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.
<PAGE>
<PAGE> 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<PAGE>
<PAGE>
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:
<TABLE>
<CAPTION>
Years Ended December 31,
1993 1992 1991 1990 1989
(In thousands)
<S> <C> <C> <C> <C> <C>
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
</TABLE>
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:
<TABLE>
<CAPTION>
Net Exploratory Net Development
Productive Dry Holes Total Productive Dry Holes Total Total
<S> <C> <C> <C> <C> <C> <C> <C>
1993 2 2 4 5 1 6 10
1992 --- 4 4 2 1 3 7
1991 2 5 7 8 3 11 18
</TABLE>
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.<PAGE>
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.<PAGE>
<PAGE>
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<PAGE>
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.<PAGE>
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.<PAGE>
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.
<PAGE>
<PAGE>
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<PAGE>
<PAGE>
<TABLE>
SCHEDULE V
MDU RESOURCES GROUP, INC.
PROPERTY, PLANT AND EQUIPMENT
For the Year Ended December 31, 1993
(In Thousands)
<CAPTION>
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
<S> <C> <C> <C> <C> <C>
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
</TABLE>
____________________
*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.<PAGE>
<PAGE>
<TABLE> 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
<S> <C> <C> <C> <C> <C>
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
</TABLE>
____________________
*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.<PAGE>
<PAGE>
<TABLE> SCHEDULE V
MDU RESOURCES GROUP, INC.
PROPERTY, PLANT AND EQUIPMENT
For the Year Ended December 31, 1991
(In Thousands)
<CAPTION>
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
<S> <C> <C> <C> <C> <C>
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
</TABLE>
____________________
*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.<PAGE>
<PAGE>
<TABLE> 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)
<CAPTION>
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
<S> <C> <C> <C> <C> <C>
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
</TABLE>
____________________
(a) Includes depreciation on transportation and other equipment that is charged
to construction, operations, maintenance and merchandising accounts.
<PAGE>
<PAGE>
<TABLE> 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)
<CAPTION>
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
<S> <C> <C> <C> <C> <C>
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
</TABLE>
____________________
(a) Includes depreciation on transportation and other equipment that is charged
to construction, operations, maintenance and merchandising accounts.<PAGE>
<PAGE>
<TABLE> 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)
<CAPTION>
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
<S> <C> <C> <C> <C> <C>
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
</TABLE>
____________________
(a) Includes depreciation on transportation and other equipment that is charged
to construction, operations, maintenance and merchandising accounts.
<PAGE>
<PAGE>
<TABLE> SCHEDULE IX
MDU RESOURCES GROUP, INC.
SHORT-TERM BORROWINGS
For the Years Ended December 31, 1993, 1992 and 1991
(Dollars In Thousands)
<CAPTION>
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
<S> <C> <C> <C> <C> <C>
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%
</TABLE>
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.
<PAGE>
<PAGE>
<TABLE>
SCHEDULE X
MDU RESOURCES GROUP, INC.
SUPPLEMENTARY INCOME STATEMENT INFORMATION
For the Years Ended December 31, 1993, 1992 and 1991
(In Thousands)
<CAPTION>
Column A Column B
Item Charged to Costs and Expenses
1993 1992 1991
<S> <C> <C> <C>
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
</TABLE>
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.
Bylaws of
MDU RESOURCES GROUP, INC.
Rev. 11/93<PAGE>
TABLE OF CONTENTS
TO BYLAWS
1. Amendments
2. Certificates of Stock
3. Chairman of the Board
4. Checks
5. Committees
6. Compensation of Directors
7. Directors
8. Directors Indemnified
9. Directors Meetings
10. Dividends
11. Election of Officers
12. Execution of Instruments
13. Execution of Proxies
14. Fiscal Year
15. Inspection of Books
16. Lost Certificate
17. Notices
18. Officers
19. Offices
20. President
21. Qualifications
22. Record Date
23. Registered Stockholders
24. Seal
25. Secretary
26. Stockholders Meetings
27. Transfer of Stock
28. Treasurer
29. Vice President<PAGE>
BYLAWS OF
MDU RESOURCES GROUP, INC.
OFFICES
1.01 Registered Office. The registered office shall be in the
City of Wilmington, County of New Castle, State of Delaware.
1.02 Other Offices. The Corporation may also have offices at
such other places, both within and without the State of Delaware,
as the Board of Directors may from time to time determine or the
business of the Corporation may require.
MEETINGS OF STOCKHOLDERS
2.01 Place of Meetings. All meetings of the stockholders for
the election of Directors shall be held in the City of Bismarck,
State of North Dakota, at such place as may be fixed from time to
time by the Board of Directors, or at such other place, either
within or without the State of Delaware, as shall be designated
from time to time by the Board of Directors and stated in the
notice of the meeting. Meetings of stockholders for any other
purpose may be held at such time and place, within or without the
State of Delaware, as shall be stated in the notice of the
meeting or in a duly executed waiver of notice thereof.
2.02 Annual Meetings. Annual meetings of stockholders,
commencing with the year 1973, shall be held on the fourth
Tuesday of April in each year, if not a legal holiday, and if a
legal holiday, then on the next secular day following, at
11:00 A.M., or at such other date and time as shall be designated
from time to time by the Board of Directors and stated in the
notice of the meeting, at which they shall elect by a plurality
vote, by written ballot, a Board of Directors, and transact such
other business as may properly be brought before the meeting.
2.03 Notice of Annual Meeting. Written notice of the annual
meeting, stating the place, date and hour of the meeting, shall
be given to each stockholder entitled to vote at such meeting not
less than ten nor more than sixty days before the date of the
meeting.
2.04 Stockholders List. The officer who has charge of the
stock ledger of the Corporation shall prepare and make, at least
ten days before every meeting of stockholders, a complete list of
the stockholders entitled to vote at the meeting, arranged in
alphabetical order, and showing the address of each stockholder
and the number of shares registered in the name of each
stockholder. Such list shall be open to the examination of any
stockholder, for any purpose germane to the meeting, during
ordinary business hours, for a period of at least ten days prior
to the meeting, either at a place within the City where the
meeting is to be held, which place shall be specified in the
notice of the meeting, or, if not so specified, at the place
where the meeting is to be held. The list shall also be produced
and kept at the time and place of the meeting during the whole
time thereof, and may be inspected by any stockholder who is
present.
2.05 Notice of Special Meeting. Written notice of a special
meeting, stating the place, date and hour of the meeting and the
purpose or purposes for which the meeting is called, shall be
given not less than ten nor more than sixty days before the date
of the meeting, to each stockholder entitled to vote at such
meeting.
2.06 Quorum. The holders of a majority of the stock issued and
outstanding and entitled to vote in person or by proxy, shall
constitute a quorum at all meetings of the stockholders for the
transaction of business, except as provided herein and except as
otherwise provided by statute or by the Certificate of
Incorporation. If, however, such quorum shall not be present or
represented at any meeting of the stockholders, the stockholders
entitled to vote thereat, present in person or represented by
proxy, shall have power to adjourn the meeting from time to time,
without notice other than announcement at the meeting, until a
quorum shall be present or represented. At such adjourned meeting
at which a quorum shall be present or represented, any business
may be transacted which might have been transacted at the meeting
as originally notified. If the adjournment is for more than
thirty days, or if, after the adjournment, a new record date is
fixed for the adjourned meeting, a notice of the adjourned
meeting shall be given to each stockholder of record entitled to
vote at the meeting.
2.07 Voting Rights. When a quorum is present at any meeting,
the vote of the holders of a majority of the stock having voting
power, present in person or represented by proxy, shall decide
any question brought before such meeting, unless the question is
one upon which, by express provision of the statutes, the
Certificate of Incorporation or these Bylaws, a different vote is
required, in which case such express provision shall govern and
control the decision of such question. Unless otherwise provided
in the Certificate of Incorporation, each stockholder shall, at
every meeting of the stockholders, be entitled to one vote in
person or by proxy for each share of the capital stock having
voting power held by such stockholder, but no proxy shall be
voted on after three years from its date, unless the proxy
provides for a longer period.
DIRECTORS
3.01 Authority of Directors. The business of the Corporation
shall be managed by its Board of Directors which may exercise all
such powers of the Corporation and do all such lawful acts and
things as are not by statute or by the Certificate of
Incorporation or by these Bylaws directed or required to be
exercised or done by the stockholders.
3.02 Qualifications. No person shall be eligible as a Director
of the Corporation who at the time of his election has passed his
seventieth birthday, provided that this age qualification shall
not apply to those persons who are officers of the Corporation.
Except for those persons who have served as Chief Executive
Officer of the Corporation, a person shall be ineligible as a
Director if at the time of his election he is a retired officer
of the Corporation. A person who has served as Chief Executive
Officer of the Corporation shall be ineligible as a Director if
at the time of his election he has been retired as Chief
Executive Officer for more than five years. The Board of
Directors may elect from those persons who have been members of
the Board of Directors, Directors Emeritus.
3.03 Place of Meetings. The Board of Directors of the
Corporation may hold meetings, both regular and special, either
within or without the State of Delaware.
3.04 Annual Meetings. The first meeting of each newly elected
Board of Directors shall be held at such time and place as shall
be specified in a notice given as herein provided for regular
meetings of the Board of Directors, or as shall be specified in a
duly executed waiver of notice thereof.
3.05 Regular Meetings. Regular meetings of the Board of
Directors may be held at the office of the Corporation in
Bismarck, North Dakota, on the second Thursday following the
first Monday of February, May, August and November of each year;
provided, however, that if a legal holiday, then on the next
preceding day that is not a legal holiday. Regular meetings of
the Board of Directors may be held at other times and other
places within or without the State of North Dakota on at least
five days notice to each Director, either personally or by mail,
telephone or telegram.
3.06 Special Meetings. Special meetings of the Board may be
called by the Chairman or President on three days notice to each
Director, either personally or by mail, telephone or telegram;
special meetings shall be called by the Chairman, President or
Secretary in like manner and on like notice on the written
request of a majority of the Board of Directors.
3.07 Quorum. At all meetings of the Board, a majority of the
Directors shall constitute a quorum for the transaction of
business and the act of a majority of the Directors present at
any such meeting at which there is a quorum shall be the act of
the Board of Directors, except as may be otherwise specifically
provided by statute, the Certificate of Incorporation or by these
Bylaws. If a quorum shall not be present at any meeting of the
Board of Directors, the Directors present may adjourn the meeting
from time to time, without notice other than announcement at the
meeting, until a quorum shall be present.
3.08 Participation of Directors by Conference Telephone.
Unless otherwise restricted by the Certificate of Incorporation
or these Bylaws, any member of the Board, or of any committee
designated by the Board, may participate in any meeting of such
Board or committee by means of conference telephone or similar
communication equipment by means of which all persons
participating in the meeting can hear each other. Participation
in any meeting by means of conference telephone or similar
communications equipment shall constitute presence in person at
such meeting.
3.09 Written Action of Directors. Unless otherwise restricted
by the Certificate of Incorporation or these Bylaws, any action
required or permitted to be taken at any meeting of the Board of
Directors or of any committee thereof may be taken without a
meeting, if all members of the Board or committee, as the case
may be, consent thereto in writing, and the writing or writings
are filed with the minutes of proceedings of the Board or
committee.
3.10 Committees. The Board of Directors may by resolution
passed by a majority of the whole Board designate one or more
committees, each committee to consist of two or more Directors of
the Corporation. The Board may designate one or more Directors as
alternate members of any committee who may replace any absent or
disqualified member at any meeting of the committee. In the
absence or disqualification of a member of a committee, the
member or members thereof present at any meeting and not
disqualified from voting, whether or not he or they constitute a
quorum, may unanimously appoint another member of the Board of
Directors to act at the meeting in the place of any such absent
or disqualified member. The Chairman of the Board shall appoint
another member of the Board of Directors to fill any committee
vacancy which may occur. Any such committee shall have, and may
exercise, the power and authority specifically granted by the
Board to the committee, but no such committee shall have the
power or authority to amend the Certificate of Incorporation,
adopt an agreement of merger or consolidation, recommend to the
stockholders the sale, lease or exchange of the Corporation s
property and assets, recommend to the stockholders a dissolution
of the Corporation or a revocation of a dissolution, or amend the
Bylaws of the Corporation. Such committee or committees shall
have such name or names as may be determined from time to time by
resolution adopted by the Board of Directors.
3.11 Reports of Committees. Each committee shall keep regular
minutes of its meetings and report the same to the Board of
Directors when required.
3.12 Compensation of Directors. Unless otherwise restricted by
the Certificate of Incorporation, the Board of Directors shall
have the authority to fix the compensation of Directors. The
Directors may be paid their expenses, if any, of attendance at
each meeting of the Board of Directors and may be paid a fixed
sum for attendance at each meeting of the Board of Directors or a
stated salary as Director. No such payment shall preclude any
Director from serving the Corporation in any other capacity and
receiving compensation therefor. Members of special or standing
committees may be allowed compensation for attending committee
meetings.
NOTICES
4.01 Notices. Whenever, under the provisions of the statutes
or of the Certificate of Incorporation or of these Bylaws, notice
is required to be given to any Director or stockholder, it shall
not be construed to mean personal notice, but such notice may be
given in writing, by mail, addressed to such Director or
stockholder, at his address as it appears on the records of the
Corporation, with postage thereon prepaid, and such notice shall
be deemed to be given at the time when the same shall be
deposited in the United States mail. Notice to Directors may also
be given by telegram or telephone.
4.02 Waiver. Whenever any notice is required to be given under
the provisions of the statutes or of the Certificate of
Incorporation or of these Bylaws, a waiver thereof in writing,
signed by the person or persons entitled to said notice, whether
before or after the time stated therein, shall be deemed
equivalent thereto.
OFFICERS
5.01 Election, Qualifications. The officers of the Corporation
shall be chosen by the Board of Directors at its first meeting
after each annual meeting of stockholders and shall be a Chairman
of the Board, a President, a Vice President, a Secretary and a
Treasurer. The Board of Directors may also choose additional Vice
Presidents, and one or more Assistant Vice Presidents, Assistant
Secretaries and Assistant Treasurers. Any number of offices may
be held by the same person, unless the Certificate of
Incorporation or these Bylaws otherwise provide.
5.02 Additional Officers. The Board of Directors may appoint
such other officers and agents as it shall deem necessary, who
shall hold their offices for such terms and shall exercise such
powers and perform such duties as shall be determined from time
to time by the Board.
5.03 Salaries. The salaries of all principal officers of the
Corporation shall be fixed by the Board of Directors.
5.04 Term. The officers of the Corporation shall hold office
until their successors are chosen and qualify. Any officer
elected or appointed by the Board of Directors may be removed at
any time by the affirmative vote of a majority of the Board of
Directors. Any vacancy occurring in any office of the Corporation
shall be filled by the Board of Directors.
5.05 Chairman of the Board. The Chairman of the Board shall
preside at all meetings of the stockholders and Directors and,
subject to the Board of Directors, shall determine the general
policies of the Corporation.
5.06 The President. The President shall preside at all
meetings of the stockholders and the Board of Directors in the
absence of the Chairman of the Board, shall have general and
active management of the business of the Corporation and shall
see that all orders and resolutions of the Board of Directors are
carried into effect.
5.07 The Vice Presidents. In the absence of the President or
in the event of his inability or refusal to act, the Vice
President (or in the event there be more than one Vice President,
the Vice Presidents in the order designated, or in the absence of
any designation, then in the order of their election) shall
perform the duties of the President, and when so acting, shall
have all the powers of and be subject to all the restrictions
upon the President. The Vice Presidents shall perform such other
duties and have such other powers as the Board of Directors may
from time to time prescribe.
5.08 The Secretary and Assistant Secretaries. The Secretary
shall record all the proceedings of the meetings of the
stockholders and Directors in a book to be kept for that purpose.
He shall give, or cause to be given, notice of all meetings of
the stockholders and special meetings of the Board of Directors,
and shall perform such other duties as may be prescribed by the
Board of Directors or President, under whose supervision he shall
be. He shall have custody of the corporate seal of the
Corporation and he, or an assistant secretary, shall have
authority to affix the same to any instrument requiring it. The
Board of Directors may give general authority to any other
officer to affix the seal of the Corporation.
The Assistant Secretary, or if there be more than one,
the Assistant Secretaries in the order determined by the Board of
Directors (or if there be no such determination, then in the
order of their election) shall, in the absence of the Secretary
or in the event of his inability or refusal to act, perform the
duties and exercise the powers of the Secretary and shall perform
such other duties and have such other powers as the Board of
Directors may from time to time prescribe.
5.09 Treasurer and Assistant Treasurers. The Treasurer shall
have the custody of the corporate funds and securities and shall
keep full and accurate accounts of receipts and disbursements in
books belonging to the Corporation and shall deposit all moneys
and other valuable effects in the name and to the credit of the
Corporation in such depositories as may be designated by the
Board of Directors.
He shall disburse the funds of the Corporation as may be
ordered by the Board of Directors, taking proper vouchers for
such disbursements, and shall render to the President and the
Board of Directors, at its regular meetings, or when the Board of
Directors so requires, an account of all his transactions as
Treasurer and of the financial condition of the Corporation.
If required by the Board of Directors, he shall give the
Corporation a bond (which shall be renewed every six years) in
such sum and with such surety or sureties as shall be
satisfactory to the Board of Directors for the faithful
performance of the duties of his office and for the restoration
to the Corporation, in case of his death, resignation, retirement
or removal from office, of all books, papers, vouchers, money and
other property of whatever kind in his possession or under his
control belonging to the Corporation.
The Assistant Treasurer, or if there shall be more than
one, the Assistant Treasurers in the order determined by the
Board of Directors (or if there be no such determination, then in
the order of their election), shall, in the absence of the
Treasurer or in the event of his inability or refusal to act,
perform the duties and exercise the powers of the Treasurer and
shall perform such other duties and have such other powers as the
Board of Directors may from time to time prescribe.
5.10 Authority and Duties. In addition to the foregoing
authority and duties, all officers of the Corporation shall
respectively have such authority and perform such duties in the
management of the business of the Corporation as may be
designated from time to time by the Board of Directors.
5.11 Execution of Instruments. All deeds, bonds, mortgages,
notes, contracts and other instruments requiring the seal of the
Corporation shall be executed on behalf of the Corporation by the
Chairman, President or a Vice President and attested by the
Secretary or an Assistant Secretary or by the Treasurer or an
Assistant Treasurer, except where the execution and attestation
thereof shall be expressly delegated by the Board of Directors to
some other officer or agent of the Corporation. When authorized
by the Board of Directors, the signature of any officer or agent
of the Corporation may be a facsimile.
5.12 Execution of Proxies. All capital stocks in other
corporations owned by this Corporation shall be voted at the
meetings, regular and/or special, of stockholders of said other
corporations by the Chairman or President of this Corporation,
or, in the absence of either of them, by a Vice President, and in
the event of the presence of more than one Vice President of this
Corporation, then by a majority of said Vice Presidents present
at such stockholders meetings, and the Chairman, President and
Secretary of this Corporation are hereby authorized to execute in
the name and under the seal of this Corporation proxies in such
form as may be required by the corporations whose stock may be
owned by this Corporation, naming as the attorney authorized to
act in said proxy such individual or individuals as to said
Chairman or President and Secretary shall seem advisable, and the
attorney or attorneys so named in said proxy shall, until the
revocation or expiration thereof, vote said stock at such
stockholders meetings only in the event that the Chairman,
President nor any Vice President of this Corporation shall be
present thereat.
CERTIFICATES OF STOCK
6.01 Certificates. Every holder of stock in the Corporation
shall be entitled to have a certificate, signed by, or in the
name of the Corporation by, the Chairman or Vice Chairman of the
Board of Directors, or the President or a Vice President and by
the Treasurer or an Assistant Treasurer, or the Secretary or an
Assistant Secretary of the Corporation, certifying the number of
shares owned by him in the Corporation.
6.02 Signatures. Any of or all the signatures on the
certificates may be facsimile. In case any officer, transfer
agent or registrar who has signed or whose facsimile signature
has been placed upon a certificate shall have ceased to be such
officer, transfer agent or registrar before such certificate is
issued, it may be issued by the Corporation with the same effect
as if he were such officer, transfer agent or registrar at the
date of issue.
6.03 Special Designation on Certificates. If the Corporation
shall be authorized to issue more than one class of stock or more
than one series of any class, the powers, designations,
preferences and relative, participating, optional or other
special rights of each class of stock or series thereof and the
qualifications, limitations, or restrictions of such preferences
and/or rights shall be set forth in full or summarized on the
face or back of the certificate which the Corporation shall issue
to represent such class or series of stock, provided, that,
except as otherwise provided in Section 202 of the General
Corporation Law of Delaware in lieu of the foregoing
requirements, there may be set forth on the face or back of the
certificate which the Corporation shall issue to represent such
class or series of stock, a statement that the Corporation will
furnish, without charge to each stockholder who so requests, the
powers, designations, preferences and relative, participating,
optional or other special rights of each class of stock or series
thereof and the qualifications, limitations or restrictions of
such preferences and/or rights.
6.04 Lost Certificates. The Board of Directors may direct a
new certificate or certificates to be issued in place of any
certificate or certificates theretofore issued by the Corporation
alleged to have been lost, stolen or destroyed, upon the making
of an affidavit of that fact by the person claiming the
certificate of stock to be lost, stolen or destroyed. When
authorizing such issue of a new certificate or certificates, the
Board of Directors may, in its discretion and as a condition
precedent to the issuance thereof, require the owner of such
lost, stolen or destroyed certificate or certificates, or his
legal representative, to advertise the same in such manner as it
shall require and/or to give the Corporation a bond in such sum
as it may direct as indemnity against any claim that may be made
against the Corporation with respect to the certificate alleged
to have been lost, stolen or destroyed.
6.05 Transfers of Stock. Upon surrender to the Corporation or
the transfer agent of the Corporation of a certificate for shares
duly endorsed or accompanied by proper evidence of succession,
assignation or authority to transfer, it shall be the duty of the
Corporation to issue a new certificate to the person entitled
thereto, cancel the old certificate and record the transaction
upon its books.
6.06 Record Date. In order that the Corporation may determine
the stockholders entitled to notice of or to vote at any meeting
of stockholders or any adjournment thereof, or to express consent
to corporate action in writing without a meeting, or entitled to
receive payment of any dividend or other distribution or
allotment of any rights, or entitled to exercise any rights in
respect of any change, conversion or exchange of stock or for the
purpose of any other lawful action, the Board of Directors may
fix, in advance, a record date, which shall not be more than
sixty days nor less than ten days before the date of such
meeting, nor more than sixty days prior to any other action. A
determination of stockholders of record entitled to notice of or
to vote at a meeting of stockholders shall apply to any
adjournment of the meeting; provided, however, that the Board of
Directors may fix a new record date for the adjourned meeting.
6.07 Registered Stockholders. The Corporation shall be
entitled to recognize the exclusive right of a person registered
on its books as the owner of shares to receive dividends, and to
vote as such owner, and to hold liable for calls and assessments
a person registered on its books as the owner of shares, and
shall not be bound to recognize any equitable or other claim to
or interest in such share or shares on the part of any other
person, whether or not it shall have express or other notice
thereof, except as otherwise provided by the laws of Delaware.
GENERAL PROVISIONS
7.01 Dividends. Dividends upon the capital stock of the
Corporation, subject to the provisions of the Certificates of
Incorporation, if any, may be declared by the Board of Directors
at any regular or special meeting, pursuant to law. Dividends may
be paid in cash, in property, or in shares of the capital stock,
subject to the provisions of the Certificates of Incorporation.
Before payment of any dividend, there may be set aside
out of the funds of the Corporation available for dividends such
sum or sums as the Directors from time to time, in their absolute
discretion, think proper as a reserve or reserves to meeting
contingencies, or for equalizing dividends, or for repairing or
maintaining any property of the Corporation, or for such other
purpose as the Directors shall think conducive to the interest of
the Corporation, and the Directors may modify or abolish any such
reserve in the manner in which it was created.
7.02 Checks. All checks or demands for money and notes of the
Corporation shall be signed by such officer or officers or such
other person or persons as the Board of Directors may from time
to time designate or as designated by an officer of the company
if so authorized by the Board of Directors.
7.03 Fiscal year. The fiscal year of the Corporation shall be
the calendar year.
7.04 Seal. The corporate seal shall have inscribed thereon the
name of the Corporation, the year of its organization and the
words "Corporate Seal, Delaware." The seal may be used by causing
it or a facsimile thereof to be impressed or affixed or
imprinted, or otherwise.
7.05 Inspection of Books and Records. Any stockholder of
record, in person or by attorney or other agent, shall, upon
written demand under oath stating the purpose thereof, have the
right, during the usual hours of business, to inspect for any
proper purpose the Corporation s stock ledger, a list of its
stockholders, and its other books and records, and to make copies
or extracts therefrom. A proper purpose shall mean a purpose
reasonably related to such person s interest as a stockholder. In
every instance where an attorney or other agent shall be the
person who seeks the right to inspection, the demand under oath
shall be accompanied by a power of attorney or such other writing
which authorizes the attorney or other agent to so act on behalf
of the stockholder. The demand under oath shall be directed to
the Corporation at its registered office in the State of Delaware
or at its principal place of business in Bismarck, North Dakota.
7.06 Amendments. These Bylaws may be altered, amended or
repealed or new Bylaws may be adopted by the stockholders or by
the Board of Directors, when such power is conferred upon the
Board of Directors by the Certificate of Incorporation, at any
regular meeting of the stockholders or of the Board of Directors
or at any special meeting of the stockholders or of the Board of
Directors if notice of such alteration, amendment, repeal or
adoption of new Bylaws be contained in the notice of such special
meeting.
7.07 Indemnification of Officers, Directors, Employees and
Agents; Insurance.
(a) The Corporation shall indemnify any person who was or
is a party or is threatened to be made a party to any threatened
pending or completed action, suit or proceeding, whether civil,
criminal, administrative or investigative (other than an action
by or in the right of the Corporation) by reason of the fact that
he is or was a director, officer, employee or agent of the
Corporation, or is or was serving at the request of the
Corporation as a director, officer, employee or agent of another
corporation, partnership, joint venture, trust or other
enterprise, against expenses (including attorneys fees),
judgments, fines and amounts paid in settlement actually and
reasonably incurred by him in connection with such action, suit
or proceeding if he acted in good faith and in a manner he
reasonably believed to be in or not opposed to the best interests
of the Corporation, and, with respect to any criminal action or
proceeding, had no reasonable cause to believe his conduct was
unlawful. The termination of any action, suit or proceeding by
judgment, order, settlement, conviction, or upon a plea of nolo
contendere or its equivalent, shall not, of itself, create a
presumption that the person did not act in good faith and in a
manner which he reasonably believed to be in or not opposed to
the best interest of the Corporation, and, with respect to any
criminal action or proceeding, had reasonable cause to believe
that his conduct was unlawful.
(b) The Corporation shall indemnify any person who was or
is a party or is threatened to be made a party to any threatened,
pending or completed action or suit by or in the right of the
Corporation to procure a judgment in its favor by reason of the
fact that he is or was a director, officer, employee or agent of
the Corporation, or is or was serving at the request of the
Corporation as a director, officer, employee or agent of another
corporation, partnership, joint venture, trust or other
enterprise against expenses (including attorneys fees) actually
and reasonably incurred by him in connection with the defense or
settlement of such action or suit if he acted in good faith and
in a manner he reasonably believed to be in or not opposed to the
best interests of the Corporation and except that no
indemnification shall be made in respect of any claim, issue or
matter as to which such person shall have been adjudged to be
liable to the Corporation, unless and only to the extent that the
Court of Chancery or the court in which such action or suit was
brought, shall determine upon application that, despite the
adjudication of liability but in view of all the circumstances of
the case, such person is fairly and reasonably entitled to
indemnity for such expenses which the Court of Chancery or such
other court shall deem proper.
(c) To the extent that a director, officer, employee or
agent of a corporation has been successful on the merits or
otherwise in defense of any action, suit or proceeding referred
to in subsections (a) and (b), or in defense of any claim, issue
or matter therein, he shall be indemnified against expenses
(including attorneys fees) actually and reasonably incurred by
him in connection therewith.
(d) Any indemnification under the foregoing provisions of
this Section (unless ordered by a court) shall be made by the
Corporation only as authorized in the specific case upon a
determination that indemnification of the director, officer,
employee or agent is proper in the circumstances because he has
met the applicable standard of conduct as set forth in
subsections (a) and (b) of this Section. Such determination shall
be made (i) by the Board of Directors by a majority vote of a
quorum consisting of directors who were not parties to such
action, suit or proceeding, or (ii) if such a quorum is not
obtainable, or, even if obtainable, a quorum of disinterested
directors so directs, by independent legal counsel in a written
opinion, or (iii) by the stockholders.
(e) Expenses (including attorneys fees) incurred by an
officer or director in defending any civil, criminal,
administrative or investigative action, suit or proceeding shall
be paid by the Corporation in advance of the final disposition of
such action, suit or proceeding upon receipt of an undertaking by
or on behalf of the director or officer to repay such amount if
it shall ultimately be determined that he is not entitled to be
indemnified by the Corporation as authorized in this Section.
Once the Corporation has received the undertaking, the
Corporation shall pay the officer or director within 30 days of
receipt by the Corporation of a written application from the
officer or director for the expenses incurred by that officer or
director. In the event the Corporation fails to pay within the
30-day period, the applicant shall have the right to sue for
recovery of the expenses contained in the written application
and, in addition, shall recover all attorneys fees and expenses
incurred in the action to enforce the application and the rights
granted in this Section 7.07. Expenses (including attorneys
fees) incurred by other employees and agents shall be paid upon
such terms and conditions, if any, as the Board of Directors
deems appropriate.
(f) The indemnification and advancement of expenses
provided by, or granted pursuant to, the other subsections of
this Section shall not be deemed exclusive of any other rights to
which those seeking indemnity or advancement of expenses may be
entitled under any bylaw, agreement, vote of stockholders or
disinterested directors or otherwise, both as to action in his
official capacity and as to action in another capacity while
holding such office.
(g) The Corporation may purchase and maintain insurance
on behalf of any person who is or was a director, officer,
employee or agent of the Corporation, or is or was serving at the
request of the Corporation as a director, officer, employee or
agent of another corporation, partnership, joint venture, trust
or other enterprise, against any liability asserted against him
and incurred by him in any such capacity, or arising out of his
status as such, whether or not the Corporation would have the
power to indemnify him against such liability under the
provisions of this Section.
(h) For the purposes of this Section, references to "the
Corporation" include all constituent corporations absorbed in a
consolidation or merger, as well as the resulting or surviving
corporation, so that any person who is or was a director,
officer, employee or agent of such a constituent corporation or
is or was serving at the request of such constituent corporation
as a director, officer, employee or agent of another corporation,
partnership, joint venture, trust or other enterprise, shall
stand in the same position under the provisions of this Section
with respect to the resulting or surviving corporation as he
would if he had served the resulting or surviving corporation in
the same capacity.
(i) For purposes of this Section, references to "other
enterprises" shall include employee benefit plans; references to
"fines" shall include any excise taxes assessed on a person with
respect to any employee benefit plan; and references to "serving
at the request of the Corporation" shall include any service as a
director, officer, employee or agent of the Corporation which
imposes duties on, or involves services by, such director,
officer, employee or agent with respect to an employee benefit
plan, its participants or beneficiaries; and a person who acted
in good faith and in a manner he reasonably believed to be in the
interest of the participants and beneficiaries of an employee
benefit plan shall be deemed to have acted in a manner "not
opposed to the best interests of the Corporation" as referred to
in this Section.
(j) The indemnification and advancement of expenses
provided by, or granted pursuant to, this Section shall, unless
otherwise provided when authorized or ratified, continue as to a
person who has ceased to be a director, officer, employee or
agent and shall inure to the benefit of the heirs, executors and
administrators of such a person.
[TEXT]
MDU RESOURCES GROUP, INC.
1993 FINANCIAL REPORT
REPORT OF MANAGEMENT
The management of MDU Resources Group, Inc. is responsible for the
preparation, integrity and objectivity of the financial information
contained in the consolidated financial statements and elsewhere in
this Annual Report. The financial statements have been prepared in
conformity with generally accepted accounting principles as applied to
its regulated and non-regulated businesses and necessarily include
some amounts that are based on informed judgments and estimates of
management.
To meet its responsibilities with respect to financial information,
management maintains and enforces a system of internal accounting
controls designed to provide assurance, on a cost effective basis,
that transactions are carried out in accordance with management's
authorizations and that assets are safeguarded against loss from
unauthorized use or disposition. The system includes an
organizational structure which provides an appropriate segregation of
responsibilities, careful selection and training of personnel, written
policies and procedures and periodic reviews by the internal audit
department. In addition, the company has a policy which requires all
employees to acknowledge their responsibility to maintain a high
standard of ethical conduct. Management believes that these measures
provide for a system that is effective and reasonably assures that all
transactions are properly recorded for the preparation of financial
statements. Management modifies and improves its system of internal
accounting controls in response to changes in business conditions.
The company's internal audit department is charged with the
responsibility for determining compliance with company procedures.
The Board of Directors, through its audit committee which is comprised
entirely of outside directors, oversees management's responsibilities
for financial reporting. The audit committee meets regularly with
management, the internal auditors and Arthur Andersen & Co.,
independent public accountants, to discuss auditing and financial
matters and to assure that each is carrying out its responsibilities.
The internal auditors and Arthur Andersen & Co. have full and free
access to the audit committee, without management present, to discuss
auditing, internal accounting control and financial reporting matters.
Arthur Andersen & Co. is engaged to express an opinion on the
financial statements. Their audit is conducted in accordance with
generally accepted auditing standards and includes examining, on a
test basis, supporting evidence, assessing the company's accounting
principles used and significant estimates made by management and
evaluating the overall financial statement presentation to the extent
necessary to allow them to report on the fairness, in all material
respects, of the financial condition and operating results of the
company.<PAGE>
<PAGE>
<TABLE>
CONSOLIDATED STATEMENTS OF INCOME
MDU RESOURCES GROUP, INC.
<CAPTION>
Years ended December 31, 1993 1992 1991
(In thousands, except per share amounts)
<S> <C> <C> <C>
Operating revenues:
Electric . . . . . . . . . . . . . . $131,109 $123,908 $128,708
Natural gas. . . . . . . . . . . . . 178,981 159,438 173,865
Mining and construction materials. . 90,397 45,032 41,201
Oil and natural gas production . . . 39,125 33,797 33,939
439,612 362,175 377,713
Operating expenses:
Fuel and purchased power . . . . . . 41,298 37,892 38,379
Purchased natural gas sold . . . . . 78,121 58,420 66,559
Operation and maintenance. . . . . . 167,374 126,311 128,253
Depreciation, depletion and
amortization . . . . . . . . . . . 45,162 39,694 36,577
Taxes, other than income . . . . . . 23,565 22,799 22,642
355,520 285,116 292,410
Operating income:
Electric . . . . . . . . . . . . . . 30,520 30,188 34,647
Natural gas distribution . . . . . . 4,730 4,509 8,518
Natural gas transmission . . . . . . 20,108 21,331 19,904
Mining and construction materials. . 16,984 11,532 9,682
Oil and natural gas production . . . 11,750 9,499 12,552
84,092 77,059 85,303
Other income -- net . . . . . . . . . 3,877 273 5,957
Interest expense -- net . . . . . . . 25,273 25,227 27,952
Carrying costs on natural gas
repurchase commitment (Note 5) . . . 3,897 5,834 8,483
Income before taxes. . . . . . . . . . 58,799 46,271 54,825
Income taxes . . . . . . . . . . . . . 19,982 10,900 16,808
Income before cumulative effect
of accounting change . . . . . . . . 38,817 35,371 38,017
Cumulative effect of accounting
change (Note 2). . . . . . . . . . . 5,521 --- ---
Net income . . . . . . . . . . . . . . 44,338 35,371 38,017
Dividends on preferred stocks. . . . . 802 807 812
Earnings on common stock . . . . . . . $ 43,536 $ 34,564 $ 37,205
Earnings per common share:
Earnings before cumulative effect
of accounting change. . . . . . . . $ 2.00 $ 1.82 $ 1.96
Cumulative effect of accounting
change. . . . . . . . . . . . . . . .29 --- ---
Earnings . . . . . . . . . . . . . . $ 2.29 $ 1.82 $ 1.96
Dividends per common share . . . . . . $ 1.52 $ 1.46 $ 1.435
Average common shares outstanding . . 18,985 18,985 18,985
Pro forma amounts assuming
retroactive application of
accounting change:
Net income . . . . . . . . . . . . . $ 38,817 $ 35,852 $ 37,619
Earnings per common share. . . . . . $ 2.00 $ 1.85 $ 1.94
The accompanying notes are an integral part of these consolidated
statements.
/TABLE
<PAGE>
<PAGE>
<TABLE>
CONSOLIDATED BALANCE SHEETS
MDU RESOURCES GROUP, INC.
<CAPTION>
December 31, 1993 1992 1991
(In thousands)
<S> <C> <C> <C>
ASSETS
Property, plant and equipment:
Electric . . . . . . . . . . . . . $ 503,690 $ 491,943 $ 482,312
Natural gas distribution . . . . . 141,100 125,314 120,155
Natural gas transmission . . . . . 258,766 278,978 271,569
Mining and construction materials. 145,014 104,370 88,535
Oil and natural gas production . . 116,833 93,667 68,253
1,165,403 1,094,272 1,030,824
Less accumulated depreciation,
depletion and amortization . . . 501,451 469,232 436,277
663,952 625,040 594,547
Current assets:
Cash and cash equivalents. . . . . 71,699 66,838 54,593
Receivables. . . . . . . . . . . . 67,553 57,902 43,334
Inventories. . . . . . . . . . . . 19,415 18,214 16,228
Exchange natural gas receivable. . 727 25,195 25,992
Deferred income taxes. . . . . . . 32,243 18,962 11,335
Other prepayments and
current assets . . . . . . . . . 13,535 15,302 10,913
205,172 202,413 162,395
Natural gas available under
repurchase commitment (Note 5) . . 79,031 92,038 99,449
Investments. . . . . . . . . . . . . 16,858 61,934 67,188
Deferred charges and other assets. . 76,038 43,085 41,112
$1,041,051 $1,024,510 $ 964,691
CAPITALIZATION AND LIABILITIES
Capitalization (see separate
statements):
Common stockholders' investment. . $ 318,131 $ 303,452 $ 296,605
Preferred stocks . . . . . . . . . 17,100 17,200 17,300
Long-term debt . . . . . . . . . . 231,770 249,845 220,623
567,001 570,497 534,528
Commitments and contingencies
(Notes 3, 4, 5, 6, 15 and 18). . . --- --- ---
Current liabilities:
Short-term borrowings. . . . . . . 9,540 7,775 ---
Accounts payable . . . . . . . . . 24,967 25,397 18,495
Taxes payable. . . . . . . . . . . 9,204 8,958 10,120
Other accrued liabilities,
including reserved revenues. . . 105,195 87,950 69,340
Exchange natural gas deliverable . 2,371 25,046 26,641
Dividends payable. . . . . . . . . 7,605 7,226 7,037
Long-term debt and preferred
stock due within one year. . . . 15,300 300 2,400
174,182 162,652 134,033
Natural gas repurchase commitment
(Note 5) . . . . . . . . . . . . . 98,525 114,937 123,981
Deferred credits:
Deferred income taxes and
unamortized investment tax
credit . . . . . . . . . . . . . 124,978 135,571 138,758
Other. . . . . . . . . . . . . . . 76,365 40,853 33,391
201,343 176,424 172,149
$1,041,051 $1,024,510 $ 964,691
The accompanying notes are an integral part of these consolidated
statements.
/TABLE
<PAGE>
<PAGE>
<TABLE> CONSOLIDATED STATEMENTS OF CAPITALIZATION
MDU RESOURCES GROUP, INC.
<CAPTION>
December 31, 1993 1992 1991
(In thousands)
<S> <C> <C> <C>
Common stockholders' investment:
Common stock (Note 9):
Authorized -- 50,000,000 shares,
$5 par value in 1993,
1992 and 1991
Outstanding -- 18,984,654 shares . $ 94,923 $ 94,923 $ 94,923
Other paid in capital . . . . . . . . 64,210 64,210 64,210
Retained earnings (Note 10) . . . . . 158,998 144,319 137,472
Total common stockholders'
investment. . . . . . . . . . . . . 318,131 303,452 296,605
Preferred stocks (Note 11):
Authorized:
Preferred -- 500,000 shares,
cumulative, par value $100,
issuable in series
Preferred stock A -- 1,000,000
shares, cumulative, without par
value, issuable in series (none
outstanding)
Preference -- 500,000 shares,
cumulative, without par value,
issuable in series (none
outstanding)
Outstanding:
Subject to mandatory redemption
requirements --
Preferred --
5.10% Series -- 22,000 shares
in 1993 (23,000 in 1992 and
24,000 in 1991). . . . . . . . 2,200 2,300 2,400
Other preferred stock --
4.50% Series -- 100,000
shares. . . . . . . . . . . . 10,000 10,000 10,000
4.70% Series -- 50,000
shares. . . . . . . . . . . . 5,000 5,000 5,000
15,000 15,000 15,000
Total preferred stocks 17,200 17,300 17,400
Less current maturities and
sinking fund requirements. . . . . . 100 100 100
Net preferred stocks . . . . . . . . . 17,100 17,200 17,300
Long-term debt (Note 12):
First mortgage bonds and notes . . . . 195,850 195,850 180,400
Pollution control lease and note
obligation, 6.2%, due in
annual installments to 2004 . . . . . 4,800 5,000 26,050
Senior secured note, 8.43%,
due December 31, 2000 . . . . . . . . 15,000 --- ---
Secured line of credit at various
interest rates, terminating
October 6, 2002 . . . . . . . . . . . 1,500 19,400 ---
Term loan at various interest rates,
terminating December 31, 1996. . . . 30,000 30,000 16,900
Other. . . . . . . . . . . . . . . . . (180) (205) (427)
Total long-term debt . . . . . . . . . 246,970 250,045 222,923
Less current maturities and sinking
fund requirements. . . . . . . . . . 15,200 200 2,300
Net long-term debt . . . . . . . . . . 231,770 249,845 220,623
Total capitalization . . . . . . . . . .$567,001 $570,497 $534,528
The accompanying notes are an integral part of these consolidated
statements.
/TABLE
<PAGE>
<PAGE>
<TABLE>
CONSOLIDATED STATEMENTS OF CASH FLOWS
MDU RESOURCES GROUP, INC.
<CAPTION>
Years ended December 31, 1993 1992 1991
(In thousands)
<S> <C> <C> <C>
Operating activities:
Net income . . . . . . . . . . . . . $ 44,338 $ 35,371 $ 38,017
Cumulative effect of accounting
change . . . . . . . . . . . . . . (5,521) --- ---
Adjustments to reconcile net income
to net cash provided by operations:
Depreciation, depletion and
amortization . . . . . . . . . . 45,162 39,694 36,577
Deferred income taxes and
investment tax credit -- net . . 16,040 (789) 747
Recovery of deferred natural gas
contract litigation settlement
costs, net of income taxes . . . 8,467 3,996 4,633
Changes in current assets and
liabilities --
Receivables. . . . . . . . . . . (775) (14,568) 983
Inventories. . . . . . . . . . . (1,201) (1,834) 5,457
Other current assets . . . . . . 12,954 (11,219) 4,402
Accounts payable . . . . . . . . (430) 6,902 (1,420)
Other current liabilities. . . . (8,160) 16,042 4,530
Other noncurrent changes . . . . . (13,687) 190 1,298
Net cash provided by operations. . . 97,187 73,785 95,224
Financing activities:
Net change in short-term borrowings. 1,765 7,775 ---
Issuance of long-term debt . . . . . 15,200 167,100 84,920
Repayment of long-term debt. . . . . (18,300) (140,200) (93,611)
Retirement of preferred stocks . . . (100) (100) (504)
Retirement of natural gas
repurchase commitment. . . . . . . (16,412) (9,044) ---
Dividends paid . . . . . . . . . . . (29,659) (28,524) (28,055)
Net cash used in financing
activities . . . . . . . . . . . . (47,506) (2,993) (37,250)
Investing activities:
Additions to property, plant and
equipment and acquisitions of
businesses --
Electric . . . . . . . . . . . . . (16,156) (13,226) (11,728)
Natural gas distribution . . . . . (15,012) (6,461) (5,758)
Natural gas transmission . . . . . (3,669) (9,452) (4,093)
Mining and construction materials. (43,123) (16,295) (909)
Oil and natural gas production . . (24,943) (25,778) (22,284)
(102,903) (71,212) (44,772)
Sale of natural gas available
under repurchase commitment. . . . 13,007 7,411 ---
Investments. . . . . . . . . . . . . 45,076 5,254 (2,851)
Net cash used in investment
activities . . . . . . . . . . . . (44,820) (58,547) (47,623)
Increase in cash and cash
equivalents. . . . . . . . . . . . 4,861 12,245 10,351
Cash and cash equivalents --
beginning of year. . . . . . . . . 66,838 54,593 44,242
Cash and cash equivalents --
end of year. . . . . . . . . . . . $ 71,699 $ 66,838 $ 54,593
The accompanying notes are an integral part of these consolidated
statements.
/TABLE
<PAGE>
<PAGE>
[TEXT] NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
MDU RESOURCES GROUP, INC.
Years Ended December 31, 1993, 1992 and 1991
NOTE 1
Statement of Principal Accounting Policies
Basis of presentation
The consolidated financial statements of MDU Resources Group, Inc.
(the "company") include the accounts of two regulated businesses --
retail sales of electricity, natural gas and propane, and natural gas
transmission, storage and sales at wholesale -- and two non-regulated
businesses -- mining and construction materials operations, and oil
and natural gas production. The statements also include the ownership
interests in the assets, liabilities and expenses of two jointly owned
electric generating stations.
The company's regulated businesses are subject to various state and
federal agency regulation. The accounting policies followed by these
businesses are generally subject to the Uniform System of Accounts of
the Federal Energy Regulatory Commission (FERC). These accounting
policies differ in some respects from those used by its non-regulated
businesses.
Intercompany coal sales, which are made at prices approximately the
same as those charged to others, and the related utility fuel
purchases are not eliminated.
Property, plant and equipment and investments
Additions to property, plant and equipment are recorded at cost when
first placed in service. When utility assets are retired, or
otherwise disposed of in the ordinary course of business, the original
cost and cost of removal, less salvage, is charged to accumulated
depreciation. The company is permitted to capitalize an allowance for
funds used during construction (AFUDC) on utility construction
projects and to include such amounts in rate base when the related
facilities are placed in service. AFUDC capitalized was insignificant
in 1993, 1992 and 1991. Property, plant and equipment are depreciated
on a straight-line basis over the average useful lives of the assets,
except for oil and natural gas production properties as described
below.
Investments, consisting principally of securities held for corporate
development purposes, are carried at cost which approximates market.
Oil and natural gas
The company uses the full-cost method of accounting for its oil and
natural gas production activities. Under this method, all costs
incurred in the acquisition, exploration and development of oil and
natural gas properties are capitalized and amortized on the units of
production method based on total proved reserves. Cost centers for
amortization purposes are determined on a country-by-country basis.
Capitalized costs are subject to a "ceiling test" that limits such
costs to the aggregate of the present value of future net revenues of
proved reserves and the lower of cost or fair value of unproved
properties. Any conveyances of properties, including gains or losses
on abandonments of properties, are treated as adjustments to the cost
of the properties with no gain or loss realized.
Natural gas in underground storage and available under repurchase
commitment
Natural gas in underground storage is carried at cost using the
last-in, first-out (LIFO) method. That portion of the cost of natural
gas in underground storage expected to be used within one year is
included in inventories.
Natural gas available under repurchase commitment is carried at
Frontier Gas Storage Company's cost of purchased natural gas, less an
allowance to reflect changed market conditions.
Inventories
Inventories, other than natural gas in underground storage, consist
primarily of materials and supplies and inventory held for resale.
These inventories are stated at the lower of average cost or market.
Utility revenue and energy cost
The company recognizes revenue each month based on the services
provided to all customers during the month. Because meters for retail
utility customers are read and billed on a monthly cycle billing
basis, revenues (and related energy costs) are estimated and recorded
for those services provided from the date which meters were last read
to month end. Prior to 1993, the company recorded revenue and the
cost of purchased natural gas sold when customers were billed. See
Note 2 for a discussion of an accounting change in the company's
revenue recognition method made effective January 1, 1993.
Natural gas costs recoverable through rate adjustments
Under the terms of certain orders of the public service commissions of
Montana, North Dakota, South Dakota and Wyoming, the company is
deferring natural gas commodity, transportation and storage costs
which are greater or less than amounts presently being recovered
through its existing rate schedules. Such orders generally provide
that these amounts are recoverable or refundable through rate
adjustments within 24 months from the time such costs are paid.
Income taxes
Effective with the adoption of Statement of Financial Accounting
Standards No. 109, "Accounting for Income Taxes" (SFAS No. 109) on
January 1, 1993, as further described in Note 2, the company is
providing deferred federal and state income taxes on all temporary
differences. Prior to 1993, the company provided deferred federal and
state income taxes on all non-utility timing differences and on all
FERC jurisdictional utility timing differences. With respect to state
jurisdictions, deferred federal and state income taxes were provided
on utility timing differences only as permitted for ratemaking
purposes.
The company uses the deferral method of accounting for investment
tax credits and amortizes the credits on electric and natural gas
distribution plant over various periods which conform to the
ratemaking treatment prescribed by the public service commissions of
Montana, North Dakota, South Dakota and Wyoming.
Cash flow information
Cash expenditures for interest and income taxes were as follows:
Years ended December 31, 1993 1992 1991
(In thousands)
Interest, net of amount capitalized. . .$22,717 $25,578 $29,749
Income taxes . . . . . . . . . . . . . .$24,545 $21,577 $17,645
The company considers all highly liquid investments purchased with
an original maturity of three months or less to be cash equivalents.
Reclassifications
Certain reclassifications have been made in the financial statements
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.
NOTE 2
Accounting Changes
Revenue recognition
On January 1, 1993, Montana-Dakota Utilities Co. (Montana-Dakota)
changed its revenue recognition method to include the accrual of
estimated unbilled revenues for electric and natural gas service.
This change results in a better matching of revenues and expenses and
is consistent with predominant industry practice. Prior to this
change, Montana-Dakota, for both its electric and natural gas
businesses, recognized revenues on a monthly cycle billing basis which
recorded revenues when customers were billed. Unbilled utility
revenues at December 31, 1993, aggregated $18.3 million and are
included in "Receivables" in the company's consolidated balance
sheets. The cumulative effect of this change on net income for the
twelve months ended December 31, 1993, is presented net of applicable
income taxes of $3,355,000.
Postretirement benefits other than pensions
On January 1, 1993, the company adopted Statement of Financial
Accounting Standards No. 106, "Employers' Accounting for
Postretirement Benefits Other Than Pensions" (SFAS No. 106). The
company has elected to amortize the transition obligation of
approximately $49 million at January 1, 1993, which represents the
accumulated postretirement benefit obligation at the time of adoption,
over 20 years as provided by SFAS No. 106. The company's annual cost
for 1993 based on the provisions of SFAS No. 106 is approximately $7.5
million, including amortization of the transition obligation discussed
above. However, substantially all of the amounts related to Montana-
Dakota's and Williston Basin Interstate Pipeline Company's (Williston
Basin) regulated operations reflecting the difference between the 1993
SFAS No. 106 required accruals of approximately $6.0 million and the
costs associated with the currently recoverable pay-as-you-go method,
estimated to be approximately $2.0 million, are being deferred
pursuant to regulatory orders received and are expected to be
recovered in future rates charged to customers. See Note 15 for more
information on the regulatory treatment of SFAS No. 106 costs.
Accounting for income taxes
On January 1, 1993, the company adopted SFAS No. 109. The company
elected to record the cumulative effect on prior years in 1993 as
allowed by SFAS No. 109, with such amount being immaterial to its
financial position or results of operations. Excess deferred income
tax balances associated with Montana-Dakota's and Williston Basin's
rate-regulated activities have been recorded as a regulatory liability
and are included in "Other deferred credits" in the company's
consolidated balance sheets at December 31, 1993. This regulatory
liability is expected to be reflected as a reduction in future rates
charged customers in accordance with applicable regulatory procedures.
NOTE 3
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 to Stockholders, 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 "Producer settlement cost recovery" and "Order 636"
contained in Note 4 for a discussion of Williston Basin's filings
under the FERC's Orders 500 and 636, respectively, 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.
NOTE 4
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.
Producer settlement cost recovery
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 in Note 3, 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.
NOTE 5
Natural Gas Repurchase Commitment
The company has offered for sale since 1984 the 61 million decatherms
(MMdk) of inventoried natural gas owned by Frontier Gas Storage
Company (Frontier), a special purpose, non-affiliated corporation.
Through an agreement, an obligation exists to repurchase all of the
natural gas at Frontier's original cost and reimburse Frontier for all
of its financing and general administrative costs. Frontier has
financed the purchase of the natural gas through the issuance of
commercial paper that has the credit support of an irrevocable $105
million letter of credit. At December 31, 1993, borrowings totalled
$101.1 million at a weighted average interest rate of 3.5 percent.
These transactions will terminate on November 30, 1995, unless
terminated earlier by the occurrence of certain events.
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.
NOTE 6
Environmental Matters
Montana-Dakota and Williston Basin discovered polychlorinated
biphenyls (PCBs) in portions of their natural gas systems and informed
the United States Environmental Protection Agency (EPA) in
January 1991. Montana-Dakota and Williston Basin believe the PCBs
entered the system from a valve sealant. Both Montana-Dakota and
Williston Basin have initiated testing, monitoring and remediation
procedures, in accordance with applicable regulations and the work
plan submitted to the EPA and the appropriate state agencies. Costs
incurred by Montana-Dakota and Williston Basin through 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 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.
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.
NOTE 7
Natural Gas in Underground Storage
Natural gas in underground storage included in natural gas
transmission property, plant and equipment amounted to approximately
$49 million at December 31, 1993, $51 million at December 31, 1992 and
$53 million at December 31, 1991. In addition, $1.3 million, $3.7
million and $3.6 million at December 31, 1993, 1992 and 1991,
respectively, of natural gas in underground storage is included in
inventories.
NOTE 8
Short-term Borrowings
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. Amounts outstanding under the
lines of credit were $9.5 million at December 31, 1993 and $7.8
million at December 31, 1992, with no amounts outstanding at
December 31, 1991. The unused portions of the lines of credit are
subject to withdrawal based on the occurrence of certain events.
NOTE 9
Common Stock
In November 1988, the company's Board of Directors declared, pursuant
to a stockholders' rights plan, a dividend of one preference share
purchase right (right) on each outstanding share of the company's
common stock. Each right becomes exercisable, upon the occurrence of
certain events, for one one-hundredth of a share of Series A
preference stock, without par value, at a purchase price of $50,
subject to certain adjustments. The rights are currently not
exercisable and will be exercisable only if a person or group
(acquiring person) either acquires ownership of 20 percent or more of
the company's common stock or commences a tender or exchange offer
that would result in ownership of 30 percent or more. In the event
the company is acquired in a merger or other business combination
transaction or 50 percent or more of its consolidated assets or
earnings power are sold, each right entitles the holder to receive
common stock of the acquiring person having a market value of twice
the exercise price of the right. The rights, which expire in November
1998, are redeemable in whole, but not in part, at the company's
option at any time for a price of $.02 per right.
There have been no changes in the amounts outstanding for common
stock and other paid in capital during the years ended December 31,
1993, 1992 and 1991.
The company's Dividend Reinvestment Plan (DRIP) provides holders of
all classes of the company's capital stock the opportunity to invest
their cash dividends in shares of common stock and to make optional
cash payments of up to $5,000 per quarter for the same purpose. The
company's Tax Deferred Compensation Savings Plans pursuant to Section
401(k) of the Internal Revenue Code are funded with common stock and
also participate in the DRIP. Since January 1, 1989, these plans have
been funded by the purchase of shares of common stock on the open
market. However, shares of authorized but unissued common stock may
be used for this purpose. At December 31, 1993, there were 1,020,229
shares of common stock reserved for issuance under the plans.
NOTE 10
Retained Earnings
Changes in retained earnings for the years ended December 31, 1993,
1992 and 1991 are as follows:
1993 1992 1991
(In thousands)
Balance at beginning of year . . . . . .$144,319 $137,472 $127,914
Net income . . . . . . . . . . . . . . . 44,338 35,371 38,017
188,657 172,843 165,931
Deduct:
Dividends declared --
Preferred stocks at required
annual rates . . . . . . . . . . . 802 807 812
Common stock . . . . . . . . . . . . 28,857 27,717 27,243
29,659 28,524 28,055
Settlement costs associated with
repurchase of preferred stocks . . . --- --- 404
Balance at end of year . . . . . . . . .$158,998 $144,319 $137,472
NOTE 11
Preferred Stocks
The preferred stocks outstanding are subject to redemption, in whole
or in part, at the option of the company with certain limitations on
30 days notice on any quarterly dividend date.
The company is obligated to make annual sinking fund contributions
to retire the 5.10% Series preferred stock. The redemption prices and
sinking fund requirements, where applicable, are summarized below:
Redemption Sinking Fund
Series Price (a) Shares Price (a)
Preferred stock:
4.50%. . . . . . . . . . . .$105.00 (b) --- ---
4.70%. . . . . . . . . . . .$102.00 (b) --- ---
5.10%. . . . . . . . . . . .$102.00 1,000 (c) $100.00
(a) Plus accrued dividends.
(b) These series are redeemable at the sole discretion of the
company.
(c) Annually on December 1, if tendered.
In the event of a voluntary or involuntary liquidation, all
preferred stock series holders are entitled to $100 per share, plus
accrued dividends.
The aggregate annual sinking fund amount applicable to preferred
stock subject to mandatory redemption requirements for each of the
five years following December 31, 1993, is $100,000.
NOTE 12
Long-term Debt and Indenture Provisions
First mortgage bonds and notes outstanding at December 31 are as
follows:
1993 1992 1991
(In thousands)
7 1/8% Series, due Nov. 1, 1993. . . .$ --- $ --- $ 9,400
8 5/8% Series, due Oct. 1, 2001. . . . --- --- 9,400
9 1/4% Series, due Sept. 15, 2003. . . --- --- 9,400
9 3/8% Series, due Nov. 15, 2011 . . . --- --- 75,200
9 1/8% Series, due May 15, 2006. . . . 50,000 50,000 50,000
9 1/8% Series, due Oct. 1, 2016. . . . 20,000 20,000 20,000
7 5/8% Sinking Fund, due Oct. 15, 1992 --- --- 1,000
8 1/2% Sinking Fund, due Oct. 1, 1996. --- --- 2,500
9% Sinking Fund, due Sept. 15, 1998. . --- --- 3,500
Pollution Control Refunding Revenue
Bonds, Series 1992 --
Mercer County, North Dakota, 6.65%,
due June 1, 2022 . . . . . . . . . 15,000 15,000 ---
Morton County, North Dakota, 6.65%,
due June 1, 2022 . . . . . . . . . 2,600 2,600 ---
Richland County, Montana, 6.65%,
due June 1, 2022 . . . . . . . . . 3,250 3,250 ---
Secured Medium-Term Notes, Series A --
5.80%, due Apr. 1, 1994. . . . . . . 15,000 15,000 ---
6.30%, due Apr. 1, 1995. . . . . . . 10,000 10,000 ---
6.95%, due Apr. 1, 1996. . . . . . . 10,000 10,000 ---
7.20%, due Apr. 1, 1997. . . . . . . 5,000 5,000 ---
8.25%, due Apr. 1, 2007. . . . . . . 30,000 30,000 ---
8.60%, due Apr. 1, 2012. . . . . . . 35,000 35,000 ---
Total first mortgage bonds
and notes. . . . . . . . . . . . . $195,850 $195,850 $180,400
The company has a revolving credit and term loan agreement which
totalled $30 million at December 31, 1993, 1992 and 1991. Amounts
outstanding under this agreement were $30 million at December 31, 1993
and 1992, respectively, and $10.5 million at December 31, 1991.
Fidelity Oil Co. has $15 million outstanding under a senior secured
note at December 31, 1993. In addition, Fidelity Oil Co. has
available $20 million under a secured line of credit, $1.5 million of
which was outstanding at December 31, 1993. At December 31, 1992,
Fidelity Oil Co. had a secured line of credit which totalled $35
million, of which $19.4 million was outstanding. However, on
January 13, 1993, $15 million of the line was converted to a senior
secured note. Fidelity Oil Co. had available $15 million under a
revolving credit and term loan agreement at December 31, 1991, $6.4
million of which was outstanding.
The amounts of long-term debt maturities and sinking fund
requirements for the five years following December 31, 1993, (net of
prepayments) aggregate $15.2 million in 1994; $10.7 million in 1995;
$40.7 million in 1996; $14.7 million in 1997 and $9.6 million in 1998.
Substantially all of the company's retail utility property is subject
to the lien of its Indenture of Mortgage. Under the terms and
conditions of such Indenture, the company could have issued
approximately $153 million of additional first mortgage bonds at
December 31, 1993. Certain natural gas transmission property is
subject to purchase money mortgages payable by Williston Basin to the
company.
In December 1991, the Financial Accounting Standards Board (FASB)
issued Statement of Financial Accounting Standards No. 107,
"Disclosures about Fair Value of Financial Instruments" (SFAS No.
107). SFAS No. 107 establishes fair value disclosure practices for
certain financial instruments. The fair value of the company's first
mortgage bonds and notes at December 31, 1993, is approximately $216
million. However, the difference between the recorded value of the
company's other debt instruments as well as investments in certain
securities and their fair values were not material.
NOTE 13
Income Taxes
Income tax expense is summarized as follows:
1993 1992 1991
(In thousands)
Current --
Federal. . . . . . . . . . . . . . . $25,665 $ 18,272 $14,287
State. . . . . . . . . . . . . . . . 3,997 3,359 2,972
Foreign. . . . . . . . . . . . . . . 10 --- ---
29,672 21,631 17,259
Deferred --
Investment tax credit -- net . . . . (1,144) (1,183) (1,236)
Income taxes:
Federal. . . . . . . . . . . . . . (9,560) (8,505) 722
State. . . . . . . . . . . . . . . 1,014 (1,043) 63
(9,690) (10,731) (451)
Total income tax expense . . . . . . . $19,982 $ 10,900 $16,808
Components of deferred tax assets and deferred tax liabilities
recognized in the company's consolidated balance sheets are as
follows:
1993
(In thousands)
Deferred tax assets:
Reserves for regulatory matters . . . . . . . . . . . . . $ 40,195
Natural gas available under repurchase commitment . . . . 7,554
Deferred investment tax credits . . . . . . . . . . . . . 4,462
Accrued land reclamation. . . . . . . . . . . . . . . . . 4,017
Accrued pension costs . . . . . . . . . . . . . . . . . . 3,676
Other . . . . . . . . . . . . . . . . . . . . . . . . . . 6,428
Total deferred tax assets. . . . . . . . . . . . . . . . . $ 66,332
Deferred tax liabilities:
Depreciation and basis differences on property,
plant and equipment . . . . . . . . . . . . . . . . . . $108,846
Basis differences on oil and natural gas
producing properties. . . . . . . . . . . . . . . . . . 15,889
Natural gas contract settlement and
restructuring costs . . . . . . . . . . . . . . . . . . 13,530
Long-term debt refinancing costs. . . . . . . . . . . . . 5,223
Other . . . . . . . . . . . . . . . . . . . . . . . . . . 4,078
Total deferred tax liabilities . . . . . . . . . . . . . . $147,566
Total income tax expense differs from the amount computed by
applying the statutory federal income tax rate to income before taxes.
The reasons for this difference are as follows:
1993 1992 1991
Amount % Amount % Amount %
(Dollars in thousands)
Computed tax at federal
statutory rate . . . . $20,580 35.0 $15,732 34.0 $18,640 34.0
Increases (reductions)
in provision for
taxes resulting from:
Depletion allowance. . (1,424) (2.4) (1,393) (3.0) (1,433) (2.6)
State income
taxes -- net of
federal income tax
benefit. . . . . . . 2,171 3.7 1,664 3.6 1,949 3.6
Tax-exempt interest. . (725) (1.2) (958) (2.1) (1,174) (2.1)
Investment tax credit
amortization . . . . (1,144) (2.0) (1,183) (2.5) (1,236) (2.3)
Other items. . . . . . 524 .9 (2,962) (6.4) 62 .1
Actual taxes . . . . . . $19,982 34.0 $10,900 23.6 $16,808 30.7
During 1992 and 1991, deferred income tax expense resulted from
differences in the timing of recognizing certain revenues and expenses
for tax and financial statement purposes. The sources of these
differences and the tax effect of each are as follows:
1992 1991
(In thousands)
Tax over book depreciation . . . . . . . . . . . $ 1,426 $ 1,834
Natural gas costs recoverable through
rate adjustments . . . . . . . . . . . . . . . 1,478 (1,562)
Natural gas contract settlement and
restructuring. . . . . . . . . . . . . . . . . (2,533) (3,028)
Reserves for regulatory matters. . . . . . . . . (7,270) (2,261)
Unbilled utility revenue . . . . . . . . . . . . (1,778) 1,093
Well drilling and development costs. . . . . . . 2,343 3,797
Land reclamation and other . . . . . . . . . . . (3,214) 912
Total deferred income tax expense. . . . . . . . $(9,548) $ 785
The company's consolidated federal income tax returns were under
examination by the Internal Revenue Service (IRS) for the tax years
1983 through 1988. In September 1991, the company received a
deficiency notice from the IRS for the tax years 1983 through 1985
which proposed substantial additional income taxes, plus interest. In
an alternative position contained in the notice of proposed
deficiency, the IRS is claiming a lower level of taxes due, plus
interest as well as penalties. In May 1992, a similar notice of
proposed deficiency was received for the years 1986 through 1988.
Although the notices of proposed deficiency encompass a number of
separate issues, the principal issue is related to the tax treatment
of deductions claimed in connection with certain investments made by
Knife River and Fidelity Oil.
The company's tax counsel has issued opinions related to the
principal issue discussed above, stating that it is more likely than
not that the company would prevail in this matter. Thus, the company
intends to contest vigorously the deficiencies proposed by the IRS
and, in that regard, has timely filed protests for the 1983 through
1988 tax years contesting the treatment proposed in the notices of
proposed deficiency. If the IRS position were upheld, the resulting
deficiencies would have a material effect on results of operations.
NOTE 14
Business Segment Data
The company's operations are conducted through five business segments.
The electric, natural gas distribution, natural gas transmission,
mining and construction materials, and oil and natural gas production
businesses are substantially all located within the United States. A
description of these segments and their primary operations is
presented on page one.
Segment operating information at December 31, 1993, 1992 and 1991,
is presented in the Consolidated Statements of Income. Other segment
information is presented below:
1993 1992 1991
(In thousands)
Depreciation, depletion and
amortization --
Electric . . . . . . . . . . . . .$ 15,307 $ 15,132 $ 15,698
Natural gas distribution . . . . . 5,114 4,809 4,673
Natural gas transmission . . . . . 7,113 6,409 6,110
Mining and construction
materials . . . . . . . . . . . . 5,594 4,527 4,035
Oil and natural gas production . . 12,034 8,817 6,061
Total depreciation, depletion
and amortization . . . . . . .$ 45,162 $ 39,694 $ 36,577
Investment information --
Identifiable assets:
Electric (a) . . . . . . . . . .$ 306,179 $ 301,959 $302,296
Natural gas distribution (a) . . 104,013 90,979 84,250
Natural gas transmission (a) . . 383,355 404,250 391,735
Mining and construction
materials. . . . . . . . . . . 120,105 105,761 102,760
Oil and natural gas
production . . . . . . . . . . 89,690 80,128 61,935
Total identifiable assets. . . 1,003,342 983,077 942,976
Corporate assets (b) . . . . . . . 37,709 41,433 21,715
Total consolidated assets. . .$1,041,051 $1,024,510 $964,691
(a) Includes, in the case of natural gas distribution and electric
property, allocations of common utility property. Natural gas
stored or available under repurchase commitment is included in
natural gas transmission identifiable assets.
(b) Corporate assets consist of assets not directly assignable to a
business segment, i.e., cash and cash equivalents, certain
accounts receivable and other miscellaneous current and deferred
assets.
Approximately 7 percent of mining and construction materials
revenues in 1993 (13 percent in 1992 and 16 percent in 1991) represent
Knife River's direct sales of lignite coal to the company. The
company's share of Knife River's sales for use at two generating
stations jointly owned by the company and other utilities was
approximately 10 percent of mining and construction materials revenues
in 1993, 20 percent in 1992 and 19 percent in 1991.
In May 1992, KRC Aggregate, Inc. (KRC Aggregate), an indirect,
wholly-owned subsidiary of Knife River, entered into the sand and
gravel business in 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.
Pro forma amounts reflecting the effects of the above acquisitions
are not disclosed as such acquisitions were not material to the
company's financial position or results of operations.
NOTE 15
Employee Benefit Plans
The company has noncontributory defined benefit pension plans covering
substantially all full-time employees. Pension benefits are based on
employee's years of service and earnings. The company makes annual
contributions to the plans consistent with the funding requirements of
federal law and regulations.
Pension expense is summarized as follows:
1993 1992 1991
(In thousands)
Service cost/benefits earned during
the year . . . . . . . . . . . . . .$ 3,277 $ 2,957 $ 2,803
Interest cost on projected benefit
obligation . . . . . . . . . . . . . 9,488 8,464 8,008
Loss (return) on plan assets . . . . . (14,540) (11,384) (25,822)
Net amortization and deferral. . . . . 2,916 491 15,637
Total pension costs. . . . . . . . . . 1,141 528 626
Less amounts capitalized . . . . . . . 133 75 58
Total pension expense. . . . . . . . .$ 1,008 $ 453 $ 568
The funded status of the company's plans is summarized as follows:
1993 1992 1991
(In thousands)
Projected benefit obligation:
Vested . . . . . . . . . . . . . . $108,718 $ 92,623 $ 81,766
Nonvested. . . . . . . . . . . . . 4,696 3,251 2,820
Accumulated benefit obligation . . . 113,414 95,874 84,586
Provision for future pay increases . 26,379 22,614 20,794
Projected benefit obligation . . . . . 139,793 118,488 105,380
Plan assets at market value. . . . . . 149,184 140,623 135,172
(9,391) (22,135) (29,792)
Plus:
Unrecognized transition asset. . . . 10,305 11,295 12,284
Unrecognized net gains and prior
service costs. . . . . . . . . . . 4,953 16,018 22,157
Accrued pension costs. . . . . . . . . $ 5,867 $ 5,178 $ 4,649
The projected benefit obligation was determined using an assumed
discount rate of 7 percent (8 percent in 1992 and 1991) and assumed
long-term rates for estimated compensation increases of 4 1/2 percent
(5 percent in 1992 and 5 1/2 percent in 1991). The change in these
assumptions had the effect of increasing the projected benefit
obligation at December 31, 1993, by $15 million. The assumed
long-term rate of return on plan assets is 8 1/2 percent. Plan assets
consist primarily of debt and equity securities.
In addition to providing pension benefits, the company has a policy
of providing all eligible employees and dependents certain other
postretirement benefits which include health care and life insurance
upon their retirement. The plans underlying these benefits may
require contributions by the employee depending on such employee's age
and years of service at retirement or the date of retirement. The
accounting for the health care plan anticipates future cost-sharing
changes that are consistent with the company's expressed intent to
increase retiree contributions each year by the excess of the expected
health care cost trend rate over 6 percent.
Postretirement benefits expense is summarized as follows:
1993
(In thousands)
Service cost/benefits earned during the year . . . . . . . . $1,098
Interest cost on accumulated postretirement
benefit obligation . . . . . . . . . . . . . . . . . . . . 3,932
Amortization of transition obligation. . . . . . . . . . . . 2,458
Total postretirement benefits expense. . . . . . . . . . . . $7,488
The funded status of the company's plans is summarized as follows:
1993
(In thousands)
Accumulated postretirement benefit obligation:
Retirees eligible for benefits . . . . . . . . . . . . . . $31,029
Active employees not fully eligible. . . . . . . . . . . . 28,592
Total. . . . . . . . . . . . . . . . . . . . . . . . . . 59,621
Plan assets at market value. . . . . . . . . . . . . . . . . 4,450
55,171
Less:
Unrecognized transition obligation . . . . . . . . . . . . 46,694
Unrecognized net losses. . . . . . . . . . . . . . . . . . 7,992
Accrued postretirement benefits cost . . . . . . . . . . . . $ 485
The health care cost trend rate assumed in determining the
accumulated postretirement benefit obligation was 12 percent in 1993,
decreasing by 1 percent per year until an ultimate rate of 6 percent
is reached in 1999 and remaining level thereafter. The health care
cost trend rate assumption has a significant effect on the amounts
reported. To illustrate, increasing the assumed health care cost
trend rates by 1 percent each year would increase the accumulated
postretirement benefit obligation as of December 31, 1993, by $3.6
million and the aggregate of the service and interest cost components
of postretirement benefits expense by $288,000.
The accumulated postretirement benefit obligation was determined
using an assumed discount rate of 7 percent (8 percent at January 1,
1993, the date of adoption) and assumed long-term rates for estimated
compensation increases, as they apply to life insurance benefits, of
4 1/2 percent (5 1/2 percent at January 1, 1993). The change in these
assumptions had the effect of increasing the accumulated
postretirement benefit obligation at December 31, 1993, by $8 million.
The assumed long-term rate of return on assets is 7 1/2 percent. Plan
assets at December 31, 1993,consist primarily of short-term
investments.
The company's accounting recognition and funding policy as it
applies to postretirement benefits, will depend, in part, on the
position of applicable regulatory bodies with respect to recovery of
such costs for its regulated businesses. Montana-Dakota filed
applications with the public service commissions of Montana, North
Dakota, South Dakota and Wyoming requesting that the commissions adopt
the principles of accrual accounting for these costs and that the
company be permitted to defer, on a limited basis, the difference
between the SFAS No. 106 required accruals and the costs associated
with the presently used pay-as-you-go method until such time that the
full SFAS No. 106 expense is allowed in the company's rates charged to
its customers. The company has received an order from the Montana
Public Service Commission authorizing such deferrals. The public
service commissions of North Dakota and Wyoming, as a part of orders
issued in 1993 related to general rate applications filed by Montana-
Dakota, adopted accrual accounting for ratemaking purposes and
generally require that these benefits be funded through an external
trust using the most tax-effective funding options available.
However, as a part of a 1993 general rate proceeding, the South Dakota
commission deferred this issue until commission hearings are held in
March 1994, and has continued the use of pay-as-you-go accounting for
ratemaking purposes until that date. The FERC, in a policy statement
issued in December 1992, has adopted accrual accounting for these
costs for ratemaking purposes and has authorized limited deferral of
the higher accrual costs. Williston Basin expects to seek recovery of
these costs in its next general rate proceeding.
The company has an unfunded, nonqualified benefit plan for executive
officers and certain key management employees that provides for
defined benefit payments upon the employee's retirement or to their
beneficiaries upon death for a 15-year period. Investments consist of
life insurance carried on plan participants which is payable to the
company upon the employee's death. The cost of these benefits in 1993
was $1.4 million.
The company has a Key Employee Stock Option Plan under which the
company is authorized to grant options for up to 800,000 shares of
common stock with an option price equal to market value on the date of
grant. At December 31, 1993, 183,040 options, with an average option
price of $23.72 per share, were outstanding, none of which were
exercisable. The company has contributed $3.2 million to a trust
established to fund its commitment under the Plan.
The company has Tax Deferred Compensation Savings Plans for eligible
employees. Each participant may contribute amounts up to 10 percent
of eligible compensation, subject to certain limitations. The company
contributes an amount equal to 50 percent of the participant's savings
contribution up to a maximum of 6 percent of such participant's
contribution. Company contributions were $1.7 million in 1993, $1.5
million in 1992 and $1.3 million in 1991.
NOTE 16
Jointly Owned Facilities
The consolidated financial statements include the company's 22.7
percent and 25.0 percent ownership interests in the assets,
liabilities and expenses of the Big Stone Station and the Coyote
Station, respectively. Each owner of the Big Stone and Coyote
stations is responsible for providing its own financing of its
investment in the jointly owned facilities.
The company's share of the Big Stone Station and Coyote Station
operating expenses is reflected in the appropriate categories of
operating expenses in the Consolidated Statements of Income.
At December 31, the company's share of the cost of utility plant in
service and related accumulated depreciation for the stations was as
follows:
1993 1992 1991
(In thousands)
Big Stone Station --
Utility plant in service . . . . . $ 47,349 $ 46,398 $ 46,783
Accumulated depreciation . . . . . 24,663 23,326 22,105
$ 22,686 $ 23,072 $ 24,678
Coyote Station --
Utility plant in service . . . . . $121,380 $121,294 $120,085
Accumulated depreciation . . . . . 42,482 39,129 35,474
$ 78,898 $ 82,165 $ 84,611
NOTE 17
Quarterly Data (Unaudited)
The following unaudited information shows selected items by quarter
for the years 1993 and 1992:
First Second Third Fourth
Quarter Quarter Quarter Quarter
1993 (In thousands, except per share
amounts)
Operating revenues . . . . . $124,169 $88,995 $98,832 $127,616
Operating expenses . . . . . 92,631 76,378 84,266 102,245
Operating income . . . . . . 31,538 12,617 14,566 25,371
Income before cumulative
effect of accounting change 15,761 3,797 6,309 12,950
Cumulative effect of
accounting change. . . . . 5,521 --- --- ---
Net income . . . . . . . . . 21,282 3,797 6,309 12,950
Earnings per common share
before cumulative effect
of accounting change . . . .82 .19 .32 .67
Cumulative effect of
accounting change per
common share . . . . . . . .29 --- --- ---
Earnings per common share. . 1.11 .19 .32 .67
Average common shares
outstanding. . . . . . . . 18,985 18,985 18,985 18,985
1992
Operating revenues . . . . . $105,576 $78,839 $70,963 $106,797
Operating expenses . . . . . 81,793 66,181 57,756 79,386
Operating income . . . . . . 23,783 12,658 13,207 27,411
Net income . . . . . . . . . 11,440 4,018 5,174 14,739
Earnings per common share. . .59 .20 .26 .77
Average common shares
outstanding. . . . . . . . 18,985 18,985 18,985 18,985
Pro forma amounts assuming
retroactive application
of accounting change:
Net income . . . . . . . . $ 10,332 $ 3,507 $ 5,098 $ 16,915
Earnings per common share. .53 .17 .26 .88
Most of the company's operations are highly seasonal and revenues
from, and certain expenses for, such operations may fluctuate between
quarterly periods. Accordingly, quarterly financial information may
not be indicative of results for a full year.
NOTE 18
Oil and Natural Gas Activities (Unaudited)
Fidelity Oil holds various oil and natural gas interests primarily
through a series of working-interest agreements with several oil and
natural gas producers and through operating agreements with Shell
Western E & P, Inc. (Shell).
Since 1986, Fidelity Oil has undertaken 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.
Fidelity Oil has net proceeds interests in the production of oil and
natural gas and has an operating agreement (Agreement) with Shell
applicable to certain of its acreage interests. 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.
The following information includes Fidelity Oil's proportionate
share of all its oil and natural gas net proceeds and working
interests.
The following table sets forth capitalized costs and related
accumulated depreciation, depletion and amortization related to oil
and natural gas producing activities at December 31:
1993 1992 1991
(In thousands)
Subject to amortization. . . . . . . . $114,572 $91,058 $66,501
Not subject to amortization. . . . . . 2,022 2,383 1,533
Total capitalized costs. . . . . . . . 116,594 93,441 68,034
Accumulated depreciation, depletion
and amortization . . . . . . . . . . 36,084 24,083 15,374
Net capitalized costs. . . . . . . . . $ 80,510 $69,358 $52,660
Capital expenditures, including those not subject to amortization,
related to oil and natural gas producing activities for the 12 months
ended December 31 are as follows:
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
The following summary reflects income resulting from the company's
operations of oil and natural gas producing activities, excluding
corporate overhead and financing costs, for the 12 months ended
December 31:
1993 1992 1991
(In thousands)
Revenues . . . . . . . . . . . . . . . $39,125 $33,797 $33,939
Production costs . . . . . . . . . . . 13,700 13,965 14,040
Depreciation, depletion and
amortization . . . . . . . . . . . . 11,998 8,782 6,027
Pretax income. . . . . . . . . . . . . 13,427 11,050 13,872
Income tax expense . . . . . . . . . . 4,606 3,658 4,745
Results of operations for
producing activities . . . . . . . . $ 8,821 $ 7,392 $ 9,127
The following table summarizes the company's estimated quantities of
proved developed oil and natural gas reserves at December 31, 1993,
1992 and 1991 and reconciles the changes between these dates.
Estimates of economically recoverable oil and natural gas reserves and
future net revenues therefrom are based upon a number of variable
factors and assumptions. For these reasons, estimates of economically
recoverable reserves and future net revenues may vary from actual
results.
1993 1992 1991
Natural Natural Natural
Oil Gas Oil Gas Oil Gas
(In thousands of barrels/Mcf)
Proved developed and
undeveloped reserves:
Balance at beginning
of year. . . . . . . 12,200 37,200 11,600 27,500 12,400 16,100
Production . . . . . . (1,500)(8,800)(1,500)(5,000) (1,500)(2,600)
Extensions and
discoveries. . . . . 600 10,600 100 5,300 400 8,900
Purchases of proved
reserves . . . . . . 500 9,200 900 8,200 200 5,700
Sales of reserves
in place . . . . . . (300) (100) --- (100) --- (100)
Revisions to previous
estimates due to
improved secondary
recovery techniques
and/or changed
economic conditions. (300) 2,200 1,100 1,300 100 (500)
Balance at end of year 11,200 50,300 12,200 37,200 11,600 27,500
Proved developed reserves:
January 1, 1991. . . . 12,300 13,900
December 31, 1991. . . 11,200 22,600
December 31, 1992. . . 11,800 36,500
December 31, 1993. . . 11,100 43,100
Virtually all of the company's interests in oil and natural gas
reserves are located in the continental United States. Reserve
interests at December 31, 1993, applicable to the company's $7.1
million gross investment in oil and natural gas properties located in
Canada comprise approximately 7 percent of the total reserves.
The standardized measure of the company's estimated discounted
future net cash flows of total proved reserves associated with its
various oil and natural gas interests at December 31 is as follows:
1993 1992 1991
(In thousands)
Future net cash flows before
income taxes . . . . . . . . . . . . $119,800 $138,500 $94,300
Future income tax expenses . . . . . . 15,600 26,600 15,300
Future net cash flows. . . . . . . . . 104,200 111,900 79,000
10% annual discount for estimated
timing of cash flows . . . . . . . . 32,600 35,200 24,900
Discounted future net cash flows
relating to proved oil and natural
gas reserves . . . . . . . . . . . . $ 71,600 $ 76,700 $54,100
The following are the sources of change in the standardized measure
of discounted future net cash flows by year:
1993 1992 1991
(In thousands)
Beginning of year. . . . . . . . . . . $ 76,700 $ 54,100 $ 68,000
Net revenues from production . . . . . (26,000) (19,700) (16,900)
Change in net realization. . . . . . . (24,000) 13,100 (53,100)
Extensions, discoveries and improved
recovery, net of future production
and development costs. . . . . . . . 16,800 8,200 12,900
Purchases of proved reserves . . . . . 14,100 16,000 7,100
Sales of reserves in place . . . . . . (1,600) (200) (300)
Changes in estimated future
development costs. . . . . . . . . . (11,600) (3,000) (5,000)
Development costs incurred
during the year. . . . . . . . . . . 7,800 4,700 9,800
Accretion of discount. . . . . . . . . 8,900 6,400 9,600
Net change in income taxes . . . . . . 6,000 (8,000) 18,200
Revisions of previous quantity
estimates. . . . . . . . . . . . . . 4,400 5,000 3,600
Other. . . . . . . . . . . . . . . . . 100 100 200
Net change . . . . . . . . . . . . . . (5,100) 22,600 (13,900)
End of year. . . . . . . . . . . . . . $ 71,600 $ 76,700 $ 54,100
The estimated discounted future cash inflows from estimated future
production of proved reserves were computed using year-end oil and
natural gas prices. Future development and production costs
attributable to proved reserves were computed by applying year-end
costs to be incurred in producing and further developing the proved
reserves. Future income tax expenses were computed by applying
statutory tax rates (adjusted for permanent differences and tax
credits) to estimated net future pretax cash flows.
Supplementary information with respect to the company's natural gas
producing activities through Williston Basin is not included herein
since the related production is anticipated to recover its equivalent
cost of service. However, as a part of the settlement applicable to
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
approximately 116,476 MMcf. The unamortized capitalized costs related
to these reserves are approximately $7.9 million at December 31, 1993,
$7.2 million at December 31, 1992, and $7.5 million at December 31,
1991. Non-depreciable capitalized costs are amortized on a composite
unit-of-production method based on total estimated recoverable
reserves and depreciable capitalized costs are amortized on a
straight-line basis over the average useful life of the asset.
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.
<PAGE>
<PAGE>
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Directors and Stockholders of MDU Resources Group,
Inc.:
We have audited the accompanying consolidated balance sheets and
statements of capitalization of MDU Resources Group, Inc. (a Delaware
corporation) and Subsidiaries as of December 31, 1993, 1992 and 1991,
and the related consolidated statements of income and cash flows for
each of the three years in the period ended December 31, 1993. These
financial statements are the responsibility of the company's
management. Our responsibility is to express an opinion on these
financial statements based on our audits.
We conducted our audits in accordance with generally accepted
auditing standards. Those standards require that we plan and perform
the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes
examining, on a test basis, evidence supporting the amounts and
disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates
made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, the financial statements referred to above present
fairly, in all material respects, the financial position of MDU
Resources Group, Inc. and Subsidiaries as of December 31, 1993, 1992
and 1991, and the results of their operations and their cash flows for
each of the three years in the period ended December 31, 1993 in
conformity with generally accepted accounting principles.
As discussed in Note 2 to the consolidated financial statements,
effective January 1, 1993, the company changed its methods of
accounting for recording electric and natural gas distribution
revenues, postretirement benefits other than pensions, and income
taxes.
/s/ Arthur Andersen & Co.
Arthur Andersen & Co.
Minneapolis, Minnesota,
January 25, 1994
<PAGE>
<TABLE>
OPERATING STATISTICS
MDU RESOURCES GROUP, INC.
<CAPTION>
1993 1992 1991
<S> <C> <C> <C>
Selected Financial Data
Operating revenues: (000's)
Electric . . . . . . . . . . . . $ 131,109 $ 123,908 $128,708
Natural gas. . . . . . . . . . . 178,981 159,438 173,865
Mining and construction
materials. . . . . . . . . . . 90,397 45,032 41,201
Oil and natural gas production . 39,125 33,797 33,939
$ 439,612 $ 362,175 $377,713
Operating income: (000's)
Electric . . . . . . . . . . . . $ 30,520 $ 30,188 $ 34,647
Natural gas distribution . . . . 4,730 4,509 8,518
Natural gas transmission . . . . 20,108 21,331 19,904
Mining and construction
materials. . . . . . . . . . . 16,984 11,532 9,682
Oil and natural gas production . 11,750 9,499 12,552
$ 84,092 $ 77,059 $ 85,303
Earnings (loss) on common
stock: (000's)
Electric . . . . . . . . . . . . $ 12,652* $ 13,302 $ 15,292
Natural gas distribution . . . . 1,182* 1,370 3,645
Natural gas transmission . . . . 4,713 3,479 449
Mining and construction
materials. . . . . . . . . . . 12,359 10,662 9,809
Oil and natural gas production . 7,109 5,751 8,010
Earnings on common stock
before cummulative effect
of accounting change . . . . . 38,015* 34,564 37,205
Cumulative effect of
accounting change. . . . . . . 5,521 --- ---
$ 43,536 $ 34,564 $ 37,205
Earnings per common share before
cumulative effect of
accounting change. . . . . . . . $ 2.00* $ 1.82 $ 1.96
Cumulative effect of accounting
change . . . . . . . . . . . . . .29 --- ---
$ 2.29 $ 1.82 $ 1.96
Pro forma amounts assuming
retroactive application of
accounting change:
Net income (000's) . . . . . . . $ 38,817 $ 35,852 $ 37,619
Earnings per common share. . . . $ 2.00 $ 1.85 $ 1.94
Common Stock Statistics
Weighted average common shares
outstanding (000's). . . . . . . 18,985 18,985 18,985
Dividends per common share . . . . $ 1.52 $ 1.46 $ 1.435
Book value per common share. . . . $ 16.76 $ 15.98 $ 15.62
Market price ratios:
Dividend payout. . . . . . . . . 76%* 80% 73%
Yield. . . . . . . . . . . . . . 5.0% 5.6% 5.8%
Price/earnings ratio . . . . . . 15.8x* 14.5x 12.6x
Market value as a percent of
book value . . . . . . . . . . 188.0% 165.0% 157.7%
Profitability Indicators
Return on average common equity. . 12.3%* 11.6% 12.7%
Return on average invested
capital. . . . . . . . . . . . . 9.4%* 8.7% 9.6%
Interest coverage. . . . . . . . . 3.4x* 3.3x 3.8x**
Fixed charges coverage, including
preferred dividends. . . . . . . 3.0x* 2.4x 2.4x
General
Total assets (000's) . . . . . . . $1,041,051 $1,024,510 $964,691
Net long-term debt (000's) . . . . $ 231,770 $ 249,845 $220,623
Redeemable preferred stock (000's) .$ 2,200 $ 2,300 $ 2,400
Capitalization ratios:
Common stockholders' investment. 56% 53% 56%
Preferred stocks . . . . . . . . 3 3 3
Long-term debt . . . . . . . . . 41 44 41
100% 100% 100%
* Before cumulative effect of an accounting change reflecting the
accrual of estimated unbilled revenues.
** Calculation reflects the provisions of the company's restatement of
its Indenture of Mortgage effective April 1992.
</TABLE>
<PAGE>
<PAGE>
<TABLE>
OPERATING STATISTICS
MDU RESOURCES GROUP, INC.
<CAPTION>
1990 1989 1988
<S> <C> <C> <C>
Selected Financial Data
Operating revenues: (000's)
Electric . . . . . . . . . . . . $124,156 $126,228 $126,128
Natural gas. . . . . . . . . . . 151,599 159,703 168,125
Mining and construction
materials. . . . . . . . . . . 38,276 41,643 42,388
Oil and natural gas production . 31,213 25,199 20,918
$345,244 $352,773 $357,559
Operating income: (000's)
Electric . . . . . . . . . . . . $ 32,221 $ 32,592 $ 33,505
Natural gas distribution . . . . 6,578 7,781 5,368
Natural gas transmission . . . . 19,362 24,835 21,189
Mining and construction
materials. . . . . . . . . . . 7,749 9,087 9,841
Oil and natural gas production . 12,523 10,420 7,352
$ 78,433 $ 84,715 $ 77,255
Earnings (loss) on common
stock: (000's)
Electric . . . . . . . . . . . . $ 14,280 $ 13,385 $ 13,444
Natural gas distribution . . . . 2,704 3,123 1,474
Natural gas transmission . . . . (7,578)* 3,722 2,320
Mining and construction
materials. . . . . . . . . . . 9,632 8,890 11,493
Oil and natural gas production . 8,071 6,765 5,115
Earnings on common stock
before cummulative effect
of accounting change . . . . . 27,109* 35,885 33,846
Cumulative effect of
accounting change. . . . . . . --- --- ---
$ 27,109* $ 35,885 $ 33,846
Earnings per common share before
cumulative effect of
accounting change. . . . . . . . $ 1.43* $ 1.89 $ 1.81
Cumulative effect of accounting
change . . . . . . . . . . . . . --- --- ---
$ 1.43* $ 1.89 $ 1.81
Pro forma amounts assuming
retroactive application of
accounting change:
Net income (000's) . . . . . . . $ 28,395* $ 36,861 $ 34,957
Earnings per common share. . . . $ 1.45 $ 1.90 $ 1.81
Common Stock Statistics
Weighted average common shares
outstanding (000's). . . . . . . 18,985 18,985 18,718
Dividends per common share . . . . $ 1.42 $ 1.47 $ 1.42
Book value per common share. . . . $ 15.12 $ 15.11 $ 14.75
Market price ratios:
Dividend payout. . . . . . . . . 99%* 78% 78%
Yield. . . . . . . . . . . . . . 6.9% 6.5% 7.5%
Price/earnings ratio . . . . . . 14.3x* 12.0x 10.5x
Market value as a percent of
book value . . . . . . . . . . 135.6% 149.7% 128.8%
Profitability Indicators
Return on average common equity. . 9.4%* 12.5% 12.4%
Return on average invested capital 7.8%* 9.2% 9.0%
Interest coverage. . . . . . . . . 2.7x* 2.8x 2.7x
Fixed charges coverage, including
preferred dividends. . . . . . . 1.9x* 2.3x 2.2x
General
Total assets (000's) . . . . . . . $959,946 $971,401 $949,509
Net long-term debt (000's) . . . . $229,786 $234,333 $242,593
Redeemable preferred stock (000's) $ 2,500 $ 2,600 $ 3,100
Capitalization ratios:
Common stockholders' investment. 54% 53% 52%
Preferred stocks . . . . . . . . 3 3 3
Long-term debt . . . . . . . . . 43 44 45
100% 100% 100%
* Reflects a $6.8 million or 36 cent per share after-tax effect of an
absorption of certain natural gas contract litigation settlement
costs.
/TABLE
<PAGE>
<TABLE>
OPERATING STATISTICS
MDU RESOURCES GROUP, INC.
<CAPTION>
1993 1992 1991
<S> <C> <C> <C>
Electric Operations
Sales to ultimate consumers
(thousand kWh) . . . . . . . . . . . .1,893,713 1,829,933 1,877,634
Sales for resale (thousand kWh). . . . . 510,987 352,550 331,314
Electric system generating and
firm purchase capability -- kW
(Interconnected system). . . . . . . . 465,200 460,200 454,400
Demand peak -- kW
(Interconnected system). . . . . . . . 350,300 339,100 387,100
Electricity produced
(thousand kWh) . . . . . . . . . . . .1,870,740 1,774,322 1,736,187
Electricity purchased
(thousand kWh) . . . . . . . . . . . . 701,736 593,612 611,884
Cost of fuel and purchased
power per kWh. . . . . . . . . . . . . $.016 $.016 $.016
Natural Gas Distribution Operations
Sales (Mdk). . . . . . . . . . . . . . . 31,147 26,681 30,074
Transportation (Mdk) . . . . . . . . . . 12,704 13,742 12,261
Weighted average degree days -- % of
previous year's actual . . . . . . . . 115% 98% 101%
Natural Gas Transmission Operations
Sales for resale (Mdk) . . . . . . . . . 13,201 16,841 19,572
Transportation (Mdk) . . . . . . . . . . 59,416 64,498 53,930
Natural gas:
Produced (Mdk) . . . . . . . . . . . . 3,876 3,551 3,742
Purchased from others -- gross (Mdk) . 5,562 14,132 16,366
Stored (owned or controlled)
Net injection (withdrawal)--MMcf . . (10,786) (2,931) (2,834)
Cost of natural gas purchased
per dk . . . . . . . . . . . . . . . . 1.78 $1.91 $2.07
Energy Marketing Operations
Natural gas volumes (Mdk). . . . . . . . 6,827 3,292 991
Mining and Construction Materials Operations
Coal: (000's)
Tonnage sales. . . . . . . . . . . . . 5,066 4,913 4,731
Recoverable reserves in tons . . . . . 230,600 235,700 256,700
Construction materials: (000's)
Aggregates (tons sold) . . . . . . . . 2,391 263 ---
Ready-mixed concrete (cubic
yards sold). . . . . . . . . . . . . 157 --- ---
Asphalt (tons sold). . . . . . . . . . 141 --- ---
Recoverable aggregate reserves
in tons. . . . . . . . . . . . . . . 74,200 20,600 ---
Oil and Natural Gas Production Operations
Production:
Oil (000's of barrels) . . . . . . . . 1,497 1,531 1,491
Natural gas (MMcf) . . . . . . . . . . 8,817 5,024 2,565
Average sales prices:
Oil (per barrel) . . . . . . . . . . . $14.84 $16.74 $19.90
Natural gas (per Mcf). . . . . . . . . $ 1.86 $ 1.53 $ 1.48
Net recoverable reserves:
Oil (000's of barrels) . . . . . . . . 11,200 12,200 11,600
Natural gas (MMcf) . . . . . . . . . . 50,300 37,200 27,500
</TABLE> <PAGE>
<TABLE>
OPERATING STATISTICS
MDU RESOURCES GROUP, INC.
<CAPTION>
1990 1989 1988
<S> <C> <C> <C>
Electric Operations
Sales to ultimate consumers
(thousand kWh). . . . . . . . . . . . 1,820,150 1,836,099 1,843,982
Sales for resale (thousand kWh). . . . 285,564 311,327 246,425
Electric system generating and
firm purchase capability -- kW
(Interconnected system). . . . . . . . 451,600 451,600 451,600
Demand peak -- kW
(Interconnected system). . . . . . . . 381,600 383,600 386,700
Electricity produced
(thousand kWh) . . . . . . . . . . . .1,674,648 1,773,849 1,691,778
Electricity purchased
(thousand kWh) . . . . . . . . . . . . 573,099 557,650 598,443
Cost of fuel and purchased
power per kWh. . . . . . . . . . . . . $.016 $.017 $.017
Natural Gas Distribution Operations
Sales (Mdk). . . . . . . . . . . . . . . 28,278 31,643 32,557
Transportation (Mdk) . . . . . . . . . . 11,806 9,321 3,314
Weighted average degree days - % of
previous year's actual . . . . . . . . 88% 112% 113%
Natural Gas Transmission Operations
Sales for resale (Mdk) . . . . . . . . . 19,658 27,274 33,515
Transportation (Mdk) . . . . . . . . . . 50,809 51,159 33,892
Natural gas:
Produced (Mdk) . . . . . . . . . . . . 1,881 1,907 1,744
Purchased from others -- gross (Mdk) . 23,158 28,869 33,841
Stored (owned or controlled)
Net injection (withdrawal)-- MMcf. . 2,782 (24) (41)
Cost of natural gas purchased
per dk . . . . . . . . . . . . . . . . $2.01 $1.68 $1.78
Energy Marketing Operations
Natural gas volumes (Mdk). . . . . . . . 1,853 843 ---
Mining and Construction Materials Operations
Coal: (000's)
Tonnage sales. . . . . . . . . . . . . 4,439 4,747 4,759
Recoverable reserves in tons . . . . . 261,500 266,000 270,800
Construction materials: (000's)
Aggregates (tons sold) . . . . . . . . --- --- ---
Ready-mixed concrete (cubic
yards sold). . . . . . . . . . . . . --- --- ---
Asphalt (tons sold). . . . . . . . . . --- --- ---
Recoverable aggregate reserves
in tons. . . . . . . . . . . . . . . --- --- ---
Oil and Natural Gas Production Operations
Production:
Oil (000's of barrels) . . . . . . . . 1,374 1,348 1,358
Natural gas (MMcf) . . . . . . . . . . 1,846 1,605 1,464
Average sales prices:
Oil (per barrel) . . . . . . . . . . . $20.11 $16.26 $13.43
Natural gas (per Mcf). . . . . . . . . $ 1.63 $ 1.66 $ 2.14
Net recoverable reserves:
Oil (000's of barrels) . . . . . . . . 12,400 12,000 11,500
Natural gas (MMcf) . . . . . . . . . . 16,100 10,800 9,400
</TABLE>
SUBSIDIARIES OF MDU RESOURCES GROUP, INC.
December 31, 1993
State or Other
Jurisdiction
in Which
Incorporated
Alaska Basic Industries, Inc. Alaska
Anchorage Sand and Gravel Company, Inc. Alaska
Centennial Energy Holdings, Inc. Delaware
Concrete, Inc. California
Fidelity Oil Co. Delaware
Fidelity Oil Holdings, Inc. Delaware
Gwinner Propane, Inc. Delaware
Knife River Coal Mining Company Minnesota
KRC Aggregate, Inc. Delaware
KRC Holdings, Inc. Delaware
LTM, Incorporated Oregon
Prairielands Energy Marketing, Inc. Delaware
Rogue Aggregates, Inc. Oregon
WBI Canadian Pipeline, Ltd. Canada
Williston Basin Interstate Pipeline Company Delaware
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the
incorporation by reference in this Form 10-K of our report dated
January 25, 1994 included in the MDU Resources Group, Inc. Annual
Report to Stockholders for 1993. We also consent to the
incorporation of our reports included or incorporated by
reference in this Form 10-K into the Company's previously filed
Registration Statements on Form S-3, No. 33-46605 and
No. 33-66682, and on Form S-8, No. 2-96459, No. 33-54486,
No. 33-53896 and No. 33-53898. It should be noted that we have
not audited any financial statements of the Company subsequent
to December 31, 1993 or performed any audit procedures subsequent
to the date of our report.
/s/ ARTHUR ANDERSEN & CO.
ARTHUR ANDERSEN & CO.
March 3, 1994
Minneapolis, Minnesota,<PAGE>
<PAGE>
CONSENT OF ENGINEER
We hereby consent to the reference to our estimates dated
January 10 and 17, 1994, appearing in this Annual Report on Form
10-K.
We also consent to the incorporation by reference in the
Registration Statements on Form S-3, No. 33-46605 and
No. 33-66682, and on Form S-8, No. 2-96459, No. 33-54486,
No. 33-53896 and No. 33-53898 of MDU Resources Group, Inc. and in
the related Prospectuses of the reference to such reports
appearing in this Annual Report on Form 10-K.
/s/ RALPH E. DAVIS ASSOCIATES, INC.
RALPH E. DAVIS ASSOCIATES, INC.
March 3, 1994
Houston, Texas
<PAGE>
<PAGE>
CONSENT OF ENGINEER
We hereby consent to the reference to our report dated
January 20, 1989, appearing in this Annual Report on Form 10-K.
We also consent to the incorporation by reference in the
Registration Statements on Form S-3, No. 33-46605 and
No. 33-66682, and on Form S-8, No. 2-96459, No. 33-54486,
No. 33-53896 and No. 33-53898 of MDU Resources Group, Inc. and in
the related Prospectuses of the reference to such report
appearing in this Annual Report on Form 10-K.
/s/ PAUL WEIR COMPANY INCORPORATED
PAUL WEIR COMPANY INCORPORATED
March 3, 1994
Des Plaines, Illinois
