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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549-1004

FORM 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934

FOR THE FISCAL YEAR ENDED DECEMBER 31, 1998 COMMISSION FILE NUMBER 1-13916

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UNION PACIFIC RESOURCES GROUP INC.
(Exact name of registrant as specified in its charter)

UTAH 13-2647483
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)

777 MAIN STREET 76102
FORT WORTH, TEXAS (Zip Code)
(Address of principal executive offices)

Registrant's telephone number, including area code: (817) 321-6000

Securities registered pursuant to Section 12(b) of the Act:

NAME OF EACH EXCHANGE
TITLE OF EACH CLASS ON WHICH REGISTERED
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Common Stock New York Stock Exchange, Inc.

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Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes [X] No [ ]

Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of 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]

As of February 28, 1999, the aggregate market value of the registrant's
common stock held by non-affiliates (using the New York Stock Exchange closing
price) was approximately $2.2 billion.

The number of shares outstanding of the registrant's common stock as of
February 28, 1999 was 252,150,993.

Certain portions of the registrant's definitive Proxy Statement for the
annual meeting of shareholders to be held on May 18, 1999 (the "Proxy
Statement") are incorporated in Part III by reference.
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TABLE OF CONTENTS

PART I
Item 1. Business.................................................... 1
Item 2. Properties.................................................. 10
Item 3. Legal Proceedings........................................... 12
Item 4. Submission of Matters to a Vote of Security Holders......... 13

PART II
Item 5. Market for the Registrant's Common Equity and Related
Stockholder Matters......................................... 14
Item 6. Selected Financial Data..................................... 15
Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations................................... 16
Item 7A. Risk Management............................................. 28
Item 8. Financial Statements and Supplementary Data................. 36
Item 9. Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure.................................... 80

PART III
Item 10. Directors and Executive Officers of the Registrant.......... 81
Item 11. Executive Compensation...................................... 81
Item 12. Security Ownership of Certain Beneficial Owners and
Management.................................................. 81
Item 13. Certain Relationships and Related Transactions.............. 81

PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports on Form
8-K......................................................... 81
Signatures............................................................ 87

Quantities of natural gas are expressed in this report in terms of thousand
cubic feet ("Mcf"), million cubic feet ("MMcf") or billion cubic feet ("Bcf").
Oil and natural gas liquids are quantified in terms of barrels ("Bbl"),
thousands of barrels ("MBbl") or millions of barrels ("MMBbl"). Oil and natural
gas liquids are compared to natural gas in terms of thousands of cubic feet of
natural gas equivalent ("Mcfe"), millions of cubic feet of natural gas
equivalent ("MMcfe"), billions of cubic feet of natural gas equivalent ("Bcfe")
or trillions of cubic feet of natural gas equivalent ("Tcfe"). One barrel of oil
or natural gas liquids is the energy equivalent of six Mcf of natural gas. Daily
oil and gas production is signified by the addition of the letter "d" to the end
of the terms defined above. Natural gas volumes also may be expressed in terms
of one million British thermal units ("MMBtu"), which is approximately equal to
one Mcf. With respect to information relating to working interests in wells or
acreage, "net" oil and gas wells or acreage is determined by multiplying gross
wells or acreage by the working interest owned therein. Unless otherwise
specified, all references to wells and acres are gross.

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PART I

ITEM 1. BUSINESS

GENERAL

Union Pacific Resources Group Inc. (a Utah corporation) and subsidiaries
(collectively, the "Company" or "UPR"), is engaged primarily in the exploration
for and the development and production of natural gas, natural gas liquids
("NGLs") and crude oil in several major producing basins in the United States,
Canada, Guatemala, Venezuela and other international areas. In addition, the
Company engages in the hard minerals business through nonoperated joint venture
and royalty interests in several coal and trona (natural soda ash) mines located
on lands within and adjacent to its Land Grant holdings in Wyoming. The Land
Grant consists of land that passes through the states of Colorado and Wyoming
and into Utah, which was granted by the federal government to a predecessor of
the Company in the mid-1800s. In the Land Grant, the Company has fee ownership
of the mineral rights under approximately 7.9 million acres. At December 31,
1998, over 79 percent of the revenues, 49 percent of fixed assets and 57 percent
of reserves of the Company are generated or located in the United States.

In 1998, the Company acquired Norcen Energy Resources Limited ("Norcen")
for a purchase price of $2.634 billion, and also assumed long-term debt
obligations of Norcen totaling approximately $1 billion. Norcen was a major
Canadian oil and gas exploration and production company with primary operations
in western Canada, the Gulf of Mexico, Guatemala and Venezuela. The acquisition
significantly increased the Company's drill site inventory and expanded the
Company's operations beyond its historical domestic focus. See additional
discussion in Note 2 to the Consolidated Financial Statements.

In 1998, the Company's Board of Directors authorized management to proceed
with a deleveraging program, including the sale of approximately $600 million of
producing properties, and to pursue potential monetization of the Company's
gathering, processing and marketing ("GPM") business segment. In November 1998,
the Company executed a merger and purchase agreement to sell the GPM segment to
Duke Energy Field Services, Inc. ("Duke") for $1.35 billion, with the sale
expected to close in the first quarter of 1999. See "Deleveraging
Program -- Property Sales," "Significant Events and Corporate Reorganization --
Property Sales and GPM Divestiture" and Note 3 to the Consolidated Financial
Statements for additional discussion.

BUSINESS STRATEGY

In each of its core areas, the Company continues to focus on the
exploration for and development of natural gas and crude oil resources, in
combination with efforts to increase margins through reductions in drilling and
operating costs. The Company's long-term strategy is to increase production by
expanding its drill site inventory and enhancing well results through the
application of economies of scale, its operating experience in its core
geographic areas and its expertise in advanced drilling and completion
technologies. The Company keeps its drilling inventory high to supply its
drilling operations, striving to maintain a three-year inventory of drill sites
in its core areas through development of its existing properties, exploration,
farm-in agreements and acquisitions of properties and companies. However, in the
current depressed price environment, the Company is holding its exploration
drilling inventory for the future. The Company maintains a high working interest
in its core areas and typically serves as operator, which allows it to control
the timing and cost of exploration and development activities and to enhance its
ability to apply its expertise to these properties.

In 1999, the Company anticipates spending approximately $500 million in
capital and exploratory expenditures, with a focus on high-return, quick-payout
projects. Approximately 20 percent of the capital will be directed to each of
the following areas: Canada, the Austin Chalk trend in Texas and Louisiana,
other U.S. Onshore, U.S. Offshore and Latin America. As a result of reduced
capital spending, the Company may not increase production in 1999. See "Outlook
and Other Matters."

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EXPLORATION AND PRODUCTION OPERATIONS

In the first quarter of 1999, the Company announced the reorganization of
its exploration and production operations into four primary business units: the
U.S. Offshore business unit and the Canada business unit, both unchanged from
the previous structure, the Latin America business unit, comprised of Guatemala,
Venezuela and other international operations, and the U.S. Onshore business
unit, which will consist of the consolidation of all other domestic business
units under the previous structure. As this reorganization is not yet fully in
place, the following discussion will address the structure of the Company's
exploration and production operations in place during 1998.

During 1998, the Company's oil and gas activities were concentrated in five
core geographic areas in the United States and four core areas for international
operations. The core areas in the United States were comprised of the following
business units: (1) the Austin Chalk trend in Texas and Louisiana, (2) East/West
Texas, (3) the Western Region, consisting of the Land Grant area in Colorado,
Wyoming and Utah, as well as additional properties in Kansas, (4) Gulf Coast
Onshore, covering the onshore coastal plain of Texas and Louisiana, and (5)
Offshore, which covers the Company's Gulf of Mexico operations. International
core areas were (1) Canada, (2) Guatemala, (3) Venezuela and (4) Other
International.

The following table sets forth 1998 capital spending excluding the Norcen
Acquisition (hereinafter defined), proved reserves as of December 31, 1998, and
1998 production information with respect to each of the Company's business
units. Natural gas constituted 56% of the Company's total proved reserves of 6.1
Tcfe as of December 31, 1998, and 58% of the Company's sales volumes of 2.467
Bcfed for the year then ended. Production from properties sold in 1998 is
included in producing property volumes for each business unit through the
effective date of each sale. See "Deleveraging Program -- Property Sales" for
additional information.

TOTAL TOTAL PRODUCING
CAPITAL PERCENT PROVED PERCENT PROPERTY PERCENT
SPENDING OF RESERVES OF VOLUMES OF
BUSINESS UNIT (MILLIONS) TOTAL (BCFE) TOTAL (MMCFED) TOTAL
- ------------- ---------- ------- -------- ------- --------- -------

Austin Chalk........................... $ 380 33% 708 11% 581 24%
East/West Texas........................ 104 9 969 16 308 13
Western Region......................... 69 6 1,322 22 500 20
Gulf Coast Onshore..................... 114 10 109 2 121 5
Offshore............................... 154 13 358 6 182 7
------ --- ----- --- ----- ---
Total USA.................... 821 71 3,466 57 1,692 69
Canada................................. 198 17 1,731 28 519 21
Guatemala.............................. 40 3 357 6 125 5
Venezuela.............................. 100 9 480 8 100 4
Other International.................... 3 -- 90 1 31 1
------ --- ----- --- ----- ---
Total........................ $1,162 100% 6,124 100% 2,467 100%
====== === ===== === ===== ===

United States Operations

Austin Chalk Business Unit. The Austin Chalk business unit manages the
Company's oil and gas activities in the Austin Chalk trend, which extends 700
miles from southern Texas through central and eastern Texas into Louisiana. At
present, the Company's Austin Chalk production is located primarily in three
fields: Giddings, Brookeland and Masters Creek. The Masters Creek field in
Louisiana and the Giddings field in Texas are currently the most active. Since
1988, the Company has participated in the drilling of over 1,500 wells and has
made aggregate capital expenditures over $2.4 billion in the Austin Chalk,
including spending of $380 million in 1998. The Company controls nearly 1.9
million developed and undeveloped net acres in the Austin Chalk and has
increased its volumes from 37 MMcfed in January 1990 to an average of 581 MMcfed
during 1998. During 1998, 90 percent of the Austin Chalk business unit's
production was attributable to Company-operated properties.

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East/West Texas Business Unit. The East/West Texas business unit manages
the Company's oil and gas activities in two major northeastern Texas producing
areas, the Carthage and Oakhill fields, as well as the Company's oil and gas
activities in western Texas, principally in the Ozona field in the Permian Basin
area. In East Texas, in addition to its production operations, the Company has
conducted exploration activities in the Cotton Valley Pinnacle Reef Trend where
3-D seismic has identified over 100 drilling prospects. In West Texas, the
Company has drilled over 980 wells in the Ozona area which is characterized by
long-lived natural gas wells that typically produce for 30 or more years. In
addition, the Company has applied its horizontal expertise in the West Texas
area and drilled 67 horizontal wells. During 1998, the Company directed $104
million of capital into the East/West Texas business unit, and recognized a 5
percent improvement in production volumes, to 308 MMcfed. At December 31, 1998,
approximately 90 percent of the producing wells in the East/West Texas business
unit were Company operated and 84 percent of the 1998 production was
attributable to Company-operated properties.

Western Region Business Unit. The Western Region business unit manages the
Company's oil and gas activities in the Land Grant area in Colorado, Wyoming and
Utah, and the Hugoton/Panoma field in Kansas. This business unit is the second
largest in terms of reserves, and ranked third in production volumes in 1998,
while absorbing only $69 million (6%) of consolidated capital expenditures. The
Company's operations in the Western Region are concentrated in the Green River
Basin and the Overthrust area. The Company currently controls approximately 8.9
million developed and undeveloped net acres in the Western Region, principally
attributable to its Land Grant ownership. Production volumes from the Western
Region business unit were 500 MMcfed in 1998, with 29 percent of the production
attributable to Company-operated properties.

Gulf Coast Onshore Business Unit. The Gulf Coast Onshore business unit
manages the Company's operations on the onshore coastal plain of Texas and
Louisiana. In 1998, production volumes improved 30 percent to 121 MMcfed. In
addition to its producing activities, this business unit conducts exploration
activities in these areas, and is evaluating 3-D seismic to identify the areas
of highest drilling potential. The Company has also formed an alliance with
another major oil and gas company to evaluate a large geographic acreage
position in southwestern Louisiana. During 1998, the Company spent $114 million
of capital in the Gulf Coast Onshore business unit, and 80 percent of production
volume was attributable to Company-operated properties.

Offshore Business Unit. The Offshore business unit manages the Company's
oil and gas activities in the Gulf of Mexico, including operations added in the
Norcen Acquisition in 1998. During 1997, the Company drilled a successful
deepwater well in Mississippi Canyon Block 755 in the Gulf of Mexico which
resulted in the discovery of significant reserves. The Company has and will
continue to delineate the discovery during 1998 and 1999, with first production
anticipated in 2002. In 1998, the Company spent $154 million of capital in the
Offshore business unit, both related to the Mississippi Canyon discovery and to
further develop other prospects, including those acquired as part of Norcen.
Production volumes of 182 MMcfed during 1998 represent a 94 percent improvement
over 1997, with 74 percent of the production attributable to Company-operated
properties.

International Operations

Canada. The Company's Canadian operations principally include properties
from the Norcen Acquisition, which were combined with the Company's previous
interests in western Canada to form a new business unit. Operations in ten core
areas are centered in the province of Alberta, with additional properties in
northeastern British Columbia and southwestern Saskatchewan. Canada currently
represents the Company's largest business unit in terms of reserve base, and was
second in production volumes (519 MMcfed) and in capital spending ($198 million)
in 1998. Canada provides a balanced commodity mix of 46 percent crude oil and
NGLs and 54 percent natural gas, as well as an asset portfolio with long reserve
life. Approximately 40 percent of Canadian oil production is heavy oil. In
Canada, UPR has working interests in approximately 5,500 gross producing wells,
and operates about 4,200 of these.

Guatemala. The Company's Guatemalan operations are comprised of the former
Basic Resources International that was also acquired as part of Norcen. The
majority of activity is currently from the Xan area,

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producing heavy to medium quality crude oil. The Company also owns a 100 percent
working interest in several exploration blocks and is focusing on an aggressive
seismic acquisition strategy to evaluate exploration and development
opportunities. Capital spending in 1998 in Guatemala was $40 million, with daily
production volumes of 125 MMcfed. The Company owns, controls and operates
infrastructure in Guatemala which includes gathering and processing facilities
at each producing field, an asphalt refinery, 285 miles of pipeline with seven
pump stations and a 420 MBbl capacity shipping terminal on the Caribbean coast.
The combination of these assets provides the Company with an integrated network
of facilities from producing fields to the port.

Venezuela. The Company's Venezuelan operations consist of the
Oritupano-Leona block, the West Guarico farm-in agreement and the Delta Centro
exploration block. The Oritupano-Leona block, in which UPR has a 45 percent
working interest, covers 433,000 acres and has approximately 200 producing
wells. Most of the activity in the block has been driven by a 3-D seismic
program conducted in prior years. The West Guarico block covers over 800,000
acres and is operated by the Company, which has a 50 percent working interest.
The project is in the beginning stages of redevelopment, focusing on seismic,
drilling, recompletions and the improvement of infrastructure. The Company has a
35 percent working interest in Delta Centro, where the block covers 500,000
acres. No wells have yet been drilled, and the primary activity has been seismic
evaluation to identify future drilling opportunities. During 1998, the Company
spent $100 million of capital in Venezuela, producing average volumes of 100
MMcfed.

Other International. Other international operations include interests in
six fields in Argentina, two non-operated platforms in Australia and an interest
in a non-operated property in Egypt. In addition, the Company is trying to
strengthen its presence in Brazil.

VOLUMES, PRICES AND PRODUCTION COSTS

The following table sets forth certain information regarding the Company's
volumes and average price realizations for natural gas, NGL and crude oil sales,
and average production costs per Mcfe for each of the last three years.

YEARS ENDED DECEMBER 31,
------------------------------
1998 1997 1996
-------- -------- --------

PRODUCING PROPERTIES:
Average daily production:
Natural gas (MMcfd).................................. 1,441.1 1,108.5 988.9
Natural gas liquids (MBbld).......................... 33.1 31.7 30.5
Crude oil (MBbld).................................... 137.9 52.9 50.6
Total (MMcfed)............................... 2,467.0 1,615.7 1,475.3
Average sales prices:
Natural gas (per Mcf)................................ $ 1.74 $ 2.00 $ 1.85
Natural gas liquids (per Bbl)........................ 7.88 11.23 11.48
Crude oil (per Bbl).................................. 10.48 18.36 18.84
Production costs (per Mcfe)(a)......................... 0.49 0.51 0.49

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(a) Includes lease operating costs, production overhead, other operating
expenses and taxes other than income taxes.

MINERALS

The Minerals business unit contributes significantly to the Company's
operating income by exploiting the hard minerals portion of the Company's
extensive fee mineral interests in the Land Grant through non-operated joint
venture and royalty arrangements in coal and trona (natural soda ash) mines. In
general, the

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Company reinvests the cash flow from its hard minerals operations into its oil
and gas business units. The Minerals business unit generated $133.5 million of
operating income during 1998, as follows:

1998 OPERATING
INCOME
---------------------
AMOUNT PERCENT
-------- ---------
(MILLIONS OF DOLLARS)

Royalties:
Soda ash(a)............................................... $ 31.8 24%
Coal(b)................................................... 15.5 12
------ ---
Total royalties................................... 47.3 36
------ ---
Nonoperated joint ventures:
Soda ash(c)............................................... 3.7 3
Coal(d)................................................... 86.0 64
------ ---
Total joint ventures.............................. 89.7 67
Overhead/other.............................................. (3.5) (3)
------ ---
Total operating income............................ $133.5 100%
====== ===

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(a) Includes properties leased to five soda ash producers, estimated to contain
resources sufficient to support over 30 years of production at current
production levels.

(b) The Company leases coal resources to six operating mines. In 1998, 60
percent of the Company's coal royalties were attributable to a single mine
which supplies an adjacent power station that is owned and operated by
affiliates of the mine owners.

(d) Represents the Company's 50 percent non-operating interest in Black Butte
Coal Company ("Black Butte"). In 1998, $79.3 million of operating income is
attributable to a single coal supply contract, which terminates at the end
of 2000. See "Management's Discussion and Analysis of Financial Condition
and Results of Operations" and Note 8 to the Consolidated Financial
Statements.

The Company's low sulfur coal deposits compete with other western coals for
industrial and utility boiler markets. At current coal pricing and extraction
cost levels, however, most of this resource is not economic to extract except
for sale to local markets. As a result, there are limited opportunities for new
coal mine development in the Land Grant.

The world's largest deposit of trona, constituting 90 percent of the
world's known trona resources, is located in the Green River Basin in
southwestern Wyoming. Approximately 40 percent of this trona deposit lies within
the Land Grant and is therefore owned by the Company. Natural soda ash, which is
produced by refining trona ore, is used primarily in the production of glass for
containers and flat glass, in the paper and water treatment industries and in
the manufacture of certain chemicals and detergents. Natural soda ash from
Wyoming contributes 32 percent of the world soda ash supply with the remainder
principally from synthetic processes. In 1998, the Company, along with its
partner, Oriental Chemical Industries, Inc. ("OCI"), completed process
improvement projects and construction of additional refining capacity at the OCI
Wyoming LP soda ash facility that increased the plant's nameplate capacity to
3.1 million tons per year. This facility is now ranked second in soda ash
capacity among domestic producers.

COMPETITION

The oil and gas industry is highly competitive. The Company actively
competes for reserve acquisitions and for exploration leases, licenses and
concessions and skilled industry personnel, frequently against companies with
substantially larger financial and other resources. The Company's competitors
include major integrated oil and gas companies and numerous other independent
oil and gas companies and individual producers and operators. In 1998, some
consolidation within the industry occurred, as companies combined their
strengths and financial resources to improve overall stability during the
current period of low oil and gas prices. To the extent the Company's capital
budget is lower than that of certain of its competitors, the Company may be
disadvantaged in effectively competing for certain reserves, leases, licenses
and concessions. Competitive factors include price, contract terms, and types
and quality of service.

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GOVERNMENT REGULATION

The Company's natural gas, NGL and crude oil exploration, development and
production operations are subject to extensive rules and regulations promulgated
by federal, provincial, state and local authorities and foreign governmental
entities.

Numerous federal, state and local departments and agencies have issued
rules and regulations binding on the oil and gas industry and its individual
members, some of which carry substantial penalties for noncompliance. State
statutes and regulations require permits for drilling operations, drilling bonds
and reports concerning operations. Most states in which the Company operates
also have statutes and regulations governing conservation and safety matters,
including the unitization or pooling of oil and gas properties, the
establishment of maximum rates of production from oil and gas wells and the
spacing of such wells. Such statutes and regulations may limit the rate at which
oil and gas otherwise could be produced from the Company's properties. The
regulatory burden on the oil and gas industry increases its cost of doing
business and, consequently, affects its profitability.

A substantial portion of the Company's oil and gas leases in the Gulf of
Mexico and a portion of its onshore leases were granted by the United States
Government and are administered by two agencies within the Department of the
Interior: the Bureau of Land Management ("BLM") and the Minerals Management
Service ("MMS"). Such leases are issued through competitive bidding, contain
relatively standardized terms and require compliance with detailed BLM and MMS
regulations and orders. Certain operations on such leases must be conducted
pursuant to appropriate permits issued by the BLM and the MMS in addition to
permits required from other agencies (such as the Coast Guard, Army Corps of
Engineers and Environmental Protection Agency). The MMS also administers bonding
requirements and has the right to require lessees to post supplemental bonds if
it deems that additional security is necessary to cover royalties due or the
costs of regulatory compliance.

Under certain extraordinary circumstances, the federal agencies have the
power to suspend or terminate Company operations on federal leases. Any such
suspension or termination could materially and adversely affect the Company's
financial condition and operations. In 1998, the MMS adopted financial
responsibility regulations under the Oil Pollution Act of 1990. See
"Environmental Regulation -- Oil Spills."

Currently, there are no federal, state or local laws that regulate the
price for sales of natural gas, NGLs and crude oil by the Company. However, the
rates charged and terms and conditions for the movement of gas in interstate
commerce through certain intrastate pipelines and production area hubs are
subject to regulation under the Natural Gas Policy Act of 1978 ("NGPA").
Pipeline and hub construction activities are, to a limited extent, also subject
to regulation under the Natural Gas Act of 1938 ("NGA"). The NGA also
establishes comprehensive controls over interstate pipelines, including the
transportation and resale of gas in interstate commerce. While these NGA
controls do not apply directly to the Company, their effect on natural gas
markets can be significant in terms of competition and cost of transportation
services. The Federal Energy Regulatory Commission ("FERC") administers the NGA
and the NGPA.

Through a series of orders, most recently the Order No. 636 Series, FERC
has taken significant steps to increase competition in the sale, purchase,
storage and transportation of natural gas. FERC's regulatory programs generally
allow more accurate and timely price signals from the consumer to the producer.
Nonetheless, the ability to respond to market forces can and does add to price
volatility, inter-fuel competition and pressure on the value of transportation
and other services.

Through many interstate pipeline specific orders, FERC has revised its
policy regarding jurisdiction over gathering facilities and services. FERC no
longer asserts jurisdiction over these facilities and services and has stated
that it is a matter to be left to the states for regulation. In 1996, the
District of Columbia Court of Appeals largely upheld FERC's policy. As a result
of the court's decision, the Texas Railroad Commission conducted inquiries
regarding the scope of its regulation of gathering facilities and services. The
Company owns and operates extensive gathering systems in Texas. In 1996, the
Railroad Commission initiated a rulemaking and ultimately issued new regulations
regarding gathering activities. Although the new regulations increased the
regulatory burden to a limited extent, the regulations are not expected to have
a significant

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impact on the Company's gathering activity. It is also possible that other
states where the Company owns gathering facilities will become more active in
the regulation of gathering activities.

As a seller of natural gas to end users, the Company also can be affected
by state regulation of local distribution activities. While the extent of such
state regulation varies, a number of states where the Company markets its
natural gas are taking steps similar to steps taken by FERC to increase gas
competition. As these programs take hold, direct access to local markets should
increase, together with competitive pressures on prices and the value of
distribution services.

Additional proposals and proceedings that might affect the natural gas
industry are considered from time to time by Congress, FERC, state regulatory
bodies and the courts. Several proposals that might affect the natural gas
industry are pending before Congress and FERC. The Company cannot predict when
or if any such proposals might become effective and their effect, if any, on the
Company's operations. Historically, the natural gas industry has been heavily
regulated; therefore, there is no assurance that the less stringent regulatory
approach recently pursued by FERC, Congress and the states will continue
indefinitely into the future.

The oil and gas industry in Canada is subject to extensive controls and
regulations imposed by various levels of government. Oil and gas exported from
Canada is subject to regulation by the National Energy Board ("NEB") and the
government of Canada. Exporters are free to negotiate prices and other terms
with purchasers, provided that the export contracts meet certain criteria
prescribed by the NEB and the government of Canada. Exports may be made pursuant
to export contracts with terms not exceeding one year in the case of light crude
oil and not exceeding two years in the case of heavy crude oil and natural gas,
provided that an order approving any such export has been obtained from the NEB.
Any export to be made pursuant to a contract of longer duration requires an NEB
license and Governor in Council approval. The governments of Alberta, British
Columbia and Saskatchewan also regulate the volume of natural gas that may be
removed from these provinces for consumption elsewhere based on such factors as
reserve availability, transportation arrangements and market considerations. In
addition, each province has legislation and regulations which govern land
tenure, royalties, production rates, environmental protection and other matters.
It is not expected that any of these controls or regulations will affect the
operations of the Company in a manner materially different than they would
affect other oil and gas companies of similar size.

The Company's minerals operations are subject to a variety of federal and
state regulations with respect to safety, land use and reclamation. In addition,
the Department of the Interior regulates the leasing of federal lands for coal
development as provided in the Mineral Lands Leasing Act of 1920.

SECTION 29 TAX CREDITS

Federal tax law provides an income tax credit against regular federal
income tax liabilities with respect to sales of the Company's production of
certain fuels produced from nonconventional sources (including both coal seam
natural gas and natural gas produced from tight sand formations), subject to a
number of limitations ("Section 29 tax credits"). Fuels qualifying for the tax
credit must be produced from a well drilled or a facility placed in service
after December 31, 1979, and before January 1, 1993, and be sold before January
1, 2003.

The basic credit, which currently is approximately $0.52 per MMBtu of
natural gas produced from tight sand reservoirs, is computed by reference to the
price of crude oil and is phased out as the price of oil exceeds certain
specified levels. The commencement of phaseout would be triggered if the average
price for crude oil rose above approximately $45 per barrel in current dollars.
The natural gas production from wells drilled on certain of the Company's
properties in the Moxa Arch and Wamsutter areas in Wyoming, the Carthage field
in eastern Texas, the Ozona field in western Texas and certain areas in the
Austin Chalk trend qualifies for this tax credit. The Company recorded
approximately $16.4 million of Section 29 tax credits in 1998. Section 29 tax
credits are not creditable against the alternative minimum tax but under certain
circumstances may be carried over and applied against regular tax liabilities in
future years. Therefore, no assurance can be given that the Company's Section 29
tax credits will reduce its federal income tax liability in any particular year.

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TEXAS SEVERANCE TAX REDUCTION

Natural gas produced from wells that have been certified as deep wells or
geologic formations certified as tight formations by the Texas Railroad
Commission ("high cost wells") and that were spudded or completed during the
period from May 24, 1989, to September 1, 1996, qualifies for an exemption from
the 7.5 percent severance tax in Texas on natural gas and NGLs produced by such
wells. Such exception ends August 31, 2001. The natural gas production from
wells drilled on certain of the Company's properties, primarily in the Austin
Chalk and East/West Texas business units, qualifies for this tax reduction. In
addition, high cost wells that are spudded or completed during the period from
September 1, 1996, to August 31, 2002, are entitled to receive a severance tax
reduction. Operators have until the later of 180 days after first production or
the 45th day of approval by the Texas Railroad Commission to obtain a high cost
gas certification without incurring a 10 percent tax penalty. The tax reduction
is based on a formula composed of the statewide "median" as determined by the
State of Texas based on actual drilling and completion costs reported by
producers. More expensive wells will receive a greater amount of tax reduction.
This tax rate reduction remains in effect for ten years or until the aggregate
tax reductions received equal 50 percent of the total drilling and completion
costs.

ENVIRONMENTAL REGULATION

The Company's operations are subject to extensive federal, state, local,
provincial and international environmental laws and regulations governing the
protection of the environment. The Company is in compliance, in all material
respects, with applicable environmental requirements. Although future
environmental obligations are not expected to have a material impact on the
results of operations or financial condition of the Company, there can be no
assurance that future developments, such as increasingly stringent environmental
laws or enforcement thereof, will not cause the Company to incur material
environmental liabilities or costs.

Air Emissions. The primary legislation affecting the Company's air
emissions is the Federal Clean Air Act and its 1990 Amendments (the "CAA").
Among other things, the CAA requires all major sources of air emissions to
obtain operating permits. The amendments also revised the definition of a "major
source" such that additional equipment involved in oil and gas production are
now covered by the permitting requirements.

Hazardous Substances and Waste Disposal. The Company currently owns or
leases numerous properties that have been used for many years for hard minerals
production or natural gas and crude oil production. Although the Company has
utilized operating and disposal practices that were standard in the industry at
the time, hydrocarbons or other wastes may have been disposed of or released on
or under the properties owned or leased by the Company. In addition, some of
these properties have been operated by third parties over whom the Company had
no control. The Comprehensive Environmental Response, Compensation and Liability
Act ("CERCLA") and comparable state statutes impose strict, joint and several
liability on owners and operators of sites and on persons who disposed of or
arranged for the disposal of "hazardous substances" found at such sites. The
Federal Resource Conservation and Recovery Act ("RCRA") and comparable state
statutes govern the disposal of "solid wastes" and "hazardous wastes." Although
CERCLA currently excludes petroleum from its definition of hazardous substance,
many state laws affecting the Company's operations impose clean-up liability
regarding petroleum and petroleum-related products. In addition, although RCRA
classifies certain oil field wastes as "nonhazardous," such exploration and
production wastes could be reclassified as hazardous wastes thereby making such
wastes subject to more stringent handling and disposal requirements. If such a
change in legislation were to be enacted, it could have a significant impact on
the Company's operating costs, as well as the oil and gas industry in general.
See "Other Matters -- Environmental Costs."

Oil Spills. Under the Oil Pollution Act of 1990 ("OPA"), owners and
operators of onshore facilities and pipelines and lessees or permittees of an
area in which an offshore facility is located ("Responsible Parties") are
strictly liable on a joint and several basis for removal costs and damages that
result from a discharge of oil into United States waters. OPA limits the strict
liability of Responsible Parties for removal costs and damages that result from
a discharge of oil from $10 million to $150 million in the case of onshore
facilities and from $35 million to $150 million plus removal costs in the case
of offshore facilities, except that these limits do not

8
11

apply if the discharge was caused by gross negligence or willful misconduct, or
by the violation of an applicable federal safety, construction or operating
regulation by the Responsible Party, its agent or subcontractor.

In addition, OPA requires certain vessels and offshore facilities to
provide evidence of financial responsibility in the amount of $150 million. The
MMS, which has jurisdiction over certain offshore facilities and pipelines,
issued a final rule in August 1998 implementing OPA requirements. OPA also
requires offshore facilities and certain onshore facilities to prepare facility
response plans, which the Company has done, for responding to a "worst case
discharge" of oil. Failure to comply with these requirements or failure to
cooperate during a spill event may subject a Responsible Party to civil or
criminal enforcement actions and penalties.

Offshore Production. Offshore oil and gas operations are subject to
regulations of the United States Department of the Interior which currently
impose strict liability upon the lessee under a federal lease for the cost of
clean-up of pollution resulting from the lessee's operations, and such lessee
could be subject to possible liability for pollution damages. In the event of a
serious incident of pollution, the Department of the Interior may require a
lessee under federal leases to suspend or cease operations in the affected
areas.

Canadian Environmental Regulation. The oil and gas industry in Canada
currently is subject to environmental regulation pursuant to provincial and
federal legislation. Environmental legislation provides for restrictions and
prohibitions on releases or emissions of various substances produced or utilized
in association with certain oil and gas industry operations. In addition,
legislation requires that well and facility sites be abandoned and reclaimed to
the satisfaction of provincial authorities. A breach of such legislation may
result in the imposition of fines and penalties. In Alberta, environmental
compliance has been governed by the Alberta Environmental Protection and
Enhancement Act ("AEPEA") since September 1, 1993. In addition to replacing a
variety of older statutes which related to environmental matters, AEPEA also
imposes certain new environmental responsibilities on oil and natural gas
operators in Alberta and, in certain instances, imposes greater penalties for
violations. In British Columbia, regulations affecting the oil and gas industry
are administered by the Ministry of Energy, Mines and Petroleum Resources.

EMPLOYEES

The Company had 2,900 employees as of December 31, 1998, 75 of which were
not full-time. Included were approximately 450 employees of the Company's GPM
segment, which is to be sold to Duke at the end of the first quarter of 1999.

Also included in the December 31, 1998 employee level above were
approximately 140 employees who were terminated by January 31, 1999, in
connection with a reduction in force announced in December 1998. In February
1999, the Company announced a second program for a reduction in force, with the
program expected to be complete by the end of the first quarter of 1999. This
program includes a voluntary retirement incentive program as well as a second
reduction in force. Approximately 250 employees will be affected, and in
connection with the program, the Company will take a pretax charge to income,
the amount of which will be determined late in the first quarter of 1999.

OTHER BUSINESS MATTERS

The Company's operations are subject to the usual hazards incident to the
drilling and operation of oil and gas wells, and the processing and
transportation of natural gas and NGLs, such as cratering, explosions,
uncontrollable flows of oil, gas or well fluids, fire, pollution and other
environmental risks. In general, many of these risks increase when drilling at
greater depths under higher pressure conditions. In addition, certain of the
Company's operations are offshore and subject to the additional hazards of
marine operations, such as capsizing, collision and damage or loss from severe
weather. Other operations involve the production, handling, processing and
transportation of gas containing hydrogen sulfide and other hazardous
substances. These hazards can cause personal injury and loss of life, severe
damage to and destruction of property and equipment, environmental damage and
suspension of operations. Litigation arising from a catastrophic occurrence in
the future at one of the Company's locations could result in the Company being
named as a defendant in lawsuits asserting potentially large claims. In
accordance with customary industry practices, insurance is maintained for the
Company against some, but not all, of the consequences of these risks. Losses
9
12

and liabilities arising from such events could reduce revenues and increase
costs to the Company to the extent not covered by insurance or otherwise already
reserved.

ITEM 2. PROPERTIES

PROVED RESERVES

The following table sets forth the proved developed and undeveloped
reserves of natural gas, NGLs and crude oil of the Company as of December 31,
1998. In connection with the Norcen Acquisition in the first quarter of 1998,
the Company used four independent firms to review Norcen estimates of
essentially all of the reserves to be acquired by the Company. Reserve estimates
as of December 31, 1998, were prepared by the Company's engineers and utilized
information from these independent reviews. Information set forth in the table
is based on reserve estimates of the Company, prepared in accordance with the
rules and regulations of the Securities and Exchange Commission ("SEC").

RESERVES AS OF DECEMBER 31, 1998
--------------------------------------
NATURAL
NATURAL GAS
GAS LIQUIDS CRUDE OIL TOTAL
CATEGORY (BCF) (MMBBL) (MMBBL) (BCFE)
- -------- ------- ------- --------- ------

Proved developed............................... 2,968 79 252 4,956
Proved undeveloped............................. 471 12 104 1,168
----- ------ ------ -----
Total proved reserves................ 3,439 91 356 6,124
===== ====== ====== =====
Percent of total..................... 56% 9% 35% 100%

There are numerous uncertainties inherent in estimating quantities of
proved reserves, including many factors beyond the control of the Company. The
reserve data set forth herein represent estimates only. Reservoir engineering is
a subjective process of estimating underground accumulations of crude oil and
natural gas that cannot be measured in an exact manner, and the accuracy of any
reserve estimate is a function of the quality of available data and of
engineering and geological interpretation and judgment.

ACREAGE

Land Grant and Other Fee Minerals. The following table summarizes the fee
mineral acreage by business unit owned by the Company as of December 31, 1998.
The Company holds royalty interests of varying percentages in the approximately
one million gross acres of the Land Grant that are subject to exploration and
production agreements with third parties. The Company's fee mineral acreage is
primarily undeveloped.

TOTAL ACRES
--------------
BUSINESS UNIT GROSS NET
- ------------- ----- -----
(IN THOUSANDS)

Austin Chalk................................................ 33 13
East/West Texas............................................. 746 260
Western Region.............................................. 8,570 8,161
Gulf Coast Onshore.......................................... 221 74
Offshore.................................................... -- --
----- -----
Total USA......................................... 9,570 8,508
Canada...................................................... -- --
Guatemala................................................... -- --
Venezuela................................................... -- --
Other International......................................... -- --
----- -----
Total fee acreage................................. 9,570 8,508
===== =====
Land Grant (included in Western Region above)............... 7,912 7,722
===== =====

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13

Leasehold. The Company's leasehold acreage by business unit as of December
31, 1998, is set forth below.

DEVELOPED ACRES UNDEVELOPED ACRES TOTAL ACRES
--------------- ------------------ ---------------
BUSINESS UNIT GROSS NET GROSS NET GROSS NET
- ------------- ------ ------ -------- ------- ------ ------
(IN THOUSANDS)

Austin Chalk........................ 1,095 813 1,325 1,048 2,420 1,861
East/West Texas..................... 477 265 713 489 1,190 754
Western Region...................... 450 208 1,013 550 1,463 758
Gulf Coast Onshore.................. 154 71 160 70 314 141
Offshore............................ 284 136 418 312 702 448
----- ----- ------ ----- ------ ------
Total USA................. 2,460 1,493 3,629 2,469 6,089 3,962
Canada.............................. 1,657 958 5,613 2,185 7,270 3,143
Guatemala........................... 26 25 1,834 1,788 1,860 1,813
Venezuela........................... 57 25 1,710 758 1,767 783
Other International................. 465 85 2,227 648 2,692 733
----- ----- ------ ----- ------ ------
Total leasehold acreage... 4,665 2,586 15,013 7,848 19,678 10,434
===== ===== ====== ===== ====== ======

Total Leasehold and Fee Mineral. The total leasehold and fee mineral
acreage by business unit as of December 31, 1998, is set forth below.

TOTAL ACRES
---------------
BUSINESS UNIT GROSS NET
- ------------- ------ ------
(IN THOUSANDS)

Austin Chalk................................................ 2,453 1,874
East/West Texas............................................. 1,936 1,014
Western Region.............................................. 10,033 8,919
Gulf Coast Onshore.......................................... 535 215
Offshore.................................................... 702 448
------ ------
Total USA......................................... 15,659 12,470
Canada...................................................... 7,270 3,143
Guatemala................................................... 1,860 1,813
Venezuela................................................... 1,767 783
Other International......................................... 2,692 733
------ ------
Total leasehold and fee acreage................... 29,248 18,942
====== ======

DRILLING ACTIVITY AND PRODUCING WELL SUMMARY

The table below summarizes the Company's drilling activity over the last
three years.

YEARS ENDED DECEMBER 31,
---------------------------------------------
1998 1997 1996
------------- ------------- -------------
GROSS NET GROSS NET GROSS NET
----- ----- ----- ----- ----- -----

Development wells:
Productive...................................... 511 357.8 685 478.6 575 413.4
Dry............................................. 39 27.2 59 46.2 35 25.7
Exploration wells:
Productive...................................... 64 46.1 35 19.1 16 8.5
Dry............................................. 22 18.0 38 22.1 29 18.2
--- ----- --- ----- --- -----
Total wells............................. 636 449.1 817 566.0 655 465.8
=== ===== === ===== === =====

The number of wells drilled is not a valid measure or indicator of the
relative success or value of a drilling program because the significance of the
reserves and their economic potential may vary widely for each
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project. As of December 31, 1998, the Company owned a working interest in 9,504
gross gas wells (7,323 net) and 4,446 gross oil wells (3,160 net). Gross wells
include 2,404 wells with multiple completions. The Company operated 66 percent
of the gross wells in which it owned an interest.

DELEVERAGING PROGRAM -- PROPERTY SALES

SALES PRICE
PROPERTY SALE PACKAGE BUSINESS UNIT (MILLIONS)
- --------------------- ------------------ -----------

DJ Basin.............................................. Western Region $ 41
Matagorda Island Blocks............................... Offshore 158
Rockies Package....................................... Western Region 46
Eugene Island Blocks.................................. Offshore 8
Canadian Package...................................... Canada 145
Caroline -- Swan Hill(a).............................. Canada 108
South Texas Package(a)................................ Gulf Coast Onshore 138
Superior Propane...................................... Canada 48
----
Total....................................... $692
====

- ---------------

(a) Sale closed in January 1999.

ITEM 3. LEGAL PROCEEDINGS

MINERAL RESERVATION LITIGATION

In August 1994, the surface owners (McCormick, et al.) of portions of five
sections of Colorado land that are subject to mineral reservations made by the
Company's predecessor in title brought suit against the Company in State
District Court, Weld County, Colorado, to quiet title to minerals, including
crude oil (in some of the lands) and natural gas. On June 23, 1997, the State
District Court granted the Company's motion for summary judgment, holding as a
matter of law that the mineral reservations at issue were unambiguous and
included all valuable nonsurface substances, including oil and gas. The Colorado
Court of Appeals affirmed the decision of the State District Court in granting
the Company's motion for summary judgment on December 10, 1998. The surface
owners filed a motion for rehearing, which is pending.

ROYALTY LITIGATION

The Company is a defendant in a number of lawsuits in which plaintiffs
allege that the Company underpaid their royalties on crude oil and natural gas
production. In addition, certain of such suits allege that the Company has
violated antitrust laws and other similar laws. None of this litigation
articulates a theory of recovery or specific amounts of damages. This litigation
against the Company and others in the oil and gas industry suggests that more
suits of this type will be filed against the Company, including, perhaps, suits
by other types of interest owners and suits in other jurisdictions. The Company
intends to defend vigorously against such litigation, as well as any similar
lawsuits subsequently brought against the Company. In the opinion of management
of the Company, the outcome of these matters should not have a material adverse
effect on the consolidated results of operations, financial condition or cash
flows of the Company.

GENERAL

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injury claims and environmental claims. While management of the Company cannot
predict the outcome of such litigation and other proceedings, management does
not expect these matters to have a material adverse effect on consolidated
results of operations, financial condition or cash flows of the Company.

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

There were no matters submitted to a vote of security holders during the
quarter ended December 31, 1998.

EXECUTIVE OFFICERS OF THE REGISTRANT

NAME POSITION AGE
---- -------- ---

Jack L. Messman(a)............ Chairman and Chief Executive Officer 59
George Lindahl III(b)......... President and Chief Operating Officer 52
V. Richard Eales(c)........... Executive Vice President 63
Thomas R. Blank(d)............ Vice President -- State, Regulatory and Public 46
Affairs
Anne M. Franklin(e)........... Vice President -- People 42
Joseph A. LaSala, Jr.(f)...... Vice President, General Counsel and Secretary 44
Donald W. Niemiec(g).......... Vice President -- Marketing 52
Morris B. Smith(h)............ Vice President and Chief Financial Officer 54
John B. Vering(i)............. Vice President -- Canada 49

- ---------------
(a) Mr. Messman has been Chairman and Chief Executive Officer of the Company
since October 1996. He was President and Chief Executive Officer of the
Company from August 1995 to October 1996, and has been a Director of the
Company during the past five years. He was President, Chief Executive
Officer and a Director of Union Pacific Resources Company ("UPRC") through
October 1995.

(b) Mr. Lindahl has held his current position with the Company since October
1996. He was Executive Vice President -- Operations of the Company from
August 1995 to October 1996. Prior thereto, he was Vice
President -- Operations for UPRC.

(c) Mr. Eales has held his current position with the Company since June 1996.
From August 1995 to June 1996, he was Executive Vice President and Chief
Financial Officer of the Company. Prior thereto, he was Vice
President -- Corporate Development of UPRC.

(d) Mr. Blank has held his current position with the Company since August 1997.
He was Communications Director for the Speaker of the House of
Representatives for the United States from February 1997 to August 1997.
Prior thereto, he was President of Hager Sharp, Inc.

(e) Ms. Franklin has held her current position with the Company since August
1995. Prior thereto, she was Director of Executive Leadership and
Development for Ameritech, Inc.

(f) Mr. LaSala has held his current position as Vice President, General Counsel
with the Company since January 1996 and assumed the role of Secretary in
June 1997. Mr. LaSala joined UPRC as Assistant General Counsel in January
1995. Prior thereto, he was Vice President -- Government and Regulatory
Affairs of USPCI, Inc., a former subsidiary of Union Pacific Corporation
("UPC").

(g) Mr. Niemiec has held his current position with the Company since August
1995. He has been Vice President -- Marketing of UPRC since 1993 and
President of Union Pacific Fuels, Inc. ("UP Fuels") since 1990.

(h) Mr. Smith has held his current position with the Company since June 1996.
From September 1995 until June 1996, he was Vice President and Controller
of UPC. From January through August 1995, he served as Vice
President -- Finance of Union Pacific Railroad Company. Prior thereto, he
served as Vice President -- Finance of USPCI, Inc.

(i) Mr. Vering has held his current position with the Company since March 1998.
From October 1996 until March 1998 he was Vice President -- Exploration and
Production Services of the Company. Prior thereto, he was General
Manager -- Austin Chalk of the Company.

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PART II

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

The common stock of the Company is traded on the New York Stock Exchange
under the symbol "UPR." Information with respect to the quarterly high and low
sales prices per share for the Company's common stock, as reported on the New
York Stock Exchange Composite Tape, as well as the dividends declared on such
stock, is set forth under Selected Quarterly Data on page 80. At February 28,
1999, there were 252,150,993 shares of outstanding common stock and
approximately 145,000 shareholders of record. At that date, the closing price of
the common stock on the New York Stock Exchange was $8.9375.

The Company has paid quarterly cash dividends of $0.05 per share since its
initial public offering in October 1995. The Company currently intends to
continue to pay quarterly cash dividends on its outstanding shares of common
stock. The determination of the amount of future cash dividends, if any, to be
declared and paid by the Company will depend upon, among other things, the
Company's financial condition, funds from operations, the level of its capital
and exploratory expenditures, future business prospects and other factors deemed
relevant by the Board of Directors. Accordingly, there can be no assurance that
dividends will be paid. The Company has no current plans to increase or decrease
its dividend.

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17

ITEM 6. SELECTED FINANCIAL DATA

FIVE-YEAR FINANCIAL SUMMARY

1998(a) 1997 1996 1995 1994
--------- -------- -------- -------- --------
(MILLIONS, EXCEPT PER SHARE AMOUNTS)

INCOME STATEMENT DATA:
Operating revenues...................... $ 1,841.0 $1,518.0 $1,369.2 $1,166.8(d) $1,107.9
Operating income (loss)................. (1,193.2) 433.9 408.5 380.3(d) 299.3
Income (loss) from continuing
operations............................ (883.1) 303.1 253.7 294.2(d) 358.7(f)
Net income (loss)....................... (898.7) 333.0 320.8 350.7(d) 390.0(f)
Per share:
Income (loss) from continuing
operations -- basic(b)............. (3.57) 1.21 1.02 n/a n/a
Income (loss) from continuing
operations -- diluted(b)........... (3.57) 1.21 1.01 n/a n/a
Net income (loss) -- basic(b)......... (3.63) 1.33 1.29 n/a n/a
Net income (loss) -- diluted(b)....... (3.63) 1.33 1.28 n/a n/a
Dividends............................. 0.20 0.20 0.20 0.05(e) n/a

FINANCIAL POSITION DATA:
Properties -- net....................... $ 6,093.3 $2,901.1 $2,404.7 $2,238.4 $2,105.2
Total assets............................ 7,642.4 4,313.7 3,531.6 3,265.7 2,532.1
Total debt.............................. 4,598.7 1,230.6 670.9 101.5 37.7
Shareholders' equity.................... 728.2 1,760.7 1,514.3 1,312.4 1,834.9

CASH FLOW DATA:
Capital and exploratory expenditures.... $ 3,828.8(c) $1,188.4 $ 773.0 $ 603.0 $1,069.5(g)
Cash provided by operations............. 1,031.1 856.2 772.5 719.0 710.7

- ---------------

(a) In 1998, the Company recorded a $760 million after-tax charge related to
asset impairments in accordance with Statement of Financial Accounting
Standards No. 121, "Accounting for the Impairment of Long-Lived Assets and
for Long-Lived Assets to Be Disposed Of" ("SFAS No. 121").

(b) Earnings per share prior to 1996 have been omitted as the Company was a
wholly owned subsidiary of UPC until the Company's initial public offering
("Offering") in October 1995. Therefore, net income per share is not
applicable for periods prior to the fourth quarter of 1995.

(d) In November 1995, the Company recorded a $122.5 million pretax ($78.5
million after-tax) gain resulting from the Columbia Gas Transmission
Company bankruptcy settlement.

(e) Represents the dividend declared with respect to the fourth quarter of
1995. Prior to October 1995, the Company was wholly owned by UPC;
therefore, dividends per share is not applicable for prior periods.

(f) In March 1994, the Company sold its interest in the Wilmington Field and
Harbor Cogeneration Plant to the Port of Long Beach, California. The
Wilmington sale resulted in a $159.2 million pretax ($100 million
after-tax) gain.

(g) In March 1994, the Company acquired Amax Oil & Gas, Inc., for a purchase
price of $725 million.

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18

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS

The following information should be read in conjunction with the
information contained in the Consolidated Financial Statements and the notes
thereto included in Item 8 of this report. The Consolidated Statements of Income
for previous periods have been restated to present the Company's GPM segment as
discontinued operations.

SIGNIFICANT EVENTS AND CORPORATE REORGANIZATION

NORCEN ACQUISITION

In March 1998, the Company acquired Norcen for an aggregate purchase price
of $2.634 billion, and also assumed long-term debt obligations of Norcen
totaling approximately $1.0 billion. The acquisition was accounted for as a
purchase effective March 3, 1998, and, therefore, Norcen's financial results
have been consolidated into the Company's results beginning in March 1998. See
Note 2 to the Consolidated Financial Statements.

PROPERTY SALES AND GPM DIVESTITURE

In 1998, the Company's Board of Directors authorized management to proceed
with a deleveraging program designed to reduce the Company's debt in order to
maintain a strong investment grade credit rating. The program included the
Company's plans to sell approximately $600 million of producing properties. The
Company announced in January 1999 that sales of nearly $700 million of
properties had been completed, with over $400 million of this amount having
closed by December 31, 1998. These sales represent a different mix of properties
sold than was originally designated. Closed sales in 1998 include properties
located in the Denver-Julesburg Basin of the Western Region (the "DJ Basin
properties"), the Matagorda Island Block 623 Field and surrounding blocks (the
"Matagorda property"), other Offshore and Western Region properties and various
Canadian properties originally identified for divestiture. In addition,
completed sales in 1999 include interests in certain south Texas properties for
$138 million and the Caroline property in Canada for $108 million. All of the
producing properties sold or identified for sale in the aggregate represent
approximately 13 percent of the Company's total proved reserves as of December
31, 1998, and approximately 6 percent of the production volumes for 1998.

In connection with this deleveraging program, the Board of Directors also
authorized management to pursue potential monetization of the Company's GPM
segment. On November 20, 1998, the Company entered into a Merger and Purchase
Agreement ("Agreement") with Duke to sell the GPM segment for $1.35 billion with
the sale expected to close at the end of the first quarter of 1999.

HYDROCARBON SALES PRICE PRESSURES

During 1998, prices for oil and natural gas declined and are expected to
remain at low levels though 1999 as a result of several factors. These factors
include, but are not limited to, high production levels from members of the
Organization of Petroleum Exporting Countries ("OPEC") and other countries,
generally mild weather conditions, the economic weakness in several Asian
countries and excessive natural gas storage levels. Because of these factors,
the 1999 NYMEX price strip for crude oil was $13.02/Bbl and $2.03/Mcf for
natural gas on December 31, 1998. These prices were 29 percent and 10 percent,
respectively, below the corresponding price strips on December 31, 1997.

IMPAIRMENT OF LONG-LIVED ASSETS

The Company recorded a pretax charge of $1.23 billion ($760.1 million after
tax) in the fourth quarter of 1998, as required by SFAS No. 121. The non-cash
asset impairment charge to earnings was recorded as depreciation, depletion and
amortization ("DD&A") expense of $1.17 billion and surrendered lease expense of
$54.5 million in the Company's Consolidated Statement of Income. As noted above,
the current and anticipated low hydrocarbon prices -- particularly their effect
on the value of the Company's heavy oil

16
19

properties in Canada and Guatemala -- and reserve revisions following a
comprehensive review of reserves completed in December 1998, are the principal
factors contributing to the impairment. Most of the reserve revisions are
associated with properties in Canada and Offshore that were acquired by the
Company in 1998. The revisions are primarily due to comprehensive reserve
reviews and disappointing well performance from recent discoveries that were not
on production at the time of the Norcen Acquisition.

CORPORATE REORGANIZATION AND REDUCTION IN FORCE

Also as a result of the current low price environment and the resulting
reduction in cash flows generated by the Company's operations, the Company
recorded a pretax charge in 1998 of $17 million ($11 million after tax) to cover
the cost of a workforce reduction at its Fort Worth, Texas headquarters and
other domestic locations, and costs associated with offshore rig commitments.

The Company has announced a second reorganization to occur in the first
quarter of 1999, which will include an additional reduction in force and a
voluntary retirement incentive program. As a result of the workforce reductions
and a reduced capital spending program, the Company has reorganized its
operations into five primary business areas: (1) U.S. Onshore, (2) U.S.
Offshore, (3) Canada, (4) Latin America and (5) Minerals. Other business areas
and all overhead operations have been similarly streamlined to improve cost
efficiencies and to reflect lower capital spending plans.

In connection with the reorganizations, the Company believes that the
reductions in force and other cost reduction programs will better align staffing
levels with expected capital spending and operating activity levels, provide an
improved cost structure and create a more effective organization in the current
economic environment.

RESULTS OF OPERATIONS

YEAR ENDED DECEMBER 31, 1998 COMPARED TO DECEMBER 31, 1997

SUMMARY FINANCIAL DATA

YEARS ENDED DECEMBER 31,
-------------------------
1998 1997
----------- ----------
(MILLIONS OF DOLLARS)

Total operating revenues.................................... $ 1,841.0 $1,518.0
Total operating expenses.................................... 3,034.2 1,084.1
Operating income (loss)..................................... (1,193.2) 433.9
Income (loss) from continuing operations.................... (883.1) 303.1
Net income (loss)........................................... (898.7) 333.0
Earnings (loss) from continuing operations per
share -- diluted.......................................... (3.57) 1.21
Earnings (loss) per share -- diluted........................ (3.63) 1.33

The Company recorded a net loss of $898.7 million in 1998, or a loss of
$3.63 per share, compared to net income of $333.0 million, or $1.33 per share,
in 1997. The decrease is primarily due to the impact of the SFAS No. 121 asset
impairment of $1.23 billion ($760.1 million after tax), the majority of which
affected continuing operations, and lower product prices.

17
20

RESULTS OF CONTINUING OPERATIONS

In 1998, the Company reported a net loss from continuing operations of
$883.1 million, compared to income from continuing operations of $303.1 million
in 1997. Included in 1998 results was a charge of $1.22 billion ($756.0 million
after tax) related to the asset impairment. The additional volumes from the
Norcen Acquisition added revenues of $456.7 million. The increased revenues were
offset by depressed product prices that reduced revenues from non-Norcen
properties by more than $200 million as average prices declined 22 percent.
Additional factors that impacted income, primarily driven by the Norcen
Acquisition, were $273.9 million of higher production, exploration and
administrative expenses and $210.3 million of higher interest expense. Included
in administrative expenses was a restructure charge of $17.0 million related to
a reduction in force of the Company's domestic operations. The Company realized
a $140.0 million improvement to operating income as a result of gains on the
sale of various properties.

The operating loss was $1,193.2 million in 1998 compared to operating
income of $433.9 million in 1997. Exploration and production operating income,
excluding the portion of the fourth quarter asset impairment charged to such
properties, declined $355.1 million to $18.3 million. These results reflect
lower prices for all products and increased operating, exploration and DD&A
costs, which offset higher volumes and the gains on the sale of various
properties. Minerals operating income dropped slightly to $133.5 million due to
a $14.3 million reserve established for a legal settlement and a $4.0 million
asset impairment but was partially offset by increased operating income due to
an amended coal supply agreement at Black Butte. General and administrative
("G&A") costs, excluding the restructure charge, increased $35.5 million
primarily due to increased administrative costs associated with expanded
Canadian and international operations and an $8.2 million charge related to the
settlement of various crude royalty and tax issues.

SUMMARY OF SEGMENT FINANCIAL DATA

YEARS ENDED DECEMBER 31,
-------------------------
1998 1997
----------- --------
(MILLIONS OF DOLLARS)

Segment operating income (loss):
Exploration and production................................ $(1,199.2) $373.4
Minerals.................................................. 133.5 135.5
Corporate/general and administrative...................... (127.5) (75.0)
--------- ------
Total............................................. $(1,193.2) $433.9
========= ======

EXPLORATION AND PRODUCTION OPERATIONS

YEARS ENDED DECEMBER 31,
-------------------------
1998 1997
----------- ----------
(MILLIONS OF DOLLARS)

Exploration and production revenues......................... $ 1,539.2 $1,293.5
Other oil and gas revenues.................................. 160.7 84.7
--------- --------
Total operating revenues.......................... 1,699.9 1,378.2
Production expense.......................................... 444.3 300.8
Exploration expense......................................... 339.0 204.7
Depreciation, depletion and amortization.................... 2,115.8 499.3
--------- --------
Total operating expenses.......................... 2,899.1 1,004.8
--------- --------
Operating income (loss)..................................... $(1,199.2) $ 373.4
========= ========

Operating Revenues

Exploration and production revenues increased by $245.7 million (19%) to
$1,539.2 million, $456.7 million of which were associated with properties added
in the Norcen Acquisition. Excluding the Norcen Acquisition properties, volumes
were essentially flat to 1997 production levels; however, product price declines

18
21

reduced revenues by $211.0 million. Other revenues increased $76.0 million from
higher gains on property sales, principally the sales of the Matagorda and DJ
Basin properties.

YEARS ENDED DECEMBER 31,
-----------------------------------
1998 1997 1998 1997
------- ------- ------ ------
(WITHOUT HEDGING) (WITH HEDGING)

Average price realizations -- exploration and
production:
Natural gas (per Mcf)............................ $ 1.77 $ 2.19 $ 1.74 $ 2.00
Natural gas liquids (per Bbl).................... 7.88 11.23 7.88 11.23
Crude oil (per Bbl).............................. 10.37 18.80 10.48 18.36
Average price (per Mcfe)......................... 1.72 2.34 1.71 2.19

YEARS ENDED DECEMBER 31,
-------------------------
1998 1997
--------- ---------

Production volumes -- exploration and production:
Natural gas (MMcfd)....................................... 1,441.1 1,108.5
Natural gas liquids (MBbld)............................... 33.1 31.7
Crude oil (MBbld)......................................... 137.9 52.9
Total (MMcfed).................................... 2,467.0 1,615.7

Exploration and production volumes improved 851.3 MMcfed to 2,467.0 MMcfed
in 1998. Canadian volumes were 481.0 MMcfed higher than last year, while other
international volumes increased 244.1 MMcfed, in both cases primarily due to
properties added in the Norcen Acquisition. Production from domestic properties
increased 126.2 MMcfed including 103.9 MMcfed added in Offshore from the Norcen
Acquisition. Offshore production from non-Norcen properties decreased largely
due to the sale of the Matagorda property. All other domestic profit centers
realized increased volumes in 1998.

Natural gas volumes increased 332.6 MMcfd (30%). Canadian volumes increased
by 263.6 MMcfd and Offshore production was up 64.1 MMcfd, largely due to
properties added in the Norcen Acquisition. Gulf Coast Onshore production was
23.2 MMcfd higher from continued drilling success in the Roleta Field and
Wadsworth Southeast area. Western Region and East/West Texas volumes improved 8
MMcfd each due to development drilling. Partially offsetting these improvements
was a 39 MMcfd decline in Austin Chalk volumes where the drilling success
achieved in Washington County in 1997 was not duplicated.

Natural gas liquids volumes increased 1.4 MBbld (4%) to 33.1 MBbld.
Production improvements included 2.9 MBbld in the Austin Chalk resulting from
the processing of gas through newly expanded facilities and 2.5 MBbld in Canada
largely due to the Norcen Acquisition. These increases were partially offset by
4.8 MBbld of lower volumes from the Western Region as a result of the decision
to reject ethane and bypass gas due to low NGL prices.

Crude oil volumes were 85.0 MBbld higher in 1998 primarily from properties
added in the Norcen Acquisition and a 7.5 MBbld improvement from the Austin
Chalk due to higher volumes in Louisiana. Canadian production was 33.7 MBbld
higher for the period, while production from Guatemala and Venezuela was 20.8
MBbld and 16.7 MBbld, respectively.

Operating Expenses

Production expenses, which include lease operating costs, production
overhead and production taxes, increased $143.5 million while production costs
on a per unit basis were $0.49 per Mcfe, 4 percent less than last year's $0.51
per Mcfe. Total lease operating expenses rose $141.3 million, of which $135.4
million was attributable to Norcen Acquisition properties. The remainder of the
lease operating expense increase largely reflects higher personnel costs
associated with other producing property purchases and higher salt water
disposal costs in East/West Texas, Austin Chalk and Gulf Coast Onshore. Lease
operating expenses on a per unit basis were up 22 percent to $0.34 per Mcfe
which reflects higher operating expenses associated with the production of heavy
crude oil in Guatemala, Venezuela and Canada. Production overhead costs were up
$2.6 million largely because of increased personnel costs due to the expanded
international operations.

19
22

Exploration expenses increased $134.3 million over last year, including
$54.5 million of surrendered lease costs that were part of the SFAS No. 121
asset impairment. Excluding the effect of the asset impairment, activity related
to properties added in the Norcen Acquisition contributed $72.8 million to the
increase. For domestic operations, exploration expenses were up 3 percent to
$210.8 million, excluding the surrendered lease asset impairment. The increase
was primarily the result of a $30.1 million increase in other surrendered lease
costs, related to the Cotton Valley Reef and other properties in East/West
Texas, and increased leasing activity in Gulf Coast Onshore. Other domestic
exploration expenses were down $23.1 million reflecting reduced activity. Dry
hole expenses, geological and geophysical costs and delay rentals were down
$10.4 million, $9.1 million and $4.2 million, respectively, while exploration
overhead was essentially flat with 1997 levels.

DD&A increased by $1,616.5 million, including $1,163.1 million related to
the SFAS No. 121 asset impairment. On a per unit basis, DD&A expense, excluding
the impairment, rose $0.21 per Mcfe to $1.06 per Mcfe. Properties added in the
Norcen Acquisition contributed $377.4 million, excluding the asset impairment.
The remaining variance from non-Norcen Acquisition properties, $76.0 million, is
associated with higher volumes that caused $11.3 million of the total increase
in DD&A, while a higher per unit rate added $64.7 million.

MINERALS OPERATIONS

YEARS ENDED DECEMBER 31,
------------------------
1998 1997
-------- --------
(MILLIONS OF DOLLARS)

Operating Income
Coal...................................................... $101.5 $ 83.3
Soda ash.................................................. 35.5 49.5
Other..................................................... (3.5) 2.7
------ ------
Total............................................. $133.5 $135.5
====== ======

Minerals operating income decreased by $2.0 million. Contributing to the
decline was $14.0 million of lower operating income from soda ash operations,
reflecting lower royalties, lower equity income from the Company's soda ash
joint venture and the inclusion of a lease bonus in 1997 results. Also affecting
1998 performance was a $14.3 million accrual for a legal settlement and a $4.0
million asset impairment charge on certain industrial mineral and uranium
properties. In addition, ballast operating income decreased due to the shutdown
of operations in 1997. Partly offsetting these items were $19.7 million of
higher equity income from Black Butte reflecting the amendment of a coal supply
contract and a $2.0 million gain from a property sale.

GENERAL AND ADMINISTRATIVE AND OTHER

G&A and other expenses increased $52.5 million to $127.5 million,
principally reflecting $21.1 million related to expanded international
operations and the $17.0 million restructuring charge. Also contributing to the
increase was an $8.2 million charge related to the settlement of various crude
royalty and tax issues, $3.3 million of additional rent expense, $2.4 million in
higher professional and temporary costs, and a $1.9 million rise in DD&A expense
for domestic overhead. On a per unit basis, excluding the restructuring charge,
G&A expenses were flat to 1997 at $0.12 per Mcfe.

Other income/expense was $69.8 million lower than 1997 results. The
reduction reflects a $46.5 million foreign currency exchange rate loss and a
$14.3 million charge related to the expiration of interest rate lock contracts
intended to hedge such rates for a contemplated bond issuance. In addition, 1997
results included the benefit of a $23.0 million partial reduction of reserves
associated with the 1994 sale of the Wilmington, California oil field, due to
the reduction of environmental remediation exposure, a $7.2 million gain on the
sale of securities held for investment and $6.7 million of higher environmental
insurance settlements. Partly offsetting these declines were an $11.0 million
gain on the closure of a foreign exchange contract entered into

20
23

in connection with the Norcen Acquisition, and the inclusion in 1997 of $17.8
million of costs related to the unsuccessful bid to acquire Pennzoil Company.

Interest expense increased $210.3 million to $249.8 million. This increase
reflects the borrowings made in connection with the Norcen Acquisition and
capital spending programs. Interest expense allocated to discontinued operations
was $21.1 million in 1998 and $13.6 million in 1997.

Income taxes declined $721.0 million compared to last year to a benefit of
$605.2 million, primarily the result of the pretax net loss in 1998. Included in
1998 results was a $22.5 million benefit due to foreign currency gains on
deferred tax liabilities in Venezuela and Guatemala. Section 29 tax credits in
1998 were $16.4 million compared to $18.8 million in 1997. The effective tax
rate in 1998 was 40.6 percent versus 28.6 percent in 1997 largely due to the
effect of the acquisition and expansion of operations outside the United States
where higher tax rates exist. Also, Section 29 tax credits were additive to the
effective rate when recording the overall tax benefit in 1998 but reduced the
effective tax rate when the overall 1997 tax expense was recorded.

RESULTS OF DISCONTINUED OPERATIONS

GATHERING, PROCESSING AND MARKETING OPERATING RESULTS

Results from discontinued operations generated a net loss of $15.6 million
for 1998, compared to income of $29.9 million in 1997. The segment reported an
operating loss of $1.0 million for 1998 versus operating income of $61.3 million
in 1997.

Operating margins were down more than $45 million from last year due to low
product prices that were not offset by lower gas purchase prices. Operating
revenues were down $66.7 million from 1997 largely due to the $35.2 million
($23.0 million after tax) charge related to firm transportation contracts that
were marked to market in connection with the GPM disposition, and lower product
prices. Volumes were up 2 percent largely due to the purchase of Highlands Gas
Corporation ("Highlands") in the third quarter of 1997, and recently expanded or
constructed facilities. Another benefit to income was the $30.0 million pretax
gain on the settlement of a gas supply agreement. Operating expenses were down
$17.9 million due to lower gas purchase costs which more than offset higher
facility operating expenses and overhead costs due to expanded operations.

RESULTS OF OPERATIONS

YEAR ENDED DECEMBER 31, 1997 COMPARED TO DECEMBER 31, 1996

SUMMARY FINANCIAL DATA

YEARS ENDED DECEMBER 31,
-------------------------
1997 1996
---------- ----------
(MILLIONS OF DOLLARS)

Total operating revenues.................................... $1,518.0 $1,369.2
Total operating expenses.................................... 1,084.1 960.7
Operating income............................................ 433.9 408.5
Income from continuing operations........................... 303.1 253.7
Net income.................................................. 333.0 320.8
Earnings from continuing operations per share -- diluted.... 1.21 1.01
Earnings per share -- diluted............................... 1.33 1.28

The Company reported net income of $333.0 million, or $1.33 per share, for
1997 compared to $320.8 million, or $1.28 per share, for 1996.

21
24

RESULTS OF CONTINUING OPERATIONS

Income for continuing operations increased 19 percent to $303.1 million in
1997, and 20 percent on a per share basis, to $1.21. Exploration and production
operating income was up 4 percent to $373.4 million due to increased volumes and
higher product prices partly offset by a $60.1 million increase in exploration
expenses and higher production costs. Minerals contributed strong operating
income of $135.5 million, up 13 percent from 1996, largely due to increased
royalty income. In addition, the Company realized higher other income despite
one-time costs associated with the unsuccessful attempt to acquire Pennzoil
Company.

SUMMARY OF SEGMENT FINANCIAL DATA

YEARS ENDED DECEMBER 31,
------------------------
1997 1996
-------- --------
(MILLIONS OF DOLLARS)

Segment operating income:
Exploration and production................................ $373.4 $359.1
Minerals.................................................. 135.5 120.0
Corporate/general and administrative...................... (75.0) (70.6)
------ ------
Total............................................. $433.9 $408.5
====== ======

EXPLORATION AND PRODUCTION OPERATIONS

YEARS ENDED DECEMBER 31,
-------------------------
1997 1996
---------- ----------
(MILLIONS OF DOLLARS)

Exploration and production revenues......................... $1,293.5 $1,148.2
Other oil and gas revenues.................................. 84.7 92.1
-------- --------
Total operating revenues.......................... 1,378.2 1,240.3
Production expense.......................................... 300.8 263.2
Exploration expense......................................... 204.7 144.6
Depreciation, depletion and amortization.................... 499.3 473.4
-------- --------
Total operating expenses.......................... 1,004.3 881.2
-------- --------
Operating income............................................ $ 373.4 $ 359.1
======== ========

Operating Revenues

Exploration and production revenues increased by $145.3 million (13%)
largely due to a 10 percent increase in volumes and increased product prices of
$0.06 per Mcfe.

YEARS ENDED DECEMBER 31,
-----------------------------------
1997 1996 1997 1996
------- ------- ------ ------
(WITHOUT HEDGING) (WITH HEDGING)

Average price realizations -- exploration and
production:
Natural gas (per Mcf)............................ $ 2.19 $ 1.94 $ 2.00 $ 1.85
Natural gas liquids (per Bbl).................... 11.23 11.48 11.23 11.48
Crude oil (per Bbl).............................. 18.80 20.14 18.36 18.84
Average price (per Mcfe)......................... 2.34 2.23 2.19 2.13

22
25

YEARS ENDED DECEMBER 31,
-------------------------
1997 1996
--------- ---------

Production volumes -- exploration and production:
Natural gas (MMcfd)....................................... 1,108.5 988.9
Natural gas liquids (MBbld)............................... 31.7 30.5
Crude oil (MBbld)......................................... 52.9 50.6
Total (MMcfed)............................................ 1,615.7 1,475.3

Volumes improved 140.4 MMcfed to 1,615.7 MMcfed for 1997, principally on
the strength of higher natural gas production.

Natural gas volumes increased 119.6 MMcfd (12%) over 1996 primarily due to
the extensive drilling programs in several business units and a lower
distribution of preferential volumes related to the Company's Section 29 Limited
Partnership (57.1 MMcfd). East/West Texas business unit gas volumes improved
35.4 MMcfd from continued success with horizontal drilling programs and
production from, and further development of, properties acquired from Castle
Energy. The Gulf Coast Onshore business unit showed an improvement of 31.1 MMcfd
reflecting successful drilling programs in southern Texas and southern
Louisiana. Austin Chalk gas volumes were up 11.0 MMcfd from success in the deep
Giddings field. These improvements were partially offset by a 14.8 MMcfd decline
in Western Region gas volumes caused by production declines.

Natural gas liquids volumes increased 1.2 MBbld (4%) with most of the
improvement attributable to the East/West Texas business unit. Crude oil volumes
increased by 2.3 MBbld (5%) primarily from drilling successes in the Masters
Creek field in Louisiana.

Operating Expenses

Production costs increased $37.6 million to $300.8 million for 1997,
primarily due to a $27.9 million rise in lease operating expenses. This increase
reflects the impact of higher volumes, as well as increased costs for workovers,
maintenance and salt water disposal, primarily in the Austin Chalk business
unit. Total production expenses per Mcfe increased to $0.51 in 1997 compared to
$0.49 in 1996.

Exploration expenses were up $60.1 million to $204.7 million, reflecting
the Company's expanded exploration programs. Surrendered lease costs were up
$24.1 million as a result of increased leasing activity in the East/West Texas
and Austin Chalk business units. Delay rentals rose $10.4 million, primarily in
the Austin Chalk, Gulf Coast Onshore and Offshore business units. In addition,
geological and geophysical costs were $16.2 million higher, primarily in the
Gulf Coast Onshore and Offshore business units, while dry hole costs were up
$8.4 million, principally in the East/West Texas, Gulf Coast Onshore and
Offshore business units.

Exploration and production DD&A expense increased $25.9 million due to
higher production volumes, partially offset by a lower unit of production rate.
Included in 1997 was $24.4 million of writedowns of various properties, while
1996 contained $26.4 million of writedowns, primarily in the Western Region,
Gulf Coast Onshore and Offshore business units.

MINERALS OPERATIONS

YEARS ENDED DECEMBER 31,
------------------------
1997 1996
-------- --------
(MILLIONS OF DOLLARS)

Operating Income
Coal...................................................... $ 83.3 $ 76.5
Soda ash.................................................. 49.5 40.2
Other..................................................... 2.7 3.3
------ ------
Total............................................. $135.5 $120.0
====== ======

23
26

Minerals operating income increased by $15.5 million over 1996, primarily
due to higher lease bonus and royalty income ($15.4 million) as a result of
higher soda ash volumes and prices. Operating expenses for minerals operations
declined $4.6 million compared to 1996, due to the shutdown of the Company's
ballast operations.

GENERAL AND ADMINISTRATIVE AND OTHER

G&A expenses in 1997 were $4.4 million higher than 1996, due to costs
associated with the implementation of employee ownership and culture change
programs, increased costs for upgrades and maintenance of the Company's computer
systems and higher personnel costs related to additional hiring associated with
increased activity levels. G&A expenses per unit were $0.12 per Mcfe in both
1997 and 1996.

Other income/expense was $28.0 million higher than 1996 from a $23 million
reserve reduction reflecting lower environmental remediation exposure related to
oil and gas properties in Wilmington, California that were sold in 1994. Other
income/expense also included a $7.2 million gain on the sale of securities held
for investment and $10 million in environmental insurance settlements. These
items were partially offset by $17.8 million in costs related to the
unsuccessful bid to acquire Pennzoil Company.

Interest expense increased $0.6 million to $39.5 million. Interest expense
allocated to discontinued operations was $13.6 million in 1997 and $11.7 million
in 1996.

Income taxes of $115.8 million were $3.4 million higher than 1996,
reflecting higher income before taxes, $9.9 million in favorable prior period
state and federal tax adjustments recorded in 1997 and an increase of $3.2
million in Section 29 tax credits. In contrast, 1996 included a $3 million
unfavorable state tax adjustment.

RESULTS OF DISCONTINUED OPERATIONS

GATHERING, PROCESSING AND MARKETING OPERATING RESULTS

Results from discontinued operations generated income of $29.9 million for
1997, a drop of $37.2 million from income of $67.1 million in 1996. Operating
income declined $56.8 million to $61.3 million for 1997.

Operating margins in 1997 were down more than $45 million from 1996 due to
low sales prices and higher gas purchase prices. Operating revenues were down
$55.1 million from 1996 largely due to lower product sales prices despite an 8
percent volume increase. The volume increase was largely due to the Highlands
acquisition and the start-up of the Masters Creek plant. Also included in 1997
results was a $6.4 million gain on the sale of the Company's investment in the
Frontier Pipeline. Included in 1996 results was a $17 million asset impairment
for the Wahsatch pipeline.

LIQUIDITY AND CAPITAL RESOURCES

The Company's primary sources of cash during 1998 were cash provided by
operations, debt financing, a forward sale and the sales of assets associated
with the Company's deleveraging program. Cash outflows for 1998 include the
purchase of Norcen, capital and exploratory expenditures, interest, dividends
and the repurchase of common stock by the Company.

Cash provided by operations for 1998 of $1.03 billion increased $174.9
million (20%) compared to 1997, as the benefit of significantly higher
production volumes was offset by lower sales prices for the Company's oil and
gas products, higher costs of expanded production operations and higher interest
expense associated with higher debt levels. Cash from operations also included
two non-recurring items: the collection of an acquired note receivable related
to Norcen's 1997 partial sale of Superior Propane ($85.4 million) and the
closure of certain commodity and foreign currency financial contracts ($63.9
million) also acquired in the Norcen Acquisition.

Cash used in investing activities for 1998 rose $1.90 billion over 1997,
primarily reflecting the $2.63 billion purchase price for Norcen. This increase
was partially offset by over $400 million of higher

24
27

proceeds from sales of producing properties and investments, associated with the
Company's deleveraging program. In 1998, this included proceeds from the sales
of the Matagorda properties ($158 million), the DJ Basin properties ($41
million), a package of Canadian properties ($145 million), a package of Western
Region business unit properties ($46 million) and the sale of the remaining
investment in Superior Propane ($48 million). Cash provided by discontinued GPM
operations of $50.4 million was $272.2 million higher than 1997. Included in
1997 were an aggressive capital expenditure program and the acquisition of
Highlands. Results in 1998 reflect lower capital expenditures, tighter margins
from the GPM operations, and a forward sale agreement that provided $171
million. The forward sale initially provided $250 million; however, in November
the Company began settling the obligation, and made payments of $79 million by
the end of the year, with the remaining amount to be settled in the first
quarter of 1999.

Capital expenditures for continuing operations, excluding the cost of the
Norcen Acquisition, were up $6.1 million compared to last year. The amounts
below include capital expenditures for Norcen properties beginning in March
1998.

1998 1997
--------- ---------
(MILLIONS OF DOLLARS)

Exploration and production
Exploration............................................... $ 286.3 $ 399.3
Production................................................ 764.9 642.7
Property purchases........................................ 110.7 130.6
-------- --------
Total exploration and production.................. 1,161.9 1,172.6
Minerals, G&A and other..................................... 32.6 15.8
-------- --------
Sub-total continuing operations........................... 1,194.5 1,188.4
Norcen purchase price....................................... 2,634.3 --
-------- --------
Continuing operations............................. $3,828.8 $1,188.4
======== ========
Gathering, processing and marketing......................... $ 143.8 $ 163.9
Highlands acquisition..................................... -- 179.4
-------- --------
Discontinued operations........................... $ 143.8 $ 343.3
======== ========

Exploration and production capital spending was down $10.7 million to $1.16
billion. Drilling expenditures of $731.4 million accounted for 61 percent of
capital expenditures for continuing operations in 1998. The Austin Chalk was
responsible for $288.3 million of drilling expenditures while Canada and
Offshore spent $114.2 million and $105.7 million, respectively. Development
drilling was concentrated in the Austin Chalk, Canada, East/West Texas and the
Western Region while exploratory drilling was focused in the Offshore, Canada
and Gulf Coast Onshore areas. Production facility capital expenditures of $135.1
million largely reflect spending on properties added in the Norcen Acquisition
to support production operations.

Property purchases of $110.7 million completed in 1998 include purchases in
the Western Region, Austin Chalk and Gulf Coast Onshore. Minerals, G&A and other
capital was up $16.8 million, primarily related to expenditures for relocating
the Fort Worth headquarters. Expenditures for discontinued operations were down
$20.1 million, excluding $179.4 million associated with the 1997 Highlands
acquisition, due to a reduction in plant expansion and construction in 1998.

25
28

At year-end 1998 and 1997, the total capitalization of the Company was as
follows:

DECEMBER 31, DECEMBER 31,
1998 1997
------------ ------------
(MILLIONS OF DOLLARS)

Long- and short-term debt:
Commercial paper and other, net........................... $2,351.9 $ 663.1
Notes and debentures...................................... 2,225.0 550.0
Capital lease obligations................................. 17.4 --
Tax exempt revenue bonds.................................. -- 20.1
(Discount) premium on notes and debentures -- net......... 4.4 (2.6)
-------- --------
Total debt........................................ 4,598.7 1,230.6
Shareholders' equity........................................ 728.2 1,760.7
-------- --------
Total capitalization.............................. $5,326.9 $2,991.3
======== ========
Debt to total capitalization.............................. 86.3% 41.1%

In October 1998, the Company replaced its eight existing facilities (the
Norcen Acquisition Facility, its $600 million and $300 million revolving credit
agreements and five Canadian facilities), which totaled approximately U.S. $2.9
billion. The facilities were replaced with three new facilities totaling an
aggregate of U.S. $2.5 billion. These new facilities are comprised of a $1.0
billion 364-day Competitive Advance/Revolving Credit Agreement (the "Bridge
Facility"), a $750 million 364-day Competitive Advance/Revolving Credit
Agreement and a $750 million Five-Year Competitive Advance/Revolving Credit
Agreement (collectively the "Facilities"). Each of the Facilities contain a
covenant stipulating that the ratio of consolidated debt to consolidated
EBITDAX -- the sum of operating income (before adjustments for income taxes,
interest expense or extraordinary gains or losses), DD&A and exploration
expenses -- cannot exceed 3.25:1.00. This covenant replaced the consolidated
debt to total capitalization ratio covenant applicable under previous
facilities. The 1998 consolidated debt to consolidated EBITDAX covenant
calculation uses pro forma EBITDAX results. The Company was in compliance with
this covenant provision at year-end 1998.

The Bridge Facility also contains mandatory reduction provisions whereby it
will be permanently reduced by 75 percent of the net proceeds from specified
asset sales (certain identified exploration and production assets and the
Company's GPM segment). At December 31, 1998, the Bridge Facility had not been
reduced pursuant to this provision as none of the specified sales had yet
occurred. The Facilities also place other restrictions on the Company regarding
the creation of liens, incurrence of additional indebtedness of subsidiaries,
transactions with affiliates, sales of stock of Union Pacific Resources Company
(a wholly-owned subsidiary of the Company) and certain mergers, consolidations
and asset sales.

Debt maturities through 2003, excluding capital leases, are $851.9 million
of commercial paper and bankers acceptances in 1999 and $250 million of term
debt in 2002. At December 31, 1998, $1.5 billion of commercial paper and bankers
acceptances had been classified as long-term, supported by the $750 million
Five-Year and the $750 million 364-day Competitive Advance/Revolving Credit
Agreements. This classification reflects the Company's intent and ability to
maintain these borrowings on a long-term basis, through the issuance of
additional commercial paper and/or new term financings.

The Company utilizes letters of credit to support certain financing
instruments, performance contracts and insurance policies. The fair value of the
letters of credit at December 31, 1998 and 1997 was $58.6 million and $10.7
million, respectively. The Company has guaranteed a portion of the OCI Wyoming,
L.P. debt facility. At December 31, 1998, OCI Wyoming, L.P. had an outstanding
debt facility balance of $49 million, of which the Company has guaranteed $24.0
million.

26
29

During 1998, the Company purchased $26.7 million of its common stock. In
1998, the Board of Directors authorized the purchase of an additional $50
million of common stock in 1999. During 1998, the Company paid quarterly cash
dividends of $0.05 per share on its outstanding common stock, and on October 29
declared a $0.05 per share dividend that was paid on January 2, 1999. The
determination of the amount of future cash dividends, if any, to be declared and
paid by the Company will depend upon, among other things, the Company's
financial condition, funds from operations, the level of its capital and
exploratory expenditures, future business prospects and other facts deemed
relevant by the Board of Directors. Accordingly, there can be no assurance that
dividends will be paid.

OUTLOOK AND OTHER MATTERS

The Company expects to realize a decrease in its oil and gas production in
1999 but anticipates that reserve additions will more than replace 1999
production. Average annual volumes, adjusted for property sales, are expected to
drop approximately 5 percent because of the reduced capital spending program
that reflects lower activity levels due to the current forecast of low product
prices at least through year-end 1999. Production growth is expected, however,
in Canada, when adjusted for property sales, and Venezuela. The Company will
continue to search for properties and reserves that will supplement its drill
site inventory.

Prices for crude oil, natural gas and NGLs for 1999 are expected to remain
at their current depressed levels. Increased production from members of OPEC
along with the decline in several Asian countries' economies has altered the
balance between supply and demand for oil, sending 1998 NYMEX crude oil prices
30 percent lower than 1997 with little optimism for a price rebound in 1999.
Natural gas prices have been similarly affected due to the recent mild winter
weather that has resulted in excessive natural gas storage levels and the
ability of consumers to switch between oil and natural gas. The Company expects
to experience price fluctuations and manages a portion of its price risk with
hedging activities; however, lower prices could affect expected future net
income, cash flows and capital spending.

In 1999, the Company anticipates spending approximately $500 million for
exploration and development projects and will be funded through cash provided by
operations. The focus will be on high-return, quick-payout programs with almost
90 percent of the capital budget devoted to development projects that generate
more immediate cash flow. Approximately 20 percent of the capital will be
directed to each of the following areas: Canada, Austin Chalk, other U.S.
Onshore, U.S. Offshore and Latin America. The Company may adjust its capital
spending as commodity prices and cash flows change. The extent and timing of
capital spending may also be affected by changes in business, financial and
operating conditions as well as by the timing and availability of suitable
investment opportunities.

The Company owns a non-operating 50 percent interest in Black Butte, a
partnership which operates a surface coal mine complex in southwestern Wyoming.
During 1998, Black Butte's sales to its largest customer under an amended coal
supply contract contributed $79.3 million to consolidated operating income. This
contract was amended in 1997 to accelerate the shipments from the year 2001 into
the years 1998, 1999 and 2000, at which time this agreement will terminate.
Operating income under the contract is expected to be approximately $74 million
in both 1999 and 2000. Although Black Butte continues to seek new buyers for its
low-sulfur coal, its mining costs are considerably higher than the mining costs
of its competition, primarily mines located in the Powder River Basin of Wyoming
and Montana. The Company does not expect to be able to replace the operating
income it receives currently under the amended contract with incremental coal
sales after 2000.

The Agreement associated with the sale of the GPM business segment to Duke
included an obligation for the Company to sell the majority of its domestic
natural gas and existing NGL production to Duke for a five-year period beginning
on the closing date of the sale. Natural gas volumes dedicated to the Agreement
include existing and future production that is available at specific delivery
points as listed in the Agreement. Prices received for the natural gas and NGL
production will be tied to current market prices. Additionally, as a result of
the Agreement, the Company agreed to reimburse Duke for losses incurred under
certain transportation contracts for up to ten years. The Company established a
reserve based on the fair value of

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30

these contracts at December 31, 1998, of $88.7 million, which is included in
other current and long-term liabilities on the Consolidated Statement of
Financial Position.

As part of the Agreement, Duke was allowed to conduct an environmental
audit and, based on the results, assert claims for the cost to remediate
environmental conditions discovered during the audit. Duke has concluded the
environmental audit and asserted claims under the Agreement. Under the terms of
the Agreement, asserted claims will not affect or delay the close of the
transaction; however, following the close of the transaction the Company has the
right to contest any environmental claims through arbitration. If it is
determined through arbitration that there are valid environmental claims in
excess of $40 million, then the Company is obligated to make payment to Duke for
such excess. While the Company is still analyzing Duke's environmental claims,
at this time it is the Company's view that there are substantial defenses to the
Duke claims.

In 1997, Union Pacific Resources Inc. ("UPRI"), the Company's wholly-owned
Canadian subsidiary, received a reassessment concerning the deductibility of
certain expenses and foreign exchange losses claimed for income tax purposes
during the period 1989 through 1993 in the amount of $81.1 million. In spite of
UPRI's disagreement and appeal, the reassessment was fully funded in 1997 and
recorded as a deferred tax benefit. As a result of the Norcen Acquisition, the
Company recorded a valuation allowance against this benefit as part of the
purchase price allocation. The carryforward benefit net of the valuation
allowance is approximately $15.8 million. On March 8, 1999, the Company entered
into an agreement with Canadian tax authorities to settle the claims out of
court. Under the terms of the settlement, the Company will receive a refund of
approximately $50 million.

The financial statements of the Company's Canadian subsidiary use the
Canadian dollar as their functional currency. Latin American subsidiaries
generally use the U.S. dollar as their functional currency. To the extent that
business transactions in these countries are not denominated in the respective
country's functional currency, the Company is exposed to foreign currency
exchange rate risk. In addition, in these subsidiaries, certain asset and
liability balances are denominated in currencies other than the subsidiary's
functional currency. These asset and liability balances must be remeasured in
the preparation of the subsidiary financial statements using a combination of
current and historical exchange rates, with any resulting remeasurement
adjustments included in net income. See additional discussion in "Item 7A. Risk
Management: Foreign Currency Risk."

ITEM 7A. RISK MANAGEMENT

The Company has established policies and procedures for managing risk
within its organization, including internal controls and governance by a risk
management committee. The level of risk assumed by the Company is based on its
objectives and earnings, and its capacity to manage risk. Limits are established
for each major category of risk, with exposures monitored and managed by Company
management and reviewed by the risk management committee.

As a result of the Norcen Acquisition, the Company's risk exposure has
changed during 1998. With higher production volumes, the Company is able to
enter into hedges covering a greater amount of production in its non-trading
activities. In addition, the additional debt incurred and the acquired foreign
operations increase the Company's exposure to changes in interest rates and
foreign currency exchange rates. At December 31, 1997, the Company's primary
risk exposure was related to commodity price risk -- non-trading activities,
where futures, swaps and option contracts for natural gas were in place for an
average of 554 MMcfd for the year 1998. These positions had an unrecognized gain
of $3.3 million at December 31, 1997. In addition, fixed price contracts were in
place for 62.6 Bcf of natural gas for 1998 through 2008, with an unrecognized
gain of $28.1 million. No other material positions were outstanding at December
31, 1997.

Unrecognized mark-to-market gains and losses were determined based on
current market prices, as quoted by recognized dealers, assuming round lot
transactions and using a mid-market convention without regard to market
liquidity. The actual gains or losses ultimately realized by the Company from
such hedges may vary significantly from the foregoing amounts due to the
volatility of the commodity markets.

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31

COMMODITY PRICE RISK -- NON-TRADING ACTIVITIES

The Company uses derivative financial instruments for non-trading purposes
in the normal course of business to manage and reduce risks associated with
contractual commitments, price volatility and other market variables. These
instruments are generally put in place to limit the risk of adverse price
movements; however, these same instruments may also limit future gains from
favorable price movements. Risk management activities are generally accomplished
pursuant to exchange-traded futures contracts or over-the-counter swaps and
options.

Recognition of realized gains/losses and option premium payments/receipts
in the Consolidated Statement of Income is deferred until the underlying
physical product is purchased or sold. Unrealized gains/losses on derivative
financial instruments are not recorded. The cash flow impact of derivative and
other financial instruments is reflected as cash flows from operations in the
Consolidated Statement of Cash Flows. Margin deposits, deferred gains/losses on
derivative financial instruments and net premiums are included in other current
assets or liabilities in the Consolidated Statement of Financial Position. At
December 31, 1998, the Company had margin deposits of $3.2 million.

The Company's oil and gas revenues can be higher or lower than what would
be reported if the hedging program were not in place. As a result, revenues were
lower by $9 million in 1998 and by $86 million in 1997. Since these transactions
were hedges on oil and gas production volumes, these impacts were also reflected
in the average sales price of the associated products.

The following table summarizes the Company's open positions as of December
31, 1998, which hedge the Company's future oil and gas production:

WEIGHTED
AVG. PRICES UNRECOGNIZED
CONTRACT PER MCF FAIR VALUE GAIN (LOSS)
PRODUCT TYPE TIME PERIOD VOLUME OR BBL (MILLIONS) (MILLIONS)
- ------- ---- ----------- ------ ----------- ---------- ------------

Gas Puts purchased Feb-Mar 1999 1.0 Bcfd $2.15 $ 15.3 $ 6.7
Gas Puts purchased Apr-Oct 1999 0.35 Bcfd 1.90 8.6 (2.5)
Gas Calls sold Apr-Oct 1999 1.0 Bcfd 2.54 3.1 18.8
Gas Swaps Feb-Mar 1999 0.8 Bcfd Var (5.0) (5.0)
Gas Swaps Apr-Oct 1999 0.8 Bcfd Var (18.5) (18.5)
Gas Futures Apr-Oct 1999 0.1 Bcfd 2.00 0.9 0.9
Gas Fixed price Feb 99-Dec 99 6.6 Bcfd 1.81 0.8 0.8
Gas Fixed price Jan 00-Dec 00 6.7 Bcfd 1.83 0.7 0.7
Gas Fixed price Jan 01-Oct 01 3.0 Bcfd 1.91 (0.6) (0.6)
Oil Swaps Feb 99-Dec 99 2.0 Mbd 8.45 (1.4) (1.4)
Oil Swaps Jan 00-Dec 00 2.0 Mbd 8.45 (1.3) (1.3)
Oil Fixed price Feb 99-Mar 99 10.0 Mbd 5.27 (2.3) (2.3)
Oil Fixed price Feb 99-Aug 99 2.0 Mbd 5.78 (0.9) (0.9)
------ ------
$ (0.6) $ (4.6)
====== ======

In connection with purchase accounting for the Norcen Acquisition, an asset
was recorded representing the fair value of acquired futures contracts, to be
amortized over the terms of the applicable contracts. At December 31, 1998,
excluding the $4.0 million remaining unamortized value of the asset, the
Company's unrecognized loss related to hedges of oil and gas production was $8.0
million.

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32

UP Fuels enters into financial contracts in conjunction with
transportation, storage and customer service programs. The following table
summarizes UP Fuels' open positions as of December 31, 1998, which are part of
the assets of the Company's GPM segment held for sale:

WEIGHTED UNRECOGNIZED
CONTRACT AVG. PRICE FAIR VALUE GAIN (LOSS)
PRODUCT TYPE TIME PERIOD VOLUME PER MCF (MILLIONS) (MILLIONS)
- ------- ---- ----------- ------ ---------- ---------- ------------

Gas Futures/swaps purchased Feb 99-Dec 01 121.6 Bcf $2.12 $(38.3) $(38.3)
Gas Futures/swaps sold Feb 99-Jan 00 38.4 Bcf 2.25 12.6 12.6
Gas Fixed price Feb 99-Jun 11 229.9 Bcf 2.88 77.1 77.1
------
$ 51.4 $ 51.4
====== ======

In connection with purchase accounting for the Norcen Acquisition, an asset
was recorded representing the fair value of acquired fixed price positions, to
be amortized over the terms of the applicable contracts. At December 31, 1998,
excluding the $66.9 million remaining unamortized value of the asset, the
Company's unrecognized gain related to UP Fuels open fixed price positions was
$10.7 million.

As a result of the sales agreement with Duke, the Company has agreed to
reimburse Duke under a keep whole agreement for losses incurred under certain
transportation contracts for up to ten years. The fair value of these contracts
at December 31, 1998, was a loss of $88.7 million, which is included in other
current liabilities and other liabilities on the Consolidated Statement of
Financial Position. The fair value of these obligations are summarized as
follows:

UNDISCOUNTED DISCOUNTED
YEAR (MILLIONS) (MILLIONS)
- ---- ------------ ----------

1999.......................................... $ 17.4 $16.7
2000.......................................... 14.8 12.9
2001.......................................... 13.2 10.4
2002.......................................... 12.1 8.7
2003.......................................... 15.6 10.1
2004-2009..................................... 60.6 29.9
------ -----
$133.7 $88.7
====== =====

TRADING ACTIVITIES

The Company periodically enters into financial contracts in conjunction
with market-making or trading activities with the objective of achieving profits
through successful anticipation of movements in commodity prices and changes in
other market variables. Market-making positions are marked-to-market and gains
and losses are immediately included as revenue in the Consolidated Statement of
Income. In addition, the fair value of unsettled positions is immediately
included in the Consolidated Statement of Financial Position as a current asset
or current liability. The net pretax loss recorded in the Consolidated Statement
of Income related to these activities for the year ended December 31, 1998, was
$1.8 million. The following table summarizes the Company's open positions as of
December 31, 1998:

WEIGHTED
AVG. PRICE
CONTRACT PER MCF FAIR VALUE
PRODUCT TYPE TIME PERIOD VOLUME OR BBL (MILLIONS)
- ------- ---- ----------- ------ ---------- ----------

Gas Futures/swaps purchased Jan 99-Dec 99 8.2 Bcf $ 2.28 $ (3.2)
Gas Futures/swaps sold Jan 99-Dec 99 8.3 Bcf 2.13 3.0
Oil Futures/swaps purchased Jan 99-Jun 99 512 MBbl 16.74 (2.0)
Oil Futures/swaps sold Jan 99-Jun 99 543 MBbl 17.13 2.4
------
$ 0.2
======

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33

INTEREST RATE RISK AND INTEREST RATE SWAPS

The table below summarizes maturities for the Company's fixed and variable
rate debt. Variable rate debt consists of commercial paper and bankers
acceptances that are generally tied to the London Interbank Offered Rate
("LIBOR"). If interest rates on the Company's variable rate debt increase or
decrease by one percentage point, the Company's annual pretax income would
decrease or increase by $23.5 million.

1999 2000 2001 2002 2003 THEREAFTER
------ ---- ---- ------ ---- ----------
(IN MILLIONS)

Variable Rate................................. $851.9 -- -- -- -- $1,500.0
Fixed Rate.................................... 1.9 $2.0 $2.1 $252.3 $2.4 1,986.1
------ ---- ---- ------ ---- --------
Total............................... $853.8 $2.0 $2.1 $252.3 $2.4 $3,486.1
====== ==== ==== ====== ==== ========

The Company periodically enters into rate swaps and contracts to hedge
certain interest rate transactions. As of December 31, 1998, the Company had no
interest rate swap positions open. During 1998, the Company entered into rate
lock contracts to hedge interest rates related to a contemplated bond issuance.
The bonds were not issued and the Company recognized a $14.3 million pretax loss
in 1998 associated with these contracts.

FOREIGN CURRENCY RISK

The Company's Canadian subsidiary uses the Canadian dollar as its
functional currency, and the Latin American subsidiaries use the U.S. dollar as
their functional currency. To the extent that business transactions in these
countries are not denominated in the respective country's functional currency,
the Company is exposed to foreign currency exchange rate risk. In addition, in
these subsidiaries, certain asset and liability balances are denominated in
currencies other than the subsidiary's functional currency. These asset and
liability balances must be remeasured in the preparation of the subsidiary
financial statements using a combination of current and historical exchange
rates, with any resulting remeasurement adjustments included in net income.

At December 31, 1998, the Company's Canadian subsidiary had outstanding
$650 million of fixed rate notes and debentures denominated in U.S. dollars.
During 1998, the Company recognized a $46.5 million pretax non-cash loss
associated with remeasurement of this debt. The potential foreign currency
remeasurement impact on earnings from a five percent change in the year-end
Canadian exchange rate would be approximately $32 million.

At December 31, 1998, Latin American subsidiaries had foreign deferred tax
liabilities denominated in the local currency, equivalent to $159.6 million in
Venezuela and $58.0 million in Guatemala. During 1998, the Company recognized
deferred tax benefits of $15.2 million and $7.3 million after tax, respectively,
associated with remeasurement of the Venezuelan and Guatemalan deferred tax
liabilities. The potential foreign currency remeasurement impact on net earnings
from a five percent change in the year-end Latin American exchange rates would
be approximately $11 million.

The Company periodically enters into foreign currency contracts to hedge
specific currency exposures from commercial transactions. The following table
summarizes the Company's open foreign currency positions at December 31, 1998:

NOTIONAL AMOUNT FAIR VALUE
YEAR (US$ MILLIONS) FORWARD RATE (US$ MILLIONS)
- ---- --------------- ------------ --------------

1999............................... $168.0 C$1.3578 $(18.5)
2000............................... 8.0 C$1.3750 (0.8)
2004............................... 70.0 C$1.3630 (6.0)
------ ------
$246.0 $(25.3)
====== ======

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34

As a result of the Norcen Acquisition, the Company acquired foreign
currency forward exchange contracts with a $643 million notional amount and
maturities through October 2004, and recorded a $15.5 million deferred liability
representing the fair value of these contracts. This liability will be amortized
over the terms of the applicable contracts. The unrecognized loss on foreign
currency contracts at December 31, 1998, excluding the $6.8 million remaining
unamortized deferred liability, was $18.5 million.

CREDIT RISK

Credit risk is the risk of loss as a result of nonperformance by
counterparties of their contractual obligations. Because the loss can occur at
some point in the future, a potential exposure is added to the current
replacement value to arrive at a total expected credit exposure. The Company has
established methodologies to determine limits, monitor and report
creditworthiness and concentrations of credit to reduce such credit risk. At
December 31, 1998, the Company's largest credit risk associated with any single
financial counterparty, represented by the net fair value of open contracts, was
$2.6 million.

In connection with the sale of the GPM segment, the Company entered into a
long-term sales agreement with Duke, which obligates the Company to sell the
majority of its domestic natural gas and NGLs to Duke for a five-year period
beginning on the closing date of the sale. Prices received will be tied to the
current market price for each product. As a result, a significant portion of the
Company's credit risk will be with a single customer. Duke is currently
considered a good credit risk; however, periodic credit evaluations will
continue. Further, due to certain agreements with Duke, letter of credit and/or
other assurances can be demanded under certain circumstances.

PERFORMANCE RISK

Performance risk results when a counterparty fails to fulfill its
contractual obligations such as commodity pricing or volume commitments.
Typically, such risk obligations are defined within the trading agreements. The
Company utilizes its credit risk methodology to manage performance risk.

OTHER MATTERS

ENVIRONMENTAL COSTS

The Company generates and disposes of hazardous and nonhazardous waste in
its current and former operations, and is subject to increasingly stringent
federal, state, local, provincial and international environmental regulations.
The Company has identified seven sites currently subject to environmental
response actions or on the Superfund National Priorities List or state superfund
lists, at which it is or may be liable for remediation costs associated with
alleged contamination or for violations of environmental requirements. Certain
federal legislation imposes joint and several liability for the remediation of
various sites; consequently, the Company's ultimate environmental liability may
include costs relating to other parties in addition to costs relating to its own
activities at each site. In addition, the Company is or may be liable for
certain environmental remediation matters involving existing or former
facilities.

As of December 31, 1998, long and short-term liabilities totaling $74.7
million had been accrued for future costs of all sites where the Company's
obligation is probable and where such costs can be reasonably estimated;
however, the ultimate cost could be lower or higher. This accrual includes
future costs for remediation and restoration of sites, as well as for ongoing
monitoring costs, but excludes any anticipated recoveries from third parties.
The accrual also includes $37.0 million for the obligation to participate in the
remediation of the Wilmington, California field properties. Cost estimates were
based on information available for each site, financial viability of other
Potentially Responsible Parties ("PRPs") and existing technology, laws and
regulations. The Company believes that it has accrued adequately for its share
of costs at sites subject to joint and several liabilities. The ultimate
liability for remediation is difficult to determine with certainty because of
the number of PRPs involved, site-specific cost sharing arrangements with other
PRPs, the degree of contamination by various wastes, the scarcity and quality of
volumetric data related to many of the sites and the speculative nature of
remediation costs.
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35

The Company also is involved in reducing emissions, spills and migration of
hazardous materials. Remediation of identified sites and control and prevention
of environmental exposures required spending of $17.0 million in 1998 and $14.7
million in 1997. In 1999, the Company anticipates spending a total of $17.0
million for remediation, control and prevention, including $8.0 million relating
to the Wilmington, California properties. The majority of the accrued
environmental liability as of December 31, 1998, is expected to be paid out over
the next five years, funded by cash generated from operations. Based on current
rules and regulations, management does not expect future environmental
obligations to have a material impact on the results of operations or financial
condition of the Company.

YEAR 2000 ISSUE

The Company has established a formal Year 2000 Readiness Program to address
the Company's issues relating to the Year 2000. Program activities are directed
by a Program Management Office staffed with a Year 2000 Program Manager, several
senior Information Technology ("IT") and engineering project managers and
representatives from key internal functions including exploration and
production, operations, purchasing, finance and legal. The Program Management
Office operates under the oversight of a Year 2000 Executive Steering Committee
and the Audit Committee of the Board of Directors. The Company has engaged CSC
Consulting ("CSC") during the inventory and assessment phases of the program and
continues to make use of CSC services for program management recommendations and
reviews. The Company has also engaged the law firm of Morgan, Lewis & Bockius
LLP for legal advice on Year 2000 related issues.

The general phases for the Company's Year 2000 Readiness Program are (1)
inventory of Year 2000 items; (2) assessment of business criticality and
compliance status of inventory items; (3) remediation and verification planning
for items determined to be material to the company; (4) remediation (including
repairing, retiring, replacing or preparing work-arounds) of material items that
are determined not to be Year 2000 compliant; (5) verification that material
items are Year 2000 compliant; and (6) deployment of corrected items into the
ongoing business environment.

The Company's Year 2000 Readiness Program is organized around the following
major areas:
- IT infrastructure
- Information systems
- Process control and embedded technology
- Third party suppliers, partners, customers and governmental entities

In the IT infrastructure area, 17 readiness projects have been designated
as having a "high" criticality. Fourteen of these 17 projects (82%) have
completed the remediation and verification phases. Thirteen of these 17 (76%)
have completed the deployment phase as well. The Company anticipates that the
"high" criticality readiness projects in this area will be completed during the
first quarter of 1999. Remaining activity in this area primarily involves
installing and testing upgrades and software releases supplied by vendors.

In the information systems program area, forty-one systems have been
designated as having "high" criticality. The remediation, verification and
deployment phases have been completed for thirty-five (85%) of these systems.
One system is currently being upgraded to a new release, already received from
the vendor. The remaining 5 critical systems are awaiting version upgrades from
a single vendor. Remaining effort in this area primarily involves installing and
testing new releases of application software packages when they are made
available by software vendors. The Company anticipates that the remaining
systems in this area will be complete by June 30, 1999.

In the process control and embedded technology area, project teams and
vendors are in the process of completing the remediation and verification
planning phases and have commenced the remediation phase. Remaining activity in
this area primarily involves implementing software upgrades to selected
equipment and verifying the Year 2000 readiness of process control and embedded
technology equipment. The Company anticipates completion by mid-1999 of both the
remediation and verification phases at each location.

In the third-party suppliers, partners, customers and governmental entities
program area, the Company is continuing the process of monitoring and assessing
the readiness of third parties. Approximately 400 third-

33
36

party entities have been contacted in writing concerning their Year 2000 plans
and readiness. The Company has also begun the process of monitoring SEC mandated
disclosures of third parties. Remaining work includes follow-up evaluations of
the readiness of "mission critical" third-party dependencies. Emphasis in this
area has also shifted to begin formal business contingency planning.

In the fourth quarter of 1998, the Company began a formal process for
business contingency planning that spans all of the above readiness program
areas. This process includes, for each business area, (i) identifying critical
dependencies, (ii) assessing exposures, (iii) identifying controllable vs.
non-controllable factors and (iv) developing proactive prevention plans and
reactive response plans. The Company anticipates completing such business
contingency plans by mid-year 1999. To incorporate the changes in status
information available from third parties, periodic updates of these contingency
plans are scheduled for September and November, 1999.

The total cost of the Company's Year 2000 Readiness Program is not expected
to be material to the Company's financial position. Not including the cost of
replacing its information systems between 1993 and 1997, the Company anticipates
spending a total of between $2.5 million and $3.0 million dollars during 1998
and 1999 for Year 2000 related modifications and testing. This estimate does not
include the Company's potential share of Year 2000 costs that may be incurred by
partnerships and joint ventures in which the Company participates but is not the
operator.

Due to the general uncertainty inherent in the Year 2000 problem, resulting
in large part from the uncertainty of the Year 2000 readiness of third-party
suppliers, partners and customers, the Company is unable to determine at this
time whether the consequences of Year 2000 failures will have a material impact
on the Company's results of operations, liquidity or financial condition. The
Company's Year 2000 Readiness Program is expected to significantly reduce the
Company's level of uncertainty about Year 2000 issues. The Company believes
that, with the completion of the Year 2000 Readiness Program, the possibility of
significant interruptions of normal operations should be reduced.

The Company believes that the "most reasonably likely worst case" scenarios
are as follows: (i) unanticipated Year 2000 induced failures in information
systems could cause a reliance on manual contingency procedures and
significantly reduce efficiencies in the performance of certain normal business
activities; (ii) unanticipated failures in embedded technology or process
control systems due to Year 2000 causes could result in temporarily suspending
operations at certain operating facilities with consequent loss of revenue; and
(iii) slow downs or disruptions in the third party supply chain due to Year 2000
causes could result in operational delays and reduced efficiencies in the
performance of certain normal business activities.

FORWARD LOOKING INFORMATION

Certain information included in this report, and other materials filed or
to be filed by the Company with the SEC (as well as information included in oral
statements or other written statements made or to be made by the Company)
contain projections and forward looking statements within the meaning of Section
21E of the Securities Exchange Act of 1934, as amended, and Section 27A of the
Securities Act of 1933, as amended. Such forward looking statements may be or
may concern, among other things, capital expenditures, drilling activity,
acquisitions and dispositions (including the timing of the completion of the
Company's deleveraging program), development activities, cost savings efforts,
production activities and volumes, hydrocarbon reserves, hydrocarbon prices,
hedging activities and the results thereof, liquidity, regulatory matters and
competition. Such forward looking statements generally are accompanied by words
such as "estimate," "expect," "predict," "anticipate," "goal," "should,"
"assume," "believe" or other words that convey the uncertainty of future events
or outcomes.

Such forward looking information is based upon management's current plans,
expectations, estimates and assumptions and is subject to a number of risks and
uncertainties that could significantly affect current plans, anticipated
actions, the timing of such actions and the Company's financial condition and
results of operations. As a consequence, actual results may differ materially
from expectations, estimates or assumptions expressed in or implied by any
forward looking statements made by or on behalf of the Company. The risks and

34
37

uncertainties include generally the volatility of oil, gas and hydrocarbon-based
financial derivative prices; basis risk and counterparty credit risk in
executing hydrocarbon price risk management activities; economic, political,
judicial and regulatory developments; competition in the oil and gas industry as
well as competition from other sources of energy; the economics of producing
certain reserves; demand and supply of oil and gas; the ability to find or
acquire and develop reserves of natural gas and crude oil; and the actions of
customers and competitors. Additionally, unpredictable or unknown factors not
discussed herein could have material adverse effects on actual results related
to matters which are the subject of forward looking information.

With respect to expected capital expenditures and drilling activity,
additional factors such as oil and gas prices and the ability to achieve debt
repayment objectives, the extent of the Company's success in acquiring oil and
gas properties and in identifying prospects for drilling, the availability of
acquisition opportunities which meet the Company's objectives as well as
competition for such opportunities, exploration and operating risks, the success
of management's cost reduction efforts and the availability of technology may
affect the amount and timing of such capital expenditures and drilling activity.
With respect to the Company's deleveraging program, factors such as the ability
to identify qualified buyers, the buyer's ability to obtain financing (if
necessary), successful negotiation of contract terms and completion of due
diligence may affect the success and timing of the completion of the program.
With respect to expected growth in production and sales volumes and estimated
reserve quantities, factors such as the extent of the Company's success in
finding, developing and producing reserves, the timing of capital spending,
deleveraging programs, uncertainties inherent in estimating reserve quantities
and the availability of technology may affect such production volumes and
reserve estimates.

With respect to liquidity, factors such as the state of domestic capital
markets, credit availability from banks or other lenders and the Company's
results of operations may affect management's plans or ability to incur
additional indebtedness. With respect to cash flow and the ability to reduce
debt, factors such as changes in oil and gas prices, the Company's success in
acquiring properties or divesting producing properties, the GPM segment or other
assets, environmental matters and other contingencies, hedging activities and
the Company's credit rating and debt levels may affect the Company's ability to
generate expected cash flows. With respect to contingencies, factors such as
changes in environmental and other governmental regulation, and uncertainties
with respect to legal matters may affect the Company's expectations regarding
the potential impact of contingencies on the operating results or financial
condition of the Company. Certain factors, such as changes in oil and gas prices
and underlying demand and the extent of the Company's success in exploiting its
current reserves and acquiring or finding additional reserves may have pervasive
effects on many aspects of the Company's business in addition to those outlined
above.

35
38

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

PAGE
----

Responsibilities for Financial Statements................... 37
Reports of Independent Public Accountants................... 38
Consolidated Statements of Income and Comprehensive Income
for the Years Ended December 31, 1998, 1997 and 1996...... 40
Consolidated Statements of Financial Position as of December
31, 1998 and 1997......................................... 41
Consolidated Statements of Cash Flows for the Years Ended
December 31, 1998, 1997 and 1996.......................... 42
Consolidated Statements of Changes in Shareholders' Equity
for the Years Ended December 31, 1998, 1997 and 1996...... 43
Business Segment Information for the Years Ended December
31, 1998, 1997 and 1996................................... 44
Notes to Consolidated Financial Statements.................. 45
Supplementary Information (Unaudited)....................... 71

36
39

RESPONSIBILITIES FOR FINANCIAL STATEMENTS

The accompanying financial statements, which consolidate the accounts of
Union Pacific Resources Group Inc. and its subsidiaries, have been prepared in
conformity with generally accepted accounting principles.

The integrity and objectivity of data in these financial statements and
accompanying notes, including estimates and judgments related to matters not
concluded by year-end, are the responsibility of management, as is all other
information in this report. Management devotes ongoing attention to the review
and appraisal of its system of internal controls. This system is designed to
provide reasonable assurance, at an appropriate cost, that the Company's assets
are protected, that transactions and events are recorded properly and that
financial reports are reliable. The system is augmented by a staff of internal
auditors; careful attention to the selection and development of qualified
financial personnel; programs to further timely communication and monitoring of
policies, standards and delegated authorities; and evaluation by independent
auditors during their examinations of the annual financial statements.

The Audit Committee of the Board of Directors, composed of four
non-employee directors, meets regularly with financial management, the internal
auditors and the independent auditors to review financial reporting and
accounting and financial controls of the Company. Both the independent auditors
and the internal auditors have unrestricted access to the Audit Committee and
meet regularly with the Audit Committee, without financial management
representatives present, to discuss the results of their examinations and their
opinions on the adequacy of internal controls and quality of financial
reporting.

Jack L. Messman
Chairman and Chief Executive Officer

Morris B. Smith
Vice President and Chief Financial
Officer

37
40

REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS

To the Board of Directors
Union Pacific Resources Group Inc.
Fort Worth, Texas

We have audited the accompanying consolidated statement of financial
position of Union Pacific Resources Group Inc. (a Utah Corporation) and
subsidiaries ("the Company") as of December 31, 1998, and the related
consolidated statements of income and comprehensive income, changes in
shareholders' equity and cash flows for the year then ended. These financial
statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements based on
our audit.

We conducted our audit in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audit provides a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly,
in all material respects, the financial position of the Company as of December
31, 1998, and the results of its operations and its cash flows for the year then
ended in conformity with generally accepted accounting principles.

We have also audited the adjustments related to discontinued operations
described in Note 3 that were applied to restate the 1997 and 1996 financial
statements. In our opinion, such adjustments are appropriate and have been
properly applied.

ARTHUR ANDERSEN LLP
Fort Worth, Texas
January 25, 1999

38
41

INDEPENDENT AUDITORS' REPORT

To the Board of Directors
Union Pacific Resources Group Inc.
Fort Worth, Texas

We have audited the accompanying consolidated statements of financial
position of Union Pacific Resources Group Inc. ("the Company") as of December
31, 1997, and the related consolidated statements of income, changes in
shareholders' equity and cash flows for each of the two years in the period
ended December 31, 1997 (which have been restated and are no longer presented
herein). These financial statements are the responsibility of the Company's
management. Our responsibility is to express an opinion on these financial
statements based on our audits.

We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in
all material respects, the consolidated financial position of the Company as of
December 31, 1997, and the results of its operations and its cash flows for each
of the two years in the period ended December 31, 1997 in conformity with
generally accepted accounting principles.

DELOITTE & TOUCHE LLP
Fort Worth, Texas
January 26, 1998

39
42

UNION PACIFIC RESOURCES GROUP INC.

CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
FOR THE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996

1998 1997 1996
--------- -------- --------
(MILLIONS, EXCEPT PER SHARE
AMOUNTS)

Operating revenues:
Producing properties...................................... $ 1,539.2 $1,293.5 $1,148.2
Other oil and gas revenues................................ 160.7 84.7 92.1
Minerals (Note 8)......................................... 141.1 139.8 128.9
--------- -------- --------
Total operating revenues.......................... 1,841.0 1,518.0 1,369.2
--------- -------- --------
Operating expenses:
Production................................................ 444.3 300.8 263.2
Exploration............................................... 339.0 204.7 144.6
Minerals (Note 8)......................................... 3.5 3.4 8.0
Depreciation, depletion and amortization (Note 6)......... 2,125.6 504.0 478.0
General and administrative................................ 104.8 71.2 66.9
Restructuring charge (Note 4)............................. 17.0 -- --
--------- -------- --------
Total operating expenses.......................... 3,034.2 1,084.1 960.7
--------- -------- --------
Operating income (loss)..................................... (1,193.2) 433.9 408.5
Other income (expense) -- net (Notes 3 and 17)............ (45.3) 24.5 (3.5)
Interest expense -- net (Notes 3 and 10).................. (249.8) (39.5) (38.9)
--------- -------- --------
Income (loss) from continuing operations before income
taxes..................................................... (1,488.3) 418.9 366.1
Income tax (expense) benefit (Note 9)....................... 605.2 (115.8) (112.4)
--------- -------- --------
Income (loss) from continuing operations.................... (883.1) 303.1 253.7
Income (loss) from discontinued operations (Note 3)......... (15.6) 29.9 67.1
--------- -------- --------
Net income (loss)........................................... $ (898.7) $ 333.0 $ 320.8
========= ======== ========
Other comprehensive income, net of tax: (Note 16)
Foreign currency translation adjustments.................. $ (67.1) $ (5.3) $ (0.5)
Minimum pension liability................................. (3.9) (1.0) --
--------- -------- --------
Comprehensive income (loss)................................. $ (969.7) $ 326.7 $ 320.3
========= ======== ========
Earnings (loss) per share -- basic: (Note 16)
Continuing operations..................................... $ (3.57) $ 1.21 $ 1.02
Discontinued operations................................... (0.06) 0.12 0.27
--------- -------- --------
Total............................................. $ (3.63) $ 1.33 $ 1.29
--------- -------- --------
Earnings (loss) per share -- diluted: (Note 16)
Continuing operations..................................... $ (3.57) $ 1.21 $ 1.01
Discontinued operations................................... (0.06) 0.12 0.27
--------- -------- --------
Total............................................. $ (3.63) $ 1.33 $ 1.28
========= ======== ========
Weighted average shares outstanding -- diluted.............. 247.7 250.9 250.1
Cash dividends per share.................................... $ 0.20 $ 0.20 $ 0.20

The accompanying accounting policies and notes to the consolidated financial
statements are an integral part of these statements.

40
43

UNION PACIFIC RESOURCES GROUP INC.

CONSOLIDATED STATEMENTS OF FINANCIAL POSITION
AS OF DECEMBER 31, 1998 AND 1997

ASSETS

1998 1997
--------- ---------
(MILLIONS OF DOLLARS)

Current assets:
Cash and temporary investments............................ $ 8.8 $ 67.1
Accounts receivable (net of allowance for doubtful
accounts of $9.8 million in 1998 and $1.9 million in
1997).................................................. 261.0 252.1
Inventories............................................... 64.6 16.8
Other current assets...................................... 107.0 60.6
--------- ---------
Total current assets.............................. 441.4 396.6
--------- ---------
Properties: (Note 6)
Cost...................................................... 11,078.2 6,268.7
Accumulated depreciation, depletion and amortization...... (4,984.9) (3,367.6)
--------- ---------
Total properties.................................. 6,093.3 2,901.1
Intangible and other assets (Note 8)........................ 180.8 138.2
Net assets of discontinued operations (Note 3).............. 926.9 877.8
--------- ---------
Total assets...................................... $ 7,642.4 $ 4,313.7
========= =========

LIABILITIES AND SHAREHOLDERS' EQUITY

Current liabilities:
Accounts payable.......................................... $ 270.5 $ 274.7
Accrued taxes payable..................................... 64.9 59.5
Other current liabilities................................. 157.5 68.3
Short-term debt........................................... 853.8 --
--------- ---------
Total current liabilities......................... 1,346.7 402.5
Long-term debt (Note 10).................................. 3,744.9 1,230.6
Deferred income taxes (Note 9)............................ 1,291.6 552.9
Retiree benefits obligations (Note 12).................... 142.9 147.7
Other long-term liabilities (Notes 13, 14 and 15)......... 388.1 219.3
Shareholders' equity (see page 43)........................ 728.2 1,760.7
--------- ---------
Total liabilities and shareholders' equity........ $ 7,642.4 $ 4,313.7
========= =========

The accompanying accounting policies and notes to the consolidated financial
statements are an integral part of these statements.

41
44

UNION PACIFIC RESOURCES GROUP INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996

1998 1997 1996
--------- --------- -------
(MILLIONS OF DOLLARS)

Cash provided by operations:
Net income................................................ $ (898.7) $ 333.0 $ 320.8
Non-cash charges to income:
Depreciation, depletion and amortization............... 2,125.6 504.0 478.0
Deferred income taxes (Note 9)......................... (659.3) 110.9 (21.3)
(Income) loss from discontinued operations (Note 3).... 15.6 (29.9) (67.1)
Other non-cash charges (credits) -- net................ 240.7 (29.4) 7.9
Exploratory expenditures.................................. 115.2 76.9 51.6
Changes in current assets and liabilities................. 92.0 (109.3) 2.6
--------- --------- -------
Cash provided by operations....................... 1,031.1 856.2 772.5
--------- --------- -------
Investing activities:
Capital and exploratory expenditures (Note 7)............. (1,194.5) (1,188.4) (773.0)
Acquisition of company (Note 2)........................... (2,634.3) -- --
Proceeds from sales of assets (Note 3).................... 436.6 37.3 30.2
Proceeds from sales of investments........................ 48.4 -- --
Cash provided (used) by discontinued operations........... 50.4 (221.8) 113.5
Other investing activities -- net......................... -- (17.7) (2.8)
--------- --------- -------
Cash (used) by investing activities............... (3,293.4) (1,390.6) (632.1)
--------- --------- -------
Financing activities:
Dividends paid............................................ (49.6) (50.0) (49.8)
Proceeds from long-term debt issuance (Note 10)........... 1,025.0 -- 550.0
Other debt financing -- net (Note 10)..................... 1,294.5 559.6 (80.2)
Repurchase of common stock................................ (26.7) (52.3) (3.5)
Repayment of advances to Union Pacific Corporation........ -- -- (567.8)
Other financings -- net (Note 10)......................... (39.2) 30.4 105.1
--------- --------- -------
Cash provided (used) by financing activities...... 2,204.0 487.7 (46.2)
--------- --------- -------
Net change in cash and temporary investments................ (58.3) (46.7) 94.2
Balance at beginning of year................................ 67.1 113.8 19.6
--------- --------- -------
Balance at end of year...................................... $ 8.8 $ 67.1 $ 113.8
========= ========= =======
Changes in current assets and liabilities:
Accounts receivable....................................... $ 215.8 $ (33.2) $ (82.5)
Inventories............................................... (17.8) (1.5) 17.5
Other current assets...................................... 3.2 21.6 1.7
Accounts payable.......................................... (153.4) (21.4) 13.2
Accrued taxes payable..................................... 3.5 (73.4) 47.0
Other current liabilities................................. 40.7 (1.4) 5.7
--------- --------- -------
Total............................................. $ 92.0 $ (109.3) $ 2.6
========= ========= =======
Supplemental cash flow disclosure:
Interest paid:
Continuing operations.................................. $ 216.0 $ 42.7 $ 31.7
Discontinued operations................................ 21.1 13.6 11.7
Income taxes paid (recovered):
Continuing operations.................................. 81.0 121.0 97.9
Discontinued operations................................ (35.0) 8.7 (18.9)

The accompanying accounting policies and notes to the consolidated financial
statements are an integral part of these statements.

42
45

UNION PACIFIC RESOURCES GROUP INC.

CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS' EQUITY
FOR THE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996

1998 1997 1996
------- -------- --------
(MILLIONS OF DOLLARS)

Common stock, no par value; authorized 400,000,000 shares:
250,685,204 shares issued and outstanding at December 31,
1998
251,888,575 shares issued and outstanding at December 31,
1997
250,058,019 shares issued and outstanding at December 31,
1996
Balance at beginning and end of year...................... $ -- $ -- $ --
------- -------- --------
Paid-in surplus:
Balance at beginning of year.............................. 991.2 872.9 860.2
Conversion, award, forfeiture and appreciation of
retention shares (Note 16)............................. 0.5 5.1 15.9
Issuance of ESOP shares (Note 16)......................... -- 107.3 --
Exercise of stock options................................. 0.6 5.5 0.5
Other..................................................... 0.3 0.4 (3.7)
------- -------- --------
Balance at end of year.................................... 992.6 991.2 872.9
------- -------- --------
Retained earnings:
Balance at beginning of year.............................. 957.4 674.4 472.9
Net income (loss)......................................... (898.7) 333.0 320.8
------- -------- --------
Total............................................. 58.7 1,007.4 793.7
Dividends declared on common stock........................ (49.6) (50.0) (49.8)
Pension asset adjustment.................................. -- -- (69.5)
------- -------- --------
Balance at end of year.................................... 9.1 957.4 674.4
------- -------- --------
Unearned compensation:
Balance at beginning of year.............................. (11.8) (17.5) (9.2)
Conversion, award, appreciation and amortization of
retention shares -- net (Note 16)...................... 5.8 5.7 (8.3)
------- -------- --------
Balance at end of year.................................... (6.0) (11.8) (17.5)
------- -------- --------
ESOP (Note 16):
Balance at beginning of year.............................. (102.0) -- --
Issuance of ESOP shares................................... -- (107.3) --
Release of ESOP shares.................................... 6.3 5.3 --
------- -------- --------
Balance at end of year.................................... (95.7) (102.0) --
------- -------- --------
Treasury stock:
Balance at beginning of year.............................. (55.8) (3.5) --
Treasury stock repurchased, at cost....................... (26.7) (52.3) (3.5)
------- -------- --------
Balance at end of year
3,666,913 shares at December 31, 1998
2,379,625 shares at December 31, 1997
154,417 shares at December 31, 1996....... (82.5) (55.8) (3.5)
------- -------- --------
Comprehensive income:
Deferred foreign exchange adjustment:
Balance at beginning of year........................... (17.3) (12.0) (11.5)
Foreign currency translation adjustment................ (67.1) (5.3) (0.5)
------- -------- --------
Balance at end of year................................. (84.4) (17.3) (12.0)
------- -------- --------
Minimum pension liability (Note 12)....................... (4.9) (1.0) --
------- -------- --------
Total comprehensive income........................ (89.3) (18.3) (12.0)
------- -------- --------
Total shareholders' equity........................ $ 728.2 $1,760.7 $1,514.3
======= ======== ========

The accompanying accounting policies and notes to the consolidated financial
statements are an integral part of these statements.

43
46

UNION PACIFIC RESOURCES GROUP INC.

BUSINESS SEGMENT INFORMATION
FOR THE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996

1998 1997 1996
--------- -------- --------
(MILLIONS OF DOLLARS)

Revenues(a):
Exploration and production................................ $ 1,699.9 $1,378.2 $1,240.3
Minerals.................................................. 141.1 139.8 128.9
--------- -------- --------
Total revenues.................................... $ 1,841.0 $1,518.0 $1,369.2
========= ======== ========
Depreciation, depletion and amortization:
Exploration and production................................ $ 2,115.8 $ 499.3 $ 473.4
Minerals.................................................. 4.1 0.9 0.9
Corporate................................................. 5.7 3.8 3.7
--------- -------- --------
Total depreciation, depletion and amortization.... $ 2,125.6 $ 504.0 $ 478.0
========= ======== ========
Operating income(b):
Exploration and production................................ $(1,199.2) $ 373.4 $ 359.1
Minerals.................................................. 133.5 135.5 120.0
Corporate................................................. (127.5) (75.0) (70.6)
--------- -------- --------
Total operating income (loss)..................... $(1,193.2) $ 433.9 $ 408.5
========= ======== ========
Fixed assets -- net:
Exploration and production................................ $ 5,988.8 $2,827.1 $2,336.2
Minerals.................................................. 10.2 14.1 16.9
Corporate................................................. 94.3 59.9 51.6
--------- -------- --------
Total fixed assets -- net......................... $ 6,093.3 $2,901.1 $2,404.7
========= ======== ========
Capital and exploratory expenditures:
Exploration and Production................................ $ 3,796.2 $1,172.6 $ 763.5
Minerals.................................................. 0.1 1.4 0.8
Corporate................................................. 32.5 14.4 8.7
--------- -------- --------
Total capital and exploratory expenditures........ $ 3,828.8 $1,188.4 $ 773.0
========= ======== ========

GEOGRAPHIC INFORMATION

1998 1997 1996
--------- -------- --------
(MILLIONS OF DOLLARS)

Revenues(a):
United States............................................. $ 1,455.9 $1,477.2 $1,333.4
Canada.................................................... 259.0 28.9 23.3
Other international....................................... 126.1 11.9 12.5
--------- -------- --------
Total revenues.................................... $ 1,841.0 $1,518.0 $1,369.2
========= ======== ========
Fixed assets -- net:
United States............................................. $ 2,965.2 $2,800.9 $2,290.8
Canada.................................................... 1,854.0 89.8 96.4
Other international....................................... 1,274.1 10.4 17.5
--------- -------- --------
Total fixed asset -- net.......................... $ 6,093.3 $2,901.1 $2,404.7
========= ======== ========

- ---------------

The Company's reportable segments are strategic business units or an aggregation
of business units with similar operations and management objectives. The
reportable segments are managed separately because each segment requires
different operational assets, technology and management strategies.

(a) 1998, 1997 and 1996 revenues include income from equity affiliates of
$89.7 million, $74.4 million and $74.5 million, respectively, for the
minerals segment.

(b) Segment operating income for the corporate segment consists primarily of
general and administrative expense.

This information should be read in conjunction with the accompanying
accounting policies and notes to the consolidated financial statements.

44
47

UNION PACIFIC RESOURCES GROUP INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

SIGNIFICANT ACCOUNTING POLICIES

Principles of Consolidation. The Consolidated Financial Statements include
the accounts of Union Pacific Resources Group Inc., a Utah Corporation, and
subsidiaries (collectively, the "Company"), including its principal operating
subsidiary Union Pacific Resources Company ("UPRC"). The Company accounts for
investments in affiliated companies (20% to 50% owned) on the equity method of
accounting. The Company also consolidates its pro-rata share of oil and gas
joint ventures. All significant intercompany transactions are eliminated. The
consolidated financial statements for previous periods include certain
reclassifications that were made to conform to the current presentation. Such
reclassifications have no effect on previously reported net income. Refer to the
accompanying notes to the financial statements for additional disclosure of the
Company's significant accounting policies.

As a result of the Company's announcement to sell its gathering, processing
and marketing business ("GPM") segment, the GPM segment has been accounted for
as a discontinued operation. GPM results of operations have been excluded from
continuing operations in the consolidated statements of income and cash flows.
GPM net assets have been segregated from continuing operations in the
accompanying statements of financial position and reported as net assets of
discontinued operations. Some prior year amounts have been restated to conform
to the current presentation.

Use of Estimates. The preparation of financial statements in conformity
with generally accepted accounting principles requires management to make
estimates and assumptions that affect the reported amounts of certain assets and
liabilities and disclosure of contingent assets and liabilities at the date of
the financial statements and the reported amounts of revenues and expenses
during each reporting period. Management believes its estimates and assumptions
are reasonable; however, such estimates and assumptions are subject to a number
of risks and uncertainties which may cause actual results to differ materially
from the Company's estimates. Significant estimates underlying these financial
statements include the estimated quantities of proved oil and gas reserves and
the related present value of estimated future net cash flows therefrom (see
Supplementary Information beginning on page 71).

Cash and Temporary Investments. Temporary investments are stated at cost
which approximates fair market value, and consist of investments with original
maturities of three months or less.

Inventories. Inventories consist primarily of hydrocarbon volumes and
materials and supplies, carried on a first-in first-out basis at the lower of
cost or market.

Oil and Gas Properties. Oil and gas properties are accounted for using the
successful efforts method. Under this method, exploration costs (drilling costs
of unsuccessful exploration wells, geological and geophysical costs,
non-producing leasehold amortization and delay rentals) are charged to expense
when incurred. Costs to develop producing properties, including drilling costs
and applicable leasehold acquisition costs, are capitalized. Costs to drill
exploratory wells that result in additions to reserves are also capitalized.

Depreciation, depletion and amortization of producing properties, including
depreciation of well and support equipment and amortization of related lease
costs, are determined by using a unit of production method based upon estimated
proved reserves. Acquisition costs of unproved properties are amortized from the
date of acquisition on a composite basis, which considers past success
experience and average lease life. Provisions for depreciation of property and
equipment other than producing properties are computed principally on the
straight-line method based on estimated service lives, which range from two to
15 years. Potential impairment of producing properties and significant unproved
properties is assessed annually on a field-by-field basis; all other unproved
properties are assessed annually on an aggregate basis (see Note 6).

Costs of future site restoration, dismantlement and abandonment for
producing properties are accrued as part of depreciation, depletion and
amortization expense for tangible equipment by assuming no salvage value in the
calculation of the unit of production rate. Additional costs are accrued for
offshore and Canadian wells

45
48
UNION PACIFIC RESOURCES GROUP INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

based on internal engineering estimates using the unit of production method with
a charge to depreciation, depletion and amortization expense. The balance of the
abandonment accrual at December 31, 1998 and 1997 was $62.1 million and $11.6
million, respectively. The increase was due primarily to the acquisition of
Norcen.

Gains or losses on retired, sold or abandoned properties that constitute
part of an amortization base are deferred by charging or crediting, net of
proceeds, to accumulated depreciation, depletion and amortization unless such
nonrecognition would significantly affect the unit of production rate. Gains or
losses from the disposition of other properties are recognized currently. Gains
and losses from the sale of operating assets that constitute an entire profit
center and significant nonoperating assets are recorded in other income. Gains
and losses from all other dispositions of operating assets are recognized in
other oil and gas revenues.

Goodwill. Intangible and other assets includes goodwill of $68.6 million
arising from business combinations prior to 1971. Such goodwill is not being
amortized because it is considered to have continuing value over an indefinite
period. The value of goodwill is periodically evaluated to determine whether any
potential impairment exists.

Income Taxes. Deferred taxes are established for all temporary differences
between the book and tax bases of assets and liabilities. In addition, deferred
tax balances must be adjusted to reflect tax rates that will be in effect in the
years in which the temporary differences are expected to reverse. Non-U.S.
subsidiaries compute taxes at rates in effect in the various countries. Earnings
of these subsidiaries may also be subject to additional income and withholding
taxes when they are distributed as dividends. Deferred tax liabilities are not
recognized on profits that are expected to be permanently reinvested by the
local subsidiaries and thus not considered available for distribution to the
parent Company. As of December 31, 1998, the Company's non-U.S. subsidiaries
have not recognized operating profits and, therefore, no undistributed earnings
are available.

Revenue Recognition. Sales from producing gas wells are recognized on the
entitlement method of accounting which defers recognition of sales when, and to
the extent that, deliveries to customers exceed the Company's net revenue
interest in production. Similarly, when deliveries are below the Company's net
revenue interest in production, sales are recorded to reflect the full net
revenue interest. The Company's net gas imbalance at December 31, 1998 was
immaterial. Crude marketing revenue, included in other oil and gas revenue, is
recorded net of the cost of crude oil purchased.

Recently issued accounting standards. In June 1998, the Financial
Accounting Standards Board issued Statement of Financial Accounting Standards
No. 133 "Accounting for Derivative Instruments and Hedging Activities" ("SFAS
No. 133"), which is effective for fiscal years beginning after June 15, 1999.
This statement requires that all derivatives be recognized on the balance sheet
and measured at fair value. If certain conditions are met, a derivative may be
specifically designated as a hedge and be eligible for special accounting
treatment. However, the special accounting treatment afforded hedge transactions
may delay the recognition of a portion of the gain or loss on the derivative,
which would later be recorded concurrent with the gain or loss on the item being
hedged. For derivatives not designated as hedges, gains or losses are recognized
in earnings in the period of change. The impact of the statement on the Company
will depend upon price volatility and the level of open derivative positions at
the end of a reporting period. The Company plans to adopt SFAS No. 133 for the
first quarter of the year ending December 31, 2000 and is currently evaluating
the effects of this pronouncement. Adoption will require the Company to begin
recording unrealized gains and losses in the statement of financial position and
in comprehensive income.

46
49
UNION PACIFIC RESOURCES GROUP INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

1. NATURE OF OPERATIONS

The Company is an independent oil and gas company engaged primarily in the
exploration for and development and production of natural gas and crude oil in
several major basins in the United States, Canada, Guatemala, Venezuela and
other international areas. The Company markets all of its crude oil production
together with significant volumes of crude oil produced by others. In 1998, the
Company marketed a substantial portion of its natural gas and natural gas
liquids ("NGLs"); however, the Company will enter into a long-term gas sales
agreement to sell a substantial portion of its natural gas and NGLs to another
company in connection with the pending sale of the GPM segment (see Note 3). In
addition, the Company engages in the hard minerals business through non-operated
joint venture and royalty interests in several coal and trona (natural soda ash)
mines.

The Company's results of operations are largely dependent on the difference
between the prices received for its hydrocarbon products and the cost to find,
develop, produce and market such resources. Hydrocarbon prices are subject to
fluctuations in response to changes in supply, market uncertainty and a variety
of factors beyond the control of the Company. These factors include worldwide
political instability, the foreign supply of oil and natural gas, the price of
foreign imports, the level of consumer demand and the price and availability of
alternative fuels. Historically, the Company has been able to manage a portion
of the operating risk relating to hydrocarbon price volatility through hedging
activities (see Note 5).

2. ACQUISITIONS

Norcen Energy Resources Limited. On January 25, 1998, the Company and Union
Pacific Resources Inc. ("UPRI"), an Alberta corporation and a wholly-owned
subsidiary of the Company, entered into a pre-acquisition agreement
("Pre-acquisition Agreement") with Norcen Energy Resources Limited ("Norcen").
Under the Pre-acquisition Agreement, the Company and UPRI agreed to make an
offer (the "Tender Offer") for up to 100 percent of the common shares of Norcen,
subject to certain conditions. On March 3, 1998, the Company announced the
closing of the Tender Offer. In total, 95.5 percent of the outstanding common
shares of Norcen were tendered at a purchase price of U.S. $13.65 per share.

On March 5, 1998, UPRI completed the compulsory acquisition of the
remaining common shares outstanding which were not tendered. (The closing of the
Tender Offer and completion of the compulsory acquisition is referred to as the
"Norcen Acquisition.") The aggregate purchase price for the Norcen Acquisition,
including non-recurring transaction costs of $28.1 million, was $2.634 billion.
In addition, the Company assumed the long-term debt obligations of Norcen.

Norcen operations primarily consisted of oil and gas exploration and
development operations in western Canada, the Gulf of Mexico, Guatemala and
Venezuela.

The Company funded the purchase price of the Norcen Acquisition through the
issuance of commercial paper, supported by a U.S. $2.7 billion 364-day
Competitive Advance/Revolving Credit Agreement dated March 2, 1998. In
accordance with Accounting Principles Board Opinion No. 16, "Business
Combinations," the Norcen Acquisition was accounted for as a purchase effective
March 3, 1998.

The following table represents the revised preliminary allocation of the
total purchase price of the assets acquired and liabilities assumed, based upon
their fair values on the date of the Norcen Acquisition and pushed down to the
acquired Company. In accordance with SFAS 109, a deferred tax liability was
recognized for the differences between the allocated values and the tax bases of
the acquired assets and liabilities. Any

47
50
UNION PACIFIC RESOURCES GROUP INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

additional adjustments to the allocation of the purchase price are not
anticipated to be material to the consolidated financial statements of the
Company.

(MILLIONS OF DOLLARS)

Working capital............................................. $ 114.4
Property, plant and equipment............................... 4,931.2
Other assets................................................ 228.2
Long-term debt.............................................. (1,012.0)
Deferred taxes.............................................. (1,495.7)
Other non-current liabilities............................... (131.8)
---------
Total purchase price.............................. $ 2,634.3
=========

The following table presents unaudited pro forma condensed consolidated
statements of income of the Company for the twelve months ended December 31,
1998 and 1997, as though the Norcen Acquisition had occurred on January 1, 1997.
Certain adjustments were made to the financial information to conform to the
accounting policies and financial statement presentation of the Company. Prior
year amounts have been restated to reflect the Company's current presentation
for discontinued operations.

TWELVE MONTHS ENDED
DECEMBER 31,
-------------------------
1998 1997
----------- ----------
(MILLIONS OF DOLLARS,
EXCEPT PER SHARE AMOUNTS)

Revenues.................................................... $ 1,940.8 $2,169.3
Costs and expenses.......................................... 3,165.2 1,810.4
--------- --------
Operating income (loss)..................................... (1,224.4) 358.9
Interest expense............................................ (284.3) (240.1)
Other income (expense) -- net............................... (45.3) 24.5
--------- --------
Income (loss) before income taxes........................... (1,554.0) 143.3
Income tax benefit (expense)................................ 629.4 (24.5)
--------- --------
Income (loss) from continuing operations.................... $ (924.6) $ 118.8
========= ========
Earnings (loss) per share -- basic and diluted
Continuing operations..................................... $ (3.73) $ 0.47

The unaudited pro forma condensed consolidated information presented above
is not necessarily indicative of the results of operations which would have
occurred had the Norcen Acquisition been consummated on January 1, 1997, nor is
it necessarily indicative of future results of operations of the Company.

Norcen Summarized Financial Information. Shortly after the Norcen
Acquisition, Norcen was amalgamated with UPRI (the "Amalgamation"). Prior to the
Amalgamation, UPRI's operations primarily consisted of oil and gas operations in
western Canada. After the Amalgamation, certain non-Canadian international
assets were or will soon be distributed or contributed from UPRI to other
subsidiaries of the Company.

As a result of the Amalgamation, UPRI assumed the obligations of Norcen,
including the public debt obligations of Norcen (the "Debt Securities"). The
Debt Securities include 6.8% Debentures due July 2, 2002, in the aggregate
principal amount of $250 million, 7 3/8% Debentures due May 15, 2006, in the
aggregate principal amount of $250 million and 7.8% Debentures due July 2, 2008
in the aggregate principal amount of $150 million, each of which have been fully
and unconditionally guaranteed by the Company.

48
51
UNION PACIFIC RESOURCES GROUP INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The following table presents summarized financial information for UPRI (as
successor to Norcen) as of and for the two months ended February 28, 1998, and
ten months ended December 31, 1998. This summarized financial information is
being provided pursuant to Section G of Topic 1 of Staff Accounting Bulletin No.
53 -- "Financial Statement Requirements in Filings Involving the Guarantee of
Securities by a Parent." The Company will continue to provide such summarized
financial information for UPRI as long as the Debt Securities remain outstanding
and guaranteed by the Company.

TWO MONTHS ENDED TEN MONTHS ENDED
FEBRUARY 28, 1998(a) DECEMBER 31, 1998(b)
-------------------- --------------------
(MILLIONS OF DOLLARS) (MILLIONS OF DOLLARS)

Summarized Statement of Income Information:
Operating revenues............................ $ 104.0 $ 357.2
Operating income (loss)....................... 4.0 (784.5)
Net loss...................................... $ (30.0)(c) $ (508.3)(d)
Summarized Statement of Financial Position Information:
Current assets................................ $ 275.6 $ 53.7
Non-current assets............................ 2,456.2 1,882.3
Current liabilities........................... 182.6 279.8
Non-current liabilities and equity............ $2,549.2 $1,656.2

- ---------------
(a) Results for Norcen as of and for the two months ended February 28, 1998.
Results have not been restated in accordance with U.S. generally accepted
accounting principles ("GAAP") and reflect the full cost method for
accounting for oil and gas operations.

(b) Results for UPRI as of and for the ten months ended December 31, 1998,
include adjustments to reflect U.S. GAAP and the successful efforts method
of accounting. Adjustments to reflect the application of the purchase
method of accounting for the Norcen Acquisition are included effective
March 3, 1998.

(c) Net loss includes $40 million in costs incurred by Norcen in connection
with the Norcen Acquisition which were not reimbursed by the Company.

(d) Results reflect the impairment and writedown of certain oil and gas
properties.

3. DIVESTITURES

Deleveraging Program. In April 1998, the Company's Board of Directors
authorized a deleveraging program which was designed to reduce debt and maintain
a strong investment grade credit rating for the Company's outstanding
indebtedness. The deleveraging program, which was initiated following the
completion of the Norcen Acquisition, included sales of the GPM segment and
non-strategic oil and gas producing properties. The completed sales undertaken
as part of the Company's deleveraging program include:

Wattenberg Properties. In May 1998, the Company completed the sale of its
interest in certain oil and gas producing properties located in the Wattenberg
area of the Denver-Julesburg Basin of Colorado to United States Exploration,
Inc. for a cash sales price of $41 million. The Company has retained a royalty
interest in these properties.

Superior Propane Income Fund. In May 1998, UPRI sold a 10 percent ownership
interest in Superior Propane Income Fund (the "Superior Fund"), together with
rights under a management agreement with Superior Propane Inc., ("Superior
Propane") and rights under an administration and advisory agreement among the
Company, Superior Propane and the Superior Fund, to Superior Management Services
Limited Partnership for a cash sales price of $48 million.

Matagorda Island Properties. In August 1998, the Company completed the sale
of its 19 percent non-operated interest in the Matagorda Island Block 623 Field
and surrounding blocks, all located in the Gulf of Mexico (off the shore of
Texas), to Enron Oil & Gas Company for a cash sales price of $158 million.

Rockies Properties. In the fourth quarter 1998, the Company completed the
sale of certain oil and gas producing properties located in Wyoming, oil
producing properties in Utah and oil producing properties in

49
52
UNION PACIFIC RESOURCES GROUP INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

North Dakota and Montana. The aggregate proceeds from the sales of these oil and
gas producing properties were approximately $46 million.

Canadian Properties. In December 1998, the Company completed sales of
certain oil and gas producing properties located in western Canada. The
aggregate proceeds from the sales of these oil and gas producing properties were
approximately $145 million.

In January 1999, the Company announced the completion of several other
large asset sales. The Company sold several of its non-core southern Texas
properties for $138 million and its Canadian Caroline-Swan Hill for $108
million. Proceeds from these sales will primarily be used to reduce the
Company's debt obligations.

Discontinued Operations. In November 1998, the Company entered into a
Merger and Purchase Agreement ("Agreement") with Duke Energy Field Services,
Inc. ("Duke") to sell its gathering, processing and marketing ("GPM") segment
for $1.35 billion in cash. The proposed sale consists primarily of the Company's
pipelines, gathering systems, natural gas processing plants and natural gas and
NGL marketing assets and operations, including interests in 19 natural gas
processing plants (together with approximately 7,200 miles of pipelines that
support these processing plants), as well as two non-operated NGL fractionation
plants. The Company will retain its crude oil marketing business. The Company
expects to record a gain on the sale of the GPM segment, which is expected to be
completed in March 1999.

As part of the Agreement, Duke was allowed to conduct an environmental
audit and, based on the results, assert claims for the cost to remediate
environmental conditions discovered during the audit. Duke has concluded the
environmental audit and asserted claims under the Agreement. Under the terms of
the Agreement, asserted claims will not affect or delay the close of the
transaction; however, following the close of the transaction, the Company has
the right to contest any environmental claims through arbitration. If it is
determined through arbitration that there are valid environmental claims in
excess of $40 million, then the Company is obligated to make payment to Duke for
such excess. The Company is analyzing Duke's environmental claims. At this time,
it is the Company's view that there are substantial defenses to the Duke
environmental claims.

The GPM segment has been reported as a discontinued operation and the GPM
net assets which are being sold have been segregated from continuing operations
in the accompanying consolidated statement of financial position. The GPM
segment results of operations and cash flows have been excluded from continuing
operations in the consolidated statements of income and cash flows for all
periods presented and have been reported as discontinued operations in the
accompanying consolidated statements of income and cash flows.

Summarized information relating to discontinued results of operations for
the years ended December 31, 1998, 1997 and 1996 are as follows:

1998 1997 1996
------- ------- -------
(MILLIONS OF DOLLARS)

Operating revenues...................................... $ 340.0 $ 406.7 $ 461.8
Operating expenses...................................... (263.4) (281.3) (287.8)
Depreciation depletion and amortization................. (77.6) (64.1) (55.9)
------- ------- -------
Operating income (loss)................................. (1.0) 61.3 118.1
Other income (expense) -- net........................... -- (0.2) 0.1
Interest expense(a)..................................... (21.1) (13.6) (11.7)
------- ------- -------
Income (loss) before taxes.............................. (22.1) 47.5 106.5
Income taxes (benefit).................................. (6.5) 17.6 39.4
------- ------- -------
Net income (loss) from discontinued operations.......... $ (15.6) $ 29.9 $ 67.1
======= ======= =======

50
53
UNION PACIFIC RESOURCES GROUP INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

- ---------------

(a) The Company allocated interest expense to the GPM segment based on the
ratio of net assets of discontinued operations to total Company net assets,
excluding $3.6 billion of debt associated with the Norcen Acquisition.

Summarized information relating to net assets of discontinued operations at
December 31, 1998 and 1997 are as follows:

1998 1997
--------- ---------
(MILLIONS OF DOLLARS)

Current Assets:
Cash and temporary investments............................ $ 5.7 $ 3.5
Accounts receivable -- net................................ 152.8 133.3
Inventories............................................... 46.8 36.3
Other current assets...................................... 5.2 7.1
-------- --------
Total current assets.............................. 210.5 180.2
Properties-net of accumulated depreciation................ 851.3 764.3
Intangible and other assets............................... 154.8 91.8
-------- --------
Total assets...................................... $1,216.6 $1,036.3
======== ========
Current Liabilities:
Accounts payable.......................................... $ 158.0 $ 152.0
Advance payment(b)........................................ 126.7 --
Other current liabilities................................. 2.0 3.2
-------- --------
Total current liabilities......................... 286.7 155.2
Other long-term liabilities............................... 3.0 3.3
-------- --------
Total liabilities................................. $ 289.7 $ 158.5
======== ========
Net assets of discontinued operations............. $ 926.9 $ 877.8
======== ========

- ---------------
(b) In June 1998, the Company entered into a third party forward sales
arrangement covering a total of 567 MMcf of gas per day. At the time of the
arrangement, the Company received $250 million and became obligated to
deliver gas from October 1998 through March 1999. The Company recorded the
obligation associated with this transaction as an advance payment included
in net assets of discontinued operations. This current liability will be
amortized as part of discontinued operations, as the gas is delivered over
the remaining term of the contract.

4. RESTRUCTURING CHARGE

As a result of depressed hydrocarbon prices, the Company announced a
workforce reduction for its domestic operations and implemented programs to
reduce overhead and other costs in November 1998. As a result of this process, a
$17 million restructuring charge was recorded in the fourth quarter of 1998. The
restructuring charge included $7.6 million for workforce reductions of
approximately 140 U.S. employees. The charge also included $5 million for a
long-term drilling rig commitment and $4.4 million for excess office space
commitments. At December 31, 1998, the remaining reserve relating to the
restructuring charge totaled $14.6 million.

Subsequent to year-end, the Company reorganized into five operating groups,
announced further workforce reductions for its Canadian and U.S. operations and
established a voluntary retirement incentive program. Another restructuring
charge will be recorded in the first quarter of 1999 associated with these
additional workforce reductions.

5. FINANCIAL INSTRUMENTS

Hedging. The Company has established policies and procedures for managing
risk within its organization, including internal controls and governance by a
risk management committee. The level of risk assumed

51
54
UNION PACIFIC RESOURCES GROUP INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

by the Company is based on its objectives and earnings, and its capacity to
manage risk. Limits are established for each major category of risk, with
exposures monitored and managed by Company management, and reviewed
semi-annually by the risk management committee. Major categories of the
Company's risk are defined as follows:

Commodity Price Risk -- Non-Trading Activities. The Company uses derivative
financial instruments for non-trading purposes in the normal course of business
to manage and reduce risks associated with contractual commitments, price
volatility, and other market variables. These instruments are generally put in
place to limit risk of adverse price movements; however, these same instruments
may also limit future gains from favorable price movements. Risk management
activities are generally accomplished pursuant to exchange-traded contracts or
over-the-counter swaps and options.

Recognition of realized gains/losses and option premium payments/receipts
relating to non-trading activities are deferred in the consolidated statement of
income until the underlying physical product is sold. Unrealized gains/losses
are not recorded. Margin deposits, deferred gains/losses and net premiums are
included in other current assets or liabilities in the consolidated statement of
financial position. The cash flow impact is reflected in cash flows provided
from operations in the consolidated statement of cash flows.

The Company's oil and gas revenues can be higher or lower than what would
be reported if the hedging program was not in place. As a result, revenues in
1998, 1997 and 1996 were $9 million, $86 million and $52 million lower,
respectively. Since these transactions were hedges on production, these impacts
were also reflected in the average sales price of the associated products.

Commodity Price Risk -- Trading Activities. The Company periodically enters
into financial contracts in conjunction with market-making or trading activities
with the objective of achieving profits through successful anticipation of
movements in commodity prices and changes in other market variables. Market-
making positions are marked-to-market and gains and losses are immediately
included as revenue in the consolidated statement of income. In addition, the
fair value of unsettled positions is immediately included in the consolidated
statement of financial position as a current asset or current liability. As of
December 31, 1998, there were no transactions in place which would materially
affect the results of operations or financial condition of the Company.

Interest Rate Swaps. The Company periodically enters into rate swaps and
contracts to hedge certain interest rate transactions. As of December 31, 1998
and 1997, there were no interest rate contracts outstanding which materially
affect the results of operations or financial condition of the Company. During
1998, the Company entered into rate lock contracts to hedge interest rates
related to a contemplated bond issuance. The bonds were not issued and the
Company recognized a $14.3 million pretax loss in 1998 associated with these
contracts.

Foreign Currency. The financial statements of foreign subsidiaries, except
those subsidiaries located in countries which have highly inflationary
economies, utilize the local currency as their functional currency. The
financial statements of foreign subsidiaries located in countries which have
highly inflationary economies utilize the U.S. dollar as their functional
currency. Monetary assets and liabilities denominated in a currency other than
the functional currency are remeasured into the functional currency with the
corresponding gains/ losses included in the consolidated statement of income.
The financial statements of those foreign subsidiaries which do not utilize the
U.S. dollar as their functional currency are translated into the U.S. dollar.
Assets and liabilities are translated at the current exchange rate, while
revenues and expenses are translated at the average exchange rate for the
reporting period. Translation gains/losses are not included in net income but
are recorded in a separate section of shareholders' equity and comprehensive
income. The Company's Canadian subsidiary's functional currency is the Canadian
dollar. Generally, the Company's other foreign subsidiaries' functional currency
is the U.S. dollar.

52
55
UNION PACIFIC RESOURCES GROUP INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

At December 31, 1998, the Company's Latin American subsidiaries had foreign
deferred tax liabilities denominated in the local currency of the respective
countries of $159.6 million in Venezuela and $58.0 million in Guatemala. During
1998, the Company recognized deferred tax benefits of $15.2 million and $7.3
million after tax, respectively, associated with remeasurement of the Venezuelan
and Guatemalan deferred tax liabilities. The potential foreign currency
remeasurement impact on net earnings from a five percent change in the year-end
Latin American would be approximately $11 million.

The Company may periodically enter into foreign currency contracts to hedge
specific currency exposures from commercial transactions. As a result of the
Norcen Acquisition, the Company acquired foreign currency forward exchange
contracts with a $643 million notional amount and maturities between March 1998
and December 1999, for which a $15.5 million deferred liability was recorded on
the Consolidated Statement of Financial Position representing the fair value of
these contracts. These contracts were deemed to be hedges of UPRI's future U.S.
dollar denominated hydrocarbon sales. This deferred liability will be amortized
over the contract terms. The unrecognized loss on such contracts at December 31,
1998, excluding the $6.8 million remaining unamortized deferred liability
recorded in purchase accounting, was $18.5 million.

Credit Risk. Credit risk is the risk of loss as a result of nonperformance
by counterparties pursuant to the terms of their contractual obligations.
Because the loss can occur at some point in the future, a potential exposure is
added to the current replacement value to arrive at a total expected credit
exposure. The Company has established methodologies to establish limits, monitor
and report creditworthiness and concentrations of credit to reduce such credit
risk. At December 31, 1998, the Company's largest credit risk associated with
any single counterparty, represented by the net fair value of open contracts
with such counterparty, was $2.6 million.

In connection with the sale of its GPM business segment, the Company will
enter into a long-term sales agreement with Duke. The long-term sales agreement
obligates the Company to sell the majority of its domestic natural gas and NGLs
to Duke for a five-year period subsequent to the closing of the sale. Prices
received for the natural gas and NGLs will be tied to the current market price
for each product. As a result, a significant portion of the Company's credit
risk will be with a single customer. Duke is currently considered a good credit
risk; however, periodic credit evaluations will continue. Further, due to
certain agreements with Duke, letters of credit and/or other assurances can be
demanded under certain circumstances.

Performance Risk. Performance risk results when a counterparty fails to
fulfill its contractual obligations with respect to commodity pricing or volume
commitments. Typically, such risk obligations are defined within the trading
agreements. The Company utilizes its credit risk methodology to manage
performance risk.

Concentrations of Credit Risk. Financial instruments which subject the
Company to concentrations of credit risk consist principally of trade
receivables and short-term cash investments. The Company places its temporary
excess cash investments in high quality short-term instruments through several
high credit quality financial institutions. A significant portion of the
Company's trade receivables relate to customers in the oil and gas industry,
and, as such, the Company is directly affected by the economy of that industry.
The Company derives a significant amount of its revenues from international
operations. The credit risk associated with trade receivables is minimized by
the Company's large customer base and ongoing procedures to monitor the
creditworthiness of customers. The Company generally requires no collateral from
its customers. Historically, the Company has not experienced significant losses
on trade receivables.

53
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UNION PACIFIC RESOURCES GROUP INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

6. PROPERTIES

Major property classifications were as follows:

AS OF DECEMBER 31,
---------------------
1998 1997
--------- --------
(MILLIONS OF DOLLARS)

Producing properties........................................ $ 9,429.9 $5,296.8
Non-producing properties.................................... 1,241.5 449.5
Construction in progress.................................... 143.4 346.5
Other....................................................... 263.4 175.9
--------- --------
Total............................................. $11,078.2 $6,268.7
========= ========

Accumulated depreciation, depletion and amortization by major property
classifications were as follows:

AS OF DECEMBER 31,
----------------------
1998 1997
--------- ---------
(MILLIONS OF DOLLARS)

Producing properties........................................ $4,642.1 $3,153.0
Non-producing properties.................................... 233.1 123.6
Other....................................................... 109.7 91.0
-------- --------
Total............................................. $4,984.9 $3,367.6
======== ========

Based upon the Company's analysis of expected future net cash flows from
its oil and gas properties, certain properties were deemed to be impaired due to
lower hydrocarbon prices and downward revisions in reserve estimates. In 1998,
the Company adjusted the net book value of such properties to their fair value,
determined using a discounted cash flow approach, with a charge to depreciation,
depletion and amortization of $1.2 billion. In 1997, the Company recorded an
impairment charge of $20.2 million. Fixed asset additions included capitalized
interest of $0.9 million and $2.0 million in 1998 and 1997, respectively.

7. CAPITAL AND EXPLORATORY EXPENDITURES

Capital and exploratory expenditures include the following:

FOR THE YEARS ENDED
----------------------------
1998 1997 1996
-------- -------- ------
(MILLIONS OF DOLLARS)

Capital expenditures:
Producing properties.................................. $3,056.9 $ 773.3 $526.0
Non-producing properties.............................. 506.6 200.7 149.8
Exploratory drilling.................................. 117.5 121.7 36.1
Other................................................. 32.6 15.8 9.5
-------- -------- ------
Total capital expenditures.................... 3,713.6 1,111.5 721.4
Exploratory expenditures:
Expensed geological and geophysical costs............. 63.1 35.2 19.0
Expensed dry hole costs............................... 52.1 41.7 32.6
-------- -------- ------
Total exploratory expenditures................ 115.2 76.9 51.6
-------- -------- ------
Total capital and exploratory expenditures.... $3,828.8 $1,188.4 $773.0
======== ======== ======

54
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UNION PACIFIC RESOURCES GROUP INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

8. INVESTMENT IN UNCONSOLIDATED AFFILIATE

The Company has a 50 percent ownership interest in Black Butte Coal Company
and R-K Leasing Company ("Black Butte"), a partnership which operates a surface
coal mine complex in southwestern Wyoming. Summarized financial information for
Black Butte is as follows:

YEARS ENDED AND AS
OF DECEMBER 31,
----------------------
1998 1997
--------- ---------
(MILLIONS OF DOLLARS)

Current assets.............................................. $ 30.4 $ 27.5
Non-current assets.......................................... 26.2 37.9
Current liabilities......................................... 21.0 17.1
Non-current liabilities and equity.......................... 35.7 48.3
Sales....................................................... $254.5 $159.7
Operating income............................................ 183.4 112.4
Partners' income............................................ 183.2 113.6

During 1998, Black Butte's sales to its largest customer under an amended
coal supply contract accounted for $79.3 million of the Company's consolidated
operating income. This coal supply contract was amended during 1997 to
accelerate shipments in the years 1998, 1999 and 2000, at which time terms of
the contract will terminate. Although Black Butte continues to seek new buyers
for its low-sulfur coal, its mining costs are considerably higher than the
mining costs for competing supplies. The Company does not expect to be able to
replace the operating income it currently receives under the contract with
incremental coal sales.

In addition, Black Butte provides an accrual for reclamation of mined
properties, based on the estimated cost of restoration of such properties in
compliance with laws governing strip mining. Accrued reclamation costs for Black
Butte as of December 31, 1998 and 1997 were $52.0 million and $50.4 million, of
which the Company's share is $26 million and $25.2 million, respectively. The
majority of cash expenditures for reclamation are expected to be incurred from
five to ten years in the future (see Note 13).

A supplier of coal to Black Butte has been assessed by the State of Montana
Department of Revenue for underpayment of production taxes related to coal
previously sold to Black Butte. The supplier is contesting this claim; however,
should the claim be successful, the supplier will claim reimbursement from Black
Butte. In 1998, the Courts ruled in favor of the State of Montana. The supplier
is appealing to the Montana State Supreme Court; however, the Company recorded
$14.3 million during 1998 as its proportionate share of the Montana Department
of Revenue assessment related to coal production taxes. Additionally, this
supplier of coal to Black Butte has been assessed by the Minerals Management
Service of the United States Department of the Interior for underpayment of
royalties related to coal previously sold to Black Butte. The liability for
underpaid royalties to the Minerals Management Service, if any, could range from
zero to $12 million.

9. INCOME TAXES

Income (loss) from continuing operations before taxes is as follows:

FOR THE YEARS ENDED DECEMBER 31,
---------------------------------
1998 1997 1996
----------- -------- --------
(MILLIONS OF DOLLARS)

Domestic................................................. $ (239.7) $405.9 $356.9
Foreign.................................................. (1,248.6) 13.0 9.2
--------- ------ ------
Total.......................................... $(1,488.3) $418.9 $366.1
========= ====== ======

55
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UNION PACIFIC RESOURCES GROUP INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Components of income tax expense (benefit) for continuing operations, were
as follows:

FOR THE YEARS ENDED DECEMBER 31,
---------------------------------
1998 1997 1996
--------- -------- --------
(MILLIONS OF DOLLARS)

Current:
U.S. federal.......................................... $ 43.2 $ (0.4) $123.4
U.S. state............................................ 6.8 5.1 10.0
Foreign............................................... 4.1 0.2 0.3
------- ------ ------
Total current................................. 54.1 4.9 133.7
------- ------ ------
Deferred:
U.S. federal.......................................... (155.7) 113.4 (22.1)
U.S. state............................................ 3.4 (2.5) 0.8
Foreign............................................... (507.0) -- --
------- ------ ------
Total deferred................................ (659.3) 110.9 (21.3)
------- ------ ------
Total income tax expense (benefit)............ $(605.2) $115.8 $112.4
======= ====== ======

Deferred tax liabilities (assets) were as follows:

AS OF DECEMBER 31,
---------------------
1998 1997
---------- --------
(MILLIONS OF DOLLARS)

Excess tax over book items, including depreciation and
exploration costs......................................... $1,528.2 $686.0
State taxes -- net.......................................... (15.0) --
Long-term liabilities....................................... (19.6) --
Alternative minimum tax..................................... (72.6) (73.2)
Pension and other retirement benefits....................... (52.6) (57.4)
Net operating losses........................................ (93.1) --
Other....................................................... 16.3 (2.5)
-------- ------
Net deferred tax liability........................ $1,291.6 $552.9
======== ======

A reconciliation between statutory and effective tax rates is as follows:

FOR THE YEARS ENDED
DECEMBER 31,
---------------------
1998 1997 1996
----- ----- -----

U.S. statutory federal tax rate............................. 35.0% 35.0% 35.0%
Section 29 credits.......................................... 1.1 (4.3) (3.3)
State taxes -- net.......................................... (0.4) 1.3 1.8
Foreign rate differentials.................................. 1.8 -- --
Foreign currency remeasurement.............................. 1.5 -- --
Non taxable entity.......................................... 1.0 -- --
Tax settlements............................................. -- (1.5) --
Other....................................................... 0.6 (1.9) (1.4)
---- ---- ----
Effective tax rate................................ 40.6% 28.6% 32.1%
==== ==== ====

56
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UNION PACIFIC RESOURCES GROUP INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The Company generates Section 29 tax credits from the sale of certain fuels
produced from nonconventional sources. Fuels qualifying for the credit must be
produced from a well drilled or a facility placed in service after December 31,
1979, and before January 1, 1993, and sold before January 1, 2003. The Company
generated $16.4 million, $18.8 million and $15.6 million of Section 29 tax
credits in 1998, 1997 and 1996, respectively. The federal tax law provides for
the use of these credits against regular federal income tax liability.
Accordingly, the Company utilized $5.1 million of Section 29 tax credits on its
1997 tax return. It is anticipated that all of the 1998 tax credits will
increase the alternative minimum tax credit carry forward and will be applied
against future tax years' regular tax liability.

The Company recognized favorable tax adjustments relating to prior year
federal tax returns in the amount of $4 million for 1998 and $2.7 million for
1997. During 1997, the Company also recognized a $6 million favorable adjustment
to state income taxes representing the settlement of a California state audit
and a favorable adjustment of $3.3 million resulting from a tax refund from
Union Pacific Corporation ("UPC").

UPC has informed the Company that all material deficiencies prior to 1986
have been settled with the Internal Revenue Service ("IRS"). UPC is negotiating
with the IRS Appeals Office concerning 1986 through 1989. The IRS is examining
the Company's returns for 1990 through 1994 in connection with the IRS'
examination of UPC's returns. The Company believes it has adequately provided
for federal and state income taxes.

While the operations of the Company in Guatemala are subject to local
income taxes, no liability has arisen in recent years, as sufficient unrecovered
costs carried forward from previous years, have been available to offset current
taxable income. Guatemalan tax benefits which can be carried forward
indefinitely were $59.5 million at December 31, 1998. All other carryforward
benefits due to net operating losses are expected to be utilized in 1999.

In 1997, UPRI (formally Norcen), received a reassessment concerning the
deductibility of certain expenses and foreign exchange losses claimed for income
tax purposes during the period 1989 through 1993 in the amount of $81.1 million.
In spite of UPRI's disagreement and appeal, the reassessment was fully funded in
1997 and recorded as a deferred tax benefit. As a result of the Norcen
Acquisition, the Company recorded a valuation allowance against this benefit as
part of the purchase price allocation. The carryforward benefit, net of the tax
valuation allowance, is approximately $15.8 million. On March 8, 1999, the
Company entered into an agreement with Canadian tax authorities to settle the
claims out of court. Under the terms of the settlement, the Company will receive
a refund of approximately $50 million dollars.

57
60
UNION PACIFIC RESOURCES GROUP INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

10. DEBT

The total debt of the Company is summarized below:

AS OF DECEMBER 31,
--------------------------------
INTEREST
RATE 1998 1997
-------- --------- ---------
(MILLIONS OF DOLLARS)

Commercial Paper and Bankers Acceptances (Average of
5.98% at December 31, 1998)............................ $2,351.9 $ 663.1
Debentures due July 2, 2002.............................. 6.8% 250.0 --
Notes due May 15, 2005................................... 6.50% 200.0 --
Debentures due May 15, 2006.............................. 7.375% 250.0 --
Notes due October 15, 2006............................... 7.0% 200.0 200.0
Notes due May 15, 2008................................... 6.75% 200.0 --
Debentures due July 2, 2008.............................. 7.8% 150.0 --
Debentures due May 15, 2018.............................. 7.05% 200.0 --
Debentures due October 15, 2026.......................... 7.5% 200.0 200.0
Debentures due May 15, 2028.............................. 7.15% 425.0 --
Debentures due November 1, 2096.......................... 7.5% 150.0 150.0
Capital lease obligations (Note 11)...................... 17.4 --
Tax exempt revenue bond due 2012......................... 4.25% -- 20.1
(Discount) Premium on notes and debentures............... 4.4 (2.6)
-------- --------
Total debt..................................... 4,598.7 1,230.6
Less: current portion.......................... 853.8 --
-------- --------
Total long-term debt........................... $3,744.9 $1,230.6
======== ========

During the first quarter of 1998, in connection with the Norcen
Acquisition, the Company issued commercial paper supported by a $2.7 billion
364-day Competitive Advance/Revolving Credit Agreement (the "Norcen Acquisition
Facility") and also assumed the outstanding debt of Norcen. The debt assumed
includes 6.8% Debentures due July 2, 2002, in the aggregate principal amount of
$250 million, 7 3/8% Debentures due May 15, 2006, in the aggregate principal
amount of $250 million and 7.8% Debentures due July 2, 2008, in the aggregate
principal amount of $150 million, each of which have been unconditionally
guaranteed by the Company. Additionally, the Company assumed $351 million in
bankers acceptances.

In October 1998, the Company replaced its eight existing facilities (the
Norcen Acquisition Facility, its $600 million and $300 million revolving credit
agreements and five Canadian facilities, which totaled approximately U.S. $2.9
billion) with three new facilities totaling an aggregate of U.S. $2.5 billion.
These new facilities are comprised of a $1.0 billion 364-day Competitive
Advance/Revolving Credit Agreement (the "Bridge Facility"), a $750 million
364-day Competitive Advance/Revolving Credit Agreement and a $750 million
Five-Year Competitive Advance/Revolving Credit Agreement (collectively the
"Facilities"). Each of the Facilities contain a covenant stipulating that the
ratio of consolidated debt to consolidated EBITDAX -- the sum of operating
income (before adjustments for income taxes, interest expense or extraordinary
gains or losses), depreciation, depletion and amortization and exploration
expenses -- cannot exceed 3.25:1.00. This covenant replaced the consolidated
debt to total capitalization ratio covenant applicable under previous
facilities. The 1998 consolidated debt to consolidated EBITDAX covenant
calculation uses pro forma EBITDAX results. The Company was in compliance with
this covenant provision at year-end 1998.

The Bridge Facility also contains mandatory reduction provisions whereby it
will be permanently reduced by seventy-five percent of the net proceeds from
specified asset sales (certain identified exploration and production assets and
the Company's GPM segment). At December 31, 1998, the Bridge Facility had not
been reduced because none of the specified asset sales had occurred. The
Facilities also place other restrictions

58
61
UNION PACIFIC RESOURCES GROUP INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

on the Company regarding the creation of liens, incurrence of additional
indebtedness by subsidiaries, transactions with affiliates, sales of stock of
UPRC and certain mergers, consolidations and asset sales.

Debt maturities through 2003, excluding capital leases, are $851.9 million
of commercial paper in 1999 and $250 million of Debentures due July 2, 2002. At
December 31, 1998, $1.5 billion of commercial paper and bankers acceptances had
been classified as long-term, supported by the $750 million Five-Year and the
$750 million 364-day Competitive Advance/Revolving Credit Agreements. This
classification reflects the Company's intent and ability to maintain these
borrowings on a long-term basis through the issuance of additional commercial
paper and/or new term financings.

The fair value of the Company's long-term debt, excluding commercial paper
and bankers acceptances, debt discount/premium and capital lease obligations was
approximately $2,088 million at December 31, 1998 and $580 million at December
31, 1997. The fair value was estimated using quoted market prices. These fair
values were $137 million less than the carrying values at December 31, 1998 and
$30 million more than the carrying value at December 31, 1997. The change in the
fair value during 1998 resulted primarily from the deterioration in general
market conditions for energy industry related fixed income securities and the
reduction in the Company's long-term credit rating. As a result of the Norcen
Acquisition, the Company recorded a $31.5 million debt premium, representing the
excess of the fair value over the carrying value of the debt acquired. The
premium is being amortized over the life of the acquired debt.

The 2005 Notes, 2008 Notes, 2018 Debentures and 2028 Debentures will be
redeemable as a whole or in part, at the option of the Company at any time. The
redemption price is equal to the greater of (i) 100% of the principal amount of
the Securities to be redeemed and (ii) the sum of the present values of the
remaining scheduled payments thereon, discounted to the redemption date on a
semi-annual basis at the Treasury Rate plus 15 basis points in the case of the
2005 Notes and the 2008 Notes, 20 basis points in the case of the 2018
Debentures and 25 basis points in the case of the 2028 Debentures plus, in each
case, accrued interest on the principal amount being redeemed to the redemption
date. There are no other notes and debentures redeemable prior to maturity. None
of the Company's notes and debentures is subject to sinking fund requirements.
At December 31, 1998, the Company had an effective shelf registration statement
on file with the Securities and Exchange Commission that would permit the
Company or certain identified subsidiaries to offer up to $1.0 billion in debt
and/or equity securities.

The Company has guaranteed a portion of the OCI Wyoming, L.P. debt
facility. At December 31, 1998, OCI Wyoming, L.P. had an outstanding debt
facility balance of $49 million, of which the Company has guaranteed $24
million. The debt is carried as an investment in affiliate on the consolidated
statement of financial position.

59
62
UNION PACIFIC RESOURCES GROUP INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

11. LEASE COMMITMENTS

The Company leases several office buildings, certain production platforms
and other property under operating leases. In 1998, the Company entered into a
capital lease for furniture and walls in its Fort Worth offices. Future minimum
lease payments for operating and capital leases with initial non-cancelable
lease terms in excess of one year as of December 31, 1998, were as follows:

AS OF DECEMBER 31, 1998
------------------------------------------
CAPITAL LEASES OPERATING LEASES TOTAL
-------------- ---------------- ------

1999............................................. $ 2.8 $ 50.8 $ 53.6
2000............................................. 2.8 44.8 47.6
2001............................................. 2.8 45.3 48.1
2002............................................. 2.8 33.4 36.2
2003............................................. 2.8 31.8 34.6
Later years...................................... 7.2 10.9 18.1
----- ------ ------
Total future minimum lease payments.............. $21.2 $217.0 $238.2
====== ======
Less: amounts representing interest.............. (3.8)
-----
Present value of minimum capital lease
obligations.................................... 17.4
-----
Less: Short-term portion of capital lease
obligations.................................... (1.9)
-----
Long-term portion of capital lease obligations... $15.5
=====

Rent expense, net of sublease income, for operating leases with terms
exceeding one month was $59.8 million in 1998, $19.2 million in 1997, and $13.2
million in 1996. Sublease income for the next five years will be $30.2 million
in 1999, $29.9 million in 2000, $29.2 million in 2001, $29.2 million in 2002,
$28.1 million in 2003 and $0.3 million thereafter. Capital leases included in
corporate fixed assets were $17.4 at December 31, 1998.

12. RETIREMENT PLANS

The Company provides pension, health care and life insurance benefits to
all eligible retirees in the U.S. and pension benefits to all eligible retirees
in Canada. No such pension or other benefits are provided to employees of other
foreign subsidiaries.

U.S. Pension Benefits. Pension benefits for U.S. employees are based on
years of service and compensation during the last years of employment.
Contributions to the plans are calculated on the Projected Unit Credit actuarial
funding method and are not less than the minimum funding standards set forth in
the Employees Retirement Income Security Act of 1974, as amended. The portion of
the funded plan's assets held in fixed-income and short-term securities was
approximately 32 percent and 34 percent as of December 31, 1998 and 1997,
respectively, with the remainder primarily in equity securities.

Other U.S. Postretirement Benefits. Postretirement health and life
insurance benefits are provided to all eligible U.S. retirees. The Company does
not currently pre-fund health care and life insurance benefit costs.

Canadian Pension Benefits. Included in the Norcen Acquisition were Norcen's
pension plans covering most Canadian employees. Benefits provided under the
defined benefit plan are based on years of service and highest compensation over
a specified number of consecutive years. The provisions under the defined
benefit plan were modified to provide employees with a defined contribution plan
option, which has been retroactively elected by substantially all active
employees. Under the defined contribution plan, the Company matches a stated
percentage of employee contributions to the plan. Both the defined benefit
payments and the defined contribution company match obligation are paid from
assets held in trust. The Company will make

60
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UNION PACIFIC RESOURCES GROUP INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

contributions to the plans, if necessary, to maintain adequate assets in trust.
Contributions are not expected to be necessary for several years.

The following pension credits and funded status are based on historical
actuarial valuations.

U.S. PENSION OTHER U.S. CANADIAN
BENEFITS BENEFITS PENSION BENEFITS
--------------- ------------- ----------------
1998 1997 1998 1997 1998
------ ------ ----- ----- ----------------
(MILLIONS OF DOLLARS)

Change in benefit obligation:
Benefit obligation at beginning of year..... $202.6 $183.9 $42.9 $45.1 $ --
Acquisition................................. -- -- -- -- 26.1
Service cost................................ 6.1 5.5 1.0 0.8 0.1
Interest cost............................... 14.3 13.3 3.0 3.3 1.4
Plan amendments............................. 2.4 -- (5.4) 0.3 --
Actuarial gain (loss)....................... 12.6 11.6 0.1 (3.6) (0.2)
Benefits paid............................... (17.0) (11.7) (1.2) (3.0) (1.8)
------ ------ ----- ----- ------
Benefit obligation at end of year........... $221.0 $202.6 $40.4 $42.9 $ 25.6
====== ====== ===== ===== ======
Change in plan assets:
Fair value of plan assets at beginning of
year..................................... $240.9 $221.3 $ -- $ -- $ --
Acquisition................................. -- -- -- -- 50.3
Actual return on plan assets................ 40.0 30.8 -- -- --
Employer contribution(a).................... 5.8 0.5 1.2 3.0 --
Benefits paid(b)............................ (17.0) (11.7) (1.2) (3.0) (2.6)
------ ------ ----- ----- ------
Fair value of plan assets at end of year.... $269.7 $240.9 $ -- $ -- $ 47.7
====== ====== ===== ===== ======
Plan assets (over) under benefit obligation... $(48.7) $(38.3) $40.4 $42.9 $(22.1)
Unamortized net transition asset.............. 15.8 17.9 -- -- --
Unrecognized prior service gain (cost)........ (9.0) (7.8) 8.0 3.4 --
Unrecognized net gain......................... 105.1 100.4 25.1 27.0 (1.9)
------ ------ ----- ----- ------
Net amount recognized......................... $ 63.2 $ 72.2 $73.5 $73.3 $(24.0)
====== ====== ===== ===== ======

- ---------------
(a) Represents payments relating to unfunded plans. The Company periodically
settles a portion of the unfunded supplemental plans benefit obligations
through the purchase of annuities.

(b) $0.8 million of Canadian pension benefits paid represent payments to fund
the defined contribution Company match.

U.S. PENSION OTHER U.S. CANADIAN
BENEFITS BENEFITS PENSION BENEFITS
------------- ------------- ----------------
1998 1997 1998 1997 1998
----- ----- ----- ----- ----------------
(MILLIONS OF DOLLARS)

Amounts recognized in the Statement of Financial
Position consist of:
Prepaid benefit cost.......................... $ -- $ -- $ -- $ -- $(24.0)
Accrued benefit liability..................... 72.0 77.0 73.5 73.3 --
Intangible asset.............................. (3.9) (3.8) -- -- --
Accumulated other comprehensive income........ (4.9) (1.0) -- -- --
----- ----- ----- ----- ------
Net amount recognized........................... $63.2 $72.2 $73.5 $73.3 $(24.0)
===== ===== ===== ===== ======
Weighted-average assumptions as of December 31
Discount rate................................. 7.0% 7.25% 7.0% 7.25% 6.5%
Expected return on plan assets................ 9.0% 9.0% -- -- 6.5%
Rate of compensation increase................. 5.0% 5.25% -- -- 5.0%

61
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UNION PACIFIC RESOURCES GROUP INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

For measurement purposes, a 7.8 percent annual rate of increase in the per
capita cost of covered health care benefits was assumed for 1998. The rate was
assumed to gradually decrease to 5 percent in 2005 and remain at that level
thereafter.

CANADIAN
U.S. PENSION BENEFITS OTHER U.S. BENEFITS PENSION
------------------------ --------------------- --------
1998 1997 1996 1998 1997 1996 1998
------ ------ ------ ----- ----- ----- --------
(MILLIONS OF DOLLARS)

Service cost-benefits earned during the period.... $ 6.1 $ 5.5 $ 4.4 $ 1.0 $ 0.8 $ 1.0 $ 0.1
Interest cost..................................... 14.3 13.4 13.3 3.0 3.3 3.4 1.4
Expected return on plan assets.................... (18.6) (17.1) (19.6) -- -- -- (2.7)
Amortization of net transition asset.............. (2.1) (2.0) (2.1) -- -- -- --
Amortization of unrecognized prior service gain
(cost).......................................... 1.2 1.2 1.2 (0.8) (0.8) (0.8) --
Amortization of unrecognized net gain............. (4.1) (4.9) (2.8) (1.7) (1.6) (1.5) --
------ ------ ------ ----- ----- ----- -----
(Benefit) charge to operations........... $ (3.2) $ (3.9) $ (5.6) $ 1.5 $ 1.7 $ 2.1 $(1.2)
====== ====== ====== ===== ===== ===== =====
Other comprehensive (income) loss................. $ 3.9 $ 1.0 $ -- $ -- $ -- $ -- $ --
====== ====== ====== ===== ===== ===== =====

Assumed health care cost trend rates have a significant effect on the
amounts reported for the postretirement benefit plan. A one-percentage-point
change in assumed health care cost trend rates would have the following effects:

1 PERCENTAGE 1 PERCENTAGE
POINT INCREASE POINT DECREASE
-------------- --------------
(MILLIONS OF DOLLARS)

Effect on total of service and interest cost components.... $0.4 $(0.4)
Effect on postretirement benefit obligation................ 3.6 (3.2)

13. ENVIRONMENTAL EXPOSURE

Environmental expenditures related to treatment or cleanup are expensed
when incurred, while environmental expenditures which extend the life of the
property or prevent future contamination are capitalized in accordance with
generally accepted accounting principles. Liabilities for these expenditures are
recorded when it is probable that obligations have been incurred and the amounts
can be reasonably estimated, based on current law and existing technologies.
Environmental accruals are recorded at undiscounted amounts and exclude claims
for recoveries from insurance or other third parties.

The Company generates and disposes of hazardous and nonhazardous waste in
its current and former operations and is subject to increasingly stringent
federal, state, local, provincial and international environmental regulations.
The Company has identified seven sites currently subject to environmental
response actions or on the Superfund National Priorities List or state superfund
lists, at which it is or may be liable for remediation costs associated with
alleged contamination or for violation of environmental requirements. Certain
federal legislation imposes joint and several liability for the remediation of
various sites; consequently, the Company's ultimate environmental liability may
include costs relating to other parties in addition to costs relating to its own
activities at each site. In addition, the Company is or may be liable for
certain environmental remediation matters involving existing or former
facilities.

In March 1994, the Company sold its interest in the Wilmington, California
field and the Harbor Cogeneration Plant to the Port of Long Beach, California.
As part of the Wilmington sales agreement, the Company agreed to participate
with the Port of Long Beach in funding environmental remediation and site
preparation, as specified by the Port of Long Beach, up to a maximum of $105.5
million. As a result, a provision of $50.5 million for future environmental
costs and $55.0 million for future site preparation costs was established ($90.7
million in total remaining at December 31, 1998) and is categorized as other
current

62
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UNION PACIFIC RESOURCES GROUP INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

liabilities and long-term liabilities (see Note 15). The majority of cash
outlays for these liabilities are expected to occur over the next 5 years.

As of December 31, 1998 and 1997, liabilities totaling $74.7 million and
$73.3 million, respectively, had been accrued for future costs of all sites
where the Company's obligation is probable and where such costs reasonably can
be estimated; however, the ultimate cost could be lower or higher. This accrual
includes future costs for remediation and restoration of sites, as well as for
ongoing monitoring costs, but excludes any anticipated recoveries from third
parties. The accrual also includes $37 million for the obligation to participate
in the remediation of the Wilmington field properties. Cost estimates were based
on information available for each site, financial viability of other Potentially
Responsible Parties ("PRPs") and existing technology, laws and regulations. The
Company believes that it has accrued adequately for its share of costs at sites
subject to joint and several liabilities. The ultimate liability for remediation
is difficult to determine with certainty because of the number of PRPs involved,
site-specific cost sharing arrangements with other PRPs, the degree of
contamination by various wastes, the scarcity and quality of volumetric data
related to many of the sites and the speculative nature of remediation costs.

The Company is also involved in reducing emissions, spills and migration of
hazardous materials. Remediation of identified sites and control of
environmental exposures required spending of $17 million in 1998 and $14.7
million in 1997. In 1999, the Company anticipates spending a total of $17
million for remediation, control and prevention, including $8 million relating
to the Wilmington properties. The majority of the December 31, 1998 accrued
environmental liability is expected to be paid out over the next five years,
funded by cash generated from operations. Based on current rules and
regulations, management does not expect future environmental obligations to have
a material impact on the results of operations or financial condition of the
Company.

14. COMMITMENTS AND CONTINGENCIES

The Company is a party to several long-term firm gas transportation
agreements that support the gas marketing program and GPM segment being sold to
Duke. The largest agreements are with Kern River Gas Transportation Company
("Kern River"), Texas Gas Transmission Corporation and Pacific Gas Transmission.
Most of the GPM firm long-term transportation contracts are to be transferred to
Duke as part of the GPM sale. The Company will keep the Kern River contract and
assign the transportation rights to Duke through May 31, 2007. In addition, as
part of the GPM sale, the Company has agreed to keep Duke whole if the
transportation market value falls below the contract transportation rates and
Duke will pay the Company if the market value exceeds the contract
transportation rates. This keep-whole agreement will be in effect for the
ten-year period subsequent to the closing of the sale. A detailed explanation of
the three major firm transportation contracts and keep-whole commitment follows.

The Kern River firm transportation contract expires May 31, 2007. Under the
transportation agreement, the Company has the right to transport 75 MMcfd of gas
on the Kern River Pipeline system which extends from Opal, Wyoming, to an
interconnection with the Southern California Gas Company pipeline system in
southern California. The current transportation rate is $0.69 per Mcf; however,
Kern River is charging $0.67 per Mcf pursuant to a rate in effect through at
least 2002. Thereafter, this rate can change based on Kern River's cost of
service and upon rate regulation policies of the Federal Energy Regulatory
Commission ("FERC"). Under a 1993 ruling of the FERC, the Company is obligated
to pay all of the fixed costs included in the transportation rate whether or not
the Company actually uses Kern River's pipeline to transport gas. Those fixed
costs presently amount to $0.61 per Mcf. The Company is a party to an additional
agreement under which it may acquire in 2001, at its option, an additional 25
MMcfd of transportation rights on the Kern River system beginning in 2002.

The Company is a party to a long-term firm transportation agreement with
Texas Gas Transmission Corporation that expires October 31, 2008. Under the
transportation agreement the Company has the rights to
63
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UNION PACIFIC RESOURCES GROUP INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

transport 90 MMcfd of gas from Carthage, Texas to Lebanon, Ohio. The Company is
obligated to pay a fixed transportation rate of $0.331 per MMBtu regardless of
the volumes transported under the agreement.

The Company is party to a long-term firm transportation agreement with
Pacific Gas Transmission ("PGT") that expires October 31, 2023. Under the
transportation agreement, the Company has the right to transport 25 MMcfd of gas
from Kingsgate, British Columbia to the California/Oregon border. The Company is
obligated to pay a fixed transportation rate of $0.328 per MMBtu regardless of
the volumes transported under the agreement. However, the Company has
third-party agreements that reimburse the Company for 90 percent of the firm
transportation cost until October 31, 2002. As part of the third-party
agreements, the Company assigned 50 percent of the firm transportation capacity.

During 1998, as a result of the Norcen Acquisition, the Company assumed
responsibility for additional long-term firm transportation agreements with PGT
to transport gas from Kingsgate, British Columbia to the California/Oregon
border. Under the transportation agreements, the Company has the rights to
transport 106 MMBtu per day of which 47 MMBtu per day will expire on October 31,
2007 and the balance of the contract commitment will expire on October 31, 2023.
The Company does have a third party agreement that recovers all the
transportation cost for 20 MMBtu per day through June 30, 2011.

Included in the balance sheet of the Company is a reserve for the fair
value of the difference between the total rate under the firm transportation
agreements and estimated market rates through March 2009. The reserve, which is
included in current and other long-term liabilities, was $88.7 million at
December 31, 1998.

In 1997, the Company entered into a letter of intent to negotiate a $150
million five year agreement with Noble Drilling (U.S.) Inc. beginning in
November 1999, for the services of a semisubmersible drilling rig designed for
operations in water depths up to 5,000 feet. Under the letter of intent, if a
final agreement is negotiated, the Company would share 50 percent of the total
rig commitment with another major oil and gas company.

In the last twelve years, the Company has disposed of significant pipeline,
refining and producing property assets, including the sale of its 37.5 percent
interest in a Corpus Christi, Texas petrochemical complex (July 1987), the
Calnev pipeline (October 1988), the Wilmington, California refinery (December
1988), the Corpus Christi refinery (50 percent sold in March 1987 and the
balance in January 1989), Wilmington field (March 1994) and the 1998
deleveraging program sales. In connection therewith, the Company has given
certain representations and warranties relating to the assets sold (covering,
among other matters, the condition and capabilities of certain assets and
compliance with environmental and other laws) and certain indemnities with
respect to liabilities associated with such assets. With respect to the Calnev
pipeline and the Corpus Christi and Wilmington refinery sales, the Company has
been advised of possible claims which may be asserted by the relevant purchasers
for alleged breaches of representations and warranties. Certain claims related
to compliance with environmental laws remain pending. In addition, as some of
the representations, warranties, and indemnities related to some of the disposed
assets have not expired, further claims may be made against the Company. While
no assurance can be given as to the actual outcome of these claims, the Company
does not expect these matters to have a materially adverse effect on its results
of operations, cash flows or financial condition.

There are lawsuits pending against the Company and certain of its
subsidiaries which are described in Part I, Item 3 -- "Legal Proceedings" in
this Annual Report on Form 10-K. The Company intends to defend vigorously
against these lawsuits as well as any similar lawsuits. In the opinion of
management of the Company, the outcome of these matters should not have a
materially adverse effect on the consolidated financial condition, cash flows or
results of operations of the Company.

The Company is a defendant in a number of lawsuits and is involved in
governmental proceedings arising in the ordinary course of business in addition
to those described above, including contract claims, personal injury claims and
environmental claims. While management of the Company cannot predict the outcome
of
64
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UNION PACIFIC RESOURCES GROUP INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

such litigation and other proceedings, management does not expect those matters
to have a materially adverse effect on the consolidated financial condition,
cash flows or results of operations of the Company.

15. OTHER LONG-TERM LIABILITIES

Other long-term liabilities include the following:

AS OF DECEMBER 31
----------------------
1998 1997
--------- ---------
(MILLIONS OF DOLLARS)

Firm transportation liabilities............................. $ 71.2 $ 8.5
Abandonment provision....................................... 58.1 7.7
Environmental............................................... 57.2 56.5
Wilmington field site preparation........................... 53.7 53.7
Equity investment -- Black Butte............................ 37.8 26.6
Executive incentive compensation............................ 25.9 18.9
Litigation and contingencies................................ 23.4 25.9
Deferred revenue............................................ 9.4 5.4
Other....................................................... 51.4 16.1
------ ------
Total other long-term liabilities................. $388.1 $219.3
====== ======

16. SHAREHOLDERS' EQUITY

Stock Option and Retention Stock Plans. Pursuant to the Company's stock
option and retention stock plans, 5,999,439 and 8,785,684 shares of Common Stock
were available for grant to employees and directors at December 31, 1998 and
1997, respectively. Shares may either be granted as options to purchase Common
Stock or as awards of retention stock. Options to purchase Common Stock under
the plans are generally granted with an exercise price equal to the fair market
value at the date of grant and are exercisable for a period of up to 10 years
from grant date. Option grants have been made to directors, officers and
employees and vest over periods up to 10 years from the grant date.

Retention stock is awarded under the plans to eligible employees, subject
to forfeiture if employment terminates during the prescribed retention period,
generally one to five years from grant. Grants of retention stock made in 1994
also required that designated Company stock prices be met to be exercisable.
These performance conditions were achieved during 1996.

To become exercisable, 933,000 options from the 1998 stock option grant
require that designated Company stock prices be met.

During 1995, UPC non-qualified stock options and certain UPC Incentive
Stock Options ("ISOs"), as well as UPC retention shares held by officers and
employees of the Company, were converted into non-qualified Company stock
options, ISOs and retention shares, respectively. The converted options and
retention shares retain the same exercise dates and vesting requirements as the
UPC options and retention shares for which they were exchanged.

65
68
UNION PACIFIC RESOURCES GROUP INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The status of the Company's stock-based compensation programs is as
follows:

WEIGHTED
COMPANY AVERAGE
SHARES EXERCISE PRICE
---------- --------------

Stock options:
Balance at December 31, 1995.............................. 3,789,638 $16.11
Conversion of UPC stock options........................ 681,206 19.49
Granted................................................ 1,471,400 27.81
Exercised.............................................. (437,472) 14.76
Expired/surrendered.................................... (288,698) 16.02
----------
Balance at December 31, 1996.............................. 5,216,074 19.97
Granted................................................ 1,111,750 25.63
Exercised.............................................. (351,723) 16.05
Expired/surrendered.................................... (91,615) 24.75
----------
Balance at December 31, 1997.............................. 5,884,486 21.20
Granted................................................ 2,951,375 17.01
Exercised.............................................. (57,487) 9.49
Expired/surrendered.................................... (207,635) 15.18
----------
Balance at December 31, 1998.............................. 8,570,739 19.84
==========
Exercisable December 31:
1996................................................... 3,035,905 $16.81
1997................................................... 3,853,035 18.72
1998................................................... 4,496,736 19.93

REGULAR PERFORMANCE
--------- -----------

Retention stock:
Balance at December 31, 1995.............................. 423,465 324,796
Awarded................................................ 604,530 --
Conversion of UPC retention stock...................... 2,610 18,698(a)
Achievement of performance conditions.................. 301,066 (301,066)
Vested................................................. (124,733) --
Forfeited, surrendered and other....................... (2,376) (42,428)(a)
--------- ---------
Unvested at December 31, 1996............................. 1,204,562 --
Awarded................................................ 209,114 --
Vested................................................. (376,295) --
Forfeited, surrendered and other....................... (34,693) --
--------- ---------
Unvested at December 31, 1997............................. 1,002,688 --
Awarded................................................ 45,580 --
Vested................................................. (531,951) --
Forfeited, surrendered and other....................... (19,200) --
--------- ---------
Unvested at December 31, 1998............................. 497,117 --
========= =========

66
69
UNION PACIFIC RESOURCES GROUP INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Weighted-average grant-date fair value of options and retention shares
granted:

RETENTION
OPTIONS(b) SHARES(c)
---------- ----------

1996........................................................ $ 9.15 $ 27.81
1997........................................................ 8.74 25.63
1998........................................................ 7.00 17.01

- ---------------

(a) Activity occurred prior to achievement of performance conditions.

(b) Calculated in accordance with the Black-Scholes option pricing model,
using the following weighted average assumptions:

1998 1997 1996
------- ------- -------

Expected volatility......................................... 51% 28% 26%
Expected dividend yield..................................... 2.25% 0.8% 0.7%
Expected option term........................................ 5 years 4 years 5 years
Risk-free rate of return.................................... 4.6% 5.7% 6.3%

Options to purchase Common Stock were as follows:

AS OF DECEMBER 31, 1998
--------------------------------------------------------
OPTIONS OUTSTANDING OPTIONS EXERCISABLE
--------------------------------- --------------------
WEIGHTED WEIGHTED WEIGHTED
AVERAGE AVERAGE AVERAGE
RANGE OF NUMBER OF YEARS TO EXERCISE NUMBER OF EXERCISE
EXERCISE PRICES SHARES EXPIRATION PRICE SHARES PRICE
- --------------- --------- ---------- -------- --------- --------

$10.44-$15.29............................. 1,909,265 5.01 $14.72 1,811,515 $14.86
$17.04-$20.94............................. 3,940,273 4.56 17.62 1,222,298 18.89
$22.50-$29.44............................. 2,721,201 7.32 26.17 1,462,923 27.05
--------- ---------
$10.44-$29.44............................. 8,570,739 5.53 19.84 4,496,736 19.93
========= =========

Since the Company applies the intrinsic value method in accounting for its
stock option and retention stock plans, it generally records no compensation
cost for its stock option plans. This method calculates compensation expense on
the measurement date (usually the date of grant) as the excess of the current
market price of the underlying common stock of the Company ("Common Stock") over
the amount the employee is required to pay for the shares, if any. The expense
is recognized over the vesting period of the grant or award. Compensation cost
recognized relating to retention stock was $6.5 million, $11.6 million and $7.4
million in 1998, 1997 and 1996, respectively. If compensation cost for the
Company's stock option plan had been determined based on the fair value at the
grant dates for awards under the plan and for options that were converted at the
Offering and Distribution, as described above, the Company's net income would
have been reduced by $13.8 million in 1998, $8 million in 1997 and $3 million in
1996. Basic and diluted earnings per share would have been reduced by $0.06 per
share in 1998, $0.03 per share in 1997 and $0.01 per share in 1996.

Earnings Per Share. Basic earnings per share ("EPS") excludes dilution and
is computed by dividing income available to common shareholders by the
weighted-average number of common shares outstanding for the period. Diluted EPS
reflects the potential dilution that could occur if securities or other
contracts to issue

67
70
UNION PACIFIC RESOURCES GROUP INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

common stock were exercised or converted into common stock. The reconciliation
between basic earnings per share ("EPS") and diluted earnings per share for the
years ended December 31 is as follows:

FOR THE YEARS ENDED DECEMBER 31,
-------------------------------------------
AVERAGE PER
INCOME SHARES SHARE
--------------------- ---------- ------
(MILLIONS OF DOLLARS) (MILLIONS)

1998
Basic EPS
Net loss.............................................. $(898.7) 247.7 $(3.63)
Less: loss from discontinued operations............... (15.6) -- (0.06)
------- ----- ------
Loss from continuing operations available to
shareholders....................................... (883.1) (3.57)
Effect of dilutive options.............................. -- --(a) --
------- ----- ------
Diluted EPS
Loss from continuing operations available to Common
shareholders....................................... $(883.1) 247.7 $(3.57)
======= ===== ======
1997
Basic EPS
Net Income............................................ $ 333.0 250.1 $ 1.33
Less: income from discontinued operations............. 29.9 -- 0.12
------- ----- ------
Income from continuing operations available to
shareholders....................................... 303.1 250.1 1.21
Effect of Dilutive options.............................. -- 0.8 --
------- ----- ------
Diluted EPS
Income from continuing operations available to Common
shareholders plus assumed conversion............... $ 303.1 250.9 $ 1.21
======= ===== ======
1996
Basic EPS
Net Income............................................ $ 320.8 249.2 $ 1.29
Less: income from discontinued operations............. 67.1 -- 0.27
------- ----- ------
Income from continuing operations available to
shareholders....................................... 253.7 1.02
Effect of dilutive options.............................. -- 0.9 (0.01)
------- ----- ------
Diluted EPS
Income from continuing operations available to Common
shareholders plus assumed conversion............... $ 253.7 250.1 $ 1.01
======= ===== ======

- ---------------
(a) 0.5 million average shares of options outstanding, as discussed above, have
been excluded from the 1998 calculation of diluted earnings per share
because to do so would have been antidilutive.

Employee Stock Ownership Plan. Effective January 2, 1997, the Company
instituted an employee stock ownership plan ("ESOP"). The ESOP purchased 3.7
million shares or $107.3 million of newly issued common stock (the "ESOP
Shares") from the Company, which will be used to fund the Company's matching
obligation under its 401(k) Thrift Plan. All domestic regular employees of the
Company are eligible to participate in the ESOP.

The ESOP Shares, which are held in trust, were purchased with the proceeds
from a 30-year loan from the Company. Such shares initially have been pledged as
collateral for the loan. As loan payments are made, shares will be released from
collateral, based on the proportion of debt service paid. Scheduled principal
and interest requirements are $7.5 million annually, and will be funded with
dividends paid on the unallocated

68
71
UNION PACIFIC RESOURCES GROUP INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

ESOP Shares and with cash contributions from the Company. Principal or interest
prepayments may be made to ensure that the Company's minimum matching obligation
is met.

Shares held by the ESOP will be included in the computation of earnings per
share as such ESOP Shares are released from collateral. Releases of ESOP Shares
will be allocated to participants' accounts and will be charged to compensation
expense at the fair market value of the shares on the date of the employer
match. Dividends on allocated ESOP Shares will be recorded as a reduction of
retained earnings; dividends on unallocated ESOP Shares will be recorded as a
reduction of the principal or accrued interest on the loan.

As of December 31, 1998, allocated and unallocated shares in the ESOP were
483,216 and 3,216,784, respectively. As of December 31, 1997, allocated and
unallocated shares were 197,395 and 3,502,605, respectively. The fair value of
unallocated ESOP shares at December 31, 1998 and 1997 is $29.2 million and $85.8
million, respectively. During 1998 and 1997, compensation cost related to the
allocation of ESOP shares to participants' accounts was $6.3 million and $5.3
million, respectively.

Preferred Stock and Shareholder Rights. The Company has 100 million shares
of no-par-value preferred stock authorized, none of which are outstanding. On
October 28, 1996, the Company's Board of Directors designated 3,000,000 of the
authorized preferred shares as non-redeemable Series A Junior Participating
Preferred Shares (the "Series A Preferred Stock"). Upon issuance, each
one-hundredth of a share of the Series A Preferred Stock will have dividend and
voting rights approximately equal to those of one share of the Company's common
stock. In addition, on October 28, 1996, the Board of Directors adopted a
shareholder rights plan with a "flip-in" threshold of 15 percent to ensure that
all shareholders of the Company receive fair value for their Common Stock in the
event of any proposed takeover of the Company and to guard against the use of
coercive tactics to gain control of the Company without offering fair value to
the Company's shareholders. Under the related Rights Agreement, the Company
declared a dividend of one right ("Right") for each outstanding share of common
stock to shareholders of record on November 7, 1996. Under certain limited
conditions as defined in the Rights Agreement, each Right entitles the
registered holder to purchase from the Company one one-hundredth of a share of
Series A Preferred Stock at $135 subject to adjustment. The Rights are not
exercisable until the Distribution Date (as defined in the Rights Agreement)
which will occur upon the earlier of (i) ten days following a public
announcement that an Acquiring Person (as defined in the Rights Agreement) has
acquired beneficial ownership of 15 percent or more of the Company's outstanding
Common Stock (the "Stock Acquisition Date") or (ii) ten business days following
the commencement of a tender offer or exchange offer that would result in a
person or group owning 15 percent or more of the Company's outstanding Common
Stock.

The Rights have certain anti-takeover effects. The Rights will cause
substantial dilution to a person or group that attempts to acquire the Company
without conditioning the offer on a substantial number of Rights being redeemed.
In the event that at any time following the Stock Acquisition Date certain
events occur as defined in the Rights Agreement, each holder of a Right, except
the Acquiring Person, will thereafter have the right to receive, upon exercise,
Company Common Stock or common stock of the acquiring company, as the case may
be, having a value equal to two times the exercise price of the Right.

The Rights should not interfere with any merger or other business
combination approved by the Company since the Board of Directors may, at its
option, at any time prior to the close of business on the earlier of the tenth
day following the Stock Acquisition Date or October 28, 2006, redeem all but not
less than all of the then outstanding Rights at $0.01 per Right. The Rights
expire on October 28, 2006, and do not have voting power or dividend privileges.

In 1998, the Company announced a program to repurchase up to $50 million of
its Common Stock in 1999. Under this program, during 1998 and 1997, the Company
repurchased 837,500 and 2,013,400 shares at a cost of $18.6 million and $49.9
million, respectively.

69
72
UNION PACIFIC RESOURCES GROUP INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Comprehensive Income. The Company's comprehensive income is as follows:

BEFORE-TAX NET-OF-TAX
AMOUNT TAX BENEFIT AMOUNT
---------- ----------- ----------
(MILLIONS OF DOLLARS)

Foreign currency translation adjustment............. $(149.6) $82.5 $(67.1)
Minimum pension liability adjustment................ (3.9) -- (3.9)
------- ----- ------
Other comprehensive income.......................... $(153.5) $82.5 $(71.0)
======= ===== ======

17. OTHER INCOME (EXPENSE) -- NET

Other income (expense) -- net consists of the following:

FOR THE YEARS ENDED
-----------------------
1998 1997 1996
------ ------ -----
(MILLIONS OF DOLLARS)

Insurance settlement proceeds............................... $ 3.3 $ 10.0 $ --
Excess reserve reductions................................... -- 23.0 1.8
Gain on sales of assets..................................... -- 7.2 4.5
Pennzoil Company acquisition costs(a)....................... (2.0) (17.8) --
UPC Spin-off charges........................................ -- -- (5.6)
Interest rate lock cost (Note 5)............................ (14.3) -- --
Foreign currency loss -- net (Note 5)....................... (35.5) -- --
Other -- net................................................ 3.2 2.1 (4.2)
------ ------ -----
Total other income (expense) -- net............... $(45.3) $ 24.5 $(3.5)
====== ====== =====

- ---------------

(a) Related to cost incurred with the unsuccessful takeover attempt of Pennzoil
Company.

70
73

UNION PACIFIC RESOURCES GROUP INC.

SUPPLEMENTARY INFORMATION (UNAUDITED)

A. PROVED RESERVES

The following table reflects estimated quantities of proved oil and gas
reserves, which have been prepared by the Company's petroleum engineers. The
Company considers such estimates to be reasonable; however, there are numerous
uncertainties inherent in estimating quantities of proved reserves, including
many factors beyond the control of the Company. Reserve engineering is a
subjective process which is dependent on the quality of available data and on
engineering and geological interpretation and judgment. Such reserve estimates
are subject to change over time as additional information becomes available.

UNITED OTHER
STATES CANADA INTERNATIONAL WORLDWIDE
------ ------ ------------- ---------

NATURAL GAS (BCF)(b): 1996
Beginning of year........................... 2,099 75 -- 2,174
Revisions of previous estimates............. 48 (2) -- 46
Extensions, discoveries and other
additions................................ 469 12 -- 481
Purchases of reserves-in-place.............. 52 -- -- 52
Sales of reserves-in-place.................. (6) -- -- (6)
Production.................................. (362) (7) -- (369)
----- ---- --- -----
Total proved, end of year........... 2,300 78 -- 2,378
===== ==== === =====
Proved developed reserves........... 2,055 70 -- 2,125
===== ==== === =====
NATURAL GAS (BCF)(b): 1997
Beginning of year........................... 2,300 78 -- 2,378
Revisions of previous estimates............. 13 (4) -- 9
Extensions, discoveries and other
additions................................ 574 14 -- 588
Purchases of reserves-in-place.............. 55 -- -- 55
Sales of reserves-in-place.................. (3) -- -- (3)
Production.................................. (401) (6) -- (407)
----- ---- --- -----
Total proved, end of year........... 2,538 82 -- 2,620
===== ==== === =====
Proved developed reserves........... 2,157 60 -- 2,217
===== ==== === =====
NATURAL GAS (BCF)(b): 1998
Beginning of year........................... 2,538 82 -- 2,620
Revisions of previous estimates............. 82 13 -- 95
Extensions, discoveries and other
additions................................ 277 101 10 388
Purchases of reserves-in-place.............. 210 998 37 1,245
Sales of reserves-in-place.................. (285) (97) -- (382)
Production.................................. (421) (103) (3) (527)
----- ---- --- -----
Total proved, end of year........... 2,401 994 44 3,439
===== ==== === =====
Proved developed reserves........... 2,079 854 35 2,968
===== ==== === =====
NATURAL GAS LIQUIDS (MMBBL)(b): 1996
Beginning of year........................... 93 7 -- 100
Revisions of previous estimates............. 12 -- -- 12
Extensions, discoveries and other
additions................................ 9 -- -- 9
Purchases of reserves-in-place.............. -- -- -- --
Sales of reserves-in-place.................. -- -- -- --
Production.................................. (13) (1) -- (14)
----- ---- --- -----
Total proved, end of year........... 101 6 -- 107
===== ==== === =====
Proved developed reserves........... 91 7 -- 98
===== ==== === =====

71
74

UNITED OTHER
STATES CANADA INTERNATIONAL WORLDWIDE
------ ------ ------------- ---------

NATURAL GAS LIQUIDS (MMBBL)(b): 1997
Beginning of year........................... 101 6 -- 107
Revisions of previous estimates............. 1 1 -- 2
Extensions, discoveries and other
additions................................ 21 1 -- 22
Purchases of reserves-in-place.............. 1 -- -- 1
Sales of reserves-in-place.................. -- -- -- --
Production.................................. (13) (1) -- (14)
----- ---- --- -----
Total proved, end of year........... 111 7 -- 118
===== ==== === =====
Proved developed reserves........... 96 7 -- 103
===== ==== === =====
NATURAL GAS LIQUIDS (MMBBL): 1998
Beginning of year........................... 111 7 -- 118
Revisions of previous estimates............. (10) 5 -- (5)
Extensions, discoveries and other
additions................................ 1 1 -- 2
Purchases of reserves-in-place.............. 3 18 -- 21
Sales of reserves-in-place.................. (29) (4) -- (33)
Production.................................. (10) (2) -- (12)
----- ---- --- -----
Total proved, end of year........... 66 25 -- 91
===== ==== === =====
Proved developed reserves........... 55 24 -- 79
===== ==== === =====
CRUDE OIL, INCLUDING CONDENSATE (MMBBL): 1996
Beginning of year........................... 74 7 3 84
Revisions of previous estimates............. (1) -- -- (1)
Extensions, discoveries and other
additions................................ 14 1 -- 15
Purchases of reserves-in-place.............. 4 -- -- 4
Sales of reserves-in-place.................. (2) -- -- (2)
Production.................................. (17) (1) (1) (19)
----- ---- --- -----
Total proved, end of year........... 72 7 2 81
===== ==== === =====
Proved developed reserves........... 66 6 2 74
===== ==== === =====
CRUDE OIL, INCLUDING CONDENSATE (MMBBL): 1997
Beginning of year........................... 72 7 2 81
Revisions of previous estimates............. 5 -- -- 5
Extensions, discoveries and other
additions................................ 57 -- -- 57
Purchases of reserves-in-place.............. 6 -- -- 6
Sales of reserves-in-place.................. -- -- -- --
Production.................................. (18) (1) (1) (20)
----- ---- --- -----
Total proved, end of year........... 122 6 1 129
===== ==== === =====
Proved developed reserves........... 87 6 1 94
===== ==== === =====
CRUDE OIL, INCLUDING CONDENSATE (MMBBL): 1998
Beginning of year........................... 122 6 1 129
Revisions of previous estimates............. (7) (4) 2 (9)
Extensions, discoveries and other
additions................................ 13 5 16 34
Purchases of reserves-in-place.............. 14 115 143 272
Sales of reserves-in-place.................. (7) (13) -- (20)
Production.................................. (22) (13) (15) (50)
----- ---- --- -----
Total proved, end of year........... 113 96 147 356
===== ==== === =====
Proved developed reserves........... 81 66 105 252
===== ==== === =====

72
75

UNITED OTHER
STATES CANADA INTERNATIONAL WORLDWIDE
------ ------ ------------- ---------

PROVED RESERVES EQUIVALENT, END OF 1996
(BCFE)(a)
Natural gas................................. 2,300 78 -- 2,378
Natural gas liquids......................... 603 42 -- 645
Crude oil, including condensate............. 435 39 10 484
----- ---- --- -----
Total proved........................ 3,338 159 10 3,507
===== ==== === =====
Proved developed reserves........... 2,995 151 10 3,156
===== ==== === =====
PROVED RESERVES EQUIVALENT, END OF 1997
(BCFE)(a)
Natural gas................................. 2,538 82 -- 2,620
Natural gas liquids......................... 665 42 -- 707
Crude oil, including condensate............. 730 37 6 773
----- ---- --- -----
Total proved........................ 3,933 161 6 4,100
===== ==== === =====
Proved developed reserves........... 3,255 139 6 3,400
===== ==== === =====
PROVED RESERVES EQUIVALENT, END OF 1998
(BCFE)(a)
Natural gas................................. 2,401 994 44 3,439
Natural gas liquids......................... 389 159 -- 548
Crude oil, including condensate............. 676 578 883 2,137
----- ---- --- -----
Total proved........................ 3,466 1,731 927 6,124
===== ==== === =====
Proved developed reserves........... 2,897 1,392 667 4,956
===== ==== === =====

- ---------------
(a) Calculated using the ratio of one Bbl to six Mcf.

(b) Reserves at the end of 1997 and 1996 include the plant share of equity gas
processed (natural gas and natural gas liquids, as appropriate, earned by
gas processing facilities through the processing of the Company's equity
production.)

73
76

B. DRILLING ACTIVITY

Drilling activity is summarized as follows:

OTHER
UNITED STATES CANADA INTERNATIONAL WORLDWIDE
------------- ------ ------------- ---------

FOR THE YEAR ENDED DECEMBER 31, 1998(a)
Gross wells...................................... 318 273 45 636
Gross productive wells........................... 290 243 42 575
Net wells:
Exploration.................................... 18 45 1 64
Development.................................... 248 115 22 385
--- --- -- ---
Total net wells........................ 266 160 23 449
=== === == ===
Net productive wells:
Exploration.................................... 13 32 1 46
Development.................................... 232 106 20 358
--- --- -- ---
Total net productive wells............. 245 138 21 404
=== === == ===
FOR THE YEAR ENDED DECEMBER 31, 1997
Gross wells...................................... 811 6 -- 817
Gross productive wells........................... 714 6 -- 720
Net wells:
Exploration.................................... 41 -- -- 41
Development.................................... 521 4 -- 525
--- --- -- ---
Total net wells........................ 562 4 -- 566
=== === == ===
Net productive wells:
Exploration.................................... 19 -- -- 19
Development.................................... 475 4 -- 479
--- --- -- ---
Total net productive wells............. 494 4 -- 498
=== === == ===
FOR THE YEAR ENDED DECEMBER 31, 1996
Gross wells...................................... 650 5 -- 655
Gross productive wells........................... 586 5 -- 591
Net wells:
Exploration.................................... 27 -- -- 27
Development.................................... 436 3 -- 439
--- --- -- ---
Total net wells........................ 463 3 -- 466
=== === == ===
Net productive wells:
Exploration.................................... 9 -- -- 9
Development.................................... 410 3 -- 413
--- --- -- ---
Total net productive wells............. 419 3 -- 422
=== === == ===

- ---------------
(a) In addition, at December 31, 1998, 10 gross wells (5 net wells) were in the
process of being drilled.

74
77

C. AVERAGE SALES PRICE AND COST

The average producing properties sales prices and costs are set forth
below:

AS OF YEARS ENDED DECEMBER 31,
--------------------------------
1998 1997 1996
-------- -------- --------

Natural gas sales price (per Mcf)
United States............................................. $ 1.84 $ 2.01 $ 1.87
Canada.................................................... 1.35 1.58 0.81
Other international....................................... 1.39 -- --
Total............................................. 1.74 2.00 1.85
Natural gas liquids sales price (per Bbl)
United States............................................. $ 8.14 $11.57 $11.80
Canada.................................................... 6.12 5.41 6.79
Other international....................................... -- -- --
Total............................................. 7.88 11.23 11.48
Crude oil sales price (per Bbl)
United States............................................. $13.23 $18.37 $18.93
Canada.................................................... 8.55 19.85 20.59
Other international....................................... 8.09 16.90 15.51
Total............................................. 10.48 18.36 18.84
Production cost (per Mcf)
United States............................................. $ 0.51 $ 0.51 $ 0.49
Canada.................................................... 0.41 0.29 0.44
Other international....................................... 0.54 0.77 0.72
Total production cost............................. 0.49 0.51 0.49

D. AVERAGE DAILY PRODUCTION AND SALES VOLUME

The average producing properties daily production and sales volume are set
forth below:

AS OF YEARS ENDED DECEMBER 31,
------------------------------
1998 1997 1996
-------- -------- --------

Natural gas (MMcfd)
United States............................................. 1,152.8 1,090.9 972.4
Canada.................................................... 281.2 17.6 16.5
Other international....................................... 7.1 -- --
------- ------- -------
Total natural gas................................. 1,441.1 1,108.5 988.9
======= ======= =======
Natural gas liquids (MBbld)
United States............................................. 28.8 30.0 28.6
Canada.................................................... 4.3 1.7 1.9
Other international....................................... -- -- --
------- ------- -------
Total natural gas liquids......................... 33.1 31.7 30.5
======= ======= =======
Crude oil (MBbld)
United States............................................. 61.0 49.2 46.7
Canada.................................................... 35.4 1.7 1.7
Other international....................................... 41.5 2.0 2.2
------- ------- -------
Total crude oil................................... 137.9 52.9 50.6
======= ======= =======
Total producing properties (MMcfed)
United States............................................. 1,692.0 1,565.8 1,423.8
Canada.................................................... 519.3 38.3 38.3
Other international....................................... 255.7 11.6 13.2
------- ------- -------
Total producing properties........................ 2,467.0 1,615.7 1,475.3
======= ======= =======

75
78

E. ACREAGE AND WELLS

Oil and gas leasehold acreage is as follows(a):

AS OF DECEMBER 31,
--------------------------------------------------
OTHER
UNITED STATES CANADA INTERNATIONAL WORLDWIDE
------------- ------ ------------- ---------
(THOUSANDS OF ACRES)

1998
Gross developed............................... 2,460 1,657 548 4,665
Net developed................................. 1,493 958 135 2,586
Gross undeveloped............................. 3,629 5,613 5,771 15,013
Net undeveloped............................... 2,469 2,185 3,194 7,848

1997
Gross developed............................... 2,200 34 83 2,317
Net developed................................. 1,528 20 21 1,569
Gross undeveloped............................. 3,836 240 -- 4,076
Net undeveloped............................... 2,759 150 -- 2,909

Productive oil and gas wells are as follows:

AS OF
DECEMBER 31, 1998
-----------------
OIL GAS
------ ------
(WELLS)

Gross(b).................................................... 4,446 9,504
Net......................................................... 3,160 7,323

- ---------------

(a) In addition, the Company has fee mineral ownership of approximately 9.6
million gross acres (8.5 million net acres), including 7.9 million gross
acres (7.7 million net acres) acquired through 19th century Congressional
Land Grant Acts. Substantial portions of this acreage are undeveloped and
are considered prospective for oil and gas.

(b) Approximately 2,404 are multiple completions, 2,183 of which are gas wells.

F. CAPITALIZED EXPLORATION AND PRODUCTION COSTS

Capitalized exploration and production costs are as follows:

OTHER
UNITED STATES CANADA INTERNATIONAL WORLDWIDE
------------- -------- ------------- ---------
(MILLIONS OF DOLLARS)

1998
Proved properties.......................... $ 1,184.9 $ 459.7 $ 251.4 $ 1,896.0
Unproved properties........................ 396.8 389.2 455.5 1,241.5
Wells and related equipment................ 4,739.5 1,838.6 1,005.7 7,583.8
Uncompleted wells and equipment............ 142.7 -- -- 142.7
--------- -------- -------- ---------
Gross capitalized costs.......... 6,463.9 2,687.5 1,712.6 10,864.0
Accumulated depreciation, depletion and
amortization............................. (3,603.2) (833.5) (438.5) (4,875.2)
--------- -------- -------- ---------
Net capitalized costs............ $ 2,860.7 $1,854.0 $1,274.1 $ 5,988.8
========= ======== ======== =========
1997
Proved properties.......................... $ 988.9 $ 3.6 $ 0.5 $ 993.0
Unproved properties........................ 438.6 10.9 -- 449.5
Wells and related equipment................ 4,205.0 121.5 29.7 4,356.2
Uncompleted wells and equipment............ 305.0 -- -- 305.0
--------- -------- -------- ---------
Gross capitalized costs.......... 5,937.5 136.0 30.2 6,103.7
Accumulated depreciation, depletion and
amortization............................. (3,210.7) (46.1) (19.8) (3,276.6)
--------- -------- -------- ---------
Net capitalized costs............ $ 2,726.8 $ 89.9 $ 10.4 $ 2,827.1
========= ======== ======== =========

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79

G. COSTS INCURRED IN EXPLORATION AND DEVELOPMENT

Costs incurred (whether capitalized or expensed) in oil and gas property
acquisition, exploration and development activities are as follows:

OTHER
UNITED STATES CANADA INTERNATIONAL WORLDWIDE
------------- -------- ------------- ---------
(MILLIONS OF DOLLARS)

1998
Costs incurred:
Proved acreage......................... $ 424.4 $1,733.7 $ 744.7 $2,902.8
Unproved acreage....................... 45.5 279.1 312.2 636.8
Exploration costs(a)................... 195.9 43.8 29.5 269.2
Development costs...................... 506.3 136.5 107.8 750.6
-------- -------- -------- --------
Total costs incurred(b)........ $1,172.1 $2,193.1 $1,194.2 $4,559.4
======== ======== ======== ========
1997
Costs incurred:
Proved acreage......................... $ 130.6 $ -- $ -- $ 130.6
Unproved acreage....................... 199.7 1.0 -- 200.7
Exploration costs(a)................... 231.9 5.0 -- 236.9
Development costs...................... 617.8 4.0 -- 621.8
-------- -------- -------- --------
Total costs incurred(b)........ $1,180.0 $ 10.0 $ -- $1,190.0
======== ======== ======== ========
1996
Costs incurred:
Proved acreage......................... $ 85.7 $ -- $ -- $ 85.7
Unproved acreage....................... 149.1 0.7 -- 149.8
Exploration costs(a)................... 112.2 2.4 -- 114.6
Development costs...................... 426.7 2.8 -- 429.5
-------- -------- -------- --------
Total costs incurred(b)........ $ 773.7 $ 5.9 $ -- $ 779.6
======== ======== ======== ========

- ---------------
(a) Includes allocated exploration overhead costs of $24.2 million in 1998,
$23.5 million in 1997 and $22.5 million in 1996, and delay rentals of $12.3
million in 1998, $14.8 million in 1997 and $4.4 million in 1996.

(b) Excludes capital expenditures relating to discontinued operations of $143.8
million in 1998, $343.3 million in 1997 and $107.3 million in 1996.

H. RESULTS OF OPERATIONS FOR PRODUCING ACTIVITIES:(A)

The results of operations for producing activities is set forth below:

OTHER
UNITED STATES CANADA INTERNATIONAL WORLDWIDE
------------- --------- ------------- ---------
(MILLIONS OF DOLLARS)

FOR THE YEAR ENDED DECEMBER 31, 1998
Revenues............................... $ 1,314.6 $ 259.2 $ 126.1 $ 1,699.9
Production costs....................... (317.0) (77.3) (50.0) (444.3)
Exploration expenses................... (267.4) (25.3) (46.3) (339.0)
Depreciation, depletion and
amortization......................... (816.2) (915.3) (384.3) (2,115.8)
--------- --------- ------- ---------
Total costs.................. (1,400.6) (1,017.9) (480.6) (2,899.1)
--------- --------- ------- ---------
Pretax results......................... (86.0) (758.7) (354.5) (1,199.2)
Income taxes (benefit)................. (48.3) (337.7) (95.0) (481.0)
--------- --------- ------- ---------
Results of operations........ $ (37.7) $ (421.0) $(259.5) $ (718.2)
========= ========= ======= =========

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80

OTHER
UNITED STATES CANADA INTERNATIONAL WORLDWIDE
------------- --------- ------------- ---------
(MILLIONS OF DOLLARS)

FOR THE YEAR ENDED DECEMBER 31, 1997
Revenues............................... $ 1,337.3 $ 28.9 $ 12.0 $ 1,378.2
Production costs....................... (293.4) (4.1) (3.3) (300.8)
Exploration expenses................... (197.6) (4.4) (2.7) (204.7)
Depreciation, depletion and
amortization......................... (481.7) (10.2) (7.4) (499.3)
--------- --------- ------- ---------
Total costs.................. (972.7) (18.7) (13.4) (1,004.8)
--------- --------- ------- ---------
Pretax results......................... 364.6 10.2 (1.4) 373.4
Income taxes........................... 108.9 -- -- 108.9
--------- --------- ------- ---------
Results of operations........ $ 255.7 $ 10.2 $ (1.4) $ 264.5
========= ========= ======= =========
FOR THE YEAR ENDED DECEMBER 31, 1996
Revenues............................... $ 1,204.5 $ 23.3 $ 12.5 $ 1,240.3
Production costs....................... (253.6) (6.1) (3.5) (263.2)
Exploration expenses................... (127.5) (3.5) (13.6) (144.6)
Depreciation, depletion and
amortization......................... (459.8) (5.9) (7.7) (473.4)
--------- --------- ------- ---------
Total costs.................. (840.9) (15.5) (24.8) (881.2)
--------- --------- ------- ---------
Pretax results......................... 363.6 7.8 (12.3) 359.1
Income taxes........................... 111.4 -- -- 111.4
--------- --------- ------- ---------
Results of operations........ $ 252.2 $ 7.8 $ (12.3) $ 247.7
========= ========= ======= =========

- ---------------
(a) Gathering, processing and marketing results, general and administrative
expenses, other income/expense and interest costs have been excluded in
computing these results of operations. Revenues include net gains from
sales of assets of $139.6 million in 1998, $18.3 million in 1997 and $3.9
million in 1996. Depreciation, depletion and amortization includes asset
impairments of $1.2 billion in 1998, $20.2 million in 1997 and $34.4
million in 1996.

I. STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATES TO PROVED
OIL AND GAS RESERVES:

The standardized measure of discounted cash flows relating to oil and gas
reserves are set forth below:

OTHER
UNITED STATES CANADA INTERNATIONAL WORLDWIDE
------------- ------ ------------- ---------
(MILLIONS OF DOLLARS)

AS OF DECEMBER 31, 1998
Future cash inflows from sales of oil and gas..... $ 6,210 $2,642 $1,128 $ 9,980
Future production and development costs........... (1,619) (998) (641) (3,258)
Future income taxes............................... (942) (536) (55) (1,533)
------- ------ ------ -------
Future net cash flows............................. 3,649 1,108 432 5,189
10% annual discount............................... (1,394) (405) (165) (1,964)
------- ------ ------ -------
Standardized measure of discounted future net cash
flows........................................... $ 2,255 $ 703 $ 267 $ 3,225
======= ====== ====== =======
AS OF DECEMBER 31, 1997
Future cash inflows from sales of oil and gas..... $ 8,822 $ 355 $ 15 $ 9,192
Future production and development costs........... (2,032) (55) (4) (2,091)
Future income taxes............................... (1,953) (86) (4) (2,043)
------- ------ ------ -------
Future net cash flows............................. 4,837 214 7 5,058
10% annual discount............................... (1,926) (85) (1) (2,012)
------- ------ ------ -------
Standardized measure of discounted future net cash
flows........................................... $ 2,911 $ 129 $ 6 $ 3,046
======= ====== ====== =======

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81

OTHER
UNITED STATES CANADA INTERNATIONAL WORLDWIDE
------------- ------ ------------- ---------
(MILLIONS OF DOLLARS)

AS OF DECEMBER 31, 1996
Future cash inflows from sales of oil and gas..... $11,569 $ 349 $ 28 $11,946
Future production and development costs........... (1,896) (111) (6) (2,013)
Future income taxes............................... (2,952) (73) (7) (3,032)
------- ------ ------ -------
Future net cash flows............................. 6,721 165 15 6,901
10% annual discount............................... (2,590) (70) (2) (2,662)
------- ------ ------ -------
Standardized measure of discounted future net cash
flows........................................... $ 4,131 $ 95 $ 13 $ 4,239
======= ====== ====== =======

An analysis of changes in the standardized measure of discounted future net
cash flows follows:

AS OF DECEMBER 31,
---------------------------
1998 1997 1996
------- ------- -------
(MILLIONS OF DOLLARS)

Beginning of year........................................... $ 3,046 $ 4,239 $ 1,871
Changes due to current year operations:
Additions and discoveries less related production and
other costs.......................................... 438 1,000 1,135
Sales of oil and gas -- net of production costs........ (1,160) (1,078) (961)
Development costs...................................... 751 622 430
Purchases of reserves-in-place......................... 1,712 125 181
Sales of reserves-in-place............................. (245) (4) (48)
Changes due to revisions in:
Price.................................................. (1,110) (2,452) 2,763
Development costs...................................... (911) (427) (269)
Quantity estimates..................................... 34 87 28
Income taxes........................................... 232 639 (1,063)
Other.................................................. 38 (289) (69)
Discount accretion.......................................... 400 584 241
------- ------- -------
End of year................................................. $ 3,225 $ 3,046 $ 4,239
======= ======= =======

Future oil and gas sales and production and development costs have been
estimated using prices and costs in effect as of each year-end. Prices used to
estimate future oil and gas sales represent the closing price for trading in
December contracts on the New York Mercantile Exchange adjusted for appropriate
regional price differentials. Such weighted average prices for 1998, 1997 and
1996 were $1.63 per Mcfe, $2.24 per Mcfe and $3.41 per Mcfe, respectively.
Future production hedged as of year-end is included in future net revenues at
the hedged price. Such prices may vary significantly from actual prices realized
by the Company for its future production. Future net revenues were discounted to
present value at 10 percent, a uniform rate set by the Financial Accounting
Standards Board. Income taxes represent the tax effect (at statutory rates) of
the difference between the standardized measure values and tax bases of the
underlying properties at the end of the year.

Changes in the supply and demand for oil, natural gas and natural gas
liquids, hydrocarbon price volatility, inflation, timing of production, reserve
revisions and other factors make these estimates inherently imprecise and
subject to substantial revision. As a result, these measures are not the
Company's estimate of future cash flows nor do these measures serve as an
estimate of current market value.

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82

J. SELECTED QUARTERLY DATA

Selected unaudited quarterly data are as follows:

FOR THE QUARTERS ENDED
-------------------------------------------------
MARCH 31 JUNE 30 SEPTEMBER 30 DECEMBER 31
-------- ------- ------------ -----------
(MILLIONS OF DOLLARS, EXCEPT PER SHARE AMOUNTS)

1998
Operating revenues.............................. $408.0 $501.7 $558.4 $ 372.9
Operating income (loss)......................... 61.2 (13.2) 81.2 (1,322.4)
Income (loss) from continuing operations........ 24.7 (33.8) (13.1) (860.9)
Net income (loss)............................... 31.2 (17.3) (17.3) (895.4)
Per share:
Income (loss) from continuing operations...... $ 0.10 $(0.13) $(0.06) $ (3.48)
Net income (loss)............................. 0.13 (0.07) (0.07) (3.61)
Dividends..................................... 0.05 0.05 0.05 0.05
Common stock price:
High.......................................... 24 1/2 25 1/4 18 9/16 14 1/2
Low........................................... 20 7/8 16 9/16 8 5/16 8 1/4
1997
Operating revenues.............................. $418.3 $364.0 $342.2 $ 393.5
Operating income................................ 162.6 100.5 69.8 101.0
Income from continuing operations............... 104.3 67.4 53.9 77.5
Net income...................................... 117.2 74.4 67.2 74.2
Per share:
Income from continuing operations............. $ 0.42 $ 0.27 $ 0.22 $ 0.31
Net income.................................... 0.47 0.30 0.27 0.30
Dividends..................................... 0.05 0.05 0.05 0.05
Common stock price:
High.......................................... 31 5/8 29 7/8 26 15/16 27 13/16
Low........................................... 23 7/8 24 1/2 23 23 1/4

First quarter 1997 results reflect the impact of increases in hydrocarbon
prices. Second quarter 1998 results reflect the impact of purchase of Norcen.
Fourth quarter 1998 results reflect the decrease in hydrocarbon prices and a
$1.2 billion writedown and impairment of certain oil and gas assets.

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

On December 4, 1997, the Company, with the approval of the Audit Committee
of the Company's Board of Directors, dismissed Deloitte & Touche LLP ("D&T") as
its independent auditors, effective upon D&T's completion of its audit of the
Company's financial statements for the fiscal year ended December 31, 1997. The
reports of D&T on the financial statements of the Company for each of 1997 and
1996 did not contain an adverse opinion or disclaimer of opinion and were not
qualified or modified as to uncertainty, audit scope or accounting principle.
During such years and through the date on which D&T was dismissed, there was no
disagreement between the Company and D&T on any matter of accounting principles
or practices, financial statement disclosure or audit scope or procedure, which
disagreements, if not resolved to the satisfaction of D&T, would have caused D&T
to make reference to the subject matter of such disagreement in connection with
its report on the Company's financial statements. On December 4, 1997, the
Company engaged Arthur Andersen LLP as its new independent auditor effective
January 1, 1998.

80
83

PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

(a) Directors of Registrant.

Information as to the names, ages, positions and offices with the Company,
terms of office, periods of service, business experience during the past five
years and certain other directorships held by each director or person nominated
to become a director is set forth in the Election of Directors segment of the
Proxy Statement and is incorporated herein by reference.

(b) Executive Officers of Registrant.

Information concerning executive officers is presented in Part I of this
report under Executive Officers of the Registrant.

Information concerning compliance with Section 16(a) of the Securities
Exchange Act of 1934 is set forth in the Reports of Ownership segment of the
Proxy Statement and is incorporated herein by reference.

ITEM 11. EXECUTIVE COMPENSATION

Information concerning remuneration received by executive officers and
directors is presented in the Compensation of Directors, Compensation Committee
Interlocks and Insider Participation and Executive Compensation segments of the
Proxy Statement and is incorporated herein by reference.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

Information as to the number of shares of equity securities beneficially
owned as of March 9, 1999, by each director and nominee for director, the five
most highly compensated executive officers and directors and executive officers
as a group is set forth in the Security Ownership of Certain Executives,
Directors and Beneficial Owners segment of the Proxy Statement and is
incorporated herein by reference.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

Information on related transactions is set forth in the Compensation
Committee Interlocks and Insider Participation segment of the Proxy Statement
and is incorporated herein by reference.

PART IV

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

(a) (1) and (2) Financial Statements and Schedules.

See "Index to Consolidated Financial Statements" set forth in Item 8 of
this Form 10-K.

No schedules are required to be filed because of the absence of conditions
under which they would be required or because the required information is set
forth in the financial statements referred to above.

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84

(a) (3) Exhibits.

Exhibits not incorporated herein by reference to a prior filing are
designated by an asterisk (*) and are filed herewith; all exhibits not so
designated are incorporated herein by reference to the Company's Form S-1
Registration Statement, Registration No. 33-95398, filed on October 10, 1995
("Form S-1") or as otherwise indicated.

EXHIBIT
NUMBER DESCRIPTION OF EXHIBIT
------- ----------------------

2.1 -- Pre-acquisition agreement between Union Pacific Resources
Group Inc., Union Pacific Resources Inc. and Norcen
Energy Resources Limited, dated January 25, 1998
(incorporated herein by reference to Exhibit 2.1 to the
Company's Current Report on Form 8-K, filed on March 17,
1998).
3.1 -- Amended and Restated Articles of Incorporation of Union
Pacific Resources Group Inc. (Exhibit 3.1 to Form S-1 and
Exhibit 3.2 to the Company's Annual Report on Form 10-K
for the year ended December 31, 1996).
3.2 -- Amended and Restated By-Laws of Union Pacific Resources
Group Inc. (Exhibit 3.2 to Form S-1).
4.1 -- Specimen of Certificate evidencing the Common Stock
(Exhibit 4 to Form S-1).
4.2 -- Amended and Restated Rights Agreement, dated as of
December 1, 1998, between Union Pacific Resources Group
Inc. and Harris Trust and Savings Bank, as rights agent
(incorporated herein by reference to the Exhibit to the
Company's Report on Form 8-A12G/A filed on February 5,
1999).
4.3 -- Indenture, dated as of March 27, 1996, between Union
Pacific Resources Group Inc. and Texas Commerce Bank
National Association, as trustee (incorporated herein by
reference to Exhibit 4.1 to the Company's Form S-3
Registration Statement, Registration No. 333-2984, dated
May 23, 1996).
4.4(a) -- Terms Agreement, dated as of October 10, 1996, for
$200,000,000 7 1/2% debentures due October 15, 2026
(incorporated herein by reference to Exhibit 4.4 to the
Company's Current Report on Form 8-K filed on March 17,
1998).
4.4(b) -- Form of 7 1/2% Rate Debenture due October 15, 2026
(incorporated herein by reference to Exhibit 4.7 to the
Company's Current Report on Form 8-K filed on March 17,
1998).
4.5(a) -- Terms Agreement, dated as of October 10, 1996, for
$200,000,000 7% notes due October 15, 2006 (incorporated
herein by reference to Exhibit 4.5 to the Company's
Current Report on Form 8-K filed on March 17, 1998).
4.5(b) -- Form of 7% Rate Note due October 15, 2006 (incorporated
herein by reference to Exhibit 4.8 to the Company's
Current Report on Form 8-K filed on March 17, 1998).
4.6(a) -- Terms Agreement, dated as of October 31, 1996, for
$150,000,000 7 1/2% debentures due November 1, 2096
(incorporated herein by reference to Exhibit 4.6 to the
Company's Current Report on Form 8-K filed on March 17,
1998).
4.6(b) -- Form of 7 1/2% Rate Note due November 1, 2096
(incorporated herein by reference to Exhibit 4.9 to the
Company's Current Report on Form 8-K filed on March 17,
1998).
4.7 -- Trust Indenture, dated as of May 7, 1996, providing for
the issue of Debt Securities in unlimited principal
amount, between Norcen Energy Resources Limited and
Montreal Trust Company of Canada, as trustee
(incorporated herein by reference to Exhibit 4.10 to the
Company's Current Report on Form 8-K filed on March 17,
1998).

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85

EXHIBIT
NUMBER DESCRIPTION OF EXHIBIT
------- ----------------------

4.8 -- First Supplemental Indenture, dated as of May 22, 1996,
to Trust Indenture dated as of May 7, 1996, providing for
the issue of 7 3/8% Debentures due May 15, 2006, in
aggregate principal amount of U.S. $250,000,000 between
Norcen Energy Resources Limited and Montreal Trust
Company of Canada, as trustee (incorporated herein by
reference to Exhibit 4.11 to the Company's Current Report
on Form 8-K filed on March 17, 1998).
4.9 -- Second Supplemental Indenture, dated as of June 26, 1996,
to Trust Indenture dated as of May 7, 1996, providing for
the issue of 7.8% Debentures due July 2, 2008, in
aggregate principal amount of U.S. $150,000,000 between
Norcen Energy Resources Limited and Montreal Trust
Company of Canada, as trustee (incorporated herein by
reference to Exhibit 4.12 to the Company's Current Report
on Form 8-K filed on March 17, 1998).
4.10 -- Third Supplemental Indenture, dated as of June 26, 1996,
to Trust Indenture dated as of May 7, 1996, providing for
the issue of 6.8% Debentures due July 2, 2002, in
aggregate principal amount of U.S. $250,000,000 between
Norcen Energy Resources Limited and Montreal Trust
Company of Canada, as trustee (incorporated herein by
reference to Exhibit 4.13 to the Company's Current Report
on Form 8-K filed on March 17, 1998).
4.11 -- Fourth Supplemental Indenture, dated as of February 27,
1998, to Trust Indenture dated as of May 7, 1996,
providing for the Guarantee of all Securities Issued or
Previously Issued under the Trust Indenture between
Norcen Energy Resources Limited, Union Pacific Resources
Group Inc., as guarantor, and Montreal Trust Company of
Canada, as trustee (incorporated herein by reference to
Exhibit 4.14 to the Company's Current Report on Form 8-K
filed on March 17, 1998).
4.12(a) -- Terms Agreement for $200,000,000 6.50% Notes due May 15,
2005 (incorporated herein by reference to Exhibit 4.1 to
the Company's Current Report on Form 8-K filed on May 26,
1998).
4.12(b) -- Form of 6.50% Note due May 15, 2005 (incorporated herein
by reference to Exhibit 4.5 to the Company's Current
Report on Form 8-K filed on May 26, 1998).
4.13(a) -- Terms Agreement for $200,000,000 6.75% Notes due May 15,
2008 (incorporated herein by reference to Exhibit 4.2 to
the Company's Current Report on Form 8-K filed on May 26,
1998).
4.13(b) -- Form of 6.75% Note due May 15, 2008 (incorporated herein
by reference to Exhibit 4.6 to the Company's Current
Report on Form 8-K filed on May 26, 1998).
4.14(a) -- Terms Agreement for $200,000,000 7.05% Notes due May 15,
2018 (incorporated herein by reference to Exhibit 4.3 to
the Company's Current Report on Form 8-K filed on May 26,
1998).
4.14(b) -- Form of 7.05% Debenture due May 15, 2018 (incorporated
herein by reference to Exhibit 4.7 to the Company's
Current Report on Form 8-K filed on May 26, 1998).
4.15(a) -- Terms Agreement for $425,000,000 7.15% Notes due May 15,
2028 (incorporated herein by reference to Exhibit 4.4 to
the Company's Current Report on Form 8-K filed on May 26,
1998).
4.15(b) -- Form of 7.15% Debenture due May 15, 2028 (incorporated
herein by reference to Exhibit 4.8 to the Company's
Current Report on Form 8-K filed on May 26, 1998).
10.1 -- Tax Allocation Agreement, dated October 6, 1995 (Exhibit
10.3 to Form S-1).
10.2 -- Indemnification Agreement, dated October 1, 1995 (Exhibit
10.4 to Form S-1).

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86

EXHIBIT
NUMBER DESCRIPTION OF EXHIBIT
------- ----------------------

10.3 -- Pension Plan Agreement, dated October 1, 1995 by and
between Union Pacific Corporation and Union Pacific
Resources Group Inc. (Exhibit 10.7 to Form S-1).
10.4 -- The Supplemental Pension Plan for Officers and Managers
of Union Pacific Corporation and Affiliates, with
amendments (incorporated herein by reference to Exhibit
10.11 to the Company's Annual Report on Form 10-K for the
year ended December 31, 1995).
10.5 -- The Supplemental Pension Plan for Exempt Salaried
Employees of Union Pacific Resources Company and
Affiliates, with amendments (incorporated herein by
reference to Exhibit 10.12 to the Company's Annual Report
on Form 10-K for the year ended December 31, 1995).
10.6 -- Executive Incentive Plan of Union Pacific Resources Group
Inc. as amended and restated June 1, 1997 (incorporated
herein by reference to Exhibit 10.2 to the Company's
Quarterly Report on Form 10-Q for the period ended March
31, 1997).
10.7(a) -- 1995 Stock Option and Retention Stock Plan of Union
Pacific Resources Group Inc. as amended and restated,
effective June 1, 1997 (incorporated herein by reference
to Exhibit 4.2 to the Company's Registration Statement on
Form S-8, dated February 28, 1997).
*10.7(b) -- Second Amendment, effective January 21, 1999, to 1995
Stock Option and Retention Stock Plan of Union Pacific
Resources Group Inc.
*10.8(a) -- 1995 Directors Stock Incentive Plan, as amended and
restated, effective July 14, 1998.
*10.8(b) -- First Amendment, effective January 21, 1999, to 1995
Directors Stock Incentive Plan, as amended and restated,
effective July 14, 1998.
10.9 -- Union Pacific Resources Group Inc. Deferred Compensation
Plan for the Board of Directors, as amended and restated,
effective September 5, 1997 (incorporated herein by
reference to Exhibit 99.2 to the Company's Registration
Statement on Form S-8, dated September 15, 1997).
10.10 -- Union Pacific Resources Group Inc. Executive Deferred
Compensation Plan, effective September 5, 1997
(incorporated herein by reference to Exhibit 99.1 to the
Company's Registration Statement on Form S-8, dated
September 15, 1997).
10.11(a) -- Conversion Agreement (Exhibit 10.13(a) to Form S-1).
10.11(b) -- Conversion Agreement for Drew Lewis (Exhibit 10.13(b) to
Form S-1).
10.11(c) -- Conversion Agreement for Jack L. Messman (Exhibit
10.13(c) to Form S-1).
10.12 -- The Union Pacific Resources Group Inc. Executive Life
Insurance Plan, adopted February 26, 1997 (incorporated
herein by reference to Exhibit 10.16 to the Company's
Annual Report on Form 10-K for the year ended December
31, 1996).
10.13(a) -- Form of Agreement relating to Change in Control by and
between Union Pacific Resources Group Inc. and Jack L.
Messman, dated February 4, 1997 (incorporated herein by
reference to Exhibit 10.17(a) to the Company's Annual
Report on Form 10-K for the year ended December 31,
1996).
10.13(b) -- Form of Agreement relating to Change in Control by and
between Union Pacific Resources Group Inc. and each of
George Lindahl III and V. Richard Eales, dated February
4, 1997 (incorporated herein by reference to Exhibit
10.17(b) to the Company's Annual Report on Form 10-K for
the year ended December 31, 1996).

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87

EXHIBIT
NUMBER DESCRIPTION OF EXHIBIT
------- ----------------------

10.13(c) -- Form of Agreement relating to Change in Control by and
between Union Pacific Resources Group Inc. and each of
Anne M. Franklin, Joseph A. LaSala, Jr., Donald W.
Niemiec, Morris B. Smith and John B. Vering, dated
February 4, 1997 (incorporated herein by reference to
Exhibit 10.17(c) to the Company's Annual Report on Form
10-K for the year ended December 31, 1996).
10.13(d) -- Form of Agreement relating to Change in Control by and
between Union Pacific Resources Group Inc. and Thomas R.
Blank, dated July 13, 1998 (incorporated herein by
reference to Exhibit 10.4 to the Company's Quarterly
Report on Form 10-Q/A filed November 12, 1998).
*10.13(e) -- Form of Amendment, dated as of January 21, 1999, to
Change in Control Agreements between Union Pacific
Resources Group Inc. and Jack L. Messman, George Lindahl
III, V. Richard Eales, Donald W. Niemiec, Morris B.
Smith, Anne M. Franklin, Joseph A. LaSala, Jr., and John
B. Vering, all dated February 4, 1997, and between Union
Pacific Resources Group Inc. and Thomas R. Blank dated
July 13, 1998.
10.14(a) -- Amended and Restated 1976 Coal Purchase Contract, dated
as of January 1, 1993, between Commonwealth Edison
Company and Black Butte Coal Company (Exhibit 10.19 to
Form S-1).
10.14(b) -- Amendment No. 1 to Amended and Restated 1976 Coal
Purchase Contract between Commonwealth Edison Company and
Black Butte Coal Company, effective as of January 1, 1996
(incorporated herein by reference to Exhibit 10.35 to the
Company's Annual Report on Form 10-K for the year ended
December 31, 1997).
10.14(c) -- Amendment No. 2 to Amended and Restated 1976 Coal
Purchase Contract between Commonwealth Edison Company and
Black Butte Coal Company, effective as of January 1, 1997
(incorporated herein by reference to Exhibit 10.36 to the
Company's Annual Report on Form 10-K for the year ended
December 31, 1997).
10.15(a) -- Transportation Agreement, dated December 15, 1989, by and
between Kern River Gas Transmission Company and Union
Pacific Fuels, Inc. (Exhibit 10.21 to Form S-1).
10.15(b) -- Amendments to Transportation Agreement dated December 15,
1989, by and between Kern River Gas Transmission Company
and Union Pacific Fuels, Inc. (incorporated herein by
reference to Exhibit 10.16 to the Company's Annual Report
on Form 10-K for the year ended December 31, 1997).
10.16 -- Gas Transportation Agreement, dated June 18, 1997, by and
between Union Pacific Fuels, Inc. and Texas Gas
Transmission Corporation (incorporated herein by
reference to Exhibit 10.17 to the Company's Annual Report
on Form 10-K for the year ended December 31, 1997).
10.17 -- Registration Rights Agreement, dated as of August 3,
1995, among Union Pacific Resources Group Inc., The
Anschutz Corporation and Anschutz Foundation
(incorporated herein by reference to Exhibit 10.19 to the
Company's Annual Report on Form 10-K for the year ended
December 31, 1995).
10.18(a) -- Agreement, dated as of August 3, 1995, by and among Union
Pacific Resources Group Inc., The Anschutz Corporation,
Anschutz Foundation and Mr. Philip F. Anschutz ("the
Anschutz Agreement") (incorporated herein by reference to
Exhibit 10.20 to the Company's Annual Report on Form 10-K
for the year ended December 31, 1995).

85
88

EXHIBIT
NUMBER DESCRIPTION OF EXHIBIT
------- ----------------------

10.18(b) -- Letter agreement, dated as of January 20, 1997, amending
the Anschutz Agreement (incorporated herein by reference
to Exhibit 10.25 to the Company's Annual Report on Form
10-K for the year ended December 31, 1996).
10.19 -- U.S. $25,000,000 Revolving Loan Agreement dated July 14,
1997, between Basic Petroleum International Limited and
Royal Bank of Canada (incorporated herein by reference to
Exhibit 10.33 to the Company's Annual Report on Form 10-K
for the year ended December 31, 1997).
10.20 -- U.S. $1,000,000,000 364-day Competitive Advance/Revolving
Credit Agreement, dated as of October 27, 1998, among
Union Pacific Resources Group Inc. and Chase Bank of
Texas, N.A., as administrative agent and the banks named
therein (incorporated herein by reference to Exhibit 10.1
to the Company's Quarterly Report on Form 10-Q/A filed
November 12, 1998).
10.21 -- U.S. $750,000,000 364-day Competitive Advance/Revolving
Credit Agreement, dated as of October 27, 1998, among
Union Pacific Resources Group Inc. and Chase Bank of
Texas, N.A., as administrative agent and the banks named
therein (incorporated herein by reference to Exhibit 10.2
to the Company's Quarterly Report on Form 10-Q/A filed
November 12, 1998).
10.22 -- U.S. $750,000,000 Five-Year Competitive Advance/Revolving
Credit Agreement, dated as of October 27, 1998, among
Union Pacific Resources Group Inc. and Chase Bank of
Texas, N.A., as administrative agent, The Chase Manhattan
Bank of Canada, as Canadian sub-agent and the banks named
therein (incorporated herein by reference to Exhibit 10.3
to the Company's Quarterly Report on Form 10-Q/A filed
November 12, 1998).
*10.23(a) -- Merger and Purchase Agreement, dated November 20, 1998,
among Union Pacific Resources Company, Union Pacific
Fuels, Inc., Duke Energy Field Services, Inc. and DEFS
Merger Sub Corp.
*10.23(b) -- Amendment, dated February 1, 1999, to Merger and Purchase
Agreement, dated November 20, 1998, among Union Pacific
Resources Company, Union Pacific Fuels, Inc., Duke Energy
Field Services, Inc. and DEFS Merger Sub Corp.
*12 -- Computation of ratio of earnings to fixed charges.
*21 -- List of subsidiaries.
*23.1 -- Consent of Arthur Andersen LLP dated as of March 15,
1999.
*23.2 -- Consent of Deloitte & Touche LLP dated as of March 15,
1999.
*24 -- Powers of attorney for Directors.
*27.1 -- Financial data schedule for the year ended December 31,
1998.
*27.2 -- Restated financial data schedules for the years ended
December 31, 1997 and 1996, for the three months ended
March 31, 1998, for the six months ended June 30, 1998,
and for the nine months ended September 30, 1998.

(b) Reports on Form 8-K.

On December 4, 1998, the Company filed a Current Report on Form 8-K
containing a copy of a press release announcing the execution of a Merger and
Purchase Agreement for the sale of the Company's domestic gas gathering,
processing and marketing operations to Duke Energy Field Services for $1.35
billion.

On January 15, 1999, the Company filed a Current Report on Form 8-K
containing a copy of a press release making three announcements: (i) the Company
will take a $760 million non-cash charge to earnings in

86
89

the fourth quarter resulting from asset impairments, (ii) the Company's
preliminary capital budget for 1999 of approximately $500 million and (iii) a
continuing cost reduction program.

On January 28, 1999, the Company filed a Current Report on Form 8-K
announcing the Company's 1998 annual operating results, net income and certain
other financial and statistical information.

87
90

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, on this 15th day of
March, 1999.

UNION PACIFIC RESOURCES GROUP INC.

By /s/ MORRIS B. SMITH
-----------------------------------
Morris B. Smith,
Vice President and Chief Financial
Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below, on this 15th day of March, 1999, by the following
persons on behalf of the registrant and in the capacities indicated.

/s/ JACK L. MESSMAN Chairman, Chief Executive Officer and Director
- ----------------------------------------------------- (Principal Executive Officer)
Jack L. Messman

/s/ MORRIS B. SMITH Vice President and Chief Financial Officer
- ----------------------------------------------------- (Principal Accounting and Financial Officer)
Morris B. Smith

* Director
- -----------------------------------------------------
H. Jesse Arnelle

* Director
- -----------------------------------------------------
Lynne V. Cheney

* Director
- -----------------------------------------------------
Preston M. Geren III

* Director
- -----------------------------------------------------
Lawrence M. Jones

* Director
- -----------------------------------------------------
Drew Lewis

* Director
- -----------------------------------------------------
Claudine B. Malone

* Director
- -----------------------------------------------------
John W. Poduska, Sr., Ph.D.

* Director
- -----------------------------------------------------
Michael E. Rossi

* Director
- -----------------------------------------------------
Samuel K. Skinner

* Director
- -----------------------------------------------------
James R. Thompson

*By /s/ JOSEPH A. LASALA, JR.
--------------------------------
(Joseph A. LaSala, Jr.,
as attorney-in-fact)

87
91

INDEX TO EXHIBITS

EXHIBIT
NUMBER DESCRIPTION OF EXHIBIT
------- ----------------------

2.1 -- Pre-acquisition agreement between Union Pacific Resources
Group Inc., Union Pacific Resources Inc. and Norcen
Energy Resources Limited, dated January 25, 1998
(incorporated herein by reference to Exhibit 2.1 to the
Company's Current Report on Form 8-K, filed on March 17,
1998).
3.1 -- Amended and Restated Articles of Incorporation of Union
Pacific Resources Group Inc. (Exhibit 3.1 to Form S-1 and
Exhibit 3.2 to the Company's Annual Report on Form 10-K
for the year ended December 31, 1996).
3.2 -- Amended and Restated By-Laws of Union Pacific Resources
Group Inc. (Exhibit 3.2 to Form S-1).
4.1 -- Specimen of Certificate evidencing the Common Stock
(Exhibit 4 to Form S-1).
4.2 -- Amended and Restated Rights Agreement, dated as of
December 1, 1998, between Union Pacific Resources Group
Inc. and Harris Trust and Savings Bank, as rights agent
(incorporated herein by reference to the Exhibit to the
Company's Report on Form 8-A12G/A filed on February 5,
1999).
4.3 -- Indenture, dated as of March 27, 1996, between Union
Pacific Resources Group Inc. and Texas Commerce Bank
National Association, as trustee (incorporated herein by
reference to Exhibit 4.1 to the Company's Form S-3
Registration Statement, Registration No. 333-2984, dated
May 23, 1996).
4.4(a) -- Terms Agreement, dated as of October 10, 1996, for
$200,000,000 7 1/2% debentures due October 15, 2026
(incorporated herein by reference to Exhibit 4.4 to the
Company's Current Report on Form 8-K filed on March 17,
1998).
4.4(b) -- Form of 7 1/2% Rate Debenture due October 15, 2026
(incorporated herein by reference to Exhibit 4.7 to the
Company's Current Report on Form 8-K filed on March 17,
1998).
4.5(a) -- Terms Agreement, dated as of October 10,1996, for
$200,000,000 7% notes due October 15, 2006 (incorporated
herein by reference to Exhibit 4.5 to the Company's
Current Report on Form 8-K filed on March 17, 1998).
4.5(b) -- Form of 7% Rate Note due October 15, 2006 (incorporated
herein by reference to Exhibit 4.8 to the Company's
Current Report on Form 8-K filed on March 17, 1998).
4.6(a) -- Terms Agreement, dated as of October 31, 1996, for
$150,000,000 7 1/2% debentures due November 1, 2096
(incorporated herein by reference to Exhibit 4.6 to the
Company's Current Report on Form 8-K filed on March 17,
1998).
4.6(b) -- Form of 7 1/2% Rate Note due November 1, 2096
(incorporated herein by reference to Exhibit 4.9 to the
Company's Current Report on Form 8-K filed on March 17,
1998).
4.7 -- Trust Indenture, dated as of May 7, 1996, providing for
the issue of Debt Securities in unlimited principal
amount, between Norcen Energy Resources Limited and
Montreal Trust Company of Canada, as trustee
(incorporated herein by reference to Exhibit 4.10 to the
Company's Current Report on Form 8-K filed on March 17,
1998).
4.8 -- First Supplemental Indenture, dated as of May 22, 1996,
to Trust Indenture dated as of May 7, 1996, providing for
the issue of 7 3/8% Debentures due May 15, 2006, in
aggregate principal amount of U.S. $250,000,000 between
Norcen Energy Resources Limited and Montreal Trust
Company of Canada, as trustee (incorporated herein by
reference to Exhibit 4.11 to the Company's Current Report
on Form 8-K filed on March 17, 1998).

EXHIBIT
NUMBER DESCRIPTION OF EXHIBIT
------- ----------------------

4.9 -- Second Supplemental Indenture, dated as of June 26, 1996,
to Trust Indenture dated as of May 7, 1996, providing for
the issue of 7.8% Debentures due July 2, 2008, in
aggregate principal amount of U.S. $150,000,000 between
Norcen Energy Resources Limited and Montreal Trust
Company of Canada, as trustee (incorporated herein by
reference to Exhibit 4.12 to the Company's Current Report
on Form 8-K filed on March 17, 1998).
4.10 -- Third Supplemental Indenture, dated as of June 26, 1996,
to Trust Indenture dated as of May 7, 1996, providing for
the issue of 6.8% Debentures due July 2, 2002, in
aggregate principal amount of U.S. $250,000,000 between
Norcen Energy Resources Limited and Montreal Trust
Company of Canada, as trustee (incorporated herein by
reference to Exhibit 4.13 to the Company's Current Report
on Form 8-K filed on March 17, 1998).
4.11 -- Fourth Supplemental Indenture, dated as of February 27,
1998, to Trust Indenture dated as of May 7, 1996,
providing for the Guarantee of all Securities Issued or
Previously Issued under the Trust Indenture between
Norcen Energy Resources Limited, Union Pacific Resources
Group Inc., as guarantor, and Montreal Trust Company of
Canada, as trustee (incorporated herein by reference to
Exhibit 4.14 to the Company's Current Report on Form 8-K
filed on March 17, 1998).
4.12(a) -- Terms Agreement for $200,000,000 6.50% Notes due May 15,
2005 (incorporated herein by reference to Exhibit 4.1 to
the Company's Current Report on Form 8-K filed on May 26,
1998).
4.12(b) -- Form of 6.50% Note due May 15, 2005 (incorporated herein
by reference to Exhibit 4.5 to the Company's Current
Report on Form 8-K filed on May 26, 1998).
4.13(a) -- Terms Agreement for $200,000,000 6.75% Notes due May 15,
2008 (incorporated herein by reference to Exhibit 4.2 to
the Company's Current Report on Form 8-K filed on May 26,
1998).
4.13(b) -- Form of 6.75% Note due May 15, 2008 (incorporated herein
by reference to Exhibit 4.6 to the Company's Current
Report on Form 8-K filed on May 26, 1998).
4.14(a) -- Terms Agreement for $200,000,000 7.05% Notes due May 15,
2018 (incorporated herein by reference to Exhibit 4.3 to
the Company's Current Report on Form 8-K filed on May 26,
1998).
4.14(b) -- Form of 7.05% Debenture due May 15, 2018 (incorporated
herein by reference to Exhibit 4.7 to the Company's
Current Report on Form 8-K filed on May 26, 1998).
4.15(a) -- Terms Agreement for $425,000,000 7.15% Notes due May 15,
2028 (incorporated herein by reference to Exhibit 4.4 to
the Company's Current Report on Form 8-K filed on May 26,
1998).
4.15(b) -- Form of 7.15% Debenture due May 15, 2028 (incorporated
herein by reference to Exhibit 4.8 to the Company's
Current Report on Form 8-K filed on May 26, 1998).
10.1 -- Tax Allocation Agreement, dated October 6, 1995 (Exhibit
10.3 to Form S-1).
10.2 -- Indemnification Agreement, dated October 1, 1995 (Exhibit
10.4 to Form S-1).
10.3 -- Pension Plan Agreement, dated October 1, 1995 by and
between Union Pacific Corporation and Union Pacific
Resources Group Inc. (Exhibit 10.7 to Form S-1).
10.4 -- The Supplemental Pension Plan for Officers and Managers
of Union Pacific Corporation and Affiliates, with
amendments (incorporated herein by reference to Exhibit
10.11 to the Company's Annual Report on Form 10-K for the
year ended December 31, 1995).

EXHIBIT
NUMBER DESCRIPTION OF EXHIBIT
------- ----------------------

10.5 -- The Supplemental Pension Plan for Exempt Salaried
Employees of Union Pacific Resources Company and
Affiliates, with amendments (incorporated herein by
reference to Exhibit 10.12 to the Company's Annual Report
on Form 10-K for the year ended December 31, 1995).
10.6 -- Executive Incentive Plan of Union Pacific Resources Group
Inc. as amended and restated June 1, 1997 (incorporated
herein by reference to Exhibit 10.2 to the Company's
Quarterly Report on Form 10-Q for the period ended March
31, 1997).
10.7(a) -- 1995 Stock Option and Retention Stock Plan of Union
Pacific Resources Group Inc. as amended and restated,
effective June 1, 1997 (incorporated herein by reference
to Exhibit 4.2 to the Company's Registration Statement on
Form S-8, dated February 28, 1997).
*10.7(b) -- Second Amendment, effective January 21, 1999, to 1995
Stock Option and Retention Stock Plan of Union Pacific
Resources Group Inc.
*10.8(a) -- 1995 Directors Stock Incentive Plan, as amended and
restated, effective July 14, 1998.
*10.8(b) -- First Amendment, effective January 21, 1999, to 1995
Directors Stock Incentive Plan, as amended and, effective
restated July 14, 1998.
10.9 -- Union Pacific Resources Group Inc. Deferred Compensation
Plan for the Board of Directors, as amended and restated,
effective September 5, 1997 (incorporated herein by
reference to Exhibit 99.2 to the Company's Registration
Statement on Form S-8, dated September 15, 1997).
10.10 -- Union Pacific Resources Group Inc. Executive Deferred
Compensation Plan, effective September 5, 1997
(incorporated herein by reference to Exhibit 99.1 to the
Company's Registration Statement on Form S-8, dated
September 15, 1997).
10.11(a) -- Conversion Agreement (Exhibit 10.13(a) to Form S-1).
10.11(b) -- Conversion Agreement for Drew Lewis (Exhibit 10.13(b) to
Form S-1).
10.11(c) -- Conversion Agreement for Jack L. Messman (Exhibit
10.13(c) to Form S-1).
10.12 -- The Union Pacific Resources Group Inc. Executive Life
Insurance Plan, adopted February 26, 1997 (incorporated
herein by reference to Exhibit 10.16 to the Company's
Annual Report on Form 10-K for the year ended December
31, 1996).
10.13(a) -- Form of Agreement relating to Change in Control by and
between Union Pacific Resources Group Inc. and Jack L.
Messman, dated February 4, 1997 (incorporated herein by
reference to Exhibit 10.17(a) to the Company's Annual
Report on Form 10-K for the year ended December 31,
1996).
10.13(b) -- Form of Agreement relating to Change in Control by and
between Union Pacific Resources Group Inc. and each of
George Lindahl III and V. Richard Eales, dated February
4, 1997 (incorporated herein by reference to Exhibit
10.17(b) to the Company's Annual Report on Form 10-K for
the year ended December 31, 1996).
10.13(c) -- Form of Agreement relating to Change in Control by and
between Union Pacific Resources Group Inc. and each of
Anne M. Franklin, Joseph A. LaSala, Jr., Donald W.
Niemiec, Morris B. Smith and John B. Vering, dated
February 4, 1997 (incorporated herein by reference to
Exhibit 10.17(c) to the Company's Annual Report on Form
10-K for the year ended December 31, 1996).
10.13(d) -- Form of Agreement relating to Change in Control by and
between Union Pacific Resources Group Inc. and Thomas R.
Blank, dated July 13, 1998 (incorporated herein by
reference to Exhibit 10.4 to the Company's Quarterly
Report on Form 10-Q/A filed November 12, 1998).

EXHIBIT
NUMBER DESCRIPTION OF EXHIBIT
------- ----------------------

*10.13(e) -- Form of Amendment, dated as of January 21, 1999, to
Change in Control Agreements between Union Pacific
Resources Group Inc. and Jack L. Messman, George Lindahl
III, V. Richard Eales, Donald W. Niemiec, Morris B.
Smith, Anne M. Franklin, Joseph A. LaSala, Jr., and John
B. Vering, all dated February 4, 1997, and between Union
Pacific Resources Group Inc. and Thomas R. Blank dated
July 13, 1998.
10.14(a) -- Amended and Restated 1976 Coal Purchase Contract, dated
as of January 1, 1993, between Commonwealth Edison
Company and Black Butte Coal Company (Exhibit 10.19 to
Form S-1).
10.14(b) -- Amendment No. 1 to Amended and Restated 1976 Coal
Purchase Contract between Commonwealth Edison Company and
Black Butte Coal Company, effective as of January 1, 1996
(incorporated herein by reference to Exhibit 10.35 to the
Company's Annual Report on Form 10-K for the year ended
December 31, 1997).
10.14(c) -- Amendment No. 2 to Amended and Restated 1976 Coal
Purchase Contract between Commonwealth Edison Company and
Black Butte Coal Company, effective as of January 1, 1997
(incorporated herein by reference to Exhibit 10.36 to the
Company's Annual Report on Form 10-K for the year ended
December 31, 1997).
10.15(a) -- Transportation Agreement, dated December 15, 1989, by and
between Kern River Gas Transmission Company and Union
Pacific Fuels, Inc. (Exhibit 10.21 to Form S-1).
10.15(b) -- Amendments to Transportation Agreement dated December 15,
1989, by and between Kern River Gas Transmission Company
and Union Pacific Fuels, Inc. (incorporated herein by
reference to Exhibit 10.16 to the Company's Annual Report
on Form 10-K for the year ended December 31, 1997).
10.16 -- Gas Transportation Agreement, dated June 18, 1997, by and
between Union Pacific Fuels, Inc. and Texas Gas
Transmission Corporation (incorporated herein by
reference to Exhibit 10.17 to the Company's Annual Report
on Form 10-K for the year ended December 31, 1997).
10.17 -- Registration Rights Agreement, dated as of August 3,
1995, among Union Pacific Resources Group Inc., The
Anschutz Corporation and Anschutz Foundation
(incorporated herein by reference to Exhibit 10.19 to the
Company's Annual Report on Form 10-K for the year ended
December 31, 1995).
10.18(a) -- Agreement, dated as of August 3, 1995, by and among Union
Pacific Resources Group Inc., The Anschutz Corporation,
Anschutz Foundation and Mr. Philip F. Anschutz ("the
Anschutz Agreement") (incorporated herein by reference to
Exhibit 10.20 to the Company's Annual Report on Form 10-K
for the year ended December 31, 1995).
10.18(b) -- Letter agreement, dated as of January 20, 1997, amending
the Anschutz Agreement (incorporated herein by reference
to Exhibit 10.25 to the Company's Annual Report on Form
10-K for the year ended December 31, 1996).
10.19 -- U.S. $25,000,000 Revolving Loan Agreement dated July 14,
1997, between Basic Petroleum International Limited and
Royal Bank of Canada (incorporated herein by reference to
Exhibit 10.33 to the Company's Annual Report on Form 10-K
for the year ended December 31, 1997).

EXHIBIT
NUMBER DESCRIPTION OF EXHIBIT
------- ----------------------

10.20 -- U.S. $1,000,000,000 364-day Competitive Advance/Revolving
Credit Agreement, dated as of October 27, 1998, among
Union Pacific Resources Group Inc. and Chase Bank of
Texas, N.A., as administrative agent and the banks named
therein (incorporated herein by reference to Exhibit 10.1
to the Company's Quarterly Report on Form 10-Q/A filed
November 12, 1998).
10.21 -- U.S. $750,000,000 364-day Competitive Advance/Revolving
Credit Agreement, dated as of October 27, 1998, among
Union Pacific Resources Group Inc. and Chase Bank of
Texas, N.A., as administrative agent and the banks named
therein (incorporated herein by reference to Exhibit 10.2
to the Company's Quarterly Report on Form 10-Q/A filed
November 12, 1998).
10.22 -- U.S. $750,000,000 Five-Year Competitive Advance/Revolving
Credit Agreement, dated as of October 27, 1998, among
Union Pacific Resources Group Inc. and Chase Bank of
Texas, N.A., as administrative agent, The Chase Manhattan
Bank of Canada, as Canadian sub-agent and the banks named
therein (incorporated herein by reference to Exhibit 10.3
to the Company's Quarterly Report on Form 10-Q/A filed
November 12, 1998).
*10.23(a) -- Merger and Purchase Agreement, dated November 20, 1998,
among Union Pacific Resources Company, Union Pacific
Fuels, Inc., Duke Energy Field Services, Inc. and DEFS
Merger Sub Corp.
*10.23(b) -- Amendment, dated February 1, 1999, to Merger and Purchase
Agreement, dated November 20, 1998, among Union Pacific
Resources Company, Union Pacific Fuels, Inc., Duke Energy
Field Services, Inc. and DEFS Merger Sub Corp.
*12 -- Computation of ratio of earnings to fixed charges.
*21 -- List of subsidiaries.
*23.1 -- Consent of Arthur Andersen LLP dated as of March 15,
1999.
*23.2 -- Consent of Deloitte & Touche LLP dated as of March 15,
1999.
*24 -- Powers of attorney for Directors.
*27.1 -- Financial data schedule for the year ended December 31,
1998.
*27.2 -- Restated financial data schedules for the years ended
December 31, 1997 and 1996, for the three months ended
March 31, 1998, for the six months ended June 30, 1998,
and for the nine months ended September 30, 1998.

- ---------------

* Filed herewith