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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549-1004
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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, 1997 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.)
801 CHERRY STREET
FORT WORTH, TEXAS 76102
(ADDRESS OF PRINCIPAL EXECUTIVE OFFICES) (ZIP CODE)
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REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE: (817) 877-6000
SECURITIES REGISTERED PURSUANT TO SECTION 12(B) OF THE ACT:
TITLE OF EACH NAME OF EACH EXCHANGE ON WHICH
CLASS 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. / /
As of February 27, 1998, the aggregate market value of the registrant's
common stock held by non-affiliates (using the New York Stock Exchange closing
price) was approximately $5.5 billion.
The number of shares outstanding of the registrant's common stock as of
February 27, 1998 was 251,043,100.
Certain portions of the registrant's definitive Proxy Statement for the
Annual Meeting of Shareholders to be held on May 20, 1998 (the 'Proxy
Statement') are incorporated in Part III by reference.
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TABLE OF CONTENTS
PAGE
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PART I
Item 1. Business....................................................................................... 1
Item 2. Properties..................................................................................... 10
Item 3. Legal Proceedings.............................................................................. 13
Item 4. Submission of Matters to a Vote of Security Holders............................................ 14
PART II
Item 5. Market for the Registrant's Common Equity and Related Stockholder Matters...................... 16
Item 6. Selected Financial Data........................................................................ 16
Item 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations.......................................................................... 17
Item 8. Financial Statements and Supplementary Data.................................................... 32
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure........... 63
PART III
Item 10. Directors and Executive Officers of the Registrant............................................. 64
Item 11. Executive Compensation......................................................................... 64
Item 12. Security Ownership of Certain Beneficial Owners and Management................................. 64
Item 13. Certain Relationships and Related Transactions................................................. 64
PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K................................ 65
Signatures................................................................................................ 70
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 wells and acres. Natural
gas liquids are referred to herein as ('NGLs').
i
PART I
ITEM 1. BUSINESS
GENERAL
Union Pacific Resources Group Inc., a Utah corporation (the 'Company'), is
engaged primarily in the exploration for and the development and production of
natural gas, natural gas liquids and crude oil in several major producing basins
in the United States and Canada. The Company emphasizes natural gas in its
exploration and production activities and also owns and operates significant
assets, in proximity to its principal producing properties, dedicated to 'gas
value chain' activities, which consist of the gathering, processing,
transportation and marketing of natural gas and natural gas liquids. The
Company, through its wholly owned subsidiary, Union Pacific Fuels, Inc. ('UP
Fuels'), markets approximately 76% of the Company's natural gas, 88% of its
crude oil and 96% of its natural gas liquids, together with significant volumes
of natural gas, natural gas liquids and crude oil produced by others. 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 (hereinafter
defined) holdings in Wyoming. The 'Land Grant' consists of land granted by the
Federal government to a predecessor and former affiliate of the Company in the
mid-1800s which passes through the states of Colorado and Wyoming and into Utah.
The Company has fee ownership of the mineral rights under approximately 7.9
million acres in the Land Grant. As of December 31, 1997, over 90% of the
Company's revenues are generated, and assets and reserves, are located in the
United States.
BUSINESS STRATEGY
The Company continues to be primarily in the business of developing and
exploring for natural gas and crude oil in its core geographic areas. The
Company's strategy is to focus on its core geographic areas in which the Company
can apply economies of scale, its operating experience and its expertise in
advanced drilling and completion technologies, as well as, to increase margins
through reductions in drilling and operating costs, and to add value through
effective sales and distribution networks. This focus generates increased
production and enhanced well results. The Company also increases its drill site
inventory through exploration, farm-in agreements and acquisitions of properties
and companies. The Company recently purchased the capital stock of Norcen Energy
Resources Limited ('Norcen') for approximately $2.6 billion (not including
Norcen debt). The Norcen acquisition will enhance the Company's onshore and
offshore Gulf Coast core area and add new core areas in Canada, Guatemala and
Venezuela. See page 27 for additional information including information
regarding the impact of the Norcen acquisition on the Company's debt structure.
The Company strives to improve its service to its customers and other
constituencies, including its partners, governmental agencies, interest owners,
vendors, employees, investors, bankers, and producers. The Company believes that
providing each customer with a high level of service will differentiate the
Company from its competition and provide the Company with a competitive
advantage.
PRODUCING PROPERTIES OPERATIONS
The Company's oil and gas activities currently are concentrated in six core
geographic areas: (1) the Austin Chalk trend in Texas and Louisiana, managed by
the Austin Chalk business unit, (2) the western portion of the Land Grant Area
in Wyoming and Utah, managed by the Rockies business unit, (3) the eastern
portion of the Land Grant in Colorado and Wyoming, with additional operations
primarily in Kansas, southern Texas and western Canada, managed by the South
Texas/Plains/Canada business unit, (4) the onshore and offshore Gulf Coast area,
managed by the Gulf Onshore/Offshore business unit, (5) eastern Texas, managed
by the East Texas business unit, and (6) western Texas, managed by the West
Texas business unit.
Natural gas and natural gas liquids constituted 81% of the Company's total
proved reserves of 4.1 Tcfe as of December 31, 1997, and 83% of the Company's
sales volumes of 1.9 Bcfed for the year then ended. For the same period,
approximately 69% of the Company's production from producing properties was
attributable to Company-operated properties.
1
The following table sets forth certain proved reserve and production
information as of December 31, 1997 with respect to each of the Company's
business units.
TOTAL PRODUCING
PROVED PERCENT PROPERTY PERCENT
RESERVES 1 OF VOLUME 2 OF
BUSINESS UNIT (BCFE) TOTAL (MMCFED) TOTAL
- --------------------------------------------------------------- ------------ ------- ----------- -------
Austin Chalk................................................... 724 18% 558 35%
Rockies........................................................ 1,203 29 414 26
South Texas/Plains/Canada...................................... 602 15 213 13
Gulf Onshore/Offshore.......................................... 327 8 122 8
East Texas..................................................... 651 16 178 11
West Texas..................................................... 593 14 114 7
------ ------- ----------- -------
Total..................................................... 4,100 100% 1,599 100%
------ ------- ----------- -------
------ ------- ----------- -------
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1 Reflects future production attributable to (i) the Company's natural gas,
natural gas liquids and crude oil production from producing
properties and (ii) the Company's portion, by virtue of its ownership
interest in gas processing facilities, of natural gas and natural gas
liquids earned by such facilities through the processing of the Company's
production from producing properties. At some of its gas processing
facilities, the Company earns gas and natural gas liquids through the
processing of third party volumes. Volumes attributable to third party
processing are not reflected in the Company's proved reserves.
2 An additional 280 MMcfed volumes related to the Company's equity interest
in gas plant ownership were produced for the year ended December 31,
1997.
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. The
Austin Chalk business unit's production is located primarily in three fields:
Giddings, Brookeland and Masters Creek. The Masters Creek field in Louisiana and
the Shallow Giddings field in Texas are currently the most active. Since 1988,
the Company has participated in the drilling of approximately 1,500 wells and
has made aggregate capital expenditures over $2 billion in the Austin Chalk
trend. The Company controls approximately 2.1 million developed and undeveloped
net acres in the Austin Chalk and has increased its volumes from an average of
37 MMcfed in January 1990 to an average of 558 MMcfed during 1997. During 1997,
90% of the Austin Chalk business unit's production was attributable to
Company-operated properties.
Rockies Business Unit. The Rockies business unit manages the Company's oil
and gas activities in the western portion of the Land Grant in Wyoming and Utah.
The Rockies business unit operations are concentrated in the Green River Basin
and the Overthrust area. The Rockies business unit currently controls
approximately 3.5 million developed and undeveloped net acres, principally
attributable to the Land Grant. During 1997, 25% of the production from the
Rockies business unit was attributable to Company-operated properties.
South Texas/Plains/Canada Business Unit. The South Texas/Plains/Canada
business unit manages the Company's oil and gas activities primarily in four
areas: the eastern portion of the Land Grant in Colorado and Wyoming, the
Hugoton/Panoma field in Kansas, the Stratton/Agua Dulce area in southern Texas
and fields in western Canada. The South Texas/Plains/Canada business unit
currently controls more than 5.8 million developed and undeveloped net acres,
principally attributable to the Land Grant. During 1997, 67% of the production
from the South Texas/Plains/Canada business unit was attributable to
Company-operated properties.
Gulf Onshore/Offshore Business Unit. The Gulf Onshore/Offshore business
unit manages the Company's oil and gas activities in the Gulf of Mexico and in
the onshore Gulf Coast area. The Gulf Onshore/Offshore business unit primarily
conducts exploration activities in southern Louisiana and the Gulf of Mexico.
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 also formed an alliance with another major
oil and gas company to evaluate a large geographic acreage position in
southwestern Louisiana. During 1997, 42% of the production from the Gulf
Onshore/Offshore business unit was attributable to Company-operated properties.
East Texas Business Unit. The East Texas business unit manages the
Company's oil and gas activities in eastern Texas. The East Texas business
unit's activities are concentrated in two major areas: the Carthage and Oakhill
fields. In addition, the Company conducted exploration activities in the Cotton
Valley Pinnacle Reef
2
Trend. For the year ended December 31, 1997, 81% of the production from the East
Texas business unit was attributable to Company-operated properties.
West Texas Business Unit. The West Texas business unit manages the
Company's oil and gas activities in western Texas, principally in the Ozona
field in the Permian Basin area. The Company has drilled over 850 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 recently applied its
horizontal expertise in the western Texas area and has drilled over 50
horizontal wells. As of December 31, 1997, approximately 95% of the producing
wells in the West Texas business unit were Company-operated and 92% of the
production in West Texas business unit was attributable to Company-operated
properties.
GATHERING, PROCESSING AND MARKETING OPERATIONS
Processing. As of December 31, 1997, the Company owned interests in 24
natural gas processing plants, 19 of which it operates, with a current
throughput capacity of 3.4 Bcfd (1.8 Bcfd net to the Company). In 1997, the
Company expanded its gathering, processing and marketing business unit with the
purchase of Highlands Gas Corporation ('Highlands') which included three gas
processing plants. The Company was able to add approximately 300 MMcfd
throughput capacity with the purchase of Highlands, start-up of the new Masters
Creek plant in Louisiana and the expansion of the Patrick Draw plant in Wyoming.
Aggregate throughput of the Company's gas processing plants for the year ended
December 31, 1997 averaged 83% of the plants' aggregate design capacity. For the
year ended December 31, 1997, production of natural gas liquids attributable to
the Company's ownership interest in gas processing facilities averaged
approximately 41.7 MBbld. See 'Properties--Gas Processing Assets'.
Gathering. The Company invests in gathering systems and natural gas,
natural gas liquids and crude oil pipelines. Some of the Company's more
significant investments in pipelines and gathering systems, include: (1) the
Company's 50% interest in the Black Lake Pipeline, a 317 mile pipeline in
Louisiana which transports natural gas liquids from the Austin Chalk area to
markets on the Gulf Coast; (2) the Company's 90% interest in the Panola Pipeline
in the eastern Texas area; (3) the Company's 100% interest in the Sonora/Fin Tex
NGL Pipeline which serves the western Texas area; (4) the Company's 55% interest
in the Ferguson-Burleson County Gas Gathering System ('Ferguson-Burleson'),
which serves the Giddings area of the Austin Chalk area; (5) the Company's 99%
interest in the Overland Trail Transmission Company pipeline, a 305 mile
pipeline, serving the Green River Basin in Wyoming; and (6) the Company's 100%
interest in the Wahsatch Gathering System, a sour gas pipeline serving the
Overthrust area in Wyoming. In addition to the systems listed in the
'Properties-Pipeline Assets' table, the Company generally owns extensive
gathering systems behind each of its natural gas processing plants which it uses
to transport unprocessed gas from producing wells to the inlet of the plants.
Marketing. In 1997, the Company, primarily through UP Fuels, sold
approximately 2 Bcfd of natural gas (about 57% of which represented the
Company's equity production), 145 MBbld of natural gas liquids (including 73
MBbld of third party liquids) and 68 MBbld of crude oil and condensate
(including 15 MBbld of third party crude oil and condensate).
In addition, UP Fuels provides storage and transportation services in
certain natural gas supply and market areas and manages the Company's market
hubs in eastern Texas and the Land Grant area. The Company has a diverse
customer base for natural gas, which includes local distribution companies,
power generation facilities, pipelines, industrial plants and other wholesale
marketing companies. The natural gas liquids customers that UP Fuels targets are
wholesalers, industrial end users and traders. UP Fuels prefers to sell its
natural gas liquids in local markets, which generally offer more attractive
pricing. Natural gas liquids not sold locally are shipped from the various
plants by pipelines to the Company's partially owned fractionators in Mt.
Belvieu, Texas. To maximize profits, UP Fuels sells crude oil directly to
refiners whenever possible. UP Fuels also exchanges or sells the crude oil
volumes to major trading locations, where the crude oil is sold to both refiners
and marketers.
3
VOLUMES, PRICES AND PRODUCTION COSTS
The following table sets forth certain information regarding the Company's
volumes of and average price realizations for natural gas, natural gas liquids
and crude oil sales, and average production costs per Mcfe for each of the last
three years.
YEARS ENDED DECEMBER 31,
-----------------------------
1997 1996 1995
------- ------- -------
PRODUCING PROPERTIES:
Average daily production: 1
Natural gas (MMcfd)........................................................ 1,102.3 980.3 915.6
Natural gas liquids (MBbld)................................................ 29.9 28.5 23.1
Crude oil (MBbld).......................................................... 52.9 50.6 52.8
Total (MMcfed).......................................................... 1,598.8 1,454.9 1,371.0
Average sales prices:
Natural gas (per Mcf)...................................................... $ 2.00 $ 1.86 $ 1.42
Natural gas liquids (per Bbl).............................................. 11.20 11.39 8.14
Crude oil (per Bbl)........................................................ 18.36 18.84 16.08
Production costs (per Mcfe): 2............................................... 0.50 0.49 0.42
GAS PROCESSING PLANTS:
Average daily sales volumes attributable to gas plant ownership: 3
Natural gas (MMcfd)........................................................ 30.5 26.7 23.9
Natural gas liquids (MBbld)................................................ 41.7 39.8 34.2
Total (MMcfed).......................................................... 280.5 265.4 229.1
Average sales prices:
Natural gas (per Mcf)...................................................... $ 2.40 $ 2.01 $ 1.51
Natural gas liquids (per Bbl).............................................. 11.91 13.16 9.38
-----------------------------
1 Does not include the Company's portion, by virtue of its ownership in gas
processing facilities, of natural gas and natural gas liquids earned by
such facilities in connection with the processing of natural gas.
2 Includes lease operating costs, production overhead, other operating
expenses and taxes, other than income taxes.
3 Represents the Company's portion, by virtue of its ownership interest in
gas processing facilities, of natural gas and natural gas liquids earned
by such facilities in connection with the processing of natural gas. The
portion of the total average daily sales volumes representing the
Company's portion earned by such facilities with respect to processing
the Company's production for each of the three years ended December 31,
1997, 1996 and 1995 are 63.9 MMcfed, 77.1 MMcfed and 66.5 MMcfed,
respectively. See 'Supplementary Information--Average Daily Production
and Sales Volume'.
MINERALS OPERATIONS
Minerals operations contribute 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 nonoperated joint venture and
royalty arrangements in coal and trona (natural soda ash) mines. In general, the
Company reinvests the cash flow from its hard minerals operations into its oil
and gas operations. For the year ended December 31, 1997, the Minerals
operations generated $135.5 million of operating income of the Company as
follows:
1997 OPERATING INCOME
--------------------------------
AMOUNT PERCENT
--------------------- -------
(MILLIONS OF DOLLARS)
Royalties:
Soda ash 1................................................................... $ 41.9 31%
Coal 2....................................................................... 16.4 12
------- -------
Total royalties........................................................... 58.3 43
------- -------
Nonoperated joint ventures:
Soda ash 3................................................................... 7.6 6
Coal 4....................................................................... 66.9 49
------- -------
Total joint ventures...................................................... 74.5 55
Overhead/other................................................................. 2.7 2
------- -------
Total operating income.................................................... $ 135.5 100%
------- -------
------- -------
(Footnotes continued on next page)
4
(Footnotes continued from previous page)
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1 Includes properties leased to five soda ash producers, estimated to
contain resources sufficient to support over 30 years of production at
current production levels.
2 The Company leases coal resources to six operating mines. In 1997, 58% 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.
3 Represents a 49% interest in OCI Wyoming LP, a nonoperated joint venture.
4 Represents the Company's 50% nonoperating interest in Black Butte Coal
Company. Of this amount, $59.3 million is attributable to a single coal
supply contract, the financially beneficial terms of which terminate at
the end of year 2000. See 'Management's Discussion and Analysis of
Financial Condition and Results of Operations' and Note 12 to the
Consolidated Financial Statements.
The Company's low sulfur coal deposits compete with other western United
States coals for industrial and utility boiler markets. At current coal pricing
and extraction cost levels, however, most of the coal deposits are not economic
to extract, except for sale to local markets. As a result, there are currently
limited opportunities for new coal mine development in the Land Grant.
The world's largest deposit of trona ore, constituting 90% of the world's
known trona resources, is located in the Green River Basin in southwestern
Wyoming. Approximately 40% 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 production
from Wyoming has increased to 30% of the world's soda ash supply with the
remainder principally from synthetic processes. As a result of the increase in
the worldwide demand for soda ash, the Company, along with its partner Oriental
Chemical Industries, Inc. ('OCI'), plans to expand the OCI Wyoming LP soda ash
facility by 950,000 tons per year, from the plant's current nameplate capacity
of 2.3 million tons per year, by 1999. For the year ended December 31, 1997, the
Company invested an additional $19.7 million in OCI Wyoming LP and guaranteed
49% of a $100 million credit facility to finance the soda ash facility
expansion.
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. 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, including pipeline distribution
logistics and efficiencies.
GOVERNMENT REGULATION
The Company's natural gas, natural gas liquids and crude oil exploration,
development and production operations are subject to extensive rules and
regulations promulgated by federal, provincial, state and local authorities.
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
5
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. The MMS also intends to adopt financial
responsibility regulations under the Oil Pollution Act of 1990. See
'Environmental Regulation--Oil Spills.'
Currently, there are no laws that regulate the price for sales of natural
gas, natural gas liquids and crude oil by the Company. However, the Company's
rates charged and terms and conditions for the movement of gas in interstate
commerce through certain of its intrastate pipelines and production area hubs
are subject to regulation under the Natural Gas Policy Act of 1978 ('NGPA'). The
pipelines' and hubs' 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. The Order No. 636 Series was largely upheld by the United
States Court of Appeals for the District of Columbia. Although a few issues were
remanded to the FERC by the Court of Appeals, the outcome of the remanded
proceedings is not expected to have a significant impact on the Company. The
remanded proceedings are pending before the FERC. Several parties petitioned the
Supreme Court to review the Court of Appeals' decision. The Court, in 1996,
denied the parties' petitions and therefore the Order No. 636 Series is no
longer subject to court review but for the remanded proceeding referenced above.
Related orders under the Order No. 636 Series are the subject of numerous
appeals to the United States Court of Appeals.
Through many interstate pipeline specific orders, the FERC has revised its
policy regarding jurisdiction over gathering facilities and services. The 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 the FERC's policy. As a
result of such court 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
Texas Railroad Commission initiated a rulemaking and ultimately issued new
regulations regarding gathering. Although the new regulations increased the
regulatory burden to a limited extent, the regulations are not expected to have
a significant 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.
As the owner of production area hubs and intrastate pipeline facilities in
Wyoming and Texas, the Company also is subject to regulation by those states as
to safety, rates and the provision of transportation services. 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.
6
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 which may be
removed from those 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 liability 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 phase-out 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 $18.8 million of Section 29 tax credits in 1997. 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
liability 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.
In 1991 and 1992, the Company entered into transactions with a
privately-held company, which provided funds for the Company to drill wells
qualifying for Section 29 tax credits. Pursuant to these transactions, the
Company conveyed much of its producing and tax credit eligible acreage in the
Carthage field and Moxa Arch and Wamsutter areas to a limited partnership
('Section 29 Limited Partnership'). This Section 29 Limited Partnership utilized
drilling funds contributed by the investor as limited partner and drilled 208
wells which qualify for Section 29 tax credits. The Company was the managing
general partner of this Section 29 Limited Partnership and had broad latitude in
conducting its operations. Prior to a defined payout, the limited partner was
entitled to receive a preferential distribution of a specified quantity of
available production from this Section 29 Limited Partnership, including gas
that did not qualify for the tax credits as well as tax credit-qualified gas.
Payout occurred in December 1996, after which point the limited partner was
entitled to receive only 1% of ongoing production of this Section 29 Limited
Partnership. The historic production allocable to the limited partner has been
deducted from the Company's reserve and production statistics. Effective
December 1997, the Company purchased the limited partner's interest in this
Section 29 Limited Partnership.
TEXAS SEVERANCE TAX REDUCTION
Natural gas produced from wells that have been certified as tight
formations or deep wells 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% severance tax in
Texas on natural gas and natural gas liquids produced by such wells. Such
exemption ends August 31, 2001. The natural gas production
7
from wells drilled on certain of the Company's properties, primarily in the
Austin Chalk, West Texas and East 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% 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 equals 50% of the total drilling and
completion costs.
ENVIRONMENTAL REGULATION
The Company's operations are subject to extensive federal, state,
provincial and local 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 may
now be covered by the permitting requirements. Although the precise requirements
of Title III of the 1990 Amendments are not yet known, the Company may incur
substantial expenditures for the additional capital, operating and maintenance
costs required to comply with these new regulations.
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 to $350 million in the case of onshore facilities and $75
million plus removal costs in the case of offshore facilities, except that these
limits do not 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, has
not yet issued a proposed rule to implement the financial responsibility
requirements and, therefore, the financial responsibility requirements
applicable under laws existing prior to OPA still apply to such
8
facilities. 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 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 1,907 employees as of December 31, 1997, 22 of whom were
not full time employees. The Company believes that its relations with its
employees are good.
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 natural gas liquids, 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 currently 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 may 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
and liabilities arising from such events could reduce revenues and increase
costs to the Company to the extent not covered by insurance or already provided
for.
9
ITEM 2. PROPERTIES
PROVED RESERVES
The following table sets forth the proved developed and undeveloped
reserves of natural gas, natural gas liquids and crude oil of the Company as of
December 31, 1997. 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. Ryder Scott Company Petroleum
Engineers ('Ryder Scott') has provided an opinion with respect to the Company's
estimate of its proved reserves as of December 31, 1997. Such opinion states
that, on a total Company basis, Ryder Scott is in agreement with the Company's
estimate of proved reserves for the properties which they reviewed. For further
information concerning Ryder Scott's review of the proved reserves of the
Company as of December 31, 1997, see Ryder Scott's letter, dated February 27,
1998, included as Exhibit 99 to this Annual Report on Form 10-K.
AS OF DECEMBER 31, 1997
-------------------------------------------
NATURAL
NATURAL GAS
GAS LIQUIDS CRUDE OIL TOTAL
CATEGORY OF RESERVES (BCF) (MMBBL) (MMBBL) (BCFE)
- ---------------------------------------------------------------- ------- ------- ---------- -------
Proved developed................................................ 2,217.0 103.3 93.9 3,400.2
Proved undeveloped.............................................. 403.3 14.6 34.9 700.3
------- ------- ---------- -------
Total proved reserves......................................... 2,620.3 117.9 128.8 4,100.5
------- ------- ---------- -------
------- ------- ---------- -------
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. Reserve 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, 1997.
TOTAL ACRES
---------------------
BUSINESS UNIT GROSS NET
- ---------------------------------------------------------------- ---------- -------
(IN THOUSANDS)
Austin Chalk......................................................................... 31 11
Rockies 1............................................................................ 3,253 3,252
South Texas/Plains/Canada 1.......................................................... 5,316 4,922
Gulf Onshore/Offshore................................................................ 215 73
East Texas........................................................................... 46 12
West Texas........................................................................... 690 238
---------- -------
Total fee acreage.................................................................. 9,551 8,508
---------- -------
---------- -------
- ------------------------
1 The fee mineral acreage associated with the Land Grant is included in Rockies and
South Texas/Plains/Canada business units........................................... 7,912 7,722
10
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, including the Land Grant, is primarily
undeveloped.
Leasehold. The Company's leasehold acreage by business unit as of December
31, 1997 is set forth below.
ACRES
--------------------------------------------------
DEVELOPED UNDEVELOPED TOTAL
-------------- -------------- --------------
BUSINESS UNIT GROSS NET GROSS NET GROSS NET
- --------------------------------------------------------- ----- ----- ----- ----- ----- -----
(IN THOUSANDS)
Austin Chalk............................................. 959 732 1,667 1,396 2,626 2,128
Rockies.................................................. 117 69 215 154 332 223
South Texas/Plains/Canada................................ 429 205 1,010 639 1,439 844
Gulf Onshore/Offshore.................................... 314 285 461 261 775 546
East Texas............................................... 266 137 561 327 827 464
West Texas............................................... 232 141 162 132 394 273
----- ----- ----- ----- ----- -----
Total leasehold acreage................................ 2,317 1,569 4,076 2,909 6,393 4,478
----- ----- ----- ----- ----- -----
----- ----- ----- ----- ----- -----
Total Leasehold and Fee Mineral. The total leasehold and fee mineral
acreage by business unit as of December 31, 1997 is set forth below.
TOTAL ACRES
----------------
BUSINESS UNIT GROSS NET
- ----------------------------------------------------------------------------------------- ------ ------
(IN THOUSANDS)
Austin Chalk............................................................................. 2,657 2,139
Rockies.................................................................................. 3,585 3,475
South Texas/Plains/Canada................................................................ 6,755 5,766
Gulf Onshore/Offshore.................................................................... 990 619
East Texas............................................................................... 873 476
West Texas............................................................................... 1,084 511
------ ------
Total leasehold and fee acreage........................................................ 15,944 12,986
------ ------
------ ------
DRILLING ACTIVITY AND PRODUCING WELL SUMMARY
The table below summarizes the Company's drilling activity over the last
three years.
YEARS ENDED DECEMBER 31,
--------------------------------------------------
1997 1996 1995
-------------- -------------- --------------
GROSS NET GROSS NET GROSS NET
----- ----- ----- ----- ----- -----
Development wells:
Productive............................................. 685 478.6 575 413.4 679 505.7
Dry.................................................... 59 46.2 35 25.7 18 7.7
Exploration wells:
Productive............................................. 35 19.1 16 8.5 6 2.8
Dry.................................................... 38 22.1 29 18.2 22 10.7
----- ----- ----- ----- ----- -----
Total wells............................................ 817 566.0 655 465.8 725 526.9
----- ----- ----- ----- ----- -----
----- ----- ----- ----- ----- -----
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 project. As of
December 31, 1997, the Company owned a working interest in 6,043 gross gas wells
(3,574 net) and 2,763 gross oil wells (1,636 net). Gross wells include 611 wells
with multiple completions. The Company operated 61% of the gross wells in which
it owned an interest.
11
GAS PROCESSING ASSETS
A listing of the Company's processing plants and their gross design
capacity is provided below. Generally, each of the processing plants has an
extensive gathering system. Average throughput in such processing plants for
1997 was approximately 83% of such processing plants' design capacity.
AVERAGE GROSS VOLUMES
YEAR ENDED
DECEMBER 31, 1997
--------------------------
AS OF DECEMBER 31, 1997 NATURAL GAS
------------------------------ NATURAL GAS LIQUIDS
WORKING INTEREST THROUGHPUT PRODUCED
GAS PLANTS PERCENT DESIGN CAPACITY (MMCFD) (MMCFD) (MBBLD)
- ----------------------------------- ----------------------- ----------------------- ----------- -----------
Rockies
*Anschutz Ranch East............. 12 650 370 17.3
Brady 1.......................... 50 0 63 2.4
*Painter......................... 19 260 248 13.2
Pineview......................... 49 15 2 0.2
*Whitney Canyon.................. 19 235 176 7.2
South Texas/Plains/Canada
Bledsoe.......................... 100 2 1 --
*Caroline........................ 7 300 340 31.0
Mt. Pearl........................ 52 11 11 0.4
Silo............................. 100 5 2 0.3
GPM
A&M 2............................ 55 50 49 4.6
Brookeland....................... 80 100 80 6.4
Bryan............................ 55 60 58 10.2
Conroe........................... 100 65 33 0.8
East Carlsbad 3.................. 100 23 24 2.3
East Texas Plant Complex 4,5..... 90 660 653 39.6
*Echo Springs.................... 34 240 233 16.3
Emigrant Trail................... 100 60 37 1.9
Gulf Plains 4,6.................. 100 110 82 5.3
Hulldale 3....................... 100 18 11 1.6
Masters Creek 7.................. 62 100 47 4.3
Ozona 4.......................... 63 120 113 11.8
Patrick Draw 4,8................. 100 120 25 1.7
Sonora 4,3....................... 100 68 62 5.6
S.W. Ozona....................... 100 90 68 7.5
Yellow Creek 4................... 100 80 30 0.2
------ ----------- -----------
Total......................... 3,442 2,818 192.1
------ ----------- -----------
------ ----------- -----------
------------------------
* Nonoperated
1 This plant ceased processing gas in August 1997; however, this plant continues to treat sour gas. This
plant's average natural gas throughput and natural gas liquids produced are set forth for the period
January through August 1997.
2 This plant was shut down February 1998.
3 This plant is one of several plants acquired in the purchase of Highlands effective as of August 1997.
4 Includes fractionation facilities.
5 This plant's design capacity during 1997 was 660 MMcfd. This plant's design capacity is expected to
increase by an additional 120 MMcfd to 780 MMcfd beginning in March 1998.
6 This plant's design capacity is expected to increase by 50 MMcfd in mid-year 1998.
7 This plant became operational in August 1997 with 100 MMcfd; this plant's design capacity is expected to
increase to 200 MMcfd in February 1998. Natural gas throughput and natural gas liquids produced represent
averages for the period August through December 1997.
8 This plant's design capacity was expanded from 30 MMcfd to 120 MMcfd during December 1997.
12
PIPELINE ASSETS
A listing of the Company's pipeline assets is provided below.
AS OF DECEMBER 31, 1997
--------------------------------------------------------
WORKING PRODUCTS LINE SIZE NUMBER OF
PIPELINE SYSTEM BY GEOGRAPHIC AREA INTEREST % SHIPPED (IN INCHES) MILES
- ------------------------------------------------------ ---------- ------------- ------------ ---------
Eastern Texas and Louisiana
Jasper Pipeline..................................... 100 NGL 6 19
*Ferguson-Burleson gathering........................ 55 Gas 2 - 18 1,509
*Black Lake Pipeline................................ 50 NGL 6 - 8 317
Eastern Texas--Carthage
East Texas Gas Systems.............................. 90 Gas 10 - 12 121
San Jacinto Pipeline................................ 90 NGL 4 - 8 35
Panola Products Pipeline............................ 90 NGL 8 - 10 195
Eastrans Ltd. Pipeline.............................. 90 Gas 8 - 12 33
Southern Texas
Stratton Crude/Condensate Pipeline.................. 100 Crude/ 3 - 4 32
Condensate
Stratton Butane/Natural Gasoline.................... 100 Butane/ 2 - 6 38
Nat. Gasoline
Stratton Propane.................................... 100 Propane 3 10
Wyoming
Emigrant Trail...................................... 100 NGL 4 8
Overland Trail...................................... 99 Gas 4 - 16 305
Wahsatch Pipeline................................... 100 Gas 4 - 10 40
Western Texas
Transwestern Pipeline System........................ 100 Gas 2 - 8 52
Sonora/Fin Tex Pipeline............................. 100 NGL 8 - 10 384
Crockett Pipeline................................... 90 NGL 8 25
Ozona Pipeline...................................... 100 NGL 6 23
- ------------------
* Nonoperated
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. The State District Court heard
arguments on the Company's motion for summary judgment on May 23, 1997. On June
23, 1997, the District Court granted the Company's motion holding as a matter of
law that the mineral reservations at issue were unambiguous and included all
valuable nonsurface substances, including oil and gas. A final judgment was
entered on August 5, 1997. Thereafter, such surface owners filed a notice of
appeal to the Colorado Court of Appeals on September 17, 1997.
13
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 materially
adverse effect on the consolidated financial condition, cash flows or results of
operations of the Company.
GENERAL
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 such litigation and other proceedings, management does not expect these
matters to have a materially adverse effect on the consolidated financial
condition, cash flows or results of operations 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
fourth quarter ended December 31, 1997.
EXECUTIVE OFFICERS OF THE REGISTRANT
The names, positions and ages of executive officers of the Company are set
forth below:
NAME POSITION AGE
- --------------------------------------- -------------------------------------------------------- ----
Jack L. Messman 1...................... Chairman and Chief Executive Officer 58
George Lindahl III 2................... President and Chief Operating Officer 51
V. Richard Eales 3..................... Executive Vice President 62
Thomas R. Blank 4...................... Vice President--State, Regulatory and Public Affairs 45
Anne M. Franklin 5..................... Vice President--People 41
Joseph A. LaSala, Jr. 6................ Vice President, General Counsel and Secretary 43
Donald W. Niemiec 7.................... Vice President--Marketing 51
Morris B. Smith 8...................... Vice President and Chief Financial Officer 53
John B. Vering 9....................... Vice President--Canada 48
----------------------------
1 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 since September 1991. He has been President, Chief Executive
Officer and a Director of Union Pacific Resources Company ('UPRC') from
May 1991 through October 1995.
2 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. From 1992 to August 1995, he was Vice
President--Operations for UPRC.
3 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.
4 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.
From January 1994 to February of 1997, he was President of Hager Sharp,
Inc. Prior thereto, he was the Senior Vice President of Hager Sharp, Inc.
5 Ms. Franklin has held her current position with the Company since August
1995. She joined UPRC as Vice President--People in June 1995. From 1993 to
June 1995, she was Director of Executive Leadership and Development for
Ameritech, Inc.
14
(Footnotes continued from previous page)
6 Mr. LaSala has held his current position with the Company since January
1996 and assumed the role of Secretary in June 1997. Mr. LaSala joined
UPRC as Assistant General Counsel in 1995. Prior to joining UPRC, he was
Vice President--Government and Regulatory Affairs of USPCI, Inc., a former
subsidiary of Union Pacific Corporation ('UPC'), from May 1993 until
December 1994 and, prior thereto, Vice President--External Relations of
USPCI, Inc.
7 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 UP Fuels since 1990.
8 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. From June 1993
through December 1994, he served as Vice President--Finance of USPCI, Inc.
Prior thereto, he was Assistant Controller--Planning and Analysis of UPC.
9 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 and UPRC.
15
PART II
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER
MATTERS
The Company completed an initial public offering of its common stock
('Common Stock') in October 1995. 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 of Common Stock, as reported
on the New York Stock Exchange Composite Tape, as well as the dividends declared
on the Common Stock, is set forth under Selected Quarterly Data on page 63.
As of February 27, 1998, there were 251,043,100 shares of Common Stock
outstanding and approximately 50,400 shareholders of record. The closing price
of the Common Stock on the New York Stock Exchange on February 27, 1998 was
$22 3/8.
The Company has paid quarterly cash dividends of $0.05 per share of Common
Stock 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.
In February 1997, the Board of Directors adopted a stock purchase program
which authorizes the Company to purchase up to $50 million of its Common Stock
outstanding in any given fiscal year. In December 1997, the Board of Directors
approved a resolution to allow the Company to purchase an additional $50 million
of its Common Stock outstanding in 1998. As of December 31, 1997, the Company
had purchased 2,013,400 shares of its Common Stock under this program for
approximately $49.9 million.
ITEM 6. SELECTED FINANCIAL DATA
The following table contains selected historical financial data for each of
last five fiscal years.
YEARS ENDED DECEMBER 31,
--------------------------------------------------------
1997 1996 1995 1994 1993
-------- -------- -------- -------- --------
(MILLIONS OF DOLLARS,EXCEPT PER SHARE AMOUNTS)
INCOME STATEMENT DATA:
Operating revenues.............................. $1,924.7 $1,831.0 $1,476.7(a) $1,332.9 $1,277.1
Operating income................................ 495.2 526.6 470.1(a) 351.3 382.9
Net income...................................... 333.0 320.8 350.7(a) 390.0(b) 243.8(c)
Per share:
Net income--basic (d)......................... 1.33 1.29 n/a n/a n/a
Net income--diluted (d)....................... 1.33 1.28 n/a n/a n/a
Dividends..................................... 0.20 0.20 0.05(e) n/a n/a
CASH FLOW DATA:
Capital and exploratory expenditures............ $1,531.7(f) $ 880.3 $ 686.4 $1,389.3(g) $ 560.4
Cash provided by operations..................... 968.8 990.4 829.4 821.0 567.5
AS OF DECEMBER 31,
--------------------------------------------------------
1997 1996 1995 1994 1993
-------- -------- -------- -------- --------
FINANCIAL POSITION DATA:
Properties--net................................. $3,665.4(f) $2,972.4 $2,764.3 $2,600.1(g) $1,780.2
Total assets.................................... 4,472.2 3,648.9 3,308.9 3,247.0 2,714.1
Long-term debt.................................. 1,230.6(f) 670.9(h) 101.5 37.7 45.6
Shareholders' equity............................ 1,760.7 1,514.3 1,312.4 1,834.9 1,596.1
(Footnotes continued on next page)
16
(Footnotes continued from previous page)
- ------------------
(a) In November 1995, the Company recorded a $122.5 million pre-tax ($78.5
million after-tax) gain resulting from the Columbia Gas Transmission
Company bankruptcy settlement ('Columbia settlement') (see Note 4 to
the Consolidated Financial Statements).
(b) In March 1994, the Company sold its interest in the Wilmington field
and Harbor Cogeneration Plant to the Port of Long Beach, California.
Such sale resulted in a $159.2 million pre-tax ($100 million after-tax)
gain.
(c) In January 1993, the Company adopted Statement of Financial Accounting
Standards ('SFAS') No. 106, 'Employers' Accounting for Postretirement
Benefits Other Than Pensions,' and SFAS No. 109, 'Accounting for Income
Taxes,' with a cumulative after-tax charge to 1993 earnings of $59
million.
(d) 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.
(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 periods prior to
the fourth quarter of 1995.
(f) In March 1994, the Company acquired Amax Oil & Gas, Inc., for a net
purchase price of $725 million.
(g) During 1997, the Company increased debt by issuing commercial paper to
fund its capital spending, including the acquisition of producing
properties and Highlands.
(h) During 1996, the Company repaid its $650 million note payable to UPC
(incurred at the time of the Offering) using cash from operations and
proceeds from the issuance of long-term debt and commercial paper (see
Note 2 to the Consolidated Financial Statements).
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 Annual Report on Form 10-K. The consolidated
statements of income for previous periods include certain reclassifications that
were made to conform to the current presentation. Such reclassifications affect
previously reported operating revenues and expenses but have no effect on
previously reported operating income or net income.
RESULTS OF OPERATIONS
YEAR ENDED DECEMBER 31, 1997 COMPARED TO YEAR ENDED DECEMBER 31, 1996
SUMMARY FINANCIAL DATA
YEARS ENDED DECEMBER
31,
--------------------
1997 1996
-------- --------
(MILLIONS OF
DOLLARS)
Operating revenues.................................................................... $1,924.7 $1,831.0
Operating expenses.................................................................... 1,429.5 1,304.4
Operating income...................................................................... 495.2 526.6
Net income............................................................................ 333.0 320.8
The Company reported net income of $333 million for the year ended December
31, 1997 compared to $320.8 million in 1996. Earnings per share on a diluted
basis increased by 4% to $1.33 from $1.28 in 1996. Improvements were achieved
from increased producing property volumes and prices and royalty income from
mineral operations. In addition, the Company experienced higher other income and
one-time tax benefits. These improvements were offset by a $60.1 million
increase in exploration expenses, reduced margins for gathering, processing and
marketing ('GPM') operations, one-time costs of $17.8 million relating to the
Company's unsuccessful attempt to acquire Pennzoil Company and higher operating
costs.
17
Operating income declined $31.4 million (6%) from 1996 due to reduced
margins for GPM operations, a $60.1 million increase in exploration expenses and
higher general and administrative costs, which more than offset improvements
from producing properties and minerals operations.
SUMMARY OF SEGMENT FINANCIAL DATA
YEARS ENDED
DECEMBER 31,
-----------------
1997 1996
------ ------
(MILLIONS OF
DOLLARS)
Segment operating income:
Producing properties................................................................. $344.4 $328.7
Gathering, processing and marketing.................................................. 94.6 150.1
Minerals............................................................................. 135.5 120.0
Corporate/general and administrative................................................. (79.3) (72.2)
------ ------
Total operating income............................................................ $495.2 $526.6
------ ------
------ ------
PRODUCING PROPERTY OPERATIONS
YEARS ENDED DECEMBER
31,
--------------------
1997 1996
-------- --------
(MILLIONS OF
DOLLARS)
Operating revenues................................................................... $1,281.2 $1,133.3
Other oil and gas revenues........................................................... 53.5 65.0
-------- --------
Total operating revenues........................................................... 1,334.7 1,198.3
Operating expenses:
Production......................................................................... 292.6 259.5
Exploration........................................................................ 204.7 144.6
Depreciation, depletion and amortization........................................... 493.0 465.5
-------- --------
Total operating expenses........................................................... 990.3 869.6
-------- --------
Operating income..................................................................... $ 344.4 $ 328.7
-------- --------
-------- --------
Total operating revenues for producing property operations increased by
$136.4 million during 1997. The improvement in operating revenues was primarily
due to prices, which were higher by $0.07 per Mcfe from 1996 to $2.20 per Mcfe
in 1997. The higher prices provided an incremental $104.5 million to operating
revenues. Additional sales volume growth of 10% provided an incremental $43.4
million to operating revenue.
YEARS ENDED DECEMBER 31,
--------------------------------------
1997 1996 1997 1996
------ ------ ------ ------
(WITHOUT (WITH HEDGING)
HEDGING)
Average price realizations--producing properties:
Natural gas (per Mcf)........................................ $ 2.19 $ 1.94 $ 2.00 $ 1.86
Natural gas liquids (per Bbl)................................ 11.20 11.39 11.20 11.39
Crude oil (per Bbl).......................................... 18.80 20.09 18.36 18.84
Average (per Mcfe)........................................... 2.34 2.23 2.20 2.13
YEARS ENDED
DECEMBER 31,
------------------
1997 1996
------- -------
Production volumes--producing properties:
Natural gas (MMcfd)............................................................... 1,102.3 980.3
Natural gas liquids (MBbld)....................................................... 29.9 28.5
Crude oil (MBbld)................................................................. 52.9 50.6
Total (MMcfed).................................................................... 1,598.8 1,454.9
18
Natural gas volumes increased 122 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). Gas volumes from the South Texas/Plains/Canada
business unit were up 22.6 MMcfd primarily due to the drilling program in
southern Texas. The East Texas business unit's volumes increased by 19.9 MMcfd
primarily due to the acquisition and development of properties acquired from
Castle Energy. The West Texas business unit's gas volumes improved 15.1 MMcfd
due to continued success with its horizontal drilling program. In addition, the
Gulf Onshore/Offshore business unit gas volumes rose 14 MMcfd primarily due to
its drilling program in the southern Louisiana area. The Austin Chalk business
unit's gas volumes increased 10.8 MMcfd due to its success in the deep Giddings
field. These improvements were partially offset by a 17.1 MMcfd reduction in
Rockies business unit's gas volumes caused by production declines. Crude oil
volumes increased by 2.3 MBbld (5%) primarily due to drilling successes in the
Masters Creek field in Louisiana. Natural gas liquids volumes rose 1.4 MBbld
(5%) with most of the improvement attributable to the East Texas business unit.
Production costs increased $33.1 million to $292.6 million for 1997,
primarily due to a $30.6 million increase in lease operating expenses. Such
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 $0.50 in 1997
from $0.49 in 1996.
Exploration expenses were up $60.1 million to $204.7 million compared to
1996 reflecting the Company's expanded exploration programs. Surrendered lease
costs were higher by $24.1 million as a result of more leasing activity in the
East Texas and the Austin Chalk business units. Delay rentals rose $10.4
million, primarily in Austin Chalk and the Gulf Onshore/Offshore business units.
In addition, geological and geophysical costs were higher by $16.2 million,
primarily in the Gulf Onshore/Offshore business unit, while dry hole costs were
up by $8.4 million, primarily in the East Texas and Gulf Onshore/Offshore
business units.
Producing property depreciation, depletion and amortization expense
increased $27.5 million due to higher production volumes. This increased
expense, was partially offset by a lower unit of production rate. There were
write-downs of assets of $24.4 million in the South Texas/Plains/Canada business
unit relating to Moca Dome in 1997 and $26.4 million in the Rockies and Gulf
Onshore/Offshore business units in 1996.
GATHERING, PROCESSING AND MARKETING OPERATIONS
YEARS ENDED
DECEMBER 31,
----------------
1997 1996
------ ------
(MILLIONS OF
DOLLARS)
Operating revenues....................................................................... $443.3 $503.8
Gas purchases............................................................................ 161.3 167.0
------ ------
Operating margin.................................................................... 282.0 336.8
Other oil and gas revenues............................................................... 6.9 --
Operating expenses:
Operating costs..................................................................... 123.9 123.0
Depreciation, depletion and amortization............................................ 70.4 63.7
------ ------
Total operating expenses.......................................................... 194.3 186.7
------ ------
Operating income......................................................................... $ 94.6 $150.1
------ ------
------ ------
Margins for the GPM operations declined $54.8 million to $282 million in
1997. Plant margins were down $26.2 million resulting from lower sales prices
($15.2 million), higher gas purchase costs and lower gas plant fees despite a 6%
improvement in volumes ($11.9 million). Pipeline margins declined $3.7 million
from 1996 reflecting lower throughput at Ferguson-Burleson and Wahsatch
pipelines. This lower throughput was partially offset by higher volumes provided
by the acquisition of Highlands. Marketing margins declined by $24.9 million as
a result of higher crude oil purchase costs and reduced margins for natural gas
and natural gas liquids. Such higher costs and reduced margins were partially
offset by additional margins on volumes from the acquisition of Highlands.
19
Other oil and gas revenues in 1997 primarily reflect a $6.4 million gain on
the sale of the Company's investment in the Frontier Pipeline.
YEARS ENDED DECEMBER 31,
-------------------------
1997 1996
---------- ----------
Average price realizations--plants:
Natural gas (per Mcf).............. $ 2.40 $ 2.01
Natural gas liquids (per Bbl)...... 11.91 13.16
Average (per Mcfe)................. 2.03 2.18
Sales Volumes--plants:
Natural gas (MMcfd)................ 30.5 26.7
Natural gas liquids (MBbld)........ 41.7 39.8
Total (MMcfed)..................... 280.5 265.4
Plant gas volumes increased by 3.8 MMcfd over the volumes in 1996, due to
the Highlands acquisition (8.3 MMcfd) and the Masters Creek plant start-up.
These volume increases were partially offset by lower inlet volumes at the
Brookeland plant (5.1 MMcfd). Plant natural gas liquids volumes increased by 1.9
MBbld primarily due to the Highlands acquisition (2.2 MBbld) and the Masters
Creek start-up.
GPM operating costs increased by $0.9 million to $123.9 million for 1997.
Higher costs relating to the assets acquired from Highlands, plant start-ups and
the addition of support staff, more than offset the absence of the $17 million
1996 asset impairment adjustment for the Wahsatch pipeline.
Depreciation, depletion and amortization for the GPM operations increased
$6.7 million, primarily due to the higher asset base resulting from plant
expansions and the acquisition of Highlands.
MINERALS OPERATIONS
YEARS ENDED DECEMBER 31,
-------------------------
1997 1996
---------- ----------
(MILLIONS OF DOLLARS)
Operating revenues...................... $ 139.8 $ 128.9
Operating expenses...................... 3.4 8.0
Depreciation, depletion and
amortization.......................... 0.9 0.9
------- -------
Operating income................... $ 135.5 $ 120.0
------- -------
------- -------
Minerals operating income increased by $15.5 million over the income in
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 the
minerals operations declined compared to 1996, primarily due to the shutdown of
the Company's ballast operations.
GENERAL AND ADMINISTRATIVE EXPENSES
YEARS ENDED DECEMBER 31,
-------------------------
1997 1996
---------- ----------
(MILLIONS OF DOLLARS)
General and administrative expenses..... $ (75.5) $ (68.4)
Depreciation, depletion and
amortization.......................... (3.8) (3.8)
------- -------
Corporate/general and
administrative.................... $ (79.3) $ (72.2)
------- -------
------- -------
General and administrative expenses were $7.1 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.
General and administrative expenses per Mcfe remained flat at $0.11 per Mcfe
from 1996 to 1997.
20
OTHER INCOME
Other income of $24.3 million was $27.7 million higher than 1996, due to a
$23 million reserve reduction relating to oil and gas properties in Wilmington,
California which were sold in 1994. Such reserves were reduced due to the
expiration of certain indemnification obligations and a reduction of other
exposure. Other income also includes 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
relating to the unsuccessful bid to acquire Pennzoil Company.
INCOME TAXES
Income taxes of $133.4 million were $18.4 million lower than 1996,
reflecting lower income before taxes, $9.9 million in prior period state and
federal tax adjustments and an increase in Section 29 tax credits. In contrast,
1996 included a $3 million unfavorable state tax adjustment. Excluding these
adjustments, the effective tax rate for 1997 would have been 30.7% (including
$18.8 million of Section 29 tax credits), compared to 31.5% for 1996 (including
$15.6 million of Section 29 tax credits).
YEAR ENDED DECEMBER 31, 1996 COMPARED TO YEAR ENDED DECEMBER 31, 1995
SUMMARY FINANCIAL DATA
YEARS ENDED DECEMBER
31,
--------------------
1996 1995
-------- --------
(MILLIONS OF
DOLLARS)
Operating revenues................................................................... $1,831.0 $1,476.7
Operating expenses................................................................... 1,304.4 1,006.6
Operating income..................................................................... 526.6 470.1
Net income........................................................................... 320.8 350.7
The Company reported net income of $320.8 million for the year ended
December 31, 1996, compared to $350.7 million in 1995. Improved operating
results were more than offset by the absence of a $78.5 million after-tax gain
in 1995 from the Columbia settlement; the absence of favorable 1995 tax
adjustments; reduced Section 29 tax credits; and increased interest expense and,
to a lesser extent, increased general and administrative costs incurred as a
result of being a public company following the Offering and related debt
restructuring in October 1995. On a pro forma basis, after giving effect to
transactions occurring at the time of the Offering (as if such transactions had
occurred at the beginning of 1995), net income for 1996 would have been $4.6
million above pro forma net income for 1995 (see Note 2 to the Consolidated
Financial Statements).
Operating income increased by $56.5 million (12%) over 1995 levels as a
result of higher product price realizations (27%) and volume growth (8%),
partially offset by the absence of a $122.5 million pre-tax gain in 1995 from
the Columbia settlement. These gains were offset partially by property
write-downs, cost increases associated with expanded exploration activity and
increased administrative expenses associated with being an independent public
company.
SUMMARY OF SEGMENT FINANCIAL DATA
YEARS ENDED DECEMBER 31,
----------------------
1996 1995
---------- ----------
(MILLIONS OF DOLLARS)
Segment operating income:
Producing properties.................. $ 328.7 $ 307.7
Gathering, processing and marketing... 150.1 107.8
Minerals.............................. 120.0 107.1
Corporate/general and
administrative..................... (72.2) (52.5)
------- -------
Total operating income............. $ 526.6 $ 470.1
------- -------
------- -------
21
PRODUCING PROPERTY OPERATIONS
YEARS ENDED DECEMBER
31,
--------------------
1996 1995
-------- --------
(MILLIONS OF
DOLLARS)
Operating revenues................................................................... $1,133.3 $ 853.6
Other oil and gas revenues........................................................... 65.0 157.1
-------- --------
Total operating revenues........................................................... 1,198.3 1,010.7
Operating expenses:
Production......................................................................... 259.5 210.5
Exploration........................................................................ 144.6 89.4
Depreciation, depletion and amortization........................................... 465.5 403.1
-------- --------
Total operating expenses........................................................ 869.6 703.0
-------- --------
Operating income..................................................................... $ 328.7 $ 307.7
-------- --------
-------- --------
Total operating revenues for producing property operations increased by
$187.6 million to $1,198.3 million in 1996. Production volume increases of 83.9
MMcfed added $39.6 million in revenues while higher prices of $0.42 per Mcfe
added $240.1 million in revenues.
Other oil and gas revenues declined by $92.1 million in 1996 reflecting the
absence of the Columbia settlement ($122.5 million), lower preferential volumes
distributed to an investor in a Section 29 Limited Partnership ($10.1 million)
and lower net gains on property sales. Such decline was partially offset by the
reduction of reserves for the Columbia settlement in 1996 and the absence of a
hedging loss in 1995 of $8.1 million.
YEARS ENDED DECEMBER 31,
--------------------------------------
1996 1995 1996 1995
------ ------ ------ ------
(WITHOUT (WITH HEDGING)
HEDGING)
Average price realizations--producing properties:
Natural gas (per Mcf)........................................... $ 1.94 $ 1.30 $ 1.86 $ 1.42
Natural gas liquids (per Bbl)................................... 11.39 8.14 11.39 8.14
Crude oil (per Bbl)............................................. 20.09 16.35 18.84 16.08
Average (per Mcfe).............................................. 2.23 1.64 2.13 1.71
YEARS ENDED DECEMBER
31,
--------------------
1996 1995
-------- --------
Production volumes--producing properties:
Natural gas (MMcfd)................................................................ 980.3 915.6
Natural gas liquids (MBbld)........................................................ 28.5 23.1
Crude oil (MBbld).................................................................. 50.6 52.8
Total (MMcfed)..................................................................... 1,454.9 1,371.0
Natural gas volumes increased by 64.7 MMcfd to 980.3 MMcfd with increases
from development drilling programs in the Austin Chalk (79.6 MMcfd) and West
Texas (17.6 MMcfd) business units and a lower distribution of preferential
volumes related to the Section 29 Limited Partnership (22.4 MMcfd). Offsetting
these increases were declines in Gulf Onshore/Offshore business unit (31.6
MMcfd) resulting largely from the depletion of several offshore wells, and
declines in the Rockies business unit (13.2 MMcfd) resulting from production
problems. Natural gas liquids volumes from producing properties increased by 5.4
MBbld to 28.5 MBbld primarily due to ethane recovery in the Rockies and South
Texas/Plains/Canada business units and additional lease gas being processed in
the Austin Chalk business unit by the expanded Brookeland plant. Crude oil
volumes were 2.2 MBbld lower at 50.6 MBbld as a result of production declines in
South Texas/Plains/Canada and Rockies business units and the sale of certain
non-core properties, partially offset by property acquisitions and drilling in
the Austin Chalk business unit.
22
Production expenses increased by $49 million (23%) to $259.5 million,
largely attributable to higher production taxes and higher lease operating
costs. The increase in production taxes of $29.2 million (57%) reflects
increased producing property revenues, the absence of a favorable 1995 Wyoming
production tax settlement ($12 million) and an unfavorable 1996 ad valorem tax
adjustment ($4.5 million). Lease operating costs were higher by $16.1 million
primarily in the Austin Chalk, East Texas and West Texas business units as a
result of increased production volumes and greater workover costs. Production
overhead was higher by $4 million in 1996. Production expenses on a per Mcfe
basis of $0.49 were $0.07 per Mcfe higher than 1995, principally reflecting the
increase in production taxes.
Exploration expenses increased by $55.2 million (62%) primarily due to
higher dry hole and surrendered lease provisions. The dry hole provision was up
$23.3 million due to an increase in exploratory drilling in southern Louisiana,
offshore, and North and South Dakota. The surrendered lease costs provision was
$29.1 million higher in 1996 than surrendered lease costs in 1995 reflecting a
write-down of North and South Dakota leasehold ($9.1 million) as well as
increases in Austin Chalk and Gulf Onshore/Offshore business units leasing
activity. Exploration overhead was $5.4 million higher in 1996 than exploration
overhead in 1995.
Depreciation, depletion and amortization expense increased by $62.4 million
to $465.5 million in 1996 as a result of asset impairment adjustments related to
certain properties in the Rockies and Gulf Onshore/Offshore business units
($17.4 million), several offshore property write-downs ($9 million), higher
producing property volumes ($25.8 million), and an unfavorable unit of
production rate ($11 million). On a per Mcfe basis, depreciation, depletion and
amortization, excluding write-downs, increased $0.02 per Mcfe to $0.83 per Mcfe
in 1996.
GATHERING, PROCESSING AND MARKETING OPERATIONS
YEARS ENDED DECEMBER 31,
-------------------------
1996 1995
---------- ----------
(MILLIONS OF DOLLARS)
Operating revenues...................... $ 503.8 $ 339.9
Gas purchases........................... 167.0 94.2
------- -------
Operating margin...................... 336.8 245.7
Other oil and gas revenues.............. -- 9.8
Operating expenses:
Operating costs....................... 123.0 94.8
Depreciation, depletion and
amortization....................... 63.7 52.9
------- -------
Total operating expenses........... 186.7 147.7
------- -------
Operating income........................ $ 150.1 $ 107.8
------- -------
------- -------
Gathering, processing and marketing margins increased by $91.1 million
(37%) to $336.8 million in 1996. Increased plant volumes of 36.3 MMcfed (16%)
added $21.2 million in plant revenues while higher prices of $0.62 per Mcfe
(40%) added $59.8 million in plant revenues. Pipeline revenue increases of $63.9
million in 1996 were primarily attributable to increased throughput and higher
prices at the Ferguson-Burleson pipeline in the Austin Chalk area and the Ozona
pipeline in western Texas. Revenues from the Wahsatch pipeline in the Rockies
area were down due to lower throughput and tariff rates. Gas purchase costs were
higher by $72.8 million as a result of increased throughput and higher prices
paid by the Ozona, Peachridge and Ferguson-Burleson pipelines and certain plants
in the Austin Chalk area.
Marketing margins increased by $24.6 million in 1996 primarily as a result
of improved natural gas and natural gas liquids margins, additional marketed
volumes and increased natural gas storage activity.
23
YEARS ENDED
DECEMBER 31,
----------------
1996 1995
------ ------
Average price realizations--plants:
Natural gas (per Mcf).................................................................. $ 2.01 $ 1.51
Natural gas liquids (per Bbl).......................................................... 13.16 9.38
Average (per Mcfe)..................................................................... 2.18 1.56
Sales volumes--plants:
Natural gas (MMcfd).................................................................... 26.7 23.9
Natural gas liquids (MBbld)............................................................ 39.8 34.2
Total (MMcfed)......................................................................... 265.4 229.1
Natural gas liquids volumes increased by 5.6 MBbld (16%) to 39.8 MBbld
primarily due to the expansion of the Ozona, Brookeland and Echo Springs plants,
greater retention percentages at the Brookeland plant reflecting third parties'
elections to reject liquids, as well as ethane recovery in other Rockies area
plants. Volume decreases occurred with a contract revision at Gulf Plains plant,
leaner gas streams and lower inlets at certain plants in the Austin Chalk area
and the disposition of certain plants in western Texas and the Rockies. Natural
gas volumes were up 2.8 MMcfd (12%) to 26.7 MMcfd resulting from the Brookeland
plant expansion and increased throughput at Gulf Plains plant.
Gathering, processing and marketing expenses increased by $28.2 million
(30%) in 1996 due to an asset impairment adjustment related to the Wahsatch
pipeline ($17 million) and higher marketing expenses ($9.6 million) associated
with system development, legal and other operating costs. GPM depreciation,
depletion and amortization costs increased $10.8 million in 1996, primarily due
to a higher asset base of plants and pipelines.
MINERALS OPERATIONS
YEARS ENDED DECEMBER 31,
-------------------------
1996 1995
---------- ----------
(MILLIONS OF DOLLARS)
Operating revenues...................... $ 128.9 $ 116.3
Operating expenses...................... 8.0 8.8
Depreciation, depletion and
amortization.......................... 0.9 0.4
------- -------
Operating income................... $ 120.0 $ 107.1
------- -------
------- -------
Minerals operating income increased by $12.9 million (12%) to $120 million
in 1996, as a result of $6.7 million in higher soda ash joint venture income, an
increase in ballast income, higher coal royalty income associated with more tons
mined on the Company's leases and decreased operating expenses.
GENERAL AND ADMINISTRATIVE EXPENSES
YEARS ENDED
DECEMBER 31,
-------------------------
1996 1995
---------- ----------
(MILLIONS OF DOLLARS)
General and administrative expenses..... $ (68.4) $ (50.3)
Depreciation, depletion and
amortization.......................... (3.8) (2.2)
------- -------
Corporate/general and
administrative.................... $ (72.2) $ (52.5)
------- -------
------- -------
General and administrative expenses increased by $19.7 million (38%) in
1996 as a result of increased costs associated with being a stand-alone public
company and costs of completing information and accounting system conversions.
On a pro forma basis, general and administrative expenses increased by $0.01 per
Mcfe to $0.11 per Mcfe. (See Note 2 to the Consolidated Financial Statements for
pro forma income information).
24
INTEREST EXPENSE AND OTHER INCOME
Interest expense increased by $31.5 million to $50.6 million in 1996, while
other income-net declined by $10.4 million. These changes principally reflect
the effects of the debt restructuring (higher debt balances and lower
interest-earning advances to UPC) that occurred at the time of the Offering.
INCOME TAXES
Income taxes increased by $44.5 million to $151.8 million in 1996 due to
higher income before taxes, a $22.3 million decrease in Section 29 tax credits,
a $3 million unfavorable state tax adjustment relating to prior years' federal
income tax audits and the absence of favorable 1995 tax adjustments totaling
$22.2 million. Excluding such adjustments, the effective tax rate for 1996 would
have been 31.5% (including Section 29 tax credits of $15.6 million) compared
with 28.3% in 1995 (including Section 29 tax credits of $37.9 million).
LIQUIDITY AND CAPITAL RESOURCES
Cash provided by operations for 1997 was $968.8 million, down by $21.6
million from 1996. The decrease principally relates to unfavorable working
capital changes due primarily to a reduction in accrued taxes payable, partially
offset by favorable changes in deferred income taxes.
The Company expects to increase its oil and gas volumes in 1998 while
growing its reserves. Sales volume growth is anticipated primarily in the Gulf
Onshore/Offshore, South Texas/Plains/Canada and Austin Chalk business units. The
Company expects to remain one of the most active drillers in the United States
in 1998 based on the number of active drilling rigs, and will continue to search
for properties and reserves which will supplement its drill site inventory. In
addition, volumes in the GPM business unit are anticipated to increase 15% as a
result of the Company's acquisition of Highlands and recent expansions of
Patrick Draw and Masters Creek plants.
Prices for oil, gas and natural gas liquids for 1998 are expected to be
lower than the average for the previous years. Increased production from OPEC
countries, including sales by Iraq, along with the decline in several Asian
countries' economies has altered the balance between supply and demand for oil,
sending recent oil prices 20% lower than in previous years. The recent mild
weather in the United States resulting from the El Nino effect has also resulted
in a downward trend in gas prices. The Company expects to experience price
fluctuations and manages some price risk with hedging activities. Lower prices
could materially affect expected future net income, cash flows and capital
spending.
The Company owns a nonoperating 50% interest in Black Butte, a partnership
which operates a surface coal mine complex in southwestern Wyoming ('Black
Butte'). During 1997, Black Butte's sales to its largest customer under an
amended coal supply contract accounted for $59.3 million, or 12%, of the
Company's 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 the financially beneficial terms of this 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 of its competition.
The Company does not expect to be able to replace the operating income it
currently receives under the contract with incremental coal sales after the year
2000.
Capital spending increased by $651.4 million (74%) to $1,531.7 million in
1997, compared to $880.3 million for 1996. The Company's ability to maintain and
improve its operating income and cash flow is dependent upon continued capital
spending, among other things. The following table summarizes capital
expenditures for 1997 and 1996.
YEARS ENDED DECEMBER 31,
----------------------------------------------------
1997 1996
------------- -------------
(MILLIONS OF DOLLARS)
Producing properties:
Production............................ $ 621.8 $429.5
Exploration........................... 399.3 237.5
Property acquisitions................. 130.6 85.7
---------- -------
Total producing properties....... 1,151.7 752.7
---------- -------
Gathering, processing and marketing... 364.2 118.1
Minerals and other.................... 15.8 9.5
---------- -------
Total capital expenditures....... $1,531.7 $880.3
---------- -------
---------- -------
25
Producing property capital spending was up by $399 million (53%) in 1997 as
a result of higher lease acquisition costs of $95.8 million, primarily in the
Austin Chalk and East Texas business units and increased exploratory and
development drilling ($222.3 million). Drilling accounted for $682.9 million
(45%) of capital expenditures in 1997, with $207.8 million in the Austin Chalk
business unit. Property acquisitions totaling $130.6 million were completed in
1997 compared to $85.7 million in 1996. The Company expanded its GPM operations
and increased its capital spending by $246.1 million in 1997. The increase in
GPM capital spending was related to the completion of the Masters Creek plant in
Louisiana, expansion of the East Texas plant and the acquisition of Highlands.
The Company expects its capital spending in 1998 to be in the range of $1.5
to $1.8 billion, including projected spending associated with the Norcen
acquisition. The Company plans to focus such spending primarily on exploration
and development activities in the Austin Chalk, Gulf Onshore/Offshore, western
Canada and Guatemala business units or areas. Such spending in the Gulf
Onshore/Offshore business unit includes capital to drill two or three additional
wells in the Gulf of Mexico in 1998 to further delineate the extent of the
discovery in the Mississippi Canyon Block 755 deepwater prospect. In addition,
the Company plans to acquire producing properties and expand its GPM operations.
As a result of continued increase in the worldwide demand for soda ash, the
Company, along with its partner Oriental Chemical Industries, Inc. ('OCI') plans
to expand the OCI Wyoming LP's soda ash facility by 950,000 tons per year, from
the plant's current nameplate capacity of 2.3 million tons per year, by 1999.
The Company has made an additional investment and expects expansion costs to be
primarily funded by a $100 million credit facility of OCI Wyoming LP guaranteed
by OCI 51% and the Company 49%.
As of December 31, 1997 and 1996, the total capitalization of the Company
was as follows:
AS OF DECEMBER 31,
----------------------
1997 1996
-------- --------
(MILLIONS OF DOLLARS)
Commercial paper, net.......................................................... $ 663.1 $ 99.6
7% Notes due 2006.............................................................. 200.0 200.0
7.5% Debentures due 2026....................................................... 200.0 200.0
7.5% Debentures due 2096....................................................... 150.0 150.0
Tax exempt revenue bonds....................................................... 20.1 24.0
Discount on notes and debentures............................................... (2.6) (2.7)
-------- --------
Total long-term debt.................................................... 1,230.6 670.9
-------- --------
Shareholders' equity........................................................... 1,760.7 1,514.3
-------- --------
Total capitalization.................................................... $2,991.3 $2,185.2
-------- --------
-------- --------
Debt to total capitalization................................................... 41.1% 30.7%
-------- --------
-------- --------
None of the Company's Notes and Debentures are redeemable prior to maturity
or subject to any sinking fund requirements. In addition, the Company has an
effective Shelf Registration Statement on file with the Securities and Exchange
Commission ('SEC'), which would permit the Company to offer up to $900 million
in debt and equity securities.
The Company has a $600 million revolving credit agreement that expires in
August 2001 and a $300 million revolving credit agreement which expires in
November 1998. Borrowings under these agreements, at the Company's election,
bear interest either at a spread over London Interbank Offered Rate ('LIBOR') or
at a spread over domestic certificate of deposit rates, in each case depending
on the Company's senior debt rating. The Company is required to pay facility
fees on the aggregate amount of the commitment ranging from 0.06% to 0.15% also
depending on the Company's senior debt rating. As a result of the Norcen
acquisition, the covenants for these agreements have been modified. Under these
agreements debt can not exceed 75% of the total of the Company's debt and
shareholders' equity (and 65% after 18 months) and requires the combined EBITDAX
(the sum of operating income; depreciation, depletion and amortization; and
exploration expenses) of the Company's Principal Subsidiaries (as defined in the
agreements) to be at least 80% of the Company's consolidated EBITDAX. These
agreements also impose certain restrictions on the Company regarding the
creation of liens, incurrence of indebtedness, transactions with affiliates,
sales of the stock of UPRC and certain mergers, consolidations and asset sales.
As of December 31, 1997, there were no borrowings outstanding under these credit
facilities although borrowing capacity is reduced by outstanding commercial
paper. The Company had the
26
capacity to borrow $900 million, less commercial paper outstanding, under these
agreements as of December 31, 1997.
Excluding commercial paper, the Company has no debt maturing in the next
five years. Outstanding commercial paper has been classified as long-term debt
reflecting the Company's intent to maintain these short-term borrowings on a
long-term basis either through the issuance of commercial paper and term
financings. In addition, the Company could borrow under the credit agreements.
As a result of the Norcen acquisition, the Company will increase its debt
by $3.6 billion, including $2.7 billion acquisition debt and approximately $900
million of existing commercial paper and debentures of Norcen. In addition to
the covenants described above, the $2.7 billion acquisition facility entered
into by the Company includes a mandatory prepayment provision and a series of
'prepayment events.' The mandatory prepayment provision requires that $1.35
billion be repaid prior to March, 1999. In addition, 75% of the net proceeds
resulting from any prepayment events should be applied to reduce the
indebtedness under the acquisition facility. Prepayment events include sales of
assets in excess of $10 million and debt and equity issuances. This increased
debt is expected to raise the Company's debt to total capitalization ratio from
41% at December 31, 1997 to approximately 72% as of March 1998. The Company
plans to pursue an aggressive deleveraging program, which may include asset and
financial divestitures and the issuance of equity securities.
The Company paid cash dividends of $50 million in 1997, which represents a
$0.05 per share quarterly cash dividend on its outstanding shares of Common
Stock. On January 26, 1998, the Board of Directors declared a $0.05 per share
quarterly cash dividend for shareholders of record on March 11, 1998, payable
April 1, 1998. 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. The Company has no current plans to increase its
dividend rate.
The Company purchased $52.3 million of its Common Stock during 1997. In
November 1997, the Board of Directors authorized the purchase of an additional
$50 million of Common Stock during 1998.
The Company believes that cash from operations, additional available
financing and proceeds from asset and financial divestitures will enable it to
fund its ongoing capital expenditures, dividends and working capital
requirements for the foreseeable future.
ITEM 7A. RISK MANAGEMENT
The Company has established policies and procedures for managing risk
within its organization. These policies and procedures incorporate internal
controls and are governed 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.
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 instruments usually limit future gains from favorable price
movements. Such risk management activities are generally accomplished pursuant
to exchange-traded contracts or over-the-counter options.
Recognition of realized gains/losses in the Consolidated Statement of
Income and option premium payments/receipts are deferred until the underlying
physical product is purchased or sold. Unrealized gains/losses on derivative
financial instruments are not recorded. 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. The cash flow impact of derivative and other financial instruments is
reflected as cash flows from operating activities in the Consolidated Statement
of Cash Flows.
27
As a result of the various hedging transactions for natural gas, natural
gas liquids and crude oil, the Company realized $28.1 million and $45.5 million
of pre-tax losses in 1997 and 1996, respectively. Since these transactions were
hedges on production, these losses were included in sales and other operating
revenues and were reflected in the average sales price of the associated
products.
The following table summarizes the Company's open positions as of December
31, 1997.
WEIGHTED FAIR UNRECOGNIZED
CONTRACT CONTRACT AVG. PRICES VALUE GAIN (LOSS)
PRODUCT TYPE TIME PERIOD VOLUME PER MCF (MILLIONS OF DOLLARS) (MILLIONS OF DOLLARS)
- ------ --------------- ------------------ ---------- ----------- --------------------- ---------------------
Gas Future/swaps Feb-Mar 1998 449 MMcfd $2.33 $ 3.7 $ 3.7
Gas Future/swaps Apr-Oct 1998 369 MMcfd $2.08 (4.3) (4.3)
Gas Future/swaps Nov-Dec 1998 100 MMcfd $2.17 (1.5) (1.5)
Gas Calls sold Feb-Mar 1998 405 MMcfd $3.20 0.1 3.8
Gas Net calls sold Apr-Oct 1998 96 MMcfd $2.58 1.1 0.8
Gas Puts purchased Feb-Mar 1998 450 MMcfd $2.21 5.5 1.0
Gas Puts purchased Apr-Oct 1998 166 MMcfd $2.04 5.0 (0.2)
Gas Fixed price Feb 1998-Jun 2008 62.6 Bcf $2.98 28.1 28.1
------
$31.4
------
------
Additionally, the Company had previously sold near-term futures contacts
and swaps for February through December 1998 with respect to notional natural
gas volumes of 47 MMcfd, then subsequently offset these positions by purchasing
corresponding volumes through futures contracts and swaps for the same delivery
periods. The unrealized gain at December 31, 1997 relating to these transactions
was $0.6 million. UP Fuels periodically enters into financial contracts in
conjunction with transportation, storage, and customer service programs. The
unrecognized mark-to-market loss associated with such contracts as of December
31, 1997 is $0.5 million.
The Company had a total unrecognized mark-to-market present value gain of
$31.5 million related to the financial and fixed price sales contracts described
above. This gain consists of $28.1 million net gain on long-term fixed price
sales contracts and $3.4 million net gain on financial derivative instruments.
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.
COMMODITY PRICE RISK-TRADING ACTIVITIES
Periodically, the Company may enter into transactions involving a wide
range of energy related derivative financial transactions that are not the
result of hedging activities. These instruments are generally put into place
based on the Company's analysis and expectations with respect to price movement
or changes in other market variables. As of December 31, 1997 and 1996, there
were no commodity price risk-trading activity contracts outstanding.
INTEREST RATE SWAPS
The Company periodically enters into rate swaps and contracts to hedge
certain interest rate transactions. As of December 31, 1997 and 1996, there were
no interest rate contracts outstanding which materially affect the results of
operations or financial condition of the Company.
FOREIGN CURRENCY CONTRACTS
The Company periodically enters into foreign currency contracts to hedge
specific currency exposures from commercial transactions. As of December 31,
1997 and 1996, there were no foreign currency contracts outstanding.
28
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, 1997, the Company's largest credit risk associated with any
single counterparty, represented by the net fair value of open contracts with
such counterparty was less than $1 million.
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 and local 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, 1997, long and short-term liabilities totaling $75.7
million 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 as much as 10% 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 $37.8 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
liability. 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 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 $14.7 million in 1997 and $11.4
million in 1996. In 1998, the Company anticipates spending a total of $20
million for remediation and control, including $9 million relating to the
Wilmington, California properties. The majority of accrued environmental
liability as of December 31,1997 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 adopted a Year 2000 Readiness Program and an implementation
plan. The Company is in the process of conducting a comprehensive evaluation and
assessment of the business risks and exposures related to the coming change in
the century. These business risks and exposures relate to the problem present in
certain
29
software and embedded logic control devices to recognize the change in the
century. If not corrected, such software and devices could fail or create
erroneous results by or at the year 2000.
Since 1993, the Company has replaced all major information systems with
Year 2000 compliance as a criterion; therefore, the Company does not currently
expect to incur any material amount of expense associated with its remediation
of its major information systems. With respect to the risks and exposures
related to the Company's customers, partners, suppliers, financial institutions
and other constituencies and the resulting potential impact on the Company's
business operations and financial condition, the Company has initiated formal
communications with its customers, partners, suppliers, financial institutions
and other constituencies to mitigate or prevent such risks and exposures. The
extent of such risks and exposures will be assessed and evaluated.
The evaluation and assessment of the extent of the risks and exposures
related to the Company's information systems, including embedded logic devices,
and the Company's customers, partners, suppliers, financial institutions, and
other constituencies, should be substantially completed during 1998. The Company
has retained a consultant to advise the Company in the evaluation and assessment
phase of the implementation plan. The costs associated with the Year 2000
Readiness Program and its implementation are not currently expected to be
material. Until the evaluation and assessment is completed, the Company can not
have a reasonable basis to conclude that the risks and exposures related to the
Year 2000 will not materially: affect future financial results, or cause
reported financial information not to reflect fairly the future operating
results, cash flows or financial condition of the Company.
FORWARD LOOKING INFORMATION
Certain information included in this report contains, 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, or will contain or include, 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, development
activities, cost savings efforts, production efforts and volumes, hydrocarbon
reserves, hydrocarbon prices, hedging activities and the results thereof,
liquidity, regulatory matters, competition and the Company's ability to realize
significant improvements with the change to a more adaptive corporate culture.
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
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. The Company
does not intend to update these cautionary statements.
With respect to expected capital expenditures and drilling activity,
additional factors such as 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 expected growth in production and sales volumes and estimated
reserve quantities, factors such as
30
the extent of the Company's success in finding, developing and producing
reserves, the timing of capital spending and acquisition 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, factors such as changes in oil and gas prices, the Company's success
in acquiring producing properties, environmental matters and other
contingencies, hedging activities, the Company's credit rating and debt levels,
and the state of domestic capital markets 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.
31
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
PAGE
----
Responsibilities for Financial Statements................................................................ 33
Independent Auditors' Report............................................................................. 34
Consolidated Statements of Income for the Years Ended December 31, 1997, 1996 and 1995................... 35
Consolidated Statements of Financial Position as of December 31, 1997 and 1996........................... 36
Consolidated Statements of Cash Flows for the Years Ended December 31, 1997, 1996 and 1995............... 37
Consolidated Statements of Changes in Shareholders' Equity for the Years Ended December 31, 1997, 1996
and 1995.............................................................................................. 38
Business Segment Information............................................................................. 39
Notes to Consolidated Financial Statements............................................................... 40
Supplementary Information (Unaudited).................................................................... 59
32
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 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 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 six 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
33
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 1996, and the related consolidated statements of income, changes in
shareholders' equity and cash flows for each of the three years in the period
ended December 31, 1997. 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 1996, and the results of its operations and its cash flows
for each of the three years in the period ended December 31, 1997 in conformity
with generally accepted accounting principles.
DELOITTE & TOUCHE LLP
Fort Worth, Texas
January 26, 1998
34
UNION PACIFIC RESOURCES GROUP INC.
CONSOLIDATED STATEMENTS OF INCOME
FOR THE YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995
1997 1996 1995
-------- -------- --------
(MILLIONS, EXCEPT PER SHARE
AMOUNTS)
Operating revenues: (Note 5)
Oil and gas operations:
Producing properties...................................................... $1,281.2 $1,133.3 $ 853.6
Gathering, processing and marketing....................................... 443.3 503.8 339.9
Other oil and gas revenues (Note 4)....................................... 60.4 65.0 166.9
-------- -------- --------
Total oil and gas operations............................................ 1,784.9 1,702.1 1,360.4
Minerals (Note 12)........................................................... 139.8 128.9 116.3
-------- -------- --------
Total operating revenues................................................ 1,924.7 1,831.0 1,476.7
-------- -------- --------
Operating expenses:
Production................................................................... 292.6 259.5 210.5
Exploration.................................................................. 204.7 144.6 89.4
Gathering, processing and marketing.......................................... 285.2 290.0 189.0
Minerals (Note 12)........................................................... 3.4 8.0 8.8
Depreciation, depletion and amortization..................................... 568.1 533.9 458.6
General and administrative................................................... 75.5 68.4 50.3
-------- -------- --------
Total operating expenses................................................ 1,429.5 1,304.4 1,006.6
-------- -------- --------
Operating income............................................................... 495.2 526.6 470.1
Other income (expense)--net (Notes 3 and 4).................................... 24.3 (3.4) 7.0
Interest expense--net (Notes 3 and 8).......................................... (53.1) (50.6) (19.1)
-------- -------- --------
Income before income taxes..................................................... 466.4 472.6 458.0
Income taxes (Note 7).......................................................... (133.4) (151.8) (107.3)
-------- -------- --------
Net income (Note 2)............................................................ $ 333.0 $ 320.8 $ 350.7
-------- -------- --------
-------- -------- --------
Earnings per share--basic (see Significant Accounting Policies--Earnings Per
Share)....................................................................... $ 1.33 $ 1.29
Earnings per share--diluted.................................................... $ 1.33 $ 1.28
Weighted average shares outstanding--diluted................................... 250.9 250.1
Cash dividends per share....................................................... $ 0.20 $ 0.20
The accompanying accounting policies and notes to the consolidated
financial statements are an integral part of these statements.
35
UNION PACIFIC RESOURCES GROUP INC.
CONSOLIDATED STATEMENTS OF FINANCIAL POSITION
AS OF DECEMBER 31, 1997 AND 1996
1997 1996
--------- ---------
(MILLIONS OF DOLLARS)
ASSETS
Current assets:
Cash and temporary investments......................................................... $ 70.6 $ 118.9
Accounts receivable (net of allowance for doubtful accounts of $3.9 million in 1997 and
$4.5 million in 1996)............................................................... 385.4 351.6
Inventories............................................................................ 53.1 29.4
Other current assets................................................................... 67.7 86.4
--------- ---------
Total current assets.............................................................. 576.8 586.3
--------- ---------
Properties: (Notes 6 and 18)
Cost................................................................................... 7,414.4 6,190.0
Accumulated depreciation, depletion and amortization................................... (3,749.0) (3,217.6)
--------- ---------
Total properties.................................................................. 3,665.4 2,972.4
Intangible and other assets (Note 12).................................................... 230.0 90.2
--------- ---------
Total assets...................................................................... $ 4,472.2 $ 3,648.9
--------- ---------
--------- ---------
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable....................................................................... $ 426.7 $ 407.4
Accrued taxes payable.................................................................. 59.3 134.1
Other current liabilities.............................................................. 71.7 71.3
--------- ---------
Total current liabilities......................................................... 557.7 612.8
Long-term debt (Notes 8 and 18).......................................................... 1,230.6 670.9
Deferred income taxes (Note 7)........................................................... 552.9 434.7
Retiree benefits obligations (Note 10)................................................... 147.7 151.4
Other long-term liabilities (Notes 12, 13, 14 and 15).................................... 222.6 264.8
Shareholders' equity (see page 38)....................................................... 1,760.7 1,514.3
--------- ---------
Total liabilities and shareholders' equity........................................ $ 4,472.2 $ 3,648.9
--------- ---------
--------- ---------
The accompanying accounting policies and notes to the consolidated
financial statements are an integral part of these statements.
36
UNION PACIFIC RESOURCES GROUP INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995
1997 1996 1995
--------- ------- ---------
(MILLIONS OF DOLLARS)
Cash provided by operations:
Net income................................................................... $ 333.0 $ 320.8 $ 350.7
Non-cash charges to income:
Depreciation, depletion and amortization.................................. 568.1 533.9 458.6
Deferred income taxes (Note 7)............................................ 119.7 37.0 (18.3)
Other non-cash charges (credits)--net..................................... (35.0) 8.0 (65.8)
Exploratory expenditures..................................................... 76.9 51.6 36.0
Changes in current assets and liabilities.................................... (93.9) 39.1 68.2
--------- ------- ---------
Cash provided by operations............................................. 968.8 990.4 829.4
--------- ------- ---------
Investing activities:
Capital and exploratory expenditures (Note 17)............................... (1,352.3) (880.3) (686.4)
Acquisition of Highlands Gas Corporation (Note 4)............................ (179.4) -- --
Proceeds from sales of assets (Note 4)....................................... 44.6 30.2 111.1
Other investing activities--net.............................................. (17.7) (2.8) (7.5)
--------- ------- ---------
Cash (used) by investing activities..................................... (1,504.8) (852.9) (582.8)
--------- ------- ---------
Financing activities:
Dividends paid (Note 2)...................................................... (50.0) (49.8) (1,713.9)
Debt financings (Note 8)..................................................... 563.5 646.9 68.0
Debt repaid.................................................................. (3.9) (77.5) (47.4)
Repurchase of common stock................................................... (52.3) (3.5) --
Proceeds from initial public offering (Note 2)............................... -- -- 843.9
Advances from (to) Union Pacific Corporation (Notes 2 and 3)................. -- (567.8) 627.1
Other financings--net (Note 8)............................................... 30.4 5.5 (3.4)
--------- ------- ---------
Cash provided (used) by financing activities............................ 487.7 (46.2) (225.7)
--------- ------- ---------
Net change in cash and temporary investments................................... (48.3) 91.3 20.9
Balance at beginning of year................................................... 118.9 27.6 6.7
--------- ------- ---------
Balance at end of year......................................................... $ 70.6 $ 118.9 $ 27.6
--------- ------- ---------
--------- ------- ---------
Changes in current assets and liabilities:
Accounts receivable.......................................................... $ (33.9) $(111.5) $ 4.0
Inventories.................................................................. (23.7) 38.1 (9.2)
Other current assets......................................................... 18.8 (1.6) 79.7
Accounts payable............................................................. 19.2 60.4 10.0
Accrued taxes payable........................................................ (74.7) 46.7 22.4
Short-term debt.............................................................. -- -- (43.2)
Other current liabilities.................................................... 0.4 7.0 4.5
--------- ------- ---------
Total................................................................... $ (93.9) $ 39.1 $ 68.2
--------- ------- ---------
--------- ------- ---------
Supplemental cash flow disclosure:
Interest paid................................................................ $ 56.3 $ 43.4 $ 20.0
Income taxes paid............................................................ 129.7 79.0 29.7
The accompanying accounting policies and notes to the consolidated
financial statements are an integral part of these statements.
37
UNION PACIFIC RESOURCES GROUP INC.
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS' EQUITY
FOR THE YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995
1997 1996 1995
-------- -------- ---------
(MILLIONS OF DOLLARS)
Common stock, $1.00 par value; authorized 5,000,000 shares:
4,485,000 shares issued and outstanding at December 31, 1994
Balance at beginning of year................................................... $ -- $ -- $ 4.5
Asset restructuring (Note 2)................................................... -- -- (4.5)
-------- -------- ---------
Balance at end of year......................................................... -- -- --
-------- -------- ---------
Common stock, no par value; authorized 400,000,000 shares:
251,888,575 shares issued and outstanding at December 31, 1997 and 250,058,019
shares issued at December 31, 1996 (Note 2)
Balance at beginning and end of year........................................... -- -- --
-------- -------- ---------
Paid-in surplus:
Balance at beginning of year................................................... 872.9 860.2 421.2
Asset restructuring (Note 2)................................................... -- -- (421.2)
Initial public offering (Note 2)............................................... -- -- 843.9
Conversion, award, forfeiture and appreciation of retention shares (Note 11)... 5.1 15.9 9.9
Issuance of ESOP shares (Note 11).............................................. 107.3 -- --
Exercise of Stock Options...................................................... 5.5 0.5 --
Other.......................................................................... 0.4 (3.7) 6.4
-------- -------- ---------
Balance at end of year......................................................... 991.2 872.9 860.2
-------- -------- ---------
Retained earnings:
Balance at beginning of year................................................... 674.4 472.9 1,422.6
Net income..................................................................... 333.0 320.8 350.7
-------- -------- ---------
Total........................................................................ 1,007.4 793.7 1,773.3
Dividends declared on common stock (Note 2).................................... (50.0) (49.8) (1,726.3)
Pension asset adjustment (Note 10)............................................. -- (69.5) --
Asset restructuring (Note 2)................................................... -- -- 425.9
-------- -------- ---------
Balance at end of year......................................................... 957.4 674.4 472.9
-------- -------- ---------
Unearned compensation:
Balance at beginning of year................................................... (17.5) (9.2) --
Conversion, award, appreciation and amortization of retention shares--net (Note
11) ......................................................................... 5.7 (8.3) (9.2)
-------- -------- ---------
Balance at end of year......................................................... (11.8) (17.5) (9.2)
-------- -------- ---------
Deferred foreign exchange adjustment:
Balance at beginning of year................................................... (12.0) (11.5) (13.4)
Foreign currency translation adjustment........................................ (5.3) (0.5) (1.9)
-------- -------- ---------
Balance at end of year......................................................... (17.3) (12.0) (11.5)
-------- -------- ---------
ESOP (Note 11):
Balance at beginning of year................................................... -- -- --
Issuance of ESOP shares........................................................ (107.3) -- --
Release of ESOP shares......................................................... 5.3 -- --
-------- -------- ---------
Balance at end of year......................................................... (102.0) -- --
Treasury stock:
Balance at beginning of year................................................... (3.5) -- --
Treasury stock, at cost........................................................ (52.3) (3.5) --
-------- -------- ---------
Balance at end of year 2,379,625 shares at December 31, 1997
154,417 shares at December 31, 1996..................... (55.8) (3.5) --
-------- -------- ---------
Minimum pension liability........................................................ (1.0) -- --
-------- -------- ---------
Total shareholders' equity................................................... $1,760.7 $1,514.3 $ 1,312.4
-------- -------- ---------
-------- -------- ---------
The accompanying accounting policies and notes to the consolidated
financial statements are an integral part of these statements.
38
UNION PACIFIC RESOURCES GROUP INC.
BUSINESS SEGMENT INFORMATION
FOR THE YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995
1997 1996 1995
-------- -------- --------
(MILLIONS OF DOLLARS)
Revenues: 1,2
Exploration and production................................................... $1,334.7 $1,198.3 $1,010.7
Gathering, processing and marketing.......................................... 450.2 503.8 349.7
Minerals..................................................................... 139.8 128.9 116.3
-------- -------- --------
Total revenues............................................................ $1,924.7 $1,831.0 $1,476.7
-------- -------- --------
-------- -------- --------
Depreciation, depletion and amortization:
Exploration and production................................................... $ 493.0 $ 465.5 $ 403.1
Gathering, processing and marketing.......................................... 70.4 63.7 52.9
Minerals..................................................................... 0.9 0.9 0.4
Corporate.................................................................... 3.8 3.8 2.2
-------- -------- --------
Total depreciation, depletion and amortization............................ $ 568.1 $ 533.9 $ 458.6
-------- -------- --------
-------- -------- --------
Operating income: 3
Exploration and production................................................... $ 344.4 $ 328.7 $ 307.7
Gathering, processing and marketing.......................................... 94.6 150.1 107.8
Minerals..................................................................... 135.5 120.0 107.1
Corporate.................................................................... (79.3) (72.2) (52.5)
-------- -------- --------
Total operating income.................................................... $ 495.2 $ 526.6 $ 470.1
-------- -------- --------
-------- -------- --------
Fixed assets--net:
Exploration and production................................................... $2,695.7 $2,227.4 $2,049.9
Gathering, processing and marketing.......................................... 843.4 637.8 610.7
Minerals..................................................................... 23.6 21.9 23.6
Corporate.................................................................... 102.7 85.3 80.1
-------- -------- --------
Total fixed assets--net................................................... $3,665.4 $2,972.4 $2,764.3
-------- -------- --------
-------- -------- --------
Capital and exploratory expenditures:
Exploration and production................................................... $1,151.7 $ 752.7 $ 577.9
Gathering, processing and marketing.......................................... 364.2 118.1 106.5
Minerals..................................................................... 1.4 0.8 0.2
Corporate.................................................................... 14.4 8.7 1.8
-------- -------- --------
Total capital and exploratory expenditures................................ $1,531.7 $ 880.3 $ 686.4
-------- -------- --------
-------- -------- --------
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.
- ------------------------
1 The exploration and production segment sells a significant portion of its oil
and gas volumes to the Company's wholly owned marketing subsidiary, Union
Pacific Fuels, Inc. at market prices. See 'Significant Accounting
Policies--Revenue Recognition.'
2 1997, 1996 and 1995 revenues include income from equity affiliates of $0.7
million, $0.8 million and $0.7 million, respectively, for the gathering,
processing and marketing segment and $74.5 million, $74.5 million and $68.2
million, respectively for the minerals segment.
3 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.
39
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. 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
and consolidates the proportionate share of such investments. All significant
intercompany transactions are eliminated. The consolidated statements of income
for previous periods include certain reclassifications that were made to conform
to the current presentation. Such reclassifications have no effect on previously
reported operating income or net income.
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, 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.
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 three to
30 years.
Costs of future site restoration, dismantlement and abandonment for onshore
producing properties are accrued (based on internal engineering estimates) 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.
Costs of future site restoration, dismantlement and abandonment for offshore
wells and production platforms also are accrued based on internal engineering
estimates using the unit of production method with a charge to depreciation,
depletion and amortization expense. The balance of the offshore abandonment
accrual at December 31, 1997 and 1996 was $7.7 million and $6.2 million,
respectively, and is classified in other long-term liabilities.
Potential impairment of producing properties and significant unproved
properties is assessed annually (unless economic events warrant more frequent
reviews) on a field-by-field basis; all other unproved properties are assessed
annually on an aggregate basis. In addition, a quarterly impairment analysis of
aggregated properties is performed by the Company using undiscounted future net
cash flows determined based upon current prices and costs.
Costs of retired, sold or abandoned properties that constitute part of an
amortization base are charged or credited, 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 (see Note 16).
Environmental Expenditures. 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 (see Note 13).
40
UNION PACIFIC RESOURCES GROUP INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
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. Goodwill of $90.7 million, acquired subsequent to 1971, is being
amortized on a straight-line basis over a 20 year period. Amortization of
goodwill was $2 million for 1997. The value of goodwill is periodically
evaluated based on the expected future undiscounted operating cash flows to
determine whether any potential impairment exists (see Note 12).
Revenue Recognition. Sales from producing gas wells are recognized on the
entitlement method of accounting which defers recognition of sales and related
costs 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 and related costs are
recorded to reflect the full net revenue interest.
Marketing revenue included in gathering, processing and marketing revenues
is recorded net of the cost of hydrocarbons purchased.
Derivative Financial Instruments. Unrealized gains/losses on derivative
financial instruments are not recorded. Recognition of realized gains/losses and
option premium payments/receipts are deferred and recorded in the Consolidated
Statement of Income when the underlying physical product is purchased or sold.
Margin deposits, realized gains/losses on derivative financial instruments and
net premiums are included in other current assets or liabilities in the
Consolidated Statement of Financial Position. The cash flow impact of derivative
and other financial instruments is reflected in cash provided by operations in
the Consolidated Statement of Cash Flows.
Income Taxes. Deferred income taxes are provided for items of income and
expense that are included in income for financial reporting purposes in
different reporting periods than for federal or state income tax purposes.
Until its spinoff from Union Pacific Corporation ('UPC') in October 1996
(see Note 2), the Company was included in UPC's consolidated income tax return.
The consolidated income tax liability of UPC through such date has been
allocated among its affiliated companies on the basis of their separate
contributions to the consolidated income tax liability, with full benefit of tax
losses and credits utilized in consolidation being allocated to the individual
companies generating such losses and credits.
Stock-Based Compensation. Compensation expense is recorded with respect to
stock option grants and retention stock awards to employees using the intrinsic
value method. 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.
Earnings Per Share. In 1997, the Financial Accounting Standards Board
('FASB') issued Statement of Financial Accounting Standards ('SFAS') No. 128,
'Earnings Per Share' ('EPS') which established new standards for computing and
presenting EPS. SFAS No. 128 replaced the presentation of primary EPS with a
presentation of basic EPS. Basic 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 common stock
were exercised or converted into common stock. EPS amounts for 1997 and 1996
have been presented and, where appropriate, restated to conform to the SFAS No.
128 requirements (see Note 11).
EPS for the year ended December 31, 1995 has been omitted from the
Consolidated Statements of Income as the Company was a wholly owned subsidiary
of UPC until its initial public offering in October 1995. Pro forma 1995 EPS
(see Note 2) are based upon 249.7 million average common shares outstanding
during the period from completion of the Offering (hereinafter defined) until
December 31, 1995.
41
UNION PACIFIC RESOURCES GROUP INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
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 59).
Recently Issued Accounting Standards. In June 1997, the FASB issued SFAS
No. 130, 'Reporting Comprehensive Income,' which establishes standards for
reporting comprehensive income and its components (revenues, expenses, gains and
losses) in a full set of general-purpose statements. It requires (a)
classification of items of other comprehensive income by their nature in a
financial statement and (b) display of the accumulated balance of other
comprehensive income separate from retained earnings and additional paid-in
surplus in the equity section of the Statement of Financial Position. The
Company plans to adopt SFAS No. 130 for the quarter ended March 31, 1998.
In June 1997, the FASB issued SFAS No. 131, 'Disclosures about Segments of
an Enterprise and Related Information,' which established standards for
reporting information about operating segments in annual financial statements
and requires selected information about operating segments in interim financial
reports issued to shareholders. SFAS No. 131 also establishes standards for
related disclosures about products and services, geographic areas and major
customers. The Company has adopted SFAS No. 131 for the year ended December 31,
1997 (See Business Segment Information beginning on page 39).
1. NATURE OF OPERATIONS
The Company is an independent energy company engaged primarily in the
exploration for and development and production of natural gas, natural gas
liquids and crude oil in several major basins in the United States and Canada.
The Company owns and operates significant assets, in proximity to its principal
producing properties, dedicated to 'gas value chain' activities, which consist
of gathering, processing, transportation and marketing of natural gas and
natural gas liquids. The Company markets a substantial portion of its own
natural gas, natural gas liquids and crude oil production together with
significant volumes of natural gas, natural gas liquids and crude oil produced
by others. The Company has a diverse customer base for its hydrocarbon products.
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.
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. SPINOFF FROM UNION PACIFIC CORPORATION
In October 1995, the Company sold 42.5 million shares of its Common Stock
in an initial public offering (the 'Offering') at an offering price of $21 per
share. Prior to consummation of the Offering, the Company was wholly owned by
UPC. Following the Offering and until October 15, 1996, UPC owned approximately
83% of the Company's outstanding Common Stock. Concurrent with the Offering, UPC
announced its intention to distribute its remaining ownership interest in the
Company to its shareholders as a dividend by means of a tax-free distribution
(the 'Distribution'). On October 15, 1996, the Distribution was consummated.
42
UNION PACIFIC RESOURCES GROUP INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
2. SPINOFF FROM UNION PACIFIC CORPORATION--(CONTINUED)
Prior to the Offering (1) UPC caused the Company to own all the rights and
assets historically employed by the natural resources business segment of UPC in
connection with the operations presented in the Consolidated Financial
Statements and (2) the Company declared dividends to UPC totaling $1,621 million
consisting of (i) a cash dividend of $912 million payable promptly after the
completion of the Offering, (ii) a $650 million note payable to UPC bearing
interest at 8.5% per annum payable within 90 days of the Distribution and (iii)
a $59 million receivable from UPC. The Company borrowed $68 million which was
used, together with the $843.9 million net proceeds from the Offering, to pay
the cash dividend of $912 million. Such transactions, referred to collectively
as the 'Asset Restructuring,' are reflected in the Consolidated Financial
Statements as of December 31, 1995 and thereafter.
As a result of the Offering and related transactions, historical results of
operations for 1995 are not directly comparable to results for the years ended
December 31, 1996 and 1997. The following pro forma information reflects
adjustments to the historical 1995 Consolidated Statement of Income necessary to
give effect to the Asset Restructuring and the Offering as if such transactions
had occurred at the beginning of 1995.
YEAR ENDED DECEMBER 31, 1995
--------------------------------------------
PRO FORMA
HISTORICAL ADJUSTMENTS PRO FORMA
---------- ----------- ---------
(MILLIONS OF DOLLARS, EXCEPT PER SHARE
AMOUNTS)
Operating income................................................... $470.1 $ (6.9) (a) $ 463.2
Other income--net.................................................. 7.0 (3.8) (b) 3.2
Interest expense................................................... (19.1) (44.6) (c) (63.7)
---------- ----------- ---------
Income before income taxes......................................... 458.0 (55.3) 402.7
Income taxes....................................................... (107.3) 20.8(d) (86.5)
---------- ----------- ---------
Net income......................................................... $350.7 $ (34.5) $ 316.2
---------- ----------- ---------
---------- ----------- ---------
Earnings per share-diluted......................................... $ 1.27
---------
---------
Weighted average shares outstanding-diluted (e).................... 249.7
---------
---------
- ------------------
(a) Adjustment to reflect management's estimate of additional
administrative and third party costs that the Company is incurring as a
result of becoming a stand-alone public company. These costs include
(1) additional administrative personnel, (2) additional third party
fees such as audit fees, actuarial fees, legal fees and stock transfer
fees, (3) additional annual stock compensation costs related to
employee retention shares (see Note 11) and (4) fees payable to UPC for
certain financial guarantees provided to the Company.
(b) Adjustment to eliminate intercompany interest income recorded by the
Company during the period, as a result of the dividend to UPC of the
$59 million intercompany receivable.
(c) Adjustment to reflect increased interest expense from the $650 million
note payable to UPC at 8.5% per annum and $68 million in bank debt at
6.1% per annum, which debt was incurred to pay a portion of the $912
million cash dividend to UPC.
(d) Adjustment to reflect decreased federal and state income tax expense
resulting from increased expenses in entries (a) through (c) above,
calculated at an assumed income tax rate of 37.5%.
(e) See 'Significant Accounting Policies--Earnings Per Share.'
In addition, reported 1996 results include approximately $2 million of
pension expense representing one quarter of approximately $8 million additional
annual pension expense associated with the October 1996 allocation of pension
assets between the Company and UPC (see Note 10).
3. RELATED PARTY TRANSACTIONS
At December 31, 1995, the Company had a $567.8 million net payable to UPC
at 8.5%, reflecting the $650 million note payable incurred in connection with
the Asset Restructuring (see Note 2), partially offset by $82.2 million in cash
advances to UPC. Such intercompany debt was repaid in part during 1996 using
cash from operations with the remainder repaid immediately following the
Distribution using proceeds from the issuance of
43
UNION PACIFIC RESOURCES GROUP INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
3. RELATED PARTY TRANSACTIONS--(CONTINUED)
long-term debt and commercial paper (see Note 8). Intercompany interest income
related to amounts receivable from UPC was $9.6 million in 1995, which is
included in other income in the Company's Consolidated Statements of Income.
Intercompany interest expense related to amounts payable to UPC after the
Offering was $32.6 million in 1996 and $14.5 million in 1995 which is included
in interest expense in the Company's Consolidated Statements of Income.
Services historically performed by UPC on behalf of the Company included
services in the areas of cash management, internal audit and tax and employee
benefits administration. Prior to the Offering, the cost of such services, which
is not significant, was not charged to the Company. As a result of the Asset
Restructuring and the Offering, UPC and the Company entered into a number of
agreements for the purpose of defining the ongoing relationship between them.
Costs incurred by the Company in 1997, 1996 and 1995 related to such agreements
were $2.9 million, $2.7 million and $0.9 million, respectively, principally
reflecting the cost of administrative services and certain financial guarantees.
In connection with the Distribution, most of these agreements with UPC have been
terminated and the terms of any ongoing agreements between the Company and UPC
have been amended as a result of arm's length negotiations. The financial impact
of any ongoing agreements is not expected to be significant.
4. SIGNIFICANT ITEMS
Columbia Gas Transmission Company. In November 1995, the Company received
a cash payment from Columbia Gas Transmission Company ('Columbia') as a part of
Columbia's emergence from Chapter 11 bankruptcy. An issue remains as to whether
the payment received is royalty bearing, other than that portion of the payment
applicable to gas actually produced and sold to Columbia, and the Company
instituted a legal proceeding to obtain a declaration of its rights and
obligations. As a result of the payment from Columbia, after taking into account
possible tax and royalty claims, the Company recorded pre-tax income of $122.5
million in the fourth quarter of 1995 ($78.5 million after tax) which is
included in other oil and gas revenues in the Company's 1995 Consolidated
Statement of Income. During 1997 and 1996, the Company reached settlements or
took default judgment with respect to a number of royalty owners named in the
suit. In 1997 and 1996, the Company recognized $18 million and $31.3 million in
other oil and gas revenues related to a reduction in its litigation and
contingencies accrual pertaining to the Columbia payment (see Note 15).
Highlands Gas Corporation. In August 1997, the Company acquired 100% of
the outstanding stock of Highlands Gas Corporation ('Highlands') for an adjusted
purchase price of approximately $179.4 million, plus the assumption of certain
liabilities. Highlands is in the business of gathering, purchasing, processing
and transporting natural gas and natural gas liquids. The acquisition included
three natural gas processing plants, five gathering systems with over 700 miles
of gas and natural gas liquids gathering pipeline and 400 miles of
transportation pipeline located in western Texas and eastern New Mexico. Results
of operations for Highlands from August through December 1997 are included in
the Consolidated Statement of Income.
5. FINANCIAL INSTRUMENTS
Hedging. The Company has established policies and procedures for managing
risk within its organization. It is balanced by internal controls and governed
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 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
44
UNION PACIFIC RESOURCES GROUP INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
5. FINANCIAL INSTRUMENTS--(CONTINUED)
risk of adverse price movements, however, these same instruments usually limit
future gains from favorable price movements. Such risk management activities are
generally accomplished pursuant to exchange-traded contracts or over-the-counter
options.
Recognition of realized gains/losses and option premium payments/receipts
are also deferred in the Consolidated Statement of Income until the underlying
physical product is sold. Unrealized gains/losses on derivative financial
instruments are not recorded. 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. The
cash flow impact of derivative and other financial instruments is reflected as
cash flows provided from operations in the Consolidated Statement of Cash Flows.
Commodity Price Risk--Trading Activities. Periodically, the Company may
enter into transactions involving a wide range of energy related derivative
financial transactions that are not the result of hedging activities. These
instruments are generally put into place based on the Company's analysis and
expectations with respect to price movement or changes in other market
variables. As of December 31, 1997 and 1996, there were no commodity trading
activity-based contracts outstanding.
Interest Rate Swaps. The Company periodically enters into rate swaps and
contracts to hedge certain interest rate transactions. As of December 31, 1997
and 1996, there were no material interest rate contracts outstanding which
materially affect the results of operation or financial condition of the
Company.
Foreign Currency Contracts. The Company periodically enters into foreign
currency contracts to hedge specific currency exposures from commercial
transactions. As of December 31, 1997 and 1996, there were no foreign currency
contracts outstanding.
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, 1997, the Company's largest credit risk associated with
any single counterparty, represented by the net fair value of open contracts
with such counterparty was less than $1 million.
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.
As a result of its hedging program, the Company's oil and gas revenues can
be higher or lower than revenues that would be reported if hedging did not
occur. During 1997 and 1996, revenues were $86 million and $52 million lower,
respectively, while during 1995, revenues were $27 million higher as a result of
hedging activities.
Fair Value of Financial Instruments. At December 31, 1997, the carrying
value of the Company's long-term debt approximates its fair market value,
estimated using current borrowing rates. The carrying value of all other
financial instruments also approximates fair market value.
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.
However, 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.
45
UNION PACIFIC RESOURCES GROUP INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
6. PROPERTIES
Major property classifications were as follows:
AS OF DECEMBER 31,
--------------------
1997 1996
-------- --------
(MILLIONS OF
DOLLARS)
Producing properties................................................................. $5,155.9 $4,311.3
Non-producing properties............................................................. 449.5 371.3
Gathering, processing and marketing.................................................. 1,240.5 1,010.7
Construction in progress............................................................. 392.6 348.8
Other................................................................................ 175.9 147.9
-------- --------
Total.............................................................................. $7,414.4 $6,190.0
-------- --------
-------- --------
Accumulated depreciation, depletion and amortization by major property
classifications were as follows:
AS OF DECEMBER 31,
--------------------
1997 1996
-------- --------
(MILLIONS OF
DOLLARS)
Producing properties................................................................. $3,090.9 $2,604.1
Non-producing properties............................................................. 123.6 142.7
Gathering, processing and marketing.................................................. 443.5 396.0
Other................................................................................ 91.0 74.8
-------- --------
Total.............................................................................. $3,749.0 $3,217.6
-------- --------
-------- --------
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
following recent downward revisions in reserve estimates. Accordingly, in the
fourth quarter of 1997 and 1996, the Company adjusted the net book value of such
properties to their fair value, determined using a discounted cash flow
approach, with charges to operations of $20.2 million and $34.4 million,
respectively.
Fixed asset additions included capitalized interest of $3.8 million in
1997, $0.2 million in 1996 and $1 million in 1995.
7. INCOME TAXES
Components of income tax expense were as follows:
FOR THE YEARS ENDED
DECEMBER 31,
--------------------------
1997 1996 1995
------ ------ ------
(MILLIONS OF DOLLARS)
Current:
Federal...................................................................... $ 8.1 $105.8 $130.2
State........................................................................ 5.6 9.0 (4.6)
------ ------ ------
Total current............................................................. 13.7 114.8 125.6
------ ------ ------
Deferred:
Federal...................................................................... 121.7 33.0 (20.8)
State........................................................................ (2.0) 4.0 2.5
------ ------ ------
Total deferred............................................................ 119.7 37.0 (18.3)
------ ------ ------
Total................................................................ $133.4 $151.8 $107.3
------ ------ ------
------ ------ ------
46
UNION PACIFIC RESOURCES GROUP INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
7. INCOME TAXES--(CONTINUED)
Deferred tax liabilities (assets) include the following:
AS OF DECEMBER
31,
-----------------
1997 1996
------ ------
(MILLIONS OF
DOLLARS)
Excess tax over book items, including depreciation and exploration costs............... $686.0 $561.0
State taxes--net....................................................................... -- 11.4
Long-term liabilities.................................................................. -- (40.7)
Alternative minimum tax................................................................ (73.2) (56.6)
Pension and other retirement benefits.................................................. (57.4) (60.0)
Other.................................................................................. (2.5) 19.6
------ ------
Net deferred tax liability................................................... $552.9 $434.7
------ ------
------ ------
A reconciliation between statutory and effective tax rates is as follows:
FOR THE YEARS ENDED DECEMBER
31,
------------------------------
1997 1996 1995
------ ------ ------
Statutory tax rate....................................................... 35.0% 35.0% 35.0%
State taxes--net......................................................... 1.3 1.8 (0.3)
Section 29 tax credits................................................... (4.3) (3.3) (8.3)
Tax settlements.......................................................... (1.5) -- (2.2)
Other.................................................................... (1.9) (1.4) (0.8)
------ ------ ------
Effective tax rate............................................. 28.6% 32.1% 23.4%
------ ------ ------
------ ------ ------
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 $18.8 million, $15.6 million and $39.9 million of Section 29 tax
credits in 1997, 1996 and 1995, respectively. The federal tax law provides for
the use of these credits against regular federal income tax liability.
Accordingly, the Company utilized $27.4 million of Section 29 tax credits on its
1996 tax return. Of the $27.4 million utilized on the 1996 tax return, $10.7
million was due to the utilization of prior year alternative minimum tax credit
carry forwards. It is anticipated that all of the 1997 tax credits will increase
the alternative minimum tax credit carry forwards and apply against future tax
years' regular tax liability.
During 1997, the Company recognized a $6 million favorable adjustment to
state income taxes representing the settlement of a California state audit. The
Company also had favorable tax adjustments of $3.3 million resulting from a tax
allocation refund from UPC to settle 1996 federal income taxes and $2.7 million
relating to prior year federal tax returns.
All tax years prior to 1979 have been closed with the Internal Revenue
Service ('IRS'). On behalf of the Company, UPC has reached a partial settlement
with the Appeals Office of the IRS for 1980 through 1985; the remaining issues
will be resolved as part of refund claims filed for those years. Additionally,
UPC is negotiating with the 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.
47
UNION PACIFIC RESOURCES GROUP INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
8. DEBT
The total debt of the Company is summarized below:
AS OF DECEMBER 31,
------------------
1997 1996
-------- ------
(MILLIONS OF
DOLLARS)
Commercial paper, net of discount, average of 6% at
December 31, 1997.................................................................... $ 663.1 $ 99.6
Notes, 7%, due 2006.................................................................... 200.0 200.0
Debentures, 7.5%, due 2026............................................................. 200.0 200.0
Debentures, 7.5%, due 2096............................................................. 150.0 150.0
Tax exempt revenue bonds, 4.25%, due 2012.............................................. 20.1 24.0
Discount on notes and debentures....................................................... (2.6) (2.7)
-------- ------
Total debt........................................................................ 1,230.6 670.9
Less current portion.............................................................. -- --
-------- ------
Total long-term debt......................................................... $1,230.6 $670.9
-------- ------
-------- ------
Excluding commercial paper, the Company has no debt maturing in the next
five years. Outstanding commercial paper has been classified as long-term debt
reflecting the Company's intent to maintain these short-term borrowings on a
long-term basis either through the issuance of commercial paper and through new
term financings.
The Company has a $600 million revolving credit agreement that expires in
August 2001 and a $300 million revolving credit agreement which expires in
November 1998. Borrowings under these agreements, at the Company's election,
bear interest either at a spread over London Interbank Offered Rate ('LIBOR') or
at a spread over domestic certificate of deposit rates, in each case depending
on the Company's senior debt rating. The Company is required to pay facility
fees on the aggregate amount of the commitment ranging from 0.06% to 0.15% also
depending on the Company's senior debt rating. Under these agreements debt can
not exceed 65% of the total of the Company's debt and shareholders' equity and
requires the combined EBITDAX (the sum of operating income, depreciation,
depletion and amortization, and exploration expenses) of the Company's Principal
Subsidiaries (as defined in these agreements) to be at least 80% of the
Company's consolidated EBITDAX. These agreements also impose certain
restrictions on the Company regarding the creation of liens, incurrence of
indebtedness, transactions with affiliates, sales of the stock of UPRC and
certain mergers, consolidations and asset sales. As of December 31, 1997, there
were no borrowings outstanding under these agreements, although borrowing
capacity is reduced by outstanding commercial paper. The Company had the
capacity to borrow $900 million, less commercial paper outstanding, under these
agreements as of December 31, 1997. In addition, the Company could borrow funds
under the credit agreements.
None of the Company's Notes and Debentures are redeemable prior to maturity
and none are subject to any sinking fund requirements. The Company has an
effective shelf registration statement on file with the SEC which permits the
Company to offer up to $900 million in debt and equity securities.
In March 1998, the Company borrowed $2.7 billion to purchase the capital
stock of Norcen Energy Resources Limited ('Norcen') and guaranteed the $900
million outstanding public debt held by Norcen (see Note 18 for additional
information about the transactions).
48
UNION PACIFIC RESOURCES GROUP INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
9. LEASES
The Company leases its headquarters office building, certain production
platforms and other property. Future minimum lease payments for operating leases
with initial lease terms which are not subject to being cancelled in excess of
one year were as follows:
AS OF DECEMBER 31, 1997
-----------------------
(MILLIONS OF DOLLARS)
1998................................................................................. $ 59.0
1999................................................................................. 47.5
2000................................................................................. 38.5
2001................................................................................. 31.5
2002................................................................................. 29.5
Later years.......................................................................... 16.4
-------
Total minimum payments.......................................................... $ 222.4
-------
-------
Rent expense, net of sublease income, for operating leases with terms
exceeding one month was $22.4 million in 1997, $27.2 million in 1996 and $31
million in 1995. Sublease income for the next five years is $28.5 million in
1998, $28.4 million in 1999, $28.1 million in 2000, $28.1 million in 2001, $28.1
million in 2002 and $14.7 million thereafter.
10. RETIREMENT PLANS
The Company provides pension, health care and life insurance benefits to
all eligible retirees.
Pension Benefits. Pension plan benefits are based on years of service and
compensation during the last years of an employee's employment. Contributions to
the plans are calculated based on the projected unit credit actuarial funding
method and are not less than the minimum funding standards set forth in the
Employee Retirement Income Security Act of 1974, as amended. The following
pension credits and funded status are based on historical actuarial valuations.
Pension cost includes the following components:
FOR THE YEARS ENDED
DECEMBER 31,
--------------------------
1997 1996 1995
------ ------ ------
(MILLIONS OF DOLLARS)
Service cost--benefits earned during the period.................................. $ 5.5 $ 4.4 $ 5.3
Interest on projected benefit obligation......................................... 13.4 13.3 14.4
Return on assets:
Actual (gain) loss............................................................. (30.8) (41.7) (49.5)
Deferred gain (loss)........................................................... 13.7 22.1 30.0
Net amortization costs........................................................... (5.7) (3.7) (2.4)
------ ------ ------
Net pension credit............................................................... $ (3.9) $ (5.6) $ (2.2)
------ ------ ------
------ ------ ------
The projected benefit obligation was determined using a discount rate of
7.25% in 1997 and 7.5% in 1996. The estimated rate of salary increase
approximated 5.25% in 1997 and 5.5% in 1996. The expected long-term rate of
return on plan assets was 9% in 1997 and 8% in 1996. The portion of the funded
plan's assets held in fixed-income and short-term securities was approximately
34% and 29% as of December 31, 1997 and 1996, respectively, with the remainder
primarily in equity securities.
49
UNION PACIFIC RESOURCES GROUP INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
10. RETIREMENT PLANS--(CONTINUED)
The funded status of the plans was as follows:
AS OF DECEMBER 31, 1997
------------------------------------
UNFUNDED
FUNDED SUPPLEMENTAL
PENSION PLAN PENSION PLAN
------------------ --------------
1997 1996 1997 1996
------- ------- ----- -----
(MILLIONS OF DOLLARS)
Plan assets at fair value.............................................. $ 240.9 $ 221.3 $ -- $ --
Actuarial present value of benefit obligations:
Vested benefits...................................................... 165.0 152.9 6.1 4.5
Non-vested benefits.................................................. 7.0 6.4 0.4 0.2
------- ------- ----- -----
Accumulated benefit obligation......................................... 172.0 159.3 6.5 4.7
Additional benefits based on estimated future salaries............... 22.8 17.4 1.3 2.5
------- ------- ----- -----
Projected benefit obligation........................................... 194.8 176.7 7.8 7.2
------- ------- ----- -----
Plan assets (over) under projected benefit obligation.................. (46.1) (44.6) 7.8 7.2
Unamortized net transition asset (obligation).......................... 18.4 21.0 (0.5) (1.1)
Unrecognized prior service cost........................................ (4.5) (5.2) (3.3) (3.8)
Unrecognized net gain (loss)........................................... 102.3 105.0 (2.3) (2.2)
Minimum liability...................................................... -- -- 4.8 4.6
------- ------- ----- -----
Pension liability................................................. $ 70.1 $ 76.2 $ 6.5 $ 4.7
------- ------- ----- -----
------- ------- ----- -----
The Company is in the process of conducting a voluntary compliance review
of its pension plan. The results of the review are not expected to have a
material impact on the funded status of the plans.
Other Postretirement Benefits. Postretirement health and life insurance
benefit costs included the following components:
FOR THE YEARS ENDED
DECEMBER 31,
-----------------------
1997 1996 1995
----- ----- -----
(MILLIONS OF DOLLARS)
Service cost--benefits earned during the period...................................... $ 0.8 $ 1.0 $ 1.2
Interest costs on accumulated benefit obligation..................................... 3.3 3.4 4.3
Net amortization costs............................................................... (2.4) (2.3) (1.5)
----- ----- -----
Charge to operations............................................................ $ 1.7 $ 2.1 $ 4.0
----- ----- -----
----- ----- -----
The liability for other postretirement benefit plans was as follows:
FOR THE YEARS ENDED
DECEMBER 31,
-------------------------
1997 1996
---------- ----------
(MILLIONS OF DOLLARS)
Accumulated postretirement benefit
obligation ('APBO'):
Retirees......................... $30.8 $35.5
Fully eligible active
employees....................... 2.3 1.9
Other active employees........... 9.8 7.7
------ ------
Total APBO.................... 42.9 45.1
Unrecognized prior service gain.... 3.4 4.4
Unrecognized net gain.............. 27.0 25.1
------ ------
Postretirement benefits
liability.................... $73.3 $74.6
------ ------
------ ------
50
UNION PACIFIC RESOURCES GROUP INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
10. RETIREMENT PLANS--(CONTINUED)
The APBO was determined using a discount rate of 7.25% in 1997 and 7.5% in
1996. The health care cost trend rate is assumed to gradually decrease from 8.5%
for 1997 to 5% for 2005 and all future years. If the assumed health care cost
trend rate increases by one percentage point in each subsequent year, the
aggregate of the service and interest cost components of annual postretirement
benefit expense would increase by $0.4 million and the APBO would rise by $3.6
million. The Company does not currently pre-fund health care and life insurance
benefit costs. Cash payments for these benefits were $3 million in 1997 and $3.6
million in 1996.
11. SHAREHOLDERS' EQUITY
Stock Option and Retention Stock Plans. Pursuant to the Company's stock
option and retention stock plans, 8,785,684 and 9,215,933 shares of Common Stock
were available as either options to purchase Common Stock or as awards of
retention stock at December 31, 1997 and 1996, respectively, for grant to
employees and directors. Options to purchase Common Stock under the plans are
granted at 100% of fair market value at the date of grant, become exercisable no
earlier than one year after grant and are exercisable for a period of up to
eleven years from grant date. Option grants have been made to directors,
officers and employees and vest over a period up to ten years from the grant
date.
Retention stock is awarded under the plan to eligible employees, subject to
forfeiture if employment terminates during the prescribed restriction period,
generally one to five years from date of grant. Multi-year retention stock
awards also have been made, with vesting two to five years from date of grant.
Multi-year grants of stock options and retention stock made in 1994 also
required that designated Company stock prices be met to be exercisable. These
performance conditions were achieved during 1995 for the stock options and
during 1996 for the retention stock.
Upon completion of the Offering and Distribution, 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 stock options, ISOs and retention stock of the Company,
respectively. The converted options and retention stock retain the same exercise
dates and vesting requirements as the UPC options and retention stock for which
they were exchanged.
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, 1994.................................................... -- $ --
Conversion of UPC stock options............................................... 3,702,443 15.87
Granted....................................................................... 88,695 25.88
Exercised..................................................................... (1,500) 15.18
----------
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
----------
----------
Exercisable December 31:
1995.......................................................................... 2,235,470 $16.26
1996.......................................................................... 3,035,905 16.81
1997.......................................................................... 3,853,035 18.72
51
UNION PACIFIC RESOURCES GROUP INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
11. SHAREHOLDERS' EQUITY--(CONTINUED)
REGULAR PERFORMANCE
---------- ------------
Retention stock:................................................................
1995
Awarded.................................................................... 33,585 14,143
Conversion of UPC retention stock.......................................... 389,880 310,653
---------- ------------
Unvested at December 31, 1995.............................................. 423,465 324,796
1996
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 --
1997
Awarded.................................................................... 209,114 --
Vested..................................................................... (376,295) --
Forfeited, surrendered and other........................................... (34,693) --
---------- ------------
Unvested at December 31, 1997.............................................. 1,002,688 --
---------- ------------
---------- ------------
Weighted-average grant-date fair value of stock options granted and retention
stock awarded:
RETENTION
OPTIONS(B) SHARES(C)
---------- ---------
1995................................................................................ $ 8.31 $ 25.88
1996................................................................................ 9.15 27.81
1997................................................................................ 8.74 25.63
- ------------------
(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:
1997 1996 1995
------- ------- -------
Expected volatility............................................................. 28% 26% 28%
Expected dividend yield......................................................... 0.8% 0.7% 0.8%
Expected option term............................................................ 4 years 5 years 5 years
Risk-free rate of return........................................................ 5.7% 6.3% 5.5%
(c) Represents market value on grant date.
Options to purchase Common Stock outstanding were as follows:
AS OF DECEMBER 31, 1997
-----------------------------------------------------------------------
OPTIONS OUTSTANDING OPTIONS EXERCISABLE
----------------------------------------- ------------------------
WEIGHTED WEIGHTED WEIGHTED
AVERAGE AVERAGE AVERAGE
RANGE OF NUMBER YEARS TO EXERCISE NUMBER EXERCISE
EXERCISE PRICES OF SHARES EXPIRATION PRICE OF SHARES PRICE
- --------------- --------- ---------- ---------- --------- ---------
$ 9.49-$15.29 1,913,601 5.89 $14.75 1,913,601 $ 14.60
$17.14-$20.94 1,242,963 5.59 19.01 1,242,963 19.06
$23.78-$29.44 2,727,922 8.34 26.73 696,471 27.06
--------- ---------
$ 9.49-$29.44 5,884,486 6.96 21.20 3,853,035 18.72
--------- ---------
--------- ---------
52
UNION PACIFIC RESOURCES GROUP INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
11. SHAREHOLDERS' EQUITY--(CONTINUED)
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. Compensation cost recognized relating to
retention stock was $11.6 million, $7.4 million and $0.7 million in 1997, 1996
and 1995, 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 $8
million in 1997, $3 million in 1996 and $3.4 million in 1995, essentially all of
which relates to option conversion at the Offering. Basic and diluted EPS would
have been reduced by $0.03 per share in 1997 and $0.01 per share both in 1996
and 1995.
Earnings Per Share. The reconciliation between basic EPS and diluted EPS
for the years ended December 31, 1997 and 1996 is as follows:
FOR THE YEARS ENDED DECEMBER 31,
-----------------------------------------------
AVERAGE PER
INCOME SHARES SHARE
--------------------- ---------- -----
(MILLIONS OF DOLLARS) (MILLIONS)
1997
Basic EPS
Income available to common shareholders....................... $ 333.0 250.1 $1.33
Effect of Dilutive Options...................................... -- 0.8 --
------- ---------- -----
Diluted EPS
Income available to common shareholders plus assumed
conversion................................................. $ 333.0 250.9 $1.33
------- ---------- -----
------- ---------- -----
1996
Basic EPS
Income available to common shareholders....................... $ 320.8 249.2 $1.29
Effect of Dilutive Options...................................... -- 0.9 (0.01)
------- ---------- -----
Diluted EPS
Income available to common shareholders plus assumed
conversion................................................. $ 320.8 250.1 $1.28
------- ---------- -----
------- ---------- -----
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 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 $8.6 million annually, and will be funded with
dividends paid on the unallocated 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 EPS as such
ESOP Shares are released from collateral. Such 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.
53
UNION PACIFIC RESOURCES GROUP INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
11. SHAREHOLDERS' EQUITY--(CONTINUED)
As of December 31, 1997, allocated and unallocated shares in the ESOP are
197,395 and 3,502,605, respectively. The fair value of unallocated ESOP shares
is $85.8 million at December 31, 1997. During 1997, compensation cost related to
the allocation of ESOP shares to participants' accounts was $5.3 million.
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% 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% 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% 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,
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 1997, the Company announced a program to repurchase up to $50 million of
its Common Stock in 1997 and another $50 million of Common Stock in 1998. During
1997, 2,013,400 shares of Common Stock were repurchased at a cost of $49.9
million.
12. INTANGIBLE AND OTHER ASSETS
Goodwill. Goodwill consists 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. During 1997,
goodwill of $90.7 million was recorded as a result of the purchase of Highlands
and is being amortized on a straight-line basis over a 20 year period.
Amortization of goodwill was $2 million for 1997.
54
UNION PACIFIC RESOURCES GROUP INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
12. INTANGIBLE AND OTHER ASSETS--(CONTINUED)
Investment in Unconsolidated Affiliate. The Company has a 50% 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:
AS OF AND FOR THE
YEARS ENDED
DECEMBER 31,
------------------
1997 1996
------ ------
(MILLIONS OF
DOLLARS)
Current assets........................................................................ $ 27.5 $ 39.8
Non-current assets.................................................................... 37.9 46.4
Current liabilities................................................................... 17.1 20.2
Non-current liabilities and equity (see Note 13)...................................... 48.3 66.0
Sales................................................................................. 159.7 192.4
Operating income...................................................................... 112.4 137.0
Partners' income...................................................................... 113.6 137.0
During 1997, Black Butte's sales to its largest customer under an amended
coal supply contract accounted for $59.3 million, or 12%, 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 the
financially beneficial 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 supply. 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, 1997 and 1996 were $50.4 million and $54.3 million, of
which the Company's share is $25.2 million and $27.2 million, respectively. The
majority of cash expenditures for reclamation are expected to be incurred from
five to ten years in the future.
A supplier of coal to Black Butte has been assessed by the Minerals
Management Service of the United States Department of the Interior and the State
of Montana Department of Revenue for underpayment of royalties and production
taxes related to coal previously sold to Black Butte. The supplier is contesting
these claims; however, should the claims be successful, the supplier may make a
claim for reimbursement from Black Butte. Although the management of Black Butte
will vigorously contest these claims, the liability associated with the
underpaid royalty and production taxes, if any, could range from zero to $36
million, of which the Company would recognize its proportionate share, which
could range from zero to $18 million.
13. ENVIRONMENTAL EXPOSURE
The Company generates and disposes of hazardous and nonhazardous waste in
its current and former operations and is subject to increasingly stringent
federal, state and local 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.
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
55
UNION PACIFIC RESOURCES GROUP INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
13. ENVIRONMENTAL EXPOSURE--(CONTINUED)
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 million for future site
preparation costs was established ($91.5 million in total remaining at December
31, 1997) and is categorized as other current liabilites and long-term
liabilities (see Note 15). The majority of cash outlays for these liabilities is
expected to occur over the next five years.
As of December 31, 1997 and 1996, long and short-term liabilities totaling
$75.7 million and $94.3 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 as
much as 10% 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 $37.8
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 liability. 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 also is involved in reducing emissions, spills and migration of
hazardous materials. Remediation of identified sites and control of
environmental exposures required spending of $14.7 million in 1997 and $11.4
million in 1996. In 1998, the Company anticipates spending a total of $20
million for remediation, control and prevention, including $9 million relating
to the Wilmington properties. The majority of the December 31, 1997 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
UP Fuels is a party to a long-term firm transportation agreement with Kern
River Gas Transmission Company ('Kern River') that expires in 2007. Under the
transportation agreement, UP Fuels 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. Ten years remain on the primary term of the agreement, and
the current transportation rate is $0.69 Mcf. This rate will be in effect
through at least mid-1998. 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, UP Fuels is
obligated to pay all of the fixed costs included in the transportation rate,
whether or not UP Fuels actually uses Kern River's pipeline to transport gas.
Those fixed costs presently amount to $0.6878 per Mcf. The undiscounted amount
of the ten-year fixed cost commitment, assuming no future changes in the rate,
is $177 million. The 1993 FERC ruling was issued notwithstanding a provision in
the transportation agreement between Kern River and UP Fuels in which the
parties agreed that a portion of the fixed costs would be paid by UP Fuels only
if and to the extent that UP Fuels uses the pipeline. In light of recent changes
in the regulatory policies of FERC, UP Fuels is seeking reinstatement of the
contractually agreed rate structure, but there is no assurance that such efforts
will be successful. UP Fuels 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 Pipeline system beginning in 2002.
56
UNION PACIFIC RESOURCES GROUP INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
14. COMMITMENTS AND CONTINGENCIES--(CONTINUED)
UP Fuels is a party to a long-term firm transportation agreement with Texas
Gas Transmission Corporation that expires in 2008. Under the transportation
agreement UP Fuels has the rights to transport 90 MMbtu per day of gas from the
Company's East Texas plant. UP Fuels is obligated to pay a fixed transportation
rate of $0.331 per MMbtu regardless of the volumes transported under the
agreement. The undiscounted amount of this commitment is $116 million.
The Company has entered into a letter of intent to enter into a $150
million five year agreement with Noble Drilling (U.S.) Inc. beginning in July
1999, for the services of a semisubmersible drilling rig designed for operations
in water depths up to 5,000 feet. Under this agreement, the Company will share
50% of the total rig commitment with another major oil and gas company.
In the last ten years, the Company has disposed of significant pipeline,
refining and producing property assets, including the sale of its 37.5% 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 (half sold in March 1987 and the balance in January
1989), and Wilmington field (March 1994). 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 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 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,
------------------
1997 1996
------ ------
(MILLIONS OF
DOLLARS)
Environmental (Notes 4 and 13)......................................................... $ 58.5 $ 74.5
Wilmington field site preparation (Note 14)............................................ 53.7 53.7
Litigation and contingencies (Notes 4 and 14).......................................... 28.5 73.8
Offshore platform lease accrual........................................................ 3.6 14.3
Other.................................................................................. 78.3 48.5
------ ------
Total other long-term liabilities.................................................... $222.6 $264.8
------ ------
------ ------
57
UNION PACIFIC RESOURCES GROUP INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)
16. OTHER INCOME--NET
Other income (expense)--net consists of the following:
FOR THE YEARS ENDED
--------------------------
1997 1996 1995
------ ------ ------
(MILLIONS OF DOLLARS)
Excess reserve reductions........................................................ $ 23.0 $ 1.8 $ 3.2
Insurance settlement proceeds.................................................... 10.0 -- --
Gain on sales of assets.......................................................... 7.2 4.5 2.2
Pennzoil acquisition costs....................................................... (17.8) -- --
Spinoff charges.................................................................. -- (5.6) --
Intercompany interest (Note 2)................................................... -- -- 9.6
Other--net....................................................................... 1.9 (4.1) (8.0)
------ ------ ------
Total other income--net........................................................ $ 24.3 $ (3.4) $ 7.0
------ ------ ------
------ ------ ------
17. CAPITAL AND EXPLORATORY EXPENDITURES
Capital and exploratory expenditures include the following:
FOR THE YEARS ENDED
----------------------------
1997 1996 1995
-------- ------ ------
(MILLIONS OF DOLLARS)
Capital expenditures:
Producing properties........................................................ $ 752.4 $515.2 $482.7
Non-producing properties.................................................... 200.7 149.8 35.0
Exploratory drilling........................................................ 121.7 36.1 24.2
Gathering, processing and marketing......................................... 364.2 118.1 106.5
Other....................................................................... 15.8 9.5 2.0
-------- ------ ------
Total capital expenditures............................................... 1,454.8 828.7 650.4
Exploratory expenditures:
Expensed geological and geophysical costs................................... 35.2 19.0 22.4
Expensed dry hole costs..................................................... 41.7 32.6 13.6
-------- ------ ------
Total exploratory expenditures........................................... 76.9 51.6 36.0
-------- ------ ------
Total capital and exploratory expenditures............................. $1,531.7 $880.3 $686.4
-------- ------ ------
-------- ------ ------
18. SUBSEQUENT EVENTS (UNAUDITED)
Norcen Acquisition. In March 1998, the Company purchased the capital stock
of Norcen for approximately $2.6 billion. As a result of the Norcen acquisition,
the Company will increase its debt by $3.6 billion, including $2.7 billion
acquisition debt and approximately $900 million of existing commercial paper and
debentures of Norcen. The $2.7 billion acquisition debt entered into by the
Company includes a mandatory prepayment program and a series of 'prepayment
events'. The mandatory prepayment provision requires that $1.35 billion be
repaid prior to March, 1999. In addition, 75% of the net proceeds applicable to
any prepayment events should be applied to reduce the indebtedness under the
acquisition facility. Prepayment events include sales of assets in excess of $10
million and debt and equity issuances. This increased debt is expected to raise
the Company's debt to total capitalization ratio from 41% at December 31, 1997
to approximately 72% as of March 1998. The Company plans to pursue an aggressive
deleveraging program, which may include asset and financial divestitures and the
issuance of equity securities.
58
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.
Ryder Scott Company Petroleum Engineers reviewed the reserves as of December 31,
1997 and indicated in their letter dated February 27, 1998, that the estimated
quantities of proved oil and gas reserves were reasonable in the aggregate (see
Exhibit 99).
AS OF DECEMBER 31,
-----------------------------------
1997 1996 1995
-------- -------- --------
Natural gas (Bcf): 1
Beginning of year..................... 2,378.4 2,173.5 2,126.0
Revisions of previous estimates....... 9.3 45.7 (122.3)
Extensions, discoveries and other
additions.......................... 588.3 481.3 518.0
Purchases of reserves-in-place........ 54.8 52.0 26.7
Sales of reserves-in-place............ (3.5) (5.5) (32.0)
Production............................ (407.0) (368.6) (342.9)
-------- -------- --------
Total proved, end of year.......... 2,620.3 2,378.4 2,173.5
-------- -------- --------
-------- -------- --------
Proved developed reserves........ 2,217.0 2,125.4 1,957.1
-------- -------- --------
-------- -------- --------
Natural gas liquids (MMBbl): 1
Beginning of year..................... 107.5 100.1 83.8
Revisions of previous estimates....... 1.9 12.0 9.9
Extensions, discoveries and other
additions.......................... 21.6 9.1 18.2
Purchases of reserves-in-place........ 0.9 0.2 0.2
Sales of reserves-in-place............ -- (0.4) (1.0)
Production............................ (14.0) (13.5) (11.0)
-------- -------- --------
Total proved, end of year.......... 117.9 107.5 100.1
-------- -------- --------
-------- -------- --------
Proved developed reserves........ 103.3 97.7 89.8
-------- -------- --------
-------- -------- --------
Crude oil, including condensate (MMBbl):
Beginning of year..................... 80.6 83.8 70.9
Revisions of previous estimates....... 5.1 (0.6) 14.1
Extensions, discoveries and other
additions.......................... 56.7 14.3 19.1
Purchases of reserves-in-place........ 5.8 3.6 1.9
Sales of reserves-in-place............ (0.1) (2.0) (2.9)
Production............................ (19.3) (18.5) (19.3)
-------- -------- --------
Total proved, end of year.......... 128.8 80.6 83.8
-------- -------- --------
-------- -------- --------
Proved developed reserves........ 93.9 74.1 78.2
-------- -------- --------
-------- -------- --------
Proved reserves equivalent, end of year
(Bcfe): 2
Natural gas........................... 2,620.3 2,378.4 2,173.5
Natural gas liquids................... 707.4 645.0 600.6
Crude oil, including condensate....... 772.8 483.6 502.8
-------- -------- --------
Total proved....................... 4,100.5 3,507.0 3,276.9
-------- -------- --------
-------- -------- --------
Proved developed reserves........ 3,400.2 3,155.8 2,965.1
-------- -------- --------
-------- -------- --------
-----------------------------
1 Includes 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).
2 Calculated using the ratio of one Bbl to six Mcf.
59
B. DRILLING ACTIVITY 1
Drilling activity is summarized as follows:
FOR THE YEARS ENDED DECEMBER 31,
----------------------------------
1997 1996 1995
---------- ---------- ----------
Gross wells........................ 817 655 725
Gross productive wells............. 720 591 685
Net wells:
Exploration...................... 41 27 14
Development...................... 525 439 513
---------- ---------- ----------
Total net wells............... 566 466 527
---------- ---------- ----------
---------- ---------- ----------
Net productive wells:
Exploration...................... 19 9 3
Development...................... 479 413 506
---------- ---------- ----------
Total net productive wells.... 498 422 509
---------- ---------- ----------
---------- ---------- ----------
-----------------------------
1 In addition, at December 31, 1997, 138 gross wells (101 net wells) were
in the process of being drilled.
C. AVERAGE SALES PRICE AND COST
The average sales prices and costs are set forth below:
AS OF YEARS ENDED DECEMBER 31,
----------------------------------
1997 1996 1995
---------- ---------- ----------
Producing properties:
Natural gas sales price (per
Mcf).......................... $ 2.00 $ 1.86 $ 1.42
Natural gas liquids sales price
(per Bbl)..................... 11.20 11.39 8.14
Crude oil sales price (per
Bbl).......................... 18.36 18.84 16.08
Production cost (per Mcfe)....... 0.50 0.49 0.42
Gas plants:
Natural gas sales price (per
Mcf).......................... 2.40 2.01 1.51
Natural gas liquids sales price
(per Bbl)..................... 11.91 13.16 9.38
D. AVERAGE DAILY PRODUCTION AND SALES VOLUME
The average daily production and sales volumes of the Company are set forth
below:
AS OF YEARS ENDED DECEMBER 31,
----------------------------------
1997 1996 1995
---------- ---------- ----------
Producing properties:
Natural gas (MMcfd).............. 1,102.3 980.3 915.6
Natural gas liquids (MBbld)...... 29.9 28.5 23.1
Crude oil (MBbld)................ 52.9 50.6 52.8
Total producing properties
(MMcfed)...................... 1,598.8 1,454.9 1,371.0
Plant share of equity gas
processed:
Natural gas (MMcfd).............. 12.9 26.7 23.9
Natural gas liquids (MBbld)...... 8.5 8.4 7.1
Total plant share of equity gas
(MMcfed)...................... 63.9 77.1 66.5
Total production reflected in
estimates of proved
reserves (MMcfed)........... 1,662.7 1,532.0 1,437.5
Plant share of third party gas
processed (MBbld)..................... 33.2 31.4 27.1
Total sales (MMcfed).......... 1,879.3 1,720.2 1,600.1
Plant share of natural gas liquids
sales (MBbld):
Equity gas processed............. 8.5 8.4 7.1
Third party gas processed........ 33.2 31.4 27.1
---------- ---------- ----------
Total......................... 41.7 39.8 34.2
---------- ---------- ----------
---------- ---------- ----------
60
E. ACREAGE AND WELLS
Oil and gas leasehold acreage is as follows: 1
AS OF DECEMBER 31,
----------------------
1997 1996
---------- ----------
(THOUSANDS OF ACRES)
Gross developed................................ 2,317 2,018
Net developed.................................. 1,569 1,179
Gross undeveloped.............................. 4,076 4,272
Net undeveloped................................ 2,909 2,935
Productive oil and gas wells are as follows:
AS OF DECEMBER 31,
----------------------
OIL GAS
---------- ----------
(WELLS)
Gross 2........................................ 2,763 6,043
Net............................................ 1,636 3,574
-----------------------------
1 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.
2 Approximately 611 wells are multiple completions, 576 of which are gas
wells.
F. CAPITALIZED EXPLORATION AND PRODUCTION COSTS
Capitalized exploration and production costs are as follows: 1
AS OF DECEMBER 31,
----------------------------------
1997 1996
---------- ------------
(MILLIONS OF DOLLARS)
Proved properties.............................. $ 993.0 $ 889.5
Unproved properties............................ 449.5 280.9
Wells and related equipment.................... 4,285.5 3,512.2
Uncompleted wells and equipment................ 182.3 291.6
---------- ----------
Gross capitalized costs................... 5,910.3 4,974.2
Accumulated depreciation, depletion and
amortization...................................... (3,214.6 ) (2,746.8)
---------- ----------
Net capitalized costs..................... $ 2,695.7 $ 2,227.4
---------- ----------
---------- ----------
-----------------------------
1 Excludes gathering, processing and marketing assets.
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:
FOR THE YEARS ENDED DECEMBER 31,
----------------------------------
1997 1996 1995
---------- ---------- ----------
(MILLIONS OF DOLLARS)
Costs incurred:
Proved acreage................... $ 130.6 $ 85.7 $ 100.5
Unproved acreage................. 200.7 149.8 35.0
Exploration costs 1.............. 236.9 114.6 80.9
Development costs................ 621.8 429.5 382.2
---------- ---------- ----------
Total costs incurred 2........ $ 1,190.0 $ 779.6 $ 598.6
---------- ---------- ----------
---------- ---------- ----------
-----------------------------
1 Includes allocated exploration overhead costs of $23.5 million in 1997,
$22.5 million in 1996 and $17.1 million in 1995, and delay rentals of
$14.8 million in 1997, $4.4 million in 1996 and $3.6 million in 1995.
2 Excludes capital expenditures relating to gathering, processing and
marketing of $364.2 million in 1997, $118.1 million in 1996 and $106.5
million in 1995.
61
H. RESULTS OF OPERATIONS FOR PRODUCING ACTIVITIES 1
The results of operations for producing activities is set forth below:
FOR THE YEARS ENDED DECEMBER 31,
-----------------------------------
1997 1996 1995
--------- --------- ---------
(MILLIONS OF DOLLARS)
Revenues........................... $ 1,334.7 $ 1,198.3 $ 1,027.7
Production costs................... (292.6) (259.5) (217.8)
Exploration expenses............... (204.7) (144.6) (89.4)
Depreciation, depletion and
amortization.......................... (493.0) (465.5) (403.1)
--------- --------- ---------
Total costs................... (990.3) (869.6) (710.3)
--------- --------- ---------
Pre-tax results.................... 344.4 328.7 317.4
Income taxes....................... (97.7) (94.9) (70.4)
--------- --------- ---------
Results of operations......... $ 246.7 $ 233.8 $ 247.0
--------- --------- ---------
--------- --------- ---------
-----------------------------
1 Gathering, processing and marketing and minerals results, general and
administrative expenses and interest costs have been excluded in
computing these results of operations. Revenues include net gains from
sales of assets of $18.3 million in 1997, $3.9 million in 1996 and $14.2
million in 1995, and the $122.5 million Columbia bankruptcy settlement in
1995.
I. STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED
OIL AND GAS RESERVES
The standardized measure of discounted future net cash flows relating to
proved oil and gas reserves are set forth below:
AS OF DECEMBER 31,
-----------------------------------
1997 1996 1995
--------- --------- ---------
(MILLIONS OF DOLLARS)
Future cash inflows from sales of
oil and gas........................... $ 9,191.9 $11,945.7 $ 5,809.2
Future production and development
costs................................. (2,091.1) (2,013.1) (1,747.8)
Future income taxes................ (2,042.8) (3,031.7) (1,114.6)
--------- --------- ---------
Future net cash flows.............. 5,058.0 6,900.9 2,946.8
10% annual discount................ (2,011.8) (2,661.9) (1,075.5)
--------- --------- ---------
Standardized measure of
discounted future net cash
flows......................... $ 3,046.2 $ 4,239.0 $ 1,871.3
--------- --------- ---------
--------- --------- ---------
An analysis of changes in the standardized measure of discounted future net
cash flows follows:
AS OF DECEMBER 31,
-----------------------------------
1997 1996 1995
--------- --------- ---------
(MILLIONS OF DOLLARS)
Beginning of year.................. $ 4,239.0 $ 1,871.3 $ 1,658.7
Changes due to current year
operations:
Additions and discoveries less
related production and other
costs......................... 1,000.4 1,135.5 549.7
Sales of oil and gas--net of
production costs.............. (1,078.1) (961.0) (716.1)
Development costs................ 621.8 429.5 382.2
Purchases of reserves-in-place... 125.4 181.1 48.8
Sales of reserves-in-place....... (3.8) (48.0) (49.5)
Changes due to revisions in:
Price............................ (2,451.9) 2,763.1 334.0
Development costs................ (427.4) (268.6) (293.6)
Quantity estimates............... 86.9 27.9 68.1
Income taxes..................... 638.9 (1,062.9) (271.5)
Other............................ (288.7) (69.6) (31.8)
Discount accretion................. 583.7 240.7 192.3
--------- --------- ---------
End of year...................... $ 3,046.2 $ 4,239.0 $ 1,871.3
--------- --------- ---------
--------- --------- ---------
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 1997, 1996 and
1995 were $2.24 Mcfe, $3.41 Mcfe and $1.77 Mcfe,
62
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%, 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.
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)
1997
Operating revenues................. $531.7(a) $444.6 $ 449.0 $ 499.4
Operating income................... 186.4(a) 115.0 94.5 99.3
Net income--basic and diluted...... 117.2(a) 74.4 67.2 74.2
Per share:
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
1996
Operating revenues................. $389.7 $427.9 $ 447.1 $ 566.3 (a)
Operating income................... 97.3 120.1 127.3 181.9 (a)
Net income......................... 59.2 70.4 76.9 114.3 (a)
Per share:
Net income--basic and diluted.... $ 0.24 $ 0.28 $ 0.31 $ 0.46
Dividends........................ 0.05 0.05 0.05 0.05
Common stock price:
High............................. $26 5/8 $ 28 $ 29 $ 31 5/8
Low.............................. 24 1/8 24 1/4 25 3/8 25 3/4
-----------------------
(a) First quarter 1997 and fourth quarter 1996 results reflect the impact
of increases in hydrocarbon prices (see 'Management's Discussion and
Analysis of Financial Condition and Results of Operations'). In
addition, during the fourth quarter of 1996, operating revenues reflect
the reduction of reserves by $31.3 million related to Columbia
bankruptcy settlement (see Note 4) and operating expenses were impacted
by $43.5 million related to the write-down 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 accountants, 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 either of the two
most recent fiscal years did not contain an adverse opinion or disclaimer of
opinion and was not qualified or modified as to uncertainty, audit scope or
accounting principle. During such years and during the period between December
31, 1996 and 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 auditing 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.
63
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 section 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.
(c) Section 16(a) Compliance.
Information concerning compliance with Section 16 (a) of the Securities
Exchange Act of 1934 is set forth in the Reports of Ownership--Section 16(a)
Reporting Compliance section 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 16, 1998, 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 Executive 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.
64
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 on page 32.
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.
(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
- ------ -------------------------------------------------------------------------------------------------
1.2 -- 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 to Form 10-K filed on March 21, 1997).
3.3 -- 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 -- Rights Agreement, dated as of October 28, 1996, between Union Pacific Resources Group Inc. and
Harris Trust and Savings Bank, as rights agent (incorporated herein by reference to the Company's
Current Report on Form 8-K filed on November 1, 1996).
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 -- 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).
4.5 -- 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).
4.6 -- 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).
4.7 -- 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).
4.8 -- 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).
4.9 -- 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).
4.10 -- 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).
65
EXHIBIT
NUMBER DESCRIPTION OF EXHIBIT
- ------ -------------------------------------------------------------------------------------------------
4.11 -- 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).
4.12 -- 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).
4.13 -- 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).
4.14 -- 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 be 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).
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 (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 -- 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 the Company's Registration
Statement on Form S-8, dated February 28, 1997).
10.8 -- 1995 Directors Stock Option Plan, as amended and restated, effective June 1, 1997 (incorporated
herein by reference to Exhibit 10.3 to the Company's Quarterly Report on Form 10-Q for the period
ended March 31, 1997).
10.9 -- Directors' Deferred Compensation Plan, as amended and restated, effective September 5, 1997
(incorporated herein by reference to the Company's Registration Statement on Form S-8, dated
September 15, 1997).
10.10 -- Executive's Deferred Compensation Plan, effective September 5, 1997 (incorporated herein by
reference 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).
66
EXHIBIT
NUMBER DESCRIPTION OF EXHIBIT
- ------ -------------------------------------------------------------------------------------------------
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).
10.14 -- 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).
10.15 -- 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).
*10.16 -- Amendments to Transportation Agreement dated December 15, 1989, by and between Kern River Gas
Transmission Company and Union Pacific Fuels, Inc.
*10.17 -- Gas Transportation Agreement, dated June 18, 1997, by and between Union Pacific Fuels, Inc. and
Texas Gas Transmission Corporation.
10.19 -- 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).
10.20 -- 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).
10.21 -- 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).
10.22 -- U.S. $900,000,000 Competitive Advance/Revolving Credit Agreement, dated as of April 16, 1996,
among Union Pacific Resources Group Inc., the lenders named therein and Texas Commerce Bank
National Association, as administrative agent, as amended through September 13, 1996
(incorporated herein by reference to Exhibit 10 to the Company's Quarterly Report on Form 10-Q
for the period ended September 30, 1996.)
*10.23 -- Third Amendment dated March 2, 1998, to the U.S. $600,000,000 Competitive Advance/Revolving
Credit Agreement, dated April 16, 1996, between Union Pacific Resources Group Inc. and Chase Bank
of Texas, N.A.
*10.24 -- U.S. $300,000,000 Competitive Advance/Revolving Credit Agreement, dated as of November 25, 1997,
among Union Pacific Resources Group Inc., the lenders named therein and Texas Commerce Bank
National Association, as administrative agent.
67
EXHIBIT
NUMBER DESCRIPTION OF EXHIBIT
- ------ -------------------------------------------------------------------------------------------------
*10.25 -- First Amendment dated March 2, 1998, to the U.S. $300,000,000 Competitive Advance/Revolving
Credit Agreement, dated November 25, 1997 among Union Pacific Resources Group Inc., the lenders
named therein and Chase Bank of Texas National Association, as administrative agent.
*10.26 -- U.S. $2,700,000,000 Competitive Advance/Revolving Credit Agreement, dated as of March 2, 1998,
among Union Pacific Resources Group Inc., the lenders named therein and the Chase Manhattan Bank,
as administrative agent and Bank of Montreal, as syndication agent.
*10.27 -- Cdn $200,000,000 Amended and Restated Extendible Revolving Term Credit Facility Agreement, dated
May 22, 1997, between Norcen Energy Resources Limited and Canadian Imperial Bank of Commerce.
*10.28 -- Cdn $100,000,000 Amended and Restated Extendible Revolving Term Credit Facility Agreement, dated
May 29, 1997, between Norcen Energy Resources Limited and Royal Bank of Canada.
*10.29 -- Cdn $100,000,000 Amended and Restated Extendible Revolving Term Credit Facility Agreement, dated
May 29, 1997, between Norcen Energy Resources Limited and Toronto-Dominion Bank.
*10.30 -- Cdn $50,000,000 Amended and Restated Extendible Revolving Term Credit Facility Agreement dated
May 29, 1997, between Norcen Energy Resources Limited and Union Bank of Switzerland (Canada).
*10.31 -- Cdn $50,000,000 Amended and Restated Extendible Revolving Term Credit Facility Agreement dated
June 9, 1997, between Norcen Energy Resources Limited and ABN AMRO Bank Canada.
*10.32 -- U.S. $150,000,000 Demand Credit Facility Agreement, dated November 20, 1997, between Norcen
Energy Venezuela, S.A. and Canadian Imperial Bank of Commerce West Indies Offshore Banking
Corporation.
*10.33 -- U.S. $25,000,000 Revolving Loan Agreement, dated July 14, 1997, between Basic Petroleum
International Limited and Royal Bank of Canada.
*10.34 -- Cdn $10,050,000 Revolving Demand Credit Facility Agreement, dated October 16, 1996, between
Superior Propane Inc. and Royal Bank of Canada.
*10.35 -- 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.
*10.36 -- 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.
*12 -- Computation of ratio of earnings to fixed charges.
16 -- Letter regarding change in certifying accountant from Deloitte & Touche LLP dated December 1997
(incorporated herein by reference to Exhibit 16.1 to the Company's Current Report on Form 8-K
dated December 10, 1997).
*21 -- List of subsidiaries.
*23(a) -- Consent of Deloitte & Touche LLP dated as of March 26, 1998.
*23(b) -- Consent of Ryder Scott Company Petroleum Engineers, dated as of March 9, 1998.
*24 -- Powers of attorney for certain Directors.
*27 -- Financial data schedule.
*99 -- Report from Ryder Scott Company Petroleum Engineers, dated as of Febuary 27, 1998, relating to
oil and gas reserves for Union Pacific Resources Group Inc. as of December 31, 1997.
68
(b) Reports on Form 8-K.
On December 11, 1997, the Company filed a Current Report on Form 8-K
concerning changes in the Company's certifying auditors. Deloitte & Touche, LLP,
will be dismissed effective with the completion of its annual audit of the
Company's financial statements for the fiscal year ended December 31, 1997. The
Company also engaged Arthur Andersen LLP as its new independent auditor
effective January 1, 1998.
On January 26, 1998, the Company filed a Current Report on Form 8-K
containing a copy of two press releases issued by the Company on January 26,
1998. The first press release announced that the Company's Board of Directors
and the Board of Directors of Norcen had unanimously approved the acquisition of
Norcen by Union Pacific Resources Inc., an Alberta corporation ('UPRI'), the
Company's indirect wholly-owned subsidiary. The second press release announced
the Company's 1997 annual operating revenues, net income and certain other
financial information.
On March 17, 1998, the Company filed a Current Report on Form 8-K
containing a copy of two press releases issued by the Company. The first press
release issued on March 3, 1998 announced the closing of its tender offer for up
to 100% of the common shares of Norcen Energy Resources Limited.
In the second press release, issued on March 6, 1998, UPRI announced that
on March 5, 1998, UPRI completed the compulsory acquisition procedures pursuant
to section 206 of the Canadian Business Corporation Act to acquire the remaining
issued and outstanding common shares of Norcen.
69
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 26th day of
March, 1998.
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 26th day of March, 1998, by the following
persons on behalf of the registrant and in the capacities indicated.
SIGNATURE TITLE
- --------------------------------------------------- ---------------------------------------------------------
/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/ MARK L. JONES
Mark L. Jones, as attorney-in-fact
70
INDEX TO EXHIBITS
EXHIBIT
NUMBER DESCRIPTION OF EXHIBIT
- ------ -------------------------------------------------------------------------------------------------
1.2 -- 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 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 to Form 10-K filed on March 21, 1997).
3.3 -- 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 -- Rights Agreement, dated as of October 28, 1996, between Union Pacific Resources Group Inc. and
Harris Trust and Savings Bank, as rights agent (incorporated herein by reference to the Company's
Current Report on Form 8-K filed on November 1, 1996).
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 -- 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).
4.5 -- 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).
4.6 -- 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).
4.7 -- 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).
4.8 -- 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).
4.9 -- 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).
4.10 -- 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).
4.11 -- 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).
4.12 -- 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).
EXHIBIT
NUMBER DESCRIPTION OF EXHIBIT
- ------ -------------------------------------------------------------------------------------------------
4.13 -- 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).
4.14 -- 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 be 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).
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 (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 -- 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 the Company's Registration
Statement on Form S-8, dated February 28, 1997).
10.8 -- 1995 Directors Stock Option Plan, as amended and restated, effective June 1, 1997 (incorporated
herein by reference to Exhibit 10.3 to the Company's Quarterly Report on Form 10-Q for the period
ended March 31, 1997).
10.9 -- Directors' Deferred Compensation Plan, as amended and restated, effective September 5, 1997
(incorporated herein by reference to the Company's Registration Statement on Form S-8, dated
September 15, 1997).
10.10 -- Executive's Deferred Compensation Plan, effective September 5, 1997 (incorporated herein by
reference 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).
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).
10.14 -- 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).
10.15 -- 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).
*10.16 -- Amendments to Transportation Agreement dated December 15, 1989, by and between Kern River Gas
Transmission Company and Union Pacific Fuels, Inc.
*10.17 -- Gas Transportation Agreement, dated June 18, 1997, by and between Union Pacific Fuels, Inc. and
Texas Gas Transmission Corporation.
10.19 -- 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).
10.20 -- 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).
10.21 -- Letter agreement, dated as of January 20, 1997, amending the Anschutz Agreement.
10.22 -- U.S. $900,000,000 Competitive Advance/Revolving Credit Agreement, dated as of April 16, 1996,
among Union Pacific Resources Group Inc., the lenders named therein and Texas Commerce Bank
National Association, as administrative agent, as amended through September 13, 1996
(incorporated herein by reference to Exhibit 10 to the Third Company's Quarterly Report on Form
10-Q for the period ended September 30, 1996.)
*10.23 -- Third Amendment dated March 2, 1998, to the U.S. 900,000,000 Competitive Advance/Revolving Credit
Agreement, dated April 16, 1996, between Union Pacific Resources Group Inc. and Chase Bank of
Texas, N.A.
*10.24 -- U.S. $300,000,000 Competitive Advance/Revolving Credit Agreement, dated as of November 25, 1997,
among Union Pacific Resources Group Inc., the lenders named therein and Texas Commerce Bank
National Association, as administrative agent.
*10.25 -- First Amendment dated March 2, 1998, to the U.S. $300,000,000 Competitive Advance/Revolving
Credit Agreement, dated November 25, 1997 among Union Pacific Resources Group Inc., the lenders
named therein and Chase Bank of Texas National Association, as administrative agent.
*10.26 -- U.S. $2,700,000,000 Competitive Advance/Revolving Credit Agreement, dated as of March 2, 1998,
among Union Pacific Resources Group Inc., the lenders named therein and the Chase Manhattan Bank,
as administrative agent and Bank of Montreal, as syndication agent.
*10.27 -- Cdn $200,000,000 Amended and Restated Extendible Revolving Term Credit Facility Agreement, dated
May 22, 1997, between Norcen Energy Resources Limited and Canadian Imperial Bank of Commerce.
*10.28 -- Cdn $100,000,000 Amended and Restated Extendible Revolving Term Credit Facility Agreement, dated
May 29, 1997, between Norcen Energy Resources Limited and Royal Bank of Canada.
EXHIBIT
NUMBER DESCRIPTION OF EXHIBIT
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*10.29 -- Cdn $100,000,000 Amended and Restated Extendible Revolving Term Credit Facility Agreement, dated
May 29, 1997, between Norcen Energy Resources Limited and Toronto-Dominion Bank.
*10.30 -- Cdn $50,000,000 Amended and Restated Extendible Revolving Term Credit Facility Agreement dated
May 29, 1997, between Norcen Energy Resources Limited and Union Bank of Switzerland (Canada).
*10.31 -- Cdn $50,000,000 Amended and Restated Extendible Revolving Term Credit Facility Agreement dated
June 9, 1997, between Norcen Energy Resources Limited and ABN AMRO Bank Canada.
*10.32 -- U.S. $150,000,000 Demand Credit Facility Agreement, dated November 20, 1997, between Norcen
Energy Venezuela, S.A. and Canadian Imperial Bank of Commerce West Indies Offshore Banking
Corporation.
*10.33 -- U.S. $25,000,000 Revolving Loan Agreement, dated July 14, 1997, between Basic Petroleum
International Limited and Royal Bank of Canada.
*10.34 -- Cdn $10,050,000 Revolving Demand Credit Facility Agreement, dated October 16, 1996, between
Superior Propane Inc. and Royal Bank of Canada.
*10.35 -- 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.
*10.36 -- 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.
*12 -- Computation of ratio of earnings to fixed charges.
16 -- Letter regarding change in certifying accountant from Deloitte & Touche LLP dated December 1997
(incorporated herein by reference to Exhibit 16.1 to the Company's Current Report on Form 8-K
dated December 10, 1997).
*21 -- List of subsidiaries.
-- Consent of Deloitte & Touche LLP dated as of March 26, 1998.
*23(a) -- Consent of Ryder Scott Company Petroleum Engineers, dated as of March 9, 1998.
*23(b) -- Powers of attorney for certain Directors.
*27 -- Financial data schedule.
*99 -- Report from Ryder Scott Company Petroleum Engineers, dated as of Febuary 27, 1998, relating to
oil and gas reserves for Union Pacific Resources Group Inc. as of December 31, 1997.
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* Filed herewith