UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
X QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
FOR THE QUARTERLY PERIOD ENDED MARCH 31, 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 May 6, 1994: 18,984,654
shares.
<PAGE>
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.
<PAGE>
INDEX
Part I
Condensed Consolidated Statements of Income --
Three and Twelve Months Ended March 31, 1994 and 1993
Condensed Consolidated Balance Sheets --
March 31, 1994 and 1993, and December 31, 1993
Condensed Consolidated Statements of Cash Flows --
Three Months Ended March 31, 1994 and 1993
Notes to Condensed Consolidated Financial Statements
Management's Discussion and Analysis of Financial
Condition and Results of Operations
Part II
Signatures
<PAGE>
MDU RESOURCES GROUP, INC.
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
Three Months Ended Twelve Months Ended
March 31, March 31,
1994 1993 1994 1993
(In thousands, except per share amounts)
Operating revenues:
Electric . . . . . . . . . . $35,798 $34,582 $132,325 $126,489
Natural gas. . . . . . . . . 60,107 68,049 171,039 173,121
Mining and construction
materials. . . . . . . . . 19,882 11,812 98,467 45,055
Oil and natural gas
production . . . . . . . . 8,575 9,726 37,974 36,103
124,362 124,169 439,805 380,768
Operating expenses:
Fuel and purchased power . . 11,422 10,533 42,187 39,099
Purchased natural gas sold . 26,837 32,452 72,506 68,421
Operation and maintenance. . 43,656 32,728 178,302 124,991
Depreciation, depletion and
amortization . . . . . . . 11,720 10,962 45,920 40,898
Taxes, other than income . . 6,212 5,956 23,821 22,545
99,847 92,631 362,736 295,954
Operating income:
Electric . . . . . . . . . . 8,711 9,315 29,916 31,464
Natural gas distribution . . 5,673 6,090 4,313 6,671
Natural gas transmission . . 6,760 10,614 16,254 24,891
Mining and construction
materials. . . . . . . . . 1,651 2,777 15,858 10,816
Oil and natural gas production . . 1,720 2,742 10,728 10,972
24,515 31,538 77,069 84,814
Other income -- net. . . . . . 928 (176) 4,981 (867)
Interest expense -- net. . . . 6,538 6,163 25,648 25,007
Carrying costs on natural gas
repurchase commitment. . . . 909 841 3,965 5,116
Income before taxes. . . . . . 17,996 24,358 52,437 53,824
Income taxes . . . . . . . . . 6,297 8,597 17,682 14,132
Income before cumulative
effect of accounting change. 11,699 15,761 34,755 39,692
Cumulative effect of accounting
change (Note 2). . . . . . . --- 5,521 --- 5,521
Net income . . . . . . . . . . 11,699 21,282 34,755 45,213
Dividends on preferred stocks. 200 201 801 806
Earnings on common stock . . . $11,499 $21,081 $33,954 $44,407
Earnings per common share:
Earnings before cumulative
effect of accounting change. . $ .61 $ .82 $ 1.79 $ 2.05
Cumulative effect of
accounting change. . . . . --- .29 --- .29
Earnings . . . . . . . . . . $ .61 $ 1.11 $ 1.79 $ 2.34
Dividends per common share . . $ .39 $ .37 $ 1.54 $ 1.47
Average common shares
outstanding. . . . . . . . . 18,985 18,985 18,985 18,985
Pro forma amounts
assuming retroactive application
of accounting change:
Net income . . . . . . . . . $11,699 $15,761 $34,755 $41,281
Earnings per common share. . $ .61 $ .82 $ 1.79 $ 2.13
The accompanying notes are an integral
part of these statements.<PAGE>
MDU RESOURCES GROUP, INC.
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
March 31, March 31, December
1994 1993 31, 1993
(In thousands)
ASSETS
Property, plant and equipment:
Electric. . . . . . . . . . . . . . $ 505,615 $ 492,492 $ 503,690
Natural gas distribution. . . . . . 151,859 127,373 141,100
Natural gas transmission. . . . . . 253,894 279,690 258,766
Mining and construction materials . 145,872 105,653 145,014
Oil and natural gas production. . . 120,815 94,733 116,833
1,178,055 1,099,941 1,165,403
Less accumulated depreciation,
depletion and amortization. . . . 512,935 479,342 501,451
665,120 620,599 663,952
Current assets:
Cash and cash equivalents . . . . . 96,547 96,686 71,699
Receivables . . . . . . . . . . . . 57,286 57,082 67,553
Inventories . . . . . . . . . . . . 20,737 13,792 19,415
Exchange natural gas receivable . . 169 25,213 727
Deferred income taxes . . . . . . . 39,259 27,673 32,243
Other prepayments and current
assets. . . . . . . . . . . . . . 8,895 6,627 13,535
222,893 227,073 205,172
Natural gas available under
repurchase commitment . . . . . . . 74,406 87,018 79,031
Investments. . . . . . . . . . . . . 18,645 61,854 16,858
Deferred charges and other assets. . 69,947 41,710 76,038
$1,051,011 $1,038,254 $1,041,051
CAPITALIZATION AND LIABILITIES
Capitalization:
Common stock (Shares outstanding --
18,984,654 at March 31, 1994
and 1993 and December 31, 1993) . $ 94,923 $ 94,923 $ 94,923
Other paid in capital . . . . . . . 64,210 64,210 64,210
Retained earnings . . . . . . . . . 163,093 158,376 158,998
322,226 317,509 318,131
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. . . . . . . . . . . 221,077 233,751 231,770
560,403 568,460 567,001
Commitments and contingencies --- --- ---
Current liabilities:
Short-term borrowings . . . . . . . 750 1,700 9,540
Accounts payable. . . . . . . . . . 23,351 17,091 24,967
Taxes payable . . . . . . . . . . . 22,936 25,702 9,204
Other accrued liabilities,
including reserved revenues . . . 125,942 103,769 105,195
Exchange natural gas deliverable. . 762 24,902 2,371
Dividends payable . . . . . . . . . 7,603 7,225 7,605
Long-term debt and preferred
stock due within one year . . . . 15,400 300 15,300
196,744 180,689 174,182
Natural gas repurchase commitment. . 92,759 108,482 98,525
Deferred credits:
Deferred income taxes and unamortized
investment tax credit . . . . . . 123,343 107,884 124,978
Other . . . . . . . . . . . . . . . 77,762 72,739 76,365
201,105 180,623 201,343
$1,051,011 $1,038,254 $1,041,051
The accompanying notes are an integral part of these statements.<PAGE>
MDU RESOURCES GROUP, INC.
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Three Months Ended
March 31,
1994 1993
(In thousands)
Operating activities:
Net income . . . . . . . . . . . . . . . . . . . $11,699 $21,282
Cumulative effect of accounting change . . . . . --- (5,521)
Adjustments to reconcile net income to net cash
provided by operations:
Depreciation, depletion and amortization . . . 11,720 10,962
Deferred income taxes and investment tax
credit -- net . . (243) (1,520)
Recovery of deferred natural gas contract litigation
settlement costs, net of income taxes. . . . 2,202 1,519
Changes in current assets and liabilities --
Receivables. . . . . . . . . . . . . . . . . 10,267 9,696
Inventories. . . . . . . . . . . . . . . . . (1,322) 4,422
Other current assets . . . . . . . . . . . . (1,818) (54)
Accounts payable . . . . . . . . . . . . . . (1,616) (8,306)
Other current liabilities. . . . . . . . . . 32,868 29,063
Other noncurrent changes . . . . . . . . . . . 4,542 7,309
Net cash provided by operating activities . . . . 68,299 68,852
Financing activities:
Net change in short-term borrowings. . . . . . . (8,790) (6,075)
Issuance of long-term debt . . . . . . . . . . . 950 600
Repayment of long-term debt. . . . . . . . . . . (11,550) (16,700)
Retirement of natural gas repurchase commitment. (5,766) (6,455)
Dividends paid . . . . . . . . . . . . . . . . . (7,604) (7,225)
Net cash used in financing activities. . . . . . (32,760) (35,855)
Investing activities:
Additions to property, plant and equipment --
Electric . . . . . . . . . . . . . . . . . . . (2,384) (1,950)
Natural gas distribution . . . . . . . . . . . (11,065) (1,609)
Natural gas transmission . . . . . . . . . . . 4,809 (839)
Mining and construction materials. . . . . . . (878) (1,282)
Oil and natural gas production . . . . . . . . (4,011) (2,569)
(13,529) (8,249)
Sale of natural gas available under repurchase
commitment . . . . . . . . . . . . . . . . . . 4,625 5,020
Investments. . . . . . . . . . . . . . . . . . . (1,787) 80
Net cash used in investing activities. . . . . . (10,691) (3,149)
Increase in cash and cash equivalents. . . . . . 24,848 29,848
Cash and cash equivalents -- beginning of year . 71,699 66,838
Cash and cash equivalents -- end of period . . . $96,547 $ 96,686
The accompanying notes are an integral
part of these statements.<PAGE>
MDU RESOURCES GROUP, INC.
NOTES TO CONDENSED CONSOLIDATED
FINANCIAL STATEMENTS
March 31, 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
March 31, 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 March 31, 1994 and 1993.
4. Pending litigation
In May 1991, KN Energy, Inc. (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
alleges, 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 alleges that Williston Basin is 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 has 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 are 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. If the FERC is not able to
ultimately resolve this dispute, both KN and Williston Basin can
request reconsideration by the Court at that time. As of the
present time, KN has not requested further action by the FERC.
Although no assurances can be provided, based on previous FERC
decisions, Williston Basin believes that the ultimate outcome
of this matter will not be material to its financial position
or results of operations.
5. Regulatory matters and revenues subject to refund
General Rate Proceedings --
Williston Basin has pending two general natural gas rate change
applications filed in 1989 and 1992 and has implemented these
changed rates subject to refund. On May 3, 1994, the FERC
issued an Order relating to the 1989 rate change which Williston
Basin is currently evaluating. Williston Basin is awaiting a
final order from the FERC on the 1992 rate change.
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 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 the
outcome of future hearings in mid-1994.
Order 636 --
As more fully described in 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 March 31, 1994, 15.3 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 45.5 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 has filed an administrative
appeal with the MMS on this issue stating the gas was properly
valued for royalty purposes. Williston Basin also believes that
the statute of limitations limits this claim. Williston Basin
is pursuing these issues before both the MMS and the courts.
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 March 31, 1994, to address this
situation aggregated approximately $755,000. 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:
Three Months Ended
March 31,
1994 1993
(In thousands)
Interest, net of amount capitalized $6,716 $6,722
Income taxes $ 589 $ 614
The Company considers all highly liquid investments purchased
with an original maturity of three months or less to be cash
equivalents.
During the three month period ended March 31, 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.<PAGE>
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 Twelve Months
Ended Ended
March 31, March 31,
1994 1993 Business 1994 1993
Utility --
$ 3.7 $ 4.1 Electric $12.3 $ 13.8
3.1 3.1 Natural gas 1.1 2.7
6.8 7.2 13.4 16.5
2.3 4.7 Natural gas transmission 2.4 6.3
1.4 2.4 Mining and construction materials 11.4 9.8
1.0 1.3 Oil and natural gas production 6.8 6.3
$11.5 $ 15.6 Earnings on common stock $34.0 $ 38.9
$ .61 $ .82 Earnings per common share $1.79 $ 2.05
Return on average common equity 10.7% 12.9%
Earnings information for the twelve months ended March 31, 1993,
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 March 31, 1994 and 1993
Consolidated earnings for the three months ended March 31,
1994, decreased $4.1 million when compared to the corresponding
period a year ago. Decreased earnings from all operating segments,
with the exception of the natural gas distribution business which
was essentially unchanged, produced the decline in consolidated
earnings. The reasons for such changes are described in the three
months discussions which follow.
Twelve Months Ended March 31, 1994 and 1993
Consolidated earnings for 1994 are down $4.9 million from the
$38.9 million earned in 1993. The decline was the result of
decreased earnings in the utility and natural gas transmission
businesses, partially offset by increased mining and construction
materials, and oil and natural gas production earnings. The
reasons for such changes are described in the twelve month
discussions which follow.
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) are key
financial and operating statistics for each of the Company's
business units.
Montana-Dakota -- Electric Operations
Three Months Twelve Months
Ended Ended
March 31, March 31,
1994 1993 1994 1993
$35.8 $ 34.6 Operating revenues $132.3 $126.5
11.4 10.5 Fuel and purchased power 42.2 39.1
10.0 9.2 Operation and maintenance expenses 38.2 34.5
8.7 9.3 Operating income 29.9 31.4
525.6 508.9 Retail sales (kWh) 1,910.5 1,861.8
127.6 111.5 Power deliveries to MAPP (kWh) 527.1 385.8
Cost of fuel and purchased power
$.016 $ .016 per kWh $.016 $ .016
Montana-Dakota -- Gas Distribution Operations
Three Months Twelve Months
Ended Ended
March 31, March 31,
1994 1993 1994 1993
Operating revenues:
$68.5 $ 61.8 Sales $158.4 $137.5
1.1 1.4 Transportation & other 4.0 4.6
53.9 48.1 Purchased natural gas sold 119.8 101.2
7.5 6.8 Operation and maintenance expenses 29.2 26.0
5.7 6.1 Operating income 4.3 6.7
Volumes (dk):
14.4 13.5 Sales 32.1 29.4
2.9 4.2 Transportation 11.4 14.2
17.3 17.7 Total throughput 43.5 43.6
103.0% 104.9% Degree days (% of normal) 104.6% 106.0%
$3.74 $ 3.57 Cost of natural gas per dk $3.74 $ 3.45
Williston Basin
Three Months Twelve Months
Ended Ended
March 31, March 31,
1994 1993 1994 1993
Operating revenues:
$ --- $ 25.7* Sales for resale $25.5* $ 62.0*
20.8* 10.8* Transportation & other 50.0* 36.4*
--- 14.4 Purchased natural gas sold 6.2 31.1
11.2** 8.5** Operation and maintenance expenses 41.6** 31.2**
6.7 10.6 Operating income 16.3 24.9
Volumes (dk):
Sales for resale--
--- 8.8 Montana-Dakota 4.1 18.1
--- .2 Other .1 .3
Transportation--
17.3 9.0 Montana-Dakota 35.6 27.2
6.9 10.6 Other 28.4 38.8
24.2 28.6 Total throughput 68.2 84.4
*Includes recovery in millions as follows:
Deferred natural gas contract
$ 3.5 $ 2.0 buy-out/buy-down costs $14.2 $ 5.8
**Includes amortization in millions as follows:
Deferred natural gas contract
$ 3.6 $ 2.0 buy-out/buy-down costs $13.4 $ 5.8
Knife River
Three Months Twelve Months
Ended Ended
March 31, March 31,
1994 1993 1994 1993
Operating revenues:
$12.8 $ 11.5 Coal $45.5 $ 43.6
7.1 .3 Construction materials 53.0 1.5
14.2 6.2 Operation and maintenance expenses 67.7 22.1
1.0 .7 Reclamation expense 3.4 2.9
1.2 1.1 Severance taxes 4.5 4.3
1.7 2.8 Operating income 15.9 10.8
Sales (000's):
1,431 1,311 Coal (tons) 5,186 4,961
276 53 Aggregates (tons) 2,614 316
52 --- Ready-mixed concrete (cubic yards) 209 ---
17 --- Asphalt (tons) 158 ---
Fidelity Oil
Three Months Twelve Months
Ended Ended
March 31, March 31,
1994 1993 1994 1993
$ 8.6 $ 9.7 Operating revenues $38.0 $ 36.1
3.0 3.0 Operation and maintenance expenses 11.6 11.9
Depreciation, depletion and
3.1 3.1 amortization 12.1 9.7
1.7 2.7 Operating income 10.7 11.0
Production (000's):
370 366 Oil (barrels) 1,501 1,532
2,144 1,960 Natural gas (Mcf) 9,001 5,840
Average sales price:
$10.85 $15.66 Oil (per barrel) $13.67 $16.79
2.09 1.98 Natural gas (per Mcf) 1.89 1.70
Three Months Ended March 31, 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 purchase of an additional five megawatts of firm capacity
through a participation power contract. Also, higher operation
expense, primarily employee benefit-related costs, and increased
depreciation expense negatively affected operating income.
Partially mitigating the operating income decline were increased
retail sales to residential and small commercial and industrial
markets, the result of the addition of over 450 customers and
increased demand, and increased large industrial sales, primarily
to a coal mining company and an abrasives manufacturer. Also
offsetting the operating income decline was an increase in
deliveries into the Mid-Continent Area Power Pool (MAPP), the
result of two electric utilities purchasing power during electric
generating station outages. Earnings from this business decreased
due to the aforementioned changes in operating income.
Montana-Dakota -- Natural Gas Distribution Operations
Operating income decreased during the first quarter as a result
of lower volumes transported to two oil refineries due to these
customers bypassing Montana-Dakota's distribution facilities.
Higher operation expenses, stemming from employee-benefit related
costs and sales expenses due to the system expansion into north-
central South Dakota, and increased depreciation expense also
decreased operating income. Partially mitigating the operating
income decline were the benefits of general rate relief realized in
North Dakota, South Dakota and Wyoming, and increased sales due to
the addition of over 4,700 new customers. Gas distribution
earnings were unchanged due to the aforementioned operating income
decline and increased carrying costs being accrued on natural gas
costs refundable through rate adjustments offset by the return
earned on the natural gas storage inventory (included in Other
Income--Net).
Williston Basin
The decline in operating income reflects decreased net
throughput, primarily lower transportation to off-system markets.
Decreased margins realized due to the timing of revenues now being
realized under the Order 636 rate structure implemented in November
1993, negatively affected 1994 first quarter earnings. 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, is generally expected to result in lower natural gas
transmission earnings during the higher volume winter heating
season than have been realized in the past, but should produce
higher earnings during the lower volume summer months. A January
1994 rate change due to a rate stipulation agreement with the FERC,
improved company production volumes at higher rates and decreased
depreciation expense partially offset the decline in operating
income. Natural gas transmission earnings decreased due to the
aforementioned changes in operating income offset in part by
decreased interest expense, the result of long-term debt
refinancing in 1993, and increased interest being accrued on
deferred buy-out/buy-down costs and gas supply realignment
transition costs.
Knife River
Operating income declined due to seasonal losses experienced at
the Alaska and Oregon construction materials businesses which were
acquired in April and September 1993, respectively. Operations of
these businesses are very seasonal whereby operating losses are
generally incurred during the winter months with significantly
higher revenues being realized during the spring and summer
construction season. Inasmuch as these two business units were
acquired subsequent to the 1993 first quarter, 1993 first quarter
results did not reflect the traditional seasonal losses from these
newly acquired businesses. Improved coal sales at all mines, the
result of increased demand by electric generation customers, at
higher prices combined with increased sales at the California
construction materials operations were somewhat offset by volume-
related increases in operating expenses. Earnings for this
business declined as a result of the operating income changes
discussed above and decreased investment income (included in Other
Income - Net), largely 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 lower average oil prices. Partially
offsetting this decline was increased natural gas production and
average prices. A volume-related increase in operating costs was
more than offset by lower per unit costs. The aforementioned
changes in operating income produced the earnings decline for this
business.
Twelve Months Ended March 31, 1994 and 1993
Montana-Dakota--Electric Operations
Operating income for the electric business declined due to
higher operation and maintenance expenses. Employee benefit-
related costs increased operation expense while higher costs
associated with repairs made at the Heskett, Big Stone and Coyote
stations accounted for the increase in maintenance expense.
Increased fuel and purchased power costs, largely higher demand
charges associated with the purchase of an additional five
megawatts of firm capacity through a participation power contract,
and increased depreciation expense also negatively affected
operating income. Somewhat offsetting the decline in operating
income was an improvement in retail sales to residential,
commercial and industrial markets, primarily due to the addition of
over 460 customers and increased demand. Also, improving operating
income was 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 as a result of the
above-mentioned operating income decline, a decrease in Other
Income--Net, reflecting the on-going effects of adopting SFAS No.
106, and increased federal income taxes. A decrease in interest
expense due to lower interest rates stemming from long-term debt
refinancing in the 1993 period and lower average short-term
borrowings and interest rates, somewhat offset the earnings
decline.
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, were the significant
factors reducing operating income for the natural gas distribution
business. Also, lower average transportation rates and lower
throughput to industrial customers, the refinement of the estimated
amount of delivered but unbilled natural gas volumes in the 1993
period, and increased depreciation expense and taxes other than
income reduced operating income. Sales increases, due to the
addition of over 4,000 residential and commercial customers,
combined with general rate relief realized in North Dakota,
South Dakota and Wyoming partially mitigated the operating
income decline. Gas distribution earnings were down due to the
aforementioned operating income change and 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 natural gas storage inventory and increased
interest income earned on natural gas costs recoverable through
rate adjustments in Montana, reduced the earnings decline.
Williston Basin
Operating income declined at the natural gas transmission
business as a result of 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 additional reserves
provided relating to the Koch settlement, increased transmission
expenses and higher employee benefit-related costs. Largely
offsetting the increased operation expenses are an out-of-period
adjustment to take-or-pay surcharge amortizations and a late 1992
accrual for retroactive company production royalties. An
adjustment to regulatory reserves reflected in operating revenues
offset the effects of the additional reserves provided for the Koch
settlement. 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 increased production
and higher average prices. Earnings for this business unit
decreased due to the aforementioned operating income decline offset
in part by reduced interest expense on long-term debt, the result
of debt refinancing in mid-1993, and lower carrying costs
associated with the natural gas repurchase commitment, primarily
the result of both lower borrowings, due to the continuing sale of
this gas, and decreased average rates.
Knife River
Operating income increased due to the inclusion of sales at 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. Lower
selling prices at the Gascoyne Mine, effective June 1, 1992,
following an amendment to the current coal supply agreement, were
largely offset by higher prices at the Beulah Mine. An increase in
operating expenses attributable to the newly acquired construction
materials businesses and a volume-related increase in coal
operating expenses, combined with the accrual of SFAS No. 106
costs, increased reclamation expense and increased stripping
expense at the Beulah Mine, due to higher overburden removal costs,
also 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 slightly as a result of a decline in oil production and
prices and a production-related increase in depreciation, depletion
and amortization. Partially offsetting the operating income
decline were higher natural gas production and prices and decreased
operation and maintenance expenses per equivalent barrel, somewhat
offset by volume-related increases in such costs. 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 is extending natural gas service to 11 north
central South Dakota communities at an estimated cost of $9.0
million. This extension has the potential of adding approximately
1.6 MMdk to annual natural gas sales. Service to seven communities
began in late 1993 with plans to provide service to the remaining
four communities, as well as surveys to determine feasibility in
neighboring communities, scheduled for 1994.
See Items 1 and 2 of the 1993 Form 10-K for both Montana-Dakota
and Williston Basin for additional information related to the
FERC's Order 636, which requires fundamental changes in the way
natural gas pipelines do business. Williston Basin, based on a
September 1993, FERC order, implemented Order 636 on November 1,
1993. 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.
See Items 1 and 2 of the 1993 Form 10-K for Williston Basin for
a further discussion on Williston Basin's construction of a 49-mile
pipeline in eastern North Dakota and Williston Basin's
interconnection in northwestern North Dakota with a Canadian
pipeline. Williston Basin continues to evaluate certain
opportunities which may exist to increase transportation and
storage services through system expansion or interconnections.
In late 1992 and early 1993 two major transportation customers,
Koch and Amerada, bypassed Williston Basin's transportation system.
See Items 1 and 2 of the 1993 Form 10-K under Williston Basin for
a further discussion of these system bypasses.
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.
Montana-Dakota and Williston Basin filed suit against Rockwell
International Corporation to recover any costs which may be
associated with the presence of polychlorinated biphenyls in
portions of their natural gas distribution and transmission
systems. See Note 9 and Items 1 and 2 of the 1993 Form 10-K under
Montana-Dakota and Williston Basin for a discussion of this and
other environmental matters.
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.
Under the legislation, the state will forego its 50 percent share
of severance taxes for coal shipped out of state after July 1,
1995, and local political subdivisions are given the option to
forego their 35 percent of the tax. The legislation passed both
House and Senate with strong support and was signed by the
governor. This tax relief will help keep the price of Gascoyne
coal competitive.
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.
Future cash flows and operating income from oil and natural gas
production and reserves are influenced by fluctuations in sales
prices as well as the cost of acquiring, finding and producing
those reserves. Although Fidelity Oil continues to acquire,
develop and explore for oil and natural gas reserves, no assurances
can be made as to the future net cash flows from those operations.
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. A decision on this matter is
pending.
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, $20 million of which is outstanding
at March 31, 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 March 31, 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 settlement provided that Williston Basin make an
immediate cash payment to Koch of $40 million and to transfer to
Koch certain natural gas gathering facilities owned by Williston
Basin having a cost, net of accumulated depreciation, of
approximately $10.4 million. 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.
In March and May 1993, Williston Basin was directed by the MMS
to pay approximately $3.5 million, plus interest, in claimed
royalty underpayments for the period December 1, 1978, through
February 29, 1988. In December 1993, Williston Basin also received
an assessment from the MDR claiming additional production taxes due
of $3.7 million, plus interest, for 1988 through 1991 production.
See Notes 7 and 8 and Items 1 and 2 in the 1993 Form 10-K under
Williston Basin for a further discussion of Williston Basin's
appeal efforts in these matters.
Knife River's capital needs of $4.5 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 $1.1
million outstanding at March 31, 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 a $5 million line of
credit, $750,000 of which is outstanding at March 31, 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 March 31, 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 March 31, 1994, the Company could have issued
approximately $127 million of additional first mortgage bonds.
The Company's coverage of fixed charges including preferred
dividends was 2.7 times for twelve months ended March 31, 1994 and
3.0 times for the year 1993. Additionally, the Company's first
mortgage bond interest coverage was 3.3 times for the twelve months
ended March 31, 1994, compared to 3.4 times in 1993. Stockholders'
equity as a percent of total capitalization was 58% and 56% at
March 31, 1994 and December 31, 1993, respectively.<PAGE>
PART II - OTHER INFORMATION
4. Results of Votes of Security Holders
The Company's Annual Meeting of Stockholders was held on
April 26, 1994. Three proposals were submitted to stockholders
as described in the Company's Proxy Statement dated March 7,
1994, and were voted upon and approved by stockholders at the
meeting. The table below briefly describes the proposals and
the results of the stockholder votes.
Shares
Against
Shares or Broker
For Withheld Abstentions Non-Votes
Proposal to elect four directors
for terms expiring in 1997:
San W. Orr, Jr. 16,245,650 231,386 --- ---
John A. Schuchart 16,243,017 234,019 --- ---
Homer A. Scott, Jr. 16,274,278 202,758 --- ---
Sister Thomas Welder, O.S.B. 16,221,978 255,058 --- ---
Proposal to amend Certificate of
Incorporation regarding stated
purposes and powers of Company 15,791,694 291,850 393,492 ---
Proposal to amend Certificate of
Incorporation to increase
number of authorized shares
of Common Stock and reduce
the par value 14,894,495 1,191,454 391,087 ---<PAGE>
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of
1934, the registrant has duly caused this report to be signed on
its behalf by the undersigned thereunto duly authorized.
MDU RESOURCES GROUP, INC.
DATE May 11, 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
