreign currency gain resulting from an increase
in value of the Brazilian Real versus the U.S. dollar was $2.1
million (after tax) and $124,000 (after tax) for the three and
nine months ended September 30, 2004, respectively. The
Company's 49 percent share of the foreign currency loss
resulting from the decrease in value of the Brazilian Real
versus the U.S. dollar was $476,000 (after tax) for the three
months ended September 30, 2003. The Company's 49 percent
share of the foreign currency gain resulting from the increase
in value of the Brazilian Real versus the U.S. dollar was $2.6
million (after tax) for the nine months ended September 30,
2003.
In February 2004, Centennial Energy Resources International,
Inc. (Centennial International), an indirect wholly owned
subsidiary of the Company, acquired 49.99 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.
In September 2004, Centennial Resources, through a wholly owned
subsidiary, acquired a 50 percent ownership interest in
Hartwell. Hartwell owns and operates a 310-megawatt natural
gas-fired electric generating facility (Hartwell Generating
Facility) located in Hartwell, Georgia and sells its output to
Oglethorpe Power Corporation under a long-term agreement.
At September 30, 2004, MPX, Carib Power and Hartwell had total
assets of $333.2 million and long-term debt of $240.7 million.
The Company's investment in the Brazil, Trinidad and Tobago and
Hartwell Generating Facilities was approximately $59.2 million,
including undistributed earnings of $20.8 million at September
30, 2004. The Company's investment in the Brazil Generating
Facility was approximately $20.6 million at September 30, 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 was $7.2 million and $18.3 million for the three
and nine months ended September 30, 2004, respectively, and was
included in other income - net. The Company's share of income
from its equity method investments was $961,000 and $3.2
million for the three and nine months ended September 30, 2003,
respectively, and was included in other income - net.
11. Impairment of long-lived asset
During the third quarter of 2004, the Company recognized a $2.1
million ($1.3 million after tax) adjustment reflecting the
reduction in value of certain gathering facilities in the Gulf
Coast region at the pipeline and energy services segment.
12. Goodwill and other intangible assets
The changes in the carrying amount of goodwill were as follows:
Balance Goodwill Goodwill Balance
as of Acquired Impaired as of
Nine Months Ended January 1, During During September 30,
September 30, 2004 2004 the Year* the Year 2004
(In thousands)
Electric $ --- $ --- $ --- $ ---
Natural gas
distribution --- --- --- ---
Utility services 62,604 28 --- 62,632
Pipeline and energy
services 9,494 --- (4,030) 5,464
Natural gas and oil
production --- --- --- ---
Construction materials
and mining 120,198 276 --- 120,474
Independent power
production and other 7,131 3,766 --- 10,897
Total $199,427 $4,070 $(4,030) $199,467
Balance Goodwill Balance
as of Acquired as of
Nine Months Ended January 1, During September 30,
September 30, 2003 2003 the Year* 2003
(In thousands)
Electric $ --- $ --- $ ---
Natural gas
distribution --- --- ---
Utility services 62,487 127 62,614
Pipeline and energy
services 9,494 --- 9,494
Natural gas and oil
production --- --- ---
Construction materials
and mining 111,887 8,083 119,970
Independent power
production and other 7,131 --- 7,131
Total $190,999 $ 8,210 $199,209
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.
Innovatum, Inc. (Innovatum), an indirect wholly owned subsidiary
of the Company which specializes in cable and pipeline
magnetization and location, developed a hand-held locating device
that can detect both magnetic and plastic materials, including
unexploded ordnance. Innovatum was working with, and had
demonstrated the device to, a Department of Defense contractor and
had also met with individuals from the Department of Defense, to
discuss the possibility of using the hand-held locating device in
their operations. In the third quarter of 2004, after
communications with the Department of Defense, and delays in
further testing resulting from a Department of Defense request to
enhance the hand-held locating device, Innovatum decreased its
expected future cash flows from the hand-held locating device.
This decrease, coupled with the continued downturn in the
telecommunications and energy industries, resulted in a revised
earnings forecast for Innovatum, and as a result, a goodwill
impairment loss of $4.0 million was recognized for the third
quarter of 2004. Innovatum, a reporting unit for goodwill
impairment testing, is part of the pipeline and energy services
segment. The fair value of Innovatum was estimated using the
expected present value of future cash flows.
As discussed in Note 8, the Company reclassified its leasehold
rights at its construction materials and mining operations from
other intangible assets, net to property, plant and equipment.
Other intangible assets were as follows:
September 30, September 30, December 31,
2004 2003 2003
(In thousands)
Amortizable intangible assets:
Noncompete agreements $13,275 $ 12,075 $12,075
Accumulated amortization (8,345) (9,621) (9,690)
4,930 2,454 2,385
Other 21,584 17,736 17,734
Accumulated amortization (4,143) (1,766) (2,265)
17,441 15,970 15,469
Unamortizable intangible
assets 960 1,603 960
Total $23,331 $ 20,027 $18,814
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 and nine months ended September 30, 2004, was $1.0 and
$2.3 million, respectively. Amortization expense for
amortizable intangible assets for the three and nine months
ended September 30, 2003, and for the year ended December 31,
2003, was $567,000, $1.6 million and $2.2 million,
respectively. Estimated amortization expense for amortizable
intangible assets is $3.3 million in 2004, $3.1 million in
2005, $2.4 million in 2006, $2.3 million in 2007, $2.3 million
in 2008 and $11.3 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 and Note 9 of
Notes to Consolidated Financial Statements.
As of September 30, 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 its
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 and nine months ended September 30, 2004 and
2003, the amount of hedge ineffectiveness recognized, which was
included in operating revenues, was immaterial. For the three
and nine months ended September 30, 2004 and 2003, Fidelity did
not exclude any components of the derivative instruments' gain
or loss from the assessment of hedge effectiveness and there
were no reclassifications into earnings as a result of the
discontinuance of hedges.
Gains and losses on derivative instruments that are
reclassified from accumulated other comprehensive income (loss)
to current-period earnings are included in the line item in
which the hedged item is recorded. As of September 30, 2004,
the maximum term of Fidelity's swap and collar agreements, in
which it is hedging its exposure to the variability in future
cash flows for forecasted transactions, is 15 months. Fidelity
estimates that over the next 12 months net losses of
approximately $16.6 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
Trinidad and Tobago, as discussed in Note 10. The electric
segment generates, transmits and distributes electricity, and
the natural gas distribution segment distributes natural gas.
These operations also supply related value-added products and
services in the northern Great Plains. The utility services
segment 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, Trinidad and Tobago
and the United States. Electric capacity and energy produced
at the power plants are sold primarily under long-term
contracts to nonaffiliated entities. Centennial Resources also
provides analysis, design, construction, refurbishment, and
operation and maintenance services to independent power
producers. These operations also include investments 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
September 30, 2004
Electric $ 47,888 $ --- $ 5,580
Natural gas distribution 32,389 --- (3,230)
Pipeline and energy
services 69,346 17,675 (1,639)
149,623 17,675 711
Utility services 111,765 1,138 (568)
Natural gas and oil
production 40,475 45,193 27,398
Construction materials
and mining 486,625 263 34,974
Independent power
production and other 16,110 1,267 9,033
654,975 47,861 70,837
Intersegment eliminations --- (65,536) ---
Total $ 804,598 $ --- $ 71,548
Inter-
External segment Earnings
Operating Operating on Common
Revenues Revenues Stock
(In thousands)
Three Months Ended
September 30, 2003
Electric $ 47,935 $ --- $ 6,279
Natural gas distribution 27,710 --- (2,524)
Pipeline and energy
services 55,173 6,230 4,662
130,818 6,230 8,417
Utility services 116,091 --- 1,669
Natural gas and oil
production 33,381 31,518 16,530
Construction materials
and mining 426,470 --- 36,135
Independent power
production and other 9,339 740 2,598
585,281 32,258 56,932
Intersegment eliminations --- (38,488) ---
Total $ 716,099 $ --- $ 65,349
Inter-
External segment Earnings
Operating Operating on Common
Revenues Revenues Stock
(In thousands)
Nine Months Ended
September 30, 2004
Electric $ 134,711 $ --- $ 9,723
Natural gas distribution 208,167 --- (2,002)
Pipeline and energy
services 197,959 58,711 5,478
540,837 58,711 13,199
Utility services 309,243 1,138 (4,763)
Natural gas and oil
production 117,019 133,837 78,794
Construction materials
and mining 973,098 463 43,437
Independent power
production and other 33,161 3,104 22,748
1,432,521 138,542 140,216
Intersegment eliminations --- (197,253) ---
Total $1,973,358 $ --- $153,415
Inter-
External segment Earnings
Operating Operating on Common
Revenues Revenues Stock
(In thousands)
Nine Months Ended
September 30, 2003
Electric $ 131,655 $ --- $ 12,862
Natural gas distribution 181,104 --- 430
Pipeline and energy
services 142,103 36,656 14,056
454,862 36,656 27,348
Utility services 328,682 --- 4,294
Natural gas and oil
production 111,246 87,334 46,062
Construction materials
and mining 811,352 --- 41,498
Independent power
production and other 25,929 2,221 9,353
1,277,209 89,555 101,207
Intersegment eliminations --- (126,211) ---
Total $1,732,071 $ --- $128,555
Excluding the asset impairments at pipeline and energy services
of $5.3 million (after tax), earnings (loss) from electric,
natural gas distribution and pipeline and energy services are
substantially all from regulated operations. Earnings from
utility services, natural gas and oil production, construction
materials and mining, and independent power production and
other are all from nonregulated operations.
16. Acquisitions
During the first nine months of 2004, the Company acquired a
number of businesses, none of which was individually material,
including construction materials and mining businesses in Idaho,
Iowa and Minnesota and an independent power production operating
and development company in Colorado. 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 $66.3 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. As discussed in Note 8, the Company recognized the
effects of the 2003 Medicare Act during the second quarter of
2004. The net periodic benefit cost for 2004 reflects
the effects of the 2003 Medicare Act. Components of net
periodic benefit cost for the Company's pension and
other postretirement benefit plans were as follows:
Other
Pension Postretirement
Three Months Benefits Benefits
Ended September 30, 2004 2003 2004 2003
(In thousands)
Components of net periodic
benefit cost:
Service cost $ 1,917 $ 1,516 $ 447 $ 488
Interest cost 3,976 3,812 1,086 1,394
Expected return on
assets (5,094) (5,140) (986) (986)
Amortization of prior
service cost 280 293 36 24
Recognized net actuarial
(gain) loss 121 (124) (40) 2
Amortization of net
transition obligation
(asset) (63) (238) 538 537
Net periodic benefit cost 1,137 119 1,081 1,459
Less amount capitalized 111 13 137 179
Net periodic benefit cost $ 1,026 $ 106 $ 944 $ 1,280
Other
Pension Postretirement
Nine Months Benefits Benefits
Ended September 30, 2004 2003 2004 2003
(In thousands)
Components of net periodic
benefit cost:
Service cost $ 5,750 $ 4,380 $ 1,343 $ 1,372
Interest cost 11,928 11,400 3,259 3,887
Expected return on
assets (15,281) (15,590) (2,958) (2,948)
Amortization of prior
service cost 841 863 108 24
Recognized net actuarial
(gain) loss 360 (260) (122) (257)
Amortization of net
transition obligation
(asset) (188) (712) 1,614 1,613
Net periodic benefit cost 3,410 81 3,244 3,691
Less amount capitalized 302 (35) 319 387
Net periodic benefit cost $ 3,108 $ 116 $ 2,925 $ 3,304
As of September 30, 2004, approximately $1.3 million has been
contributed to the defined benefit pension plans and
approximately $3.1 million has been contributed to the
postretirement benefit plans. The Company presently
anticipates contributing an additional $300,000 to its pension
plans in 2004 for a total of $1.6 million for the year. The
Company presently anticipates contributing an additional
$600,000 to its postretirement benefit plans in 2004 for a
total of $3.7 million for the year.
In addition to the qualified plan defined pension benefits
reflected in the tables above, the Company also has an
unfunded, nonqualified benefit plan for executive officers and
certain key management employees that provides for defined
benefit payments at age 65 following the employee's retirement
or to the beneficiaries upon death for a 15-year period. The
Company's net periodic benefit cost for this plan for the three
and nine months ended September 30, 2004, was $1.8 million and
$5.6 million, respectively. The Company's net periodic benefit
cost for this plan for the three and nine months ended
September 30, 2003, was $1.4 million and $3.8 million,
respectively.
18. Regulatory matters and revenues subject to refund
On September 7, 2004, Great Plains filed an application with
the Minnesota Public Utilities Commission (MPUC) for a natural
gas rate increase. Great Plains requested a total of $1.4
million annually or 4.0 percent above current rates. The
Company requested an interim increase of $1.4 million annually
to be effective November 7, 2004. On October 21, 2004, the
MPUC ordered Great Plains to file supplemental information
necessary to determine the completeness of the filing.
Supplemental information is expected to be filed with the MPUC
in November 2004. Interim rates will be effective 60 days from
the date the filing is determined to be complete. A final
order from the MPUC is expected in late 2005.
On June 7, 2004, Montana-Dakota filed an application with the
South Dakota Public Utilities Commission (SDPUC) for a natural
gas rate increase for the Black Hills service area. Montana-
Dakota requested a total of $1.3 million annually or 2.2
percent above current rates. A final order from the SDPUC is
due December 7, 2004.
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. The MTPSC
has not acted on Montana-Dakota's request for an interim
increase of $500,000 on an annual basis. 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. 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. On September 22,
2004, the NDPSC approved a Settlement Agreement. The
Settlement Agreement results in an increase in annual revenues
of $2.5 million or 2.1 percent effective October 1, 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.
On May 11, 2004, the FERC issued an Order on Rehearing and
Compliance and Remanding Certain Issues for Hearing (Order on
Rehearing). The Order on Rehearing denied rehearing on all of
the issues addressed by Williston Basin in its August 2003
request for rehearing except for the issue of the proper rate
to utilize for transmission system negative salvage expenses.
In addition, the FERC remanded the issues regarding certain
service and annual demand quantity restrictions to an ALJ for
resolution. On June 14, 2004, Williston Basin requested
clarification of a few of the issues addressed in the May 11,
2004, Order on Rehearing including determinations associated
with cost of service and cost allocation, as discussed in the
FERC's Order on Rehearing. On June 14, 2004, Williston Basin
also made its filing to comply with the requirements of the
various FERC orders in this proceeding. Williston Basin is
awaiting a decision from the FERC on Williston Basin's
compliance filing and clarification 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.
On June 4, 2004, following preliminary discovery, Williston
Basin and Montana-Dakota joined with other defendants and filed
a Motion to Dismiss on the grounds that the information upon
which Grynberg bases his complaint was publicly disclosed prior
to the filing of his complaint and further, that he is not the
original source of such information. The Motion to Dismiss is
additionally based on the grounds that Grynberg disclosed the
filing of the complaint prior to the entry of a court order
allowing such disclosure and that Grynberg failed to provide
adequate information to the government prior to filing suit.
In the event the Motion to Dismiss is not granted, it is
expected that further discovery will follow. Williston Basin
and Montana-Dakota believe Grynberg will not prevail in the
suit or recover damages from Williston Basin and/or Montana-
Dakota because insufficient facts exist to support the
allegations. Williston Basin and Montana-Dakota believe
Grynberg's claims are without merit and intend to vigorously
contest this suit.
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.
Fidelity has been named as a defendant in, and/or certain of
its operations are or have been the subject of, over a dozen
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 May 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, the National
Environmental Policy Act, the Federal Land Management Policy
Act, the National Historic Preservation Act and the Montana
Environmental Policy Act. The cases involving alleged
violations of the Federal Clean Water Act have been resolved
without a finding that Fidelity is in violation of the Federal
Clean Water Act. Fidelity presently has no exposure to
penalties, fines or damages for any claims under the Federal
Clean Water Act. The suits that remain extant include a
variety of claims that state and federal government agencies
violated various environmental laws that impose procedural
requirements such as the National Environmental Policy Act, the
Federal Land Management Policy Act, the National Historic
Preservation Act and the Montana Environmental Policy Act.
These 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 these
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 matter, the State of North Dakota (State) and the
EPA entered into a Memorandum of Understanding (MOU) on
February 24, 2004, stating the principles to be used by the
State in completing dispersion modeling of air quality in
Theodore Roosevelt National Park and other "Class I" areas in
North Dakota and Montana.
In April 2004, the Dakota Resource Council filed a petition for
review of the MOU with the United States Eighth Circuit Court
of Appeals. The Petition was dismissed, without prejudice, in
June 2004 upon stipulation of the EPA, the Dakota Resource
Council and the State.
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 Brazil Generating Facility, as
discussed in Note 10. 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 September 30, 2004, the
aggregate amount of borrowings outstanding subject to these
guarantees was $34.7 million and the scheduled repayment of
these borrowings is $10.8 million in 2005, $10.7 million in
2006 and 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, which are joint and
several obligations. 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 September 30, 2004, was $13.6 million. There is
no fixed maximum amount guaranteed in relation to the natural
gas and oil price swap and 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
September 30, 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
September 30, 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 September 30, 2004, the fixed maximum amounts
guaranteed under these agreements aggregated $81.7 million.
The amounts of scheduled expiration of the maximum amounts
guaranteed under these agreements aggregate $6.7 million in
2004; $35.8 million in 2005; $3.8 million in 2006; $1.7 million
in 2007; $96,000 in 2008; $2.1 million in 2009; $15.0 million
in 2010; $12.0 million in 2012; $500,000, which is subject to
expiration 30 days after the receipt of written notice; and
$4.0 million, which has no scheduled maturity date. The amount
outstanding by subsidiaries of the Company under the above
guarantees was $347,000 and was reflected on the Consolidated
Balance Sheets at September 30, 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 September 30, 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 September 30, 2004,
because these intercompany transactions are eliminated in
consolidation.
In addition, Centennial has issued guarantees to third parties
related to the Company's routine purchase of maintenance items
for which no fixed maximum amounts have been specified. These
guarantees have no scheduled maturity date. In the event a
subsidiary of the Company defaults under its obligation in
relation to the purchase of certain maintenance items,
Centennial would be required to make payments under these
guarantees. Any amounts outstanding by subsidiaries of the
Company for these maintenance items were reflected on the
Consolidated Balance Sheets at September 30, 2004.
As of September 30, 2004, Centennial was contingently liable
for performance of certain of its subsidiaries under
approximately $331 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 is 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.
20. Related party transactions
In 2004, Bitter Creek Pipelines, LLC (Bitter Creek), an
indirect wholly owned subsidiary of the Company, entered into
two natural gas gathering agreements with Nance Petroleum
Corporation (Nance), a wholly owned subsidiary of St. Mary Land
& Exploration Company (St. Mary). Mr. Robert Nance, an
executive officer and shareholder of St. Mary, is also a member
of the Board of Directors of the Company. The natural gas
gathering agreements with Nance are effective upon completion
of certain high and low pressure gathering facilities, which is
expected to occur later this year. Bitter Creek estimates
capital expenditures related to the completion of the gathering
lines and the expansion of its gathering facilities to
accommodate the natural gas gathering agreements for the next
three years to be approximately $8.5 million in 2004, $2.2
million in 2005 and $2.2 million in 2006. The natural gas
gathering agreements are each for a term of 15 years and month-
to-month thereafter. Bitter Creek estimates revenues from
these contracts for the next three years to be approximately
$80,000 in 2004, $1.9 million in 2005 and $3.8 million in 2006.
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
electric and natural gas distribution segments also supply related
value-added products and services in the northern Great Plains. The
utility services segment includes all the operations of Utility
Services, Inc., which 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 includes WBI Holdings' 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 includes the natural gas and oil acquisition, exploration,
development and production operations, primarily in the Rocky
Mountain region of the United States and in and around the Gulf of
Mexico, of WBI Holdings. The construction materials and mining
segment includes the results of Knife River, which 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
Trinidad and Tobago. Electric capacity and energy produced at the
power plants are sold primarily under long-term contracts to
nonaffiliated entities. Centennial Resources also provides
analysis, design, construction, refurbishment, and operation and
maintenance services to independent power producers. These
operations also include investments not directly being pursued by
the Company's other businesses.
Excluding the asset impairments at pipeline and energy services of
$5.3 million (after tax), earnings (loss) 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.
The Company's strategy is to apply its expertise in energy and
transportation infrastructure industries to increase market share
through internal growth along with acquisition of well-managed
companies and development of projects that enhance shareholder value
and are accretive to earnings per share and returns on invested
capital.
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 $410 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 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, a number of 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 Nine Months
Ended Ended
September 30, September 30,
2004 2003 2004 2003
Electric $ 5.6 $ 6.3 $ 9.7 $ 12.9
Natural gas distribution (3.2) (2.5) (2.0) .4
Utility services (.6) 1.7 (4.8) 4.3
Pipeline and energy services (1.6) 4.6 5.5 14.1
Natural gas and oil production 27.4 16.5 78.8 46.1
Construction materials and mining 34.9 36.1 43.4 41.5
Independent power production
and other 9.0 2.6 22.8 9.3
Earnings on common stock $71.5 $ 65.3 $153.4 $128.6
Earnings per common
share - basic $ .61 $ .58 $ 1.32 $ 1.16
Earnings per common
share - diluted $ .60 $ .58 $ 1.31 $ 1.15
Return on average common equity
for the 12 months ended 13.2% 13.4%
________________________________
Three Months Ended September 30, 2004 and 2003
Consolidated earnings for the quarter ended September 30, 2004,
increased $6.2 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 pipeline and energy services, utility services,
construction materials and mining, natural gas distribution and
electric businesses partially offset the earnings increase.
Natural gas and oil production earnings increased $10.9 million due
to higher average realized natural gas and oil prices, increased
natural gas production, partially offset by higher depreciation,
depletion and amortization expense and higher general and
administrative expenses.
Earnings increased $6.4 million at the independent power production
and other businesses due to the effects of changes in foreign
currency rates and the value of the embedded derivative in the
Brazilian electric power sales contract, lower financing costs, and
acquisitions made since the comparable prior period.
Pipeline and energy services experienced a $1.6 million loss
compared to $4.6 million in earnings for the comparable prior period
due primarily to a $4.0 million (before and after tax) noncash
goodwill impairment relating to the Company's cable and pipeline
magnetization and location business, as well as a $1.3 million
(after tax) adjustment reflecting the reduction in value of certain
gathering facilities in the Gulf Coast region. Higher operating
expenses and lower average transportation rates also contributed to
the unfavorable variance. Partially offsetting the decrease in
earnings was higher natural gas volumes transported to storage,
increased natural gas transportation volumes on the Grasslands
Pipeline and higher gathering rates.
Utility services experienced a $600,000 loss compared to $1.7
million of earnings for the comparable prior period due primarily to
lower inside electrical margins and workload, as well as severance-
related expenses.
The decrease in construction materials and mining earnings of $1.2
million reflects the effects of wet weather in certain regions,
decreased benefits realized from the substantially complete harbor-
deepening project in southern California and higher operating costs
in Minnesota resulting in lower aggregate margins. Also adding to
the decline in earnings were lower construction revenues, slightly
lower asphalt volumes and margins and higher fuel costs. Earnings
from companies acquired since the comparable prior period and higher
ready-mixed concrete volumes and margins partially offset the
earnings decrease.
The natural gas distribution business experienced a seasonal loss
which was $700,000 higher than the comparable prior period as a
result of higher operation and maintenance expenses partially
offset by higher retail sales prices, the result of rate increases
effective in Minnesota, South Dakota and North Dakota.
Electric earnings decreased $700,000 as a result of lower retail
sales volumes, higher operation and maintenance expense, and
decreased sales for resale prices and volumes. The seasonal effects
of a new rate design for retail customers in North Dakota combined
with higher sales to large industrial customers, partially offset
the earnings decrease.
Nine Months Ended September 30, 2004 and 2003
Consolidated earnings for the nine months ended September 30, 2004,
increased $24.8 million from the comparable prior period due to
higher earnings at the natural gas and oil production, independent
power production and other, and construction materials and mining
businesses. Decreased earnings at the utility services, pipeline
and energy services, electric, and natural gas distribution
businesses partially offset the earnings increase.
In 2004, the Company resolved federal and related state income tax
matters for the 1998 through 2000 tax years. The Company reflected
the effects of this tax resolution and, in addition, reversed
reserves that had previously been provided and were deemed to be no
longer required, which resulted in a benefit of $5.9 million (after-
tax), including interest, for the nine months ended September 30,
2004.
Natural gas and oil production earnings increased $32.7 million due
to higher average realized natural gas and oil prices, increased
natural gas production, and 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.
A favorable resolution of federal and related state income tax
matters also contributed to the increase in earnings. Higher
depreciation, depletion and amortization expense; higher general and
administrative expense; and higher interest expense, partially
offset the earnings increase.
Earnings increased $13.5 million at the independent power production
and other businesses due to changes in value of the embedded
derivative in the Brazilian electric power sales contract, lower
financing costs and new acquisitions since the comparable prior
period, partially offset by the effects of changes in foreign
currency rates.
Earnings at the construction materials and mining business increased
$1.9 million as a result of higher ready-mixed concrete and asphalt
volumes and margins, earnings from companies acquired since the
comparable prior period and a favorable resolution of federal and
related state income tax matters. Lower aggregate volumes at a
large harbor-deepening project in southern California which is now
substantially complete, as well as higher general and administrative
expenses, partially offset the earnings increase.
Utility services experienced a $4.8 million loss compared to $4.3
million of earnings for the comparable prior period due primarily to
lower inside electrical margins and workload, as well as severance-
related expenses.
Earnings decreased $8.6 million at the pipeline and energy services
business due to a $4.0 million (before and after tax) goodwill
impairment and a $1.3 million (after tax) asset valuation
adjustment, as previously discussed; lower revenues from traditional
off-system transportation services; higher operating expenses; and
lower average transportation rates. Higher natural gas
transportation volumes on the Grasslands Pipeline, higher natural
gas volumes transported into storage and a favorable resolution of
federal and related state income tax matters, partially offset the
decrease in earnings.
Electric earnings decreased $3.2 million as a result of higher
operation and maintenance expense, higher fuel and purchased power-
related costs, lower retail sales volumes and increased interest
expense. Higher average sales for resale prices, the seasonal
effects of the North Dakota rate design, and a favorable resolution
of federal and related state income tax matters, partially offset
the decrease in earnings.
Natural gas distribution experienced a loss of $2.0 million compared
to earnings of $400,000 for the comparable prior period due to
higher operation and maintenance expense, lower service and repair
margins and lower retail sales volumes. Higher retail sales prices,
the result of rate increases effective in South Dakota, Minnesota
and North Dakota; and a favorable resolution of federal and related
state income tax matters, partially offset the decrease in earnings.
Financial and operating data
The following tables (dollars in millions, where applicable) are key
financial and operating statistics for each of the Company's
businesses.
Electric
Three Months Nine Months
Ended Ended
September 30, September 30,
2004 2003 2004 2003
Operating revenues $ 47.9 $ 47.9 $ 134.7 $ 131.7
Operating expenses:
Fuel and purchased power 16.0 16.1 49.1 44.8
Operation and maintenance 14.0 12.6 43.5 38.9
Depreciation, depletion and
amortization 5.0 5.1 15.1 15.0
Taxes, other than income 2.0 1.9 6.2 5.8
37.0 35.7 113.9 104.5
Operating income $ 10.9 $ 12.2 $ 20.8 $ 27.2
Retail sales (million kWh) 595.5 630.2 1,721.9 1,760.0
Sales for resale (million kWh) 190.8 212.7 588.1 587.1
Average cost of fuel and
purchased power per kWh $ .019 $ .018 $ .020 $ .018
Natural Gas Distribution
Three Months Nine Months
Ended Ended
September 30, September 30,
2004 2003 2004 2003
Operating revenues:
Sales $ 31.4 $ 26.8 $ 204.9 $ 178.1
Transportation and other 1.0 .9 3.3 3.0
32.4 27.7 208.2 181.1
Operating expenses:
Purchased natural gas sold 22.1 18.1 163.1 136.6
Operation and maintenance 11.3 9.7 36.4 31.4
Depreciation, depletion and
amortization 2.4 2.4 7.0 7.6
Taxes, other than income 1.3 1.3 4.3 3.9
37.1 31.5 210.8 179.5
Operating income (loss) $ (4.7) $ (3.8) $ (2.6)$ 1.6
Volumes (MMdk):
Sales 3.1 3.1 24.9 25.9
Transportation 2.7 2.8 9.1 8.8
Total throughput 5.8 5.9 34.0 34.7
Degree days (% of normal)* 66% 92% 95% 100%
Average cost of natural gas,
including transportation
thereon, per dk $ 7.07 $ 5.80 $ 6.56 $ 5.27
_____________________
* Degree days are a measure of the daily temperature-related demand
for energy for heating.
Utility Services
Three Months Nine Months
Ended Ended
September 30, September 30,
2004 2003 2004 2003
Operating revenues $ 112.9 $ 116.1 $ 310.4 $ 328.7
Operating expenses:
Operation and maintenance 106.4 106.5 295.3 300.4
Depreciation, depletion
and amortization 2.6 2.6 7.9 7.7
Taxes, other than income 3.8 3.6 12.2 11.4
112.8 112.7 315.4 319.5
Operating income (loss) $ .1 $ 3.4 $ (5.0)$ 9.2
Pipeline and Energy Services
Three Months Nine Months
Ended Ended
September 30, September 30,
2004 2003 2004 2003
Operating revenues:
Pipeline $ 21.5 $ 24.2 $ 67.2 $ 74.7
Energy services 65.5 37.2 189.4 104.1
87.0 61.4 256.6 178.8
Operating expenses:
Purchased natural gas sold 60.5 36.5 177.1 101.3
Operation and maintenance 12.0 11.0 37.9 34.8
Depreciation, depletion
and amortization 4.1 3.8 13.3 11.2
Taxes, other than income 1.9 1.4 5.7 4.3
Asset impairments 6.1 --- 6.1 ---
84.6 52.7 240.1 151.6
Operating income $ 2.4 $ 8.7 $ 16.5 $ 27.2
Transportation volumes (MMdk):
Montana-Dakota 8.2 9.2 24.1 25.6
Other 26.4 13.7 60.9 44.3
34.6 22.9 85.0 69.9
Gathering volumes (MMdk) 20.3 18.8 59.6 56.4
Natural Gas and Oil Production
Three Months Nine Months
Ended Ended
September 30, September 30,
2004 2003 2004 2003
Operating revenues:
Natural gas $ 68.2 $ 52.7 $ 203.0 $ 160.5
Oil 16.2 12.2 45.4 37.9
Other 1.2 --- 2.4 .2
85.6 64.9 250.8 198.6
Operating expenses:
Purchased natural gas sold 1.1 --- 2.2 .1
Operation and maintenance:
Lease operating costs 8.6 8.4 25.4 22.9
Gathering and transportation 3.4 4.0 8.6 11.1
Other 5.4 3.7 17.3 12.5
Depreciation, depletion
and amortization 18.1 15.3 52.6 44.6
Taxes, other than income:
Production and property
taxes 5.6 5.4 16.0 16.0
Other .1 .1 .4 .4
42.3 36.9 122.5 107.6
Operating income $ 43.3 $ 28.0 $ 128.3 $ 91.0
Production:
Natural gas (MMcf) 15,074 13,470 44,376 40,367
Oil (000's of barrels) 455 453 1,362 1,380
Average realized prices
(including hedges):
Natural gas (per Mcf) $ 4.52 $ 3.91 $ 4.58 $ 3.98
Oil (per barrel) $ 35.74 $ 26.86 $ 33.33 $ 27.48
Average realized prices
(excluding hedges):
Natural gas (per Mcf) $ 4.66 $ 4.26 $ 4.70 $ 4.42
Oil (per barrel) $ 40.05 $ 27.78 $ 36.05 $ 28.64
Production costs, including
taxes, per net equivalent Mcf:
Lease operating costs $ .49 $ .52 $ .48 $ .47
Gathering and
transportation .19 .25 .16 .23
Production and property
taxes .31 .33 .31 .33
$ .99 $ 1.10 $ .95 $ 1.03
Construction Materials and Mining
Three Months Nine Months
Ended Ended
September 30, September 30,
2004 2003 2004 2003
Operating revenues $ 486.9 $ 426.5 $ 973.6 $ 811.3
Operating expenses:
Operation and maintenance 400.5 338.3 820.3 668.9
Depreciation, depletion
and amortization 18.5 16.4 51.6 46.6
Taxes, other than income 10.2 8.5 26.3 19.5
429.2 363.2 898.2 735.0
Operating income $ 57.7 $ 63.3 $ 75.4 $ 76.3
Sales (000's):
Aggregates (tons) 15,653 14,119 31,647 28,738
Asphalt (tons) 3,938 3,647 6,586 5,510
Ready-mixed concrete
(cubic yards) 1,426 1,161 3,239 2,588
Independent Power Production and Other
Three Months Nine Months
Ended Ended
September 30, September 30,
2004 2003 2004 2003
Operating revenues $ 17.4 $ 10.1 $ 36.3 $ 28.1
Operating expenses:
Operation and maintenance 9.5 4.1 17.7 11.3
Depreciation, depletion and
amortization 2.4 2.1 6.9 6.0
Taxes, other than income .6 --- 1.8 ---
12.5 6.2 26.4 17.3
Operating income $ 4.9 $ 3.9 $ 9.9 $ 10.8
Net generation capacity - kW* 279,600 279,600 279,600 279,600
Electricity produced and sold
(thousand kWh)* 61,877 103,816 177,380 242,410
_____________________
* Excludes equity method investments.
NOTE: The earnings from the Company's equity method investments in
Brazil, Trinidad and Tobago, and Hartwell, Georgia were included in
other income - net and, thus, are not reflected in the above table.
Amounts presented in the preceding tables for operating revenues,
purchased natural gas sold and operation and maintenance expense
will not agree with the Consolidated Statements of Income due to
the elimination of intersegment transactions. The amounts (dollars
in millions) relating to the elimination of intersegment
transactions are as follows:
Three Months Nine Months
Ended Ended
September 30, September 30,
2004 2003 2004 2003
Operating revenues $ 65.5 $ 38.5 $ 197.2 $ 126.2
Purchased natural gas sold 59.4 34.7 183.8 114.4
Operation and maintenance 6.1 3.8 13.4 11.8
For further information on intersegment eliminations, see Note 15
of Notes to Consolidated Financial Statements.
Three Months Ended September 30, 2004 and 2003
Electric
Electric earnings decreased $700,000 as a result of lower retail
sales volumes due primarily to significantly cooler weather in July
and August resulting in a 15 percent decrease in residential sales
compared to 2003; higher operation and maintenance expense,
including increased payroll and benefit-related costs; and a
decrease in sales for resale prices and volumes. The seasonal
effects of a new rate design for retail customers in North Dakota
combined with higher sales to large industrial customers partially
offset the decrease in earnings.
Natural Gas Distribution
Seasonal losses at the natural gas distribution business were
$700,000 higher than the comparable prior period. Higher operation
and maintenance expense, including payroll and benefit-related costs
were partially offset by higher retail sales prices, the result of
rate increases effective in Minnesota, South Dakota and North
Dakota. The pass-through of higher natural gas prices is reflected
in the increase in both sales revenues and purchased natural gas
sold. For further information on the retail rate increases, see
Note 18 of Notes to Consolidated Financial Statements.
Utility Services
Utility services experienced a $600,000 loss for the third quarter,
compared to $1.7 million in earnings for the comparable prior
period. Lower inside electrical margins and workload in the Central
region and decreased line construction margins in the Rocky Mountain
region, as well as severance-related expenses were partially offset
by increased line construction margins and workload in the
Southwest, Northwest and Central regions, and higher equipment
sales.
Pipeline and Energy Services
The pipeline and energy services business experienced a $1.6 million
loss for the third quarter of 2004, compared to $4.6 million in
earnings for the comparable prior period. The loss was due to a
noncash goodwill impairment of $4.0 million (before and after tax)
and a $1.3 million (after tax) asset valuation adjustment, as
previously discussed. Also contributing to the unfavorable variance
were higher operating expenses, including higher payroll and benefit-
related costs and increased costs associated with last year's
expansion of pipeline and gathering operations; and lower average
transportation rates. Higher natural gas volumes transported into
storage, and increased natural gas transportation volumes on the
Grasslands Pipeline, as well as higher gathering rates, partially
offset the decreases. 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. For further information on the noncash
asset impairments, see Notes 11 and 12 of Notes to Consolidated
Financial Statements.
Natural Gas and Oil Production
Natural gas and oil production earnings increased $10.9 million due
to higher average realized natural gas prices of 16 percent due in
part to the Company's ability to access higher-priced markets for
much of its operated natural gas production through the Grasslands
Pipeline, completed late last year. Increased natural gas
production of 12 percent and higher average realized oil prices of
33 percent also added to the increase in earnings. Higher
depreciation, depletion and amortization expense due to higher
production volumes and higher rates; and increased general and
administrative costs, partially offset the earnings increase.
Construction Materials and Mining
Construction materials and mining earnings decreased $1.2 million
from the comparable prior period. The effects of wet weather in
certain operating regions, decreased benefits realized from the
substantially complete harbor-deepening project in southern
California and higher operating costs in Minnesota resulted in lower
aggregate margins. Also adding to the decline in earnings were
lower construction revenues, and slightly lower asphalt volumes and
margins at existing operations, as well as higher fuel costs.
Partially offsetting the decreases were earnings from companies
acquired since the comparable prior period and increased ready-mixed
concrete volumes and margins. The increase in revenues and the
related increase in operating expense resulted largely from
businesses acquired since the comparable prior period.
Independent Power Production and Other
Earnings for the independent power production and other businesses
increased $6.4 million due largely to higher net income of $4.9
million from the Company's share of its equity investment in Brazil.
The higher net income was due primarily to the effects of changes in
foreign currency rates and the value of the embedded derivative in
the electric power sales contract, as well as lower financing costs.
Earnings from acquisitions made since the comparable period last
year also added to the increase. Despite reduced demand at the
Colorado electric generation facility related to cool summer
weather, domestic operations also contributed to higher earnings.
For additional information regarding equity method investments, see
Note 10 of Notes to Consolidated Financial Statements.
Nine Months Ended September 30, 2004 and 2003
Electric
Electric earnings decreased $3.2 million as a result of higher
operation and maintenance expense, largely increased payroll-related
costs, pension expense and company-owned generation facility
maintenance expenses; and higher fuel and purchased power-related
costs, including higher demand charges resulting from a scheduled
maintenance outage at an electric supplier's generating station.
Lower retail sales volumes, as previously discussed, and higher
interest expense due to higher average rates, also added to the
earnings decrease. Higher average sales for resale prices of 14
percent, the seasonal effects of the rate design in North Dakota and
a favorable resolution of federal and related state income tax
matters partially offset the earnings decline.
Natural Gas Distribution
The natural gas distribution business experienced a loss of $2.0
million compared to earnings of $400,000 for the comparable prior
period. The decrease in earnings was due to higher operation and
maintenance expense, largely increased payroll-related and pension
expenses; lower service and repair margins; and a 4 percent decrease
in retail sales volumes due to weather that was 4 percent warmer
than last year. Partially offsetting the earnings decrease were
higher retail sales prices, the result of rate increases effective
in South Dakota, Minnesota and North Dakota, and a favorable
resolution of federal and related state income tax matters. The
pass-through of higher natural gas prices is reflected in the
increase in both sales revenues and purchased natural gas sold.
Utility Services
Utility services experienced a $4.8 million loss compared to $4.3
million in earnings for the comparable prior period. Lower inside
electrical margins due largely to lower than expected results on
certain large jobs that are nearly complete and lower workloads, as
well as decreased line construction margins in the Central and Rocky
Mountain regions were partially offset by increased line
construction margins in the Southwest and Northwest regions and
higher equipment sales. Also affecting the results were severance-
related costs.
Pipeline and Energy Services
Earnings at the pipeline and energy services business decreased $8.6
million due largely to the $4.0 million (before and after tax)
noncash goodwill impairment and $1.3 million (after tax) asset
valuation adjustment, as previously discussed. Also adding to the
earnings decline were lower revenues from traditional off-system
transportation services; higher operating expenses, which were
partially the result of increased costs associated with last year's
expansion of pipeline and gathering operations and higher payroll-
related costs; and lower average transportation rates. Higher
natural gas transportation volumes on the Grasslands Pipeline, which
began providing natural gas transmission service late in 2003;
higher natural gas volumes transported into storage; and a favorable
resolution of federal and related state income tax matters,
partially offset the decrease in earnings. The increase in energy
services revenues and the related increase in purchased natural gas
sold includes the effect of higher natural gas prices and volumes
since the comparable prior period.
Natural Gas and Oil Production
Natural gas and oil production earnings increased $32.7 million due
to higher average realized natural gas prices of 15 percent due in
part to the Company's ability to access higher-priced markets for
much of its operated natural gas production through the recently
constructed Grasslands Pipeline; higher natural gas production of 10
percent; and 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. Higher average
realized oil prices of 21 percent and a favorable resolution of
federal and related state income tax matters also contributed to the
increase in earnings. Partially offsetting the earnings increase
were higher depreciation, depletion and amortization expense due to
higher rates and higher natural gas production volumes; higher
general and administrative costs; and higher interest expense.
Construction Materials and Mining
The increase in construction materials and mining earnings of $1.9
million reflects higher ready-mixed concrete and asphalt volumes and
margins, all at existing operations. Earnings from companies
acquired since the comparable prior period and favorable resolution
of federal and related state income tax matters also added to the
earnings increase. Lower aggregate volumes from the comparable
prior period at a large harbor-deepening project in southern
California which is now substantially complete, as well as higher
general and administrative expenses, partially offset the earnings
increase. The increase in revenues and the related increase in
operating expense resulted largely from businesses acquired since
the comparable prior period.
Independent Power Production and Other
Earnings for the independent power production and other businesses
increased $13.5 million due largely to higher net income of $13.1
million from the Company's share of its equity investment in Brazil.
The higher net income was due primarily to changes in value of the
embedded derivative in the electric power sales contract combined
with lower financing costs, largely the result of obtaining low-
cost, long-term financing for the operation in mid-2003, partially
offset by the effects of changes in foreign currency rates.
Acquisitions made since the comparable prior period also added to
the increase in earnings. For additional information regarding
equity method investments, see Note 10 of Notes to Consolidated
Financial Statements.
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 and pipeline and energy
services businesses are dependent on factors including commodity
prices, which cannot be predicted or controlled.
These factors include: price fluctuations in natural gas and crude
oil prices; fluctuations in commodity price basis differentials;
availability of economic supplies of natural gas; drilling successes
in natural gas and oil operations; the timely receipt of necessary
permits and approvals; 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 challenging
telecommunications market may have a general negative impact on the
Company's future revenues.
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.
The Company relies on financing sources and capital markets. If the
Company is 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, and
delays 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, a number of 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 an
electric power sales contract 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 and construction and
drilling activities for the pipeline and energy services and natural
gas and oil production businesses. In addition, severe weather can
be destructive, causing outages, reduced natural gas and oil
production, 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 $1.70 to $1.85.
- - 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 anticipates investing approximately $410 million in
capital expenditures during 2004.
- - 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.
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.
- - As part of the North Dakota Industrial Commission's Lignite
Vision 21 project, the Company submitted an air quality permit
application in May 2004 to construct a 175-megawatt coal-fired plant
at Gascoyne, North Dakota. The air permit application is now under
review at the North Dakota Department of Health. This segment is
also involved in the review of other potential projects to replace
capacity associated with expiring contracts, and to provide for
future growth. 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. On July 15, 2004,
Montana-Dakota entered into a firm capacity contract to purchase 15
megawatts of capacity and associated energy for the summer of 2005
and 25 megawatts of capacity and associated energy for the summer of
2006 from a neighboring utility.
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.
- - Montana-Dakota has pending applications with state regulatory
authorities in Montana and South Dakota seeking increases in natural
gas retail rates of $1.5 million annually and $1.3 million annually,
respectively or 1.8 percent and 2.2 percent, respectively above
current rates. In addition, Great Plains has filed an application
with the state regulatory authority in Minnesota seeking an increase
in natural gas rates for $1.4 million annually or 4.0 percent above
current rates. While Montana-Dakota and Great Plains believe that
they 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
$380 million to $430 million in 2004.
- - This segment anticipates margins for 2004 to be significantly
lower than 2003 levels.
- - This segment's work backlog as of September 30, 2004, was
approximately $220 million compared to $158 million at September 30,
2003.
Pipeline and energy services
- - In 2004, total natural gas throughput is expected to increase
approximately 15 percent to 20 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 effects of a Federal Energy Regulatory Commission
rate order received in July 2003 and rehearing order received in May
2004.
Natural gas and oil production
- - In 2004, the Company expects a combined natural gas and oil
production increase of approximately 8 percent over 2003 levels. The
decrease from the previously disclosed estimated increase in
production of 10 percent is largely due to delays in the receipt of
various regulatory approvals, which are affecting producers
throughout the Rocky Mountain region. The Company is confident that
it will receive such regulatory approvals, but forecasting the
timing of such receipt is difficult. Also affecting the revised
production forecast to a lesser extent is the recent hurricane
activity in the Gulf of Mexico. 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 nine months ended September
30, 2004.
- - Due to regulatory approval delays encountered and the potential
for further delays, the Company is now expecting to drill between
200 and 300 wells in 2004.
- - Natural gas prices in the Rocky Mountain region for November
through December 2004, reflected in the Company's 2004 earnings
guidance, are in the range of $4.75 to $5.25 per Mcf. The Company's
estimates for natural gas prices on the NYMEX for November through
December 2004, reflected in the Company's 2004 earnings guidance,
are in the range of $5.50 to $6.00 per Mcf. For 2004, the Company
expects that more than two-thirds of its natural gas production will
be priced using Rocky Mountain or other non-NYMEX prices.
- - NYMEX crude oil prices for October through December 2004,
reflected in the Company's 2004 earnings guidance, are in the range
of $45 to $50 per barrel.
- - The Company has hedged a portion of its 2004 natural gas
production. The Company has entered into agreements representing
approximately 35 percent to 40 percent of 2004 estimated annual
natural gas production. The agreements are at various
indices/prices and range from a low CIG index of $3.75 to a high
NYMEX price of $10.18 per Mcf. CIG is an index pricing point
related to Colorado Interstate Gas Co.'s system.
- - This segment 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 25
percent to 30 percent of 2004 estimated annual oil production.
- - The Company has hedged a portion of its 2005 estimated natural
gas production. The Company has entered into agreements
representing approximately 30 percent to 35 percent of its 2005
estimated annual natural gas production. The agreements are at
various indices/prices and range from a low Ventura index of $4.75
to a high NYMEX price of $10.18 per Mcf. Ventura is an index
pricing point related to Northern Natural Gas Co.'s system.
- - This segment has hedged a portion of its 2005 oil production.
The Company has entered into agreements at NYMEX prices with a low
of $30.70 and a high of $52.05 representing approximately 30 percent
to 35 percent of its 2005 estimated annual oil production.
Construction materials and mining
- - Aggregate volumes in 2004 are expected to be slightly higher
than 2003 levels. Ready-mixed concrete volumes are expected to
increase by 17 percent to 22 percent, while asphalt volumes are
expected to increase 10 percent to 15 percent over 2003.
- - Revenues in 2004 are expected to increase by approximately 13
percent to 18 percent over 2003 levels.
- - The Company expects that the replacement funding legislation
for the Transportation Equity Act for the 21st Century (TEA-21) will
be equal to or higher than previous funding levels.
- - Work backlog as of mid-October 2004 was approximately $501
million, compared to $425 million at mid-October 2003.
Independent power production and other
- - Earnings projections for independent power production and other
operations are expected to be in the range of $22 million to $25
million in 2004.
- - The Company is constructing a 116-megawatt coal-fired electric
generating project near Hardin, Montana. A power sales agreement
with Powerex Corp., a subsidiary of BC Hydro, has been secured for
the entire output of the plant for a term expiring October 31, 2008,
with an option for a two-year extension. The projected on-line date
for this plant is late 2005.
New Accounting Standards
In December 2003, the FASB issued FIN 46 (revised), which replaced
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 FSP No. FAS 106-1. FSP 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 2003 Medicare Act. In May
2004, the FASB issued FSP No. FAS 106-2. The Company elected the
one-time deferral of accounting for the effects of the 2003 Medicare
Act in the quarter ended March 31, 2004, the first period in which
the plan's accounting for the effects of the 2003 Medicare Act
normally would have been reflected in the Company's financial
statements. During the second quarter of 2004, the Company adopted
FSP No. FAS 106-2 retroactive to the beginning of the year. The
Company expects to be entitled to some federal subsidy. The
expected federal subsidy reduced the accumulated postretirement
benefit obligation (APBO) at January 1, 2004, by approximately
$3.2 million, and net periodic benefit cost for 2004 by
approximately $285,000 (as compared with the amount calculated
without considering the effects of the subsidy). In addition, the
Company expects a reduction in future participation in the
postretirement plans, which further reduced the APBO at January 1,
2004, by approximately $12.7 million and net periodic benefit cost
for 2004 by approximately $1.3 million.
An issue had 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. In September 2004, the FASB Staff issued FSP No. 142-2.
FSP No. 142-2 does not change the balance sheet classification of
drilling and mineral rights of oil and gas producing entities. FSP
No. 142-2 did not have an effect on the Company's financial
position, results of operations or cash flows.
In April 2004, the FASB issued FSP Nos. FAS 141-1 and FAS 142-1.
The Company adopted FSP Nos. FAS 141-1 and FAS 142-1 in the second
quarter of 2004. FSP Nos. FAS 141-1 and FAS 142-1 required
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. FSP Nos. FAS 141-1 and
FAS 142-1 affected the asset classification in the consolidated
balance sheet and associated footnote disclosure only, so the
reclassifications did not affect the Company's stockholders' equity,
cash flows or results of operations.
In September 2004, the Securities and Exchange Commission issued SAB
106 which is an interpretation regarding the application of SFAS No.
143 by oil and gas producing companies following the full cost
accounting method. SAB 106 shall be applied to all entities subject
to SAB 106 as of the beginning of the first quarter beginning after
October 4, 2004. The adoption of SAB 106 is not expected to have a
material effect on the Company's financial position or results of
operations.
For further information on FIN 46 (revised), FSP Nos. FAS 106-1 and
106-2, SFAS Nos. 142 and FSP No. 142-2, FSP Nos. FAS 141-1 and FAS
142-1, and SAB 106 see Note 8 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 nine months
of 2004 increased $20.3 million from the comparable 2003 period, the
result of an increase in net income of $24.8 million and higher
depreciation, depletion and amortization expense of $15.7 million,
resulting largely from increased property, plant and equipment
balances and asset impairments of $6.1 million. Partially
offsetting the increase in cash flows from operating activities were
increased earnings, net of distributions, from equity method
investments of $15.3 million and the absence in 2004 of the 2003
cumulative effect of an accounting change of $7.6 million.
Investing activities --
Cash flows used in investing activities in the first nine months of
2004 decreased $47.1 million compared to 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 $89.5 million and an
increase in proceeds from notes receivable of $14.2 million, offset
in part by an increase in investments of $56.6 million. Net capital
expenditures exclude the noncash transactions related to
acquisitions, including the issuance of the Company's equity
securities. The noncash transactions were $33.1 million and $40.1
million for the first nine months of 2004 and 2003, respectively.
Financing activities --
Cash flows provided by financing activities in the first nine months
of 2004 decreased $33.1 million compared to the comparable 2003
period, primarily the result of a decrease in the issuance of long-
term debt of $170.8 million. A decrease in repayment of long-term
debt of $58.3 million and an increase in the issuance of common
stock of $65.2 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
nine months of 2004 were $279.8 million and are estimated to be
approximately $410 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
- 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 16 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 Hawaii, Idaho, Iowa and Minnesota and an
independent power production operating and 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
September 30, 2004.
MDU Resources Group, Inc.
The Company has a revolving credit agreement with various banks
totaling $90 million at September 30, 2004. There were no amounts
outstanding under the credit agreement at September 30, 2004. The
credit agreement supports the Company's $75 million commercial paper
program. Under the Company's commercial paper program, $7.5 million
was outstanding at September 30, 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 of approximately $11,000
(after tax) based on September 30, 2004, variable rate borrowings.
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 is unable to successfully negotiate the credit
agreement, or in the event the fees on this facility became too
expensive, which it does not currently anticipate, the Company would
seek alternative funding. One source of alternative funding might
involve the securitization of certain Company assets.
In order to borrow under the Company's credit agreement, the Company
must be in compliance with the applicable covenants and certain
other conditions. The significant covenants include maximum
leverage ratios, minimum interest coverage ratio, limitation on sale
of assets and limitation on investments. The Company was in
compliance with these covenants and met the required conditions at
September 30, 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.
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 September 30, 2004,
the Company could have issued approximately $323 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 September 30,
2004 and December 31, 2003. Additionally, the Company's first
mortgage bond interest coverage was 6.7 times and 7.4 times for the
twelve months ended September 30, 2004 and December 31, 2003,
respectively. Common stockholders' equity as a percent of total
capitalization (net of long-term debt due within one year) was
63 percent and 60 percent at September 30, 2004 and December 31,
2003, respectively.
Centennial Energy Holdings, Inc.
Centennial has two revolving credit agreements with various banks
and institutions that support $325 million of Centennial's $350
million commercial paper program. There were no outstanding
borrowings under the Centennial credit agreements at September 30,
2004. Under the Centennial commercial paper program, $89.5 million
was outstanding at September 30, 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. One of these credit
agreements is for $300 million and expires on August 17, 2007. The
other agreement is for $25 million and expires on April 30, 2007.
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 September
30, 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 $134,000 (after
tax) based on September 30, 2004, variable rate borrowings. Based
on Centennial's overall interest rate exposure at September 30,
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
September 30, 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
September 30, 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 September 30, 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 Brazil Generating Facility, as discussed in Note
10 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 September 30,
2004, the aggregate amount of borrowings outstanding subject to
these guarantees was $34.7 million and the scheduled repayment of
these borrowings is $10.8 million in 2005, $10.7 million in 2006 and
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, which are joint and several
obligations. 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 September 30, 2004, Centennial was contingently liable for
performance of certain of its subsidiaries under approximately
$331 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 is
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 are no material changes in the Company's contractual
obligations relating to long-term debt and operating leases from
those reported in the Company's Annual Report on Form 10-K for the
year ended December 31, 2003.
The Company's contractual obligations relating to purchase
commitments at September 30, 2004, were $634.8 million, compared to
purchase commitments of $492.7 million at December 31, 2003. The
increase in purchase commitments was primarily due to electric
generation construction contracts. At September 30, 2004, the
Company's contractual obligations relating to purchase commitments
for the twelve months ended September 30 in each of the following
years, were as follows:
2005 2006 2007 2008 2009 Thereafter Total
(In millions)
Purchase
commitments $283.3 $92.3 $51.7 $38.3 $33.9 $135.3 $634.8
In addition to the above obligations, the Company has certain
purchase obligations for natural gas connected to its gathering
system. These purchases and the resale of the natural gas are at
market-based prices. These obligations continue as long as natural
gas is produced. However, if the purchase and resale of natural gas
become uneconomical, the purchase commitments can be canceled by the
Company with 60 days notice. These purchase obligations are
currently estimated at approximately $10 million annually.
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 Notes
9 and 13 of Notes to Consolidated Financial Statements.
The following table summarizes hedge agreements entered into by
Fidelity as of September 30, 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 $ 5.24 3,065 $(3,969)
Natural gas swap
agreements maturing
in 2005 $ 5.37 7,750 $(10,118)
Weighted
Average
Floor/Ceiling Notional
Price Amount
(Per MMBtu) (In MMBtu's) Fair Value
Natural gas collar
agreements maturing
in 2004 $4.58/5.23 2,302 $(2,758)
Natural gas collar
agreements maturing
in 2005 $5.15/6.22 12,775 $(9,403)
Weighted
Average Notional
Fixed Price Amount
(Per barrel) (In barrels) Fair Value
Oil swap agreements
maturing in 2004 $ 29.59 138 $(2,663)
Oil swap agreement
maturing in 2005 $ 30.70 183 $(2,467)
Weighted
Average
Floor/Ceiling Notional
Price Amount
(Per barrel) (In barrels) Fair Value
Oil collar agreement
maturing in 2005 $32.00/36.50 164 $(1,414)
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 10 of Notes to
Consolidated Financial Statements.
MDU Brasil's equity income from this Brazilian investment is
impacted by fluctuations in currency exchange rates on
transactions denominated in a currency other than the
Brazilian Real, including the effects of changes in currency
exchange rates with respect to the Brazil Generating
Facility's U.S. dollar denominated obligations. At
September 30, 2004, these U.S. dollar denominated
obligations approximated $73.0 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 $2.8
million (after tax) based on the above U.S. dollar
denominated obligations at September 30, 2004.
The investment of Centennial International in the Brazil
Generating Facility at September 30, 2004, was approximately
$19.7 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 electric power
sales contract. For further information on the Brazil
Generating Facility see Note 10 of Notes to Consolidated
Financial Statements. 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 control over financial reporting
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 relation to the lawsuits filed in connection with Fidelity's
coalbed natural gas development, the cases involving alleged
violations of the Federal Clean Water Act have been resolved without
a finding that Fidelity is in violation of the Federal Clean Water
Act. Fidelity presently has no exposure to penalties, fines or
damages for any claims under the Federal Clean Water Act.
The State of North Dakota and the EPA entered into a MOU on February
24, 2004, stating the principles to be used by the State in
completing dispersion modeling of air quality in Theodore Roosevelt
National Park and other "Class I" areas in North Dakota and Montana.
In April 2004, the Dakota Resource Council filed a petition for
review of the MOU with the United States Eighth Circuit Court of Appeals.
The Petition was dismissed, without prejudice, in June 2004 upon
stipulation of the EPA, the Dakota Resource Council and the State.
For more information on the above legal actions, see Note 19 of
Notes to Consolidated Financial Statements, which is incorporated by
reference.
ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
Between July 1, 2004 and September 30, 2004, the Company issued
26,235 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 in the acquisition of a business
acquired by the Company in a prior period. The Common Stock and
Rights issued by the Company in these transactions were issued in a
private transaction exempt from registration under the Securities
Act of 1933 pursuant to Section 4(2) thereof, Rule 506 promulgated
thereunder, or both. The classes of persons to whom these
securities were sold were either accredited investors or other
persons to whom such securities were permitted to be offered under
the applicable exemption.
ITEM 6. EXHIBITS
10(a) MDU Resources Group, Inc. Executive Incentive
Compensation Plan, as amended
10(b) Montana-Dakota Executive Incentive Compensation Plan
10(c) Performance Share Award Agreement
10(d) Agreement on Retirement, dated October 4, 2004,
between Ronald D. Tipton and the Company
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
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of
1934, the registrant has duly caused this report to be signed on its
behalf by the undersigned thereunto duly authorized.
MDU RESOURCES GROUP, INC.
DATE: November 5, 2004 BY: /s/ Martin A. White
Martin A. White
Chairman of the Board, President
and Chief Executive Officer
BY: /s/ Vernon A. Raile
Vernon A. Raile
Acting Chief Financial Officer
EXHIBIT INDEX
Exhibit No.
10(a) MDU Resources Group, Inc. Executive Incentive Compensation
Plan, as amended
10(b) Montana-Dakota Executive Incentive Compensation Plan
10(c) Performance Share Award Agreement
10(d) Agreement on Retirement, dated October 4, 2004, between
Ronald D. Tipton and the Company
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