UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
X QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2001
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 October 19, 2001: 69,147,245
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, distributes natural gas and provides related value-
added products and services in Montana, North Dakota, South Dakota
and Wyoming. Great Plains Natural Gas Co. (Great Plains), another
public utility division of the company, distributes natural gas in
southeastern North Dakota and western Minnesota.
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 in the Rocky Mountain, Midwest, Southern and
Central regions of the United States and provides energy-
related marketing and management services. The natural gas
and oil production segment is engaged in natural gas and
oil acquisition, exploration and production primarily in
the Rocky Mountain region of the United States and in the
Gulf of Mexico.
Knife River mines and markets aggregates and related value-
added construction materials products and services in
Alaska, California, Hawaii, Minnesota, Montana, Oregon,
Washington and Wyoming.
Utility Services is a diversified infrastructure
construction company specializing in electric, natural gas
and telecommunication utility construction as well as
interior industrial electrical, exterior lighting and
traffic signalization. Utility Services has engineering,
design and build capability and provides related specialty
equipment sales and rental services throughout most of the
United States.
Centennial Capital invests in new growth and synergistic
opportunities which are not directly being pursued by the
existing business units but which are consistent with the
company's philosophy and growth strategy.
The company, through its wholly owned subsidiary, MDU Resources
International, Inc., invests in projects outside the United States
which are consistent with the company's philosophy, growth strategy
and areas of expertise.
INDEX
Part I -- Financial Information
Consolidated Statements of Income --
Three and Nine Months Ended September 30, 2001 and 2000
Consolidated Balance Sheets --
September 30, 2001 and 2000, and December 31, 2000
Consolidated Statements of Cash Flows --
Nine Months Ended September 30, 2001 and 2000
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 Nine Months
Ended Ended
September 30, September 30,
2001 2000 2001 2000
(In thousands, except per share amounts)
Operating revenues $551,680 $530,834 $1,739,345 $1,265,802
Operating expenses:
Fuel and purchased power 14,982 13,399 42,703 39,603
Purchased natural gas sold 36,840 123,132 502,394 389,906
Operation and maintenance 356,677 277,512 823,052 582,511
Depreciation, depletion and
amortization 36,205 28,686 102,737 75,130
Taxes, other than income 13,737 12,082 41,352 32,121
458,441 454,811 1,512,238 1,119,271
Operating income 93,239 76,023 227,107 146,531
Other income -- net 1,855 1,947 16,416 8,624
Interest expense 11,459 13,333 34,171 34,539
Income before income taxes 83,635 64,637 209,352 120,616
Income taxes 32,889 24,645 82,502 46,133
Net income 50,746 39,992 126,850 74,483
Dividends on preferred stocks 190 191 571 575
Earnings on common stock $ 50,556 $ 39,801 $ 126,279 $ 73,908
Earnings per common share -- basic $ .75 $ .63 $ 1.89 $ 1.23
Earnings per common share -- diluted $ .74 $ .63 $ 1.87 $ 1.23
Dividends per common share $ .23 $ .22 $ .67 $ .64
Weighted average common shares
outstanding -- basic 67,650 62,975 66,781 60,015
Weighted average common shares
outstanding -- diluted 68,127 63,345 67,519 60,238
The accompanying notes are an integral part of these consolidated statements.
MDU RESOURCES GROUP, INC.
CONSOLIDATED BALANCE SHEETS
(Unaudited)
September 30, September 30, December 31,
2001 2000 2000
(In thousands)
ASSETS
Current assets:
Cash and cash equivalents $ 57,817 $ 47,267 $ 36,512
Receivables 357,027 284,491 342,354
Inventories 95,669 76,065 64,017
Deferred income taxes 14,839 7,043 8,048
Prepayments and other current assets 27,722 43,992 29,355
553,074 458,858 480,286
Investments 37,917 41,480 41,380
Property, plant and equipment 2,718,035 2,424,888 2,496,123
Less accumulated depreciation,
depletion and amortization 919,212 862,148 895,109
1,798,823 1,562,740 1,601,014
Deferred charges and other assets 282,657 182,791 190,279
$2,672,471 $2,245,869 $2,312,959
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Short-term borrowings $ --- $ 12,000 $ 8,000
Long-term debt and preferred
stock due within one year 11,131 6,407 19,695
Accounts payable 141,950 131,003 171,929
Taxes payable 28,984 9,372 10,437
Dividends payable 15,840 14,385 14,423
Other accrued liabilities,
including reserved revenues 91,191 79,135 59,989
289,096 252,302 284,473
Long-term debt 843,915 758,170 728,166
Deferred credits and other liabilities:
Deferred income taxes 327,560 262,034 281,000
Other liabilities 118,013 119,926 121,860
445,573 381,960 402,860
Preferred stock subject to mandatory
redemption 1,400 1,500 1,400
Commitments and contingencies
Stockholders' equity:
Preferred stocks 15,000 15,000 15,000
Common stockholders' equity:
Common stock (Shares issued --
$1.00 par value, 69,386,316
at September 30, 2001, 64,466,401 at
September 30, 2000 and 65,267,567 at
December 31, 2000) 69,386 64,466 65,268
Other paid-in capital 626,655 497,572 518,771
Retained earnings 381,752 278,525 300,647
Accumulated other comprehensive
income 3,320 --- ---
Treasury stock at cost - 239,521
shares (3,626) (3,626) (3,626)
Total common stockholders' equity 1,077,487 836,937 881,060
Total stockholders' equity 1,092,487 851,937 896,060
$2,672,471 $2,245,869 $2,312,959
The accompanying notes are an integral part of these consolidated statements.
MDU RESOURCES GROUP, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Nine Months Ended
September 30,
2001 2000
(In thousands)
Operating activities:
Net income $126,850 $74,483
Adjustments to reconcile net income to net cash provided
by operating activities:
Depreciation, depletion and amortization 102,737 75,130
Deferred income taxes and investment tax credit 8,448 20,627
Changes in current assets and liabilities, net of
acquisitions:
Receivables 54,776 (63,224)
Inventories (26,844) (2,563)
Other current assets 7,460 (18,584)
Accounts payable (55,426) 19,695
Other current liabilities 43,667 14,792
Other noncurrent changes (2,867) 676
Net cash provided by operating activities 258,801 121,032
Investing activities:
Capital expenditures including acquisitions of businesses (340,572) (323,225)
Net proceeds from sale or disposition of property 34,847 5,092
Net capital expenditures (305,725) (318,133)
Investments 3,041 2,001
Additions to notes receivable --- (5,000)
Proceeds from notes receivable 4,000 4,000
Net cash used in investing activities (298,684) (317,132)
Financing activities:
Net change in short-term borrowings (8,000) (3,242)
Issuance of long-term debt 158,807 201,815
Repayment of long-term debt (96,031) (20,461)
Issuance of common stock 52,157 27,278
Dividends paid (45,745) (39,527)
Net cash provided by financing activities 61,188 165,863
Increase (decrease) in cash and cash equivalents 21,305 (30,237)
Cash and cash equivalents -- beginning of year 36,512 77,504
Cash and cash equivalents -- end of period $ 57,817 $ 47,267
The accompanying notes are an integral part of these consolidated statements.
MDU RESOURCES GROUP, INC.
NOTES TO CONSOLIDATED
FINANCIAL STATEMENTS
September 30, 2001 and 2000
(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, 2000 (2000 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 2000 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. 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 may not be indicative of results for the
full fiscal year.
3. Cash flow information
Cash expenditures for interest and income taxes were as
follows:
Nine Months Ended
September 30,
2001 2000
(In thousands)
Interest, net of amount capitalized $28,158 $28,520
Income taxes $57,528 $25,946
4. 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 common stockholders' equity as previously reported.
5. Impairment testing of natural gas and oil properties
The company uses the full-cost method of accounting for its
natural gas and oil production activities. Under this method,
all costs incurred in the acquisition, exploration and
development of natural gas and oil properties are capitalized
and amortized on the units of production method based on total
proved reserves. Any conveyances of properties, including
gains or losses on abandonments of properties, are treated as
adjustments to the cost of the properties with no gain or loss
recognized. Capitalized costs are subject to a "ceiling test"
that limits such costs to the aggregate of the present value of
future net revenues of proved reserves based on single point in
time spot market prices, as mandated under the rules of the
Securities and Exchange Commission, and the lower of cost or
fair value of unproved properties. Future net revenue is
estimated based on end-of-quarter spot market prices adjusted
for contracted price changes. If capitalized costs exceed the
full-cost ceiling at the end of any quarter, a permanent
noncash write-down is required to be charged to earnings in
that quarter unless subsequent price changes eliminate or
reduce an indicated write-down.
Due to aberrantly low spot natural gas prices that existed
on the last trading day of the quarter, the company's
capitalized costs under the full-cost method of accounting
exceeded the full-cost ceiling at September 30, 2001. The
lower natural gas prices were largely attributable to a sharp
decline in nationwide spot market prices, especially natural
gas prices in the Rocky Mountain region, over a relatively
short period of time following the terrorist attacks on New
York and Washington, D.C. on September 11, 2001, and prior to
October 1, 2001. Oil prices likewise experienced a sharp drop
during this same period. The company believes the decline in
natural gas prices does not reflect the economics of its
production assets in that natural gas prices actually being
received by the company at the end of the quarter were
significantly higher than the spot market prices at that time.
In addition, historic natural gas prices have also generally
been much higher and only a small portion of the company's
natural gas is sold using spot market pricing. As of September
30, 2001, the capitalized costs exceeded the full-cost ceiling
and would have resulted in a write-down of the company's
natural gas and oil properties in the amount of approximately
$32 million after tax. However, subsequent to September 30,
2001, natural gas prices both nationwide and in the Rocky
Mountain region increased significantly, thereby eliminating
the need for a write-down of the company's natural gas and oil
producing properties.
6. New accounting pronouncements
In June 2001, the Financial Accounting Standards Board
(FASB) approved Statement of Financial Accounting Standards No.
141, "Business Combinations" (SFAS No. 141). SFAS No. 141
requires that all business combinations be accounted for using
the purchase method of accounting. The use of the pooling-of-
interest method of accounting for business combinations is
prohibited. The provisions of SFAS No. 141 apply to all
business combinations initiated after June 30, 2001. The
company is accounting for business combinations after June 30,
2001, in accordance with SFAS No. 141.
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 should be amortized over
their useful life and reviewed for impairment in accordance
with FASB Statement of Financial Accounting Standards No. 121,
"Accounting for the Impairment of Long-Lived Assets and for
Long-Lived Assets to Be Disposed Of." 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 will be subject immediately to the
provisions of SFAS No. 142. The company will adopt SFAS No.
142 on January 1, 2002. The company will cease amortization of
its recorded goodwill in place at June 30, 2001, on January 1,
2002. The company has not yet quantified the effects of
adopting SFAS No. 142 on its financial position or results of
operations.
In June 2001, the 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 August 2001, the FASB approved Statement of Financial
Accounting Standards No. 144, "Accounting for the Impairment or
Disposal of Long-Lived Assets" (SFAS No. 144). SFAS No. 144
supersedes FASB Statement of Financial Accounting Standards No.
121, "Accounting for the Impairment of Long-Lived Assets and
for Long-Lived Assets to Be Disposed Of" (SFAS No. 121). SFAS
No. 121 did not address the accounting for a segment of a
business accounted for as a discontinued operation which
resulted in two accounting models for long-lived assets to be
disposed of. SFAS No. 144 establishes a single accounting
model for long-lived assets to be disposed of by sale and
requires that those long-lived assets be measured at the lower
of carrying amount or fair value less cost to sell, whether
reported in continuing operations or in discontinued
operations. SFAS No. 144 is effective for fiscal years
beginning after December 15, 2001. The company will adopt SFAS
No. 144 on January 1, 2002, but has not yet quantified the
effects of adopting SFAS No. 144 on its financial position or
results of operations.
The company adopted Statement of Financial Accounting
Standards No. 133, "Accounting for Derivative Instruments and
Hedging Activities" (SFAS No. 133), amended by Statement of
Financial Accounting Standards No. 137, "Accounting for
Derivative Instruments and Hedging Activities - Deferral of the
Effective Date of FASB Statement No. 133" and Statement of
Financial Accounting Standards No. 138, "Accounting for Certain
Derivative Instruments and Certain Hedging Activities" (all
such statements hereinafter referred to as SFAS No. 133) on
January 1, 2001. SFAS No. 133 establishes accounting and
reporting standards requiring that every derivative instrument
(including certain derivative instruments embedded in other
contracts) be recorded on the balance sheet as either an asset
or liability measured at its fair value. SFAS No. 133 requires
that changes in the derivative instrument's fair value be
recognized currently in earnings unless specific hedge
accounting criteria are met. Special accounting for qualifying
hedges allows derivative gains and losses to offset the related
results on the hedged item in the income statement, and
requires that a company must formally document, designate and
assess the effectiveness of transactions that receive hedge
accounting treatment.
SFAS No. 133 requires that as of the date of initial
adoption, the difference between the fair market value of
derivative instruments recorded on the balance sheet and the
previous carrying amount of those derivative instruments be
reported in net income or other comprehensive income (loss), as
appropriate, as the cumulative effect of a change in accounting
principle in accordance with APB 20, "Accounting Changes." On
January 1, 2001, the company reported a net-of-tax cumulative-
effect adjustment of $6.1 million in accumulated other
comprehensive loss to recognize at fair value all derivative
instruments that are designated as cash-flow hedging
instruments, which the company expects to reflect in earnings,
subject to changes in natural gas and oil market prices, over
the twelve months ending December 31, 2001. The transition to
SFAS No. 133 did not have an effect on the company's net income
at adoption.
7. Derivative instruments
As of September 30, 2001, the company held derivative
instruments designated as cash flow hedging instruments. All
derivative instruments are recognized on the Consolidated
Balance Sheets at fair value.
Hedging activities
The cash flow hedging instruments in place at September 30,
2001, are comprised of natural gas and oil price swap
agreements and an interest rate swap agreement. The objective
for holding the natural gas and oil price swap agreements is 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 objective for holding the interest rate swap agreement is
to manage a portion of the company's interest rate risk on the
forecasted issuances of fixed-rate debt under the company's
commercial paper program. The company designated each of the
natural gas and oil price swap agreements as a hedge of the
forecasted sale of natural gas and oil production and
designated the interest rate swap agreement as a hedge of the
risk of changes in interest rates on the company's forecasted
issuances of fixed-rate debt under the company's commercial
paper program.
The company's policy allows the use of derivative
instruments as part of an overall energy price and interest
rate risk management program to efficiently manage and minimize
commodity price and interest rate risk. The company's policy
prohibits the use of derivative instruments for speculating to
take advantage of market trends and conditions and the company
has procedures in place to monitor compliance with its
policies. The company is exposed to credit-related losses in
relation to hedged derivative instruments in the event of
nonperformance by counterparties. The company has policies and
procedures, which management believes minimize credit-risk
exposure. These policies and procedures include an evaluation
of potential counterparties' credit ratings, credit exposure
limitations, settlement of natural gas and oil price swap
agreements monthly and settlement of interest rate swap
agreements within 90 days. Accordingly, the company does not
anticipate any material effect to its financial position or
results of operations as a result of nonperformance by
counterparties.
Upon the adoption of SFAS No. 133, the company recorded the
fair market value of the natural gas and oil price swap
agreements on the company's Consolidated Balance Sheets. On an
ongoing basis, the company adjusts its balance sheet to reflect
the current fair market value of the natural gas and oil price
swap agreements and the interest rate swap agreement. The
related gains or losses on these agreements are recorded in
common stockholders' equity as a component of other
comprehensive income (loss). At the date the underlying
transaction occurs, the amounts accumulated in other
comprehensive income (loss) are reported in the Consolidated
Statements of Income. To the extent that the hedges are not
effective, the ineffective portion of the changes in fair
market value is recorded directly in earnings.
For the three months and nine months ended September 30,
2001, the company recognized the ineffectiveness of all cash-
flow hedges, which is included in operating revenues and
interest expense on the Consolidated Statements of Income for
the natural gas and oil price swap agreements and the interest
rate swap agreement, respectively. For the three months and
nine months ended September 30, 2001, the amount of
ineffectiveness recognized was immaterial. For the three
months and nine months ended September 30, 2001, the company
did not exclude any components of the derivative instruments'
loss from the assessment of hedge effectiveness and there were
no reclassifications into earnings as a result of the
discontinuance of hedges.
Gains and losses on derivative instruments that are
reclassified from accumulated other comprehensive income (loss)
to current-period earnings are included in the line item in
which the hedged item is recorded. As of September 30, 2001,
the maximum length of time over which the company is hedging
its exposure to the variability in future cash flows for
forecasted transactions is 15 months and the company estimates
that net gains of approximately $3.0 million will be
reclassified from accumulated other comprehensive income into
earnings, subject to changes in natural gas and oil market
prices and interest rates, within the twelve months between
October 1, 2001 and September 30, 2002 as the hedged
transactions affect earnings.
In the event a derivative instrument does not qualify for
hedge accounting because it is no longer highly effective in
offsetting changes in cash flows of a hedged item; or if the
derivative instrument expires or is sold, terminated, or
exercised; or if management determines that designation of the
derivative instrument as a hedge instrument is no longer
appropriate, hedge accounting will be discontinued, and the
derivative instrument would continue to be carried at fair
value with changes in its fair value recognized in earnings.
In these circumstances, the net gain or loss at the time of
discontinuance of hedge accounting would remain in other
comprehensive income (loss) until the period or periods during
which the hedged forecasted transaction affects earnings, at
which time the net gain or loss would be reclassified into
earnings. In the event a cash flow hedge is discontinued
because it is unlikely that a forecasted transaction will
occur, the derivative instrument would continue to be carried
on the balance sheet at its fair value, and gains and losses
that were accumulated in other comprehensive income (loss)
would be recognized immediately in earnings. The company's
policy requires approval to terminate a hedge agreement prior
to its original maturity.
Energy marketing
The company had entered into other derivative instruments
that were not designated as hedges in its energy marketing
operations. In the third quarter of 2001, the company sold the
vast majority of its energy marketing operations. The
derivative instruments entered into by these operations prior
to the sale in the third quarter of 2001 were natural gas
forward purchase and sale commitments. These commitments
involved the purchase and sale of natural gas and related
delivery of such commodity. These operations sought to match
natural gas purchases and sales on specific derivative
instruments so that a margin was obtained on the transportation
of such commodity as distinguished from earning a margin on
changes in market prices. The net change in fair value
representing unrealized gains and losses resulting from changes
in market prices on these derivative instruments was reflected
as operating revenues or purchased natural gas sold on the
company's Consolidated Statements of Income. Net unrealized
gains and losses on these derivative instruments were not
material for the three months and nine months ended September
30, 2001 and 2000.
8. Comprehensive income
Upon the adoption of SFAS No. 133 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
September 30, 2001, the company has recorded unrealized gains
and losses on natural gas and oil price swap and interest rate
swap agreements in accordance with SFAS No. 133. These amounts
are reflected in the following table. For additional
information on the adoption of SFAS No. 133, see Notes 6 and 7
of the Notes to the Consolidated Financial Statements.
The company's comprehensive income, and the components of
other comprehensive income, net of taxes, were as follows:
Three Months Ended
September 30,
2001 2000
(In thousands)
Net income $ 50,746 $ 39,992
Other comprehensive income -
Net unrealized gain on derivative
instruments qualifying as hedges:
Net unrealized gain on derivative
instruments arising during the
period, net of tax of $1,191 1,824 ---
Reclassification adjustment for
gains on derivative instruments
included in net income, net of
tax of $992 (1,519) ---
Net unrealized gain on derivative
instruments qualifying as hedges 305 ---
Comprehensive income $ 51,051 $ 39,992
Nine Months Ended
September 30,
2001 2000
(In thousands)
Net income $126,850 $ 74,483
Other comprehensive income -
Net unrealized gain 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 $2,782 4,262 ---
Reclassification adjustment for
losses on derivative instruments
included in net income, net of
tax of $3,355 5,138 ---
Net unrealized gain on derivative
instruments qualifying as hedges 3,320 ---
Comprehensive income $130,170 $ 74,483
9. Business segment data
The company's reportable business 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
segments. Substantially all of the company's operations are
located within the United States. 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 construction
company specializing in electric, natural gas and
telecommunication utility construction as well as interior
industrial electrical, exterior lighting and traffic
signalization. Utility services has engineering, design and
build capability and provides related specialty equipment sales
and rental services throughout most of the United States. The
pipeline and energy services segment provides natural gas
transportation, underground storage and gathering services
through regulated and nonregulated pipeline systems in the
Rocky Mountain, Midwest, Southern and Central regions of the
United States, provides energy-related marketing and management
services and invests in new growth and synergistic
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 and markets aggregates and
related value-added construction materials products and
services in Alaska, California, Hawaii, Minnesota, Montana,
Oregon, Washington and Wyoming.
On May 11, 2001, the company announced that the sale of its
coal operations to Westmoreland Coal Company for $28.8 million
in cash, excluding final settlement cost adjustments, had been
finalized. 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 2000 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 September 30, 2001
Electric $ 48,154 $ --- $ 8,265
Natural gas distribution 18,710 --- (2,747)
Utility services 92,208 --- 3,405
Pipeline and energy
services 59,430 5,391 3,895
Natural gas and oil
production 31,579 10,891 10,519
Construction materials
and mining 301,599 --- 27,219
Intersegment eliminations --- (16,282) ---
Total $ 551,680 $ --- $ 50,556
Three Months
Ended September 30, 2000
Electric $ 42,078 $ --- $ 5,920
Natural gas distribution 24,912 --- (2,180)
Utility services 60,056 --- 3,860
Pipeline and energy
services 136,679 7,508 2,997
Natural gas and oil
production 25,012 10,241 10,001
Construction materials
and mining 238,647 3,450* 19,203
Intersegment eliminations --- (17,749) ---
Total $ 527,384 $ 3,450* $ 39,801
* 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)
Nine Months
Ended September 30, 2001
Electric $ 129,143 $ --- $ 15,224
Natural gas distribution 200,809 --- (1,620)
Utility services 236,710 4 9,321
Pipeline and energy
services 454,819 34,197 9,656
Natural gas and oil
production 121,310 48,192 56,440
Construction materials
and mining 591,538 5,016* 37,258
Intersegment eliminations --- (82,393) ---
Total $1,734,329 $ 5,016* $ 126,279
Nine Months
Ended September 30, 2000
Electric $ 118,799 $ --- $ 12,179
Natural gas distribution 116,370 --- (270)
Utility services 107,243 --- 5,387
Pipeline and energy
services 381,989 37,622 6,645
Natural gas and oil
production 69,861 21,985 23,499
Construction materials
and mining 461,680 9,860* 26,468
Intersegment eliminations --- (59,607) ---
Total $1,255,942 $ 9,860* $ 73,908
* In accordance with the provisions of SFAS No. 71,
intercompany coal sales are not eliminated.
During the first nine months of 2001, the company acquired a
number of businesses, none of which was individually material,
including construction materials and mining businesses in
Hawaii, Minnesota and Oregon, utility services businesses based
in Missouri and Oregon and an energy services company
specializing in cable and pipeline locating and tracking
systems. The total purchase consideration, consisting of the
company's common stock and cash, for these businesses was
$165.4 million.
10. Regulatory matters and revenues subject to refund
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. On May 9, 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 the
pending regulatory proceeding. Williston Basin believes that
such reserves are adequate based on its assessment of the
ultimate outcome of the proceeding.
11. Litigation
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. On March 5, 2001, the North
Dakota District Court entered a final judgment on the July 2000
order granting the motions for summary judgment. On May 4,
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.
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 or 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. On May 18, 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.
On September 12, 2001, the defendants in this suit filed a
motion to dismiss with the State District Court.
Williston Basin and Montana-Dakota believe the claims of
Grynberg and Quinque are without merit and intend to vigorously
contest these suits.
12. 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.
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 and Centennial
Capital. 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 Nine Months
Ended Ended
September 30, September 30,
2001 2000 2001 2000
Electric $ 8.3 $ 5.9 $ 15.2 $12.2
Natural gas distribution (2.7) (2.2) (1.6) (.3)
Utility services 3.4 3.9 9.3 5.4
Pipeline and energy services 3.9 3.0 9.7 6.6
Natural gas and oil production 10.5 10.0 56.4 23.5
Construction materials and mining 27.2 19.2 37.3 26.5
Earnings on common stock $50.6 $ 39.8 $126.3 $73.9
Earnings per common
share - basic $ .75 $ .63 $ 1.89 $1.23
Earnings per common
share - diluted $ .74 $ .63 $ 1.87 $1.23
Return on average common equity
for the 12 months ended 17.0% 13.7%
________________________________
Three Months Ended September 30, 2001 and 2000
Consolidated earnings for the quarter ended September 30, 2001,
increased $10.8 million from the comparable period a year ago due to
higher earnings at the construction materials and mining, electric,
pipeline and energy services, and natural gas and oil production
businesses, partially offset by lower earnings at the other business
segments.
Nine Months Ended September 30, 2001 and 2000
Consolidated earnings for the nine months ended September 30,
2001, increased $52.4 million from the comparable period a year ago
due to higher earnings at the natural gas and oil production,
construction materials and mining, utility services, pipeline and
energy services and electric businesses, partially offset by lower
earnings at the natural gas distribution business segment.
________________________________
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 Nine Months
Ended Ended
September 30, September 30,
2001 2000 2001 2000
Operating revenues:
Retail sales $ 37.9 $ 34.4 $ 103.5 $ 98.9
Sales for resale and other 10.3 7.7 25.6 19.9
48.2 42.1 129.1 118.8
Operating expenses:
Fuel and purchased power 15.0 13.4 42.7 39.6
Operation and maintenance 10.5 10.0 34.0 31.9
Depreciation, depletion and
amortization 4.9 4.8 14.5 14.3
Taxes, other than income 1.8 1.7 5.6 5.6
32.2 29.9 96.8 91.4
Operating income $ 16.0 $ 12.2 $ 32.3 $ 27.4
Retail sales (million kWh) 597.3 561.7 1,640.4 1,592.1
Sales for resale (million kWh) 201.0 222.4 649.0 680.6
Average cost of fuel and
purchased power per kWh $ .018 $ .016 $ .018 $ .016
Natural Gas Distribution
Three Months Nine Months
Ended Ended
September 30, September 30,
2001 2000 2001 2000
Operating revenues:
Sales $ 17.8 $ 24.1 $ 197.9 $ 113.7
Transportation and other .9 .8 2.9 2.7
18.7 24.9 200.8 116.4
Operating expenses:
Purchased natural gas sold 10.7 16.8 162.6 82.2
Operation and maintenance 8.3 7.7 27.8 23.6
Depreciation, depletion and
amortization 2.3 2.3 7.0 6.1
Taxes, other than income 1.2 1.1 3.8 3.5
22.5 27.9 201.2 115.4
Operating income (loss) $ (3.8) $ (3.0) $ (0.4)$ 1.0
Volumes (MMdk):
Sales 3.0 3.2 24.6 21.2
Transportation 2.9 3.1 9.8 9.0
Total throughput 5.9 6.3 34.4 30.2
Degree days (% of normal) 88% 118% 98% 92%
Average cost of natural gas,
including transportation
thereon, per dk $ 3.53 $ 5.28 $ 6.61 $ 3.88
Utility Services
Three Months Nine Months
Ended Ended
September 30, September 30,
2001 2000 2001 2000
Operating revenues $ 92.2 $ 60.1 $ 236.7 $ 107.2
Operating expenses:
Operation and maintenance 80.7 49.5 206.4 89.9
Depreciation, depletion
and amortization 2.1 1.4 5.8 3.3
Taxes, other than income 2.6 1.9 6.2 3.5
85.4 52.8 218.4 96.7
Operating income $ 6.8 $ 7.3 $ 18.3 $ 10.5
Pipeline and Energy Services
Three Months Nine Months
Ended Ended
September 30, September 30,
2001 2000 2001 2000
Operating revenues:
Pipeline $ 22.7 $ 19.2 $ 64.9 $ 48.6
Energy services 42.1 125.0 424.1 371.0
64.8 144.2 489.0 419.6
Operating expenses:
Purchased natural gas sold 40.2 123.3 416.4 363.6
Operation and maintenance 10.4 9.0 33.9 26.6
Depreciation, depletion
and amortization 3.9 3.2 10.7 7.9
Taxes, other than income 1.6 1.4 4.6 3.7
56.1 136.9 465.6 401.8
Operating income $ 8.7 $ 7.3 $ 23.4 $ 17.8
Transportation volumes (MMdk):
Montana-Dakota 8.9 6.7 26.4 22.4
Other 19.2 15.5 46.8 42.3
28.1 22.2 73.2 64.7
Gathering volumes (MMdk) 15.2 13.2 44.0 28.0
Natural Gas and Oil Production
Three Months Nine Months
Ended Ended
September 30, September 30,
2001 2000 2001 2000
Operating revenues:
Natural gas $ 29.2 $ 21.3 $ 124.8 $ 51.0
Oil 12.4 11.6 38.9 32.5
Other .9 2.3 5.8 8.4
42.5 35.2 169.5 91.9
Operating expenses:
Purchased natural gas sold .7 .6 2.4 3.0
Operation and maintenance 11.9 8.5 34.7 23.4
Depreciation, depletion
and amortization 10.3 6.5 30.4 17.7
Taxes, other than income 2.3 2.1 8.7 6.1
25.2 17.7 76.2 50.2
Operating income $ 17.3 $ 17.5 $ 93.3 $ 41.7
Production:
Natural gas (MMcf) 9,921 7,361 29,641 20,198
Oil (000's of barrels) 510 486 1,492 1,428
Average realized prices:
Natural gas (per Mcf) $ 2.94 $ 2.90 $ 4.21 $ 2.52
Oil (per barrel) $ 24.33 $ 23.86 $ 26.04 $ 22.79
Construction Materials and Mining
Three Months Nine Months
Ended Ended
September 30, September 30,
2001 2000 2001 2000
Operating revenues:
Construction materials $ 301.6 $ 233.2 $ 584.3 $ 447.7
Coal --- 8.9 12.3 23.8
301.6 242.1 596.6 471.5
Operating expenses:
Operation and maintenance 236.5 193.0 489.7 387.8
Depreciation, depletion
and amortization 12.7 10.5 34.3 25.9
Taxes, other than income 4.2 3.9 12.4 9.7
253.4 207.4 536.4 423.4
Operating income $ 48.2 $ 34.7 $ 60.2 $ 48.1
Sales (000's):
Aggregates (tons) 11,023 6,700 19,951 13,510
Asphalt (tons) 3,310 1,627 4,732 2,583
Ready-mixed concrete
(cubic yards) 804 516 1,916 1,223
Coal (tons) --- 818 1,171 2,190
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 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: $16.3 million, $14.7 million
and $1.6 million for the three months ended September 30, 2001;
$17.8 million, $17.6 million and $.2 million for the three months
ended September 30, 2000; $82.4 million, $79.0 million and $3.4
million for the nine months ended September 30, 2001; and $59.6
million, $58.9 million and $.7 million for the nine months ended
September 30, 2000, respectively.
Three Months Ended September 30, 2001 and 2000
Electric
Electric earnings increased due to higher average realized sales
for resale prices, and increased retail sales volumes due largely to
an increased summer cooling load resulting from warmer weather
compared to the same period a year ago. Higher operation and
maintenance expense, primarily increased payroll costs, partially
offset the earnings increase.
Natural Gas Distribution
Earnings at the natural gas distribution business decreased due
to higher operation and maintenance expense, primarily increased
payroll costs and higher bad debt expense, and reduced operating
revenue caused by lower weather-related sales, the result of 24
percent warmer weather than the same period last year. The pass-
through of lower natural gas prices added to the decline in sales
revenue and purchased natural gas sold.
Utility Services
Utility services earnings declined largely due to lower
construction margins due, in part, to a slow down in the economy.
Higher selling, general and administrative expenses also added to
the earnings decline. Partially offsetting the earnings decrease
were higher equipment sales at existing operations and earnings from
businesses acquired since the comparable period last year.
Pipeline and Energy Services
Earnings at the pipeline and energy services business increased
due to higher transportation volumes moved to storage, higher
average rates and increased gathering volumes at the pipeline.
Higher operation and maintenance expense, primarily increased
material costs, higher contract services, and increased payroll
costs, the sale of the company's Kentucky energy services operations
and higher depreciation, depletion and amortization expense
partially offset the earnings increase. The decrease in energy
services revenue and the related decrease in purchased natural gas
sold resulted primarily from decreased energy marketing volumes,
largely at certain energy services operations which were sold, as
previously discussed.
Natural Gas and Oil Production
Natural gas and oil production earnings increased largely due to
an increase in natural gas and oil production of 35 percent and 5
percent since last year, respectively, combined with slightly higher
realized natural gas and oil prices. Higher realized prices were
the result of gains on hedging activities. The higher production
was the result of the ongoing development of existing properties.
Also adding to the earnings increase was lower interest expense, a
result of lower debt balances combined with lower average interest
rates. Partially offsetting the earnings improvement were increased
depreciation, depletion and amortization expense due to higher
production volumes and higher rates, increased operation and
maintenance expense, mainly higher lease operating expenses and
higher general and administrative costs, and lower sales volumes of
inventoried natural gas. Hedging activities for natural gas for the
third quarter of 2001 and 2000 resulted in realized prices that were
111 and 86 percent, respectively, of what otherwise would have been
received. In addition, hedging activities for oil for the third
quarter of 2001 and 2000 resulted in realized prices that were 102
and 81 percent, respectively, of what otherwise would have been
received.
Construction Materials and Mining
Earnings for the construction materials and mining business
increased largely as a result of earnings from businesses acquired
since the comparable period last year and from increases at existing
aggregate, asphalt and cement operations. Partially offsetting the
earnings increase were lower construction workloads and margins,
largely increased competition and less available work, due, in part,
to a slow down in the economy, and the timing of projects, at
certain West Coast operations. The absence of coal volumes due to
the sale of the coal operations, as previously discussed in Note 9
of Notes to the Consolidated Financial Statements, also partially
offset the earnings increase.
Nine Months Ended September 30, 2001 and 2000
Electric
Electric earnings increased due to higher average realized sales
for resale prices, increased retail sales volumes, as previously
discussed, and insurance recovery proceeds related to a 2000 outage
at an electric generating station. Increased fuel and purchased
power costs, largely due to an extended maintenance outage at an
electric power supplier's generating station, partially offset the
earnings increase. Also partially offsetting the earnings increase
were higher operation and maintenance expense, primarily higher
payroll costs.
Natural Gas Distribution
Earnings at the natural gas distribution business decreased as
a result of higher operation and maintenance expenses, primarily
increased bad debt expense and higher payroll costs. Decreased
return on natural gas storage, demand and prepaid commodity
balances, decreased service and repair margins, and lower average
realized rates, also added to the earnings decline. Slightly
offsetting the decline were increased sales, partially due to
weather that was 7 percent colder than the same period last year,
and earnings from a natural gas utility business acquired in July
2000. The pass-through of higher natural gas prices added to the
increase in sales revenue and purchased natural gas sold.
Utility Services
Utility services earnings increased as a result of earnings from
businesses acquired since the comparable period last year, as well
as increased workloads and equipment sales at existing operations.
The earnings improvement was partially offset by higher selling,
general and administrative costs.
Pipeline and Energy Services
Earnings at the pipeline and energy services business increased
due to higher transportation volumes combined with higher average
rates, increased gathering volumes and increased earnings from an
acquisition in June 2000 at the pipeline. Also contributing to the
earnings increase were higher natural gas sales margins, increased
pipeline and cable magnetization and locating services revenues at
energy services. Partially offsetting the earnings increase were
higher operation and maintenance expense, the write-off of an
investment in a software development company of $699,000 (after
tax), and increased depreciation, depletion and amortization
expense. The higher operations and maintenance expense was due
primarily to increased compressor-related expenses, higher payroll
expenses and increased contract services. The increase in energy
services revenue and the related increase in purchased natural gas
sold resulted from higher natural gas prices, partially offset by
decreased energy marketing volumes, as previously discussed.
Natural Gas and Oil Production
Natural gas and oil production earnings increased largely due to
increased realized natural gas and oil prices which were 67 percent
and 14 percent higher than last year, respectively, combined with
higher natural gas and oil production of 47 percent and 4 percent
since last year, respectively. The higher production was largely
the result of a natural gas property acquisition in April 2000 and
the ongoing development of that property as well as existing
properties. Also adding to the earnings increase was lower interest
expense, a result of lower debt balances combined with lower average
rates. Partially offsetting the earnings improvement were increased
depreciation, depletion and amortization expense, due to higher
production volumes and higher rates, increased operation and
maintenance expense, mainly higher lease operating expenses and
higher general and administrative costs, and lower sales volumes of
inventoried natural gas. Hedging activities for natural gas for the
nine months ended September 30, 2001 and 2000 resulted in realized
prices that were 99 and 89 percent, respectively, of what otherwise
would have been received. In addition, hedging activities for oil
for the nine months ended September 30, 2001 and 2000 resulted in
realized prices that were 102 and 83 percent, respectively, of what
otherwise would have been received.
Construction Materials and Mining
Earnings for the construction materials and mining business
increased largely due to a gain from the sale of the coal
operations of $11.0 million ($6.6 million after tax), included in
other income - net, as previously discussed, partially offset by
lower coal sales volumes due primarily to four months of operations
in 2001 compared to nine months in 2000. At the construction
materials business, earnings from businesses acquired since the
comparable period last year and increases largely from existing
asphalt and aggregate operations, also added to the earnings
improvement. Partially offsetting the earnings increase were lower
construction workloads and margins, as previously described, the
absence of last year's gain of $1.2 million after tax on the sale of
nonstrategic property, increased interest expense, the result of
higher acquisition-related borrowings, higher depreciation,
depletion and amortization due to increased plant balances, and
higher selling, general and administrative costs.
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 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), natural gas and oil commodity prices,
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, and the availability of
economic expansion or development opportunities.
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 the company for each of its
six major 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.
MDU Resources Group, Inc.
- Over the past five years, the company has experienced a
compound annual earnings per share growth rate of approximately 14
percent. Currently, the company anticipates that its earnings per
share growth rate for this single year will be approximately 17
percent to 28 percent, excluding the one-time gain from the sale of
the company's coal operations and the write-off of an investment
taken in the second quarter.
- Earnings per share, diluted, for 2001 are projected in the
$2.10 to $2.30 range, excluding the gain on the sale of the
company's coal operations and the write-off of an investment.
- Earnings per share, diluted, for 2002 are projected in the
$1.90 to $2.10 range.
- The company's long-term growth goals on compound annual
earnings per share from operations are in the range of 10 percent to
12 percent. However, the general weakening of the economy combined
with the recent terrorist events have added uncertainty in the
ability of the company to achieve this goal in the early years of
the planning cycle.
- The company expects to issue and sell equity from time to time
to keep its debt at the nonregulated businesses at no more than 40
percent of total capitalization.
- The company estimates that the benefit resulting solely from
the discontinuance of goodwill amortization would be five to six
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.
Previously, a smaller town in western North Dakota was considering
municipalization of Montana-Dakota's electric facilities. In August
2001, the voters of this town in a special election turned down the
opportunity to pursue municipalization of the electric system.
Montana-Dakota is currently negotiating the terms of a new franchise
with this town. 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.
- Due to growing electric demand, a gas-fired 40-megawatt
electric plant may be added in the three 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.
Natural Gas Distribution
- Annual natural gas throughput for 2001 is expected to be
approximately 54 million decatherms, with about 38 million
decatherms from sales and 16 million decatherms from transportation.
- The number of natural gas retail customers at existing
operations is expected to grow by approximately 1.5 percent on an
annual basis over the next three to five years.
Utility Services
- Revenues for this segment are expected to exceed $300 million
in 2001 and be approximately $500 million in 2002.
- This segment's goal is to achieve compound annual revenue and
earnings growth rates of approximately 20 percent to 25 percent over
the next five years. However, the general weakening of the economy
combined with the recent terrorist events have added uncertainty in
the ability of the company to achieve this goal in the early years
of the planning cycle.
Pipeline and Energy Services
- Two pipeline projects completed in 2000, are providing the
pipeline company the ability to move approximately 40 percent more
coalbed natural gas through its system than has historically been
transported, as well as enabling additional deliveries to
interconnecting pipeline systems, including the company's own
transmission system.
- In 2001, natural gas throughput, including transportation and
gathering, for this segment is expected to increase by approximately
10 percent to 20 percent.
- A 250-mile pipeline to transport additional gas to market and
enhance the use of the company's storage facilities is in the
planning stages and regulatory approval is expected to be sought
later this year.
Natural Gas and Oil Production
- During the first nine months of 2001, the company drilled 514
new wells in its coalbed fields and in other operated fields in
Montana and Colorado.
- Combined natural gas and oil production at this segment is
expected to be approximately 30 percent higher in 2001 than in 2000.
In 2002, this segment expects a combined production increase of
approximately 30 percent over 2001 levels.
- The company's estimates for natural gas prices in the Rocky
Mountain Region for November and December 2001 are in the range of
$2.00 to $2.50 per Mcf. The company's estimates for natural gas
prices on the NYMEX for November and December 2001 are in the range
of $2.50 to $3.25 per Mcf.
- During the first nine months of 2001, more than half of this
segment's natural gas production was priced using Mid-Continent or
Rocky Mountain prices.
- For 2002, the company's estimates for natural gas prices in the
Rocky Mountain Region are in the range of $2.25 to $2.75 per Mcf and
estimates for natural gas prices on the NYMEX are in the range of
$2.75 to $3.50.
- The company's estimates for NYMEX crude oil prices are in the
range of $20 to $25 per barrel for the remainder of 2001 and for
2002.
- This segment has entered into hedging arrangements for a
portion of its 2001 production. The company has entered into swap
agreements and fixed price forward sales representing approximately
30 percent to 35 percent of 2001 estimated annual natural gas
production. Natural gas swap prices range from $4.57 to $5.39 per
Mcf based on NYMEX and $4.04 to $4.44 per Mcf for Rocky Mountain gas
sales. In addition, approximately 30 percent to 35 percent of 2001
estimated annual oil production is hedged at NYMEX prices ranging
from $27.51 to $29.22 per barrel.
- This segment has hedged a portion of its 2002 production. The
company has entered into a swap agreement and fixed price forward
sales representing approximately 10 percent to 15 percent of 2002
estimated annual natural gas production. The natural gas swap is at
an average NYMEX price of $4.34 per Mcf. The company has also
entered into oil swap agreements at average NYMEX prices in the
range of $24.80 to $25.25 per barrel, representing approximately 20
percent to 25 percent of the company's 2002 estimated annual oil
production.
Construction Materials and Mining
- Aggregate, asphalt and ready-mixed concrete volumes are
expected to increase by approximately 35 percent to 45 percent, 75
percent to 85 percent and 40 percent to 50 percent, respectively, in
2001.
- This segment's goal is to achieve compound annual revenue and
earnings growth rates of approximately 10 percent to 20 percent over
the next five years. However, the general weakening of the economy
combined with the recent terrorist events have added uncertainty in
the ability of the company to achieve this goal in the early years
of the planning cycle.
- With the acquisitions made this year, aggregate reserves now
total more than 1 billion tons.
- With the acquisitions made this year and strong performance in
existing markets, 2001 revenues at this segment are expected to
exceed $750 million.
New Accounting Standards
In June 2001, the Financial Accounting Standards Board (FASB)
approved Statement of Financial Accounting Standards No. 141,
"Business Combinations" (SFAS No. 141), Statement of Financial
Accounting Standards No. 142, "Goodwill and Other Intangible Assets"
(SFAS No. 142), and Statement of Financial Accounting Standards No.
143, "Accounting for Asset Retirement Obligations" (SFAS No. 143).
In August 2001, the FASB approved Statement of Financial Accounting
Standards No. 144, "Accounting for the Impairment or Disposal of
Long-lived Assets" (SFAS No. 144). For more information on SFAS No.
141, SFAS No. 142, SFAS No. 143, and SFAS No. 144 see Note 6 of
Notes to Consolidated Financial Statements.
Liquidity and Capital Commitments
Net capital expenditures for the year 2001 are estimated at
$424.2 million, including those for acquisitions to date, system
upgrades, routine replacements, service extensions, routine
equipment maintenance and replacements, pipeline and gathering
expansion projects, the building of construction materials handling
and transportation facilities, the further enhancement of natural
gas and oil production and reserve growth, and for potential future
acquisitions and other growth opportunities. 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 2001
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,
the company's $40 million revolving credit and term loan agreement,
none of which is outstanding at September 30, 2001, 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 2001 capital expenditures referred to above
include completed 2001 acquisitions including construction materials
and mining businesses based in Hawaii, Minnesota, and Oregon,
utility services businesses based in Missouri and Oregon, and an
energy services company specializing in cable and pipeline locating
and tracking systems. 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.
Centennial, a direct wholly owned subsidiary of the company, has
a revolving credit agreement with various banks that supports
Centennial's $350 million commercial paper program. Under the
commercial paper program, $299.4 million was outstanding at
September 30, 2001. The commercial paper borrowings are classified
as long term as Centennial intends to refinance these borrowings on
a long-term basis through continued commercial paper borrowings
supported by the revolving credit agreement. Centennial intends to
renew this existing credit agreement on an annual basis.
Centennial has an uncommitted long-term master shelf agreement
that allows for borrowings of up to $300 million. Under the master
shelf agreement, $210 million was outstanding at September 30, 2001.
On September 28, 2001, the company reported the sale of 1,105,353
shares of the company's Common Stock to Acqua Wellington North
American Equities Fund, Ltd. (Acqua Wellington), pursuant to a
purchase agreement by and between the company and Acqua Wellington.
The company received proceeds from this sale of $25 million. These
proceeds are anticipated to be used for refunding of outstanding
debt obligations and for other general corporate purposes.
The company's issuance of first mortgage debt is subject to
certain restrictions imposed under the terms and conditions of
its Indenture of Mortgage. Generally, those restrictions require
the company to 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 September 30, 2001, the company could have issued
approximately $300 million of additional first mortgage bonds.
The company's coverage of fixed charges including preferred
dividends was 5.4 times and 4.1 times for the twelve months ended
September 30, 2001, and December 31, 2000, respectively.
Additionally, the company's first mortgage bond interest coverage
was 9.6 times and 8.3 times for the twelve months ended
September 30, 2001, and December 31, 2000, respectively. Common
stockholders' equity as a percent of total capitalization was 56
percent and 54 percent at September 30, 2001, and December 31, 2000,
respectively.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
There are no material changes in market risk faced by the company
from those reported in the company's Annual Report on Form 10-K for
the year ended December 31, 2000. For more information on market
risk, see Part II, Item 7A in the company's Annual Report on Form 10-
K for the year ended December 31, 2000, and Notes to Consolidated
Financial Statements in this form 10-Q.
PART II -- OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
On September 12, 2001, the defendants in the Quinque legal
proceeding filed a motion to dismiss with the State District Court.
For more information on this legal action, see Note 11 of Notes to
Consolidated Financial Statements.
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
a) Exhibits
12 Computation of Ratio of Earnings to Fixed Charges and
Combined Fixed Charges and Preferred Stock Dividends
b) Reports on Form 8-K
Form 8-K was filed on September 21, 2001. Under Item 5 -- Other
Events, the company reported the press release issued September
20, 2001, regarding natural gas price volatility.
Form 8-K was filed on September 28, 2001. Under Item 5 -- Other
Events, the company reported the sale of 1,105,353 shares of
company Common Stock to Acqua Wellington North American Equities
Fund, Ltd.
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act
of 1934, the registrant has duly caused this report to be signed
on its behalf by the undersigned thereunto duly authorized.
MDU RESOURCES GROUP, INC.
DATE October 26, 2001 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.
12 Computation of Ratio of Earnings to Fixed Charges
and Combined Fixed Charges and Preferred Stock
Dividends