UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
X QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
FOR THE QUARTERLY PERIOD ENDED MARCH 31, 1999
OR
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the Transition Period from _____________ to ______________
Commission file number 1-3480
MDU Resources Group, Inc.
(Exact name of registrant as specified in its charter)
Delaware 41-0423660
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
Schuchart Building
918 East Divide Avenue
P.O. Box 5650
Bismarck, North Dakota 58506-5650
(Address of principal executive offices)
(Zip Code)
(701) 222-7900
(Registrant's telephone number, including area code)
Indicate by check mark whether the registrant (1) has filed
all reports required to be filed by Section 13 or 15(d) of the
Securities Exchange Act of 1934 during the preceding 12 months
(or for such shorter period that the registrant was required to
file such reports), and (2) has been subject to such filing
requirements for the past 90 days. Yes X. No.
Indicate the number of shares outstanding of each of the
issuer's classes of common stock, as of May 7, 1999: 53,156,004
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 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, distributes natural gas and
operates electric power generation, transmission and distribution
facilities, serving 256 communities in North Dakota, eastern
Montana, northern and western South Dakota and northern Wyoming.
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 subsidiaries,
provides underground storage, transportation and
gathering services through an interstate pipeline system
serving Montana, North Dakota, South Dakota and Wyoming,
produces natural gas, and seeks new energy markets while
continuing to expand present markets for natural gas and
propane in the Midwestern, Southern and Central regions
of the United States.
Knife River, through its wholly owned subsidiary, KRC
Holdings, Inc. (KRC Holdings) and its subsidiaries, mines
and markets aggregates and construction materials in
Alaska, California, Hawaii and Oregon, and operates
lignite coal mines 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.
Utility Services, through its wholly owned subsidiaries,
installs and repairs electric transmission and
distribution power lines, fiber optic cable and natural
gas pipeline and provides related supplies, equipment and
engineering services throughout the western United States
and Hawaii.
INDEX
Part I -- Financial Information
Consolidated Statements of Income --
Three Months Ended March 31, 1999 and 1998
Consolidated Balance Sheets --
March 31, 1999 and 1998, and December 31, 1998
Consolidated Statements of Cash Flows --
Three Months Ended March 31, 1999 and 1998
Notes to Consolidated Financial Statements
Management's Discussion and Analysis of Financial
Condition and Results of Operations
Quantitative and Qualitative Disclosures About Market Risk
Part II -- Other Information
Signatures
Exhibit Index
Exhibits
PART I -- FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
MDU RESOURCES GROUP, INC.
CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
Three Months Ended
March 31,
1999 1998
(In thousands, except
per share amounts)
Operating revenues:
Electric $ 58,974 $ 44,740
Natural gas 128,931 73,543
Construction materials and mining 60,038 38,961
Oil and natural gas production 11,103 12,878
259,046 170,122
Operating expenses:
Fuel and purchased power 13,503 11,833
Purchased natural gas sold 90,705 32,175
Operation and maintenance 101,999 69,723
Depreciation, depletion and amortization 20,140 17,789
Taxes, other than income 7,238 6,393
233,585 137,913
Operating income:
Electric 11,175 8,448
Natural gas distribution 5,464 6,793
Natural gas transmission 9,135 12,895
Construction materials and mining (1,239) 1,158
Oil and natural gas production 926 2,915
25,461 32,209
Other income -- net 3,768 2,602
Interest expense 8,806 7,135
Income before income taxes 20,423 27,676
Income taxes 7,702 9,883
Net income 12,721 17,793
Dividends on preferred stocks 193 194
Earnings on common stock $ 12,528 $ 17,599
Earnings per common share -- basic $ .24 $ .39
Earnings per common share -- diluted $ .23 $ .39
Dividends per common share $ .20 $ .1917
Weighted average common shares outstanding -- basic 53,147 45,375
Weighted average common shares outstanding -- diluted 53,420 45,629
The accompanying notes are an integral part of these consolidated statements.
MDU RESOURCES GROUP, INC.
CONSOLIDATED BALANCE SHEETS
(Unaudited)
March 31, March 31, December 31,
1999 1998 1998
(In thousands)
ASSETS
Current assets:
Cash and cash equivalents $ 36,930 $ 50,857 $ 39,216
Receivables 123,639 89,131 124,114
Inventories 43,176 34,549 44,865
Deferred income taxes 20,974 17,896 16,918
Prepayments and other current assets 17,849 18,896 15,536
242,568 211,329 240,649
Investments 40,550 18,131 43,029
Property, plant and equipment:
Electric 587,299 567,416 583,047
Natural gas distribution 179,396 173,468 178,522
Natural gas transmission 312,766 289,781 304,054
Construction materials and mining 493,080 414,520 484,419
Oil and natural gas production 264,478 250,341 260,758
1,837,019 1,695,526 1,810,800
Less accumulated depreciation,
depletion and amortization 741,392 686,642 726,123
1,095,627 1,008,884 1,084,677
Deferred charges and other assets 95,289 72,933 84,420
$1,474,034 $1,311,277 $1,452,775
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Short-term borrowings $ 122 $ 1,625 $ 15,000
Long-term debt and preferred
stock due within one year 2,502 10,436 3,292
Accounts payable 61,326 31,128 60,023
Taxes payable 20,540 16,508 9,226
Dividends payable 10,824 9,633 10,799
Other accrued liabilities,
including reserved revenues 85,756 79,701 71,129
181,070 149,031 169,469
Long-term debt 417,778 338,073 413,264
Deferred credits and other liabilities:
Deferred income taxes 173,885 178,899 173,094
Other liabilities 128,777 140,664 129,506
302,662 319,563 302,600
Preferred stock subject to mandatory
redemption 1,600 1,700 1,600
Commitments and contingencies
Stockholders' equity:
Preferred stocks 15,000 15,000 15,000
Common stockholders' equity:
Common stock (Shares issued --
$3.33 par value, 53,395,525
at March 31, 1999, 32,991,683
at March 31, 1998 and 53,272,951
at December 31, 1998) 177,807 109,862 177,399
Other paid-in capital 174,264 160,792 171,486
Retained earnings 207,479 220,882 205,583
Treasury stock at cost -- 239,521
shares at March 31, 1999 and
December 31, 1998 and 159,681
shares at March 31, 1998 (3,626) (3,626) (3,626)
Total common stockholders' equity 555,924 487,910 550,842
Total stockholders' equity 570,924 502,910 565,842
$1,474,034 $1,311,277 $1,452,775
The accompanying notes are an integral part of these consolidated statements.
MDU RESOURCES GROUP, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Three Months Ended
March 31,
1999 1998
(In thousands)
Operating activities:
Net income $ 12,721 $ 17,793
Adjustments to reconcile net income to net cash provided
by operating activities:
Depreciation, depletion and amortization 20,140 17,789
Deferred income taxes and investment tax credit (3,352) 450
Changes in current assets and liabilities:
Receivables 475 7,785
Inventories 1,689 10,577
Other current assets (2,313) (3,295)
Accounts payable 1,303 (3,368)
Other current liabilities 25,966 (6,322)
Other noncurrent changes (11,453) (4,190)
Net cash provided by operating activities 45,176 37,219
Financing activities:
Net change in short-term borrowings (14,878) (7,722)
Issuance of long-term debt 25,089 37,301
Repayment of long-term debt (21,366) (6,670)
Issuance of common stock 3,186 ---
Retirement of natural gas repurchase commitment (1,288) (4,786)
Dividends paid (10,825) (9,634)
Net cash provided by (used in) financing activities (20,082) 8,489
Investing activities:
Capital expenditures including acquisitions of businesses:
Electric (5,159) (2,779)
Natural gas distribution (2,211) (1,617)
Natural gas transmission (9,256) (1,117)
Construction materials and mining (12,231) (11,054)
Oil and natural gas production (8,751) (10,935)
(37,608) (27,502)
Net proceeds from sale or disposition of property 7,130 946
Net capital expenditures (30,478) (26,556)
Sale of natural gas available under repurchase commitment 619 2,727
Investments 2,479 804
Net cash used in investing activities (27,380) (23,025)
Increase (decrease) in cash and cash equivalents (2,286) 22,683
Cash and cash equivalents -- beginning of year 39,216 28,174
Cash and cash equivalents -- end of period $ 36,930 $ 50,857
The accompanying notes are an integral part of these consolidated statements.
MDU RESOURCES GROUP, INC.
NOTES TO CONSOLIDATED
FINANCIAL STATEMENTS
March 31, 1999 and 1998
(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, 1998 (1998 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 1998 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. For
the three months ended March 31, 1999 and 1998, comprehensive
income equaled net income as reported.
2. Seasonality of operations
Some of the company's operations are highly seasonal and
revenues from, and certain expenses for, such operations may
fluctuate significantly among quarterly periods. Accordingly,
the interim results may not be indicative of results for the
full fiscal year.
3. Cash flow information
Cash expenditures for interest and income taxes were as
follows:
Three Months Ended
March 31,
1999 1998
(In thousands)
Interest, net of amount capitalized $3,131 $3,033
Income taxes $ 130 $ 437
4. Reclassifications
Certain reclassifications have been made in the financial
statements for the prior period to conform to the current
presentation. Such reclassifications had no effect on net
income or common stockholders' equity as previously reported.
5. New accounting pronouncement
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 will adopt SFAS
No. 133 on January 1, 2000, and has not yet quantified the
impacts of adopting SFAS No. 133 on the company's financial
position or results of operations.
6. Derivatives
Williston Basin Interstate Pipeline Company (Williston
Basin), a wholly owned subsidiary of WBI Holdings, and Fidelity
Oil have entered into certain price swap and collar agreements
to manage a portion of the market risk associated with
fluctuations in the price of oil and natural gas. These swap
and collar agreements are not held for trading purposes. The
swap and collar agreements call for Williston 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 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 swap and collar agreements are closely
matched, and hedge prices are established in the areas of
operations. Amounts payable or receivable on the 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 generally offset by corresponding increases and
decreases in the value of the underlying commodity
transactions.
Innovative Gas Services, Incorporated, an indirect energy
marketing subsidiary of WBI Holdings, 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
generally offset by corresponding increases and decreases in
the value of the underlying commodity transactions.
Knife River had 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 was not held for trading purposes. The
interest rate swap agreement called 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 were based on the three-month floating London Interbank
Offered Rate. Settlement amounts payable or receivable under
this interest rate swap agreement were recorded in "Interest
expense" on the Consolidated Statements of Income in the
accounting period they were incurred. The amounts payable or
receivable were generally 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 compliance with its policies. The company
is exposed to credit-related losses in relation to financial
instruments in the event of nonperformance by counterparties,
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):
Three Months Ended
March 31,
1999 1998
Oil swap agreement:*
Weighted average fixed price per barrel --- $ 20.92
Notional amount (in barrels) --- 54
Natural gas swap agreements:*
Weighted average fixed price per MMBtu --- $ 2.23
Notional amount (in MMBtu's) --- 1,170
Natural gas collar agreements:*
Weighted average floor/ceiling
price per MMBtu $2.10/$2.51 $2.10/$2.67
Notional amount (in MMBtu's) 720 450
Interest rate swap agreement:**
Range of fixed interest rates --- 5.50%-6.50%
Notional amount (in dollars) --- $10,000
*Receive fixed -- pay variable
**Receive variable -- pay fixed
The following table summarizes hedge agreements
outstanding at March 31, 1999 (notional amounts in thousands):
Weighted
Average
Floor/Ceiling Notional
Year of Price Amount
Expiration (Per MMBtu) (In MMBtu's)
Natural gas collar
agreements* 1999 $2.10/$2.51 2,200
Weighted
Average Notional
Year of Fixed Price Amount
Expiration (Per MMBtu) (In MMBtu's)
Natural gas futures
contracts* 2000 $2.38 1,000
* Receive fixed -- pay variable
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 commodity hedge agreements are expected to be
generally offset by corresponding increases and decreases in
the value of the underlying commodity transactions. The
company's net favorable position on all hedge agreements
outstanding at March 31, 1999, was $457,000.
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
is expected to generally offset the corresponding increases or
decreases in the value of the underlying commodity transaction
or interest on the related debt instrument.
7. Common stock
On May 14, 1998, the company's Board of Directors approved
a three-for-two common stock split 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. Common stock
information appearing in the accompanying Consolidated Statements
of Income has been restated to give retroactive effect to
the stock split.
At the Annual Meeting of Stockholders held on April 27,
1999, the company's common stockholders approved an amendment
to the Certificate of Incorporation increasing the authorized
number of common shares from 75 million shares to 150 million
shares and reducing the par value of the common stock from
$3.33 per share to $1.00 per share.
8. Business segment data
The company's operations are conducted through five
business segments. The company's reportable segments are those
that are based on the company's method of internal reporting,
which generally segregates the strategic business units due to
differences in products, services and regulation. The
electric, natural gas distribution, natural gas transmission,
construction materials and mining, and oil and natural gas
production businesses are substantially all located within the
United States. The electric business operates electric power
generation, transmission and distribution facilities in North
Dakota, South Dakota, Montana and Wyoming and installs and
repairs electric transmission and distribution power lines and
provides related supplies, equipment and engineering services
throughout the western United States and Hawaii. The natural
gas distribution business provides natural gas distribution
services in North Dakota, South Dakota, Montana and Wyoming.
The natural gas transmission business serves the Midwestern,
Southern and Central regions of the United States providing
natural gas transmission and related services including storage
and production along with energy marketing and management,
wholesale/retail propane and energy facility construction. The
construction materials and mining business produces and markets
aggregates and construction materials in Alaska, California,
Hawaii and Oregon, and operates lignite coal mines in Montana
and North Dakota. The oil and natural gas production business
is engaged in oil and natural gas acquisition, exploration and
production activities throughout the United States, the Gulf of
Mexico and Canada.
Segment information follows the same accounting policies as
described in Note 1 of the company's 1998 Annual Report.
Segment information included in the accompanying Consolidated
Statements of Income is as follows:
Operating
Operating Revenues Earnings
Revenues Inter- on Common
External segment Stock
Three Months (In thousands)
Ended March 31, 1999
Electric $ 58,974 $ --- $ 5,163
Natural gas distribution 61,126 --- 2,878
Natural gas transmission 67,805 20,583 5,531
Construction materials
and mining 57,762* 2,276 (1,373)
Oil and natural gas
production 11,103 --- 329
Intersegment eliminations --- (20,583) ---
Total $ 256,770 $ 2,276 $12,528
Three Months
Ended March 31, 1998
Electric $ 44,740 $ --- $ 3,592
Natural gas distribution 62,635 --- 3,627
Natural gas transmission 10,908 18,805 8,142
Construction materials
and mining 37,280* 1,681 252
Oil and natural gas
production 12,878 --- 1,986
Intersegment eliminations --- (18,805) ---
Total $ 168,441 $ 1,681 $17,599
* Includes sales, for use at the Coyote Station, an electric
generating station jointly owned by the company and other
utilities, of (in thousands) $1,786 and $1,774 for the three
months ended March 31, 1999 and 1998, respectively.
9. Regulatory matters and revenues subject to refund
Williston Basin had pending with the Federal Energy
Regulatory Commission (FERC) a general natural gas rate change
application implemented in 1992. In October 1997, Williston
Basin appealed to the United States 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. On
January 22, 1999, the D.C. Circuit Court issued its opinion
remanding the issues of return on equity, ad valorem taxes and
throughput to the FERC for further explanation and
justification. The mandate was issued by the D.C. Circuit
Court to the FERC on March 11, 1999. Based on the D.C. Circuit
Court's opinion, Williston Basin anticipates that the FERC will
modify its prior order thereby allowing Williston Basin to seek
reimbursement from its customers of a portion of the refunds
made in 1997 relating to certain of these remanded issues.
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. In July 1998, the FERC issued an order which addressed
various issues including storage cost allocations, return on
equity and throughput. In August 1998, Williston Basin
requested rehearing of 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.
10. Natural gas repurchase commitment
As described in Note 15 of its 1998 Annual Report, the
company has offered for sale since 1984 the inventoried natural
gas available under a repurchase commitment with Frontier Gas
Storage Company. 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. In August 1998, Williston Basin requested
rehearing on the July 1998 FERC order which addressed various
issues, including a requirement that storage deliverability
costs be allocated to the Frontier gas.
11. 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.
On April 20, 1999, the U.S. Court of Appeals issued its
order which affirmed in part and reversed in part the Federal
District Court's June 1997 decision. Additionally, the U.S.
Court of Appeals remanded the case to the Federal District
Court for further determination of the prices and volumes to be
used for determination of damages. The U.S. Court of Appeals
also remanded to the lower court for further consideration the
issue of whether pre-judgment interest on damages is
applicable. As a result of the decision by the U.S. Court of
Appeals, and in the absence of rehearing, the prior judgment of
$15.6 million by the Federal District Court will be vacated.
Based on the decision by the U.S. Court of Appeals, Williston
Basin estimates its liability for damages on the remanded
issues will be less than $5 million.
Williston Basin believes that it is entitled to recover
from customers 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 FERC's 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. In November 1998, the North Dakota
District Court entered an order directing the entry of judgment
in favor of Williston Basin and the company. In December 1998,
Apache and Snyder filed a motion for relief asking the North
Dakota District Court to reconsider its November 1998 order.
On February 4, 1999, the North Dakota District Court denied the
motion for relief filed by Apache and Snyder. On March 31,
1999, judgment was entered, thereby dismissing Apache and
Snyder's claims against the company.
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 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 customers. However, the amount of costs that
can ultimately be recovered is subject to approval by the FERC
and market conditions.
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 with 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-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. 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. In October
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. The company is currently
awaiting a final decision from the arbitration panel. Although
unable to predict the ultimate outcome of the arbitration,
Knife River and the company believe that the Co-owners' claims
for past damages (if any) are substantially overstated and
intend to vigorously defend the prices going forward.
12. 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.
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 (dollars in millions, where applicable)
summarizes the contribution to consolidated earnings by each of
the company's businesses.
Three Months
Ended
March 31,
1999 1998
Electric $ 5.2 $ 3.6
Natural gas distribution 2.9 3.6
Natural gas transmission 5.5 8.1
Construction materials and mining (1.4) .3
Oil and natural gas production .3 2.0
Earnings on common stock $ 12.5 $ 17.6
Earnings per common share - basic $ .24 $ .39*
Earnings per common share - diluted $ .23 $ .39*
Return on average common equity
for the 12 months ended 5.1%** 14.8%
________________________________
* Reflects the company's three-for-two common stock split
effected in July 1998.
**Reflects $39.9 million in noncash after-tax write-downs of oil and
natural gas properties in 1998.
Three Months Ended March 31, 1999 and 1998
Consolidated earnings for the quarter ended March 31, 1999,
decreased $5.1 million from the comparable period a year ago due to
lower earnings at the natural gas transmission, construction
materials and mining, oil and natural gas production and natural gas
distribution businesses. Increased earnings at the electric
business 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 (dollars in millions, where applicable) are
key financial and operating statistics for each of the company's
business units.
Electric Operations
Three Months
Ended
March 31,
1999 1998
Operating revenues:
Retail sales $ 34.0 $ 33.0
Sales for resale and other 6.2 3.3
Utility services 18.8 8.4
59.0 44.7
Operating expenses:
Fuel and purchased power 13.5 11.8
Operation and maintenance 26.6 17.6
Depreciation, depletion and amortization 5.1 4.7
Taxes, other than income 2.6 2.1
47.8 36.2
Operating income 11.2 8.5
Retail sales (million kWh) 536.1 523.2
Sales for resale (million kWh) 268.6 129.4
Average cost of fuel and purchased
power per kWh $ .016 $ .017
Natural Gas Distribution Operations
Three Months
Ended
March 31,
1999 1998
Operating revenues:
Sales $ 60.1 $ 61.5
Transportation and other 1.0 1.1
61.1 62.6
Operating expenses:
Purchased natural gas sold 44.9 45.4
Operation and maintenance 7.8 7.5
Depreciation, depletion and amortization 1.8 1.8
Taxes, other than income 1.1 1.1
55.6 55.8
Operating income 5.5 6.8
Volumes (MMdk):
Sales 13.2 14.0
Transportation 3.1 3.2
Total throughput 16.3 17.2
Degree days (% of normal) 87% 94%
Average cost of natural gas, including
transportation, per dk $ 3.40 $ 3.24
Natural Gas Transmission Operations
Three Months
Ended
March 31,
1999 1998
Operating revenues:
Transportation and storage $ 15.4 $ 19.0
Energy marketing and natural
gas production 73.0 10.7
88.4 29.7
Operating expenses:
Purchased natural gas sold 66.4 5.6
Operation and maintenance 8.6 7.7
Depreciation, depletion and amortization 2.7 2.0
Taxes, other than income 1.6 1.5
79.3 16.8
Operating income 9.1 12.9
Transportation volumes (MMdk):
Montana-Dakota 8.3 8.4
Other 8.8 14.4
17.1 22.8
Produced (Mdk) 2,668 1,751
Construction Materials and Mining Operations
Three Months
Ended
March 31,
1999 1998
Operating revenues:
Construction materials $ 50.1 $ 29.7
Coal 10.0 9.3
60.1 39.0
Operating expenses:
Operation and maintenance 54.7 33.1
Depreciation, depletion and amortization 5.7 3.9
Taxes, other than income .9 .9
61.3 37.9
Operating income (loss) (1.2) 1.1
Sales (000's):
Aggregates (tons) 1,538 863
Asphalt (tons) 104 30
Ready-mixed concrete (cubic yards) 217 139
Coal (tons) 879 788
Oil and Natural Gas Production Operations
Three Months
Ended
March 31,
1999 1998
Operating revenues:
Oil $ 5.0 $ 6.8
Natural gas 6.1 6.1
11.1 12.9
Operating expenses:
Operation and maintenance 4.3 3.8
Depreciation, depletion and amortization 4.9 5.4
Taxes, other than income 1.0 .8
10.2 10.0
Operating income .9 2.9
Production:
Oil (000's of barrels) 481 483
Natural gas (MMcf) 3,476 2,808
Average sales price:
Oil (per barrel) $ 10.35 $ 14.05
Natural gas (per Mcf) 1.76 2.17
Amounts presented in the preceding tables for natural gas
operating revenues and purchased natural gas sold for the three
months ended March 31, 1999 and 1998, 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 March 31, 1999 and 1998
Electric Operations
Electric earnings increased due to increased electric utility
earnings and earnings at the utility services companies acquired
since the comparable period last year. Sales for resale revenue
improved due to 108 percent higher volumes resulting from increased
generating station availability, favorable contracts and reduced
line load constraints and higher average rates due to favorable
contracts. Higher retail sales to residential, commercial and
industrial customers also contributed to the earnings improvement.
Increased operation and maintenance expense resulting primarily from
higher materials and subcontractor costs at the Heskett and Big
Stone stations partially offset the electric utility earnings
improvement. Utility services contributed $897,000 to earnings
during the first quarter of 1999 compared to $352,000 a year ago.
Natural Gas Distribution Operations
Earnings decreased at the natural gas distribution business
due to reduced weather-related sales, the result of 8 percent
warmer weather. A rate reduction implemented in North Dakota
and increased operation and maintenance expense also contributed
to the earnings decline. Increased return on gas in storage and
prepaid demand balances partially offset the decrease in
earnings.
Natural Gas Transmission Operations
Earnings at the natural gas transmission business decreased due
to lower transportation revenues resulting from a $5.0 million ($3.1
million after tax) reversal of reserves in 1998 relating to a FERC
order concerning a compliance filing and decreased transportation to
off-system markets at lower average transportation rates. Reduced
sales of natural gas held under the repurchase commitment and lower
average prices received on company-owned production also added to
the decline in earnings. Earnings from new acquisitions, the
recognition of $1.7 million resulting from a favorable 1999 order
received from the D.C. Circuit Court relating to the 1992 general
rate proceeding, increased storage revenues and higher production
from company-owned reserves partially offset the earnings decline.
The increase in energy marketing revenue and the related increase in
purchased natural gas sold resulted from the acquisition of a
natural gas marketing business in July 1998.
Construction Materials and Mining Operations
Construction materials and mining earnings decreased largely due
to normal seasonal losses realized in 1999 by construction materials
businesses not owned during the full quarter last year and wet
weather experienced at the larger construction materials markets.
Increased ready-mixed concrete volumes, a transportation volume-
related credit and lower cement costs were largely offset by higher
selling, general and administrative costs and increased aggregate
costs due to higher off-season maintenance at the existing
construction materials operations. Higher interest expense
resulting mainly from increased acquisition-related long-term debt
also added to the decline in earnings. Earnings at the coal
operations increased slightly due to higher demand-related sales.
Oil and Natural Gas Production Operations
Earnings for the oil and natural gas production business
decreased largely as a result of decreased operating revenues
resulting from realized oil and natural gas prices which were 26
percent and 19 percent lower than last year, respectively.
Increased natural gas production due to new acquisitions
somewhat offset the operating revenue decline. Operation and
maintenance expenses increased due largely to the previously
mentioned acquisitions. Decreased depreciation, depletion and
amortization due to lower rates resulting from the 1998 write-
downs of oil and natural gas properties partially offset the
decrease 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).
Nonregulated Operations --
Certain important factors which could cause actual results
or outcomes for the company and all or certain of its
nonregulated 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 Nonregulated 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 third parties, including
suppliers and vendors, to identify and address year 2000 issues
in a timely manner.
Prospective Information
Montana-Dakota has obtained and holds valid and existing
franchises authorizing it to conduct its electric operations in
all of the municipalities it serves where such franchises are
required. As franchises expire, Montana-Dakota may face
increasing competition in its service areas, particularly its
service to smaller towns, from rural electric cooperatives.
Montana-Dakota intends to protect its service area and seek
renewal of all expiring franchises and will continue to take
steps to effectively operate in an increasingly competitive
environment.
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. In 1997, the company established a
task force with coordinators in each of its major operating
units to address the year 2000 issue. 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 implementation.
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 such systems. As of March 31, 1999, the
awareness and inventory phases, including assigning priorities
to IT 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, vendors and major customers, that such entities are
year 2000 compliant. The company has identified key suppliers,
vendors and customers and as of March 31, 1999, based on
contacts with and representations obtained from approximately 63
percent of these third parties, the company is not aware of any
material third party year 2000 problems. The company will
continue to contact those material third parties that have not
responded seeking written verification of year 2000 readiness.
Thus, the company is presently 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 March 31, 1999, 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. The testing phase
involves testing systems to confirm year 2000 readiness. The
implementation phase is the process of moving a remediated item
into production status. The table below represents the
approximate percentage of completion by business segment for the
remediation, testing and implementation phases as of March 31,
1999.
Remediation Testing Implementation
Electric and Natural
Gas Distribution 87% 62% 89%
Natural Gas Transmission 93% 61% 95%
Construction Materials
and Mining 40% 20% 35%
Oil and Natural Gas
Production 95% 90% 90%
The company has established a target date of October 1,
1999, to complete the remediation, testing and implementation
phases.
Costs --
The estimated total 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 March 31, 1999, the
company has incurred incremental costs of less than $750,000.
These costs are being funded through cash flows from operations.
The company has not established a formal process to track
internal year 2000 costs but such costs would be principally
related to payroll and benefits. 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 is developing contingency plans for
its mission-critical operations. As of March 31, 1999, the
utility division, which includes electric generation and
transmission and electric and natural gas distribution, has
prepared preliminary contingency plans in accordance with
guidelines and schedules set forth by the North American
Electric Reliability Council (NERC) working in conjunction with
the Mid-Continent Area Power Pool, the utility's regional
reliability council. Such plans are in addition to existing
business recovery and emergency plans established to restore
electric and natural gas service following an interruption
caused by weather or equipment failure. In addition, the
company has and will continue to participate with the NERC in
national drills to assess industry preparation. The natural gas
transmission business has adopted the guidelines used at the
utility and has materially completed plans for its
administrative and accounting systems. The contingency plans
for its other business operations are in the development stage.
The oil and natural gas production and the construction
materials and mining businesses are in various stages of their
contingency planning efforts. Some of the additional
contingency plans under consideration include but are not
limited to: stockpiling inventories, increasing staffing at
critical times, identifying alternative suppliers for critical
products and services, using the company's radio system in the
event there is a partial loss of voice and data communications
and developing manual workarounds and backup procedures.
Contingency plans will continue to be developed and finalized
and the company anticipates having all such contingency plans in
place by October 1, 1999.
Liquidity and Capital Commitments
The 1999 electric and natural gas distribution capital
expenditures are estimated at $30.8 million, including those for
system upgrades, routine replacements, service extensions and
routine equipment maintenance and replacements. It is
anticipated that all of the funds required for these capital
expenditures will be met from internally generated funds, the
company's $40 million revolving credit and term loan agreement,
existing short-term lines of credit aggregating $50 million, a
commercial paper credit facility at Centennial, as described
below, and through the issuance of long-term debt, the amount
and timing of which will depend upon needs, internal cash
generation and market conditions. At March 31, 1999, $22
million under the revolving credit and term loan agreement and
none of the commercial paper supported by the short-term lines
of credit were outstanding.
Capital expenditures in 1999 for the natural gas
transmission business, including those for pipeline expansion
projects, routine system improvements and continued development
of natural gas reserves are estimated at $37.4 million. Capital
expenditures are expected to be met with a combination of
internally generated funds, a commercial paper credit facility
at Centennial, as described below, and through the issuance of
long-term debt, the amount and timing of which will depend upon
needs, internal cash generation and market conditions.
The 1999 capital expenditures for the construction
materials and mining business, including those for routine
equipment rebuilding and replacement and the building of
construction materials handling and transportation facilities,
are estimated at $48.3 million. It is anticipated that funds
generated from internal sources, a commercial paper credit
facility at Centennial, as described below, a $10 million line
of credit, $5.2 million of which was outstanding at March 31,
1999, and the issuance of long-term debt will meet the needs of
this business segment.
Capital expenditures for the oil and natural gas production
business related to its oil and natural gas acquisition,
development and exploration program are estimated at $63.6
million for 1999. It is anticipated that capital expenditures
will be met from internal sources, a $30 million note shelf
facility, $13 million of which was outstanding at March 31,
1999, a commercial paper credit facility at Centennial, as
described below, and the issuance of the company's equity
securities.
Centennial, a direct subsidiary of the company, has a
revolving credit agreement with various banks on behalf of its
subsidiaries that allows for borrowings of up to $200 million.
This facility supports the Centennial commercial paper program.
Under the commercial paper program, $109.7 million was
outstanding at March 31, 1999.
The estimated 1999 capital expenditures set forth above for
the electric, natural gas distribution, natural gas transmission
and construction materials and mining operations 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's issuance of first mortgage debt is subject to
certain restrictions imposed under the terms and conditions of
its Indenture of Mortgage. Generally, those restrictions require
the company to pledge $1.43 of unfunded property to the Trustee
for each dollar of indebtedness incurred under the Indenture and
that annual earnings (pretax and before interest charges), as
defined in the Indenture, equal at least two times its annualized
first mortgage bond interest costs. Under the more restrictive
of the two tests, as of March 31, 1999, the company could have
issued approximately $276 million of additional first mortgage
bonds.
The company's coverage of combined fixed charges and
preferred stock dividends was 2.2 and 2.5 times for the twelve
months ended March 31, 1999, and December 31, 1998, respectively.
Additionally, the company's first mortgage bond interest coverage
was 6.1 times for the twelve months ended March 31, 1999, and
December 31, 1998. Common stockholders' equity as a percent of
total capitalization was 56 percent at March 31, 1999, and
December 31, 1998.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET
RISK
There are no material changes in market risk faced by the
company from those reported in the company's Annual Report on
Form 10-K for the year ended December 31, 1998. For more
information on market risk, see Part II, Item 7A in the company's
Annual Report on Form 10-K for the year ended December 31, 1998,
and Notes to Consolidated Financial Statements in this Form 10-Q.
PART II -- OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
On April 20, 1999, the U.S. Court of Appeals issued its
order which affirmed in part and reversed in part the Federal
District Court's June 1997 decision relating to a suit filed by
the estate of W. A. Moncrief. Based on the decision by the
U.S. Court of Appeals, Williston Basin estimates its liability
for damages on the remanded issues will be less than $5 million.
For more information on this legal action, see Note 11 of Notes to
Consolidated Financial Statements.
On March 31, 1999, judgment was entered, dismissing Apache
and Snyder's claims against the company. For more information on
this legal action, see Note 11 of Notes to Consolidated Financial
Statements.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
The company's Annual Meeting of Stockholders was held on
April 27, 1999. Two proposals were submitted to stockholders as
described in the company's Proxy Statement dated March 15, 1999,
and were voted upon and approved by stockholders at the meeting.
The table below briefly describes the proposals and the results
of the stockholder votes.
Shares
Shares Against or Broker
For Withheld Abstentions Non-Votes
Proposal to amend Certificate
of Incorporation to increase
the number of authorized
shares of Common Stock and
reduce the par value 41,759,552 3,737,799 773,805 ---
Proposal to elect three directors:
For terms expiring in 2002 --
Thomas Everist 45,613,261 657,895 --- ---
Robert L. Nance 45,568,619 702,537 --- ---
John A. Schuchart 45,339,288 931,868 --- ---
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
a) Exhibits
3(a(1))Composite Certificate of Incorporation of the company,
as amended to date, filed as Exhibit 3(a) to Form 10-K
for the year ended December 31, 1994, in File No. 1-3480
3(a(2))Amendment to Article FOURTH of the Certificate
of Incorporation
10(a) Key Employee Stock Option Plan, as amended to date
10(b) Non-Employee Director Stock Compensation Plan, as
amended to date
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
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 May 13, 1999 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.
3(a(1)) Composite Certificate of Incorporation of the company, as
amended to date, filed as Exhibit 3(a) to Form 10-K for the
year ended December 31, 1994, in File No. 1-3480
3(a(2)) Amendment to Article FOURTH of the Certificate of Incorporation
10(a) Key Employee Stock Option Plan, as amended to date
10(b) Non-Employee Director Stock Compensation Plan, as amended to
date
12 Computation of Ratio of Earnings to Fixed Charges
and Combined Fixed Charges and Preferred Stock
Dividends
27 Financial Data Schedule