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SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934 (FEE REQUIRED)
FOR THE FISCAL YEAR ENDED DECEMBER 31, 1996 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 76102
FORT WORTH, TEXAS (Zip Code)
(Address of principal executive offices)
Registrant's telephone number, including area code: (817) 877-6000
Securities registered pursuant to Section 12(b) of the Act:
NAME OF EACH EXCHANGE ON
TITLE OF EACH CLASS WHICH REGISTERED
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Common Stock New York Stock Exchange, Inc.
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Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes X No
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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 25, 1997, the aggregate market value of the registrant's
common stock held by non-affiliates (using the New York Stock Exchange closing
price) was approximately $6,192,422,750.
The number of shares outstanding of the registrant's common stock as of
February 25, 1997 was 253,776,970.
Certain portions of the registrant's definitive Proxy Statement for the
annual meeting of shareholders to be held on May 7, 1997 (the "Proxy Statement")
are incorporated in Part III by reference.
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TABLE OF CONTENTS
PART I
Item 1. Business.................................................... 1
Item 2. Properties.................................................. 10
Item 3. Legal Proceedings........................................... 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................. 30
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.......... 63
Item 11. Executive Compensation...................................... 63
Item 12. Security Ownership of Certain Beneficial Owners and
Management.................................................. 63
Item 13. Certain Relationships and Related Transactions.............. 63
PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports on Form
8-K......................................................... 63
Signatures............................................................ 67
Quantities of natural gas are expressed in this report in terms of thousand
cubic feet (Mcf), million cubic feet (MMcf) or billion cubic feet (Bcf). Oil and
natural gas liquids are quantified in terms of barrels (Bbl), thousands of
barrels (MBbl) or millions of barrels (MMBbl). Oil and natural gas liquids are
compared to natural gas in terms of thousands of cubic feet of natural gas
equivalent (Mcfe), millions of cubic feet of natural gas equivalent (MMcfe),
billions of cubic feet of natural gas equivalent (Bcfe) or trillions of cubic
feet of natural gas equivalent (Tcfe). One barrel of oil or natural gas liquids
is the energy equivalent of six Mcf of natural gas. Daily oil and gas production
is signified by the addition of the letter "d" to the end of the terms defined
above. Natural gas volumes also may be expressed in terms of one million British
thermal units (MMBtu), which is approximately equal to one Mcf. With respect to
information relating to working interests in wells or acreage, "net" oil and gas
wells or acreage is determined by multiplying gross wells or acreage by the
working interest owned therein. Unless otherwise specified, all references to
wells and acres are gross.
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PART I
ITEM 1. BUSINESS
GENERAL
Union Pacific Resources Group Inc., a Utah corporation (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 72% 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. Over 90% of the Company's revenues, assets and
reserves are generated or located in the United States. See "Business Segment
Information" on page 37.
In October 1995, the Company sold 42.5 million shares of its common stock
in an initial public offering (the "Offering"). The Company's stock is traded on
the New York Stock Exchange under the symbol "UPR." Prior to completion of the
Offering, the Company was wholly owned by Union Pacific Corporation, a Utah
corporation ("UPC"). Upon completion of 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.
UPC acquired Champlin Petroleum Company ("Champlin") in 1970 to manage the
exploitation of its oil and gas operations on the Land Grant. The Land Grant
consists of land granted by the Federal government to a predecessor of UPC in
the mid-1800s which passes through the states of Colorado and Wyoming and into
Utah and intersects several highly productive oil and gas basins. In the Land
Grant Area, the Company has fee ownership of the mineral rights under
approximately 7.9 million acres constituting the initial Land Grant and controls
the mineral rights under approximately 700,000 additional acres. In 1971, UPC
combined its own oil and gas operations with those of Champlin. In 1987, the
Champlin name was changed to Union Pacific Resources Company ("UPRC") and UPRC
also became responsible for managing UPC's hard mineral assets. In October 1995,
UPRC and certain oil and gas operations of other affiliated companies which were
wholly owned subsidiaries of UPC, representing, collectively, UPC's natural
resources business segment, were combined to form the Company.
BUSINESS STRATEGY
In each of its core areas, the focus of the Company is on the exploration
for and development of natural gas and crude oil resources and on efforts to
increase margins through reductions in drilling and operating costs and
effective and efficient sales and distribution networks. The Company's strategy
is to apply economies of scale, its operating experience in its core geographic
areas and its expertise in advanced drilling and completion technologies, to
increase production by expanding the Company's North American drill site
inventory and enhancing well performance results. In addition to developing its
existing properties, the Company also increases drill site inventory through
exploration, farm-in agreements and acquisitions of properties and companies.
The Company's growth in recent years has occurred through exploration and
development in core geographic areas as well as producing property purchases,
the most significant of which was the $725 million acquisition of Amax Oil &
Gas, Inc. ("Amax") in March 1994.
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OIL AND GAS OPERATIONS
The Company's oil and gas activities are concentrated in six core
geographic areas: (1) the Austin Chalk trend in Texas and Louisiana, (2) the
Rockies, consisting of the western portion of the Land Grant Area in Wyoming and
Utah, (3) Plains/Canada, consisting of the eastern portion of the Land Grant
Area in Colorado and Wyoming, with additional operations primarily in Kansas and
western Canada, (4) the onshore and offshore Gulf Coast area, (5) eastern and
southern Texas and (6) western Texas. Natural gas and natural gas liquids
constituted 86% of the Company's total proved reserves of over 3.5 Tcfe as of
December 31, 1996, and 82% of the Company's sales volumes of 1.7 Bcfed for the
year then ended. For the same period, approximately 64% of the Company's
production from producing properties was attributable to Company-operated
properties.
The following table sets forth certain reserve and sales information as of
December 31, 1996 with respect to each of the Company's business units.
PROVED RESERVES(1)
AS OF SALES VOLUMES
DECEMBER 31, 1996 YEAR ENDED DECEMBER 31, 1996
------------------- -----------------------------------------------
SALES
TOTAL PRODUCING FROM TOTAL
PROVED PERCENT PROPERTY GAS PLANT SALES PERCENT
RESERVES OF VOLUMES OWNERSHIP VOLUMES(2) OF
BUSINESS UNIT (BCFE) TOTAL (MMCFED) (MMCFED) (MMCFED) TOTAL
------------- -------- ------- --------- --------- ---------- -------
Austin Chalk.................... 558 16% 535 24 559 32%
Rockies......................... 1,244 36 392 14 406 24
Plains/Canada................... 402 11 144 6 150 9
Gulf Onshore/Offshore........... 206 6 125 -- 125 7
East/South Texas................ 538 15 163 20 183 11
West Texas...................... 559 16 96 57 153 9
Natural Gas Processing.......... -- -- -- 144 144 8
----- --- ----- --- ----- ---
Total......................... 3,507 100% 1,455 265 1,720 100%
===== === ===== === ===== ===
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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) Excludes natural gas, natural gas liquids and crude oil purchased from third
parties for resale by UP Fuels. See "Business -- Marketing."
Austin Chalk Business Unit. The Austin Chalk business unit manages the
Company's oil and gas activities in the Austin Chalk trend, which extends 700
miles from southern Texas through central and eastern Texas into Louisiana. At
present, the Company's Austin Chalk production is located primarily in the
Giddings and Brookeland fields. The Louisiana Extension of the Austin Chalk
currently is the focus of significant activity. Since 1988, the Company has
participated in the drilling of approximately 1,300 horizontal wells and has
made aggregate capital expenditures of $1.9 billion in the Austin Chalk area.
The Company currently controls approximately two million developed and
undeveloped net acres in the Austin Chalk and has increased its sales volumes
from 37 MMcfed in January 1990 to an average of 559 MMcfed during 1996. During
1996, 90% of the Company's production from the Austin Chalk 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 Area in Wyoming and
Utah. The Company's operations in the Rockies are concentrated in the Green
River Basin and the Overthrust area. The Company currently controls
approximately 3.5 million developed and undeveloped net acres in the Rockies,
principally attributable to its Land
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Grant ownership. During 1996, 23% of the Company's production from the Rockies
was attributable to Company-operated properties.
Plains/Canada Business Unit. The Plains/Canada business unit manages the
Company's oil and gas activities primarily in three areas: the eastern portion
of the Land Grant Area in Colorado and Wyoming, the Hugoton/Panoma field in
Kansas and fields in western Canada. The Company currently controls more than
5.7 million developed and undeveloped net acres in Plains/Canada, principally
attributable to its Land Grant ownership. As of December 31, 1996, the Company
had an interest in approximately 1,300 gross producing wells in the
Plains/Canada area. The Company also had royalty interests in 3,700 producing
wells in Plains/Canada in which the Company did not also own a working interest.
During 1996, 49% of the Company's production from Plains/Canada 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 the
onshore Gulf Coast. In addition to its producing operations, the unit conducts
exploration activities in southern Louisiana, southern Texas and the Gulf of
Mexico. During 1996, 49% of the Company's production from the Gulf
Onshore/Offshore area was attributable to Company-operated properties.
East/South Texas Business Unit. The East/South Texas business unit manages
the Company's oil and gas activities in two major producing areas: the Carthage
and Oakhill fields in northeastern Texas and the Stratton/Agua Dulce area in
southern Texas. The Company also controls significant gathering, processing and
transportation assets in East/South Texas that are integral to its natural gas
production activities. For the year ended December 31, 1996, 87% of the
Company's production from East/South Texas 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 obtained its producing properties
in the Ozona field through the acquisition of Amax in March 1994. The Amax
acquisition included approximately 850 operated natural gas wells in the Ozona
field, which is characterized by long-lived natural gas wells that typically
produce for 30 or more years. Since the Amax acquisition, the Company has
drilled over 600 wells in the Ozona area and has substantially modernized and
expanded its gathering, processing and transportation facilities. As of December
31, 1996, approximately 84% of the gross producing wells in the West Texas area
were Company operated. During 1996, 93% of the Company's production from West
Texas was attributable to Company-operated properties.
Plants and Pipelines. The Company owns interests in 21 natural gas
processing plants, 16 of which it operates, with a current throughput capacity
of 3.2 Bcfd (1.6 Bcfd net to the Company). Aggregate throughput of the Company's
gas processing plants for the year ended December 31, 1996 averaged 84% of the
plants' aggregate design capacity. For the year ended December 31, 1996,
production of natural gas liquids attributable to the Company's ownership
interest in gas processing facilities averaged approximately 39.8 MBbld. In
addition to the gas value chain assets included in the Amax acquisition, the
Company has invested approximately $100 million per year in each of the last
three years to increase processing and gathering capacity. The Company currently
is developing a gas processing facility in the Austin Chalk and has plans to
expand its Patrick Draw plant in the Rockies as well as its East Texas plant
complex. See "Properties -- Gas Processing Assets."
During 1996, the Company became a partner with Arco Pipeline Company on a
50/50 basis in the Black Lake liquids pipeline, a 270-mile pipeline in Louisiana
which can transport up to 45 MBbld of natural gas liquids from the Austin Chalk
area to markets on the Gulf Coast. Both the Black Lake and Panola pipelines
deliver unfractionated natural gas liquids to the Enterprise and Mont Belvieu I
fractionators in which the Company has equity ownership. The Company also has a
55% nonoperating interest in the Ferguson-Burleson County Gas Gathering System,
a 585 MMcfd capacity system serving the deep Giddings area of the Austin Chalk
and controls both the 265-mile Overland Trail Transmission Company pipeline
serving the Green River Basin in the Rockies and the 100 MMcfd Wahsatch
Gathering System, a sour gas pipeline serving the Yellow Creek and Cave Creek
areas of the Overthrust. In general, the Company owns extensive gathering
systems
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behind each of its natural gas processing plants which it uses to transport
unprocessed gas from producing wells to the inlet of the plant.
Marketing. In 1996, the Company, primarily through UP Fuels, sold
approximately 1.8 Bcfd of natural gas (about 56% of which represented the
Company's equity production), 151.6 MBbld of natural gas liquids (including 83.3
MBbld of third party liquids) and 63.5 MBbld of crude oil and condensate
(including 12.9 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 East 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. Where possible, UP Fuels sells crude oil directly to refiners.
If these customers are not available locally, UP Fuels exchanges or sells the
crude oil volumes to major trading locations where they are sold to both
refiners and marketers.
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,
--------------------------------------------
1994 1995 1996
------------ ------------ ------------
PRODUCING PROPERTIES:
Average daily production(1):
Natural gas (MMcfd)................................ 754.8 915.6 980.3
Natural gas liquids (MBbld)........................ 18.8 23.1 28.5
Crude oil (MBbld).................................. 63.1 52.8 50.6
Total (MMcfed)............................. 1,246.2 1,371.0 1,454.9
Average sales prices:
Natural gas (per Mcf).............................. $ 1.82 $ 1.42 $ 1.86
Natural gas liquids (per Bbl)...................... 7.86 8.14 11.39
Crude oil (per Bbl)................................ 14.34 16.08 18.84
Production costs (per Mcfe)(2)....................... 0.55 0.42 0.49
PLANTS, PIPELINES AND MARKETING:
Average daily sales volumes attributable to gas plant
ownership(3):
Natural gas (MMcfd)................................ 17.5 23.9 26.7
Natural gas liquids (MBbld)........................ 31.2 34.2 39.8
Total (MMcfed)............................. 204.7 229.1 265.4
Average sales prices:
Natural gas (per Mcf).............................. $ 1.81 $ 1.51 $ 2.01
Natural gas liquids (per Bbl)...................... 9.97 9.38 13.16
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(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, 1994, 1995 and
1996 are 43.9 MMcfed, 66.5 MMcfed and 77.1 MMcfed, respectively. See
"Supplementary Information -- Average Daily Production and Sales Volume" on
page 58.
MINERALS
The Minerals business unit contributes significantly to the Company's
operating income by exploiting the hard minerals portion of the Company's
extensive fee mineral interests in the Land Grant through 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
in its oil and gas business units. The Minerals business unit generated $120
million of operating income during 1996, as follows:
1996 OPERATING INCOME
--------------------------------
AMOUNT PERCENT
------ -------
(MILLIONS OF DOLLARS)
Royalties:
Soda ash(1)............................................. $ 26.5 22%
Coal(2)................................................. 15.9 13
------- ---
Total royalties................................. 42.4 35
------- ---
Nonoperated joint ventures:
Soda ash(3)............................................. 13.7 11
Coal(4)................................................. 60.7 51
------- ---
Total joint ventures............................ 74.4 62
Overhead/other............................................ 3.2 3
------- ---
Total operating income.......................... $120.0 100%
======= ===
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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 1996, 62% 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, $54.8 million is attributable to a single coal
supply contract, the financially beneficial terms of which terminate at the
end of 2001. 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 coals for
industrial and utility boiler markets. At current coal pricing and extraction
cost levels, however, most of this resource is not economic to extract, except
for sale to local markets. As a result, there are limited opportunities for new
coal mine development in the Land Grant.
The world's largest deposit of trona 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
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Land Grant and is therefore owned by the Company. Natural soda ash, which is
produced by refining trona ore, is used primarily in the production of glass for
containers and flat glass, in the paper and water treatment industries and in
the manufacture of certain chemicals and detergents. Natural soda ash from
Wyoming has grown to 30% of the world soda ash supply with the remainder
principally from synthetic processes, and will continue to expand while
worldwide demand continues to increase. As a result of the continued increase in
the worldwide demand for soda ash, the Company, along with its partner Oriental
Chemical Industries, Inc., 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. The Company's share of expansion costs is
expected to be funded primarily with partnership debt.
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 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
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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
and, on the whole, have helped natural gas to be more responsive to changing
market conditions. 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.
Several parties have petitioned the Supreme Court to review the Court of
Appeals' decision. It is uncertain whether the Supreme Court will agree to hear
the case. 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 has begun initial
inquiries regarding the scope of its regulation of gathering. The Company owns
and operates extensive gathering systems in Texas. At this time, the Company
cannot predict the extent to which any new Railroad Commission policy will
affect its 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.
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.
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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 phaseout would be triggered if the average
price for crude oil rose above approximately $45/Bbl 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 the Rockies, the Carthage field in East
Texas, the Ozona field in West Texas and certain areas in the Austin Chalk trend
qualifies for this tax credit. The Company recorded approximately $15.6 million
of Section 29 tax credits in 1996. 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 which, utilizing drilling
funds contributed by the investor as limited partner, drilled 208 wells which
qualify for Section 29 tax credits. The Company is the managing general partner
of this producing partnership and has broad latitude in conducting operations on
the assets therein. Prior to a defined payout, the limited partner was entitled
to receive a preferential distribution of a specified quantity of available
production from this 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 is entitled to receive only 1% of ongoing
production. Both the historic and future forecasted production allocable to the
limited partner have been deducted from the Company's reserve and production
statistics.
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 ending
August 31, 2001. The natural gas production from wells drilled on certain of the
Company's properties in the Austin Chalk, West Texas and East/South 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 180
days after first production to obtain a high cost gas certification. 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 credit.
This tax rate reduction remains in effect for ten years or until the aggregate
tax credits received equal 50% of the total drilling and completion costs.
8
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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 "Management's Discussion and Analysis of Financial Condition and Results of
Operations -- 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 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
9
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liability for pollution damages. In the event of a serious incident of
pollution, the Department of the Interior may require a lessee under Federal
leases to suspend or cease operations in the affected areas.
Canadian Environmental Regulation. The oil and gas industry in Canada
currently is subject to environmental regulation pursuant to provincial and
federal legislation. Environmental legislation provides for restrictions and
prohibitions on releases or emissions of various substances produced or utilized
in association with certain oil and gas industry operations. In addition,
legislation requires that well and facility sites be abandoned and reclaimed to
the satisfaction of provincial authorities. A breach of such legislation may
result in the imposition of fines and penalties. In Alberta, environmental
compliance has been governed by the Alberta Environmental Protection and
Enhancement Act ("AEPEA") since September 1, 1993. In addition to replacing a
variety of older statutes which related to environmental matters, AEPEA also
imposes certain new environmental responsibilities on oil and natural gas
operators in Alberta and, in certain instances, imposes greater penalties for
violations. In British Columbia, regulations affecting the oil and gas industry
are administered by the Ministry of Energy, Mines and Petroleum Resources.
EMPLOYEES
The Company had 1,584 employees as of December 31, 1996. 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.
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, 1996. 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.
RESERVES AS OF DECEMBER 31, 1996
------------------------------------------
NATURAL
NATURAL GAS
GAS LIQUIDS CRUDE OIL TOTAL
CATEGORY (BCF) (MMBBL) (MMBBL) (BCFE)
-------- ------- ------- --------- -------
Proved developed........................... 2,125.4 97.7 74.1 3,155.8
Proved undeveloped......................... 253.0 9.8 6.5 351.2
------- ----- ---- -------
Total proved..................... 2,378.4 107.5 80.6 3,507.0
======= ===== ==== =======
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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, 1996.
TOTAL ACRES
--------------
BUSINESS UNIT GROSS NET
------------- ----- -----
(IN THOUSANDS)
Austin Chalk................................................ 31 11
Rockies..................................................... 3,253 3,252
Plains/Canada............................................... 5,316 4,922
Gulf Onshore/Offshore....................................... 215 73
East/South Texas............................................ 46 12
West Texas.................................................. 690 238
----- -----
Total fee acreage................................. 9,551 8,508
===== =====
Land Grant (included above in Rockies and Plains/Canada).... 7,912 7,722
===== =====
The Company holds royalty interests of varying percentages in the
approximately one million gross acres of the Land Grant that are subject to
exploration and production agreements with third parties. The Company's fee
mineral acreage is primarily undeveloped.
Leasehold. The Company's leasehold acreage by business unit as of December
31, 1996 is set forth below.
ACRES
---------------------------------------------
DEVELOPED UNDEVELOPED TOTAL
------------- ------------- -------------
BUSINESS UNIT GROSS NET GROSS NET GROSS NET
------------- ----- ----- ----- ----- ----- -----
(IN THOUSANDS)
Austin Chalk............................ 783 561 1,995 1,459 2,778 2,020
Rockies................................. 126 71 268 185 394 256
Plains/Canada........................... 371 173 970 650 1,341 823
Gulf Onshore/Offshore................... 300 122 281 201 581 323
East/South Texas........................ 224 125 604 321 828 446
West Texas.............................. 214 127 154 119 368 246
----- ----- ----- ----- ----- -----
Total leasehold acreage....... 2,018 1,179 4,272 2,935 6,290 4,114
===== ===== ===== ===== ===== =====
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Total Leasehold and Fee Mineral. The total leasehold and fee mineral
acreage by business unit as of December 31, 1996 is set forth below.
TOTAL ACRES
----------------
BUSINESS UNIT GROSS NET
------------- ------ ------
(IN THOUSANDS)
Austin Chalk................................................ 2,809 2,031
Rockies..................................................... 3,647 3,508
Plains/Canada............................................... 6,657 5,745
Gulf Onshore/Offshore....................................... 796 396
East/South Texas............................................ 874 458
West Texas.................................................. 1,058 484
------ ------
Total acreage..................................... 15,841 12,622
====== ======
DRILLING ACTIVITY AND PRODUCING WELL SUMMARY
The table below summarizes the Company's drilling activity over the last
three years.
YEARS ENDED DECEMBER 31,
--------------------------------------------------
1994 1995 1996
-------------- -------------- --------------
GROSS NET GROSS NET GROSS NET
----- ----- ----- ----- ----- -----
Development wells:
Productive......................... 615 364.5 679 505.7 575 413.4
Dry................................ 14 8.7 18 7.7 35 25.7
Exploration wells:
Productive......................... 29 16.0 6 2.8 16 8.5
Dry................................ 19 8.1 22 10.7 29 18.2
---- ----- ---- ----- ---- -----
Total wells................ 677 397.3 725 526.9 655 465.8
==== ===== ==== ===== ==== =====
The number of wells drilled is not a valid measure or indicator of the
relative success or value of a drilling program because the significance of the
reserves and their economic potential may vary widely for each project. As of
December 31, 1996, the Company owned interests in 5,011 gross gas wells (2,703
net) and 2,786 gross oil wells (1,620 net). Gross wells include 577 wells with
multiple completions. The Company operated 59% of the gross wells in which it
owned an interest.
GAS PROCESSING ASSETS
A listing of the Company's processing plants as of December 31, 1996 is
provided below.
AVERAGE GROSS VOLUMES
YEAR ENDED
DECEMBER 31, 1996
--------------------------
NATURAL GAS
DESIGN NATURAL GAS LIQUIDS
WORKING CAPACITY THROUGHPUT PRODUCED
GAS PLANT BY BUSINESS UNIT INTEREST % (MMCFD)(1) (MMCFD) (MBBLD)
-------------------------- ---------- ---------- ----------- -----------
Austin Chalk
Brookeland(2)...................... 80 100 116 9.6
Rockies
*Anschutz Ranch East(3,4)........... 12 650 390 17.5
Brady(5,6,7)....................... 42 65 58 2.5
*Painter(8)......................... 19 260 259 12.7
Pineview........................... 49 15 2 0.2
*Whitney Canyon(6).................. 19 235 169 7.8
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AVERAGE GROSS VOLUMES
YEAR ENDED
DECEMBER 31, 1996
--------------------------
NATURAL GAS
DESIGN NATURAL GAS LIQUIDS
WORKING CAPACITY THROUGHPUT PRODUCED
GAS PLANT BY BUSINESS UNIT INTEREST % (MMCFD)(1) (MMCFD) (MBBLD)
-------------------------- ---------- ---------- ----------- -----------
Plains/Canada
Bledsoe(4,5)....................... 100 2 1 --
*Caroline(4,6)...................... 7 300 329 29.5
Mt. Pearl(4,5)..................... 52 11 9 0.4
Silo............................... 100 5 3 0.4
East/South Texas
Gulf Plains(7)..................... 100 110 82 5.6
West Texas
Ozona(7,9)......................... 63 120 94 11.1
S.W. Ozona......................... 100 90 59 7.2
Natural Gas Processing
A&M(10)............................ 55 50 48 4.9
Bryan(10).......................... 55 60 56 10.3
Conroe............................. 100 65 36 0.9
East Texas plant complex(7)........ 89 660 623 37.8
*Echo Springs....................... 34 240 244 17.8
Emigrant Trail..................... 100 60 41 1.8
Patrick Draw(7).................... 100 30 24 1.7
Yellow Creek(7,11)................. 100 80 34 0.3
----- ----- -----
Total....................... 3,208 2,677 180.0
===== ===== =====
- - ---------------
* Nonoperated
(1) Represents the gross design capacity of the gas plant as of December 31,
1996.
(2) Includes 50 MMcfd of design capacity which came on-line in 1996.
(3) Design capacity includes 260 MMcfd utilized for field pressure maintenance.
During 1995, pressure maintenance ceased, resulting in current processing
capacity of 390 MMcfd. As a result, an additional 80 MMcfd from the
Anschutz Ranch field normally processed at this plant currently is being
processed at Painter complex.
(4) Financial and operating statistics are included in the producing property,
rather than the plants, pipelines and marketing disclosures (the plant is
accounted for as a lease facility).
(5) Residue gas can be reinjected for pressure maintenance.
(6) Sour gas facility (capable of processing gas containing hydrogen sulfide).
(7) Includes fractionation facilities.
(8) Nitrogen is reinjected for pressure maintenance.
(9) Includes 30 MMcfd of design capacity which came on-line in May 1996.
(10) Straddle plants which process gas gathered by the Ferguson-Burleson County
Gas Gathering System.
(11) Straddle plant (a plant located near a transmission facility which
processes gas dedicated to or gathered by a third party).
Average throughput in these plants for 1996 was approximately 84% of design
capacity.
ITEM 3. LEGAL PROCEEDINGS
In August 1994, the surface owners 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 the District Court of Weld County,
Colorado, to quiet title to minerals, including crude oil (in some of the lands)
and natural gas. In September 1994, the case was removed to the United States
District Court for the District of Colorado. The Company plans to file a motion
for summary judgment asking the state court to rule as a
13
16
matter of law that it owns the oil and gas and all minerals that are part of a
severed mineral estate. No trial date currently is set. Similar claims were made
under identical mineral reservations by Utah and Wyoming surface owners in cases
litigated in the Federal courts of Utah and Wyoming between 1979 and 1987. In
those cases, the Federal courts held as a matter of law that, under the laws of
Utah and Wyoming, these mineral reservations unambiguously reserved oil and gas
to Union Pacific Railroad Company and its successors. These holdings were
affirmed by the United States Court of Appeals for the Tenth Circuit. While the
Company believes that the rule of law applied by the Federal courts in Utah and
Wyoming also should be applied under Colorado law, there are Colorado court
decisions that could provide a basis for an alternative interpretation. The
value of the disputed reserves in the properties subject to the lawsuit is
estimated to be approximately $5 million. Approximately 400,000 acres of other
lands in Weld County, Colorado, are subject to mineral reservations that are in
the same form as the reservations at issue in the present suit. An adverse
interpretation of the reservations at issue is likely to implicate the mineral
title in these other lands as well. In addition, over two million acres of lands
elsewhere in Colorado are subject to the same forms of mineral reservations.
Depending on the grounds of an adverse decision in the case, title to minerals
held by the Company in some or all of these lands also could be affected, which
might have the effect of significantly reducing the Company's interest in the
Las Animas area of southeastern Colorado and the Denver-Julesburg Basin in
eastern Colorado.
The Company is a defendant in three contract suits now pending in Fayette
County, Lee County and Harris County (transferred from Calhoun County), Texas,
in which the plaintiffs allege that the Company underpaid their royalties for
crude oil production in Texas. Plaintiffs seek certification as a class action
in each suit. The Texas General Land Office is a plaintiff in the Fayette County
suit (filed August 1995). The allegations are premised upon plaintiffs' theory
that the defendants (including the Company) use "posted prices" to determine the
amounts payable as royalties for crude oil production. Plaintiffs allege that
the defendants "set" these posted prices, that posted prices are consistently
below "market value," and that this practice has resulted in the underpayment of
royalties to plaintiffs.
The Company also is one of the defendants in an antitrust suit filed in
September 1996 in the Circuit Court of Escambia County, Alabama, against a
number of crude oil producers alleging that the use of posted prices by
defendants to pay royalties on crude oil produced in the United States arises
from a combination, conspiracy or agreement designed to fix, depress and
maintain such crude prices at artificially low levels. The plaintiffs have
received a "conditional" certification as a class action on behalf of all
working and royalty interest owners of crude oil produced in the United States
since 1986 who have been paid by defendants based on posted prices. The suit was
removed to Federal court, United States District Court, Southern District,
Mobile, Alabama Division, on October 17, 1996. Plaintiffs' motion to remand the
suit back to the Circuit Court is pending. Defendants' motion to transfer the
suit to Houston also is pending.
None of these suits described above articulate a theory of recovery or a
specific amount of damages. This litigation activity against the Company and
others in the oil and gas industry suggests that more suits of this type may be
filed against the Company including, perhaps, suits by other types of interest
owners and in jurisdictions other than Texas and Alabama. The Company intends to
defend vigorously against the foregoing, as well as any similar suits. If such
suits ultimately are resolved against the Company on a widespread basis,
however, damage awards and a loss of future revenue could result which, in the
aggregate, could be materially adverse to 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 personal injury claims and environmental
claims. While the Company cannot predict the outcome of such litigation and
other proceedings, it does not expect those matters to have a materially adverse
effect on its results of operations or financial condition.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
There were no matters submitted to a vote of security holders during the
quarter ended December 31, 1996.
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EXECUTIVE OFFICERS OF THE REGISTRANT
NAME POSITION AGE
---- -------- ---
Jack L. Messman(1).................... Chairman and Chief Executive Officer 57
George Lindahl III(2)................. President and Chief Operating Officer 50
V. Richard Eales(3)................... Executive Vice President 61
Anne M. Franklin(4)................... Vice President -- People 40
Mark S. Knouse(5)..................... Vice President -- External Affairs and Secretary 46
Joseph A. LaSala, Jr.(6).............. Vice President and General Counsel 42
Donald W. Niemiec(7).................. Vice President -- Marketing 50
Morris B. Smith(8).................... Vice President and Chief Financial Officer 52
John B. Vering(9)..................... Vice President -- Exploration and Production Services 47
- - ---------------
(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 UPRC since May 1991.
(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. Prior thereto, he was Vice
President -- Exploration 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) 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. Prior thereto, she held various positions in marketing and
operations at Indiana Bell Telephone Company (currently Ameritech).
(5) Mr. Knouse has held his current position with the Company since August 1995.
Prior thereto, he was Vice President -- Government Relations and Public
Affairs of UPRC.
(6) Mr. LaSala has held his current position with the Company since January
1996. Mr. LaSala joined UPRC in January 1995 as Assistant General Counsel.
He was Vice President -- Government and Regulatory Affairs of USPCI, Inc., a
former subsidiary of UPC, from May 1993 until December 1994 and, prior
thereto, Vice President -- External Relations of USPCI.
(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 October
1996. Prior thereto, he was General Manager -- Austin Chalk of the Company
and UPRC.
15
18
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 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 for the Company's common stock, as reported on
the New York Stock Exchange Composite Tape, as well as the dividends declared on
such stock, is set forth under Selected Quarterly Data on page 62.
At February 25, 1997, there were 253,776,970 shares of outstanding common
stock and approximately 58,000 shareholders of record. At that date, the closing
price of the common stock on the New York Stock Exchange was $24.63.
The Company has paid quarterly cash dividends of $0.05 per share since its
initial public offering. 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 October 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. In
February 1997, the Board of Directors adopted a stock repurchase program which
authorizes the Company to purchase up to $50 million of its common stock
outstanding in any given fiscal year.
ITEM 6. SELECTED FINANCIAL DATA
FIVE-YEAR FINANCIAL SUMMARY
1992 1993 1994 1995 1996
-------- -------- -------- -------- --------
(MILLIONS, EXCEPT PER SHARE AMOUNTS)
INCOME STATEMENT DATA:
Operating revenues................. $1,222.5 $1,277.1 $1,332.9 $1,476.7(a) $1,831.0
Operating income................... 318.7 382.9 351.3 470.1(a) 526.6
Net income......................... 272.3 243.8(b) 390.0(c) 350.7(a) 320.8
Per share:
Net income(d).................... n/a n/a n/a n/a 1.28
Dividends........................ n/a n/a n/a 0.05(e) 0.20
FINANCIAL POSITION DATA:
Properties -- net.................. $1,660.5 $1,780.2 $2,600.1(f) $2,764.3 $2,972.4
Total assets....................... 2,586.4 2,714.1 3,247.0 3,308.9 3,648.9
Long-term debt..................... 48.2 45.6 37.7 101.5 670.9(g)
Shareholders' equity............... 1,475.2 1,596.1 1,834.9 1,312.4 1,514.3
CASH FLOW DATA:
Capital and exploratory
expenditures..................... $ 594.4 $ 560.4 $1,389.3(f) $ 686.4 $ 880.3
Cash provided by operations........ 776.2 567.5 821.0 829.4 990.4
- - ---------------
(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 (see Note 4 to the Consolidated Financial
Statements).
(b) In January 1993, the Company adopted Statement of Financial Accounting
Standards ("SFAS") No. 106, "Employers' Accounting for Postretirement
Benefits Other Than Pensions," and SFAS
16
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No. 109, "Accounting for Income Taxes," with a cumulative after-tax charge
to 1993 earnings of $59 million.
(c) In March 1994, the Company sold its interest in the Wilmington Field and
Harbor Cogeneration Plant to the Port of Long Beach, California. The
Wilmington sale resulted in a $159.2 million pre-tax ($100 million
after-tax) gain (see Note 4 to the Consolidated Financial Statements).
(d) Earnings per share prior to 1996 have been omitted as the Company was a
wholly owned subsidiary of UPC until the Offering in October 1995.
Therefore, net income per share is not applicable for periods prior to the
fourth quarter of 1995. See "Selected Quarterly Data" on page 62.
(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 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
8 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 report. The consolidated statements of income
for previous periods include certain reclassifications that were made to conform
to the current presentation. Such reclassifications effect 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, 1996 COMPARED TO YEAR ENDED DECEMBER 31, 1995
SELECTED FINANCIAL DATA
YEARS ENDED
DECEMBER 31,
----------------------
1995 1996
--------- ---------
(MILLIONS OF DOLLARS)
Total operating revenues.................................... $1,476.7 $1,831.0
Total operating expenses.................................... 1,006.6 1,304.4
Operating income............................................ 470.1 526.6
Net income.................................................. 350.7 320.8
The Company reported net income of $320.8 million for the year ended
December 31, 1996, down by $29.9 million (9%) from $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 bankruptcy 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 stand-alone 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, 1996 net
income would have been $4.6 million (1%) above 1995 pro forma net income (see
Note 2 to the Consolidated Financial Statements).
17
20
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 bankruptcy settlement. Demand for hydrocarbons to replenish
inventory, the unresolved Iraqi situation, capacity problems in Mexico and
weather-related demand provided product price support throughout 1996. Volume
growth has been achieved through drilling, property purchases, plant expansion
and ethane recovery. These gains were offset partially by property writedowns,
cost increases associated with expanded exploration activity and increased
administrative expenses associated with being a stand-alone public company.
OIL AND GAS OPERATIONS
Operating Revenues
OPERATING REVENUES -- OIL AND GAS OPERATIONS
YEARS ENDED
DECEMBER 31,
----------------------
1995 1996
-------- ----------
(MILLIONS OF DOLLARS)
Producing properties........................................ $853.6 $1,133.3
Plants, pipelines and marketing............................. 339.9 503.8
Other oil and gas revenues.................................. 166.9 65.0
Producing property revenues increased by $279.7 million (33%) to $1,133.3
million. Production volume increases of 83.9 MMcfed (6%) added $39.6 million in
revenues while higher product prices of $0.42/Mcfe (25%) added $240.1 million in
revenues.
YEARS ENDED DECEMBER 31,
-----------------------------------
1995 1996 1995 1996
------- ------- ------ ------
(WITHOUT HEDGING) (WITH HEDGING)
Average product price realizations -- producing
properties:
Natural gas (per Mcf)............................ $ 1.30 $ 1.94 $ 1.42 $ 1.86
Natural gas liquids (per Bbl).................... 8.14 11.39 8.14 11.39
Crude oil (per Bbl).............................. 16.35 20.09 16.08 18.84
Average (per Mcfe)............................... 1.64 2.23 1.71 2.13
YEARS ENDED
DECEMBER 31,
------------------
1995 1996
------- -------
Production volumes -- producing properties:
Natural gas (MMcfd)....................................... 915.6 980.3
Natural gas liquids (MBbld)............................... 23.1 28.5
Crude oil (MBbld)......................................... 52.8 50.6
Total (MMcfed)............................................ 1,371.0 1,454.9
Natural gas volumes increased by 64.7 MMcfd (7%) to 980.3 MMcfd with
increases from development drilling programs in the Austin Chalk (98.1 MMcfd)
and West Texas (17.6 MMcfd) and a lower distribution of preferential volumes
related to the Company's Section 29 Limited Partnership (22.4 MMcfd). Offsetting
these increases were declines in the Gulf Onshore/Offshore (30.4 MMcfd)
resulting largely from the depletion of several offshore wells, and declines in
the Rockies (13.3 MMcfd) resulting from production problems. Natural gas liquids
("NGL") volumes from producing properties increased by 5.4 MBbld (23%) to 28.5
MBbld primarily due to ethane recovery in the Rockies and Plains/Canada and
additional lease gas being processed in the Austin Chalk by the expanded
Brookeland plant. Crude oil volumes were 2.2 MBbld (4%) lower at 50.6 MBbld as a
result of production declines in Plains/Canada and the Rockies and the sale of
certain non-core properties, partially offset by property acquisitions and
drilling in the Austin Chalk.
18
21
Plants, pipelines and marketing revenues of $503.8 million increased by
$163.9 million (48%) from $339.9 million in 1995. Increased plant volumes of
36.3 MMcfed (16%) added $21.2 million in plant revenues while higher prices of
$0.62/Mcfe (40%) added $59.8 million in plant revenues. Pipeline revenue
increases of $63.9 million were primarily attributable to increased throughput
and higher prices at the Ferguson/Burleson pipeline in the Austin Chalk ($25.3
million) and Ozona pipeline in West Texas ($33.5 million). Revenues from the
Wahsatch pipeline in the Rockies were down with lower throughput and tariff
rates. Marketing revenues increased by $24.6 million primarily as a result of
improved natural gas and NGL margins, additional marketed volumes and increased
natural gas storage activity.
YEARS ENDED
DECEMBER 31,
----------------
1995 1996
------ ------
Average product price realizations -- plants:
Natural gas (per Mcf)..................................... $ 1.51 $ 2.01
Natural gas liquids (per Bbl)............................. 9.38 13.16
Average (per Mcfe)........................................ 1.56 2.18
Sales volumes -- plants:
Natural gas (MMcfd)....................................... 23.9 26.7
Natural gas liquids (MBbld)............................... 34.2 39.8
Total (MMcfed)............................................ 229.1 265.4
NGL volumes increased by 5.6 MBbld (16%) to 39.8 MBbld primarily due to the
expansion of the Ozona (West Texas), Brookeland (Austin Chalk) and Echo Springs
(Rockies) plants, greater retention percentages at the East Texas plant
reflecting third parties' elections to reject liquids, as well as ethane
recovery in other Rockies plants. Volume decreases occurred with a contract
revision at Gulf Plains in East/South Texas, leaner gas streams and lower inlets
at Giddings plants in the Austin Chalk and the disposition of certain plants in
West Texas and the Rockies. Natural gas volumes were up 2.8 MMcfd (12%) to 26.7
MMcfd resulting from the Brookeland expansion and increased throughput at Gulf
Plains.
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. As a result of the payment from Columbia, after taking into
account possible tax and royalty claims, the Company recorded a $122.5 million
pre-tax ($78.5 million after-tax) gain in the fourth quarter of 1995 which is
included in other oil and gas revenues in the Company's 1995 Consolidated
Statement of Income. During 1996, as a result of favorable litigation activity
and the determination and payment of its severance tax liability, the Company
recognized $31.3 million in other oil and gas revenues related to a reduction in
its litigation and contingencies accrual pertaining to the Columbia payment.
Other oil and gas revenues declined by $101.9 million (61%) in 1996
reflecting the absence of the 1995 Columbia settlement, lower preferential
volumes distributed to an investor in the Company's Section 29 Limited
Partnership ($10.1 million) and lower net gains on property sales ($10.3
million), partially offset by the 1996 release of a portion of the Company's
litigation and contingency accrual related to the Columbia settlement and the
absence of a 1995 hedging loss ($8.1 million).
19
22
Operating Expenses
OPERATING EXPENSES -- OIL AND GAS OPERATIONS
YEARS ENDED
DECEMBER 31,
----------------------
1995 1996
--------- ---------
(MILLIONS OF DOLLARS)
Production.................................................. $210.5 $259.5
Exploration................................................. 89.4 144.6
Plants, pipelines and marketing............................. 189.0 290.0
Depreciation, depletion and amortization.................... 458.6 533.9
Production expenses increased by $49.0 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 ($12.0 million) and an unfavorable 1996 ad valorem tax
adjustment ($4.5 million). Lease operating costs were up $16.1 million primarily
in the Austin Chalk, East/South Texas and West Texas as a result of increased
production volumes and greater workover costs. Production overhead was
unfavorable by $4.0 million. Production expenses on a per unit basis of
$0.49/Mcfe were $0.07/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 South Louisiana,
offshore, and North and South Dakota. The surrendered lease provision was $29.1
million higher than 1995 reflecting a writeoff of North and South Dakota
leasehold ($9.1 million) as well as increases in Austin Chalk and Gulf
Onshore/Offshore leasing activity. Exploration overhead was unfavorable by $5.4
million.
Plants, pipelines and marketing expenses increased by $101.0 million (53%)
with higher plant and pipeline gas purchase costs and a SFAS 121 asset
impairment adjustment related to the Wahsatch pipeline ($17.0 million). Gas
purchase costs were up $71.7 million as a result of increased throughput and
higher prices at the Ozona, Peachridge and Ferguson/Burleson pipelines ($53.0
million) and Giddings plants ($8.8 million) and increased retention percentages
at East Texas ($4.0 million). Marketing expenses were up $9.6 million with
system development, legal and other operating costs.
Depreciation, depletion and amortization increased by $75.3 million (16%)
to $533.9 million as a result of SFAS 121 asset impairment adjustments related
to certain properties in the Rockies and Gulf Onshore/Offshore ($17.4 million),
several offshore property writeoffs ($9.0 million), higher producing property
volumes ($25.8 million), a higher asset base in plants and pipelines ($11.0
million) and an unfavorable unit of production rate ($11.0 million). On a per
unit basis for producing properties, depreciation, depletion and amortization,
excluding the writedowns, increased by $0.02/Mcfe to $0.83/Mcfe.
Total Oil and Gas Operating Income
Total oil and gas operating income increased by $63.3 million (15%) with
higher producing property operating income of $11.2 million and increased
plants, pipelines and marketing operating income of $52.1 million.
MINERALS -- Minerals operating income increased by $12.9 million to $120.0
million (12%), primarily due to higher soda ash joint venture income of $6.7
million reflecting higher prices, an increase in ballast income, higher coal
royalty income associated with more tons mined from the Company's leases and
favorable operating expense.
GENERAL AND ADMINISTRATIVE EXPENSES -- General and administrative expenses
increased by $18.1 million (36%) to $68.4 million principally reflecting
increased costs associated with being a stand-alone public
20
23
company and costs of completing information and accounting system conversions.
On a pro forma per unit basis, general and administrative expenses increased by
$0.01/Mcfe (10%) to $0.11/Mcfe. See Note 2 to the Consolidated Financial
Statements for pro forma income information.
INTEREST AND OTHER INCOME -- Interest expense increased by $31.5 million to
$50.6 million, while other income/expense was unfavorable by $10.4 million.
These changes principally reflect the annual effects of debt restructuring which
occurred at the time of the Offering in 1995.
INCOME TAXES -- Income taxes of $151.8 million increased by $44.5 million from
1995 levels due to higher income before taxes, a $22.3 million decrease in
Section 29 tax credits, a $3.0 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).
YEAR ENDED DECEMBER 31, 1995 COMPARED TO YEAR ENDED DECEMBER 31, 1994
SELECTED FINANCIAL DATA
YEARS ENDED
DECEMBER 31,
----------------------
1994 1995
--------- ---------
(MILLIONS OF DOLLARS)
Total operating revenues.................................... $1,332.9 $1,476.7
Total operating expenses.................................... 981.6 1,006.6
Operating income............................................ 351.3 470.1
Net income.................................................. 390.0 350.7
The Company reported net income of $350.7 million for the year ended
December 31, 1995, down by $39.3 million from $390 million in 1994. The decrease
resulted from the absence of a $100 million after-tax gain on the sale of oil
and gas properties in Wilmington, California, in 1994, partially offset by the
$78.5 million after-tax gain from the Columbia settlement in 1995. Excluding the
1994 Wilmington sale and the 1995 Columbia settlement, 1995 net income would
have been $17.8 million lower than 1994 net income, primarily reflecting
additional general and administrative and interest expense incurred in the
fourth quarter of 1995 attributable to becoming a stand-alone public company.
Total operating revenues increased by $143.8 million (11%) to $1,476.7
million in 1995 as the pre-tax gain of $122.5 million from the Columbia
bankruptcy settlement and increased plants, pipelines and marketing revenues of
$90.8 million were offset partially by decreases in revenues from producing
properties ($32.4 million), other oil and gas revenues ($32.1 million) and
minerals revenues ($5 million). Operating expenses increased by $25.0 million to
$1,006.6 million reflecting higher plants, pipelines and marketing costs ($38.2
million), depreciation, depletion and amortization expenses ($32.2 million) and
general and administrative costs ($10.3 million), partially offset by lower
production costs ($41.8 million) and exploration expenses ($18.2 million).
Operating income increased by $118.8 million (34%) to $470.1 million. Excluding
the Columbia settlement, 1995 operating income would have been $3.7 million
lower than 1994.
21
24
OIL AND GAS OPERATIONS
Operating Revenues
OPERATING REVENUES -- OIL AND GAS OPERATIONS
YEARS ENDED
DECEMBER 31,
----------------------
1994 1995
--------- ---------
(MILLIONS OF DOLLARS)
Producing properties.................... $886.0 $853.6
Plants, pipelines and marketing......... 249.1 339.9
Other oil and gas revenues.............. 76.5 166.9
Producing property revenues decreased by $32.4 million (4%) to $853.6
million. Production volumes increased by 124.8 MMcfed (10%) to add $65.5 million
in revenues; however, this improvement was more than offset by lower prices
which reduced revenues by $90.8 million.
YEARS ENDED DECEMBER 31,
-----------------------------------
1994 1995 1994 1995
------- ------- ------ ------
(WITHOUT HEDGING) (WITH HEDGING)
Average product price realizations -- producing
properties:
Natural gas (per Mcf)............................ $ 1.69 $ 1.30 $ 1.82 $ 1.42
Natural gas liquids (per Bbl).................... 7.86 8.14 7.86 8.14
Crude oil (per Bbl).............................. 14.34 16.35 14.34 16.08
Average (per Mcfe)............................... 1.87 1.64 1.95 1.71
YEARS ENDED
DECEMBER 31,
--------------------
1994 1995
-------- --------
Production volumes -- producing properties:
Natural gas (MMcfd)....................................... 754.8 915.6
Natural gas liquids (MBbld)............................... 18.8 23.1
Crude oil (MBbld)......................................... 63.1 52.8
Total (MMcfed)............................................ 1,246.2 1,371.0
Natural gas volumes increased by 160.8 MMcfd (21%) to 915.6 MMcfd. The
Austin Chalk accounted for 84.7 MMcfd of the increase. Crude oil volumes
declined by 10.3 MBbld (16%) to 52.8 MBbld. The Austin Chalk declined by 5.6
MBbld to 25.8 MBbld as a result of more emphasis on the gas prone deep portions
of the trend and the natural decline of older properties. The October 1994 sale
of Point Arguello, an offshore California heavy oil field, reduced crude
production by another 5.2 MBbld. NGL production from producing properties
increased by 4.3 MBbld (23%) to 23.1 MBbld. All business units showed
improvement with the majority of the increase coming from the Rockies (2.3
MBbld).
22
25
Plants, pipelines and marketing revenues increased by $90.8 million (36%)
to $339.9 million. Increased plant volumes of 24.4 MMcfed (12%) added $15.3
million in plant revenues, but lower prices reduced revenues by $10 million.
Plant revenues also benefitted from a $23.7 million improvement in other
revenues, stemming principally from higher processing and compression fees.
Marketing revenues increased by $17.3 million to $56.3 million in 1995,
primarily as a result of lower firm transportation costs and a rate refund
related to the Company's transportation agreement with Kern River Gas
Transmission Company (see Note 14 to the Consolidated Financial Statements).
Pipeline revenues increased by $44.5 million primarily as a result of the
start-up and expansion of pipelines in the Austin Chalk, West Texas and the
Rockies.
YEARS ENDED
DECEMBER 31,
----------------
1994 1995
------ ------
Average product price
realizations -- plants:
Natural gas (per Mcf)................. $ 1.81 $ 1.51
Natural gas liquids (per Bbl)......... 9.97 9.38
Average (per Mcfe).................... 1.67 1.56
Sales volumes -- plants:
Natural gas (MMcfd)................... 17.5 23.9
Natural gas liquids (MBbld)........... 31.2 34.2
Total (MMcfed)........................ 204.7 229.1
NGL volumes increased by 3 MBbld (10%) to 34.2 MBbld primarily due to the
expansion of the Company's two Ozona plants in West Texas. Natural gas volumes
were up by 6.4 MMcfd (37%) to 23.9 MMcfd primarily because of higher throughput
volumes associated with a full year of production at the Brookeland plant in the
Austin Chalk.
Other oil and gas revenues increased by $90.4 million in 1995 as a result
of the Columbia settlement ($122.5 million), partially offset by an $8.1 million
loss brought about by weakened correlation for natural gas hedges, lower gains
on property sales ($12.3 million), a decrease in recognition of deferred revenue
($8 million) reflecting lower preferential volumes distributed to an investor in
the Company's Section 29 Limited Partnership (see "Business -- Section 29 Tax
Credits") and the absence of a favorable 1994 market sharing settlement ($4.9
million).
Operating Expenses
OPERATING EXPENSES -- OIL AND GAS OPERATIONS
YEARS ENDED
DECEMBER 31,
----------------------
1994 1995
--------- ---------
(MILLIONS OF DOLLARS)
Production.............................. $252.3 $210.5
Exploration............................. 107.6 89.4
Plants, pipelines and marketing......... 150.8 189.0
Depreciation, depletion and
amortization.......................... 426.4 458.6
Production expenses decreased by $41.8 million (17%) to $210.5 million,
largely because of lower production taxes ($23.7 million) reflecting the
successful resolution of a production tax audit, lower product prices and tax
exemptions related to high cost gas wells. Production expenses excluding
production taxes decreased on a per unit basis from $0.39/Mcfe to $0.33/Mcfe in
1995 as the sale of several properties with relatively high operating costs
reduced lease costs by $8.7 million.
Exploration expenses decreased by $18.2 million to $89.4 million, primarily
due to a decrease in dry hole costs ($18.9 million) associated with a reduction
in exploratory drilling. Expenditures for seismic data were $4 million higher
than in 1994.
23
26
Operating expenses for plants, pipelines and marketing were up by $38.2
million (25%) to $189.0 million principally due to expenses from the start-up
and expansion of additional gas value chain assets, partially offset by lower
gas plant expenses.
Depreciation, depletion and amortization increased by $32.2 million (8%) to
$458.6 million as a result of higher production and a higher asset base in
plants. On a per unit basis for producing properties, depreciation, depletion
and amortization expense decreased by $0.01/Mcfe from $0.82/Mcfe to $0.81/Mcfe.
Total Oil and Gas Operating Income
Total oil and gas operating income increased by $137.9 million to $415.5
million in 1995, primarily reflecting the $122.5 million pre-tax gain from the
Columbia bankruptcy settlement.
MINERALS -- Minerals revenues declined by $5 million to $116.3 million, largely
due to lower coal royalties associated with fewer tons mined from the Company's
leases. Minerals expenses were up by $4.3 million. As a result, Minerals
operating income declined by $9.2 million.
GENERAL AND ADMINISTRATIVE EXPENSES -- General and administrative expenses
increased by $10.3 million in 1995 to $50.3 million principally reflecting
nonrecurring costs associated with the Offering, increased costs associated with
being a stand-alone public company and costs of converting to new information
and accounting systems. See Note 2 to the Consolidated Financial Statements for
pro forma income information.
INTEREST AND OTHER INCOME -- Interest and other income declined by $181.5
million to a $12.1 million expense primarily reflecting the absence of the
$159.2 million pre-tax gain recorded on the sale of the Wilmington field in 1994
and a $14.5 million increase in interest expense in 1995 associated with debt
incurred at the time of the Offering.
INCOME TAXES -- Income taxes decreased by $23.4 million in 1995 because of lower
income before taxes, primarily reflecting the difference between the gain on the
sale of the Wilmington field ($159.2 million) in 1994 and the gain on the
Columbia settlement ($122.5 million) in 1995 and favorable 1995 tax adjustments
totaling $22.2 million. The effective tax rate for 1995, excluding such
favorable tax adjustments, would have been 28.3% (including $37.9 million of
Section 29 tax credits) compared with 25.1% for 1994 (including $52.2 million of
Section 29 tax credits).
LIQUIDITY AND CAPITAL RESOURCES
Cash provided by operations for 1996 was $990.4 million, up by $161 million
from 1995. The increase principally relates to increases in producing property
revenues net of production costs, improvements in cash margins from plants,
pipelines and marketing, higher distributed equity income primarily from Black
Butte Coal Company ("Black Butte") and favorable changes in working capital.
These increases were partially offset by the absence of the 1995 Columbia
bankruptcy settlement, increased payments for interest and income taxes and, to
a lesser extent, increased general and administrative costs associated with
being a stand-alone public company.
The Company expects to increase its oil and gas sales volumes in 1997 while
growing its reserves. Sales volume growth is anticipated primarily in the Gulf
Onshore/Offshore, Austin Chalk and West Texas. The Company expects to remain one
of the most active drillers in the United States in 1997 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, third party
pipeline expansions which will increase gas transportation capacity from Wyoming
by approximately 395 MMcfd should be in service in 1997. This new capacity
should enable Rockies gas to be shipped to higher-price markets in the future.
The Company owns a nonoperating 50% interest in Black Butte, a partnership
which operates a surface coal mine complex in southwestern Wyoming. During 1996,
Black Butte's sales to its largest customer under an amended coal supply
contract accounted for $54.8 million, or 10%, of the Company's consolidated
operating income. Operating income from this amended contract is expected to be
relatively constant through the end of 2001, when the financially beneficial
terms of this agreement will terminate. Although Black Butte
24
27
continues to seek new buyers for its low-sulfur coal, its mining costs are
considerably higher than the mining costs for competing supplies. The Company
does not expect to be able to replace the operating income it receives currently
under the amended contract with incremental coal sales.
Capital spending for 1996 of $880.3 million was up by $193.9 million (28%)
compared to $686.4 million for 1995. The Company's ability to maintain and
improve its operating income and cash flow is dependent, among other things,
upon continued capital spending. A summary of capital expenditures for 1996
compared to 1995 is as follows:
YEARS ENDED
DECEMBER 31,
----------------------
1995 1996
--------- ---------
(MILLIONS OF DOLLARS)
Producing properties:
Production............................ $382.2 $429.5
Exploration........................... 95.2 237.5
Property acquisitions................. 100.5 85.7
------ ------
Total producing properties.... 577.9 752.7
Plants, pipelines and marketing......... 106.5 118.1
Minerals and other...................... 2.0 9.5
------ ------
Total......................... $686.4 $880.3
====== ======
Producing property capital spending was up by $174.8 million (30%) as a
result of higher lease acquisition costs of $114.8 million primarily in the
Austin Chalk ($63.1 million), East/South Texas ($33.3 million) and North and
South Dakota ($13.7 million), and increased exploratory and development drilling
($77.2 million). Drilling accounted for $468.2 million (53%) of capital
expenditures, with $207.8 million (44%) in the Austin Chalk. Property
acquisitions totaling $85.7 million were completed in 1996 compared to $100.5
million in 1995.
The Company expects to increase its level of capital spending in 1997 to
over $1.0 billion. Spending is expected to focus on exploration and development
activities in the Austin Chalk business unit, drilling in the Gulf
Onshore/Offshore and exploration and development in East/South Texas as well as
gas value chain assets. The Company plans to complete construction of the
Masters Creek gas plant to facilitate development of the Louisiana Extension of
the Austin Chalk, expand the Patrick Draw plant in the Rockies from 30 MMcfd of
capacity to 120 MMcfd and add a fifth gas processing plant at its East Texas
plant complex. The Company's capital spending programs may be adjusted as
business and operating conditions change.
In addition, as a result of continued increase in the worldwide demand for
soda ash, the Company, along with its partner Oriental Chemical Industries,
Inc., 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. The Company's share of expansion costs is expected to be funded
primarily with partnership debt.
25
28
The Company restructured its debt portfolio in 1996, refinancing its
indebtedness to UPC with a combination of long-term fixed-rate notes and
debentures and short-term commercial paper. As of December 31, 1995 and 1996,
the total capitalization of the Company was as follows:
AS OF DECEMBER 31,
----------------------
1995 1996
--------- ---------
(MILLIONS OF DOLLARS)
Short-term debt
Note payable to Union Pacific
Corporation........................ $ 650.0 $ --
Advances (to) Union Pacific
Corporation........................ (82.2) --
-------- --------
Total short-term debt......... 567.8 --
-------- --------
Long-term debt
Bank credit agreement................. 68.0 --
Commercial paper, net................. -- 99.6
7% Notes due 2006..................... -- 200.0
7.5% Debentures due 2026.............. -- 200.0
7.5% Debentures due 2096.............. -- 150.0
Tax exempt revenue bonds.............. 33.5 24.0
Discount on notes and debentures...... -- (2.7)
-------- --------
Total long-term debt.......... 101.5 670.9
-------- --------
Shareholders' equity.................... 1,312.4 1,514.3
-------- --------
Total capitalization.......... $1,981.7 $2,185.2
======== ========
Debt to total capitalization............ 33.8% 30.7%
======== ========
In October 1996, the Company issued $200 million of 7% Notes due 2006 and
$200 million of 7.5% Debentures due 2026. In November 1996, the Company issued
$150 million of 7.5% Debentures due 2096. Proceeds were used, together with
proceeds from the issuance of commercial paper, to repay the Company's note
payable to UPC and for general corporate purposes. None of the Company's Notes
and Debentures are redeemable prior to maturity and none are subject to any
sinking fund requirements. In addition, the Company has filed a Form S-3
Registration Statement with the Securities and Exchange Commission which would
permit the Company to offer up to $900 million in debt and equity securities
upon the effectiveness of such Registration Statement.
The Company has a $600 million revolving credit agreement that expires in
August 2001. Borrowings under the agreement, 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 .06% to .15% also depending
on the Company's senior debt rating. The agreement contains covenants which
limit the ratio of debt to the sum of debt and shareholders' equity of the
Company to 65% and which require the combined EBITDAX (the sum of operating
income; depreciation, depletion and amortization; and exploration expenses) of
the Company's Principal Operating Subsidiaries (as defined in the agreement) to
be at least 80% of the Company's consolidated EBITDAX. The agreement also
imposes 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,
1996, there were no borrowings outstanding under this credit facility although
borrowing capacity is reduced by outstanding commercial paper. The Company had
the capacity to borrow $500 million under such credit facility as of December
31, 1996.
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 continued issuance of commercial paper and/or
26
29
through new long-term financings, or by using its currently available long-term
credit facility if alternative financing is not available.
The Company paid cash dividends of $49.8 million in 1996, which represents
a $0.05 per share quarterly cash dividend 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 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 believes that, following the 1996 refinancing of its debt, cash
from operations and additional available financing will enable it to fund its
capital expenditures, dividends and working capital requirements for the
foreseeable future.
OTHER MATTERS
PRICE RISK MANAGEMENT
The Company is principally a natural gas company, as natural gas and
natural gas liquids made up 82% of the Company's production in 1996. Natural gas
and, to a lesser degree, crude oil and natural gas liquids prices are influenced
by seasonal factors, natural gas transportation and storage infrastructure,
imports, political and regulatory developments and competition from other
sources of energy, and have been volatile over the last three years. Final
prices for prompt month natural gas contracts traded on the New York Mercantile
Exchange ("NYMEX") for delivery of gas at Henry Hub, Louisiana, during the
period from January 1, 1994 to December 31, 1996, have ranged from $1.39/Mcf to
$3.90/Mcf. Cash prices received by the Company in its specific producing areas
have exhibited similar volatility during this same period.
Changes in sales prices received for production directly affect the
Company's determination to proceed with the exploration for and development of
natural gas and crude oil and the quantity of proved reserves. Its revenues,
profitability and cash flow are substantially dependent upon prevailing prices
for its hydrocarbon product. Based upon the results of operations for the year
ended December 31, 1996, and excluding the effect of the Company's hedging
program, a change of $0.10/Mcf in the average price of natural gas, a change of
$1.00/Bbl in the average price of natural gas liquids and a change of $1.00/Bbl
in the average price of crude oil throughout such period would have resulted in
approximate changes in net income of $23 million, $15 million and $11 million,
respectively.
The Company uses hydrocarbon-based derivative financial instruments from
time to time to reduce risks associated with hydrocarbon price volatility. While
the use of these hedging arrangements may limit the downside risk of adverse
price movements, it may also limit future gains from favorable movements.
Hedging generally is accomplished pursuant to exchange-traded futures contracts
or master swap agreements based on standard forms. Hedging gains and losses are
deferred and recognized at delivery of the commodity. The Company does not hold
or issue derivative financial instruments for trading purposes and does not
hedge any significant amount of production beyond a 24-month time frame. The
Company also enters into long-term fixed price sales agreements for physical
deliveries of natural gas. Such long-term commitments are not reflected in the
Company's Consolidated Statements of Financial Position.
The Company had certain financial and fixed price sales contracts in place
at December 31, 1996 (see Note 5 to the Consolidated Financial Statements). The
total unrecognized mark-to-market present value gain related to such contracts
at December 31, 1996 was $30.5 million, consisting of a $26.4 million net gain
on contracts for physical delivery and a $4.1 million net gain on financial
contracts. Unrecognized mark-to-market gains or losses were determined based
upon current market value, as quoted by recognized dealers, assuming a round lot
transaction and using a mid-market convention without regard to market
liquidity.
In connection with its futures contract hedging activity, the Company is
required to deposit monies with NYMEX, representing cash requirements for
contract margins and deposits for unrealized losses on open contracts. Such
deposits are included in other current assets in the Company's Consolidated
Statements of
27
30
Financial Position. At December 31, 1996, the Company had margin requirements
totaling $44.7 million, which had been met with cash deposits of $30.9 million
and unrealized gains on open contracts of $13.8 million.
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 1994 and 1995, revenues were $36 million and $27 million higher,
respectively, while during 1996, revenues were $52 million lower as a result of
hedging activities.
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
10 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, 1996, long and short-term liabilities totaling $94.3
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 $44.2 million for the obligation to
participate in the remediation of the Wilmington field properties. Cost
estimates were based on information available for each site, financial viability
of other Potentially Responsible Parties ("PRPs") and existing technology, laws
and regulations. The Company believes that it has accrued adequately for its
share of costs at sites subject to joint and several 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 $6.2 million in 1995 and $11.4
million in 1996. In 1997, the Company anticipates spending a total of $20
million for remediation, control and prevention, including $10 million relating
to the Wilmington properties. The majority of the December 31, 1996 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.
28
31
FORWARD LOOKING INFORMATION
Certain information included in this report contains, and other materials
filed or to be filed by the Company with the Securities and Exchange Commission
(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 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.
29
32
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
PAGE
----
Responsibilities for Financial
Statements............................ 31
Independent Auditors' Report............ 32
Consolidated Statements of Income for
the Years Ended December 31, 1994,
1995 and 1996......................... 33
Consolidated Statements of Financial
Position as of December 31, 1995 and
1996.................................. 34
Consolidated Statements of Cash Flows
for the Years Ended December 31, 1994,
1995 and 1996......................... 35
Consolidated Statements of Changes in
Shareholders' Equity for the Years
Ended December 31, 1994, 1995 and
1996.................................. 36
Business Segment Information............ 37
Notes to Consolidated Financial
Statements............................ 38
Supplementary Information (Unaudited)... 57
30
33
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
JOHN E. JACKSON
Controller and Chief Accounting Officer
31
34
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, 1995 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, 1996. 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, 1995 and 1996, and the results of its operations and its cash flows
for each of the three years in the period ended December 31, 1996 in conformity
with generally accepted accounting principles.
DELOITTE & TOUCHE LLP
Fort Worth, Texas
January 29, 1997
32
35
UNION PACIFIC RESOURCES GROUP INC.
CONSOLIDATED STATEMENTS OF INCOME
FOR THE YEARS ENDED DECEMBER 31, 1994, 1995 AND 1996
1994 1995 1996
-------- -------- --------
(MILLIONS, EXCEPT PER SHARE
AMOUNTS)
Operating revenues: (Note 5)
Oil and gas operations:
Producing properties................................... $ 886.0 $ 853.6 $1,133.3
Plants, pipelines and marketing........................ 249.1 339.9 503.8
Other oil and gas revenues (Note 4).................... 76.5 166.9 65.0
-------- -------- --------
Total oil and gas operations...................... 1,211.6 1,360.4 1,702.1
Minerals (Note 12)........................................ 121.3 116.3 128.9
-------- -------- --------
Total operating revenues.......................... 1,332.9 1,476.7 1,831.0
-------- -------- --------
Operating expenses:
Production................................................ 252.3 210.5 259.5
Exploration............................................... 107.6 89.4 144.6
Plants, pipelines and marketing........................... 150.8 189.0 290.0
Minerals (Note 12)........................................ 4.5 8.8 8.0
Depreciation, depletion and amortization.................. 426.4 458.6 533.9
General and administrative................................ 40.0 50.3 68.4
-------- -------- --------
Total operating expenses.......................... 981.6 1,006.6 1,304.4
-------- -------- --------
Operating income............................................ 351.3 470.1 526.6
Other income -- net (Notes 3 and 4)......................... 174.0 7.0 (3.4)
Interest expense -- net (Notes 3 and 8)..................... (4.6) (19.1) (50.6)
-------- -------- --------
Income before income taxes.................................. 520.7 458.0 472.6
Income taxes (Note 7)....................................... (130.7) (107.3) (151.8)
-------- -------- --------
Net income (Note 2)......................................... $ 390.0 $ 350.7 $ 320.8
======== ======== ========
Earnings per share (see Significant Accounting
Policies -- Earnings Per Share)........................... $ 1.28
Weighted average shares outstanding......................... 250.1
Cash dividends per share.................................... $ 0.20
The accompanying accounting policies and notes to the consolidated
financial statements are an integral part of these statements.
33
36
UNION PACIFIC RESOURCES GROUP INC.
CONSOLIDATED STATEMENTS OF FINANCIAL POSITION
AS OF DECEMBER 31, 1995 AND 1996
ASSETS
1995 1996
--------- ---------
(MILLIONS OF DOLLARS)
Current assets:
Cash and temporary investments............................ $ 27.6 $ 118.9
Accounts receivable (net of allowance for doubtful
accounts of $4.9 million in 1995 and $4.5 million in
1996).................................................. 240.1 351.6
Inventories............................................... 67.5 29.4
Other current assets...................................... 84.8 86.4
--------- ---------
Total current assets.............................. 420.0 586.3
--------- ---------
Properties: (Note 6)
Cost...................................................... 5,450.4 6,190.0
Accumulated depreciation, depletion and amortization...... (2,686.1) (3,217.6)
--------- ---------
Total properties.................................. 2,764.3 2,972.4
Intangible and other assets (Note 12)....................... 124.6 90.2
--------- ---------
Total assets...................................... $ 3,308.9 $ 3,648.9
========= =========
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable.......................................... $ 347.0 $ 407.4
Accrued taxes payable..................................... 87.4 134.1
Note payable to and advances from Union Pacific
Corporation -- net (Notes 3 and 8)..................... 567.8 --
Other current liabilities................................. 64.3 71.3
--------- ---------
Total current liabilities......................... 1,066.5 612.8
Long-term debt (Note 8)..................................... 101.5 670.9
Deferred income taxes (Note 7).............................. 438.5 434.7
Retiree benefits obligations (Note 10)...................... 73.1 151.4
Deferred revenues........................................... 26.4 4.9
Other long-term liabilities (Notes 12, 13, 14 and 15)....... 290.5 259.9
Shareholders' equity (see page 36).......................... 1,312.4 1,514.3
--------- ---------
Total liabilities and shareholders' equity........ $ 3,308.9 $ 3,648.9
========= =========
The accompanying accounting policies and notes to the consolidated
financial statements are an integral part of these statements.
34
37
UNION PACIFIC RESOURCES GROUP INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED DECEMBER 31, 1994, 1995 AND 1996
1994 1995 1996
-------- --------- -------
(MILLIONS OF DOLLARS)
Cash provided by operations:
Net income................................................ $ 390.0 $ 350.7 $ 320.8
Non-cash charges to income:
Depreciation, depletion and amortization............... 426.4 458.6 533.9
Deferred income taxes (Note 7)......................... 174.4 (18.3) 37.0
Other non-cash charges (credits) -- net................ (139.2) (65.8) 8.0
Exploratory expenditures.................................. 45.8 36.0 51.6
Changes in current assets and liabilities................. (76.4) 68.2 39.1
-------- --------- -------
Cash provided by operations....................... 821.0 829.4 990.4
-------- --------- -------
Investing activities:
Capital and exploratory expenditures (Notes 4 and 16)..... (1,389.3) (686.4) (880.3)
Proceeds from sales of assets (Note 4).................... 331.0 111.1 30.2
Other investing activities -- net......................... 0.5 (7.5) (2.8)
-------- --------- -------
Cash (used) by investing activities............... (1,057.8) (582.8) (852.9)
-------- --------- -------
Financing activities:
Dividends paid (Note 2)................................... (148.0) (1,713.9) (49.8)
Debt financings (Note 8).................................. 21.2 68.0 547.3
Debt repaid............................................... (18.3) (47.4) (77.5)
Proceeds from initial public offering (Note 2)............ -- 843.9 --
Advances from (to) Union Pacific Corporation (Notes 2 and
3)..................................................... 399.6 627.1 (567.8)
Other financings -- net (Note 8).......................... (22.3) (3.4) 101.6
-------- --------- -------
Cash provided (used) by financing activities...... 232.2 (225.7) (46.2)
-------- --------- -------
Net change in cash and temporary investments................ (4.6) 20.9 91.3
Balance at beginning of year................................ 11.3 6.7 27.6
-------- --------- -------
Balance at end of year...................................... $ 6.7 $ 27.6 $ 118.9
======== ========= =======
Changes in current assets and liabilities:
Accounts receivable....................................... $ 33.8 $ 4.0 $(111.5)
Inventories............................................... (34.2) (9.2) 38.1
Note receivable........................................... (62.7) 62.7 (0.6)
Federal income tax receivable............................. (44.1) 44.1 --
Other current assets...................................... (25.2) (27.1) (1.0)
Accounts payable.......................................... 18.0 10.0 60.4
Accrued taxes payable..................................... (5.6) 22.4 46.7
Short-term debt........................................... 10.9 (43.2) --
Other current liabilities................................. 32.7 4.5 7.0
-------- --------- -------
Total............................................. $ (76.4) $ 68.2 $ 39.1
======== ========= =======
Supplemental cash flow disclosure:
Interest paid............................................. $ 4.6 $ 20.0 $ 43.4
Income taxes paid......................................... 14.9 29.7 79.0
The accompanying accounting policies and notes to the consolidated
financial statements are an integral part of these statements.
35
38
UNION PACIFIC RESOURCES GROUP INC.
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS' EQUITY
FOR THE YEARS ENDED DECEMBER 31, 1994, 1995 AND 1996
1994 1995 1996
-------- -------- --------
(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 $ 4.5 $ --
Asset restructuring (Note 2).............................. -- (4.5) --
-------- -------- --------
Balance at end of year.................................... 4.5 -- --
-------- -------- --------
Common stock, no par value; authorized 400,000,000 shares;
249,248,603 shares issued and outstanding at December 31,
1995 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.............................. 421.2 421.2 860.2
Asset restructuring (Note 2).............................. -- (421.2) --
Initial public offering (Note 2).......................... -- 843.9 --
Conversion, award and appreciation of retention shares
(Note 11).............................................. -- 9.9 15.9
Other..................................................... -- 6.4 (3.2)
-------- -------- --------
Balance at end of year.................................... 421.2 860.2 872.9
-------- -------- --------
Retained earnings:
Balance at beginning of year.............................. 1,180.6 1,422.6 472.9
Net income................................................ 390.0 350.7 320.8
-------- -------- --------
Total............................................. 1,570.6 1,773.3 793.7
Dividends declared on common stock (Note 2)............... (148.0) (1,726.3) (49.8)
Pension asset adjustment (Note 10)........................ -- -- (69.5)
Asset restructuring (Note 2).............................. -- 425.9 --
-------- -------- --------
Balance at end of year.................................... 1,422.6 472.9 674.4
-------- -------- --------
Unearned compensation:
Balance at beginning of year.............................. -- -- (9.2)
Conversion, award, appreciation and amortization of
retention shares -- net (Note 11)...................... -- (9.2) (8.3)
-------- -------- --------
Balance at end of year.................................... -- (9.2) (17.5)
-------- -------- --------
Deferred foreign exchange adjustment:
Balance at beginning of year.............................. (10.2) (13.4) (11.5)
Foreign currency translation adjustment................... (3.2) 1.9 (0.5)
-------- -------- --------
Balance at end of year.................................... (13.4) (11.5) (12.0)
-------- -------- --------
Treasury stock, at cost; 154,417 shares at December 31, 1996
Balance at end of year.................................... -- -- (3.5)
-------- -------- --------
Total shareholders' equity........................ $1,834.9 $1,312.4 $1,514.3
======== ======== ========
The accompanying accounting policies and notes to the consolidated
financial statements are an integral part of these statements.
36
39
UNION PACIFIC RESOURCES GROUP INC.
BUSINESS SEGMENT INFORMATION
FOR THE YEARS ENDED DECEMBER 31, 1994, 1995 AND 1996
1994 1995 1996
-------- -------- --------
(MILLIONS OF DOLLARS)
Operating revenues:
Oil and gas............................................... $1,211.6 $1,360.4 $1,702.1
Minerals.................................................. 121.3 116.3 128.9
-------- -------- --------
Total............................................. $1,332.9 $1,476.7 $1,831.0
======== ======== ========
Depreciation, depletion and amortization:
Oil and gas............................................... $ 423.3 $ 456.0 $ 529.2
Minerals.................................................. 0.5 0.4 0.9
Corporate................................................. 2.6 2.2 3.8
-------- -------- --------
Total............................................. $ 426.4 $ 458.6 $ 533.9
======== ======== ========
Other operating expenses:
Oil and gas............................................... $ 510.7 $ 488.9 $ 694.1
Minerals.................................................. 4.5 8.8 8.0
Corporate................................................. 40.0 50.3 68.4
-------- -------- --------
Total............................................. $ 555.2 $ 548.0 $ 770.5
======== ======== ========
Operating income:
Oil and gas............................................... $ 277.6 $ 415.5 $ 478.8
Minerals.................................................. 116.3 107.1 120.0
Corporate................................................. (42.6) (52.5) (72.2)
-------- -------- --------
Total............................................. $ 351.3 $ 470.1 $ 526.6
======== ======== ========
Capital and exploratory expenditures:
Oil and gas............................................... $1,387.3 $ 684.2 $ 870.8
Minerals.................................................. 0.2 0.2 0.8
Corporate................................................. 1.8 2.0 8.7
-------- -------- --------
Total............................................. $1,389.3 $ 686.4 $ 880.3
======== ======== ========
Assets:
Oil and gas............................................... $2,815.3 $2,985.7 $3,331.0
Minerals.................................................. 26.8 29.2 23.5
Corporate(a).............................................. 404.9 294.0 294.4
-------- -------- --------
Total............................................. $3,247.0 $3,308.9 $3,648.9
======== ======== ========
- - ---------------
(a) Includes items such as unallocated working capital and intangible and other
assets.
This information should be read in conjunction with the accompanying
accounting policies and notes to the consolidated financial statements.
37
40
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, including
its principal operating subsidiary Union Pacific Resources Company ("UPRC").
These operations are hereinafter referred to collectively as the "Company." The
Company accounts for investments in affiliated companies (20% to 50% owned) on
the equity method of accounting and consolidates its proportionate share of oil
and gas ventures. All material 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, 1995 and 1996 was $13.1 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.
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 is reviewed periodically to determine whether any potential
impairment exists.
38
41
UNION PACIFIC RESOURCES GROUP INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
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 plants, pipelines and marketing revenues is
recorded net of the cost of hydrocarbons purchased.
Hedging Transactions. The Company uses hydrocarbon-based derivative
financial instruments from time to time to reduce risks associated with
hydrocarbon price volatility. Gains and losses from hedging transactions
generally are recognized at delivery of the commodity. However, when correlation
between the derivative contract price and the price of the underlying commodity
falls below 80%, affected derivative positions are marked to market, with the
resulting gain or loss recognized immediately in income (see Note 5).
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 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 Company 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. Earnings per share for 1996 is based upon 250,077,716
weighted average common shares outstanding during the period, including shares
issuable upon exercise of outstanding stock options determined using the
treasury stock method.
Earnings per share for the years ended December 31, 1994 and 1995 have 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 earnings per share (see Note 2) and fourth quarter 1995 earnings per
share (see page 62) are based upon 249.7 million average common shares
outstanding during the period from completion of the Offering (hereinafter
defined) until December 31, 1995.
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 57).
Recently Issued Accounting Standards. The Accounting Standards Executive
Committee of the American Institute of Certified Public Accountants has adopted
Statement of Position 96-1, "Environmental Remediation Liabilities," which
provides guidance on the recognition, measurement, display and disclosure of
environmental remediation liabilities. The statement is effective for the
Company's 1997 fiscal year.
39
42
UNION PACIFIC RESOURCES GROUP INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Management has evaluated such statement and believes that it will not have a
material effect on the financial condition or results of operations of the
Company.
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 principally in the United States. The Company owns and
operates significant assets, in proximity to its principal producing properties,
dedicated to the gathering, processing and transportation 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.
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 are not directly comparable to results for the year ended December
31, 1996. The following pro forma information reflects
40
43
UNION PACIFIC RESOURCES GROUP INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
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, 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................................. $ 1.27
=======
Weighted average shares outstanding(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 $2.0 million of
pension expense representing one quarter of approximately $8.0 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 long-term debt and commercial
paper (see Note 8). Intercompany interest income related to amounts receivable
from UPC was $15.8 million and $9.6 million in 1994 and 1995, respectively,
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 $14.5 million in 1995 and $32.6 million in 1996 which is
included in interest expense in the Company's Consolidated Statements of Income.
41
44
UNION PACIFIC RESOURCES GROUP INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
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 1995 and 1996 related to such agreements were
$0.9 million and $2.7 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 has
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 1996, the Company reached settlements or took
default judgment with respect to a number of royalty owners named in the suit.
The Company also made a determination and payment of its severance tax
liability. As a result, in the fourth quarter of 1996, the Company recognized
$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).
Amax Oil & Gas, Inc. In March 1994, the Company acquired Amax Oil & Gas,
Inc. ("Amax") for $725 million. Amax's operations consisted principally of
natural gas producing properties and related processing and transportation
facilities, located primarily in western and southern Texas and Louisiana. At
the date of acquisition, these properties included interests in 14 major fields,
encompassing over 500,000 acres and approximately 2,000 producing wells. The
Company initially recorded 550 Bcfe of proved reserves related to the Amax
acquisition.
Wilmington Field Sale. 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. Proceeds from the sale consisted of $280 million in cash
and two interest-bearing notes of $62.5 million each which subsequently have
been collected. The Wilmington sale resulted in a $159.2 million pre-tax ($100
million after-tax) gain. Such pre-tax gain is included in other income in the
Company's 1994 Consolidated Statement of Income. The sale of the Wilmington
hydrocarbon reserves (approximately 3% of the Company's year end 1993 proved
reserves) has not significantly affected the Company's ongoing operating
results.
As part of the Wilmington sales agreement, the Company agreed to
participate with the Port of Long Beach in funding environmental remediation and
site preparation, as specified by the Port of Long Beach, up to a maximum of
$105.5 million. As a result, the determination of the gain on the sale of the
Wilmington properties included provisions of $50.5 million for future
environmental costs and $55.0 million for future site preparation costs ($97.9
million in total remaining at December 31, 1996) categorized as other current
and long-term liabilities (see Notes 13 and 15). The majority of cash outlays
for these liabilities is expected to occur over the next five years.
42
45
UNION PACIFIC RESOURCES GROUP INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
5. FINANCIAL INSTRUMENTS
Hedging. The Company uses hydrocarbon-based derivative financial
instruments from time to time to reduce risks associated with hydrocarbon price
volatility. While the use of these hedging arrangements may limit the downside
risk of adverse price movements, it may also limit future gains from favorable
movements. Hedging generally is accomplished pursuant to exchange-traded futures
contracts or master swap agreements based on standard forms. Hedging gains and
losses are deferred and recognized at delivery of the commodity. The Company
does not hold or issue derivative financial instruments for trading purposes and
does not hedge any significant amount of production beyond a 24-month time
frame. In connection with its futures contract hedging activity, the Company is
required to deposit monies with the New York Mercantile Exchange ("NYMEX"),
representing cash requirements for contract margins and deposits for unrealized
losses on open contracts. Such deposits are included in other current assets in
the Company's Consolidated Statements of Financial Position. At December 31,
1996, the Company had margin requirements totaling $44.7 million, which were met
with cash deposits of $30.9 million and unrealized gains on open contracts of
$13.8 million. Deferred losses on other derivative positions, primarily
representing January hedges deferred as of December 31, were $17.1 million at
December 31, 1996, and are included in other current assets in the Company's
Consolidated Statement of Financial Position.
The Company addresses market risk by selecting hydrocarbon-based derivative
financial instruments whose historical value fluctuations correlate with those
of the item being hedged, so that gains or losses on the financial instruments
will be substantially offset by gains or losses on the hedged item. Basis risk,
which arises from differences between wellhead prices in the Company's specific
producing locations and the underlying NYMEX prices contained in the financial
instruments, is managed by using basis swaps in combination with futures
contracts and price swaps. In December 1995, the Company recorded an $8.1
million pre-tax ($5.3 million after-tax) charge relating to loss of correlation
between NYMEX prices and the actual wellhead prices ultimately received by the
Company for a portion of its first quarter 1996 hedged natural gas production.
Such loss was included as a reduction in other oil and gas revenues in the
Company's 1995 Consolidated Statement of Income.
The Company is exposed to credit losses in the event of nonperformance by
its counterparties. Credit risk related to hedging activities is managed by
requiring that counterparties meet certain minimum credit standards and by
conducting mark-to-market analysis to review potential exposure and determine if
collateral is required. At December 31, 1996, the largest credit risk associated
with any of the Company's counterparties, representing the fair value of
contracts with a positive net fair value at the reporting date, was
approximately $4.0 million. The Company anticipates that its counterparties,
which consist principally of organized exchanges, major financial institutions
and large dealers, will be able to satisfy their obligations related to the
Company's contracts.
At December 31, 1996, the Company had near-term futures contracts and price
swaps for February through December 1997 with respect to natural gas volumes of
696 MMcfd at $2.06/Mcf. The unrecognized mark-to-market gain associated with
such contracts, representing the price the Company would receive to close such
contracts at the reporting date, was $23.7 million. With respect to crude oil,
at December 31, 1996, the Company had near-term NYMEX-related contracts for
January through December 1997 with respect to crude oil volumes of 20 MBbld at
$20.23/Bbl, with an unrecognized mark-to-market loss of $19.8 million.
Additionally, the Company has simultaneously purchased commodity put options
(floor) and sold commodity call options (ceiling), the combination of which has
the effect of establishing a minimum and maximum price the Company would receive
for its crude oil. At December 31, 1996, the Company had established a floor of
$19.17/Bbl (including net premium paid) and a ceiling of $24.67/Bbl (including
net premium paid) with respect to 25.0 MBbld of crude oil for January through
December 1997. The Company will continue to receive current market prices for
its crude oil as long as market prices remain within the range established by
the floor and the ceiling. The fair value of such options at December 31, 1996
was a negative
43
46
UNION PACIFIC RESOURCES GROUP INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
$1.8 million, representing the net cost to repurchase the options given current
market prices using an option pricing model. Net option premiums, which are
included in other current assets in the Company's Consolidated Statements of
Financial Position, are deferred and recognized in income as the related volumes
are produced.
Also at December 31, 1996, the Company had near-term futures contracts and
price swaps for January through December 1998 with respect to natural gas
volumes of 37 MMcfd at $2.21/Mcf. The unrecognized mark-to-market gain
associated with such contracts was $0.7 million.
The Company also enters into long-term fixed price sales agreements for
physical deliveries of natural gas, and at December 31, 1996, had outstanding
contracts relating to 81.5 Bcf of natural gas for periods through December 31,
2008. Average annual commitments during this period would have comprised no more
than 2% of the Company's 1996 natural gas sales volumes. Such long-term
commitments are not reflected in the Company's Consolidated Statements of
Financial Position. The Company's marketing subsidiary, Union Pacific Fuels,
Inc. ("UP Fuels"), enters into long-term financial contracts that, in
combination with these long-term fixed price sales agreements, secure a margin
on the corresponding volume positions. At December 31, 1996, long-term fixed
price sales commitments for which corresponding financial positions had not been
entered into totaled 69.8 Bcf at an average price of $2.95/Mcf, with a positive
fair value of $26.6 million. The remaining commitments for 11.7 Bcf had been
offset with financial contracts for similar volumes. The unrecognized
mark-to-market present value related to such hedged commitments at December 31,
1996 comprises a $0.2 million loss on the long-term fixed price sales
commitments and a $1.3 million gain on the corresponding financial contracts.
At December 31, 1996, the Company had a total unrecognized mark-to-market
present value gain of $30.5 million related to the financial and fixed price
sales contracts described above. Such gain comprises a $26.4 million net gain on
contracts for physical delivery and a $4.1 million net gain on financial
contracts. Unrecognized mark-to-market gains or losses were determined based
upon current market value, as quoted by recognized dealers, assuming a round lot
transaction and using a mid-market convention without regard to market
liquidity.
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 1994 and 1995, revenues were $36 million and $27 million higher,
respectively, while during 1996, revenues were $52 million lower as a result of
hedging activities.
Fair Value of Financial Instruments. At December 31, 1996, 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.
44
47
UNION PACIFIC RESOURCES GROUP INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
6. PROPERTIES
Major property classifications as of December 31 are as follows:
1995 1996
-------- --------
(MILLIONS OF DOLLARS)
Producing properties........................................ $3,873.7 $4,311.3
Non-producing properties.................................... 276.4 371.3
Plants, pipelines and equipment............................. 898.8 1,010.7
Construction in progress.................................... 254.4 348.8
Other....................................................... 147.1 147.9
-------- --------
Total............................................. $5,450.4 $6,190.0
======== ========
Accumulated depreciation, depletion and amortization by major property
classifications is as follows:
1995 1996
-------- --------
(MILLIONS OF DOLLARS)
Producing properties........................................ $2,196.5 $2,604.1
Non-producing properties.................................... 86.3 142.7
Plants, pipelines and equipment............................. 334.7 396.0
Other....................................................... 68.6 74.8
-------- --------
Total............................................. $2,686.1 $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 1996, the Company adjusted the net book value of such
properties to their fair value, determined using a discounted cash flow
approach, with a charge to operations of $34.4 million.
Fixed asset additions included capitalized interest of $0.9 million in
1994, $1.0 million in 1995 and $0.2 million in 1996.
7. INCOME TAXES
Components of income tax expense are as follows:
1994 1995 1996
------ ------ ------
(MILLIONS OF DOLLARS)
Current:
Federal............................................ $(41.4) $130.2 $105.8
State.............................................. (2.3) (4.6) 9.0
------ ------ ------
Total current................................. (43.7) 125.6 114.8
------ ------ ------
Deferred:
Federal............................................ 168.6 (20.8) 33.0
State.............................................. 5.8 2.5 4.0
------ ------ ------
Total deferred................................ 174.4 (18.3) 37.0
------ ------ ------
Total...................................... $130.7 $107.3 $151.8
====== ====== ======
45
48
UNION PACIFIC RESOURCES GROUP INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Deferred tax liabilities (assets) as of December 31 include the following:
1995 1996
-------- --------
(MILLIONS OF DOLLARS)
Excess tax over book items, including depreciation and
exploration costs......................................... $479.5 $561.0
State taxes -- net.......................................... 12.3 11.4
Long-term liabilities....................................... (51.3) (40.7)
Alternative minimum tax..................................... (37.7) (56.6)
Pension and other retirement benefits....................... (18.5) (60.0)
Other....................................................... 54.2 19.6
------ ------
Net deferred tax liability................................ $438.5 $434.7
====== ======
A reconciliation between statutory and effective tax rates is as follows:
1994 1995 1996
----- ---- ----
Statutory tax rate........................................ 35.0% 35.0% 35.0%
State taxes -- net........................................ 0.5 (0.3) 1.8
Section 29 tax credits.................................... (10.0) (8.3) (3.3)
Tax settlements........................................... -- (2.2) --
Other..................................................... (0.4) (0.8) (1.4)
----- ---- ----
Effective tax rate...................................... 25.1% 23.4% 32.1%
===== ==== ====
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 $52.2 million, $39.9 million and $15.6 million of Section 29 tax
credits in 1994, 1995 and 1996, respectively. The Federal tax law provides for
the use of these credits against regular Federal income tax liability.
Accordingly, the Company utilized on its tax returns $27.5 million of Section 29
tax credits in 1994 and anticipates the utilization of $15.6 million in 1996.
Section 29 tax credits of $18.8 million in 1995 increased the alternative
minimum tax credit and may be carried over and applied against regular tax
liability in future years.
All tax years prior to 1979 have been closed with the Internal Revenue
Service ("IRS"). 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 UPC's returns
for 1990 through 1994. The Company believes it has adequately provided for
Federal and state income taxes.
46
49
UNION PACIFIC RESOURCES GROUP INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
8. DEBT
Total debt as of December 31 is summarized below:
1995 1996
--------- ---------
(MILLIONS OF DOLLARS)
Note payable to and advances from UPC -- net, 8.5%, due
1996..................................................... $ 567.8 $ --
Commercial paper, net of discount, average of 5.7% at
December 31, 1996........................................ -- 99.6
Bank credit agreement, 6.1% LIBOR floating at December 31,
1995..................................................... 68.0 --
Notes, 7%, due 2006........................................ -- 200.0
Debentures, 7.5%, due 2026................................. -- 200.0
Debentures, 7.5%, due 2096................................. -- 150.0
Tax exempt revenue bonds, 4.15% to 4.25%, due 2003 through
2012..................................................... 33.5 24.0
Discount on notes and debentures........................... -- (2.7)
------- -------
Total debt....................................... 669.3 670.9
Less current portion............................. (567.8) --
------- -------
Total long-term debt............................. $ 101.5 $ 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 continued issuance of commercial paper and/or
through new long-term financings, or by using its currently available long-term
credit facility if alternative financing is not available.
The Company has a $600 million revolving credit agreement that expires in
August 2001. Borrowings under the agreement, 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 .06% to .15% also depending
on the Company's senior debt rating. The agreement contains covenants which
limit the ratio of debt to the sum of debt and shareholders' equity of the
Company to 65% and which require the combined EBITDAX (the sum of operating
income; depreciation, depletion and amortization; and exploration expenses) of
the Company's Principal Operating Subsidiaries (as defined in the agreement) to
be at least 80% of the Company's consolidated EBITDAX. The agreement also
imposes 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,
1996, there were no borrowings outstanding under this credit facility although
borrowing capacity is reduced by outstanding commercial paper. The Company had
the capacity to borrow $500 million under such credit facility as of December
31, 1996.
In October 1996, the Company issued $200 million of 7% Notes due 2006 and
$200 million of 7.5% Debentures due 2026. In November 1996, the Company issued
$150 million of 7.5% Debentures due 2096. Proceeds were used, together with
proceeds from the issuance of commercial paper, to repay the Company's note
payable to UPC and for general corporate purposes. None of the Company's Notes
and Debentures are redeemable prior to maturity and none are subject to any
sinking fund requirements. In addition, the Company has filed a Form S-3
Registration Statement with the Securities and Exchange Commission which would
permit the Company to offer up to $900 million in debt and equity securities
upon the effectiveness of such Registration Statement.
47
50
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 non-cancelable lease terms in excess of one year as of December 31,
1996, are as follows:
(MILLIONS OF DOLLARS)
---------------------
1997........................................................ $ 56.8
1998........................................................ 57.1
1999........................................................ 48.5
2000........................................................ 40.2
2001........................................................ 30.2
Later years................................................. 59.3
-------
Total minimum payments............................ $292.1
=======
Rent expense, net of sublease income, for operating leases with terms
exceeding one month was $33.8 million in 1994, $31.0 million in 1995 and $27.2
million in 1996. Sublease rentals for the next five years are $28.7 million in
1997, $28.4 million in 1998, $28.3 million in 1999, $28.1 million in 2000, $28.1
million in 2001 and $56.7 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 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:
1994 1995 1996
------ ------ ------
(MILLIONS OF DOLLARS)
Service cost -- benefits earned during the period........ $ 4.7 $ 5.3 $ 4.4
Interest on projected benefit obligation................. 13.1 14.4 13.3
Return on assets:
Actual (gain) loss..................................... 4.0 (49.5) (41.7)
Deferred gain (loss)................................... (22.9) 30.0 22.1
Net amortization costs................................... (2.2) (2.4) (3.7)
------ ------ ------
Net pension credit............................. $ (3.3) $ (2.2) $ (5.6)
====== ====== ======
The projected benefit obligation was determined using a discount rate of
7.25% in 1995 and 7.5% in 1996. The estimated rate of salary increase
approximated 5.25% in 1995 and 5.5% in 1996. The expected long-term rate of
return on plan assets was 8.0% in both years. The portion of the funded plan's
assets held in fixed-income and short-term securities was approximately 32% and
29% as of December 31, 1995 and 1996, respectively, with the remainder primarily
in equity securities.
48
51
UNION PACIFIC RESOURCES GROUP INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The funded status of the plans as of December 31 is as follows:
UNFUNDED
FUNDED SUPPLEMENTAL
PENSION PLAN PLAN
---------------- --------------
1995 1996 1995 1996
------ ------ ----- -----
(MILLIONS OF DOLLARS)
Plan assets at fair value............... $282.3 $221.3 $ -- $ --
------ ------ ----- -----
Actuarial present value of benefit
obligations:
Vested benefits....................... 156.4 152.9 2.8 4.5
Non-vested benefits................... 7.0 6.4 0.2 0.2
------ ------ ----- -----
Accumulated benefit obligation.......... 163.4 159.3 3.0 4.7
Additional benefits based on estimated
future
salaries........................... 29.2 17.4 5.5 2.5
------ ------ ----- -----
Projected benefit obligation............ 192.6 176.7 8.5 7.2
------ ------ ----- -----
Plan assets (over) under projected
benefit obligation.................... (89.7) (44.6) 8.5 7.2
Unamortized net transition asset
(obligation).......................... 23.6 21.0 (1.8) (1.1)
Unrecognized prior service cost......... (6.0) (5.2) (6.1) (3.8)
Unrecognized net gain (loss)............ 59.5 105.0 (3.4) (2.2)
Minimum liability....................... -- -- 5.8 4.6
------ ------ ----- -----
Pension liability (asset)..... $(12.6) $ 76.2 $ 3.0 $ 4.7
====== ====== ===== =====
In connection with the Distribution, pension assets related to UPC's funded
pension plan, in which the Company had participated, were allocated between UPC
and the Company, resulting in the elimination of the balance of net pension
assets and the creation of a December 31, 1996 funded pension liability of $76.2
million, as well as a net-of-tax charge to retained earnings of $69.5 million.
The Company has adopted a new pension plan with substantially the same terms as
those of the UPC pension plan. The additional cost to the Company associated
with the allocation of pension assets between UPC and the Company is expected to
be approximately $8 million annually.
Other Postretirement Benefits. Postretirement health and life insurance
benefits cost includes the following components:
1994 1995 1996
----- ----- -----
(MILLIONS OF DOLLARS)
Service cost -- benefits earned during
the period............................ $ 1.2 $ 1.2 $ 1.0
Interest costs on accumulated benefit
obligation............................ 3.7 4.3 3.4
Net amortization costs.................. (0.9) (1.5) (2.3)
----- ----- -----
Charge to operations.......... $ 4.0 $ 4.0 $ 2.1
===== ===== =====
49
52
UNION PACIFIC RESOURCES GROUP INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The liability for other postretirement benefit plans as of December 31 is
as follows:
1995 1996
----- -----
(MILLIONS OF
DOLLARS)
Accumulated postretirement benefit
obligation ("APBO"):
Retirees.............................. $45.2 $35.5
Fully eligible active employees....... 2.0 1.9
Other active employees................ 12.2 7.7
----- -----
Total APBO.................... 59.4 45.1
Unrecognized prior service gain......... 5.2 4.4
Unrecognized net gain................... 11.5 25.1
----- -----
Postretirement benefits
liability................... $76.1 $74.6
===== =====
The APBO was determined using a discount rate of 7.25% in 1995 and 7.5% in
1996. The health care cost trend rate is assumed to gradually decrease from 9.5%
for 1997 to 5.0% for 2009 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 $0.6 million and the APBO would rise by $4.4
million. The Company does not currently pre-fund health care and life insurance
benefit costs. Cash payments for these benefits were $1.6 million in 1995 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, 11,660,601 and 9,215,933 shares of common
stock or options for such shares were available at December 31, 1995 and 1996,
respectively, for grant to employees and directors. Options 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 ten
years from grant date. Multi-year option grants have been made to officers and
key employees and vest over a three-year period from grant date.
Retention shares of common stock are awarded under the plans to eligible
employees, subject to forfeiture if employment terminates during the prescribed
retention period, generally one to five years from grant. Multi-year retention
stock awards also have been made, with vesting three to five years from grant.
To become exercisable, 1994 multi-year grants of stock options and
retention stock also required that designated Company stock prices be met. These
performance conditions were achieved during 1995 for stock options and during
1996 for 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 Company stock options, ISOs and retention shares,
respectively. The converted options and retention shares retain the same
exercise dates and vesting requirements as the UPC options and retention shares
for which they were exchanged.
50
53
UNION PACIFIC RESOURCES GROUP INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The status of the Company's stock-based compensation programs is as
follows:
WEIGHTED
COMPANY AVERAGE
SHARES EXERCISE PRICE
--------- --------------
Stock options:
Balance at December 31, 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
=========
Exercisable December 31:
1995................................................... 2,235,470 $16.26
1996................................................... 3,035,905 16.81
REGULAR PERFORMANCE
--------- -----------
Retention shares:
1995
Awarded............................ 33,585 14,143
Conversion of UPC retention
shares........................... 389,880 310,653
--------- --------
Unvested at December 31, 1995...... 423,465 324,796
1996
Awarded............................ 604,530 --
Conversion of UPC retention
shares........................... 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 --
========= ========
Weighted-average grant-date fair value of options and retention shares
granted:
RETENTION
OPTIONS(b) SHARES(c)
---------- ---------
1995................................................. $8.31 $25.88
1996................................................. 9.15 27.81
- - ---------------
(a) Activity occurred prior to achievement of performance conditions.
(b) Calculated in accordance with the Black-Scholes option pricing model, using
the following assumptions:
1995 1996
------- -------
Expected volatility........................................ 28% 26%
Expected dividend yield.................................... .86% .7%
Expected option term....................................... 5 years 5 years
Risk-free rate of return................................... 5.5% 6.3%
(c) Represents market value on grant date.
51
54
UNION PACIFIC RESOURCES GROUP INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Stock options outstanding as of December 31, 1996 are as follows:
OPTIONS OUTSTANDING OPTIONS EXERCISABLE
--------------------------------- --------------------
WEIGHTED WEIGHTED WEIGHTED
AVERAGE AVERAGE AVERAGE
RANGE OF YEARS TO EXERCISE EXERCISE
EXERCISE PRICES NUMBER EXPIRATION PRICE NUMBER PRICE
--------------- --------- ---------- -------- --------- --------
$8.09-15.07...................... 380,861 2.75 $11.65 380,861 $11.65
15.18-20.94...................... 3,141,176 6.90 16.94 2,531,544 17.20
23.78-28.94...................... 1,694,037 9.50 27.47 123,500 24.66
--------- ---------
8.09-28.94...................... 5,216,074 7.52 19.97 3,035,905 16.81
========= =========
The Company applies the intrinsic value method in accounting for its stock
option and retention stock plans. Accordingly, no compensation cost has been
recognized for its stock option plans. Compensation cost recognized for its
retention stock plan was $0.7 million and $7.4 million in 1995 and 1996,
respectively. Had compensation cost for the Company's stock option plan 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 $3.4
million in 1995 (essentially all of which relates to option conversion at the
Offering) and $3.0 million in 1996 (of which $0.7 million relates to option
conversion at the Distribution). Earnings per share would have been reduced by
$0.01 per share in both 1995 and 1996.
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. Principal and interest
requirements are $8.7 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 earnings per
share 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.
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
52
55
UNION PACIFIC RESOURCES GROUP INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
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,
Company common stock or common stock of the acquiring company, as the case may
be, having a value equal to two times the exercise price of the Right.
The Rights should not interfere with any merger or other business
combination approved by the Company since the Board of Directors may, at its
option, at any time prior to the close of business on the earlier of the tenth
day following the Stock Acquisition Date or October 28, 2006, redeem all but not
less than all of the then outstanding Rights at $0.01 per Right. The Rights
expire on October 28, 2006, and do not have voting power or dividend privileges.
12. 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 as of and for the year ended December 31 is as follows:
1995 1996
--------- ---------
(MILLIONS OF DOLLARS)
Current assets.............................................. $ 35.7 $ 39.8
Non-current assets.......................................... 60.5 46.4
Current liabilities......................................... 16.1 20.2
Non-current liabilities and equity (see Note 13)............ 80.1 66.0
Sales....................................................... 176.0 192.4
Operating income............................................ 109.2 137.0
Partners' income............................................ 108.9 137.0
During 1996, Black Butte's sales to its largest customer under an amended
coal supply contract accounted for $54.8 million, or 10%, of the Company's
consolidated operating income. Operating income from this amended contract is
expected to be relatively constant through the end of 2001, when the financially
beneficial terms of this agreement will terminate. Although Black Butte
continues to seek new buyers for its low-sulfur coal, its mining costs are
considerably higher than the mining costs for competing supplies. The Company
does not expect to be able to replace the operating income it currently receives
under the amended contract with incremental coal sales.
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
53
56
UNION PACIFIC RESOURCES GROUP INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
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
10 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, 1996, long and short-term liabilities totaling $94.3
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 $44.2 million for the obligation to
participate in the remediation of the Wilmington field properties (see Note 4).
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 $6.2 million in 1995 and $11.4
million in 1996. In 1997, the Company anticipates spending a total of $20
million for remediation, control and prevention, including $10 million relating
to the Wilmington properties. The majority of the December 31, 1996 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.
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, 1996 are $54.3 million, of which the Company's share is
$27.2 million. The majority of cash expenditures for reclamation are expected to
be incurred from five to ten years in the future.
14. COMMITMENTS AND CONTINGENCIES
UP Fuels is a party to a long-term firm transportation agreement with Kern
River Gas Transmission Company 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. Eleven
years remain on the primary term of the agreement, and the current
transportation rate is $0.69 per Mcf. UP Fuels is obligated to pay the fixed
portion of that rate, presently $0.6878 per Mcf, whether or not it actually
transports any gas. This rate will be in effect through at least mid-1997, and
thereafter can change based on
54
57
UNION PACIFIC RESOURCES GROUP INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
cost of service factors and prevailing rate policy at the Federal Energy
Regulatory Commission. The undiscounted amount of the commitment is $197
million. UP Fuels is party to an additional agreement under which it may acquire
in 2001, at its option, an additional 25 MMcfd of transportation rights on the
Kern River system for periods beginning in 2002.
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 petrochemical complex (July 1987), the Calnev pipeline
(October 1988), the Wilmington 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 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 report. The Company intends to defend vigorously against these lawsuits as
well as any similar lawsuits. If such suits ultimately are resolved against the
Company on a widespread basis, however, damage awards and a loss of future
revenue could result which, in the aggregate, could be materially adverse to the
Company.
The Company is a defendant in a number of other lawsuits and is involved in
governmental proceedings arising in the ordinary course of business in addition
to those described above. The Company also has entered into commitments and
provided guarantees for specific financial and contractual obligations of its
subsidiaries and affiliates. The Company does not expect that these lawsuits,
commitments or guarantees will have a materially adverse effect on its results
of operations or financial condition.
15. OTHER LONG-TERM LIABILITIES
Other long-term liabilities as of December 31 include the following:
1995 1996
--------- ---------
(MILLIONS OF DOLLARS)
Environmental (Notes 4 and 13).......... $ 78.0 $ 74.5
Wilmington field site preparation (Note
4).................................... 53.7 53.7
Litigation and contingencies (Notes 4
and 14)............................... 93.5 73.8
Offshore platform lease accrual......... 14.5 14.3
Other................................... 50.8 43.6
------ ------
Total......................... $290.5 $259.9
====== ======
55
58
UNION PACIFIC RESOURCES GROUP INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
16. CAPITAL AND EXPLORATORY EXPENDITURES
Capital and exploratory expenditures include the following:
1994 1995 1996
-------- ------ ------
(MILLIONS OF DOLLARS)
Capital expenditures:
Producing properties.................. $ 790.8 $482.7 $515.2
Non-producing properties.............. 192.4 35.0 149.8
Exploratory drilling.................. 28.5 24.2 36.1
Plants, pipelines and marketing....... 329.8 106.5 118.1
Other................................. 2.0 2.0 9.5
-------- ------ ------
Total capital expenditures.... 1,343.5 650.4 828.7
-------- ------ ------
Exploratory expenditures:
Expensed geological and geophysical
costs.............................. 18.4 22.4 19.0
Expensed dry hole costs............... 27.4 13.6 32.6
-------- ------ ------
Total exploratory
expenditures................ 45.8 36.0 51.6
-------- ------ ------
Total capital and exploratory
expenditures................ $1,389.3 $686.4 $880.3
======== ====== ======
56
59
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.
1994 1995 1996
------- ------- -------
Natural gas (Bcf)(a):
Beginning of year........................................ 1,731.2 2,126.0 2,173.5
Revisions of previous estimates.......................... (33.1) (122.3) 45.7
Extensions, discoveries and other additions.............. 360.3 518.0 481.3
Purchases of reserves-in-place........................... 385.4 26.7 52.0
Sales of reserves-in-place............................... (36.0) (32.0) (5.5)
Production............................................... (281.8) (342.9) (368.6)
------- ------- -------
Total proved, end of year........................ 2,126.0 2,173.5 2,378.4
======= ======= =======
Proved developed reserves........................ 2,054.4 1,957.1 2,125.4
======= ======= =======
Natural gas liquids (MMBbl)(a):
Beginning of year........................................ 74.3 83.8 100.1
Revisions of previous estimates.......................... (5.8) 9.9 12.0
Extensions, discoveries and other additions.............. 4.6 18.2 9.1
Purchases of reserves-in-place........................... 21.4 0.2 0.2
Sales of reserves-in-place............................... (2.2) (1.0) (0.4)
Production............................................... (8.5) (11.0) (13.5)
------- ------- -------
Total proved, end of year........................ 83.8 100.1 107.5
======= ======= =======
Proved developed reserves........................ 81.2 89.8 97.7
======= ======= =======
Crude oil, including condensate (MMBbl):
Beginning of year........................................ 82.6 70.9 83.8
Revisions of previous estimates.......................... 4.9 14.1 (0.6)
Extensions, discoveries and other additions.............. 24.5 19.1 14.3
Purchases of reserves-in-place........................... 6.5 1.9 3.6
Sales of reserves-in-place............................... (24.6) (2.9) (2.0)
Production............................................... (23.0) (19.3) (18.5)
------- ------- -------
Total proved, end of year........................ 70.9 83.8 80.6
======= ======= =======
Proved developed reserves........................ 69.9 78.2 74.1
======= ======= =======
Proved reserves equivalent, end of year (Bcfe)(b):
Natural gas.............................................. 2,126.0 2,173.5 2,378.4
Natural gas liquids...................................... 502.9 600.6 645.0
Crude oil, including condensate.......................... 425.2 502.8 483.6
------- ------- -------
Total proved..................................... 3,054.1 3,276.9 3,507.0
======= ======= =======
Proved developed reserves........................ 2,961.0 2,965.1 3,155.8
======= ======= =======
- - ---------------
(a) 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).
(b) Calculated using the ratio of one Bbl to six Mcf.
57
60
UNION PACIFIC RESOURCES GROUP INC.
SUPPLEMENTARY INFORMATION (UNAUDITED) -- (CONTINUED)
B. DRILLING ACTIVITY(A)
1994 1995 1996
---- ---- ----
Gross wells............................. 677 725 655
Gross productive wells.................. 644 685 591
Net wells:
Exploration........................... 24 14 27
Development........................... 373 513 439
--- --- ---
Total net wells............... 397 527 466
=== === ===
Net productive wells:
Exploration........................... 16 3 9
Development........................... 365 506 413
--- --- ---
Total net productive wells.... 381 509 422
=== === ===
- - ---------------
(a) In addition, at December 31, 1996, 140 gross wells (95 net wells) were in
the process of being drilled.
C. AVERAGE SALES PRICE AND COST
1994 1995 1996
------ ------ ------
Producing properties:
Natural gas sales price (per Mcf)..... $ 1.82 $ 1.42 $ 1.86
Natural gas liquids sales price (per
Bbl)............................... 7.86 8.14 11.39
Crude oil sales price (per Bbl)....... 14.34 16.08 18.84
Production cost (per Mcfe)............ 0.55 0.42 0.49
Gas plants:
Natural gas sales price (per Mcf)..... $ 1.81 $ 1.51 $ 2.01
Natural gas liquids sales price (per
Bbl)............................... 9.97 9.38 13.16
D. AVERAGE DAILY PRODUCTION AND SALES VOLUME
1994 1995 1996
-------- -------- --------
Producing properties:
Natural gas (MMcfd)................... 754.8 915.6 980.3
Natural gas liquids (MBbld)........... 18.8 23.1 28.5
Crude oil (MBbld)..................... 63.1 52.8 50.6
Total producing properties (MMcfed)... 1,246.2 1,371.0 1,454.9
Plant share of equity gas processed:
Natural gas (MMcfd)................... 17.5 23.9 26.7
Natural gas liquids (MBbld)........... 4.4 7.1 8.4
Total plant share of equity gas
(MMcfed)........................... 43.9 66.5 77.1
Total production reflected in
estimates of proved reserves
(MMcfed).................... 1,290.1 1,437.5 1,532.0
Plant share of third party gas processed
(MBbld)............................... 26.8 27.1 31.4
Total sales (MMcfed).......... 1,450.9 1,600.1 1,720.2
Plant share of natural gas liquids sales
(MBbld):
Equity gas processed.................. 4.4 7.1 8.4
Third party gas processed............. 26.8 27.1 31.4
-------- -------- --------
Total................................. 31.2 34.2 39.8
======== ======== ========
58
61
UNION PACIFIC RESOURCES GROUP INC.
SUPPLEMENTARY INFORMATION (UNAUDITED) -- (CONTINUED)
E. ACREAGE AND WELLS
Oil and gas leasehold acreage as of December 31 is as follows(a):
1995 1996
----- -----
(THOUSANDS OF
ACRES)
Gross developed......................... 1,822 2,018
Net developed........................... 1,017 1,179
Gross undeveloped....................... 3,331 4,272
Net undeveloped......................... 2,194 2,935
Productive oil and gas wells at December 31, 1996 are as follows:
OIL GAS
----- -----
(WELLS)
Gross(b)................................ 2,786 5,011
Net..................................... 1,620 2,703
- - ---------------
(a) In addition, the Company has fee mineral ownership of approximately 9.6
million gross acres (8.5 million net acres), including 7.9 million gross
acres (7.7 million net acres) acquired through 19th century Congressional
Land Grant Acts. Substantial portions of this acreage are undeveloped and
are considered prospective for oil and gas.
(b) Approximately 577 are multiple completions, 405 of which are gas wells.
F. CAPITALIZED EXPLORATION AND PRODUCTION COSTS
Capitalized exploration and production costs as of December 31 are as
follows(a):
1995 1996
--------- ---------
(MILLIONS OF DOLLARS)
Proved properties....................... $ 865.7 $ 889.5
Unproved properties..................... 148.3 280.9
Wells and related equipment............. 3,136.1 3,512.2
Uncompleted wells and equipment......... 182.6 291.6
--------- ---------
Gross capitalized costs....... 4,332.7 4,974.2
Accumulated depreciation, depletion and
amortization.......................... (2,282.8) (2,746.8)
--------- ---------
Net capitalized costs......... $ 2,049.9 $ 2,227.4
========= =========
- - ---------------
(a) Excludes plants, pipelines and marketing assets.
59
62
UNION PACIFIC RESOURCES GROUP INC.
SUPPLEMENTARY INFORMATION (UNAUDITED) -- (CONTINUED)
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:
1994 1995 1996
-------- ------ ------
(MILLIONS OF DOLLARS)
Costs incurred:
Proved acreage........................ $ 440.6 $100.5 $ 85.7
Unproved acreage...................... 35.4 35.0 149.8
Exploration costs(a).................. 100.5 80.9 114.6
Development costs..................... 507.2 382.2 429.5
-------- ------ ------
Total costs incurred(b)....... $1,083.7 $598.6 $779.6
======== ====== ======
- - ---------------
(a) Includes allocated exploration overhead costs of $21.6 million in 1994,
$17.1 million in 1995 and $22.5 million in 1996, and delay rentals of $4.6
million in 1994, $3.6 million in 1995 and $4.4 million in 1996.
(b) Excludes capital expenditures relating to plants, pipelines and marketing of
$329.8 million in 1994, $106.5 million in 1995 and $118.1 million in 1996.
H. RESULTS OF OPERATIONS FOR PRODUCING ACTIVITIES(A)
1994 1995 1996
------- -------- --------
(MILLIONS OF DOLLARS)
Revenues................................ $ 962.5 $1,027.7 $1,198.3
Production costs........................ (252.3) (217.8) (259.5)
Exploration expenses.................... (107.6) (89.4) (144.6)
Depreciation, depletion and
amortization.......................... (373.2) (403.1) (465.5)
------- -------- --------
Total costs................... (733.1) (710.3) (869.6)
------- -------- --------
Pre-tax results......................... 229.4 317.4 328.7
Income taxes............................ (28.8) (70.4) (94.9)
------- -------- --------
Results of operations......... $ 200.6 $ 247.0 $ 233.8
======= ======== ========
- - ---------------
(a) Plants, pipelines and marketing 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 $26.5 million
in 1994, $14.2 million in 1995 and $3.9 million in 1996, and the $122.5
million Columbia bankruptcy settlement in 1995.
60
63
UNION PACIFIC RESOURCES GROUP INC.
SUPPLEMENTARY INFORMATION (UNAUDITED) -- (CONTINUED)
I. STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED
OIL AND GAS RESERVES
1994 1995 1996
--------- --------- ---------
(MILLIONS OF DOLLARS)
Future cash inflows from sales of oil and gas........ $ 5,023.1 $ 5,809.2 $11,945.7
Future production and development costs.............. (1,790.9) (1,747.8) (2,013.1)
Future income taxes.................................. (722.3) (1,114.6) (3,031.7)
--------- --------- ---------
Future net cash flows................................ 2,509.9 2,946.8 6,900.9
10% annual discount.................................. (851.2) (1,075.5) (2,661.9)
--------- --------- ---------
Standardized measure of discounted future net cash
flows.............................................. $ 1,658.7 $ 1,871.3 $ 4,239.0
========= ========= =========
An analysis of changes in the standardized measure of discounted future net
cash flows follows:
1994 1995 1996
--------- --------- ---------
(MILLIONS OF DOLLARS)
Beginning of year.................................... $ 1,288.6 $ 1,658.7 $ 1,871.3
Changes due to current year operations:
Additions and discoveries less related production
and other costs................................. 570.7 549.7 1,135.5
Sales of oil and gas -- net of production costs.... (744.0) (716.1) (961.0)
Development costs.................................. 745.6 382.2 429.5
Purchases of reserves-in-place..................... 270.9 48.8 181.1
Sales of reserves-in-place......................... (36.1) (49.5) (48.0)
Changes due to revisions in:
Price.............................................. (9.6) 334.0 2,763.1
Development costs.................................. (811.9) (293.6) (268.6)
Quantity estimates................................. (80.4) 68.1 27.9
Income taxes....................................... 184.2 (271.5) (1,062.9)
Other.............................................. 107.0 (31.8) (69.6)
Discount accretion................................... 173.7 192.3 240.7
--------- --------- ---------
End of year.......................................... $ 1,658.7 $ 1,871.3 $ 4,239.0
========= ========= =========
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. 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.
61
64
UNION PACIFIC RESOURCES GROUP INC.
SUPPLEMENTARY INFORMATION (UNAUDITED) -- (CONTINUED)
J. SELECTED QUARTERLY DATA
Selected unaudited quarterly data are as follows:
FOR THE QUARTER ENDED
--------------------------------------------------
MARCH 31 JUNE 30 SEPTEMBER 30 DECEMBER 31
-------- ------- ------------ -----------
(MILLIONS, EXCEPT PER SHARE AMOUNTS)
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........................... $ 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
1995
Operating revenues..................... $ 324.7 $ 341.3 $ 335.3 $ 475.4(b)
Operating income....................... 86.5 88.1 98.4 197.1(b)
Net income............................. 61.2 73.6 76.7 139.2(b)
Per share:
Net income(c)........................ n/a n/a n/a $ 0.56
Dividends(c)......................... n/a n/a n/a 0.05
Common stock price:
High(c).............................. n/a n/a n/a $ 26 1/4
Low(c)............................... n/a n/a n/a 21 1/8
- - ---------------
(a) 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 release of a $31.3 million contingency
accrual related to potential claims in connection with the 1995 Columbia
bankruptcy settlement (see Note 4) and operating expenses were impacted by
$43.5 million related to the writeoff and impairment of certain oil and gas
assets (see Note 6).
(b) In November 1995, the Company recorded a $122.5 million pre-tax ($78.5
million after-tax) gain resulting from the Columbia bankruptcy settlement
(see Note 4).
(c) Net income and dividends per share have been omitted for all periods prior
to the fourth quarter of 1995 as the Company was a wholly owned subsidiary
of UPC until October 1995 (see Note 2).
62
65
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
(a) Directors of Registrant.
Information as to the names, ages, positions and offices with the Company,
terms of office, periods of service, business experience during the past five
years and certain other directorships held by each director or person nominated
to become a director is set forth in the Election of Directors segment of the
Proxy Statement and is incorporated herein by reference.
(b) Executive Officers of Registrant.
Information concerning executive officers is presented in Part I of this
report under Executive Officers of the Registrant.
(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 segment of the
Proxy Statement and is incorporated herein by reference.
ITEM 11. EXECUTIVE COMPENSATION
Information concerning remuneration received by executive officers and
directors is presented in the Compensation of Directors, Compensation Committee
Interlocks and Insider Participation and Executive Compensation segments of the
Proxy Statement and is incorporated herein by reference.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
Information as to the number of shares of equity securities beneficially
owned as of March 3, 1997, 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.
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 30.
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.
63
66
(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
------- ----------------------
3.1 -- Amended and Restated Articles of Incorporation of Union
Pacific Resources Group Inc. (Exhibit 3.1 to Form S-1)
*3.2 -- Articles of Amendment of the Amended and Restated
Articles of Incorporation of Union Pacific Resources
Group Inc., dated November 5, 1996
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 -- Form of Debt Security (incorporated herein by reference
to Exhibit 4.3 to the Company's Form S-3 Registration
Statement, Registration No. 333-2984, dated May 23, 1996)
4.5 -- Form of Fixed Rate Note (incorporated herein by reference
to Exhibit 4.4 to the Company's Form S-3 Registration
Statement, Registration No. 333-2984, dated May 23, 1996)
10.1 -- Services Agreement (Exhibit 10.1 to Form S-1)
10.2 -- Stock Restriction, Registration and Option Agreement
(Exhibit 10.2 to Form S-1)
10.3 -- Tax Allocation Agreement (Exhibit 10.3 to Form S-1)
10.4 -- Indemnification Agreement (Exhibit 10.4 to Form S-1)
10.5 -- Cash Management Agreement (Exhibit 10.5 to Form S-1)
10.6 -- Intercompany Credit Agreement (Exhibit 10.6 to Form S-1)
10.7 -- Pension Plan Agreement (Exhibit 10.7 to Form S-1)
10.8 -- Asset Exchange Agreement (Exhibit 10.8 to Form S-1)
10.9 -- Asset Purchase and Sale Agreement (Exhibit 10.26 to Form
S-1)
10.10 -- Amended Agreement Regarding 1971 Plan of Reorganization
(Exhibit 10.27 to Form S-1)
10.11 -- Executive Incentive Plan of Union Pacific Resources Group
Inc. (Exhibit 10.9 to Form S-1)
10.12 -- 1995 Stock Option and Retention Stock Plan of Union
Pacific Resources Group Inc. (Exhibit 10.10 to Form S-1)
64
67
EXHIBIT
NUMBER DESCRIPTION OF EXHIBIT
------- ----------------------
10.13 -- 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)
10.14 -- 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)
10.15(a) -- Conversion Agreement (Exhibit 10.13(a) to Form S-1)
10.15(b) -- Conversion Agreement for Drew Lewis (Exhibit 10.13(b) to
Form S-1)
10.15(c) -- Conversion Agreement for Jack L. Messman (Exhibit
10.13(c) to Form S-1)
*10.16 -- The Union Pacific Resources Group Inc. Executive Life
Insurance Plan, adopted February 26, 1997
*10.17(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
*10.17(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
*10.17(c) -- Form of Agreement relating to Change in Control by and
between Union Pacific Resources Group Inc. and each of
Anne M. Franklin, Mark S. Knouse, Joseph A. LaSala, Jr.,
Donald W. Niemiec, Morris B. Smith and John B. Vering,
dated February 4, 1997
10.18 -- 1995 Directors Stock Option Plan (Exhibit 10.14 to Form
S-1)
10.19 -- Stock Unit Grant and Deferred Compensation Plan for the
Board of Directors, effective September 28, 1995 (Exhibit
10.15 to Form S-1)
10.20 -- 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)
10.21 -- 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)
10.22 -- Nineteenth Amendment to Transportation Agreement dated
December 15, 1989, dated as of May 23, 1994, by and
between Kern River Gas Transmission Company and Union
Pacific Fuels, Inc. (Exhibit 10.22 to Form S-1)
10.23 -- 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)
10.24 -- 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)
*10.25 -- Letter agreement, dated as of January 20, 1997, amending
the Anschutz Agreement
65
68
EXHIBIT
NUMBER DESCRIPTION OF EXHIBIT
------- ----------------------
10.26 -- 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)
*10.27 -- Letter, dated as of November 15, 1996, amending the
Competitive Advance/ Revolving Credit Agreement
*11 -- Computation of pro forma earnings per share
*12 -- Computation of ratio of earnings to fixed charges
*21 -- List of subsidiaries
*23 -- Consent of Deloitte & Touche LLP dated as of March 21,
1997
*24 -- Powers of attorney
*27 -- Financial data schedule
99 -- Financial statements for the fiscal year ended December
31, 1996, required by Form 11-K for the Union Pacific
Resources Group Inc. Thrift Plan -- to be filed by
amendment
(b) Reports on Form 8-K.
None.
66
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 21st day of
March, 1997.
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 21st day of March, 1997, by the following
persons on behalf of the registrant and in the capacities indicated.
/s/ JACK L. MESSMAN Chairman and Chief Executive Officer
- - ----------------------------------------------------- (Principal Executive Officer)
(Jack L. Messman)
/s/ MORRIS B. SMITH Vice President and Chief Financial Officer (Principal
- - ----------------------------------------------------- Financial Officer)
(Morris B. Smith)
/s/ JOHN E. JACKSON Controller
- - ----------------------------------------------------- (Principal Accounting Officer)
(John E. Jackson)
* 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
- - -----------------------------------------------------
Samuel K. Skinner
* Director
- - -----------------------------------------------------
James R. Thompson
*By /s/ MARK L. JONES
-------------------------------------------------
(Mark L. Jones, as attorney-in-fact)
67
70
INDEX TO EXHIBITS
EXHIBIT
NUMBER DESCRIPTION OF EXHIBIT
------- ----------------------
3.1 -- Amended and Restated Articles of Incorporation of Union
Pacific Resources Group Inc. (Exhibit 3.1 to Form S-1)
*3.2 -- Articles of Amendment of the Amended and Restated
Articles of Incorporation of Union Pacific Resources
Group Inc., dated November 5, 1996
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 -- Form of Debt Security (incorporated herein by reference
to Exhibit 4.3 to the Company's Form S-3 Registration
Statement, Registration No. 333-2984, dated May 23, 1996)
4.5 -- Form of Fixed Rate Note (incorporated herein by reference
to Exhibit 4.4 to the Company's Form S-3 Registration
Statement, Registration No. 333-2984, dated May 23, 1996)
10.1 -- Services Agreement (Exhibit 10.1 to Form S-1)
10.2 -- Stock Restriction, Registration and Option Agreement
(Exhibit 10.2 to Form S-1)
10.3 -- Tax Allocation Agreement (Exhibit 10.3 to Form S-1)
10.4 -- Indemnification Agreement (Exhibit 10.4 to Form S-1)
10.5 -- Cash Management Agreement (Exhibit 10.5 to Form S-1)
10.6 -- Intercompany Credit Agreement (Exhibit 10.6 to Form S-1)
10.7 -- Pension Plan Agreement (Exhibit 10.7 to Form S-1)
10.8 -- Asset Exchange Agreement (Exhibit 10.8 to Form S-1)
10.9 -- Asset Purchase and Sale Agreement (Exhibit 10.26 to Form
S-1)
10.10 -- Amended Agreement Regarding 1971 Plan of Reorganization
(Exhibit 10.27 to Form S-1)
10.11 -- Executive Incentive Plan of Union Pacific Resources Group
Inc. (Exhibit 10.9 to Form S-1)
10.12 -- 1995 Stock Option and Retention Stock Plan of Union
Pacific Resources Group Inc. (Exhibit 10.10 to Form S-1)
10.13 -- 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)
71
EXHIBIT
NUMBER DESCRIPTION OF EXHIBIT
------- ----------------------
10.14 -- 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)
10.15(a) -- Conversion Agreement (Exhibit 10.13(a) to Form S-1)
10.15(b) -- Conversion Agreement for Drew Lewis (Exhibit 10.13(b) to
Form S-1)
10.15(c) -- Conversion Agreement for Jack L. Messman (Exhibit
10.13(c) to Form S-1)
*10.16 -- The Union Pacific Resources Group Inc. Executive Life
Insurance Plan, adopted February 26, 1997
*10.17(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
*10.17(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
*10.17(c) -- Form of Agreement relating to Change in Control by and
between Union Pacific Resources Group Inc. and each of
Anne M. Franklin, Mark S. Knouse, Joseph A. LaSala, Jr.,
Donald W. Niemiec, Morris B. Smith and John B. Vering,
dated February 4, 1997
10.18 -- 1995 Directors Stock Option Plan (Exhibit 10.14 to Form
S-1)
10.19 -- Stock Unit Grant and Deferred Compensation Plan for the
Board of Directors, effective September 28, 1995 (Exhibit
10.15 to Form S-1)
10.20 -- 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)
10.21 -- 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)
10.22 -- Nineteenth Amendment to Transportation Agreement dated
December 15, 1989, dated as of May 23, 1994, by and
between Kern River Gas Transmission Company and Union
Pacific Fuels, Inc. (Exhibit 10.22 to Form S-1)
10.23 -- 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)
10.24 -- 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)
*10.25 -- Letter agreement, dated as of January 20, 1997, amending
the Anschutz Agreement
10.26 -- 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)
72
EXHIBIT
NUMBER DESCRIPTION OF EXHIBIT
------- ----------------------
*10.27 -- Letter, dated as of November 15, 1996, amending the
Competitive Advance/ Revolving Credit Agreement
*11 -- Computation of pro forma earnings per share
*12 -- Computation of ratio of earnings to fixed charges
*21 -- List of subsidiaries
*23 -- Consent of Deloitte & Touche LLP dated as of March 21,
1997
*24 -- Powers of attorney
*27 -- Financial data schedule
99 -- Financial statements for the fiscal year ended December
31, 1996, required by Form 11-K for the Union Pacific
Resources Group Inc. Thrift Plan -- to be filed by
amendment
- - ---------------
* Filed herewith