UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
X QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
FOR THE QUARTERLY PERIOD ENDED JUNE 30, 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, 1998:
52,844,778 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 and 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 and Hawaii and provides
related supplies, equipment and engineering services.
INDEX
Part I -- Financial Information
Consolidated Statements of Income --
Three and Six Months Ended June 30, 1998 and 1997
Consolidated Balance Sheets --
June 30, 1998 and 1997, and December 31, 1997
Consolidated Statements of Cash Flows --
Six Months Ended June 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 Six Months
Ended Ended
June 30, June 30,
1998 1997 1998 1997
(In thousands, except per share amounts)
Operating revenues:
Electric $ 48,182 $ 31,770 $ 92,921 $ 69,043
Natural gas 38,102 42,379 111,646 102,442
Construction materials and mining 80,895 35,081 119,856 58,084
Oil and natural gas production 12,536 16,150 25,414 35,623
179,715 125,380 349,837 265,192
Operating expenses:
Fuel and purchased power 12,408 10,221 24,241 22,399
Purchased natural gas sold 11,334 16,090 43,509 37,118
Operation and maintenance 103,844 60,876 173,567 114,670
Depreciation, depletion and amortization 19,365 14,406 37,154 30,075
Taxes, other than income 6,259 5,339 12,652 11,726
Write-down of oil and natural gas
properties (Note 6) 33,100 --- 33,100 ---
186,310 106,932 324,223 215,988
Operating income (loss):
Electric 7,502 4,268 15,950 12,716
Natural gas distribution (819) (53) 5,974 7,045
Natural gas transmission 7,828 7,177 20,724 14,590
Construction materials and mining 9,368 1,708 10,525 1,019
Oil and natural gas production (30,474) 5,348 (27,559) 13,834
(6,595) 18,448 25,614 49,204
Other income -- net 2,554 2,027 5,156 1,574
Interest expense 7,215 7,041 14,350 14,133
Income (loss) before income taxes (11,256) 13,434 16,420 36,645
Income taxes (5,471) 4,693 4,412 13,308
Net income (loss) (5,785) 8,741 12,008 23,337
Dividends on preferred stocks 195 196 389 391
Earnings (loss) on common stock $ (5,980) $ 8,545 $ 11,619 $ 22,946
Earnings (loss) per common share -- basic $ (.12) $ .20 $ .24 $ .53
Earnings (loss) per common share -- diluted $ (.12) $ .20 $ .24 $ .53
Dividends per common share $ .1917 $ .1850 $ .3833 $ .3700
Average common shares outstanding -- basic 50,936 43,104 48,171 42,999
Average common shares outstanding -- diluted 50,936 43,247 48,412 43,129
The accompanying notes are an integral part of these consolidated statements.
MDU RESOURCES GROUP, INC.
CONSOLIDATED BALANCE SHEETS
(Unaudited)
June 30, June 30, December 31,
1998 1997 1997
(In thousands)
ASSETS
Current assets:
Cash and cash equivalents $ 43,106 $ 31,514 $ 28,174
Receivables 88,059 58,697 80,585
Inventories 40,664 28,003 41,322
Deferred income taxes 16,041 23,375 17,356
Prepayments and other current assets 15,106 25,480 12,479
202,976 167,069 179,916
Investments 20,513 54,216 18,935
Property, plant and equipment:
Electric 571,936 552,636 566,247
Natural gas distribution 175,219 167,464 172,086
Natural gas transmission 292,865 281,205 288,709
Construction materials and mining 446,936 180,658 243,110
Oil and natural gas production 218,373 224,381 240,193
1,705,329 1,406,344 1,510,345
Less accumulated depreciation,
depletion and amortization 694,878 645,086 670,809
1,010,451 761,258 839,536
Deferred charges and other assets 74,795 63,839 75,505
$1,308,735 $1,046,382 $1,113,892
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Short-term borrowings $ 8,439 $ 7,675 $ 3,347
Long-term debt and preferred
stock due within one year 5,571 6,854 7,902
Accounts payable 39,880 31,216 31,571
Taxes payable --- 3,379 9,057
Dividends payable 10,040 8,173 8,574
Other accrued liabilities,
including reserved revenues 68,850 97,032 88,563
132,780 154,329 149,014
Long-term debt 332,126 258,306 298,561
Deferred credits and other liabilities:
Deferred income taxes 178,995 119,299 119,747
Other liabilities 130,959 133,960 143,574
309,954 253,259 263,321
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,
$3.33 par value at June 30, 1998,
28,747,683, $3.33 par value at
June 30, 1997 and 29,143,332, $3.33
par value at December 31, 1997) 171,859 95,730 97,047
Other paid-in capital 143,885 69,386 76,526
Retained earnings 205,057 198,572 212,723
Treasury stock at cost (239,521 shares) (3,626) --- ---
Total common stockholders' equity 517,175 363,688 386,296
Total stockholders' equity 533,875 380,488 402,996
$1,308,735 $1,046,382 $1,113,892
The accompanying notes are an integral part of these consolidated statements.
MDU RESOURCES GROUP, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Six Months Ended
June 30,
1998 1997
(In thousands)
Operating activities:
Net income $ 12,008 $ 23,337
Adjustments to reconcile net income to net cash provided
by operating activities:
Depreciation, depletion and amortization 37,154 30,075
Deferred income taxes and investment tax credit -- net 4,995 4,444
Recovery of deferred natural gas contract litigation
settlement costs, net of income taxes --- 2,890
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
Inventories 4,636 (642)
Other current assets (44) (9,913)
Accounts payable 4,440 (364)
Other current liabilities (30,354) 1,877
Other noncurrent changes (8,829) 2,743
Net cash provided by operating activities 56,722 68,937
Financing activities:
Net change in short-term borrowings (1,408) 3,725
Issuance of long-term debt 58,501 ---
Repayment of long-term debt (40,490) (27,365)
Issuance of common stock 30,109 5,983
Retirement of natural gas repurchase commitment (12,374) (37,018)
Dividends paid (19,674) (16,306)
Net cash provided by (used in) financing activities 14,664 (70,981)
Investing activities:
Capital expenditures including acquisitions of businesses --
Electric (5,861) (7,098)
Natural gas distribution (3,847) (4,007)
Natural gas transmission (5,066) (3,935)
Construction materials and mining (29,632) (8,647)
Oil and natural gas production (19,014) (14,061)
(63,420) (37,748)
Net proceeds from sale or disposition of property 2,557 2,889
Net capital expenditures (60,863) (34,859)
Sale of natural gas available under repurchase commitment 5,987 21,333
Investments (1,578) (715)
Net cash used in investing activities (56,454) (14,241)
Increase (decrease) in cash and cash equivalents 14,932 (16,285)
Cash and cash equivalents -- beginning of year 28,174 47,799
Cash and cash equivalents -- end of period $ 43,106 $ 31,514
The accompanying notes are an integral part of these consolidated statements.
MDU RESOURCES GROUP, INC.
NOTES TO CONSOLIDATED
FINANCIAL STATEMENTS
June 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. Accounting change
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 six months ended June 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 six months ended June 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 for
September 23, 1998.
Williston Basin believes that it is entitled to recover
from ratepayers 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.
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 merit and intends to
vigorously contest this suit.
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 of 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-
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.
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. A hearing before the arbitration panel is
currently scheduled for October 5, 1998. 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.
Williston Basin is currently evaluating the implication of the
order and what option to pursue.
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
costs to the Frontier gas were appropriate. See Note 8 regarding
the July 29, 1998 FERC order which addresses various issues,
including the 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 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:
Six Months Ended
June 30,
1998 1997
(In thousands)
Interest, net of amount capitalized $12,408 $12,384
Income taxes $17,489 $12,435
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, has 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 hedge agreements are not held for trading
purposes. The hedge agreements call for the Company 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 hedge
agreements are closely matched, and hedge prices are established in
the areas of the Company's operations. Amounts payable or
receivable on hedge 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.
Knife River has entered into an interest rate swap
agreement to manage a portion of its interest rate exposure on
long-term debt. This interest rate swap agreement is not held for
trading purposes. The interest rate swap agreement calls 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 are based on the three-month floating London
Interbank Offered Rate. Settlement amounts payable or receivable
under this interest rate swap agreement are recorded in "Interest
expense" on the Consolidated Statements of Income in the accounting
period they are incurred. The amounts payable or receivable are
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):
Six Months Ended
June 30,
1998 1997
Oil swap agreements:*
Range of fixed prices per barrel $20.92 $19.77-$21.36
Notional amount (in barrels) 109 362
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 4,493
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 agreements outstanding
at June 30, 1998 (notional amounts in thousands):
Notional
Fixed Price Amount
Year (Per barrel) (In barrels)
Oil swap agreement* 1998 $20.92 110
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% $10,000
* 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 collar agreements outstanding
at June 30, 1998, was $35,000. 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 Six Months
Ended Ended
June 30, June 30,
Business 1998 1997 1998 1997
Electric $ 3.0 $ .9 $ 6.6 $ 4.3
Natural gas distribution (.9) (.5) 2.7 3.3
Natural gas transmission 4.3 3.5 12.4 6.0
Construction materials and mining 5.6 1.3 5.9 1.1
Oil and natural gas production (18.0) 3.3 (16.0) 8.2
Earnings on common stock $ (6.0) $ 8.5 $ 11.6 $ 22.9
Earnings per common share -- basic $ (.12) $ .20 $ .24 $ .53
Earnings per common share -- diluted $ (.12) $ .20 $ .24 $ .53
Return on average common equity
for the 12 months ended 10.0% 13.1%
Three Months Ended June 30, 1998 and 1997
Consolidated earnings for the quarter ended June 30, 1998, were
down $14.5 million from the comparable period a year ago due to
lower 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 partially offset
the earnings decrease.
Six Months Ended June 30, 1998 and 1997
Consolidated earnings for the six months ended June 30, 1998,
were down $11.3 million from the comparable period a year ago due
to decreased earnings at the oil and natural gas production
business, largely resulting from the aforementioned non-cash write-
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 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 Six Months
Ended Ended
June 30, June 30,
1998 1997 1998 1997
Operating revenues:
Retail sales $ 29.4 $ 30.0 $ 62.4 $ 64.2
Sales for resale and other 4.7 1.8 8.0 4.8
Utility services 14.1 --- 22.5 ---
48.2 31.8 92.9 69.0
Operating expenses:
Fuel and purchased power 12.4 10.2 24.2 22.4
Operation and maintenance 21.2 11.2 38.7 21.6
Depreciation, depletion and
amortization 4.8 4.3 9.5 8.7
Taxes, other than income 2.3 1.8 4.5 3.6
40.7 27.5 76.9 56.3
Operating income 7.5 4.3 16.0 12.7
Retail sales (kWh) 459.4 465.2 982.6 1,008.8
Sales for resale (kWh) 180.1 45.8 309.5 160.7
Cost of fuel and purchased
power per kWh $ .018 $ .018 $ .018 $ .018
Natural Gas Distribution Operations
Three Months Six Months
Ended Ended
June 30, June 30,
1998 1997 1998 1997
Operating revenues:
Sales $ 23.5 $ 25.9 $ 85.1 $ 81.5
Transportation and other .7 .7 1.7 1.7
24.2 26.6 86.8 83.2
Operating expenses:
Purchased natural gas sold 15.3 16.9 60.7 55.4
Operation and maintenance 6.9 7.1 14.5 15.1
Depreciation, depletion and
amortization 1.8 1.7 3.5 3.5
Taxes, other than income 1.0 1.0 2.1 2.1
25.0 26.7 80.8 76.1
Operating income (.8) (.1) 6.0 7.1
Volumes (dk):
Sales 4.5 5.6 18.5 20.7
Transportation 1.8 1.8 5.0 4.7
Total throughput 6.3 7.4 23.5 25.4
Degree days (% of normal) 99% 119% 95% 105%
Average cost of natural gas,
including transportation,
per dk $ 3.41 $ 3.01 $ 3.28 $ 2.66
Natural Gas Transmission Operations
Three Months Six Months
Ended Ended
June 30, June 30,
1998 1997* 1998 1997*
Operating revenues:
Transportation and storage $ 13.9 $ 13.8 $ 32.9 $ 31.1
Energy marketing and
natural gas production 8.2 9.2 18.9 17.6
22.1 23.0 51.8 48.7
Operating expenses:
Purchased gas sold 4.2 5.8 9.8 9.9
Operation and maintenance 6.7 8.7 14.3 19.7
Depreciation, depletion and
amortization 2.0 --- 4.1 1.8
Taxes, other than income 1.4 1.3 2.9 2.7
14.3 15.8 31.1 34.1
Operating income 7.8 7.2 20.7 14.6
Volumes (dk):
Transportation--
Montana-Dakota 7.6 8.8 16.0 17.6
Other 15.2 11.3 29.6 23.7
22.8 20.1 45.6 41.3
Produced (000's of dk) 1,718 1,654 3,470 3,411
* Includes $2.2 million and $4.7 million for the three months and six months
ended, respectively, of amortization and related recovery of deferred natural
gas contract buy-out/buy-down and gas supply realignment costs.
Construction Materials and Mining Operations
Three Months Six Months
Ended Ended
June 30, June 30,
1998 1997** 1998 1997**
Operating revenues:
Construction materials $ 71.9 $ 32.7 $101.6 $ 46.8
Coal 9.0 2.4 18.3 11.3
80.9 35.1 119.9 58.1
Operating expenses:
Operation and maintenance 65.4 30.3 98.6 51.2
Depreciation, depletion and
amortization 5.2 2.7 9.1 4.7
Taxes, other than income .9 .4 1.7 1.2
71.5 33.4 109.4 57.1
Operating income 9.4 1.7 10.5 1.0
Sales (000's):
Aggregates (tons) 2,560 1,111 3,422 1,695
Asphalt (tons) 391 196 421 250
Ready-mixed concrete
(cubic yards) 259 113 398 182
Coal (tons) 773 214 1,561 978
** 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 Six Months
Ended Ended
June 30, June 30,
1998 1997 1998 1997
Operating revenues:
Oil $ 6.3 $ 9.0 $ 13.1 $ 19.1
Natural gas 6.2 7.1 12.3 16.5
12.5 16.1 25.4 35.6
Operating expenses:
Operation and maintenance 3.6 4.2 7.4 8.3
Depreciation, depletion and
amortization 5.6 5.7 11.0 11.4
Taxes, other than income .7 .9 1.5 2.1
Write-down of oil and
natural gas properties 33.1 --- 33.1 ---
43.0 10.8 53.0 21.8
Operating income (30.5) 5.3 (27.6) 13.8
Production (000's):
Oil (barrels) 490 525 973 1,045
Natural gas (Mcf) 2,942 3,345 5,750 6,766
Average sales price:
Oil (per barrel) $12.90 $17.23 $13.47 $18.23
Natural gas (per Mcf) 2.11 2.12 2.14 2.45
Amounts presented in the above tables for natural gas operating
revenues and purchased natural gas sold for the three and six
months ended June 30, 1998 and 1997, and operation and maintenance
expenses for the three and six months ended June 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 June 30, 1998 and 1997
Electric Operations
Operating income increased at the electric business due to 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. Operating income improved at the utility primarily due to
increased sales for resale revenue and decreased maintenance
expense. Increased sales for resale volumes, due to favorable
market conditions, and higher average realized rates due 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,
partially offset the operating income improvement at the electric
utility.
Earnings for the electric business increased due to the
operating income improvement at the electric utility, $747,000 in
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.
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 17 percent warmer weather. The pass-
through of higher average natural gas costs partially offset the
revenue decline. Decreased operation and maintenance expense,
primarily lower employee benefit-related costs, partially offset
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 increased transportation revenues.
Higher transportation to storage, somewhat offset by lower
transportation to on and off-system markets, was largely
responsible for the transportation revenue improvement. Higher
average discounted rates, primarily off-system transportation and
gathering, also added to the revenue increase. In addition,
transportation revenue increased due to the absence of additional
1997 reserved revenues, with a corresponding reduction in
depreciation expense, which resulted from 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. Decreased energy
marketing natural gas sales volumes and margins, partially offset
the operating income increase.
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.
Construction Materials and Mining Operations
Construction Materials Operations --
Construction materials operating income increased $4.6 million
primarily due to the acquisitions of 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. 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 decreased due primarily
to lower construction activity in California caused by weather-
related delays and lower ready-mixed concrete margins in southern
Oregon. Increased asphalt margins in Alaska and lower asphalt cost
in California somewhat offset the operating income decline at the
other construction materials operations.
Coal Operations --
Operating income for the coal operations increased $3.1 million
primarily due to increased revenues resulting from higher sales of
509,000 tons to the Coyote Station. The increases in 1998 were
largely the result of the 1997 ten-week maintenance outage.
Increased operation and maintenance 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 such 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 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 operating income decline. Decreased oil
revenue resulted from a $2.3 million decline due to lower average
prices and a $451,000 decrease due to lower production. The
decrease in natural gas revenue was largely due to a $852,000
decline arising from lower production. Decreased operation and
maintenance expenses, 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. 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. Decreased interest expense due to lower
average long-term debt balances slightly offset the decline in
earnings.
Six Months Ended June 30, 1998 and 1997
Electric Operations
Operating income at the electric business increased due to the
acquisitions of ILB and HLE in July 1997, and Pouk & Steinle, Inc.
in April 1998, and increased electric utility operating income.
Increased sales for resale revenue and lower maintenance expense
contributed to the utility operating income increase. Sales for
resale revenue increased due to 93 percent higher volumes and
higher margins of 30 percent, both due to favorable market
conditions. 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 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 due to lower
average long-term debt balances and interest rates.
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. Increased average realized rates and the
pass-through of higher average natural gas costs more than offset
the revenue decline that resulted from reduced sales volumes.
Decreased operation and maintenance expense due primarily to lower
payroll and 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 transportation to storage
and off-system markets, somewhat offset by lower transportation to
on-system markets, also added to the transportation revenue
improvement. Higher average discounted rates, primarily off-system
transportation and gathering, also contributed to the revenue
increase. In addition, transportation revenue increased due to 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, also added to the operating income improvement.
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.
Construction Materials and Mining Operations
Construction Materials Operations --
Construction materials operating income increased $6.2 million
primarily due to the acquisitions of 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. Operating income at the other construction materials
operations declined due primarily to lower construction activity in
California caused mainly by weather-related delays.
Coal Operations --
Operating income for the coal operations increased $3.3 million
primarily due to increased revenues resulting from higher sales of
553,000 tons to the Coyote Station. The increases in 1998 were
largely due to the 1997 ten-week maintenance outage. Increased
operation and maintenance 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 such 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 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 million decline due to lower
average prices and a $970,000 decrease due to lower production.
The decrease in natural gas revenue was due to a $2.1 million
decline arising from lower average prices and a $2.1 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, depletion and amortization decreased due to
lower production, also somewhat offsetting the decline in operating
income. In addition, 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. Decreased interest expense due to lower
average long-term debt balances slightly offset the decline in
earnings.
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 others to 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 headquartered 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.
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. The Company is currently evaluating and will
continue to evaluate the potential effects 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 order to address the year 2000 issue and is testing
and will continue to test such modifications in order to determine
whether they effectively mitigate potential problems. Based on its
assessments to date, the Company believes that the costs expected
to be incurred specifically related to such modifications will not
be material to its results of operations. Failure by 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 currently unable to
determine the potential adverse consequences, if any, that could
result from each such entities' failure to effectively address the
year 2000 issue.
Liquidity and Capital Commitments
Montana-Dakota's net capital needs for 1998 are estimated at
$23 million for net capital expenditures and $20.4 million for the
retirement of long-term securities. Estimated net capital
expenditures include those 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 June 30, 1998, and through the issuance of long-term
debt, the amount and timing of which will depend upon Montana-
Dakota's needs, internal cash generation and market conditions. In
May 1998, the Company redeemed $20 million of its 9 1/8 percent
Series first mortgage bonds, due May 15, 2006.
WBI Holdings' 1998 net capital expenditures are estimated at
$29.2 million, including those required for the acquisition of IGS
and MEC and for routine system improvements and continued
development of natural gas reserves. WBI Holdings expects to meet
its net capital expenditures for 1998 with a combination of
internally generated funds, short-term lines of credit aggregating
$35.6 million, $325,000 of which was outstanding at June 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 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 include
routine equipment upgrades and replacements and the building of
construction materials handling facilities. It is anticipated that
these net capital expenditures will be met through funds generated
from internal sources, lines of credit aggregating $45.9 million,
$9.2 million of which was outstanding at June 30, 1998, a revolving
credit agreement of $85 million, $69 million of which was
outstanding at June 30, 1998, and the issuance of the Company's
equity securities. Amounts available under the short-term lines of
credit recently increased from $32.4 million to $45.9 million.
Fidelity Oil's 1998 net capital expenditures related to its oil
and natural gas program are estimated at $100 million, including
those required for the acquisition of a majority interest in 60
natural gas wells in eastern Texas, as previously discussed. It is
anticipated that Fidelity's 1998 net capital expenditures will be
used to further enhance production and reserve growth, and such
expenditures will 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
million of issued notes, $13 million in an uncommitted note shelf
facility, and a $70 million revolving line of credit, $300,000 of
which was outstanding at June 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 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 of which was outstanding at June 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. To the extent that
acquisitions occur, 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 million of which was outstanding on
June 30, 1998, and its $40 million revolving credit and term loan
agreement, $40 million of which was outstanding at June 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.
The Company's issuance of first mortgage debt is subject to
certain restrictions imposed under the terms and conditions of its
Indenture of Mortgage. Generally, those restrictions require the
Company to pledge $1.43 of unfunded property to the Trustee for
each dollar of indebtedness incurred under the Indenture and that
annual earnings (pretax and before interest charges), as defined in
the Indenture, equal at least two times its annualized first
mortgage bond interest costs. Under the more restrictive of the
two tests, as of June 30, 1998, the Company could have issued
approximately $283 million of additional first mortgage bonds.
The Company's coverage of combined fixed charges and preferred
stock dividends was 2.8 and 3.4 times for the twelve months ended
June 30, 1998, and December 31, 1997, respectively. Additionally,
the Company's first mortgage bond interest coverage was 7.0 and 6.0
times for the twelve months ended June 30, 1998, and December 31,
1997, respectively. Common stockholders' equity as a percent of
total capitalization was 60 percent and 55 percent at June 30,
1998, and December 31, 1997, respectively.
PART II -- OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
On May 15, 1998, Grynberg appealed the U.S. District Court's
decision. 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 April 1, 1998, the Company issued to the shareholders of
Angell Bros., Inc., 407,185 shares (before stock split) of Common
Stock, $3.33 par value, to acquire all of the issued and
outstanding capital stock of Angell Bros., Inc. On April 28, 1998
and August 12, 1998, the Company issued to the shareholders of Pouk
& Steinle, Inc. 138,360 shares (before stock split) and 23,038
shares (after stock split), respectively, of Common Stock, $3.33
par value, to acquire all of the issued and outstanding capital
stock of Pouk & Steinle, Inc. The 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's 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) Computation of Ratio of Earnings to Fixed Charges and
Combined Fixed Charges and Preferred Stock Dividends
(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.
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, 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) Computation of Ratio of Earnings to Fixed Charges
and Combined Fixed Charges and Preferred Stock
Dividends
(27) Financial Data Schedule