UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
X QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
FOR THE QUARTERLY PERIOD ENDED June 30, 2004
OR
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the Transition Period from _____________ to ______________
Commission file number 1-3480
MDU Resources Group, Inc.
(Exact name of registrant as specified in its charter)
Delaware 41-0423660
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
Schuchart Building
918 East Divide Avenue
P.O. Box 5650
Bismarck, North Dakota 58506-5650
(Address of principal executive offices)
(Zip Code)
(701) 222-7900
(Registrant's telephone number, including area code)
Indicate by check mark whether the registrant (1) has filed all
reports required to be filed by Section 13 or 15(d) of the
Securities Exchange Act of 1934 during the preceding 12 months (or
for such shorter period that the registrant was required to file
such reports), and (2) has been subject to such filing requirements
for the past 90 days. Yes X. No.
Indicate by check mark whether the registrant is an accelerated
filer (as defined in Rule 12b-2 of the Exchange Act). Yes X. No.
Indicate the number of shares outstanding of each of the issuer's
classes of common stock, as of July 30, 2004: 117,492,838 shares.
INTRODUCTION
This Form 10-Q contains forward-looking statements within the
meaning of Section 21E of the Securities Exchange Act of 1934.
Forward-looking statements are all statements other than statements
of historical fact, including without limitation, those statements
that are identified by the words "anticipates," "estimates,"
"expects," "intends," "plans," "predicts" and similar expressions.
In addition to the risk factors and cautionary statements included
in this Form 10-Q at Item 2 -- Management's Discussion and Analysis
of Financial Condition and Results of Operations - Risk Factors and
Cautionary Statements that May Affect Future Results, the following
are some other factors that should be considered for a better
understanding of the financial condition of MDU Resources Group,
Inc. (Company). These other factors may impact the Company's
financial results in future periods.
- Acquisition, disposal and impairment of assets or facilities
- Changes in operation, performance and construction of plant
facilities or other assets
- Changes in present or prospective generation
- Changes in anticipated tourism levels
- The availability of economic expansion or development
opportunities
- Population growth rates and demographic patterns
- Market demand for, and/or available supplies of, energy
products and services
- Changes in tax rates or policies
- Unanticipated project delays or changes in project costs
- Unanticipated changes in operating expenses or capital
expenditures
- Labor negotiations or disputes
- Inflation rates
- Inability of the various contract counterparties to meet their
contractual obligations
- Changes in accounting principles and/or the application of such
principles to the Company
- Changes in technology
- Changes in legal proceedings
- The ability to effectively integrate the operations of acquired
companies
- Fluctuations in natural gas and crude oil prices
- Decline in general economic environment
- Changes in governmental regulation
- Changes in currency exchange rates
- Unanticipated increases in competition
- Variations in weather
The Company is a diversified natural resource company which was
incorporated under the laws of the state of Delaware in 1924. Its
principal executive offices are at the Schuchart Building, 918 East
Divide Avenue, P.O. Box 5650, Bismarck, North Dakota 58506-5650,
telephone (701) 222-7900.
Montana-Dakota Utilities Co. (Montana-Dakota), a public utility
division of the Company, through the electric and natural gas
distribution segments, generates, transmits and distributes
electricity and distributes natural gas in the northern Great
Plains. Great Plains Natural Gas Co. (Great Plains), another public
utility division of the Company, distributes natural gas in
southeastern North Dakota and western Minnesota. These operations
also supply related value-added products and services in the
northern Great Plains.
The Company, through its wholly owned subsidiary, Centennial Energy
Holdings, Inc. (Centennial), owns WBI Holdings, Inc. (WBI Holdings),
Knife River Corporation (Knife River), Utility Services, Inc.
(Utility Services), Centennial Energy Resources LLC (Centennial
Resources) and Centennial Holdings Capital LLC (Centennial Capital).
WBI Holdings is comprised of the pipeline and energy
services and the natural gas and oil production segments.
The pipeline and energy services segment provides natural
gas transportation, underground storage and gathering
services through regulated and nonregulated pipeline
systems primarily in the Rocky Mountain and northern Great
Plains regions of the United States. The pipeline and
energy services segment also provides energy-related
management services, including cable and pipeline
magnetization and locating. The natural gas and oil
production segment is engaged in natural gas and oil
acquisition, exploration, development and production
activities, primarily in the Rocky Mountain region of the
United States and in and around the Gulf of Mexico.
Knife River mines aggregates and markets crushed stone,
sand, gravel and related construction materials, including
ready-mixed concrete, cement, asphalt and other value-added
products, as well as performs integrated construction
services, in the central and western United States and in
the states of Alaska and Hawaii.
Utility Services specializes in electrical line
construction, pipeline construction, inside electrical
wiring and cabling and the manufacture and distribution of
specialty equipment.
Centennial Resources owns electric generating facilities in
the United States and has investments in electric generating
facilities in Brazil and The Republic of Trinidad and Tobago
(Trinidad and Tobago). Electric capacity and energy
produced at the power plants are sold primarily under long-
term contracts to nonaffiliated entities. Centennial
Resources also provides analysis, design, construction,
refurbishment, and operation and maintenance services to
independent power producers. These operations also include
investments not directly being pursued by the Company's
other businesses. These activities are reflected in this
Form 10-Q under independent power production and other.
Centennial Capital insures various types of risks as a
captive insurer for certain of the Company's subsidiaries.
The function of the captive insurer is to fund the
deductible layers of the insured companies' general
liability and automobile liability coverages. Centennial
Capital also owns certain real and personal property and
contract rights. These activities are reflected in this
Form 10-Q under independent power production and other.
On August 14, 2003, the Company's Board of Directors approved a
three-for-two common stock split. For more information on the
common stock split, see Note 3 of Notes to Consolidated Financial
Statements.
INDEX
Part I -- Financial Information
Consolidated Statements of Income --
Three and Six Months Ended June 30, 2004 and 2003
Consolidated Balance Sheets --
June 30, 2004 and 2003, and December 31, 2003
Consolidated Statements of Cash Flows --
Six Months Ended June 30, 2004 and 2003
Notes to Consolidated Financial Statements
Management's Discussion and Analysis of Financial
Condition and Results of Operations
Quantitative and Qualitative Disclosures About Market Risk
Controls and Procedures
Part II -- Other Information
Legal Proceedings
Changes in Securities and Use of Proceeds
Exhibits and Reports on Form 8-K
Signatures
Exhibit Index
Exhibits
PART I -- FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
MDU RESOURCES GROUP, INC.
CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
Three Months Six Months
Ended Ended
June 30, June 30,
2004 2003 2004 2003
(In thousands, except per share amounts)
Operating revenues:
Electric, natural gas distribution
and pipeline and energy services $159,368 $128,175 $ 391,215 $ 324,045
Utility services, natural gas and oil
production, construction materials
and mining and other 493,933 420,044 777,545 691,928
653,301 548,219 1,168,760 1,015,973
Operating expenses:
Fuel and purchased power 16,370 13,262 33,095 28,669
Purchased natural gas sold 39,534 27,625 134,278 103,731
Operation and maintenance:
Electric, natural gas distribution
and pipeline and energy services 38,329 34,313 80,530 71,478
Utility services, natural gas and oil
production, construction materials
and mining and other 397,084 332,003 643,454 554,383
Depreciation, depletion and
amortization 51,787 46,911 101,298 90,976
Taxes, other than income 25,466 19,420 47,351 39,103
568,570 473,534 1,040,006 888,340
Operating income 84,731 74,685 128,754 127,633
Other income -- net 9,570 4,949 14,364 8,632
Interest expense 15,653 12,820 29,499 25,679
Income before income taxes 78,648 66,814 113,619 110,586
Income taxes 20,018 23,341 31,410 39,416
Income before cumulative effect of
accounting change 58,630 43,473 82,209 71,170
Cumulative effect of accounting
change (Note 14) --- --- --- (7,589)
Net income 58,630 43,473 82,209 63,581
Dividends on preferred stocks 172 188 342 375
Earnings on common stock $ 58,458 $ 43,285 $ 81,867 $ 63,206
Earnings per common share -- basic:
Earnings before cumulative effect
of accounting change $ .50 $ .39 $ .71 $ .64
Cumulative effect of accounting
change --- --- --- (.07)
Earnings per common share -- basic $ .50 $ .39 $ .71 $ .57
Earnings per common share -- diluted:
Earnings before cumulative effect of
accounting change $ .50 $ .39 $ .70 $ .64
Cumulative effect of accounting change --- --- --- (.07)
Earnings per common share -- diluted $ .50 $ .39 $ .70 $ .57
Dividends per common share $ .17 $ .16 $ .34 $ .32
Weighted average common shares
outstanding -- basic 116,559 110,602 115,609 110,461
Weighted average common shares
outstanding -- diluted 117,567 111,532 116,632 111,283
Pro forma amounts assuming retroactive
application of accounting change:
Net income $ 58,630 $ 43,473 $ 82,209 $ 71,170
Earnings per common share -- basic $ .50 $ .39 $ .71 $ .64
Earnings per common share -- diluted $ .50 $ .39 $ .70 $ .64
The accompanying notes are an integral part of these consolidated financial
statements.
MDU RESOURCES GROUP, INC.
CONSOLIDATED BALANCE SHEETS
(Unaudited)
June 30, June 30, December 31,
2004 2003 2003
(In thousands, except shares
and per share amounts)
ASSETS
Current assets:
Cash and cash equivalents $ 132,476 $ 66,342 $ 86,341
Receivables, net 421,653 348,209 357,677
Inventories 121,920 97,490 114,051
Deferred income taxes 5,457 7,585 3,104
Prepayments and other current assets 62,304 54,929 52,367
743,810 574,555 613,540
Investments 78,067 42,112 44,975
Property, plant and equipment 3,744,146 3,375,456 3,584,038
Less accumulated depreciation,
depletion and amortization 1,267,014 1,111,628 1,187,105
2,477,132 2,263,828 2,396,933
Deferred charges and other assets:
Goodwill 200,553 196,394 199,427
Other intangible assets, net 21,105 20,577 18,814
Other 91,941 103,352 106,903
313,599 320,323 325,144
$3,612,608 $3,200,818 $3,380,592
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Short-term borrowings $ --- $ 5,500 $ ---
Long-term debt and preferred
stock due within one year 93,249 17,938 27,646
Accounts payable 183,097 163,033 150,316
Taxes payable 23,031 12,999 15,358
Dividends payable 20,139 18,005 19,442
Other accrued liabilities 132,866 104,667 101,299
452,382 322,142 314,061
Long-term debt 887,721 938,609 939,450
Deferred credits and other liabilities:
Deferred income taxes 467,376 379,608 444,779
Other liabilities 232,464 231,624 231,666
699,840 611,232 676,445
Preferred stock subject to mandatory
redemption --- 1,200 ---
Commitments and contingencies
Stockholders' equity:
Preferred stocks 15,000 15,000 15,000
Common stockholders' equity:
Common stock (Note 3)
Shares issued -- $1.00 par value
117,829,664 at June 30, 2004,
74,479,251 at June 30, 2003 and
113,716,632 at December 31, 2003 117,830 74,479 113,717
Other paid-in capital 843,658 755,017 757,787
Retained earnings 617,222 502,403 575,287
Accumulated other comprehensive loss (17,419) (15,638) (7,529)
Treasury stock at cost - 359,281
shares at June 30, 2004 and
December 31, 2003, and 239,521
shares at June 30, 2003 (3,626) (3,626) (3,626)
Total common stockholders' equity 1,557,665 1,312,635 1,435,636
Total stockholders' equity 1,572,665 1,327,635 1,450,636
$3,612,608 $3,200,818 $3,380,592
The accompanying notes are an integral part of these consolidated financial
statements.
MDU RESOURCES GROUP, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Six Months Ended
June 30,
2004 2003
(In thousands)
Operating activities:
Net income $ 82,209 $ 63,581
Cumulative effect of accounting change --- 7,589
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation, depletion and amortization 101,298 90,976
Earnings, net of distributions, from equity
method investments (10,455) (943)
Deferred income taxes 10,141 11,547
Changes in current assets and liabilities, net
of acquisitions:
Receivables (45,143) (20,769)
Inventories (2,863) (1,399)
Other current assets (11,508) (17,284)
Accounts payable 24,026 24,399
Other current liabilities 23,814 3,024
Other noncurrent changes 809 3,247
Net cash provided by operating activities 172,328 163,968
Investing activities:
Capital expenditures (141,868) (130,780)
Acquisitions, net of cash acquired (22,006) (115,246)
Net proceeds from sale or disposition of property 10,001 6,984
Investments (22,684) 2,420
Proceeds from notes receivable 22,000 7,812
Net cash used in investing activities (154,557) (228,810)
Financing activities:
Net change in short-term borrowings --- (14,500)
Issuance of long-term debt 55,115 214,084
Repayment of long-term debt (42,202) (100,168)
Proceeds from issuance of common stock, net 54,917 188
Dividends paid (39,466) (35,976)
Net cash provided by financing activities 28,364 63,628
Increase (decrease) in cash and cash equivalents 46,135 (1,214)
Cash and cash equivalents -- beginning of year 86,341 67,556
Cash and cash equivalents -- end of period $132,476 $66,342
The accompanying notes are an integral part of these consolidated financial
statements.
MDU RESOURCES GROUP, INC.
NOTES TO CONSOLIDATED
FINANCIAL STATEMENTS
June 30, 2004 and 2003
(Unaudited)
1. Basis of presentation
The accompanying consolidated interim financial statements were
prepared in conformity with the basis of presentation reflected
in the consolidated financial statements included in the Annual
Report to Stockholders for the year ended December 31, 2003
(2003 Annual Report), and the standards of accounting
measurement set forth in Accounting Principles Board (APB)
Opinion No. 28 and any amendments thereto adopted by the
Financial Accounting Standards Board (FASB). Interim financial
statements do not include all disclosures provided in annual
financial statements and, accordingly, these financial
statements should be read in conjunction with those appearing
in the Company's 2003 Annual Report. The information is
unaudited but includes all adjustments that are, in the opinion
of management, necessary for a fair presentation of the
accompanying consolidated interim financial statements.
2. Seasonality of operations
Some of the Company's operations are highly seasonal and
revenues from, and certain expenses for, such operations may
fluctuate significantly among quarterly periods. Accordingly,
the interim results for particular businesses, and for the
Company as a whole, may not be indicative of results for the
full fiscal year.
3. Common stock split
On August 14, 2003, the Company's Board of Directors approved a
three-for-two common stock split to be effected in the form of
a 50 percent common stock dividend. The additional shares of
common stock were distributed on October 29, 2003, to common
stockholders of record on October 10, 2003. Common stock
information appearing in the accompanying consolidated
financial statements has been restated to give retroactive
effect to the stock split. Additionally, preference share
purchase rights have been appropriately adjusted to reflect the
effects of the split.
4. Allowance for doubtful accounts
The Company's allowance for doubtful accounts as of June 30,
2004 and 2003, and December 31, 2003, was $8.0 million,
$8.3 million and $8.1 million, respectively.
5. Earnings per common share
Basic earnings per common share were computed by dividing
earnings on common stock by the weighted average number of
shares of common stock outstanding during the applicable
period. Diluted earnings per common share were computed by
dividing earnings on common stock by the total of the weighted
average number of shares of common stock outstanding during the
applicable period, plus the effect of outstanding stock
options, restricted stock grants and performance share awards.
For the three and six months ended June 30, 2004, 205,305
shares, with an average exercise price of $24.54, attributable
to the exercise of outstanding stock options, were excluded
from the calculation of diluted earnings per share because
their effect was antidilutive. For the three and six months
ended June 30, 2003, 209,805 shares and 3,500,220 shares,
respectively, with an average exercise price of $24.56 and
$20.10, respectively, attributable to the exercise of
outstanding stock options, were excluded from the calculation
of diluted earnings per share because their effect was
antidilutive. For the three and six months ended June 30, 2004
and 2003, no adjustments were made to reported earnings in the
computation of earnings per share. Common stock outstanding
includes issued shares less shares held in treasury.
6. Stock-based compensation
The Company has stock option plans for directors, key employees
and employees. In the third quarter of 2003, the Company
adopted the fair value recognition provisions of Statement of
Financial Accounting Standards (SFAS) No. 123, "Accounting for
Stock-Based Compensation," and began expensing the fair market
value of stock options for all awards granted on or after
January 1, 2003. Compensation expense recognized for awards
granted on or after January 1, 2003, for the three and six
months ended June 30, 2004, was $2,000 and $5,000, 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 the
grant.
Since the Company adopted SFAS No. 123 effective January 1,
2003, for newly granted options only, the following table
illustrates the effect on earnings and earnings per common
share for the three and six months ended June 30, 2004 and
2003, as if the Company had applied SFAS No. 123 and recognized
compensation expense for all outstanding and unvested stock
options based on the fair value at the date of grant:
Three Months Ended
June 30,
2004 2003
(In thousands, except
per share amounts)
Earnings on common stock, as
reported $ 58,458 $ 43,285
Stock-based compensation expense
included in reported earnings,
net of related tax effects 2 ---
Total stock-based compensation
expense determined under fair
value method for all awards,
net of related tax effects (79) (717)
Pro forma earnings on common stock $ 58,381 $ 42,568
Earnings per common share -- basic --
as reported $ .50 $ .39
Earnings per common share -- basic --
pro forma $ .50 $ .38
Earnings per common share -- diluted --
as reported $ .50 $ .39
Earnings per common share -- diluted --
pro forma $ .50 $ .38
Six Months Ended
June 30,
2004 2003
(In thousands, except
per share amounts)
Earnings on common stock, as
reported $ 81,867 $ 63,206
Stock-based compensation expense
included in reported earnings,
net of related tax effects 5 ---
Total stock-based compensation
expense determined under fair
value method for all awards,
net of related tax effects (172) (1,307)
Pro forma earnings on common stock $ 81,700 $ 61,899
Earnings per common share -- basic --
as reported:
Earnings before cumulative effect
of accounting change $ .71 $ .64
Cumulative effect of accounting
change --- (.07)
Earnings per common share -- basic $ .71 $ .57
Earnings per common share -- basic --
pro forma:
Earnings before cumulative effect
of accounting change $ .71 $ .63
Cumulative effect of accounting
change --- (.07)
Earnings per common share -- basic $ .71 $ .56
Earnings per common share -- diluted
-- as reported:
Earnings before cumulative effect
of accounting change $ .70 $ .64
Cumulative effect of accounting
change --- (.07)
Earnings per common share --
diluted $ .70 $ .57
Earnings per common share -- diluted
-- pro forma:
Earnings before cumulative effect
of accounting change $ .70 $ .63
Cumulative effect of accounting
change --- (.07)
Earnings per common share --
diluted $ .70 $ .56
7. Cash flow information
Cash expenditures for interest and income taxes were as
follows:
Six Months Ended
June 30,
2004 2003
(In thousands)
Interest, net of amount capitalized $26,269 $23,316
Income taxes paid, net $21,295 $31,263
8. Reclassifications
Certain reclassifications have been made in the financial
statements for the prior year to conform to the current
presentation. Such reclassifications had no effect on net
income or stockholders' equity as previously reported.
9. New accounting standards
In December 2003, the FASB issued FASB Interpretation No. 46
(revised December 2003), "Consolidation of Variable Interest
Entities" (FIN 46 (revised)), which replaced FASB
Interpretation No. 46, "Consolidation of Variable Interest
Entities" (FIN 46). FIN 46 (revised) clarifies the application
of Accounting Research Bulletin No. 51, "Consolidated Financial
Statements," to certain entities in which equity investors do
not have the characteristics of a controlling financial
interest or do not have sufficient equity at risk for the
entity to finance its activities without additional
subordinated support. An enterprise shall consolidate a
variable interest entity if that enterprise is the primary
beneficiary. An enterprise is considered the primary
beneficiary if it has a variable interest that will absorb a
majority of the entity's expected losses, receive a majority of
the entity's expected residual returns or both. FIN 46
(revised) shall be applied to all entities subject to FIN 46
(revised) no later than the end of the first reporting period
that ends after March 15, 2004.
The Company evaluated the provisions of FIN 46 (revised) and
determined that the Company does not have any controlling
financial interests in any variable interest entities and,
therefore, is not required to consolidate any variable interest
entities in its financial statements. The adoption of FIN 46
(revised) did not have an effect on the Company's financial
position or results of operations.
In January 2004, the FASB issued FASB Staff Position No. FAS
106-1, "Accounting and Disclosure Requirements Related to the
Medicare Prescription Drug, Improvement and Modernization Act
of 2003" (FSP No. FAS 106-1). FSP No. FAS 106-1 permits a
sponsor of a postretirement health care plan that provides a
prescription drug benefit to make a one-time election to defer
accounting for the effects of the Medicare Prescription Drug,
Improvement and Modernization Act of 2003 (2003 Medicare Act).
In May 2004, the FASB issued FASB Staff Position No. FAS 106-2,
"Accounting and Disclosure Requirements Related to the Medicare
Prescription Drug, Improvement and Modernization Act of 2003
(FSP No. FAS 106-2). FSP No. FAS 106-2 requires (a) that the
effects of the federal subsidy be considered an actuarial gain
and recognized in the same manner as other actuarial gains and
losses and (b) certain disclosures for employers that sponsor
postretirement health care plans that provide prescription drug
benefits.
The Company provides prescription drug benefits to certain
eligible employees. The Company elected the one-time deferral
of accounting for the effects of the 2003 Medicare Act in the
quarter ending March 31, 2004, the first period in which the
plan's accounting for the effects of the 2003 Medicare Act
normally would have been reflected in the Company's financial
statements.
During the second quarter of 2004, the Company adopted FSP No.
FAS 106-2 retroactive to the beginning of the year. The
Company and its actuarial advisors determined that benefits
provided to certain participants are expected to be at least
actuarially equivalent to Medicare Part D (the federal
prescription drug benefit), and, accordingly, the Company
expects to be entitled to a federal subsidy. The expected
federal subsidy reduced the accumulated postretirement benefit
obligation (APBO) at January 1, 2004, by approximately $3.2
million, and net periodic benefit cost for 2004 by
approximately $285,000 (as compared with the amount calculated
without considering the effects of the subsidy). In addition,
the Company expects a reduction in future participation in the
postretirement plans, which further reduced the APBO at January
1, 2004, by approximately $12.7 million and net periodic
benefit cost for 2004 by approximately $1.3 million.
See Note 17 for the components of net periodic benefit cost.
The net periodic benefit cost for the three and six months
ended June 30, 2004, was reduced by approximately $767,000 to
reflect the effects of the 2003 Medicare Act.
SFAS No. 142, "Goodwill and Other Intangible Assets,"
discontinues the practice of amortizing goodwill and indefinite
lived intangible assets and initiates an annual review for
impairment. Intangible assets with a determinable useful life
will continue to be amortized over that period. The
amortization provisions apply to goodwill and intangible assets
acquired after June 30, 2001. SFAS No. 141, "Business
Combinations," and SFAS No. 142 clarify that more assets should
be distinguished and classified between tangible and
intangible. The Company did not change or reclassify
contractual mineral rights included in property, plant and
equipment related to its natural gas and oil production
business upon adoption of SFAS No. 142. The Company has
included such mineral rights as part of property, plant and
equipment under the full-cost method of accounting for natural
gas and oil properties. An issue has arisen within the natural
gas and oil industry as to whether contractual mineral rights
under SFAS No. 142 should be classified as intangible rather
than as part of property, plant and equipment. Recently, the
FASB Staff issued proposed FASB Staff Position No. FAS 142-b,
"Application of FASB Statement No. 142, Goodwill and Other
Intangible Assets, to Oil- and Gas-Producing Entities," which
indicates that the exception in SFAS No. 142 does not change
the accounting prescribed in SFAS No. 19, "Financial Accounting
and Reporting by Oil and Gas Producing Companies," including
the balance sheet classification of drilling and mineral rights
of oil and gas producing entities and, as a result, the
contractual mineral rights should continue to be classified as
part of property, plant and equipment. The anticipated
resolution of this matter is not expected to have an effect on
the Company's financial position, results of operations or cash
flows.
In April 2004, the FASB issued FASB Staff Position Nos. FAS 141-
1 and FAS 142-1, "Interaction of FASB Statements No. 141,
'Business Combinations,' and No. 142, 'Goodwill and Other
Intangible Assets,' and EITF Issue No. 04-2, 'Whether Mineral
Rights are Tangible or Intangible Assets,'" (FSP Nos. FAS 141-1
and FAS 142-1). FSP Nos. FAS 141-1 and FAS 142-1 amend SFAS
No. 141 and SFAS No. 142 to clarify that certain mineral rights
held by mining entities that are not within the scope of SFAS
No. 19 be classified as tangible assets rather than intangible
assets. FSP Nos. FAS 141-1 and FAS 142-1 shall be applied to
the first reporting period beginning after April 29, 2004. FSP
Nos. FAS 141-1 and FAS 142-1 required reclassification of the
Company's leasehold rights at its construction materials and
mining operations from other intangible assets, net to
property, plant and equipment, as well as changes to Notes to
Consolidated Financial Statements. FSP Nos. FAS 141-1 and FAS
142-1 affected the asset classification in the consolidated
balance sheet and associated footnote disclosure only, so the
reclassifications did not affect the Company's stockholders'
equity, cash flows or results of operations.
10. Comprehensive income
Comprehensive income is the sum of net income as reported and
other comprehensive loss. The Company's other comprehensive
loss resulted from losses on derivative instruments qualifying
as hedges, minimum pension liability adjustments and foreign
currency translation adjustments.
Comprehensive income, and the components of other comprehensive
loss and related tax effects, was as follows:
Three Months Ended
June 30,
2004 2003
(In thousands)
Net income $ 58,630 $ 43,473
Other comprehensive loss:
Net unrealized loss on derivative
instruments qualifying as hedges:
Net unrealized loss on derivative
instruments arising during the
period, net of tax of $3,711 and
$2,241 in 2004 and 2003,
respectively (5,804) (3,587)
Less: Reclassification adjustment
for loss on derivative instruments
included in net income, net of tax
of $1,473 and $1,871 in 2004 and
2003, respectively (2,304) (2,926)
Net unrealized loss on derivative
instruments qualifying as hedges (3,500) (661)
Foreign currency translation
adjustment (377) (475)
(3,877) (1,136)
Comprehensive income $ 54,753 $42,337
Six Months Ended
June 30,
2004 2003
(In thousands)
Net income $ 82,209 $ 63,581
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 $6,424 and
$4,635 in 2004 and 2003,
respectively (10,047) (7,331)
Less: Reclassification adjustment
for loss on derivative instruments
included in net income, net of tax
of $1,020 and $1,440 in 2004 and
2003, respectively (1,595) (2,252)
Net unrealized loss on derivative
instruments qualifying as hedges (8,452) (5,079)
Foreign currency translation
adjustment (1,438) (755)
(9,890) (5,834)
Comprehensive income $ 72,319 $ 57,747
11. Equity method investments
The Company has a number of equity method investments,
including MPX Participacoes, Ltda. (MPX) and Carib Power
Management LLC (Carib Power). The Company assesses its equity
method investments for impairment whenever events or changes in
circumstances indicate that such carrying values may not be
recoverable. None of the Company's equity method investments
have been impaired and, accordingly, no impairment losses have
been recorded in the accompanying consolidated financial
statements or related equity method investment balances.
MPX was formed in August 2001 when MDU Brasil Ltda. (MDU
Brasil), an indirect wholly owned Brazilian subsidiary of the
Company, entered into a joint venture agreement with a
Brazilian firm. MDU Brasil has a 49 percent interest in MPX.
MPX, through a wholly owned subsidiary, owns and operates a 220-
megawatt natural gas-fired electric generating facility (Brazil
Generating Facility) in the Brazilian state of Ceara.
Petrobras, the Brazilian state-controlled energy company, has
agreed to purchase all of the capacity and market all of the
Brazil Generating Facility's energy. The power purchase
agreement with Petrobras expires in May 2008. Petrobras also
is under contract to supply natural gas to the Brazil
Generating Facility during the term of the power purchase
agreement. This natural gas supply contract is renewable by a
wholly owned subsidiary of MPX for an additional 13 years. The
Brazil Generating Facility generates energy based upon economic
dispatch and available gas supplies. Under current conditions,
including, in particular, existing constraints in the region's
gas supply infrastructure, the Company does not expect the
facility to generate a significant amount of energy at least
through 2006.
The functional currency for the Brazil Generating Facility is
the Brazilian real. The power purchase agreement with
Petrobras contains an embedded derivative, which derives its
value from an annual adjustment factor, which largely indexes
the contract capacity payments to the U.S. dollar. The
Company's 49 percent share of the gain from the change in the
fair value of the embedded derivative in the power purchase
agreement was $4.1 million (after tax) for the three and six
months ended June 30, 2004. The Company's 49 percent share of
the loss from the change in the fair value of the embedded
derivative in the power purchase agreement was $4.5 million
(after tax) and $6.0 million (after tax) for the three and six
months ended June 30, 2003, respectively. The Company's 49
percent share of the foreign currency loss resulting from a
decrease in value of the Brazilian real versus the U.S. dollar
was $1.8 million (after tax) and $2.0 million (after tax) for
the three and six months ended June 30, 2004, respectively.
The Company's 49 percent share of the foreign currency gains
resulting from the increase in value of the Brazilian real
versus the U.S. dollar was $2.2 million (after tax) and $3.1
million (after tax) for the three and six months ended June 30,
2003, respectively.
In February 2004, Centennial Energy Resources International,
Inc. (Centennial International), an indirect wholly owned
subsidiary of the Company, acquired 49.9 percent of Carib
Power. Carib Power, through a wholly owned subsidiary, owns a
225-megawatt natural gas-fired electric generating facility
located in Trinidad and Tobago (Trinidad and Tobago Generating
Facility). The functional currency for the Trinidad and Tobago
Generating Facility is the U.S. dollar.
At June 30, 2004, MPX and Carib Power had total assets of
$202.8 million and long-term debt of $158.0 million. The
Company's investment in the Brazil and Trinidad and Tobago
Generating Facilities was approximately $26.0 million,
including undistributed earnings of $14.8 million at June 30,
2004. The Company's investment in the Brazil Generating
Facility was approximately $20.6 million at June 30, 2003, and
$25.2 million, including undistributed earnings of $4.6 million
at December 31, 2003.
The Company's share of income from its equity method
investments was $7.7 million and $11.1 million for the three
and six months ended June 30, 2004, respectively, and was
included in other income - net. The Company's share of income
from its equity method investments, including MPX, was $1.3
million and $2.3 million for the three and six months ended
June 30, 2003, respectively, and was included in other income -
net.
12. Goodwill and other intangible assets
The changes in the carrying amount of goodwill were as follows:
Balance Goodwill Balance
as of Acquired as of
Six Months January 1, During June 30,
Ended June 30, 2004 2004 the Year* 2004
(In thousands)
Electric $ --- $ --- $ ---
Natural gas
distribution --- --- ---
Utility services 62,604 28 62,632
Pipeline and energy
services 9,494 --- 9,494
Natural gas and oil
production --- --- ---
Construction materials
and mining 120,198 (2,668) 117,530
Independent power
production and other 7,131 3,766 10,897
Total $ 199,427 $ 1,126 $ 200,553
__________________
* Includes purchase price adjustments related to acquisitions
acquired in a prior period.
Balance Goodwill Balance
as of Acquired as of
Six Months January 1, During June 30,
Ended June 30, 2003 2003 the Year* 2003
(In thousands)
Electric $ --- $ --- $ ---
Natural gas
distribution --- --- ---
Utility services 62,487 127 62,614
Pipeline and energy
services 9,494 --- 9,494
Natural gas and oil
production --- --- ---
Construction materials
and mining 111,887 5,268 117,155
Independent power
production and other 7,131 --- 7,131
Total $ 190,999 $ 5,395 $ 196,394
__________________
* Includes purchase price adjustments related to acquisitions
acquired in a prior period.
Balance Goodwill Balance
as of Acquired as of
Year Ended January 1, During December 31,
December 31, 2003 2003 the Year* 2003
(In thousands)
Electric $ --- $ --- $ ---
Natural gas
distribution --- --- ---
Utility services 62,487 117 62,604
Pipeline and energy
services 9,494 --- 9,494
Natural gas and oil
production --- --- ---
Construction materials
and mining 111,887 8,311 120,198
Independent power
production and other 7,131 --- 7,131
Total $ 190,999 $ 8,428 $ 199,427
__________________
* Includes purchase price adjustments related to acquisitions
acquired in a prior period.
As discussed in Note 9, 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:
June 30, June 30, December 31,
2004 2003 2003
(In thousands)
Amortizable intangible assets:
Noncompete agreements $ 10,275 $ 12,075 $ 12,075
Accumulated amortization (8,024) (9,552) (9,690)
2,251 2,523 2,385
Other 21,292 17,719 17,734
Accumulated amortization (3,398) (1,268) (2,265)
17,894 16,451 15,469
Unamortizable intangible
assets 960 1,603 960
Total $ 21,105 $ 20,577 $ 18,814
The unamortizable intangible assets were recognized in
accordance with SFAS No. 87, "Employers' Accounting for
Pensions," which requires that if an additional minimum
liability is recognized an equal amount shall be recognized as
an intangible asset, provided that the asset recognized shall
not exceed the amount of unrecognized prior service cost. The
unamortizable intangible asset will be eliminated or adjusted
as necessary upon a new determination of the amount of
additional liability.
Amortization expense for amortizable intangible assets for the
three and six months ended June 30, 2004, was $702,000 and $1.3
million, respectively. Amortization expense for amortizable
intangible assets for the three and six months ended June 30,
2003, and for the year ended December 31, 2003, was $630,000,
$1.1 million and $2.2 million, respectively. Estimated
amortization expense for amortizable intangible assets is $3.0
million in 2004, $2.4 million in 2005, $1.8 million in 2006,
$1.7 million in 2007, $1.7 million in 2008 and $10.8 million
thereafter.
13. Derivative instruments
From time to time, the Company utilizes derivative instruments
as part of an overall energy price, foreign currency and
interest rate risk management program to efficiently manage and
minimize commodity price, foreign currency and interest rate
risk. The following information should be read in conjunction
with Notes 1 and 5 in the Company's Notes to Consolidated
Financial Statements in the 2003 Annual Report.
As of June 30, 2004, Fidelity Exploration & Production Company
(Fidelity), an indirect wholly owned subsidiary of the Company,
held derivative instruments designated as cash flow hedging
instruments.
Hedging activities
Fidelity utilizes natural gas and oil price swap and collar
agreements to manage a portion of the market risk associated
with fluctuations in the price of natural gas and oil on its
forecasted sales of natural gas and oil production. Each of
the natural gas and oil price swap and collar agreements was
designated as a hedge of the forecasted sale of natural gas and
oil production.
For the three and six months ended June 30, 2004 and 2003, the
amount of hedge ineffectiveness recognized, which was included
in operating revenues, was immaterial. For the three and six
months ended June 30, 2004 and 2003, Fidelity did not exclude
any components of the derivative instruments' gain or loss from
the assessment of hedge effectiveness and there were no
reclassifications into earnings as a result of the
discontinuance of hedges.
Gains and losses on derivative instruments that are
reclassified from accumulated other comprehensive income (loss)
to current-period earnings are included in the line item in
which the hedged item is recorded. As of June 30, 2004, the
maximum term of Fidelity's swap and collar agreements, in which
it is hedging its exposure to the variability in future cash
flows for forecasted transactions, is 18 months. Fidelity
estimates that over the next 12 months net losses of
approximately $9.2 million will be reclassified from
accumulated other comprehensive loss into earnings, subject to
changes in natural gas and oil market prices, as the hedged
transactions affect earnings.
14. Asset retirement obligations
The Company adopted SFAS No. 143, "Accounting for Asset
Retirement Obligations," on January 1, 2003. The Company
recorded obligations related to the plugging and abandonment of
natural gas and oil wells, decommissioning of certain electric
generating facilities, reclamation of certain aggregate
properties and certain other obligations associated with leased
properties. Removal costs associated with certain natural gas
distribution, transmission, storage and gathering facilities
have not been recognized as these facilities have been
determined to have indeterminate useful lives.
Upon adoption of SFAS No. 143, the Company recorded an
additional discounted liability of $22.5 million and a
regulatory asset of $493,000, increased net property, plant and
equipment by $9.6 million and recognized a one-time cumulative
effect charge of $7.6 million (net of deferred income tax
benefits of $4.8 million). The Company believes that any
expenses under SFAS No. 143 as they relate to regulated
operations will be recovered in rates over time and
accordingly, deferred such expenses as a regulatory asset upon
adoption. The Company will continue to defer those SFAS
No. 143 expenses that it believes will be recovered in rates
over time. In addition to the $22.5 million liability recorded
upon the adoption of SFAS No. 143, the Company had previously
recorded a $7.5 million liability related to retirement
obligations.
15. Business segment data
The Company's reportable segments are those that are based on
the Company's method of internal reporting, which generally
segregates the strategic business units due to differences in
products, services and regulation. The Company has six
reportable segments consisting of electric, natural gas
distribution, utility services, pipeline and energy services,
natural gas and oil production, and construction materials and
mining. The independent power production and other operations
do not individually meet the criteria to be considered a
reportable segment.
The vast majority of the Company's operations are located
within the United States. The Company also has investments in
foreign countries, which largely consist of investments in
natural gas-fired electric generating facilities in Brazil and
Trinidad and Tobago, as discussed in Note 11. The electric
segment generates, transmits and distributes electricity, and
the natural gas distribution segment distributes natural gas.
These operations also supply related value-added products and
services in the northern Great Plains. The utility services
segment specializes in electrical line construction, pipeline
construction, inside electrical wiring and cabling and the
manufacture and distribution of specialty equipment. The
pipeline and energy services segment provides natural gas
transportation, underground storage and gathering services
through regulated and nonregulated pipeline systems primarily
in the Rocky Mountain and northern Great Plains regions of the
United States. The pipeline and energy services segment also
provides energy-related management services, including cable
and pipeline magnetization and locating. The natural gas and
oil production segment is engaged in natural gas and oil
acquisition, exploration, development and production
activities, primarily in the Rocky Mountain region of the
United States and in and around the Gulf of Mexico. The
construction materials and mining segment mines aggregates and
markets crushed stone, sand, gravel and related construction
materials, including ready-mixed concrete, cement, asphalt and
other value-added products, as well as performs integrated
construction services, in the central and western United States
and in the states of Alaska and Hawaii. The independent power
production and other operations own electric generating
facilities in the United States and have investments in
electric generating facilities in Brazil and Trinidad and
Tobago. Electric capacity and energy produced at the power
plants are sold primarily under long-term contracts to
nonaffiliated entities. Centennial Resources also provides
analysis, design, construction, refurbishment, and operation
and maintenance services to independent power producers. These
operations also include investments not directly being pursued
by the Company's other businesses. The information below
follows the same accounting policies as described in Note 1 of
the Company's 2003 Annual Report. Information on the Company's
businesses was as follows:
Inter-
External segment Earnings
Operating Operating on Common
Revenues Revenues Stock
(In thousands)
Three Months
Ended June 30, 2004
Electric $ 39,834 $ --- $ 735
Natural gas distribution 47,461 --- (1,097)
Pipeline and energy
services 72,073 13,423 4,434
159,368 13,423 4,072
Utility services 97,226 --- (2,294)
Natural gas and oil
production 39,038 45,181 26,136
Construction materials
and mining 347,026 200 20,345
Independent power
production and other 10,643 919 10,199
493,933 46,300 54,386
Intersegment eliminations --- (59,723) ---
Total $653,301 $ --- $ 58,458
Inter-
External segment Earnings
Operating Operating on Common
Revenues Revenues Stock
(In thousands)
Three Months
Ended June 30, 2003
Electric $ 38,049 $ --- $ 1,766
Natural gas distribution 42,409 --- (1,291)
Pipeline and energy
services 47,717 8,508 5,083
128,175 8,508 5,558
Utility services 108,928 --- 1,515
Natural gas and oil
production 36,746 27,912 17,866
Construction materials
and mining 264,129 --- 12,803
Independent power
production and other 10,241 740 5,543
420,044 28,652 37,727
Intersegment eliminations --- (37,160) ---
Total $548,219 $ --- $ 43,285
Inter-
External segment Earnings
Operating Operating on Common
Revenues Revenues Stock
(In thousands)
Six Months
Ended June 30, 2004
Electric $ 86,824 $ --- $ 4,143
Natural gas distribution 175,779 --- 1,228
Pipeline and energy
services 128,612 41,036 7,117
391,215 41,036 12,488
Utility services 197,477 --- (4,195)
Natural gas and oil
production 76,544 88,644 51,395
Construction materials
and mining 486,473 200 8,464
Independent power
production and other 17,051 1,837 13,715
777,545 90,681 69,379
Intersegment eliminations --- (131,717) ---
Total $1,168,760 $ --- $ 81,867
Inter-
External segment Earnings
Operating Operating on Common
Revenues Revenues Stock
(In thousands)
Six Months
Ended June 30, 2003
Electric $ 83,720 $ --- $ 6,583
Natural gas distribution 153,397 --- 2,954
Pipeline and energy
services 86,928 30,427 9,394
324,045 30,427 18,931
Utility services 212,591 --- 2,625
Natural gas and oil
production 77,865 55,816 29,532
Construction materials
and mining 384,882 --- 5,363
Independent power
production and other 16,590 1,481 6,755
691,928 57,297 44,275
Intersegment eliminations --- (87,724) ---
Total $1,015,973 $ --- $ 63,206
Earnings from electric, natural gas distribution and pipeline
and energy services are substantially all from regulated
operations. Earnings from utility services, natural gas and
oil production, construction materials and mining, and
independent power production and other are all from
nonregulated operations.
16. Acquisitions
During the first six months of 2004, the Company acquired a
number of businesses, none of which was individually material,
including construction materials and mining businesses in Idaho,
Iowa and Minnesota and an independent power production operating
and development company in Colorado. The total purchase
consideration for these businesses and purchase price
adjustments with respect to certain other acquisitions acquired
prior to 2004, including the Company's common stock and cash,
was $54.6 million.
The above acquisitions were accounted for under the purchase
method of accounting and, accordingly, the acquired assets and
liabilities assumed have been preliminarily recorded at their
respective fair values as of the date of acquisition. Final
fair market values are pending the completion of the review of
the relevant assets, liabilities and issues identified as of the
acquisition date. The results of operations of the acquired
businesses are included in the financial statements since the
date of each acquisition. Pro forma financial amounts
reflecting the effects of the above acquisitions are not
presented, as such acquisitions were not material to the
Company's financial position or results of operations.
17. Employee benefit plans
The Company has noncontributory defined benefit pension plans
and other postretirement benefit plans for certain eligible
employees. As discussed in Note 9, the Company recognized the
effects of the 2003 Medicare Act during the second quarter of
2004. The net periodic benefit cost (income) for 2004 reflects
the effects of the 2003 Medicare Act. Components of net
periodic benefit cost (income) for the Company's pension and
other postretirement benefit plans were as follows:
Other
Pension Postretirement
Three Months Benefits Benefits
Ended June 30 2004 2003 2004 2003
(In thousands)
Components of net periodic
benefit cost (income):
Service cost $ 1,984 $ 1,432 $ 312 $ 442
Interest cost 4,011 3,794 850 1,247
Expected return on
assets (5,100) (5,225) (979) (981)
Amortization of prior
service cost 283 285 72 ---
Recognized net actuarial
(gain) loss (8) (68) (27) (130)
Amortization of net
transition obligation
(asset) (62) (237) 550 538
Net periodic benefit cost
(income) 1,108 (19) 778 1,116
Less amount capitalized 117 (37) 80 128
Net periodic benefit cost
(income) $ 991 $ 18 $ 698 $ 988
Other
Pension Postretirement
Six Months Benefits Benefits
Ended June 30 2004 2003 2004 2003
(In thousands)
Components of net periodic
benefit cost (income):
Service cost $ 3,833 $ 2,864 $ 896 $ 884
Interest cost 7,952 7,588 2,173 2,493
Expected return on
assets (10,187) (10,450) (1,972) (1,962)
Amortization of prior
service cost 561 570 72 ---
Recognized net actuarial
(gain) loss 239 (136) (82) (259)
Amortization of net
transition obligation
(asset) (125) (474) 1,076 1,076
Net periodic benefit cost
(income) 2,273 (38) 2,163 2,232
Less amount capitalized 191 (48) 182 208
Net periodic benefit cost
(income) $ 2,082 $ 10 $ 1,981 $ 2,024
As of June 30, 2004, approximately $900,000 has been
contributed to the defined benefit pension plans and
approximately $2.4 million has been contributed to the
postretirement benefit plans. The Company presently
anticipates contributing an additional $400,000 to its pension
plans in 2004 for a total of $1.3 million for the year. The
Company presently anticipates contributing an additional $1.3
million to its postretirement benefit plans for a total of $3.7
million for the year.
In addition to the qualified plan defined pension benefits
reflected in the tables above, the Company also has an
unfunded, nonqualified benefit plan for executive officers and
certain key management employees that provides for defined
benefit payments at age 65 following the employee's retirement
or to the beneficiaries upon death for a 15-year period. The
Company's net periodic benefit cost for this plan for the three
and six months ended June 30, 2004, was $2.3 million and $3.8
million, respectively. The Company's net periodic benefit cost
for this plan for the three and six months ended June 30, 2003,
was $1.2 million and $2.4 million, respectively.
18. Regulatory matters and revenues subject to refund
On June 7, 2004, Montana-Dakota filed an application with the
South Dakota Public Utilities Commission (SDPUC) for a natural
gas rate increase for the Black Hills service area. Montana-
Dakota requested a total of $1.3 million annually or 2.2
percent above current rates. A final order from the SDPUC is
due December 7, 2004.
On April 1, 2004, Montana-Dakota filed an application with the
Montana Public Service Commission (MTPSC) for a natural gas
rate increase. Montana-Dakota requested a total of $1.5
million annually or 1.8 percent above current rates. Montana-
Dakota requested an interim increase of $500,000 annually to be
effective within 30 days of the filing of the natural gas rate
increase. A final order from the MTPSC is due January 1, 2005.
On March 3, 2004, Montana-Dakota filed an application with the
North Dakota Public Service Commission (NDPSC) for a natural
gas rate increase. Montana-Dakota requested a total of $3.3
million annually or 2.8 percent above current rates. The
natural gas rate increase application included an interim
increase of $1.9 million annually to be effective within 60
days of the filing of the natural gas rate increase. On April
26, 2004, Montana-Dakota filed an amendment to its request for
interim rate increase requesting an interim increase of $1.7
million annually. On April 27, 2004, the NDPSC issued an Order
approving Montana-Dakota's interim rate increase of $1.7
million annually effective for service rendered on or after May
3, 2004. Montana-Dakota began collecting such rates effective
May 3, 2004, subject to refund until the NDPSC issues a final
order. A final order from the NDPSC is due October 3, 2004.
In December 1999, Williston Basin Interstate Pipeline Company
(Williston Basin), an indirect wholly owned subsidiary of the
Company, filed a general natural gas rate change application
with the Federal Energy Regulatory Commission (FERC).
Williston Basin began collecting such rates effective June 1,
2000, subject to refund. In May 2001, the Administrative Law
Judge (ALJ) issued an Initial Decision on Williston Basin's
natural gas rate change application. The Initial Decision
addressed numerous issues relating to the rate change
application, including matters relating to allowable levels of
rate base, return on common equity, and cost of service, as
well as volumes established for purposes of cost recovery, and
cost allocation and rate design. In July 2003, the FERC issued
its Order on Initial Decision. The Order on Initial Decision
affirmed the ALJ's Initial Decision on many of the issues
including rate base and certain cost of service items as well
as volumes to be used for purposes of cost recovery, and cost
allocation and rate design. However, there are other issues as
to which the FERC differed with the ALJ including return on
common equity and the correct level of corporate overhead
expense. In August 2003, Williston Basin requested rehearing
of a number of issues including determinations associated with
cost of service, throughput, and cost allocation and rate
design, as discussed in the FERC's Order on Initial Decision.
On May 11, 2004, the FERC issued an Order on Rehearing and
Compliance and Remanding Certain Issues for Hearing (Order on
Rehearing). The Order on Rehearing denied rehearing on all of
the issues addressed by Williston Basin in its August 2003
request for rehearing except for the issue of the proper rate
to utilize for transmission system negative salvage expenses.
In addition, the FERC remanded the issues regarding certain
service and annual demand quantity restrictions to an ALJ for
resolution. On June 14, 2004, Williston Basin requested
clarification of a few of the issues addressed in the May 11,
2004, Order on Rehearing including determinations associated
with cost of service and cost allocation, as discussed in the
FERC's Order on Rehearing. On June 14, 2004, Williston Basin
also made its filing to comply with the requirements of the
various FERC orders in this proceeding. Williston Basin is
awaiting a decision from the FERC on Williston Basin's
compliance filing and clarification request but is unable to
predict the timing of the FERC's decision.
Reserves have been provided for a portion of the revenues that
have been collected subject to refund with respect to Williston
Basin's pending regulatory proceeding. Williston Basin
believes that such reserves are adequate based on its
assessment of the ultimate outcome of the proceeding.
19. Contingencies
Litigation
In June 1997, Jack J. Grynberg (Grynberg) filed a Federal False
Claims Act Suit against Williston Basin and Montana-Dakota and
filed over 70 similar suits against natural gas transmission
companies and producers, gatherers, and processors of natural
gas. Grynberg, acting on behalf of the United States under the
Federal False Claims Act, alleged improper measurement of the
heating content and volume of natural gas purchased by the
defendants resulting in the underpayment of royalties to the
United States. In April 1999, the United States Department of
Justice decided not to intervene in these cases. In response
to a motion filed by Grynberg, the Judicial Panel on
Multidistrict Litigation consolidated all of these cases in the
Federal District Court of Wyoming.
On June 4, 2004, following preliminary discovery, Williston
Basin and Montana-Dakota joined with other defendants and filed
a Motion to Dismiss on the grounds that the information upon
which Grynberg bases his complaint was publicly disclosed prior
to the filing of his complaint and further, that he is not the
original source of such information. The Motion to Dismiss is
additionally based on the grounds that Grynberg disclosed the
filing of the complaint prior to the entry of a court order
allowing such disclosure.
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 the subject of, over a dozen lawsuits filed
in connection with its coalbed natural gas development in the
Powder River Basin in Montana and Wyoming. These lawsuits were
filed in federal and state courts in Montana between June 2000
and May 2004 by a number of environmental organizations,
including the Northern Plains Resource Council and the Montana
Environmental Information Center as well as the Tongue River
Water Users' Association and the Northern Cheyenne Tribe.
Portions of two of the lawsuits have been transferred to
Federal District Court in Wyoming. The lawsuits involve
allegations that Fidelity and/or various government agencies
are in violation of state and/or federal law, including the
Federal Clean Water Act and the National Environmental Policy
Act. The lawsuits seek injunctive relief, invalidation of
various permits and unspecified damages. Fidelity is unable to
quantify the damages sought in any of these cases, and will be
unable to do so until after completion of discovery in the
separate cases. Fidelity is vigorously defending all coalbed-
related lawsuits in which it is involved. If the plaintiffs
are successful in these lawsuits, the ultimate outcome of the
actions could have a material effect on Fidelity's existing
coalbed natural gas operations and/or the future development of
its coalbed natural gas properties.
Montana-Dakota has joined with two electric generators in
appealing a finding by the North Dakota Department of Health
(Department) in September 2003 that the Department may
unilaterally revise operating permits previously issued to
electric generating plants. Although it is doubtful that any
revision of Montana-Dakota's operating permits by the
Department would reduce the amount of electricity its plants
could generate, the finding, if allowed to stand, could
increase costs for sulfur dioxide removal and/or limit Montana-
Dakota's ability to modify or expand operations at its North
Dakota generation sites. Montana-Dakota and the other electric
generators filed their appeal of the order in October 2003, in
the Burleigh County District Court in Bismarck, North Dakota.
Proceedings have been stayed pending discussions with the
United States Environmental Protection Agency (EPA), the
Department and the other electric generators.
In a related case, the Dakota Resource Council filed an action
in Federal District Court in Denver, Colorado, in September
2003, to require the EPA to enforce certain air quality
standards in North Dakota. If successful, the action could
require the curtailment of discharges of sulfur dioxide into
the atmosphere by existing electric generating facilities and
could preclude or hinder the construction of future generating
facilities in North Dakota. The Company had filed a Motion to
Intervene in the lawsuit and had joined in a brief supporting a
Motion to Dismiss filed by the EPA. The EPA Motion to Dismiss
was granted on April 1, 2004.
The Company cannot predict the outcome of the Department or
Dakota Resource Council matters or their ultimate impact on its
operations.
The Company is also involved in other legal actions in the
ordinary course of its business. Although the outcomes of any
such legal actions cannot be predicted, management believes
that the outcomes with respect to these other legal proceedings
will not have a material adverse effect upon the Company's
financial position or results of operations.
Environmental matters
In December 2000, Morse Bros., Inc. (MBI), an indirect wholly
owned subsidiary of the Company, was named by the EPA as a
Potentially Responsible Party in connection with the cleanup of
a commercial property site, acquired by MBI in 1999, and part
of the Portland, Oregon, Harbor Superfund Site. Sixty-eight
other parties were also named in this administrative action.
The EPA wants responsible parties to share in the cleanup of
sediment contamination in the Willamette River. To date, costs
of the overall remedial investigation of the harbor site for
both the EPA and the Oregon State Department of Environmental
Quality (DEQ) are being recorded, and initially paid, through
an administrative consent order by the Lower Willamette Group
(LWG), a group of 10 entities which does not include MBI. The
LWG estimates the overall remedial investigation and
feasibility study will cost approximately $10 million. It is
not possible to estimate the cost of a corrective action plan
until the remedial investigation and feasibility study has been
completed, the EPA has decided on a strategy, and a record of
decision has been published. While the remedial investigation
and feasibility study for the harbor site has commenced, it is
expected to take several years to complete. The development of
a proposed plan and record of decision on the harbor site is
not anticipated to occur until 2006, after which a cleanup plan
will be undertaken.
Based upon a review of the Portland Harbor sediment
contamination evaluation by the DEQ and other information
available, MBI does not believe it is a Responsible Party. In
addition, MBI has notified Georgia-Pacific West, Inc., the
seller of the commercial property site to MBI, that it intends
to seek indemnity for any and all liabilities incurred in
relation to the above matters, pursuant to the terms of their
sale agreement.
The Company believes it is not probable that it will incur any
material environmental remediation costs or damages in relation
to the above administrative action.
Guarantees
Centennial has unconditionally guaranteed a portion of certain
bank borrowings of MPX in connection with the Company's equity
method investment in the Brazil Generating Facility, as
discussed in Note 11. The Company, through MDU Brasil, owns 49
percent of MPX. The main business purpose of Centennial
extending the guarantee to MPX's creditors is to enable MPX to
obtain lower borrowing costs. At June 30, 2004, the aggregate
amount of borrowings outstanding subject to these guarantees
was $40.1 million and the scheduled repayment of these
borrowings is $5.6 million in 2004, $10.7 million in 2005,
2006, and 2007 and $2.4 million in 2008. The individual
investor (who through EBX Empreendimentos Ltda. (EBX), a
Brazilian company, owns 51 percent of MPX) has also guaranteed
these loans. In the event MPX defaults under its obligation,
Centennial and the individual investor would be required to
make payments under their guarantees, which are joint and
several obligations. Centennial and the individual investor
have entered into reimbursement agreements under which they
have agreed to reimburse each other to the extent they may be
required to make any guarantee payments in excess of their
proportionate ownership share in MPX. These guarantees are not
reflected on the Consolidated Balance Sheets.
In addition, WBI Holdings has guaranteed certain of its
subsidiary's natural gas and oil price swap and collar
agreement obligations. The amount of the subsidiary's
obligation at June 30, 2004, was $4.0 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
June 30, 2004, expire in 2004 and 2005; however, the subsidiary
continues to enter into additional hedging activities and, as a
result, WBI Holdings from time to time may issue additional
guarantees on these hedging obligations. At June 30, 2004, the
amount outstanding was reflected on the Consolidated Balance
Sheets. In the event the above subsidiary defaults under its
obligations, WBI Holdings would be required to make payments
under its guarantees.
Certain subsidiaries of the Company have outstanding guarantees
to third parties that guarantee the performance of other
subsidiaries of the Company. These guarantees are related to
natural gas transportation and sales agreements, electric power
supply agreements, insurance policies and certain other
guarantees. At June 30, 2004, the fixed maximum amounts
guaranteed under these agreements aggregated $74.8 million.
The amounts of scheduled expiration of the maximum amounts
guaranteed under these agreements aggregate $9.6 million in
2004; $31.3 million in 2005; $3.9 million in 2006; $549,000 in
2007; $911,000 in 2009; $13.0 million in 2010; $12.0 million in
2012; $500,000, which is subject to expiration 30 days after
the receipt of written notice; and $3.0 million, which has no
scheduled maturity date. The amount outstanding by
subsidiaries of the Company under the above guarantees was
$349,000 and was reflected on the Consolidated Balance Sheets
at June 30, 2004. In the event of default under these
guarantee obligations, the subsidiary issuing the guarantee for
that particular obligation would be required to make payments
under its guarantee.
Fidelity and WBI Holdings have outstanding guarantees to
Williston Basin. These guarantees are related to natural gas
transportation and storage agreements that guarantee the
performance of Prairielands Energy Marketing, Inc.
(Prairielands), an indirect wholly owned subsidiary of the
Company. At June 30, 2004, the fixed maximum amounts
guaranteed under these agreements aggregated $22.9 million.
Scheduled expiration of the maximum amounts guaranteed under
these agreements aggregate $2.9 million in 2005 and $20.0
million in 2009. In the event of Prairielands' default in its
payment obligations, the entity issuing the guarantee for that
particular obligation would be required to make payments under
its guarantee. The amount outstanding by Prairielands under
the above guarantees was $1.2 million, which was not reflected
on the Consolidated Balance Sheets at June 30, 2004, because
these intercompany transactions are eliminated in
consolidation.
In addition, Centennial has issued guarantees to third parties
related to the Company's routine purchase of maintenance items
for which no fixed maximum amounts have been specified. These
guarantees have no scheduled maturity date. In the event a
subsidiary of the Company defaults under its obligation in
relation to the purchase of certain maintenance items,
Centennial would be required to make payments under these
guarantees. Any amounts outstanding by subsidiaries of the
Company for these maintenance items were reflected on the
Consolidated Balance Sheets at June 30, 2004.
As of June 30, 2004, Centennial was contingently liable for
performance of certain of its subsidiaries under approximately
$290 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.
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
Overview
This subsection of Item 2 -- Management's Discussion and Analysis of
Financial Condition and Results of Operations (Management's
Discussion and Analysis) is a brief overview of the important
factors that management focuses on in evaluating the Company's
businesses, the Company's financial condition and operating
performance, the Company's overall business strategy and the
earnings of the Company for the period covered by this report. This
subsection is not intended to be a substitute for reading the entire
Management's Discussion and Analysis section. Reference is made to
the various important factors listed under the heading Risk Factors
and Cautionary Statements that May Affect Future Results, as well as
other factors that are listed in the Introduction in relation to any
forward-looking statement.
Business and Strategy Overview
The Company has six reportable segments consisting of electric,
natural gas distribution, utility services, pipeline and energy
services, natural gas and oil production, and construction materials
and mining. The independent power production and other operations
do not individually meet the criteria to be considered a reportable
segment.
The electric segment includes the electric generation, transmission
and distribution operations of Montana-Dakota. The natural gas
distribution segment includes the natural gas distribution
operations of Montana-Dakota and Great Plains Natural Gas Co. The
electric and natural gas distribution segments also supply related
value-added products and services in the northern Great Plains. The
utility services segment includes all the operations of Utility
Services, Inc., which specializes in electrical line construction,
pipeline construction, inside electrical wiring and cabling and the
manufacture and distribution of specialty equipment. The pipeline
and energy services segment includes WBI Holdings' natural gas
transportation, underground storage and gathering services through
regulated and nonregulated pipeline systems primarily in the Rocky
Mountain and northern Great Plains regions of the United States.
The pipeline and energy services segment also provides energy-
related management services, including cable and pipeline
magnetization and locating. The natural gas and oil production
segment includes the natural gas and oil acquisition, exploration,
development and production operations, primarily in the Rocky
Mountain region of the United States and in and around the Gulf of
Mexico, of WBI Holdings. The construction materials and mining
segment includes the results of Knife River, which mines aggregates
and markets crushed stone, sand, gravel and related construction
materials, including ready-mixed concrete, cement, asphalt and other
value-added products, as well as performs integrated construction
services, in the central and western United States and in the states
of Alaska and Hawaii. The independent power production and other
operations own electric generating facilities in the United States
and have investments in electric generating facilities in Brazil and
Trinidad and Tobago. Electric capacity and energy produced at the
power plants are sold primarily under long-term contracts to
nonaffiliated entities. Centennial Resources also provides
analysis, design, construction, refurbishment, and operation and
maintenance services to independent power producers. These
operations also include investments not directly being pursued by
the Company's other businesses.
Earnings from electric, natural gas distribution, and pipeline and
energy services are substantially all from regulated operations.
Earnings from utility services, natural gas and oil production,
construction materials and mining, and independent power production
and other are all from nonregulated operations.
On August 14, 2003, the Company's Board of Directors approved a
three-for-two common stock split. For more information on the
common stock split, see Note 3 of Notes to Consolidated Financial
Statements.
The Company's strategy is to apply its expertise in energy and
transportation infrastructure industries to increase market share
through internal growth along with acquisition of well-managed
companies and development of projects that enhance shareholder value
and are accretive to earnings per share and returns on invested
capital.
The Company has capabilities to fund its growth and operations
through various sources, including internally generated funds,
commercial paper credit facilities and through the issuance of long-
term debt and the Company's equity securities. Net capital
expenditures are estimated to be approximately $450 million for
2004.
The Company faces certain challenges and risks as it pursues its
growth strategies, including, but not limited to the following:
- The natural gas and oil production business experiences
fluctuations in average natural gas and oil prices. These prices
are volatile and subject to significant change at any time. The
Company hedges a portion of its natural gas and oil production in
order to mitigate price volatility.
- The uncertain economic environment and the depressed
telecommunications market have been challenging, particularly for
the Company's utility services business, which has been subjected to
lower margins and decreased workloads. These economic factors have
also negatively affected the Company's energy services business.
- Fidelity continues to seek additional reserve and production
growth through acquisition, exploration, development and production
of natural gas and oil resources, including the development and
production of its coalbed natural gas properties. Future growth is
dependent upon success in these endeavors. Fidelity has been named
as a defendant in, and/or certain of its operations are the subject
of, over a dozen lawsuits filed in connection with its coalbed
natural gas development in the Powder River Basin in Montana and
Wyoming. If the plaintiffs are successful in these lawsuits, the
ultimate outcome of the actions could have a material effect on
Fidelity's existing coalbed natural gas operations and/or the future
development of its coalbed natural gas properties.
For further information on certain factors that should be considered
for a better understanding of the Company's financial condition, see
the various important factors listed under the heading Risk Factors
and Cautionary Statements that May Affect Future Results, as well as
other factors that are listed in the Introduction.
For information pertinent to various commitments and contingencies,
see Notes to Consolidated Financial Statements.
Earnings Overview
The following table (dollars in millions, where applicable)
summarizes the contribution to consolidated earnings by each of
the Company's businesses.
Three Months Six Months
Ended Ended
June 30, June 30,
2004 2003 2004 2003
Electric $ .7 $ 1.8 $ 4.2 $ 6.6
Natural gas distribution (1.1) (1.3) 1.2 2.9
Utility services (2.3) 1.5 (4.2) 2.6
Pipeline and energy services 4.4 5.1 7.1 9.4
Natural gas and oil production 26.2 17.9 51.4 29.5
Construction materials and mining 20.4 12.8 8.5 5.4
Independent power production
and other 10.2 5.5 13.7 6.8
Earnings on common stock $58.5 $ 43.3 $ 81.9 $63.2
Earnings per common
share - basic $ .50 $ .39 $ .71 $ .57
Earnings per common
share - diluted $ .50 $ .39 $ .70 $ .57
Return on average common equity
for the 12 months ended 13.3% 13.0%
________________________________
Three Months Ended June 30, 2004 and 2003
Consolidated earnings for the quarter ended June 30, 2004,
increased $15.2 million from the comparable prior period due
to higher earnings at the natural gas and oil production,
construction materials and mining, independent power
production and other, and natural gas distribution
businesses. Decreased earnings at the utility services,
electric and pipeline and energy services businesses
partially offset the earnings increase.
In 2004, the Company resolved federal and related state
income tax matters for the 1998 through 2000 tax years. The
Company reflected the effects of this tax resolution and, in
addition, reversed reserves that had previously been
provided and were deemed to be no longer required, which
resulted in a benefit of $5.9 million (after-tax), including
interest, for the three months ended June 30, 2004.
Natural gas and oil production earnings increased $8.3
million due to higher average realized natural gas and oil
prices, increased natural gas production and a favorable
resolution of federal and related state income tax matters,
partially offset by higher depreciation, depletion and
amortization expense and higher operating expenses.
The increase in construction materials and mining earnings
of $7.6 million, which was largely from existing operations,
reflects higher aggregate, asphalt and ready-mixed concrete
volumes and margins, and increased construction activity. A
favorable resolution of federal and related state income tax
matters and earnings from companies acquired since the
comparable prior period also added to the earnings increase.
Earnings increased $4.7 million at the independent power
production and other businesses due to the increased value
of the embedded derivative in the Brazilian electric power
purchase agreement, lower financing costs, and acquisitions
made since the comparable prior period, partially offset by
foreign currency changes.
The natural gas distribution business experienced a slightly
lower normal seasonal loss of $200,000 as a result of a
favorable resolution of federal and related state income tax
matters and higher retail sales prices, partially offset by
higher operation and maintenance expenses.
Utility services experienced a $2.3 million loss compared to
$1.5 million of earnings for the comparable prior period due
primarily to decreased inside electrical margins, largely
due to lower than expected results on certain large jobs
that are nearly complete.
Electric earnings decreased $1.1 million as a result of
lower retail sales margins and higher operation and
maintenance expense, partially offset by a favorable
resolution of federal and related state income tax matters
and higher sales for resale volumes.
Earnings decreased $700,000 at the pipeline and energy
services business due to higher operating expenses, lower
storage revenues and lower revenues from traditional off-
system transportation services. Partially offsetting the
decrease in earnings were a favorable resolution of federal
and related state income tax matters and an increase in
natural gas transportation volumes and firm services as a
result of the Grasslands Pipeline.
Six Months Ended June 30, 2004 and 2003
Consolidated earnings for the six months ended June 30,
2004, increased $18.7 million from the comparable prior
period due to higher earnings at the natural gas and oil
production, independent power production and other, and
construction materials and mining businesses. Decreased
earnings at the utility services, electric, pipeline and
energy services, and natural gas distribution businesses
partially offset the earnings increase.
In 2004, the Company resolved federal and related state
income tax matters for the 1998 through 2000 tax years. The
Company reflected the effects of this tax resolution and, in
addition, reversed reserves that had previously been
provided and were deemed to be no longer required, which
resulted in a benefit of $5.9 million (after-tax), including
interest, for the six months ended June 30, 2004.
Natural gas and oil production earnings increased $21.9
million due to higher average realized natural gas and oil
prices and the absence in 2004 of a $12.7 million ($7.7
million after tax) noncash transition charge in 2003,
reflecting the cumulative effect of an accounting change, as
discussed in Note 14 of Notes to Consolidated Financial
Statements. Higher natural gas production and a favorable
resolution of federal and related state income tax matters
also contributed to the increase in earnings. Higher
depreciation, depletion and amortization expense; higher
operation and maintenance expense, largely increased general
and administrative costs; and higher interest expense
partially offset the earnings increase.
Earnings increased $6.9 million at the independent power
production and other businesses due to the increased value
of the embedded derivative in the Brazilian power purchase
agreement and lower financing costs, partially offset by
foreign currency changes.
Earnings at the construction materials and mining business
increased $3.1 million as a result of higher asphalt and
ready-mixed concrete volumes and margins, increased
construction activity and a favorable resolution of federal
and related state income tax matters. Partially offsetting
the earnings increase were higher operation and maintenance
expense, including increased general and administrative
expenses; and lower aggregate volumes at a large harbor-
deepening project in southern California compared to the
prior period, which project is now substantially complete.
Utility services experienced a $4.2 million loss compared to
$2.6 million of earnings for the comparable prior period due
primarily to decreased inside electrical margins, largely
due to lower than expected results on certain large jobs
that are nearly complete.
Electric earnings decreased $2.4 million as a result of
higher operation and maintenance expense, higher fuel and
purchased power-related costs and higher interest expense.
A favorable resolution of federal and related state income
tax matters and higher average sales for resale prices
partially offset the decrease in earnings.
Earnings decreased $2.3 million at the pipeline and energy
services business due to higher operating expenses, lower
storage revenues and lower revenues from traditional off-
system transportation services. Partially offsetting the
decrease in earnings were a favorable resolution of federal
and related state income tax matters and an increase in
natural gas transportation volumes and firm services as a
result of the Grasslands Pipeline.
Natural gas distribution earnings decreased $1.7 million due
to higher operation and maintenance expense, lower retail
sales volumes and decreased service and repair margins. A
favorable resolution of federal and related state income tax
matters and higher retail sales prices partially offset the
decrease in earnings.
Financial and operating data
The following tables (dollars in millions, where applicable) are key
financial and operating statistics for each of the Company's
businesses.
Electric
Three Months Six Months
Ended Ended
June 30, June 30,
2004 2003 2004 2003
Operating revenues $ 39.8 $ 38.1 $ 86.8 $ 83.7
Operating expenses:
Fuel and purchased power 16.4 13.3 33.1 28.7
Operation and maintenance 14.6 12.9 29.6 26.2
Depreciation, depletion and
amortization 5.0 5.0 10.0 9.9
Taxes, other than income 2.0 1.8 4.2 3.9
38.0 33.0 76.9 68.7
Operating income $ 1.8 $ 5.1 $ 9.9 $ 15.0
Retail sales (million kWh) 505.3 529.8 1,126.5 1,129.9
Sales for resale (million kWh) 170.0 122.9 397.2 374.3
Average cost of fuel and
purchased power per kWh $ .022 $ .020 $ .020 $ .018
Natural Gas Distribution
Three Months Six Months
Ended Ended
June 30, June 30,
2004 2003 2004 2003
Operating revenues:
Sales $ 46.5 $ 41.4 $ 173.5 $ 151.4
Transportation and other 1.0 1.0 2.3 2.0
47.5 42.4 175.8 153.4
Operating expenses:
Purchased natural gas sold 35.4 30.4 141.0 118.5
Operation and maintenance 11.3 10.0 25.1 21.6
Depreciation, depletion and
amortization 2.3 2.5 4.7 5.1
Taxes, other than income 1.4 1.3 2.9 2.7
50.4 44.2 173.7 147.9
Operating income (loss) $ (2.9)$ (1.8) $ 2.1 $ 5.5
Volumes (MMdk):
Sales 5.4 5.3 21.7 22.8
Transportation 2.6 3.0 6.5 6.1
Total throughput 8.0 8.3 28.2 28.9
Degree days (% of normal)* 98% 91% 96% 100%
Average cost of natural gas,
including transportation
thereon, per dk $ 6.58 $ 5.69 $ 6.49 $ 5.20
_____________________
* Degree days are a measure of the daily temperature-related demand
for energy for heating.
Utility Services
Three Months Six Months
Ended Ended
June 30, June 30,
2004 2003 2004 2003
Operating revenues $ 97.2 $ 108.9 $ 197.5 $ 212.6
Operating expenses:
Operation and maintenance 93.5 99.8 188.9 194.0
Depreciation, depletion
and amortization 2.5 2.7 5.2 5.1
Taxes, other than income 3.7 3.3 8.5 7.7
99.7 105.8 202.6 206.8
Operating income (loss) $ (2.5)$ 3.1 $ (5.1) $ 5.8
Pipeline and Energy Services
Three Months Six Months
Ended Ended
June 30, June 30,
2004 2003 2004 2003
Operating revenues:
Pipeline $ 22.7 $ 25.1 $ 45.7 $ 50.5
Energy services 62.8 31.1 123.9 66.8
85.5 56.2 169.6 117.3
Operating expenses:
Purchased natural gas sold 59.2 30.3 116.5 64.8
Operation and maintenance 12.5 11.4 25.9 23.7
Depreciation, depletion
and amortization 4.7 3.7 9.2 7.4
Taxes, other than income 1.9 1.4 3.8 2.9
78.3 46.8 155.4 98.8
Operating income $ 7.2 $ 9.4 $ 14.2 $ 18.5
Transportation volumes (MMdk):
Montana-Dakota 7.6 8.0 15.9 16.4
Other 20.4 18.1 34.5 30.6
28.0 26.1 50.4 47.0
Gathering volumes (MMdk) 19.8 18.6 39.3 37.5
Natural Gas and Oil Production
Three Months Six Months
Ended Ended
June 30, June 30,
2004 2003 2004 2003
Operating revenues:
Natural gas $ 68.5 $ 52.6 $ 134.9 $ 107.8
Oil 14.9 12.0 29.1 25.8
Other .8 .1 1.2 .1
84.2 64.7 165.2 133.7
Operating expenses:
Purchased natural gas sold .7 --- 1.1 .1
Operation and maintenance:
Lease operating costs 8.6 6.4 16.8 14.5
Gathering and
transportation 2.7 3.7 5.2 7.0
Other 5.9 3.9 11.9 8.9
Depreciation, depletion
and amortization 17.9 15.2 34.5 29.4
Taxes, other than income:
Production and property
taxes 5.7 5.0 10.4 10.6
Other .1 .2 .3 .3
41.6 34.4 80.2 70.8
Operating income $ 42.6 $ 30.3 $ 85.0 $ 62.9
Production:
Natural gas (MMcf) 14,796 13,258 29,302 26,897
Oil (000's of barrels) 450 453 907 927
Average realized prices
(including hedges):
Natural gas (per Mcf) $ 4.63 $ 3.97 $ 4.60 $ 4.01
Oil (per barrel) $ 33.09 $ 26.52 $ 32.12 $ 27.79
Average realized prices
(excluding hedges):
Natural gas (per Mcf) $ 4.78 $ 4.31 $ 4.73 $ 4.50
Oil (per barrel) $ 35.75 $ 26.98 $ 34.03 $ 29.06
Production costs, including
taxes, per net equivalent Mcf:
Lease operating costs $ .49 $ .40 $ .48 $ .45
Gathering and
transportation .15 .23 .15 .22
Production and property
taxes .33 .32 .30 .32
$ .97 $ .95 $ .93 $ .99
Construction Materials and Mining
Three Months Six Months
Ended Ended
June 30, June 30,
2004 2003 2004 2003
Operating revenues $ 347.2 $ 264.1 $ 486.7 $ 384.9
Operating expenses:
Operation and maintenance 286.6 219.2 419.7 330.7
Depreciation, depletion
and amortization 17.0 15.6 33.2 30.2
Taxes, other than income 9.6 6.4 16.1 11.0
313.2 241.2 469.0 371.9
Operating income $ 34.0 $ 22.9 $ 17.7 $ 13.0
Sales (000's):
Aggregates (tons) 11,187 9,592 15,994 14,619
Asphalt (tons) 2,346 1,701 2,648 1,863
Ready-mixed concrete
(cubic yards) 1,239 912 1,813 1,427
Independent Power Production and Other
Three Months Six Months
Ended Ended
June 30, June 30,
2004 2003 2004 2003
Operating revenues $ 11.6 $ 11.0 $ 18.9 $ 18.1
Operating expenses:
Operation and maintenance 3.6 3.1 8.3 7.3
Depreciation, depletion and
amortization 2.4 2.2 4.5 3.9
Taxes, other than income 1.1 --- 1.1 ---
7.1 5.3 13.9 11.2
Operating income $ 4.5 $ 5.7 $ 5.0 $ 6.9
Net generation capacity - kW* 279,600 279,600 279,600 279,600
Electricity produced and sold
(thousand kWh)* 84,148 89,694 115,503 138,594
_____________________
* Reflects domestic independent power production operations.
NOTE: The earnings from the Company's equity method investments in
Brazil and Trinidad and Tobago were included in other income - net
and, thus, are not reflected in the above table.
Amounts presented in the preceding tables for operating revenues,
purchased natural gas sold and operation and maintenance expense
will not agree with the Consolidated Statements of Income due to
the elimination of intersegment transactions. The amounts (dollars
in millions) relating to the elimination of intersegment
transactions were as follows:
Three Months Six Months
Ended Ended
June 30, June 30,
2004 2003 2004 2003
Operating revenues $ 59.7 $ 37.2 $ 131.7 $ 87.7
Purchased natural gas sold 55.8 33.1 124.3 79.7
Operation and maintenance 3.9 4.1 7.4 8.0
For further information on intersegment eliminations, see Note 15
of Notes to Consolidated Financial Statements.
Three Months Ended June 30, 2004 and 2003
Electric
Electric earnings decreased $1.1 million as a result of lower retail
sales margins, largely due to higher fuel and purchased power-
related costs, including higher demand charges resulting from a
scheduled outage at an electric supplier's generating station; and a
5 percent decrease in retail sales volumes. Higher operation and
maintenance expense, including increased payroll-related costs and
company-owned generation facility subcontract expenses, along with
increased interest expense, also contributed to the earnings
decrease. Partially offsetting the decrease in earnings were a
favorable resolution of federal and related state income tax matters
and higher sales for resale volumes of 38 percent due to stronger
sales for resale markets.
Natural Gas Distribution
Normal seasonal losses at the natural gas distribution business
decreased $200,000 due to a favorable resolution of federal and
related state income tax matters and higher retail sales prices
primarily due to a rate increase effective in South Dakota,
partially offset by higher operation and maintenance expense,
including increased payroll-related costs and higher subcontract
costs.
Utility Services
Utility services experienced a $2.3 million loss for the second
quarter, compared to $1.5 million in earnings for the comparable
prior period. The decrease in earnings was due to lower inside
electrical margins, largely due to lower than expected results on
certain large jobs that are nearly complete, and higher general and
administrative expenses. Increased line construction margins in the
Southwest, Central and Rocky Mountain regions partially offset the
earnings decrease.
Pipeline and Energy Services
Earnings at the pipeline and energy services business decreased
$700,000 as a result of higher operating expenses, which were
partially the result of increased costs associated with last year's
expansion of pipeline and gathering operations and higher payroll-
related costs. Lower storage service revenues and lower revenues
from traditional off-system transportation services also contributed
to the earnings decrease. Partially offsetting the decrease in
earnings were a favorable resolution of federal and related state
income tax matters and an increase in natural gas transportation
volumes and firm services as a result of the Grasslands Pipeline,
which began providing natural gas transmission service late in 2003.
The increase in energy services revenues and the related increase in
purchased natural gas sold includes the effect of increases in
natural gas prices and volumes since the comparable prior period.
Natural Gas and Oil Production
Natural gas and oil production earnings increased $8.3 million due
to higher average realized natural gas prices of 17 percent due in
part to the Company's ability to access higher-priced markets for
much of its operated natural gas production through the Grasslands
Pipeline, completed late last year; increased natural gas production
of 12 percent; and higher average realized oil prices of 25 percent.
A favorable resolution of federal and related state income tax
matters also contributed to the increase in earnings. Partially
offsetting the earnings increase were higher depreciation, depletion
and amortization expense due to higher rates and higher natural gas
production volumes; higher operation and maintenance expense,
primarily higher lease operating expenses and increased general and
administrative costs; and higher interest expense.
Construction Materials and Mining
The increase in construction materials and mining earnings of $7.6
million, which was largely from existing operations, reflects
increased aggregate, asphalt and ready-mixed concrete volumes and
margins, and increased construction activity. A favorable
resolution of federal and related state income tax matters and
earnings from companies acquired since the comparable prior period
also added to the earnings increase. Partially offsetting the
earnings increase were lower aggregate volumes at a large harbor-
deepening project in southern California compared to the prior
period, which project is now substantially complete and higher
operation and maintenance expense, including higher general and
administrative expenses.
Independent Power Production and Other
Earnings for the independent power production and other businesses
increased $4.7 million largely due to higher net income of $5.5
million from the Company's share of its equity investment in Brazil.
The higher net income was due primarily to the increased value of
the embedded derivative in the electric power purchase agreement
combined with lower financing costs, largely the result of obtaining
low-cost, long-term financing for the operation in mid-2003,
partially offset by foreign currency changes. Domestic and
international acquisitions made since the comparable prior period
also added to the increase in earnings. Lower revenues from
existing domestic operations, due in part to lower sales volumes,
partially offset the earnings increase.
Six Months Ended June 30, 2004 and 2003
Electric
Electric earnings decreased $2.4 million as a result of higher
operation and maintenance expense, including increased payroll-
related costs, pension expense and company-owned generation facility
subcontract expenses; higher fuel and purchased power-related costs,
as previously discussed; and higher interest expense. Partially
offsetting the decrease in earnings were a favorable resolution of
federal and related state income tax matters and higher average
sales for resale prices of 26 percent.
Natural Gas Distribution
Earnings at the natural gas distribution business decreased $1.7
million due to higher operation and maintenance expense, including
increased payroll-related costs, pension expense and subcontract
costs; a 5 percent decrease in retail sales volumes due to weather
that was 3 percent warmer than last year; and decreased service and
repair margins. Partially offsetting the earnings decrease were a
favorable resolution of federal and related state income tax matters
and higher retail sales prices, primarily due to a rate increase
effective in South Dakota.
Utility Services
Utility services experienced a $4.2 million loss for the first six
months of 2004, compared to $2.6 million in earnings for the
comparable prior period. The decrease in earnings was due to lower
inside electrical margins, largely due to lower than expected
results on certain large jobs that are nearly complete; decreased
line construction margins in the Central and Rocky Mountain regions;
and higher general and administrative expenses. Increased line
construction margins in the Southwest and Northwest regions
partially offset the earnings decrease.
Pipeline and Energy Services
Earnings at the pipeline and energy services business decreased $2.3
million as a result of higher operating expenses, which were
partially the result of increased costs associated with last year's
expansion of pipeline and gathering operations and higher payroll-
related costs. Also contributing to the earnings decrease were
lower storage service revenues and lower revenues from traditional
off-system transportation services. Partially offsetting the
decrease in earnings were a favorable resolution of federal and
related state income tax matters and an increase in natural gas
transportation volumes and firm services as a result of the
Grasslands Pipeline, which began providing natural gas transmission
service late in 2003. The increase in energy services revenues and
the related increase in purchased natural gas sold includes the
effect of increases in natural gas prices and volumes compared to
the prior period.
Natural Gas and Oil Production
Natural gas and oil production earnings increased $21.9 million due
to higher average realized natural gas prices of 15 percent due in
part to the Company's ability to access higher-priced markets for
much of its operated natural gas production through the recently
constructed Grasslands Pipeline and the absence in 2004 of a 2003
noncash transition charge, as previously discussed. Higher natural
gas production of 9 percent, higher average realized oil prices of
16 percent and a favorable resolution of federal and related state
income tax matters also contributed to the increase in earnings.
Partially offsetting the earnings increase were higher depreciation,
depletion and amortization expense due to higher rates and higher
natural gas production volumes; higher operation and maintenance
expense, largely increased general and administrative costs; and
higher interest expense.
Construction Materials and Mining
The increase in construction materials and mining earnings of $3.1
million reflects higher asphalt and ready-mixed concrete volumes and
margins and increased construction activity, all at existing
operations. A favorable resolution of federal and related state
income tax matters also added to the earnings increase. Partially
offsetting the increase in earnings were higher operation and
maintenance expense, including increased general and administrative
expenses; and lower aggregate volumes at a large harbor-deepening
project in southern California from the prior period, which project
is now substantially complete. The increase in revenues and the
related increase in operating expense resulted largely from
businesses acquired since the comparable prior period.
Independent Power Production and Other
Earnings for the independent power production and other businesses
increased $6.9 million largely due to higher net income of $8.2
million from the Company's share of its equity investment in Brazil.
The higher net income was due primarily to the increased value of
the embedded derivative in the power purchase agreement combined
with lower financing costs, largely the result of obtaining low-
cost, long-term financing for the operation in mid-2003, partially
offset by foreign currency changes. Domestic and international
acquisitions made since the comparable prior period also added to
the increase in earnings. Lower revenues from existing domestic
operations, due in part to lower sales volumes, partially offset the
earnings increase.
Risk Factors and Cautionary Statements that May Affect Future
Results
The Company is including the following factors and cautionary
statements in this Form 10-Q to make applicable and to take
advantage of the safe harbor provisions of the Private Securities
Litigation Reform Act of 1995 for any forward-looking statements
made by, or on behalf of, the Company. Forward-looking statements
include statements concerning plans, objectives, goals, strategies,
future events or performance, and underlying assumptions (many of
which are based, in turn, upon further assumptions) and other
statements that are other than statements of historical facts. From
time to time, the Company may publish or otherwise make available
forward-looking statements of this nature, including statements
contained within Prospective Information. All these subsequent
forward-looking statements, whether written or oral and whether made
by or on behalf of the Company, are also expressly qualified by
these factors and cautionary statements.
Forward-looking statements involve risks and uncertainties, which
could cause actual results or outcomes to differ materially from
those expressed. The Company's expectations, beliefs and
projections are expressed in good faith and are believed by the
Company to have a reasonable basis, including without limitation,
management's examination of historical operating trends, data
contained in the Company's records and other data available from
third parties. Nonetheless, the Company's expectations, beliefs or
projections may not be achieved or accomplished.
Any forward-looking statement contained in this document speaks only
as of the date on which the statement is made, and the Company
undertakes no obligation to update any forward-looking statement or
statements to reflect events or circumstances that occur after the
date on which the statement is made or to reflect the occurrence of
unanticipated events. New factors emerge from time to time, and it
is not possible for management to predict all of the factors, nor
can it assess the effect of each factor on the Company's business or
the extent to which any factor, or combination of factors, may cause
actual results to differ materially from those contained in any
forward-looking statement.
Following are some specific factors that should be considered for a
better understanding of the Company's financial condition. These
factors and the other matters discussed herein are important factors
that could cause actual results or outcomes for the Company to
differ materially from those discussed in the forward-looking
statements included elsewhere in this document.
Economic Risks
The Company's natural gas and oil production business is dependent
on factors, including commodity prices, which cannot be predicted or
controlled.
These factors include: price fluctuations in natural gas and crude
oil prices; availability of economic supplies of natural gas;
drilling successes in natural gas and oil operations; the ability to
contract for or to secure necessary drilling rig contracts and to
retain employees to drill for and develop reserves; the ability to
acquire natural gas and oil properties; the timely receipt of
necessary permits and approvals; and other risks incidental to the
operations of natural gas and oil wells. Significant changes in
these factors could negatively affect the results of operations and
financial condition of the Company's natural gas and oil production
business.
The construction and operation of power generation facilities may
involve unanticipated changes or delays which could negatively
impact the Company's business and its results of operations.
The construction and operation of power generation facilities
involves many risks, including start-up risks, breakdown or failure
of equipment, competition, inability to obtain required governmental
permits and approvals, and inability to negotiate acceptable
acquisition, construction, fuel supply, off-take, transmission or
other material agreements, as well as the risk of performance below
expected levels of output or efficiency. Such unanticipated events
could negatively impact the Company's business and its results of
operations.
The uncertain economic environment and depressed telecommunications
market may have a general negative impact on the Company's future
revenues and may result in a goodwill impairment for Innovatum, Inc.
(Innovatum), an indirect wholly owned subsidiary of the Company.
In response to the ongoing war against terrorism by the United
States and the bankruptcy of several large energy and
telecommunications companies and other large enterprises, the
financial markets have been volatile. A soft economy could
negatively affect the level of public and private expenditures on
projects and the timing of these projects which, in turn, would
negatively affect the demand for the Company's products and
services.
Innovatum, which specializes in cable and pipeline magnetization and
locating, is subject to the economic conditions within the
telecommunications and energy industries. Innovatum has also
developed a hand-held locating device that can detect both magnetic
and plastic materials. Innovatum could face a future goodwill
impairment if there is a continued downturn in the
telecommunications and energy industries or if it cannot find a
successful market for the hand-held locating device. At June 30,
2004, the goodwill amount at Innovatum was approximately
$8.3 million. The determination of whether an impairment will occur
is dependent on a number of factors, including the level of spending
in the telecommunications and energy industries, the success of the
hand-held locating device at Innovatum, rapid changes in technology,
competitors and potential new customers.
The Company relies on financing sources and capital markets. If the
Company is unable to obtain financing in the future, the Company's
ability to execute its business plans, make capital expenditures or
pursue acquisitions that the Company may otherwise rely on for
future growth could be impaired.
The Company relies on access to both short-term borrowings,
including the issuance of commercial paper, and long-term capital
markets as a source of liquidity for capital requirements not
satisfied by its cash flow from operations. If the Company is not
able to access capital at competitive rates, the ability to
implement its business plans may be adversely affected. Market
disruptions or a downgrade of the Company's credit ratings may
increase the cost of borrowing or adversely affect its ability to
access one or more financial markets. Such disruptions could
include:
- A severe prolonged economic downturn
- The bankruptcy of unrelated industry leaders in the same line
of business
- Capital market conditions generally
- Volatility in commodity prices
- Terrorist attacks
- Global events
Environmental and Regulatory Risks
Some of the Company's operations are subject to extensive
environmental laws and regulations that may increase costs of
operations, impact or limit business plans, or expose the Company to
environmental liabilities. One of the Company's subsidiaries is
subject to litigation in connection with its coalbed natural gas
development activities.
The Company is subject to extensive environmental laws and
regulations affecting many aspects of its present and future
operations including air quality, water quality, waste management
and other environmental considerations. These laws and regulations
can result in increased capital, operating and other costs, and
delays as a result of compliance, remediation, containment and
monitoring obligations, particularly with regard to laws relating to
power plant emissions and coalbed natural gas development. These
laws and regulations generally require the Company to obtain and
comply with a wide variety of environmental licenses, permits,
inspections and other approvals. Public officials and entities, as
well as private individuals and organizations, may seek to enforce
applicable environmental laws and regulations. The Company cannot
predict the outcome (financial or operational) of any related
litigation that may arise.
Existing environmental regulations may be revised and new
regulations seeking to protect the environment may be adopted or
become applicable to the Company. Revised or additional
regulations, which result in increased compliance costs or
additional operating restrictions, particularly if those costs are
not fully recoverable from customers, could have a material effect
on the Company's results of operations.
Fidelity has been named as a defendant in, and/or certain of its
operations are the subject of, over a dozen lawsuits filed in
connection with its coalbed natural gas development in the Powder
River Basin in Montana and Wyoming. If the plaintiffs are
successful in these lawsuits, the ultimate outcome of the actions
could have a material effect on Fidelity's existing coalbed natural
gas operations and/or the future development of its coalbed natural
gas properties.
The Company is subject to extensive government regulations that may
have a negative impact on its business and its results of
operations.
The Company is subject to regulation by federal, state and local
regulatory agencies with respect to, among other things, allowed
rates of return, financings, industry rate structures, and recovery
of purchased power and purchased gas costs. These governmental
regulations significantly influence the Company's operating
environment and may affect its ability to recover costs from its
customers. The Company is unable to predict the impact on operating
results from the future regulatory activities of any of these
agencies.
Changes in regulations or the imposition of additional regulations
could have an adverse impact on the Company's results of operations.
Risks Relating to Foreign Operations
The value of the Company's investments in foreign operations may
diminish due to political, regulatory and economic conditions and
changes in currency exchange rates in countries where the Company
does business.
The Company is subject to political, regulatory and economic
conditions and changes in currency exchange rates in foreign
countries where the Company does business. Significant changes in
the political, regulatory or economic environment in these countries
could negatively affect the value of the Company's investments
located in these countries. Also, since the Company is unable to
predict the fluctuations in the foreign currency exchange rates,
these fluctuations may have an adverse impact on the Company's
results of operations.
The Company's 49 percent equity method investment in a 220-megawatt
natural gas-fired electric generation project in Brazil includes a
power purchase agreement that contains an embedded derivative. This
embedded derivative derives its value from an annual adjustment
factor that largely indexes the contract capacity payments to the
U.S. dollar. In addition, from time to time, other derivative
instruments may be utilized. The valuation of these financial
instruments, including the embedded derivative, can involve
judgments, uncertainties and the use of estimates. As a result,
changes in the underlying assumptions could affect the reported fair
value of these instruments. These instruments could recognize
financial losses as a result of volatility in the underlying fair
values, or if a counterparty fails to perform.
Other Risks
Competition is increasing in all of the Company's businesses.
All of the Company's businesses are subject to increased
competition. The independent power industry includes numerous
strong and capable competitors, many of which have greater resources
and more experience in the operation, acquisition and development of
power generation facilities. Utility services' competition is based
primarily on price and reputation for quality, safety and
reliability. The construction materials products are marketed under
highly competitive conditions and are subject to such competitive
forces as price, service, delivery time and proximity to the
customer. The electric utility and natural gas industries are also
experiencing increased competitive pressures as a result of consumer
demands, technological advances, deregulation, greater availability
of natural gas-fired generation and other factors. Pipeline and
energy services competes with several pipelines for access to
natural gas supplies and gathering, transportation and storage
business. The natural gas and oil production business is subject to
competition in the acquisition and development of natural gas and
oil properties as well as in the sale of its production output. The
increase in competition could negatively affect the Company's
results of operations and financial condition.
Weather conditions can adversely affect the Company's operations and
revenues.
The Company's results of operations can be affected by changes in
the weather. Weather conditions directly influence the demand for
electricity and natural gas, affect the wind-powered operation at
the independent power production business, affect the price of
energy commodities, affect the ability to perform services at the
utility services and construction materials and mining businesses
and affect ongoing operation and maintenance 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 and/or property damage, which could
require additional costs to be incurred. As a result, adverse
weather conditions could negatively affect the Company's results of
operations and financial condition.
Prospective Information
The following information includes highlights of the key growth
strategies, projections and certain assumptions for the Company and
its subsidiaries over the next few years and other matters for each
of the Company's businesses. Many of these highlighted points are
forward-looking statements. There is no assurance that the
Company's projections, including estimates for growth and increases
in revenues and earnings, will in fact be achieved. Reference is
made to assumptions contained in this section, as well as the
various important factors listed under the heading Risk Factors and
Cautionary Statements that May Affect Future Results, and other
factors that are listed in the Introduction. Changes in such
assumptions and factors could cause actual future results to differ
materially from targeted growth, revenue and earnings projections.
MDU Resources Group, Inc.
- - Earnings per common share for 2004, diluted, are projected in
the range of $1.75 to $1.90, an increase from prior guidance of
$1.60 to $1.75.
- - The Company expects the percentage of 2004 earnings per common
share, diluted, by quarter to be in the following approximate
ranges:
- Third quarter - 35 percent to 40 percent
- Fourth quarter - 23 percent to 28 percent
- - The Company's long-term compound annual growth goals on
earnings per share from operations are in the range of 6 percent to
9 percent.
- - The Company will consider issuing equity from time to time to
keep debt at the nonregulated businesses at no more than 40 percent
of total capitalization.
Electric
- - Montana-Dakota has obtained and holds valid and existing
franchises authorizing it to conduct its electric operations in all
of the municipalities it serves where such franchises are required.
As franchises expire, Montana-Dakota may face increasing competition
in its service areas, particularly its service to smaller towns,
from rural electric cooperatives. Montana-Dakota intends to protect
its service area and seek renewal of all expiring franchises and
will continue to take steps to effectively operate in an
increasingly competitive environment.
- - The expected return for this segment in 2004 is anticipated to
be generally consistent with overall authorized levels.
- - In mid-May, the Company submitted an air quality permit
application to construct a 175-megawatt coal-fired plant at
Gascoyne, North Dakota. The air permit application is now under
review at the North Dakota Department of Health, and the Company is
confident the new facility will provide it with the opportunity to
replace capacity associated with expiring contracts and help it meet
its growing needs into the future. As an alternative for the
capacity needs, this segment is also involved in a coalition with
four other utilities to study the feasibility of building a coal-
based facility, possibly combined with a wind energy facility, at
potential sites in North Dakota, South Dakota and Iowa. The costs
of building and/or acquiring the additional generating capacity
needed by the utility are expected to be recovered in rates.
- - On January 9, 2004, Montana-Dakota entered into a firm capacity
contract with a Midwest utility to purchase 5 megawatts of capacity
during the period May 1, 2004 to October 31, 2004, 15 megawatts
during the period May 1, 2005 to October 31, 2005 and 25 megawatts
during the period May 1, 2006 to October 31, 2006. In addition, on
January 9, 2004, Montana-Dakota entered into a firm power contract
with the same Midwest utility to purchase 70 megawatts of power
during the period November 1, 2006 to December 31, 2006, 80
megawatts during the period January 1, 2007 to December 31, 2007, 90
megawatts during the period January 1, 2008 to December 31, 2008 and
100 megawatts during the period January 1, 2009 to December 31,
2010. All capacity and power purchases from these contracts are
contingent upon the parties securing transmission service for the
delivery of capacity and power to Montana-Dakota's customer load.
Transmission service has not yet been secured. On July 15, 2004,
Montana-Dakota entered into a firm capacity contract to purchase 15
megawatts of capacity and associated energy for the summer of 2005
and 25 megawatts of capacity and associated energy for the summer of
2006 from a neighboring utility.
Natural gas distribution
- - Montana-Dakota and Great Plains have obtained and hold valid
and existing franchises authorizing them to conduct their natural
gas operations in all of the municipalities they serve where such
franchises are required. As franchises expire, Montana-Dakota and
Great Plains may face increasing competition in their service areas.
Montana-Dakota and Great Plains intend to protect their service
areas and seek renewal of all expiring franchises and will continue
to take steps to effectively operate in an increasingly competitive
environment.
- - Annual natural gas throughput for 2004 is expected to be
approximately 51 million decatherms.
- - The Company expects to seek natural gas rate increases from
time to time to offset higher expected operating costs.
- - Montana-Dakota has filed applications with state regulatory
authorities in three states (Montana, North Dakota and South Dakota)
seeking increases in natural gas retail rates that are in the range
of $1.3 million to $3.3 million annually or 1.8 percent to 2.8
percent above current rates. While Montana-Dakota believes that it
should be authorized to increase retail rates in the amounts
requested, there is no assurance that the increases ultimately
allowed will be for the full amount requested in each jurisdiction.
For further information on the natural gas rate increase
applications, see Note 18 of Notes to Consolidated Financial
Statements.
Utility services
- - Revenues for this segment are expected to be in the range of
$400 million to $450 million in 2004.
- - This segment anticipates margins for 2004 to be lower than 2003
levels. However, margins for the second half of 2004 should improve
over those experienced in the first half of 2004.
- - This segment's work backlog as of June 30, 2004, was
approximately $217 million compared to $150 million at June 30,
2003.
Pipeline and energy services
- - In 2004, total natural gas throughput is expected to increase
approximately 15 percent to 20 percent over 2003 levels largely due
to the Grasslands Pipeline, which began providing natural gas
transmission service on December 23, 2003.
- - Firm capacity for the Grasslands Pipeline is currently 90
million cubic feet per day with expansion possible to 200 million
cubic feet per day.
- - Transportation rates are expected to decline in 2004 from 2003
levels due to the estimated effects of a FERC rate order received in
July 2003 and order on rehearing received in May 2004.
- - Innovatum could face a future goodwill impairment based on
certain economic conditions, as previously discussed in Risk Factors
and Cautionary Statements that May Affect Future Results. Innovatum
recently developed a hand-held locating device that can detect both
magnetic and plastic materials. One of the possible uses for this
product would be in the detection of unexploded ordnance. Innovatum
is in the preliminary stages of working with and demonstrating the
device to a Department of Defense contractor and has met with
individuals from the Department of Defense.
Natural gas and oil production
- - In 2004, the Company believes a combined production increase of
approximately 10 percent over 2003 levels remains possible. A
portion of this increase is predicated on the timely receipt of
various regulatory approvals, which is affecting producers
throughout the Rocky Mountain region. The Company is confident that
it will receive such permits, but forecasting the timing of such
receipt is difficult. Also affecting the forecasted production
increase is the timely installation of infrastructure. Currently,
this segment's gross operated natural gas production is
approximately 140,000 Mcf to 150,000 Mcf per day.
- - Natural gas production from operated properties was 73 percent
of total natural gas production for the six months ended June 30,
2004.
- - This segment expects to drill more than 400 wells in 2004.
- - Natural gas prices in the Rocky Mountain region for August
through December 2004, reflected in the Company's 2004 earnings
guidance, are in the range of $4.50 to $5.00 per Mcf. The Company's
estimates for natural gas prices on the NYMEX for August through
December 2004, reflected in the Company's 2004 earnings guidance,
are in the range of $5.50 to $6.00 per Mcf. During 2003, more than
two-thirds of this segment's natural gas production was priced using
Rocky Mountain or other non-NYMEX prices.
- - NYMEX crude oil prices for July through December 2004,
reflected in the Company's 2004 earnings guidance, are in the range
of $33 to $37 per barrel.
- - The Company has hedged a portion of its 2004 natural gas
production. The Company has entered into agreements representing
approximately 30 percent to 35 percent of 2004 estimated annual
natural gas production. The agreements are at various indices and
range from a low CIG index of $3.75 to a high NYMEX index of $6.11
per Mcf. CIG is an index pricing point related to Colorado
Interstate Gas Co.'s system.
- - This segment has hedged a portion of its 2004 oil production.
The Company has entered into agreements at NYMEX prices with a low
of $28.84 and a high of $30.28, representing approximately 25
percent to 30 percent of 2004 estimated annual oil production.
- - The Company has hedged a portion of its 2005 estimated natural
gas production. The Company has entered into agreements
representing approximately 15 percent to 20 percent of its 2005
estimated annual natural gas production. The agreements are at a
Ventura index with a low of $4.75 and a high of $5.87 per Mcf.
Ventura is an index pricing point related to Northern Natural Gas
Co.'s system.
- - This segment has hedged a portion of its 2005 oil production.
The Company has entered into agreements at NYMEX prices with a low
of $30.70 and a high of $36.50 representing approximately 20 percent
to 25 percent of its 2005 estimated annual oil production.
Construction materials and mining
- - Aggregate volumes in 2004 are expected to be comparable to 2003
levels. Ready-mixed concrete volumes are expected to increase by 18
percent to 23 percent, while asphalt volumes are expected to
increase 10 percent to 15 percent over 2003.
- - Revenues in 2004 are expected to increase by approximately 13
percent to 18 percent over 2003 levels.
- - The Company is confident that the replacement funding
legislation for the Transportation Equity Act for the 21st Century
(TEA-21) will be equal to or higher than previous funding levels.
- - As of mid-July, this segment had $545 million in work backlog
compared to $497 million in mid-July of 2003.
- - The four labor contracts that Knife River was negotiating, as
reported in Items 1 and 2 -- Business and Properties - General in
the Company's 2003 Form 10-K, have been ratified and signed. The
Company considers its relations with its employees to be
satisfactory.
Independent power production and other
- - Earnings projections for independent power production and other
operations are expected to be in the range of $18 million to $23
million in 2004.
- - The Company is constructing a 116-megawatt coal-fired electric
generating project near Hardin, Montana. A power sales agreement
with Powerex Corp., a subsidiary of BC Hydro, has been secured for
the entire output of the plant for a three-year term with an option
for a two-year extension. The projected on-line date for this plant
is late 2005.
- - On July 20, 2004, an indirect wholly owned subsidiary of the
Company signed an agreement to acquire a 50 percent ownership
interest in a 310-megawatt natural gas-fired electric generating
facility in Georgia. The transaction is subject to receipt of
certain third-party consents and approval from the FERC. The
acquisition is anticipated to close in late third quarter or early
fourth quarter 2004.
New Accounting Standards
In December 2003, the FASB issued FASB Interpretation No. 46
(revised December 2003), "Consolidation of Variable Interest
Entities" (FIN 46 (revised)), which replaced FASB Interpretation No.
46, "Consolidation of Variable Interest Entities" (FIN 46). FIN 46
(revised) shall be applied to all entities subject to FIN 46
(revised) no later than the end of the first reporting period that
ends after March 15, 2004. The adoption of FIN 46 (revised) did not
have an effect on the Company's financial position or results of
operations.
In January 2004, the FASB issued FASB Staff Position No. FAS 106-1,
"Accounting and Disclosure Requirements Related to the Medicare
Prescription Drug, Improvement and Modernization Act of 2003" (FSP
No. FAS 106-1). FSP No. FAS 106-1 permits a sponsor of a
postretirement health care plan that provides a prescription drug
benefit to make a one-time election to defer accounting for the
effects of the Medicare Prescription Drug, Improvement and
Modernization Act of 2003 (2003 Medicare Act). In May 2004, the
FASB issued FASB Staff Position No. FAS 106-2, "Accounting and
Disclosure Requirements Related to the Medicare Prescription Drug,
Improvement and Modernization Act of 2003" (FSP No. FAS 106-2). The
Company provides prescription drug benefits to certain eligible
employees. The Company elected the one-time deferral of accounting
for the effects of the 2003 Medicare Act in the quarter ending March
31, 2004, the first period in which the plan's accounting for the
effects of the 2003 Medicare Act normally would have been reflected
in the Company's financial statements. During the second quarter of
2004, the Company adopted FSP No. FAS 106-2 retroactive to the
beginning of the year. The Company and its actuarial advisors
determined that benefits provided to certain participants are
expected to be at least actuarially equivalent to Medicare Part D
(the federal prescription drug benefit), and, accordingly, the
Company expects to be entitled to some federal subsidy. The
expected federal subsidy reduces the accumulated postretirement
benefit obligation (APBO) at January 1, 2004, by approximately $3.2
million, and net periodic benefit cost for 2004 by approximately
$285,000 (as compared with the amount calculated without considering
the effects of the subsidy). In addition, the Company expects a
reduction in future participation in the postretirement plans, which
further reduced the APBO at January 1, 2004, by approximately $12.7
million and net periodic benefit cost for 2004 by approximately $1.3
million.
SFAS No. 142, "Goodwill and Other Intangible Assets," discontinues
the practice of amortizing goodwill and indefinite lived intangible
assets and initiates an annual review for impairment. Intangible
assets with a determinable useful life will continue to be amortized
over that period. The amortization provisions apply to goodwill and
intangible assets acquired after June 30, 2001. SFAS No. 141,
"Business Combinations," and SFAS No. 142 clarify that more assets
should be distinguished and classified between tangible and
intangible. An issue has arisen within the natural gas and oil
industry as to whether contractual mineral rights under SFAS No. 142
should be classified as intangible rather than as part of property,
plant and equipment. The anticipated resolution of this matter is
not expected to have an effect on the Company's financial position,
results of operations or cash flows.
In April 2004, the FASB issued FASB Staff Position Nos. FAS 141-1
and FAS 142-1, "Interaction of FASB Statements No. 141, 'Business
Combinations,' and No. 142, 'Goodwill and Other Intangible Assets,'
and EITF Issue No. 04-2, 'Whether Mineral Rights are Tangible or
Intangible Assets,'" (FSP Nos. FAS 141-1 and FAS 142-1). FSP Nos.
FAS 141-1 and FAS 142-1 shall be applied to the first reporting
period beginning after April 29, 2004. FSP Nos. FAS 141-1 and FAS
142-1 required reclassification of the Company's leasehold rights at
its construction materials and mining operations from other
intangible assets, net to property, plant and equipment, as well as
changes to Notes to Consolidated Financial Statements. FSP Nos. FAS
141-1 and FAS 142-1 affected the asset classification in the
consolidated balance sheet and associated footnote disclosure only,
so the reclassifications did not affect the Company's stockholders'
equity, cash flows or results of operations.
For further information on FIN 46 (revised), FSP Nos. FAS 106-1 and
106-2, SFAS Nos. 142 and 141, and FSP Nos. FAS 141-1 and FAS 142-1,
see Note 9 of Notes to Consolidated Financial Statements.
Critical Accounting Policies Involving Significant Estimates
The Company's critical accounting policies involving significant
estimates include impairment testing of long-lived assets and
intangibles, impairment testing of natural gas and oil production
properties, revenue recognition, purchase accounting, asset
retirement obligations, and pension and other postretirement
benefits. There were no material changes in the Company's critical
accounting policies involving significant estimates from those
reported in the Company's Annual Report on Form 10-K for the year
ended December 31, 2003. For more information on critical
accounting policies involving significant estimates, see Part II,
Item 7 in the Company's Annual Report on Form 10-K for the year
ended December 31, 2003.
Liquidity and Capital Commitments
Cash flows
Operating activities --
Cash flows provided by operating activities in the first six months
of 2004 increased $8.4 million from the comparable 2003 period, the
result of an increase in net income of $18.6 million and higher
depreciation, depletion and amortization expense of $10.3 million,
resulting largely from increased property, plant and equipment
balances and higher mineral production rates and volumes. Partially
offsetting the increase in cash flows from operating activities were
an increase in earnings, net of distributions, from equity method
investments of $9.5 million and the absence in 2004 of the 2003
cumulative effect of an accounting change of $7.6 million.
Investing activities --
Cash flows used in investing activities in the first six months of
2004 decreased $74.3 million compared to the comparable 2003 period,
the result of a decrease in net capital expenditures (capital
expenditures; acquisitions, net of cash acquired; and net proceeds
from the sale or disposition of property) of $85.2 million and an
increase in proceeds from notes receivable of $14.2 million, offset
in part by an increase in investments of $25.1 million. Net capital
expenditures exclude the noncash transactions related to
acquisitions, including the issuance of the Company's equity
securities. The noncash transactions were $32.6 million and $4.9
million for the first six months of 2004 and 2003, respectively.
Financing activities --
Cash flows provided by financing activities in the first six months
of 2004 decreased $35.3 million compared to the comparable 2003
period, primarily the result of a decrease in the issuance of long-
term debt of $159.0 million. A decrease in repayment of long-term
debt of $58.0 million and an increase in the issuance of common
stock of $54.7 million, primarily due to net proceeds received from
an underwritten public offering, partially offset the decrease in
cash provided by financing activities.
Defined benefit pension plans
The Company has qualified noncontributory defined benefit pension
plans (Pension Plans) for certain employees. Plan assets consist of
investments in equity and fixed income securities. Various
actuarial assumptions are used in calculating the benefit expense
(income) and liability (asset) related to the Pension Plans.
Actuarial assumptions include assumptions about the discount rate,
expected return on plan assets and rate of future compensation
increases as determined by the Company within certain guidelines.
At December 31, 2003, certain Pension Plans' accumulated benefit
obligations exceeded these plans' assets by approximately
$4.3 million. Pretax pension expense (income) reflected in the
years ended December 31, 2003, 2002 and 2001, was $153,000, ($2.4)
million and ($4.4) million, respectively. The Company's pension
expense is currently projected to be approximately $4.0 million to
$5.0 million in 2004. A reduction in the Company's assumed discount
rate for Pension Plans along with declines in the equity markets
experienced in 2002 and 2001 have combined to largely produce the
increase in these costs. Funding for the Pension Plans is
actuarially determined. The minimum required contributions for
2003, 2002 and 2001 were approximately $1.6 million, $1.2 million
and $442,000, respectively. For further information on the
Company's Pension Plans, see Note 17 of Notes to Consolidated
Financial Statements.
Capital expenditures
Net capital expenditures, including the issuance of the Company's
equity securities in connection with acquisitions, for the first six
months of 2004 were $186.5 million and are estimated to be
approximately $450 million for the year 2004. Estimated capital
expenditures include those for:
- Completed acquisitions
- System upgrades
- Routine replacements
- Service extensions
- Routine equipment maintenance and replacements
- Land and building improvements
- Pipeline and gathering expansion projects
- Further enhancement of natural gas and oil production and
reserve growth
- Power generation opportunities, including certain construction
costs for a 116-megawatt coal-fired development project, as
previously discussed
- Other growth opportunities
Approximately 15 percent of estimated 2004 net capital expenditures
are for completed acquisitions. The Company continues to evaluate
potential future acquisitions and other growth opportunities;
however, they are dependent upon the availability of economic
opportunities and, as a result, capital expenditures may vary
significantly from the estimated 2004 capital expenditures referred
to above. It is anticipated that all of the funds required for
capital expenditures will be met from various sources. These
sources include internally generated funds; commercial paper credit
facilities at Centennial and MDU Resources Group, Inc., as described
below; and through the issuance of long-term debt and the Company's
equity securities.
The estimated 2004 capital expenditures referred to above include
completed 2004 acquisitions involving construction materials and
mining businesses in Idaho, Iowa and Minnesota and an independent
power production operating and development company in Colorado. Pro
forma financial amounts reflecting the effects of the above
acquisitions are not presented as such acquisitions were not
material to the Company's financial position or results of
operations.
Capital resources
Certain debt instruments of the Company and its subsidiaries,
including those discussed below, contain restrictive covenants, all
of which the Company and its subsidiaries were in compliance with at
June 30, 2004.
MDU Resources Group, Inc.
The Company has a revolving credit agreement with various banks
totaling $90 million at June 30, 2004. There were no amounts
outstanding under the credit agreement at June 30, 2004. The credit
agreement supports the Company's $75 million commercial paper
program. There were no amounts outstanding under the Company's
commercial paper program at June 30, 2004. The credit agreement
expires on July 18, 2006.
The Company's goal is to maintain acceptable credit ratings
in order to access the capital markets through the issuance
of commercial paper. If the Company were to experience a
minor downgrade of its credit ratings, it would not
anticipate any change in its ability to access the capital
markets. However, in such event, the Company would expect a
nominal basis point increase in overall interest rates with
respect to its cost of borrowings. If the Company were to
experience a significant downgrade of its credit ratings,
which it does not currently anticipate, it may need to
borrow under its credit agreement.
To the extent the Company needs to borrow under its credit
agreement, it would be expected to incur increased
annualized interest expense on its variable rate debt. This
was not applicable at June 30, 2004, as there were no
variable rate borrowings at such time.
Prior to the maturity of the credit agreement, the Company
plans to negotiate the extension or replacement of this
agreement that provides credit support to access the capital
markets. In the event the Company 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 June 30, 2004.
In the event the Company does not comply with the applicable
covenants and other conditions, alternative sources of
funding may need to be pursued, as previously described.
There are no credit facilities that contain cross-default
provisions between the Company and any of its subsidiaries.
The Company's issuance of first mortgage debt is subject to
certain restrictions imposed under the terms and conditions
of its Indenture of Mortgage. Generally, those restrictions
require the Company to fund $1.43 of unfunded property or
use $1.00 of refunded bonds for each dollar of indebtedness
incurred under the Indenture and, in some cases, to certify
to the trustee that annual earnings (pretax and before
interest charges), as defined in the Indenture, equal at
least two times its annualized first mortgage bond interest
costs. Under the more restrictive of the tests, as of June
30, 2004, the Company could have issued approximately $318
million of additional first mortgage bonds.
The Company's coverage of fixed charges including preferred
dividends was 4.7 times for the twelve months ended June 30,
2004 and December 31, 2003. Additionally, the Company's
first mortgage bond interest coverage was 6.8 times and 7.4
times for the twelve months ended June 30, 2004 and December
31, 2003, respectively. Common stockholders' equity as a
percent of total capitalization (net of long-term debt and
preferred stock due within one year) was 63 percent and 60
percent at June 30, 2004 and December 31, 2003,
respectively.
Centennial Energy Holdings, Inc.
Centennial has three revolving credit agreements with
various banks and institutions that support $300 million of
Centennial's $350 million commercial paper program. There
were no outstanding borrowings under the Centennial credit
agreements at June 30, 2004. Under the Centennial commercial
paper program, $85.5 million was outstanding at June 30,
2004. The Centennial commercial paper borrowings are
classified as long-term debt as Centennial intends to
refinance these borrowings on a long-term basis through
continued Centennial commercial paper borrowings and as
further supported by the Centennial credit agreements. One
of these credit agreements is for $137.5 million and expires
on September 3, 2004, and allows for subsequent borrowings
up to a term of one year. Another credit agreement is for
$137.5 million and expires on September 5, 2006. The other
credit agreement is for $25 million and expires on April 30,
2007. Centennial intends to negotiate the extension or
replacement of these agreements prior to their maturities.
Centennial has an uncommitted long-term master shelf
agreement that allows for borrowings of up to $400
million. Under the terms of the master shelf agreement,
$384.0 million was outstanding at June 30, 2004. To meet
potential future financing needs, Centennial may pursue
other financing arrangements, including private and/or
public financing.
Centennial's goal is to maintain acceptable credit ratings
in order to access the capital markets through the issuance
of commercial paper. If Centennial were to experience a
minor downgrade of its credit ratings, it would not
anticipate any change in its ability to access the capital
markets. However, in such event, Centennial would expect a
nominal basis point increase in overall interest rates with
respect to its cost of borrowings. If Centennial were to
experience a significant downgrade of its credit ratings,
which it does not currently anticipate, it may need to
borrow under its committed bank lines.
To the extent Centennial needs to borrow under its committed
bank lines, it would be expected to incur increased
annualized interest expense on its variable rate debt of
approximately $128,000 (after tax) based on June 30, 2004,
variable rate borrowings. Based on Centennial's overall
interest rate exposure at June 30, 2004, this change would
not have a material effect on the Company's results of
operations or cash flows.
Prior to the maturity of the Centennial credit agreements,
Centennial plans to negotiate the extension or replacement
of these agreements that provide credit support to access
the capital markets. In the event Centennial was unable to
successfully negotiate these agreements, or in the event the
fees on such facilities became too expensive, which
Centennial does not currently anticipate, it would seek
alternative funding. One source of alternative funding
might involve the securitization of certain Centennial
assets.
In order to borrow under Centennial's credit agreements and
the Centennial uncommitted long-term master shelf agreement,
Centennial and certain of its subsidiaries must be in
compliance with the applicable covenants and certain other
conditions. The significant covenants include maximum
capitalization ratios, minimum interest coverage ratios,
minimum consolidated net worth, limitation on priority debt,
limitation on sale of assets and limitation on loans and
investments. Centennial and such subsidiaries were in
compliance with these covenants and met the required
conditions at June 30, 2004. In the event Centennial or
such subsidiaries do not comply with the applicable
covenants and other conditions, alternative sources of
funding may need to be pursued as previously described.
Certain of Centennial's financing agreements contain cross-
default provisions. These provisions state that if
Centennial or any subsidiary of Centennial fails to make any
payment with respect to any indebtedness or contingent
obligation, in excess of a specified amount, under any
agreement that causes such indebtedness to be due prior to
its stated maturity or the contingent obligation to become
payable, the applicable agreements will be in default.
Certain of Centennial's financing agreements and
Centennial's practice limit the amount of subsidiary
indebtedness.
Williston Basin Interstate Pipeline Company
Williston Basin has an uncommitted long-term master shelf
agreement that allows for borrowings of up to $100 million.
Under the terms of the master shelf agreement, $55.0 million
was outstanding at June 30, 2004.
In order to borrow under Williston Basin's uncommitted long-
term master shelf agreement, it must be in compliance with
the applicable covenants and certain other conditions. The
significant covenants include limitation on consolidated
indebtedness, limitation on priority debt, limitation on
sale of assets and limitation on investments. Williston
Basin was in compliance with these covenants and met the
required conditions at June 30, 2004. In the event
Williston Basin does not comply with the applicable
covenants and other conditions, alternative sources of
funding may need to be pursued.
Off balance sheet arrangements
Centennial has unconditionally guaranteed a portion of certain bank
borrowings of MPX in connection with the Company's equity method
investment in the Brazil Generating Facility, as discussed in Note
11 of Notes to Consolidated Financial Statements. The Company,
through MDU Brasil, owns 49 percent of MPX. The main business
purpose of Centennial extending the guarantee to MPX's creditors is
to enable MPX to obtain lower borrowing costs. At June 30, 2004,
the aggregate amount of borrowings outstanding subject to these
guarantees was $40.1 million and the scheduled repayment of these
borrowings is $5.6 million in 2004, $10.7 million in 2005, 2006, and
2007 and $2.4 million in 2008. The individual investor (who through
EBX, a Brazilian company, owns 51 percent of MPX) has also
guaranteed these loans. In the event MPX defaults under its
obligation, Centennial and the individual investor would be required
to make payments under their guarantees, which are joint and several
obligations. Centennial and the individual investor have entered
into reimbursement agreements under which they have agreed to
reimburse each other to the extent they may be required to make any
guarantee payments in excess of their proportionate ownership share
in MPX. These guarantees are not reflected on the Consolidated
Balance Sheets.
As of June 30, 2004, Centennial was contingently liable for
performance of certain of its subsidiaries under approximately $290
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 on long-term debt and operating leases from those
reported in the Company's Annual Report on Form 10-K for the year
ended December 31, 2003.
The Company's contractual obligations on purchase commitments at
June 30, 2004, increased $117.6 million or 24 percent from December
31, 2003, primarily due to an increase in commitments for electric
generation construction contracts. At June 30, 2004, the Company's
contractual obligations on purchase commitments for the twelve
months ended June 30, were as follows:
2005 2006 2007 2008 2009 Thereafter Total
(In millions)
Purchase
commitments $257.8 $88.8 $55.0 $36.2 $32.6 $139.9 $610.3
For more information on contractual obligations and commercial
commitments, see Part II, Item 7 in the Company's Annual Report on
Form 10-K for the year ended December 31, 2003.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The Company is exposed to the impact of market fluctuations
associated with commodity prices, interest rates and foreign
currency. The Company has policies and procedures to assist in
controlling these market risks and utilizes derivatives to manage a
portion of its risk.
Commodity price risk --
Fidelity utilizes natural gas and oil price swap and collar
agreements to manage a portion of the market risk associated with
fluctuations in the price of natural gas and oil on its forecasted
sales of natural gas and oil production. For more information on
commodity price risk, see Part II, Item 7A in the Company's Annual
Report on Form 10-K for the year ended December 31, 2003, and Note
13 of Notes to Consolidated Financial Statements.
The following table summarizes hedge agreements entered into by
Fidelity as of June 30, 2004. These agreements call for Fidelity to
receive fixed prices and pay variable prices.
(Notional amount and fair value in thousands)
Weighted
Average Notional
Fixed Price Amount
(Per MMBtu) (In MMBtu's) Fair Value
Natural gas swap
agreements maturing
in 2004 $ 5.14 5,520 $ (5,008)
Natural gas swap
agreements maturing
in 2005 $ 5.32 7,300 $ (4,164)
Weighted
Average
Floor/Ceiling Notional
Price Amount
(Per MMBtu) (In MMBtu's) Fair Value
Natural gas collar
agreements maturing
in 2004 $4.62/$5.28 4,878 $ (4,040)
Natural gas collar
agreement maturing
in 2005 $4.92/$5.66 5,475 $ (3,256)
Weighted
Average Notional
Fixed Price Amount
(Per barrel) (In barrels) Fair Value
Oil swap agreements
maturing in 2004 $ 29.59 276 $ (1,977)
Oil swap agreement
maturing in 2005 $ 30.70 183 $ (757)
Weighted
Average
Floor/Ceiling Notional
Price Amount
(Per barrel) (In barrels) Fair Value
Oil collar agreement
maturing in 2005 $32.00/$36.50 164 $ (120)
Interest rate risk --
There were no material changes to interest rate risk faced
by the Company from those reported in the Company's Annual
Report on Form 10-K for the year ended December 31, 2003.
For more information on interest rate risk, see Part II,
Item 7A in the Company's Annual Report on Form 10-K for the
year ended December 31, 2003.
Foreign currency risk --
MDU Brasil has a 49 percent equity investment in a 220-
megawatt natural gas-fired electric generating facility in
Brazil, which has a portion of its borrowings and payables
denominated in U.S. dollars. MDU Brasil has exposure to
currency exchange risk as a result of fluctuations in
currency exchange rates between the U.S. dollar and the
Brazilian real. The functional currency for the Brazil
Generating Facility is the Brazilian real. For further
information on this investment, see Note 11 of Notes to
Consolidated Financial Statements.
MDU Brasil's equity income from this Brazilian investment is
impacted by fluctuations in currency exchange rates on
transactions denominated in a currency other than the
Brazilian real, including the effects of changes in currency
exchange rates with respect to the Brazil Generating
Facility's U.S. dollar denominated obligations. At June 30,
2004, these U.S. dollar denominated obligations approximated
$80.4 million. If, for example, the value of the Brazilian
real decreased in relation to the U.S. dollar by 10 percent,
MDU Brasil, with respect to its interest in the Brazil
Generating Facility, would record a foreign currency loss in
net income of approximately $3.6 million (after tax) based
on the above U.S. dollar denominated obligations at June 30,
2004.
The investment of Centennial International in the Brazil
Generating Facility at June 30, 2004, was approximately
$13.8 million.
A portion of the Brazil Generating Facility's foreign
currency exchange risk is being managed through contractual
provisions, which are largely indexed to the U.S. dollar,
contained in the Brazil Generating Facility's power purchase
agreement with Petrobras. The Brazil Generating Facility
has also historically used derivative instruments to manage
a portion of its foreign currency risk and may utilize such
instruments in the future.
ITEM 4. CONTROLS AND PROCEDURES
The following information includes the evaluation of
disclosure controls and procedures by the Company's chief
executive officer and the chief financial officer, along
with any significant changes in internal controls of the
Company.
Evaluation of disclosure controls and procedures
The term "disclosure controls and procedures" is defined in
Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act
of 1934 (Exchange Act). These rules refer to the controls
and other procedures of a company that are designed to
ensure that information required to be disclosed by a
company in the reports it files under the Exchange Act is
recorded, processed, summarized and reported within required
time periods. The Company's chief executive officer and
chief financial officer have evaluated the effectiveness of
the Company's disclosure controls and procedures and they
have concluded that, as of the end of the period covered by
this report, such controls and procedures were effective to
accomplish those tasks.
Changes in internal control over financial reporting
The Company maintains a system of internal accounting
controls designed to provide reasonable assurance that the
Company's transactions are properly authorized, the
Company's assets are safeguarded against unauthorized or
improper use, and the Company's transactions are properly
recorded and reported to permit preparation of the Company's
financial statements in conformity with generally accepted
accounting principles in the United States of America.
There were no changes in the Company's internal control over
financial reporting that occurred during the period covered
by this report that have materially affected, or are
reasonably likely to materially affect, the Company's
internal control over financial reporting.
PART II -- OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
On June 4, 2004, following preliminary discovery, Williston Basin
and Montana-Dakota joined with other defendants and filed a Motion
to Dismiss in the Grynberg case.
For more information on the above legal action, see Note 19 of Notes
to Consolidated Financial Statements, which is incorporated by
reference.
ITEM 2. CHANGES IN SECURITIES AND USE OF PROCEEDS
Between April 1, 2004 and June 30, 2004, the Company issued 663,768
shares of Common Stock, $1.00 par value, and the Preference Share
Purchase Rights appurtenant thereto, as part of the consideration
paid by the Company for all of the issued and outstanding capital
stock with respect to businesses acquired during this period. The
Common Stock and Rights issued by the Company in these transactions
were issued in a private transaction exempt from registration under
the Securities Act of 1933 pursuant to Section 4(2) thereof, Rule
506 promulgated thereunder, or both. The classes of persons to whom
these securities were sold were either accredited investors or other
persons to whom such securities were permitted to be offered under
the applicable exemption.
The following table includes information with respect to the
Issuer's purchase of equity securities:
(a) (b) (c) (d)
Maximum Number (or
Total Total Number of Approximate Dollar
Number of Average Shares (or Units) Value) of Shares (or
Shares Price Purchased as Part Units) that May Yet
(or Units) Paid of Publicly Be Purchased Under
Purchased per Share Announced Plans the Plans or
Period (1) (or Unit) or Programs (2) Programs (2)
January 1 to
January 31, 2004
February 1 to
February 29, 2004 29,662 $23.72
March 1 to
March 31, 2004 1,863 $23.78
April 1 to
April 30, 2004
May 1 to
May 31, 2004
June 1 to
June 30, 2004 12,333 $22.81
Total 43,858
(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 6. EXHIBITS AND REPORTS ON FORM 8-K
a) Exhibits
10(a) Change of Control Employment Agreement between the
Company and Paul Gatzemeier
10(b) Change of Control Employment Agreement between the
Company and Mary B. Hager
10(c) Change of Control Employment Agreement between the
Company and Bruce T. Imsdahl
10(d) Change of Control Employment Agreement between the
Company and Cindy C. Redding
10(e) Change of Control Employment Agreement between the
Company and Paul K. Sandness
10(f) Change of Control Employment Agreement between the
Company and Daryl A. Splichal
10(g) Change of Control Employment Agreement between the
Company and Floyd E. Wilson
10(h) Non-Employee Director Stock Compensation Plan, as amended
12 Computation of Ratio of Earnings to Fixed Charges and
Combined Fixed Charges and Preferred Stock Dividends
31(a) Certification of Chief Executive Officer filed pursuant
to Section 302 of the Sarbanes-Oxley Act of 2002
31(b) Certification of Chief Financial Officer filed pursuant
to Section 302 of the Sarbanes-Oxley Act of 2002
32 Certification of Chief Executive Officer and Chief
Financial Officer furnished pursuant to 18 U.S.C. Section
1350, as adopted pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002
b) Reports on Form 8-K
Form 8-K was filed on April 20, 2004. Under Item 12 -- Results
of Operations and Financial Condition, the Company reported the
press release issued April 20, 2004, regarding earnings for the
quarter ended March 31, 2004.
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of
1934, the registrant has duly caused this report to be signed on its
behalf by the undersigned thereunto duly authorized.
MDU RESOURCES GROUP, INC.
DATE: August 6, 2004 BY: /s/ Warren L. Robinson
Warren L. Robinson
Executive Vice President
and Chief Financial Officer
BY: /s/ Vernon A. Raile
Vernon A. Raile
Senior Vice President
and Chief Accounting Officer
EXHIBIT INDEX
Exhibit No.
10(a) Change of Control Employment Agreement between the Company
and Paul Gatzemeier
10(b) Change of Control Employment Agreement between the Company
and Mary B. Hager
10(c) Change of Control Employment Agreement between the Company
and Bruce T. Imsdahl
10(d) Change of Control Employment Agreement between the Company
and Cindy C. Redding
10(e) Change of Control Employment Agreement between the Company
and Paul K. Sandness
10(f) Change of Control Employment Agreement between the Company
and Daryl A. Splichal
10(g) Change of Control Employment Agreement between the Company
and Floyd E. Wilson
10(h) Non-Employee Director Stock Compensation Plan, as amended
12 Computation of Ratio of Earnings to Fixed Charges
and Combined Fixed Charges and Preferred Stock
Dividends
31(a) Certification of Chief Executive Officer filed pursuant to
Section 302 of the Sarbanes-Oxley Act of 2002
31(b) Certification of Chief Financial Officer filed pursuant to
Section 302 of the Sarbanes-Oxley Act of 2002
32 Certification of Chief Executive Officer and Chief Financial
Officer furnished pursuant to 18 U.S.C. Section 1350, as
adopted pursuant to Section 906 of the Sarbanes-Oxley Act of
2002