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, 19951996
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 $3.33 on which registered
and Preference Share Purchase Rights New York Stock Exchange
Pacific 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, and (2) has been
subject to such filing requirements for the past 90 days. Yes X.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 23, 1996: $587,338,000.21, 1997: $629,122,000.
Indicate the number of shares outstanding of each of the Registrant's
classes of common stock, as of February 23, 1996: 28,476,98121, 1997: 28,596,475 shares.
DOCUMENTS INCORPORATED BY REFERENCE.
1. Pages 23 through 49 of the Annual Report to Stockholders for 1995,1996,
incorporated in Part II, Items 6 and 8 of this Report.
2. Proxy Statement, dated March 4, 1996,3, 1997, incorporated in Part III,
Items 10, 11, 12 and 13 of this Report.
CONTENTS
PART I
Items 1 and 2 -- Business and Properties
General
Montana-Dakota Utilities Co. --
Electric Generation, Transmission and Distribution
Retail Natural Gas and Propane Distribution
Williston Basin Interstate Pipeline Company
Knife River Coal Mining Company Coal--
Construction Materials Operations
Construction MaterialsCoal Operations
Consolidated Construction Materials and Mining
Operations
Fidelity Oil Group
Item 3 -- Legal Proceedings
Item 4 -- Submission of Matters to a Vote of
Security Holders
PART II
Item 5 -- Market for the Registrant's Common Stock and
Related Stockholder Matters
Item 6 -- Selected Financial Data
Item 7 -- Management's Discussion and Analysis of
Financial Condition and Results of
Operations
Item 8 -- Financial Statements and Supplementary Data
Item 9 -- Change in and Disagreements with Accountants
on Accounting and Financial Disclosure
PART III
Item 10 -- Directors and Executive Officers of the
Registrant
Item 11 -- Executive Compensation
Item 12 -- Security Ownership of Certain Beneficial
Owners and Management
Item 13 -- Certain Relationships and Related
Transactions
PART IV
Item 14 -- Exhibits, Financial Statement Schedules and
Reports on Form 8-K
PART I
This Form 10-K contains forward-looking statements within the
meaning of Section 21E of the Securities Exchange Act of 1934.
Forward-looking statements should be read with the cautionary
statements and important factors included in this Form 10-K at Item
7 -- "Management's Discussion and Analysis of Financial Condition
and Results of Operations -- Safe Harbor for Forward-Looking
Statements." Forward-looking statements are all statements other
than statements of historical fact, including without limitation
those that are identified by the use of the words "anticipates,"
"estimates," "expects," "intends," "plans," "predicts" and similar
expressions.
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 256 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 CompanyCorporation (Knife
River), and 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.Wyoming and, effective
January 1, 1997, through its wholly owned subsidiary,
Prairielands Energy Marketing, Inc. (Prairielands), seeks
new energy markets while continuing to expand present
markets for natural gas and propane.
Knife River, through its wholly owned subsidiary, KRC
Holdings, Inc. (KRC Holdings) and its subsidiaries, surface
mines and markets aggregates and related construction
materials in Oregon, California, Alaska and Hawaii. In
addition, Knife River surface mines and markets low sulfur
lignite coal at mines located in Montana and North Dakota and,
throughDakota.
Effective February 7, 1997, Knife River Coal Mining Company
changed its wholly owned subsidiary, KRC Holdings, Inc.
(KRC Holdings), surface mines and markets aggregates and
related construction materials in the Anchorage, Alaska
area, southern Oregon, north-central California and the
Hawaiian Islands.name to Knife River Corporation.
Fidelity Oil is comprised of Fidelity Oil Co. and Fidelity
Oil Holdings, Inc., which own oil and natural gas interests
inthroughout the western United States, the Gulf Coastof Mexico and Canada
through investments with several oil and natural gas
producers.
Prairielands seeks new energy markets while continuing to
expand present markets for natural gas. Its activities
include buying and selling natural gas and arranging
transportation services to end users, pipelines and local
distribution companies and, through its wholly owned
subsidiary, Prairie Propane, Inc., operating bulk propane
facilities in north-central and 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.
As of December 31, 1995,1996, the Company had 1,8641,867 full-time
employees with 9582 employed at MDU Resources Group, Inc., including
Fidelity Oil, and Prairielands, 1,0901,041 at Montana-Dakota, 277289 at Williston Basin,
158 at Knife River's coal operations and 244including Prairielands, 303 at Knife River's construction materials
operations and 152 at Knife River's coal operations. Approximately
523511 and 8789 of the Montana-Dakota and Williston Basin employees,
respectively, are represented by the International Brotherhood of
Electrical Workers. Labor contractsWorkers (IBEW). Montana-Dakota's labor contract expired
on December 31, 1996, and Montana-Dakota is presently involved in
labor negotiations with such employeesthe IBEW. Employees subject to the
collective bargaining agreement voluntarily continue to work under
the terms and conditions of the expired contract. Discussions were
held with the IBEW, but no agreement was reached. Current
negotiations are being held through the help of federal mediation.
Montana-Dakota believes these negotiations will not result in a
work stoppage or have any material financial effect throughon its results
of operations. Williston Basin's labor contract with the IBEW also
expired on December 1996, for both Montana-Dakota31, 1996. Negotiations with the IBEW have been
concluded and Williston Basin.Basin's newly negotiated agreement through
May 1999 was ratified by the affected IBEW membership effective
February 3, 1997. However, the new labor agreement has not been
fully executed. Knife River's coal operations haveRiver has a labor contract through
August 1998, with the United Mine Workers of America, which
represents its coal operation's hourly workforce approximating 106aggregating 94
employees. In addition, Knife River'sRiver has 11 labor contracts which
represent 109 of its construction materials operations have 8 labor contracts
covering 100 employees. These contracts have expiration dates
ranging from May 1996, to December 1998.
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 23 through 47 in
the Company's Annual Report to Stockholders for 19951996 (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 112,000nearly 113,000 residential, commercial, industrial and municipal
customers located in 177 communities and adjacent rural areas as of
December 31, 1995.1996. 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 System Demand," and approximately 3,100 miles
and
3,900 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, 1995,1996, Montana-Dakota's net electric plant investment
approximated $280.7$281.4 million.
All of Montana-Dakota's electric properties, with certain
exceptions, are subject to the lien of the Indenture of Mortgage
dated May 1, 1939, as supplemented, amended and restated, from the
Company to The Bank of New York and W. T. Cunningham, successor
trustees.
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. Retail rates, service, accounting
and, in certain cases, security issuances are also subject to
regulation by the public service commissions of North Dakota Public Service Commission (NDPSC),
Montana Public Service Commission (MPSC), South Dakota Public
Utilities Commission (SDPUC) and Wyoming.Wyoming Public Service Commission
(WPSC). The percentage of Montana-Dakota's 19951996 electric utility
operating revenues by jurisdiction is as follows: North Dakota --
60 percent; Montana -- 23 percent; South Dakota -- 8 percent and
Wyoming -- 9 percent.
System Supply and System Demand --
Through an interconnected electric system, Montana-Dakota
serves markets in portions of the following states and 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 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 411,013415,408 kW. Montana-Dakota's four principal
generating stations are steam-turbine generating units using coal
for fuel. The nameplate rating for Montana-Dakota's ownership
interest in these four plants (includingstations(including interests in the Big
Stone Station and the Coyote Station aggregating 22.7 percent and
25.0 percent, respectively) 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 through
October 31, 2006, up to 66,400 kW of participation power from Basin
Electric Power Cooperative (Basin) (61,400 kW in 1995) for its interconnected system.
The following table sets forth details applicable to the Company's
electric generating stations:
1996 Net
Generation
Nameplate Summer 1995 Net(kilowatt-
Generating Rating Capability Generationhours in
Station Type (kW) (kW) (MWh)thousands)
North Dakota --
Coyote* Steam 103,647 106,750 699,032681,712
Heskett Steam 86,000 99,800 227,472102,000 367,126
Williston Combustion
Turbine 7,800 8,900 (66)**88
South Dakota --
Big Stone* Steam 94,111 98,763 548,35199,558 563,862
Montana --
Lewis & Clark Steam 44,000 43,800 224,18145,200 194,266
Glendive Combustion
Turbine 34,780 31,600 12,13014,598
Miles City Combustion
Turbine 23,150 21,400 6,9778,017
393,488 411,013 1,718,077
*Reflects415,408 1,829,669
* Reflects Montana-Dakota's ownership interest.
**Station use exceeded generation.
Virtually all of the current fuel requirements of the Coyote,
Heskett and Lewis & Clark stations are met with coal supplied by
Knife River under various long-term contracts. See "Construction
Materials and Mining Operations and Property (Knife River) -- Coal
Operations" for a discussion of a suit and arbitration filed by the
Co-owners of the Coyote Station against Knife River and the
Company. The majority of the Big Stone Station's fuel requirements
are currently being met with coal supplied by Westmoreland
Resources, Inc. under a contract which expires on December 31,
1999.
During the years ended December 31, 1991,1992, through December 31,
1995,1996, the average cost of 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 coal so consumed was as follows:
Years Ended December 31,
1996 1995 1994 1993 1992 1991
Average cost of
coal per
million Btu $.93 $.94 $.97 $.96 $.97 $.99
Average cost of
coal per ton $13.64 $12.90 $12.88 $12.78 $12.79 $13.06
The maximum electric peak demand experienced to date
attributable to sales to retail customers on the interconnected
system was 412,700 kW in August 1995. Due to a cooler than normal
summer, the 1996 summer peak was only 393,300 kW. The summer peak,
assuming normal weather, was previously forecasted to have been
approximately 410,700 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
20002001 will approximate .61.4 percent annually.
Kilowatt-hour (kWh) sales have increased approximately 1.7 percent
annually during the most recent five years. Montana-Dakota's
latest forecast indicates that its kilowatt-hour (kWh) sales growth
rate, on a normalized basis, through 20002001 will approximate
.8 percent annually. Montana-Dakota currently estimates that it
has adequate capacity available through existing generating
stations and long-term firm purchase contracts through the year
2005.1999.
Montana-Dakota has major interconnections with its neighboring
utilities, all of whomwhich are Mid-Continent Area Power Pool (MAPP)
members, which itmembers. Montana-Dakota considers these interconnections 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. 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 a
peak shaving load management system, Montana-Dakota estimates this
annual peak will not be exceeded through 1998.1999.
The Sheridan System iswas supplied through an interconnection
with Pacific Power & Light Company under a supply contract through
December 31, 1996. In September 1994, Montana-Dakota entered into
a ten-year power supply contract with Black Hills Corporation,
which operates its electric utility asBeginning January 1, 1997, Black Hills Power
and Light Company (BHPL). Beginning January 1, 1997, BHPL will supplybegan supplying the electric power and energy for
Montana-Dakota's electric service requirements for its Sheridan
System. TheSystem under a ten-year power supply contract is subjectwhich allows for the
purchase of up to approval55,000 kW of the FERC.capacity.
Regulation and Competition --
The electric utility industry can be expected to continue to
become increasingly competitive due to a variety of regulatory,
economic and technological changes. The increasing level of
competition is being fostered, in part, by the enactment in 1992 of
the National Energy Policy Act
of 1992 (NEPA). NEPA encourages competition by allowing both utilities and non-utilities to formfacilitating the creation
of non-regulated generators. As a result of competition in
electric generation, wholesale power markets have become
increasingly competitive. Under NEPA, the FERC may order access to
utility transmission systems by third-party energy producers on a
case-by-case basis and may order electric utilities to enlarge
their transmission systems to transport (wheel) power for such
third parties, subject to certain conditions. To date, no third
party producers are connected to Montana-Dakota's system.
On March 29, 1995,April 24, 1996, the FERC issued a Notice of Proposed
Rulemaking (NOPR)its final rule (Order No.
888) on Open Access Non-Discriminatory Transmission
Services by Public Utilities and Transmitting Utilities (FERC
Docket No. RM95-8-000) and a supplemental NOPR on Recovery of
Stranded Costs (FERC Docket No. RM94-7-001).
The proposed rules are intended to facilitate competition among
generators for sales to the bulk power supply market. If adopted,
the NOPR would require public utilities under the Federal Power Act
to file a generic set ofwholesale electric transmission tariff terms and conditions
as set forth in the rulemaking to provide open access to their
transmission systems. Previously, the FERC had not imposed on
utilities a general obligation to provide access to their
transmission systems. In addition, each public utility would also
be required to establish separate rates for its transmission and
generation services for new wholesale service, and to take
transmission services (including ancillary services) under the same
tariffs that would be applicable to third-party users for all of
its new wholesale sales and purchases of energy.
The supplemental NOPR on stranded costs provides a basis for
recovery by regulated public utilities of legitimate and verifiable
stranded costs associated with exiting wholesale requirements
customers and retail customers who become unbundled wholesale
transmission customers of the utility. The FERC would provide
public utilities with a mechanism for recovery of
stranded costs
that result from municipalization, former retail customers becoming
wholesale customers, or the loss of a wholesale customer. The FERC
would consider allowing recovery of stranded investment costs
associated with retail wheeling only if a state regulatory
commission lacks the authority to consider that issue.
It is anticipated that a final rule will be issued in the
first half of 1996. In connectioncosts. On July 8, 1996, Montana-Dakota filed proposed
tariffs with the FERC's NOPR,FERC in compliance with Order 888. Under the
MAPPproposed tariffs, which became effective on July 9, 1996, eligible
transmission service customers can choose to purchase transmission
services from a variety of options ranging from full use of the
transmission network on a firm long-term basis to a fully
interruptible service available on an hourly basis. The proposed
tariffs also include a full range of ancillary services necessary
to support the transmission of energy while maintaining reliable
operation of Montana-Dakota's transmission system. Montana-Dakota
is currently preparingawaiting final approval of the proposed tariffs by the FERC.
In a filingrelated matter, on March 29, 1996, the Mid-Continent Area
Power Pool (MAPP), of which Montana-Dakota is a member, filed a
restated operating agreement with the FERC to provide for wholesale
open access transmission on its members' systems on a non-discriminatorynon-
discriminatory basis. It is expected that such filingThe FERC approved MAPP's restated agreement,
excluding MAPP's market-based rate proposal, effective November 1,
1996. The FERC has requested additional information from the MAPP
on its market-based rate proposal before it will be submittedtake further
action.
On December 18, 1996, Montana-Dakota filed a Request for Waiver
of the requirements of FERC Order No. 889 as it relates to the
Standards of Conduct. The Standards of Conduct require companies
to physically separate their transmission operations/reliability
functions from their marketing/merchant functions. The Request for
Waiver is based on criteria established by the FERC, in
1996. Although no assurances can be providedexempting
small public utilities as todefined by the competitive
effects resulting from open access, Montana-Dakota does not believe
it will materially impact its operations.
ManyUnited States Small
Business Administration.
Three of the four state public service commissions which
regulate the Company's electric operations continue to evaluate
utility commissions, including Montana, are
currently studying the issue ofregulations with respect to retail wheeling.competition (retail
wheeling). Additionally, federal legislation addressing this issue
has been introduced. The MPSC, NDPSC and WPSC have initiated
discussions with jurisdictional utilities on the effects retail
wheeling would have on the industry and its customers. The MPSC
has adopted a set of principles to guide restructuring in that
state. These principles are similar to those recently adopted by
the National Association of Regulatory Utility Commissioners
(NARUC). The NARUC's general principle is that customers should
have access to adequate, safe, reliable and efficient services at
fair and reasonable prices at the lowest long-term cost to society,
and structural changes in the industry should be encouraged when
they result in improved economic efficiency and serve the broader
public interest. The NDPSC recently asked for comments from
jurisdictional utilities on the applicability of the NARUC's
principles, the effects of wholesale competition, and the effects
of mergers and acquisitions on the industry. The NDPSC held an
informal hearing and panel discussion in December 1996, regarding
these matters. Further discussions will be held on the issues
surrounding retail wheeling. The WPSC will continue its study of
retail wheeling during 1997, with a comprehensive review of the
whole issue and its likely economic impact on the State of Wyoming.
The SDPUC has not initiated any proceedings to date.
Although Montana-Dakota is unable to predict the outcome of
such regulatory proceedings or legislation or the extent of such
competition, Montana-Dakota is continuing to take steps to
effectively operate in an increasingly competitive environment.
Fuel adjustment clauses contained in North Dakota and South
Dakota jurisdictional electric rate schedules allow Montana-Dakota
to reflect increases or decreases in fuel and purchased power costs
(excluding demand charges) on a timely basis. Expedited rate
filing procedures in Wyoming allow Montana-Dakota to timely reflect
increases or decreases in fuel and purchased power costs as well as
changes in demand and load management costs. In Montana
(23 percent of electric revenues), such cost changes are includible
in general rate filings.
Capital Requirements --
The following schedule (in millions of dollars) summarizes the
19951996 actual and 19961997 through 19981999 anticipated constructionnet capital
expenditures applicable to Montana-Dakota's electric operations:
Actual Estimated
1995 1996 1997 1998 1999
Production $ 5.74.9 $ 5.45.2 $ 5.18.1 $ 7.39.4
Transmission 2.0 3.02.1 2.5 2.8 3.2 2.9
Distribution, General
and Common 12.0 9.9 8.511.1 10.0 7.5 $19.7 $18.3 $16.87.5
$18.1 $17.7 $18.4 $20.1
Environmental Matters --
Montana-Dakota's electric operations, are subject to extensive
federal, state and local laws and regulations providing for 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 environmental regulations
and permitting requirements.
The U.S. Clean Air Act (Act)(Clean Air 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 coal
fired. All of these stations, with the exception of the Big Stone
Station, are either 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. The emissions requirement at the Big Stone Station is
expected to be met by switching to competitively priced lower
sulfur ("compliance") coal.
In addition, the Clean Air Act will limitlimits the amount of nitrous
oxide emissions, although the rules as they relate to the majority ofemissions. Montana-Dakota's generating stations, have not yet been finalizedwith the
exception of the Big Stone Station, are within the limitations set
by the United States Environmental Protection Agency (EPA).
Accordingly, Montana-Dakota is currently unable to determine what modifications
may be necessary or the costs associated with any changes which may
be required.required at the Big Stone Station.
Governmental regulations establishing environmental protection
standards are continuously evolving and, therefore, the character,
scope, cost and availability of the measures which will permit
compliance with evolving laws or regulations, cannot now be
accurately predicted. Montana-Dakota did not incur any significant
environmental expenditures in 19951996 and does not expect to incur any
significant capital expenditures related to environmental
facilities during 19961997 through 1998.1999.
Retail Natural Gas and Propane Distribution
General --
Montana-Dakota sells natural gas and propane at retail, serving
over 195,000200,000 residential, commercial and industrial customers
located in 140142 communities and adjacent rural areas as of
December 31, 1995,1996, and provides natural gas transportation services
to certain customers on its system. These services are provided
through a natural gas
distribution system aggregating over 4,000 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 134,100 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, 1995,1996, Montana-Dakota's
net natural gas and propane distribution plant investment
approximated $80.0$78.5 million.
All of Montana-Dakota's natural gas distribution properties,
with certain exceptions, are subject to the lien of the Indenture
of Mortgage dated May 1, 1939, as supplemented, amended and
restated, from the Company to The Bank of New York and W. T.
Cunningham, successor trustees.
The natural gas and propane distribution operations of
Montana-Dakota are subject to regulation by the public service
commissions of North Dakota, Montana, South DakotaNDPSC, MPSC, SDPUC
and WyomingWPSC regarding retail rates, service, accounting and, in
certain instances, security issuances. The percentage of
Montana-Dakota's 19951996 natural gas and propane utility operating
revenues by jurisdiction is as follows: North Dakota -- 4344
percent; Montana -- 3029 percent; South Dakota -- 2021 percent and
Wyoming -- 76 percent.
System Supply, System Demand and Competition --
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 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. These markets are highly seasonal and
sales volumes depend on weather patterns.
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 Gas1996 1995 1994 1993 1992 1991
and Propane Throughput
Mdk (thousands of decatherms)
Sales:
Residential 22,682 20,135 19,039 19,565 17,141
18,904
Commercial 15,325 13,509 12,403 11,196 9,256
10,865
Industrial 276 295 398 386 284
305
Total Sales 38,283 33,939 31,840 31,147 26,681
30,074
Transportation:
Commercial 1,677 1,742 2,011 3,461 3,450
3,582
Industrial 7,746 9,349 7,267 9,243 10,292
8,679
Total Transporta-
tion 9,423 11,091 9,278 12,704 13,742
12,261
Total Throughput 47,706 45,030 41,118 43,851 40,423 42,335
The restructuring of the natural gas industry, as described
under "Natural Gas Transmission Operations and Property (Williston
Basin)", has resulted in additional competition in retail natural
gas markets. In response to these changed market conditions
Montana-Dakota has established various natural gas transportation
service rates for its distribution business to retain interruptible
commercial and industrial load. Certain of these services include
transportation under flexible rate schedules and capacity release
contracts whereby Montana-Dakota's interruptible customers can
avail themselves of the advantages of open access transportation on
the Williston Basin system. These services have enhanced Montana-
Dakota's competitive posture with alternate fuels, although certain
of Montana-Dakota's customers have the potential of bypassing
Montana-Dakota's distribution system by directly accessing
Williston Basin's facilities.
Montana-Dakota acquires all of its system requirements directly
from producers, processors and marketers. Such natural gas is
supplied under firm contracts, specifying market-based pricing, varying in length from less than one year to over four years and
is transported under firm transportation agreements by Williston
Basin and Northern Gas Company and, with respect to Montana-Dakota's
system expansion intoMontana-
Dakota's north-central South Dakota and to south-
centralsouth-central North Dakota
markets, by South Dakota Intrastate Pipeline Company and Northern
Border Pipeline Company, respectively. Montana-Dakota has also
contracted with Williston Basin to provide firm storage services
which enable Montana-Dakota to purchase natural gas at more uniform
daily volumes throughout the year and, thus, meet winter peak
requirements as well as allow it to better manage its natural gas
costs. 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.
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. Current
regulatory practices allow Montana-Dakota to recover increases or
refund decreases in such costs within 24 months from the time such
changes occur.
OnIn June 30, 1995, Montana-Dakota filed a general natural gas rate
increase application with the Montana Public Service
Commission (MPSC)MPSC requesting increased revenuesan increase of approximately $2.1
million or 4.4 percent. Hearings were heldOn April 17, 1996, the MPSC issued an
order in January 1996
and Montana-Dakota is awaitingthis proceeding authorizing additional annual revenues of
$1.0 million, or 49 percent of the MPSC's order.original amount requested. The
rate increase became effective May 1, 1996.
Capital Requirements --
In 1995, Montana-Dakota expended $8.9Montana-Dakota's net capital expenditures aggregated $5.7
million for natural gas and propane distribution facilities in 1996
and currently anticipates
expendingare anticipated to be approximately $7.7$8.4 million, $7.8 million
and $8.0$8.1 million in 1996, 1997, 1998 and 1998,1999, 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 with regard to the issuesissue 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. In
January 1994, Montana-Dakota, Williston Basin and Rockwell
International Corporation (Rockwell), manufacturer of the valve
sealant, reached an agreement under which Rockwell has and will
continue to reimburse Montana-Dakota and Williston Basin for a
portion of certain remediation costs. On the basis of findings to
date, Montana-Dakota and Williston Basin estimate future
environmental assessment and remediation costs will aggregate $3
million to $15 million. Based on such estimated cost, the expected
recovery from Rockwell and the ability of Montana-Dakota and
Williston Basin to recover their portions of such costs from
ratepayers, Montana-Dakota and Williston Basin believe that the
ultimate costs related to these matters will not be material to each
of their respective financial positions or results of operations.
In June 1990, Montana-Dakota was notified by the EPA that it
and several others were named as Potentially Responsible Parties
(PRPs) in connection with the cleanup of pollution at a landfill
site located in Minot, North Dakota. In June 1993, the EPA issued
its decision on the selected remediation to be performed at the
site. Based on the EPA's proposed remediation plan, estimates of
the total cleanup costs, including oversight costs, at this site
range from approximately $3.7 million to $4.8 million. In October
1995, the EPA and the City of Minot entered into a consent decree
which requires the city to implement as well as assume liability
for all cleanup costs associated with the remediation plan. The
remaining liability at this site for past and future federal
government oversight costs has been estimated by the EPA to be
approximately $1 million. Montana-Dakota believes that it was not
a material contributor to this contamination and, therefore,
further believes that its share of the approximately $1 million
estimated remaining liability will not have a material effect on
its results of operations.
CENTENNIAL ENERGY HOLDINGS, INC.
NATURAL GAS TRANSMISSION OPERATIONS AND PROPERTY (WILLISTON BASIN)
General --
Williston Basin owns and operates over 3,8003,600 miles of
transmission, gathering and storage lines and 2423 compressor stations
located in the states of Montana, North Dakota, South Dakota and
Wyoming. Through three underground storage fields 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 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. Williston Basin has interconnections with
seven pipelines in Wyoming, Montana and North Dakota which provide
for supply and market access. At December 31, 1995,1996, the net natural
gas transmission plant investment was approximately $161.1$159.0 million.
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, sales,
transportation, gathering and related storage operations.
System Demand and Competition --
The natural gas transmission industry, although regulated, is
very competitive. Beginning in the mid-1980s customers began
switching their natural gas service from a bundled merchant service
to transportation, and with the implementation of Order 636 which
unbundled pipelines' services, this transition was accelerated.
This change reflects most customers' willingness to purchase their
natural gas supply from producers, processors or marketers rather
than pipelines. Williston Basin competes with several pipelines for
its customers' transportation business and at times will have to
discount rates in an effort to retain market share. However, the
strategic location of Williston Basin's system near five natural gas
producing basins and the availability of underground storage and
gathering services provided by Williston Basin along with
interconnections with other pipelines serve to enhance Williston
Basin's competitive position.
Although a significant portion of Williston Basin's firm
customers, including Montana-Dakota, have relatively secure
residential and commercial end-
users,end-users, virtually all have some price-sensitiveprice-
sensitive end-users that could switch to alternate fuels.
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 essentially all suchof Montana-Dakota's
natural gas for Montana-Dakota under firm transportation agreements.agreements, which in 1996,
represented 91 percent of Williston Basin's currently subscribed
firm transportation capacity. On November 7, 1996, Montana-Dakota
executed a new firm transportation agreement with Williston Basin
for a term of five years beginning in July 1997. Montana-Dakota's
current firm transportation agreements will expire at that time.
In addition, Montana-Dakota has contracted with Williston Basin to
provide firm storage services to facilitate meeting Montana-Dakota's
winter peak requirements.
Preliminary discussions are currently underway between Montana-
Dakota and Williston Basin regarding the renewal of firm
transportation agreements representing 97 percent of Williston
Basin's currently subscribed firm transportation capacity, which
will expire in mid 1997. Williston Basin is currently unable to
determine the outcome of these discussions.
For additional information regarding Williston Basin's
sales
and transportation for 19931994 through 1995,1996, see Item 7 -- "Management's
Discussion and Analysis of Financial Condition and Results of
Operations".
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 facilities enable its customers to purchase natural gas at
more uniform daily volumes throughout the year and, thus, facilitate
meeting winter peak requirements.
In November 1994, Williston Basin completed a storage
enhancement project which increased its certificated storage
withdrawal capacity by 95 MMcf per day. This increase allows
Williston Basin to expand and enhance the storage services it
offers to its customers.
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 non-traditional, 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 other pipeline
interconnections or enhancements which 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, currently provides access up to 10,000 Mcf per day firm
Canadian supply with additional opportunities for interruptible
volumes.
Natural Gas Production --
Williston Basin owns in fee or holds natural gas leases and
operating rights primarily applicable to the shallow rights (above
2,000 feet) in the Cedar Creek Anticline in southeastern Montana and
to all rights in the Bowdoin area located in north-central Montana.
In 1994, Williston Basin undertook a drilling program designed
to increase production and to gain updated data from which to
assess the future production capabilities of its natural gas
reserves. In late 1994, upon analysis of the results of this
program, it was determined that the future production related to
these properties can be accelerated and, as a result, the economic
value of these reserves has become material to its operations.
Information on Williston Basin's natural gas production, average
sales prices and production costs per Mcf related to its natural gas
interests for 1996, 1995 and 1994 is as follows:
1996 1995 1994
Production (MMcf) 6,324 5,184 4,932
Average sales price $1.11 $0.91 $1.37
Production costs, including taxes per Mcf$0.43 $0.30 $0.47
Williston Basin's gross and net productive well counts and gross
and net developed and undeveloped acreage for its natural gas
interests at December 31, 1995,1996, are as follows:
Gross Net
Productive Wells 522 469532 479
Developed Acreage (000's) 228 206233 210
Undeveloped Acreage (000's) 53 4749 44
The following table shows the results of natural gas development
wells drilled and tested during 1996, 1995 and 1994:
1996 1995 1994
Productive 32 17 13
Dry Holes --- --- ---
Total 32 17 13
At December 31, 1995,1996, there were five wellswas 1 well in the process of
drilling.
Williston Basin's recoverable proved developed and undeveloped
natural gas reserves approximated 113.0133.4 Bcf at December 31, 1995.1996.
These amounts are supported by a report dated January 23, 1996,31, 1997,
prepared by Ralph E. Davis Associates, Inc., an independent firm of
petroleum and natural gas engineers.
For additional information related to Williston Basin's natural
gas interests, see Note 19 of Notes to Consolidated Financial
Statements.
Pending Litigation --
In November 1993, the estate of W. A. Moncrief (Moncrief), a
producer from whom Williston Basin purchased a portion of its
natural gas supply, filed suit in Federal District Court for the
District of Wyoming (Court)(Federal District Court) against Williston Basin
and the Company disputing certain price and volume issues under the
contract.
In
its complaint, Moncrief alleged that, for the period January 1,
1985, through December 31, 1992, it had suffered damages ranging
from $1.2 million to $5.0 million, without interest, on the price
paid by Williston Basin for natural gas purchased. Moncrief
requested that the Court award it such amount and further requested
that Williston Basin be obligated for damages for additional volumes
not purchased for the period from November 1, 1993, (the date when
Williston Basin implemented FERC Order 636 and abandoned its natural
gas sales merchant function) to mid-1996, the remaining period of
the contract.
In June 1994, Moncrief filed a motion to amend its complaint
whereby it alleged a new pricing theory under Section 105 of the
Natural Gas Policy Act for natural gas purchased in the past and for
future volumes which Williston Basin refused to purchase effective
November 1, 1993. In July 1994, the Court denied Moncrief's motion
to amend its complaint.
However, in July 1994, the Court, as part of addressing the
proper litigants in this matter, allowed Moncrief to amend its
complaint to assert its new pricing theory under the contract.
Through the course of this action Moncrief has submitted damage
calculations which totaltotalled approximately $19 million or, under its
alternative pricing theory, approximately $39 million.
On March 10,
1995,August 16, 1996, the Federal District Court issued a summary judgment dismissing Moncrief's
pricing theories and substantially reducing Moncrief's claims.
Trial was held in Januaryits
decision finding that Moncrief is entitled to damages for the
difference between the price Moncrief would have received under the
geographic favored-nations price clause of the contract for the
period from August 13, 1993, through July 7, 1996, and the actual
price received for the gas. The favored-nations price is the
highest price paid from time to time under contracts in the same
geographic region for natural gas of similar quantity and quality.
The Federal District Court reopened the record until October 15,
1996, to receive additional briefs and exhibits on this issue.
On October 15, 1996, Moncrief submitted its brief claiming
damages ranging as high as $22 million under the geographic favored-
nations price theory. Williston Basin, is awaiting the
Court's decision.in its brief, contended that
Moncrief waived its claim for a favored-nations price under an
agreement with Williston Basin, and Moncrief's damage claims inwere
calculated utilizing non-comparable contracts. Williston Basin's
opinion, are
grossly overstated.exhibits show Moncrief's damages should be limited to approximately
$800,000 under the geographic favored-nations price theory.
A hearing on all pending matters is currently scheduled for
April 3, 1997. Williston Basin plans to file for recovery from
ratepayers of amounts which may be ultimately due to Moncrief, if
any.
In December 1993, Apache Corporation (Apache) and Snyder Oil
Corporation (Snyder) filed suit in North Dakota District Court,
Northwest Judicial District, against Williston Basin and the
Company. Apache and Snyder are oil and natural gas producers who
had processing agreements with Koch Hydrocarbon Company (Koch).
Williston Basin and the Company had a natural gas purchase contract
with Koch. Apache and Snyder have alleged they are entitled to
damages for the breach of Williston Basin's and the Company's
contract with Koch. Williston Basin and the Company believe that
if Apache and Snyder have any legal claims, such claims are with
Koch, not with Williston Basin or the Company. Williston Basin, the
Company and Koch have settled their disputes. Apache and Snyder
have recently provided alleged damages under differing theories
ranging up to $8.2 million without interest. A motion to intervene
in the case by several other producers, all of whom had contracts
with Koch but not with Williston Basin, was denied on December 13,
1996. Trial on this matter is scheduled for September 8, 1997.
The claims of Apache and Snyder, in Williston Basin's opinion,
are without merit and overstated. If any amounts are ultimately
found to be due Apache and Snyder, Williston Basin plans to file for
recovery from ratepayers.
On July 18, 1996, Jack J. Grynberg (Grynberg) filed suit in
United States District Court for the District of Columbia against
Williston Basin and over 70 other natural gas pipeline companies.
Grynberg, acting on behalf of the United States under the False
Claims Act, is alleging improper measurement of the heating content
or volume of natural gas purchased by the defendants resulting in
the underpayment of royalties to the United States. The United
States government, particularly officials from the Departments of
Justice and Interior, reviewed the complaint and the evidence
presented by Grynberg and declined to intervene in the action,
permitting Grynberg to proceed on his own. Williston Basin believes
Grynberg's claims are without merit and intends to vigorously
contest this suit.
Regulatory Matters and Revenues Subject to Refund --
Williston Basin hadhas pending with the FERC two general natural
gas rate change applications implemented in 19891992 and 1992.1996. In May 1994,July
1995, the FERC issued an order relating to Williston Basin's 1992
rate change application. In August 1995, Williston Basin filed,
under protest, tariff sheets in compliance with the 1989 rate change.FERC's order,
with rates which went into effect on September 1, 1995. Williston
Basin requested rehearing of certain issues addressed in the order and a stay of compliance and refund pending issuance of
a final order by the FERC. The requested stay was denied by the
FERC and inorder.
On July 1994, Williston Basin refunded $47.8 million to its
customers, including $33.4 million to Montana-Dakota, all of which
had been reserved. On April 5, 1995,19, 1996, the FERC issued an order granting in part and
denying in part Williston Basin's rehearing request. As a result of the FERC's order, Williston Basin,A hearing was
held on May 18, 1995, billed its customers approximately $2.7 million, plus
interest, to recover a portion of the amount previously refunded in
July 1994.
On July 25, 1995, the FERC issued an order relating to Williston
Basin's 1992 rate change application. On August 24, 1995, Williston
Basin filed, under protest, tariff sheets in compliance with the
FERC's order, with rates to be effective September 1, 1995.
Williston Basin requested rehearing of certain issues addressed in
the order29, 1996, and the rehearingthis matter is currently pending before
the FERC. OnIn addition, Williston Basin has appealed certain issues
contained in the FERC's orders to the U.S. Court of Appeals for the
D.C. Circuit (D.C. Circuit Court).
In June 30, 1995, Williston Basin filed a general rate increase
application with the FERC. As a result of FERC requestingorders issued after
Williston Basin's application was filed, in December 1995, Williston
Basin filed revised base rates with the FERC resulting in an
increase of $3.6$8.9 million or 6.5519.1 percent over the currently
effective August 1, 1995.rates. Williston Basin began collecting such increase
effective January 1, 1996, subject to refund,refund.
On February 3, 1997, Williston Basin filed briefs with the D.C.
Circuit Court related to its appeal of orders which had been
received from the FERC beginning in May 1993, regarding the
appropriate selling price of certain natural gas in underground
storage which was determined to be excess upon Williston Basin's
implementation of Order 636. The FERC ordered that the gas be
offered for sale to Williston Basin's customers at its original
cost. Williston Basin requested rehearing of this matter on January 1, 1996.the
grounds that the FERC's order constituted a confiscation of its
assets, which request was subsequently denied by the FERC.
Williston Basin believes that it should be allowed to sell this
natural gas at its fair value and retain any profits resulting from
such sales since its ratepayers had never paid for the natural gas.
Oral arguments on this matter before the D.C. Circuit Court are
scheduled for May 9, 1997.
Reserves have been provided for a portion of the revenues that
have been collected subject to refund with respect to pending
regulatory proceedings and for the recovery of certain producer
settlement buy-out/buy-down costs to reflect future resolution of
certain issues with the FERC. Williston Basin believes that such
reserves are adequate based on its assessment of the ultimate
outcome of the various proceedings.
Natural Gas Repurchase Commitment --
The Company has offered for sale since 1984 the inventoried
natural gas available under a repurchase commitment with Frontier
Gas Storage Company, as described in Note 3 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.
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 $5.7 million, $6.0 million and
$4.6 million in 1996, 1995 and $3.9 million in 1995, 1994, and 1993, respectively.
The FERC has issued orders that have held that storage costs
should be allocated to this gas, prospectively beginning May 1992,
as opposed to being included in rates applicable to Williston
Basin's customers. These storage costs, as initially allocated to
the Frontier gas, approximated $2.1 million annually, and represent
costsfor which
Williston Basin may not recover. This matter is
currently on appeal. The issue regarding the applicability of
assessing storage chargeshas provided reserves. Williston Basin appealed
these orders to the gas creates additional uncertainty
asD.C. Circuit Court. On December 26, 1996, the
D.C. Circuit Court issued its order ruling that the FERC's actions
in allocating costs to the costs associated with holdingFrontier gas were appropriate. Williston
Basin is awaiting a final order from the gas.FERC.
Beginning in October 1992, as a result of prevailing natural gas
prices, Williston Basin began to sell and transport a portion of the
natural gas held under the repurchase commitment. Through December 31, 1995, 17.6the
second quarter of 1996, 17.8 MMdk of this natural gas had been sold bysold.
However, in the third quarter of 1996, Williston Basin, based on a
number of factors including differences in regional natural gas
prices and natural gas sales occurring at that time, wrote down the
remaining 43.0 MMdk of this gas to its then current market value.
The value of this gas was determined using the sum of discounted
cash flows of expected future sales occurring at then current
regional natural gas prices as adjusted for use by both on- and off-system markets.anticipated future price
increases. This resulted in a write-down aggregating $18.6 million
($11.4 million after tax). In addition, Williston Basin will continuewrote off
certain other costs related to aggressivelythis natural gas of approximately
$2.5 million ($1.5 million after tax). The amounts related to this
write-down are included in "Costs on natural gas repurchase
commitment" in the Consolidated Statements of Income. The
recognition of the then current market the remaining
43.2 MMdkvalue of this natural gas
wheneverfacilitated the sale by Williston Basin of 10.4 MMdk from the date
of the write-down through December 31, 1996, and should allow
Williston Basin to market conditions are
favorable. In addition, it will continuethe remaining 32.5 MMdk on a sustained
basis enabling Williston Basin to seek long-term sales
contracts.liquidate this asset over
approximately the next five years.
Other Information --
In December 1994, the United States Minerals Management Service
(MMS) directed Williston Basin to pay approximately $1.9 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 March 1,
1988, through December 31, 1991. This matter is currently on appeal
with the MMS.
In December 1993, Williston Basin received from the Montana
Department of Revenue (MDR) an assessment claiming additional
production taxes due of $3.7 million, plus interest, for 1988
through 1991 production. These claimed taxes result from the MDR's
belief that certain natural gas production during the period at
issue was not properly valued. Williston Basin does not agree with
the MDR and has reached an agreement with the MDR that the appeal
process be held in abeyance pending further review.
Capital Requirements --
The following schedule (in millions of dollars) summarizes the
19951996 actual and 19961997 through 19981999 anticipated constructionnet capital
expenditures applicable to Williston Basin's operations:
Actual Estimated
1995 1996 1997 1998 1999
Production and Gathering $3.5$---* $ 5.94.5 $ 3.6 $ 6.56.7 $13.0
Underground Storage .3 .3 .2 .2.1 .4 1.0 1.4
Transmission 3.5 3.8 7.1 11.33.2 5.4 4.2 10.9
General 2.4 1.6 1.9 1.9
$9.7 $11.6 $12.8 $19.9and Other 1.7 2.2** 1.7** 4.7**
$5.0 $12.5 $13.6 $30.0
* Net of $5.1 million in preferred stock and cash received from
the sale of 208 miles of underutilized gathering lines and
related facilities to Interenergy Corporation.
** Includes net capital expenditures for Prairielands.
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.
CONSTRUCTION MATERIALS AND MINING 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, North Dakota, Savage, Montana and, until August
1995, at Gascoyne, North Dakota. The average annual production
from the Beulah and Savage mines approximates 2.6 million and
300,000 tons, respectively, while the Gascoyne Mine's production
had historically averaged 2.1 million tons annually. Reserve
estimates related to these mine locations are discussed herein.
During the last five years, Knife River mined and sold the
following amounts of lignite coal:
Years Ended December 31,
1995 1994 1993 1992 1991
(In thousands)
Tons sold:
Montana-Dakota generating stations 453 691 624 521 618
Jointly-owned generating stations--
Montana-Dakota's share 883 1,049 1,034 1,021 953
Others 2,767 3,358 3,299 3,259 3,069
Industrial and other sales 115 108 109 112 91
Total 4,218 5,206 5,066 4,913 4,731
Revenues $39,956 $45,634 $44,230 $43,770 $41,201
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.
In June 1994, Knife River was notified by the owners of the Big
Stone Station that its contract for supplying approximately 2.1
million tons of lignite annually from the Gascoyne Mine would not
be renewed. The current contract expired in August 1995 and, as a
result, Knife River closed the Gascoyne Mine. The costs of closing
the Gascoyne Mine did not have a significant effect on Knife
River's results of operations.
On November 27, 1995, a suit was filed in District Court
(Court), County of Burleigh, State of North Dakota by Minnkota
Power Cooperative, Inc., Otter Tail Power Company, Northwestern
Public Service Company and Northern Municipal Power Agency (Co-
owners), the owners of an aggregate 75 percent interest in the
Coyote Station, against the Company and Knife River. In its
complaint, the Co-owners have alleged a breach of contract against
Knife River of the long-term coal supply agreement (Agreement)
between the owners of the Coyote Station and Knife River. The Co-
owners have requested a determination by the Court of the pricing
mechanism to be applied to the Agreement and have further requested
damages during the term of such alleged breach on the difference
between the prices charged by Knife River and the prices as may
ultimately be determined by the Court. The Co-owners are also
alleging a breach of fiduciary duties by the Company as operating
agent of the Coyote Station, asserting essentially that the Company
was unable to cause Knife River to reduce its coal price
sufficiently under such contract, and are seeking damages in an
unspecified amount. On January 8, 1996, the Company and Knife
River filed separate motions with the Court to dismiss or stay
pending arbitration. Such matter is pending before the Court with
oral arguments scheduled for April 22, 1996. The Company and Knife
River believe they have meritorious defenses and intend to
vigorously defend the suit.
Knife River does not anticipate any significant growth in its
lignite coal operations in the near future due to competition from
coal and other alternate fuel sources. Limited growth
opportunities may be available to Knife River's lignite coal
operations through the continued evaluation and pursuit of niche
markets such as agricultural products processing facilities, as
well as participating in the development of clean coal
technologies.
In order to seek greater growth opportunities and to utilize
further its surface mining expertise, Knife River, in 1992, began
expanding its operations into the mining and marketing of
aggregates and related construction materials as discussed below.
Construction Materials Operations:
General --
Knife River, through KRC Holdings, operates construction
materials and mining businesses in the Anchorage, Alaska area,
north and north-central California, southern Oregon and southern Oregon.the
Hawaiian Islands. These operations produce and sell construction
aggregates (sand and gravel) and supply ready-mixed concrete for
use in most types of construction including homes, schools,
shopping centers, office buildings and industrial parks as well as
roads, freeways and bridges.
In addition, the Alaskan, northern California and Oregon
operations produce and sell asphalt for various commercial and
roadway applications. Although not common to all locations, other
products include the manufacture and/or sale of cement, various
finished concrete products and other building materials and related
construction services.
In September 1995,April 1996, KRC Holdings through its wholly owned
subsidiary, Knife River Hawaii,purchased Baldwin Contracting
Company, Inc., (Baldwin) of Chico, California. Baldwin is a major
supplier of aggregate, asphalt and construction services in the
northern Sacramento Valley and adjacent Sierra Nevada Mountains of
northern California. Baldwin also provides a variety of
construction services, primarily earth moving, grading, road and
highway construction and maintenance.
In June 1996, KRC Holdings purchased the assets of Medford
Ready-Mix Concrete, Inc. (Medford) located in Medford, Oregon. The
acquired a 50 percent
interest in Hawaiian Cement, which was previously owned by Lone
Star Industries, Inc. Hawaiian Cement is one ofcompany serves the largestresidential and small commercial
construction materials suppliers in Hawaii serving four of the
islands. Hawaiian Cement's operations include construction
aggregate mining,market with ready-mixed concrete and cement manufacturing and
distribution. Hawaiian Cement, headquartered in Honolulu, Hawaii,
is a partnership which is also 50 percent owned by Adelaide
Brighton Ltd. of Adelaide, Australia.
The following table reflectsaggregates.
For information regarding sales volumes and revenues for the
construction materials operations during the last three years:
Years Ended December 31,
1995for 1994 1993
(In thousands)
Aggregates (tons) 2,904 2,688 2,391
Asphalt (tons) 373 391 141
Ready-mixed concrete (cubic yards) 307 315 157
Revenues $73,110 $71,012 $46,167through 1996, see Item
7 -- "Management's Discussion and Analysis of Financial Condition
and Results of Operations."
Competition --
Knife River's construction materials products are marketed
under highly competitive conditions. Since there are generally no
measurable product differences in the market areas in which Knife
River conducts its construction materials businesses, price is the
principal competitive force these products are subject to, with
service, delivery time and proximity to the customer also being
significant factors. The number and size of competitors varies in
each of Knife River's principal market areas and product lines.
The demand for construction materials products is significantly
influenced by the cyclical nature of the construction industry in
general. The key economic factors affecting product demand are
changes in the level of local, state and federal governmental
spending, general economic conditions within the market area which
influences both the commercial and private sectors, and prevailing
interest rates.
Knife River is not dependent on any single customer or group of
customers for sales of its construction materials products, the
loss of which would have a materially adverse affect on its
construction materials businesses. During 1993, 1994, 1995 and 1995,1996, no
single customer accounted for more than 10 percent of annual
construction materials revenues.
Coal Operations:
General --
Knife River is engaged in lignite coal mining operations.
Knife River's surface mining operations are located at Beulah,
North Dakota and Savage, Montana. The average annual production
from the Beulah and Savage mines approximates 2.6 million and
300,000 tons, respectively. Reserve estimates related to these
mine locations are discussed herein. During the last five years,
Knife River mined and sold the following amounts of lignite coal:
Years Ended December 31,
1996 1995 1994 1993 1992
(In thousands)
Tons sold:
Montana-Dakota generating stations 528 453 691 624 521
Jointly-owned generating stations--
Montana-Dakota's share 565 883 1,049 1,034 1,021
Others 1,695 2,767 3,358 3,299 3,259
Industrial and other sales 111 115 108 109 112
Total 2,899 4,218 5,206 5,066 4,913
Revenues $32,696 $39,956 $45,634 $44,230 $43,770
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.
In November 1995, a suit was filed in District Court, County of
Burleigh, State of North Dakota (State District Court) by Minnkota
Power Cooperative, Inc., Otter Tail Power Company, Northwestern
Public Service Company and Northern Municipal Power Agency (Co-
owners), the owners of an aggregate 75 percent interest in the
Coyote Station, against the Company and Knife River. In its
complaint, the Co-owners alleged a breach of contract against Knife
River of the long-term coal supply agreement (Agreement) between the
owners of the Coyote Station and Knife River. The Co-owners have
requested a determination by the State District Court of the pricing
mechanism to be applied to the Agreement and have further requested
damages during the term of such alleged breach on the difference
between the prices charged by Knife River and the prices as may
ultimately be determined by the State District Court. The Co-owners
also alleged a breach of fiduciary duties by the Company as
operating agent of the Coyote Station, asserting essentially that
the Company was unable to cause Knife River to reduce its coal price
sufficiently under the Agreement, and are seeking damages in an
unspecified amount. On January 8, 1996, the Company and Knife River
filed separate motions with the State District Court to dismiss or
stay pending arbitration. On May 6, 1996, the State District Court
granted the Company's and Knife River's motions and stayed the suit
filed by the Co-owners pending arbitration, as provided for in the
Agreement.
On September 12, 1996, the Co-owners notified the Company and
Knife River of their demand for arbitration of the pricing dispute
that had arisen under the Agreement. The demand for arbitration,
filed with the American Arbitration Association (AAA), did not make
any direct claim against the Company in its capacity as operator of
the Coyote Station. The Co-owners requested that the arbitrators
make a determination that the pricing dispute is not a proper
subject for arbitration. In the alternative, the Co-owners
requested the arbitrators to make a determination that the prices
charged by Knife River were excessive and that the Co-owners should
be awarded damages based upon the difference between the prices that
Knife River charged and a "fair and equitable" price, approximately
$50 million or more. Upon application by the Company and Knife
River, the AAA administratively determined that the Company was not
a proper party defendant to the arbitration, and the arbitration is
proceeding against Knife River. Although unable to predict the
outcome of the arbitration, Knife River and the Company believe that
the Co-owners claims are without merit and intend to vigorously
defend the prices charged pursuant to the Agreement.
Knife River does not anticipate any significant growth in its
lignite coal operations in the near future due to competition from
coal and other alternate fuel sources. Limited growth opportunities
may be available to Knife River's lignite coal operations through
the continued evaluation and pursuit of niche markets such as
agricultural products processing facilities.
Consolidated Construction Materials and Mining Operations:
Capital Requirements --
The following schedule (in millions of dollars) summarizes the
19951996 actual, including the amountamounts related to the acquisition of
Hawaiian Cement,Baldwin and 1996Medford, and 1997 (including amounts related to
anticipated acquisitions) through 19981999 anticipated constructionnet capital
expenditures applicable to Knife River's consolidated construction
materials and mining operations:
Actual Estimated
1995 1996 1997 1998 1999
Construction Materials $35.5 $3.1 $3.0 $3.3$22.2 $31.1 $ 9.4 $ 6.6
Coal 1.3 3.6 4.81.9 4.3 4.6 4.5
$36.8 $6.7 $7.8 $7.8$24.1 $35.4 $14.0 $11.1
Knife River continues to seek additional growth opportunities.
These include not only identifying possibilities for alternate uses
of lignite coal but also investigating the acquisition of other surface mining
properties, particularly those relating to sand and gravel
aggregates and related products such as ready-mixed concrete,
asphalt and various finished aggregate products.
Environmental Matters --
Knife River's construction materials and mining operations are
subject to regulation customary for surface mining operations,
including federal, state and local environmental and reclamation
regulations. Except as may be found with regard to the issue
described below, Knife River believes that these operations areit is in substantial
compliance with those regulations.
In September 1995, Unitek Environmental Services, Inc. and
Unitek Solvent Services, Inc. (Unitek) filed a complaint against
Hawaiian Cement in the United States District Court for the District
of Hawaii (District Court) alleging that dust emissions from
Hawaiian Cement's cement manufacturing plant at Kapolei, Hawaii
(Plant) violated the Hawaii State Implementation Plan (SIP) of the
Clean Air Act, constituted a continual nuisance and trespass on the
plaintiff's property, and that Hawaiian Cement's conduct warranted
the payment of punitive damages. Hawaiian Cement is a Hawaiian
general partnership whose general partners (with joint and several
liability) are Knife River Hawaii, Inc., an indirect wholly owned
subsidiary of the Company, and Adelaide Brighton Cement (Hawaii),
Inc. Unitek is seeking civil penalties under the Clean Air Act (as
described below), and had sought damages for various claims (as
described above) of up to $20 million in the aggregate.
On August 7, 1996, the District Court issued an order granting
Plaintiffs' motion for partial summary judgment relating to the
Clean Air Act, indicating that it would issue an injunction shortly.
The issue of civil penalties under the Clean Air Act was reserved
for further hearing at a later date, and Unitek's claims for damages
were not addressed by the District Court at such time.
On September 16, 1996, Unitek and Hawaiian Cement reached a
settlement which resolved all claims relating to the $20 million in
damages that Unitek had previously sought. However, the settlement
did not resolve the matter regarding the civil penalties sought by
Unitek relating to the alleged violations by Hawaiian Cement of the
Clean Air Act nor did it affect the EPA's Notice of Violation (NOV)
as discussed below. Based on a joint petition filed by Unitek and
Hawaiian Cement, the District Court stayed the proceeding and the
issuance of an injunction while the parties continue to negotiate
the remaining Clean Air Act claims.
On May 7, 1996, the EPA issued a NOV to Hawaiian Cement. The
NOV states that dust emissions from the Plant violated the SIP.
Under the Clean Air Act, the EPA has the authority to issue an order
requiring compliance with the SIP, issue an administrative order
requiring the payment of penalties of up to $25,000 per day per
violation (not to exceed $200,000), or bring a civil action for
penalties of not more than $25,000 per day per violation and/or
bring a civil action for injunctive relief. It is also possible
that the EPA could elect to join the suit filed by Unitek.
Depending upon the specific actions that may ultimately be taken by
either the EPA or the District Court, Hawaiian Cement is likely to
have to modify its operations at its cement manufacturing facility.
Hawaiian Cement has met with the EPA and settlement discussions are
currently ongoing.
Although no assurance can be provided, the Company does not
believe that the total cost of any modifications to the facility,
the level of civil penalties which may ultimately be assessed or
settlement costs, will have a material effect on the Company's
results of operations.
Reserve Information --
As of December 31, 1995,1996, the combined construction materials
operations had under ownership approximately 120 million tons of
recoverable aggregate reserves.
As of December 31, 1996, Knife River had under ownership or
lease, reserves of approximately 232229 million tons of recoverable
lignite coal, (including 114 million tons at the recently closed
Gascoyne Mine), 9289 million tons of which are at present mining
locations. Such reserve estimates were prepared by Weir
International Mining Consultants, independent mining engineers and
geologists, in a report dated May 9, 1994, and have been adjusted
for 1994 and 1995through 1996 production. Knife River estimates that
approximately 7067 million tons of its reserves will be needed to
supply Montana-Dakota's Coyote, Heskett and Lewis & Clark 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, 1995, the combined construction materials
operations had under ownership approximately 68 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 undertakes ventures, through working-interest
agreements with selected operators. These venturesOil's operations vary from the acquisition of producing
properties with potential development opportunities to exploration
and are located inthroughout 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, 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 an operating agreement with
Shell Western E&P, Inc., 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.interests.
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 1996, 1995 1994 and 19931994
are as follows:
1996 1995 1994 1993
Oil:
Production (000's of barrels) 2,149 1,973 1,565 1,497
Average sales price $17.91 $15.07 $13.14 $14.84
Natural Gas:
Production (MMcf) 14,067 12,319 9,228 8,817
Average sales price $2.09 $1.51 $1.84 $1.86
Production costs, including taxes,
per net equivalent barrel $3.31 $3.18 $4.04 $3.98
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
workingrelated to its interests at
December 31, 1995,1996, are as follows:
Gross Net
Productive Wells:
Oil 4,829 1792,712 148
Natural Gas 600 30491 28
Total 5,429 2093,203 176
Developed Acreage (000's) 1,085 83702 65
Undeveloped Acreage (000's) 655 67947 73
Exploratory and Development Wells --
The following table shows the results of oil and natural gas
wells drilled and tested during 1996, 1995 1994 and 1993:1994:
Net Exploratory Net Development
Productive Dry Holes Total Productive Dry Holes Total Total
1996 1 2 3 4 0 4 7
1995 3 2 5 8 1 9 14
1994 4 3 7 6 1 7 14
1993 2 2 4 5 1 6 10
At December 31, 1995,1996, there were three development wells and no
exploratory wells or
development wells in the process of drilling.
Capital Requirements --
The following summary (in millions of dollars) reflects net
capital expenditures, including those not subject to amortization,
related to oil and natural gas activities for the years 1996, 1995
and 1994:
1996 1995 1994
and
1993:
1995 1994 1993
Acquisitions $23.2 $ 9.49.1 $ 5.6 $ 9.33.2
Exploration 8.1 7.7 13.2 7.812.6
Development 22.6 19.7 7.8
Total15.9 22.2 18.8
Net Capital Expenditures $39.7 $38.5 $24.9$47.2 $39.0 $34.6
Fidelity Oil plans additional commitmentsOil's net capital expenditures are anticipated to oil and gas
investments and has budgeted $40 million, $45 million andbe
approximately $50 million for the years 1996,both 1997 and 1998 respectively,and $55 million for
such
activities.1999.
Reserve Information --
Fidelity Oil's recoverable proved developed and undeveloped oil
and natural gas reserves approximated 14.216.1 million barrels and 66.066.8
Bcf, respectively, at December 31, 1995.1996. Of these amounts, 9.29.3
million barrels and 2.12.2 Bcf, as supported by a report dated
January 9, 1996,1997, 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 19 of Notes to Consolidated
Financial Statements.
ITEM 3. LEGAL PROCEEDINGS
The Company and Knife River have been named as defendants in a
legal action primarily related to coal pricing issues at the Coyote
Station. Such suit was filed by the Co-owners of the Coyote
Station as described under Items 1 and 2Williston Basin -- "Business and
Properties -- Construction Materials and Mining Operations and
Property." The Company's and Knife River's assessment of this
proceeding is included in the description of the litigation.
Williston Basin has been named as a defendant in a legal action
primarily related to certain natural gas price and volume issues.
Such suit was filed by MoncriefMoncrief.
In addition, Williston Basin has been named as a defendant in
a legal action related to a natural gas purchase contract. Such
suit was filed by Apache and Snyder.
Also, Williston Basin and over 70 other natural gas pipeline
companies have been named as defendants in a legal action related
to measurement of the heating content or volume of natural gas
purchased by the defendants. Such suit was filed by Grynberg.
The above legal actions are described under Items 1 and 2 --
"Business and Properties -- Natural Gas Transmission Operations and
Property.Property (Williston Basin)." Williston Basin'sThe Company's assessment of this proceedingthe
proceedings are included in the respective descriptions of the
litigation.
Knife River --
The Company and Knife River have been named as defendants in a
legal action primarily related to coal pricing issues at the Coyote
Station. The suit has been stayed by the State District Court
pending arbitration. Such suit was filed by the Co-owners of the
Coyote Station.
Hawaiian Cement has been named as a defendant in a legal action
primarily related to dust emissions from Hawaiian Cement's cement
manufacturing plant at Kapolei, Hawaii. Such suit was filed by
Unitek. In addition, the EPA has issued a NOV to Hawaiian Cement.
The above legal actions are described under Items 1 and 2 --
"Business and Properties -- Construction Materials and Mining
Operations and Property (Knife River)." The Company's assessment
of the proceedings is included in the descriptionrespective descriptions 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 1995.1996.
PART II
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON STOCK AND RELATED
STOCKHOLDER MATTERS
The Company's common stock is listed on the New York Stock
Exchange and the Pacific Stock Exchange under the symbol "MDU". The
price range of the Company's common stock as reported by theThe Wall
Street Journal composite tape during 19951996 and 19941995 and dividends
declared thereon were as follows:
Common
Common Common Stock
Stock Price Stock Price Dividends
(High)* (Low)* Per Share*
1995Share
1996
First Quarter $23.00 $19.88 $0.2725
Second Quarter 23.50 20.13 0.2725
Third Quarter 22.38 20.75 0.2775
Fourth Quarter 23.38 21.25 0.2775
$1.1000
1995*
First Quarter $18.67 $17.17 $ .27$0.2666
Second Quarter 20.00 17.75 .270.2666
Third Quarter 21.33 19.08 .270.2725
Fourth Quarter 23.08 19.63 .27
$1.08
1994
First Quarter $21.50 $19.58 $ .26
Second Quarter 21.42 17.67 .26
Third Quarter 18.83 16.92 .26
Fourth Quarter 18.67 16.92 .27
$1.050.2725
$1.0782
_______________________
* Adjusted for October 1995 three-for-two common stock split.
As of December 31, 1995,1996, the Company's common stock was held by
approximately 13,900over 14,600 stockholders.
ITEM 6. SELECTED FINANCIAL DATA
Reference is made to Selected Financial Data on pages 48 and 49
of the Company's Annual Report which is incorporated herein by
reference.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
Overview
The following table (in millions of dollars) summarizes the
contribution to consolidated earnings by each of the Company's
businesses.
Years ended December 31,
Business 1996 1995 1994
1993
Electric $ 11.4 $ 12.0 $ 11.7
$ 12.6
Natural gas distribution 4.9 1.6 .3 1.2
Natural gas transmission 2.5 8.4 6.1 4.7
Construction materials and
mining 11.5 10.8 11.6 12.4
Oil and natural gas production 14.4 8.0 9.3 7.1
Earnings on common stock $ 44.7 $ 40.8 $ 39.0 $ 38.0
Earnings per common share $ 1.57 $ 1.43 $ 1.37 $ 1.34
Return on average common equity 13.0% 12.3% 12.1%
Earnings for 1996 increased $3.9 million from the comparable
period a year ago due primarily to higher oil and natural gas
production and prices at the oil and natural gas production
businesses. Increased retail sales at the electric and natural gas
distribution businesses, primarily the result of 14 percent colder
weather than the comparable period a year ago, also added to the
increase in earnings. Increased transportation of natural gas held
under the repurchase commitment and increased volumes transported
to storage, combined with the benefits of a favorable rate change
implemented in January 1996, at the natural gas transmission
business further improved earnings. In addition, earnings from
Baldwin and Hawaiian Cement, businesses acquired in April 1996, and
September 1995, respectively, contributed to the earnings increase.
The write-down to the then current market price of the natural gas
available under the repurchase commitment partially offset the
earnings increase. The write-down, which approximated $21.1
million, or $12.9 million after tax, was significantly offset by
the reversal of certain reserves for tax and other contingencies at
the natural gas transmission and oil and natural gas production
businesses, aggregating $7.4 million and $1.8 million after tax,
respectively. The net effect of these items resulted in a $3.7
million, or 13 cent per common share, net charge to earnings for
the 12 months
ended 12.3% 12.1% 12.3%
Earnings information presented in this table and inyear. Also somewhat offsetting the following discussion is beforeearnings improvement was
the $8.9 million ($5.5 million after
tax) cumulativenonrecurring effect of a 1993 accounting change. See Note 1favorable FERC order received in April
1995. The order allowed for the one-time billing of Notescustomers for
$2.2 million after tax, including interest, to Consolidated Financial Statements forrecover a further discussionportion of
this accounting change.the amount previously refunded in July 1994. In addition,
increased purchased power demand charges at the electric business
and increased operating costs at the electric, natural gas
transmission and oil and natural gas production businesses
partially offset the earnings improvement. Higher interest expense
at the construction materials and mining and oil and natural gas
production businesses also somewhat offset the earnings increase.
The effects of lower coal sales to the Big Stone Station due to the
expiration of the coal contract in August 1995 and the resulting
closure of the Gascoyne mine also partially offset the earnings
improvement.
Earnings for 1995 increased $1.8 million from the comparable
period a year ago. Increasedearlier due primarily to increased retail sales at
the electric business and increased throughput at the natural gas
distribution and natural gas transmission businesses, increasedbusinesses. Increased
oil prices and oil and natural gas production at the oil and
natural gas production business andcombined with the benefits derived
from favorable rate changes at the natural gas distribution and
transmission businesses also increased earnings. The favorable
rate change at the natural gas transmission business resulted from
athe previously described FERC order received in April 1995 on a
rehearing request relating to a 1989 general rate proceeding.
The order
allowed for the one-time billing to customers for approximately
$2.2 million (after tax) to recover a portion of the amount
previously refunded in July 1994. Income from a 50% percent
interest in Hawaiian Cement acquired in September 1995 also contributed to the earnings
increase. 1994 earnings included the benefit of a $4.5 million
gain (after tax) realized on the sale of an equity investment in
General Atlantic Resources, Inc. (GARI). Additionally, the effects
of decreased natural gas prices at the natural gas transmission and
oil and natural gas production businesses, lower coal sales to the
Big Stone Station due to the expiration of a coal contract in
August 1995, and the resulting
closure of the Gascoyne Mine, and increased costs associated with rainy West Coast
weather at the construction materials operations
partially offset the earnings increase.
Earnings for 1994 increased $1.0 million from 1993. The 1994
realization of an investment gain related to the sale of an equity
investment in GARI, which was $3.3 million (after tax) more than
a corresponding gain realized in 1993, increased earnings. In
addition, higher retail electric sales at the electric business,
favorable rate changes at the natural gas distribution and
transmission businesses, increased sales at the construction
materials operations due to the September 1993 acquisition of the
Oregon construction materials businesses and higher oil revenue due
to increased production at the oil and natural gas production
business contributed to the earnings increase. Increased electric
purchased power demand charges, increased operation and maintenance
expenses at the electric and natural gas distribution businesses,
lower throughput at the natural gas distribution and transmission
businesses, a seasonal first quarter loss experienced at the
Alaskan construction materials operations which was acquired in
April 1993, lower average oil prices at the oil and natural gas
production business, partially offset
the earnings increase.
________________________________
Reference should be made to Items 1 and 2 -- "Business and
Properties" and Notes to Consolidated Financial Statements for
information pertinent to various commitments and contingencies.
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 1993 and 1994 to conform to the 1995
presentation. Such reclassifications had no effect on net income
or common stockholders' investment as previously reported.
Montana-Dakota -- Electric Operations
Years ended December 31,
1996 1995 1994 1993
Operating revenues:
Retail sales $128.8 $ 124.4 $ 123.2 $ 119.7
Sales for resale and other 10.0 10.2 10.7
11.4138.8 134.6 133.9 131.1
Operating expenses:
Fuel and purchased power 44.0 41.8 43.2 41.3
Operation and maintenance 41.4 40.1 41.0 37.4
Depreciation, depletion and
amortization 17.1 16.3 15.5 15.3
Taxes, other than income 6.8 6.5 6.6
6.6109.3 104.7 106.3
100.6
Operating income 29.5 29.9 27.6 30.5
Retail sales (kWh) 2,067.9 1,993.7 1,955.1 1,893.7
Sales for resale (kWh) 374.6 408.0 444.5
511.0
CostAverage cost of fuel and
purchased power per kWh $ .017 $ .016 $ .017 $ .016
Montana-Dakota -- Natural Gas Distribution Operations
Years ended December 31,
1996 1995 1994 1993
Operating revenues:
Sales $151.5 $ 146.8 $ 151.7 $ 151.7
Transportation and other 3.5 3.7 3.6
4.3155.0 150.5 155.3 156.0
Operating expenses:
Purchased natural gas sold 102.7 102.6 111.3 114.0
Operation and maintenance 30.0 30.4 30.0 28.6
Depreciation, depletion and
amortization 6.9 6.7 6.1 5.1
Taxes, other than income 3.9 3.9 4.0
3.6143.5 143.6 151.4
151.3
Operating income 11.5 6.9 3.9 4.7
Volumes (dk):
Sales 38.3 33.9 31.8
31.2
Transportation 9.4 11.1 9.3
12.7
Total throughput 47.7 45.0 41.1 43.9
Degree days (% of normal) 116.2% 101.6% 96.7%
105.5%
CostAverage cost of natural gas,
including transportation,
per dk $ 2.67 $ 3.02 $ 3.50 $ 3.66
Williston Basin -- Natural Gas Transmission Operations
Years ended December 31,
1996 1995 1994
1993
Operating revenues:
Sales for resaleTransportation $ ---60.4* $ ---54.1* $ 51.3*
Transportation 54.1* 52.6*
30.8*
Storage 10.7 12.6 10.6 2.2
Natural gas production and
other 7.5 5.2 7.7
7.078.6 71.9 70.9
91.3
Operating expenses:
Purchased natural gas sold --- --- 20.6
Operation and maintenance 37.2* 35.7* 38.8* 39.0*
Depreciation, depletion and
amortization 6.7 7.0 6.6 7.1
Taxes, other than income 4.5 3.8 4.2
4.548.4 46.5 49.6
71.2
Operating income 30.2 25.4 21.3 20.1
Volumes (dk):
Sales for resale--
Montana-Dakota --- --- 13.0
Other --- --- .2
Transportation--
Montana-Dakota 43.4 35.4 33.0
18.5
Other 38.8 32.6 30.9
40.9
Total throughput82.2 68.0 63.9
72.6
Produced (Mdk) 6,073 4,981 4,732 3,876
* Includes amortization and
related recovery of deferred
natural gas contract buy-out/
buy-down and gas supply
realignment costs $ 10.6 $ 11.4 $ 12.8 $ 13.4
Knife River -- Construction Materials and Mining Operations
Years ended December 31,
1996** 1995** 1994 1993
Operating revenues:
Construction materials $ 99.5 $ 73.1 $ 71.0
$ 46.2
Coal 32.7 39.9 45.6
44.2132.2 113.0 116.6 90.4
Operating expenses:
Operation and maintenance 105.8 87.8 88.2 62.7
Depreciation, depletion and
amortization 7.0 6.2 6.4 5.6
Taxes, other than income 3.3 4.5 5.4
5.1116.1 98.5 100.0
73.4
Operating income 16.1 14.5 16.6 17.0
Sales (000's):
Aggregates (tons) 3,374 2,904 2,688
2,391
Asphalt (tons) 694 373 391 141
Ready-mixed concrete
(cubic yards) 340 307 315
157
Coal (tons) 2,899 4,218 5,206 5,066
** Does not include information related to Knife River's 50 percent ownership
interest in Hawaiian Cement which was acquired in September 1995 and is
accounted for under the equity method.
Fidelity Oil -- Oil and Natural Gas Production Operations
Years ended December 31,
1996 1995 1994 1993
Operating revenues:
Oil $ 39.0 $ 30.1 $ 20.9
$ 22.7
Natural gas 29.3 18.7 17.1
16.468.3 48.8 38.0 39.1
Operating expenses:
Operation and maintenance 15.6 13.7 12.0 11.6
Depreciation, depletion and
amortization 25.0 18.6 13.5 12.0
Taxes, other than income 3.5 2.6 3.7
3.744.1 34.9 29.2
27.3
Operating income 24.2 13.9 8.8 11.8
Production (000's):
Oil (barrels) 2,149 1,973 1,565 1,497
Natural gas (Mcf) 14,067 12,319 9,228 8,817
Average sales price:
Oil (per barrel) $17.91 $ 15.07 $ 13.14
$ 14.84
Natural gas (per Mcf) 2.09 1.51 1.84 1.86
Amounts presented in the above tables for natural gas operating
revenues, purchased natural gas sold and operation and maintenance
expenses will not agree with the Consolidated Statements of Income
due to the elimination of intercompany transactions between
Montana-Dakota's natural gas distribution business and Williston
Basin's natural gas transmission business. The amounts relating to
the elimination of intercompany transactions for natural gas
operating revenues, purchased natural gas sold and operation and
maintenance expenses were $58.2 million, $53.8 million and $4.4
million, respectively, for 1996, $54.6 million, $49.2 million and
$5.4 million, respectively, for 1995, and $65.2 million, $58.5
million and $6.7 million, respectively, for 1994,1994.
1996 compared to 1995
Montana-Dakota -- Electric Operations
Operating income at the electric business decreased primarily
due to increased fuel and $68.3purchased power costs, resulting
primarily from both higher purchased power demand charges and
increased net sales. The increase in demand charges, related to a
participation power contract, is the result of the pass-through of
periodic maintenance costs as well as the purchase of an additional
five megawatts of capacity beginning in May 1996, which brings the
total level of capacity available under this contract to 66
megawatts. Also contributing to the operating income decline were
higher operation expenses, primarily resulting from higher
transmission and payroll-related costs due to establishing certain
contingency reserves, and higher depreciation expense, due to an
increase in average depreciable plant. Increased revenues,
primarily higher retail sales due to increased weather-related
demand from residential and commercial customers in the first and
fourth quarters, largely offset the operating income decline.
Lower sales for resale volumes due to line capacity restrictions
within the regional power pool were more than offset by higher
average realized rates also partially offsetting the operating
revenue increase.
Earnings for the electric business decreased due to the
operating income decline, and decreased service and repair income
and lower investment income, both included in Other income -- net.
Montana-Dakota -- Natural Gas Distribution Operations
Operating income at the natural gas distribution business
improved largely as a result of increased sales revenue. The sales
revenue improvement resulted primarily from a 3.6 million $56.5decatherm
increase in volumes sold due to 14% colder weather and increased
sales resulting from the addition of over 3,600 customers. Also
contributing to the sales revenue improvement were the effects of
a general rate increase placed into effect in Montana in May 1996.
However, the pass-through of lower average natural gas costs
partially offset the sales revenue improvement. Decreased
operations expense due to lower payroll-related costs also added to
the operating income improvement. Lower transportation revenues,
primarily decreased volumes transported to large industrial
customers, somewhat offset the operating income improvement.
Industrial transportation declined due to lower volumes transported
to two agricultural processing facilities, one which closed in
September 1995, and one which experienced lower production, and to
a cement manufacturing facility due to its use of alternate fuel.
Natural gas distribution earnings increased due to the
operating income improvement, decreased interest expense and higher
service and repair income. The decline in interest expense
resulted from lower average long-term debt and natural gas costs
refundable through rate adjustment balances.
Williston Basin -- Natural Gas Transmission Operations
Operating income at the natural gas transmission business
increased primarily due to an improvement in transportation
revenues resulting from increased transportation of natural gas
held under the repurchase commitment, increased volumes transported
to storage and the reversal of certain reserves for regulatory
contingencies of $3.9 million ($2.4 million after tax). The
benefits derived from a favorable rate change implemented in
January 1996, also added to the revenue improvement. The
nonrecurring effect of a favorable FERC order received in April
1995, on a rehearing request relating to a 1989 general rate
proceeding partially offset the transportation revenue improvement.
The order allowed for the one-time billing of customers for
approximately $2.7 million ($1.7 million after tax) to recover a
portion of the amount previously refunded in July 1994. In
addition, reduced recovery of deferred natural gas contract buy-
out/buy-down and $11.8gas supply realignment costs partially offset the
increase in transportation revenue. An increase in natural gas
production revenue, due to both higher volumes and prices, also
contributed to the operating income improvement. Decreased storage
revenues, due primarily to the implementation of lower rates in
January 1996, partially offset the increase in operating income.
Operation expenses increased primarily due to higher payroll-
related costs and production royalties but were slightly offset by
reduced amortization of deferred natural gas contract buy-out/buy-
down costs.
Earnings for this business decreased due to the write-down to
the then current market price of the natural gas available under
the repurchase commitment. The effect of the write-down, which was
$21.1 million, respectively,or $12.9 million after tax, was significantly offset
by the reversal of certain income tax reserves aggregating $4.8
million. Decreased interest income, largely related to $583,000
(after tax) of interest on the previously discussed 1995 refund
recovery combined with higher company production refunds (both
included in Other income -- net), also added to the earnings
decline. Increased net interest expense ($366,000 after tax),
largely resulting from higher average reserved revenue balances
partially offset by decreased long-term debt expense due to lower
average borrowings, further reduced earnings. The earnings
decrease was somewhat offset by the increase in operating income.
Knife River -- Construction Materials and Mining Operations
Construction Materials Operations --
Construction materials operating income increased $3.3 million
due to higher revenues. The revenue improvement is largely due to
revenues realized as a result of the Baldwin and Medford
acquisitions. Revenues at most other construction materials
operations decreased as a result of lower aggregate and asphalt
sales due to lower demand, and lower construction sales due to the
nature of work being performed this year as compared to last year,
offset in part by increased building materials sales and aggregate
and ready-mixed concrete prices. Operation and maintenance
expenses increased due to the above acquisitions but were somewhat
offset by a reduction at other construction materials operations
resulting from lower volumes sold and less work involving the use
of subcontractors.
Coal Operations --
Operating income for 1993.coal operations decreased $1.7 million
primarily due to decreased revenues, largely the result of the
expiration of the coal contract with the Big Stone Station in
August 1995, and the resulting closure of the Gascoyne Mine.
Higher average sales prices due to price increases at the Beulah
Mine partially offset the decreased coal revenues. Decreased
operation and maintenance expenses, depreciation expense and taxes
other than income, largely due to the mine closure, partially
offset the decline in operating income.
Consolidated --
Earnings increased due to the increase in construction
materials operating income and income from Hawaiian Cement of $1.7
million as compared to $1.0 million in 1995(included in Other
income -- net). Higher interest expense ($1.4 million after tax),
resulting mainly from increased long-term debt due to the
acquisition of Hawaiian Cement, Baldwin and Medford, and the
decline in coal operating income somewhat offset the increase in
earnings.
Fidelity Oil -- Oil and Natural Gas Production Operations
Operating income for the oil and natural gas production
business increased primarily as a result of higher oil and natural
gas revenues. Higher oil revenue resulted from a $5.6 million
increase due to higher average prices and a $3.2 million increase
due to improved production. The increase in natural gas revenue
was due to a $7.0 million increase arising from higher prices and
a $3.6 million improvement resulting from higher production.
Increased operation and maintenance expenses, largely due to higher
production, and higher taxes other than income, primarily the
result of higher prices, both partially offset the operating income
improvement. Also reducing operating income was increased
depreciation, depletion and amortization expense resulting from
increased average rates and higher production. Depreciation,
depletion and amortization rates increased in part due to the
accrual of estimated future well abandonment costs ($515,000 after
tax).
Earnings for this business unit increased due to the operating
income improvement and lower income taxes due to the reversal of
certain tax reserves aggregating $1.8 million. Increased interest
expense ($815,000 after tax), resulting mainly from higher average
borrowings, and lower tax benefits somewhat offset the earnings
improvement.
1995 compared to 1994
Montana-Dakota -- Electric Operations
Operating income at the electric business increased primarily
due to higher retail sales revenues and lower fuel and purchased
power costs. Higher average usage by residential and commercial
customers, due to more normal weather, contributed to the revenue
improvement. Reduced demand by oil producers and refiners
contributed to a decline in industrial sales, which somewhat offset
the retail sales revenue improvement. Fuel and purchased power
costs decreased due to changes in generation mix between lower and
higher cost generating stations. This decrease was partially
offset by higher purchased power demand charges. The increase in
demand charges, related to a participation power contract, is the
result of the purchase of an additional five megawatts of capacity
beginning in May 1995, offset in part by the pass-through of
periodic maintenance chargescosts during 1994. Decreased maintenance
expenses at the Coyote Station, due to less scheduled downtime,
partially offset by increased turbine, generator and boiler
maintenance at the Heskett Station, also improved operating income.
Increased depreciation expense, due to higher average depreciable
plant, balances, and lower sales for resale due to a surplus of low-cost
hydroelectric energy available from the Western Area Power
Administration during August through November 1995 partially offset
the increase in operating income.
Earnings for the electric business improved due to the
operating income increase, partially offset by higher income taxes.
Montana-Dakota -- Natural Gas Distribution Operations
Operating income increased at the natural gas distribution
business due to the effect of $2.3 million in general rate
increases and improved sales. The sales improvement resulted from
the addition of over 5,100 customers and more normal weather than
a year ago.1994. The pass-through of lower average natural gas costs and the
effects of a Wyoming Supreme Court order granting recovery in 1994
of a prior refund made by Montana-Dakota and the
pass-through of lower average natural gas costs reduced revenues. The
effect of higher volumes transported were largely offset by lower
average transportation rates. Higher operation expenses, due
primarily to higher benefit-relatedpayroll-related costs somewhat offset by lower
sales expenses, partially offset the operating income improvement.
Increased depreciation expense, due to higher average depreciable
plant,
balances, also partially offset the increase in operating income.
Natural gas distribution earnings increased due to the
improvement in operating income. A decreased return recognizedrealized on
net storage gas inventory and deferred demand costs partially
offset the earnings increase. This return decline of approximately
$619,000 (after tax) results from decreases in the net book balance
on which the natural gas distribution business is allowed to earn
a return.
Williston Basin -- Natural Gas Transmission Operations
OperatingNatural gas transmission operating income increased primarily
due to an increase in transportation and storage revenues. The
transportation revenue increase resulted primarily from the
benefits of athe favorable FERC order received in April 1995 on a
rehearing request relating to a 1989 general rate proceeding. The order allowed for the one-time
billing to customers for approximately $2.7 million ($1.7 million
after tax) to recover a portion of the amountproceeding as
previously refunded
in July 1994.discussed. In addition, higher demand revenues
associated with the storage enhancement project completed in late
1994, and increased volumes transported to storage, somewhat offset
by decreased transportation of natural gas held under the
repurchase commitment and reduced recovery of deferred natural gas
contract litigation
settlementbuy-out/buy-down and gas supply realignment costs, required to be recovered, added
to the transportation revenue improvement. Lower operation and
maintenance expenses, primarily lower production royalty expenses
and reduced amortization of deferred natural gas contract litigation settlementbuy-
out/buy-down and gas supply realignment costs, required to be amortized, and lower taxes
other than income, largely lower production taxes, further
contributed to the increase in operating income. A decline in
natural gas production revenue, primarily due to a 54 cent per
decatherm decline in realized natural gas prices, somewhat reduced
by increased volumes produced, partially offset the increase in
operating income. Increased depreciation expense, resulting from
higher average depreciable plant,
balances, also somewhat reduced the
operating income improvement.
Earnings for this business improved due primarily to the
increase in operating income, higher interest income, lower company
production refunds (included in Other income--net)income -- net) and lower
interest expense. Higher interest income of $583,000 (after tax)
is related to the previously described refund recovery. The
decline in interest expense aggregating $623,000 (after tax) is
primarily due to long-term debt retirements and lower interest
rates. Increased carrying costs on the natural gas repurchase
commitment, due to higher average interest rates, partially offset
the earnings increase.
Knife River -- Construction Materials and Mining Operations
Construction Materials Operations --
Construction materials operating income declined $636,000
primarily due to higher operation expenses. Operation expenses
increased due primarily to additional work required to be
subcontracted, due to unusually wet weather, and increased sales
volumes. Increased revenues due to higher aggregate sales volumes,
increased cement sales volumes at higher prices, increased soil
remediation volumes, but at lower prices, higher ready-mixed concrete prices, but lower volumes, higher
construction and aggregate delivery revenues and increased steel
fabrication sales volumes, partially offset the operating income
decline. Lower asphalt sales, volumes due to increased competition, lower
ready-mixed concrete sales and lower average soil remediation
prices partially offset the revenue improvement.
Coal Operations --
Operating income for the coal operations decreased $1.5 million
primarily due to decreased coal revenues, primarily the result of
lower sales to the Big Stone Station due to the expiration of the
coal contract in August 1995 and the resulting closure of the
Gascoyne Mine. Decreased operation expenses, resulting primarily
from lower sales volumes and lower depreciation expense and lower
taxes other than income, both due primarily to the closure of the
Gascoyne Mine, partially offset the decline in operating income.
Consolidated --
Earnings decreased due to the decline in coal and construction
materials operating income and increased interest expense, due to
increased long-term debt borrowings. Income from athe 50 percent
interest in Hawaiian Cement acquired in September 1995 and gains
from the sale of equipment relating to the Gascoyne Mine closure,
partially offset the decline in earnings. These items are
reflected in Other income--net.income -- net.
Fidelity Oil -- Oil and Natural Gas Production Operations
Operating income for the oil and natural gas production
business increased primarily as a result of higher oil revenues,
$5.4 million of which was due to increased production, and $3.8
million of which stemmed from higher average oil prices. Also,
increased natural gas revenue, $5.7 million of which was due to
higher natural gas volumes produced partially offset by a $4.1
million revenue decrease resulting from lower natural gas prices,
contributed to the operating income improvement. Also adding to
operating income was decreased production taxes, stemming largely
from the timing of payments in 1995 as compared to 1994.
Operation expenses increased, as a result of higher production but
were somewhat offset by lower average production costs, partially
offsetting the operating income improvement. Also reducing
operating income was increased depreciation, depletion and
amortization expense largely due to higher production.
Earnings for this business declined due to the 1994 realization
of a $4.5 million gain (after tax) related to the sale of an equity
investment in GARI. The increase in operating income partially
offset the earnings decrease.
1994 comparedSafe Harbor for Forward-Looking Statements
The Company is including the following cautionary statement in
this Form 10-K to 1993
Montana-Dakota -- Electric Operationsmake applicable and to take advantage of the safe
harbor provisions of the Private Securities Litigation Reform Act
of 1995 for any forward-looking statements made by, or on behalf
of, the Company. Forward-looking statements include statements
concerning plans, objectives, goals, strategies, future events or
performance, and underlying assumptions (many of which are based,
in turn, upon further assumptions) and other statements which are
other than statements of historical facts. From time to time, the
Company may publish or otherwise make available forward-looking
statements of this nature. All such subsequent forward-looking
statements, whether written or oral and whether made by or on
behalf of the Company, are also expressly qualified by these
cautionary statements.
Forward-looking statements involve risks and uncertainties
which could cause actual results or outcomes to differ materially
from those expressed. The declineCompany's expectations, beliefs and
projections are expressed in good faith and are believed by the
Company to have a reasonable basis, including without limitation
management's examination of historical operating income reflects increased fueltrends, data
contained in the Company's records and other data available from
third parties, but there can be no assurance that the Company's
expectations, beliefs or projections will be achieved or
accomplished. Furthermore, any forward-looking statement speaks
only as of the date on which such statement is made, and the
Company undertakes no obligation to update any forward-looking
statement or statements to reflect events or circumstances that
occur after the date on which such statement is made or to reflect
the occurrence of unanticipated events. New factors emerge from
time to time, and it is not possible for management to predict all
of such factors, nor can it assess the impact of each such factor
on the Company's business or the extent to which any such factor,
or combination of factors, may cause actual results to differ
materially from those contained in any forward-looking statement.
Regulated Operations--
In addition to other factors and matters discussed elsewhere
herein, some important factors that could cause actual results or
outcomes for the Company and its regulated operations to differ
materially from those discussed in forward-looking statements
include prevailing governmental policies and regulatory actions
with respect to allowed rates of return, financings, or industry
and rate structures, weather conditions, acquisition and disposal
of assets or facilities, operation and construction of plant
facilities, recovery of purchased power and purchased powergas costs,
present or prospective generation, wholesale and operation expenses. Fuelretail competition
(including but not limited to electric retail wheeling and
purchased
power costs increased principally due to higher demand charges
associated with the pass-throughtransmission costs), availability of periodic maintenance costseconomic supplies of natural
gas, and the purchase of an additional five megawatts of firm capacity
related to a participation power contract. Operation expenses
increased primarily the result of higher payroll and benefit-
related costs, largely the accrual of SFAS No. 106 costs. In
addition, decreased sales for resale, the result of a delay in
water conservation efforts by hydroelectric generators, reduced
operating income. Increased retail sales to all major markets, the
result of increased demand due to more normal summer weather than
that experienced in 1993, partially offset the operating income
decline.
Earnings for the electric business decreased due to the
operating income decline and increased long-term debt interest,
resulting from lower interest received from Williston Basin due to
the retirement of intercompany debt, partially offset by the
retirement of $15.0 million of 5.8 percent medium-term notes on
April 1, 1994. Decreased income taxes somewhat offset the earnings
decline.
Montana-Dakota -- Natural Gas Distribution Operations
Operating income decreased at thepresent or prospective natural gas distribution business from the corresponding period in 1993 dueor
transmission competition (including but not limited to a 1.7 million
decatherm (MMdk) weather-related decline in salesprices of
alternate fuels and decreased
transportation volumes, primarily due to two oil refineries
bypassing Montana-Dakota's distribution facilities. In addition,
higher operation and maintenance expenses, primarily increased
payroll and benefit-related costs and increased distribution and
sales expenses due to the system expansion into north-central South
Dakota, and increased depreciation expense reduced operating
income. The benefits of general rate increases placed into effect
in late 1993 and during 1994 in North Dakota, South Dakota, Wyoming
and Montana and the addition of nearly 5,000 customers improved
operating income. Also contributing to operating income was a
Wyoming Supreme Court order granting recovery in 1994 of a prior
refund.
Gas distribution earnings decreased due to the operating income
decline and increased interest expense, primarily carrying costs
being accrued on natural gas costs refundable through rate
adjustments, higher financing costs related to increased capital
expenditures and the previously described intercompany debt
retirement. The return earned on the storage gas inventory
(included in Other income--net) somewhat mitigated the decline in
earnings.
Williston Basin -- Natural Gas Transmission Operations
The increase in operating income reflects a January 1994 rate
change due to a rate stipulation agreement with the FERC and the
realization of revenue related to 5.0 MMdk of natural gas
transported to storage. Prior to the implementation of Order 636,
these revenues were recognized during the winter months when gas
was withdrawn from storage whereas such revenues are now recognized
primarily in the summer months when gas is transported to storage.
Natural gas production revenues increased due to increased volumes
produced, partially offset by a 15 cent per decatherm decline in
realized natural gas prices. In addition, decreased operation and
maintenance expenses, depreciation and taxes other than income,
primarily due to the saledeliverability costs).
Non-regulated Operations--
Certain important factors which could cause actual results or
transfer of unneeded facilities,
further improved operating income. Decreased net throughput,
primarily to off-system markets and LDC end users, partially offset
the operating income increase. A 1993 out-of-period credit
adjustment to take-or-pay surcharge amortizations also partially
offset the improvement in operating income.
Earnings for this business increased due to the operating
income improvement, decreased long-term debt interest, the result
of debt refinancing and debt retirements in July 1993, and April
1994, respectively, and increased interest being accrued on gas
supply realignment transition costs (included in Other income--
net). Partially offsetting the earnings improvement were increased
carrying costs associated with the natural gas repurchase
commitment, due to higher average rates, and decreased investment
income, the result of lower investible funds stemming from a
regulatory refund made in mid-1994.
Knife River -- Construction Materials and Mining Operations
Construction Materials Operations --
Increased sales due to the September 1993 acquisition of the
Oregon construction materials businesses and improved cement,
asphalt and building materials sales at the Alaskan operations were
the primary contributors to the $461,000 increase in construction
materials operating income. Somewhat offsetting this improvement
were the effects of a seasonal first quarter loss experienced at
the Alaskan operations which was acquired in April 1993 and reduced
aggregate and ready-mixed concrete sales at these operations due to
fewer large commercial construction projects in the area than 1993.
Coal Operations --
Operating incomeoutcomes for the coalCompany and all or certain of its non-regulated
operations decreased $853,000
primarily due to increased operation expenses. Higher overburden
removal costs atdiffer materially from those discussed in forward-
looking statements include the Beulah Mine,level of governmental expenditures
on public projects and increased reclamation
expenses and costs associated with an early retirement program
stemmingproject schedules, changes in anticipated
tourism levels, competition from the closing of the Gascoyne Mine in mid-1995
increased operation expenses. An improvement in coal revenues,
primarily increased sales at the Gascoyne Mine, mainly the result
of increased demand by electric generation customers, and increased
selling prices at the Beulah Mine, partially offset the decline in
coal operating income.
Consolidated --
Earnings decreased due to the decline in coal operating income
and reduced investment income, primarily lower investible funds due
to the aforementioned acquisitions. The improvement in
construction materials operating income somewhat mitigated the
earnings decline.
Fidelity Oil -- Oil and Natural Gas Production Operations
Operating income for theother suppliers, oil and natural
gas production
business declined as a result of lowercommodity prices, drilling successes in oil revenues, $2.7 million
of which was due to lower average oil prices partially offset by a
$1.0 million increase resulting from higher production. A volume-
related increase in operation expenses and depreciation, depletion
and amortization also contributed to the decline in operating
income. A natural gas revenue improvement, $764,000 of which was
due to higher natural gas production, partially offset the decline
in operating income.
Earnings for this business improved due to the realization of
an investment gain related to the sale of an equity investment in
GARI, which was $3.3 million (after tax) more than a corresponding
gain realized in 1993. The decline in operating income partially
offset the earnings increase.
Prospective Information
Each of the Company's businesses is subject to competition,
varying in both type and degree. See Items 1 and 2 for a further
discussion of the effects these competitive forces have on each of
the Company's businesses.
The operating results of the Company's electric, natural gas
distribution, natural gas transmission, and construction materials
and mining businesses are, in varying degrees, influenced by the
weather as well as by the general economic conditions within their
respective market areas. Additionally, the ability to recover
costs through the regulatory process affects the operating results
of the Company's electric, natural gas distribution and natural gas
transmission businesses.
Knife River continuesoperations, ability to seek additionalacquire oil and natural gas properties, and
the availability of economic expansion or development
opportunities.
Factors Common to Regulated and Non-Regulated Operations--
The business and profitability of the Company are also
influenced by economic and geographic factors, including political
and economic risks, changes in and compliance with environmental
and safety laws and policies, weather conditions, population growth
opportunities.
These includerates and demographic patterns, market demand for energy from
plants or facilities, changes in tax rates or policies,
unanticipated project delays or changes in project costs,
unanticipated changes in operating expenses or capital
expenditures, labor negotiations or disputes, changes in credit
ratings or capital market conditions, inflation rates, inability of
the acquisitionvarious counterparties to meet their obligations with respect
to the Company's financial instruments, changes in accounting
principles and/or the application of other surface mining properties,
particularly those relatingsuch principles to sandthe
Company, changes in technology and gravel aggregates and
related products such as ready-mixed concrete, asphalt and various
finished aggregate products. See Items 1 and 2 under Knife River
for a discussionlegal proceedings.
New Accounting Standard
In October 1996, the American Institute of an acquisition made during 1995.
In March 1995, the Financial Accounting Standards BoardCertified Public
Accountants issued Statement of Financial Accounting Standards No. 121, "AccountingPosition 96-1, "Environmental
Remediation Liabilities" (SOP 96-1). SOP 96-1 provides
authoritative guidance for the Impairmentrecognition, measurement, display
and disclosure of Long-Lived Assets and for Long-Lived Assets
to Be Disposed Of" (SFAS No. 121). SFAS No. 121 imposes stricter
criteria for assets, including regulatory assets, by requiring that
such assets be probable of future recovery at each balance sheet
date.environmental remediation liabilities in
financial statements. The Company will adopt SFAS No. 121SOP 96-1 on
January 1, 1996,1997, and the adoption willis not expected to have a
material affecteffect on the Company's financial position or results of
operations.
This conclusion may
change in the future depending on the extent to which recovery of
the Company's long-lived assets is influenced by an increasingly
competitive environment in the electric and natural gas industries.
Liquidity and Capital Commitments
The Company's construction costs and additional investments in
construction materials and mining, and oil and natural gas
activitiesnet capital expenditures (in millions of dollars)
for 19931994 through 19951996 and as anticipated for 19961997 through 19981999 are
summarized in the following table, which also includes the
Company's capital needs for the retirement of maturing long-term
securities.
Actual Estimated
1993
1994 1995 Company/Description 1996 Capital Expenditures-- 1997 1998 1999
Montana-Dakota:
$ 16.2 $ 14.2 $ 19.7$19.7 $18.7 Electric $ 18.3 $ 16.8 $ 17.7
15.0$17.0 $17.8 $20.1
13.2 8.9 6.3 Natural Gas Distribution 7.7 7.8 8.0
31.29.5 8.1 8.1
27.4 28.6 26.0 24.6 25.7
5.425.0 26.5 25.9 28.2
14.4 9.7 10.1 Williston Basin* 12.6 13.3 29.3
3.6 36.8 25.0 Knife River 35.4 13.9 11.1
38.6 39.9 51.8 Fidelity 55.0 55.0 60.0
1.0 2.6 .8 Prairielands * * *
85.0 117.6 112.7 129.5 108.1 128.6
Net proceeds from sale or
(3.6) (2.8) (11.8) disposition of property (5.5) (4.4) (4.3)
81.4 114.8 100.9 Net capital expenditures 124.0 103.7 124.3
Retirement of Long-term
Debt/Preferred Stock--
28.3 10.4 35.4 Montana-Dakota 11.4 6.4 6.4
7.5 10.0 7.5 Williston Basin 11.6 12.8 19.9
43.1 3.6 36.8 Knife River 6.7 7.8 7.8
24.9 38.6 39.9.5 .4 .5
--- --- --- Fidelity 40.0 45.0 50.0
1.0 1.0 2.6--- 7.7 8.3
--- .1 .5 Prairielands 3.3 1.2 2.6
105.6 85.0 117.6 87.6 91.4 106.0
Retirement of Long-Term
3.2* * *
35.8 20.5 Debt/Preferred Stock 17.1 16.6 11.4
$108.8 $120.8 $138.143.4 11.9 14.5 15.2
$117.2 $135.3 $144.3 Total $104.7 $108.0 $117.4$135.9 $118.2 $139.5
* Effective January 1, 1997, information related to Prairielands is
included with Williston Basin.
In reconciling constructionnet capital expenditures to investing activities
per the Consolidated Statements of Cash Flows, the constructionnet capital
expenditures for Prairielands, which is not considered a major
business segment, are not reflected in investing activities in the
Consolidated Statements of Cash Flows for 1993, 1994, 1995 and 1995.1996. In
addition, the 1994 capital expenditures for Montana-
Dakota'sMontana-Dakota's
natural gas distribution business are reflected net of $5.8 million
of storage gas purchased from Williston Basin while the 1993 and 1994
Williston Basin amounts areamount is reflected in the table above net of the
sale of storage gas of $1.7 million and $8.3 million, respectively.million.
In 1995 the Company's regulated businesses operated by Montana-
Dakota and Williston Basin1996 Montana-Dakota provided all of the funds needed for construction purposes. The Company's 1995its
net capital needs to retire
maturing long-termexpenditures and securities were $20.5 million.
It is anticipated thatretirements, excluding the
$25 million discussed below, from internal sources. Montana-Dakota
will continueexpects to provide all of the funds required for its construction requirementsnet capital
expenditures and securities retirements for the years 19961997 through
19981999 from internal sources, through the use of its $30 million
revolving credit and term loan agreement, $21.5$30 million of which was
outstanding at December 31, 1995,1996, and through the issuance of long-termlong-
term debt, the amount and timing of which will depend upon the
Company's needs, internal cash generation and market conditions.
In June 1996, the Company redeemed $25 million of its 9 1/8% Series
first mortgage bonds, due May 15, 2006. The funds required to
retire the 9 1/8% Series first mortgage bonds were provided by
Williston Basin's repayment of $27.5 million of intercompany debt
payable to the Company.
Williston Basin's 1996 net capital expenditures and securities
retirements were met through internally generated funds and the
issuance of long-term debt as discussed below. Williston Basin
expects to meet its construction requirements
and financing needsnet capital expenditures for the years 19961997
through 19981999 with a combination of internally generated funds,
short-term lines of credit aggregating $35$40.4 million, none$2 million of
which iswas outstanding at December 31, 1995,1996, and through the
issuance of long-term debt, the amount and timing of which will
depend upon Williston Basin's needs, internal cash generation and
market conditions. On April 1,
1994,In May 1996, Williston Basin borrowed $25privately placed
$20 million under a term loan
agreement,of notes with the proceeds and cash on hand used to
repay the $27.5 million of intercompany debt payable to the
Company. In addition, in November 1996, Williston Basin privately
placed $15 million of notes with the proceeds used solely for the purpose of
refinancing purchase money mortgages payable to the Company. At
December 31, 1995, $7.5 million is available and outstanding under
the term loan agreement.replace other
maturing long-term debt.
Knife River's 19951996 net capital needs,expenditures including the
acquisitionacquisitions of a 50 percent interest in Hawaiian Cement,Baldwin and Medford, were met through funds on
hand, funds generated from internal sources, short-term lines of
credit and a long-term revolving credit agreement. It is anticipated that
funds generated from internal sources, short-term lines of credit
aggregating $6$11 million, none of which was outstanding at December
31, 1995, and1996, a long-term revolving credit agreement of $40$55 million, $25$47 million
of which was outstanding at December 31, 1995,1996, and the issuance of
long-term debt and the Company's equity securities will continue to meet the
needs of this business unit for 1997 through 1999. In April 1996,
through 1998, excluding funds which may be required
for future acquisitions. It is anticipated that funds required for
future acquisitions will be met primarily throughamounts available under the issuancerevolving credit agreement were
increased from $40 million to $55 million. Also in April 1996,
amounts available under the short-term lines of a combination of long-term debtcredit were
increased from $6 million to $8 million and equity securities.in August 1996, were
further increased from $8 to $11 million.
Fidelity Oil's 19951996 net capital needsexpenditures related to its oil
and natural gas acquisition, development and exploration program
were met through funds generated from internal sources and long-term
lineslong-
term credit facilities. Fidelity's borrowing base, based on proven
and producing reserves, is currently $65 million, which consists of
$23 million of issued notes, $7 million in an uncommitted note
shelf facility, and a $35 million revolving line of credit, aggregating $25 million, $2$14.8
million of which was outstanding at December 31, 1995.1996. In April
1996, the borrowing base was increased from $55 million to $65
million and concurrently the amount available under the revolving
line of credit was increased from $25 million to $35 million. It
is anticipated that Fidelity's 19961997 through 19981999 net capital
needsexpenditures and debt retirements will be met from internal sources
and itsexisting long-term lines of credit.
See Note 13 of Notes to Consolidated Financial Statements for
a discussion of notices of proposed deficiency 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' 1995 capital needs were met through funds
generated internally and short-term lines of credit aggregating
$5.4 million, $600,000 of which was outstanding at December 31,
1995. It is anticipated that Prairielands' 1996 through 1998
capital needs will be met from internal sources and its short-term
lines of credit.facilities.
The Company utilizes its short-term lines of credit aggregating
$40 million, $2 million of which was outstanding on December 31,
1996, and its $30 million revolving credit and term loan agreement,
all of which is outstanding at December 31, 1996, to meet its
short-term financing needs and to take advantage of market
conditions when timing the placement of long-
termlong-term or permanent
financing. There were no borrowings outstanding
at December 31, 1995, under the short-term lines of credit.
The Company's issuance of first mortgage debt is subject to
certain restrictions imposed under the terms and conditions of its
Indenture of Mortgage. Generally, those restrictions require the
Company to pledge $1.43 of unfunded property to the Trustee for
each dollar of indebtedness incurred under the Indenture and that
annual earnings (pretax and before interest charges), as defined in
the Indenture, equal at least two times its annualized first
mortgage bond interest costs. Under the more restrictive of the
two tests, as of December 31, 1995,1996, the Company could have issued
approximately $200$247 million of additional first mortgage bonds.
The Company's coverage of fixed charges including preferred
dividends was 3.02.7 and 2.93.0 times for 19951996 and 1994,1995, respectively.
Additionally, the Company's first mortgage bond interest coverage
was 5.4 times in 1996 compared to 3.9 times in 1995 compared to 3.3 times in 1994. Stockholders'
equity1995. Common
stockholders' investment as a percent of total capitalization was
57%54% and 58%57% at December 31, 19951996 and 1994,1995, 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 23 through 47 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 1 through 5 and 1318 and 1419 of the
Company's Proxy Statement dated March 4, 19963, 1997 (Proxy Statement)
which is incorporated herein by reference.
ITEM 11. EXECUTIVE COMPENSATION
Reference is made to Pages 613 through 1318 of the Proxy
Statement.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT
Reference is made to Page 1419 of the Proxy Statement.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
None.
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON
FORM 8-K
(a) Financial Statements, Financial Statement Schedules and
Exhibits.
Index to Financial Statements and Financial Statement
Schedules.
Page
1. Financial Statements:
Report of Independent Public Accountants *
Consolidated Statements of Income for each
of the three years in the period ended
December 31, 19951996 *
Consolidated Balance Sheets at December 31,
1996, 1995 1994 and 19931994 *
Consolidated Statements of Capitalization at
December 31, 1996, 1995 1994 and 19931994 *
Consolidated Statements of Cash Flows for
each of the three years in the period ended
December 31, 19951996 *
Notes to Consolidated Financial Statements *
2. Financial Statement Schedules (Schedules 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 19951996 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 19951996 is not to be
deemed filed as part of this report.
3. Exhibits:
3(a) Composite Certificate of Incorporation of
MDU Resources Group, Inc.,the Company, as amended to date, filed as
Exhibit 3(a) to Form 10-K for the year
ended December 31, 1994, in File No. 1-3480 *
3(b) By-laws of MDU Resources Group, Inc.,the Company, as amended to date filed as Exhibit 3(b)
to Form 10-K for the year ended
December 31, 1994, in File No. 1-3480 ***
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,4(b) Rights Agreement, dated as of
November 3, 1988, between the Company
and Norwest Bank Minnesota, N.A.,
Rights Agent, filed as Exhibit 10(a)4(c)
in Registration No. 33-66682 *
+ 10(a) Executive Incentive Compensation Plan **
+ 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, as
amended to date filed as Exhibit 10(d)
to Form 10-K for the year ended
December 31, 1994, in File No. 1-3480 ***
+ 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 *
+ 10(g) Non-Employee Director Stock Compensation
Plan, **filed as Exhibit 10(g) to Form 10-K
for the year ended December 31, 1995, in
File No. 1-3480 *
12 Computation of Ratio of Earnings to Fixed
Charges **
13 Selected financial data, financial
statements and supplementary data as
contained in the Annual Report to
Stockholders for 19951996 **
21 Subsidiaries of MDU Resources Group, Inc. **
23(a) Consent of Independent Public Accountants **
23(b) Consent of Engineer **
23(c) Consent of Engineer **
27 Financial Data Schedule **
____________________
* 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.
(b) Reports on Form 8-K.
Form 8-K was filed on December 12, 1995. Under Item 5--Other
Events, it was reported that on November 27, 1995, a suit was
filed in District Court, County of Burleigh, State of North
Dakota by Minnkota Power Cooperative, Inc., Otter Tail Power
Company, Northwestern Public Service Company, and Northern
Municipal Power Agency, the owners of an aggregate interest of
75 percent of the Coyote electrical generating station,
against the Company (an owner of a 25 percent interest in the
Coyote Station) and Knife River.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrant has duly caused this report to be signed
on its behalf by the undersigned, thereunto duly authorized.
MDU RESOURCES GROUP, INC.
Date: February 28, 19961997 By: /s/ Harold J. Mellen, Jr.
Harold J. Mellen, Jr. (President
and Chief Executive Officer)
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
registrant in the capacities and on the date indicated.
Signature Title Date
/s/ Harold J. Mellen, Jr. Chief Executive February 28, 19961997
Harold J. Mellen, Jr. Officer
(President and Chief Executive Officer) and Director
/s/ Douglas C. Kane Chief Operating February 28, 19961997
Douglas C. Kane (Executive Vice President Officer and
and Chief Operating Officer) Director
/s/ Warren L. Robinson Chief Financial February 28, 19961997
Warren L. Robinson (Vice President, Officer
Treasurer and Chief Financial Officer)
/s/ Vernon A. Raile Chief Accounting February 28, 19961997
Vernon A. Raile (Vice President, Officer
Controller and Chief Accounting Officer)
/s/ John A. Schuchart Director February 28, 19961997
John A. Schuchart (Chairman of the Board)
/s/ San W. Orr, Jr. Director February 28, 1997
San W. Orr, Jr. (Vice Chairman of the Board)
/s/ Thomas Everist Director February 28, 19961997
Thomas Everist
/s/ Richard L. Muus Director February 28, 19961997
Richard L. Muus
/s/ Robert L. Nance Director February 28, 19961997
Robert L. Nance
/s/ John L. Olson Director February 28, 19961997
John L. Olson
/s/ San W. Orr, Jr. Director February 28, 1996
San W. Orr, Jr.
/s/ Charles L. Scofield Director February 28, 1996
Charles L. Scofield
/s/ Homer A. Scott, Jr. Director February 28, 19961997
Homer A. Scott, Jr.
/s/ Joseph T. Simmons Director February 28, 19961997
Joseph T. Simmons
/s/ Stanley F. Staples, Jr. Director February 28, 1996
Stanley F. Staples, Jr.
/s/ Sister Thomas Welder Director February 28, 19961997
Sister Thomas Welder
EXHIBIT INDEX
Exhibit No.
3(a) Composite Certificate of Incorporation
of MDU Resources Group, Inc., as amended
to date, filed as Exhibit 3(a) to
Form 10-K for the year ended
December 31, 1994, in File No. 1-3480 *
3(b) By-laws of MDU Resources Group, Inc.,
as amended to date, filed as Exhibit 3(b)
to Form 10-K for the year ended
December 31, 1994, in File No. 1-3480 *
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, as
amended to date, filed as Exhibit 10(d)
to Form 10-K for the year ended
December 31, 1994, in File No. 1-3480 *
+ 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 *
+ 10(g) Non-Employee Director Stock Compensation
Plan **
12 Computation of Ratio of Earnings to Fixed
Charges **
13 Selected financial data, financial
statements and supplementary data as
contained in the Annual Report to
Stockholders for 1995 **
21 Subsidiaries of MDU Resources Group, Inc. **
23(a) Consent of Independent Public Accountants **
23(b) Consent of Engineer **
23(c) Consent of Engineer **
27 Financial Data Schedule **
* 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.