UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
X QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 1995
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 November 3, 1995:
28,476,981 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 255 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, north-central
California and the Hawaiian Islands.
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, Prairie Propane,
Inc., operates bulk propane facilities in
north-central and southeastern North Dakota.
<PAGE>
INDEX
Part I
Consolidated Statements of Income --
Three and Nine Months Ended September 30, 1995
and 1994
Consolidated Balance Sheets --
September 30, 1995 and 1994, and December 31, 1994
Consolidated Statements of Cash Flows --
Nine Months Ended September 30, 1995 and 1994
Notes to Consolidated Financial Statements
Management's Discussion and Analysis of Financial
Condition and Results of Operations
Part II
Signatures
Exhibit Index
Exhibit<PAGE>
MDU RESOURCES GROUP, INC.
CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
Three Months Nine Months
Ended Ended
September 30, September 30,
1995 1994 1995 1994
(In thousands, except per share amounts)
Operating revenues:
Electric. . . . . . . . . . . . . . . $ 34,780 $ 33,007 $100,290 $ 99,461
Natural gas . . . . . . . . . . . . . 28,083 23,327 119,129 117,330
Mining and construction
materials . . . . . . . . . . . . . 39,471 39,849 89,446 90,795
Oil and natural gas
production. . . . . . . . . . . . . 11,611 10,345 32,865 28,340
113,945 106,528 341,730 335,926
Operating expenses:
Fuel and purchased power. . . . . . . 10,684 10,224 31,330 32,052
Purchased natural gas sold. . . . . . 5,088 2,468 36,119 38,751
Operation and maintenance . . . . . . 56,980 56,480 153,098 152,347
Depreciation, depletion and
amortization. . . . . . . . . . . . 13,609 12,414 39,768 35,986
Taxes, other than income. . . . . . . 5,245 6,032 17,028 18,209
91,606 87,618 277,343 277,345
Operating income (loss):
Electric. . . . . . . . . . . . . . . 8,482 7,689 22,072 20,916
Natural gas distribution. . . . . . . (2,405) (3,871) 2,355 405
Natural gas transmission. . . . . . . 5,832 4,369 18,836 16,001
Mining and construction
materials . . . . . . . . . . . . . 7,332 8,053 12,404 14,743
Oil and natural gas
production. . . . . . . . . . . . . 3,098 2,670 8,720 6,516
22,339 18,910 64,387 58,581
Other income -- net . . . . . . . . . . 1,095 8,367 3,228 10,570
Interest expense. . . . . . . . . . . . 6,089 6,288 18,095 19,365
Carrying costs on natural gas
repurchase commitment . . . . . . . . 1,503 1,195 4,480 3,343
Income before taxes . . . . . . . . . . 15,842 19,794 45,040 46,443
Income taxes. . . . . . . . . . . . . . 5,370 7,443 15,634 16,716
Net income . . . . . . . . . . . . . . 10,472 12,351 29,406 29,727
Dividends on preferred stocks . . . . . 197 198 594 598
Earnings on common stock. . . . . . . . $ 10,275 $ 12,153 $ 28,812 $ 29,129
Earnings per common share . . . . . . . $ .36 $ .43 $ 1.01 $ 1.02
Dividends per common share. . . . . . . $ .27 $ .27 $ .81 $ .79
Average common shares
outstanding . . . . . . . . . . . . . 28,477 28,477 28,477 28,477
The accompanying notes are an integral part of these statements.<PAGE>
MDU RESOURCES GROUP, INC.
CONSOLIDATED BALANCE SHEETS
(Unaudited)
September 30, September 30, December 31,
1995 1994 1994
(In thousands)
ASSETS
Property, plant and equipment:
Electric. . . . . . . . . . . . . . . $ 530,633 $ 510,376 $ 514,152
Natural gas distribution. . . . . . . 163,658 159,081 157,174
Natural gas transmission. . . . . . . 270,781 261,547 263,971
Mining and construction materials . . 151,408 146,401 147,284
Oil and natural gas production. . . . 180,045 144,120 151,532
1,296,525 1,221,525 1,234,113
Less accumulated depreciation,
depletion and amortization. . . . . 586,488 532,599 541,842
710,037 688,926 692,271
Current assets:
Cash and cash equivalents . . . . . . 37,059 38,546 37,190
Receivables . . . . . . . . . . . . . 44,535 40,530 55,409
Inventories . . . . . . . . . . . . . 27,561 26,199 27,090
Deferred income taxes . . . . . . . . 28,611 24,043 26,694
Other prepayments and current assets. 12,172 9,488 12,287
149,938 138,806 158,670
Natural gas available under
repurchase commitment . . . . . . . . 70,750 73,013 70,913
Investments . . . . . . . . . . . . . . 45,650 15,693 16,914
Deferred charges and other assets . . . 60,283 67,573 65,950
$1,036,658 $ 984,011 $ 1,004,718
CAPITALIZATION AND LIABILITIES
Capitalization:
Common stock (Shares outstanding --
28,476,981, $3.33 par value at
September 30, 1995, 18,984,654,
$3.33 par value at September 30,
1994 and December 31, 1994). . . . $ 94,828 $ 63,219 $ 63,219
Other paid in capital . . . . . . . . 64,305 95,914 95,914
Retained earnings . . . . . . . . . . 173,914 165,724 168,050
333,047 324,857 327,183
Preferred stock subject to mandatory
redemption requirements . . . . . . 2,000 2,100 2,000
Preferred stock redeemable at option
of the Company. . . . . . . . . . . 15,000 15,000 15,000
Long-term debt. . . . . . . . . . . . 233,328 206,363 217,693
583,375 548,320 561,876
Commitments and contingencies . . . . . --- --- ---
Current liabilities:
Short-term borrowings . . . . . . . . 1,335 280 680
Accounts payable. . . . . . . . . . . 20,671 21,502 20,222
Taxes payable . . . . . . . . . . . . 12,872 3,867 8,817
Other accrued liabilities, including
reserved revenues . . . . . . . . . 91,200 80,519 88,516
Dividends payable . . . . . . . . . . 7,958 7,793 7,793
Long-term debt and preferred stock due
within one year . . . . . . . . . . 18,080 20,425 20,450
152,116 134,386 146,478
Natural gas repurchase commitment . . . 88,200 91,022 88,404
Deferred credits:
Deferred income taxes . . . . . . . . 116,466 116,446 114,341
Other . . . . . . . . . . . . . . . . 96,501 93,837 93,619
212,967 210,283 207,960
$1,036,658 $ 984,011 $ 1,004,718
The accompanying notes are an integral part of these statements.
<PAGE>
MDU RESOURCES GROUP, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Nine Months Ended
September 30,
1995 1994
(In thousands)
Operating activities:
Net income. . . . . . . . . . . . . . . . . . . . . . $ 29,406 $ 29,727
Adjustments to reconcile net income to net cash
provided by operations:
Depreciation, depletion and amortization . . . . . 39,768 35,986
Deferred income taxes and investment tax
credit--net . . . . . . . . . . . . . . . . . . 5,111 5,972
Recovery of deferred natural gas contract litigation
settlement costs, net of income taxes. . . . . . 5,939 6,022
Changes in current assets and liabilities --
Receivables. . . . . . . . . . . . . . . . . . . 10,874 27,023
Inventories. . . . . . . . . . . . . . . . . . . (471) (6,784)
Other current assets . . . . . . . . . . . . . . (1,802) 12,974
Accounts payable . . . . . . . . . . . . . . . . 449 (3,465)
Other current liabilities. . . . . . . . . . . . 6,904 (32,196)
Other noncurrent changes . . . . . . . . . . . . . 1,794 6,693
Net cash provided by operating activities . . . . . . 97,972 81,952
Financing activities:
Net change in short-term borrowings . . . . . . . . . 655 (9,260)
Issuance of long-term debt. . . . . . . . . . . . . . 31,160 25,900
Repayment of long-term debt . . . . . . . . . . . . . (17,910) (46,200)
Retirement of natural gas repurchase commitment . . . (204) (7,503)
Dividends paid. . . . . . . . . . . . . . . . . . . . (23,542) (23,001)
Net cash used in financing activities . . . . . . . . (9,841) (60,064)
Investing activities:
Additions to property, plant and equipment
and acquisitions of businesses --
Electric. . . . . . . . . . . . . . . . . . . . . (12,748) (8,218)
Natural gas distribution. . . . . . . . . . . . . (6,306) (19,363)
Natural gas transmission. . . . . . . . . . . . . (6,833) (3,341)
Mining and construction materials . . . . . . . . (36,114) (2,670)
Oil and natural gas production. . . . . . . . . . (28,688) (28,632)
(90,689) (62,224)
Sale of natural gas available under repurchase
commitment . . . . . . . . . . . . . . . . . . . . 163 6,018
Investments . . . . . . . . . . . . . . . . . . . . . 2,264 1,165
Net cash used in investing activities . . . . . . . . (88,262) (55,041)
Decrease in cash and cash equivalents . . . . . . . . (131) (33,153)
Cash and cash equivalents--beginning of year. . . . . 37,190 71,699
Cash and cash equivalents--end of period. . . . . . . $ 37,059 $ 38,546
The accompanying notes are an integral part of these statements.
<PAGE>
MDU RESOURCES GROUP, INC.
NOTES TO CONSOLIDATED
FINANCIAL STATEMENTS
September 30, 1995 and 1994
(Unaudited)
1. Basis of presentation
The accompanying consolidated interim financial statements
were prepared in conformity with the basis of presentation
reflected in the consolidated financial statements included in
the Annual Report to Stockholders for the year ended
December 31, 1994 (1994 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 1994 Annual Report. The information is
unaudited but includes all adjustments which are, in the opinion
of management, necessary for a fair presentation of the
accompanying consolidated interim financial statements.
2. Seasonality of operations
Some of the Company's operations are highly seasonal and
revenues from, and certain expenses for, such operations may
fluctuate significantly among quarterly periods. Accordingly,
the interim results may not be indicative of results for the
full fiscal year.
3. Common stock split
On August 17, 1995, the Company's Board of Directors approved
a three-for-two common stock split to be effected in the form
of a 50 percent common stock dividend. The additional shares
of common stock were distributed on October 13, 1995, to common
stockholders of record on September 27, 1995. All common stock
information appearing in the accompanying consolidated financial
statements has been restated to give retroactive effect to the
stock split. Additionally, preference share purchase rights
have been appropriately adjusted to reflect the effects of the
split.
4. Pending litigation
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 (Court) 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 from November 1, 1993, (the date when Williston Basin
implemented FERC Order 636 and abandoned its natural gas sales
merchant function, see "Order 636" contained in Note 3 of the
1994 Annual Report for a further discussion of Williston Basin's
implementation of Order 636) to mid-1996, the remaining period
of the contract.
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 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, allowed Moncrief to amend
its complaint to assert its new pricing theory under the
contract. Through the course of this action Moncrief has
submitted its damage calculations which total approximately $19
million or, under its alternative pricing theory, approximately
$39 million. On March 10, 1995, the Court issued a summary
judgment dismissing Moncrief's pricing theories and
substantially reducing Moncrief's claims. On May 31, 1995, the
United States Court of Appeals for the Tenth Circuit determined
not to hear, at that time, Moncrief's attempt to appeal the
summary judgment ruling. Trial is scheduled to begin January 8,
1996, with the District Court.
Moncrief's damage claims, in Williston Basin's opinion, are
grossly overstated. Williston Basin further believes it has
meritorious defenses and intends to defend vigorously 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
Williston Basin has pending with the Federal Energy
Regulatory Commission (FERC) a general natural gas rate change
application implemented in 1992. On July 25, 1995, the FERC
issued an order relating to Williston Basin's 1992 rate change
application. On August 24, 1995, Williston Basin filed, under
protest, tariff sheets in compliance with the FERC's order, with
rates to be effective September 1, 1995. Williston Basin
requested rehearing of certain issues addressed in the order
which is pending before FERC.
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 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.
6. Natural gas repurchase commitment
The Company has offered for sale since 1984 the inventoried
natural gas available under a repurchase commitment with
Frontier Gas Storage Company, as described in Note 4 of its 1994
Annual Report. As part of the corporate realignment effected
January 1, 1985, the Company agreed, pursuant to the settlement
approved by the FERC, to remove from rates the financing costs
associated with this natural gas.
The FERC has issued orders that have held that storage costs
should be allocated to this gas, prospectively beginning
May 1992, as opposed to being included in rates applicable to
Williston Basin's customers. These storage costs, as initially
allocated to the Frontier gas, approximated $2.1 million
annually and represent costs which Williston Basin may not
recover. This matter is currently on appeal. The issue
regarding the applicability of assessing storage charges to the
gas creates additional uncertainty as to the costs associated
with holding the gas.
Beginning in October 1992, as a result of prevailing natural
gas prices, Williston Basin began to sell and transport a
portion of the natural gas held under the repurchase commitment.
Through September 30, 1995, 17.6 MMdk of this natural gas had
been sold by Williston Basin for use by both on- and off-system
markets. Williston Basin will continue to aggressively market
the remaining 43.2 MMdk of this natural gas whenever market
conditions are favorable. In addition, it will continue to seek
long-term sales contracts.
7. 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. On January 31, 1994, Montana-
Dakota, Williston Basin and Rockwell International Corporation
(Rockwell), manufacturer of the valve sealant, reached an
agreement under which Rockwell will reimburse Montana-Dakota and
Williston Basin for a portion of certain remediation costs. On
the basis of findings to date, Montana-Dakota and Williston
Basin estimate that the 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. Both Montana-Dakota and Williston
Basin consider unreimbursed environmental remediation costs to
be recoverable through rates, since they are prudent costs
incurred in the ordinary course of business. Accordingly,
Montana-Dakota and Williston Basin have sought and will continue
to seek recovery of such costs through rate filings. Based on
the estimated cost of the remediation program and the expected
recovery from third parties and 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 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. 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.
8. 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 1991. In September 1991, the Company
received a notice of proposed deficiency 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 and
penalties. In 1992 and the first quarter of 1995, similar
notices of proposed deficiency were received for the years 1986
through 1988 and 1989 through 1991, respectively. 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 intends to contest vigorously the deficiencies
proposed by the IRS and, in that regard, has timely filed
protests for the 1983 through 1991 tax years contesting the
treatment proposed in the notices of proposed deficiency.
Although it is reasonably possible that the ultimate resolution
of such matters could result in a loss of up to approximately
$18 million in excess of consolidated reserves, management
believes the Company has meritorious defenses to mitigate or
eliminate the proposed deficiencies. In that regard, the
Company's outside 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.
9. Cash flow information
Cash expenditures for interest and income taxes were as
follows:
Nine Months Ended
September 30,
1995 1994
(In thousands)
Interest, net of amount capitalized $19,773 $18,748
Income taxes $11,910 $12,763
During the nine month period ended September 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.<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 Nine Months
Ended Ended
September 30, September 30,
Business 1995 1994 1995 1994
Electric $ 3.9 $ 3.3 $ 9.1 $ 8.2
Natural gas distribution (2.0) (3.0) (.3) (1.3)
Natural gas transmission 1.7 .9 6.6 4.6
Mining and construction
materials 5.1 5.1 8.8 9.8
Oil and natural gas production 1.6 5.9 4.6 7.8
Earnings on common stock $ 10.3 $ 12.2 $ 28.8 $ 29.1
Earnings per common share $ .36 $ .43 $ 1.01 $ 1.02
Return on average common
equity for the 12 months
ended 11.8% 13.1%
Earnings for the quarter ended September 30, 1995, were down
$1.9 million from the comparable period a year ago. The lower
earnings for 1995 were primarily the result of a $4.5 million gain
(after-tax) realized in the third quarter of 1994 related to the
sale of an equity investment in General Atlantic Resources, Inc.
(GARI). The effect of lower natural gas prices at the natural gas
transmission and oil and natural gas production businesses and
increased costs associated with weather-related construction delays
at the Alaska and Oregon construction materials operations also
contributed to the decrease in earnings. Increased electric sales,
higher throughput at the natural gas distribution and transmission
businesses, favorable rate changes at the natural gas distribution
business, higher oil and natural gas production at the oil and
natural gas production business, partially offset the earnings
decline.
Earnings for the nine months ended September 30, 1995, were down
$317,000 from the comparable period a year ago. The lower earnings
for 1995 were primarily the result of the gain realized on the sale
of the equity investment in GARI, as previously described.
Additionally, the effects of decreased natural gas prices at the
natural gas transmission and oil and natural gas production
businesses, and increased costs associated with weather-related
construction delays at the Alaska and Oregon construction materials
operations contributed to the decrease in earnings. Increased
sales at the electric business and increased throughput at the
natural gas distribution and transmission businesses, increased oil
prices and oil and natural gas production at the oil and natural
gas production business and benefits derived from favorable rate
changes at the natural gas distribution and transmission businesses
increased earnings. The favorable rate change at the natural gas
transmission business resulted from a FERC order received in
April 1995 on a rehearing request relating to a 1989 general rate
proceeding. The order allowed for the one-time billing of
customers for approximately $2.2 million (after-tax) to recover a
portion of the amount previously refunded in July 1994.
The 1.3 percent decline in the return on average common equity
for the 12 months ended September 30, 1995, when compared to the 12
months ended September 30, 1994, is due to a $3.1 million decline
in earnings due primarily to the gain realized on the sale of the
equity investment in GARI, as previously described.
_______________________
Reference should be made to Notes to Consolidated Financial
Statements for information concerning various commitments and
contingencies.
<PAGE>
Financial and operating data
The following tables (in millions, where applicable) are key
financial and operating statistics for each of the Company's
business units. Certain reclassifications have been made in the
following statistics for 1994 to conform to the 1995 presentation.
Such reclassifications had no effect on net income or common
stockholders' investment as previously reported.
Montana-Dakota -- Electric Operations
Three Months Nine Months
Ended Ended
September 30, September 30,
1995 1994 1995 1994
Operating revenues:
Retail sales $ 31.9 $ 30.7 $ 92.6 $ 91.9
Sales for resale and other 2.9 2.3 7.7 7.6
34.8 33.0 100.3 99.5
Operating expenses:
Fuel and purchased power 10.7 10.2 31.3 32.1
Operation and maintenance 9.9 9.5 29.3 29.5
Depreciation, depletion and
amortization 4.0 3.9 12.2 11.8
Taxes, other than income 1.7 1.7 5.4 5.2
26.3 25.3 78.2 78.6
Operating income 8.5 7.7 22.1 20.9
Retail sales (kWh) 507.8 484.5 1,479.0 1,457.3
Sales for resale (kWh) 98.0 85.0 302.8 296.3
Cost of fuel and purchased
power per kWh $ .016 $ .016 $ .016 $ .017
Montana-Dakota -- Natural Gas Distribution Operations
Three Months Nine Months
Ended Ended
September 30, September 30,
1995 1994 1995 1994
Operating revenues:
Sales $ 15.7 $ 13.7 $ 99.7 $ 105.7
Transportation and other .8 .7 2.6 2.6
16.5 14.4 102.3 108.3
Operating expenses:
Purchased natural gas sold 9.2 8.2 69.3 78.0
Operation and maintenance 7.0 7.6 22.5 22.4
Depreciation, depletion and
amortization 1.7 1.5 5.0 4.5
Taxes, other than income 1.0 1.0 3.1 3.0
18.9 18.3 99.9 107.9
Operating income (loss) (2.4) (3.9) 2.4 .4
Volumes (dk):
Sales 2.9 2.3 22.2 21.2
Transportation 2.1 1.6 7.6 6.2
Total throughput 5.0 3.9 29.8 27.4
Degree days (% of normal) 132.2% 83.7% 102.1% 99.0%
Cost of natural gas, including
transportation, per dk $ 3.18 $ 3.50 $ 3.13 $ 3.67<PAGE>
Williston Basin -- Natural Gas Transmission Operations
Three Months Nine Months
Ended Ended
September 30, September 30,
1995 1994 1995 1994
Operating revenues:
Transportation $ 12.2* $ 11.1* $ 41.9* $ 39.5*
Storage 3.1 2.5 9.0 7.4
Natural gas production and
other .9 1.5 3.5 6.0
16.2 15.1 54.4 52.9
Operating expenses:
Operation and maintenance 7.7* 8.1* 27.3* 28.7*
Depreciation, depletion and
amortization 1.8 1.6 5.3 4.9
Taxes, other than income .9 1.0 3.0 3.3
10.4 10.7 35.6 36.9
Operating income 5.8 4.4 18.8 16.0
Volumes (dk):
Transportation--
Montana-Dakota 7.3 5.0 26.9 25.4
Other 9.7 7.4 25.1 23.6
Total transportation 17.0 12.4 52.0 49.0
Produced (Mdk) 1,192 1,095 3,656 3,445
*Includes amortization and
related recovery of
deferred natural gas
contract buy-out/buy-down
and gas supply realignment
costs $ 2.5 $ 2.2 $ 9.4 $ 9.8
Knife River -- Mining and Construction Materials Operations
Three Months Nine Months
Ended Ended
September 30, September 30,
1995 1994 1995 1994
Operating revenues:
Coal $ 9.4 $ 11.1 $ 31.8 $ 33.4
Construction materials 30.0 28.7 57.6 57.4
39.4 39.8 89.4 90.8
Operating expenses:
Operation and maintenance 29.5 28.8 68.6 67.2
Depreciation, depletion and
amortization 1.6 1.7 4.8 4.9
Taxes, other than income 1.0 1.3 3.6 3.9
32.1 31.8 77.0 76.0
Operating income 7.3 8.0 12.4 14.8
Sales (000's):
Coal (tons) 977 1,220 3,469 3,823
Aggregates (tons) 1,166 938 2,245 2,155
Asphalt (tons) 179 189 317 314
Ready-mixed concrete
(cubic yards) 99 117 237 254<PAGE>
Fidelity Oil -- Oil and Natural Gas Production Operations
Three Months Nine Months
Ended Ended
September 30, September 30,
1995 1994 1995 1994
Operating revenues:
Natural gas $ 4.4 $ 4.3 $ 12.7 $ 13.2
Oil 7.2 6.1 20.2 15.1
11.6 10.4 32.9 28.3
Operating expenses:
Operation and maintenance 3.4 3.0 9.8 9.1
Depreciation, depletion and
amortization 4.5 3.7 12.4 9.9
Taxes, other than income .6 1.0 2.0 2.8
8.5 7.7 24.2 21.8
Operating income 3.1 2.7 8.7 6.5
Production (000's):
Natural gas (Mcf) 3,088 2,365 8,566 6,704
Oil (barrels) 472 404 1,307 1,160
Average sales price:
Natural gas (per Mcf) $ 1.43 $ 1.79 $ 1.48 $ 1.98
Oil (per barrel) 14.99 14.83 15.19 12.76
Amounts presented in the above tables for natural gas operating
revenues, purchased natural gas sold and operation and maintenance
expenses will not agree with the Consolidated Statements of Income due
to the elimination of intercompany transactions between Montana-
Dakota's natural gas distribution business and Williston Basin's
natural gas transmission business.
Three Months Ended September 30, 1995 and 1994
Montana-Dakota--Electric Operations
Operating income at the electric business increased primarily due
to higher retail sales and sales for resale revenue. Increased
average usage by residential and commercial customers, due to more
normal summer weather, and increased sales for resale at higher rates,
contributed to the revenue improvement. Reduced demand by oil
producers and refiners, contributed to a decline in industrial sales,
which somewhat offset the retail sales revenue improvement. Fuel and
purchased power costs increased due to increased volumes sold and
higher demand charges. The increase in demand costs, related to a
participation power contract, is the result of the purchase of an
additional five megawatts of capacity beginning in May 1995.
Increased maintenance expense, largely due to increased costs for
turbine, generator and boiler maintenance at the Heskett Station and
increased storm damage costs, partially offset the improvement in
operating income.
Earnings for the electric business improved due to the operating
income increase.
Montana-Dakota--Natural Gas Distribution Operations
Operating income at the natural gas distribution business improved
largely as a result of increased sales revenue and decreased operation
and maintenance expenses. The effect of general rate increases placed
into effect in North Dakota, South Dakota and Montana in late 1994
and increased sales volumes contributed to the sales revenue
improvement. However, the pass-through of lower average natural gas
costs partially offset the sales revenue increase. Transportation
revenues increased due to increased volumes transported, but were
somewhat offset by lower average rates. Lower operation and
maintenance expenses, primarily decreased payroll costs and decreased
sales expenses, further contributed to the improvement in operating
income.
Natural gas distribution earnings increased due to the operating
income improvement.
Williston Basin
Natural gas transmission operating income improved primarily due
to an increase in transportation and storage revenues. Increased
volumes transported to local distribution companies and to storage
added to the transportation revenue improvement. Higher demand
revenues associated with the storage enhancement project completed in
late 1994 contributed to the storage revenue improvement. Lower
operation and maintenance expenses, primarily lower production costs
and lower payroll-related costs, further contributed to the increase
in operating income. A decline in natural gas production revenue,
largely resulting from a 58 cent per decatherm decline in realized
natural gas prices, partially offset the increase in operating income.
Increased company production volumes partially offset the decline in
natural gas production revenue.
Earnings for this business increased primarily due to the
improvement in operating income, lower company production refunds
(included in Other Income -- Net) and lower interest expense. Lower
long-term debt interest expense, due to debt retirements and lower
rates, was partially offset by higher interest expense due to higher
reserved revenue balances contributing to the decrease in interest
expense. Increased carrying costs associated with the natural gas
repurchase commitment, due to higher average interest rates, partially
offset the earnings increase.
Knife River
Coal Operations --
Operating income for the coal operations decreased $366,000
primarily as a result of decreased coal revenues, due to lower coal
sales stemming from the Gascoyne Mine closure. The principal factor
contributing to the mine's closing was the expiration of the coal
contract with the Big Stone electric generating station in August.
Lower operation expenses, the result of lower sales volumes and lower
stripping and benefit-related costs at the Beulah and Savage mines,
partially offset the operating income decline. Decreased depreciation
expense, primarily due to lower depreciable plant balances, and lower
severance taxes, primarily due to lower volumes, also partially offset
the operating income decline.
Construction Materials Operations --
Construction materials operating income declined $355,000 primarily
due to higher operation expenses. Operation expenses increased
primarily due to increased work required to be performed by
subcontractors, largely caused by construction delays due to the
unusually wet weather. In addition, higher cost ready-mixed concrete
design requirements and higher delivery costs due to longer hauls, and
higher sales volumes further increased operation expenses. Increased
soil remediation volumes, but at lower prices, increased aggregate and
cement sales volumes, higher construction and aggregate delivery
revenue, and higher ready-mixed concrete prices, partially offset the
decline in operating income. Lower ready-mixed concrete sales volumes
partially offset the revenue improvement.
Consolidated --
Coal and construction materials earnings were unchanged from 1994,
due to higher other income, primarily from gains realized on the sale
of equipment due to the Gascoyne Mine closure, which was offset by the
decline in operating income.
Fidelity Oil
Operating income for the oil and natural gas production business
increased primarily as a result of higher oil revenues. Higher oil
production increased revenues by $1.0 million. Increased natural gas
production contributed $1.3 million to revenues but was largely offset
by a $1.1 million revenue decrease due to lower natural gas prices.
Decreased production taxes, stemming largely from the timing of
payments in 1995 as compared to 1994, further contributed to the
operating income improvement. Partially offsetting the operating
income improvement were increased operation expenses and depreciation,
depletion and amortization, primarily the result of increased
production.
Earnings for this business declined due to the 1994 realization of
a $4.5 million gain (after-tax) related to the sale of an equity
investment in GARI. Increased interest expense of $162,000, due
primarily to higher average borrowings, also added to the decline in
earnings. The earnings decrease was partially offset by the increase
in operating income.
Nine Months Ended September 30, 1995 and 1994
Montana-Dakota--Electric Operations
Operating income at the electric business increased primarily due
to higher retail sales revenues and lower fuel and purchased power
costs. Higher residential and commercial sales, primarily in the
third quarter, contributed to the revenue improvement. Lower large
industrial sales, as previously described in the three month's
discussion, partially offset the revenue improvement. Fuel and
purchased power costs decreased due to changes in generation mix
between lower cost versus higher cost generating stations, which were
partially offset by higher demand charges. The increase in demand
charges, related to a participation power contract, is the result of
the purchase of an additional five megawatts of capacity beginning
in May 1995, offset in part by the pass-through of periodic
maintenance charges during 1994. Decreased maintenance expenses at
the Coyote Station, due to less scheduled downtime, partially offset
by increased maintenance expenses at the Heskett Station, as
previously described in the three month's discussion, also improved
operating income. Increased depreciation expense, due to higher
depreciable plant balances, partially offset the increase in operating
income.
Earnings for the electric business improved due to the operating
income increase.
Montana-Dakota--Natural Gas Distribution Operations
Operating income increased at the natural gas distribution business
due to the effect of $1.9 million in general rate increases, as
previously described, and increased sales. The sales improvement
results from the addition of 5,200 customers and colder weather than
a year ago. The effects of a Wyoming Supreme Court order granting
recovery in 1994 of a prior refund made by Montana-Dakota and the
pass-through of lower average natural gas costs reduced revenues. The
effect of higher volumes transported were offset by lower average
transportation rates. Increased depreciation expense, due to higher
depreciable plant balances, partially offset the increase in operating
income.
Natural gas distribution earnings increased due to the improvement
in operating income. A decreased return recognized on net storage gas
inventory and demand balances partially offset the earnings increase.
This return decline of approximately $918,000 results from decreases
in the net book balance on which the natural gas distribution business
is allowed to earn a return.
Williston Basin
Operating income increased primarily due to an increase in
transportation and storage revenues. The transportation revenue
increase resulted primarily from the benefits of a favorable FERC
order received in April 1995 on a rehearing request relating to a 1989
general rate proceeding. The order allowed for the one-time billing
of customers for approximately $2.7 million ($1.7 million after-tax)
to recover a portion of the amount previously refunded in July 1994.
In addition, increased volumes transported to local distribution
companies and storage, somewhat offset by decreased transportation of
natural gas held under the repurchase commitment, added to the
transportation revenue improvement. Higher demand revenues associated
with the storage enhancement project completed in late 1994
contributed to the storage revenue improvement. Lower operation and
maintenance expenses, primarily lower production royalty expenses, and
lower taxes other than income, largely lower production taxes, further
contributed to the increase in operating income. A decline in company
production revenue, primarily due to a 66 cent per decatherm decline
in realized natural gas prices, somewhat reduced by increased volumes
produced, partially offset the increase in operating income.
Increased depreciation expense, resulting from higher depreciable
plant balances, also somewhat reduced the operating income
improvement.
Earnings for this business improved due primarily to the increase
in operating income, higher interest income, lower company production
refunds and lower interest expense. Higher interest income of
$952,000 ($583,000 after-tax) is related to the previously described
refund recovery. The decline in interest expense of $1.4 million is
primarily due to long-term debt retirements, lower rates and lower
reserved revenue balances. Increased carrying costs on the natural
gas repurchase commitment, due to higher average interest rates,
partially offset the earnings increase.
Knife River
Coal Operations --
Operating income for the coal operations decreased $887,000
primarily due to decreased coal revenues, primarily the result of
lower sales to the Big Stone Station due to the expiration of the coal
contract in August 1995. Higher revenues resulting from price
increases at the Beulah and Gascoyne mines and increased sales at the
Beulah Mine, partially offset the decline in coal revenues. The
higher sales at the Beulah Mine are due mainly to less scheduled
downtime this year at the Coyote Station. Lower operation expenses,
resulting primarily from lower sales volumes and lower benefit-related
costs, lower depreciation expense and lower taxes other than income
also partially offset the decline in operating income. Higher
stripping costs at the Beulah Mine and higher reclamation costs at the
Beulah and Gascoyne mines stemming from working in higher leveling
cost areas partially offset the decrease in operation expenses.
Construction Materials Operations --
Construction materials operating income declined $1.5 million
primarily due to higher operation and maintenance expenses.
Operation and maintenance expenses increased due primarily to the
timing of maintenance work, and additional work required to be
performed by subcontractors, due to construction delays caused by
unusually wet weather, and increased sales volumes. Increased
revenues due to increased soil remediation volumes, but at lower
prices, increased steel fabrication sales volumes at higher prices,
higher aggregate and cement sales volumes, increased construction and
aggregate delivery revenues, and higher ready-mixed concrete sales
prices, partially offset the operating income decline. Lower ready-
mixed concrete sales volumes partially offset the revenue improvement.
Consolidated --
Earnings decreased due to the decline in coal and construction
materials operating income. Increased other income, primarily from
the sale of equipment relating to the Gascoyne Mine closure, partially
offset the decline in earnings.
Fidelity Oil
Operating income for the oil and natural gas production business
increased primarily as a result of higher oil revenues, $3.2 million
of which was due to higher average oil prices, and $1.9 million of
which stemmed from increased production. Decreased natural gas prices
reduced natural gas revenues by $4.2 million but were largely offset
by a $3.7 million revenue improvement due to higher volumes produced.
Also adding to operating income were decreased production taxes,
stemming largely from the timing of payments in 1995 as compared to
1994. Operation expenses increased, as a result of higher production
but were somewhat offset by lower average production costs, partially
offsetting the operating income improvement. Also reducing operating
income was increased depreciation, depletion and amortization expense
largely due to higher production.
Earnings for this business declined due to gains realized on the
sale of an equity investment in GARI, as previously discussed, and
increased interest expense of $451,000, due primarily to higher
average borrowings. The increase in operating income partially offset
the earnings decrease.
Prospective Information
Each of the Company's businesses is subject to competition, varying
in both type and degree. See Items 1 and 2 in the 1994 Annual Report
on Form 10-K (1994 Form 10-K) for a further discussion of the effects
these competitive forces have on each of the Company's businesses.
The operating results of the Company's electric, natural gas
distribution, natural gas transmission, and mining and construction
materials businesses are, in varying degrees, influenced by the
weather as well as by the general economic conditions within their
respective market areas. Additionally, the ability to recover costs
through the regulatory process affects the operating results of the
Company's electric, natural gas distribution and natural gas
transmission businesses.
On June 30, 1995, Montana-Dakota filed a general natural gas rate
increase application with the Montana Public Service Commission (MPSC)
requesting an increase of $2.1 million or 4.4%. The MPSC has until
April 1, 1996, to issue an order. Also, on June 30, 1995, Williston
Basin filed a general rate increase application with the FERC
requesting an increase of $3.6 million or 6.55%, effective August 1,
1995. On July 27, 1995, the FERC issued an order suspending the
implementation of the increased rates, subject to refund, until
January 1, 1996.
In early 1995, Montana-Dakota, announced plans to close 45 district
offices throughout the four-state service territory during 1995 and
early 1996. These closings are part of the continuous improvement
program begun several years ago which, along with other changes, are
expected to result in a utility workforce reduction of nearly
10 percent. Through September 30, 1995, 38 district offices have been
closed. Additionally, two operating divisions were combined to
increase efficiency. The utility now operates from five division
centers, down from eight three years ago.
In September 1995, Knife River's construction materials subsidiary,
KRC Holdings, Inc., acquired a 50 percent interest in Hawaiian
Cement, which was previously owned by Lone Star Industries, Inc.
Hawaiian Cement is one of the largest construction materials suppliers
in Hawaii serving four of the islands. Hawaiian Cement's operations
include construction aggregate mining, ready mixed-concrete and cement
manufacturing and distribution. Hawaiian Cement, headquartered in
Honolulu, Hawaii, is a partnership which is also 50 percent owned by
Adelaide Brighton Cement of Adelaide, Australia.
Knife River continues to seek 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 March 1995, the Financial Accounting Standards Board issued
Statement of Financial Accounting Standards No. 121, "Accounting for
the Impairment of Long-Lived Assets and for Long-Lived Assets to Be
Disposed Of" (SFAS No. 121). SFAS No. 121 imposes stricter criteria
for assets, including regulatory assets, by requiring that such assets
be probable of future recovery at each balance sheet date. The
Company anticipates adopting SFAS No. 121 on January 1, 1996, and does
not expect that adoption will have a material affect on the Company's
financial position or results of operations. This conclusion may
change in the future depending on the extent to which recovery of the
Company's long-lived assets is influenced by an increasingly
competitive environment in the electric and natural gas industries.
FERC Rulemaking on Transmission Access --
On March 29, 1995, the FERC issued a Notice of Proposed Rulemaking
(NOPR) on Open Access Non-Discriminatory Transmission Services by
Public Utilities and Transmitting Utilities (FERC Docket No. RM95-8-
000) and a supplemental NOPR on Recovery of Stranded Costs (FERC
Docket No. RM94-7-001).
The rules proposed in the NOPR are intended to facilitate
competition among generators for sales to the bulk power supply
market. If adopted, the NOPR on open access transmission would
require public utilities under the Federal Power Act to file a generic
set of transmission tariff terms and conditions as set forth in the
rulemaking to provide open access to their transmission systems.
Previously, the FERC had not imposed on utilities a general obligation
to provide access to their transmission systems. In addition, each
public utility would also be required to establish separate rates for
its transmission and generation services for new wholesale service,
and to take transmission services (including ancillary services) under
the same tariffs that would be applicable to third-party users for all
of its new wholesale sales and purchases of energy.
The supplemental NOPR on stranded costs provides a basis for
recovery by regulated public utilities of legitimate and verifiable
stranded costs associated with exiting wholesale requirements
customers and retail customers who become unbundled wholesale
transmission customers of the utility. The FERC would provide public
utilities a mechanism for recovery of stranded costs that result from
municipalization, former retail customers becoming wholesale
customers, or the loss of a wholesale customer. The FERC will
consider allowing recovery of stranded investment costs associated
with retail wheeling only if a state regulatory commission lacks the
authority to consider that issue.
It is anticipated that the proposed rule may be modified and that
a final rule may take effect in early 1996. The Company is continuing
to evaluate the NOPR to determine its impact on the Company and its
customers, but cannot predict the outcome of this matter.
Liquidity and Capital Commitments
The Company's regulated businesses operated by Montana-Dakota
and Williston Basin estimate construction costs of approximately
$38.1 million for the year 1995. The Company's 1995 capital needs
to retire maturing long-term securities are estimated at $20.5
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, $18 million of which is outstanding
at September 30, 1995, 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 short-term lines of credit aggregating $35 million, none
of which is outstanding at September 30, 1995, 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. At September 30, 1995, $10.0 million is available
and outstanding under the term loan agreement.
Knife River's capital needs for 1995, including the Hawaiian
Cement acquisition, are estimated at $38.0 million and will be met
through funds on hand, funds generated from internal sources,
short-term lines of credit and a long-term revolving credit
agreement. Knife River has short-term lines of credit aggregating
$6 million, none of which is outstanding at September 30, 1995. In
addition, Knife River has a long-term revolving credit agreement of
$40 million, $25 million of which is outstanding at September 30,
1995. It is anticipated that funds required for future
acquisitions will be met primarily from a combination of long-term
debt and equity securities.
Fidelity Oil's 1995 capital needs related to its oil and natural
gas acquisition, development and exploration program, estimated at
$40.0 million, will be met through funds generated from internal
sources and long-term lines of credit aggregating $55 million. On
July 14, 1995, amounts available under the long-term lines of
credit were increased from $35 to $55 million. At September 30,
1995, $22 million is outstanding under the long-term lines of
credit.
See Note 8 for a discussion of notices of proposed deficiency
received from the IRS proposing substantial additional income
taxes. If the IRS position were upheld, the level of funds
required would be significant.
Prairielands' 1995 capital needs, estimated at $2.6 million,
will be met through funds generated internally and short-term lines
of credit aggregating $5.4 million, $1.3 million of which is
outstanding at September 30, 1995.
The Company utilizes its short-term lines of credit aggregating
$40 million 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 September 30, 1995, under the short-term 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 September 30, 1995, the Company could have issued
approximately $167 million of additional first mortgage bonds.
The Company's coverage of fixed charges including preferred
dividends was 2.8 and 2.9 times for the twelve months ended
September 30, 1995, and December 31, 1994, respectively.
Additionally, the Company's first mortgage bond interest coverage
was 3.7 and 3.3 times for the twelve months ended September 30,
1995, and December 31, 1994, respectively. Stockholders' equity as
a percent of total capitalization was 57% and 58% at September 30,
1995, and December 31, 1994, respectively.
PART II - OTHER INFORMATION
6. Exhibits and Reports on Form 8-K
a) Exhibits
(27) Financial Data Schedule
b) Reports on Form 8-K
None.<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 November 8, 1995 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
<PAGE>
EXHIBIT INDEX
Exhibit No.
(27) Financial Data Schedule
<TABLE> <S> <C>
<ARTICLE> UT
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM THE
CONSOLIDATED STATEMENTS OF INCOME, CONSOLIDATED BALANCE SHEETS AND CONSOLIDATED
STATEMENTS OF CASH FLOWS AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH
FINANCIAL STATEMENTS.
</LEGEND>
<CIK> 0000067716
<NAME> MDU RESOURCES GROUP INC.
<MULTIPLIER> 1000
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<S> <C>
<PERIOD-TYPE> 9-MOS
<FISCAL-YEAR-END> DEC-31-1995
<PERIOD-START> JAN-01-1995
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<COMMON> 94,828
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<TOTAL-COMMON-STOCKHOLDERS-EQ> 333,047
2,000
15,000
<LONG-TERM-DEBT-NET> 321,528
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<OTHER-OPERATING-EXPENSES> 277,343
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<EARNINGS-AVAILABLE-FOR-COMM> 28,812
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