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 JUNESEPTEMBER 30, 1998
OR
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the Transition Period from _____________ to ______________
Commission file number 1-3480
MDU Resources Group, Inc.
(Exact name of registrant as specified in its charter)
Delaware 41-0423660
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
Schuchart Building
918 East Divide Avenue
P.O. Box 5650
Bismarck, North Dakota 58506-5650
(Address of principal executive offices)
(Zip Code)
(701) 222-7900
(Registrant's telephone number, including area code)
Indicate by check mark whether the registrant (1) has filed
all reports required to be filed by Section 13 or 15(d)of the
Securities Exchange Act of 1934 during the preceding 12 months
(or for such shorter period that the registrant was required to
file such reports), and (2) has been subject to such filing
requirements for the past 90 days. Yes X. No.
Indicate the number of shares outstanding of each of the
issuer's classes of common stock, as of August 7,November 6, 1998:
52,844,77853,025,495 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), the public
utility division of the Company, provides electric and/or
natural gas and propane distribution service at retail to 256
communities in North Dakota, eastern Montana, northern and
western South Dakota and northern Wyoming, and owns and
operates electric power generation and transmission facilities.
The Company, through its wholly owned subsidiary, Centennial
Energy Holdings, Inc. (Centennial), owns WBI Holdings, Inc.
(WBI Holdings), Knife River Corporation (Knife River), the
Fidelity Oil Group (Fidelity Oil) and Utility Services, Inc.
(Utility Services).
WBI Holdings, through its wholly owned subsidiary,
Williston Basin Interstate Pipeline Company
(Williston Basin), produces natural gas and provides
underground storage, transportation and gathering services
through an interstate pipeline system serving Montana, North
Dakota, South Dakota and Wyoming. In addition, WBI Holdings,
through its wholly owned subsidiary, WBI Energy Services, Inc.
and its subsidiaries, seeks new energy markets while continuing
to expand present markets for natural gas and propane in the
Midwestern andand/or southern regions of the United States. Williston Basin Interstate Pipeline
Company was recently reorganized into several operating
units. WBI Holdings, Inc. became the parent company for
all of the operating companies.
Knife River, through its wholly owned subsidiary, KRC
Holdings, Inc. (KRC Holdings) and its subsidiaries, surface
mines and markets aggregates and related construction materials
in Alaska, California, Hawaii and Oregon. In addition, Knife
River surface mines and markets low sulfur lignite coal at
mines located in Montana and North Dakota.
Fidelity Oil is comprised of Fidelity Oil Co. and
Fidelity Oil Holdings, Inc., which own oil and natural gas
interests throughout the United States, the Gulf of Mexico and
Canada through investments with several oil and natural gas
producers.
Utility Services, through its wholly owned
subsidiaries, installs and repairs electric transmission,
electric and natural gas distribution, telecommunication cable
and fiber optic systems in the western United States andand/or
Hawaii and provides related supplies, equipment and engineering
services.
INDEX
Part I -- Financial Information
Consolidated Statements of Income --
Three and SixNine Months Ended JuneSeptember 30, 1998 and 1997
Consolidated Balance Sheets --
JuneSeptember 30, 1998 and 1997, and December 31, 1997
Consolidated Statements of Cash Flows --
SixNine Months Ended JuneSeptember 30, 1998 and 1997
Notes to Consolidated Financial Statements
Management's Discussion and Analysis of Financial
Condition and Results of Operations
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 SixNine Months
Ended Ended
JuneSeptember 30, JuneSeptember 30,
1998 1997 1998 1997
(In thousands, except per share amounts)
Operating revenues:
Electric $ 48,18258,791 $ 31,770 $ 92,921 $ 69,04348,031 $151,712 $117,074
Natural gas 38,102 42,379 111,646 102,44264,110 34,476 175,756 136,919
Construction materials and mining 80,895 35,081 119,856 58,084134,047 65,771 253,903 123,854
Oil and natural gas production 12,536 16,150 25,414 35,623
179,715 125,380 349,837 265,19213,030 15,421 38,444 51,044
269,978 163,699 619,815 428,891
Operating expenses:
Fuel and purchased power 12,408 10,221 24,241 22,39912,841 11,255 37,082 33,655
Purchased natural gas sold 11,334 16,090 43,509 37,11838,461 9,870 81,970 46,988
Operation and maintenance 103,844 60,876 173,567 114,670149,649 90,479 323,215 205,148
Depreciation, depletion and
amortization 19,365 14,406 37,154 30,07520,006 16,869 57,161 46,943
Taxes, other than income 6,259 5,339 12,652 11,7266,326 6,202 18,978 17,928
Write-down of oil and natural gas
properties (Note 6) 33,100--- --- 33,100 ---
186,310 106,932 324,223 215,988227,283 134,675 551,506 350,662
Operating income (loss):income:
Electric 7,502 4,268 15,950 12,71611,565 9,646 27,515 22,362
Natural gas distribution (819) (53) 5,974 7,045(2,987) (2,339) 2,986 4,706
Natural gas transmission 7,828 7,177 20,724 14,5908,357 6,745 29,081 21,335
Construction materials and mining 9,368 1,708 10,525 1,01922,774 9,650 33,300 10,669
Oil and natural gas production (30,474) 5,348 (27,559) 13,834
(6,595) 18,448 25,614 49,2042,986 5,322 (24,573) 19,157
42,695 29,024 68,309 78,229
Other income -- net 2,554 2,027 5,156 1,5741,202 1,399 6,359 2,972
Interest expense 7,215 7,041 14,350 14,1338,050 7,783 22,400 21,916
Income (loss) before income taxes (11,256) 13,434 16,420 36,64535,847 22,640 52,268 59,285
Income taxes (5,471) 4,693 4,412 13,30813,309 8,445 17,723 21,753
Net income (loss) (5,785) 8,741 12,008 23,33722,538 14,195 34,545 37,532
Dividends on preferred stocks 195194 196 389 391582 586
Earnings (loss) on common stock $ (5,980)22,344 $ 8,54513,999 $ 11,61933,963 $ 22,94636,946
Earnings (loss) per common share -- basic $ (.12).42 $ .20.32 $ .24.68 $ .53.86
Earnings (loss) per common share -- diluted $ (.12).42 $ .20.32 $ .24.68 $ .53.85
Dividends per common share $ .20 $ .1917 $ .1850.5833 $ .3833 $ .3700.5617
Average common shares
outstanding -- basic 50,936 43,104 48,171 42,99952,703 43,577 49,698 43,194
Average common shares
outstanding -- diluted 50,936 43,247 48,412 43,12953,062 43,733 49,966 43,332
The accompanying notes are an integral part of these consolidated statements.
MDU RESOURCES GROUP, INC.
CONSOLIDATED BALANCE SHEETS
(Unaudited)
JuneSeptember 30, JuneSeptember 30, December 31,
1998 1997 1997
(In thousands)
ASSETS
Current assets:
Cash and cash equivalents $ 43,10651,006 $ 31,51466,164 $ 28,174
Receivables 88,059 58,697119,997 71,229 80,585
Inventories 40,664 28,00350,997 45,391 41,322
Deferred income taxes 16,041 23,37514,305 22,327 17,356
Prepayments and other current assets 15,106 25,48019,601 28,796 12,479
202,976 167,069255,906 233,907 179,916
Investments 20,513 54,21624,722 18,537 18,935
Property, plant and equipment:
Electric 571,936 552,636578,211 560,007 566,247
Natural gas distribution 175,219 167,464176,850 169,005 172,086
Natural gas transmission 292,865 281,205300,140 283,505 288,709
Construction materials and mining 446,936 180,658468,490 238,742 243,110
Oil and natural gas production 218,373 224,381273,983 232,736 240,193
1,705,329 1,406,3441,797,674 1,483,995 1,510,345
Less accumulated depreciation,
depletion and amortization 694,878 645,086709,272 655,210 670,809
1,010,451 761,2581,088,402 828,785 839,536
Deferred charges and other assets 74,795 63,83985,618 79,295 75,505
$1,308,735 $1,046,382$1,454,648 $1,160,524 $1,113,892
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Short-term borrowings $ 8,4398,272 $ 7,67516,038 $ 3,347
Long-term debt and preferred
stock due within one year 5,571 6,8545,456 8,792 7,902
Accounts payable 39,880 31,21657,119 39,106 31,571
Taxes payable --- 3,3799,157 6,223 9,057
Dividends payable 10,040 8,17310,774 8,555 8,574
Other accrued liabilities,
including reserved revenues 68,850 97,03277,151 101,390 88,563
132,780 154,329167,929 180,104 149,014
Long-term debt 332,126 258,306400,244 322,998 298,561
Deferred credits and other liabilities:
Deferred income taxes 178,995 119,299182,586 121,563 119,747
Other liabilities 130,959 133,960128,570 142,550 143,574
309,954 253,259311,156 264,113 263,321
Commitments and contingencies
Stockholders' equity:
Preferred stock subject to mandatory
redemption requirements 1,700 1,800 1,700
Preferred stock redeemable at option
of the Company 15,000 15,000 15,000
16,700 16,800 16,700
Common stockholders' equity:
Common stock (Note 4)
(Shares outstanding -- 51,369,923,52,897,244,
$3.33 par value at JuneSeptember 30, 1998,
28,747,683,29,078,507, $3.33 par value at
JuneSeptember 30, 1997 and 29,143,332,
$3.33 par value at December 31, 1997) 171,859 95,730176,945 96,831 97,047
Other paid-in capital 143,885 69,386168,479 75,466 76,526
Retained earnings 205,057 198,572216,821 204,212 212,723
Treasury stock at cost (239,521 shares) (3,626) --- ---
Total common stockholders'
equity 517,175 363,688558,619 376,509 386,296
Total stockholders' equity 533,875 380,488575,319 393,309 402,996
$1,308,735 $1,046,382$1,454,648 $1,160,524 $1,113,892
The accompanying notes are an integral part of these consolidated statements.
MDU RESOURCES GROUP, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
SixNine Months Ended
JuneSeptember 30,
1998 1997
(In thousands)
Operating activities:
Net income $ 12,00834,545 $ 23,33737,532
Adjustments to reconcile net income to net
cash provided by operating activities:
Depreciation, depletion and amortization 37,154 30,07557,161 46,943
Deferred income taxes and investment
tax credit -- net 4,995 4,4445,862 9,282
Recovery of deferred natural gas contract litigation
settlement costs, net of income taxes --- 2,8903,130
Write-down of oil and natural gas properties, net of
income taxes (Note 6) 20,025 ---
Changes in current assets and liabilities --
Receivables 12,691 14,490(7,350) 16,569
Inventories 4,636 (642)(4,861) (8,352)
Other current assets (44) (9,913)(1,559) (10,496)
Accounts payable 4,440 (364)11,531 2,028
Other current liabilities (30,354) 1,877(15,219) 5,269
Other noncurrent changes (8,829) 2,743(8,404) (111)
Net cash provided by operating activities 56,722 68,93791,731 101,794
Financing activities:
Net change in short-term borrowings (1,408) 3,725(2,795) 6,777
Issuance of long-term debt 58,501 ---111,370 53,129
Repayment of long-term debt (40,490) (27,365)(25,934) (21,488)
Issuance of common stock 30,109 5,98329,795 10,059
Retirement of natural gas repurchase commitment (12,374) (37,018)(15,174) (49,361)
Dividends paid (19,674) (16,306)(30,447) (24,861)
Net cash provided by (used in) financing activities 14,664 (70,981)66,815 (25,745)
Investing activities:
Capital expenditures including acquisitions of businesses --
Electric (5,861) (7,098)(5,267) (11,945)
Natural gas distribution (3,847) (4,007)(6,112) (6,155)
Natural gas transmission (5,066) (3,935)(12,874) (7,260)
Construction materials and mining (29,632) (8,647)(42,339) (36,005)
Oil and natural gas production (19,014) (14,061)
(63,420) (37,748)(74,661) (22,561)
(141,253) (83,926)
Net proceeds from sale or disposition of property 2,557 2,8893,083 2,665
Net capital expenditures (60,863) (34,859)(138,170) (81,261)
Sale of natural gas available under
repurchase commitment 5,987 21,3337,094 25,928
Investments (1,578) (715)(4,638) (2,351)
Net cash used in investing activities (56,454) (14,241)(135,714) (57,684)
Increase (decrease) in cash and cash equivalents 14,932 (16,285)22,832 18,365
Cash and cash equivalents -- beginning of year 28,174 47,799
Cash and cash equivalents -- end of period $ 43,10651,006 $ 31,51466,164
The accompanying notes are an integral part of these consolidated statements.
MDU RESOURCES GROUP, INC.
NOTES TO CONSOLIDATED
FINANCIAL STATEMENTS
JuneSeptember 30, 1998 and 1997
(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, 1997
(1997 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 1997 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. 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.
3. Seasonality of operations
Some of the Company's operations are highly seasonal and
revenues from, and certain expenses for, such operations may
fluctuate significantly among quarterly periods. Accordingly, the
interim results may not be indicative of results for the full
fiscal year.
4. Common stock split
On May 14, 1998, the Company's Board of Directors approved
a three-for-two common stock split to be effected in the form of a
50 percent common stock dividend. The additional shares of common
stock were distributed on July 13, 1998, to common stockholders of
record on July 3, 1998. All common stock information appearing in
the accompanying consolidated financial statements has been
restated to give retroactive effect to the stock split.
Additionally, preference share purchase rights have been
appropriately adjusted to reflect the effects of the split.
5. New Accounting changePronouncements
On January 1, 1998, the Company adopted Statement of
Financial Accounting Standards No. 130, "Reporting Comprehensive
Income" (SFAS No. 130). SFAS No. 130 provides authoritative
guidance on the reporting and display of comprehensive income
and its components. For the three months and sixnine months ended
JuneSeptember 30, 1998, comprehensive income equaled net income as
reported.
In June 1998, the Financial Accounting Standards Board
issued Statement of Financial Accounting Standards No. 133,
"Accounting for Derivative Instruments and Hedging Activities"
(SFAS No. 133). SFAS No. 133 establishes accounting and reporting
standards requiring that every derivative instrument (including
certain derivative instruments embedded in other contracts) be
recorded in the balance sheet as either an asset or liability
measured at its fair value. SFAS No. 133 requires that changes in
the derivative's fair value be recognized currently in earnings
unless specific hedge accounting criteria are met. Special
accounting for qualifying hedges allows a derivative's 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 is effective for fiscal years beginning after
June 15, 1999. SFAS No. 133 must be applied to derivative
instruments and certain derivative instruments embedded in hybrid
contracts that were issued, acquired, or substantively modified
after December 31, 1997. The Company has not yet quantified
the impacts of adopting SFAS No. 133.
6. Write-down of oil and natural gas properties
The Company uses the full-cost method of accounting for its
oil and natural gas production activities. Under this method, all
costs incurred in the acquisition, exploration and development of
oil and natural gas properties are capitalized and amortized on the
units of production method based on total proved reserves.
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 and the lower of cost or fair value of unproved
properties. Future net revenue is estimated based on end-of-quarter
prices adjusted for contracted price changes. If capitalized costs
exceed the full-cost ceiling at the end of any quarter, a permanent
write-down is required to be charged to earnings in that quarter.
Such a charge has no effect on the Company's cash flows.
Due to significantly lower oil prices, the Company's
capitalized costs under the full-cost method of accounting exceeded
the full-cost ceiling at June 30, 1998. The Company was required
to recognize a write-down of its oil and natural gas producing
properties. This charge amounted to $33.1 million pretax and
reduced earnings for the three and sixnine months ended JuneSeptember 30, 1998 by
$20 million.
7. Pending litigation
W. A. Moncrief --
In November 1993, the estate of W.A. Moncrief (Moncrief),
a producer from whom Williston Basin purchased a portion of its
natural gas supply, filed suit in Federal District Court for the
District of Wyoming (Federal District Court) against Williston
Basin and the Company disputing certain price and volume issues
under the contract.
Through the course of this action Moncrief submitted damage
calculations which totaled approximately $19 million or, under its
alternative pricing theory, approximately $39 million.
In June 1997, the Federal District Court issued its order
awarding Moncrief damages of approximately $15.6 million. In July
1997, the Federal District Court issued an order limiting
Moncrief's reimbursable costs to post-judgment interest, instead of
both pre- and post-judgment interest as Moncrief had sought.
In August 1997, Moncrief filed a notice of appeal with the United
States Court of Appeals for the Tenth Circuit (U.S. Court of
Appeals) related to the Federal District Court's orders. In
September 1997, Williston Basin and the Company filed a notice of
cross-appeal. Oral argument before the U.S. Court of Appeals has been scheduled forwas
held September 23, 1998. Williston Basin and the Company are
awaiting a decision from the U.S. Court of Appeals.
Williston Basin believes that it is entitled to recover
from ratepayerscustomers virtually all of the costs which might
ultimately be incurred as a result of this litigation as gas supply
realignment transition costs pursuant to the provisions of the
Federal Energy Regulatory Commission's (FERC) Order 636. However,
the amount of costs that can ultimately be recovered is subject to
approval by the FERC and market conditions.
Apache Corporation/Snyder Oil Corporation --
In December 1993, Apache Corporation (Apache) and Snyder
Oil Corporation (Snyder) filed suit in North Dakota Northwest
Judicial District Court (North Dakota District Court), against
Williston Basin and the Company. Apache and Snyder are oil and
natural gas producers which had processing agreements with Koch
Hydrocarbon Company (Koch). Williston Basin and the Company had a
natural gas purchase contract with Koch. Apache and Snyder have
alleged they are entitled to damages for the breach of Williston
Basin's and the Company's contract with Koch. Williston Basin
and the Company believe that if Apache and Snyder have any legal
claims, such claims are with Koch, not with Williston Basin or the
Company as Williston Basin, the Company and Koch have settled their
disputes. Apache and Snyder have submitted damage estimates under
differing theories aggregating up to $4.8 million without interest.
A motion to intervene in the case by several other producers, all of
which had contracts with Koch but not with Williston Basin, was denied
in December 1996. The trial before the North Dakota District Court
was completed in November 1997. Williston Basin and the Company
are awaiting a decision from the North Dakota District Court.
In a related matter, in March 1997, a suit was filed by
nine other producers, several of which had unsuccessfully tried to
intervene in the Apache and Snyder litigation, against Koch,
Williston Basin and the Company. The parties to this suit are
making claims similar to those in the Apache and Snyder litigation,
although no specific damages have been stated.
In Williston Basin's opinion, the claims of Apache and
Snyder are without merit and overstated and the claims of the nine
other producers are without merit. If any amounts are ultimately
found to be due, Williston Basin plans to file with the FERC for
recovery from ratepayers.customers.
Jack J. Grynberg --
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 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. The United States government, particularly officials from
the Departments of Justice and Interior, reviewed the complaint and
the evidence presented by Grynberg and declined to intervene in the
action, permitting Grynberg to proceed on his own. In March 1997,
the U.S. District Court dismissed the suit without prejudice
against 53 of the defendants, including Williston Basin, on the
grounds that the parties were improperly joined in the suit and
that Grynberg's claim of fraud was not specific enough as it
related to any individual party to the suit. On May 15, 1998,
Grynberg appealed the U.S. District Court's decision. Williston
Basin believes Grynberg's claims are without meritjoined other defendants and intends to
vigorously contest this suit.filed a motion for summary
affirmance. The motion was granted on October 6, 1998, and the
appeal was effectively dismissed.
Coal Supply Agreement --
In November 1995, a suit was filed in District Court,
County of Burleigh, State of North Dakota (State District Court) by
Minnkota Power Cooperative, Inc., Otter Tail Power Company,
Northwestern Public Service Company and Northern Municipal Power
Agency (Co-owners), the owners of an aggregate 75 percent interest
in the Coyote electric generating station (Coyote Station), against
the Company (an owner of a 25 percent interest in the Coyote
Station) and Knife River. In its complaint, the Co-owners have
alleged a breach of contract against Knife River ofwith respect to
the long-term coal supply agreement (Agreement) between the owners
of the Coyote Station and Knife River. The Co-owners have
requested a determination by the State District Court of the
pricing mechanism to be applied to the Agreement and have further
requested damages during the term of such alleged breach on the
difference between the prices charged by Knife River and the prices
that may ultimately be determined by the State District Court. The
Co-
ownersCo-owners also alleged a breach of fiduciary duties by the Company
as operating agent of the Coyote Station, asserting essentially
that the Company was unable to cause Knife River to reduce its coal
price sufficiently under the Agreement, and the Co-owners are
seeking damages in an unspecified amount. In May 1996, the State
District Court stayed the suit filed by the Co-owners pending
arbitration, as provided for in the Agreement.
In September 1996, the Co-owners notified the Company and
Knife River of their demand for arbitration of the pricing dispute
that had arisen under the Agreement. The demand for arbitration,
filed with the American Arbitration Association (AAA), did not make
any direct claim against the Company in its capacity as operator of
the Coyote Station. The Co-owners requested that the arbitrators
make a determination that the pricing dispute is not a proper
subject for arbitration. By an April 1997 order, the arbitration
panel concluded that the claims raised by the Co-owners are
arbitrable. The Co-owners have requested the arbitrators to make
a determination that the prices charged by Knife River were
excessive and that the Co-owners should be awarded damages, based
upon the difference between the prices that Knife River charged and
a "fair and equitable" price, of approximately $50 million or more.price. Upon application by the Company and
Knife River, the AAA administratively determined that the Company
was not a proper party defendant to the arbitration, and the
arbitration is proceeding against Knife River. AOn October 9, 1998,
a hearing before the arbitration panel was completed. At the
hearing the Co-owners requested damages of approximately $24
million, including interest, plus a reduction in the future price
of coal under the Agreement. A decision from the arbitration panel
is currently scheduled for October 5, 1998.expected after the completion of a post-hearing briefing.
Although unable to predict the outcome of the arbitration, Knife
River and the Company believe that the Co-owners' claims are
without merit and intend to vigorously defend the prices charged
pursuant to the Agreement.
8. Regulatory matters and revenues subject to refund
Williston Basin had pending with the FERC a general natural
gas rate change application implemented in 1992. In October 1997,
Williston Basin appealed to the U.S. Court of Appeals for the D.C.
Circuit (D.C. Circuit Court) certain issues decided by the FERC in
prior orders concerning the 1992 proceeding. Oral argument before
the D.C. Circuit Court has been scheduled for November 19, 1998.
In December 1997, the FERC issued an order accepting, subject to
certain conditions, Williston Basin's July 1997 compliance filing.
In December 1997, Williston Basin submitted a compliance filing
pursuant to the FERC's December 1997 order and refunded $33.8
million to its customers, including $30.8 million to Montana-Dakota,
in addition to the $6.1 million interim refund that it had
previously made in November 1996. All such amounts had been
previously reserved. On March 25, 1998, the FERC issued an order
accepting Williston Basin's December 1997 compliance filing.
In June 1995, Williston Basin filed a general rate increase
application with the FERC. As a result of FERC orders issued after
Williston Basin's application was filed, Williston Basin filed
revised base rates in December 1995 with the FERC resulting in an
increase of $8.9 million or 19.1 percent over the then current
effective rates. Williston Basin began collecting such increase
effective January 1, 1996, subject to refund. On July 29, 1998,
the FERC issued an order which may be subject to rehearing.addressed various issues. On August
28, 1998, Williston Basin is currently evaluating the implicationrequested rehearing of the
order and what option to pursue.such order.
Reserves have been provided for a portion of the revenues
that have been collected subject to refund with respect to pending
regulatory proceedings and to reflect future resolution of certain
issues with the FERC. Williston Basin believes that such reserves
are adequate based on its assessment of the ultimate outcome of the
various proceedings.
9. Natural gas repurchase commitment
The Company has offered for sale since 1984 the inventoried
natural gas available under a repurchase commitment with Frontier
Gas Storage Company, as described in Note 3 of its 1997 Annual
Report. As a part of the corporate realignment effected January 1,
1985, the Company agreed, pursuant to the settlement approved by
the FERC, to remove from rates the financing costs associated with
this natural gas.
The FERC has issued orders that have held that storage
costs should be allocated to this gas, prospectively beginning
May 1992, as opposed to being included in rates applicable to
Williston Basin's customers. These storage costs, as initially
allocated to the Frontier gas, approximated $2.1 million annually,
for which Williston Basin has provided reserves. Williston Basin
appealed these orders to the D.C. Circuit Court which in December
1996 issued its order ruling that the FERC's actions in allocating
storage capacity costs to the Frontier gas were appropriate. See Note 8 regardingOn
August 28, 1998, Williston Basin requested rehearing on the July
29, 1998 FERC order which addressesaddressed various issues, including thea
requirement that storage deliverability costs to be allocated to the
Frontier gas.
10. Environmental matters
Montana-Dakota and Williston Basin discovered
polychlorinated biphenyls (PCBs) in portions of their natural gas
systems and informed the United States Environmental Protection
Agency (EPA) in January 1991. Montana-Dakota and Williston Basin
believe the PCBs entered the system from a valve sealant. In
January 1994, Montana-Dakota, Williston Basin and Rockwell
International Corporation (Rockwell), manufacturer of the valve
sealant, reached an agreement under which Rockwell has reimbursed
and will continue to reimburse Montana-Dakota and Williston Basin
for a portion of certain remediation costs. On the basis of
findings to date, Montana-Dakota and Williston Basin estimate
future environmental assessment and remediation costs will aggregate
$3 million to $15 million. Based on such estimated cost, the
expected recovery from Rockwell and the ability of Montana-Dakota
and Williston Basin to recover their portions of such costs from
ratepayers, Montana-Dakota and Williston Basin believe that the
ultimate costs related to these matters will not be material to each
of their respective financial positions or results of operations.
11. Cash flow information
Cash expenditures for interest and income taxes were as
follows:
SixNine Months Ended
JuneSeptember 30,
1998 1997
(In thousands)
Interest, net of amount capitalized $12,408 $12,384$16,000 $16,865
Income taxes $17,489 $12,435$24,178 $18,235
The Company's Consolidated Statements of Cash Flows include
the effects from acquisitions.
12. Derivatives
The Company, in connection with the operations of Williston Basin and Fidelity Oil hashave entered into certain
price swap and collar agreements (hedge agreements) to manage a portion of the market
risk associated with fluctuations in the price of oil and natural
gas. These hedgeswap and collar agreements are not held for trading
purposes. The hedgeswap and collar agreements call for the CompanyWilliston Basin
and Fidelity Oil to receive monthly payments from or make payments
to counterparties based upon the difference between a fixed and a
variable price as specified by the hedge agreements. The variable price
is either an oil price quoted on the New York Mercantile Exchange
(NYMEX) or a quoted natural gas price on the NYMEX or Colorado
Interstate Gas Index. The Company believes that there is a high
degree of correlation because the timing of purchases and production
and the hedgeswap and collar agreements are closely matched, and hedge
prices are established in the areas of the Company's operations. Amounts payable
or receivable on hedgethe swap and collar agreements are matched and
reported in operating revenues on the Consolidated Statements of
Income as a component of the related commodity transaction at the
time of settlement with the counterparty. The amounts payable or
receivable are offset by corresponding increases and decreases in
the value of the underlying commodity transactions.
Innovative Gas Services, Incorporated, an energy marketing
subsidiary of WBI Energy Services, Inc., participates in the natural
gas futures market to hedge a portion of the price risk associated
with natural gas purchase and sale commitments. These futures are
not held for trading purposes. Gains or losses on the futures
contracts are deferred until the transaction occurs, at which point
they are reported in "Purchased natural gas sold" on the
Consolidated Statements of Income. The gains or losses on the
futures contracts are offset by corresponding increases and
decreases in the value of the underlying commodity transactions.
Knife River hashad entered into an interest rate swap
agreement, which expired in August 1998, to manage a portion of its
interest rate exposure on long-term debt. This interest
rate swap agreement iswas not held for trading purposes. The interest
rate swap agreement callscalled for Knife River to receive quarterly
payments from or make payments to counterparties based upon the
difference between fixed and variable rates as specified by the
interest rate swap agreement. The variable prices arewere based on the
three-month floating London Interbank Offered Rate. Settlement
amounts payable or receivable under this interest rate swap
agreement arewere recorded in "Interest expense" on the Consolidated
Statements of Income in the accounting period they arewere incurred.
The amounts payable or receivable arewere offset by interest on the
related debt instrument.
The Company's policy prohibits the use of derivative
instruments for trading purposes and the Company has procedures in
place to monitor their use. The Company is exposed to credit-related
losses in the event of nonperformance by counterparties to
these financial instruments, but does not expect any counterparties
to fail to meet their obligations given their existing credit
ratings.
The following table summarizes the Company's hedging
activity (notional amounts in thousands):
SixNine Months Ended
JuneSeptember 30,
1998 1997
Oil swap agreements:*
Range of fixed prices per barrel $20.92 $19.77-$21.36
Notional amount (in barrels) 109 362164 546
Natural gas swap/collar agreements:*
Range of fixed prices per MMBtu $1.54-$2.67 $1.30-$2.25
Notional amount (in MMBtu's) 3,258 4,4934,914 6,324
Natural gas futures contracts:*
Range of fixed prices per MMBtu $2.21-$2.50 ---
Notional amount (in MMBtu's) 480 ---
Interest rate swap agreements:**
Range of fixed interest rates 5.50%-6.50% 5.50%-6.50%
Notional amount (in dollars) $10,000 $30,000
* Receive fixed -- pay variable
** Receive variable -- pay fixed
The following table summarizes swap and collar agreements
outstanding at JuneSeptember 30, 1998 (notional amounts in thousands):
Notional
Fixed Price Amount
Year (Per barrel) (In barrels)
Oil swap agreement* 1998 $20.92 11055
Range of Notional
Fixed Prices Amount
Year (Per MMBtu) (In MMBtu's)
Natural gas swap/collar
agreements* 1998 $1.54-$2.67 2,824
Notional
Range of Fixed Amount
Year Interest Rates (In dollars)
Interest rate swap
agreement** 1998 5.50%-6.50% $10,0001,168
1999 $2.10-$2.50 1,460
* Receive fixed -- pay variable
** Receive variable -- pay fixed
The fair value of these derivative financial instruments
reflects the estimated amounts that the Company would receive or pay
to terminate the contracts at the reporting date, thereby taking
into account the current favorable or unfavorable position on open
contracts. The favorable or unfavorable position is currently not
recorded on the Company's financial statements. Favorable and
unfavorable positions related to oil and natural gas hedge
agreements will be offset by corresponding increases and decreases
in the value of the underlying commodity transactions. A favorable
or unfavorable position on the interest rate swap agreement will be
offset by interest on the related debt instrument. The
Company's net favorable position on all swap and collarhedge agreements outstanding
at JuneSeptember 30, 1998, was $35,000.$358,000. In the event a hedge agreement
does not qualify for hedge accounting or when the underlying
commodity transaction or related debt instrument matures, is sold,
is extinguished, or is terminated, the current favorable or
unfavorable position on the open contract would be included in
results of operations. The Company's policy requires approval to
terminate a hedge agreement prior to its original maturity. In the
event a hedge agreement is terminated, the realized gain or loss at
the time of termination would be deferred until the underlying
commodity transaction or related debt instrument is sold or matures
and would be offset by corresponding increases or decreases in the
value of the underlying commodity transaction or interest on the
related debt instrument.
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 includes the electric operations of
Montana-Dakota, as well as the operations of Utility Services.
Natural Gas Distribution includes Montana-Dakota's natural gas
distribution operations. Natural Gas Transmission includes WBI
Holdings' storage, transportation, gathering, natural gas production
and energy marketing operations. Construction Materials and Mining
includes the results of Knife River's operations, while Oil and
Natural Gas Production includes the operations of Fidelity Oil.
Overview
The following table (in millions of dollars) summarizes the
contribution to consolidated earnings by each of the Company's
businesses.
Three Months SixNine Months
Ended Ended
JuneSeptember 30, JuneSeptember 30,
Business 1998 1997 1998 1997
Electric $ 3.05.4 $ .94.4 $ 6.612.0 $ 4.38.7
Natural gas distribution (.9) (.5) 2.7 3.3(2.4) (2.0) .4 1.3
Natural gas transmission 4.3 3.5 12.4 6.04.2 3.0 16.6 8.9
Construction materials and mining 13.3 5.6 1.3 5.9 1.119.2 6.8
Oil and natural gas production (18.0) 3.3 (16.0) 8.21.8 3.0 (14.2) 11.2
Earnings on common stock $ (6.0)22.3 $ 8.514.0 $ 11.634.0 $ 22.936.9
Earnings per common share --- basic $ (.12).42 $ .20.32 $ .24.68 $ .53.86
Earnings per common share --- diluted $ (.12).42 $ .20.32 $ .24.68 $ .53.85
Return on average common equity
for the 12 months ended 10.0% 13.1%10.8% 14.4%
Three Months Ended JuneSeptember 30, 1998 and 1997
Consolidated earnings for the quarter ended JuneSeptember 30, 1998,
were down $14.5up $8.3 million from the comparable period a year ago due to
lowerhigher earnings at the construction materials and mining, natural
gas transmission and electric businesses. Decreased earnings at the
oil and natural gas production business,
largely resulting from a $20 million after tax non-cash write-down
of oil and natural gas properties. Decreased earnings at the
natural gas distribution
business also added to the earnings
decline. Higher earnings at the construction materials and mining,
electric and natural gas transmission businesses partiallysomewhat offset the earnings decrease.
Siximprovement.
Nine Months Ended JuneSeptember 30, 1998 and 1997
Consolidated earnings for the sixnine months ended JuneSeptember 30,
1998, were down $11.3$2.9 million from the comparable period a year ago
due to decreased earnings at the oil and natural gas production
business, largely resulting from the aforementioneda second quarter $20 million after
tax non-cash write-
downwrite-down of oil and natural gas properties, and lower
earnings at the natural gas distribution business. Increased
earnings at the natural gas transmission, construction materials and mining, natural gas
transmission and electric businesses somewhat offset the earnings
decline.
________________________________
Reference should be made to Notes to Consolidated Financial
Statements for information pertinent to various commitments and
contingencies.
Financial and operating data
The following tables (in millions, where applicable) are key
financial and operating statistics for each of the Company's
business units. Certain reclassifications have been made in the
following statistics 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.
Electric Operations
Three Months SixNine Months
Ended Ended
JuneSeptember 30, JuneSeptember 30,
1998 1997 1998 1997
Operating revenues:
Retail sales $ 29.435.1 $ 30.033.2 $ 62.497.6 $ 64.297.5
Sales for resale and other 4.7 1.8 8.0 4.83.8 2.7 11.7 7.5
Utility services 14.1 --- 22.5 ---
48.2 31.8 92.9 69.019.9 12.1 42.4 12.1
58.8 48.0 151.7 117.1
Operating expenses:
Fuel and purchased power 12.4 10.2 24.2 22.412.9 11.3 37.1 33.7
Operation and maintenance 21.2 11.2 38.7 21.626.7 20.3 65.5 42.0
Depreciation, depletion and
amortization 4.8 4.3 9.5 8.75.2 4.4 14.6 13.1
Taxes, other than income 2.4 2.3 1.8 4.5 3.6
40.7 27.5 76.9 56.37.0 5.9
47.2 38.3 124.2 94.7
Operating income 7.5 4.3 16.0 12.711.6 9.7 27.5 22.4
Retail sales (kWh) 459.4 465.2 982.6 1,008.8550.8 517.6 1,533.5 1,526.3
Sales for resale (kWh) 180.1 45.8 309.5 160.7112.2 70.6 421.7 231.3
Cost of fuel and purchased
power per kWh $ .018 $ .018 $ .018 $ .018
Natural Gas Distribution Operations
Three Months SixNine Months
Ended Ended
JuneSeptember 30, JuneSeptember 30,
1998 1997 1998 1997
Operating revenues:
Sales $ 23.513.8 $ 25.916.1 $ 85.198.9 $ 81.597.5
Transportation and other .7 .7 1.7 1.7
24.2 26.6 86.8 83.22.5 2.5
14.5 16.8 101.4 100.0
Operating expenses:
Purchased natural gas sold 15.3 16.9 60.7 55.47.7 9.6 68.5 65.0
Operation and maintenance 6.9 7.1 14.5 15.17.0 6.8 21.5 22.0
Depreciation, depletion and
amortization 1.8 1.7 3.5 3.51.8 5.3 5.3
Taxes, other than income 1.0 1.0 2.1 2.1
25.0 26.7 80.8 76.1.9 3.1 3.0
17.5 19.1 98.4 95.3
Operating income (.8) (.1) 6.0 7.1(loss) (3.0) (2.3) 3.0 4.7
Volumes (dk):
Sales 4.5 5.6 18.5 20.72.4 2.7 20.9 23.4
Transportation 1.8 1.8 5.0 4.72.1 2.1 7.0 6.8
Total throughput 6.3 7.4 23.5 25.44.5 4.8 27.9 30.2
Degree days (% of normal) 99% 119% 95% 105%61.7% 91.0% 93.6% 104.4%
Average cost of natural gas, including
transportation, per dk $ 3.413.18 $ 3.013.57 $ 3.283.27 $ 2.662.77
Natural Gas Transmission Operations
Three Months SixNine Months
Ended Ended
JuneSeptember 30, JuneSeptember 30,
1998 1997* 1998 1997*
Operating revenues:
Transportation and storage $ 13.914.4 $ 13.814.5 $ 32.947.3 $ 31.145.5
Energy marketing and
natural gas production 8.2 9.2 18.9 17.639.4 7.6 58.4 25.3
53.8 22.1 23.0 51.8 48.7105.7 70.8
Operating expenses:
Purchased gas sold 4.2 5.8 9.8 9.935.0 4.4 44.8 14.4
Operation and maintenance 6.7 8.7 14.3 19.77.0 7.8 21.3 27.4
Depreciation, depletion and
amortization 2.0 --- 4.1 1.82.1 1.9 6.2 3.7
Taxes, other than income 1.4 1.3 2.9 2.7
14.3 15.8 31.1 34.14.3 4.0
45.5 15.4 76.6 49.5
Operating income 7.8 7.2 20.7 14.68.3 6.7 29.1 21.3
Volumes (dk):
Transportation--
Montana-Dakota 7.6 8.8 16.0 17.68.0 9.0 24.0 26.6
Other 15.2 11.3 29.6 23.7
22.8 20.1 45.6 41.316.4 15.3 45.9 39.0
24.4 24.3 69.9 65.6
Produced (000's of dk) 1,718 1,654 3,470 3,4111,676 1,709 5,145 5,120
* Includes $2.2$.4 million and $4.7$5.1 million for the three months and sixnine months
ended, respectively, of amortization and related recovery of deferred natural
gas contract buy-out/buy-down andand/or gas supply realignment costs.
Construction Materials and Mining Operations
Three Months SixNine Months
Ended Ended
JuneSeptember 30, JuneSeptember 30,
1998 1997** 1998 1997**
Operating revenues:
Construction materials $126.4 $ 71.9 $ 32.7 $101.6 $ 46.858.8 $228.0 $105.7
Coal 9.0 2.4 18.3 11.3
80.9 35.1 119.9 58.17.7 7.0 25.9 18.2
134.1 65.8 253.9 123.9
Operating expenses:
Operation and maintenance 65.4 30.3 98.6 51.2104.8 52.3 203.5 103.3
Depreciation, depletion and
amortization 5.2 2.7 9.1 4.75.6 3.1 14.6 7.8
Taxes, other than income .9 .4 1.7 1.2
71.5 33.4 109.4 57.1.8 2.5 2.1
111.3 56.2 220.6 113.2
Operating income 9.4 1.7 10.5 1.022.8 9.6 33.3 10.7
Sales (000's):
Aggregates (tons) 2,560 1,111 3,422 1,6954,540 2,057 7,962 3,752
Asphalt (tons) 391 196 421 250973 362 1,393 612
Ready-mixed concrete
(cubic yards) 259 113 398 182342 177 740 358
Coal (tons) 773 214 1,561 978678 593 2,239 1,571
** Prior to August 1, 1997, financial results did not include information
related to Knife River's ownership interest in Hawaiian Cement, 50
percent of which was acquired in September 1995, and was accounted for
under the equity method. On July 31, 1997, Knife River acquired the
50 percent interest in Hawaiian Cement that it did not previously own, and
subsequent to that date financial results are consolidated into Knife
River's financial statements.
Oil and Natural Gas Production Operations
Three Months SixNine Months
Ended Ended
JuneSeptember 30, JuneSeptember 30,
1998 1997 1998 1997
Operating revenues:
Oil $ 6.35.7 $ 9.08.3 $ 13.118.8 $ 19.127.4
Natural gas 6.27.3 7.1 12.3 16.5
12.5 16.1 25.4 35.619.6 23.6
13.0 15.4 38.4 51.0
Operating expenses:
Operation and maintenance 3.6 4.2 7.4 8.34.1 3.5 11.4 11.9
Depreciation, depletion and
amortization 5.65.3 5.7 11.0 11.416.4 17.1
Taxes, other than income .7.6 .9 1.5 2.1 2.9
Write-down of oil and
natural gas properties 33.1--- --- 33.1 ---
43.0 10.8 53.0 21.810.0 10.1 63.0 31.9
Operating income (30.5)(loss) 3.0 5.3 (27.6) 13.8(24.6) 19.1
Production (000's):
Oil (barrels) 490 525 973 1,045455 523 1,428 1,568
Natural gas (Mcf) 2,942 3,345 5,750 6,7663,649 3,236 9,399 10,002
Average sales price:
Oil (per barrel) $12.90 $17.23 $13.47 $18.23$12.65 $15.98 $13.21 $17.48
Natural gas (per Mcf) 2.11 2.12 2.14 2.451.99 2.19 2.08 2.36
Amounts presented in the above tables for natural gas operating
revenues and purchased natural gas sold for the three and sixnine
months ended JuneSeptember 30, 1998 and 1997, and operation and
maintenance expenses for the three and sixnine months ended JuneSeptember
30, 1997, will not agree with the Consolidated Statements of Income
due to the elimination of intercompany transactions between
Montana-Dakota's natural gas distribution business and WBI Holdings' natural
gas transmission business.
Three Months Ended JuneSeptember 30, 1998 and 1997
Electric Operations
Operating income increased at the electric business due to
increased operating income at the electric utility and the
acquisitions of International Line Builders, Inc. (ILB) and High
Line Equipment, Inc. (HLE) in July 1997, and Pouk & Steinle, Inc. in April 1998, and increased operating income at the electric
utility.Harp Line
Constructors Co. (Harp Line) and Harp Engineering, Inc. (Harp
Engineering) in July 1998. Operating income improved at the utility
primarily due to increased retail sales and sales for resale
revenue. Retail sales revenue increased due to higher sales to
residential and decreased maintenance
expense. Increasedcommercial customers resulting from warmer weather
while sales for resale volumes improved due to favorable market
conditions, and higher average realized rates dueconditions. Increased depreciation expense, primarily to favorable short-term contracts both contributed to the sales for
resale revenue improvement. The decrease in maintenance expense
was due to 1997 costs of $1.6 million associated with a ten-week
maintenance outage at the Coyote Station. In addition, damages
caused by an April 1997 blizzard also added to the decline in
maintenance expense. Increased purchased power demand charges
resulting from the pass-through of periodic maintenance costs and
lower retail sales volumes, primarily to residential customers,
partiallyincreased
depreciable plant, somewhat offset the operating income improvement at the electric
utility.increase.
Earnings for the electric business increased due to the
operating income improvement at the electric utility, $747,000 in
earningsimprovement. Earnings attributable to ILB, HLE and Pouk & Steinle, Inc., and
decreased net interest expense due largely to lower average long-
term debt balances and interest rates.Utility
Services were $982,000.
Natural Gas Distribution Operations
Operating income decreased at the natural gas distribution
business due to reduced operating revenue caused by lower weather-
related sales, the result of 1732 percent warmer weather. The pass-
through of higherlower average natural gas costs partially offsetadded to the revenue decline. Decreaseddecline in operating
revenue. Increased operation and maintenance expense primarily lower employee benefit-related costs, partially offsetalso added to
the decrease in operating income.
Natural gas distribution earnings decreased due to the
previously discussed decrease in operating income.
Increased
service and repair income somewhat offset the earnings decline.
Natural Gas Transmission Operations
Operating income at the natural gas transmission business
increased primarily due to increasedhigher average transportation revenues.
Higher transportationmargins
resulting from higher volumes transported to storage somewhatpartially
offset by lower transportationvolumes transported to off-system markets. Increased
prices on company-owned natural gas production and off-system markets, was largely
responsible for the transportation revenue improvement. Higher
average discounted rates, primarily off-system transportation and
gathering,decreased
operations expense also added to the revenue increase. In addition,
transportation revenue increased due to the absence of additional
1997 reserved revenues, with a corresponding reductionoperating income improvement.
The decline in depreciationoperations expense which resulted from FERC orders relating tolower production
royalties caused by a 1992 general rate proceeding.1997 royalty settlement with the United States
Minerals Management Service (MMS). The revenue increase was partially
offset by the completion of the recovery of deferred natural gas
contract buy-out/buy-down and gas supply realignment costs in 1997,
with a related reduction in operation expense. Decreased energy marketing
naturalrevenue and the related increase in purchased gas sales volumes and margins, partially offsetsold resulted from
the operating income increase.acquisition of Innovative Gas Services, Incorporated (IGS) in
July 1998.
Earnings for this business increased due to the operating income
improvement gains realized on the sale of natural gas held
under the repurchase commitment and decreased carrying costs on
this gas stemming from lower average borrowings. Higher company
production refund accruals (included in Other income -- net)
somewhat offset the earnings increase.interest expense.
Construction Materials and Mining Operations
Construction Materials Operations --
Construction materials operating income increased $4.6$12.6 million
primarily due to the acquisitions ofwhich have occurred since the
comparable period a year ago. These acquisitions include the 50
percent interest in Hawaiian Cement that Knife River did not
previously own in July 1997, Morse Bros., Inc. (MBI) and S2 - F
Corp. (S2-F) in March 1998, and Angell Bros., Inc. in April 1998, and
Hap Taylor & Sons, Inc. in July 1998. Prior to August 1997, Knife
River's original 50 percent ownership interest in Hawaiian Cement
was accounted for under the equity method. However, with the
acquisition mentioned above, Knife River began consolidating
Hawaiian Cement into its financial statements. Operating income at
the other construction materials operations decreasedincreased due primarily
to lower construction activity in California caused by weather-
related delayshigher aggregate sales volumes and lower ready-mixed concrete margins in southern Oregon. Increased asphaltOregon
resulting from increased construction activity and higher cement
margins in Alaska and Hawaii due to lower costs. Increased ready-
mixed concrete volumes in Alaska and higher asphalt costvolumes in
California somewhat offsetand southern Oregon also added to the operating income
decline at the
other construction materials operations.improvement.
Coal Operations --
Operating income for the coal operations increased $3.1 million
primarily$613,000
largely due to increased revenues resulting primarily from higher
demand-related sales of
509,000 tons toat both the Coyote Station. The increases in 1998 were
largely the result of the 1997 ten-week maintenance outage.
Increased operationBeulah and maintenance expenses and taxes other than
income, all primarily due to the increase in volumes sold,
partially offset the operating income improvement.Savage mines.
Consolidated --
Earnings increasedimproved due to increased operating income at both the
construction materials and coal operations and gains realized
from the sale of equipment.operations. Higher interest expense
resulting mainly from increased long-term debt due to suchthe
aforementioned acquisitions
decreased Other income -- net due to the consolidation of Hawaiian
Cement, as previously described, and an insurance settlement
received in 1997 related to the Unitek litigation, partially offset the increase in
earnings.
Oil and Natural Gas Production Operations
Operating income for the oil and natural gas production business
decreased largely as a result of a $33.1 million ($20
million after tax) non-cash write-down oflower oil and natural gas
properties, as previously discussed in Note 6 of Notes to
Consolidated Financial Statements. Lower oil and natural gas
revenues also added to the operating income decline.revenues. Decreased oil
revenue resulted from a $2.3$1.7 million decline due to lower average
prices and a $451,000$860,000 decrease due to lower production. The
decrease in naturalNatural gas
revenue was largelyrevenues increased slightly due to a $852,000
decline$824,000 increase arising from
higher production, including the effects of the acquisition of a
majority interest in the Willow Springs Field in east Texas in July
1998, somewhat offset by a $626,000 decline due to lower production. Decreased operationaverage
prices. Operation and maintenance expenses,expense increased due largely to
the result of decreased production, lower
administrative costs associated with a working interest agreement
and a decline in well maintenance, partially offset the decrease in
operating income.previously mentioned acquisition. Taxes other than income
decreased mainly due to lower production taxes resulting from lower
commodity prices, which
also partially offsetoffsetting the operating income decline.
Earnings for this business unit decreased due to the decrease
in operating income. Decreasedincome and increased interest expense due to lower
average long-term debt balancesexpense. Lower income
taxes slightly offset the decline in earnings.
SixNine Months Ended JuneSeptember 30, 1998 and 1997
Electric Operations
Operating income at the electric business increased due to the
acquisitions of ILBInternational Line Builders, Inc. (ILB) and HLEHigh
Line Equipment, Inc. (HLE) in July 1997, and Pouk & Steinle, Inc. in
April 1998, and Harp Line and Harp Engineering in July 1998, and due
to increased operating income at the electric utility operating income.utility. Increased
sales for resale revenue and lower maintenance expense contributed
to the utility operating income increase. Sales for resale revenue
increased due to 9382 percent higher volumes and higher margins of 3029
percent, both due to favorable market conditions. The decrease in
maintenance expense was due to 1997 costs of $1.6$1.9 million associated
with a ten-week maintenance outage at the Coyote Station. In
addition, damages caused by an April 1997 blizzard also added to the
decline in maintenance expense.expense for 1998. Increased average realized
retail rates also contributed to the operating income improvement.
Increased fuel and purchased power costs, largely higher purchased
power demand charges resulting from the pass-
throughpass-through of periodic
maintenance costs, and lower retail sales
volumes, primarily to residential and commercial customers, partially offset the operating income improvement
at the electric utility.
Earnings for the electric business increased due to the
aforementioned operating income increase at the electric utility,
$1.1 million in earnings attributable to ILB, HLE and Pouk &
Steinle, Inc. and decreased net interest
expense dueexpense. Earnings attributable to lower
average long-term debt balances and interest rates.Utility Services were $2.1
million.
Natural Gas Distribution Operations
Operating income decreased at the natural gas distribution
business due to reduced weather-related sales, the result of 10
percent warmer weather. IncreasedOperating revenues increased due to
increased average realized rates and the pass-through of higher
average natural gas costs, more thanpartially offset by the revenue decline that resulted from reducedaforementioned
reduction in sales volumes. Decreased operation and maintenance
expense due primarily to lower payroll andemployee benefit-related costs
partially offset the operating income decline.
Natural gas distribution earnings decreased due to the
previously discussed decline in operating income, partially offset
by increased service and repair income.
Natural Gas Transmission Operations
Operating income at the natural gas transmission business
increased primarily due to increases in transportation revenues.
The increase in transportation revenue resulted from a $5.0 million
($3.1 million after tax) reversal of reserves in the first quarter
of 1998 for certain contingencies relating to a FERC order
concerning a compliance filing. Higher transportationvolumes transported to
storage,
and off-system markets, somewhat offset by lower transportationvolumes transported to on-systemon- and
off-system markets, also added to the transportation revenue
improvement. Higherand higher average discounted rates primarily off-system
transportation and gathering, also
contributed to the revenue increase. In addition, transportation revenue increased due toLower production royalties
caused by a 1997 MMS royalty settlement, as previously discussed in
the absence of additional 1997 reserved revenues, with a corresponding
reduction in depreciation expense, as a result of FERC orders
relating to a 1992 general rate proceeding. The revenue increase
was partially offset by the completion of the recovery of deferred
natural gas contract buy-out/buy-down and gas supply realignment
costs in 1997, with a related reduction in operation expense.
Increased energy marketing revenues, due to higher natural gas
volumes sold,three months discussion, also added to the operating income
increase. In addition, higher average prices on company-owned
natural gas production added to the operating income improvement.
The increase in energy marketing revenue and the related increase
in purchased gas sold result from the acquisition of IGS in July
1998.
Earnings for this business increased due to the operating income
improvement, gains realized on the sale of natural gas held under
the repurchase commitment and decreased carrying costs on
this gas stemming from lower average borrowings.interest expense.
Construction Materials and Mining Operations
Construction Materials Operations --
Construction materials operating income increased $6.2$18.7 million
primarily due to the acquisitions ofpreviously described in the 50 percent interest in
Hawaiian Cement that Knife River did not previously own in July
1997, MBI and S2-F in March 1998, and Angell Bros., Inc. in April
1998. Prior to August 1997, Knife River's original 50 percent
ownership interest in Hawaiian Cement was accounted for under the
equity method. However, with the acquisition mentioned above,
Knife River began consolidating Hawaiian Cement into its financial
statements.three
months discussion. Operating income at the other construction
materials operations declinedincreased due primarilyto higher aggregate sales volumes
and margins in Alaska and southern Oregon due to increased
construction activity, higher cement margins in Alaska and Hawaii
due to lower construction activitycosts and lower asphalt costs in California caused mainly by weather-related delays.1998 when compared to
higher cost 1997 flood-related work in California.
Coal Operations --
Operating income for the coal operations increased $3.3$3.9 million
primarily due to increased revenues resulting from higher sales,
of
553,000 tonsprimarily to the Coyote Station. The increasesincrease in 1998 weresales to the
Coyote Station was largely due to thea 1997 ten-week maintenance
outage. Increased operation and maintenanceoperating expenses, and taxes other than income, all primarily due to the
increase in volumes sold, partially offset the operating income
improvement.
Consolidated --
Earnings increased due to increased operating income at both the
construction materials and coal operations and gains realized from
the sale of equipment. Higher interest expense resulting mainly
from increased long-term debt due to suchthe previously noted
acquisitions, decreased Other income -- net due to the consolidation
of Hawaiian Cement, as previously described in the three months
discussion, and an insurance settlement received in 1997 related to
the Unitek litigation, all partially offset the increase in
earnings.
Oil and Natural Gas Production Operations
Operating income for the oil and natural gas production business
decreased largely as a result of the $33.1 million ($20 million
after tax) non-cash write-down of oil and natural gas properties,
as previously discussed in Note 6 of Notes to Consolidated Financial
Statements. Lower oil and natural gas revenues also added to the
decrease in operating income. Decreased oil revenue resulted from
a $5.0$6.7 million decline due to lower average prices and a $970,000$1.9
million decrease due to lower production. The decrease in natural
gas revenue was due to a $2.1$2.8 million decline arising from lower
average prices and a $2.1$1.2 million reduction due to lower production.
Decreased operation and maintenance expenses, the result of lower
production and decreased well maintenance, partially offset the
decrease in operating income. Depreciation,Decreased depreciation, depletion and
amortization decreased due to lower production, also somewhat offsetting the decline in operating
income. In addition,and decreased taxes other than
income, decreased, mainly due to lower production taxes resulting from lower
commodity prices,
which also partially offset the operating income
decline.
Earnings for this business unit decreased due to the decrease
in operating income. Decreasedincome, partially offset by lower interest expense due to lower
average long-term debt balances slightly offset the decline in
earnings.and
decreased income taxes.
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. 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.
Regulated Operations --
In addition to other factors and matters discussed elsewhere
herein, some important factors that could cause actual results or
outcomes for the Company and its regulated operations 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, wholesale and retail competition (including but not
limited to electric retail wheeling and transmission costs),
availability of economic supplies of natural gas, and present or
prospective natural gas distribution or transmission competition
(including but not limited to prices of alternate fuels and system
deliverability costs).
Non-Regulated Operations --
Certain important factors which could cause actual results or
outcomes for the Company and all or certain of its non-regulated
operations to differ materially from those discussed in forward-
looking statements include the level of governmental expenditures
on public projects and project schedules, changes in anticipated
tourism levels, competition from other suppliers, oil and natural
gas commodity prices, drilling successes in oil and natural gas
operations, ability to acquire oil and natural gas properties, and
the availability of economic expansion or development opportunities.
Factors Common to Regulated and Non-Regulated Operations --
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 obligations with respect to the Company's financial
instruments, changes in accounting principles and/or the application
of such principles to the Company, changes in technology and legal
proceedings, and the ability of the Company and othersthird parties,
including suppliers and vendors, to identify and address year 2000
technical
issues.
Prospective Information
On July 1, 1998, the Company acquired Harp Line Constructors
Co. (Harp Line) and Harp Engineering, Inc. (Harp Engineering).
Both companies are headquarteredissues in Kalispell, Montana, and provide
various construction and engineering services to electric, natural
gas and telecommunication utilities in Montana and other western
states.
On July 1, 1998, the Company also acquired Innovative Gas
Services (IGS) and its affiliated company, Marcon Energy
Corporation (MEC), a full service natural gas marketing company
located in Owensboro, Kentucky. IGS currently transacts the
majority of its business on the Texas Gas interstate pipeline
system which originates in the Louisiana Gulf Coast area and in
East Texas and serves customers in the Midwestern and southern
regions of the United States.
On July 15, 1998, Fidelity Oil Co. acquired a majority interest
in 60 natural gas wells located over 8,000 acres within the Willow
Springs Field in eastern Texas.
On July 31, 1998, the Company acquired Hap Taylor & Sons, Inc.
(HTS), a privately held contractor and construction materials
company serving central Oregon. HTS specializes as a general
contractor building subdivisions and destination resorts and also
produces aggregates, ready-mixed concrete and asphalt for its use
in construction projects.
The Company continues to seek additional growth opportunities,
including investing in the development of related lines of
business.timely manner.
Year 2000 Compliance
The year 2000 issue is the result of computer programs having
been written using two digits rather than four digits to define the
applicable year. TheIn 1997, the Company is currently evaluating and will
continue to evaluate the potential effectsestablished a task force with
coordinators in each of the year 2000 issue
on its systems. The Company is making and will continue to make
those modifications to its systems that it deems necessary or
desirable in ordermajor operating units to address the
year 2000 issueissue. The scope of the year 2000 readiness effort
includes information technology (IT) and non-IT systems, including,
computer hardware, software, networking, communications, embedded
and micro-processor controlled systems, building controls and office
equipment. The Company's year 2000 plan is based upon a six-phase
approach involving awareness, inventory, assessment, remediation,
testing and will continueimplementation.
State of Readiness --
The Company is conducting a corporate-wide awareness program,
compiling an inventory of IT and non-IT systems, and assigning
priorities to test such modifications in ordersystems. As of September 30, 1998, the awareness
and inventory phases, including assigning priorities to determine
whether they effectively mitigate potential problems. BasedIT and non-
IT systems, have been substantially completed.
The assessment phase involves the review of each inventory item
for year 2000 compliance and efforts to obtain representations and
assurances from third parties, including suppliers and vendors, that
such entities are year 2000 compliant. As of September 30, 1998,
based on its
assessmentscontacts with and representations obtained from third
parties to date, the Company believes that the costs expectedis not aware of any material third
party year 2000 problems. The Company will continue to be incurred specifically related to such modifications will not
be material to its resultscontact
third parties seeking written verification of operations. Failure byyear 2000 readiness.
Thus, the Company to effectively address the year 2000 issue could have a material
effect on its results of operations and its ability to conduct its
business.
The Company's systems and operations with respect to the year
2000 issue may also be affected by other entities with which the
Company transacts business. The Company is currentlypresently unable to determine the potential
adverse consequences, if any, that could result from each such
entities' failure to effectively address the year 2000 issue. As
of September 30, 1998, the assessment phase, as it relates to the
Company's review of its inventory items, has been substantially
completed.
The remediation, testing and implementation phases of the
Company's year 2000 plan are currently in various stages of
completion. The remediation phase includes replacements,
modifications and/or upgrades necessary for year 2000 compliance
that were identified in the assessment phase. As of September 30,
1998, the remediation phase at the oil and natural gas production
business is substantially complete; at the electric, natural gas
distribution and natural gas transmission businesses is more than
50 percent complete; and at the construction materials and mining
business is in the beginning stages of completion. The testing
phase involves testing systems to confirm year 2000 readiness. As
of September 30, 1998, the testing phase at the oil and natural gas
production business is substantially complete; at the electric,
natural gas distribution and natural gas transmission businesses is
over 25 percent complete; and at the construction materials and
mining business is in the beginning stages of completion. The
implementation phase is the process of moving a year 2000 compliant
item into production status. As of September 30, 1998, the
implementation phase at the oil and natural production business is
substantially complete; at the electric, natural gas distribution
and natural gas transmission businesses is more than 50 percent
complete; and at the construction materials and mining business is
in the beginning stages of completion. The Company has established
a target date of October 1, 1999 to complete the remediation,
testing and implementation phases.
Costs --
The estimated incremental cost to the Company of the year 2000
issue is approximately $1 million to $3 million during the 1998
through 2000 time periods. As of September 30, 1998, the Company
has incurred incremental costs of less than $100,000. These costs
are being funded through cash flows from operations. The Company's
current estimate of costs of the year 2000 issue is based on the
facts and circumstances existing at this time, which were derived
utilizing numerous assumptions of future events.
Risks --
The failure to correct a material year 2000 problem, including
failures on the part of third parties, could result in a temporary
interruption in, or failure of, certain critical business
operations, including electric distribution, generation and
transmission; natural gas distribution, transmission, storage and
gathering; energy marketing; mining and marketing of coal,
aggregates and related construction materials; oil and natural gas
exploration, production, and development; and utility line
construction and repair services. Although the Company believes
the project will be completed by October 1, 1999, unforeseen and
other factors could cause delays in the project, the results of
which could have a material effect on the results of operations and
the Company's ability to conduct its business.
Contingency Planning --
Due to the general uncertainty inherent in the year 2000 issue,
including the uncertainty of the year 2000 readiness of third
parties, the Company anticipates having contingency plans in place
by October 1, 1999 designed to address the Company's critical
business operations as previously discussed.
Liquidity and Capital Commitments
Montana-Dakota's 1998 net capital needs for 1998expenditures are estimated at
$23$23.0 million, for net capital expenditures and $20.4 million for the
retirement of long-term securities. Estimated net capital
expenditures includeincluding those required for system upgrades, routine
replacements and service extensions. It is anticipated that
Montana-Dakota will continue to provide all of the funds required
for its net capital expenditures and securities retirements from internal sources, through the
use of the Company's $40 million revolving credit and term loan
agreement, $40 million of which was outstanding at JuneSeptember 30,
1998, and through the issuance of long-term debt of the Company, the
amount and timing of which will depend upon Montana-
Dakota'sMontana-Dakota's needs,
internal cash generation and market conditions. In
MayOn September 18,
1998, the Company redeemed $20issued $15 million of its 9 1/8 percent
Series first mortgage bonds, due May 15, 2006.in Secured Medium-Term Notes.
WBI Holdings' 1998 net capital expenditures are estimated at
$29.2$30.1 million, including those required for the acquisition of IGS
and MECMarcon Energy Corporation (MEC) and for routine system
improvements and continued development of natural gas reserves. WBI
Holdings expects to continue to meet its net capital expenditures
for 1998 with a combination of internally generated funds, short-termshort-
term lines of credit aggregating $35.6 million, $325,000$3.7 million of
which was outstanding at JuneSeptember 30, 1998, and through the
issuance of long-term debt and the Company's equity securities, the
amount and timing of which will depend upon WBI Holdings' needs,
internal cash generation and market conditions.
Knife River's 1998 net capital expenditures are estimated at
$177$164.6 million, including expenditures required for the acquisitions
of MBI, S2-F, Angell Bros., Inc. and Hap Taylor & Sons, Inc. Knife
River's 1998 estimated net capital expenditures also includeand
routine equipment upgrades and replacements and the building of
construction materials handling facilities.replacements. It is anticipated that
these net capital expenditures will continue to be met through funds
generated from internal sources, lines of credit aggregating $45.9$45.5
million, $9.2$5.4 million of which was outstanding at JuneSeptember 30,
1998, a revolving credit agreement of $85 million, $69$77 million of
which was outstanding at JuneSeptember 30, 1998, and the issuance of the
Company's equity securities. Amounts available underOn October 29, 1998, Knife River
privately placed $55 million of notes with the short-term lines of
credit recently increased from $32.4 millionproceeds used to
$45.9 million.repay other long-term debt.
Fidelity Oil's 1998 net capital expenditures related to its oil
and natural gas program are estimated at $100$94.0 million, including
those required for the acquisition of a majority interest in 60
natural gas wells in eastern Texas, as previously discussed.the
Willow Springs Field. It is anticipated that Fidelity's 1998 net
capital expenditures will be used to further enhance production and
reserve growth, and such expenditures will continue to be met from
internal sources, existing long-term credit facilities and the
issuance of the Company's equity securities. Fidelity's borrowing
base, which is based on total proved reserves, is currently $100
million. This consists of $17$16 million of issued notes, $13$14 million
in an uncommitted note shelf facility, and a $70 million revolving
line of credit, $300,000$46.9 million of which was outstanding at JuneSeptember
30, 1998. On July 13, Fidelity's
borrowing base increased from $65 million to $100 million.
Other corporate net capital expenditures for 1998 are estimated
at $18$18.9 million, including those expenditures required for the
acquisition of Pouk & Steinle, Inc., Harp Line and Harp Engineering,
and for routine equipment maintenance and replacements. These
capital expenditures are anticipated to be met through internal
sources, short-term lines of credit aggregating $4.8 million, $739,000$2.6
million of which was outstanding at JuneSeptember 30, 1998, and the
issuance of the Company's equity securities.
The estimated 1998 net capital expenditures set forth above do
not include potential future acquisitions. The Company continues
to seek additional growth opportunities, including investing in the
development of related lines of business. To the extent that
acquisitions occur, the Company anticipates that such acquisitions
would be financed with existing credit facilities and the issuance
of long-term debt and the Company's equity securities.
The Company utilizes its short-term lines of credit,
aggregating $50 million, $2 millionnone of which was outstanding on JuneSeptember
30, 1998, and its $40 million revolving credit and term loan
agreement, $40 million of which was outstanding at JuneSeptember 30,
1998, as previously described, to meet its short-term financing
needs and to take advantage of market conditions when timing the
placement of long-term or permanent financing.
Centennial presently intends to implement in the fourth quarter
of 1998, a $200 million commercial paper credit facility which would
be used to replace certain existing short-term credit facilities at
its subsidiaries.
The Company's issuance of first mortgage debt is subject to
certain restrictions imposed under the terms and conditions of its
Indenture of Mortgage. Generally, those restrictions require the
Company to 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 JuneSeptember 30, 1998, the Company could have issued
approximately $283$270 million of additional first mortgage bonds.
The Company's coverage of combined fixed charges and preferred
stock dividends was 2.83.2 and 3.4 times for the twelve months ended
JuneSeptember 30, 1998, and December 31, 1997, respectively.
Additionally, the Company's first mortgage bond interest coverage
was 7.06.6 and 6.0 times for the twelve months ended JuneSeptember 30,
1998, and December 31, 1997, respectively. Common stockholders'
equity as a percent of total capitalization was 6057 percent and 55
percent at JuneSeptember 30, 1998, and December 31, 1997, respectively.
PART II -- OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
Williston Basin joined other defendants and filed a motion for
summary affirmance in relation to the Grynberg legal proceeding.
The motion was granted on October 6, 1998 and the appeal was
effectively dismissed. For more information on this legal action,
see Note 7 of Notes to Consolidated Financial Statements.
On May 15,October 9, 1998, Grynberg appealeda hearing before the U.S. District Court's
decision.arbitration panel was
completed in relation to the long-term coal supply agreement between
the owners of the Coyote Station and Knife River. At the hearing
the Co-owners requested damages of approximately $24 million,
including interest, plus a reduction in the future price of coal
under the agreement. A decision from the arbitration panel is
expected after the completion of a post-hearing briefing. For more
information on this legal action, see Note 7 of Notes to
Consolidated Financial Statements.
ITEM 2. CHANGES IN SECURITIES AND USE OF PROCEEDS
On AprilJuly 1, 1998 and October 26, 1998, the Company issued to the
shareholders of Angell Bros., Inc., 407,185IGS and MEC, 192,023 shares (before stock split) and
15,141 shares (after stock split), respectively, of Common Stock,
$3.33 par value, (Company Common Stock) to acquire all of the issued
and outstanding capital stock of Angell Bros., Inc.IGS and MEC. On April 28,July 1, 1998, July
16, 1998 and August 12,September 9, 1998, the Company issued to the
shareholders of Pouk
& Steinle, Inc. 138,360Harp Line 372,939 shares (before stock split),
221,564 shares (after stock split), and 23,03826,048 shares (after stock
split), respectively, of Company Common Stock, $3.33
par value, to acquire all of the
issued and outstanding capital stock of PoukHarp Line. On July 1, 1998,
the Company issued to the shareholders of Harp Engineering, 14,771
shares (before stock split) of Company Common Stock, to acquire all
of the issued and outstanding capital stock of Harp Engineering.
On July 31, 1998 and September 9, 1998, the Company issued to the
shareholders of Hap Taylor & Steinle,Sons, Inc., 383,692 shares (after stock
split) and 3,380 shares (after stock split), respectively, of
Company Common Stock, to acquire all of the issued and outstanding
capital stock of Hap Taylor & Sons, Inc. The Company Common Stock
issued by the
Company in these two transactions was issued in private sales exempt from
registration pursuant to Section 4(2) of the Securities Act of 1933.
The shareholders have acknowledged that they are holding the Company'sCompany
Common Stock as an investment and not with a view to distribution.
ITEM 5. OTHER INFORMATION
Rule 14a-4 of the Securities and Exchange Commission's proxy
rules allows the Company to use discretionary voting authority to
vote on matters coming before an annual meeting of stockholders, if
the Company does not have notice of the matter at least 45 days
before the date on which the Company first mailed its proxy
materials for the prior year's annual meeting of stockholders or
the date specified by an advance notice provision in the Company's
Bylaws. The Company's Bylaws contain such an advance notice
provision.
Under the Company's Bylaws, no business may be brought before
an Annual Meeting of Stockholders except as specified in the notice
of the meeting or as otherwise properly brought before the meeting
by or at the direction of the Board or by a stockholder entitled
to vote who has delivered written notice to the Secretary of the
Company (containing certain information specified in the Bylaws)
not less than 120 days prior to the date on which the Company first
mailed its proxy materials for the prior year's Annual Meeting.
The Bylaws also provide that nominations for Director may be made
only by the Board or the Nominating Committee, or by a stockholder
entitled to vote who has delivered written notice to the Secretary
of the Company (containing certain information specified in the
Bylaws) not less than 120 days prior to the date on which the
Company first mailed its proxy materials for the prior year's
Annual Meeting. For the Company's Annual Meeting of Stockholders
expected to be held on April 27, 1999, stockholders must submit
such written notice to the Secretary of the Company on or before
November 9, 1998.
This requirement is separate and apart from the Securities and
Exchange Commission's requirements that a stockholder must meet in
order to have a stockholder proposal included in the Company's
proxy statement under Rule 14a-8. For the Company's Annual Meeting
of Stockholders expected to be held on April 27, 1999, any
stockholder who wishes to submit a proposal for inclusion in the
Company's proxy materials pursuant to Rule 14a-8 must submit such
proposal to the Secretary of the Company on or before November 9,
1998.
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
a) Exhibits
(12)3(b) By-laws of the Company, as amended to date
12 Computation of Ratio of Earnings to Fixed Charges and
Combined Fixed Charges and Preferred Stock Dividends
(27)27 Financial Data Schedule
b) Reports on Form 8-K
Form 8-K was filed on July 7, 1998. Under Item 5--Other
Events, the Company announced the acquisitions of Harp Line, Harp
Engineering, IGS and MEC. It was also reported that because of
the lowest oil prices in over a decade second quarter earnings
would include a special non-cash charge of approximately $20
million after tax.None.
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of
1934, the registrant has duly caused this report to be signed on its
behalf by the undersigned thereunto duly authorized.
MDU RESOURCES GROUP, INC.
DATE August 13,November 12, 1998 BY /s/ Warren L. Robinson
Warren L. Robinson
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)3(b) By-laws of the Company, as amended to date
12 Computation of Ratio of Earnings to Fixed Charges
and Combined Fixed Charges and Preferred Stock
Dividends
(27)27 Financial Data Schedule