UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
X QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the Quarterly Period Ended September 30, 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 Identification No.)
incorporation or organization)
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 November 5, 1999:
57,012,053 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, South
Dakota, Montana and Wyoming.
The company, through its wholly owned subsidiary, Centennial
Energy Holdings, Inc. (Centennial), owns WBI Holdings, Inc. (WBI
Holdings), Knife River Corporation (Knife River), and Utility
Services, Inc. (Utility Services).
WBI Holdings, through its wholly owned subsidiaries,
serves the Midwestern, Southern, Central and Rocky
Mountain regions of the United States providing natural
gas transmission and related services including storage
along with energy marketing and management, wholesale/
retail propane and energy facility construction, and
owns oil and natural gas interests throughout the
United States and the Gulf of Mexico. Effective
September 1, 1999, Fidelity Oil Co. and Fidelity Oil
Holdings, Inc., previously wholly owned subsidiaries
of Centennial, became indirect wholly owned subsidiaries
of WBI Holdings.
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, Montana, Oregon and
Wyoming, and operates lignite coal mines in Montana and
North Dakota.
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 and Nine Months Ended September 30, 1999 and 1998
Consolidated Balance Sheets --
September 30, 1999 and 1998, and December 31, 1998
Consolidated Statements of Cash Flows --
Nine Months Ended September 30, 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 Nine Months
Ended Ended
September 30, September 30,
1999 1998 1999 1998
(In thousands, except per share amounts)
Operating revenues:
Electric $ 65,849 $ 58,791 $185,237 $151,712
Natural gas 120,945 64,110 357,979 175,756
Construction materials and mining 174,132 134,047 342,040 253,903
Oil and natural gas production 14,665 13,030 39,648 38,444
375,591 269,978 924,904 619,815
Operating expenses:
Fuel and purchased power 13,270 12,841 39,225 37,082
Purchased natural gas sold 85,091 38,461 247,546 81,970
Operation and maintenance 195,314 149,649 441,084 323,215
Depreciation, depletion and amortization 20,838 20,006 60,960 57,161
Taxes, other than income 7,022 6,326 20,924 18,978
Write-down of oil and natural gas
properties (Note 3) --- --- --- 33,100
321,535 227,283 809,739 551,506
Operating income:
Electric 13,399 11,565 35,467 27,515
Natural gas distribution (2,212) (2,987) 2,729 2,986
Natural gas transmission 15,571 8,357 39,645 29,081
Construction materials and mining 23,466 22,774 28,420 33,300
Oil and natural gas production 3,832 2,986 8,904 (24,573)
54,056 42,695 115,165 68,309
Other income -- net 2,200 1,202 7,033 6,359
Interest expense 9,178 8,050 26,436 22,400
Income before income taxes 47,078 35,847 95,762 52,268
Income taxes 17,980 13,309 36,147 17,723
Net income 29,098 22,538 59,615 34,545
Dividends on preferred stocks 193 194 579 582
Earnings on common stock $ 28,905 $ 22,344 $ 59,036 $ 33,963
Earnings per common share -- basic $ .53 $ .42 $ 1.10 $ .68
Earnings per common share -- diluted $ .52 $ .42 $ 1.09 $ .68
Dividends per common share $ .21 $ .20 $ .61 $ .5833
Weighted average common shares
outstanding -- basic 54,995 52,703 53,845 49,698
Weighted average common shares
outstanding -- diluted 55,278 53,062 54,102 49,966
The accompanying notes are an integral part of these consolidated statements.
MDU RESOURCES GROUP, INC.
CONSOLIDATED BALANCE SHEETS
(Unaudited)
September 30, September 30, December 31,
1999 1998 1998
(In thousands)
ASSETS
Current assets:
Cash and cash equivalents $ 38,837 $ 51,006 $ 39,216
Receivables 184,181 119,997 124,114
Inventories 64,736 50,997 44,865
Deferred income taxes 14,958 14,305 16,918
Prepayments and other current assets 30,084 19,601 15,536
332,796 255,906 240,649
Investments 43,651 24,722 43,029
Property, plant and equipment:
Electric 597,164 578,211 583,047
Natural gas distribution 182,693 176,850 178,522
Natural gas transmission 341,788 300,140 304,054
Construction materials and mining 592,713 468,490 484,419
Oil and natural gas production 273,363 273,983 260,758
1,987,721 1,797,674 1,810,800
Less accumulated depreciation,
depletion and amortization 776,050 709,272 726,123
1,211,671 1,088,402 1,084,677
Deferred charges and other assets 98,825 85,618 84,420
$1,686,943 $1,454,648 $1,452,775
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Short-term borrowings $ 3,479 $ 8,272 $ 15,000
Long-term debt and preferred
stock due within one year 5,106 5,456 3,292
Accounts payable 93,968 57,119 60,023
Taxes payable 20,645 9,157 9,226
Dividends payable 12,093 10,774 10,799
Other accrued liabilities,
including reserved revenues 82,454 77,151 71,129
217,745 167,929 169,469
Long-term debt 487,953 400,244 413,264
Deferred credits and other liabilities:
Deferred income taxes 196,876 182,586 173,094
Other liabilities 117,418 128,570 129,506
314,294 311,156 302,600
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 --
$1.00 par value, 56,904,804
at September 30, 1999, $3.33 par value,
53,136,765 at September 30, 1998 and
53,272,951 at December 31, 1998) 56,905 176,945 177,399
Other paid-in capital 365,796 168,479 171,486
Retained earnings 231,276 216,821 205,583
Treasury stock at cost - 239,521
shares (3,626) (3,626) (3,626)
Total common stockholders' equity 650,351 558,619 550,842
Total stockholders' equity 665,351 573,619 565,842
$1,686,943 $1,454,648 $1,452,775
The accompanying notes are an integral part of these consolidated statements.
MDU RESOURCES GROUP, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Nine Months Ended
September 30,
1999 1998
(In thousands)
Operating activities:
Net income $ 59,615 $ 34,545
Adjustments to reconcile net income to net cash provided
by operating activities:
Depreciation, depletion and amortization 60,960 57,161
Deferred income taxes and investment tax credit 6,754 (6,633)
Write-down of oil and natural gas properties (Note 3) --- 33,100
Changes in current assets and liabilities:
Receivables (28,789) (7,350)
Inventories (13,810) (4,861)
Other current assets (14,067) (3,907)
Accounts payable 24,761 11,531
Other current liabilities 19,705 (15,219)
Other noncurrent changes (11,376) (6,636)
Net cash provided by operating activities 103,753 91,731
Financing activities:
Net change in short-term borrowings (17,244) (2,795)
Issuance of long-term debt 79,633 111,370
Repayment of long-term debt (17,867) (25,934)
Issuance of common stock 3,184 29,795
Retirement of natural gas repurchase commitment (14,296) (15,174)
Dividends paid (33,922) (30,447)
Net cash provided by (used in) financing activities (512) 66,815
Investing activities:
Capital expenditures including acquisitions of businesses:
Electric (14,943) (5,267)
Natural gas distribution (6,888) (6,112)
Natural gas transmission (39,514) (12,874)
Construction materials and mining (34,910) (42,339)
Oil and natural gas production (20,620) (74,661)
(116,875) (141,253)
Net proceeds from sale or disposition of property 12,447 3,083
Net capital expenditures (104,428) (138,170)
Sale of natural gas available under repurchase commitment 1,330 7,094
Investments (522) (4,638)
Net cash used in investing activities (103,620) (135,714)
Increase (decrease) in cash and cash equivalents (379) 22,832
Cash and cash equivalents -- beginning of year 39,216 28,174
Cash and cash equivalents -- end of period $ 38,837 $ 51,006
The accompanying notes are an integral part of these consolidated statements.
MDU RESOURCES GROUP, INC.
NOTES TO CONSOLIDATED
FINANCIAL STATEMENTS
September 30, 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 and nine months ended September 30, 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. 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 noncash write-down is
required to be charged to earnings in that quarter.
Due to low oil prices, the company's capitalized costs
under the full-cost method of accounting exceeded the full-
cost ceiling at June 30, 1998. Accordingly, the company was
required to write down its oil and natural gas producing
properties. This noncash write-down amounted to $33.1
million ($20.0 million after tax) for the nine months ended
September 30, 1998.
4. Cash flow information
Cash expenditures for interest and income taxes were as
follows:
Nine Months Ended
September 30,
1999 1998
(In thousands)
Interest, net of amount capitalized $18,059 $16,000
Income taxes $21,724 $24,178
5. 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.
6. New accounting pronouncement
In June 1998, the Financial Accounting Standards Board
(FASB) 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.
In June 1999, the effective date of SFAS No. 133 was
delayed by the FASB to fiscal years beginning after June 15,
2000. The company will adopt SFAS No. 133 on January 1,
2001, and has not yet quantified the impacts of adopting
SFAS No. 133 on its financial position or results of
operations.
7. Derivatives
Williston Basin Interstate Pipeline Company (Williston
Basin) and Fidelity Oil Co., both indirect wholly owned
subsidiaries of WBI Holdings, 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 Co. 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
wholly owned 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.
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 hedge
agreements outstanding at September 30, 1999 (notional
amounts in thousands):
Weighted
Average Notional
Year of Fixed Price Amount
Expiration (Per Barrel) (In Barrels)
Oil swap agreements* 2000 $18.90 586
Weighted
Average Notional
Year of Fixed Price Amount
Expiration (Per MMBtu) (In MMBtu's)
Natural gas swap
agreement* 2000 $2.55 1,537
Weighted
Average
Floor/Ceiling Notional
Year of Price Amount
Expiration (Per Barrel) (In Barrels)
Oil collar agreements* 1999 $14.69/$18.69 184
Weighted
Average
Floor/Ceiling Notional
Year of Price Amount
Expiration (Per MMBtu) (In MMBtu's)
Natural gas collar
agreements* 1999 $2.15/$2.58 1,104
2000 $2.30/$2.65 2,562
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 unfavorable
position on all hedge agreements outstanding at
September 30, 1999, was $1.4 million.
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.
8. Common stock
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.
9. 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 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, Central and Rocky
Mountain 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 mines and
markets aggregates and construction materials in Alaska,
California, Hawaii, Montana, Oregon and Wyoming, 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 and the Gulf of
Mexico.
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 September 30, 1999
Electric $ 65,849 $ --- $ 6,647
Natural gas distribution 19,926 --- (1,730)
Natural gas transmission 101,019 4,615 8,248
Construction materials
and mining 170,749 3,383* 13,615
Oil and natural gas
production 14,665 --- 2,125
Intersegment eliminations --- (4,615) ---
Total $ 372,208 $ 3,383* $ 28,905
Three Months
Ended September 30, 1998
Electric $ 58,791 $ --- $ 5,464
Natural gas distribution 14,513 --- (2,354)
Natural gas transmission 49,597 4,235 4,162
Construction materials
and mining 130,555 3,492* 13,283
Oil and natural gas
production 13,030 --- 1,789
Intersegment eliminations --- (4,235) ---
Total $ 266,486 $ 3,492* $ 22,344
* In accordance with the provisions of Statement of Financial
Accounting Standards No. 71, "Accounting for the Effects of
Regulation" (SFAS No. 71), intercompany coal sales are not
eliminated.
Operating
Operating Revenues Earnings
Revenues Inter- on Common
External segment Stock
Nine Months (In thousands)
Ended September 30, 1999
Electric $ 185,237 $ --- $ 16,874
Natural gas distribution 106,931 --- 598
Natural gas transmission 251,048 31,735 21,807
Construction materials
and mining 331,516 10,524* 14,506
Oil and natural gas
production 39,648 --- 5,251
Intersegment eliminations --- (31,735) ---
Total $ 914,380 $ 10,524* $ 59,036
Nine Months
Ended September 30, 1998
Electric $ 151,712 $ --- $ 12,049
Natural gas distribution 101,347 --- 362
Natural gas transmission 74,409 31,271 16,623
Construction materials
and mining 243,319 10,584* 19,178
Oil and natural gas
production 38,444 --- (14,249)
Intersegment eliminations --- (31,271) ---
Total $ 609,231 $ 10,584* $ 33,963
* In accordance with the provisions of SFAS No. 71,
intercompany coal sales are not eliminated.
The company has acquired a number of businesses during the
first nine months of 1999, none of which were individually
material, including construction materials and mining
companies with operations in California, Montana, Oregon and
Wyoming and a utility services company based in Oregon. The
total purchase consideration for these businesses,
consisting of the company's common stock and cash, was $74.5
million.
10. 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. By order dated June 1, 1999, the FERC remanded the
return on equity issue to an Administrative Law Judge for
further proceedings. On October 13, 1999, the FERC approved
a settlement proposed by the parties to the proceeding which
resolves the remanded return on equity issue and concludes
the proceeding. Based on the FERC's approval of this
settlement, Williston Basin sought reimbursement from its
customers of a portion of the refunds made in 1997 relating
to the return on equity issue.
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. On June 1, 1999, the FERC issued an order approving
and denying various issues addressed in Williston Basin's
rehearing request, and also remanded the return on equity
issue to an Administrative Law Judge for further
proceedings. On July 1, 1999, Williston Basin requested
rehearing of certain issues which were contained in the
June 1, 1999 FERC order. On September 29, 1999, the FERC
granted Williston Basin's request for rehearing with respect
to the return on equity issue but also ordered Williston
Basin to issue refunds prior to the final determination in
this proceeding. As a result, on October 29, 1999,
Williston Basin issued refunds to its customers totaling
$11.3 million, all amounts which had previously been
reserved. In addition, on July 29, 1999, Williston Basin
appealed to the D.C. Circuit Court certain issues concerning
storage cost allocations as decided by the FERC in its
June 1, 1999 order. On October 12, 1999, the D.C. Circuit
Court issued an order which dismissed Williston Basin's
appeal but permitted Williston Basin to again appeal such
previously contested issues upon final determination of all
issues by the FERC in this proceeding.
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. Based on
the June 1, 1999 FERC orders referenced above, Williston
Basin in the second quarter of 1999 determined that reserves
it had previously established exceeded its expected refund
obligation and, accordingly, reversed reserves in the amount
of $4.4 million after-tax. Williston Basin believes that
its remaining reserves are adequate based on its assessment
of the ultimate outcome of the various proceedings.
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 of the issue of whether pre-judgment
interest on damages is recoverable by Moncrief. 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. Apache and
Snyder filed a notice of appeal with the North Dakota
Supreme Court on May 17, 1999. Oral argument before the
North Dakota Supreme Court was held on October 28, 1999.
Williston Basin and the company are awaiting a decision from
the North Dakota Supreme 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 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 requested that the
arbitrators 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 proceeded 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. Based on its assessment
of the proceedings, Knife River's earnings in the second
quarter of 1999 reflected a $3.7 million after-tax charge
regarding the coal pricing issues and related tax matters.
As a result of a decision rendered by the arbitrators in
August 1999, Knife River's 1999 third quarter earnings
include a $1.9 million after-tax charge reflecting the
resolution of this matter.
Royalty Interest Owners --
On June 3, 1999, several oil and gas royalty interest
owners filed suit in Colorado State District Court, in the
City and County of Denver, against WBI Production, Inc. (WBI
Production), an indirect wholly owned subsidiary of the
company, and several former producers of natural gas with
respect to certain gas production properties in the state of
Colorado. The complaint arose as a result of the purchase
by WBI Production effective January 1, 1999, of certain
natural gas producing leaseholds from the former producers.
Prior to February 1, 1999, the natural gas produced from the
leaseholds was sold at above market prices pursuant to a
natural gas contract. Pursuant to the contract, the royalty
interest owners were paid royalties based upon the above
market prices. The royalty interest owners have alleged
that WBI Production took assignment of the rights to the
natural gas contract from the former owner of the contract
and, with respect to natural gas produced from such leases
and sold at market prices thereafter, wrongly ceased paying
the higher royalties on such gas.
In their complaint, the royalty interest owners have
alleged, in part, breach of oil and gas lease obligations
and unjust enrichment on the part of WBI Production and the
other former producers with respect to the amount of
royalties being paid to the royalty interest owners. The
royalty interest owners have requested damages for
additional royalties and other costs, including pre-judgment
interest. No specific amount of damages has been stated.
Trial before the Colorado State District Court has been
scheduled for April 24, 2000.
WBI Production intends to vigorously contest the suit.
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
customers, 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, energy marketing and
natural gas production operations, excluding the operations of
Fidelity Oil Co. and Fidelity Oil Holdings, Inc. Construction
materials and mining includes the results of Knife River's
operations, while oil and natural gas production includes the
operations of Fidelity Oil Co. and Fidelity Oil Holdings, Inc.
Overview
The following table (dollars in millions, where applicable)
summarizes the contribution to consolidated earnings by each of
the company's businesses.
Three Months Nine Months
Ended Ended
September 30, September 30,
1999 1998 1999 1998
Electric $ 6.6 $ 5.4 $ 16.9 $12.0
Natural gas distribution (1.7) (2.4) .6 .4
Natural gas transmission 8.3 4.2 21.8 16.6
Construction materials and mining 13.6 13.3 14.5 19.2
Oil and natural gas production 2.1 1.8 5.2 (14.2)
Earnings on common stock $28.9 $ 22.3 $ 59.0 $34.0
Earnings per common share - basic $ .53 $ .42 $ 1.10 $ .68**
Earnings per common share - diluted $ .52 $ .42 $ 1.09 $ .68**
Return on average common equity
for the 12 months ended 10.2%* 10.8%**
* Reflects the effect of a $19.9 million noncash after-tax write-
down of oil and natural gas properties in December 1998.
** Reflects the effect of a $20 million noncash after-tax write-
down of oil and natural gas properties in June 1998.
Three Months Ended September 30, 1999 and 1998
Consolidated earnings for the quarter ended September 30, 1999,
were up $6.6 million from the comparable period a year ago due to
higher earnings at all businesses.
Nine Months Ended September 30, 1999 and 1998
Consolidated earnings for the nine months ended September 30,
1999, were up $25.0 million from the comparable period a year ago
due to higher earnings at the oil and natural gas production
business, largely resulting from a 1998 $20 million noncash after-
tax write-down of oil and natural gas properties. Higher earnings
at the electric, natural gas distribution and natural gas
transmission businesses also added to the increase in earnings.
Decreased earnings at the construction materials and mining
business partially offset the earnings improvement.
________________________________
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 Nine Months
Ended Ended
September 30, September 30,
1999 1998 1999 1998
Operating revenues:
Retail sales $ 33.9 $ 35.1 $ 98.4 $ 97.6
Sales for resale and other 6.3 3.8 18.9 11.7
Utility services 25.7 19.9 67.9 42.4
65.9 58.8 185.2 151.7
Operating expenses:
Fuel and purchased power 13.3 12.9 39.2 37.1
Operation and maintenance 31.4 26.7 87.4 65.5
Depreciation, depletion and
amortization 5.2 5.2 15.5 14.6
Taxes, other than income 2.6 2.4 7.6 7.0
52.5 47.2 149.7 124.2
Operating income $ 13.4 $ 11.6 $ 35.5 $ 27.5
Retail sales (million kWh) 537.1 550.8 1,554.7 1,533.5
Sales for resale (million kWh) 187.2 112.2 704.5 421.7
Average cost of fuel and
purchased power per kWh $ .017 $ .018 $ .016 $ .018
Natural Gas Distribution Operations
Three Months Nine Months
Ended Ended
September 30, September 30,
1999 1998 1999 1998
Operating revenues:
Sales $ 19.1 $ 13.8 $ 104.3 $ 98.9
Transportation and other .8 .7 2.6 2.5
19.9 14.5 106.9 101.4
Operating expenses:
Purchased natural gas sold 12.1 7.7 73.4 68.5
Operation and maintenance 7.2 7.0 22.1 21.5
Depreciation, depletion and
amortization 1.8 1.8 5.5 5.3
Taxes, other than income 1.0 1.0 3.2 3.1
22.1 17.5 104.2 98.4
Operating income (loss) $ (2.2) $ (3.0) $ 2.7 $ 3.0
Volumes (MMdk):
Sales 3.1 2.4 21.3 20.9
Transportation 2.6 2.1 7.9 7.0
Total throughput 5.7 4.5 29.2 27.9
Degree days (% of normal) 168.5% 61.7% 95.1% 93.6%
Average cost of gas, including
transportation thereon,
per dk $ 3.87 $ 3.18 $ 3.44 $ 3.27
Natural Gas Transmission Operations
Three Months Nine Months
Ended Ended
September 30, September 30,
1999 1998 1999 1998
Operating revenues:
Transportation and storage $ 19.6 $ 14.4 $ 55.4 $ 47.3
Energy marketing and
natural gas production 86.0 39.4 227.4 58.4
105.6 53.8 282.8 105.7
Operating expenses:
Purchased natural gas sold 77.6 35.0 205.8 44.8
Operation and maintenance 8.0 7.0 24.4 21.3
Depreciation, depletion and
amortization 2.7 2.1 7.9 6.2
Taxes, other than income 1.7 1.4 5.0 4.3
90.0 45.5 243.1 76.6
Operating income $ 15.6 $ 8.3 $ 39.7 $ 29.1
Transportation volumes (MMdk):
Montana-Dakota 7.6 8.0 22.9 24.0
Other 11.6 16.4 33.2 45.9
19.2 24.4 56.1 69.9
Natural gas production (Mdk) 2,765 1,676 8,035 5,145
Construction Materials and Mining Operations
Three Months Nine Months
Ended Ended
September 30, September 30,
1999 1998 1999 1998
Operating revenues:
Construction materials $ 165.8 $ 126.4 $ 315.8 $ 228.0
Coal 8.3 7.7 26.2 25.9
174.1 134.1 342.0 253.9
Operating expenses:
Operation and maintenance 143.0 104.8 292.8 203.5
Depreciation, depletion and
amortization 6.7 5.6 18.2 14.6
Taxes, other than income .9 .9 2.6 2.5
150.6 111.3 313.6 220.6
Operating income $ 23.5 $ 22.8 $ 28.4 $ 33.3
Sales (000's):
Aggregates (tons) 5,208 4,540 9,778 7,962
Asphalt (tons) 1,415 973 2,326 1,393
Ready-mixed concrete
(cubic yards) 354 342 861 740
Coal (tons) 789 678 2,430 2,239
Oil and Natural Gas Production Operations
Three Months Nine Months
Ended Ended
September 30, September 30,
1999 1998 1999 1998
Operating revenues:
Oil $ 7.3 $ 5.7 $ 19.0 $ 18.8
Natural gas 7.4 7.3 20.7 19.6
14.7 13.0 39.7 38.4
Operating expenses:
Operation and maintenance 5.7 4.1 14.4 11.4
Depreciation, depletion and
amortization 4.4 5.3 13.9 16.4
Taxes, other than income .8 .6 2.5 2.1
Write-down of oil and
natural gas properties --- --- --- 33.1
10.9 10.0 30.8 63.0
Operating income (loss) $ 3.8 $ 3.0 $ 8.9 $ (24.6)
Production:
Oil (000's of barrels) 414 455 1,332 1,428
Natural gas (MMcf) 2,899 3,649 9,687 9,399
Average sales price:
Oil (per barrel) $ 17.54 $ 12.65 $ 14.25 $ 13.21
Natural gas (per Mcf) $ 2.55 $ 1.99 $ 2.13 $ 2.08
Amounts presented in the preceding tables for natural gas
operating revenues and purchased natural gas sold for the three
and nine months ended September 30, 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 September 30, 1999 and 1998
Electric Operations
Electric earnings improved due to increased earnings at the
utility services companies and increased electric utility
earnings. Utility services contributed $1.9 million to earnings
during the third quarter of 1999 compared to $982,000 a year ago.
The increase is due to increased workload and higher margins from
existing operations and earnings from a business acquired since
the comparable period last year. At the electric utility, sales
for resale revenue improved due to higher volumes and increased
average realized rates, both largely resulting from favorable
contracts. Lower retail sales to residential and commercial
customers, due to colder weather than last year, partially offset
the electric utility earnings improvement.
Natural Gas Distribution Operations
Earnings increased at the natural gas distribution business
largely due to increased sales volumes and higher volumes
transported, primarily to industrial customers.
Natural Gas Transmission Operations
Earnings at the natural gas transmission business increased
primarily due to a $3.9 million after-tax reserve adjustment
relating to the resolution of certain production tax and other
state tax matters. Increased volumes produced from company-owned
natural gas reserves at higher natural gas prices combined with
earnings from new acquisitions also added to the improvement.
Decreased transportation to storage and off-system markets at
lower average transportation rates somewhat offset the earnings
increase. The increase in energy marketing revenue and the
related increase in purchased natural gas sold resulted primarily
from increased energy marketing volumes.
Construction Materials and Mining Operations
Construction materials and mining earnings increased primarily
due to the acquisitions which have occurred since the comparable
period a year ago and increased earnings at existing construction
materials operations. Increased asphalt volumes, construction
activity, and sales of other product lines, partially offset by
higher aggregate costs and higher selling, general and
administrative costs contributed to the increased earnings at the
existing construction materials businesses. Earnings at the coal
operations decreased largely due to a $1.9 million after-tax
charge relating to the coal contract arbitration proceedings and
related tax matters, as discussed under Coal Supply Agreement in
Note 11 of Notes to Consolidated Financial Statements. Higher
stripping costs and lower average sales prices also contributed to
the coal earnings decline.
Oil and Natural Gas Production Operations
Earnings for the oil and natural gas production business
increased as a result of increased realized oil and natural gas
prices which were 39 percent and 28 percent higher than last year,
respectively. Lower oil and natural gas production, resulting
mainly from property sales and the postponement of in-field
drilling due to 1998 depressed commodity prices, and increased
operation and maintenance expenses resulting from higher general
and administrative expenses largely offset the earnings
improvement.
Nine Months Ended September 30, 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 a 67 percent increase in volumes and increased
average realized rates, both largely resulting from favorable
contracts. Lower retail fuel and purchased power costs and higher
retail sales to commercial and industrial customers also
contributed to the earnings improvement. Increased generation at
lower cost versus higher cost generating stations and decreased
purchased power demand charges resulting from the 1998 pass-
through of periodic maintenance costs, related to a participation
power contract, contributed to the decline in retail fuel and
purchased power costs. Increased operation and maintenance
expense resulting largely from higher subcontractor costs,
primarily at the Lewis & Clark station due to boiler and turbine
maintenance, and increased payroll expense partially offset the
electric utility earnings improvement. Earnings attributable to
utility services were $4.6 million compared to $2.1 million a year
ago. The earnings improvement is due to earnings from
acquisitions since the comparable period last year and increased
workload and higher margins from existing operations.
Natural Gas Distribution Operations
Earnings increased at the natural gas distribution business
due to higher sales volumes. Higher returns on gas in storage and
prepaid demand balances, increased volumes transported, primarily
to industrial customers, and higher service and repair income also
contributed to the earnings improvement. A rate reduction
implemented in North Dakota in early 1999 and increased operation
and maintenance expense resulting from higher payroll expenses
partially offset the earnings improvement.
Natural Gas Transmission Operations
Earnings at the natural gas transmission business increased
largely due to a $4.4 million after-tax reserve revenue adjustment
in the second quarter associated with FERC orders received in the
1992 and 1995 rate proceedings and the previously discussed $3.9
million after-tax reserve adjustment which occurred in the third
quarter. The recognition of $1.7 million in the first quarter
resulting from a favorable order received from the D.C. Circuit
Court relating to the 1992 general rate proceeding also
contributed to the increase in earnings. In addition, increased
volumes produced from company-owned natural gas reserves at higher
natural gas prices combined with earnings from new acquisitions
also added to the earnings improvement. Decreased transportation
to storage and off-system markets at lower average transportation
rates and reduced sales of natural gas in inventory somewhat
offset the earnings increase. The $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 also
partially offset the 1999 earnings increase. 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 and increased energy marketing
volumes.
Construction Materials and Mining Operations
Construction materials and mining earnings decreased primarily
due to lower earnings at the coal operations largely resulting
from $5.6 million in after-tax charges relating to the coal
contract arbitration proceedings and related tax matters, as
discussed under Coal Supply Agreement in Note 11 of Notes to
Consolidated Financial Statements. Lower average sales prices and
higher stripping costs also added to the coal earnings decline.
Earnings at the construction materials businesses increased due to
businesses acquired since the comparable period last year and
increased earnings at existing construction materials operations.
Higher asphalt and aggregate volumes, increased construction
activity and sales of other product lines all contributed to the
increase in construction materials operations. Higher selling,
general and administrative costs, higher aggregate costs and
increased interest expense resulting from increased acquisition-
related long-term debt somewhat offset the increased earnings at
the construction materials business. Normal seasonal losses
realized in the first quarter of 1999 by construction materials
businesses not owned during the full first quarter last year also
partially offset the earnings improvement at the construction
materials business.
Oil and Natural Gas Production Operations
Earnings for the oil and natural gas production business
increased largely as a result of the 1998 $20 million noncash
after-tax write-down of oil and natural gas properties, as
discussed in Note 3 of Notes to Consolidated Financial Statements.
Higher oil and natural gas prices, increased natural gas
production and decreased depreciation, depletion and amortization
due largely to lower rates resulting from the June 1998 and
December 1998 write-downs of oil and natural gas properties also
added to the earnings improvement. Decreased oil production, as
previously discussed, increased income taxes, and higher operation
and maintenance expense partially offset the increase in earnings.
Higher operation and maintenance expense resulted from changes in
production mix and increased well maintenance and higher general
and administrative expenses.
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, the effects of competition, 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, the
ability to effectively integrate the operations of acquired
companies, 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.
The company has acquired a number of businesses during the
first nine months of 1999, none of which were individually
material, including construction materials and mining companies
with operations in California, Montana, Oregon and Wyoming and a
utility services company based in Oregon. The total purchase
consideration for these businesses, consisting of the company's
common stock and cash, was $74.5 million.
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 September 30, 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 September 30, 1999, based on
contacts with and representations obtained from approximately 72
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. As
to those who have not responded, 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 September 30, 1999, the
assessment phase has been substantially completed.
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. As of September 30, 1999, the
remediation, testing and implementation phases have been
substantially completed.
Costs --
The estimated total incremental cost to the company of the
year 2000 issue is approximately $1.2 million to $2 million during
the 1998 through 2000 time periods. As of September 30, 1999, the
company has incurred incremental costs of approximately $1.2
million. 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 are 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 has
substantially completed its year 2000 plan, unforeseen factors
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 September 30, 1999, the
utility division, which includes electric generation and
transmission and electric and natural gas distribution, has
prepared 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 participated with the NERC in
national drills to assess industry preparation. The natural gas
transmission business has adopted guidelines similar to the
utility division and has also completed plans for its
administrative and accounting systems. The contingency plans for
the other business operations are substantially completed.
Additional contingency plans include but are not limited to:
stockpiling inventories, scheduling staffing at critical times,
identifying alternative suppliers, 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.
Liquidity and Capital Commitments
The 1999 electric and natural gas distribution capital
expenditures are estimated at $42.8 million, including those for a
utility services company acquisition to date, 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 $75 million, a commercial paper credit facility
at Centennial, as described below, the issuance of long-term debt
and the issuance of the company's equity securities. At September
30, 1999, $37 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 acquisitions to date, pipeline
expansion projects, routine system improvements and continued
development of natural gas reserves are estimated at $49.8
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 the
issuance of long-term debt.
The 1999 capital expenditures for the construction materials
and mining business, including those for acquisitions to date,
routine equipment rebuilding and replacement and the building of
construction materials handling and transportation facilities, are
estimated at $112.4 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, none of which was outstanding at September 30, 1999, and
the issuance of long-term debt and the company's equity securities
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 $61.7 million
for 1999. It is anticipated that capital expenditures will be met
from internal sources, a commercial paper credit facility at
Centennial, as described below, and the issuance of long-term debt
and 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 $240 million.
This facility supports the Centennial commercial paper program.
Under the commercial paper program, $163 million was outstanding
at September 30, 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 September 30, 1999, 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 3.4 and 2.5 times for the twelve
months ended September 30, 1999, and December 31, 1998,
respectively. Additionally, the company's first mortgage bond
interest coverage was 6.9 and 6.1 times for the twelve months
ended September 30, 1999, and December 31, 1998, respectively.
Common stockholders' equity as a percent of total capitalization
was 56 percent at September 30, 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
Oral argument before the North Dakota Supreme Court was held
on October 28, 1999 in the Apache and Snyder legal proceeding.
Williston Basin and the company are awaiting a decision from the
North Dakota Supreme Court.
As a result of a decision rendered by the arbitrators in
August 1999, Knife River's third quarter earnings include a $1.9
million after-tax charge reflecting the resolution of the coal
supply agreement arbitration proceedings.
Trial before the Colorado State District Court has been
scheduled for April 24, 2000 in the oil and gas royalty interest
owners legal proceeding.
For more information on the above legal actions see Note 11
of Notes to Consolidated Financial Statements.
ITEM 2. CHANGES IN SECURITIES AND USE OF PROCEEDS
On August 16, 1999, the company issued to the shareholders of
Loy Clark Pipeline Co., 516,661 shares of Common Stock, $1.00 par
value, to acquire all of the issued and outstanding capital stock
of Loy Clark Pipeline Co. On September 1, 1999, the company
issued to the shareholders of JTL Group, Inc., a Montana
corporation, and JTL Group, Inc., a Wyoming corporation, an
aggregate of 2,094,515 shares of Common Stock, $1.00 par value, to
acquire all of the issued and outstanding capital stock of JTL
Group, Inc., a Montana corporation, and JTL Group, Inc., a Wyoming
corporation. 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 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
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 November 12, 1999 BY /s/ Warren L. Robinson
Warren L. Robinson
Executive Vice President,
Treasurer and Chief Financial
Officer
BY /s/ Vernon A. Raile
Vernon A. Raile
Vice President, Controller
and Chief Accounting Officer
EXHIBIT INDEX
Exhibit No.
12 Computation of Ratio of Earnings to Fixed Charges and
Combined Fixed Charges and Preferred Stock Dividends
27 Financial Data Schedule
MDU RESOURCES GROUP, INC.
COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES
AND COMBINED FIXED CHARGES AND PREFERRED STOCK DIVIDENDS
Twelve Months Year
Ended Ended
September 30, 1999 December 31, 1998
(In thousands of dollars)
Earnings Available for
Fixed Charges:
Net Income per Consolidated
Statements of Income $ 59,177 $ 34,107
Income Taxes 35,909 17,485
95,086 51,592
Rents (a) 1,947 1,749
Interest (b) 35,125 31,587
Total Earnings Available
for Fixed Charges $132,158 $ 84,928
Preferred Dividend Requirements $ 773 $ 777
Ratio of Income Before Income
Taxes to Net Income 161% 151%
Preferred Dividend Factor on
Pretax Basis 1,245 1,173
Fixed Charges (c) 37,072 33,336
Combined Fixed Charges and
Preferred Stock Dividends $ 38,317 $ 34,509
Ratio of Earnings to Fixed
Charges 3.6x 2.5x
Ratio of Earnings to
Combined Fixed Charges
and Preferred Stock Dividends 3.4x 2.5x
(a) Represents portion (33 1/3%) of rents which is estimated to
approximately constitute the return to the lessors on their
investment in leased premises.
(b) Represents interest and amortization of debt discount and
expense on all indebtedness and excludes amortization of gains
or losses on reacquired debt which, under the Uniform System of
Accounts, is classified as a reduction of, or increase in,
interest expense in the Consolidated Statements of Income.
Also includes carrying costs associated with natural gas
available under a repurchase agreement with Frontier Gas
Storage Company. In May 1999, the Company purchased the
remaining natural gas subject to the repurchase commitment
thereby extinguishing the repurchase commitment.
(c) Represents rents and interest, both as defined above.
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