UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
X QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2005
OR
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the Transition Period from _____________ to ______________
Commission file number 1-3480
MDU Resources Group, Inc.
(Exact name of registrant as specified in its charter)
Delaware 41-0423660
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
Schuchart Building
918 East Divide Avenue
P.O. Box 5650
Bismarck, North Dakota 58506-5650
(Address of principal executive offices)
(Zip Code)
(701) 222-7900
(Registrant's telephone number, including area code)
Indicate by check mark whether the registrant (1) has filed all
reports required to be filed by Section 13 or 15(d) of the
Securities Exchange Act of 1934 during the preceding 12 months (or
for such shorter period that the registrant was required to file
such reports), and (2) has been subject to such filing requirements
for the past 90 days. Yes X. No.
Indicate by check mark whether the registrant is an accelerated
filer (as defined in Rule 12b-2 of the Exchange Act). Yes X. No.
Indicate the number of shares outstanding of each of the issuer's
classes of common stock, as of April 27, 2005: 118,417,188 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 (MD&A) - 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
- 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 or regulatory 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 western
Minnesota and southeastern North Dakota. 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, builds and operates electric
generating facilities in the United States and has
investments in domestic and international natural resource-
based projects. Electric capacity and energy produced at
its power plants are sold primarily under mid- and long-term
contracts to nonaffiliated entities.
Centennial Capital insures various types of risks as a
captive insurer for certain of the Company's subsidiaries.
The function of the captive 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 the Other category.
INDEX
Part I -- Financial Information
Consolidated Statements of Income --
Three Months Ended March 31, 2005 and 2004
Consolidated Balance Sheets --
March 31, 2005 and 2004, and December 31, 2004
Consolidated Statements of Cash Flows --
Three Months Ended March 31, 2005 and 2004
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
Submission of Matters to a Vote of Security Holders
Exhibits
Signatures
Exhibit Index
Exhibits
PART I -- FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
MDU RESOURCES GROUP, INC.
CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
Three Months Ended
March 31,
2005 2004
(In thousands, except
per share amounts)
Operating revenues:
Electric, natural gas distribution and
pipeline and energy services $255,373 $231,848
Utility services, natural gas and oil production,
construction materials and mining, independent
power production and other 348,922 283,611
604,295 515,459
Operating expenses:
Fuel and purchased power 16,186 16,725
Purchased natural gas sold 113,499 94,744
Operation and maintenance:
Electric, natural gas distribution and
pipeline and energy services 38,985 42,199
Utility services, natural gas and oil production,
construction materials and mining, independent
power production and other 291,004 246,372
Depreciation, depletion and amortization 52,839 49,511
Taxes, other than income 26,669 21,885
539,182 471,436
Operating income 65,113 44,023
Earnings from equity method investments 1,314 3,425
Other income 1,151 1,368
Interest expense 13,017 13,846
Income before income taxes 54,561 34,970
Income taxes 20,141 11,390
Net income 34,420 23,580
Dividends on preferred stocks 171 172
Earnings on common stock $ 34,249 $ 23,408
Earnings per common share -- basic $ .29 $ .20
Earnings per common share -- diluted $ .29 $ .20
Dividends per common share $ .18 $ .17
Weighted average common shares outstanding --
basic 117,827 114,658
Weighted average common shares outstanding --
diluted 118,773 115,709
The accompanying notes are an integral part of these consolidated
financial statements.
MDU RESOURCES GROUP, INC.
CONSOLIDATED BALANCE SHEETS
(Unaudited)
March 31, March 31, December 31,
2005 2004 2004
(In thousands, except shares
and per share amounts)
ASSETS
Current assets:
Cash and cash equivalents $ 146,667 $ 113,183 $ 99,377
Receivables, net 392,694 336,615 440,903
Inventories 133,916 108,694 143,880
Deferred income taxes 10,151 5,942 2,874
Prepayments and other current assets 58,190 61,586 41,144
741,618 626,020 728,178
Investments 119,508 68,680 120,555
Property, plant and equipment 4,026,501 3,656,917 3,931,428
Less accumulated depreciation,
depletion and amortization 1,404,500 1,225,196 1,358,723
2,622,001 2,431,721 2,572,705
Deferred charges and other assets:
Goodwill 199,840 198,737 199,743
Other intangible assets, net 16,003 19,823 22,269
Other 88,370 110,478 90,071
304,213 329,038 312,083
$3,787,340 $3,455,459 $3,733,521
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Long-term debt due within one year $ 46,827 $ 50,572 $ 72,046
Accounts payable 169,501 135,015 184,993
Taxes payable 51,265 24,282 28,372
Dividends payable 21,482 20,024 21,449
Other accrued liabilities 182,367 128,435 142,233
471,442 358,328 449,093
Long-term debt 907,061 878,541 873,441
Deferred credits and other liabilities:
Deferred income taxes 484,928 459,111 494,589
Other liabilities 248,562 234,775 235,385
733,490 693,886 729,974
Commitments and contingencies
Stockholders' equity:
Preferred stocks 15,000 15,000 15,000
Common stockholders' equity:
Common stock
Shares issued -- $1.00 par value
118,774,075 at March 31, 2005,
117,151,449 at March 31, 2004 and
118,586,065 at December 31, 2004 118,774 117,151 118,586
Other paid-in capital 866,306 831,677 863,449
Retained earnings 711,954 578,788 699,095
Accumulated other comprehensive loss (32,602) (13,542) (11,491)
Treasury stock at cost -
375,855 shares at March 31, 2005,
390,658 shares at March 31, 2004
and 359,281 shares at
December 31, 2004 (4,085) (4,370) (3,626)
Total common stockholders' equity 1,660,347 1,509,704 1,666,013
Total stockholders' equity 1,675,347 1,524,704 1,681,013
$3,787,340 $3,455,459 $3,733,521
The accompanying notes are an integral part of these consolidated
financial statements.
MDU RESOURCES GROUP, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Three Months Ended
March 31,
2005 2004
(In thousands)
Operating activities:
Net income $ 34,420 $ 23,580
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation, depletion and amortization 52,839 49,511
Earnings, net of distributions, from equity
method investments 288 (3,425)
Deferred income taxes (4,224) 4,194
Changes in current assets and liabilities, net
of acquisitions:
Receivables 47,876 27,278
Inventories 9,964 8,942
Other current assets (17,046) (11,087)
Accounts payable (15,492) (17,781)
Other current liabilities 32,475 23,321
Other noncurrent changes 10,461 (474)
Net cash provided by operating activities 151,561 104,059
Investing activities:
Capital expenditures (98,439) (53,538)
Acquisitions, net of cash acquired (52) (5,167)
Net proceeds from sale or disposition of property 4,649 4,614
Investments 1,092 (21,548)
Proceeds from notes receivable --- 2,000
Net cash used in investing activities (92,750) (73,639)
Financing activities:
Issuance of long-term debt 70,996 4,253
Repayment of long-term debt (62,596) (42,467)
Proceeds from issuance of common stock 1,528 54,078
Dividends paid (21,449) (19,442)
Net cash used in financing activities (11,521) (3,578)
Increase in cash and cash equivalents 47,290 26,842
Cash and cash equivalents -- beginning of year 99,377 86,341
Cash and cash equivalents -- end of period $146,667 $113,183
The accompanying notes are an integral part of these consolidated
financial statements.
MDU RESOURCES GROUP, INC.
NOTES TO CONSOLIDATED
FINANCIAL STATEMENTS
March 31, 2005 and 2004
(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 on Form 10-K for the year ended
December 31, 2004 (2004 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 2004 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 March 31, 2005
and 2004, and December 31, 2004, was $7.0 million, $8.2 million
and $6.8 million, respectively.
4. Natural gas in underground storage
Natural gas in underground storage for the Company's regulated
operations is carried at cost using the last-in, first-out method.
The portion of the cost of natural gas in underground storage
expected to be used within one year was included in inventories
and was $4.8 million, $2.1 million and $24.9 million at March 31,
2005 and 2004, and December 31, 2004, respectively. The remainder
of natural gas in underground storage was included in other assets
and was $43.3 million, $42.6 million, and $43.3 million at March
31, 2005 and 2004, and December 31, 2004, respectively.
5. Inventories
Inventories, other than natural gas in underground storage for the
Company's regulated operations, consisted primarily of aggregates
held for resale of $78.2 million, $61.8 million and $71.0 million;
materials and supplies of $37.5 million, $32.0 million and $31.0
million; and other inventories of $13.4 million, $12.8 million and
$17.0 million; as of March 31, 2005 and 2004, and December 31,
2004, respectively. These inventories were stated at the lower of
average cost or market.
6. Earnings per common share
Basic earnings per common share were computed by dividing earnings
on common stock by the weighted average number of shares of common
stock outstanding during the applicable period. Diluted earnings
per common share were computed by dividing earnings on common
stock by the total of the weighted average number of shares of
common stock outstanding during the applicable period, plus the
effect of outstanding stock options, restricted stock grants and
performance share awards. For the three months ended March 31,
2004, 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 months ended
March 31, 2005 and 2004, 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.
7. Stock-based compensation
The Company has stock option plans for directors, key employees
and employees. In 2003, the Company adopted the fair value
recognition provisions of Statement of Financial Accounting
Standards (SFAS) No. 123, "Accounting for Stock-Based
Compensation," and began expensing the fair market value of stock
options for all awards granted on or after January 1, 2003.
Compensation expense recognized for awards granted on or after
January 1, 2003, for the three months ended March 31, 2005 and
2004, was $4,000 and $3,000, 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.
The Company adopted SFAS No. 123 effective January 1, 2003, for
newly granted options only. The following table illustrates the
effect on earnings and earnings per common share for the three
months ended March 31, 2005 and 2004, as if the Company had
applied SFAS No. 123 and recognized compensation expense for all
outstanding and unvested stock options based on the fair value at
the date of grant:
Three Months Ended
March 31,
2005 2004
(In thousands, except
per share amounts)
Earnings on common stock, as
reported $ 34,249 $ 23,408
Stock-based compensation expense
included in reported earnings,
net of related tax effects 4 3
Total stock-based compensation
expense determined under fair
value method for all awards,
net of related tax effects (37) (92)
Pro forma earnings on common stock $ 34,216 $ 23,319
Earnings per common share -- basic --
as reported $ .29 $ .20
Earnings per common share -- basic --
pro forma $ .29 $ .20
Earnings per common share -- diluted --
as reported $ .29 $ .20
Earnings per common share -- diluted --
pro forma $ .29 $ .20
8. Cash flow information
Cash expenditures for interest and income taxes were as follows:
Three Months Ended
March 31,
2005 2004
(In thousands)
Interest, net of amount capitalized $ 4,839 $ 8,520
Income taxes (refunded) paid, net $ 2,972 $(1,267)
9. 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.
10. New accounting standards
SAB No. 106
In September 2004, the Securities and Exchange Commission (SEC)
issued Staff Accounting Bulletin No. 106 (SAB No. 106) which is an
interpretation regarding the application of SFAS No. 143,
"Accounting for Asset Retirement Obligations" by oil and gas
producing companies following the full-cost accounting method.
SAB No. 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 No. 106 also states that a
company is expected to disclose in the financial statement
footnotes and MD&A how the company's calculation of the ceiling
test and depreciation, depletion and amortization are affected by
the adoption of SFAS No. 143. SAB No. 106 was effective for the
Company as of January 1, 2005. The adoption of SAB No. 106 did
not have a material effect on the Company's financial position or
results of operations. The effects of the adoption of SFAS No.
143 and SAB No. 106 as they relate to the Company's natural gas
and oil production properties are described below.
Ceiling Test Calculation
As discussed in Note 1 of the 2004 Annual Report, the Company's
natural gas and oil production properties are subject to a
"ceiling test" that limits capitalized costs to the aggregate of
the present value of future net revenues of proved reserves based
on single point-in-time spot market prices, as mandated under the
rules of the SEC, and the cost of unproved properties. Prior to
the adoption of SFAS No. 143, the Company calculated the full-cost
ceiling by reducing its expected future revenues from proved
natural gas and oil reserves by the estimated future expenditures
to be incurred in developing and producing such reserves,
including future retirements, discounted using a factor mandated
by the rules of the SEC. While expected future cash flows related
to the asset retirement obligations were included in the
calculation of the ceiling test, no associated asset retirement
obligation was recognized on the balance sheet.
Upon the adoption of SFAS No. 143 but prior to the effective date
of SAB No. 106, the Company continued to calculate the full-cost
ceiling as previously described. In addition, the Company
recorded the fair value of a liability for the asset retirement
obligation and capitalized the cost by increasing the carrying
amount of the related long-lived asset.
Upon the adoption of SAB No. 106, the future capitalized
discounted cash outflows associated with settling asset retirement
obligations that are accrued on the consolidated balance sheet are
excluded from the computation of the present value of estimated
future net revenues for purposes of the full-cost ceiling
calculation in accordance with SAB No. 106.
Depreciation, Depletion, and Amortization
Costs subject to amortization include: (A) all capitalized costs,
less accumulated amortization, other than the cost of acquiring
and evaluating unproved property; (B) the estimated future
expenditures (based on current costs) to be incurred in developing
proved reserves; and (C) estimated dismantlement and abandonment
costs, net of estimated salvage values.
Subsequent to the adoption of SFAS No. 143, the estimated future
dismantlement and abandonment costs described in (C) above are
included in the capitalized costs described in (A) above at the
expected future cost discounted to the present value, to the
extent that a legal obligation exists. Under SFAS No. 143, the
recognition of the asset retirement obligation does not take into
account estimated salvage values. The liability associated with
the recognition of an asset retirement obligation is accreted over
time with accretion expense recorded in depreciation, depletion,
and amortization expense on the income statement. The Company's
estimated dismantlement and abandonment costs as described in (C)
above were adjusted to account for asset retirement obligations
accrued on the consolidated balance sheet when calculating the
depreciation, depletion and amortization rates. In addition,
estimated salvage values were included in the Company's
depreciation, depletion and amortization calculation. The
Company's estimate of future dismantlement and abandonment costs
that will be incurred as a result of future development activities
on proved reserves continues to be included in the calculation of
costs to be amortized.
Any gains or losses on the settlement of an asset retirement
obligation, if applicable, are treated as adjustments to the
capitalized costs, consistent with the full-cost accounting
method.
SFAS No. 123 (revised)
In December 2004, the FASB issued SFAS No. 123 (revised 2004),
"Share-Based Payment" (SFAS 123 (revised)). SFAS No. 123
(revised) revises SFAS No. 123 and requires entities to recognize
compensation expense in an amount equal to the fair value of share-
based payments granted to employees. SFAS No. 123 (revised)
requires a company to record compensation expense for all awards
granted after the date of adoption of SFAS No. 123 (revised) and
for the unvested portion of previously granted awards that remain
outstanding at the date of adoption. SFAS No. 123 (revised) is
effective for the Company on January 1, 2006. The Company is
evaluating the effects of the adoption of SFAS No. 123 (revised).
FIN 47
In March 2005, the FASB issued FASB Interpretation No. 47,
"Accounting for Conditional Asset Retirement Obligations - An
Interpretation of FASB Statement No. 143" (FIN 47). FIN 47
addresses the diverse accounting practices that developed with
respect to the timing of liability recognition for legal
obligations associated with the retirement of a tangible long-
lived asset when the timing and/or method of settlement of the
obligation are conditional on a future event. FIN 47 concludes
that an entity is required to recognize a liability for the fair
value of a conditional asset retirement obligation when incurred
if the liability's fair value can be reasonably estimated. FIN 47
is effective for the Company at the end of the fiscal year ending
December 31, 2005. The Company is evaluating the effects of the
adoption of FIN 47.
EITF No. 04-6
In March 2005, the FASB ratified Emerging Issues Task Force Issue
No. 04-6, "Accounting for Stripping Costs in the Mining Industry"
(EITF No. 04-6). EITF No. 04-6 requires that post-production
stripping costs be treated as a variable inventory production
cost. As a result, such costs will be subject to inventory
costing procedures in the period they are incurred. EITF No. 04-6
is effective for the Company on January 1, 2006. The Company is
evaluating the effects of the adoption of EITF No. 04-6.
11. Comprehensive income
Comprehensive income is the sum of net income as reported and
other comprehensive income (loss). The Company's other
comprehensive loss resulted from losses on derivative instruments
qualifying as hedges and foreign currency translation adjustments.
For more information on derivative instruments, see Note 14 of
Notes to Consolidated Financial Statements.
Comprehensive income, and the components of other comprehensive
loss and related tax effects, were as follows:
Three Months Ended
March 31,
2005 2004
(In thousands)
Net income $ 34,420 $23,580
Other comprehensive loss:
Net unrealized loss on
derivative instruments qualifying
as hedges:
Net unrealized loss on
derivative instruments arising
during the period, net of tax of
$15,891 and $3,636 in 2005 and 2004,
respectively (25,384) (5,687)
Less: Reclassification adjustment
for loss on derivative
instruments included in net income,
net of tax of $2,734 and $470 in
2005 and 2004, respectively (4,367) (735)
Net unrealized loss on
derivative instruments qualifying
as hedges (21,017) (4,952)
Foreign currency translation
adjustment (94) (1,061)
(21,111) (6,013)
Comprehensive income $ 13,309 $17,567
12. 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 has been impaired and, accordingly, no
impairment losses have been recorded in the accompanying
consolidated financial statements or related equity method
investment balances.
MDU Brasil Ltda. (MDU Brasil), an indirect wholly owned Brazilian
subsidiary of the Company, has a 49 percent interest in MPX, which
was formed in August 2001 when MDU Brasil entered into a joint
venture agreement with a Brazilian firm. MPX, through a wholly
owned subsidiary, owns and operates a 220-megawatt natural gas-
fired electric generating facility (Termoceara Generating
Facility) in the Brazilian state of Ceara. Petrobras, the
Brazilian state-controlled energy company, entered into a contract
to purchase all of the capacity and market all of the energy from
the Termoceara Generating Facility. The first phase of 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 Termoceara 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 Termoceara Generating Facility generates electricity 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 Termoceara 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 fair value of the
embedded derivative in the electric power sales contract for the
three months ended March 31, 2004, was $29,000 (after tax). 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 for the three months ended March 31, 2004, was $159,000
(after tax).
During 2004, Petrobras initiated discussions with a number of
owners of thermoelectric plants, including MPX, regarding a
possible renegotiation of their related power purchase agreements
or buyout of the generating plants. On January 13, 2005,
Petrobras obtained a Brazilian court order permitting it to cease
making monthly capacity payments to MPX and to instead deposit the
payments into a court account until the matter is resolved. On
February 2, 2005, the court revoked its January 13, 2005, order
and stated that MPX could withdraw the amounts deposited by
Petrobras. This decision was upheld on appeal on February 17,
2005. Under the existing contract, Petrobras agreed to jointly
market all of the facility's energy, and in the event that the
facility's revenues are insufficient to cover its costs during
certain periods, to make certain monthly contingency payments.
Petrobras has stated that, because of structural changes in the
Brazilian electric power markets since the contract was signed in
2001, the contingency payments had become permanent payment
obligations entitling Petrobras to renegotiate the contract. The
contract contains a dispute resolution provision which creates a
30-day period for accelerated negotiations. It provides that if
the parties do not reach agreement during the 30-day period, the
dispute is to be resolved by arbitration.
On March 24, 2005, MPX and Petrobras signed a term sheet (Term
Sheet) suspending arbitration proceedings and providing a
framework in principle to sell the Termoceara Generating Facility
to Petrobras. The Term Sheet provides for the sale of the
Termoceara Generating Facility for US $137 million, subject to
adjustment based on due diligence and Term Sheet stipulations.
The sale is contingent on the parties entering into a definitive
purchase agreement, the satisfactory completion of due diligence
review and audit of MPX and certain other matters. It is
anticipated that the sale would be completed by mid-year 2005 and
that the financial results of the sale will be reflected upon
closing.
In 2005, revenues were not recognized under the original 2002
electric power sales contract, only cost reimbursements from
Petrobras pursuant to the Term Sheet. The Termoceara Generating
Facility is being accounted for as an asset held for sale and as a
result no depreciation, depletion and amortization expense has
been recorded in 2005. However, if the sale of the Termoceara
Generating Facility to Petrobras does not occur, MPX plans to
pursue the collection of the entire capacity payments under the
electric power sales contract through arbitration and/or
litigation.
Centennial has unconditionally guaranteed a portion of certain
bank borrowings of MPX. For more information on this guarantee,
see Note 18.
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
(Trinity Generating Facility). The Trinity Generating Facility
sells its output to the Trinidad and Tobago Electric Commission
(T&TEC), the governmental entity responsible for the transmission,
distribution and administration of electrical power to the
national electrical grid of Trinidad and Tobago. The power
purchase agreement expires in September 2029. T&TEC also is under
contract to supply natural gas to the Trinity Generating Facility
during the term of the power purchase contract. The functional
currency for the Trinity Generating Facility is the U.S. dollar.
In September 2004, Centennial Resources, through wholly owned
subsidiaries, acquired a 50-percent ownership interest in a 310-
megawatt natural gas-fired electric generating facility located in
Hartwell, Georgia (Hartwell Generating Facility). The Hartwell
Generating Facility sells its output under a power purchase
agreement with Oglethorpe Power Corporation (Oglethorpe) that
expires in May 2019. Oglethorpe reimburses the Hartwell
Generating Facility for actual costs of fuel acquired to operate
the plant. American National Power, a wholly owned subsidiary of
International Power of the United Kingdom, holds the remaining 50-
percent ownership interest and is the operating partner for the
facility.
At March 31, 2005 and December 31, 2004, MPX, Carib Power and
Hartwell had total assets of $344.0 million and $334.2 million,
and long-term debt of $217.2 million and $224.9 million,
respectively. At March 31, 2004, MPX and Carib Power had total
assets of $204.6 million and long-term debt of $161.3 million.
The Company's investment in the Termoceara, Trinity and Hartwell
Generating Facilities was approximately $65.4 million, including
undistributed earnings of $26.4 million, at March 31, 2005, and
$65.7 million, including undistributed earnings of $26.6 million
at December 31, 2004. The Company's investment in the Termoceara
and Trinity Generating Facilities was approximately $39.3 million,
including undistributed earnings of $7.6 million, at March 31,
2004.
13. Goodwill and other intangible assets
The changes in the carrying amount of goodwill were as follows:
Balance Goodwill Balance
as of Acquired as of
Three Months January 1, During March 31,
Ended March 31, 2005 2005 the Year* 2005
(In thousands)
Electric $ --- $ --- $ ---
Natural gas
distribution --- --- ---
Utility services 62,632 6 62,638
Pipeline and energy
services 5,464 --- 5,464
Natural gas and oil
production --- --- ---
Construction materials
and mining 120,452 --- 120,452
Independent power
production 11,195 91 11,286
Other --- --- ---
Total $ 199,743 $ 97 $199,840
Balance Goodwill Balance
as of Acquired as of
Three Months January 1, During March 31,
Ended March 31, 2004 2004 the Year* 2004
(In thousands)
Electric $ --- $ --- $ ---
Natural gas
distribution --- --- ---
Utility services 62,604 --- 62,604
Pipeline and energy
services 9,494 --- 9,494
Natural gas and oil
production --- --- ---
Construction materials
and mining 120,198 (690) 119,508
Independent power
production 7,131 --- 7,131
Other --- --- ---
Total $199,427 $ (690) $198,737
Balance Goodwill Goodwill Balance
as of Acquired Impaired as of
Year Ended January 1, During During December 31,
December 31, 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 120,198 254 --- 120,452
Independent power
production 7,131 4,064 --- 11,195
Other --- --- --- ---
Total $199,427 $4,346 $(4,030) $199,743
__________________
* 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 (before and after tax) was
recognized in 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 1 in the Company's Notes to Consolidated
Financial Statements in the 2004 Annual Report, 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:
March 31, March 31, December 31,
2005 2004 2004
(In thousands)
Amortizable intangible assets:
Acquired contracts $14,936 $12,656 $15,041
Accumulated amortization (5,690) (2,422) (5,013)
9,246 10,234 10,028
Noncompete agreements 10,575 10,275 10,575
Accumulated amortization (8,266) (7,957) (8,186)
2,309 2,318 2,389
Other 4,224 6,652 9,535
Accumulated amortization (627) (341) (534)
3,597 6,311 9,001
Unamortizable intangible
assets 851 960 851
Total $16,003 $19,823 $22,269
The unamortizable intangible assets were recognized in accordance
with SFAS No. 87, "Employers' Accounting for Pensions," which
requires that if an additional minimum liability is recognized an
equal amount shall be recognized as an intangible asset, provided
that the asset recognized shall not exceed the amount of
unrecognized prior service cost. The unamortizable intangible
asset will be eliminated or adjusted as necessary upon a new
determination of the amount of additional liability.
Amortization expense for amortizable intangible assets for the
three months ended March 31, 2005 and 2004, and for the year ended
December 31, 2004, was $864,000, $566,000 and $3.8 million,
respectively. Estimated amortization expense for amortizable
intangible assets is $2.8 million in 2005, $1.9 million in 2006,
$1.8 million in 2007, $1.9 million in 2008, $1.8 million in 2009
and $5.8 million thereafter.
14. 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 2004 Annual Report.
As of March 31, 2005, 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 months ended March 31, 2005 and 2004, the amount of
hedge ineffectiveness, which was included in operating revenues,
was immaterial. For the three months ended March 31, 2005 and
2004, 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 March 31, 2005, 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 21 months. Fidelity estimates that over the next
12 months net losses of approximately $23.3 million will be
reclassified from accumulated other comprehensive loss into
earnings, subject to changes in natural gas and oil market prices,
as the hedged transactions affect earnings.
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. Prior to the fourth quarter of 2004, the
Company reported 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 did not individually meet the criteria to be considered
a reportable segment. In the fourth quarter of 2004, the Company
separated independent power production as a reportable business
segment due to the significance of its operations. The Company's
operations are now conducted through seven reportable segments and
all prior period information has been restated to reflect this
change.
The vast majority of the Company's operations are located within
the United States. The Company also has investments in foreign
countries, which largely consist of investments in natural gas-
fired electric generating facilities in Brazil and Trinidad and
Tobago, as discussed in Note 12.
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 segment owns, builds and operates
electric generating facilities in the United States and has
investments in domestic and international natural resource-based
projects. Electric capacity and energy produced at its power
plants are sold primarily under mid- and long-term contracts to
nonaffiliated entities.
The information below follows the same accounting policies as
described in Note 1 in the Company's Notes to Consolidated
Financial Statements in the 2004 Annual Report. Information on
the Company's businesses was as follows:
Inter-
External segment Earnings
Operating Operating on Common
Revenues Revenues Stock
(In thousands)
Three Months
Ended March 31, 2005
Electric $ 44,319 $ --- $ 3,134
Natural gas distribution 144,976 --- 4,821
Pipeline and energy
services 66,078 26,748 3,227
255,373 26,748 11,182
Utility services 113,708 152 1,958
Natural gas and oil
production 38,310 48,770 28,805
Construction materials
and mining 187,087 7 (8,536)
Independent power
production 9,817 --- 756
Other --- 1,367 84
348,922 50,296 23,067
Intersegment eliminations --- (77,044) ---
Total $ 604,295 $ --- $ 34,249
Inter-
External segment Earnings
Operating Operating on Common
Revenues Revenues Stock
(In thousands)
Three Months
Ended March 31, 2004
Electric $ 46,989 $ --- $ 3,408
Natural gas distribution 128,320 --- 2,323
Pipeline and energy
services 56,539 27,613 2,683
231,848 27,613 8,414
Utility services 100,251 --- (1,901)
Natural gas and oil
production 37,507 43,462 25,260
Construction materials
and mining 139,446 --- (11,881)
Independent power
production 6,407 --- 3,263
Other --- 919 253
283,611 44,381 14,994
Intersegment eliminations --- (71,994) ---
Total $ 515,459 $ --- $ 23,408
Earnings from electric, natural gas distribution and pipeline and
energy services are substantially all from regulated operations.
Earnings (loss) from utility services, natural gas and oil
production, construction materials and mining, independent power
production, and other are all from nonregulated operations.
16. Employee benefit plans
The Company has noncontributory defined benefit pension plans and
other postretirement benefit plans for certain eligible employees.
The Company recognized the effects of the Medicare Prescription
Drug, Improvement and Modernization Act of 2003 (2003 Medicare
Act) during the second quarter of 2004. The net periodic benefit
cost for the three months ended March 31, 2004, does not reflect
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 March 31, 2005 2004 2005 2004
(In thousands)
Components of net periodic
benefit cost:
Service cost $ 2,047 $ 1,849 $ 485 $ 583
Interest cost 4,156 3,941 1,097 1,324
Expected return on
assets (4,910) (5,087) (983) (993)
Amortization of prior
service cost 256 278 --- ---
Recognized net actuarial
(gain) loss 209 247 (39) (55)
Amortization of net
transition obligation
(asset) (11) (63) 538 526
Net periodic benefit cost 1,747 1,165 1,098 1,385
Less amount capitalized 172 74 91 102
Net periodic benefit cost $ 1,575 $ 1,091 $1,007 $1,283
In addition to the qualified plan defined pension benefits
reflected in the table above, the Company also has an unfunded,
nonqualified benefit plan for executive officers and certain key
management employees that generally provides for defined benefit
payments at age 65 following the employee's retirement or to their
beneficiaries upon death for a 15-year period. The Company's net
periodic benefit cost for this plan for the three months ended
March 31, 2005 and 2004, was $1.9 million and $1.5 million,
respectively.
17. Regulatory matters and revenues subject to refund
On March 24, 2005, Montana-Dakota filed an application with the
South Dakota Public Utilities Commission (SDPUC) for the East
River service area for a natural gas rate increase. Montana-
Dakota requested a total increase of $850,000 annually or 12.8
percent above current rates. A final order from the SDPUC is
expected in late 2005.
In September 2004, Great Plains filed an application with the
Minnesota Public Utilities Commission (MPUC) for a natural gas
rate increase. Great Plains had requested a total increase of
$1.4 million annually or approximately 4.0 percent above current
rates. Great Plains also requested an interim increase of $1.4
million annually. In November 2004, the MPUC issued an Order
authorizing an interim increase of $1.4 million annually effective
with service rendered on or after January 10, 2005, subject to
refund. A final order from the MPUC is expected in late 2005.
In December 1999, Williston Basin Interstate Pipeline Company
(Williston Basin), an indirect wholly owned subsidiary of the
Company, filed a general natural gas rate change application with
the Federal Energy Regulatory Commission (FERC). Williston Basin
began collecting such rates effective June 1, 2000, subject to
refund. In May 2001, the Administrative Law Judge (ALJ) issued an
Initial Decision on Williston Basin's natural gas rate change
application. The Initial Decision addressed numerous issues
relating to the rate change application, including matters
relating to allowable levels of rate base, return on common
equity, and cost of service, as well as volumes established for
purposes of cost recovery, and cost allocation and rate design.
In July 2003, the FERC issued its Order on Initial Decision. The
Order on Initial Decision affirmed the ALJ's Initial Decision on
many of the issues including rate base and certain cost of service
items as well as volumes to be used for purposes of cost recovery,
and cost allocation and rate design. However, there are other
issues as to which the FERC differed with the ALJ including return
on common equity and the correct level of corporate overhead
expense. In August 2003, Williston Basin requested rehearing of a
number of issues including determinations associated with cost of
service, throughput, and cost allocation and rate design, as
discussed in the FERC's Order on Initial Decision. In May 2004,
the FERC issued an 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. In June 2004, Williston Basin requested
clarification of a few of the issues addressed in the Order on
Rehearing including determinations associated with cost of service
and cost allocation, as discussed in the FERC's Order on
Rehearing. In June 2004, Williston Basin also made its filing to
comply with the requirements of the various FERC orders in this
proceeding. Williston Basin participated in a hearing before the
ALJ in early January 2005, regarding certain service and annual
demand quantity restrictions remanded to the ALJ by the FERC in
its Order on Rehearing. On April 8, 2005, the ALJ issued an
Initial Decision on the matters remanded by the FERC. In the
Initial Decision, the ALJ decided that Williston Basin had not
supported its position regarding the service and annual demand
quantity restrictions. Williston Basin plans on filing its Brief
on Exceptions regarding these issues with the FERC by May 9, 2005.
On April 19, 2005, the FERC issued its Order on Compliance Filing
and Motion for Refunds. In this Order, the FERC approved
Williston Basin's refund rates and established rates to be
effective April 19, 2005. Williston Basin is required to make a
compliance filing complying with the requirements of this Order
regarding rates and issue refunds by May 19, 2005.
A liability has been provided for a portion of the revenues that
have been collected subject to refund with respect to Great
Plains' and Williston Basin's pending regulatory proceedings.
Great Plains and Williston Basin believe that the liability is
adequate based on their assessment of the ultimate outcome of the
proceedings.
18. Contingencies
Litigation
In June 1997, Jack J. Grynberg (Grynberg) filed suit under the
Federal False Claims Act 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 United States
District Court for the District of Wyoming (Wyoming Federal
District Court).
In June 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
based 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. The Motion to Dismiss was heard
on March 17 and 18, 2005, by the Special Master appointed by the
Wyoming Federal District Court.
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, more than 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 November 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
the Wyoming Federal District Court. 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. There presently are no claims
pending for penalties, fines or damages 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 and the
lawsuits seek injunctive relief, invalidation of various permits
and unspecified damages.
In consolidated suits filed in the United States District Court
for the District of Montana (Montana Federal District Court), the
Northern Plains Resource Council and the Northern Cheyenne Tribe
asserted that further development by Fidelity and others of
coalbed natural gas operations in Montana should be enjoined until
the Bureau of Land Management (BLM) completes a supplemental
environmental impact statement (SEIS) that takes into account the
phased development of this natural resource in the region. The
Company estimates that it could take approximately eighteen months
to two years for the BLM to complete the SEIS. On April 5, 2005,
the Montana Federal District Court ordered, among other things,
that while the SEIS is being prepared, the BLM is enjoined from
approving production-related coalbed natural gas applications for
permits to drill (APDs) on federal leases outside of a defined
geographic area and that within this geographic area the BLM is
required to limit the number of production-related APDs to keep
the total number of federal, state and private wells to a maximum
of 500 new wells per year. This limited injunction is
substantially consistent with the position taken by the BLM before
the Montana Federal District Court. Fidelity does not expect the
Montana Federal District Court's decision to have a material
adverse effect on its coalbed natural gas operations or related
cash flows. The Northern Cheyenne Tribe and the Northern Plains
Resource Council filed Notices of Appeal and Motions for
Injunction Pending Appeal, respectively, on April 25 and 26, 2005.
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 (ND
Health Department) in September 2003 that the ND Health 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 ND Health
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 U.S. Environmental Protection
Agency (EPA), the ND Health Department and the other electric
generators.
In a related matter, the state of North Dakota and the EPA entered
into a Memorandum of Understanding (MOU) in February 2004,
establishing the principles to be used by the state of North
Dakota 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 of North Dakota.
The Company cannot predict the outcome of the ND Health 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.
In August 2004, Colorado Power Partners (CPP) and BIV Generation
Company, LLC (BIV), indirect wholly owned subsidiaries of the
Company, were each issued a draft Compliance Order on Consent
(Compliance Orders) by the Colorado Department of Public Health
and Environment (CDPHE). The Compliance Orders were issued in
connection with excess emission periods of nitrogen oxides and
carbon monoxide at the Company's electric generating facilities in
Brush, Colorado, occurring mainly during start-up and shut-down
periods. CPP, BIV and the CDPHE have been negotiating the final
Compliance Orders, and execution of the final Compliance Orders is
expected to occur by mid-year 2005. CPP and BIV have agreed to
certain of the terms of the Compliance Orders which, at this time,
include administrative penalties of $52,500 and $56,000,
respectively. The Company does not believe that the Compliance
Orders will have a material effect on the Company's results of
operations.
Guarantees
Centennial has unconditionally guaranteed a portion of certain
bank borrowings of MPX in connection with the Company's equity
method investment in the Termoceara Generating Facility, as
discussed in Note 12. The Company, through MDU Brasil, owns 49
percent of MPX. The main business purpose of Centennial extending
the guarantee to MPX's creditors is to enable MPX to obtain lower
borrowing costs. At March 31, 2005, the aggregate amount of
borrowings outstanding subject to these guarantees was $29.4
million and the scheduled repayment of these borrowings is $5.5
million in 2005, $10.7 million in each of 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 Fidelity's
natural gas and oil price swap and collar agreement obligations.
Fidelity's obligations at March 31, 2005, were $16.0 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
March 31, 2005, expire in 2005 and 2006; however, Fidelity
continues to enter into additional hedging activities and, as a
result, WBI Holdings from time to time may issue additional
guarantees on these hedging obligations. At March 31, 2005, the
amount outstanding was reflected on the Consolidated Balance
Sheets. In the event Fidelity defaults under its obligations, WBI
Holdings would be required to make payments under its guarantees.
Certain subsidiaries of the Company have outstanding guarantees to
third parties that guarantee the performance of other subsidiaries
of the Company. These guarantees are related to natural gas
transportation and sales agreements, electric power supply
agreements, insurance policies and certain other guarantees. At
March 31, 2005, the fixed maximum amounts guaranteed under these
agreements aggregated $105.6 million. The amounts of scheduled
expiration of the maximum amounts guaranteed under these
agreements aggregate $30.8 million in 2005; $17.9 million in 2006;
$2.1 million in 2007; $200,000 in 2008; $900,000 in 2009; $30.0
million in 2010; $12.0 million in 2012; $2.2 million in 2028;
$500,000, which is subject to expiration 30 days after the receipt
of written notice and $9.0 million, which has no scheduled
maturity date. The amount outstanding by subsidiaries of the
Company under the above guarantees was $561,000 and was reflected
on the Consolidated Balance Sheets at March 31, 2005. In the
event of default under these guarantee obligations, the subsidiary
issuing the guarantee for that particular obligation would be
required to make payments under its guarantee.
Fidelity and WBI Holdings have outstanding guarantees to Williston
Basin. These guarantees are related to natural gas transportation
and storage agreements that guarantee the performance of
Prairielands Energy Marketing, Inc. (Prairielands), an indirect
wholly owned subsidiary of the Company. At March 31, 2005, 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 2008
and $20.0 million in 2009. In the event of Prairielands' default
in its payment obligations, the subsidiary issuing the guarantee
for that particular obligation would be required to make payments
under its guarantee. The amount outstanding by Prairielands under
the above guarantees was $1.6 million, which was not reflected on
the Consolidated Balance Sheet at March 31, 2005, 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 Sheet
at March 31, 2005.
As of March 31, 2005, Centennial was contingently liable for the
performance of certain of its subsidiaries under approximately
$441 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.
19. Related party transactions
In 2004, Bitter Creek Pipelines, LLC (Bitter Creek) entered into
two natural gas gathering agreements with Nance Petroleum
Corporation (Nance Petroleum), a wholly owned subsidiary of St.
Mary Land & Exploration Company (St. Mary). Robert L. 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 Petroleum were effective upon completion of
certain high and low pressure gathering facilities, which occurred
in mid-December 2004. Bitter Creek's capital expenditures related
to the completion of the gathering lines and the expansion of its
gathering facilities to accommodate the natural gas gathering
agreements were $1.0 million for the three months ended March 31,
2005, and are estimated for the next three years to be $2.5
million in 2005, $2.2 million in 2006 and $3.3 million in 2007.
The natural gas gathering agreements are each for a term of 15
years and month-to-month thereafter. Bitter Creek's revenues from
these contracts were $252,000 for the three months ended March 31,
2005, and estimated revenues from these contracts for the next
three years are $1.9 million in 2005, $3.8 million in 2006 and
$5.8 million in 2007. The amount due from Nance Petroleum at
March 31, 2005, was $91,000.
Montana-Dakota entered into an agreement to purchase natural gas
from Nance Petroleum for the period April 1, 2005 to October 31,
2005. Montana-Dakota estimates that it will purchase between $2.5
million to $3.5 million of natural gas from Nance Petroleum during
this period.
20. Pending Acquisition
On April 19, 2005, Fidelity signed purchase and sale agreements to
acquire natural gas and oil properties for an aggregate cash
purchase price of $145 million, subject to accounting and purchase
price adjustments customary for oil and natural gas acquisitions
of this type. The acquisition is expected to close in May 2005,
conditional upon completion of a due diligence process, including
environmental reviews, and satisfaction of other standard closing
conditions.
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
OVERVIEW
This subsection of MD&A is an 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 MD&A 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
Prior to the fourth quarter of 2004, the Company reported 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 did not individually meet the
criteria to be considered a reportable segment. In the fourth quarter
of 2004, the Company separated independent power production as a
reportable business segment due to the significance of its operations.
The Company's operations are now conducted through seven reportable
segments and all prior period information has been restated to reflect
this change.
The vast majority of the Company's operations are located within the
United States. The Company also has investments in foreign countries,
which largely consist of investments in natural gas-fired electric
generating facilities in Brazil and Trinidad and Tobago, as discussed
in Note 12 of Notes to Consolidated Financial Statements.
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 WBI Holdings' 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. 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
operations of Centennial Resources owns, builds and operates electric
generating facilities in the United States and has investments in
electric generating facilities in Brazil, Trinidad and Tobago, and the
United States. Electric capacity and energy produced at its power
plants are sold primarily under mid- and long-term contracts to
nonaffiliated entities.
Earnings from electric, natural gas distribution and pipeline and
energy services are substantially all from regulated operations.
Earnings from utility services, natural gas and oil production,
construction materials and mining, 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 properties, 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 $660 million for 2005.
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 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 the
effects of price volatility.
- Economic volatility both domestically and in the foreign countries
where the Company does business affects the Company's operations as
well as the demand for its products and services and, as a result,
may have a negative impact on the Company's future revenues.
- Fidelity continues to seek additional reserve and production
growth, both in areas of existing activity and in other regions,
through acquisition, exploration, development and production of natural
gas and oil resources, including the development and production of its
coalbed natural gas properties in the Powder River Basin. In this
context, Fidelity has been named as a defendant in, and/or certain of
its operations are the subject of, more than a dozen lawsuits filed in
connection with its coalbed natural gas development program. Some of
these actions have been successfully resolved and Fidelity is actively
defending the others. If the plaintiffs are successful in the
outstanding 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 in
this region.
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 summarizes the contribution to consolidated
earnings by each of the Company's businesses.
Three Months
Ended
March 31,
2005 2004
(Dollars in millions,
where applicable)
Electric $ 3.1 $ 3.4
Natural gas distribution 4.8 2.3
Utility services 2.0 (1.9)
Pipeline and energy services 3.2 2.7
Natural gas and oil production 28.8 25.3
Construction materials and mining (8.5) (11.9)
Independent power production .7 3.2
Other .1 .3
Earnings on common stock $ 34.2 $ 23.4
Earnings per common share - basic $ .29 $ .20
Earnings per common share - diluted $ .29 $ .20
Return on average common equity
for the 12 months ended 13.5% 12.7%
________________________________
Three Months Ended March 31, 2005 and 2004
Consolidated earnings for the quarter ended March 31, 2005, increased
$10.8 million from the comparable prior period largely due to:
- Higher natural gas prices of 10 percent and higher oil prices of
27 percent at the natural gas and oil production business
- Increased outside electrical line construction workloads and
margins at the utility services business
- Improving economic conditions in Oregon contributed to increases
in all product lines in that region at the construction materials and
mining business
- Higher retail sales prices, resulting from rate increases
effective in North Dakota, Minnesota, South Dakota and Montana at the
natural gas distribution business
Partially offsetting the increase in earnings was a decrease in
earnings from the Company's equity method investment in Brazil as
the result of the pending sale of the Termoceara Generating
Facility as discussed in Note 12 of Notes to Consolidated Financial
Statements.
FINANCIAL AND OPERATING DATA
The following tables contain key financial and operating statistics for
each of the Company's businesses.
Electric
Three Months
Ended
March 31,
2005 2004
(Dollars in millions,
where applicable)
Operating revenues $ 44.3 $ 47.0
Operating expenses:
Fuel and purchased power 16.2 16.7
Operation and maintenance 13.8 15.0
Depreciation, depletion and amortization 5.1 5.0
Taxes, other than income 2.3 2.3
37.4 39.0
Operating income $ 6.9 $ 8.0
Retail sales (million kWh) 604.5 621.1
Sales for resale (million kWh) 198.0 227.3
Average cost of fuel and purchased
power per kWh $ .019 $ .019
Three Months Ended March 31, 2005 and 2004
Electric earnings decreased $300,000 due to:
- Lower retail sales margins largely the result of a 3 percent
decrease in retail sales volumes, primarily lower residential and
commercial sales volumes, and the effects of a seasonal rate design in
North Dakota
- Lower sales for resale volumes of 13 percent, the result of
decreased market demand due to milder weather
Partially offsetting the decrease were:
- Decreased operation and maintenance expenses of $700,000 (after
tax), largely payroll-related costs
- Higher average sales for resale prices of 9 percent
Natural Gas Distribution
Three Months
Ended
March 31,
2005 2004
(Dollars in millions,
where applicable)
Operating revenues:
Sales $143.6 $127.0
Transportation and other 1.3 1.3
144.9 128.3
Operating expenses:
Purchased natural gas sold 120.5 105.6
Operation and maintenance 11.9 13.8
Depreciation, depletion and amortization 2.4 2.3
Taxes, other than income 1.6 1.6
136.4 123.3
Operating income $ 8.5 $ 5.0
Volumes (MMdk):
Sales 15.8 16.3
Transportation 4.0 3.8
Total throughput 19.8 20.1
Degree days (% of normal)* 93% 96%
Average cost of natural gas, including
transportation thereon, per dk $ 7.61 $ 6.46
_____________________
* Degree days are a measure of the daily temperature-related demand
for energy for heating.
Three Months Ended March 31, 2005 and 2004
Earnings at the natural gas and distribution business increased $2.5
million, the result of:
- Higher retail sales prices, the result of rate increases effective
in North Dakota, Minnesota, South Dakota and Montana
- Lower operation and maintenance expenses of $1.2 million (after
tax), primarily payroll-related
Utility Services
Three Months
Ended
March 31,
2005 2004
(In millions)
Operating revenues $ 113.9 $ 100.3
Operating expenses:
Operation and maintenance 101.2 95.5
Depreciation, depletion and amortization 2.7 2.6
Taxes, other than income 5.8 4.8
109.7 102.9
Operating income (loss) $ 4.2 $ (2.6)
Three Months Ended March 31, 2005 and 2004
Utility services had $2.0 million in earnings for the first quarter,
compared to a $1.9 million loss in the comparable prior period. The
increase is due to:
- Increased outside electrical line construction workloads and
margins
- An increase from equipment sales and rentals of $500,000 (after
tax)
- Lower general and administrative expenses of $500,000 (after tax),
largely lower payroll-related costs due in part to a reduction in work
force
Pipeline and Energy Services
Three Months
Ended
March 31,
2005 2004
(Dollars in millions)
Operating revenues:
Pipeline $ 19.7 $ 23.1
Energy services 73.1 61.1
92.8 84.2
Operating expenses:
Purchased natural gas sold 65.5 57.3
Operation and maintenance 13.3 13.4
Depreciation, depletion and amortization 4.7 4.7
Taxes, other than income 2.0 1.9
85.5 77.3
Operating income $ 7.3 $ 6.9
Transportation volumes (MMdk):
Montana-Dakota 7.7 8.3
Other 13.9 14.1
21.6 22.4
Gathering volumes (MMdk) 20.0 19.5
Three Months Ended March 31, 2005 and 2004
Earnings increased $500,000 at the pipeline and energy services
business due to:
- Higher gathering rates of $1.1 million (after tax)
- Lower operations and maintenance expenses, largely lower payroll-
related expenses
Partially offsetting the increase were lower average transportation and
storage rates in 2005 of $1.5 million (after tax), due in part to the
estimated effects of a FERC rate order received in July 2003 and
rehearing order received in May 2004 which resulted in lower
anticipated rates effective July 1, 2004.
Natural Gas and Oil Production
Three Months
Ended
March 31,
2005 2004
(Dollars in millions,
where applicable)
Operating revenues:
Natural gas $ 72.4 $ 66.4
Oil 14.6 14.2
Other .1 .4
87.1 81.0
Operating expenses:
Purchased natural gas sold .1 .4
Operation and maintenance:
Lease operating costs 7.9 8.2
Gathering and transportation 2.8 2.5
Other 5.5 6.0
Depreciation, depletion and
amortization 17.2 16.6
Taxes, other than income:
Production and property taxes 5.9 4.7
Other .2 .1
39.6 38.5
Operating income $ 47.5 $ 42.5
Production:
Natural gas (MMcf) 14,427 14,506
Oil (000's of barrels) 367 457
Average realized prices (including hedges):
Natural gas (per Mcf) $ 5.02 $ 4.57
Oil (per barrel) $ 39.68 $ 31.16
Average realized prices (excluding hedges):
Natural gas (per Mcf) $ 5.02 $ 4.68
Oil (per barrel) $ 44.11 $ 32.34
Production costs, including
taxes, per net equivalent Mcf:
Lease operating costs $ .47 $ .48
Gathering and transportation .17 .14
Production and property taxes .36 .27
$ 1.00 $ .89
Three Months Ended March 31, 2005 and 2004
The natural gas and oil production business experienced a $3.5 million
increase in earnings due to:
- Higher average realized natural gas prices of 10 percent
- Higher average realized oil prices of 27 percent
Partially offsetting the increase were:
- Decreased oil production of 20 percent, primarily due to normal
production declines
- Higher depreciation, depletion and amortization expense of
$300,000 (after tax) due to higher rates, partially offset by decreased
production
Construction Materials and Mining
Three Months
Ended
March 31,
2005 2004
(Dollars in millions)
Operating revenues $ 187.1 $ 139.4
Operating expenses:
Operation and maintenance 170.4 133.0
Depreciation, depletion and amortization 18.1 16.2
Taxes, other than income 8.1 6.5
196.6 155.7
Operating loss $ (9.5) $ (16.3)
Sales (000's):
Aggregates (tons) 5,906 4,807
Asphalt (tons) 361 302
Ready-mixed concrete (cubic yards) 660 574
Three Months Ended March 31, 2005 and 2004
The construction materials and mining business experienced a seasonal
loss of $8.5 million in the first quarter. However, the seasonal loss
decreased by $3.4 million from the $11.9 million loss experienced in
the first quarter of 2004 due to:
- Improving economic conditions in Oregon which contributed to
increases in all the product lines in that region
- Increased ready-mixed concrete volumes
- Favorable weather at several operating locations
Independent Power Production
Three Months
Ended
March 31,
2005 2004
(Dollars in millions)
Operating revenues $ 9.8 $ 6.4
Operating expenses:
Operation and maintenance 6.4 3.9
Depreciation, depletion and amortization 2.5 2.1
Taxes, other than income .7 ---
9.6 6.0
Operating income $ .2 $ .4
Net generation capacity - kW* 279,600 279,600
Electricity produced and sold (thousand kWh)* 37,250 31,355
_____________________
* Excludes equity method investments.
NOTE: The earnings from the Company's equity method investments are
not reflected in the above table.
Three Months Ended March 31, 2005 and 2004
Earnings for the independent power production business decreased $2.5
million due to the absence in 2005 of earnings from the Company's
equity method investment in Brazil pursuant to the terms of the
pending sale of the Termoceara Generating Facility as discussed in
Note 12 of Notes to Consolidated Financial Statements. Earnings of
$900,000 (after tax) from equity method investments acquired since the
comparable period last year partially offset the decrease in earnings.
Other and Intersegment Transactions
Amounts presented in the preceding tables will not agree with the
Consolidated Statements of Income due to the Company's other
operations and the elimination of intersegment transactions. The
amounts relating to these items are as follows:
Three Months
Ended
March 31,
2005 2004
(In millions)
Other:
Operating revenues $ 1.4 $ .9
Operation and maintenance 1.2 .8
Depreciation, depletion and
amortization .1 ---
Taxes, other than income .1 ---
Intersegment transactions:
Operating revenues $77.0 $72.0
Purchased natural gas sold 72.6 68.5
Operation and maintenance 4.4 3.5
For further information on intersegment eliminations, see Note 15 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 and commodity price basis differentials, 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 and pipeline and energy services businesses.
The construction and operation of power generation facilities may
involve unanticipated changes or delays that 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 Company's utility services business operates in highly competitive
markets characterized by low margins in a number of service lines and
geographic areas.
This business' ability to return to profitability on a sustained basis
will depend upon improved capital spending for electric construction
services and management's ability to successfully refocus the business
on more profitable markets, reduce operating costs and implement
process improvements in project management.
Economic volatility affects the Company's operations as well as the
demand for its products and services and, as a result, may have a
negative impact on the Company's future revenues.
The global demand for natural resources, interest rates, governmental
budget constraints, and the ongoing threat of terrorism can create
volatility in the financial markets. 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
- A deterioration in capital market conditions
- Volatility in commodity prices
- Terrorist attacks
- Fluctuations in the value of the dollar on currency exchanges
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 ongoing
litigation and 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 injunctive relief or other
remedies 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
delay and/or 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.
The pending sale of the Termoceara Generating Facility may impact the
Company's future earnings.
The Company signed a Term Sheet that provides a framework in principle
for the sale of the Termoceara Generating Facility to Petrobras. At
the completion of the sale, the Company will no longer generate
earnings from its equity method investment in the project, and there
can be no assurance that the Company will be able to use the proceeds
from the sale in a manner that will provide comparable future earnings.
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 production 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 2005, diluted, are projected in the
range of $1.80 to $2.00, an increase from prior guidance of $1.70 to
$1.90.
- The Company expects the percentage of 2005 earnings per common
share, diluted, by quarter to be in the following approximate ranges:
- Second quarter - 24 percent to 29 percent
- Third quarter - 32 percent to 37 percent
- Fourth quarter - 22 percent to 27 percent
- These projections include the estimated effects of the anticipated
sale of the Termoceara Generating Facility located in Brazil, the
pending acquisition of natural gas and oil properties as discussed in
Note 20 of Notes to Consolidated Financial Statements, and an
investment in an additional international project.
- The Company's long-term compound annual growth goals on earnings
per share from operations are in the range of 7 percent to 10 percent.
- The Company anticipates investing approximately $660 million in
capital expenditures during 2005.
- 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
- The expected earnings in 2005 are anticipated to be slightly lower
than 2004.
- This segment is involved in the review of potential power projects
to replace capacity associated with expiring purchased power contracts
and to provide for future growth. Those projects include participation
in a proposed 600-megawatt (MW) coal-fired facility to be located in
northeastern South Dakota and construction of a 175-MW lignite coal-
fired facility (Vision 21) to be located in southwestern North Dakota.
An air quality permit application is under review at the ND Health
Department for the 175-MW facility. The costs of building and/or
acquiring the additional generating capacity needed by the utility are
expected to be recovered in rates.
- 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.
- On October 25, 2004, Montana-Dakota issued a request for proposal
for 70 megawatts to 100 megawatts of firm capacity and associated
energy for the period of November 1, 2006 through December 31, 2010.
Montana-Dakota is currently in the process of evaluating the responses.
A decision is expected to be made late 2005.
Natural gas distribution
- The expected earnings for this segment for 2005 are projected to
be somewhat higher than the earnings for 2004.
- In September 2004, a natural gas rate case was filed with the MPUC
requesting an increase of $1.4 million annually, or 4.0 percent above
current rates. An interim increase of $1.4 million annually was
approved by the MPUC effective January 10, 2005, subject to refund. A
final order is expected in late 2005.
- On March 24, 2005, a natural gas rate case was filed with the
SDPUC for the East River service area requesting an increase of
$850,000 annually, or 12.8 percent above current rates. A final order
is expected in late 2005.
- 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.
Utility services
- Revenues are expected to be in the range of $450 million to $500
million in 2005.
- The Company anticipates margins to increase substantially in 2005
as compared to 2004 levels.
- Work backlog as of March 31, 2005, was approximately $226 million,
compared to $174 million at March 31, 2004.
Pipeline and energy services
- In 2005, total natural gas gathering and transportation throughput
is expected to remain at the record levels achieved in 2004.
- Firm capacity for the Grasslands Pipeline is currently 90,000 Mcf
per day with expansion possible to 200,000 Mcf per day.
- Transportation and storage rate reductions due to the estimated
effects of a FERC rate order received in July 2003 and rehearing order
received in May 2004 have been reflected in earnings projections.
- The labor contract that Williston Basin was negotiating, as
reported in Items 1 and 2 - Business and Properties - General in the
Company's 2004 Annual Report, remains in negotiations.
Natural gas and oil production
- The Company is expecting to drill up to 500 wells in 2005,
dependent on the timely receipt of regulatory approvals. Delays in
receipt of drilling permits are affecting producers throughout the
Rocky Mountain region.
- In 2005, the Company expects a combined natural gas and oil
production increase of approximately 6 percent to 10 percent over 2004
levels. A portion of this increase is predicated on the timely receipt
of various regulatory approvals and the closing of the pending
acquisition as discussed in Note 20 of Notes to Consolidated Financial
Statements. Currently, this segment's net combined natural gas and oil
production is approximately 175,000 Mcf equivalent to 185,000 Mcf
equivalent per day.
- Estimates of natural gas prices in the Rocky Mountain region for
May through December 2005 reflected in 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 May through December 2005 reflected in
earnings guidance are in the range of $5.75 to $6.25 per Mcf. During
2004, more than three-fourths of this segment's natural gas production
was priced using Rocky Mountain or other non-NYMEX prices.
- Estimates of NYMEX crude oil prices for April through December
2005 reflected in earnings guidance are projected in the range of $40
to $45 per barrel.
- The Company has hedged approximately 35 percent to 40 percent of
its 2005 estimated annual natural gas production at various indices
with prices ranging from a low Ventura index of $4.75 per Mcf to a high
NYMEX price of $10.18 per Mcf. Ventura is an index pricing point
related to Northern Natural Gas Co.'s system.
- The Company has hedged approximately 35 percent to 40 percent of
its 2005 estimated annual oil production at NYMEX prices ranging from a
low of $30.70 per barrel to a high of $52.05 per barrel.
- The Company has hedged approximately 5 percent to 10 percent of
its 2006 estimated annual natural gas production at various indices
with prices ranging from a low Ventura index of $6.00 per Mcf to a high
Ventura index of $7.60 per Mcf.
- The Company has hedged approximately 5 percent to 10 percent of
its 2006 estimated annual oil production at NYMEX prices ranging from a
low of $43.00 per barrel to a high of $54.15 per barrel.
Construction materials and mining
- The Company anticipates improved earnings in 2005 as compared to
2004 with an expected return to normal weather conditions in Texas.
- Aggregate, ready-mixed concrete and asphalt volumes in 2005 are
expected to be comparable to 2004 levels.
- Revenues in 2005 are expected to be somewhat higher than 2004
levels.
- The Company expects that the replacement funding legislation for
the Transportation Equity Act for the 21st Century will be equal to or
higher than previous funding levels.
- Work backlog as of March 31, 2005, was approximately $527 million,
compared to $449 million at March 31, 2004.
- The labor contract that Knife River was negotiating, as reported
in Items 1 and 2 - Business and Properties - General in the Company's
2004 Annual Report, remains in negotiations.
Independent power production
- Earnings for 2005 are expected to be lower than 2004 earnings
primarily due to benefits realized in 2004 from foreign currency gains,
the effects of the embedded derivative in the Brazilian electric power
sales contract and as a result of the pending sale of the Brazilian
electric generating facility.
- The Company is constructing a 116-MW coal-fired electric
generating facility 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
the purchaser having an option for a two-year extension. The projected
on-line date for this plant is late 2005.
NEW ACCOUNTING STANDARDS
SAB No. 106
In September 2004, the SEC issued SAB No. 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 No.
106 was effective for the Company as of January 1, 2005. The adoption
of SAB No. 106 did not have a material effect on the Company's
financial position or results of operations.
SFAS No. 123 (revised)
In December 2004, the FASB issued SFAS No. 123 (revised). SFAS No. 123
(revised) revises SFAS No. 123 and requires entities to recognize
compensation expense in an amount equal to the fair value of share-
based payments granted to employees. SFAS No. 123 (revised) requires a
company to record compensation expense for all awards granted after the
date of adoption of SFAS No. 123 (revised) and for the unvested portion
of previously granted awards that remain outstanding at the date of
adoption. SFAS No. 123 (revised) is effective for the Company on
January 1, 2006. The Company is evaluating the effects of the adoption
of SFAS No. 123 (revised).
FIN 47
In March 2005, the FASB issued FIN 47. FIN 47 addresses the diverse
accounting practices that developed with respect to the timing of
liability recognition for legal obligations associated with the
retirement of a tangible long-lived asset when the timing and/or method
of settlement of the obligation are conditional on a future event. FIN
47 is effective for the Company at the end of the fiscal year ending
December 31, 2005. The Company is evaluating the effects of the
adoption of FIN 47.
EITF No. 04-6
In March 2005, the FASB ratified EITF No. 04-6. EITF No. 04-6 requires
that post-production stripping costs be treated as a variable inventory
production cost. EITF No. 04-6 is effective
for the Company on January 1, 2006. The Company is evaluating the
effects of the adoption of EITF No. 04-6.
For further information on SAB No. 106, SFAS No. 123 (revised), FIN 47
and EITF No. 04-6, see Note 10 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 2004 Annual
Report. For more information on critical accounting policies involving
significant estimates, see Part II, Item 7 in the 2004 Annual Report.
LIQUIDITY AND CAPITAL COMMITMENTS
Cash flows
Operating activities
Cash flows provided by operating activities in the first quarter of
2005 increased $47.5 million from the comparable 2004 period, largely
the result of an increase in working capital of $27.1 million and
higher net income of $10.8 million. Partially offsetting the increase
was decreased deferred income taxes of $8.4 million.
Investing activities
Cash flows used in investing activities in the first quarter of 2005
increased $19.1 million compared to the comparable 2004 period, the
result of an increase in net capital expenditures (capital
expenditures; acquisitions, net of cash acquired; and net proceeds from
the sale or disposition of property) of $39.8 million primarily due to
the construction of a 116-megawatt coal-fired electric generating
facility near Hardin, Montana and higher ongoing capital expenditures.
Largely offsetting the increase was a decrease in investments of $22.6
million due in part to the purchase of the Trinity Generating Facility
in February 2004 at the independent power production business.
Financing activities
Cash flows provided by financing activities in the first quarter of
2005 decreased $7.9 million compared to the comparable 2004 period, the
result of a $52.6 million decrease in the issuance of common stock as
the result of proceeds received from an underwritten public offering in
2004. An increase of $20.1 million in the repayment of long-term debt
also contributed to the decrease. Partially offsetting the decrease
was an increase in the issuance of long-term debt of $66.7 million.
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, 2004, certain
Pension Plans' accumulated benefit obligations exceeded these plans'
assets by approximately $3.7 million. Pretax pension expense (income)
reflected in the years ended December 31, 2004, 2003 and 2002, was $4.1
million, $153,000, and ($2.4) million, respectively. The Company's
pension expense is currently projected to be approximately $6.5 million
to $7.5 million in 2005. 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 2004, 2003 and 2002
were approximately $1.2 million, $1.6 million, and $1.2 million,
respectively. For further information on the Company's Pension Plans,
see Note 16 of Notes to Consolidated Financial Statements.
Capital expenditures
Net capital expenditures for the first three months of 2005 were $93.8
million. Net capital expenditures, including the issuance of the
Company's equity securities in connection with acquisitions, are
estimated to be approximately $660 million for the year 2005.
Estimated capital expenditures include those for:
- Potential future acquisitions
- System upgrades
- Routine replacements
- Service extensions
- Routine equipment maintenance and replacements
- Buildings, 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 costs for
additional electric generating capacity and for a 116-megawatt coal-
fired development project, as previously discussed
- Other growth opportunities
Approximately 28 percent of estimated 2005 net capital expenditures are
associated with potential future acquisitions, including the pending
acquisition discussed in Note 20 of Notes to Consolidated Financial
Statements. 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
2005 capital expenditures referred to previously. 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.
Capital resources
Certain debt instruments of the Company and its subsidiaries, including
those discussed below, contain restrictive covenants, all of which the
Company and its subsidiaries were in compliance with at March 31, 2005.
MDU Resources Group, Inc.
The Company has a revolving credit agreement with various banks
totaling $90 million at March 31, 2005. There were no amounts
outstanding under the credit agreement at March 31, 2005. The credit
agreement supports the Company's $75 million commercial paper program.
There were no amounts outstanding under the Company's commercial paper
program at March 31, 2005. The commercial paper borrowings classified
as long-term debt are intended to be refinanced on a long-term basis
through continued MDU Resources commercial paper borrowings and as
further supported by the credit agreement, which expires on July 18,
2006.
The Company's goal is to maintain acceptable credit ratings in order to
access the capital markets through the issuance of commercial paper.
If the Company were to experience a minor downgrade of its credit
ratings, it would not anticipate any change in its ability to access
the capital markets. However, in such event, the Company would expect
a nominal basis point increase in overall interest rates with respect
to its cost of borrowings. If the Company were to experience a
significant downgrade of its credit ratings, which it does not
currently anticipate, it may need to borrow under its credit agreement.
To the extent the Company needs to borrow under its credit agreement,
it would be expected to incur increased annualized interest expense on
its variable rate debt. This was not applicable at March 31, 2005, as
there were no variable rate borrowings.
Prior to the maturity of the credit agreement, the Company plans to
negotiate the extension or replacement of this agreement, which
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 March 31, 2005. In the
event the Company does not comply with the applicable covenants and
other conditions, alternative sources of funding may need to be
pursued, as previously described.
There are no credit facilities that contain cross-default provisions
between the Company and any of its subsidiaries.
On April 19, 2005, the Company issued conditional notices of redemption
to redeem $20.9 million in Montana-Dakota Pollution Control Refunding
Revenue Bonds in May 2005. Commercial paper borrowings will be used to
fund the redemption.
The Company's issuance of first mortgage debt is subject to certain
restrictions imposed under the terms and conditions of its Indenture of
Mortgage. Generally, those restrictions require the Company to fund
$1.43 of unfunded property or use $1.00 of refunded bonds for each
dollar of indebtedness incurred under the Indenture and, in some cases,
to certify to the trustee that annual earnings (pretax and before
interest charges), as defined in the Indenture, equal at least two
times its annualized first mortgage bond interest costs. Under the
more restrictive of the tests, as of March 31, 2005, the Company could
have issued approximately $346 million of additional first mortgage
bonds.
The Company's coverage of fixed charges including preferred dividends
was 5.0 times and 4.7 times for the twelve months ended March 31, 2005,
and December 31, 2004, respectively. Additionally, the Company's first
mortgage bond interest coverage was 7.5 times and 7.1 times for the
twelve months ended March 31, 2005, and December 31, 2004,
respectively. Common stockholders' equity as a percent of total
capitalization (net of long-term debt due within one year) was 64
percent and 65 percent at March 31, 2005, and December 31, 2004,
respectively.
Centennial Energy Holdings, Inc.
Centennial has three revolving credit agreements with various banks and
institutions that support $335 million of Centennial's $350 million
commercial paper program. There were no outstanding borrowings under
the Centennial credit agreements at March 31, 2005. Under the
Centennial commercial paper program, $97 million was outstanding at
March 31, 2005. 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, and another agreement is for $25 million
and expires on April 30, 2007. Pursuant to the $25 million credit
agreement, on the last business day of April in 2005 and 2006, the line
of credit will be reduced by $3.6 million each year. Centennial
intends to negotiate the extension or replacement of these agreements
prior to their maturities. The third agreement is an uncommitted line
for $10 million, which was effective on January 25, 2005, and may be
terminated by the bank at any time.
Centennial has an uncommitted long-term master shelf agreement that
allows for borrowings of up to $450 million (previously $400
million) which was amended and restated on April 29, 2005. Under the
terms of the master shelf agreement, $359 million was outstanding at
March 31, 2005. The ability to request additional borrowings under
this master shelf agreement will expire in April 2008. 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 $146,000 (after tax)
based on March 31, 2005, variable rate borrowings. Based on
Centennial's overall interest rate exposure at March 31, 2005, 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,
which provide credit support to access the capital markets. In the
event Centennial was unable to successfully negotiate these agreements,
or in the event the fees on such facilities became too expensive, which
Centennial does not currently anticipate, it would seek alternative
funding. One source of alternative funding might involve the
securitization of certain Centennial assets.
In order to borrow under Centennial's credit agreements and the
Centennial uncommitted long-term master shelf agreement, Centennial and
certain of its subsidiaries must be in compliance with the applicable
covenants and certain other conditions. The significant covenants
include maximum capitalization ratios, minimum interest coverage
ratios, minimum consolidated net worth, limitation on priority debt,
limitation on sale of assets and limitation on loans and investments.
Centennial and such subsidiaries were in compliance with these
covenants and met the required conditions at March 31, 2005. In the
event Centennial or such subsidiaries do not comply with the applicable
covenants and other conditions, alternative sources of funding may need
to be pursued as previously described.
Certain of Centennial's financing agreements contain cross-default
provisions. These provisions state that if Centennial or any
subsidiary of Centennial fails to make any payment with respect to any
indebtedness or contingent obligation, in excess of a specified amount,
under any agreement that causes such indebtedness to be due prior to
its stated maturity or the contingent obligation to become payable, the
applicable agreements will be in default. Certain of Centennial's
financing agreements and Centennial's practice limit the amount of
subsidiary indebtedness.
Williston Basin Interstate Pipeline Company
Williston Basin has an uncommitted long-term master shelf agreement
that allows for borrowings of up to $100 million. Under the terms of
the master shelf agreement, $55.0 million was outstanding at March 31,
2005. The ability to request additional borrowings under this master
shelf agreement expires on December 20, 2005.
In order to borrow under Williston Basin's uncommitted long-term master
shelf agreement, it must be in compliance with the applicable covenants
and certain other conditions. The significant covenants include
limitation on consolidated indebtedness, limitation on priority debt,
limitation on sale of assets and limitation on investments. Williston
Basin was in compliance with these covenants and met the required
conditions at March 31, 2005. 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 Termoceara Generating Facility, as discussed in
Note 12. The Company, through MDU Brasil, owns 49 percent of MPX. The
main business purpose of Centennial extending the guarantee to MPX's
creditors is to enable MPX to obtain lower borrowing costs. At
March 31, 2005, the aggregate amount of borrowings outstanding subject
to these guarantees was $29.4 million and the scheduled repayment of
these borrowings is $5.5 million in 2005, $10.7 million in each of 2006
and 2007 and $2.5 million in 2008. The individual investor (who
through EBX 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 March 31, 2005, Centennial was contingently liable for
performance of certain of its subsidiaries under approximately
$441 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, operating leases and purchase commitments
from those reported in the 2004 Annual Report.
For more information on contractual obligations and commercial
commitments, see Part II, Item 7 in the 2004 Annual Report.
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 2004 Annual Report, and Notes 11 and 14 of
Notes to Consolidated Financial Statements.
The following table summarizes hedge agreements entered into by
Fidelity as of March 31, 2005. 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 2005 $ 5.48 6,049 $(12,869)
Natural gas swap
agreements maturing
in 2006 $ 6.80 5,360 $ (3,975)
Weighted
Average
Floor/Ceiling Notional
Price Amount
(Per MMBtu) (In MMBtu's) Fair Value
Natural gas collar
agreements maturing
in 2005 $ 5.34/$6.60 12,375 $(14,500)
Natural gas collar
agreement maturing
in 2006 $ 6.00/$7.60 1,825 $ (995)
Weighted
Average Notional
Fixed Price Amount
(Per barrel) (In barrels) Fair Value
Oil swap agreement
maturing in 2005 $ 30.70 138 $ (3,511)
Weighted
Average
Floor/Ceiling Notional
Price Amount
(Per barrel) (In barrels) Fair Value
Oil collar agreements
maturing in 2005 $38.27/$45.67 430 $ (4,529)
Oil collar agreement
maturing in 2006 $43.00/$54.15 183 $ (896)
Interest rate risk
There were no material changes to interest rate risk faced by the
Company from those reported in the 2004 Annual Report. For more
information on interest rate risk, see Part II, Item 7A in the 2004
Annual Report.
Foreign currency risk
MDU Brasil has a 49-percent equity method investment in an 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 Termoceara Generating Facility is the
Brazilian Real.
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 Termoceara
Generating Facility's U.S. dollar denominated obligations. At March
31, 2005, these U.S. dollar denominated obligations approximated $53.7
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 Termoceara Generating Facility, would record a
foreign currency loss in net income of approximately $2.0 million
(after tax) based on the above U.S. dollar denominated obligations at
March 31, 2005.
The investment of Centennial International in the Termoceara
Generating Facility at March 31, 2005, was approximately $24.7
million.
A portion of the Termoceara 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 Termoceara
Generating Facility's electric power sales contract. The Termoceara
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.
For further information on this investment including the Term Sheet
involving the potential sale of the Termoceara Generating Facility to
Petrobras, see Note 12 of Notes to Consolidated Financial Statements.
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.
Changes in internal controls
The Company maintains a system of internal accounting controls that is
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
For information regarding legal proceedings, see Note 18 of Notes to
Consolidated Financial Statements, which is incorporated by reference.
ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
ISSUER PURCHASES OF EQUITY SECURITIES
(a) (b) (c) (d)
Total Total Number Maximum Number
Number Average of Shares (or (or Approximate
of Price Units) Purchased Dollar Value) of
Shares Paid as Part of Shares (or
(or per Publicly Units) that May
Units) Share Announced Yet Be Purchased
Period Purchased (or Plans or Under the Plans
(1) Unit) Programs (2) or Programs (2)
January 1 through
January 31, 2005
February 1 through
February 28, 2005 16,574 $27.68
March 1 through
March 31, 2005
Total 16,574 $27.68
(1) Represents shares of common stock withheld by the Company at the
request of its executive officers and employees to pay taxes pursuant
to officer and employee compensation plans.
(2) Not applicable. The Company does not currently have in place any
publicly announced plans or programs to purchase equity securities.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
The Company's Annual Meeting of Stockholders was held on April 26,
2005. Three proposals were submitted to stockholders as described in
the Company's Proxy Statement dated March 11, 2005, and were voted upon
and approved by stockholders at the meeting. The table below briefly
describes the proposals and the results of the stockholder votes.
Shares
Shares Against or Broker
For Withheld Abstentions Non-Votes
Proposal to elect three directors:
For terms expiring in 2008 --
Thomas Everist 102,103,344 1,339,097 --- ---
Patricia L. Moss 102,103,582 1,338,859 --- ---
Robert L. Nance 102,139,057 1,303,384 --- ---
Proposal to ratify the appointment
of Deloitte and Touche LLP as
the Company's independent
auditors for 2005 102,564,803 442,250 435,388 ---
Proposal to re-approve the
material terms of the
performance goals under the 1997
Executive Long-term Incentive
Plan 96,596,246 5,524,760 1,321,435 ---
ITEM 6. EXHIBITS
10(a) Supplemental Income Security Plan, as amended and restated
February 17, 2005
10(b) 1997 Executive Long-Term Incentive Plan, as amended
February 17, 2005
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: May 4, 2005 BY: /s/ Warren L. Robinson
Warren L. Robinson
Executive Vice President
and Chief Financial
Officer
BY: /s/ Vernon A. Raile
Vernon A. Raile
Senior Vice President
and Chief Accounting
Officer
EXHIBIT INDEX
Exhibit No.
10(a) Supplemental Income Security Plan, as amended and restated
February 17, 2005
10(b) 1997 Executive Long-Term Incentive Plan, as amended
February 17, 2005
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