UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
X QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
FOR THE QUARTERLY PERIOD ENDED MARCH 31, 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 May 7, 2001: 67,928,033 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.
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 and
provides energy-related marketing and management services in
the Rocky Mountain, Midwest, Southern and Central regions of
the United States. 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. On May 11, 2001, the company announced that the
sale of its coal operations to Westmoreland Coal Company has
been finalized. For more information on the above sale see
Note 7 of Notes to Consolidated Financial Statements and
Prospective Information contained in Item 2 -- Management's
Discussion and Analysis of Financial Condition and
Results of Operations.
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 Holdings Capital Corp. anticipates making investments
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.
INDEX
Part I -- Financial Information
Consolidated Statements of Income --
Three Months Ended March 31, 2001 and 2000
Consolidated Balance Sheets --
March 31, 2001 and 2000, and December 31, 2000
Consolidated Statements of Cash Flows --
Three Months Ended March 31, 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 Ended
March 31,
2001 2000
(In thousands, except
per share amounts)
Operating revenues $641,248 $371,989
Operating expenses:
Fuel and purchased power 13,088 14,399
Purchased natural gas sold 325,771 171,770
Operation and maintenance 195,086 125,918
Depreciation, depletion and amortization 32,096 22,139
Taxes, other than income 11,686 8,333
577,727 342,559
Operating income 63,521 29,430
Other income -- net 2,358 2,368
Interest expense 11,714 10,281
Income before income taxes 54,165 21,517
Income taxes 21,478 8,153
Net income 32,687 13,364
Dividends on preferred stocks 191 192
Earnings on common stock $ 32,496 $ 13,172
Earnings per common share -- basic $ .50 $ .23
Earnings per common share -- diluted $ .49 $ .23
Dividends per common share $ .22 $ .21
Weighted average common shares outstanding -- basic 65,405 57,051
Weighted average common shares outstanding -- diluted 65,979 57,188
The accompanying notes are an integral part of these consolidated statements.
MDU RESOURCES GROUP, INC.
CONSOLIDATED BALANCE SHEETS
(Unaudited)
March 31, March 31, December 31,
2001 2000 2000
(In thousands)
ASSETS
Current assets:
Cash and cash equivalents $ 30,978 $ 37,622 $ 36,512
Receivables 312,790 179,585 342,354
Inventories 65,146 57,468 64,017
Deferred income taxes 12,834 16,564 8,048
Prepayments and other current assets 27,193 29,452 29,355
448,941 320,691 480,286
Investments 42,101 42,907 41,380
Property, plant and equipment 2,557,908 2,066,881 2,496,123
Less accumulated depreciation,
depletion and amortization 919,627 809,568 895,109
1,638,281 1,257,313 1,601,014
Deferred charges and other assets 198,285 122,959 190,279
$2,327,608 $1,743,870 $2,312,959
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Short-term borrowings $ --- $ --- $ 8,000
Long-term debt and preferred
stock due within one year 9,228 3,841 19,695
Accounts payable 148,244 98,245 171,929
Taxes payable 33,127 13,704 10,437
Dividends payable 14,751 12,174 14,423
Other accrued liabilities,
including reserved revenues 91,012 80,412 59,989
296,362 208,376 284,473
Long-term debt 679,094 518,164 728,166
Deferred credits and other liabilities:
Deferred income taxes 283,982 215,621 281,000
Other liabilities 123,514 114,117 121,860
407,496 329,738 402,860
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, 66,441,325
at March 31, 2001, 57,296,167 at
March 31, 2000 and 65,267,567 at
December 31, 2000) 66,441 57,296 65,268
Other paid-in capital 547,859 372,661 518,771
Retained earnings 318,585 244,761 300,647
Accumulated other comprehensive loss (1,003) --- ---
Treasury stock at cost - 239,521
shares (3,626) (3,626) (3,626)
Total common stockholders' equity 928,256 671,092 881,060
Total stockholders' equity 943,256 686,092 896,060
$2,327,608 $1,743,870 $2,312,959
The accompanying notes are an integral part of these consolidated statements.
MDU RESOURCES GROUP, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Three Months Ended
March 31,
2001 2000
(In thousands)
Operating activities:
Net income $ 32,687 $ 13,364
Adjustments to reconcile net income to net cash provided
by operating activities:
Depreciation, depletion and amortization 32,096 22,139
Deferred income taxes and investment tax credit (931) 969
Changes in current assets and liabilities, net of
acquisitions:
Receivables 53,030 (9,938)
Inventories (948) 7,250
Other current assets 6,387 (5,028)
Accounts payable (35,054) 16,966
Other current liabilities 49,714 19,346
Other noncurrent changes (4,372) 71
Net cash provided by operating activities 132,609 65,139
Investing activities:
Capital expenditures including acquisitions of businesses (87,069) (32,628)
Net proceeds from sale or disposition of property 4,194 1,219
Net capital expenditures (82,875) (31,409)
Investments 3 221
Additions to notes receivable --- (5,000)
Proceeds from notes receivable 4,000 4,000
Net cash used in investing activities (78,872) (32,188)
Financing activities:
Net change in short-term borrowings (8,000) (14,693)
Issuance of long-term debt 60,000 25,400
Repayment of long-term debt (121,971) (71,368)
Issuance of common stock 25,449 ---
Dividends paid (14,749) (12,172)
Net cash used in financing activities (59,271) (72,833)
Decrease in cash and cash equivalents (5,534) (39,882)
Cash and cash equivalents -- beginning of year 36,512 77,504
Cash and cash equivalents -- end of period $ 30,978 $ 37,622
The accompanying notes are an integral part of these consolidated statements.
MDU RESOURCES GROUP, INC.
NOTES TO CONSOLIDATED
FINANCIAL STATEMENTS
March 31, 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:
Three Months Ended
March 31,
2001 2000
(In thousands)
Interest, net of amount capitalized $7,168 $4,728
Income taxes $ 280 $ 600
4. New accounting pronouncement
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." 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.
5. Derivative instruments
As of March 31, 2001, the company held derivative
instruments designated as cash flow hedging instruments and
other derivative instruments in relation to its energy
marketing operations which have not been designated as hedges.
All derivative instruments are recognized on the Consolidated
Balance Sheets at fair value.
Hedging activities
The cash flow hedging instruments in place at March 31,
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 ended March 31, 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 ended March 31, 2001, the
amount of ineffectiveness recognized was immaterial. For the
three months ended March 31, 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 March 31, 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 nine months and the company estimates that
losses of $1.0 million will be reclassified from accumulated
other comprehensive loss into earnings, subject to changes in
natural gas and oil market prices and interest rates, within
the nine months between April 1, 2001 and December 31, 2001 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
In its energy marketing operations, the company enters into
other derivative instruments that have not been designated as
hedges. These derivative instruments are natural gas forward
purchase and sale commitments. These commitments involve the
purchase and sale of natural gas and related delivery of such
commodity. The energy marketing operations seek to match
natural gas purchases and sales on specific derivative
instruments so that a margin is obtained on the transportation
of such commodity as distinguished from earning a margin on
changes in market prices. In addition, the energy marketing
derivative instruments are generally entered into on a seasonal
basis with a duration generally not exceeding 12 months. The
net change in fair value representing unrealized gains and
losses resulting from changes in market prices on these
derivative instruments is 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
ended March 31, 2001 and 2000.
The company is exposed to credit risk in relation to
derivative instruments entered into at the company's energy
marketing operations in the event of nonperformance by
counterparties. The company maintains credit procedures, which
management believes minimize credit-risk exposure. These
procedures include applying specific eligibility criteria to
prospective counterparties and may require letters of credit or
similar security to secure payment on such sales contracts.
However, despite mitigation efforts, defaults by counterparties
may occur. To date, no such defaults have had a material
effect on the company's financial position or results of
operations.
6. 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
March 31, 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 4 and 5 of the Notes to
the Consolidated Financial Statements in this Form 10-Q.
The company's comprehensive income, and the components of
other comprehensive loss, net of taxes, were as follows:
Three Months Ended
March 31,
2001 2000
(In thousands)
Net income $ 32,687 $ 13,364
Other comprehensive loss - unrealized
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) ---
Unrealized gain on derivative
instruments arising during the
period, net of tax of $1,631 2,498 ---
Reclassification adjustment for
losses on derivative instruments
included in net income, net of tax of
$1,684 2,579 ---
Net unrealized loss on derivative
instruments qualifying as hedges (1,003) ---
Comprehensive income $ 31,684 $ 13,364
7. 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. 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 business 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 and
provides energy-related marketing and management services in
the Rocky Mountain, Midwest, Southern and Central regions of
the United States. 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, has been
finalized. 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
will record a gain from the sale in the second quarter of 2001.
The company's estimate of the gain on the sale of the coal operations
is in the range of $4 million to $8 million after tax and is subject
to various post-closing adjustments.
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 March 31, 2001
Electric $ 42,953 $ --- $ 4,807
Natural gas distribution 140,855 --- 2,674
Utility services 67,319 4 2,044
Pipeline and energy
services 248,276 21,374 2,378
Natural gas and oil
production 49,215 22,417 28,032
Construction materials
and mining 88,787 3,843* (7,439)
Intersegment eliminations --- (43,795) ---
Total $ 637,405 $ 3,843* $ 32,496
Three Months
Ended March 31, 2000
Electric $ 40,320 $ --- $ 3,223
Natural gas distribution 62,417 --- 2,580
Utility services 22,836 --- 453
Pipeline and energy
services 147,738 20,497 2,729
Natural gas and oil
production 23,043 4,190 6,409
Construction materials
and mining 72,050 3,585* (2,222)
Intersegment eliminations --- (24,687) ---
Total $ 368,404 $ 3,585* $ 13,172
* 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.
8. 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, which is
subject to revision by the FERC, on Williston Basin's natural
gas rate change application. Williston Basin is evaluating the
implications of the Initial Decision.
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.
9. 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. Williston Basin and Montana-
Dakota are awaiting a decision from the Federal District Court.
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, 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 for Stevens County, Kansas.
Williston Basin and Montana-Dakota believe the claims of
Grynberg and Quinque are without merit and intend to vigorously
contest these suits.
10. 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 and energy marketing and management services. 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
Ended
March 31,
2001 2000
Electric $ 4.8 $ 3.2
Natural gas distribution 2.7 2.6
Utility services 2.0 .5
Pipeline and energy services 2.4 2.7
Natural gas and oil production 28.0 6.4
Construction materials and mining (7.4) (2.2)
Earnings on common stock $ 32.5 $ 13.2
Earnings per common share - basic $ .50 $ .23
Earnings per common share - diluted $ .49 $ .23
Return on average common equity
for the 12 months ended 15.6% 13.4%
________________________________
Three Months Ended March 31, 2001 and 2000
Consolidated earnings for the quarter ended March 31, 2001,
increased $19.3 million from the comparable period a year ago due
to higher earnings at the natural gas and oil production, utility
services, electric, and natural gas distribution businesses,
partially offset by lower earnings at the other business
segments.
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
Ended
March 31,
2001 2000
Operating revenues:
Retail sales $ 34.5 $ 34.0
Sales for resale and other 8.5 6.3
43.0 40.3
Operating expenses:
Fuel and purchased power 13.1 14.4
Operation and maintenance 12.6 11.3
Depreciation, depletion and amortization 4.9 4.7
Taxes, other than income 2.0 2.1
32.6 32.5
Operating income $ 10.4 $ 7.8
Retail sales (million kWh) 549.7 546.5
Sales for resale (million kWh) 267.6 256.8
Average cost of fuel and purchased
power per kWh $ .015 $ .017
Natural Gas Distribution
Three Months
Ended
March 31,
2001 2000
Operating revenues:
Sales $ 139.7 $ 61.4
Transportation and other 1.2 1.0
140.9 62.4
Operating expenses:
Purchased natural gas sold 120.9 45.8
Operation and maintenance 10.8 8.5
Depreciation, depletion and amortization 2.3 1.9
Taxes, other than income 1.4 1.3
135.4 57.5
Operating income $ 5.5 $ 4.9
Volumes (MMdk):
Sales 16.2 13.3
Transportation 4.2 3.4
Total throughput 20.4 16.7
Degree days (% of normal) 98% 87%
Average cost of natural gas, including
transportation thereon, per dk $ 7.46 $ 3.45
Utility Services
Three Months
Ended
March 31,
2001 2000
Operating revenues $ 67.3 $ 22.8
Operating expenses:
Operation and maintenance 59.1 20.0
Depreciation, depletion and amortization 1.9 .9
Taxes, other than income 1.8 .8
62.8 21.7
Operating income $ 4.5 $ 1.1
Pipeline and Energy Services
Three Months
Ended
March 31,
2001 2000
Operating revenues:
Pipeline $ 21.0 $ 15.1
Energy services 248.6 153.2
269.6 168.3
Operating expenses:
Purchased natural gas sold 247.0 149.1
Operation and maintenance 11.6 8.9
Depreciation, depletion and amortization 3.4 2.2
Taxes, other than income 1.5 1.4
263.5 161.6
Operating income $ 6.1 $ 6.7
Transportation volumes (MMdk):
Montana-Dakota 8.5 8.7
Other 10.4 11.3
18.9 20.0
Gathering volumes (MMdk) 14.6 7.1
Natural Gas and Oil Production
Three Months
Ended
March 31,
2001 2000
Operating revenues:
Natural gas $ 54.4 $ 14.0
Oil 13.5 10.4
Other 3.7 2.8
71.6 27.2
Operating expenses:
Purchased natural gas sold .7 1.3
Operation and maintenance 11.0 6.9
Depreciation, depletion and amortization 9.5 5.6
Taxes, other than income 3.8 2.0
25.0 15.8
Operating income $ 46.6 $ 11.4
Production:
Natural gas (MMcf) 9,689 6,466
Oil (000's of barrels) 494 471
Average realized prices:
Natural gas (per Mcf) $ 5.62 $ 2.17
Oil (per barrel) $ 27.33 $ 21.97
Construction Materials and Mining
Three Months
Ended
March 31,
2001 2000
Operating revenues:
Construction materials $ 83.2 $ 68.4
Coal 9.4 7.2
92.6 75.6
Operating expenses:
Operation and maintenance 90.9 70.5
Depreciation, depletion and amortization 10.1 6.8
Taxes, other than income 1.2 .8
102.2 78.1
Operating loss $ (9.6) $ (2.5)
Sales (000's):
Aggregates (tons) 2,689 2,126
Asphalt (tons) 124 93
Ready-mixed concrete (cubic yards) 391 288
Coal (tons) 904 678
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: $43.8 million, $42.9
million and $.9 million for the three months ended March 31, 2001;
and $24.6 million, $24.4 million and $.2 million for the three
months ended March 31, 2000, respectively.
Three Months Ended March 31, 2001 and 2000
Electric
Electric earnings increased due to increased sales for resale
volumes at higher average realized rates, primarily the result of a
strong sales for resale market, and lower fuel and purchased power
costs, largely due to insurance recovery proceeds related to a 2000
outage at an electric generating station. Higher operation and
maintenance expense, primarily increased payroll expense and higher
subcontractor costs, partially offset the earnings increase.
Natural Gas Distribution
Earnings increased at the natural gas distribution business due
to higher retail sales volumes resulting from weather that was 12
percent colder than the comparable period last year and earnings
from a business acquired in July 2000. This increase was largely
offset by higher operation and maintenance expense, primarily
increased payroll expense and higher bad debt expense. Lower
service and repair margins and lower average realized rates, also
partially offset the earnings improvement. Significantly higher
natural gas prices also added to the increase in sales revenue and
purchased natural gas sold.
Utility Services
Utility services earnings increased as a result of higher line
construction margins in the Rocky Mountain region, primarily related
to fiber-optic-cable installation projects, and earnings from
businesses acquired since the comparable period last year.
Pipeline and Energy Services
Earnings at the pipeline and energy services business decreased
due to higher operation and maintenance expense, primarily higher
compressor-related expenses and outside services, and decreased
storage revenues. Higher natural gas throughput at the pipeline
partially offset the earnings decline. The increase in energy
services revenue and the related increase in purchased natural gas
sold resulted from significantly higher natural gas prices.
Natural Gas and Oil Production
Natural gas and oil production earnings increased largely due to
an increase in natural gas and oil production of 50 percent and 5
percent since last year, respectively, combined with higher realized
natural gas and oil prices which were 159 percent and 24 percent
higher than last year, respectively. The higher production was due
to an acquisition since the comparable period last year and ongoing
development of existing properties. Higher margins on inventoried
natural gas also added to the earnings increase. Partially
offsetting the earnings improvement were increased depreciation,
depletion and amortization expense, due to higher production volumes
and higher rates, and increased operation and maintenance expense,
mainly higher lease operating expenses and higher general and
administrative costs due primarily to an acquisition. Hedging
activities for natural gas for the first three months of 2001
resulted in realized prices that were 93 percent of what otherwise
would have been received. Hedging activities for natural gas for
the first three months of 2000 resulted in realized prices that were
unchanged. In addition, hedging activities for oil for the first
three months of 2001 and 2000 resulted in realized prices that were
102 and 84 percent, respectively, of what otherwise would have been
received.
Construction Materials and Mining
Earnings for the construction materials and mining business
decreased largely due to lower earnings at the construction
materials operations as a result of normal seasonal losses realized
in the first quarter of 2001 by businesses acquired since the
comparable period last year and higher interest expense resulting
from higher acquisition-related borrowings. Also adding to the
earnings decline were increased selling, general and administrative
costs and decreased construction activity, due to weather-related
delays, partially offset by increased aggregate and ready-mixed
concrete volumes at existing construction materials operations.
Earnings at the coal operations improved mainly due to increased
coal volumes.
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, 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 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.
* The company anticipates that its earnings per share growth rate
from operations for 2001 will be in excess of 25 percent.
* Earnings per share, diluted, from operations for 2001 are
projected in the $2.30 to $2.50 range, excluding a gain from the
sale of the company's coal operations.
* The company expects the percentage of 2001 earnings per share
from operations for the following quarters to be in the following
approximate ranges:
- Second Quarter: 20 to 25 percent
- Third Quarter: 30 to 35 percent
- Fourth Quarter: 20 to 25 percent
* 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.
* Based on existing operations and current accounting rules,
annual goodwill amortization expense is expected to be approximately
$4.7 million.
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.
Currently, a smaller town in western North Dakota is considering
municipalization of Montana-Dakota's electric facilities. Montana-
Dakota is vigorously contesting any such proposal but is currently
unable to determine the ultimate outcome of any such proceeding.
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 North Dakota Lignite
Research Council to determine the feasibility of constructing a 500
megawatt class lignite-fired power plant in western North Dakota.
Natural gas distribution
* Annual natural gas throughput for 2001 is expected to be
approximately 55 million decatherms, with about 39 million
decatherms from sales and 16 million from transportation.
* The number of natural gas retail customers at existing
operations is expected to grow by approximately 1.5 to 2 percent on
an annual basis over the next three to five years.
* This business segment expects growth in sales of new value-
added products and services, such as appliance repair contracts and
home security systems.
Utility services
* This segment is growing both internally and through acquisitions of
utility services companies. The company's strategy is to acquire
utility services businesses that are well managed, have excellent
reputations and are growth-driven.
* Revenues for the utility services segment are expected to exceed
$300 million in 2001.
* This business segment's goal is to achieve compound annual revenue
and earnings growth rates of approximately 20 to 25 percent over the
next five years.
Pipeline and energy services
* Two pipeline projects related to the company's coal bed natural
gas drilling program in the Powder River Basin of Wyoming and
Montana were completed in 2000. The two projects provide the
pipeline company the ability to move approximately 40 percent more
coal bed natural gas through its system than has historically been
transported, as well as enabling additional deliveries to other
pipeline systems. The largest project involved building a 75-mile,
nonregulated pipeline through the heart of the basin, to move gas
produced from throughout the Powder River Basin to interconnecting
pipeline systems, including the company's own transmission system.
* In 2001, natural gas throughput for this segment is expected to
increase by approximately 10 to 20 percent.
* This segment continues business development activities looking
for assets and resources or system expansions that add value to
existing operations through further vertical integration of its
natural gas delivery and storage systems.
Natural gas and oil production
* The 2001 drilling program is projected to include over 500
wells, 90 percent of which are expected to be drilled on company
operated properties and the emphasis will continue to be on natural
gas. The 2001 drilling program is expected to be the single largest
drilling program in the company's history.
* During the first quarter of 2001, 159 wells were drilled, 98
percent of which were completed.
* Combined natural gas and oil production in 2000 totaled 40.5
Bcf equivalents - a daily average of 111,000 Mcf equivalents. For
the month of March 2001, combined production averaged 135,500 Mcf
equivalents per day, which was 38 percent higher than March 2000.
* Currently, there are approximately 165 wells producing in the
Powder River Basin of Wyoming and Montana. For the month of March,
gross production averaged 19,200 Mcf equivalents per day.
* Combined natural gas and oil production at this business
segment is expected to be approximately 30 percent higher in 2001
than in 2000.
* The company's estimates for natural gas prices in the Rocky
Mountain region for April through December 2001 are in the range of
$3.15 to $4.15 per Mcf. The company's estimates for natural gas
prices on the NYMEX for April through December 2001 are in the range
of $3.75 to $4.75 per Mcf.
* The company's estimates for NYMEX crude oil prices are in the
range of $23 to $27 per barrel for April through December 2001.
* This business 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
25 to 30 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 35 to 40 percent of 2001 estimated annual
oil production is hedged at NYMEX prices ranging from $27.51 to
$29.22 per barrel.
* This business segment has entered into a hedging arrangement
for a portion of its 2002 production. The company has entered into
an oil swap agreement at an average NYMEX price of $25.25 per
barrel. This swap agreement represents approximately 8 percent of
the company's 2002 estimated annual oil production. At this time,
the company has not entered into any natural gas swap agreements for
2002 natural gas production. However, the company has approximately
10 percent of its estimated 2002 annual natural gas production under
fixed price forward sales.
Construction materials and mining
* 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, has been finalized.
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 will record
a gain from the sale in the second quarter of 2001. The company's
estimate of the gain on the sale of the coal operations is in the
range of $4 million to $8 million after tax and is subject to various
post-closing adjustments. While the sale will add to the company's
2001 earnings, future earnings will be decreased as a result of the
loss of earnings from the coal operations. Earnings from coal
operations would normally be expected to contribute less than
10 percent of annual earnings of the construction materials
and mining segment.
* The construction materials and mining business estimates that
it currently has nearly one billion tons of economically recoverable
aggregate reserves. These reserves are strategically located and
represent more than a 40-year supply at current consumption levels.
* Including the effects of acquisitions completed in 2000 and
2001, aggregate, asphalt and ready-mixed concrete volumes are
expected to increase by approximately 35 to 45 percent, 80 to 90
percent and 35 to 45 percent, respectively, in 2001.
* As of mid-April, the construction materials and mining unit had
approximately $197 million in backlog.
* This segment expects to achieve compound annual revenue and
earnings growth rates of approximately 10 to 20 percent over the
next five years.
* Earnings are expected to increase from a combination of
acquisitions and by optimizing both synergies and improvements at
existing operations.
Liquidity and Capital Commitments
Net capital expenditures for the year 2001 are estimated at
$354.1 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. The company continues to evaluate potential future
acquisitions; however, these acquisitions 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 March 31, 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 two completed 2001 acquisitions including a construction
materials and mining company based in Minnesota that was acquired in
mid-April 2001 and a utility services company based in Missouri that
was acquired in early January 2001. 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 on behalf of its
subsidiaries that supports $315 million of Centennial's $325 million
commercial paper program. Under the commercial paper program,
$192.9 million was outstanding at March 31, 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 due September 29, 2003. Centennial intends to renew this
existing credit agreement on an annual basis.
Centennial has an uncommitted long-term master shelf agreement
on behalf of its subsidiaries that allows for borrowings of up to
$200 million. Under the master shelf agreement, $150 million was
outstanding at March 31, 2001.
On March 6, 2001, the company reported the sale of 358,429
shares of the company's Common Stock to Paul Revere Capital Partners
Ltd. (Paul Revere), pursuant to a purchase agreement by and between
the company and Paul Revere. The company received proceeds from
this sale of $10 million. These proceeds were 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 March 31, 2001, the company could have issued
approximately $297 million of additional first mortgage bonds.
The company's coverage of fixed charges including preferred
dividends was 4.5 times and 4.1 times for the twelve months ended
March 31, 2001, and December 31, 2000, respectively. Additionally,
the company's first mortgage bond interest coverage was 9.0 times
and 8.3 times for the twelve months ended March 31, 2001, and
December 31, 2000, respectively. Common stockholders' equity as a
percent of total capitalization was 57 percent and 54 percent at
March 31, 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 March 5, 2001, the North Dakota District Court entered
a final judgment on the July 2000 order granting the motions for
summary judgment to dismiss the claims of the 11 natural gas
producers. 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.
Upon motion of plaintiffs, the Quinque case has been remanded
to State District Court for Stevens County, Kansas.
For more information on the above legal actions see Note 9 of
Notes to Consolidated Financial Statements.
ITEM 2. CHANGES IN SECURITIES AND USE OF PROCEEDS
Between January 1, 2001 and March 31, 2001, the company issued
264,728 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 a business 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 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
The company's Annual Meeting of Stockholders was held on
April 24, 2001. Two proposals were submitted to stockholders as
described in the company's Proxy Statement dated March 9, 2001, and
were voted upon and approved by stockholders at the meeting. The
table below briefly describes the proposals and the results of the
stockholder votes.
Shares
Shares Against or Broker
For Withheld Abstentions Non-Votes
Proposal to amend the 1997
Executive Long-Term Incentive
Plan 31,528,117 8,272,505 1,038,761 12,770,086
Proposal to elect five directors:
For terms expiring in 2004 --
Dennis W. Johnson 51,899,581 1,709,888 --- ---
John L. Olson 53,240,868 368,601 --- ---
Joseph T. Simmons 53,221,546 387,923 --- ---
Martin A. White 53,269,790 339,679 --- ---
For a term expiring in 2002 --
Douglas C. Kane 53,212,205 397,264 --- ---
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
a) Exhibits
10(a) 1997 Executive Long-Term Incentive Plan, as amended to date
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 March 8, 2001. Under Item 5 -- Other
Events, the company reported the sale of 358,429 shares of
company Common Stock to Paul Revere Capital Partners Ltd.
Form 8-K was filed on March 20, 2001. Under Item 5 -- Other
Events, the company reported the press release issued March 14,
2001 regarding revised earnings forecast for 2001.
Form 8-K was filed on April 25, 2001. Under Item 5 -- Other
Events, the company reported the press release issued April 24,
2001 regarding earnings for the quarter ended March 31, 2001.
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of
1934, the registrant has duly caused this report to be signed on its
behalf by the undersigned thereunto duly authorized.
MDU RESOURCES GROUP, INC.
DATE May 14, 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.
10(a) 1997 Executive Long-Term Incentive Plan, as amended to date
12 Computation of Ratio of Earnings to Fixed Charges
and Combined Fixed Charges and Preferred Stock
Dividends