MDU RESOURCES GROUP INC - 10-K Annual Report

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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
X ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 1993
OR
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the transition period from ______________ to ____________
Commission file number 1-3480
MDU Resources Group, Inc.
(Exact name of registrant as specified in its charter)
Delaware 41-0423660
(State or other jurisdiction of (I.R.S. Employer Identification No.)
incorporation or organization)
400 North Fourth Street 58501
Bismarck, North Dakota (Zip Code)
(Address of principal executive offices)
Registrant's telephone number, including area code: (701) 222-7900
Securities registered pursuant to Section 12(b) of the Act:
Title of each class Name of each exchange
Common Stock, par value $5 on which registered
and Preference Share Purchase Rights New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act:
Preferred Stock, par value $100
(Title of Class)
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 by check mark if disclosure of delinquent filers pursuant to
Item 405 of Regulation S-K is not contained herein, and will not be
contained, to the best of the Registrant's knowledge, in definitive
proxy or information statements incorporated by reference in Part III of
this Form 10-K or any amendment to this Form 10-K. X

State the aggregate market value of the voting stock held by
nonaffiliates of the registrant as of February 25, 1994: $569,540,000.

Indicate the number of shares outstanding of each of the Registrant's
classes of common stock, as of February 25, 1994: 18,984,654 shares.

DOCUMENTS INCORPORATED BY REFERENCE.
1. Pages 27 through 53 of the Annual Report to Stockholders for 1993,
incorporated in Part II, Items 6 and 8 of this Report.
2. Proxy Statement, dated March 7, 1994, incorporated in Part III,
Items 10, 11, 12 and 13 of this Report.

CONTENTS

PART I

Items 1 and 2 -- Business and Properties
General
Montana-Dakota Utilities Co.
Electric Generation, Transmission and Distribution
Retail Natural Gas and Propane Distribution
Williston Basin Interstate Pipeline Company
Knife River Coal Mining Company
Coal Operations
Construction Materials Operations
Consolidated Mining and Construction Materials
Operations
Fidelity Oil Group

Item 3 -- Legal Proceedings

Item 4 -- Submission of Matters to a Vote of
Security Holders

PART II

Item 5 -- Market for the Registrant's Common Stock and
Related Stockholder Matters

Item 6 -- Selected Financial Data

Item 7 -- Management's Discussion and Analysis of
Financial Condition and Results of Operations

Item 8 -- Financial Statements and Supplementary Data

Item 9 -- Change in and Disagreements with Accountants on
Accounting and Financial Disclosure

PART III

Item 10 -- Directors and Executive Officers of the
Registrant

Item 11 -- Executive Compensation

Item 12 -- Security Ownership of Certain Beneficial
Owners and Management

Item 13 -- Certain Relationships and Related
Transactions

PART IV

Item 14 -- Exhibits, Financial Statement Schedules and
Reports on Form 8-K

PART I

ITEMS 1 AND 2. BUSINESS AND PROPERTIES

General

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., operating bulk propane
facilities in southeastern North Dakota.

The significant industries within the Company's retail utility
service area consist of agriculture and the related processing of
agricultural products and energy-related activities such as oil and
natural gas production, oil refining, coal mining and electric
power generation.

Details applicable to the Company's continuing construction
program and the expansion of the Company's non-regulated mining and
construction materials, and oil and natural gas production
operations are discussed in the sections devoted to each business.
See Item 7 -- "Management's Discussion and Analysis of Financial
Condition and Results of Operations" for a discussion of "Liquidity
and Capital Commitments" and the anticipated level of funds to be
generated internally for these activities.

All of the Company's electric and natural gas distribution
properties, with certain exceptions, are subject to the lien of the
Indenture of Mortgage dated May 1, 1939, as supplemented and
amended, from the Company to The Bank of New York and W. T.
Cunningham, successor trustees.

As of December 31, 1993, the Company had 2,052 full-time
employees with 96 employed at MDU Resources Group, Inc., including
Fidelity Oil and Prairielands, 1,224 at Montana-Dakota, 271 at
Williston Basin and 461 at Knife River. Approximately 577 and 86
of the Montana-Dakota and Williston Basin employees, respectively,
are represented by the International Brotherhood of Electrical
Workers. Labor contracts with such employees are in effect through
August 1995, for Montana-Dakota and December 1994, for Williston
Basin. Knife River's coal operations have a labor contract through
August 1995, with the United Mine Workers of America, which
represents its hourly workforce approximating 136 employees. Knife
River's construction materials operations have eight labor
contracts covering 122 employees. These contracts have expiration
dates ranging from February 1994, to May 1997.

The financial results and data applicable to each of the
Company's business segments as well as their financing requirements
are set forth in Item 7 -- "Management's Discussion and Analysis of
Financial Condition and Results of Operations".

Any reference to the Company's Consolidated Financial
Statements and Notes thereto shall be to the Consolidated Financial
Statements and Notes thereto contained on pages 27 through 51 in
the Company's Annual Report to Stockholders for 1993 (Annual
Report), which are incorporated by reference herein.

ENERGY DISTRIBUTION OPERATIONS AND PROPERTY (MONTANA-DAKOTA)

Electric Generation, Transmission and Distribution

General --

Montana-Dakota provides electric service at retail, serving
over 110,000 residential, commercial, industrial and municipal
customers located in 176 communities and adjacent rural areas as of
December 31, 1993. The principal properties owned by Montana-
Dakota for use in its electric operations include interests in
seven electric generating stations, as further described under
"System Supply and Demand", and over 3,100 miles and 3,800 miles of
transmission lines and distribution lines, respectively. Montana-
Dakota has obtained and holds valid and existing franchises
authorizing it to conduct its electric operations in all of the
municipalities it serves where such franchises are required. As of
December 31, 1993, Montana-Dakota's net electric plant investment
approximated $276.1 million.

The electric operations of Montana-Dakota are subject to
regulation by the Federal Energy Regulatory Commission (FERC) under
provisions of the Federal Power Act with respect to the
transmission and sale of power at wholesale in interstate commerce,
interconnections with other utilities, the issuance of securities,
accounting and other matters. These operations, including retail
rates, service, accounting and, in certain cases, security
issuances are also subject to regulation by the public service
commissions of North Dakota, Montana, South Dakota and Wyoming.
The percentage of Montana-Dakota's 1993 electric utility retail
operating revenues by jurisdiction is as follows: North Dakota --
60%; Montana -- 23%; South Dakota -- 8% and Wyoming -- 9%.

System Supply and Demand --

Through an interconnected electric system, Montana-Dakota
serves markets in portions of the following states and their major
communities -- western North Dakota, including Bismarck, Dickinson
and Williston; eastern Montana, including Glendive and Miles City;
and northern South Dakota, including Mobridge. The interconnected
system consists of seven on-line electric generating stations
(including interests in the Big Stone Station and the Coyote
Station aggregating 22.7% and 25.0%, respectively) which have an
aggregate turbine nameplate rating attributable to Montana-Dakota's
interest of 393,488 Kilowatts (kW) and a total summer net
capability of 414,150 kW. The four principal generating stations
are steam-turbine generating units using lignite coal for fuel.
The nameplate rating for Montana-Dakota's ownership interest in
these four plants is 327,758 kW. The balance of Montana-Dakota's
interconnected system electric generating capability is supplied by
three combustion turbine peaking stations. Additionally, Montana-
Dakota has contracted to purchase ultimately up to 66,000 kW of
participation power from Basin Electric Power Cooperative (Basin)
(51,000 kW in 1993) for its interconnected system as described
herein. The following table sets forth details applicable to the
Company's electric generating stations:

Nameplate Summer 1993 Net
Generating Rating Capability Generation
Station Type (kW) (kW) (MWh)

North Dakota --
Coyote* Steam 103,647 106,500 666,355
Heskett Steam 86,000 102,000 434,292
Williston Combustion
Turbine 7,800 10,000 (29)**
South Dakota --
Big Stone* Steam 94,111 101,750 525,547

Montana --
Lewis & Clark Steam 44,000 43,800 233,104
Glendive Combustion
Turbine 34,780 30,100 7,051
Miles City Combustion
Turbine 23,150 20,000 4,420

393,488 414,150 1,870,740

*Reflects Montana-Dakota's ownership interest.
**Station use exceeded generation.

Virtually all of the current fuel requirements of Montana-
Dakota's principal generating stations are met with lignite coal
supplied by Knife River under various long-term contracts.

During the years ended December 31, 1989, through December 31,
1993, the average cost of lignite coal consumed, including freight,
per million British thermal units (Btu) at Montana-Dakota's
electric generating stations (including the Big Stone and Coyote
stations) in the interconnected system and the average cost per
ton, including freight, of the lignite coal so consumed was as
follows:

Years Ended December 31,
1993 1992 1991 1990 1989
Average cost of
lignite coal per
million Btu. . . . $.96 $.97 $.99 $.98 $1.00
Average cost of
lignite coal
per ton. . . . . . $12.78 $12.79 $13.06 $13.10 $13.22

In recent years, Knife River, in response to competitive
pressure, has reduced its coal prices at its mine locations, all of
which provide coal to Montana-Dakota. Most recently, Montana-
Dakota and Knife River entered into a new five-year coal sales
contract stipulating reduced coal prices for sales made from Knife
River's Savage Mine to the Lewis & Clark Station effective
January 1, 1993. This contract replaced an existing contract which
was to expire in September 1993. This reduction has allowed
Montana-Dakota to be more competitive in the Mid-Continent Area
Power Pool (MAPP).

The maximum electric peak demand experienced to date
attributable to sales to retail customers on the interconnected
system was 387,100 kW in July 1991. Due to an unseasonably cool
summer, the 1993 summer peak was only 350,300 kW. The summer peak,
assuming normal weather, was previously forecasted to have been
approximately 384,500 kW. Montana-Dakota's latest forecast for its
interconnected system indicates that its annual peak will continue
to occur during the summer and the peak demand growth rate through
1998 will approximate 1.8% annually. Kilowatt-hour (kWh) sales
would have increased approximately 1% annually during the most
recent five years and, on a normalized basis, Montana-Dakota's
latest forecast indicates that its sales growth rates through 1998
will approximate 1.7% annually. This moderate improvement in sales
is due, in part, to stabilized economic conditions and a recovery
from drought conditions which had prevailed for several years.

Montana-Dakota has a participation power contract through
October 31, 2006, with Basin for the ultimate purchase of up to
approximately 66,000 kW (14.8% of the unit's maximum net capacity)
from the Antelope Valley Station II, a lignite coal-fired
generating station located near Beulah, North Dakota. Currently
Montana-Dakota purchases 51,000 kW of such capacity and, under the
terms of the contract, Montana-Dakota will purchase, on an
incremental basis, an additional 5,000 kW of capacity each year for
the years 1994 through 1996 for a total of 66,000 kW annually for
the period 1996 through October 31, 2006.

Montana-Dakota anticipates having a summer capacity position
(after providing for the 15% MAPP reserve requirement) as follows:
1994 -- 13,000 kW reserve; 1995 -- 14,000 kW reserve; 1996 --
13,000 kW reserve; 1997 -- 6,000 kW reserve and 1998 --(3,000) kW
deficiency.

Montana-Dakota has major interconnections with its neighboring
utilities, all of whom are MAPP members, which it considers
adequate for coordinated planning, emergency assistance, exchange
of capacity and energy and power supply reliability.

Through a separate electric system (Sheridan System), Montana-
Dakota serves Sheridan, Wyoming and neighboring communities. That
system is supplied through an interconnection with Pacific Power &
Light Company under a long-term supply contract through the year
1996. The maximum peak demand experienced to date and attributable
to Montana-Dakota sales to retail consumers on that system was
approximately 46,600 kW and occurred in December 1983. Due to the
implementation of a peak shaving load management system, Montana-
Dakota estimates this annual peak will not be exceeded through
1995.

Montana-Dakota has in place an integrated resource plan which
is used in planning for a reliable future supply of electricity
which will coincide with anticipated customer demand. On the
supply side, Montana-Dakota currently estimates that it has
adequate capacity available through existing generating stations
and long-term firm purchase contracts until the late 1990s. At
that time, it is anticipated that Montana-Dakota will need to
construct a natural gas combustion turbine peaking station in order
to meet its interconnected system's peak demand requirements.
Emerging generation technologies and purchases from other sources,
if available, are alternatives which will be continually monitored
as supply options. On the demand side, Montana-Dakota currently
offers rate and other incentives to its customers designed to
promote conservation, load shifting and peak shaving efforts. The
development and evaluation of other economically feasible strategic
marketing programs continues. Montana-Dakota has filed, as
required pursuant to established filing requirements, its
integrated resource plan with the Montana and North Dakota public
service commissions.

Regulatory Matters --

The cost of coal purchased from Knife River for use at
Montana-Dakota's electric generating stations is subject to certain
recoverability limits established by the Montana, North Dakota and
South Dakota public service commissions. These limits allow for
the recovery of coal costs which are established based on the
commissions' determination of a reasonable return on equity for
Knife River's coal operations, regardless of the actual cost of
coal purchased. Although disallowances have occurred in the past,
such amounts have not been material to Montana-Dakota's electric
operations.

Fuel adjustment clauses contained in North Dakota and South
Dakota jurisdictional electric rate schedules and expedited rate
filing procedures in Wyoming allow Montana-Dakota to reflect
increases or decreases in fuel and purchased power costs (excluding
capacity costs) on a timely basis. As a result of a settlement
approved by the Wyoming Public Service Commission in late
November 1993, Montana-Dakota will be developing and implementing
a tariff for its Wyoming electric operations which will permit the
reflection of increases or decreases in capacity and load
management costs in its electric rates. Development and
implementation is anticipated to be completed by April 1, 1994. In
Montana (23% of electric revenues), such cost changes are
includible in general rate filings.

On April 30, 1993, Montana-Dakota filed a general electric rate
case with the Wyoming Public Service Commission (WPSC), requesting
an increase of $379,000, or 3.6 percent. On November 30, 1993,
Montana-Dakota and the WPSC reached a settlement of this proceeding
providing for an increase of $52,000, effective December 1, 1993,
and authorizing the capacity and load management tracking
mechanisms previously discussed.

As a result of a 1993 inquiry by the North Dakota Public
Service Commission (NDPSC) regarding the level of Montana-Dakota's
electric earnings, the NDPSC reconsidered its prior order in which
it had permitted deferral, for a limited time period, of additional
expenses related to the implementation by Montana-Dakota of
Statement of Financial Accounting Standards No. 106, "Employers'
Accounting for Postretirement Benefits Other Than Pensions" (SFAS
No. 106). On January 19, 1994, the NDPSC issued an order which
requires the expensing, commencing January 1, 1994, of the ongoing
SFAS No. 106 incremental expense estimated at approximately $1.0
million annually. The order further stated that the SFAS No. 106
costs deferred by Montana-Dakota in 1993 are expected to be
recoverable in future rates.

Capital Requirements --

The following schedule (in millions of dollars) summarizes the
1993 actual and 1994 through 1996 anticipated construction
expenditures applicable to Montana-Dakota's electric operations:

Estimated
Actual
1993 1994 1995 1996

Production . . . . . . . . . $ 5.1 $ 4.2 $ 4.0 $ 6.0
Transmission . . . . . . . . 2.0 1.9 4.8 3.4
Distribution, General
and Common . . . . . . . . 9.1 10.8 11.0 10.0
$16.2 $16.9 $19.8 $19.4

Environmental Matters --

Montana-Dakota's electric operations, are subject to extensive
federal, state and local laws and regulations providing for
environmental, air, water and solid waste pollution control; state
facility-siting regulations; zoning and planning regulations of
certain state and local authorities; federal health and safety
regulations and state hazard communication standards.

Montana-Dakota believes it is in substantial compliance with
all existing applicable regulations, including environmental
regulations, as well as all applicable permitting requirements.

Governmental regulations establishing environmental protection
standards are continually evolving. Therefore, the character,
scope, cost and availability of the measures which will permit
compliance with evolving laws or regulations, cannot now be
accurately predicted.

The Clean Air Act (Act) requires electric generating facilities
to reduce sulfur dioxide emissions by the year 2000 to a level not
exceeding 1.2 pounds per million Btu. Montana-Dakota's baseload
electric generating stations are lignite coal fired. All of these
stations, with the exception of the Big Stone Station, are equipped
with scrubbers or utilize an atmospheric fluidized bed combustion
boiler, which permits them to operate with emission levels less
than the 1.2 pounds per million Btu. Current assessments indicate
that the emissions requirement could be met at the Big Stone
Station through various alternatives including installation of a
sulfur scrubber, switching to lower sulfur ("compliance") coal,
utilization of processed or "clean" coal, or fuel blending.
Montana-Dakota is unable to predict which alternative may be used
or the costs that may be associated with each of the alternatives,
some of which may be substantial.

In addition, the Act will limit the amount of nitrous oxide
emissions, although the final rules as they relate to the majority
of Montana-Dakota's generating stations have not yet been
finalized. Accordingly, Montana-Dakota is unable to determine what
modifications may be necessary or the costs associated with any
changes which may be required.

Montana-Dakota incurred costs of approximately $1.9 million in
1993 for the installation of sulfur dioxide monitoring systems at
the Heskett and Lewis & Clark stations. Montana-Dakota does not
expect to incur any additional substantial expenditures related to
environmental facilities during 1994 through 1996, subject to
evolving regulations.

Retail Natural Gas and Propane Distribution

General --

Montana-Dakota sells natural gas at retail, serving over
186,000 residential, commercial and industrial customers located in
133 communities and adjacent rural areas as of December 31, 1993,
and provides natural gas transportation services to certain
customers on its system. These services are provided through a
natural gas distribution system aggregating over 3,800 miles. In
addition, Montana-Dakota sells propane at retail, serving over 600
residential and commercial customers in two small communities
through propane distribution systems aggregating 13 miles.
Montana-Dakota has obtained and holds valid and existing franchises
authorizing it to conduct natural gas and propane distribution
operations in all of the municipalities it serves where such
franchises are required. As of December 31, 1993, Montana-Dakota's
net gas and propane distribution plant investment approximated
$72.1 million.

The natural gas distribution operations of Montana-Dakota are
subject to regulation by the public service commissions of North
Dakota, Montana, South Dakota and Wyoming regarding retail rates,
service, accounting and, in certain instances, security issuances.
The percentage of Montana-Dakota's 1993 natural gas and propane
utility operating revenues by jurisdiction is as follows: North
Dakota -- 43%; Montana -- 32%; South Dakota -- 18% and Wyoming --
7%.

System Supply and Demand --

Montana-Dakota serves retail natural gas markets, consisting
principally of residential and firm commercial space and water
heating users, in portions of the following states and their major
communities -- North Dakota, including Bismarck, Dickinson,
Williston, Minot and Jamestown; eastern Montana, including
Billings, Glendive and Miles City; western and north-central South
Dakota, including Rapid City, Pierre and Mobridge; and northern
Wyoming, including Sheridan. In addition, propane distribution
services are provided to two small communities, one located in
eastern Montana and the other in southwestern North Dakota. These
markets are highly seasonal and volumes sold depend on weather
patterns.

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 million decatherms (MMdk) to annual natural gas sales. Service
to seven communities is complete, with service to the remaining
four communities, as well as surveys to determine feasibility of
service in neighboring communities, scheduled for 1994.

The following table reflects Montana-Dakota's natural gas and
propane sales and natural gas transportation volumes during the
last five years:

Years Ended December 31,
Retail Natural Gas 1993 1992 1991 1990 1989
and Propane Throughput Mdk (thousands of decatherms)

Sales:
Residential. . . . . .19,565 17,141 18,904 16,486 17,890
Commercial . . . . . .11,196 9,256 10,865 11,382 13,145
Industrial . . . . . . 386 284 305 410 608
Total Sales. . . . .31,147 26,681 30,074 28,278 31,643
Transportation:
Commercial . . . . . . 3,461 3,450 3,582 2,982 2,483
Industrial . . . . . . 9,243 10,292 8,679 8,824 6,838
Total Transporta-
tion . . . . . . .12,704 13,742 12,261 11,806 9,321
Total Throughput . . . .43,851 40,423 42,335 40,084 40,964

The Company has been pursuing an aggressive marketing program
targeting small and large fleet vehicle owners for the use of
compressed natural gas (CNG) as a vehicle fuel. CNG is a more
environmentally sound fuel than gasoline, dramatically reducing
carbon monoxide and other emissions, and costs substantially less
than gasoline. Currently the Company has 13 refueling stations
providing CNG to over 500 vehicles. In 1993, Montana-Dakota's
throughput of CNG was 19 Mdk or the equivalent of approximately
158,000 gallons of gasoline.

In recent years, Montana-Dakota has obtained the majority of
its annual natural gas requirements from Williston Basin, with the
balance being provided by various producers under firm contracts.
However, commensurate with Williston Basin's unbundling of its
various services as a result of its implementation of the FERC's
Order 636 on November 1, 1993, as further described under
"Interstate Natural Gas Pipeline Operations and Property (Williston
Basin)" Montana-Dakota elected to acquire approximately 88 percent
of its system requirements directly from producers and processors
with the balance still being provided by Williston Basin. Such
natural gas is supplied under firm contracts varying in length from
less than one year to over five years and is transported under firm
transportation agreements by Williston Basin and, with respect to
Montana-Dakota's system expansion into north-central South Dakota,
by South Dakota Intrastate Pipeline Company. Montana-Dakota has
also contracted with Williston Basin to provide firm storage
services which enable Montana-Dakota to purchase natural gas at
more nearly uniform daily volumes throughout the year and thus,
meet winter peak requirements at lower costs.

Montana-Dakota has implemented an integrated resource plan
which is used in planning for a reliable future supply of natural
gas which will coincide with anticipated customer demand. Montana-
Dakota estimates that, based on supplies of natural gas currently
available through its suppliers and expected to be available, it
will have adequate supplies of natural gas to meet its system
requirements for the next five years. Other supply alternatives
being evaluated are the installation of peak shaving facilities,
the acquisition of storage gas inventories to meet peak demand and
the interconnection with other pipelines. On the demand side,
Montana-Dakota is evaluating the use of various conservation
programs which include energy audits, weatherization programs and
incentives for the installation of high efficiency appliances such
as boilers, furnaces and water heaters. The development and
evaluation of other economically feasible strategic marketing
programs continues.

Regulatory Matters --

Montana-Dakota's retail natural gas rate schedules contain
clauses permitting adjustments in rates based upon changes in
natural gas commodity, transportation and storage costs. The
various commissions' current regulatory practices allow
Montana-Dakota to recover increases or refund decreases in such
costs within 24 months from the time such changes occur.

In July 1992, Montana-Dakota requested the NDPSC to implement
a gas weather normalization adjustment mechanism in November 1992.
In October 1992, the NDPSC disallowed the adjustment mechanism.
Montana-Dakota requested reconsideration of this matter, which was
granted by the NDPSC in December 1992. A continuance was granted
until such time as a general natural gas rate case should be filed.
Montana-Dakota filed a general natural gas rate case on July 30,
1993, requesting increased revenues of $1.8 million, or 2.8
percent. On November 23, 1993, Montana-Dakota and the NDPSC
reached a settlement of this proceeding which provides for
additional revenues of approximately $1.1 million, or 57 percent of
the original amount requested, effective December 1, 1993. In
order to reach a favorable settlement and place increased rates
into effect this heating season, the implementation of the weather
normalization adjustment mechanism was omitted from the settlement.
Montana-Dakota anticipates requesting the implementation of this
mechanism in a future proceeding.

On June 30, 1993, Montana-Dakota filed a general natural gas
rate case with the WPSC requesting increased revenues of
approximately $430,000, or 4.3 percent. Montana-Dakota and the
WPSC reached a settlement of this proceeding on November 30, 1993,
providing for an increase equal to Montana-Dakota's request
effective December 1, 1993.

Montana-Dakota filed a general natural gas rate case with the
South Dakota Public Utilities Commission (SDPUC) on September 3,
1993, requesting increased revenues of approximately $1.3 million,
or 5 percent. On January 19, 1994, Montana-Dakota and the SDPUC
reached a settlement of this proceeding which provides for
additional revenues of $605,000, or 47 percent of the original
amount requested, effective January 19, 1994. However, the issue
related to Montana-Dakota's request that the SDPUC authorize
accrual accounting for postretirement benefits, representing
26 percent of the amount originally requested, was deferred and
commission hearings are scheduled for March 1994.

In December 1992, the MPSC issued an order on certain purchased
gas cost adjustment filings covering the period December 1989
through November 1992, permitting an interim increase in natural
gas rates effective as of the date of its order. However, the MPSC
deferred ruling on the prudency of Montana-Dakota's decision not to
implement its 1990 and 1991 gas supply conversion options. The
MPSC issued a procedural schedule for disposition of this deferred
issue in mid-1993, but later suspended this matter until a future
date. In August 1993, the MPSC issued an interim order in a
purchased gas cost adjustment filing made in April 1993, permitting
an interim increase in natural gas rates effective as of the date
of the order.

Capital Requirements --

In 1993, Montana-Dakota expended $15.0 million for natural gas
and propane distribution facilities and currently anticipates
expending approximately $12.4 million, $10.4 million and $11.3
million in 1994, 1995 and 1996, respectively.

Environmental Matters --

Montana-Dakota's natural gas and propane distribution
operations are generally subject to extensive federal, state and
local environmental, facility siting, zoning and planning laws and
regulations. Except as may be found with regard to the issues
described below, Montana-Dakota believes it is in substantial
compliance with those regulations.

Montana-Dakota and Williston Basin discovered polychlorinated
biphenyls (PCBs) in portions of their natural gas systems and
informed the 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 December 31, 1993, to address this
situation aggregated approximately $720,000. 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 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 on January 20, 1993, between the EPA and the PRPs outlining
the EPA's proposed remedy and the settlement process. On June 21,
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.

CENTENNIAL ENERGY HOLDINGS, INC.

INTERSTATE NATURAL GAS TRANSMISSION OPERATIONS AND PROPERTY
(WILLISTON BASIN)

General --

Williston Basin owns and operates approximately 3,800 miles of
transmission, gathering and storage lines and 25 compressor
stations located in the states of North Dakota, South Dakota,
Montana and Wyoming and has interconnections with seven pipelines
in Wyoming, Montana and North Dakota. Through three underground
storage facilities located in Montana and Wyoming, storage services
are provided to local distribution companies, producers, suppliers
and others, and serve to enhance system deliverability. Williston
Basin's system is strategically located near five natural gas
producing basins readily making natural gas supplies available to
Williston Basin's transportation and storage customers. In
addition, Williston Basin produces natural gas from owned reserves
which is sold to others or used by Williston Basin for its
operating needs. At December 31, 1993, the net interstate natural
gas transmission plant investment was approximately $159.9 million,
of which approximately $76.8 million is subject to certain purchase
money mortgages payable to the Company.

Under the Natural Gas Act (NGA), as amended, Williston Basin is
subject to the jurisdiction of the FERC regarding certificate, rate
and accounting matters applicable to natural gas purchases,
wholesale sales, transportation and related storage operations.

In recent years, the business operations of Williston Basin, as
well as the natural gas pipeline industry in general, have
undergone substantial transformation. This transformation reflects
significant changes in both natural gas markets and Federal
regulatory policies.

In the past, Williston Basin had served primarily as a natural
gas merchant, purchasing supplies under long-term contracts with
numerous producers and reselling to local distribution companies
under long-term service agreements. NGA regulatory policies
related to both pipeline rates and conditions of service stressed
stability of gas supplies and service, and the reasonable
opportunity for recovery by pipelines of their costs of providing
that service.

Beginning in the 1980's, changes in natural gas markets, which
resulted from increased supplies and reduced demand, and changing
regulatory policies, required Williston Basin to revise long-term
service arrangements in order to respond to a more competitive,
price-sensitive marketplace. This situation was compounded by the
advent of open-access transportation, which served to foster
competition among gas suppliers. Williston Basin continuously
modified its business practices in order to respond to this
increasingly competitive business environment and to regulatory
uncertainties.

In April 1992, the FERC issued Order 636, which requires
fundamental changes in the way natural gas pipelines do business.
See "Regulatory Matters and Revenues Subject to Refund -- Order
636" for a further discussion on Williston Basin's implementation
of Order 636.

For additional information regarding Williston Basin's sales
and transportation for 1991 through 1993, see Item 7 -
"Management's Discussion and Analysis of Financial Condition and
Results of Operations".

System Demand --

In recent years, Williston Basin has provided the majority of
Montana-Dakota's annual natural gas requirements. However, upon
Williston Basin's implementation of Order 636, Montana-Dakota
elected to acquire substantially all of its system requirements
directly from processors and other producers. Williston Basin
transports all such natural gas for Montana-Dakota under a firm
transportation agreement. In addition, Montana-Dakota has
contracted with Williston Basin to provide firm storage services to
facilitate meeting Montana-Dakota's winter peak requirements.

In February 1991, Williston Basin and Northern States Power
Company (NSP) reached an agreement providing for the firm
transportation delivery by Williston Basin to NSP of 8,000 Mcf
of natural gas per day. Construction by Williston Basin of
an interconnection to NSP was completed in November 1992. This
interconnection also provides Williston Basin the added
capability of up to 15,000 Mcf per day of interruptible
transportation. During 1993, 2.3 million decatherms (MMdk) of
natural gas was transported through this interconnection.

Certain of Williston Basin's transportation customers with
large regional supplies of natural gas have the potential of
bypassing Williston Basin by accessing other pipelines' facilities.
In 1991, two of Williston Basin's major transportation customers,
Koch Hydrocarbon Company (Koch) and Amerada Hess Corporation
(Amerada) indicated their intent to construct pipeline facilities
in North Dakota bypassing Williston Basin's pipeline system. Both
Koch and Amerada filed applications with the FERC requesting
exemption from the FERC's jurisdiction for these proposed
facilities, which the FERC approved. Williston Basin requested
rehearing of these decisions, which the FERC denied and, as a
result, Williston Basin appealed the orders to the U.S. Court of
Appeals for the D.C. Circuit. Subsequently, applications were
filed by both Koch and Amerada with the NDPSC requesting approval
of the siting corridors for these facilities. Amerada's and Koch's
requests were approved by the NDPSC in August 1992. Construction
of Amerada's line was completed in late 1992, with Koch's line
being completed in early 1993. On August 12 and August 26, 1993,
the Court remanded Koch's and Amerada's applications, respectively,
back to the FERC at the FERC's request. Subsequently, the FERC
vacated its prior order which exempted Koch's facilities from the
FERC's jurisdiction, stating that such order was moot because Koch
had not constructed the facilities as originally requested. The
FERC is continuing to evaluate its order regarding Amerada's
facilities. As a result of these bypasses, Williston Basin
received 11.3 MMdk less natural gas for transportation in 1993 than
in 1992.

System Supply --

Williston Basin's underground storage facilities have a
certificated storage capacity of approximately 353,300 million
cubic feet (MMcf), including 28,900 MMcf and 46,300 MMcf of
recoverable and nonrecoverable native gas, respectively. Williston
Basin's storage certificate authorizes a company-owned gas
inventory of up to 180 billion cubic feet on an annual average
basis inclusive of recoverable and nonrecoverable native gas.
Williston Basin's storage facilities enable its customers to
purchase natural gas at more nearly uniform daily volumes
throughout the year and thus, facilitate meeting winter peak
requirements at lower costs.

On April 1, 1993, Williston Basin filed an application with the
FERC for authority to increase its certificated storage withdrawal
capacity by 95 MMcf, which the FERC approved on September 20, 1993.
This increase will allow Williston Basin to expand and enhance the
storage services it offers to its customers. Williston Basin has
estimated that $10.4 million will be expended in 1994 related to
this enhancement.

Natural gas supplies from traditional regional sources have
declined during the past several years and such declines are
anticipated to continue. As a result, Williston Basin anticipates
that a potentially significant amount of the future supply needed
to meet its customers' demands will come from off-system sources.
Williston Basin expects to facilitate the movement of these
supplies by making available its transportation and storage
services. Opportunities may exist to increase transportation and
storage services through system expansion or interconnections and
could provide substantial future benefits to Williston Basin.

In 1993, Williston Basin interconnected its facilities with
those of Many Islands Pipeline Ltd., a subsidiary of TransGas Ltd.,
a Saskatchewan, Canada pipeline. This interconnect, from which
Williston Basin began receiving firm transportation gas in January
1994, will provide initial access to up to 10,000 Mcf per day firm
Canadian supply with additional opportunities for interruptible
volumes.

As supported by a study dated January 17, 1994, by Ralph E.
Davis Associates, Inc., (an independent firm of petroleum and
natural gas engineers) Williston Basin has available 116,476 MMcf
of owned gas in producing fields.

Pending Litigation --

Koch Hydrocarbon Company (Koch) --

On August 11, 1993, Koch and Williston Basin reached a
settlement that terminated the litigation, as previously described
in the 1992 Annual Report on Form 10-K and the September 30, 1993
Quarterly Report on Form 10-Q, with respect to all parties. The
settlement, as to both the Company and Williston Basin, satisfies
all of Koch's claims for the past obligation, releases any claim
with respect to obligations up to the present time and terminates
any contractual arrangements with respect to the purchase of
natural gas between the parties for the future. The settlement
thus resolves both the past and the future obligation. In return,
Williston Basin agreed to make an immediate cash payment to Koch of
$40 million (inclusive of the $32 million awarded by the District
Court in October 1991) 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. Since the amount of costs which can ultimately be
recovered is subject to regulatory and market uncertainties, the
Company has provided reserves which it believes are adequate for
any amounts that may not be recovered. Williston Basin expects to
recover $8.3 million in settlement costs through its purchased gas
cost adjustment recovery mechanism. See "Regulatory Matters and
Revenues Subject to Refund" for a discussion of Williston Basin's
filings under the FERC's Orders 500 and 636 requesting recovery of
the balance of the costs associated with the Koch settlement.

KN Energy, Inc. (KN) --

In May 1991, KN, a pipeline for whom Williston Basin transports
natural gas, filed suit against Williston Basin in Federal District
Court for the District of Montana. KN 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.

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. Williston Basin is awaiting final
orders from the 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 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.

Open Access Transportation and Producer Settlement Cost Recovery --

In order to make available the alternate take-or-pay cost
recovery mechanism embodied in FERC Order 500 under the NGA,
Williston Basin, in March 1989, filed an application with the FERC
requesting a blanket certificate to transport natural gas under
such authority. Williston Basin also filed proposed tariff
provisions to govern implementation of the alternate take-or-pay
cost recovery mechanism available under the Order 500 series,
although a specific election on cost absorption was not specified.
In August 1989, Williston Basin received an order from the FERC
issuing the requested blanket certificate. Williston Basin filed
tariffs for Order 500 transportation services which were accepted
by the FERC, subject to the outcome of other proceedings.

In June 1990, Williston Basin filed to recover 75 percent of
$43.4 million ($32.6 million) in buy-out/buy-down costs 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 $10.8 million of such costs through a direct
surcharge to its sales customers, substantially all of which has
been received, with an equal amount being charged to second quarter
1990 earnings. Williston Basin elected to recover the remaining 50
percent ($21.7 million) through a commodity sales rate surcharge.
In July 1990, the FERC issued an order requiring Williston Basin to
recalculate its surcharge and apply it to total throughput.
Through December 31, 1993, Williston Basin has collected $23.6
million, including interest, of these costs through its commodity
sales and transportation rate surcharges. In November 1990,
Williston Basin appealed this order to the U.S. Court of Appeals
for the D.C. Circuit. Oral argument before the Court was held in
November 1991. In July 1992, the Court issued its order denying
Williston Basin's appeal and remanding certain aspects of the case
to the FERC. On May 6, 1993, the FERC issued an order on those
issues remanded by the Court. The principal issue addressed by
this order involved the exemption of one of Williston Basin's major
transportation customers from the assessment of take-or-pay
surcharges. Williston Basin made a filing seeking authority to
reallocate these costs to its other customers, which the FERC
approved.

On August 26, 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 --

In April 1992, the FERC issued Order 636, which requires
fundamental changes in the way natural gas pipelines do business.
Under Order 636, pipelines are required to offer unbundled
transportation service, with the transportation customer having the
option of purchasing gas from other suppliers. Pipelines are also
required to provide "equivalent" transportation services for all
customers regardless of whether they are purchasing gas from such
pipeline or other suppliers. As a part of Order 636, the FERC
acknowledged that incremental costs may be required in the
transition to the FERC-mandated service structures. Such costs
include facility costs, gas supply contract restructuring and
similar costs. Specific references concerning the allowed recovery
of such costs are included in the final rule.

In addition, Order 636 changes the rate design methodology used
for pipeline transportation to the straight fixed variable (SFV)
method. Under the SFV approach, all fixed storage and transmission
costs, including return on equity and associated taxes, are
included in the demand charge (a fixed monthly charge) and all
variable costs are recovered through a commodity charge based on
volumes transported. Under SFV, pipelines should be able to
recover all fixed costs properly allocable to firm transportation
regardless of how much gas is actually transported. Also included
in Order 636 were guidelines addressing abandonment of services,
capacity release and/or assignment of firm capacity rights.

In October 1992, Williston Basin 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 on February 12, 1993, in which it accepted Williston
Basin's filing subject to certain conditions.

On March 15, 1993, Williston Basin filed further tariff
revisions with the FERC in compliance with the FERC's February 12,
1993, order, and on March 12, 1993, filed for rehearing and/or
clarification of other matters raised in the February 12, 1993,
order. On May 13, 1993, the FERC issued an order addressing both
Williston Basin's rehearing request and its March 15 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 on June 30, 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.

On September 17, 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 13, 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 on December 16,
1993. Williston Basin has appealed the FERC's decisions to the
U.S. Court of Appeals for the D.C. Circuit.

On November 5, 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. The GSR
cost recovery being requested reflects costs paid to Koch as part
of a lawsuit settlement, as previously described under "Pending
Litigation" and does not include other GSR costs, if any, which may
be incurred, and future recovery sought, by Williston Basin. This
matter is currently pending before the FERC.

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.

Natural Gas Repurchase Commitment --

The Company has offered for sale since 1984 the 61 MMdk of
inventoried natural gas available under a repurchase commitment
with Frontier Gas Storage Company, as described in Note 5 of Notes
to Consolidated Financial Statements. As a part of the corporate
realignment effected January 1, 1985, the Company agreed, pursuant
to the Settlement approved by the FERC, to remove from rates the
financing costs associated with this natural gas and not recover
any loss on its sale from customers.

In January 1986, because of the uncertainty as to when a sale
would be made, Williston Basin began charging the financing costs
associated with this repurchase commitment to operations as
incurred. Such costs, consisting principally of interest and
related financing fees, approximated $3.9 million, $5.8 million and
$8.5 million in 1993, 1992 and 1991, respectively.

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
December 31, 1993, 12.5 MMdk of this natural gas had been sold and
transported by Williston Basin to off-system markets. Williston
Basin will continue to aggressively market the remaining 48.3 MMdk
of this natural gas as long as market conditions remain favorable.
In addition, it will continue to seek long-term sales contracts.

Other Information --

Supplementary information with respect to natural gas producing
activities is not included herein since the related production is
anticipated to recover its equivalent cost of service. However, as
a part of the corporate realignment in January 1985, the Company
agreed to adjust retail rates so as to limit flow-through of prices
higher than cost of service to 50 percent of the excess. Based on
the terms of the Settlement, refunds for the 1991 and 1992
production years aggregating $1.0 million and $176,000,
respectively, were made in the ensuing year. Estimated reserves
associated with this gas are 116,476 MMcf. The unamortized capital
costs related to these reserves are approximately $7.9 million at
December 31, 1993.

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.

On December 21, 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.

Capital Requirements --

Williston Basin's construction expenditures approximated $5.4
million in 1993, and are estimated to be $19.5 million, $14.6
million and $24.3 million in 1994, 1995 and 1996, respectively.

Environmental Matters --

Williston Basin's interstate natural gas transmission
operations are generally subject to federal, state and local
environmental, facility-siting, zoning and planning laws and
regulations. Except as may be found with regard to the issues
described below, Williston Basin believes it is in substantial
compliance with those regulations.

See "Environmental Matters" under "Montana-Dakota -- Retail
Natural Gas and Propane Distribution" for a discussion of PCBs
contained in Montana-Dakota's and Williston Basin's natural gas
systems.

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),
the agency for the state of Montana which regulates air quality.
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.

MINING AND CONSTRUCTION MATERIALS OPERATIONS AND PROPERTY
(KNIFE RIVER)

Coal Operations:

General --

The Company, through Knife River, is engaged in lignite coal
mining operations. Knife River's surface mining operations are
located at Beulah and Gascoyne, North Dakota and Savage, Montana.
The average annual production from the Beulah, Gascoyne and Savage
mines approximates 2.4 million, 2.1 million and 275,000 tons,
respectively. Reserve estimates related to these mine locations
are discussed herein. During the last five years, Knife River
mined and sold the following amounts of lignite coal:

Years Ended December 31,
1993 1992 1991 1990 1989
(In thousands)

Tons sold:
Montana-Dakota generating stations. . 624 521 618 592 675
Jointly-owned generating stations--
Montana-Dakota's share. . . . 1,034 1,021 953 895 933
Others. . . . . . . . . . . . 3,299 3,259 3,069 2,872 2,982
Industrial and other sales . . 109 112 91 80 157
Total . . . . . . . . . . . . 5,066 4,913 4,731 4,439 4,747
Revenues . . . . . . . . . . . $44,230 $43,770 $41,201 $38,276 $41,643

In recent years, in response to competitive pressures from
other mines, Knife River has reduced its coal prices and/or not
passed through cost increases which are allowed under its
contracts. Although Knife River has contracts in place specifying
the selling price of coal, these price concessions are being made
in an effort to remain competitive and maximize sales. Ongoing
cost containment measures and enhanced mining efficiencies continue
to assist Knife River in maintaining its market position.

Knife River and Montana-Dakota entered into a five-year coal
sales contract for sales made from the Savage Mine to Montana-
Dakota's Lewis and Clark Station effective January 1, 1993. This
contract stipulates a reduction in the price paid for coal mined in
government-owned properties. The reduction is the result of Knife
River's success in obtaining a reduction in the federal royalty
rate paid.

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.

Construction Materials Operations:

General --

In May 1992, KRC Aggregate, Inc. (KRC Aggregate), an indirect,
wholly-owned subsidiary of Knife River, entered into the sand and
gravel business in north-central California through the purchase of
certain properties, including mining and processing equipment.
These operations, located near Lodi, California, surface mine,
process and market aggregate products to various customers,
including road and housing contractors, tile manufacturers and
ready-mix plants, with a market area extending approximately 60
miles from the mine.

On April 2, 1993, the assets of Alaska Basic Industries, Inc.
(ABI) and its subsidiaries were purchased by KRC Aggregate. ABI is
a vertically integrated construction materials business
headquartered in Anchorage, Alaska. ABI's nine divisions handle
the sale of its sand and gravel aggregates and related products
such as ready-mixed concrete, asphalt and finished aggregate
products.

Effective September 1, 1993, KRC Aggregate, purchased the stock
of LTM, Incorporated (LTM), Rogue Aggregates, Inc. (Rogue) and
Concrete, Inc., construction materials subsidiaries of Terra
Industries. Headquartered in Medford, Oregon, LTM and Rogue are
vertically integrated construction materials businesses serving
southern Oregon markets. Their products include sand and gravel
aggregates, ready-mixed concrete, asphalt and finished aggregate
products. Concrete, Inc., headquartered in Stockton, California,
operates four ready-mix plants in San Joaquin County. These ready-
mix plants became part of KRC Aggregate's Lodi, California
operations.

Sales volumes and revenues for the construction materials
operations during 1992 and 1993 were as follows:

Years Ended December 31,
(In thousands)
1993 1992

Aggregates (tons). . . . . . . . . . . . 2,391 263
Ready-mixed concrete (cubic yards) . . . 157 ---
Asphalt (tons) . . . . . . . . . . . . . 141 ---
Revenues . . . . . . . . . . . . . . . . $ 46,167 $ 1,262

Consolidated Mining and Construction Materials Operations:

Capital Requirements --

Consolidated construction expenditures for Knife River
approximated $46.5 million in 1993, including amounts related to
the acquisition by KRC Aggregate of ABI, LTM, Rogue and Concrete,
Inc. Construction expenditures are estimated to be $4.5 million in
1994, $5.6 million in 1995 and $7.6 million in 1996. Such
expenditures are primarily for replacement of existing equipment,
mine-site improvements, lease acquisitions and further development
of the Beulah mine.

Knife River continues to seek out additional mining
opportunities. This includes 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
processes. Any capital expenditures related to other potential
mining acquisitions are not reflected in the above 1994-1996
capital needs.

Environmental Matters --

Knife River's mining and construction materials operations are
subject to regulation customary for surface mining operations,
including federal, state and local environmental and reclamation
regulations. Knife River believes that these operations are in
substantial compliance with those regulations.

One of Knife River's major coal customers, the Big Stone
Station, will be required to comply with the Clean Air Act emission
standards by the year 2000. Alternatives available to this
customer include installation of a sulfur scrubber, switching to
lower sulfur coal, using processed or "clean" coal, or fuel
blending. Some of the alternatives could have a significant
adverse effect on Knife River's coal operations including its
ability to extend the existing coal contract beyond its 1995
expiration date.

Knife River continues its involvement in lignite research with
emphasis placed upon enhancement of lignite coal as a boiler fuel.
In addition, Knife River continues to monitor progress on clean
coal technologies.

Reserve Information --

As of December 31, 1993, Knife River had under ownership or
lease, reserves of approximately 231 million tons of recoverable
lignite coal at present mining locations. Such reserves estimates
were prepared by Paul Weir Company Incorporated, independent mining
engineers and geologists, in a report dated January 20, 1989, and
have been adjusted for 1989 through 1993 production and the
relinquishment of federal and fee coal contracts at two mine sites.
Knife River estimates that approximately 109 million tons of its
reserves will be needed to supply all of Montana-Dakota's existing
generating stations for the expected lives of those stations and to
fulfill the existing commitments of Knife River for sales to third
parties.

As of December 31, 1993, the combined construction materials
operations had under ownership approximately 74 million tons of
recoverable aggregate reserves.

OIL AND NATURAL GAS OPERATIONS AND PROPERTY (FIDELITY OIL)

General --

The Company, through Fidelity Oil, is involved in the
acquisition, exploration, development and production of oil and
natural gas properties. Fidelity Oil has had oil and natural gas
interests since 1951 when an operating agreement (Agreement)
relating to its net proceeds acreage interests was signed with
Shell Western E&P, Inc. (Shell). Beginning in 1986, Fidelity Oil
undertook a growth and development strategy focused on programs
directed at the acquisition of producing properties, exploration
and development.

Fidelity Oil, through its net proceeds interests, owns in fee
or holds oil and natural gas leases and operating rights applicable
to the deep rights (below 2,000 feet) in the Cedar Creek Anticline
in southeastern Montana. Pursuant to the Agreement, Shell, as
operator, controls all development, production, operations and
marketing applicable to such acreage. As a net proceeds interest
owner, Fidelity Oil is entitled to proceeds only when a particular
unit has reached payout status.

Fidelity Oil undertakes ventures, through a series of
working-interest agreements with several different partners, that
vary from the acquisition of producing properties with potential
development opportunities to exploration and are located in the
western United States, offshore in the Gulf of Mexico and in
Canada. In these ventures, Fidelity Oil shares revenues and
expenses from the development of specified properties in proportion
to its investments.

Operating Information --

Information on Fidelity Oil's oil and natural gas production,
average sales prices and production costs per net equivalent barrel
related to its oil and natural gas net proceeds and working
interests for 1993, 1992 and 1991 are as follows:

1993 1992 1991
Oil:
Production (000's of barrels). . . . . 1,500 1,500 1,500
Average sales price. . . . . . . . . . $14.84 $16.74 $19.90
Natural Gas:
Production (MMcf). . . . . . . . . . . 8,800 5,000 2,600
Average sales price. . . . . . . . . . $1.86 $1.53 $1.48
Production costs, including taxes,
per net equivalent barrel. . . . . . . $3.98 $4.81 $5.86

Well and Acreage Information --

Fidelity Oil's gross and net productive well counts and gross
and net developed and undeveloped acreage for the net proceeds and
working interests at December 31, 1993, are as follows:

Gross Net
Productive Wells:
Oil. . . . . . . . . . . . . . . . . . . . 3,530 129
Natural Gas . . . . . . . . . . . . . . . 627 29
Total. . . . . . . . . . . . . . . . . . 4,157 158
Developed Acreage (000's). . . . . . . . . . 562 75
Undeveloped Acreage (000's). . . . . . . . . 683 52

Exploratory and Development Wells --

The following table shows the results of oil and natural gas
wells drilled and tested during 1993, 1992 and 1991:

Net Exploratory Net Development
Productive Dry Holes Total Productive Dry Holes Total Total

1993 2 2 4 5 1 6 10
1992 --- 4 4 2 1 3 7
1991 2 5 7 8 3 11 18

At December 31, 1993, there were two exploratory wells and one
development well in the process of drilling.

Capital Requirements --

The following summary reflects capital expenditures, including
those not subject to amortization, related to oil and natural gas
activities for the years 1993, 1992 and 1991:

1993 1992 1991
(In thousands)

Acquisitions . . . . . . . . . . . . . $ 9,296 $ 9,976 $ 4,667
Exploration. . . . . . . . . . . . . . 7,787 11,074 7,781
Development. . . . . . . . . . . . . . 7,836 4,715 9,824
Total Capital Expenditures . . . . . $24,919 $25,765 $22,272

Fidelity Oil plans additional commitments to oil and gas
investments and has budgeted approximately $30 million for each of
the years 1994 through 1996 for such activities. Such investments
are expected to be financed with a combination of funds on hand at
December 31, 1993, funds to be internally generated and the $20
million currently available under Fidelity Oil's long-term
financing arrangements, $1.5 million of which was outstanding at
December 31, 1993.

Reserve Information --

Fidelity Oil's recoverable proved developed and undeveloped oil
and natural gas reserves approximated 11.2 million barrels and 50.3
Bcf, respectively, at December 31, 1993. Of these amounts, 8.3
million barrels and 2.0 Bcf, as supported by a report dated
January 10, 1994, prepared by Ralph E. Davis Associates, Inc., an
independent firm of petroleum and natural gas engineers, were
related to its properties located in the Cedar Creek Anticline in
southeastern Montana.

For additional information related to Fidelity Oil's oil and
natural gas interests, see Note 18 of Notes to Consolidated
Financial Statements.

ITEM 3. LEGAL PROCEEDINGS

Williston Basin has been named as a defendant in a legal action
primarily related to its transportation services. Such suit was
filed by KN as described under "Pending Litigation". Williston
Basin's assessment of this proceeding is included in the
description of the litigation.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

No matters were submitted to a vote of security holders during
the fourth quarter of 1993.
PART II

ITEM 5. MARKET FOR THE REGISTRANT'S COMMON STOCK AND RELATED
STOCKHOLDER MATTERS

MDU Resources Group, Inc. common stock is listed on the New
York Stock Exchange and uses the symbol "MDU". The price range of
the Company's common stock as reported by the Wall Street Journal
composite tape during 1993 and 1992 and dividends declared thereon
were as follows:

Common
Common Common Stock
Stock Price Stock Price Dividends
(High) (Low) Per Share

1993
First Quarter . . . . . . . . $29 1/4 $25 7/8 $ .37
Second Quarter. . . . . . . . 32 1/2 29 .37
Third Quarter . . . . . . . . 32 29 3/4 .39
Fourth Quarter. . . . . . . . 33 1/8 30 1/2 .39
$1.52

1992
First Quarter . . . . . . . . $25 3/4 $23 1/4 $ .36
Second Quarter. . . . . . . . 26 7/8 21 7/8 .36
Third Quarter . . . . . . . . 25 1/2 23 7/8 .37
Fourth Quarter. . . . . . . . 26 3/4 25 .37
$1.46

As of December 31, 1993, the Company's common stock was held by
approximately 15,100 stockholders.

ITEM 6. SELECTED FINANCIAL DATA

Reference is made to selected Financial Data on pages 52 and 53
of the Company's Annual Report which is incorporated herein by
reference.

ITEM 7. 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.

Years ended December 31,
Business 1993 1992 1991
Utility --
Electric . . . . . . . . . . . . $12.6 $13.3 $15.3
Natural gas. . . . . . . . . . . 1.2 1.4 3.6
13.8 14.7 18.9
Natural gas transmission . . . . . 4.7 3.5 0.5
Mining and construction
materials. . . . . . . . . . . . 12.4 10.7 9.8
Oil and natural gas production . . 7.1 5.7 8.0
Earnings on common stock . . . . . $38.0 $34.6 $37.2
Earnings per common share. . . . . $2.00 $1.82 $1.96
Return on average common equity. . 12.3% 11.6% 12.7%

Earnings information presented in this table and in the following
discussion is before the $8.9 million ($5.5 million after-tax) cumulative
effect of an accounting change. See Note 2 of Notes to Consolidated
Financial Statements for a further discussion of this accounting change.

1993 compared to 1992

Consolidated earnings for 1993 are up $3.4 million when compared to 1992.
The improvement is attributable to increased earnings from the natural gas
transmission, mining and construction materials, and oil and natural gas
production businesses, partially offset by a slight decrease in utility
earnings. The reasons for such changes are described in the "1993
compared to 1992" discussions which follow.

1992 compared to 1991

Consolidated earnings for 1992 are down $2.6 million from the $37.2
million earned in 1991. The decline was the result of decreased earnings
in the utility and oil and natural gas production businesses, partially
offset by increased natural gas transmission and mining and construction
materials earnings. The reasons for such changes are described in the
"1992 compared to 1991" discussions which follow.

________________________________

Reference should be made to Items 1 and 2 -- "Business and Properties
- - Interstate Natural Gas Transmission Operations and Property" and Notes
3, 4 and 5 of Notes to 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.
Certain reclassifications have been made in the following statistics for
1992 and 1991 to conform to the 1993 presentation. Such reclassifications
had no effect on net income or common stockholders' investment as
previously reported.

Montana-Dakota -- Electric Operations

Years ended December 31,
1993* 1992 1991

Operating revenues . . . . . . . . $131.1 $123.9 $128.7
Fuel and purchased power . . . . . 41.3 37.9 38.4
Operation and maintenance
expenses . . . . . . . . . . . . 37.4 34.2 33.7
Operating income . . . . . . . . . 30.5 30.2 34.6

Retail sales (kWh) . . . . . . . . 1,893.7 1,829.9 1,877.6
Power deliveries to MAPP (kWh) . . 511.0 352.6 331.3

Cost of fuel and purchased
power per kWh. . . . . . . . . . $ .016 $ .016 $ .016

Montana-Dakota -- Natural Gas Distribution Operations

Years ended December 31,
1993* 1992 1991
Operating revenues:
Sales. . . . . . . . . . . . . . $151.7 $123.8 $134.4
Transportation & other . . . . . 4.3 4.4 4.2
Purchased natural gas sold . . . . 114.0 89.5 98.3
Operation and maintenance
expenses . . . . . . . . . . . . 28.6 26.0 23.8
Operating income . . . . . . . . . 4.7 4.5 8.5

Volumes (dk):
Sales. . . . . . . . . . . . . . 31.2 26.7 30.1
Transportation . . . . . . . . . 12.7 13.7 12.2
Total throughput . . . . . . . . . 43.9 40.4 42.3

Degree days (% of normal). . . . . 105.5% 87.1% 97.9%
Cost of natural gas per dk . . . . $ 3.66 $ 3.35 $ 3.27

*See Note 2 of Notes to Consolidated Financial Statements for a
discussion of an accounting change to reflect unbilled revenues.

Williston Basin
Years ended December 31,
1993 1992 1991
Operating revenues:
Sales for resale. . . . . . . . . $51.3* $63.5* $78.8*
Transportation & other. . . . . . 40.0* 35.5* 37.2*
Purchased natural gas sold . . . . 20.6 33.6 45.3
Operation and maintenance
expenses . . . . . . . . . . . . 39.0** 33.0** 39.6**
Operating income . . . . . . . . . 20.1 21.3 19.9

Volumes (dk):
Sales for resale:
Montana-Dakota. . . . . . . . . 13.0 16.5 19.3
Other . . . . . . . . . . . . . .2 .3 .3
Transportation:
Montana-Dakota. . . . . . . . . 27.3 24.9 22.1
Other . . . . . . . . . . . . . 32.1 39.6 31.8
Total throughput . . . . . . . . . 72.6 81.3 73.5

Cost of natural gas per dk . . . . $1.78 $1.91 $2.07
_________________________________
* Includes recovery of deferred
natural gas contract
buy-out/buy-down costs. . . . . $13.0 $ 5.8 $ 6.5
** Includes amortization of
deferred natural gas contract
buy-out/buy-down costs. . . . . $11.8 $ 6.2 $ 6.6

Knife River
Years ended December 31,
1993 1992 1991
Operating revenues:
Coal. . . . . . . . . . . . . . . $44.2 $43.8 $41.2
Construction materials. . . . . . 46.2 1.2 ---
Operation and maintenance
expenses . . . . . . . . . . . . 59.6 21.2 20.2
Reclamation expense. . . . . . . . 3.1 3.0 2.8
Severance taxes. . . . . . . . . . 4.4 4.3 4.2
Operating income . . . . . . . . . 17.0 11.5 9.7

Sales (000's):
Coal (tons) . . . . . . . . . . . 5,066 4,913 4,731
Aggregates (tons) . . . . . . . . 2,391 263 ---
Ready-mixed concrete
(cubic yards) . . . . . . . . . 157 --- ---
Asphalt (tons). . . . . . . . . . 141 --- ---

Fidelity Oil
Years ended December 31,
1993 1992 1991

Operating revenues . . . . . . . . $39.1 $33.8 $33.9
Operation and maintenance
expenses. . . . . . . . . . . . . 11.6 12.0 11.8
Depreciation, depletion and
amortization. . . . . . . . . . . 12.0 8.8 6.0
Operating income . . . . . . . . . 11.8 9.5 12.6

Production (000's):
Oil (barrels) . . . . . . . . . 1,497 1,531 1,491
Natural gas (Mcf). . . . . . . . 8,817 5,024 2,565

Average sales price:
Oil (per barrel) . . . . . . . . $14.84 $16.74 $19.90
Natural gas (per Mcf). . . . . . 1.86 1.53 1.48

1993 compared to 1992

Montana-Dakota--Electric Operations

Operating income for the electric business increased due to an
improvement in retail sales to residential and commercial markets,
primarily the result of colder weather in the first quarter of 1993
and the addition of nearly 540 customers. Also, improving
operating income was an increase in deliveries into the MAPP, the
result of water conservation efforts by hydroelectric generators
and the temporary shutdown of a nuclear generating station in Iowa.
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
partially offset the improvement in operating income. Higher
operation and maintenance expenses also negatively affected
operating income. 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. Earnings from this business unit
declined as a result of 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 1992 and
lower average short-term borrowings and interest rates, and the
aforementioned operating income improvement, somewhat offset the
earnings decline.

Montana-Dakota--Natural Gas Distribution Operations

Sales increases of 4.5 MMdk or $3.6 million, due to
significantly colder weather than 1992 and the addition of over
3,500 residential and commercial customers, improved operating
income for the natural gas distribution business. However,
partially offsetting this improvement were the 1992 refinement of
the estimated amount of delivered but unbilled natural gas volumes
and increased operation and depreciation expenses. Employee
benefit-related costs and distribution and sales expenses related
to the system expansion into north-central South Dakota accounted
for the majority of the operation expense increase. A Wyoming rate
decrease effective in the second quarter of 1992 also reduced the
operating income improvement. Gas distribution earnings decreased
due to higher financing costs related to increased capital
expenditures and carrying charges being accrued on natural gas
costs refundable through rate adjustments, offset in part by
interest savings resulting from 1992 long-term debt refinancing.
The aforementioned operating income change and increased Other
Income--Net, primarily due to the return being earned on deferred
storage costs 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 decreased transportation volumes reflecting
the effects of bypasses by two major transportation customers.
Partially offsetting the effects of these bypasses were the
increased movement of 3.4 MMdk of natural gas held under the
repurchase commitment, due to favorable natural gas prices, and
higher volumes transported on the November 1992 interconnection
with NSP (1.8 MMdk), although at lower average rates than those
replaced. Operating income was also negatively affected by the
delay in the implementation of Order 636 until November 1, 1993.
See Items 1 and 2 for Williston Basin for further discussions on
the implementation of Order 636. Operation expenses increased
slightly due to additional reserves related to the Koch settlement,
increased transmission expenses and higher employee benefit-related
costs. Largely offsetting the increased operation expenses are
lower contract restructuring amortizations, an out-of-period
adjustment to take-or-pay surcharge amortizations and a 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. Maintenance expenses increased as a result of
compressor overhauls at several compressor station facilities. A
weather-related sales improvement of 3.3 MMdk, or $2.8 million,
combined with increased general rates implemented in November 1992,
partially offset the operating income decline. Income from company
production improved due to increased production, but at lower
average prices. Earnings for this business unit increased due to
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 and decreased average rates, offset in part by the
decline in operating income discussed above.

Knife River

Operating income increased due to sales from the newly acquired
Alaskan and Oregon construction materials businesses and an
improvement in coal tons sold at all mines, mainly the result of
increased demand by electric generation customers. Lower selling
prices at the Gascoyne Mine, effective June 1, 1992, following an
amendment to the current coal supply agreement, partially offset
the operating income increase. An increase in operating expenses
resulting from the newly acquired construction materials businesses
and a volume-related increase in coal operating expenses, combined
with the accrual of SFAS No. 106 costs 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 and lower earned returns, and increased federal income
taxes.

Fidelity Oil

Operating income for the oil and natural gas production
business increased as a result of higher natural gas production and
prices. In addition, decreased operation and maintenance expenses
per equivalent barrel were somewhat offset by volume-related
increases in such costs. Partially offsetting the operating income
improvement was a decline in oil production and prices and
increased depreciation, depletion and amortization, reflecting both
increased production and higher rates. The aforementioned increase
in operating income was further improved by the realization of
certain investment gains resulting in the earnings improvement for
this business. Increased interest expense, stemming from both
higher average borrowings and rates, and increased federal income
taxes, somewhat reduced earnings.

1992 compared to 1991

Montana-Dakota -- Electric Operations

The decline in operating income was due to reduced residential
and commercial sales resulting primarily from warmer winter weather
combined with a cooler summer than that experienced a year ago. An
increase in deliveries into the MAPP, primarily in the fourth
quarter, was more than offset by the decline in the average price.
The fourth quarter increase in deliveries into the MAPP reflects
water conservation efforts by hydroelectric generators. The
discounting of sales prices necessitated by a weak wholesale market
contributed to the price decline experienced for sales to the MAPP.
Higher demand charges associated with the purchase of firm capacity
through a participation power contract and an increase in operation
expense, primarily payroll and benefit-related, also reduced
operating income. The demand charge increase results from the
additional purchase of 5 megawatts of firm capacity which began in
May 1992 and the passthrough of costs associated with a periodic
maintenance outage. Partially mitigating the operating income
decline was an increase in large industrial sales, lower
depreciation expense and a reduction in maintenance expense
reflecting the impact of 1991 maintenance outages at the Heskett
and Coyote stations. Earnings from this business unit decreased
for the reasons discussed above, partially offset by reduced
interest expense, the result of certain bond refinancings in the
second and fourth quarter of 1991 and the second quarter of 1992
offset in part by increased average borrowings under lines of
credit.

Montana-Dakota -- Gas Distribution Operations

A sales decline of 2.4 MMdk or $2.0 million, related to
significantly warmer first quarter weather than in 1991, the
refinement of the estimated amount of delivered but unbilled
natural gas volumes and an increase in operation expenses, largely
payroll and benefit-related costs, were the primary contributors to
the operating income decline. The addition of over 2,400
residential and commercial customers mitigated in part the sales
decline. Transportation volumes increased largely due to the
addition of a large industrial customer in the second quarter of
1992, although at discounted rates, and the conversion of a
principal customer from firm commercial sales to transportation.
A North Dakota rate increase, which was placed into effect in the
third quarter of 1991, partially mitigated the operating income
decline. Gas distribution earnings decreased for the reasons
discussed above offset in part by decreased interest expense
related to carrying charges being accrued on natural gas costs
refundable through rate adjustments and the effects of the bond
refinancings discussed in Electric Operations above.

Williston Basin

Operating income improved as a result of increased
transportation volumes reflecting the movement of 4.4 MMdk of
natural gas held under the repurchase commitment, due to favorable
natural gas prices. Reduced operation expenses resulting from
December 1991 additions to reserves maintained for regulatory and
market uncertainties and reduced litigation expenses and contract
restructuring amortizations, offset in part by increased payroll
and benefit-related costs and the accrual for retroactive company
production royalties, also contributed to the increase in operating
income. Partially offsetting the operating income increase were
decreased weather-related sales of approximately 571 Mdk or
$516,000, lower average realized rates on transportation services,
due to a higher level of discounted transportation services being
used, and decreased company production revenues, the result of both
reduced volumes and lower prices. Earnings for this business unit
increased as a result of the changes in operating income discussed
above, decreased carrying costs associated with the natural gas
repurchase commitment, largely due to lower interest rates, and
reduced interest expense on revenues being reserved stemming from
lower interest rates and lower carrying charges being accrued on
natural gas costs refundable through rate adjustments. Decreased
interest income related to recoverable natural gas contract
litigation settlement costs and higher company-owned production
refund accruals somewhat mitigated the earnings improvement.

Knife River

Increased coal sales at the Beulah mine, primarily due to
outages experienced in 1991 by a major electric generation
customer, were the primary factor improving operating income.
Aggregate sales at the newly acquired construction materials
business also added to operating revenues. Decreased coal sales at
the Gascoyne and Savage mines due to reduced weather-related demand
from electric generating station customers and increased operation
and maintenance expenses partially offset the operating income
improvement. The increase in operation and maintenance expenses
resulted from a volume-related increase in coal operation expenses
and first year expenses at the construction materials business
offset in part by equipment efficiencies and lower stripping costs
due to recovery of third seam coal at the Beulah mine. Mining and
construction materials earnings increased for reasons discussed
above offset in part by reduced investment income, largely due to
lower returns resulting from declining interest rates, and
increased corporate development-related costs (both included in
Other Income--Net).

Fidelity Oil

An increase in oil and natural gas production was more than
offset by lower average sales prices for oil producing the decline
in operating income. A volume-related increase in operating costs
related to working interests and increased depreciation, depletion
and amortization also reduced operating income. Decreased
operating costs associated with the net proceeds interests
resulting from cost controls implemented by the operator, somewhat
mitigated the operating income decline. Earnings for the oil and
natural gas production business decreased as a result of the above
changes in operating income and increased interest expense stemming
from increased average borrowings.

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. Both recovery
mechanisms reduce the effect the changes in these costs have on
Montana-Dakota's results. See Items 1 and 2 for a further
discussion of these items as they apply to Montana-Dakota's
operations.

In July 1992, Montana-Dakota requested the NDPSC to implement
a gas weather normalization adjustment mechanism in November 1992.
In October 1992, the NDPSC disallowed the adjustment mechanism.
Montana-Dakota requested reconsideration of this matter, which was
granted by the NDPSC in December 1992. A continuance was granted
until such time as a general natural gas rate case should be filed.
Based on a settlement reached with the NDPSC in connection with a
general natural gas rate case filed in July 1993, the
implementation of the weather normalization adjustment mechanism
was omitted from the settlement. See Items 1 and 2 under Montana-
Dakota for a further discussion of the weather normalization
adjustment mechanism as well as general rate increase applications
filed and settlements reached with the NDPSC, SDPUC and WPSC,
respectively.

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 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 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.
As a result of these bypasses, Williston Basin received 11.3 MMdk
less natural gas for transportation in 1993 than in 1992. See
Items 1 and 2 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 Items 1 and 2
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 Items 1 and 2 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
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.

On January 1, 1993, Montana-Dakota changed its revenue
recognition method to include the accrual of estimated unbilled
revenues. This change will provide for a better matching of
revenues and expenses and is consistent with predominant industry
practice. See Note 2 of Notes to Consolidated Financial Statements
for a further discussion of this accounting change.

The FASB issued SFAS No. 109, "Accounting for Income Taxes"
(SFAS No. 109) in February 1992, which changes the accounting
method used to measure and recognize income tax effects in
financial statements. SFAS No. 109, among other things, requires
that existing deferred tax balances be revised to reflect any
change in statutory rates. The Company adopted this new standard
on January 1, 1993. Based on the provisions of SFAS No. 109, the
effect on the Company's financial position or results of operations
was not material. Any excess deferred income tax balances
associated with rate-regulated activities at the time of
implementation have been recorded as a regulatory liability and are
expected to be reflected as a reduction in future rates charged
customers in accordance with applicable regulatory procedures. See
Notes 2 and 13 for a further discussion on the adoption of this
standard.

In December 1990, the FASB issued SFAS No. 106, "Employers'
Accounting for Postretirement Benefits Other than Pensions" (SFAS
No. 106). SFAS No. 106 establishes accounting standards for
postretirement benefits whereby an employer must recognize in its
financial statements on an ongoing basis the actuarially calculated
obligation (accumulated postretirement benefit obligation) and
related annual costs associated with providing such benefits to
employees upon retirement. These benefits are recognized ratably
over the employee's term of employment to such employee's eligible
retirement date, as earned, rather than the previously used pay-as-
you-go practice which recognized such costs when they were paid.
The Company adopted this new standard on January 1, 1993. Based on
the health care and life insurance benefits which are available to
all eligible employees and their dependents upon the employees'
retirement, the Company's annual cost based on the provisions of
SFAS No. 106 for 1993 is approximately $7.5 million, including
amortization of the initial accumulated postretirement benefit
obligation of $49 million over 20 years. See Notes 2 and 15 of
Notes to Consolidated Financial Statements for a further discussion
on the adoption of this standard 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.

The FASB issued SFAS No. 112, "Employers' Accounting for
Postemployment Benefits" (SFAS No. 112) in November 1992. SFAS
No. 112 establishes accounting standards for postemployment
benefits whereby an employer must recognize the benefits provided
to former or inactive employees, their beneficiaries, and covered
dependents after employment, but before retirement. SFAS No. 112
is effective for fiscal years beginning after December 15, 1993,
and therefore, the Company will be required to adopt this new
standard in 1994. The Company believes, based on an evaluation of
the benefits it provides which are covered by the provisions of
SFAS No. 112, that such amounts are not material to its financial
position or results of operations.

Liquidity and Capital Commitments

The Company's construction costs and additional investments in
non-regulated mining and construction materials, and oil and
natural gas activities (in millions of dollars) for 1991 through
1993 and as anticipated for 1994 through 1996 are summarized in the
following table, which also includes the Company's capital needs
for the retirement of maturing long-term securities.

Estimated
1991 1992 1993 Company/Description 1994 1995 1996
Montana-Dakota:
$ 11.7 $ 13.2 $ 16.2 Electric $16.9 $19.8 $ 19.4
5.8 6.5 15.0 Natural Gas Distribution 12.4 10.4 11.3
17.5 19.7 31.2 29.3 30.2 30.7
4.1 9.4 5.4 Williston Basin 19.5 14.6 24.3
.9 16.3 46.5 Knife River 4.5 5.6 7.6
22.3 25.8 24.9 Fidelity 30.0 30.0 30.0
--- --- 1.0 Prairielands .2 .2 ---
44.8 71.2 109.0 83.5 80.6 92.6

Retirement/Repurchase
94.1 140.3 18.4 of Securities 15.3 10.8 10.8
$138.9 $211.5 $127.4 Total $98.8 $91.4 $103.4

In 1993, both Montana-Dakota's and Williston Basin's internal
sources provided all of the funds needed for construction purposes.
The Company's capital needs to retire maturing long-term corporate
securities were $300,000.

It is anticipated that Montana-Dakota will continue to provide
all of the funds required for its construction requirements for the
years 1994 through 1996 from internal sources, through the use of
its $30 million revolving credit and term loan agreement, all of
which is outstanding at December 31, 1993, 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, a $35 million line of credit currently available, none of
which is outstanding at December 31, 1993, 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.

As further described in Items 1 and 2 under Williston Basin, on
August 11, 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,
Williston Basin believes that financing arrangements currently in
place are adequate to finance these costs. See Items 1 and 2 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 Items 1 and 2 under Williston Basin for a further discussion of
Williston Basin's appeal efforts in these matters.

Knife River's 1993 capital needs were met through funds on hand
and funds generated from internal sources. It is anticipated that
funds on hand and funds generated from internal sources will
continue to meet the needs of this business unit for 1994 through
1996, excluding funds which may be required for future
acquisitions.

Fidelity Oil's 1993 capital needs related to its oil and
natural gas acquisition, development and exploration program were
met through funds generated from internal sources and a $20 million
secured line of credit. It is anticipated that Fidelity's 1994
through 1996 capital needs will be met from internal sources and
its secured line of credit. There was $1.5 million outstanding at
December 31, 1993, under the secured line of credit.

See Note 13 of Notes to the Consolidated Financial Statements
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' 1993 capital needs were met through funds
generated internally. It is anticipated that Prairielands' 1994
and 1995 capital needs will be met through funds generated from
internal sources and a $5 million line of credit, $2.0 million of
which is outstanding at December 31, 1993.

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 was $7.5 million outstanding at December 31,
1993, 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 December 31, 1993, the Company could have issued
approximately $153 million of additional first mortgage bonds.

The Company's coverage of fixed charges including preferred
dividends was 3.0 and 2.4 times for 1993 and 1992, respectively.
Additionally, the Company's first mortgage bond interest coverage
was 3.4 times in 1993 compared to 3.3 times in 1992. Stockholders'
equity as a percent of total capitalization was 56% and 53% at
December 31, 1993 and 1992, respectively.

Effects of Inflation

The Company's consolidated financial statements reflect
historical costs, thus combining the impact of dollars spent at
various times. Such dollars have been affected by inflation, which
generally erodes the purchasing power of monetary assets and
increases operating costs. During times of chronic inflation, the
loss of purchasing power and increased operating costs could
potentially result in inadequate returns to stockholders primarily
because of the lag in rate relief granted by regulatory agencies.
Further, because the ratemaking process restricts the amount of
depreciation expense to historical costs, cash flows from the
recovery of such depreciation are inadequate to replace utility
plant.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Reference is made to Pages 27 through 51 of the Annual Report.

ITEM 9. CHANGE IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING
AND FINANCIAL DISCLOSURE

None.

PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

Reference is made to Pages 3 through 6 and 13 and 14 of the
Company's Proxy Statement dated March 7, 1994 (Proxy Statement)
which is incorporated herein by reference.

ITEM 11. EXECUTIVE COMPENSATION

Reference is made to Pages 7 through 13 of the Proxy
Statement.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT

Reference is made to Page 14 of the Proxy Statement.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

None.
PART IV

ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON
FORM 8-K

(a) Financial Statements, Financial Statement Schedules and
Exhibits.

Index to Financial Statements and Financial Statement
Schedules.

1. Financial Statements:

Report of Independent Public Accountants. . . . . *
Consolidated Statements of Income for each
of the three years in the period ended
December 31, 1993 . . . . . . . . . . . . . . . *
Consolidated Balance Sheets at December 31,
1993, 1992 and 1991 . . . . . . . . . . . . . . *
Consolidated Statements of Capitalization at
December 31, 1993, 1992 and 1991. . . . . . . . *
Consolidated Statements of Cash Flows for
each of the three years in the period ended
December 31, 1993 . . . . . . . . . . . . . . . *
Notes to Consolidated Financial Statements. . . . *

2. Financial Statement Schedules:

Report of Independent Public Accountants
on Schedules . . . . . . . . . . . . . . . . . **
Schedule V -- Property, Plant and Equipment for
the three years ended December 31, 1993
Schedule VI -- Accumulated Depreciation,
Depletion and Amortization of Property,
Plant and Equipment for the three years
ended December 31, 1993 . . . . . . . . . . . . **
Schedule IX -- Short-Term Borrowings for each
of the three years in the period ended
December 31, 1993 . . . . . . . . . . . . . . . **
Schedule X -- Supplementary Income Statement
Information for each of the three years
in the period ended December 31, 1993 . . . . . **

Schedules other than those listed above are omitted because of the
absence of the conditions under which they are required, or because
the information required is included in the Company's Consolidated
Financial Statements and Notes thereto.
____________________

* The Consolidated Financial Statements listed in the above index
which are included in the Company's Annual Report to Stockholders
for 1993 are hereby incorporated by reference. With the
exception of the pages referred to in Items 6 and 8, the
Company's Annual Report to Stockholders for 1993 is not to be
deemed filed as part of this report.
**Filed herewith.
3. Exhibits:

3(a) Composite Certificate of Incorporation
of MDU Resources Group, Inc., as amended
to date, filed as Exhibit 4(a) in
Registration No. 33-13092 . . . . . . . . . *
3(b) By-laws of MDU Resources Group, Inc.,
as amended to date. . . . . . . . . . . . . **
4(a) Indenture of Mortgage, dated as of
May 1, 1939, as restated in the
Forty-Fifth Supplemental Indenture,
dated as of April 21, 1992, and the
Forty-Sixth through Forty-Eighth
Supplements thereto between the
Company and the New York Trust
Company (The Bank of New York,
successor Corporate Trustee) and
A. C. Downing (W. T. Cunningham,
successor Co-Trustee), filed as
Exhibit 4(a) in Registration
No. 33-66682; and Exhibits 4(e), 4(f)
and 4(g) in Registration No. 33-53896 . . . *
+ 10(a) Management Incentive Compensation Plan,
filed as Exhibit 10(a) in Registration
No. 33-66682. . . . . . . . . . . . . . . . *
+ 10(b) 1992 Key Employee Stock Option Plan,
filed as Exhibit 10(f) in Registration
No. 33-66682. . . . . . . . . . . . . . . . *
+ 10(c) Restricted Stock Bonus Plan, filed as
Exhibit 10(b) in Registration
No. 33-66682. . . . . . . . . . . . . . . . *
+ 10(d) Supplemental Income Security Plan, filed
as Exhibit 10(c) in Registration
No. 33-66682. . . . . . . . . . . . . . . . *
+ 10(e) Directors' Compensation Policy, filed
as Exhibit 10(d) in Registration
No. 33-66682. . . . . . . . . . . . . . . . *
+ 10(f) Deferred Compensation Plan for Directors,
filed as Exhibit 10(e) in Registration
No. 33-66682. . . . . . . . . . . . . . . . *
13 Financial statements and supplementary
data as contained in the Annual Report to
Stockholders for 1993 . . . . . . . . . . . **
21 Subsidiaries of MDU Resources Group, Inc. . **
23(a) Consent of Independent Public Accountants . **
23(b) Consent of Engineer . . . . . . . . . . . . **
23(c) Consent of Engineer . . . . . . . . . . . . **

(b) Reports on Form 8-K.

None.
____________________

* Incorporated herein by reference as indicated.
** Filed herewith.
+ Management contract, compensatory plan or arrangement
required to be filed as an exhibit to this form pursuant
to Item 14(c) of this report.

REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS ON SCHEDULES

To MDU Resources Group, Inc:

We have audited, in accordance with generally accepted
auditing standards, the consolidated financial statements
included in the MDU Resources Group, Inc. Annual Report to
Stockholders incorporated by reference in this Form 10-K, and
have issued our report thereon dated January 25, 1994. Our
audits of the consolidated financial statements were made for the
purpose of forming an opinion on those statements taken as a
whole. The schedules are presented for purposes of complying
with the Securities and Exchange Commission's rules and are not
part of the basic financial statements. These schedules have
been subjected to the auditing procedures applied in the audits
of the basic financial statements and, in our opinion, fairly
state in all material respects the financial data required to be
set forth therein in relation to the basic financial statements
taken as a whole.

/s/ ARTHUR ANDERSEN & CO.
ARTHUR ANDERSEN & CO.

Minneapolis, Minnesota,
January 25, 1994

SCHEDULE V
MDU RESOURCES GROUP, INC.
PROPERTY, PLANT AND EQUIPMENT
For the Year Ended December 31, 1993
(In Thousands)

Column A Column B Column C Column D Column E Column F
Other
Balance Changes Balance
Beginning Additions Add End of
Classification of Year at Cost Retirements (Deduct) Year

Electric --
Intangible. . . . . . . . . $ 115 $ 27 $ --- $ --- $ 142
Production. . . . . . . . . 225,626 3,010 572 (16) 228,048
Transmission. . . . . . . . 107,048 1,724 269 --- 108,503
Distribution. . . . . . . . 109,518 6,459 814 (76) 115,087
General . . . . . . . . . . 36,983 1,998 680 (1,755) 36,546
Plant Acquisition Adjustments 7,781 --- 414 --- 7,367
Electric Plant Held for
Future Use. . . . . . . . 763 --- --- --- 763
Electric Plant Leased to Others --- --- --- 76 76
Construction Work in Progress 4,109 2,978 --- 71 7,158
491,943 16,196 2,749 (1,700)* 503,690
Natural Gas Distribution --
Intangible. . . . . . . . . 235 --- --- --- 235
Distribution. . . . . . . . 101,575 11,979 434 24 113,144
General . . . . . . . . . . 21,969 2,056 953 1,747 24,819
Plant Acquisition Adjustments --- 16 --- --- 16
Construction Work in Progress 1,535 1,422 --- (71) 2,886
125,314 15,473 1,387 1,700* 141,100
Natural Gas Transmission --
Intangible 102 --- --- --- 102
Production and Gathering. . 37,565 1,342 15,443 (64) 23,400
Products Extraction . . . . 1,393 --- 1,390 --- 3
Underground Storage . . . . 17,192 21 --- 4 17,217
Transmission. . . . . . . . 155,149 3,427 6,837 60 151,799
General . . . . . . . . . . 12,933 917 565 --- 13,285
Leased to Others. . . . . . 396 --- 396 --- ---
Production Property Held for
Future Use. . . . . . . . 107 --- --- --- 107
Natural Gas Stored
Underground -- Noncurrent 51,291 --- 2,758 --- 48,533
Plant Acquisition Adjustments 272 --- 11 --- 261
Construction Work in Progress 2,578 1,481 --- --- 4,059
278,978 7,188 27,400 ---* 258,766
Mining and Construction
Materials --
Plant Facilities. . . . . . 102,788 44,555 2,345 (99) 144,899
Construction Work in Progress 1,582 (1,467) --- --- 115
104,370 43,088 2,345 (99) 145,014
Oil and Natural Gas Production --
Exploration and Production. 93,667 24,943 1,777 --- 116,833
$1,094,272 $106,888 $35,658 $ (99) $1,165,403

____________________

*Reclassification between plant accounts.

Plant is depreciated on a straight-line basis as follows:

Electric . . . . . . . . . . . . . . . . . . . .3.2%
Natural Gas Distribution. . . . . . . . . . . . .4.3%
Natural Gas Transmission. . . . . . . . . . . . .3.5%
Mining and Construction Materials . . . . . . . .3.3 to 33.3%

Depletion of natural gas, coal and oil production properties is provided on a
unit-of-production method based on estimated proved recoverable reserves.

SCHEDULE V
MDU RESOURCES GROUP, INC.
PROPERTY, PLANT AND EQUIPMENT
For the Year Ended December 31, 1992
(In Thousands)

Column A Column B Column C Column D Column E Column F
Other
Balance Changes Balance
Beginning Additions Add End of
Classification of Year at Cost Retirements (Deduct) Year

Electric --
Intangible. . . . . . . . . $ 67 $ --- $ --- $ 48 $ 115
Production. . . . . . . . . 224,565 1,258 194 (3) 225,626
Transmission. . . . . . . . 104,744 3,053 748 (1) 107,048
Distribution. . . . . . . . 104,237 6,195 908 (6) 109,518
General . . . . . . . . . . 36,593 1,794 1,066 (338) 36,983
Plant Acquisition Adjustments 8,196 --- 414 (1) 7,781
Electric Plant Held for
Future Use. . . . . . . . --- 752 --- 11 763
Construction Work in Progress 3,910 200 --- (1) 4,109
482,312 13,252 3,330 (291)* 491,943
Natural Gas Distribution --
Intangible. . . . . . . . . 235 --- --- --- 235
Distribution. . . . . . . . 97,496 4,690 611 --- 101,575
General . . . . . . . . . . 21,235 1,437 993 290 21,969
Construction Work in Progress 1,189 345 --- 1 1,535
120,155 6,472 1,604 291* 125,314
Natural Gas Transmission --
Intangible. . . . . . . . . 102 --- --- --- 102
Production and Gathering. . 37,846 254 570 35 37,565
Products Extraction . . . . 1,393 --- --- --- 1,393
Underground Storage . . . . 17,103 141 52 --- 17,192
Transmission. . . . . . . . 148,049 7,713 580 (33) 155,149
General . . . . . . . . . . 12,577 1,145 787 (2) 12,933
Leased to Others. . . . . . 396 --- --- --- 396
Production Property Held for
Future Use. . . . . . . . 107 --- --- --- 107
Natural Gas Stored
Underground -- Noncurrent 52,835 --- 1,544 --- 51,291
Plant Acquisition Adjustments 282 --- 10 --- 272
Construction Work in Progress 879 1,699 --- --- 2,578
271,569 10,952 3,543 ---* 278,978
Mining and Construction
Materials --
Plant Facilities. . . . . . 88,535 14,713 460 --- 102,788
Construction Work in Progress --- 1,582 --- --- 1,582
88,535 16,295 460 --- 104,370
Oil and Natural Gas Production --
Exploration and Production. 68,253 25,778 364 --- 93,667
$1,030,824 $72,749 $9,301 $ --- $1,094,272

____________________

*Reclassification between plant accounts.

Plant is depreciated on a straight-line basis as follows:

Electric . . . . . . . . . . . . . . . . . . . .3.2%
Natural Gas Distribution. . . . . . . . . . . . .4.3%
Natural Gas Transmission. . . . . . . . . . . . .3.1%
Mining and Construction Materials . . . . . . . .3.3 to 33.3%

Depletion of natural gas, coal and oil production properties is provided on a
unit-of-production method based on estimated proved recoverable reserves.

SCHEDULE V
MDU RESOURCES GROUP, INC.
PROPERTY, PLANT AND EQUIPMENT
For the Year Ended December 31, 1991
(In Thousands)

Column A Column B Column C Column D Column E Column F
Other
Balance Changes Balance
Beginning Additions Add End of
Classification of Year at Cost Retirements (Deduct) Year

Electric --
Intangible. . . . . . . . . $ 66 $ --- $ --- $ 1 $ 67
Production. . . . . . . . . 219,371 7,712 2,518 --- 224,565
Transmission. . . . . . . . 103,765 1,317 296 (42) 104,744
Distribution. . . . . . . . 101,712 3,435 959 49 104,237
General . . . . . . . . . . 34,588 2,218 739 526 36,593
Plant Acquisition Adjustments 8,610 --- 414 --- 8,196
Construction Work in Progress 6,595 (2,689) --- 4 3,910
474,707 11,993 4,926 538* 482,312
Natural Gas Distribution --
Intangible. . . . . . . . . 236 --- --- (1) 235
Distribution. . . . . . . . 94,363 3,645 512 --- 97,496
General . . . . . . . . . . 21,015 1,621 867 (534) 21,235
Construction Work in Progress 684 508 --- (3) 1,189
116,298 5,774 1,379 (538)* 120,155
Natural Gas Transmission --
Intangible. . . . . . . . . 102 --- --- --- 102
Production and Gathering. . 38,688 144 973 (13) 37,846
Products Extraction . . . . 1,392 1 --- --- 1,393
Underground Storage . . . . 16,786 321 5 1 17,103
Transmission. . . . . . . . 146,034 2,453 445 7 148,049
General . . . . . . . . . . 11,660 1,396 484 5 12,577
Leased to Others. . . . . . 396 --- --- --- 396
Production Property Held for
Future Use. . . . . . . . 107 --- --- --- 107
Natural Gas Stored
Underground -- Noncurrent 51,797 1,038 --- --- 52,835
Plant Acquisition Adjustments 293 --- 11 --- 282
Construction Work in Progress 1,101 (222) --- --- 879
268,356 5,131 1,918 ---* 271,569
Mining and Construction
Materials --
Plant Facilities. . . . . . 88,477 939 881 --- 88,535
Construction Work in Progress 30 (30) --- --- ---
88,507 909 881 --- 88,535
Oil and Natural Gas Production --
Exploration and Production. 46,290 22,284 321 --- 68,253
$994,158 $46,091 $9,425 $ --- $1,030,824

____________________

*Reclassification between plant accounts.

Plant is depreciated on a straight-line basis as follows:

Electric . . . . . . . . . . . . . . . . . . . .3.3%
Natural Gas Distribution. . . . . . . . . . . . .4.3%
Natural Gas Transmission. . . . . . . . . . . . .3.0%
Mining and Construction Materials . . . . . . . .3.3 to 33.3%

Depletion of natural gas, coal and oil production properties is provided on a
unit-of-production method based on estimated proved recoverable reserves.

SCHEDULE VI
MDU RESOURCES GROUP, INC.
ACCUMULATED DEPRECIATION, DEPLETION AND AMORTIZATION
of Property, Plant and Equipment
For the Year Ended December 31, 1993
(In Thousands)

Column A Column B Column C Column D Column E Column F
Additions Other
Balance Charged to Changes Balance
Beginning Cost and Add End of
Description of Year Expenses(a) Retirements (Deduct) Year

Accumulated Provision for
Depreciation:
Electric --
Intangible . . . . . . . $ 61 $ 27 $ --- $ --- $ 88
Production . . . . . . . . 100,559 6,686 575 (16) 106,654
Transmission . . . . . . . 45,042 2,532 158 1 47,417
Distribution . . . . . . . 49,131 3,693 1,009 1 51,816
General. . . . . . . . . . 17,389 1,751 562 (27) 18,551
Retirement Work in Progress 3,105 --- 78 --- 3,027
215,287 14,689 2,382 (41) 227,553
Natural Gas Distribution --
Intangible . . . . . . . . 102 27 --- --- 129
Distribution . . . . . . . 53,830 4,535 648 426 58,143
General. . . . . . . . . . 10,243 995 499 61 10,800
Retirement Work in Progress (18) --- 14 --- (32)
64,157 5,557 1,161 487 69,040
Natural Gas Transmission --
Production and Gathering . 6,836 1,293 3,056 642 5,715
Products Extraction. . . . 757 38 795 --- ---
Underground Storage. . . . 5,791 397 (1) 2 6,191
Transmission . . . . . . . 77,750 4,539 3,786 8 78,511
General. . . . . . . . . . 6,630 1,014 325 1 7,320
Leased to Others . . . . . 179 4 183 --- ---
Retirement Work in Progress 113 128 195 (1) 45
98,056 7,413 8,339 652 97,782
Mining and Construction
Materials. . . . . . . . . 66,206 5,455 2,299 49 69,411
$443,706 $33,114 $14,181 $1,147 $463,786
Accumulated Provision for
Depletion:
Natural Gas Transmission --
Production . . . . . . . . $ 1,078 $ 18 $ --- $ --- $ 1,096
Mining and Construction
Materials. . . . . . . . . 260 237 --- (148) 349
Oil and Natural Gas Production 24,188 12,034 2 --- 36,220
$ 25,526 $12,289 $ 2 $ (148) $ 37,665

____________________

(a) Includes depreciation on transportation and other equipment that is charged
to construction, operations, maintenance and merchandising accounts.

SCHEDULE VI
MDU RESOURCES GROUP, INC.
ACCUMULATED DEPRECIATION, DEPLETION AND AMORTIZATION
of Property, Plant and Equipment
For the Year Ended December 31, 1992
(In Thousands)

Column A Column B Column C Column D Column E Column F
Additions Other
Balance Charged to Changes Balance
Beginning Cost and Add End of
Description of Year Expenses(a) Retirements (Deduct) Year

Accumulated Provision for
Depreciation:
Electric --
Intangible . . . . . . . . $ 38 $ 23 $ --- $ --- $ 61
Production . . . . . . . . 94,106 6,703 251 1 100,559
Transmission . . . . . . . 43,267 2,475 702 2 45,042
Distribution . . . . . . . 46,660 3,505 1,032 (2) 49,131
General. . . . . . . . . . 16,705 1,773 998 (91) 17,389
Retirement Work in Progress 2,958 --- (147) --- 3,105
203,734 14,479 2,836 (90) 215,287
Natural Gas Distribution --
Intangible . . . . . . . . 75 27 --- --- 102
Distribution . . . . . . . 50,453 4,271 894 --- 53,830
General. . . . . . . . . . 10,051 839 737 90 10,243
Retirement Work in Progress (40) --- (22) --- (18)
60,539 5,137 1,609 90 64,157
Natural Gas Transmission --
Production and Gathering . 6,464 974 449 (153) 6,836
Products Extraction. . . . 665 92 --- --- 757
Underground Storage. . . . 5,501 360 70 --- 5,791
Transmission . . . . . . . 74,008 4,152 564 154 77,750
General. . . . . . . . . . 6,316 983 668 (1) 6,630
Leased to Others . . . . . 168 11 --- --- 179
Retirement Work in Progress 1 118 6 --- 113
93,123 6,690 1,757 --- 98,056
Mining and Construction
Materials. . . . . . . . . 62,157 4,474 440 15 66,206
$419,553 $30,780 $6,642 $ 15 $443,706
Accumulated Provision for
Depletion:
Natural Gas Transmission --
Production . . . . . . . . $ 1,062 $ 16 $ --- $ --- $ 1,078
Mining and Construction
Materials. . . . . . . . . 215 53 8 --- 260
Oil and Natural Gas Production 15,447 8,817 76 --- 24,188
$ 16,724 $ 8,886 $ 84 $ --- $ 25,526

____________________

(a) Includes depreciation on transportation and other equipment that is charged
to construction, operations, maintenance and merchandising accounts.

SCHEDULE VI
MDU RESOURCES GROUP, INC.
ACCUMULATED DEPRECIATION, DEPLETION AND AMORTIZATION
of Property, Plant and Equipment
For the Year Ended December 31, 1991
(In Thousands)

Column A Column B Column C Column D Column E Column F
Additions Other
Balance Charged to Changes Balance
Beginning Cost and Add End of
Description of Year Expenses(a) Retirements (Deduct) Year

Accumulated Provision for
Depreciation:
Electric --
Intangible . . . . . . . . $ 24 $ 13 $ --- $ 1 $ 38
Production . . . . . . . . 89,911 6,767 2,572 --- 94,106
Transmission . . . . . . . 41,167 2,448 328 (20) 43,267
Distribution . . . . . . . 44,331 3,388 1,079 20 46,660
General. . . . . . . . . . 15,462 1,687 672 228 16,705
Retirement Work in Progress 2,952 --- (6) --- 2,958
193,847 14,303 4,645 229 203,734
Natural Gas Distribution --
Intangible . . . . . . . . 48 27 --- --- 75
Distribution . . . . . . . 47,069 4,112 728 --- 50,453
General. . . . . . . . . . 9,859 822 400 (230) 10,051
Retirement Work in Progress (58) --- (18) --- (40)
56,918 4,961 1,110 (230) 60,539
Natural Gas Transmission --
Production and Gathering . 6,436 890 862 --- 6,464
Products Extraction. . . . 572 93 --- --- 665
Underground Storage. . . . 5,161 346 6 --- 5,501
Transmission . . . . . . . 70,226 4,031 249 --- 74,008
General. . . . . . . . . . 5,753 883 320 --- 6,316
Leased to Others . . . . . 158 10 --- --- 168
Retirement Work in Progress (41) 123 81 --- 1
88,265 6,376 1,518 --- 93,123
Mining and Construction
Materials. . . . . . . . . 59,028 4,006 877 --- 62,157
$398,058 $29,646 $8,150 $ (1) $419,553
Accumulated Provision for
Depletion:
Natural Gas Transmission --
Production . . . . . . . . $ 1,049 $ 13 $ --- $ --- $ 1,062
Mining and Construction
Materials. . . . . . . . . 186 29 --- --- 215
Oil and Natural Gas Production 9,460 6,061 74 --- 15,447
$ 10,695 $ 6,103 $ 74 $ --- $ 16,724

____________________

(a) Includes depreciation on transportation and other equipment that is charged
to construction, operations, maintenance and merchandising accounts.

SCHEDULE IX
MDU RESOURCES GROUP, INC.
SHORT-TERM BORROWINGS
For the Years Ended December 31, 1993, 1992 and 1991
(Dollars In Thousands)

Column A Column B Column C Column D Column E Column F
Highest Month Average Weighted
Weighted End Balance Daily Average
Balance Average Outstanding Balance Interest Rate
Category of End of Interest During the Outstanding During the
Short-Term Borrowings Year Rate Year During Year Year

Notes Payable to Banks:
1993 . . . . . . . . $ --- ---% $ --- $ --- ---%
1992 . . . . . . . . $ --- ---% $ --- $ --- ---%
1991 . . . . . . . . $ --- ---% $ --- $ --- ---%

Commercial Paper:
1993 . . . . . . . . $ 9,540 4.2% $33,190 $17,285 3.6%
1992 . . . . . . . . $ 7,775 5.2% $37,875 $22,735 4.0%
1991 . . . . . . . . $ 170 6.5% $24,000 $ 8,788 6.5%

The Company and its subsidiaries had unsecured lines of credit from several
banks totalling $86 million at December 31, 1993, $80 million at
December 31, 1992, and $73 million at December 31, 1991. These line of
credit agreements provide for bank borrowings against the lines and/or
support for commercial paper issues. The agreements provide for commitment
fees at varying rates. The unused portions of the lines of credit are
subject to withdrawal based on the occurrence of certain events.

The weighted average interest rate is calculated by dividing interest
expense for the year by the amount of average daily borrowings outstanding.

SCHEDULE X

MDU RESOURCES GROUP, INC.
SUPPLEMENTARY INCOME STATEMENT INFORMATION
For the Years Ended December 31, 1993, 1992 and 1991
(In Thousands)

Column A Column B
Item Charged to Costs and Expenses
1993 1992 1991

Maintenance and Repairs. . . . . . . . . $21,462 $17,767 $18,334
Taxes, Other Than Income --
Real Estate and Personal Property . . $ 9,598 $ 8,786 $ 8,431
State Severance . . . . . . . . . . . 5,105 5,555 5,968
Other . . . . . . . . . . . . . . . . 8,862 8,458 8,243
$23,565 $22,799 $22,642

Note: Depreciation and amortization of intangible assets, preoperating
costs and similar deferrals, royalties and advertising costs are
omitted as they are each less than 1% of operating revenues.