UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
X QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
FOR THE QUARTERLY PERIOD ENDED JUNE 30, 1994
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.)
400 North Fourth Street, Bismarck, North Dakota 58501
(Address of principal executive offices)
(Zip Code)
(701) 222-7900
(Registrant's telephone number, including area code)
Indicate by check mark whether the registrant (1) has filed all
reports required to be filed by Section 13 or 15(d) of the Securities
Exchange Act of 1934 during the preceding 12 months (or for such shorter
period that the registrant was required to file such reports), and (2)
has been subject to such filing requirements for the past 90 days. Yes
X. No.
Indicate the number of shares outstanding of each of the issuer's
classes of common stock, as of August 5, 1994: 18,984,654 shares.
INTRODUCTION
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 400
North Fourth Street, Bismarck, North Dakota 58501, telephone (701)
222-7900.
Montana-Dakota Utilities Co. (Montana-Dakota), the public
utility division of the Company, provides electric and/or natural
gas and propane distribution service at retail to 251 communities
in North Dakota, eastern Montana, northern and western South Dakota
and northern Wyoming, and owns and operates electric power
generation and transmission facilities.
The Company, through its wholly-owned subsidiary, Centennial
Energy Holdings, Inc. (Centennial), owns Williston Basin Interstate
Pipeline Company (Williston Basin), Knife River Coal Mining Company
(Knife River), the Fidelity Oil Group (Fidelity Oil) and
Prairielands Energy Marketing, Inc. (Prairielands).
Williston Basin produces natural gas and provides
underground storage, transportation and gathering services
through an interstate pipeline system serving Montana,
North Dakota, South Dakota and Wyoming.
Knife River surface mines and markets low sulfur lignite
coal at mines located in Montana and North Dakota and,
through its wholly-owned subsidiary KRC Holdings, Inc.,
surface mines and markets aggregates and related
construction materials in the Anchorage, Alaska area,
southern Oregon and north-central California.
Fidelity Oil is comprised of Fidelity Oil Co. and Fidelity
Oil Holdings, Inc., which own oil and natural gas
interests in the western United States, the Gulf Coast and
Canada through investments with several oil and natural
gas producers.
Prairielands seeks new energy markets while continuing to
expand present markets for natural gas. Its activities
include buying and selling natural gas and arranging
transportation services to end users, pipelines and local
distribution companies and, through its wholly-owned
subsidiary, Gwinner Propane, Inc., operates bulk propane
facilities in southeastern North Dakota.
INDEX
Part I
Condensed Consolidated Statements of Income --
Three, Six and Twelve Months Ended
June 30, 1994 and 1993
Condensed Consolidated Balance Sheets --
June 30, 1994 and 1993, and December 31, 1993
Condensed Consolidated Statements of Cash Flows --
Six Months Ended June 30, 1994 and 1993
Notes to Condensed Consolidated Financial Statements
Management's Discussion and Analysis of Financial
Condition and Results of Operations
Signatures
MDU RESOURCES GROUP, INC.
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
Three Months Six Months Twelve Months
Ended Ended Ended
June 30, June 30, June 30,
1994 1993 1994 1993 1994 1993
(In thousands, except per share amounts)
Operating revenues:
Electric. . . . . . . .$ 30,656 $ 29,600 $ 66,454 $ 64,182 $133,381 $127,298
Natural gas . . . . . . 33,896 31,130 94,003 99,179 173,805 172,152
Mining and construction
materials . . . . . . 31,064 18,715 50,946 30,527 110,816 53,521
Oil and natural gas
production . . . . . 9,420 9,550 17,995 19,276 37,844 37,953
105,036 88,995 229,398 213,164 455,846 390,924
Operating expenses:
Fuel and purchased
power . . . . . . . . 10,406 9,079 21,828 19,612 43,514 39,059
Purchased natural
gas sold. . . . . . . 9,446 11,451 36,283 43,903 70,501 67,813
Operation and
maintenance . . . . . 52,211 38,838 95,867 71,566 191,675 134,157
Depreciation, depletion
and amortization. . . 11,852 11,298 23,572 22,260 46,474 42,503
Taxes, other than
income. . . . . . . . 5,965 5,712 12,177 11,668 24,074 22,619
89,880 76,378 189,727 169,009 376,238 306,151
Operating income (loss):
Electric. . . . . . . . 4,516 5,228 13,227 14,543 29,204 30,746
Natural gas distribution (1,397) (1,770) 4,276 4,320 4,686 4,764
Natural gas transmission. 4,872 2,886 11,632 13,500 18,240 25,344
Mining and construction
materials . . . . . . 5,039 3,352 6,690 6,129 17,545 11,774
Oil and natural gas
production . . . . . 2,126 2,921 3,846 5,663 9,933 12,145
15,156 12,617 39,671 44,155 79,608 84,773
Other income -- net. . . 1,275 (97) 2,203 (273) 6,353 (1,765)
Interest expense -- net. 6,539 6,063 13,077 12,226 26,124 24,188
Carrying costs on
natural gas repurchase
commitment. . . . . . . 1,239 1,043 2,148 1,884 4,161 4,630
Income before income
taxes . . . . . . . . 8,653 5,414 26,649 29,772 55,676 54,190
Income taxes . . . . . . 2,976 1,617 9,273 10,214 19,041 14,719
Income before cumulative
effect of accounting
change . . . . . . . . 5,677 3,797 17,376 19,558 36,635 39,471
Cumulative effect of
accounting change
(Note 2). . . . . . . . --- --- --- 5,521 --- 5,521
Net income . . . . . . . 5,677 3,797 17,376 25,079 36,635 44,992
Dividends on preferred
stocks . . . . . . . . 200 201 400 402 800 805
Earnings on common
stock . . . . . . . .$ 5,477 $ 3,596 $ 16,976 $ 24,677 $ 35,835 $ 44,187
Earnings per common share:
Earnings before cumulative
effect of accounting
change. . . . . . . .$ .29 $ .19 $ .89 $ 1.01 $ 1.89 $ 2.04
Cumulative effect of
accounting change . . --- --- --- .29 --- .29
Earnings. . . . . . . .$ .29 $ .19 $ .89 $ 1.30 $ 1.89 $ 2.33
Dividends per common
share . . . . . . . .$ .39 $ .37 $ .78 $ .74 $ 1.56 $ 1.48
Average common shares
outstanding . . . . . . 18,985 18,985 18,985 18,985 18,985 18,985
Pro forma amounts assuming
retroactive application of
accounting change:
Net income. . . . . . .$ 5,677 $ 3,797 $ 17,376 $ 19,558 $ 36,635 $ 41,569
Earnings per common
share . . . . . . . .$ .29 $ .19 $ .89 $ 1.01 $ 1.89 $ 2.15
The accompanying notes are an integral part of these statements.
MDU RESOURCES GROUP, INC.
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
June 30, June 30, December 31,
1994 1993 1993
(In thousands)
ASSETS
Property, plant and equipment:
Electric. . . . . . . . . . . . . $ 505,613 $ 495,521 $ 503,690
Natural gas distribution. . . . . 155,301 131,217 141,100
Natural gas transmission. . . . . 258,022 275,652 258,766
Mining and construction materials 146,140 124,390 145,014
Oil and natural gas production. . 131,737 105,082 116,833
1,196,813 1,131,862 1,165,403
Less accumulated depreciation,
depletion and amortization . . . 522,465 489,858 501,451
674,348 642,004 663,952
Current assets:
Cash and cash equivalents . . . . 80,871 104,683 71,699
Receivables . . . . . . . . . . . 47,366 42,969 67,553
Inventories . . . . . . . . . . . 23,877 18,607 19,415
Deferred income taxes . . . . . . 37,514 31,812 32,243
Other prepayments and current
assets . . . . . . . . . . . . 9,690 10,378 14,262
199,318 208,449 205,172
Natural gas available under
repurchase commitment . . . . . . 73,966 82,658 79,031
Investments. . . . . . . . . . . . 17,081 36,958 16,858
Deferred charges and other assets. 69,587 46,712 76,038
$1,034,300 $1,016,781 $1,041,051
CAPITALIZATION AND LIABILITIES
Capitalization:
Common stock (Shares outstanding --
18,984,654, $3.33 par value
at June 30, 1994, and $5.00 par
value at June 30, 1993
and December 31, 1993) $ 63,219 $ 94,923 $ 94,923
Other paid in capital . . . . . . 95,914 64,210 64,210
Retained earnings . . . . . . . . 161,165 154,946 158,998
320,298 314,079 318,131
Preferred stock subject to mandatory
redemption requirements . . . . 2,100 2,200 2,100
Preferred stock redeemable at option
of the Company. . . . . . . . . 15,000 15,000 15,000
Long-term debt. . . . . . . . . . 218,832 221,758 231,770
556,230 553,037 567,001
Commitments and contingencies. . . --- --- ---
Current liabilities:
Short-term borrowings . . . . . . 500 3,000 9,540
Accounts payable. . . . . . . . . 23,460 15,673 24,967
Taxes payable . . . . . . . . . . 16,750 22,802 9,204
Other accrued liabilities, including
reserved revenues . . . . . . . 124,042 110,948 107,566
Dividends payable . . . . . . . . 7,603 7,225 7,605
Long-term debt and preferred stock due
within one year . . . . . . . . 10,400 15,300 15,300
182,755 174,948 174,182
Natural gas repurchase commitment. 92,211 103,047 98,525
Deferred credits:
Deferred income taxes and unamortized
investment tax credit . . . . . 123,063 106,107 124,978
Other . . . . . . . . . . . . . . 80,041 79,642 76,365
203,104 185,749 201,343
$1,034,300 $1,016,781 $1,041,051
The accompanying notes are an integral part of these statements.
MDU RESOURCES GROUP, INC.
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Six Months Ended
June 30,
1994 1993
(In thousands)
Operating activities:
Net income . . . . . . . . . . . . . . . . . . . $17,376 $ 25,079
Cumulative effect of accounting change . . . . . --- (5,521)
Adjustments to reconcile net income to net cash
provided by operations:
Depreciation, depletion and amortization. . . . 23,572 22,260
Deferred income taxes and investment tax
credit -- net . . . . . . . . . . . . . . . . 93 (2,805)
Recovery of deferred natural gas contract
litigation settlement costs, net of
income taxes . . . . . . . . . . . . . . . . 3,174 2,023
Changes in current assets and liabilities --
Receivables. . . . . . . . . . . . . . . . . 20,187 23,809
Inventories. . . . . . . . . . . . . . . . . (4,462) (393)
Other current assets . . . . . . . . . . . . (699) 17,269
Accounts payable . . . . . . . . . . . . . . (1,507) (9,724)
Other current liabilities. . . . . . . . . . 24,020 8,440
Other noncurrent changes . . . . . . . . . . . 5,682 14,369
Net cash provided by operating activities. . . . 87,436 94,806
Financing activities:
Net change in short-term borrowings. . . . . . . (9,040) (4,775)
Issuance of long-term debt . . . . . . . . . . . 31,100 9,750
Repayment of long-term debt. . . . . . . . . . . (48,950) (22,850)
Retirement of natural gas repurchase commitment. (6,314) (11,890)
Dividends paid . . . . . . . . . . . . . . . . . (15,209) (14,452)
Net cash used in financing activities. . . . . . (48,413) (44,217)
Investing activities:
Additions of property, plant and equipment
and acquisitions of businesses --
Electric . . . . . . . . . . . . . . . . . . (2,704) (5,603)
Natural gas distribution . . . . . . . . . . (14,811) (5,485)
Natural gas transmission . . . . . . . . . . 493 (2,723)
Mining and construction materials. . . . . . (1,884) (20,239)
Oil and natural gas production . . . . . . . (15,787) (13,050)
(34,693) (47,100)
Sale of natural gas available under repurchase
commitment . . . . . . . . . . . . . . . . . . 5,065 9,380
Investments. . . . . . . . . . . . . . . . . . . (223) 24,976
Net cash used in investing activities. . . . . . (29,851) (12,744)
Increase in cash and cash equivalents. . . . . . 9,172 37,845
Cash and cash equivalents -- beginning of year . 71,699 66,838
Cash and cash equivalents -- end of period . . . $80,871 $104,683
The accompanying notes are an integral part of these statements.
MDU RESOURCES GROUP, INC.
NOTES TO CONDENSED CONSOLIDATED
FINANCIAL STATEMENTS
June 30, 1994 and 1993
(Unaudited)
1. Basis of presentation
The accompanying condensed 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, 1993 (1993 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 1993 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 condensed consolidated interim financial
statements.
2. Accounting change
On January 1, 1993, Montana-Dakota changed its revenue
recognition method to include the accrual of estimated unbilled
revenues for electric and natural gas service. This change
results in a better matching of revenues and expenses and is
consistent with predominant industry practice. Prior to this
change, Montana-Dakota, for both its electric and natural gas
businesses, recognized revenues on a monthly cycle billing basis
which recorded revenues when customers were billed. The
cumulative effect on net income for the twelve months ended
June 30, 1994, is presented net of applicable income taxes of
$3,355,000.
3. Seasonality of operations
Most 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. Therefore, the accompanying quarterly
financial information is supplemented by information for the
twelve months ended June 30, 1994 and 1993.
4. Pending litigation
KN Energy, Inc. (KN) --
In May 1991, KN, a pipeline for whom Williston Basin transports
natural gas, filed suit against Williston Basin in Federal
District Court for the District of Montana. KN alleged, in
part, that Williston Basin breached its contract with KN by
failing to provide priority transportation for KN, and by
charging KN transportation rates which were excessive. KN also
alleged that Williston Basin was responsible for any take-or-pay
costs it may incur as a result of the breach. Although no
amount of damages was specified, KN asked the Court to order
Williston Basin to reimburse KN for damages and certain other
costs it had incurred along with requiring specific performance
pursuant to the contract. Williston Basin filed a motion for
summary judgment with the Court in August 1992, requesting that
the Court dismiss KN's suit on the basis that these matters were
more appropriate for FERC resolution. In September 1992, the
Court denied Williston Basin's motion for summary judgment, but
suspended the proceedings before it and referred these matters
to the FERC. On June 30, 1994, Williston Basin and KN reached
a settlement which terminated this litigation and certain issues
related to several other court and FERC administrative
proceedings between Williston Basin and KN. Under the terms of
the settlement, KN and Williston Basin made payments of
offsetting amounts claimed. The favorable resolution of this
litigation did not have a material effect on Williston Basin's
results of operations.
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 against Williston Basin and the Company
disputing certain price and volume issues under the contract.
In its complaint, Moncrief alleged that, for the period January
1, 1985, through December 31, 1992, it had suffered damages
ranging from $1.2 million to $5.0 million, without interest, on
the price paid by Williston Basin for natural gas purchased.
Moncrief requested that the Court award it such amount and,
further requested that Williston Basin be obligated for damages
for additional volumes not purchased for the period November 1,
1993, (the date when Williston Basin implemented FERC Order 636
and abandoned its natural gas sales merchant function. See
"Regulatory Matters and Revenues Subject to Refund -- Order 636"
for a further discussion of Williston Basin's implementation of
Order 636) to mid-1996, the remaining period of the contract.
Trial was set for July 25, 1994.
On June 9, 1994, Moncrief filed a motion to amend its complaint
whereby it alleged a new pricing theory under Section 105 of the
Natural Gas Policy Act for natural gas purchased in the past and
for future volumes which Williston Basin refused to purchase
effective November 1, 1993. On July 5, 1994, in the course of
discovery, Moncrief submitted its damage calculation which
totalled approximately $18 million or, under its alternative new
pricing theory, $38 million. On July 13, 1994, the Court denied
Moncrief's motion to amend its complaint.
However, on July 15, 1994, the Court, as part of addressing the
proper litigants in this matter, rescheduled trial for
November 1, 1994, and allowed Moncrief to amend its complaint
to assert its new pricing theory under the contract.
These damage claims in Williston Basin's opinion, are grossly
overstated. Williston Basin further believes it has meritorious
defenses and intends to vigorously defend such suit. Williston
Basin plans to file for recovery from ratepayers of amounts
which may be ultimately due to Moncrief, if any.
5. Regulatory matters and revenues subject to refund
General Rate Proceedings --
Williston Basin had pending with the FERC two general natural
gas rate change applications implemented in 1989 and 1992. On
May 3, 1994, the FERC issued an order relating to the 1989 rate
change. Williston Basin requested rehearing of certain issues
addressed in the order and a stay of compliance and refund
pending issuance of a final order by the FERC. The requested
stay was denied by the FERC and on July 20, 1994, Williston
Basin refunded $47.8 million to its customers, including $33.4
million to Montana-Dakota. Williston Basin's request for
rehearing, which was granted by the FERC, is currently pending
as is the issuance of an initial order by the FERC with respect
to the 1992 rate change application.
Reserves have been provided for a portion of the revenues
collected subject to refund with respect to pending regulatory
proceedings and for the recovery of certain producer settlement
buy-out/buy-down costs as discussed below 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.
Producer Settlement Cost Recovery --
In August 1993, Williston Basin filed to recover 75 percent of
$28.7 million ($21.5 million) in buy-out/buy-down costs paid to
Koch Hydrocarbon Company as part of a lawsuit settlement under
the alternate take-or-pay cost recovery mechanism embodied in
Order 500. As permitted under Order 500, Williston Basin
elected to recover 25 percent or $7.2 million of such costs
through a direct surcharge to sales customers, substantially all
of which has been received. In addition, through reserves
previously provided, Williston Basin has absorbed an equal
amount. Williston Basin elected to recover the remaining 50
percent ($14.3 million) through a throughput surcharge
applicable to both sales and transportation. Williston Basin
began collecting these costs, subject to refund, on October 1,
1993, pending final approval by the FERC.
Order 636 --
As more fully described in the 1993 Annual Report on Form 10-K
(1993 Form 10-K), Williston Basin, in October 1992, filed a
revised tariff with the FERC designed to comply with Order 636.
The revised tariff reflected the cost allocation and rate design
necessary to the unbundling of Williston Basin's current
services. The FERC issued an order in February 1993, in which
it accepted Williston Basin's filing subject to certain
conditions.
In March 1993, Williston Basin filed further tariff revisions
with the FERC in compliance with the FERC's February 1993 order,
and also in March 1993, filed for rehearing and/or clarification
of other matters raised in the February 1993 order. In
May 1993, the FERC issued an order addressing both Williston
Basin's rehearing request and its March tariff filing. A
significant issue addressed by the FERC's order was a
determination that certain natural gas in underground storage
which was determined to be excess upon the future implementation
of Order 636 must be sold at market prices. The order further
required that the profit from such sale be used to offset any
transition costs. Williston Basin requested rehearing of this
and other issues by the FERC.
An appeal was filed by Williston Basin in June 1993, with the
U.S. Court of Appeals for the D.C. Circuit related to, among
other things, the FERC allowing firm transportation customers
flexible receipt and delivery points anywhere on Williston
Basin's pipeline system upon implementation of Order 636.
In September 1993, the FERC issued its order authorizing
Williston Basin's implementation of Order 636 tariffs effective
November 1, 1993. As a part of this order, the FERC reversed
its May 1993 determination related to the sale of certain
natural gas in underground storage and ordered that this storage
gas be offered for sale to Williston Basin's customers at its
original cost. As a result, any profits which would have been
realized on the sale at market prices of this storage gas will
not reduce Williston Basin's Order 636 transition costs.
Williston Basin requested rehearing of this issue by the FERC
on the grounds that requiring the sale of this storage gas at
cost results in a confiscation of its assets, which the FERC
denied in December 1993. Williston Basin has appealed the
FERC's decisions to the U.S. Court of Appeals for the D.C.
Circuit.
In November 1993, Williston Basin filed with the FERC, pursuant
to the provisions of Order 636, revised tariff sheets requesting
the recovery of $13.4 million of gas supply realignment
transition costs (GSR costs) effective December 1, 1993. As a
result of a December 1993 FERC order, Williston Basin began
collecting these costs subject to refund on December 1, 1993.
The GSR cost recovery reflects costs paid to Koch as part of a
lawsuit settlement and does not include other GSR costs, if any,
which may be incurred, and future recovery sought, by Williston
Basin.
Montana-Dakota has also filed revised gas cost tariffs with each
of its four state regulatory commissions reflecting the effects
of Williston Basin's November 1, 1993 implementation of
Order 636. In October 1993, all four state regulatory
commissions approved the revised tariffs.
Although no assurances can be provided, the Company believes
that Order 636 will not have a significant effect on its
financial position or results of operations.
6. Natural gas repurchase commitment
As more fully described in the 1993 Form 10-K and Note 5 of its
1993 Annual Report, the Company in 1981, entered into a series
of agreements for the purpose of financing the acquisition and
storage of natural gas through Frontier Gas Storage Company
(Frontier), a special purpose, non-affiliated corporation.
Through an agreement, an obligation exists to repurchase all of
the natural gas at Frontier's original cost and reimburse
Frontier for all of its financing and general administrative
costs.
As also described in the 1993 Form 10-K, the FERC issued an
order in July 1989, ruling on several cost-of-service issues
reserved as a part of the 1985 corporate realignment. Addressed
as a part of this order were certain rate design issues related
to the permissible rates for the transportation of the natural
gas held under the repurchase commitment. The issue relating
to the cost of storing this gas was not decided by that order.
As a part of orders issued in August 1990 and May 1991 related
to a general rate increase application, the FERC held that
storage costs should be allocated to this gas. Williston
Basin's July 1991 refund related to a general rate increase
application, reflected implementation of the above finding on
a prospective basis only. The public service commissions of
Montana and South Dakota and the Montana Consumer Counsel
protested whether such storage costs should be allocated to the
gas prospectively rather than retroactively to May 2, 1986. In
October 1991, the FERC issued an order rejecting Williston
Basin's compliance filing on the basis that, among other things,
Williston Basin is required to allocate storage costs to this
gas retroactive to May 2, 1986. Williston Basin requested
rehearing of the FERC's order on this issue in November 1991.
In February 1992, the FERC issued an order which reversed its
October 1991 order and held that such storage costs be allocated
to this gas on a prospective basis only, commencing March 6,
1992. A compliance filing was made with the FERC in March 1992,
which the FERC approved on and with an effective date beginning
May 20, 1992. These storage costs, as initially allocated to
the Frontier gas, approximated $2.1 million annually and
represent costs which Williston Basin may not recover. The
issue regarding the applicability of assessing storage charges
to the gas, which was appealed by Williston Basin to the U.S.
Court of Appeals for the D.C. Circuit in July 1991, creates
additional uncertainty as to the costs associated with holding
this gas. In July 1992, the Court, at the FERC's request,
returned the proceeding to the FERC for its further
consideration.
Beginning in October 1992, as a result of increases in natural
gas prices, Williston Basin began to sell and transport a
portion of the natural gas held under the repurchase commitment.
Through June 30, 1994, 15.6 MMdk of this natural gas had been
sold and transported by Williston Basin, primarily to off-system
markets. Williston Basin will continue to aggressively market
the remaining 45.2 MMdk of this natural gas as long as market
conditions remain favorable. In addition, it will continue to
seek long-term sales contracts.
7. Company production royalties
In March and May 1993, Williston Basin was directed by the
United States Minerals Management Service (MMS) to pay
approximately $3.5 million, plus interest, in claimed royalty
underpayments. These royalties are attributable to natural gas
production by Williston Basin from federal leases in Montana and
North Dakota for the period December 1, 1978, through
February 29, 1988. Williston Basin had filed appeals with both
the MMS and the Courts regarding this issue.
On July 6, 1994, Williston Basin and the MMS reached a
settlement which terminated the litigation and all
administrative proceedings. The settlement provided that
Williston Basin make a cash payment of $2.1 million, including
interest, in satisfaction of all claimed royalty underpayments.
Williston Basin had previously provided reserves adequate to
cover the costs of the settlement.
8. Production taxes
In December 1993, Williston Basin received from the Montana
Department of Revenue (MDR) an assessment claiming additional
production taxes due of $3.7 million, plus interest, for 1988
through 1991 production. These claimed taxes result from the
MDR's belief that certain natural gas production during the
period at issue was not properly valued. Williston Basin does
not agree with the MDR and has reached an agreement with the MDR
that the appeal process be held in abeyance pending further
review.
9. 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. Both Montana-
Dakota and Williston Basin have initiated testing, monitoring
and remediation procedures, in accordance with applicable
regulations and the work plan submitted to the EPA and the
appropriate state agencies. Costs incurred by Montana-Dakota
and Williston Basin through June 30, 1994, to address this
situation aggregated approximately $785,000. These costs are
related to the testing being performed, and the costs to remove,
dispose of and replace certain property found to be
contaminated. On the basis of findings to date, Montana-Dakota
and Williston Basin estimate that future environmental
assessment and remediation costs that will be incurred range
from $3 million to $15 million. This estimate depends upon a
number of assumptions concerning the scope of remediation that
will be required at certain locations, the cost of remedial
measures to be undertaken and the time period over which the
remedial measures are implemented. In a separate action,
Montana-Dakota and Williston Basin filed suit in Montana State
Court, Yellowstone County, in January 1991, against Rockwell
International Corporation, manufacturer of the valve sealant,
to recover any costs which may be associated with the presence
of PCBs in the system, including a remediation program. On
January 31, 1994, Montana-Dakota, Williston Basin and Rockwell
reached a settlement which terminated this litigation. Pursuant
to the terms of the settlement, Rockwell will reimburse Montana-
Dakota and Williston Basin for a portion of certain remediation
costs incurred or expected to be incurred. In addition, both
Montana-Dakota and Williston Basin consider unreimbursed
environmental remediation costs and costs associated with
compliance with environmental standards to be recoverable
through rates, since they are prudent costs incurred in the
ordinary course of business and, accordingly, have sought and
will continue to seek recovery of such costs through rate
filings. Although no assurances can be given, based on the
estimated cost of the remediation program and the expected
recovery of most of these costs from third parties or
ratepayers, Montana-Dakota and Williston Basin believe that the
ultimate costs related to these matters will not be material to
Montana-Dakota's or Williston Basin's financial position or
results of operations.
In mid-1992, Williston Basin discovered that several of its
natural gas compressor stations had been operating without air
quality permits. As a result, in late 1992, applications for
permits were filed with the Montana Air Quality Bureau (Bureau).
In March 1993, the Bureau cited Williston Basin for operating
the compressors without the requisite air quality permits and
further alleged excessive emissions by the compressor engines
of certain air pollutants, primarily oxides of nitrogen and
carbon monoxide. Williston Basin is currently engaged in
further testing these air emissions but is currently unable to
determine the costs that will be incurred to remedy the
situation although such costs are not expected to be material
to its financial position or results of operations.
In June 1990, Montana-Dakota was notified by the EPA that it and
several others were named as Potentially Responsible Parties
(PRPs) in connection with the cleanup of pollution at a landfill
site located in Minot, North Dakota. An informational meeting
was held in January 1993, between the EPA and the PRPs outlining
the EPA's proposed remedy and the settlement process. In June
1993, the EPA issued its decision on the selected remediation
to be performed at the site. Based on the EPA's proposed
remediation plan, current estimates of the total cleanup costs
for all parties, including oversight costs, at this site range
from approximately $3.7 million to $4.8 million. Montana-Dakota
believes that it was not a material contributor to this
contamination and, therefore, further believes that its share
of the liability for such cleanup will not have a material
effect on its results of operations.
10. Federal tax matters
The Company's consolidated federal income tax returns were under
examination by the Internal Revenue Service (IRS) for the tax
years 1983 through 1988. In September 1991, the Company
received a deficiency notice from the IRS for the tax years 1983
through 1985 which proposed substantial additional income taxes,
plus interest. In an alternative position contained in the
notice of proposed deficiency, the IRS is claiming a lower level
of taxes due, plus interest as well as penalties. In May 1992,
a similar notice of proposed deficiency was received for the
years 1986 through 1988. Although the notices of proposed
deficiency encompass a number of separate issues, the principal
issue is related to the tax treatment of deductions claimed in
connection with certain investments made by Knife River and
Fidelity Oil.
The Company's tax counsel has issued opinions related to the
principal issue discussed above, stating that it is more likely
than not that the Company would prevail in this matter. Thus,
the Company intends to contest vigorously the deficiencies
proposed by the IRS and, in that regard, has timely filed
protests for the 1983 through 1988 tax years contesting the
treatment proposed in the notices of proposed deficiency. If
the IRS position were upheld, the resulting deficiencies would
have a material effect on results of operations.
11. Cash flow information
Cash expenditures for interest and income taxes were as follows:
Six Months Ended
June 30,
1994 1993
(In thousands)
Interest, net of amount capitalized $11,795 $11,412
Income taxes $ 7,237 $10,364
The Company considers all highly liquid investments purchased
with an original maturity of three months or less to be cash
equivalents.
During the six month period ended June 30, 1994, the Company's
natural gas transmission business sold $8.3 million of natural
gas in underground storage to the natural gas distribution
business. The cash flow effects of this intercompany sale and
purchase shown under "Investing activities" were not eliminated.
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
Overview
The following table (in millions of dollars) summarizes the
contribution to consolidated earnings by each of the Company's
businesses.
Three Months Six Months Twelve Months
Ended Ended Ended
June 30, June 30, June 30,
1994 1993 Business 1994 1993 1994 1993
Utility --
$ 1.1 $ 1.9 Electric $ 4.9 $ 6.0 $ 11.6 $ 13.5
(1.3) (1.7) Natural gas 1.8 1.5 1.4 1.5
(.2) .2 6.7 7.5 13.0 15.0
1.4 (.4) Natural gas transmission 3.7 4.3 4.2 7.0
Mining and construction
3.3 2.3 materials 4.7 4.6 12.4 9.9
Oil and natural gas
1.0 1.5 production 1.9 2.8 6.2 6.8
$ 5.5 $ 3.6 Earnings on common stock $ 17.0 $ 19.2 $ 35.8 $ 38.7
$ .29 $ .19 Earnings per common share $ .89 $ 1.01 $ 1.89 $ 2.04
Return on average common equity 11.3% 12.7%
Earnings information presented in this table and in the following
discussion is before the $8.9 million ($5.5 million after-tax)
cumulative effect of an accounting change. See Note 2 of Notes to
Condensed Consolidated Financial Statements for a further
discussion of this accounting change.
Three Months Ended June 30, 1994 and 1993
Consolidated earnings for the three months ended June 30, 1994,
increased $1.9 million when compared to the corresponding period a
year ago. Improvements in natural gas distribution, natural gas
transmission and mining and construction materials earnings were
partially offset by decreased earnings at the electric and oil and
natural gas production businesses. The discussion of the three
month period includes the reasons for such changes.
Six Months Ended June 30, 1994 and 1993
Consolidated earnings for the six months ended June 30, 1994,
were $17.0 million, down $2.2 million from the same period in 1993.
The decrease in earnings was a result of decreased electric,
natural gas transmission and oil and natural gas production
earnings, offset in part by increased natural gas distribution and
mining and construction materials earnings, all as described in the
year-to-date analysis.
Twelve Months Ended June 30, 1994 and 1993
For the twelve month period ended June 30, 1994, consolidated
earnings decreased $2.9 million from the same period last year. An
earnings decline at the utility, natural gas transmission and oil
and natural gas production businesses was partially offset by
increased earnings at the mining and construction materials
businesses. The reasons for such changes are discussed in the
twelve month section.
Reference should be made to Notes 4, 5 and 6 of Notes to
Condensed Consolidated Financial Statements for information
pertinent to pending litigation, regulatory matters and revenues
subject to refund and a natural gas repurchase commitment.
Financial and operating data
The following tables (in millions, where applicable) contain key
financial and operating statistics for each of the Company's
business units.
Montana-Dakota -- Electric Operations
Three Months Six Months Twelve Months
Ended Ended Ended
June 30, June 30, June 30,
1994 1993 1994 1993 1994 1993
$ 30.6 $ 29.6 Operating revenues $ 66.5 $ 64.2 $133.4 $127.3
10.4 9.1 Fuel and purchased power 21.8 19.6 43.5 39.1
Operation and
10.1 9.8 maintenance expenses 20.1 18.9 38.5 35.9
4.5 5.2 Operating income 13.2 14.6 29.2 30.7
447.1 432.3 Retail sales (kWh) 972.8 941.2 1,925.3 1,865.8
Power deliveries to
83.8 87.8 MAPP (kWh) 211.3 199.3 523.1 426.4
Cost of fuel and purchased
$ .018 $ .017 power per kWh $ .017 $ .016 $ .016 $ .016
Montana-Dakota -- Gas Distribution Operations
Three Months Six Months Twelve Months
Ended Ended Ended
June 30, June 30, June 30,
1994 1993 1994 1993 1994 1993
Operating revenues:
$ 23.6 $ 21.8 Sales $ 92.1 $ 83.6 $160.1 $134.7
.7 .9 Transportation & other 1.8 2.3 3.9 4.6
15.9 15.3 Purchased natural gas sold 69.8 63.4 120.5 99.3
Operation and
7.3 7.0 maintenance expenses 14.8 13.9 29.5 26.9
(1.4) (1.8) Operating income 4.3 4.3 4.7 4.8
Volumes (dk):
4.5 4.2 Sales 18.9 17.6 32.4 28.4
1.7 2.3 Transportation 4.6 6.6 10.7 14.4
6.2 6.5 Total throughput 23.5 24.2 43.1 42.8
86.6% 107.5% Degree days (% of normal) 99.7% 104.3% 102.0% 106.2%
$ 3.54 $ 3.65 Cost of natural gas per dk $ 3.70 $ 3.59 $ 3.72 $ 3.49
Williston Basin
Three Months Six Months Twelve Months
Ended Ended Ended
June 30, June 30, June 30,
1994 1993 1994 1993 1994 1993
Operating revenues:
$ --- $ 8.5* Sales for resale $ --- $ 34.2* $ 17.0* $ 61.6*
17.0* 7.5* Transportation & other 37.8* 18.3* 59.5* 36.9*
--- 3.2 Purchased natural gas sold --- 17.6 3.0 30.5
Operation and
9.4** 7.0** maintenance expenses 20.6** 15.5** 44.0** 31.3**
4.9 2.9 Operating income 11.6 13.5 18.2 25.3
Volumes (dk):
Sales for resale--
--- 1.8 Montana-Dakota --- 10.7 2.3 18.2
--- --- Other --- .2 --- .3
Transportation--
6.2 4.8 Montana-Dakota 23.4 13.7 37.0 27.5
6.2 7.1 Other 13.2 17.8 27.5 39.2
12.4 13.7 Total throughput 36.6 42.4 66.8 85.2
*Includes recovery in millions as follows:
Deferred natural gas contract
$ 1.5 $ .7 buy-out/buy-down costs $ 5.1 $ 2.6 $ 15.2 $ 5.4
**Includes amortization in millions as follows:
Deferred natural gas contract
$ 1.6 $ .9 buy-out/buy-down costs $ 5.2 $ 2.9 $ 14.0 $ 5.9
Knife River
Three Months Six Months Twelve Months
Ended Ended Ended
June 30, June 30, June 30,
1994 1993 1994 1993 1994 1993
Operating revenues:
$ 9.5 $ 9.1 Coal $ 22.3 $ 20.6 $ 45.9 $ 42.9
21.6 9.7 Construction materials 28.6 9.9 64.9 10.6
Operation and
22.6 12.3 maintenance expenses 36.8 18.3 78.1 29.2
.6 .7 Reclamation expense 1.6 1.4 3.3 2.9
1.0 1.0 Severance taxes 2.3 2.1 4.6 4.3
5.1 3.4 Operating income 6.7 6.1 17.6 11.8
Sales (000's):
1,172 1,092 Coal (tons) 2,603 2,403 5,266 4,960
939 435 Aggregates (tons) 1,217 488 3,120 639
Ready-mixed concrete
86 24 (cubic yards) 137 24 269 24
107 18 Asphalt (tons) 125 18 248 18
Fidelity Oil
Three Months Six Months Twelve Months
Ended Ended Ended
June 30, June 30, June 30,
1994 1993 1994 1993 1994 1993
$ 9.4 $ 9.5 Operating revenues $ 18.0 $ 19.3 $ 37.8 $ 38.0
Operation and
3.1 2.6 maintenance expenses 6.1 5.7 12.0 11.6
Depreciation, depletion
3.2 3.1 and amortization 6.2 6.1 12.2 10.7
2.1 2.9 Operating income 3.9 5.7 9.9 12.2
Production (000's):
386 367 Oil (barrels) 756 733 1,520 1,508
2,195 2,154 Natural gas (Mcf) 4,339 4,114 9,042 6,949
Average sales price:
$12.44 $16.15 Oil (per barrel) $11.66 $15.91 $12.75 $16.82
2.07 1.63 Natural gas (per Mcf) 2.08 1.80 1.99 1.74
Three Months Ended June 30, 1994 and 1993
Montana-Dakota--Electric Operations
The decline in operating income was due to increased fuel and
purchased power costs, principally higher demand charges associated
with the pass-through of periodic maintenance costs as well as the
purchase of an additional five megawatts of firm capacity through
a participation power contract. Also, higher operation expense,
primarily increased payroll costs, contributed to the operating
income decline. Partially mitigating the operating income decline
were increased commercial and industrial sales due to increased
demand. Earnings from this business unit declined due to the
aforementioned changes in operating income and increased long-term
debt interest, the result of lower interest received from Williston
Basin due to the retirement of intercompany debt partially offset
by the retirement of $15.0 million of 5.8 percent medium-term notes
on April 1, 1994.
Montana-Dakota--Natural Gas Distribution Operations
Operating income improved during the period primarily due to the
benefits of general rate relief placed into effect in December
1993, and January 1994, in North Dakota, South Dakota and Wyoming
and the addition of over 4,900 customers when compared to the same
period last year. The effects of a Wyoming Supreme Court order
granting recovery of a prior refund made by Montana-Dakota also
increased operating income. Increased operation expenses,
primarily payroll costs, and increased depreciation expense
partially offset the operating income increase. Gas distribution
earnings increased due to the aforementioned operating income
changes and increased Other Income -- Net, primarily the return
earned on the investment in natural gas in storage, offset in part
by increased long-term debt interest, the result of the previously
described intercompany debt retirement.
Williston Basin
The improvement in operating income reflects increased margins
realized due to the timing of revenues now being realized under the
Order 636 rate structure implemented in November 1993. The new
rate methodology, which shifts a greater portion of revenues to a
fixed monthly demand which in the past had been primarily commodity
based, results in lower natural gas transmission earnings during
the higher volume winter heating season than have been realized in
the past, but produce higher earnings during the lower volume
summer months. See Note 5 for more information on the
implementation of Order 636. Revenue recognized as a result of 3.3
million decatherms (MMdk) of natural gas transported to storage
increased operating income. However, prior to 1994 such revenue
was not recognized until the natural gas was withdrawn from storage
during the winter months. Also contributing to the operating
income increase were higher realized rates, primarily due to a rate
stipulation agreement with the FERC in January 1994, and a decline
in operation and maintenance expenses and depreciation expense,
primarily due to the sale or transfer of unneeded facilities. In
addition, company production volumes improved 236,000 decatherms
(Mdk) increasing operating income. Reduced volumes transported,
primarily to off-system markets at lower average rates, somewhat
offset the operating income improvement. Natural gas transmission
earnings increased due to the aforementioned changes in operating
income, increased interest being accrued on deferred buy-out/buy-
down costs and gas supply realignment transition costs and
decreased long-term debt interest. The decline in long-term debt
interest was the result of debt retirements and debt refinancing in
July 1993, and April 1994. Increased carrying costs associated with
the natural gas repurchase commitment, the result of higher
interest rates, and increased interest expense on revenues being
reserved, decreased Williston Basin's earnings.
Knife River
The operating income increase for this business was due to sales
from the September 1993 acquisition of an Oregon construction
materials business. Increased coal sales at the Gascoyne Mine also
added to the operating income increase. An increase in operation
expenses, primarily related to the aforementioned volume increases,
reduced operating income. Earnings increased due to the
improvement in operating income offset in part by reduced
investment income (included in Other Income -- Net), primarily
resulting from lower investable funds due to the aforementioned
acquisition.
Fidelity Oil
Operating income for the oil and natural gas production business
declined as a result of decreased oil prices and an increase in
operation and maintenance expenses, largely related to increased
per unit production costs. Partially offsetting the operating
income decline were increased oil production and higher average
natural gas sales prices. Earnings for this business unit
decreased as a result of the changes in operating income discussed
above.
Six Months Ended June 30, 1994 and 1993
Montana-Dakota--Electric Operations
The decline in operating income reflects increased fuel and
purchased power costs, principally higher demand charges associated
with the pass-through of periodic maintenance costs and the
purchase of an additional five megawatts of firm capacity through
a participation power contract. Increased operation expense,
primarily higher payroll and benefit-related costs, and increased
depreciation expense also negatively affected operating income.
Partially mitigating the operating income decline were increased
sales to all major markets, the result of increased demand.
Earnings for the electric business decreased due to the
aforementioned changes in operating income and increased long-term
debt interest, resulting from lower interest received from
Williston Basin due to the retirement of intercompany debt,
partially offset by the retirement of $15.0 million of 5.8 percent
medium-term notes on April 1, 1994.
Montana-Dakota--Natural Gas Distribution Operations
Operating income at the natural gas distribution business was
essentially unchanged from the corresponding period in 1993. The
benefits of general rate relief placed into effect in December
1993, and January 1994, in North Dakota, South Dakota and Wyoming
and the addition of nearly 4,900 customers, improved operating
income. In addition, a Wyoming Supreme Court order granting
recovery of a prior refund, increased operating income. Offsetting
the above-mentioned increases were lower volumes transported,
primarily due to two oil refineries bypassing Montana-Dakota's
distribution facilities, and higher operating expenses. Increased
employee benefit-related costs, increased distribution and sales
expenses due to the system expansion into north-central South
Dakota, and increased depreciation expense are the primary factors
contributing to the operating expense increase. Gas distribution
earnings improved due to increased Other Income -- Net, primarily
the return earned on the natural gas storage inventory offset in
part by increased interest expense, primarily carrying costs being
accrued on natural gas costs refundable through rate adjustments,
higher financing costs related to increased capital expenditures
and the previously described intercompany debt retirement.
Williston Basin
The decline in operating income reflects decreased net
throughput, primarily decreased volumes transported to discounted
off-system markets at lower prices. Decreased margins realized due
to the timing of revenues being realized under the Order 636 rate
structure implemented in November 1993, negatively affected 1994
year-to-date earnings. See Note 5 and the three months' discussion
above for more information on the implementation of Order 636. A
January 1994 rate change due to a rate stipulation agreement with
the FERC and improved company production volumes at higher rates,
partially offset the decline in operating income. Also a
mitigating factor is the realization of revenue related to natural
gas transported to storage, as described in the three months'
discussion, and decreased operating expenses, primarily maintenance
and depreciation expenses. Earnings for this business decreased
due to the operating income reasons discussed above and increased
interest expense on revenues being reserved. The decline in natural
gas transmission earnings was somewhat offset by decreased long-
term debt interest, the result of debt retirements and debt
refinancing in July 1993, and April 1994, and increased interest
being accrued on deferred buy-out/buy-down costs and gas supply
realignment transition costs.
Knife River
Operating income increased due to an improvement in coal sales
at all mines, mainly the result of increased demand by electric
generation customers, and sales from the newly acquired Oregon
construction materials business. A volume-related increase in
operation expenses partially offset the operating income increase.
Also offsetting the operating income improvement was a decline
related to seasonal first quarter losses experienced at the Alaska
construction materials business which was acquired in April 1993.
Operations of the construction materials businesses are highly
seasonal whereby operating losses are generally incurred during the
winter months with significantly higher revenues being realized
during the spring and summer construction season. Earnings
increased due to the aforementioned changes in operating income
offset in part by reduced investment income (included in Other
Income -- Net), primarily lower investable funds due to the
aforementioned acquisitions.
Fidelity Oil
Operating income for the oil and natural gas production business
declined as a result of lower average oil prices and an increase in
operation and maintenance expenses, due to both increased volumes
and higher per unit costs. Partially offsetting the operating
income decline were higher average natural gas prices and an
improvement in oil and natural gas production. Earnings from this
business decreased due to the aforementioned changes in operating
income.
Twelve Months Ended June 30, 1994 and 1993
Montana-Dakota--Electric Operations
Operating income for the electric business declined due to higher
operation expense, primarily employee benefit-related costs,
increased depreciation expense and increased fuel and purchased
power costs. Higher demand charges associated with the pass-
through of periodic maintenance costs and the purchase of an
additional five megawatts of firm capacity through a participation
power contract were the primary factors behind the increase in fuel
and purchased power costs. Partially mitigating the operating
income decline was an improvement in retail sales, primarily due to
increased demand, and an increase in deliveries into the MAPP, the
result of a temporary shutdown of a nuclear generating station in
Iowa. Earnings from this business unit decreased for the reasons
discussed above as well as decreased Other Income -- Net,
reflecting the on-going effects of adopting SFAS No. 106 and
increased federal income taxes, the result of the 1993 tax law
change. Also reducing electric earnings was increased long-term
debt interest due to lower interest received from Williston Basin
due to the retirement of intercompany debt, partially offset by the
retirement of $15.0 million of 5.8 percent medium-term notes on
April 1, 1994.
Montana-Dakota--Natural Gas Distribution Operations
Increased operation expense, primarily employee benefit-related
costs and distribution and sales expenses related to the system
expansion into north-central South Dakota, was the significant
factor reducing operating income for the natural gas distribution
business. Also, lower volumes transported to commercial and
industrial customers, primarily due to two oil refineries bypassing
Montana-Dakota's distribution facilities, and increased
depreciation expense reduced operating income. Sales increases,
due to the addition of over 3,900 customers, combined with general
rate relief realized in North Dakota, South Dakota and Wyoming
partially mitigated the operating income decline. Also somewhat
offsetting the decrease in operating income was the effects of a
Wyoming Supreme Court order granting recovery of a prior refund.
Gas distribution earnings decreased slightly due to the
aforementioned operating income change, higher financing costs
related to increased capital expenditures and carrying charges
being accrued on natural gas costs refundable through rate
adjustments. Increased Other Income--Net, primarily due to the
return being earned on the natural gas storage inventory, reduced
the earnings decline.
Williston Basin
Operating income declined at the natural gas transmission
business as a result of decreased net throughput, primarily lower
transportation to off-system markets, and revenue timing
differences resulting from the implementation of Order 636. See
Note 5 and the three months discussion above for more information
on the implementation of Order 636. Operation expenses increased
due to higher employee benefit-related costs and additional
reserves provided relating to the Koch settlement, however an
adjustment to regulatory reserves reflected in operating revenues
offset the effects of these additional reserves. Also, offsetting
the increased operation expenses was an out-of-period adjustment to
take-or-pay surcharge amortizations. Increased general rates
implemented in November 1992, and a January 1994 rate change due to
a rate stipulation agreement with the FERC, partially offset the
operating income decline. Income from company production improved
due to both increased production and higher average prices.
Revenue associated with natural gas transported to storage, as
described in the three months discussion, also increased operating
income. Earnings for this business unit decreased due to the
aforementioned operating income decline offset in part by increased
interest income being accrued on deferred buy-out/buy-down costs
and gas supply realignment transition costs. Reduced interest on
long-term debt, the result of debt retirements and debt refinancing
in July 1993, and April 1994, and lower carrying costs associated
with the natural gas repurchase commitment, primarily the result of
lower borrowings due to the sale of this gas, also partially
mitigated the earnings decline.
Knife River
Operating income improved due to sales from the newly acquired
Alaskan and Oregon construction materials businesses and an
improvement in coal tons sold at all mines, mainly the result of
increased demand by electric generation customers. Higher selling
prices at the Beulah Mine more than offset lower prices at the
Gascoyne and Savage mines. An increase in operating expenses
attributable to the newly acquired construction materials
businesses and a volume-related increase in coal operating expenses
reduced operating income. Earnings increased due to the above-
described operating income improvement, offset in part by reduced
investment income (included in Other Income--Net), primarily
resulting from lower investable funds due to the 1993 acquisitions.
Fidelity Oil
Operating income for the oil and natural gas production business
decreased as a result of a decline in oil prices and a volume-
related increase in depreciation, depletion and amortization.
Partially offsetting the operating income decline were higher
natural gas production and prices. The effect of lower average per
unit production costs was more than offset by a volume-related
increase. Earnings for this business improved due to the
realization of certain investment gains. The decline in operating
income, increased interest expense, stemming from both higher
average borrowings and rates, and increased federal income taxes,
somewhat reduced earnings.
Prospective Information
The operating results of the Company's utility and pipeline
businesses are significantly influenced by the weather, the general
economy of their respective service territories, and the ability to
recover costs through the regulatory process.
Montana-Dakota is generally allowed to recover through general
rates the costs of providing utility services which include fuel
and purchased power costs and the cost of natural gas purchased.
The electric business utilizes either fuel adjustment clauses or
expedited rate filings to recover changes in fuel and purchased
power costs in the interim periods. The natural gas business has
similar mechanisms in place to pass through the changes in natural
gas commodity, transportation and storage costs (including carrying
costs). These recovery mechanisms reduce the effect the changes in
these costs have on Montana-Dakota's results. See Items 1 and 2 of
the 1993 Form 10-K for a further discussion of these items as they
apply to Montana-Dakota's operations.
See Items 1 and 2 of the 1993 Form 10-K under Montana-Dakota for
a discussion of general rate increase applications filed and
settlements reached with the NDPSC, SDPUC and WPSC, respectively.
On April 1, 1994, Montana-Dakota filed a general natural gas rate
increase application with the MPSC requesting an increase of $2.6
million or 5.29%, with 25% requested on an interim basis to be
effective within 30 days. The MPSC has not yet acted on Montana-
Dakota's request for interim rates. Montana-Dakota Utilities Co.
has also filed general natural gas rate cases in North Dakota and
South Dakota requesting increases of 1.3 percent and 3.7 percent,
respectively. These filings were made on May 13, 1994, in North
Dakota and June 29, 1994, in South Dakota, representing a combined
$2.1 million increase in revenues.
On October 1, 1992, as a result of increases in natural gas
prices, Williston Basin began to sell and transport a portion of
the natural gas held under the repurchase commitment. Williston
Basin will continue to aggressively market this natural gas as long
as market conditions remain favorable. In addition, it will
continue to seek long-term sales contracts. See Note 6 and Items
1 and 2 of the 1993 Form 10-K under Williston Basin for additional
information on the natural gas held under this repurchase
agreement.
In early 1993, Knife River, together with the Lignite Energy
Council, supported the introduction of legislation in North Dakota
which would provide severance tax relief for its Gascoyne Mine.
The legislation was designed to assist in keeping the Gascoyne coal
competitive. However, in June 1994, Knife River was notified by
the owners of the Big Stone Station that its contract for supplying
approximately 2.1 million tons of lignite annually would not be
renewed. The current contract expires in mid-1995 and Knife River
anticipates closing the Gascoyne Mine upon the expiration of the
contract. The costs of closing the Gascoyne Mine are not expected
to have a significant effect on Knife River's results of
operations.
Knife River continues to seek out additional growth
opportunities. These include not only identifying possibilities
for alternate uses of lignite coal but also investigating the
acquisition of other surface mining properties, particularly those
relating to sand and gravel aggregates and related products such as
ready-mixed concrete, asphalt and various finished aggregate
products. In 1993, Knife River acquired two construction materials
operations, one in Anchorage, Alaska, and the other with locations
in Medford, Oregon and Stockton, California. See Items 1 and 2 of
the 1993 Form 10-K under Knife River for a further discussion of
these acquisitions.
See Notes 2 and 15 of Notes to Consolidated Financial
Statements contained in the 1993 Annual Report for a further
discussion on the Company's 1993 adoption of SFAS No. 106,
"Employers' Accounting for Postretirement Benefits Other than
Pensions" (SFAS No. 106) and the Company's efforts regarding
regulatory recovery, including the NDPSC's January 19, 1994, order
which requires the expensing, commencing January 1, 1994, of the
ongoing SFAS No. 106 incremental expense estimated at $1.0 million
annually. A hearing was held by the SDPUC on March 24, 1994, on
the recovery of SFAS No. 106 costs. On July 21, 1994, the
Commission issued an order rejecting the Company's request,
determining that the pay-as-you-go method must be used for
ratemaking purposes. The 1994 SFAS No. 106 incremental expense is
estimated to be approximately $250,000 annually.
Liquidity and Capital Commitments
The Company's regulated businesses operated by Montana-Dakota
and Williston Basin estimate construction costs of approximately
$48.8 million for the year 1994. The Company's 1994 capital needs
to retire maturing long-term corporate securities are estimated at
$15.3 million.
It is anticipated that Montana-Dakota will continue to provide
all of the funds required for its construction requirements from
internal sources and through the use of its $30 million revolving
credit and term loan agreement, none of which is outstanding at
June 30, 1994, and through the issuance of long-term debt, the
amount and timing of which will depend upon the Company's needs,
internal cash generation and market conditions.
Williston Basin expects to meet its construction requirements
and financing needs with a combination of internally generated
funds and a $35 million line of credit currently available, none of
which is outstanding at June 30, 1994, and through the issuance of
long-term debt, the amount and timing of which will depend upon the
Company's needs, internal cash generation and market conditions.
On April 1, 1994, Williston Basin borrowed $25 million under a term
loan agreement, with the proceeds used solely for the purpose of
refinancing purchase money mortgages payable to the Company, as
further described in Note 12 of Notes to Consolidated Financial
Statements contained in the 1993 Annual Report.
As further described in Items 1 and 2 of the 1993 Form 10-K
under Williston Basin, in August 1993, Koch and Williston Basin
reached a settlement that terminated the litigation with respect to
all parties. The Company believes that it is entitled to recover
from ratepayers most of the costs that were incurred as a result of
this settlement, although the amount of the costs which can
ultimately be recovered is subject to regulatory and market
uncertainties. See Items 1 and 2 of the 1993 Form 10-K under
Williston Basin for a further discussion of this settlement and
Williston Basin's efforts regarding regulatory recovery.
Knife River's capital needs of $5.5 million, excluding those
required for potential mining acquisitions, will be met through
funds on hand and funds generated from internal sources. In
addition, effective April 20, 1994, Knife River has available
$5 million under a revolving credit and term loan agreement. It is
anticipated that funds on hand, funds generated from internal
sources and the revolving credit and term loan agreement will
continue to meet the needs of this business unit.
Fidelity Oil's 1994 capital needs related to its oil and
natural gas acquisition, development and exploration program,
estimated at $30.0 million, will be met through funds generated
from internal sources, and a $20 million secured line of credit and
other additional long-term financing arrangements. There was $6.1
million outstanding at June 30, 1994, under the secured line of
credit.
See Note 10 for a discussion of deficiency notices received
from the IRS proposing substantial additional income taxes. The
level of funds which could be required as a result of the proposed
deficiencies could be significant if the IRS position were upheld.
Prairielands' capital needs of $225,000 are anticipated to be
met through funds generated internally and its $5.4 million lines
of credit, $500,000 of which is outstanding at June 30, 1994.
The Company utilizes its $40 million lines of credit and its
$30 million revolving credit and term loan agreement to meet its
short-term financing needs and to take advantage of market
conditions when timing the placement of long-term or permanent
financing. There were no borrowings outstanding at June 30, 1994,
under the lines of credit.
The Company's issuance of first mortgage debt is subject to
certain restrictions imposed under the terms and conditions of its
Indenture of Mortgage. Generally, those restrictions require the
Company to pledge $1.43 of unfunded property to the Trustee for
each dollar of indebtedness incurred under the Indenture and that
annual earnings (pretax and before interest charges) as defined in
the Indenture, equal at least two times its annualized first
mortgage bond interest costs. Under the more restrictive of the
two tests, as of June 30, 1994, the Company could have issued
approximately $132 million of additional first mortgage bonds.
The Company's coverage of fixed charges including preferred
dividends was 2.8 times for twelve months ended June 30, 1994, and
3.0 times for the year 1993. Additionally, the Company's first
mortgage bond interest coverage was 3.5 times for the twelve months
ended June 30, 1994, compared to 3.4 times in 1993. Stockholders'
equity as a percent of total capitalization was 58% and 56% at
June 30, 1994, and December 31, 1993, respectively.
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of
1934, the registrant has duly caused this report to be signed on
its behalf by the undersigned thereunto duly authorized.
MDU RESOURCES GROUP, INC.
DATE August 9, 1994 BY /s/ Warren L. Robinson
Warren L. Robinson
Vice President, Treasurer
and Chief Financial Officer
/s/ Vernon A. Raile
Vernon A. Raile
Vice President, Controller and
Chief Accounting Officer