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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, 2002
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 the number of shares outstanding of each of the
issuer's classes of common stock, as of August 6, 2002: 71,441,275
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 should be read with the cautionary
statements and important factors included in this Form 10-Q at Item
2 -- Management's Discussion and Analysis of Financial Condition and
Results of Operations -- Safe Harbor for Forward-looking Statements.
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.
MDU Resources Group, Inc. (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.
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) and Centennial Holdings Capital Corp.
(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 and provides energy-
related marketing and management services, as well as cable
and pipeline locating services. The natural gas and oil
production segment is engaged in natural gas and oil
acquisition, exploration and production activities
primarily in the Rocky Mountain region of the United States
and in the Gulf of Mexico.
Knife River mines aggregates and markets crushed stone,
sand, gravel and other related construction materials,
including ready-mixed concrete, cement and asphalt, as well
as value-added products and services in the north central
and western United States, including Alaska and Hawaii.
Utility Services is a diversified infrastructure company
specializing in engineering, design and build capability for
electric, gas and telecommunication utility construction, as
well as industrial and commercial electrical, exterior
lighting and traffic signalization throughout most of the
United States. Utility Services also provides related
specialty equipment manufacturing, sales and rental
services.
Centennial Capital invests in new growth and synergistic
opportunities, including independent power production, which
are not directly being pursued by the existing business
units but which are consistent with the Company's philosophy
and growth strategy. These activities are reflected in the
pipeline and energy services segment.
The Company, through its wholly owned subsidiary, MDU Resources
International, Inc. (MDU International), invests in projects
outside the United States which are consistent with the Company's
philosophy, growth strategy and areas of expertise. These
activities are reflected in the pipeline and energy services
segment.
INDEX
Part I -- Financial Information
Consolidated Statements of Income --
Three and Six Months Ended June 30, 2002 and 2001
Consolidated Balance Sheets --
June 30, 2002 and 2001, and December 31, 2001
Consolidated Statements of Cash Flows --
Six Months Ended June 30, 2002 and 2001
Consolidated Statements of Comprehensive Income --
Three and Six Months Ended June 30, 2002 and 2001
Notes to Consolidated Financial Statements
Management's Discussion and Analysis of Financial
Condition and Results of Operations
Quantitative and Qualitative Disclosures About Market Risk
Part II -- Other Information
Signatures
Exhibit Index
Exhibits
PART I -- FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
MDU RESOURCES GROUP, INC.
CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
Three Months Six Months
Ended Ended
June 30, June 30,
2002 2001 2002 2001
(In thousands, except per share amounts)
Operating revenues $480,218 $546,418 $862,153 $1,187,665
Operating expenses:
Fuel and purchased power 13,124 14,633 27,068 27,721
Purchased natural gas sold 19,781 139,783 55,476 465,554
Operation and maintenance 342,376 273,562 577,890 466,376
Depreciation, depletion and amortization 37,845 34,476 73,948 66,531
Taxes, other than income 15,897 13,617 30,779 27,615
429,023 476,071 765,161 1,053,797
Operating income 51,195 70,347 96,992 133,868
Other income -- net 1,230 12,202 4,819 14,561
Interest expense 10,977 10,998 21,522 22,712
Income before income taxes 41,448 71,551 80,289 125,717
Income taxes 16,595 28,134 31,714 49,614
Net income 24,853 43,417 48,575 76,103
Dividends on preferred stocks 189 191 378 381
Earnings on common stock $ 24,664 $ 43,226 $ 48,197 $ 75,722
Earnings per common share -- basic $ .35 $ .64 $ .69 $ 1.14
Earnings per common share -- diluted $ .35 $ .63 $ .68 $ 1.13
Dividends per common share $ .23 $ .22 $ .46 $ .44
Weighted average common shares
outstanding -- basic 70,456 67,264 69,965 66,339
Weighted average common shares
outstanding -- diluted 71,027 68,376 70,502 67,173
The accompanying notes are an integral part of these consolidated statements.
MDU RESOURCES GROUP, INC.
CONSOLIDATED BALANCE SHEETS
(Unaudited)
June 30, June 30, December 31,
2002 2001 2001
(In thousands, except shares
and per share amount)
ASSETS
Current assets:
Cash and cash equivalents $ 48,350 $ 30,799 $ 41,811
Receivables, net 312,115 316,640 285,081
Inventories 83,565 81,096 95,341
Deferred income taxes 16,534 12,924 18,973
Prepayments and other current assets 71,728 33,880 40,286
532,292 475,339 481,492
Investments 36,910 37,402 38,198
Property, plant and equipment 2,883,268 2,612,574 2,738,612
Less accumulated depreciation,
depletion and amortization 1,007,905 888,582 946,470
1,875,363 1,723,992 1,792,142
Deferred charges and other assets
Goodwill 182,021 125,661 173,997
Other intangible assets, net 85,409 69,500 76,234
Other 62,784 46,764 61,008
330,214 241,925 311,239
$2,774,779 $2,478,658 $2,623,071
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Short-term borrowings $ 4,500 $ --- $ ---
Long-term debt and preferred
stock due within one year 15,442 9,531 11,185
Accounts payable 124,560 155,857 110,649
Taxes payable 11,747 6,944 11,826
Dividends payable 16,617 15,157 16,108
Other accrued liabilities 91,395 77,889 95,559
264,261 265,378 245,327
Long-term debt 834,900 748,646 783,709
Deferred credits and other liabilities:
Deferred income taxes 355,720 317,611 342,412
Other liabilities 139,125 114,589 125,552
494,845 432,200 467,964
Preferred stock subject to mandatory
redemption 1,300 1,400 1,300
Commitments and contingencies
Stockholders' equity:
Preferred stocks 15,000 15,000 15,000
Common stockholders' equity:
Common stock (Shares issued --
$1.00 par value, 71,664,751
at June 30, 2002, 68,273,213 at
June 30, 2001 and 70,016,851 at
December 31, 2001) 71,665 68,273 70,017
Other paid-in capital 688,812 601,527 646,521
Retained earnings 410,224 346,845 394,641
Accumulated other comprehensive
income (loss) (2,602) 3,015 2,218
Treasury stock at cost - 239,521
shares (3,626) (3,626) (3,626)
Total common stockholders' equity 1,164,473 1,016,034 1,109,771
Total stockholders' equity 1,179,473 1,031,034 1,124,771
$2,774,779 $2,478,658 $2,623,071
The accompanying notes are an integral part of these consolidated statements.
MDU RESOURCES GROUP, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Six Months Ended
June 30,
2002 2001
(In thousands)
Operating activities:
Net income $ 48,575 $ 76,103
Adjustments to reconcile net income to net cash provided
by operating activities:
Depreciation, depletion and amortization 73,948 66,531
Deferred income taxes and investment tax credit 4,870 5,185
Changes in current assets and liabilities, net of
acquisitions:
Receivables (17,220) 55,132
Inventories 14,325 (14,446)
Other current assets (31,198) 513
Accounts payable 9,898 (31,124)
Other current liabilities (4,804) 9,734
Other noncurrent changes 552 (7,154)
Net cash provided by operating activities 98,946 160,474
Investing activities:
Capital expenditures (114,020) (143,234)
Acquisitions, net of cash acquired (14,963) (39,777)
Net proceeds from sale or disposition of property 4,402 33,728
Investments 1,288 3,556
Proceeds from notes receivable 4,000 4,000
Net cash used in investing activities (119,293) (141,727)
Financing activities:
Net change in short-term borrowings 4,500 (8,000)
Issuance of long-term debt 78,237 62,109
Repayment of long-term debt (23,037) (75,673)
Proceeds from issuance of common stock, net 178 27,009
Dividends paid (32,992) (29,905)
Net cash provided by (used in) financing activities 26,886 (24,460)
Increase (decrease) in cash and cash equivalents 6,539 (5,713)
Cash and cash equivalents -- beginning of year 41,811 36,512
Cash and cash equivalents -- end of period $ 48,350 $ 30,799
The accompanying notes are an integral part of these consolidated statements.
MDU RESOURCES GROUP, INC.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Unaudited)
Three Months Ended
June 30,
2002 2001
(In thousands)
Net income $ 24,853 $ 43,417
Other comprehensive income (loss):
Net unrealized gain on derivative
instruments qualifying as hedges, net of tax 1,610 4,018
Minimum pension liability adjustment, net of tax (4,340) ---
(2,730) 4,018
Total comprehensive income $ 22,123 $ 47,435
Six Months Ended
June 30,
2002 2001
(In thousands)
Net income $ 48,575 $ 76,103
Other comprehensive income (loss):
Net unrealized gain (loss) on derivative
instruments qualifying as hedges, net of tax (480) 3,015
Minimum pension liability adjustment, net of tax (4,340) ---
(4,820) 3,015
Total comprehensive income $ 43,755 $ 79,118
The accompanying notes are an integral part of these consolidated statements.
MDU RESOURCES GROUP, INC.
NOTES TO CONSOLIDATED
FINANCIAL STATEMENTS
June 30, 2002 and 2001
(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, 2001 (2001 Annual Report), and the standards of
accounting measurement set forth in Accounting Principles Board
Opinion No. 28 and any amendments thereto adopted by the
Financial Accounting Standards Board. 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 2001 Annual Report. The information is
unaudited but includes all adjustments which are, in the
opinion of management, necessary for a fair presentation of the
accompanying consolidated interim financial statements.
2. Allowance for doubtful accounts
The Company's allowance for doubtful accounts as of
June 30, 2002 and 2001, and December 31, 2001 was $8.4 million,
$4.3 million and $5.8 million, respectively.
3. Seasonality of operations
Some of the Company's operations are highly seasonal and
revenues from, and certain expenses for, such operations may
fluctuate significantly among quarterly periods. Accordingly,
the interim results for particular segments, and for the
Company as a whole, may not be indicative of results for the
full fiscal year.
4. Cash flow information
Cash expenditures for interest and income taxes were as
follows:
Six Months Ended
June 30,
2002 2001
(In thousands)
Interest, net of amount capitalized $ 19,236 $20,399
Income taxes $ 40,589 $45,754
5. Reclassifications
Certain reclassifications have been made in the financial
statements for the prior period to conform to the current
presentation. Such reclassifications had no effect on net
income or stockholders' equity as previously reported.
6. New accounting standards
In June 2001, the Financial Accounting Standards Board
(FASB) approved Statement of Financial Accounting Standards No.
143, "Accounting for Asset Retirement Obligations" (SFAS No.
143). SFAS No. 143 requires entities to record the fair value
of a liability for an asset retirement obligation in the period
in which it is incurred. When the liability is initially
recorded, the entity capitalizes a cost by increasing the
carrying amount of the related long-lived asset. Over time,
the liability is accreted to its present value each period, and
the capitalized cost is depreciated over the useful life of the
related asset. Upon settlement of the liability, an entity
either settles the obligation for the recorded amount or incurs
a gain or loss upon settlement. SFAS No. 143 is effective for
fiscal years beginning after June 15, 2002. The Company will
adopt SFAS No. 143 on January 1, 2003, but has not yet
quantified the effects of adopting SFAS No. 143 on its
financial position or results of operations.
In April 2002, the FASB approved Statement of Financial
Accounting Standards No. 145, "Rescission of FASB Statements
No. 4, 44 and 64, Amendment of FASB Statement No. 13, and
Technical Corrections" (SFAS No. 145). FASB No. 4 required all
gains or losses from extinguishment of debt to be classified as
extraordinary items net of income taxes. SFAS No. 145 requires
that gains and losses from extinguishment of debt be evaluated
under the provisions of Accounting Principles Board Opinion No.
30, and be classified as ordinary items unless they are unusual
or infrequent or meet the specific criteria for treatment as an
extraordinary item. SFAS No. 145 is effective for fiscal
years beginning after May 15, 2002. The Company has not yet
quantified the effects of adopting SFAS No. 145 on its
financial position or results of operations.
In June 2002, the Emerging Issues Task Force (EITF)
adopted the position in EITF Issue No. 02-3, "Recognition and
Reporting of Gains and Losses on Energy Trading Contracts under
EITF Issues No. 98-10, 'Accounting for Contracts Involved in
Energy Trading and Risk Management Activities,' and No. 00-17,
'Measuring the Fair Value of Energy-Related Contracts in
Applying Issue No. 98-10'" (EITF No. 02-3) that mark-to-market
gains and losses on energy trading contracts should be reported
net in the income statement whether or not settled physically in
financial statements issued for periods ending after July 15, 2002.
EITF No. 02-3 states that all comparative financial statements
should be reclassified to conform to this consensus. Although
this new accounting guidance will require the Company's mark-to-
market gains and losses on energy trading contracts to be shown
net on the income statement, it is not expected to impact the
overall financial position or results of operations of the Company.
The Company will apply this consensus to financial statements issued
for periods ending after July 15, 2002, but has not yet quantified
the financial statement effect from this guidance.
In June 2002, the FASB approved Statement of Financial
Accounting Standards No. 146, "Accounting for Costs Associated
with Exit or Disposal Activities" (SFAS No. 146). SFAS No. 146
addresses financial accounting and reporting for costs
associated with exit or disposal activities and nullifies EITF
Issue No. 94-3, "Liability Recognition for Certain Employee
Termination Benefits and Other Costs to Exit an Activity
(including Certain Costs Incurred in a Restructuring)" (EITF
No. 94-3). SFAS No. 146 requires recognition of a liability
for a cost associated with an exit or disposal activity when
the liability is incurred, as opposed to when the entity
commits to an exit plan under EITF No. 94-3. SFAS No. 146 is to
be applied prospectively to exit or disposal activities
initiated after December 31, 2002. The Company has not yet
determined the effect, if any, of the adoption of SFAS No. 146.
7. Derivative instruments
The Company utilizes derivative instruments, including
natural gas and oil price swap and natural gas collar
agreements, to manage a portion of the market risk associated
with fluctuations in the price of natural gas and oil on the
Company's forecasted sales of natural gas and oil production.
The following information should be read in conjunction with
Note 3 in the Company's Notes to Consolidated Financial
Statements in the 2001 Annual Report.
For the three months and six months ended June 30, 2002
and 2001, the amount of hedge ineffectiveness recognized was
immaterial. For the three months and six months ended June 30,
2002 and 2001, the Company 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.
As of June 30, 2002, the maximum length of time over which
the Company is hedging its exposure to the variability in
future cash flows for forecasted transactions is 18 months.
The Company estimates that net gains of approximately $2.1
million will be reclassified from accumulated other
comprehensive income into earnings, subject to changes in
natural gas and oil market prices, as the hedged transactions
affect earnings within the twelve months between July 1, 2002
and June 30, 2003.
8. Comprehensive income
On January 1, 2001, the Company recorded a cumulative-
effect adjustment in accumulated other comprehensive loss to
recognize all derivative instruments designated as hedges at
fair value. As of June 30, 2002 and 2001, the Company has
recorded unrealized gains and losses on natural gas and oil
price swap and collar agreements and an interest rate swap
agreement which qualify for hedge accounting. As of June 30,
2002, the Company also recorded a minimum pension liability
adjustment. These amounts are reflected in the following
table.
The Company's comprehensive income, and the components of
other comprehensive income, net of taxes, were as follows:
Three Months Ended
June 30,
2002 2001
(In thousands)
Net income $ 24,853 $ 43,417
Other comprehensive income (loss) --
Net unrealized gain on derivative
instruments qualifying as hedges:
Net unrealized gain on derivative
instruments arising during the
period, net of tax of $1,110 and
$2,413 in 2002 and 2001, respectively 1,700 3,755
Less: Reclassification adjustment for
gain (loss) on derivative instruments
included in net income, net of
tax of $58 and $172 in
2002 and 2001, respectively 90 (263)
Net unrealized gain on derivative
instruments qualifying as hedges 1,610 4,018
Minimum pension liability adjustment,
net of tax of $2,781 (4,340) ---
(2,730) 4,018
Comprehensive income $ 22,123 $ 47,435
Six Months Ended
June 30,
2002 2001
(In thousands)
Net income $ 48,575 $ 76,103
Other comprehensive income (loss) --
Net unrealized gain (loss) on derivative
instruments qualifying as hedges:
Unrealized loss on derivative
instruments at January 1, 2001,
due to cumulative effect of a
change in accounting principle,
net of tax of $3,970 --- (6,080)
Net unrealized gain on derivative
instruments arising during the
period, net of tax of $574 and
$3,428 in 2002 and 2001, respectively 880 5,309
Less: Reclassification adjustment for
gain (loss) on derivative instruments
included in net income, net of
tax of $888 and $2,472 in
2002 and 2001, respectively 1,360 (3,786)
Net unrealized gain (loss) on derivative
instruments qualifying as hedges (480) 3,015
Minimum pension liability adjustment,
net of tax of $2,781 (4,340) ---
(4,820) 3,015
Comprehensive income $ 43,755 $ 79,118
9. Goodwill and other intangible assets
In June 2001, the FASB approved Statement of Financial
Accounting Standards No. 142, "Goodwill and Other Intangible
Assets" (SFAS No. 142). SFAS No. 142 changes the accounting
for goodwill and intangible assets and requires that goodwill
no longer be amortized but be tested for impairment at least
annually at the reporting unit level in accordance with SFAS
No. 142. Recognized intangible assets with determinable useful
lives should be amortized over their useful life and reviewed
for impairment in accordance with Statement of Financial
Accounting Standards No. 144, "Accounting for the Impairment or
Disposal of Long-Lived Assets" (SFAS No. 144). The provisions of
SFAS No. 142 are effective for fiscal years beginning after
December 15, 2001, except for provisions related to the
nonamortization and amortization of goodwill and intangible
assets acquired after June 30, 2001, which were subject
immediately to the provisions of SFAS No. 142. The Company
adopted SFAS No. 142 on January 1, 2002. SFAS No. 142
requires a transitional goodwill impairment test at each
reporting unit within six months of the date of adoption of
SFAS No. 142. However, the amounts used in the transitional
goodwill impairment testing shall be measured as of January 1,
2002. The Company completed its transitional goodwill impairment
testing and determined that no impairment exists as of January 1,
2002. Therefore, no impairment loss has been recorded for the
three months and six months ended June 30, 2002, in connection
with the adoption of SFAS No. 142.
On January 1, 2002, in accordance with SFAS No. 142, the
Company ceased amortization of its goodwill recorded in
business combinations which occurred on or before June 30,
2001. The following information is presented as if SFAS No.
142 was adopted as of January 1, 2001. The reconciliation of
previously reported earnings and earnings per share to the
amounts adjusted for the exclusion of goodwill amortization net
of the related income tax effect is as follows:
Three Months Ended
June 30,
2002 2001
(In thousands, except
per share amounts)
Reported earnings on common stock $ 24,664 $43,226
Add: Goodwill amortization, net of tax --- 913
Adjusted earnings on common stock $ 24,664 $44,139
Reported earnings per common
share -- basic $ .35 $ .64
Add: Goodwill amortization, net of tax --- .02
Adjusted earnings per common
share -- basic $ .35 $ .66
Reported earnings per common
share -- diluted $ .35 $ .63
Add: Goodwill amortization, net of tax --- .02
Adjusted earnings per common
share -- diluted $ .35 $ .65
Six Months Ended
June 30,
2002 2001
(In thousands, except
per share amounts)
Reported earnings on common stock $ 48,197 $75,722
Add: Goodwill amortization, net of tax --- 1,793
Adjusted earnings on common stock $ 48,197 $77,515
Reported earnings per common
share -- basic $ .69 $ 1.14
Add: Goodwill amortization, net of tax --- .03
Adjusted earnings per common
share -- basic $ .69 $ 1.17
Reported earnings per common
share -- diluted $ .68 $ 1.13
Add: Goodwill amortization, net of tax --- .02
Adjusted earnings per common
share -- diluted $ .68 $ 1.15
The changes in the carrying amount of goodwill for the six
months ended June 30, 2002, by business segment are as follows:
Net
Balance Goodwill Balance
as of Acquired as of
January 1, During June 30,
2002 the Year 2002
(In thousands)
Electric $ --- $ --- $ ---
Natural gas
distribution --- --- ---
Utility services 61,909 (738) 61,171
Pipeline and energy
services 9,336 158 9,494
Natural gas and oil
production --- --- ---
Construction materials
and mining 102,752 8,604 111,356
Total $173,997 $ 8,024 $182,021
Included in other intangible assets on the Company's
Consolidated Balance Sheets are the following:
June 30, June 30, December 31,
2002 2001 2001
(In thousands)
Amortizable intangible
assets:
Leasehold rights $ 79,005 $ 65,580 $ 72,955
Accumulated amortization (1,524) (868) (1,149)
77,481 64,712 71,806
Noncompete agreements 12,090 12,030 12,034
Accumulated amortization (9,096) (8,456) (8,811)
2,994 3,574 3,223
Other 5,149 1,347 1,377
Accumulated amortization (215) (133) (172)
4,934 1,214 1,205
Total $ 85,409 $ 69,500 $ 76,234
Amortization expense for intangible assets for the three
months and six months ended June 30, 2002, was approximately
$472,000 and $703,000, respectively. Estimated amortization
expense for intangible assets is $2.3 million in 2002, $2.6
million in 2003, $2.3 million in 2004, $2.3 million in 2005,
$2.3 million in 2006 and $74.3 million thereafter.
10. Common stock
At the Annual Meeting of Stockholders held on April 23,
2002, the Company's common stockholders approved an amendment
to the Certificate of Incorporation increasing the authorized
number of common shares from 150 million shares to 250 million
shares with a par value of $1.00 per share.
11. 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's operations are conducted through six
business segments. The vast majority of the Company's
operations are located within the United States. The Company
also has investments in foreign countries, which largely
consists of an investment in a natural gas fired electric
generating station in Brazil. The electric segment generates,
transmits and distributes electricity and the natural gas
distribution segment distributes natural gas. These operations
also supply related value-added products and services in the
northern Great Plains. The utility services segment consists
of a diversified infrastructure company specializing in
engineering, design and build capability for electric, gas and
telecommunication utility construction, as well as industrial
and commercial electrical, exterior lighting and traffic
signalization throughout most of the United States. Utility
services provides related specialty equipment manufacturing
sales and rental services. The pipeline and energy services
segment provides natural gas transportation, underground
storage and gathering services through regulated and
nonregulated pipeline systems primarily in the Rocky Mountain
and northern Great Plains regions of the United States. Energy-
related marketing and management services as well as cable and
pipeline locating services also are provided. The pipeline and
energy services segment includes investments in domestic and
international growth opportunities. The natural gas and oil
production segment is engaged in natural gas and oil
acquisition, exploration and production activities primarily in
the Rocky Mountain region of the United States and in the Gulf
of Mexico. The construction materials and mining segment mines
aggregates and markets crushed stone, sand, gravel and other
related construction materials, including ready-mixed concrete,
cement and asphalt, as well as value-added products and
services in the north central and western United States,
including Alaska and Hawaii.
In 2001, the Company sold its coal operations to
Westmoreland Coal Company for $28.2 million in cash, including
final settlement cost adjustments. The sale of the coal
operations was effective April 30, 2001. Included in the sale
were active coal mines in North Dakota and Montana, coal sales
agreements, reserves and mining equipment, and certain
development rights at the former Gascoyne Mine site in North
Dakota. The Company retains ownership of coal reserves and
leases at its former Gascoyne Mine site. The Company recorded
a gain of $11.0 million ($6.6 million after tax) included in
other income - net on the Company's Consolidated Statements of
Income from the sale in the second quarter of 2001.
Segment information follows the same accounting policies
as described in Note 1 of the Company's 2001 Annual Report.
Segment information included in the accompanying Consolidated
Statements of Income is as follows:
Inter-
External segment Earnings
Operating Operating on Common
Revenues Revenues Stock
(In thousands)
Three Months
Ended June 30, 2002
Electric $ 36,292 $ --- $ 1,673
Natural gas distribution 34,120 --- (815)
Utility services 116,344 --- 834
Pipeline and energy
services 36,110 9,267 2,750
Natural gas and oil
production 27,775 15,989 9,341
Construction materials
and mining 229,577 --- 10,881
Intersegment eliminations --- (25,256) ---
Total $ 480,218 $ --- $ 24,664
Three Months
Ended June 30, 2001
Electric $ 38,036 $ --- $ 2,152
Natural gas distribution 41,246 --- (1,547)
Utility services 77,183 --- 3,873
Pipeline and energy
services 147,111 7,432 3,383
Natural gas and oil
production 40,517 14,884 17,888
Construction materials
and mining 201,153 1,172* 17,477
Intersegment eliminations --- (22,316) ---
Total $ 545,246 $ 1,172* $ 43,226
* In accordance with the provisions of Statement of Financial
Accounting Standards No. 71, "Accounting for the Effects of
Regulation" (SFAS No. 71), intercompany coal sales are not
eliminated.
Inter-
External segment Earnings
Operating Operating on Common
Revenues Revenues Stock
(In thousands)
Six Months
Ended June 30, 2002
Electric $ 76,362 $ --- $ 5,164
Natural gas distribution 105,832 --- 3,701
Utility services 224,631 --- 2,184
Pipeline and energy
services 55,910 32,017 5,577
Natural gas and oil
production 76,509 29,663 30,411
Construction materials
and mining 322,909 --- 1,160
Intersegment eliminations --- (61,680) ---
Total $ 862,153 $ --- $ 48,197
Six Months
Ended June 30, 2001
Electric $ 80,989 $ --- $ 6,959
Natural gas distribution 182,100 --- 1,127
Utility services 144,502 4 5,917
Pipeline and energy
services 395,387 28,806 5,761
Natural gas and oil
production 89,732 37,301 45,920
Construction materials
and mining 289,939 5,016* 10,038
Intersegment eliminations --- (66,111) ---
Total $1,182,649 $ 5,016* $ 75,722
* In accordance with the provisions of SFAS No. 71,
intercompany coal sales are not eliminated.
On April 1, 2000, Fidelity Exploration & Production
Company (Fidelity), an indirect wholly owned subsidiary of the
Company, purchased substantially all of the assets of Preston
Reynolds & Co., Inc. (Preston), a coalbed natural gas
development operation based in Colorado with related oil and
gas leases and properties in Montana and Wyoming. Pursuant to
the asset purchase and sale agreement, Preston could, but was
not obligated to purchase, acquire and own an undivided 25
percent working interest (Seller's Option Interest) in certain
oil and gas leases or properties acquired and/or generated by
Fidelity. Fidelity had the right, but not the obligation, to
purchase Seller's Option Interest for an amount as specified in
the agreement. On July 10, 2002, Fidelity purchased the
Seller's Option Interest.
12. Acquisitions
During the first six months of 2002, the Company acquired
construction materials and mining businesses in Minnesota and
Montana, an energy development company in Montana and a utility
services company in California, none of which was individually
material. The total purchase consideration for these
businesses, consisting of the Company's common stock and cash,
was $56.8 million.
The above acquisitions were accounted for under the
purchase method of accounting and accordingly, the acquired
assets and liabilities assumed have been preliminarily recorded
at their respective fair values as of the date of acquisition.
Final fair market values are pending the completion of the
review of the relevant assets, liabilities and issues
identified as of the acquisition date. The results of
operations of the acquired businesses are included in the
financial statements since the date of each acquisition. Pro
forma financial amounts reflecting the effects of the above
acquisitions are not presented as such acquisitions were not
material to the Company's financial position or results of
operations.
13. Regulatory matters and revenues subject to refund
On June 10, 2002, Montana-Dakota filed with the Wyoming
Public Service Commission (WYPSC) for a natural gas rate
increase. The Company is requesting a total of $662,000
annually or 5.6 percent above current rates.
On May 20, 2002, Montana-Dakota filed with the Montana
Public Service Commission (MTPSC) for a natural gas rate
increase. The Company is requesting a total of $3.6 million
annually or 6.5 percent above current rates.
On April 12, 2002, Montana-Dakota filed with the North
Dakota Public Service Commission (NDPSC) for a natural gas rate
increase. The Company is requesting a total of $2.8 million
annually or 4.1 percent above current rates.
The NDPSC authorized its Staff to initiate an
investigation into the earnings levels of Montana-Dakota's
North Dakota electric operations based on Montana-Dakota's 2000
Annual Report to the NDPSC. The investigation was based on a
complaint filed with the NDPSC on September 7, 2001, by the
NDPSC Staff. On April 24, 2002, the NDPSC issued an Order
requiring Montana-Dakota to reduce its North Dakota electric
rates by $4.3 million annually, effective May 8, 2002. On
April 25, 2002, Montana-Dakota filed an appeal of the NDPSC
Order in the North Dakota South Central Judicial District Court
(District Court). The filing also requested a stay of the
effectiveness of the NDPSC Order while the appeal is pending.
Montana-Dakota is challenging the NDPSC's determination of the
level of electricity sales to other utilities expected to be
received by Montana-Dakota. On May 2, 2002, the District Court
granted Montana-Dakota's request for a stay of a portion of the
$4.3 million annual rate reduction ordered by the NDPSC.
Accordingly, Montana-Dakota implemented an annual rate
reduction of $800,000 effective with service rendered on and
after May 8, 2002, rather than the $4.3 million annual
reduction ordered by the NDPSC. The remaining $3.5 million is
subject to refund if Montana-Dakota does not prevail in this
proceeding.
Reserves have been provided for the revenues that have
been collected subject to refund with respect to Montana-
Dakota's pending electric rate reduction.
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 issued an initial decision on
Williston Basin's natural gas rate change application, which
matter is currently pending before and subject to revision by
the FERC.
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.
14. Litigation
In January 2002, Fidelity Oil Co. (FOC), one of the
Company's natural gas and oil production subsidiaries, entered
into a compromise agreement with the former operator of certain
of FOC's oil production properties in southeastern Montana.
The compromise agreement resolved litigation involving the
interpretation and application of contractual provisions
regarding net proceeds interests paid by the former operator to
FOC for a number of years prior to 1998. The terms of the
compromise agreement are confidential. As a result of the
compromise agreement, the natural gas and oil production
segment reflected a nonrecurring gain in its financial results
for the first quarter of 2002 of approximately $16.6 million
after-tax. As part of the settlement, FOC gave the former
operator a full and complete release, and FOC is not asserting
any such claim against the former operator for periods after
1997.
In March 1997, 11 natural gas producers filed suit in
North Dakota Southwest Judicial District Court (North Dakota
District Court) against Williston Basin and the Company. The
natural gas producers had processing agreements with Koch
Hydrocarbon Company (Koch). Williston Basin and the Company
had natural gas purchase contracts with Koch. The natural gas
producers alleged they were entitled to damages for the breach
of Williston Basin's and the Company's contracts with Koch
although no specific damages were stated. A similar suit was
filed by Apache Corporation (Apache) and Snyder Oil Corporation
(Snyder) in North Dakota Northwest Judicial District Court in
December 1993. The North Dakota Supreme Court in December 1999
affirmed the North Dakota Northwest Judicial District Court
decision dismissing Apache's and Snyder's claims against
Williston Basin and the Company. Based in part upon the
decision of the North Dakota Supreme Court affirming the
dismissal of the claims brought by Apache and Snyder, Williston
Basin and the Company filed motions for summary judgment to
dismiss the claims of the 11 natural gas producers. The
motions for summary judgment were granted by the North Dakota
District Court in July 2000. In March 2001, the North Dakota
District Court entered a final judgment on the July 2000 order
granting the motions for summary judgment. In May 2001, the 11
natural gas producers appealed the North Dakota District
Court's decision by filing a Notice of Appeal with the North
Dakota Supreme Court. Oral argument was held before the North
Dakota Supreme Court in December 2001. On April 16, 2002, the
North Dakota Supreme Court affirmed the summary judgment
entered by the North Dakota District Court. On April 30, 2002,
the 11 natural gas producers filed a petition for rehearing by
the North Dakota Supreme Court. On May 17, 2002, the North
Dakota Supreme Court denied the 11 natural gas producers
petition for rehearing.
Williston Basin and the Company believe the claims of the
11 natural gas producers are without merit and intend to
continue vigorously contesting this suit. Williston Basin and
the Company believe it is not probable that the 11 natural gas
producers will ultimately succeed given the current status of
the litigation.
In July 1996, Jack J. Grynberg (Grynberg) filed suit in
United States District Court for the District of Columbia (U.S.
District Court) against Williston Basin and over 70 other
natural gas pipeline companies. Grynberg, acting on behalf of
the United States under the Federal False Claims Act, alleged
improper measurement of the heating content and volume of
natural gas purchased by the defendants resulting in the
underpayment of royalties to the United States. In March 1997,
the U.S. District Court dismissed the suit without prejudice
and the dismissal was affirmed by the United States Court of
Appeals for the D.C. Circuit in October 1998. In June 1997,
Grynberg filed a similar Federal False Claims Act suit against
Williston Basin and Montana-Dakota and filed over 70 other
separate similar suits against natural gas transmission
companies and producers, gatherers, and processors of natural
gas. In April 1999, the United States Department of Justice
decided not to intervene in these cases. In response to a
motion filed by Grynberg, the Judicial Panel on Multidistrict
Litigation consolidated all of these cases in the Federal
District Court of Wyoming (Federal District Court). Oral
argument on motions to dismiss was held before the Federal
District Court in March 2000. In May 2001, the Federal
District Court denied Williston Basin's and Montana-Dakota's
motion to dismiss. The matter is currently pending.
The Quinque Operating Company (Quinque), on behalf of
itself and subclasses of gas producers, royalty owners and
state taxing authorities, instituted a legal proceeding in
State District Court for Stevens County, Kansas, (State
District Court) against over 200 natural gas transmission
companies and producers, gatherers, and processors of natural
gas, including Williston Basin and Montana-Dakota. The
complaint, which was served on Williston Basin and Montana-
Dakota in September 1999, contains allegations of improper
measurement of the heating content and volume of all natural
gas measured by the defendants other than natural gas produced
from federal lands. In response to a motion filed by the
defendants in this suit, the Judicial Panel on Multidistrict
Litigation transferred the suit to the Federal District Court
for inclusion in the pretrial proceedings of the Grynberg suit.
Upon motion of plaintiffs, the case has been remanded to State
District Court. In September 2001, the defendants in this suit
filed a motion to dismiss with the State District Court. The
matter is currently pending.
Williston Basin and Montana-Dakota believe the claims of
Grynberg and Quinque are without merit and intend to vigorously
contest these suits. Williston Basin and Montana-Dakota
believe it is not probable that Grynberg and Quinque will
ultimately succeed given the current status of the litigation.
15. Environmental matters
In December 2000, Morse Bros., Inc. (MBI), an indirect
wholly owned subsidiary of the Company, was named by the United
States Environmental Protection Agency (EPA) as a Potentially
Responsible Party in connection with the cleanup of a
commercial property site, now owned by MBI, 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. Based upon a review of
the Portland Harbor sediment contamination evaluation by the
Oregon State Department of Environmental Quality and other
information available, MBI does not believe it is a Responsible
Party. In addition, MBI intends to seek indemnity for any and
all liabilities incurred in relation to the above matters from
Georgia-Pacific West, Inc., the seller of the commercial
property site to MBI, 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.
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
For purposes of segment financial reporting and discussion of
results of operations, electric and natural gas distribution include
the electric and natural gas distribution operations of Montana-
Dakota and the natural gas distribution operations of Great Plains
Natural Gas Co. Utility services includes all the operations of
Utility Services, Inc. Pipeline and energy services includes WBI
Holdings' natural gas transportation, underground storage, gathering
services, energy marketing and management services; Centennial
Capital, which invests in domestic growth opportunities; and MDU
International, which invests in international growth opportunities.
Natural gas and oil production includes the natural gas and oil
acquisition, exploration and production operations of WBI Holdings,
while construction materials and mining includes the results of
Knife River's operations.
Reference should be made to Notes to Consolidated Financial
Statements for information pertinent to various commitments and
contingencies.
Overview
The following table (dollars in millions, where applicable)
summarizes the contribution to consolidated earnings by each of
the Company's business segments.
Three Months Six Months
Ended Ended
June 30, June 30,
2002 2001 2002 2001
Electric $ 1.7 $ 2.1 $ 5.2 $ 7.0
Natural gas distribution (.8) (1.5) 3.7 1.1
Utility services .8 3.9 2.2 5.9
Pipeline and energy services 2.8 3.3 5.6 5.8
Natural gas and oil production 9.3 17.9 30.4 45.9
Construction materials and mining 10.9 17.5 1.1 10.0
Earnings on common stock $24.7 $ 43.2 $ 48.2 $ 75.7
Earnings per common
share - basic $ .35 $ .64 $ .69 $ 1.14
Earnings per common
share - diluted $ .35 $ .63 $ .68 $ 1.13
Return on average common equity
for the 12 months ended 11.5% 16.9%
________________________________
Three Months Ended June 30, 2002 and 2001
Consolidated earnings for the quarter ended June 30, 2002,
decreased $18.5 million from the comparable period a year ago
due to lower earnings at the natural gas and oil production,
construction materials and mining, utility services, pipeline
and energy services, and electric businesses. A lower seasonal
loss at the natural gas distribution business slightly offset
the earnings decline.
Six Months Ended June 30, 2002 and 2001
Consolidated earnings for the six months ended June 30, 2002,
decreased $27.5 million from the comparable period a year ago due to
lower earnings at the natural gas and oil production, construction
materials and mining, utility services, electric, and pipeline and
energy services businesses. Increased earnings at the natural gas
distribution business slightly offset the earnings decline.
________________________________
Financial and operating data
The following tables (dollars in millions, where applicable) are
key financial and operating statistics for each of the Company's
business segments.
Electric
Three Months Six Months
Ended Ended
June 30, June 30,
2002 2001 2002 2001
Operating revenues:
Retail sales $ 31.3 $ 31.1 $ 66.2 $ 65.6
Sales for resale and other 5.0 6.9 10.2 15.4
36.3 38.0 76.4 81.0
Operating expenses:
Fuel and purchased power 13.1 14.6 27.1 27.7
Operation and maintenance 11.5 10.9 22.9 23.5
Depreciation, depletion and
amortization 4.9 4.9 9.8 9.7
Taxes, other than income 1.8 1.8 3.8 3.8
31.3 32.2 63.6 64.7
Operating income $ 5.0 $ 5.8 $ 12.8 $ 16.3
Retail sales (million kWh) 500.9 493.4 1,059.7 1,043.1
Sales for resale (million kWh) 199.8 180.4 426.4 448.0
Average cost of fuel and
purchased power per kWh $ .018 $ .020 $ .017 $ .018
Natural Gas Distribution
Three Months Six Months
Ended Ended
June 30, June 30,
2002 2001 2002 2001
Operating revenues:
Sales $ 33.2 $ 40.4 $103.9 $180.1
Transportation and other .9 .9 2.0 2.0
34.1 41.3 105.9 182.1
Operating expenses:
Purchased natural gas sold 22.7 31.0 73.8 151.9
Operation and maintenance 8.8 8.8 18.5 19.5
Depreciation, depletion and
amortization 2.4 2.4 4.8 4.7
Taxes, other than income 1.3 1.2 2.6 2.6
35.2 43.4 99.7 178.7
Operating income (loss) $ (1.1) $ (2.1) $ 6.2 $ 3.4
Volumes (MMdk):
Sales 6.6 5.4 23.1 21.6
Transportation 2.7 2.7 6.4 6.9
Total throughput 9.3 8.1 29.5 28.5
Degree days (% of normal) 122% 99% 104% 98%
Average cost of natural gas,
including transportation
thereon, per dk $ 3.47 $ 5.78 $ 3.20 $ 7.04
Utility Services
Three Months Six Months
Ended Ended
June 30, June 30,
2002 2001 2002 2001
Operating revenues $116.3 $ 77.2 $224.6 $144.5
Operating expenses:
Operation and maintenance 108.5 66.7 207.4 125.7
Depreciation, depletion
and amortization 2.3 1.7 4.4 3.7
Taxes, other than income 3.5 1.8 7.7 3.6
114.3 70.2 219.5 133.0
Operating income $ 2.0 $ 7.0 $ 5.1 $ 11.5
Pipeline and Energy Services
Three Months Six Months
Ended Ended
June 30, June 30,
2002 2001 2002 2001
Operating revenues:
Pipeline $ 23.7 $ 21.2 $ 44.9 $ 42.3
Energy services and other 21.7 133.3 43.0 381.9
45.4 154.5 87.9 424.2
Operating expenses:
Purchased natural gas sold 18.7 129.1 36.1 376.2
Operation and maintenance 12.8 11.9 26.7 23.6
Depreciation, depletion
and amortization 3.7 3.4 7.4 6.7
Taxes, other than income 1.4 1.5 3.1 3.0
36.6 145.9 73.3 409.5
Operating income $ 8.8 $ 8.6 $ 14.6 $ 14.7
Transportation volumes (MMdk):
Montana-Dakota 7.4 9.0 15.2 17.5
Other 21.3 17.2 31.9 27.6
28.7 26.2 47.1 45.1
Gathering volumes (MMdk) 16.7 14.2 33.6 28.8
Natural Gas and Oil Production
Three Months Six Months
Ended Ended
June 30, June 30,
2002 2001 2002 2001
Operating revenues:
Natural gas $ 32.1 $ 41.2 $ 57.6 $ 95.6
Oil 11.7 12.9 21.2 26.4
Other --- 1.3 27.4* 5.0
43.8 55.4 106.2 127.0
Operating expenses:
Purchased natural gas sold --- 1.1 --- 1.8
Operation and maintenance 13.7 11.7 27.2 22.7
Depreciation, depletion
and amortization 11.3 10.6 22.9 20.1
Taxes, other than income 3.2 2.6 5.7 6.4
28.2 26.0 55.8 51.0
Operating income $ 15.6 $ 29.4 $ 50.4 $ 76.0
Production:
Natural gas (MMcf) 10,949 10,031 22,352 19,720
Oil (000's of barrels) 502 488 983 982
Average realized prices:
Natural gas (per Mcf) $ 2.93 $ 4.10 $ 2.57 $ 4.85
Oil (per barrel) $23.20 $26.52 $21.60 $26.93
_____________________
* Includes the effects of a nonrecurring compromise agreement.
Construction Materials and Mining
Three Months Six Months
Ended Ended
June 30, June 30,
2002 2001 2002 2001
Operating revenues:
Construction materials $229.6 $199.4 $322.9 $282.7
Coal ---** 2.9 ---** 12.3
229.6 202.3 322.9 295.0
Operating expenses:
Operation and maintenance 190.8 164.5 282.5 253.2
Depreciation, depletion
and amortization 13.2 11.5 24.6 21.6
Taxes, other than income 4.7 4.7 7.9 8.2
208.7 180.7 315.0 283.0
Operating income $ 20.9 $ 21.6 $ 7.9 $ 12.0
Sales (000's):
Aggregates (tons) 8,869 6,239 12,445 8,928
Asphalt (tons) 1,820 1,298 1,987 1,422
Ready-mixed concrete
(cubic yards) 793 721 1,194 1,112
Coal (tons) ---** 268 ---** 1,171
_____________________
** Coal operations were sold effective April 30, 2001.
Amounts presented in the preceding tables for operating revenues,
purchased natural gas sold and operation and maintenance expenses
will not agree with the Consolidated Statements of Income due to the
elimination of intercompany transactions between the pipeline and
energy services segment and the natural gas distribution, utility
services, construction materials and mining, and natural gas and oil
production segments. The amounts relating to the elimination of
intercompany transactions for operating revenues, purchased natural
gas sold, and operation and maintenance expenses are as follows:
$25.3 million, $21.6 million and $3.7 million for the three months
ended June 30, 2002; $22.3 million, $21.4 million and $.9 million
for the three months ended June 30, 2001; $61.7 million, $54.4
million and $7.3 million for the six months ended June 30, 2002; and
$66.1 million, $64.3 million and $1.8 million for the six months
ended June 30, 2001, respectively.
Three Months Ended June 30, 2002 and 2001
Electric
Electric earnings decreased as a result of significantly lower
average realized sales for resale prices, combined with higher
operation and maintenance expense, primarily increased subcontractor
costs. Partially offsetting the earnings decline were decreased fuel
and purchased power costs, largely lower demand charges resulting
from the absence of a 2001 extended maintenance outage at an
electric supplier's generating station.
Natural Gas Distribution
Normal seasonal losses at the natural gas distribution business
decreased as a result of higher retail sales volumes, largely the
result of weather that was 31 percent colder than last year. The
pass-through of lower natural gas prices resulted in the decrease in
sales revenues and purchased natural gas sold.
Utility Services
Utility services earnings decreased as a result of lower line
construction margins in the Rocky Mountain region related primarily
to decreased fiber optic construction work, lower construction
margins in the Central region due to an unfavorable settlement of a
billing dispute of $724,000 (after tax) and a more competitive
bidding environment for inside electrical work, the write-off of
receivables of $1.4 million (after tax) associated with a company in
the telecommunications industry, and decreased equipment sales.
Earnings from businesses acquired since the comparable period last
year partially offset these decreases. The increase in revenues and
the related increase in operation and maintenance expense resulted
largely from businesses acquired since the comparable period last
year.
Pipeline and Energy Services
Earnings at the pipeline and energy services business decreased
as a result of ongoing development costs of $1.8 million, largely in
connection with domestic and international energy projects. This
decrease was due, in part, to delays in commercial production of
power from the natural gas fired electric generation project in
Brazil due to delays in the third party delivery of the natural gas
supply. Higher operation and maintenance expenses related to
expansion of the gathering system to accommodate increasing natural
gas volumes, and lower technology services revenues at one of the
Company's energy services operations, largely due to the depressed
telecommunications market also decreased earnings. Partially
offsetting the earnings decline were higher gathering volumes at
higher average rates and higher volumes transported into storage.
The absence in 2002 of a 2001 write-off of an investment in a
software development company of $699,000 (after tax) also partially
offset the earnings decline. The decrease in energy services
revenue and the related decrease in purchased natural gas sold were
due primarily to decreased energy marketing volumes resulting from
the sale of the vast majority of the Company's low-margin energy
marketing operations in the third quarter of 2001.
Natural Gas and Oil Production
Natural gas and oil production earnings decreased largely due to
lower realized natural gas and oil prices which were 29 percent and
13 percent lower than last year, respectively, partially offset by
higher natural gas production of 9 percent, largely from operated
production in the Rocky Mountain area. Also adding to the earnings
decline were increased operation and maintenance expense, mainly
higher lease operating expenses, and increased depreciation,
depletion and amortization expense, both relating to higher
production volumes. Hedging activities for natural gas for the
second quarter of 2002 and 2001 resulted in realized prices that
were 105 percent and unchanged, respectively, of what otherwise
would have been received. In addition, hedging activities for oil
for the second quarter of 2002 and 2001 resulted in realized prices
that were 99 and 102 percent, respectively, of what otherwise would
have been received.
Construction Materials and Mining
Earnings for the construction materials and mining business
decreased as a result of the one-time gain in 2001 from the sale of
the Company's coal operations of $11.0 million ($6.6 million after
tax), included in other income - net, as previously discussed in
Note 11 of Notes to Consolidated Financial Statements. Earnings
decreased as a result of a late construction season start in Montana
due to cold and wet spring weather and the absence of earnings from
the Company's coal operations that were sold effective April 30,
2001. These decreases were offset by the net earnings at the other
existing construction materials and mining locations as well as
earnings from companies acquired since the comparable period last
year.
Six Months Ended June 30, 2002 and 2001
Electric
Electric earnings decreased as a result of significantly lower
average realized sales for resale prices due to weaker demand in the
sales for resale markets, combined with the absence in 2002 of 2001
insurance recovery proceeds related to a 2000 outage at an electric
generating station. Partially offsetting the earnings decline were
decreased fuel and purchased power costs due in part to lower demand
charges resulting from the absence of a 2001 extended maintenance
outage at an electric supplier's generating station, and decreased
operation and maintenance expense, largely lower payroll costs.
Natural Gas Distribution
Earnings at the natural gas distribution business increased as a
result of higher retail sales volumes, largely the result of weather
that was 5 percent colder than last year, increased return on
natural gas storage, demand and prepaid commodity balances,
decreased operation and maintenance expense due primarily to
decreased bad debt expense and lower payroll costs, and higher
service and repair margins. The pass-through of lower natural gas
prices resulted in the decrease in sales revenues and purchased
natural gas sold.
Utility Services
Utility services earnings decreased as a result of lower line
construction margins in the Rocky Mountain region, lower
construction margins in the Central region, the write-off of a
receivable, and decreased equipment sales, all as previously
discussed. Partially offsetting the decline in earnings were
decreased interest expense due to lower average borrowings and
earnings from businesses acquired since the comparable period last
year. The increase in revenues and the related increase in
operation and maintenance expense resulted largely from businesses
acquired since the comparable period last year.
Pipeline and Energy Services
Earnings at the pipeline and energy services business decreased
as a result of ongoing development costs of $1.9 million, largely in
connection with domestic and international energy projects. This
decrease was due, in part, to delays in commercial production of
power from the natural gas fired electric generation project in
Brazil due to delays in the third party delivery of the natural gas
supply. Higher operation and maintenance expense largely related to
the expansion of the gathering system to accommodate increasing
natural gas volumes, lower technology services revenues at one of
the Company's energy services operations, as previously discussed,
and higher depreciation, depletion and amortization expense
resulting from increased property, plant and equipment balances also
decreased earnings. Partially offsetting the earnings decline were
higher gathering volumes at higher average rates, higher volumes
transported into storage, and increased storage revenues. The
absence in 2002 of a 2001 write-off of an investment in a software
development company, as previously discussed, also partially offset
the earnings decline. The decrease in energy services revenue and
the related decrease in purchased natural gas sold were due
primarily to decreased energy marketing volumes resulting from the
sale of the vast majority of the Company's low-margin energy
marketing operations in the third quarter of 2001.
Natural Gas and Oil Production
Natural gas and oil production earnings decreased largely due to
lower realized natural gas and oil prices which were 47 percent and
20 percent lower than last year, respectively, partially offset by
higher natural gas production of 13 percent, largely from operated
production in the Rocky Mountain area. Also adding to the earnings
decline were increased operation and maintenance expense, mainly
higher lease operating expenses, lower sales volumes of inventoried
natural gas, and increased depreciation, depletion and amortization
expense due to higher production volumes and higher rates.
Partially offsetting the earnings decline were the effects of the
nonrecurring compromise agreement of $27.4 million ($16.6 million
after-tax), included in operating revenue, as discussed in Note 14
of Notes to Consolidated Financial Statements. Hedging activities
for natural gas for the six months ended June 30, 2002 and 2001
resulted in realized prices that were 104 and 96 percent,
respectively, of what otherwise would have been received. In
addition, hedging activities for oil for the six months ended
June 30, 2002 and 2001 resulted in realized prices that were 102
percent, of what otherwise would have been received.
Construction Materials and Mining
Earnings for the construction materials and mining business
decreased due to the previously mentioned 2001 one-time gain from
the sale of the Company's coal operations. Decreased construction
activity, the result of a late construction season start in Montana
due to cold and wet spring weather, and lower ready-mixed concrete
volumes at existing operations, higher depreciation, depletion and
amortization expense due to higher property, plant and equipment
balances, and increased selling, general and administrative costs
added to the earnings decrease. The absence of earnings from the
Company's coal operations that were sold in April 2001, also added
to the earnings decrease. Increased aggregate and asphalt margins
partially offset the earnings decrease.
Safe Harbor for Forward-looking Statements
The Company is including the following cautionary statement 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 which are other
than statements of historical facts. From time to time, the Company
may publish or otherwise make available forward-looking statements
of this nature, including statements contained within Prospective
Information. All such subsequent forward-looking statements,
whether written or oral and whether made by or on behalf of the
Company, are also expressly qualified by these 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, but there can be no assurance that the Company's
expectations, beliefs or projections will be achieved or
accomplished. Furthermore, any forward-looking statement speaks
only as of the date on which such statement is made, and the Company
undertakes no obligation to update any forward-looking statement or
statements to reflect events or circumstances that occur after the
date on which such statement is made or to reflect the occurrence of
unanticipated events. New factors emerge from time to time, and it
is not possible for management to predict all of such factors, nor
can it assess the effect of each such factor on the Company's
business or the extent to which any such factor, or combination of
factors, may cause actual results to differ materially from those
contained in any forward-looking statement.
In addition to other factors and matters discussed elsewhere
herein, some important factors that could cause actual results or
outcomes for the Company to differ materially from those discussed
in forward-looking statements include natural gas and oil commodity
prices, prevailing governmental policies and regulatory actions with
respect to allowed rates of return, financings, or industry and rate
structures, acquisition and disposal of assets or facilities,
operation and construction of plant facilities, recovery of
purchased power and purchased gas costs, present or prospective
generation and availability of economic supplies of natural gas.
Other important factors include the level of governmental
expenditures on public projects and the timing of such projects,
changes in anticipated tourism levels, the effects of competition
(including but not limited to electric retail wheeling and
transmission costs and prices of alternate fuels and system
deliverability costs), 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, ability to acquire natural gas and oil properties,
the availability of economic expansion or development opportunities,
and political, regulatory and economic conditions and changes in
currency rates in foreign countries where the Company does business.
The business and profitability of the Company are also influenced
by economic and geographic factors, including political and economic
risks, economic disruptions caused by terrorist activities, changes
in and compliance with environmental and safety laws and policies,
weather conditions, population growth rates and demographic
patterns, market demand for energy from plants or facilities,
changes in tax rates or policies, unanticipated project delays or
changes in project costs, unanticipated changes in operating
expenses or capital expenditures, labor negotiations or disputes,
changes in credit ratings or capital market conditions, inflation
rates, inability of the various counterparties to meet their
contractual obligations, changes in accounting principles and/or the
application of such principles to the Company, changes in technology
and legal proceedings, and the ability to effectively integrate the
operations of acquired companies.
Prospective Information
The following information includes highlights of the key growth
strategies, projections and certain assumptions for the Company over
the next few years and other matters for each of its six business
segments. 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 should be made to
assumptions contained in this section as well as the various
important factors listed under the heading Safe Harbor for Forward-
looking Statements. Changes in such assumptions and factors could
cause actual future results to differ materially from the Company's
targeted growth, revenue and earnings projections. Given the
current business environment, the Company is reviewing its long-term
growth goals.
MDU Resources Group, Inc.
- - Earnings per share, diluted, for 2002 are projected in the
$1.80 to $2.00 range. Excluding the benefit of the compromise
agreement discussed in Note 14 of Notes to Consolidated Financial
Statements, earnings per share from operations are projected to be
in the approximate range of $1.60 to $1.80.
- - Weighted average diluted common shares outstanding for the
twelve months ended December 31, 2001, were 67.9 million. The
Company anticipates a 3 percent to 7 percent increase in weighted
average diluted shares outstanding by 2002 year end.
- - The Company expects the percentage of 2002 earnings per share
from operations, excluding the benefit of the compromise agreement,
by quarter to be in the following approximate ranges:
- Third Quarter - 40 percent to 45 percent
- Fourth Quarter - 29 percent to 34 percent
- - The Company will examine issuing equity from time to time to
keep its debt at the nonregulated businesses at no more than 40
percent of total capitalization subject to market conditions.
- - The Company estimates that the benefit resulting solely from
the discontinuance of goodwill amortization would be 5 to 6 cents
per common share in 2002.
Electric
- - Montana-Dakota has obtained and holds valid and existing
franchises authorizing it to conduct its electric and natural gas
operations in all of the municipalities it serves where such
franchises are required. As franchises expire, Montana-Dakota may
face increasing competition in its service areas, particularly its
service to smaller towns, from rural electric cooperatives. Montana-
Dakota intends to protect its service area and seek renewal of all
expiring franchises and will continue to take steps to effectively
operate in an increasingly competitive environment.
- - On May 2, 2002, the District Court granted Montana-Dakota's
request for a stay of a portion of the $4.3 million annual rate
reduction ordered by the NDPSC. Accordingly, Montana-Dakota
implemented an annual rate reduction of $800,000 effective with
service rendered on and after May 8, 2002, rather than the $4.3
million annual reduction ordered by the NDPSC. The remaining $3.5
million is subject to refund if Montana-Dakota does not prevail in
this proceeding. Reserves have been provided for the revenues that
have been collected subject to refund with respect to this pending
electric rate reduction. For more information on this proceeding
see Note 13 of Notes to Consolidated Financial Statements.
- - Due to growing electric demand, a 40-megawatt natural gas
turbine power plant may be added in the two to five year planning
horizon.
- - Currently, the Company is working with the State of North
Dakota to determine the feasibility of constructing a 500-megawatt
lignite-fired power plant in western North Dakota. The first
preliminary decision is expected in December 2002.
Natural gas distribution
- - Annual natural gas throughput for 2002 is expected to be
approximately 56 million decatherms, with about 40 million
decatherms from sales and 16 million decatherms from transportation.
- - On June 10, 2002, Montana-Dakota filed with the WYPSC for a
natural gas rate increase. The Company is requesting a total of
$662,000 annually or 5.6 percent above current rates.
- - On May 20, 2002, Montana-Dakota filed with the MTPSC for a
natural gas rate increase. The Company is requesting a total of
$3.6 million annually or 6.5 percent above current rates.
- - On April 12, 2002, Montana-Dakota filed with the NDPSC for a
natural gas rate increase. The Company is requesting a total of
$2.8 million annually or 4.1 percent above current rates.
Utility services
- - Revenues for this segment are expected to approximate $500
million in 2002.
- - Earnings for 2002, compared to 2001, are expected to increase
by approximately 10 percent.
Pipeline and energy services
- - In 2002, natural gas throughput from this segment, including
both transportation and gathering, is expected to increase by
approximately 5 percent over the 2001 record level throughput.
- - A 247-mile pipeline to transport additional natural gas to
market and enhance the use of the Company's storage facilities is
currently under regulatory review. Depending upon the timing of the
receipt of the necessary regulatory approval, construction
completion could occur as early as late 2003.
- - The Company continues to pursue electric generation
opportunities in Brazil. These projects are targeted toward a niche
market where we will provide energy on a contractual basis in order
to reduce risk. The first 100 megawatts have begun commercial
production and the second 100 megawatts are scheduled to begin
commercial production early in 2003.
- - The Company's plans to construct a 113-megawatt coal-fired
electric generation station in Montana are pending. The Company
purchased plant equipment and obtained all permits necessary to
begin construction. NorthWestern Energy terminated the power
purchase agreement for the energy from this plant; however, the
Company believes there are other markets for the energy and is
studying its options regarding this project. Pending completion
of this study, the Company has deferred construction activities
and is investigating suspension of construction activities. At
June 30, 2002, the Company's investment in this project was
approximately $16.5 million.
Natural gas and oil production
- - Due to delays caused by weather, regulatory hurdles and
environmental objections to discharge of water, the Company now
anticipates combined natural gas and oil production at this segment
in 2002 to be approximately 10 percent to 15 percent higher than in
2001. To help mitigate the water issues, the Company is
implementing new water management practices and policies.
- - Due to the aforementioned reasons, this segment now expects to
drill approximately 250 wells in 2002.
- - Natural gas prices in the Rocky Mountain Region for July
through December 2002 reflected in the Company's 2002 earnings
guidance are in the range of $2.00 to $2.50 per Mcf. The Company's
estimates for natural gas prices on the NYMEX for July through
December 2002 reflected in the Company's 2002 earnings guidance are
in the range of $3.25 to $3.75 per Mcf. During 2001, more than half
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 2002 reflected
in the Company's 2002 earnings guidance are in the range of $24 to
$27 per barrel.
- - This segment has hedged a portion of its 2002 production. The
Company has entered into swap agreements and fixed price forward
sales representing approximately 35 percent to 40 percent of 2002
estimated annual natural gas production. These natural gas swaps
are at various indices and range from a low CIG index of $2.73 to a
high NYMEX price of $4.34. The Company has also entered into oil
swap agreements at average NYMEX prices in the range of $24.80 to
$25.90 per barrel, representing approximately 30 percent to 35
percent of the Company's 2002 estimated annual oil production.
- - In addition to these 2002 hedges, the Company has hedged a
portion of its 2003 production. The Company has entered into
costless collars and fixed price forward sales, representing
approximately 5 percent to 10 percent of 2003 estimated annual
natural gas production. The costless collars range from
approximately $3.15 to $4.25 per Mcf.
Construction materials and mining
- - Excluding the effects of potential future acquisitions,
aggregate volumes are expected to increase by approximately 18
percent to 23 percent in 2002 and asphalt and ready-mixed concrete
volumes are expected to increase by 15 percent to 20 percent and 5
percent to 10 percent, respectively in 2002.
- - Revenues for this segment are expected to exceed $900 million
in 2002.
New Accounting Standards
In June 2001, the FASB approved Statement of Financial
Accounting Standards No. 143, "Accounting for Asset Retirement
Obligations." For further information on SFAS No. 143, see Note 6
of Notes to Consolidated Financial Statements.
In June 2001, the FASB approved Statement of Financial
Accounting Standards No. 142, "Goodwill and Other Intangible
Assets." Under SFAS No. 142, goodwill and other intangible assets
with indefinite lives are no longer amortized but are reviewed
annually, or more frequently if impairment issues arise, for
impairment. As of December 31, 2001, the Company had unamortized
goodwill of $174.0 million that was subject to the provisions of
SFAS No. 142. Had SFAS No. 142 been in effect for 2001, earnings
would have been $4.2 million higher.
In August 2001, the FASB approved Statement of Financial
Accounting Standards No. 144, "Accounting for the Impairment or
Disposal of Long-Lived Assets." The adoption of SFAS No. 144 was
effective for the Company beginning on January 1, 2002. The
adoption of SFAS No. 144 did not have a material affect on the
Company's financial position or results of operations.
In April 2002, the FASB approved Statement of Financial
Accounting Standards No. 145, "Rescission of FASB Statements No. 4,
44 and 64, Amendment of FASB Statement No. 13, and Technical
Corrections." For further information on SFAS No. 145, see Note 6
of Notes to Consolidated Financial Statements.
In June 2002, the EITF adopted the position in EITF No. 02-3,
"Recognition and Reporting of Gains and Losses on Energy Trading
Contracts under EITF Issues No. 98-10, 'Accounting for Contracts
Involved in Energy Trading and Risk Management Activities,' and
No. 00-17, 'Measuring the Fair Value of Energy-Related Contracts in
Applying Issue No. 98-10.'" For further information on EITF
No. 02-3, see Note 6 of Notes to Consolidated Financial Statements.
In June 2002, the FASB approved SFAS No. 146, "Accounting for
Costs Associated with Exit or Disposal Activities." For further
information on SFAS No. 146, see Note 6 of Notes to Consolidated
Financial Statements.
Critical Accounting Policies
The Company's critical accounting policies include impairment of
long-lived assets and intangibles, impairment testing of natural gas
and oil production properties, revenue recognition, derivatives,
purchase accounting and accounting for the effects of regulation.
There are no material changes in the Company's critical accounting
policies from those reported in the Company's Annual Report on Form
10-K for the year ended December 31, 2001. For more information on
critical accounting policies, see Part II, Item 7 in the Company's
Annual Report on Form 10-K for the year ended December 31, 2001.
Liquidity and Capital Commitments
Cash flows
Operating activities --
Cash flows from operating activities in the first six months of
2002 decreased $61.5 million from the comparable 2001 period,
primarily due to a decrease in net income of $27.5 million and the
decrease in cash from changes in working capital items of $48.8
million. This decrease was primarily due to lower natural gas
prices in the first six months of 2002 compared to the same period
of 2001. Higher depreciation, depletion and amortization expense of
$7.4 million resulting largely from increased property, plant and
equipment balances partially offset the decrease in cash flows from
operating activities.
Investing activities --
Cash flows used in investing activities in the first six months
of 2002 decreased $22.4 million compared to the comparable period in
2001, the result of a decrease in net capital expenditures,
including acquisitions and net proceeds from the sale or disposition
of property. Net capital expenditures exclude the following noncash
transactions related to acquisitions: issuance of the Company's
equity securities of $41.8 million and $57.3 million in the first
six months of 2002 and 2001, respectively.
Financing activities --
Financing activities resulted in an increase in cash flows for
the first six months of 2002 of $51.3 million compared to the
comparable 2001 period. This increase was largely due to the
decrease in the repayment of long-term debt of $52.6 million and the
increase in issuance of long-term debt of $16.1 million. This
increase was partially offset by a decrease in proceeds from
issuance of common stock of $26.8 million.
Capital expenditures
Net capital expenditures for the year 2002 are estimated at
approximately $390 million, including those for acquisitions, system
upgrades, routine replacements, service extensions, routine
equipment maintenance and replacements, land and building
improvements, pipeline and gathering expansion projects, the further
enhancement of natural gas and oil production and reserve growth,
power generation opportunities and for potential future acquisitions
and other growth opportunities. Approximately 30 percent to 35
percent of estimated net capital expenditures for 2002 are for
completed and potential future 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, actual acquisitions and
capital expenditures may vary significantly from the estimated 2002
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,
a revolving credit and term loan agreement, a commercial paper
credit facility at Centennial, as described below, and through the
issuance of long-term debt and the Company's equity securities.
The estimated 2002 capital expenditures referred to above
include completed 2002 acquisitions including construction materials
and mining businesses in Minnesota and Montana; a utility services
company in California; and an energy development company in Montana.
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
The Company has a revolving credit and term loan agreement with
various banks that allows for borrowings of up to $40 million.
Under this agreement, $5 million was outstanding at June 30, 2002.
The borrowings under this agreement, which allows for subsequent
borrowings up to a term of one year, are classified as long term as
the Company intends to refinance these borrowings on a long-term
basis. The Company intends to renew this agreement, which expires
on December 31, 2002.
Centennial has a revolving credit agreement (Centennial credit
agreement) with various banks that supports Centennial's $350
million commercial paper program (Centennial commercial paper
program). There were no outstanding borrowings under the Centennial
credit agreement at June 30, 2002. Under the Centennial commercial
paper program, $297.9 million was outstanding at June 30, 2002. The
Centennial commercial paper borrowings are classified as long term
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 agreement, which
allows for subsequent borrowings up to a term of one year.
Centennial intends to renew the Centennial credit agreement, which
expires September 27, 2002, on an annual basis.
Centennial has an uncommitted long-term master shelf agreement
that allows for borrowings of up to $300 million. Under the terms
of the master shelf agreement, $242.2 million was outstanding at
June 30, 2002. On August 2, 2002, Centennial borrowed an additional
$50 million under the terms of this agreement. The $50 million in
proceeds were used to pay down Centennial commercial paper program
borrowings. Centennial currently plans to expand its borrowing
capacity under this facility.
MDU International has a credit agreement that allows for
borrowings of up to $25 million. Under this agreement, $4.5 million
was outstanding at June 30, 2002. The Company intends to renew this
credit agreement, which expires June 30, 2003, on an annual basis.
The Company also has unsecured short-term lines of credit from
a number of banks totaling $60 million that allow the Company to
borrow under the lines and/or provide credit support for a
commercial paper program. There were no outstanding borrowings
under these lines of credit or this commercial paper program at
June 30, 2002. The Company intends to renew these lines of credit
on an annual basis.
The Company's goal is to maintain acceptable credit ratings
under its credit agreements and individual bank lines of credit 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 rating, the Company 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 the Company does not currently anticipate, it
may need to borrow under its committed bank lines.
To the extent the Company needs to borrow under its committed
bank lines, it would be expected to incur increased annualized
interest expense on its variable rate debt by approximately $447,000
(after-tax) for the calendar year 2002 based on June 30, 2002
variable rate borrowings. Based on the Company's overall interest
rate exposure at June 30, 2002, this change would not have a
material affect on the Company's results of operations.
On an annual basis, the Company negotiates the placement of the
Centennial credit agreement and its individual bank lines of credit
that provide credit support to access the capital markets. In the
event the Company were unable to successfully negotiate the bank
credit facilities, or in the event the fees on such facilities
became too expensive, which the Company 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 or its subsidiaries'
credit facilities, the Company and 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,
limitations on priority debt, limitations on sale of assets and
limitations on loans and investments in addition to certain
restrictions imposed under the terms and conditions of the Company's
Indenture of Mortgage as discussed below. The Company and its
subsidiaries are in compliance with these covenants and met the
required conditions at June 30, 2002. In the event the Company or
its subsidiaries do not comply with the applicable covenants and
other conditions, alternative sources of funding may need to be
pursued as previously described.
The Centennial credit agreement and the Centennial uncommitted
long-term master shelf agreement 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 which causes such indebtedness to be due
prior to its stated maturity or the contingent obligation to become
payable, the Centennial credit agreement and the Centennial
uncommitted long-term master shelf agreement will be in default.
The Centennial credit agreement, the Centennial uncommitted long-
term master shelf agreement and Company practice limit the amount of
subsidiary indebtedness.
Currently, there are no credit facilities that contain cross-
default provisions between Centennial and the Company.
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 pledge $1.43 of unfunded property to the Trustee for each
dollar of indebtedness incurred under the Indenture and 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 two tests,
as of June 30, 2002, the Company could have issued approximately
$312 million of additional first mortgage bonds.
The Company's coverage of fixed charges including preferred
dividends was 4.5 times and 5.3 times for the twelve months ended
June 30, 2002 and December 31, 2001, respectively. Additionally,
the Company's first mortgage bond interest coverage was 8.0 times
and 8.5 times for the twelve months ended June 30, 2002 and
December 31, 2001, respectively. Common stockholders' equity as a
percent of total capitalization was 58 percent at June 30, 2002 and
December 31, 2001.
Contractual obligations and commercial commitments
There are no material changes in the Company's contractual
obligations on long-term debt, operating leases and purchase
commitments from those reported in the Company's Annual Report on
Form 10-K for the year ended December 31, 2001. For more
information on contractual obligations and commercial commitments,
see Item 7 in the Company's Annual Report on Form 10-K for the year
ended December 31, 2001.
Certain subsidiaries of the Company have financial guarantees
outstanding at June 30, 2002. These guarantees as of June 30, 2002,
are approximately $27.9 million, of which approximately $24.5
million pertain to Centennial's guarantee of certain obligations in
connection with the natural gas fired electric generation station in
Brazil, as discussed in Notes 10 and 15 of Notes to Consolidated
Financial Statements in the 2001 Annual Report and Items 2 and 3 of
this 10-Q. As of June 30, 2002, with respect to these guarantees,
there were approximately $23.5 million outstanding through 2003,
$1.4 million outstanding through 2004 and $3.0 million outstanding
thereafter.
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 --
The Company utilizes derivative instruments, including natural
gas and oil price swap and natural gas collar agreements, to manage
a portion of the market risk associated with fluctuations in the
price of natural gas and oil on the Company's 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, 2001, and Notes to
Consolidated Financial Statements in this Form 10-Q.
The following table summarizes hedge agreements entered into by
certain wholly owned subsidiaries of the Company, as of June 30,
2002. These agreements call for the subsidiaries 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 2002 $ 3.50 8,769 $4,486
Weighted
Average Notional
Fixed Price Amount
(Per barrel) (In barrels) Fair Value
Oil swap agreements
maturing in 2002 $ 24.89 388 $(535)
Weighted
Average
Floor/Ceiling Notional
Price Amount
(Per MMBtu) (In MMBtu's) Fair Value
Natural gas collar
agreements maturing
in 2003 $3.19/4.16 5,110 $(1,078)
The following table summarizes hedge agreements entered into by
certain wholly owned subsidiaries of the Company, as of December 31,
2001. These agreements call for the subsidiaries 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
agreement maturing
in 2002 $ 4.34 1,150 $1,878
Weighted
Average Notional
Fixed Price Amount
(Per barrel) (In barrels) Fair Value
Oil swap agreements
maturing in 2002 $ 24.96 405 $1,789
Interest rate risk --
There are 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, 2001. 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,
2001.
Foreign currency risk --
The Company has a 49 percent equity investment in a 200
megawatt natural gas fired electric generation project (Project) in
Brazil which has a portion of its borrowings and payables
denominated in U.S. Dollars. The Company 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 of the Project during its construction phase was deemed to
be the U.S. Dollar. Upon commencement of operations of the first
100 megawatts of the Project on July 7, 2002, the functional
currency of the Project became the Brazilian Real. Adjustments
attributable to the translation of nonmonetary assets between the
U.S. Dollar and the Brazilian Real as of July 7, 2002, will be
recorded in accumulated other comprehensive income in the third
quarter of 2002.
Subsequent to July 7, 2002, the effect of changes in currency
exchange rates with respect to the Project's third party U.S. Dollar
denominated borrowings and payables will be reflected in net income.
At June 30, 2002, the Project had third party U.S. Dollar denominated
borrowings and payables of approximately $59.3 million. If, for
example, the value of the Brazilian Real decreased in relation to
the U.S. Dollar by 10 percent, the Company, with respect to its
interest in the Project, would record a foreign currency translation
loss in net income of approximately $2.7 million (after tax) based
on the third party U.S. Dollar denominated borrowings and payables
at June 30, 2002.
The Project also has U.S. Dollar denominated borrowings payable
to a subsidiary of the Company of $23.8 million. Foreign currency
translation adjustments on the Project's borrowings payable to the
Company would be recorded in accumulated other comprehensive income.
The Company's equity income from this Brazilian investment is
also impacted by fluctuations in currency exchange rates. In
addition to the Company's investment in this Project, which
consisted of the borrowings payable to a subsidiary of the Company
as noted above, Centennial has guaranteed project obligations and
loans of approximately $24.5 million as of June 30, 2002.
The Company is managing a portion of its foreign currency
exchange risk through contractual provisions contained in the
Project's power purchase agreement with Petrobras that provides for
annual partial price adjustments based on changes in the U.S.
Dollar/Brazilian Real exchange rate. On August 12, 2002, the
Company entered into a foreign currency collar agreement for a
notional amount of $21.3 million with a fixed price floor of R$3.10
and a fixed price ceiling of R$3.40 to manage a portion of its
foreign currency risk. The term of the collar agreement is from
August 12, 2002 through February 3, 2003, and the collar agreement
settles on February 3, 2003. Gains or losses on this derivative
instrument will be recorded in earnings each period.
PART II -- OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
On May 17, 2002, the North Dakota Supreme Court denied the 11
natural gas producers petition for rehearing.
For more information on the above legal action see Note 14 of
Notes to Consolidated Financial Statements.
ITEM 2. CHANGES IN SECURITIES AND USE OF PROCEEDS
Between April 1, 2002 and June 30, 2002, the Company issued
1,043,195 shares of Common Stock, $1.00 par value, as part of the
consideration for all of the issued and outstanding capital stock
with respect to businesses acquired during this period and as a
final adjustment with respect to an acquisition in a prior period.
The Common Stock issued by the Company in these transactions was
issued in private sales exempt from registration pursuant to
Section 4(2) of the Securities Act of 1933. The former owners of
the businesses acquired, and now shareholders of the Company, are
accredited investors and have acknowledged that they would hold the
Company's Common Stock as an investment and not with a view to
distribution.
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
a) Exhibits
3(a) Restated Certificate of Incorporation of the
Company, as amended to date
12 Computation of Ratio of Earnings to Fixed Charges and Combined
Fixed Charges and Preferred Stock Dividends
99 Statement Pursuant to Section 906 of Sarbanes - Oxley Act
of 2002
b) Reports on Form 8-K
Form 8-K was filed on July 25, 2002. Under Item 5 -- Other
Events, the Company reported the press release issued July 24,
2002, regarding earnings for the quarter ended June 30, 2002.
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of
1934, as amended, 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 13, 2002 BY /s/ Warren L. Robinson
Warren L. Robinson
Executive Vice President,
Treasurer and Chief
Financial Officer
BY /s/ Vernon A. Raile
Vernon A. Raile
Vice President, Controller and
Chief Accounting Officer
EXHIBIT INDEX
Exhibit No.
3(a) Restated Certificate of Incorporation of the Company, as
amended to date
12 Computation of Ratio of Earnings to Fixed Charges
and Combined Fixed Charges and Preferred Stock
Dividends
99 Statement Pursuant to Section 906 of Sarbanes - Oxley Act of
2002