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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549-1004
FORM 10-K
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED DECEMBER 31, 1999 COMMISSION FILE NUMBER 1-13916
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UNION PACIFIC RESOURCES GROUP INC.
(Exact name of registrant as specified in its charter)
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<S> <C>
UTAH 13-2647483
(State or other jurisdiction of Incorporation (I.R.S. Employer Identification No.)
or organization)
777 MAIN STREET 76102
FORT WORTH, TEXAS (Zip Code)
(Address of principal executive offices)
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Registrant's telephone number, including area code: (817) 321-6000
Securities registered pursuant to Section 12(b) of the Act:
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NAME OF EACH EXCHANGE
TITLE OF EACH CLASS ON WHICH REGISTERED
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Common Stock New York Stock Exchange, Inc.
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Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes [X] No [ ]
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [ ]
As of February 29, 2000, the aggregate market value of the registrant's
common stock held by non-affiliates (using the New York Stock Exchange closing
price) was approximately $2.25 billion.
The number of shares outstanding of the registrant's common stock as of
February 29, 2000 was 251,952,336.
Certain portions of the registrant's definitive Proxy Statement for the
annual meeting of shareholders to be held on May 24, 2000 (the "Proxy
Statement") are incorporated in Part III by reference.
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TABLE OF CONTENTS
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PART I
Item 1. Business.................................................... 1
Item 2. Properties.................................................. 10
Item 3. Legal Proceedings........................................... 12
Item 4. Submission of Matters to a Vote of Security Holders......... 13
PART II
Item 5. Market for the Registrant's Common Equity and Related
Stockholder Matters......................................... 14
Item 6. Selected Financial Data..................................... 14
Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations................................... 15
Item 7A. Qualitative and Quantitative Disclosures About Market
Risk........................................................ 32
Item 8. Financial Statements and Supplementary Data................. 38
Item 9. Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure.................................... 86
PART III
Item 10. Directors and Executive Officers of the Registrant.......... 86
Item 11. Executive Compensation...................................... 87
Item 12. Security Ownership of Certain Beneficial Owners and
Management.................................................. 87
Item 13. Certain Relationships and Related Transactions.............. 87
PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports on Form
8-K......................................................... 87
Signatures ............................................................ 94
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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.
Natural gas volumes also may be expressed in terms of one million British
thermal units ("MMBtu"), which is approximately equal to one Mcf. Daily oil and
gas production is signified by the addition of the letter "d" to the end of the
terms defined above. With respect to information relating to working interests
in wells or acreage, "net" oil and gas wells or acreage is determined by
multiplying gross wells or acreage by the working interest owned therein. Unless
otherwise specified, all references to wells and acres are gross.
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PART I
ITEM 1. BUSINESS
GENERAL
Union Pacific Resources Group Inc. (a Utah corporation) and subsidiaries
(collectively, the "Company" or "UPR") is engaged primarily in the exploration
for and the development and production of natural gas, natural gas liquids
("NGLs") and crude oil in several major producing basins in the United States,
Canada, Guatemala, Venezuela and other international areas. In addition, the
Company engages in the hard minerals business through non-operated joint venture
and royalty arrangements in several coal, industrial minerals and trona (natural
soda ash) mines located on lands within and adjacent to its Land Grant holdings
in Wyoming. The Land Grant consists of land that passes through the states of
Colorado and Wyoming and into Utah, which was granted by the Federal government
to a predecessor of the Company in the mid-1800s. In the Land Grant, the Company
has fee ownership of the mineral rights under approximately 7.9 million acres.
As of December 31, 1999, over 68 percent of the revenues, 44 percent of the
fixed assets and 56 percent of the proved reserves of the Company are generated
or located in the United States. As of December 31, 1999, 19 percent of the
revenues, 35 percent of fixed assets and 28 percent of the proved reserves of
the Company are generated or located in Canada.
In March 1998, the Company acquired Norcen Energy Resources Limited
("Norcen") for a cash purchase price of $2.634 billion ("Norcen Acquisition").
The Company also assumed long-term debt obligations of Norcen totaling
approximately $1 billion and funded the purchase price through the issuance of
commercial paper, supported by a U.S. $2.7 billion 364-Day Competitive
Advance/Revolving Credit Agreement dated March 2, 1998. Norcen was a major
Canadian oil and gas exploration and production company with primary operations
in western Canada, the Gulf of Mexico, Guatemala and Venezuela. The acquisition
expanded the Company's operations beyond its historical domestic focus. See Note
2 to the Consolidated Financial Statements.
Following the Norcen Acquisition, the Company commenced a deleveraging
program which included the sales in 1998 and 1999 of approximately $745 million
of non-strategic properties. Additionally, the Company sold its gathering,
processing and marketing ("GPM") business segment to Duke Energy Field Services,
Inc. ("Duke") for $1.36 billion in March 1999 ("GPM Disposition"). See
"Deleveraging Program and Discontinued Operations" in Note 3 to the Consolidated
Financial Statements.
BUSINESS STRATEGY
During 1999, the Company shifted its business strategy from prior years.
The Company sold its GPM business segment and began to focus on its upstream
exploration and production business segment. Although other international
operations, primarily in Latin America, were expanded as a result of the Norcen
Acquisition, the Company focuses primarily on onshore North American core
operating areas where it has expertise and a large acreage position with natural
gas prospects and can create shareholder value.
The Company's strategy is to become the premier North American onshore
exploration and production value creator through its technical and operational
abilities in the exploitation of natural gas, primarily in Texas, the Rockies
and Canada. In each of its core areas, the Company focuses on the exploration
for and the development of natural gas and crude oil resources, in combination
with efforts to increase margins through reductions in drilling and operating
costs. The Company's long-term strategy is to increase production by enhancing
well results through the application of economies of scale, its operating
experience in its core geographic areas and its expertise in advanced drilling
and completion technologies. The Company strives to keep its drilling inventory
high to supply its drilling operations with an inventory of drill sites in its
core areas through development of its existing properties, exploration, farm-in
agreements and acquisitions of properties and companies. The Company maintains a
high working interest in its core areas and typically serves as operator, which
allows it to control the timing and cost of exploration and development
activities and to enhance its ability to apply its expertise to these
properties.
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The Company plans to increase its capital spending in 2000 from the $428
million spent in 1999 to approximately $650 million for exploration and
development projects. The Company plans an additional $100 million for select
property acquisitions. The capital program will be funded through cash provided
by operations. Almost 83 percent of the capital budget will be focused on the
development of fields which have already been proved and which are expected to
provide more immediate cash flow with low risk. The remainder of the Company's
budget will be for select exploration projects and other development drilling
that has the potential for long-term impact. Both the development and
exploration programs will employ the Company's ongoing strategy of applying its
expertise in advanced drilling and completion technologies. Approximately 38
percent of the capital budget will be invested in U.S. Onshore, 29 percent in
Canada, 14 percent in U.S. Offshore and 19 percent in Other International. The
Company may adjust its capital spending as commodity prices and cash flows
change. The extent and timing of capital spending may also be affected by
changes in business, financial and operating conditions as well as by the timing
and availability of suitable investment opportunities. See "Outlook and Other
Matters."
The Company's primary financial strategy is to continue to improve its
balance sheet by reducing debt. During 1999, the Company reduced total debt by
over 39% or approximately $1.8 billion. During 2000, the Company expects to
further reduce debt by at least $200 million. The Company expects its cash
provided by operations to be approximately $1 billion for 2000, assuming a NYMEX
price forecast of $26 per barrel for crude oil and $2.70 per Mcf for natural
gas. To the extent that cash provided by operations is generated in excess of
this forecast or due to the monetization of assets, the additional cash could be
used to further reduce debt and/or initiate a common stock repurchase program if
approved by the Board of Directors. See "Outlook and Other Matters."
EXPLORATION AND PRODUCTION OPERATIONS
The Company's exploration and production operations are organized into four
primary business operating areas: U.S. Onshore, U.S. Offshore, Canada and Other
International. Other International is comprised of Guatemala, Venezuela and
other international operations.
The following table sets forth 1999 capital spending, production
information and proved reserves as of December 31, 1999, with respect to each of
the Company's operating areas. Natural gas constituted 58% of the Company's
total proved reserves of 5.7 Tcfe as of December 31, 1999, and 59% of the
Company's sales volumes of 2.15 Bcfed for the year then ended. Production from
properties sold in 1999 is included in producing property volumes for each area
through the date of each sale.
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PRODUCING
TOTAL TOTAL PROPERTY
CAPITAL PERCENT PROVED PERCENT SALES PERCENT
SPENDING OF RESERVES OF VOLUMES OF
OPERATING AREA (MILLIONS) TOTAL (BCFE) TOTAL (MMCFED) TOTAL
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U.S. Onshore.......................... $185 43% 2,814 49% 1,274 59%
U.S. Offshore......................... 53 13 361 7 139 7
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Total United States.............. 238 56 3,175 56 1,413 66
Canada........................... 123 29 1,585 28 462 21
Guatemala............................. 19 4 322 6 128 6
Venezuela............................. 43 10 538 9 114 5
Other................................. 5 1 84 1 35 2
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Total Other International........ 67 15 944 16 277 13
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Total....................... $428 100% 5,704 100% 2,152 100%
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United States Operations
The Company's United States operations currently has proved reserves of 3.2
Tcfe and produced 1,413 MMcfed in 1999. Over 70 percent of the proved reserves
in the United States is natural gas. Capital spending in the United States in
1999 was $238 million.
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U.S. Onshore
The Company's U.S. Onshore oil and gas activities are concentrated in five
core geographic areas. The core areas in the U.S. Onshore are comprised of the
following: (1) the Land Grant area in Colorado, Wyoming and Utah, (2) the
Coastal Plain area of Texas and Louisiana, (3) the Austin Chalk trend in Texas
and Louisiana, (4) the East Texas area and (5) the West Texas area. During 1999,
the Company spent $185 million or 43 percent of its capital budget in the U.S.
Onshore and produced 1,274 MMcfed or 59 percent of the Company's total produced
volumes.
The Land Grant core area includes the Company's oil and gas properties in
Colorado, Wyoming and Utah, and the Hugoton/Panoma field in Kansas. The
Company's operations in the Land Grant are concentrated in the Green River Basin
and the Overthrust area. The Company currently controls approximately 8.9
million developed and undeveloped net acres, principally attributable to its
Land Grant ownership. During 1999, the Company drilled a successful Rock Island
4H well in the deep over-pressured Frontier formation of the Green River Basin.
Although the wells drilled in early 2000 near the Rock Island 4H were not
successful, the formation's resource is large so the Company will continue to
test the Frontier formation during 2000 to further understand its potential.
The Coastal Plain core area includes the Company's oil and gas properties
along the onshore coastal plain of Texas and Louisiana. In addition to its
producing activities, the Company conducted extensive seismic evaluations in
1999 and drilled a successful exploration well in the Company's Etouffee
prospect in South Louisiana. The Company will continue to develop this area and
explore the nearby Turtle Soup area during 2000, while bringing on production
from the successful well in the Etouffee prospect.
The Austin Chalk core area includes the Company's oil and gas properties in
the Austin Chalk trend, which extends 700 miles from southern Texas through
central and eastern Texas into Louisiana. At present, the Company's Austin Chalk
production is located primarily in three fields: Giddings, Brookeland and
Masters Creek. The Company controls nearly 1.9 million developed and undeveloped
net acres in the Austin Chalk.
The East Texas core area includes the Company's oil and gas properties in
northeastern Texas, primarily in the Carthage and Oakhill fields. In addition to
its Carthage and Oakhill production operations, the Company has participated in
3-D seismic and has identified several high impact exploratory prospects.
The West Texas core area includes the Company's oil and gas properties in
western Texas, primarily in the Ozona field. The Company has drilled
approximately 1,000 wells in the Ozona area, which is characterized by
long-lived natural gas wells that typically produce for 30 or more years.
U.S. Offshore
The U.S. Offshore operations are comprised of the Company's oil and gas
properties in the Gulf of Mexico, including operations added in the Norcen
Acquisition in 1998. During 1999, the Company spent $53 million of its capital
budget in the U.S. Offshore and produced 139 MMcfed. During 1997, the Company
drilled a successful deepwater well in Mississippi Canyon Block 755 in the Gulf
of Mexico, which resulted in the discovery of significant reserves. The Company
has and will continue to delineate the discovery during 2000 and 2001, with
first production anticipated in 2002. The Company may also drill an exploration
well in both the Garden Banks Block 700 and Green Canyon Block 281 during 2000.
Canadian Operations
The Company's Canadian operations principally include properties acquired
in the Norcen Acquisition. Operations in ten core areas are centered in the
province of Alberta, with additional properties in northeastern British Columbia
and southwestern Saskatchewan. Canada currently has proved reserves of 1.6 Tcfe
and produced 462 MMcfed in 1999. Capital spending in 1999 in Canada was $123
million. Canada provides a balanced commodity mix of 35 percent crude oil and
NGLs and 65 percent natural gas, as well as an asset portfolio with long reserve
lives. Approximately 46 percent of Canadian oil production is heavy oil. The
Company has significant heavy crude oil assets in the Moose Hill, Lindbergh and
Hayter areas which are located in eastern Alberta and western Saskatchewan.
These areas cover approximately 420,000 acres and consist of over 860 producing
wells and over 1,000 drill site prospects. As a result of the Company's
successful Klua well in British Columbia during 1999, the Company will continue
to focus on the region and add reserves.
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Other International Operations
The Company's Other International oil and gas operation activities are
concentrated in Latin America, primarily in Guatemala and Venezuela. The Company
also maintains less significant international oil and gas operation activities,
including interests in six fields in Argentina, two non-operated offshore
producing properties in Australia, an exploitation interest in Brazil with
potential exploration upside, and a producing interest in a non-operated
property in Egypt. Other International currently has proved reserves of 0.9 Tcfe
and produced 277 MMcfed in 1999.
Guatemala. The Company's Guatemalan operations are conducted by Basic
Resources International, a company that was acquired in the Norcen Acquisition.
The majority of activity for the Guatemalan operations is currently in the Xan
area, producing heavy to medium quality crude oil. The Company owns a 100
percent working interest in several exploration blocks and is focusing on an
aggressive seismic acquisition strategy to evaluate exploration and development
opportunities. Capital spending in 1999 in Guatemala was $19 million, with
average production volumes of 21 MBbld. The Company owns, controls and operates
infrastructure in Guatemala which includes gathering and processing facilities
at each producing field, an asphalt refinery, 285 miles of pipeline with seven
pump stations and a 420 MBbl capacity shipping terminal on the Caribbean coast.
The combination of these assets provides the Company with an integrated network
of facilities from producing fields to the port.
Venezuela. The Company's Venezuelan operations primarily consist of the
Oritupano-Leona and the West Guarico concessions. The Oritupano-Leona block, in
which the Company has a 45 percent working interest, covers 433,000 acres and
has approximately 205 producing wells. Most of the activity in the block has
been driven by a 3-D seismic program conducted in prior years. The West Guarico
block covers over 800,000 acres, approximately nine producing wells and is
operated by the Company, which has a 50 percent working interest. The project is
in the beginning stages of redevelopment and in 1999, the Company focused on
seismic, drilling, recompletions and the improvement of infrastructure. After
drilling a dry hole on the Delta Centro prospect in 1999, the Company fully
impaired the project's lease with a $50 million charge to exploration expense.
During 1999, the Company spent $43 million of capital in Venezuela, with average
production volumes of 19 MBbld.
VOLUMES, PRICES AND PRODUCTION COSTS
The following table sets forth certain information regarding the Company's
volumes and average price realizations after the effects of hedging for natural
gas, NGL and crude oil sales, and average production costs per Mcfe for each of
the last three years.
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
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1999 1998 1997
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Average daily production:
Natural gas (MMcfd)....................................... 1,278.8 1,441.1 1,108.5
Natural gas liquids (MBbld)............................... 28.4 33.1 31.7
Crude oil (MBbld)......................................... 117.1 137.9 52.9
Total (MMcfed).................................... 2,151.6 2,467.0 1,615.7
Average sales prices including the effects of hedging:
Natural gas (per Mcf)..................................... $ 1.83 $ 1.74 $ 2.00
Natural gas liquids (per Bbl)............................. 10.95 7.88 11.23
Crude oil (per Bbl)....................................... 11.81 10.48 18.36
Production costs (per Mcfe)(a).............................. 0.51 0.49 0.51
</TABLE>
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(a) Includes lease operating costs, production overhead, other operating
expenses and taxes other than income taxes.
PRINCIPLE CUSTOMER
In connection with the GPM Disposition, the Company entered into a
long-term sales agreement with Duke. The long-term sales agreement obligates the
Company to sell the majority of its domestic natural gas and existing NGL
production to Duke through March 2004. During 1999, sales to Duke accounted for
31% of the Company's consolidated revenues and 38% of United States revenues.
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MINERALS
The Minerals business segment contributes significantly to the Company's
operating income by exploiting the hard minerals portion of the Company's
extensive fee mineral interests in the Land Grant through non-operated joint
venture and royalty arrangements in coal, trona and industrial mineral mines. In
general, the Company reinvests the cash flow from its hard minerals operations
into its oil and gas business segment. The Minerals business segment generated
$117.8 million of operating income during 1999, as follows:
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1999 OPERATING INCOME
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AMOUNT PERCENT
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(MILLIONS OF DOLLARS)
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Royalties:
Soda ash(a)........................................... $ 27.2 23%
Coal(b)............................................... 11.8 10
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Total royalties............................... 39.0 33
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Non-operated joint ventures:
Soda ash(c)........................................... (0.9) --
Coal(d)............................................... 79.3 67
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Total joint ventures.......................... 78.4 67
Overhead/other.......................................... 0.4 --
------ ---
Total operating income........................ $117.8 100%
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(a) Includes royalties from properties leased to four soda ash producers. In
total, these properties contain resources sufficient to support over 50
years of production at current production levels.
(b) The Company leases coal resources to six operating mines. In 1999, 52
percent of the Company's coal royalties were attributable to a single mine
which supplies an adjacent power station that is owned and operated by
affiliates of the mine owners.
(c) Represents operating income from the Company's 49 percent interest in OCI
Wyoming LP, a non-operated joint venture.
(d) Represents operating income from the Company's 50 percent non-operating
interest in Black Butte Coal Company ("Black Butte").
The Company's low sulfur coal deposits, which are located in southeastern
Montana and southwestern Wyoming, compete with other western coal for industrial
and utility boiler markets which burn the coal to produce steam to generate
electricity. The Company's mines primarily use the surface mining method of
extraction, although the Company also receives royalties on some underground
mines. The Company's coal mines are served by a single rail line and incur
greater transportation costs than some of its competitors in the western United
States. Additionally, competing western coal companies in the Powder River Basin
in Wyoming have lower stripping ratios than the Company's mines. At current coal
pricing and higher transportation and extraction cost levels, 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.
Approximately 80%, 84% and 78% of the Black Butte revenues in 1999, 1998
and 1997, respectively were derived from a coal supply contract with
Commonwealth Edison Company which terminates at the end of 2000. In 1999, $73.4
million of the Company's operating income was attributable to the contract. See
"Management's Discussion and Analysis of Financial Condition Results of
Operations", "Outlook and Other Matters" and Note 14 to the Consolidated
Financial Statements.
The world's largest deposit of trona, constituting 90 percent of the
world's known trona resources, is located in the Green River Basin in
southwestern Wyoming. All of the reserves which can be mined in this trona
deposit lie within the Land Grant and adjoining lands. The Company owns lands
containing approximately 50% of these reserves and has leased a portion of those
lands to companies which mine and refine trona. Natural soda ash, which is
produced by refining trona ore, is used primarily in the production of glass for
containers and flat glass, in the paper and water treatment industries and in
the manufacture of certain chemicals and detergents. Natural soda ash from
Wyoming contributes 31 percent of the world soda ash supply with the remainder
principally from synthetic processes. In addition to fee mineral ownership of
and royalty interests in trona reserves, the Company, along with its partner,
Oriental Chemical Industries, Inc. ("OCI"), owns a soda ash refining facility at
OCI Wyoming LP. This facility is ranked second in soda ash capacity among
domestic producers at 3.1 million tons per year.
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COMPETITION
The oil and gas industry is highly competitive. The Company actively
competes for reserve acquisitions, exploration leases, licenses, concessions and
skilled industry personnel, frequently against companies with substantially
larger financial and other resources. The Company's competitors include major
integrated oil and gas companies and numerous other independent oil and gas
companies and individual producers and operators. In the past several years,
some consolidation within the industry has occurred, as companies combined their
strengths and financial resources to improve overall stability and operating
efficiencies and to reduce costs. 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, pipeline access and types and
quality of service.
GOVERNMENT REGULATION
The Company's natural gas, NGL and crude oil exploration, development and
production operations are subject to extensive rules and regulations promulgated
by Federal, provincial, state and local authorities and foreign governmental
entities.
Numerous Federal, state and local departments and agencies have issued
rules and regulations binding on the oil and gas industry and its individual
members, some of which carry substantial penalties for non-compliance. 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 the U.S. Department of the Interior, Minerals
Management Service ("MMS"). Such leases are issued through competitive bidding,
contain relatively standardized terms and require compliance with detailed MMS
regulations and orders. Certain operations on such leases must be conducted
pursuant to appropriate permits issued by the MMS in addition to permits
required from other agencies (such as the Coast Guard, Army Corps of Engineers
and Environmental Protection Agency). The MMS also administers bonding
requirements and has the right to require lessees to post supplemental bonds if
it deems that additional security is necessary to cover royalties due or the
costs of regulatory compliance.
Under certain extraordinary circumstances, the Federal agencies have the
power to suspend or terminate Company operations on Federal leases. Any such
suspension or termination could materially and adversely affect the Company's
financial condition and operations. In 1998, the MMS adopted financial
responsibility regulations under the Oil Pollution Act of 1990. See
"Environmental Regulation -- Oil Spills."
Currently, there are no Federal, state or local laws that regulate the
price for sales of natural gas, NGLs or crude oil produced by the Company.
However, the rates charged and terms and conditions for the movement of gas in
interstate commerce through certain intrastate pipelines and production area
hubs are subject to regulation under the Natural Gas Policy Act of 1978
("NGPA"). Pipeline and hub construction activities are, to a limited extent,
also subject to regulation under the Natural Gas Act of 1938 ("NGA"). The NGA
also establishes comprehensive controls over interstate pipelines, including the
transportation 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, FERC has taken significant steps to increase
competition in the sale, purchase, storage and transportation of natural gas.
FERC's regulatory programs generally allow more accurate and timely price
signals from the consumer to the producer. Nonetheless, the ability to respond
to market forces can and does add to price volatility, inter-fuel competition
and pressure on the value of transportation and other services.
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Through many interstate pipeline specific orders, FERC has revised its
policy regarding jurisdiction over gathering facilities and services. FERC no
longer asserts jurisdiction over these facilities and services and has stated
that it is a matter to be left to the states for regulation. In 1996, the
District of Columbia Court of Appeals largely upheld FERC's policy. As a result
of the court's decision, the Texas Railroad Commission conducted inquiries
regarding the scope of its regulation of gathering facilities and services. The
Company owns several gathering systems in Texas. In 1996, the Texas Railroad
Commission initiated a rulemaking and ultimately issued new regulations
regarding gathering activities. Although the new regulations increased the
regulatory burden to a limited extent, the regulations have not had a
significant impact on the Company's gathering activity. It is also possible that
other states where the Company owns gathering facilities will become more active
in the regulation of gathering activities.
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 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
being pursued by FERC, Congress and the states will continue indefinitely into
the future.
The oil and gas industry in Canada is subject to extensive controls and
regulations imposed by various levels of government. Oil and gas exported from
Canada is subject to regulation by the National Energy Board ("NEB") and the
government of Canada. Exporters are free to negotiate prices and other terms
with purchasers, provided that the export contracts meet certain criteria
prescribed by the NEB and the government of Canada. Exports may be made pursuant
to export contracts with terms not exceeding one year in the case of light crude
oil and not exceeding two years in the case of heavy crude oil and natural gas,
provided that an order approving any such export has been obtained from the NEB.
Any export to be made pursuant to a contract of longer duration requires an NEB
license and Governor in Council approval. The governments of Alberta, British
Columbia and Saskatchewan also regulate the volume of natural gas that may be
removed from these provinces for consumption elsewhere based on such factors as
reserve availability, transportation arrangements and market considerations. In
addition, each province has legislation and regulations which govern land
tenure, royalties, production rates, environmental protection and other matters.
It is not expected that any of these controls or regulations will affect the
operations of the Company in a manner materially different than they would
affect other oil and gas companies of similar size.
The Company is subject to various laws and regulations governing its other
international operations. The Company's other international operations can be
affected from time to time by political developments and laws and regulations in
the countries where it operates, such as the forced divestiture of assets,
production restrictions, import and export controls, price controls, changes in
taxes, royalties and other amounts payable to governments, retroactive tax and
royalty claims, expropriation of property, cancellation of contract rights and
concessions by host governments, foreign exchange rate changes, restrictions as
to currency conversion, tariffs and other international trade restrictions and
environmental regulations. The likelihood of such occurrences is not
predictable.
The Company's minerals operations are subject to a variety of Federal and
state regulations with respect to safety, land use and reclamation. In addition,
the Department of the Interior regulates the leasing of Federal lands for coal
development as provided in the Mineral Lands Leasing Act of 1920.
SECTION 29 TAX CREDITS
Federal tax law provides an income tax credit against regular Federal
income tax liabilities with respect to sales of the Company's production of
certain fuels produced from non-conventional 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 must be sold before
January 1, 2003.
The basic credit which 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
7
<PAGE> 10
rose above approximately $48 per barrel. The natural gas production from wells
drilled on certain of the Company's properties in the Moxa Arch and Wamsutter
areas in Wyoming, the Carthage field in eastern Texas, the Ozona field in
western Texas and certain areas in the Austin Chalk trend qualifies for this tax
credit. The Company recorded approximately $17.9 million of Section 29 tax
credits in 1999. Section 29 tax credits are not creditable against the
alternative minimum tax but under certain circumstances may be carried over and
applied against regular tax liabilities in future years. Therefore, no assurance
can be given that the Company's Section 29 tax credits will reduce its Federal
income tax liability in any particular year.
TEXAS SEVERANCE TAX REDUCTION
Natural gas produced from wells that have been certified as deep wells or
geologic formations certified as tight formations by the Texas Railroad
Commission ("high cost wells") and that were spudded or completed during the
period from May 24, 1989 to September 1, 1996 qualifies for an exemption from
the 7.5 percent severance tax in Texas on natural gas and NGLs produced by such
wells. Such exemption ends August 31, 2001. The natural gas production from
wells drilled on certain of the Company's properties, primarily in the Austin
Chalk trend and fields in East and West Texas, 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, 2010 are entitled to receive a severance
tax reduction. For the maximum tax rate reduction, operators must file by the
later of 180 days after first production or the 45th day after approval by the
Texas Railroad Commission. The tax reduction is based on a formula composed of
the statewide "median" as determined by the State of Texas based on actual
drilling and completion costs reported by producers. More expensive wells will
receive a greater amount of tax reduction. This tax rate reduction remains in
effect for ten years or until the aggregate tax reductions received equal 50
percent of the total drilling and completion costs.
ENVIRONMENTAL REGULATION
The Company's operations are subject to extensive Federal, state, local,
provincial and international environmental laws and regulations governing the
protection of the environment. The Company is in compliance, in all material
respects, with applicable environmental requirements. Although future
environmental obligations are not expected to have a material impact on the
results of operations or financial condition of the Company, there can be no
assurance that future developments, such as increasingly stringent environmental
laws or enforcement thereof, will not cause the Company to incur material
environmental liabilities or costs.
Air Emissions. The primary legislation affecting the Company's air
emissions is the Federal Clean Air Act and its 1990 Amendments (the "CAA").
Among other things, the CAA requires all major sources of air emissions to
obtain operating permits. The amendments also revised the definition of a "major
source" such that additional equipment involved in oil and gas production is now
covered by the permitting requirements.
Hazardous Substances and Waste Disposal. The Company currently owns or
leases numerous properties that have been used for many years for hard minerals
production or natural gas and crude oil production. Although the Company has
utilized operating and disposal practices that were standard in the industry at
the time, hydrocarbons or other wastes may have been disposed of or released on
or under the properties owned or leased by the Company. In addition, some of
these properties have been operated by third parties over whom the Company had
no control. The Comprehensive Environmental Response, Compensation and Liability
Act ("CERCLA") and comparable state statutes impose strict, joint and several
liability on owners and operators of sites and on persons who disposed of or
arranged for the disposal of "hazardous substances" found at such sites. The
Federal Resource Conservation and Recovery Act ("RCRA") and comparable state
statutes govern the disposal of "solid wastes" and "hazardous wastes." Although
CERCLA currently excludes petroleum from its definition of hazardous substance,
many state laws affecting the Company's operations impose clean-up liability
regarding petroleum and petroleum-related products. In addition, although RCRA
classifies certain oil field wastes as "non-hazardous," such exploration and
production wastes could be reclassified as hazardous wastes thereby making such
wastes subject to more stringent handling and disposal requirements. If such a
change in legislation were to be enacted, it could have a significant impact on
the Company's operating costs, as well as the oil and gas industry in general.
See "Other Matters -- Environmental Costs."
8
<PAGE> 11
Oil Spills. Under the Oil Pollution Act of 1990 ("OPA"), owners and
operators of onshore facilities and pipelines and lessees or permittees of an
area in which an offshore facility is located ("Responsible Parties") are
strictly liable on a joint and several basis for removal costs and damages that
result from a discharge of oil into United States waters. OPA limits the strict
liability of Responsible Parties for removal costs and damages that result from
a discharge of oil from $10 million to $150 million in the case of onshore
facilities and from $35 million to $150 million plus removal costs in the case
of offshore facilities, except that these limits do not 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 owners of certain vessels and offshore facilities
to provide evidence of financial responsibility in the amount of $150 million.
The MMS, which has jurisdiction over certain offshore facilities and pipelines,
issued a final rule in August 1998 implementing OPA requirements. OPA also
requires offshore facilities and certain onshore facilities to prepare facility
response plans, which the Company has done, for responding to a "worst case
discharge" of oil. Failure to comply with these requirements or failure to
cooperate during a spill event may subject Responsible Parties to civil or
criminal enforcement actions and penalties.
Offshore Production. Offshore oil and gas operations are subject to
regulations of the United States Department of the Interior which currently
impose strict liability upon the lessee under a Federal lease for the cost of
clean-up of pollution resulting from the lessee's operations, and such lessee
could be subject to possible liability for pollution damages. In the event of a
serious incident of pollution, the Department of the Interior may require a
lessee under Federal leases to suspend or cease operations in the affected
areas.
Canadian Environmental Regulations. 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. Federal legislation governing
environmental performance includes the Canadian Environmental Protection Act and
the Navigable Protection Act. In Alberta, environmental compliance is regulated
by the Environmental Protection and Enhancement Act. The Waste Management Act
established environmental standards in British Columbia. Similarly, the
Environmental Management Protection Act governs compliance in Saskatchewan.
International Environmental Regulations. All phases of the oil and gas
industry are subject to regulatory oversight by various agencies and regulatory
bodies within each country. These governmental bodies provide for the protection
of the environment covering such items as emissions control, discharges,
permits, cleanups and land use.
EMPLOYEES
The Company had 2,223 employees as of February 29, 2000, 21 of which were
not full-time. 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, crude oil and NGLs, such as cratering,
explosions, uncontrollable flows of oil, gas or well fluids, fire, pollution and
other environmental risks. In general, many of these risks increase when
drilling at greater depths under higher pressure conditions. In addition,
certain of the Company's operations are offshore and subject to the additional
hazards of marine operations, such as capsizing, collision and damage or loss
from severe weather. Other operations involve the production, handling,
processing and transportation of gas containing hydrogen sulfide and other
hazardous substances. These hazards can cause personal injury and loss of life,
severe damage to and destruction of property and equipment, environmental damage
and suspension of operations. Litigation arising from a catastrophic occurrence
in the future at one of the Company's locations could result in the Company
being named as a defendant in lawsuits asserting potentially large claims. In
accordance with customary industry practices, insurance is maintained for the
Company against some, but not all, of the consequences of these
9
<PAGE> 12
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
otherwise already reserved.
ITEM 2. PROPERTIES
PROVED RESERVES
The following table sets forth the proved developed and undeveloped
reserves of natural gas, NGLs and crude oil of the Company as of December 31,
1999. Reserve estimates as of December 31, 1999 were prepared by the Company's
engineers. Information set forth in the table is based on reserve estimates of
the Company, prepared in accordance with the rules and regulations of the
Securities and Exchange Commission ("SEC").
<TABLE>
<CAPTION>
RESERVES AS OF DECEMBER 31, 1999
---------------------------------------
NATURAL
NATURAL GAS
GAS LIQUIDS CRUDE OIL TOTAL
CATEGORY (BCF) (MMBBL) (MMBBL) (BCFE)
- -------- ------- ------- --------- -------
<S> <C> <C> <C> <C>
Proved developed....................................... 2,691.5 59.8 216.8 4,351.1
Proved undeveloped..................................... 599.3 3.2 122.3 1,352.3
------- ---- ----- -------
Total proved reserves........................ 3,290.8 63.0 339.1 5,703.4
======= ==== ===== =======
Percent of total............................. 58% 6% 36% 100%
</TABLE>
There are numerous uncertainties inherent in estimating quantities of
proved reserves, including many factors beyond the control of the Company. The
reserve data set forth herein represent estimates only. Reservoir engineering is
a subjective process of estimating underground accumulations of crude oil and
natural gas that cannot be measured in an exact manner, and the accuracy of any
reserve estimate is a function of the quality of available data and of
engineering and geological interpretation and judgment.
ACREAGE
Land Grant and Other Fee Minerals. The Company owns fee mineral acreage
totaling 9,421 (gross) or 8,474 (net) thousand acres as of December 31, 1999. Of
this amount, 7,912 (gross) or 7,722 (net) thousand acres are within the
Company's Land Grant area. 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 operating area as of December
31, 1999 is set forth below.
<TABLE>
<CAPTION>
DEVELOPED UNDEVELOPED
ACRES ACRES TOTAL ACRES
------------- -------------- --------------
OPERATING AREA GROSS NET GROSS NET GROSS NET
- -------------- ----- ----- ------ ----- ------ -----
(IN THOUSANDS)
<S> <C> <C> <C> <C> <C> <C>
U. S. Onshore................................. 2,003 1,267 1,696 1,155 3,699 2,422
U. S. Offshore................................ 263 124 342 224 605 348
----- ----- ------ ----- ------ -----
Total United States................. 2,266 1,391 2,038 1,379 4,304 2,770
Canada........................................ 1,618 942 5,297 1,924 6,915 2,866
Guatemala..................................... 25 25 1,834 1,788 1,859 1,813
Venezuela..................................... 53 25 1,714 758 1,767 783
Other International........................... 476 85 2,229 656 2,705 741
----- ----- ------ ----- ------ -----
Total leasehold acreage............. 4,438 2,468 13,112 6,505 17,550 8,973
===== ===== ====== ===== ====== =====
</TABLE>
10
<PAGE> 13
Total Leasehold and Fee Mineral. The total leasehold and fee mineral
acreage by operating area as of December 31, 1999 is set forth below.
<TABLE>
<CAPTION>
TOTAL ACRES
---------------
OPERATING AREA GROSS NET
- -------------- ------ ------
(IN THOUSANDS)
<S> <C> <C>
U. S. Onshore............................................... 13,120 10,896
U. S. Offshore.............................................. 605 348
------ ------
Total United States............................... 13,725 11,244
Canada...................................................... 6,915 2,866
Guatemala................................................... 1,859 1,813
Venezuela................................................... 1,767 783
Other International......................................... 2,705 741
------ ------
Total leasehold and fee acreage................... 26,971 17,447
====== ======
</TABLE>
DRILLING ACTIVITY AND PRODUCING WELL SUMMARY
The table below summarizes the Company's drilling activity over the last
three years.
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
---------------------------------------------
1999 1998 1997
------------- ------------- -------------
GROSS NET GROSS NET GROSS NET
----- ----- ----- ----- ----- -----
<S> <C> <C> <C> <C> <C> <C>
Development wells:
Productive...................................... 553 413.1 511 357.8 685 478.6
Dry............................................. 23 18.1 39 27.2 59 46.2
Exploration wells:
Productive...................................... 47 43.1 64 46.1 35 19.1
Dry............................................. 20 15.1 22 18.0 38 22.1
--- ----- --- ----- --- -----
Total wells............................. 643 489.4 636 449.1 817 566.0
=== ===== === ===== === =====
</TABLE>
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, 1999, the Company owned a working interest in 9,194 gross gas wells
(6,047 net) and 4,106 gross oil wells (2,468 net). Gross wells include 2,265
wells with multiple completions. The Company operated 66 percent of the gross
wells in which it owned an interest.
DELEVERAGING PROGRAM -- PROPERTY SALES
In 1998, following the Norcen Acquisition, the Company commenced a
deleveraging program designed to reduce the Company's debt. The Company sold
approximately $745 million of non-strategic properties and assets in 1998 and
1999. The majority of the proceeds from the property sales, along with the
Company's sale of its GPM business segment, were primarily used to retire debt.
As a result of the property sales, the Company's reserves were reduced by 704.1
Bcfe in 1998 and 128.5 Bcfe in 1999. A summary of properties that have been sold
is as follows:
<TABLE>
<CAPTION>
SALES PRICE
NON-STRATEGIC PROPERTIES OPERATING AREA (MILLION OF DOLLARS)
- ------------------------ -------------- --------------------
<S> <C> <C>
1998
Denver -- Julesburg Basin............................ U.S. Onshore $ 41
Matagorda Island Blocks.............................. U.S. Offshore 158
Rockies Package...................................... U.S. Onshore 46
Eugene Island Blocks................................. U.S. Offshore 8
Canadian Package..................................... Canada 145
Superior Propane..................................... Canada 48
----
Total...................................... $446
====
1999
Caroline -- Swan Hill................................ Canada $108
South Texas Package.................................. U.S. Onshore 138
Deadwood East Texas.................................. U.S. Onshore 18
Rockies Package...................................... U.S. Onshore 10
Project Orange....................................... Other 25
----
Total...................................... $299
====
</TABLE>
11
<PAGE> 14
ITEM 3. LEGAL PROCEEDINGS
GENERAL
The Company is a defendant in a number of lawsuits and is involved in
governmental proceedings arising in the ordinary course of business, including,
but not limited to, royalty claims, contract claims and environmental claims.
The Company has also been named as a defendant in various personal injury
claims, including numerous claims by employees of third-party contractors
alleging exposure to asbestos and asbestos-containing materials while working at
the Corpus Christi refinery, which the Company sold in segments in 1987 and
1989. While the Company's management cannot predict the outcome of such
litigation and other proceedings, management does not expect these matters to
have a materially adverse effect on the consolidated results of operations,
financial condition or cash flows of the Company. Discussed below are several
specific proceedings.
MINERAL RESERVATION LITIGATION
In August 1994, the surface owners (McCormick, et al.) of portions of five
sections of Colorado land that are subject to mineral reservations made by the
Company's predecessor in title brought suit against the Company in State
District Court, Weld County, Colorado, to quiet title to minerals, including
crude oil (in some of the lands) and natural gas. On June 23, 1997, the State
District Court granted the Company's motion for summary judgment, holding as a
matter of law that the mineral reservations at issue were unambiguous and
included all valuable non-surface substances, including oil and gas. The
Colorado Court of Appeals affirmed the decision of the State District Court in
granting the Company's motion for summary judgment on December 10, 1998 and then
denied the surface owners' motion for rehearing. The surface owners then filed a
Petition for Writ with the Colorado Supreme Court, which was granted in
September 1999. Oral arguments are expected to be heard during the first half of
2000.
ROYALTY LITIGATION
The Company is a defendant in a number of lawsuits in which plaintiffs
allege that the Company underpaid royalties to them on crude oil and natural gas
production. In addition, certain of such suits allege that the Company has
violated antitrust laws and other similar laws. None of this litigation
specifies the amount of damages being claimed. This litigation against the
Company and others in the oil and gas industry suggests that more suits of this
type will be filed against the Company, including, perhaps, suits by other types
of interest owners and suits in other jurisdictions. The Company intends to
vigorously defend against such litigation, as well as any similar lawsuits
subsequently brought against the Company. In the opinion of management of the
Company, the outcome of these matters should not have a material adverse effect
on the consolidated results of operations, financial condition or cash flows of
the Company.
A group of royalty owners purporting to represent all of the Company's gas
royalty owners in Texas (Neinast, et al.) was granted class action certification
in December 1999, by the 21st Judicial District Court of Washington County,
Texas, in connection with a gas royalty underpayment case against the Company.
This court did not review the merits of the claims being asserted. The pleadings
did not specify the damages being claimed and no evidence has been provided to
the Company with respect to the amount of damages being claimed. The Company
appealed this class certification decision to the Houston Court of Appeals -
First District. This appeal is on an expedited schedule, with the Company filing
its brief on March 13, 2000.
During 1999, the Company, together with other oil and gas company
defendants, agreed to settle several suits involving allegations of royalty
underpayments on crude oil production. These settlements were without any
admission of fault or wrongdoing on the part of the Company. The Company's
portion of the settlements did not have a material adverse effect on
consolidated results of operations, financial condition or cash flows of the
Company.
12
<PAGE> 15
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, 1999.
EXECUTIVE OFFICERS OF THE REGISTRANT
<TABLE>
<CAPTION>
NAME POSITION AGE
- ---- -------- ---
<S> <C> <C>
George Lindahl III (a).................... Chairman, President and Chief Executive Officer 53
Thomas R. Blank (b)....................... Vice President -- State, Regulatory and Public 47
Affairs
Kerry R. Brittain (c)..................... Vice President, General Counsel and Secretary 53
Anne M. Franklin (d)...................... Vice President -- People 43
Donald W. Niemiec (e)..................... Vice President -- Marketing and Corporate 53
Development
Morris B. Smith (f)....................... Vice President, Chief Financial Officer and 55
Treasurer
John B. Vering (g)........................ Vice President -- Canadian Operations 50
</TABLE>
- ---------------
(a) Mr. Lindahl has held his current position with the Company since July 1999.
He was President and Chief Operating Officer from October 1996 to July 1999.
He was Executive Vice President -- Operations of the Company from August
1995 to October 1996. Prior thereto, he was Vice President -- Operations for
UPRC.
(b) Mr. Blank has held his current position with the Company since August 1997.
He was Communications Director for the Speaker of the House of
Representatives for the United States from February 1997 to August 1997.
Prior thereto, he was President of Hager Sharp, Inc.
(c) Mr. Brittain has held his current position with the Company since March
2000. Prior thereto, he was an Assistant General Counsel of the Company.
(d) Ms. Franklin has held her current position with the Company since August
1995. Prior thereto, she was Director of Executive Leadership and
Development for Ameritech, Inc.
(e) Mr. Niemiec has held his current position with the Company since September
1999. He served as Vice President -- Marketing from August 1995 until
September 1999. He has been Vice President -- Marketing of UPRC since 1993
and President of Union Pacific Fuels, Inc. ("UP Fuels") from 1990 to March
1999.
(f) Mr. Smith has held his current position as Vice President and Chief
Financial Officer with the Company since June 1996 and assumed the role of
Treasurer in June 1999. From September 1995 until June 1996, he was Vice
President and Controller of Union Pacific Corporation ("UPC"). Prior
thereto, he was Vice President -- Finance of Union Pacific Railroad Company.
(g) Mr. Vering has held his current position with the Company since March 1998.
From October 1996 until March 1998 he was Vice President -- Exploration and
Production Services of the Company. Prior thereto, he was General
Manager -- Austin Chalk of the Company.
13
<PAGE> 16
PART II
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER
MATTERS
The common stock of the Company is traded on the New York Stock Exchange
under the symbol "UPR." Information with respect to the quarterly high and low
sales prices per share for the Company's common stock, as reported on the New
York Stock Exchange Composite Tape, as well as the dividends declared on such
stock, is set forth under Selected Quarterly Data on page 85. At February 29,
2000, there were 251,952,336 shares of outstanding common stock and
approximately 113,400 shareholders of record. At that date, the closing price of
the common stock on the New York Stock Exchange was $8.9375.
The Company has paid quarterly cash dividends of $0.05 per share since its
initial public offering in October 1995. The Company currently intends to
continue to pay quarterly cash dividends on its outstanding shares of common
stock. The determination of the amount of future cash dividends, if any, to be
declared and paid by the Company will depend upon, among other things, (i) the
Company's financial condition, (ii) funds from operations, (iii) the level of
its capital and exploratory expenditures, (iv) future business prospects and (v)
other factors deemed relevant by the Board of Directors. Accordingly, there can
be no assurance that dividends will be paid. The Company has no current plans to
increase or decrease its dividend.
ITEM 6. SELECTED FINANCIAL DATA
FIVE-YEAR FINANCIAL SUMMARY
<TABLE>
<CAPTION>
AS OF OR FOR THE YEARS ENDED DECEMBER 31,
-------------------------------------------------------------
1999 1998 1997 1996 1995
-------- --------- -------- -------- --------
(MILLIONS, EXCEPT PER SHARE AMOUNTS)
<S> <C> <C> <C> <C> <C>
INCOME STATEMENT DATA:
Operating revenues................ $1,727.5 $ 1,841.0 $1,518.0 $1,369.2 $1,166.8(d)
Operating income (loss)........... 135.8 (1,193.2) 433.9 408.5 380.3
Income (loss) from continuing
operations...................... 89.2 (883.1) 303.1 253.7 294.2
Net income (loss)................. 225.8(a) (898.7)(b) 333.0 320.8 350.7
Per share:
Income (loss) from continuing
operations -- basic.......... 0.36 (3.57) 1.21 1.02 n/a(e)
Income (loss) from continuing
operations -- diluted........ 0.36 (3.57) 1.21 1.01 n/a(e)
Net income (loss) -- basic...... 0.91 (3.63) 1.33 1.29 n/a(e)
Net income (loss) -- diluted.... 0.91 (3.63) 1.33 1.28 n/a(e)
Dividends....................... 0.20 0.20 0.20 0.20 0.05(f)
FINANCIAL POSITION DATA:
Properties -- net................. $5,471.0 $ 6,093.3 $2,901.1 $2,404.7 $2,238.4
Total assets...................... 6,146.9 7,642.4 4,313.7 3,531.6 3,265.7
Total debt........................ 2,799.6 4,598.7 1,230.6 670.9 101.5
Shareholders' equity.............. 937.5 728.2 1,760.7 1,514.3 1,312.4
CASH FLOW DATA:
Capital and exploratory
expenditures.................... $ 428.2 $ 3,828.8(c) $1,188.4 $ 773.0 $ 603.0
Cash provided by operations....... 995.5 1,031.1 856.2 772.5 719.0
</TABLE>
- ---------------
(a) In 1999, the Company recorded a $157.0 million gain on the GPM Disposition,
net of tax and a $3.4 million net of tax extraordinary gain on the early
extinguishment of debt.
(b) In 1998, the Company recorded a $760 million after-tax charge related to
asset impairments in accordance with Statement of Financial Accounting
Standards No. 121, "Accounting for the Impairment of Long-Lived Assets and
for Long-Lived Assets to Be Disposed Of" ("SFAS No. 121").
14
<PAGE> 17
(c) In March 1998, the Company acquired Norcen for $2.634 billion.
(d) In November 1995, the Company recorded a $122.5 million pretax ($78.5
million after-tax) gain resulting from the Columbia Gas Transmission Company
bankruptcy settlement.
(e) Earnings per share information prior to 1996 has been omitted as the Company
was a wholly-owned subsidiary of UPC until the Company's initial public
offering in October 1995. Therefore, net income per share is not applicable
for periods prior to the fourth quarter of 1995.
(f) Represents the dividend declared with respect to the fourth quarter of 1995.
Prior to October 1995, the Company was wholly owned by UPC; therefore,
dividends per share is not applicable for prior periods.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
The following information should be read in conjunction with the
information contained in the Consolidated Financial Statements and the notes
thereto included in Item 8 of this Annual Report. The Consolidated Statement of
Income for 1997 has been restated to present the Company's GPM business segment
as discontinued operations.
SIGNIFICANT EVENTS
NORCEN ACQUISITION
In March 1998, the Company acquired Norcen for an aggregate purchase price
of $2.634 billion, and also assumed long-term debt obligations of Norcen
totaling approximately $1 billion. The acquisition was accounted for as a
purchase effective March 3, 1998, and, therefore, Norcen's financial results are
reflected in the Company's results beginning in March 1998. See Note 2 to the
Consolidated Financial Statements.
PROPERTY SALES AND GPM DIVESTITURE
In 1998, following the Norcen Acquisition, the Company commenced a
deleveraging program designed to reduce the Company's debt. By December 31,
1998, the Company had sold over $400 million of properties. Properties sold
included the Denver-Julesburg Basin in the Rockies (the "DJ Basin"), the
Matagorda Island Block 623 Field and surrounding blocks (the "Matagorda
property") and other U.S. Offshore, Rockies and certain Canadian properties.
During 1999, the Company continued its deleveraging program. The property
sales in 1999 included properties located in Canada's Caroline-Swan Hill field,
South Texas, and various properties in East Texas and the Rockies. The Company
also monetized a gas co-generation project.
In addition, the Company's sale of the GPM business segment to Duke was
completed on March 31, 1999 for $1.36 billion. The GPM business segment was
presented as a discontinued operation in the Consolidated Financial Statements.
See Note 3 to the Consolidated Financial Statements.
CRUDE OIL AND NATURAL GAS SALES PRICE AND HEDGING LOSSES
During 1998, prices for oil and natural gas declined as a result of several
factors. These factors included, but were not limited to, high production levels
from members of the Organization of Petroleum Exporting Countries ("OPEC") and
other countries, generally mild weather conditions, the economic weakness in
several Asian countries and excessive natural gas storage levels. These prices
were 29 percent and 10 percent, respectively, below the corresponding price
strips on December 31, 1997.
During 1999, prices for crude oil and natural gas increased. Members of
OPEC and other countries lowered crude oil production levels and natural gas
storage levels declined. The Company was unable to take full advantage of the
price increases, primarily due to solvency-based oil hedges that were put into
place at an average price of $14.50 per barrel. Those hedges, which expired in
December 1999, lowered revenues and operating income by about $178.1 million
during 1999.
15
<PAGE> 18
IMPAIRMENT OF LONG-LIVED ASSETS
The Company recorded a pretax charge of $1.23 billion ($760.1 million after
tax) in the fourth quarter of 1998, as required by SFAS No. 121. The non-cash
asset impairment charge to earnings was recorded as DD&A expense of $1.17
billion and surrendered lease expense of $54.5 million in the Company's
Consolidated Statement of Income. Low hydrocarbon prices at the end of
1998 -- particularly their effect on the value of the Company's heavy oil
properties in Canada and Guatemala -- and reserve revisions following a
comprehensive review of reserves completed in December 1998, were the principal
factors contributing to the impairment. Most of the reserve revisions were
associated with properties in Canada and U.S. Offshore that were acquired by the
Company in 1998. The revisions also reflect disappointing well performance from
discoveries that were not on production at the time of the Norcen Acquisition.
In 1999, the Company recorded a pretax charge of $120.6 million for
impairment of assets. The non-cash asset impairment charges to earnings were
recorded as DD&A expense of $70.6 million and surrendered lease expense of $50
million in the Company's Consolidated Statement of Income. Reserve revisions
following a comprehensive review of reserves was the principal factor
contributing to $70.6 million impairment of producing properties. These
properties were primarily in the Gulf Coast Onshore area. Surrendered lease
expense of $50.0 million was recorded for the Delta Centro project in Venezuela
as a result of a $9.2 million dry hole drilled on the prospect in 1999.
CORPORATE REORGANIZATION AND REDUCTION IN FORCE
As a result of the low price environment in 1998 and the resulting
reduction in cash flows generated by the Company's operations, the Company
recorded a pretax charge in 1998 of $17 million to cover the cost of a workforce
reduction at its Fort Worth, Texas headquarters and other domestic locations,
and costs associated with an offshore rig commitment.
During the first quarter of 1999, the Company reorganized its operating
groups, announced workforce reductions for its Canadian and U.S. operations and
established an early retirement program. As a result of these actions, the
Company recorded a $14.5 million restructuring charge. The charge included $7.3
million for severance costs and excess office space commitments, an additional
$4.2 million liability for pension and other postretirement benefits in
connection with the early retirement program and a $3.0 million valuation
allowance for specialty drilling equipment and supplies no longer required for
cancelled drilling programs. The charge was partially offset by the $3.1 million
reversal of the 1998 charge associated with the offshore rig commitment.
16
<PAGE> 19
RESULTS OF OPERATIONS
YEAR ENDED DECEMBER 31, 1999 COMPARED TO DECEMBER 31, 1998
SUMMARY FINANCIAL DATA
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
-------------------------
1999 1998
---------- -----------
(MILLIONS OF DOLLARS)
<S> <C> <C>
Total operating revenues.................................... $1,727.5 $ 1,841.0
Total operating expenses.................................... 1,591.7 3,034.2
Operating income (loss)..................................... 135.8 (1,193.2)
Income (loss) from continuing operations.................... 89.2 (883.1)
Net income (loss)........................................... 225.8 (898.7)
</TABLE>
The Company recorded net income of $225.8 million ($0.91 per share) in
1999, compared to a net loss of $898.7 million ($3.63 per share) in 1998. The
improvement was largely due to the recording of a $1.23 billion ($760.1 million
after-tax) SFAS No. 121 asset impairment in 1998, and a $157.0 million after-tax
gain on the 1999 sale of the GPM business segment to Duke. In addition, higher
commodity prices combined with cost reduction programs contributed to improved
results from continuing operations. A $3.4 million after tax extraordinary gain
was also recorded in 1999 on the extinguishment of debt. Restructuring charges
related to corporate reorganization and reductions in force were included in the
results of both 1999 ($11.4 million) and 1998 ($17.0 million).
RESULTS OF CONTINUING OPERATIONS
The Company recorded income from continuing operations of $89.2 million for
1999 compared to a loss of $883.1 million last year, with earnings per share of
$0.36 in 1999 up from a loss of $3.57 per share a year ago. Included in 1998
results was a charge of $1.22 billion ($756.0 million after-tax) related to the
asset impairment. Higher prices contributed $132.4 million to income, while
significant cost reductions were achieved as a result of cost control programs,
property sales and workforce reductions. These reductions resulted in a $65.2
million decrease in lease operating costs and substantially lower overhead
costs. Interest costs declined by $31.1 million due to the debt reduction
resulting from the use of proceeds from the Company's aggressive deleveraging
program and the GPM Disposition. The Company also recorded $58.1 million after
tax income for tax settlements in the United States and Canada and $97.5 million
after tax in higher gains from foreign currency remeasurement. Offsetting these
benefits were the impacts of lower volumes of $196.5 million, lower minerals
income of $15.7 million, lower gains on assets sales of $49.5 million and a
$43.4 million charge for natural gas firm transportation obligations associated
with the GPM Disposition.
SUMMARY OF SEGMENT FINANCIAL DATA
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
-------------------------
1999 1998
--------- -----------
(MILLIONS OF DOLLARS)
<S> <C> <C>
Segment operating income (loss):
Exploration and production................................ $ 122.5 $(1,199.2)
Minerals.................................................. 117.8 133.5
Corporate ("General and Administrative").................. (104.5) (127.5)
------- ---------
Total............................................. $ 135.8 $(1,193.2)
======= =========
</TABLE>
Operating income increased by $1.33 billion to $135.8 million for the year.
Exploration and production operating income, excluding the $1.22 billion 1998
asset impairment charge, increased by $104.1 million to $122.5 million. Lower
volumes reduced operating income by $196.5 million, while gains on sales of
assets and
17
<PAGE> 20
investments decreased by $21.0 million largely due to the sale of the Matagorda
property in 1998. Price improvements added $132.4 million to revenues, while
exploration and production expenses decreased by $60.3 million, associated with
reduced capital spending, lower volumes, cost saving initiatives, and the
restructuring of the Company. DD&A expenses, excluding impairments declined by
$201.8 million, caused by both lower volumes ($121.8 million) and DD&A per unit
rates ($80.0 million).
Minerals operating income decreased by $15.7 million to $117.8 million.
Black Butte equity income was down by $7.3 million to $79.3 million, primarily
due to coal contract obligations which were delayed until 2000, offset by the
absence of a $14.3 million accrual for a legal settlement in 1998. Coal
royalties declined by $3.7 million due to lower volumes of coal extracted and
sold from Company property. (See "Outlook and Other Matters" regarding Black
Butte equity income and a coal contract that expires in 2000). In addition, soft
market conditions for soda ash resulted in lower prices and a $4.6 million
decline in equity income and soda ash royalties, while lower future uranium mine
reclamation costs provided a $4.0 million offsetting income benefit.
General and administrative ("G&A") expenses decreased by $23.0 million,
reflecting lower legal costs and cost savings related to the reductions in force
that occurred in late 1998 and early 1999. Restructuring charges affected both
years -- $11.4 million in 1999 and $17.0 million in 1998. The 1999 reduction in
G&A was partially offset by $11.2 million of payroll expense related to the
vesting of the January 1999 retention stock awards.
EXPLORATION AND PRODUCTION OPERATIONS
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
-------------------------
1999 1998
---------- -----------
(MILLIONS OF DOLLARS)
<S> <C> <C>
Exploration and production revenues......................... $1,473.3 $ 1,537.4
Other oil and gas revenues................................ 133.7 162.5
-------- ---------
Total operating revenues.......................... 1,607.0 1,699.9
-------- ---------
Operating expenses:
Production................................................ 400.6 444.3
Exploration............................................... 267.9 339.0
Depreciation, depletion and amortization.................. 816.0 2,115.8
-------- ---------
Total operating expenses.......................... 1,484.5 2,899.1
-------- ---------
Operating income (loss)..................................... $ 122.5 $(1,199.2)
======== =========
</TABLE>
Operating Revenues
Exploration and production revenues decreased by $64.1 million (4%) to
$1,473.3 million for 1999, due to a $196.5 million reduction associated with
lower volumes, partly offset by a $132.4 million increase associated with higher
product prices. Other oil and gas revenues decreased by $28.8 million largely
due to $49.5 million in lower gains on property sales, offset by $28.5 million
of gains on the disposition of a gas co-generation project. Hedging positions in
both crude and natural gas products reduced revenues by $178.1 million for 1999
compared to a reduction of $9.0 million for 1998.
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
-----------------------------------
1999 1998 1999 1998
------- ------- ------ ------
(WITHOUT HEDGING) (WITH HEDGING)
<S> <C> <C> <C> <C>
Average price realizations:
Natural gas (per Mcf).................................... $ 1.94 $ 1.77 $ 1.83 $ 1.74
Natural gas liquids (per Bbl)............................ 10.95 7.88 10.95 7.88
Crude oil (per Bbl)...................................... 14.84 10.37 11.81 10.48
Average price (per Mcfe)................................. 2.10 1.72 1.88 1.71
</TABLE>
18
<PAGE> 21
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
-------------------------
1999 1998
--------- ---------
<S> <C> <C>
Production volumes:
Natural gas (MMcfd)....................................... 1,278.8 1,441.1
Natural gas liquids (MBbld)............................... 28.4 33.1
Crude oil (MBbld)......................................... 117.1 137.9
Total (MMcfed)............................................ 2,151.6 2,467.0
</TABLE>
Exploration and production volumes of 2,151.6 MMcfed decreased by 315.4
MMcfed (13%) from 1998 results primarily due to property sales (approximately
153 MMcfed) and production declines related to reduced capital spending levels.
Results for 1998 include only ten months of results from properties acquired
through the Norcen Acquisition.
U.S. Onshore volumes decreased by 236.5 MMcfed, reflecting the decline in
capital spending and effects of property sales, which contributed 58 MMcfed to
the decrease. U.S. Offshore volumes decreased by 42.9 MMcfed as the impact of
property sales (approximately 35 MMcfed) and production declines offset the full
year of production from properties acquired through the Norcen Acquisition.
Canadian volumes decreased by 56.9 MMcfed primarily related to the impact of
property sales (approximately 60 MMcfed) that were partially offset by the full
year of production from properties acquired through the Norcen Acquisition.
Other International volumes improved 20.9 MMcfed over 1998, primarily due to the
inclusion of the full year of volumes in 1999 from properties acquired through
the Norcen Acquisition.
Natural gas volumes decreased by 162.3 MMcfd to 1,278.8 MMcfd during 1999,
principally reflecting reduced capital spending levels, property sales and
production declines for existing properties, offset by the inclusion of a full
year of volumes from properties acquired through the Norcen Acquisition. Total
United States volumes declined by 159.7 MMcfd, while Canada volumes decreased by
3.4 MMcfd.
Natural gas liquid volumes decreased by 4.7 MBbld to 28.4 MBbld. The
decline is largely related to the sales of the offshore Matagorda property in
the third quarter of 1998 and the South Texas and the Canadian Caroline-Swan
Hill properties in early 1999, as well as production declines resulting from
reduced capital spending levels. Partially countering the decline was ethane
recovery in the U.S. Onshore for most of 1999.
Crude oil volumes declined by 20.8 MBbld to 117.1 MBbld for 1999. The
decrease reflects property sales as well as production declines in U.S. Onshore
and Canada, offset by the full year of Norcen property volumes in 1999. U.S.
Onshore volumes declined by 15.8 MBbld, while Canada volumes decreased by 6.6
MBbld. Other International volumes improved 3.3 MBbld largely due to the
inclusion of the full year of production from properties acquired through the
Norcen Acquisition.
Operating Expenses
Production expenses, which include lease operating costs, production
severance and property taxes, and production overhead, were $400.6 million for
1999, down $43.7 million from last year. Production costs per unit increased
from $0.49 per Mcfe last year to $0.51 per Mcfe for 1999, reflecting the impacts
of production declines and higher production taxes caused by higher prices.
Total lease operating costs declined by $65.2 million primarily due to property
sales and cost reduction efforts initiated in late 1998. Included in the lease
operating cost decline were lower costs for personnel, workovers, maintenance
and repairs and salt water disposal. The reduction was significant as 1999
results include the full year of expenses related to the properties acquired
through the Norcen Acquisition. Lease operating expenses on a per unit basis
dropped from $0.34 per Mcfe in 1998 to $0.31 per Mcfe. Production severance and
property taxes increased by $23.8 million from last year, reflecting increased
product prices for U.S. Onshore and Guatemalan operations, as well as $8.2
million related to severance tax audit adjustments. Production overhead costs
decreased by $2.3 million from 1998, despite $3.6 million of production overhead
costs related to the vesting of the January 1999 retention stock awards. The
majority of the overhead savings in 1999 was the result of lower personnel and
related costs in connection with the reductions in work force.
19
<PAGE> 22
Exploration expenses of $267.9 million decreased by $71.1 million from last
year, primarily due to the Company's reduced capital spending program. Dry hole
expenses decreased by $17.2 million, geological and geophysical costs were $30.5
million lower and other surrendered lease costs dropped $13.4 million. Included
in 1999 dry hole expenses was $24.0 million related to a well that was
reclassified to an exploratory dry hole in the fourth quarter of 1999.
Exploration overhead costs declined by $6.2 million primarily from reductions in
personnel ($2.1 million) and computer costs ($2.9 million) caused by work force
reductions.
DD&A costs for exploration and production properties declined by $1.3
billion from last year to $816.0 million. Included in the 1999 results was $65.1
million, primarily related to the impairment of certain U.S. Onshore properties,
while 1998 results included $1,163.1 million related to producing property
impairments. Excluding the impairments, lower production volumes caused a $121.8
million reduction, while lower DD&A rates produced an $80.0 million decline.
DD&A per unit rates decreased from $1.06 per Mcfe last year to $0.96 per Mcfe in
1999 largely due to the asset impairment recorded by the Company in 1998.
MINERALS OPERATIONS
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
------------------------
1999 1998
-------- --------
(MILLIONS OF DOLLARS)
<S> <C> <C>
Operating Income
Coal...................................................... $ 91.1 $101.5
Soda ash.................................................. 26.3 35.5
Other..................................................... 0.4 (3.5)
------ ------
Total operating income............................ $117.8 $133.5
====== ======
</TABLE>
Operating income for minerals declined by $15.7 million from last year.
Equity income from the Black Butte joint venture declined by $7.3 million
reflecting lower volumes resulting from postponement of contract obligations
until 2000, partially offset by the absence of a $14.3 million accrual in 1998
for a legal settlement (See "Outlook and Other Matters" regarding the Black
Butte Contract expiration in 2000). Coal royalty income decreased by $3.7
million from lower volumes as mining operations focused on Federal sections, and
soda ash royalties decreased by $4.6 million reflecting soft conditions in the
soda ash market. Operating income at the Company's soda ash joint venture was
down $4.6 million, also related to the soft conditions in the soda ash market.
Results in 1999 also include a $4.0 million reserve release related to lower
reclamation requirements and a $5.5 million impairment charge, while results
from 1998 include a $2.0 million gain on the sale of industrial mineral
properties and a $4.0 million asset impairment charge.
GENERAL AND ADMINISTRATIVE AND OTHER INCOME/EXPENSE
General and administrative expenses (including DD&A) of $104.5 million
decreased by $23.0 million from 1998. Restructuring charges affected both
years -- $11.4 million in 1999 and $17.0 million in 1998 -- both related to a
corporate reorganization and reductions in work force. Included in 1999 general
and administrative expenses were $11.2 million of payroll expense related to the
vesting of the January 1999 retention stock awards. Contributing to lower costs
in 1999 were benefits in several cost categories reflecting savings from the
late 1998 and early 1999 reductions in force, early retirement programs and the
GPM Disposition. These savings contributed to declines of $5.2 million in
salaries and benefits, $4.2 million in computer costs, $3.0 million in
professional and temporary services and $1.7 million in rent expense. In
addition, legal costs decreased by $2.8 million and donations decreased by $2.1
million.
Other income/expense -- net increased by $77.0 million over 1998 to income
of $31.7 million for 1999. Causing the majority of the improvement was 1999
foreign currency gains of $44.2 million primarily related to the remeasurement
of U.S. dollar denominated debt in Canada, while 1998 results included a $46.5
million charge related to the same issue. Interest income increased by $19.4
million to $30.5 million in 1999, principally related to interest income from
the Canadian ($7.1 million) and UPC ($20.5 million) tax settlements. Also
included in 1999 results was a charge of $43.4 million for natural gas firm
transportation
20
<PAGE> 23
contract obligations. Results in 1998 included a $14.3 million charge related to
the expiration of interest rate lock contracts intended to hedge interest rates
for a contemplated bond issuance, and an $11.0 million gain on the closure of a
foreign exchange contract entered into in connection with the 1998 Norcen
Acquisition.
Interest expense declined by $31.1 million to $218.7 million in 1999,
reflecting reduced debt balances partly offset by higher interest rates on fixed
rate debt. The debt reduction is primarily the result of the use of proceeds
from the sale of the GPM business segment to pay down debt at the end of March
1999, as well as other actions taken to reduce debt since mid-1998 in connection
with the Company's deleveraging program. Interest expense in 1998 included only
ten months of interest on debt from the Norcen Acquisition, completed on March
3, 1998.
The income tax benefit from continuing operations declined by $464.8
million to $140.4 million for 1999. Lower pretax loss from continuing
operations, primarily due to the 1998 SFAS No. 121 asset impairment charge,
which had provided a tax benefit of $464.6 million in 1998. Included in 1999
results were benefits of $27.9 million related to a Canadian tax settlement and
$11.9 million related to a tax settlement with UPC (See Note 8). Also offsetting
the decline, was the recording of $28.1 million of favorable tax adjustments in
1999 primarily related to prior years and a $9.2 million reduction in state
taxes. Section 29 credits were $17.9 million in 1999 and $16.4 million in 1998,
while 1999 also included $29.3 million of foreign currency gains related to the
remeasurement of deferred tax liabilities in Guatemala and Venezuela, compared
to gains of $22.5 million included in 1998.
RESULTS OF DISCONTINUED OPERATIONS
Income from discontinued operations, net of taxes, was $133.2 million for
1999, an increase of $148.8 from 1998 results. The variance is due to the $157.0
million after-tax gain from the GPM Disposition. GPM business segment operating
loss for 1999 was $23.8 million after-tax primarily due to a $21.5 million
pretax charge related to firm transportation contracts that were marked to
market, as well as lower margins and product prices.
RESULTS OF OPERATIONS
YEAR ENDED DECEMBER 31, 1998 COMPARED TO DECEMBER 31, 1997
SUMMARY FINANCIAL DATA
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
------------------------
1998 1997
---------- ---------
(MILLIONS OF DOLLARS)
<S> <C> <C>
Total operating revenues.................................... $ 1,841.0 $1,518.0
Total operating expenses.................................... 3,034.2 1,084.1
Operating income (loss)..................................... (1,193.2) 433.9
Income (loss) from continuing operations.................... (883.1) 303.1
Net income (loss)........................................... (898.7) 333.0
</TABLE>
The Company recorded a net loss of $898.7 million in 1998, or a loss of
$3.63 per share, compared to net income of $333.0 million, or $1.33 per share,
in 1997. The decrease is primarily due to the impact of the SFAS No. 121 asset
impairment of $1.23 billion ($760.1 million after tax), the majority of which
affected continuing operations, and lower product prices.
21
<PAGE> 24
RESULTS OF CONTINUING OPERATIONS
In 1998, the Company reported a net loss from continuing operations of
$883.1 million, compared to income from continuing operations of $303.1 million
in 1997. Included in 1998 results was a charge of $1.22 billion ($756.0 million
after tax) for the asset impairment. The additional volumes from the Norcen
Acquisition added revenues of $456.7 million, while depressed product prices
reduced revenues from non-Norcen properties by more than $200 million as average
prices declined 22 percent. Additional factors that impacted income, primarily
driven by the Norcen Acquisition, were $273.9 million of higher production,
exploration and administrative expenses and $210.3 million of higher interest
expense. Included in administrative expenses was a restructuring charge of $17.0
million related to a reduction in force of the Company's domestic operations.
The Company realized a $140.0 million improvement to operating income as a
result of gains on the sale of various properties.
SUMMARY OF SEGMENT FINANCIAL DATA
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
-------------------------
1998 1997
---------- -------
(MILLIONS OF DOLLARS)
<S> <C> <C>
Segment operating income (loss):
Exploration and production................................ $(1,199.2) $373.4
Minerals.................................................. 133.5 135.5
Corporate ("General and Administrative").................. (127.5) (75.0)
--------- ------
Total............................................. $(1,193.2) $433.9
========= ======
</TABLE>
The operating loss was $1,193.2 million in 1998 compared to operating
income of $433.9 million in 1997. Exploration and production operating income,
excluding the asset impairment related to such properties, declined by $355.1
million to $18.3 million. These results reflect lower prices for all products
and increased operating, exploration and DD&A costs, which offset higher volumes
and the gains on the sale of various properties. Minerals operating income
dropped slightly to $133.5 million due to a $14.3 million accrual for a legal
settlement and a $4.0 million asset impairment but was partially offset by
increased operating income due to an amended coal supply agreement at Black
Butte. General and administrative expenses, excluding the restructuring charge,
increased by $35.5 million primarily due to increased administrative expenses
associated with expanded Canadian and Other International operations and an $8.2
million charge related to the settlement of various crude royalty and tax
issues.
EXPLORATION AND PRODUCTION OPERATIONS
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
-------------------------
1998 1997
--------- --------
(MILLIONS OF DOLLARS)
<S> <C> <C>
Exploration and production revenues......................... $ 1,537.4 $1,293.5
Other oil and gas revenues.................................. 162.5 84.7
--------- --------
Total operating revenues.......................... 1,699.9 1,378.2
Production expense.......................................... 444.3 300.8
Exploration expense......................................... 339.0 204.7
Depreciation, depletion and amortization.................... 2,115.8 499.3
--------- --------
Total operating expenses.......................... 2,899.1 1,004.8
--------- --------
Operating income (loss)..................................... $(1,199.2) $ 373.4
========= ========
</TABLE>
Operating Revenues
Exploration and production revenues increased by $243.9 million (19%) to
$1,537.4 million, $456.7 million of which were associated with properties added
in the Norcen Acquisition. Excluding the Norcen
22
<PAGE> 25
Acquisition properties, volumes were essentially flat to 1997 production levels;
however, product price declines reduced revenues by $211.0 million. Other oil
and gas revenues increased by $77.8 million from higher gains on property sales,
principally the sales of the DJ Basin and the Matagorda property.
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
-----------------------------------
1998 1997 1998 1997
------- ------- ------ ------
(WITHOUT HEDGING) (WITH HEDGING)
<S> <C> <C> <C> <C>
Average price realizations:
Natural gas (per Mcf).................................... $ 1.77 $ 2.19 $ 1.74 $ 2.00
Natural gas liquids (per Bbl)............................ 7.88 11.23 7.88 11.23
Crude oil (per Bbl)...................................... 10.37 18.80 10.48 18.36
Average price (per Mcfe)................................. 1.72 2.34 1.71 2.19
</TABLE>
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
------------------------
1998 1997
-------- --------
<S> <C> <C>
Production volumes:
Natural gas (MMcfd)....................................... 1,441.1 1,108.5
Natural gas liquids (MBbld)............................... 33.1 31.7
Crude oil (MBbld)......................................... 137.9 52.9
Total (MMcfed).................................... 2,467.0 1,615.7
</TABLE>
Exploration and production volumes improved by 851.3 MMcfed to 2,467.0
MMcfed in 1998. Canada volumes were 481.0 MMcfed higher than last year, while
Other International volumes increased by 244.1 MMcfed, in both cases primarily
due to properties added in the Norcen Acquisition. Production from domestic
properties increased by 126.2 MMcfed including 97.2 MMcfed added in U.S.
Offshore largely from the Norcen Acquisition which offset the sale of the
Matagorda property. U.S. Onshore realized an increase of 54.5 MMcfed in 1998.
Natural gas volumes increased by 332.6 MMcfd (30%). Canada volumes
increased by 263.6 MMcfd and U.S. Offshore production was up 64.1 MMcf, largely
due to properties added in the Norcen Acquisition. U.S. Onshore production was
essentially flat due to declines in the Austin Chalk area that offset
improvements in all other areas.
Natural gas liquids volumes increased by 1.4 MBbld (4%) to 33.1 MBbld.
Production improvements included 2.5 MBbld in Canada largely due to the Norcen
Acquisition. This increase was partially offset by lower volumes from the U.S.
Onshore as a result of the decision to reject ethane and bypass gas due to low
NGL prices.
Crude oil volumes were 85.0 MBbld higher in 1998 primarily from properties
added in the Norcen Acquisition. Canada production was 33.7 MBbld higher for
1998, while additional production from Guatemala and Venezuela was 20.8 MBbld
and 16.7 MBbld, respectively. U.S. Onshore production was up 8.0 MBbld.
Operating Expenses
Production expenses increased by $143.5 million while production costs on a
per unit basis were $0.49 per Mcfe, 4 percent less than last year's $0.51 per
Mcfe. Total lease operating expenses rose by $141.3 million, of which $135.4
million was attributable to Norcen Acquisition properties. Lease operating
expenses on a per unit basis were up 22 percent to $0.34 per Mcfe which reflects
higher operating expenses associated with the production of heavy crude oil in
Guatemala, Venezuela and Canada. Production overhead costs were up $2.6 million
largely because of increased personnel costs due to the expanded international
operations.
Exploration expenses in 1998 increased by $134.3 million over 1997,
including $54.5 million of surrendered lease costs that were part of the SFAS
No. 121 asset impairment. Excluding the effect of the asset impairment, activity
related to properties added in the Norcen Acquisition contributed $72.8 million
to the increase. For domestic operations, exploration expenses were up 3 percent
to $210.8 million, excluding the surrendered lease asset impairment.
23
<PAGE> 26
DD&A increased by $1,616.5 million, including $1,163.1 million related to
the SFAS No. 121 asset impairment. On a per unit basis, DD&A expense, excluding
the asset impairment, rose $0.21 per Mcfe to $1.06 per Mcfe. Properties added in
the Norcen Acquisition contributed $377.4 million, excluding the asset
impairment. The remaining variance from non-Norcen Acquisition properties, $76.0
million, is associated with higher volumes that caused $11.3 million of the
total increase in DD&A, while a higher per unit rate added $64.7 million.
MINERALS OPERATIONS
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
------------------------
1998 1997
-------- --------
(MILLIONS OF DOLLARS)
<S> <C> <C>
Operating Income
Coal...................................................... $101.5 $ 83.3
Soda ash.................................................. 35.5 49.5
Other..................................................... (3.5) 2.7
------ ------
Total operating income............................ $133.5 $135.5
====== ======
</TABLE>
Minerals operating income decreased by $2.0 million. Contributing to the
decline was $14.0 million of lower operating income from soda ash operations,
reflecting lower royalties, lower equity income from the Company's soda ash
joint venture and the inclusion of a lease bonus in 1997 results. Also affecting
1998 performance was a $14.3 million accrual for a legal settlement and a $4.0
million asset impairment on certain industrial mineral and uranium properties.
Partly offsetting these items were $19.7 million of higher equity income from
Black Butte reflecting the amendment of a coal supply contract and a $2.0
million gain from a property sale.
GENERAL AND ADMINISTRATIVE AND OTHER INCOME/EXPENSE
General and administrative expenses increased by $52.5 million to $127.5
million, principally reflecting $21.1 million related to expanded international
operations and the $17.0 million restructuring charge. Also contributing to the
increase was an $8.2 million charge related to the settlement of various crude
royalty and tax issues, $3.3 million of additional rent expense, $2.4 million in
higher professional and temporary costs, and a $1.9 million rise in DD&A expense
for domestic overhead. On a per unit basis, excluding the restructuring charge,
G&A expenses were flat as compared to 1997 at $0.12 per Mcfe.
Other income/expense was $69.8 million lower than 1997 results. The
reduction reflects a $46.5 million foreign currency exchange rate loss and a
$14.3 million charge related to the expiration of interest rate lock contracts
intended to hedge such rates for a contemplated bond issuance. In addition, 1997
results included the benefit of a $23.0 million partial reduction of reserves
associated with the 1994 sale of the Wilmington, California oil field, due to
the reduction of environmental remediation exposure, a $7.2 million gain on the
sale of securities held for investment and $6.7 million of higher environmental
insurance settlements. Partly offsetting these declines were an $11.0 million
gain on the closure of a foreign exchange contract entered into in connection
with the Norcen Acquisition and the inclusion in 1997 of $17.8 million of costs
related to the unsuccessful bid to acquire Pennzoil Company.
Interest expense increased by $210.3 million to $249.8 million. This
increase reflects the borrowings made in connection with the Norcen Acquisition
and capital spending programs. Interest expense allocated to discontinued
operations was $21.1 million in 1998 and $13.6 million in 1997.
Income taxes declined by $721.0 million from 1997 to a benefit of $605.2
million, primarily the result of the pretax net loss in 1998. Included in 1998
results was a $22.5 million benefit due to foreign currency gains on deferred
tax liabilities in Venezuela and Guatemala. Section 29 tax credits in 1998 were
$16.4 million compared to $18.8 million in 1997. The effective tax rate in 1998
was 40.6 percent versus 28.6 percent in 1997 largely due to the effect of the
acquisition and expansion of operations outside the United States where higher
tax rates exist.
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<PAGE> 27
RESULTS OF DISCONTINUED OPERATIONS
Results from discontinued operations generated a net loss of $15.6 million
for 1998, compared to income of $29.9 million in 1997. The segment reported an
operating loss of $1.0 million for 1998 versus operating income of $61.3 million
in 1997. Operating margins decreased by more than $45.0 million from 1997 due to
low product prices that were not offset by lower gas purchase prices. Operating
revenues decreased by $66.7 million from 1997 largely due to the $35.2 million
($23.0 million after tax) charge related to firm transportation contracts that
were marked to market in connection with the GPM Disposition, and lower product
prices. Volumes were up two percent while other benefits to income include the
$30.0 million pretax gain on the settlement of a gas supply agreement and lower
operating expenses that decreased by $17.9 million.
LIQUIDITY AND CAPITAL RESOURCES
The Company's primary sources of cash during 1999 were cash provided by
operations, long-term debt issuance and proceeds from the GPM Disposition and
other assets associated with the Company's deleveraging program. Cash outflows
for 1999 included the repayment of debt, capital and exploratory expenditures,
interest and dividends.
Cash from operations of $995.5 million was $35.6 million lower than in
1998. Higher prices provided $132.4 million, while lower volumes caused a
reduction of $196.5 million. Improvements were also achieved, primarily from tax
settlements ($65.9 million), lower lease operating costs ($65.2 million) and
interest expense ($31.1 million), as well as favorable results from the
Company's cost control programs. However, these improvements were offset by
lower minerals income, cash payments related to restructuring charges and
unfavorable changes in other working capital items.
Cash provided by investing activities was over $1.0 billion in 1999, up
from a usage of $3.3 billion last year. During 1999, the Company received
proceeds of $1.36 billion from the GPM Disposition, while 1998 included a $2.6
billion payment for the acquisition of Norcen. Proceeds from sales of assets and
other investments of $281.3 million were $203.7 million lower than 1998,
primarily reflecting higher 1998 property sales and asset monetizations in
connection with the Company's deleveraging program. Discontinued operations
required a use of cash of $203.6 million in 1999 compared to providing a $50.4
million source of cash in 1998.
Capital and exploratory expenditures from continuing operations (excluding
the Norcen Acquisition) decreased by $766.3 million from $1.2 billion in 1998 to
$428.2 million for 1999, reflecting the Company's effort to control capital
spending in light of depressed product prices early in 1999 and to achieve debt
reduction goals. The 1998 amounts set forth below include capital expenditures
for Norcen properties beginning in March.
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<PAGE> 28
CAPITAL AND EXPLORATORY EXPENDITURES
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
-------------------------
1999 1998
-------- ----------
(MILLIONS OF DOLLARS)
<S> <C> <C>
Exploration and production
Exploration............................................... $ 78.1 $ 286.3
Production................................................ 329.7 764.9
Property purchases........................................ 15.3 110.7
------ --------
Total exploration and production.................. 423.1 1,161.9
Minerals, G&A and other..................................... 5.1 32.6
------ --------
Sub-total continuing operations........................... 428.2 1,194.5
Norcen purchase price....................................... -- 2,634.3
------ --------
Continuing operations............................. $428.2 $3,828.8
====== ========
Discontinued operations -- GPM.................... $ 32.9 $ 143.8
====== ========
</TABLE>
Exploration and production capital spending was down by $738.8 million to
$423.1 million, principally reflecting the effort to control capital spending in
light of depressed product prices early in 1999 and to achieve debt reduction
goals. The major categories of capital spending included development drilling
($232.6 million), other development capital ($97.2 million) and exploratory
drilling ($36.6 million). Exploration and development drilling by area included
$143.0 million in U.S. Onshore, $32.5 million in U.S. Offshore, $74.0 million in
Canada and $19.7 million in Other International, including $11.6 million in
Venezuela. Minerals, G&A and other capital was down $27.5 million to $5.1
million as spending in 1998 included costs related to the Fort Worth office
relocation.
As of December 31, 1999 and 1998, the total capitalization of the Company
was as follows:
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
------------------------
1999 1998
--------- ---------
(MILLIONS OF DOLLARS)
<S> <C> <C>
Long-term and short-term debt:
Commercial paper and other, net........................... $ 135.1 $2,351.9
Notes and debentures...................................... 2,630.5 2,225.0
Capital lease obligations................................. 16.0 17.4
(Discount) premium on notes and debentures -- net......... 18.0 4.4
-------- --------
Total debt........................................ 2,799.6 4,598.7
Shareholders' equity........................................ 937.5 728.2
-------- --------
Total capitalization.............................. $3,737.1 $5,326.9
======== ========
Debt to total capitalization.............................. 74.9% 86.3%
</TABLE>
At year-end 1998, the Company had three debt facilities totaling an
aggregate of U.S. $2.5 billion. These facilities were comprised of a $1.0
billion 364-Day Competitive Advance/Revolving Credit Agreement (the "Bridge
Facility"), a $750 million 364-Day Competitive Advance/Revolving Credit
Agreement and a $750 million Competitive Advance/Revolving Credit Agreement
("Long-Term Facility") expiring in October 2003.
In April 1999, the Company issued $500 million of notes and debentures
comprised of $200 million 7.3% Notes due April 2009 and $300 million 7.95%
Debentures due April 2029. The notes and debentures were issued under the
Company's existing $1.0 billion shelf registration statement, of which $500
million remains available.
During the first half of 1999, commercial paper, supported in part by the
Company's Bridge Facility, was repaid using proceeds from the Company's
deleveraging program and the GPM Disposition and the issuance
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<PAGE> 29
of the long-term notes and debentures. The Bridge Facility was terminated in
April 1999. The $750 million 364-Day Competitive Advance/Revolving Credit
Agreement expired in October 1999, leaving the Company with the Long-Term
Facility at year-end 1999. The Long-Term Facility contains a covenant
stipulating that the ratio of consolidated debt to consolidated EBITDAX -- the
sum of operating income (before adjustments for income taxes, interest expense
or extraordinary gains or losses), depreciation, depletion and amortization and
exploration expenses -- cannot exceed 3.25:1.00. The Long-Term Facility also
places other restrictions on the Company regarding the creation of liens,
incurrence of additional indebtedness by subsidiaries, transactions with
affiliates, sales of stock of Union Pacific Resources Company (a wholly-owned
subsidiary of the Company) and certain mergers, consolidations and asset sales.
The Company was in compliance with the covenant provisions at year-end 1999 and
1998.
The 2005, 2008 and 2009 Notes and the 2018, 2028 and 2029 Debentures are
redeemable as a whole or in part, at the option of the Company at any time. The
redemption price is equal to the greater of (i) 100% of the principal amount of
the securities to be redeemed or (ii) the sum of the present values of the
remaining scheduled payments thereon, discounted to the redemption date on a
semi-annual basis at the Treasury Rate, plus a stated basis point spread and
accrued interest on the principal amount being redeemed to the redemption date.
There are no other notes or debentures redeemable prior to maturity. None of the
Company's notes and debentures is subject to a sinking fund requirement. At
December 31, 1999, the Company had an effective shelf registration statement on
file with the Securities and Exchange Commission that would permit the Company
or certain identified subsidiaries to offer up to $500 million in debt, equity
and/or other securities.
During 1999, the Company purchased on the open market and retired long-term
debt with a face value of $94.5 million at a discount prior to maturity. The
retirement of long-term debt due to the repurchases resulted in an extraordinary
gain of $3.4 million, net of $1.8 million of tax. The gain on the retirement was
classified as a gain from an extraordinary item on the Consolidated Statement of
Income. The Company may, at its discretion, make additional open market
purchases of debt prior to maturity.
At December 31, 1999, $135.1 million of commercial paper and bankers'
acceptances were classified as long-term. This classification reflects the
Company's intent and ability to maintain these borrowings on a long-term basis,
supported by the Long-Term Facility, through the issuance of additional
commercial paper and/or new term financings. Debt maturities through 2004,
excluding capital leases, are $135.1 million of bankers' acceptances due in 2000
and $250 million of debentures due July 2, 2002.
The fair value of the Company's long-term debt, excluding commercial paper
and bankers' acceptances, debt discount/premium and capital lease obligations
was approximately $2,467 million at December 31, 1999 and $2,088 million at
December 31, 1998. The fair value was estimated using quoted market prices.
These fair values were trading at a discount to their face value of 93.8% at
December 31, 1999 and 1998.
In April 1999, the Company's senior unsecured credit ratings were
downgraded by Standard & Poor's to BBB-, and by Moody's to Baa3. Its commercial
paper ratings were downgraded by Standard & Poor's to A3 and by Moody's to P3.
Fitch IBCA has continued to rate the Company's senior unsecured credit with a
BBB+ rating and its commercial paper with a F2 rating. The Company expects these
ratings to improve as debt is paid down.
The Company has guaranteed a portion of the OCI Wyoming, L.P. debt
facility. At December 31, 1999, OCI Wyoming, L.P. had an outstanding debt
facility balance of $30 million, of which the Company has guaranteed $14.7
million.
The Company utilizes letters of credit to support certain financing
instruments, performance contracts and insurance policies. The fair value of the
letters of credit at December 31, 1999 and 1998 was $41.3 million and $58.6
million, respectively.
During 1998, the Company purchased $26.7 million of its common stock.
During 1999, the Company paid quarterly cash dividends of $0.05 per share on its
outstanding common stock, and on October 21,1999, declared a $0.05 per share
dividend that was paid on January 2, 2000. 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,
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<PAGE> 30
the Company's financial condition, funds from operations, the level of its
capital and exploratory expenditures, future business prospects and other facts
deemed relevant by the Board of Directors. Accordingly, there can be no
assurance that dividends will be paid.
OUTLOOK AND OTHER MATTERS
The Company expects its average oil and gas production to decline slightly
in 2000 compared to 1999. Production declines during the first part of 2000 are
expected to be reversed in the second half of 2000 and following years, as the
Company increases its capital spending and new projects are completed and placed
into service. The Company's proved reserves declined by about seven percent in
1999. The Company's ability to replace reserves in 1999 was impacted by the
postponement of the Mississippi Canyon Block 755 ("Gomez") deep-water offshore
prospect until 2000, together with the declines related to reduced capital
spending in 1999. The Company's reserve replacement costs were $0.91 per Mcfe,
which was below its five year average of $1.10 per Mcfe. In 2000, the Company
expects to modestly grow its reserves through development drilling programs and
to continue to pursue exploration opportunities.
Prices for crude oil, natural gas and NGLs in the first quarter of 2000
were higher than historic average hydrocarbon prices. NYMEX crude oil prices
have risen sharply from about $10 per barrel in early 1999 to over $30 per
barrel in early 2000, as the demand for crude oil has exceeded worldwide
production and inventory. Reduced crude oil production by members of OPEC and an
increase in consumption of crude oil in Asian countries resulting from their
improved economies have contributed to the greater demand for crude oil. The
increase in natural gas prices in the first quarter of 2000 reflects the tight
natural gas supplies compared to United States demand. Cold weather in early
2000 in the northeast United States, an increase in demand for the industrial
use of natural gas and lower production resulting from the decline in drilling
in prior years have contributed to the draw down in gas inventory supplies. The
Company expects prices to remain high in 2000; however, price fluctuations could
affect expected future net income, cash flows, capital spending and debt
reduction. For 2000, the Company has reduced some of its exposure to lower
prices by purchasing puts and fixed price contracts and limited some of the
upside of higher prices by selling calls and fixed price contracts. Slightly
more than one-half of the Company's estimated 2000 production was hedged in
early 2000.
The Company plans to increase its capital spending in 2000 from the $428
million spent in 1999 to approximately $650 million for exploration and
development projects. The Company plans an additional $100 million for select
property acquisitions. The capital program will be funded through cash provided
by operations. Almost 83 percent of the capital budget will be focused on the
development of fields which have already been proved and which are expected to
provide more immediate cash flow with low risk. The remainder of the Company's
budget will be for select exploration projects and other development drilling
that has the potential for long-term impact. Both the development and
exploration programs will employ the Company's ongoing strategy of applying its
expertise in advanced drilling and completion technologies. Approximately 38
percent of the capital budget will be invested in U.S. Onshore, 29 percent in
Canada, 14 percent in U.S. Offshore and 19 percent in Other International. The
Company may adjust its capital spending as commodity prices and cash flows
change. The extent and timing of capital spending may also be affected by
changes in business, financial and operating conditions as well as by the timing
and availability of suitable investment opportunities. See "Outlook and Other
Matters."
In U.S. Onshore, the Company plans to drill delineation wells in the
Etouffee discovery area in South Louisiana and a well in its Turtle Soup
prospect near the Etouffee discovery. Using its horizontal drilling expertise,
the Company plans to expand its success in the Frontier area of the Green River
Basin in the Land Grant. After its success in 1999 with the Rock Island 4H, the
Company made plans to drill four additional wells in the deep over-pressured
Frontier formation to further understand the formation's potential. These wells
include the Table Rock 115H, Sage Flat Unit 7H, Sidewinder 1H and Sidewinder 2H.
Although several of the wells drilled in early 2000 near the Rock Island 4H were
not successful, the formation's resources are large so the Company will continue
to test the Frontier formation during 2000 to further understand its potential.
In the U.S. Offshore, the Company plans to drill an exploration well at Garden
Banks Block 700 and a Green Canyon Block 281 exploration well. Additionally, the
Company plans to drill another well during 2000
28
<PAGE> 31
at its Gomez discovery. In Canada, the Company expects to start producing its
1999 Klua discovery well and is set to spud an adjacent well in the northeast
British Columbia territory. An exploratory well at the Sullivan Creek prospect
in southwestern Alberta is also planned during the second half of 2000. The
Company is continuing its Canadian heavy oil drilling program which began in the
fourth quarter 1999. In Guatemala, the Company plans to drill step-out wells in
the Xan area in addition to a high potential impact exploratory well at the
Libertad prospect in 2000. The Company plans to increase its spending and
drilling activity in Venezuela by drilling 24 wells in the Oritupano-Leona
concession area and increase its facility capacity.
The Company expects to continue to improve its balance sheet by reducing
debt by at least $200 million in 2000. The Company expects its cash from
operations to be approximately $1 billion for 2000, assuming a NYMEX price
forecast of $26 per barrel for crude oil and $2.70 per Mcf for natural gas. To
the extent that cash from operations is generated in excess of this forecast or
due to proceeds from the monetization of its minerals business or the sales of
assets, the additional cash could be used to further reduce debt and/or initiate
a common stock repurchase program if approved by the Board of Directors. The
Company expects to experience lower interest expense in its Consolidated
Statement of Income in future years as a result of its debt reduction program.
The Company will continue to focus on maximizing shareholder value during
2000 through debt reduction. In response to industry and market changes,
including industry consolidation, the Company considers from time to time
additional strategies to enhance shareholder value in light of such changes.
These include, among others, strategic alliances and joint ventures; spin-offs;
purchase, sale or merger transactions with other large companies; a
recapitalization of the Company and other similar transactions. In considering
any of these strategies, the Company evaluates the consequences of such
strategies including, among other things, the leverage that would result from
such a transaction, the tax effects of the transaction, and the accounting
consequences of the transaction. In addition, such strategies could have various
other significant consequences, including changes in the management, control or
operational or acquisition strategies of the Company. There can be no assurance
that any one of these strategies will be undertaken, or that, if undertaken, any
such strategy will be completed successfully.
Although the Company's deleveraging program was completed during 1999, the
Company will continue to evaluate its asset portfolio and may from time to time
sell, purchase or trade certain oil and gas properties to focus on its core
operating areas and generate additional value. Additionally, the potential
exists for gains to be recognized during 2000 related to properties sold in
1999. As some of the major oil and gas industry companies merge, the Company
expects some of these companies to divest properties in the Company's core
operating areas where it has expertise. The Company hopes to position itself to
enable it to purchase some of these properties. The Company is seeking to reduce
its capital exposure in the Gomez project by selling or transferring a portion
of its working interest. The Company is also planning to sell about $100 million
of Canadian assets, certain properties in south Louisiana and its properties in
Argentina.
The Company owns a non-operating 50 percent interest in Black Butte, a
partnership which operates a surface coal mine complex in southwestern Wyoming.
During 1999, Black Butte's sales to its largest customer under a coal supply
contract contributed $73.4 million to consolidated operating income. This
contract will terminate at the end of 2000. Operating income under the contract
is expected to be approximately $71.1 million in 2000. Although Black Butte
continues to seek new buyers for its low-sulfur coal, its mining costs are
considerably higher than the mining costs of its competition. The Company does
not expect to be able to replace the operating income it currently receives
under the contract with incremental coal sales after 2000.
During 1998 and 1999, the Company reported tax benefits due to operating
losses and tax settlements with governmental agencies and UPC. Additionally,
during the fourth quarter 1999, the Company implemented certain available tax
management strategies that caused a decrease in current tax liability for 1999.
The Company cannot predict with certainty when the tax will be paid.
In connection with the GPM Disposition, the Company entered into a
long-term sales agreement with Duke. The long-term sales agreement obligates the
Company to sell the majority of its domestic natural gas and existing NGL
production to Duke through March 2004. Natural gas volumes dedicated to the
agreement
29
<PAGE> 32
include existing and future production that is available at specific delivery
points identified in the agreement. Prices received for the natural gas and NGL
production will be tied to current market prices. Additionally, as a result of
the agreement, the Company and Duke agreed to keep one another whole on certain
gas transportation contracts for up to ten years. The Company will pay Duke if
transportation market values fall below the contract transportation rates, while
Duke will pay the Company if the market value exceeds the contract
transportation rates. The Company established a liability based on the estimated
fair value of these firm transportation contracts. The balance of the firm
transportation liability at December 31, 1999 was $125.6 million and was
included in other current and long-term liabilities on the Consolidated
Statement of Financial Position. The Company anticipates payments for the firm
transportation liability to be approximately $43.8 million during 2000.
The Company, through one of its affiliates, is a party to a lease agreement
("base lease") for the leveraged lease financing of the Corpus Christi West
Plant Refinery ("West Plant") with an initial term expiring December 31, 2003,
and successive renewal periods lasting through January 31, 2011. At the
conclusion of the initial term of the base lease, any renewal period or January
31, 2011, the Company has the right to purchase the West Plant at the fair
market sales value. In connection with the sale by the Company of its refining
business in 1987 and 1989, the West Plant was subleased to CITGO Petroleum
Corporation ("CITGO") with sublease payments during the initial term equal to
the Company's base lease payments and during any renewal period equal to the
lesser of the base lease rental, which will be tied to the fair market rental
value, or $5 million annually. Additionally, CITGO has the option under the
sublease to purchase the West Plant from the Company at the conclusion of the
initial term or any renewal term at the fair market sales value, or on January
31, 2011 at a nominal price. If the fair market rental value of the base lease
during any renewal term exceeds CITGO's maximum obligation under the sublease,
or if CITGO purchases the West Plant on January 31, 2011 and the fair market
sales value of the West Plant is greater than the purchase amount specified in
the sublease, the Company will be obligated to pay the excess amounts. The
Company is unable at this time to determine the fair market rental value or the
fair market sales value of the West Plant, but will periodically evaluate the
potential of the obligation.
The financial statements of the Company's Canadian subsidiary use the
Canadian dollar as its functional currency. Latin American subsidiaries
generally use the U.S. dollar as their functional currency. To the extent that
business transactions in these countries are not denominated in the functional
currency, the Company is exposed to foreign currency exchange rate risk. In
addition, in these subsidiaries, certain asset and liability balances are
denominated in currencies other than the subsidiary's functional currency. These
asset and liability balances must be remeasured in the preparation of the
subsidiary financial statements using a combination of current and historical
exchange rates, with any resulting remeasurement adjustments included in net
income. See "Item 7A. Qualitative and Quantitative Disclosure About Market
Risk -- Foreign Currency Risk".
YEAR 2000 ISSUE
The Company established a formal Year 2000 Readiness Program to address the
Company's issues related to the Year 2000. Program activities are directed by a
Program Management Office staffed with a Year 2000 Program Manager, several
senior Information Technology and engineering project managers and
representatives from key internal functions including exploration and
production, operations, purchasing, finance and legal. The Program Management
Office operated under the oversight of a Year 2000 Executive Steering Committee
and the Audit Committee of the Board of Directors.
As of February 29, 2000, the Company has not experienced any material
system issues from Year 2000 causes. Furthermore, there has been no indication
of third party Year 2000 issues that would materially affect the ongoing
operation or financial performance of the Company. Based on the evidence
available through February 29, 2000, the Company believes that any consequences
of Year 2000 issues will not have a material impact on the Company's
consolidated results of operations, cash flows or financial condition.
The total cost of the Company's Year 2000 Readiness Program was not
material to the Company's results of operations, cash flows or financial
position. Not including the cost of replacing its information systems
30
<PAGE> 33
between 1993 and 1997, the Company spent a total of $2.1 million during 1998 and
1999 for Year 2000 related modifications and testing. This estimate does not
include the cost of internal salaries for personnel involved with Year 2000
related activities. This estimate also does not include the Company's potential
share of Year 2000 costs that may be incurred by partnerships and joint ventures
in which the Company participates but is not the operator.
ENVIRONMENTAL COSTS
The Company has generated and disposed of hazardous and nonhazardous waste
in its current operations as well as its formerly owned operations and is
subject to increasingly stringent Federal, state, local, provincial and
international environmental regulations. The Company has identified seven sites
currently subject to environmental response actions or on the Superfund National
Priorities List or state superfund lists at which it is or may be liable for
remediation costs associated with alleged contamination or for violations of
environmental requirements. Certain Federal legislation imposes joint and
several liability for the remediation of various sites; consequently, the
Company's ultimate environmental liability may include costs relating to other
parties in addition to costs relating to its own activities at each site. In
addition, the Company is or may be liable for certain environmental remediation
matters involving existing or former facilities.
As of December 31, 1999, long-term and short-term liabilities totaling
$65.2 million had been accrued for future costs relating to all sites where the
Company's obligation is probable and where such costs can be reasonably
estimated; however, the ultimate cost could be lower or higher. This accrual
includes future costs for remediation and restoration of sites, as well as for
ongoing monitoring costs, but excludes any anticipated recoveries from third
parties. The accrual also includes $34.1 million for the obligation to
participate in the remediation of the Wilmington, California field properties.
Cost estimates were based on information available for each site, financial
viability of other Potentially Responsible Parties ("PRPs") and existing
technology, laws and regulations. The Company believes that it has accrued
adequately for its share of costs at sites subject to joint and several
liabilities. The ultimate liability for remediation is difficult to determine
with certainty because of the number of PRPs involved, site-specific cost
sharing arrangements with other PRPs, the degree of contamination by various
wastes, the scarcity and quality of volumetric data related to many of the sites
and the speculative nature of remediation costs.
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 $11.6 million in 1999 and $17.0
million in 1998. In 2000, the Company anticipates spending a total of $19
million for remediation, control and prevention. Anticipated payments for
accrued environmental liability as of December 31, 1999, which will be funded by
cash generated from operations, are expected to be $17 million in 2000, $13.2
million in 2001, $12.5 million in 2002, $10 million in 2003, $8 million in 2004
and $4.5 million thereafter. Based on current rules and regulations, management
does not expect future environmental obligations to have a material impact on
the results of operations, financial condition or cash flows of the Company.
FORWARD-LOOKING INFORMATION
Certain information included in this report, and other materials filed or
to be filed by the Company with the SEC (as well as information included in oral
statements or other written statements made or to be made by the Company)
contain projections and forward-looking statements within the meaning of Section
21E of the Securities Exchange Act of 1934, as amended, and Section 27A of the
Securities Act of 1933, as amended. Such forward-looking statements may be or
may concern, among other things, capital expenditures, drilling activity,
acquisitions and development activities, cost savings efforts, production
activities and sales volumes, oil, gas and NGL reserves and prices, hedging
activities and the results thereof, liquidity, debt repayment, regulatory
matters and competition. Such forward-looking statements generally are
accompanied by words such as "estimate," "expect," "predict," "anticipate,"
"goal," "should," "could," "assume," "believe" or other words that convey the
uncertainty of future events or outcomes.
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<PAGE> 34
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, cash
flows 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 crude oil, natural 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; the oil and gas industry's consolidation activity;
demand and supply of oil and gas; the ability to find or acquire and develop
reserves of natural gas and crude oil; and the actions of customers and
competitors. Additionally, unpredictable or unknown factors not discussed herein
could have material adverse effects on actual results related to matters which
are the subject of forward-looking information.
With respect to expected capital expenditures and drilling activity,
additional factors such as crude oil and natural gas prices and the ability to
achieve debt repayment objectives, the extent of the Company's success in
acquiring oil and gas properties and in identifying prospects for drilling, the
availability of acquisition opportunities which meet the Company's objectives as
well as competition for such opportunities, exploration and operating risks, the
success of management's cost reduction efforts, the ability to find working
interest partners to share certain capital risks 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, uncertainties inherent in estimating reserve quantities and
the availability of technology may affect such production sales volumes and
reserve estimates.
With respect to liquidity, factors such as the state of domestic capital
markets, credit availability from banks or other lenders and the Company's
results of operations may affect management's plans or ability to incur
additional indebtedness. With respect to cash flow and the ability to reduce
debt or to repurchase the Company's common stock, factors such as changes in
crude oil and natural gas prices, the Company's success in acquiring properties
or divesting or monetizing properties, environmental matters and other
contingencies, hedging activities and the Company's credit rating and debt
levels may affect the Company's ability to generate expected cash flows. With
respect to contingencies, factors such as changes in environmental and other
domestic and foreign 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, cash flows or financial
condition of the Company. Certain factors, such as changes in crude oil and
natural 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.
ITEM 7A. QUALITATIVE AND QUANTITATIVE DISCLOSURE ABOUT MARKET RISK
The Company has established policies and procedures for managing risk
within its organization, including internal controls and governance by a risk
management committee. The level of risk assumed by the Company is based on its
objectives and earnings, and its capacity to manage risk. Limits are established
for each major category of risk, with exposures monitored and managed by Company
management and reviewed by the risk management committee.
The Company's primary risk exposure is related to natural gas firm
transportation and commodity price risk. During 1999, while hydrocarbon prices
were near historic lows and the Company's debt balance was high, the Company
entered into hedging arrangements. These hedges were primarily solvency driven
in order to shield the Company from losses which may have resulted in a
violation of certain debt covenants. As prices recovered in the second half of
1999, the Company experienced higher prices and revenue at the well-head;
however, the higher well-head revenue was partially lowered by the $178.1
million in losses associated with the hedge positions that were entered into in
early 1999. The lower priced hedges expired at the end of 1999. For 2000, the
Company has reduced some of its exposure to lower prices by purchasing puts and
fixed price
32
<PAGE> 35
contracts and has limited some of the upside of higher prices by selling calls
and fixed price contracts. In early 2000, the Company hedged slightly more than
one-half of its estimated 2000 production with a combination of the fixed price
and option hedging strategies.
Below is a more comprehensive and quantitative disclosure of the Company's
market risks.
NON-TRADING ACTIVITIES
Commodity Price Risk. The Company uses derivative financial instruments for
non-trading purposes in the normal course of business to manage and reduce risks
associated with price volatility, contractual commitments and other market
variables. The Company's hedging approach is designed to respond to changing
market conditions where practicable, while at the same time permitting the
evaluation of the need to protect against significant commodity price
reductions. These financial instruments usually limit future gains from
favorable price movements. The volume of production hedged and the mix of
derivative instruments employed are regularly evaluated and adjusted in response
to changing market conditions and Company objectives.
Recognition of realized gains/losses and option premium payments/receipts
related to non-trading activities is deferred in the Consolidated Statement of
Income until the underlying physical product is sold. Unrealized gains/losses
are not recorded. Margin deposits, deferred gains/losses and net premiums are
included in other current assets or liabilities in the Consolidated Statement of
Financial Position. The cash flow impact is reflected in cash flows provided by
operations in the Consolidated Statement of Cash Flows.
Utilization of the Company's hedging program may result in the realization
on the crude oil and natural gas prices varying from market prices that the
Company receives from the sales of crude oil and natural gas. As a result of the
hedging programs, revenues in 1999, 1998 and 1997 were $178.1 million, $9
million and $86 million lower, respectively, than if the hedging program had not
been in effect. Since these transactions were hedges on production, these
impacts were also reflected in the average sales price of the associated
products. At December 31, 1999, the Company had margin deposits of $7.4 million
and a $26.6 million liability related to recorded hedging losses.
The following table summarizes the Company's open positions as of December
31, 1999 related to equity natural gas and crude oil production. Based on these
hedge positions, for each $1.00 increase in the price of a barrel of oil,
annualized oil revenues would be reduced by approximately $24.5 million, while
for every $0.10 per Mcf increase in the price of natural gas, annualized gas
revenues would be lower by approximately $23.1 million.
<TABLE>
<CAPTION>
WEIGHTED UNRECOGNIZED
CONTRACT AVG. PRICE PER FAIR VALUE GAIN/(LOSS)
PRODUCT TYPE TIME PERIOD VOLUME MCF OR BBL (MILLIONS OF DOLLARS) (MILLIONS OF DOLLARS)
- ------- -------------- --------------- ---------- -------------- --------------------- ---------------------
<S> <C> <C> <C> <C> <C> <C>
Gas Puts Purchased Feb -- Mar 2000 298 MMcfd $ 2.50 $ 5.8 $ 5.8
Gas Calls Sold Feb -- Mar 2000 298 MMcfd 3.11 (0.3) (0.3)
Gas Puts Purchased Apr -- Jul 2000 403 MMcfd 2.32 9.1 9.1
Gas Calls Sold Apr -- Jul 2000 403 MMcfd 2.72 (3.2) (3.2)
Gas Puts Purchased Aug -- Sep 2000 503 MMcfd 2.30 5.3 5.3
Gas Calls Sold Aug -- Sep 2000 503 MMcfd 2.69 (3.3) (3.3)
Gas Puts Purchased Oct -- 2000 253 MMcfd 2.35 1.7 1.7
Gas Calls Sold Oct -- 2000 253 MMcfd 2.72 (0.9) (0.9)
Gas Swaps Feb -- Mar 2000 290 MMcfd Var. (1.3) (1.3)
Gas Swaps Apr -- Oct 2000 175 MMcfd Var. (0.2) (0.2)
Gas Futures Feb -- Jul 2000 370 MMcfd 2.43 5.6 5.6
Gas Futures Aug -- Dec 2000 170 MMcfd 2.44 (1.6) (1.6)
Gas Fixed Price Jan -- Oct 2000 10 MMcfd 2.80 2.2 2.2
Gas Fixed Price Jan -- Dec 2000 10 MMcfd 1.54 (2.1) (2.1)
Gas Fixed Price Jan -- Oct 2001 10 MMcfd 1.54 (1.8) (1.8)
Gas Physical Calls Apr -- Oct 2000 10 MMcfd 2.17 (0.1) 0.2
Sold
Oil Puts Purchased Jan -- Dec 2000 34.5 Mbd 17.29 6.3 6.3
Oil Calls Sold Jan -- Dec 2000 34.5 Mbd 21.77 (29.2) (29.2)
</TABLE>
33
<PAGE> 36
<TABLE>
<CAPTION>
WEIGHTED UNRECOGNIZED
CONTRACT AVG. PRICE PER FAIR VALUE GAIN/(LOSS)
PRODUCT TYPE TIME PERIOD VOLUME MCF OR BBL (MILLIONS OF DOLLARS) (MILLIONS OF DOLLARS)
- ------- -------------- --------------- ---------- -------------- --------------------- ---------------------
<S> <C> <C> <C> <C> <C> <C>
Oil Swaps Jan 2000 26.4 Mbd 23.02 (1.9) (1.9)
Oil Swaps Feb -- Aug 2000 35 Mbd 20.31 (17.4) (17.4)
Oil Swaps Sep -- Dec 2000 30 Mbd 20.38 (0.6) (0.6)
Oil Swaps Jan -- Dec 2000 2 Mbd 17.35 (0.1) (0.1)
Oil Fixed Price Jan -- Feb 2000 2 Mbd 22.47 0.2 0.2
Oil Fixed Price Jan -- Oct 2000 2 Mbd 16.94 (0.1) (0.1)
Oil Fixed Price Jan -- Apr 2000 8 Mbd 20.89 1.5 1.5
Oil Fixed Price Jan -- Dec 2000 2 Mbd 18.30 0.4 0.4
------ ------
Totals: ($26.0) ($25.7)
====== ======
</TABLE>
Unrecognized mark-to-market gains and losses were determined based on
current market prices at December 30, 1999, as quoted by recognized dealers,
assuming round lot transactions and using a mid-market convention without regard
to market liquidity. The actual gains or losses ultimately realized by the
Company from such hedges may vary significantly from the foregoing amounts due
to the volatility of the commodity markets.
The following table summarizes the Company's closed positions at December
31, 1999 related to the Company's equity natural gas production:
<TABLE>
<CAPTION>
UNRECOGNIZED
GAIN/(LOSS)
PRODUCT TYPE TIME PERIOD (MILLIONS OF DOLLARS)
- ------- ------------- ---------------- ---------------------
<S> <C> <C> <C>
Gas Options Jan 2000 $2.5
Gas Futures/Swaps Jan 2000 2.3
----
Totals: $4.8
====
</TABLE>
The Company enters into financial contracts in conjunction with its
alliance with South Jersey Resources Group (the "Alliance"). The Company has a
50% ownership interest in the Alliance which provides natural gas storage and
customer service programs. The following table summarizes the Alliance's open
positions as of December 31, 1999:
<TABLE>
<CAPTION>
WEIGHTED AVG.
CONTRACT PRICE FAIR VALUE
PRODUCT TYPE TIME PERIOD VOLUME PER MCF (MILLIONS OF DOLLARS)
- ------- ----------------------- --------------- -------- ------------- ---------------------
<S> <C> <C> <C> <C> <C>
Gas Puts Purchased Feb -- Mar 2000 0.3 Bcf $ 2.88 $ 0.2
Gas Puts Sold Feb -- Mar 2000 0.9 Bcf 2.29 (0.1)
Calls Sold Feb -- June 0.9 Bcf 2.79 (0.1)
Gas 2000
Gas Futures/Swaps Purchased Feb -- Dec 2000 17.5 Bcf 2.78 (4.4)
Gas Futures/Swaps Purchased Jan -- Oct 2001 1.1 Bcf 3.37 --
Gas Futures/Swaps Purchased Feb -- Dec 2000 10.9 Bcf 2.79 2.6
Gas Futures/Swaps Purchased Jan -- Apr 2001 0.6 Bcf 2.48 --
-----
Totals: $(1.8)
=====
<CAPTION>
UNRECOGNIZED
GAIN/(LOSS)
PRODUCT (MILLIONS OF DOLLARS)
- ------- ---------------------
<S> <C>
Gas $ 0.2
Gas --
--
Gas
Gas (4.4)
Gas --
Gas 2.6
Gas --
-----
$(1.6)
=====
</TABLE>
Firm Transportation Price Risk. The Company was a party to several
long-term firm gas transportation agreements that supported the gas marketing
program within the GPM business segment which was sold to Duke. Most of the GPM
business segment's firm long-term transportation contracts were transferred to
Duke in the GPM Disposition. As part of the GPM Disposition, the Company and
Duke agreed that the Company will keep Duke whole on certain transportation
contracts ("keep-whole agreement"). The Company will pay Duke if transportation
market values fall below the contract transportation rates, while Duke agreed to
pay the Company if the market value exceeds the contract transportation rates.
This keep-whole agreement will be in effect until the earlier of (i) each
contract's expiration date, or (ii) March 2009. Transportation contracts
transferred to Duke in the GPM Disposition and included in the keep-whole
agreement with Duke relate to various pipelines. The significant contracts
covered by the keep-whole agreement include: (i) an agreement with Texas Gas
Transmission Corporation for a transportation rate of $0.331 per MMBtu for 90
MMBtud of
34
<PAGE> 37
gas from Carthage, Texas to Lebanon, Ohio expiring October 31, 2008; (ii) an
agreement with Pacific Gas Transmission ("PGT") for a transportation rate of
$0.328 per MMBtu for 25 MMBtud of gas from Kingsgate, British Columbia to the
California/Oregon border expiring October 31, 2023; and (iii) a second agreement
with PGT expiring October 31, 2023 for 106 MMBtud of which 47 MMBtud will expire
on October 31, 2007. The keep-whole agreement excludes 45 MMBtud of the PGT
amount through October 31, 2002 then 20 MMBtud through the end of the contract.
The Company retained a contract with Kern River Gas Transportation Company
("Kern River") which expires on May 31, 2007. Under the transportation
agreement, the Company has the right to transport 75 MMcfd of gas on the Kern
River system. The current transportation rate is $0.69 per Mcf. This rate can
change based on Kern River's cost of service and upon rate regulation policies
of the FERC. The Company is a party to an additional agreement under which it
may acquire in 2001, at its option, an additional 25 MMcfd of transportation
rights on the Kern River system beginning in 2002. As a result of the GPM
Disposition, the Company entered into an agreement whereby Duke would operate
and handle volume nominations related to the Company's contract with Kern River.
Currently, Duke is utilizing the Company's volume transportation rights under
the Kern River contract and paying the Company market rates.
The estimated fair value of the firm transportation contracts at December
31, 1999 was a loss of $125.6 million, which is included in other current
liabilities and other long-term liabilities on the Consolidated Statement of
Financial Position. The Company may adjust its reserve based on changes in
current quoted future market rates or estimated long-term rates. Such
adjustments could be significant. Management believes its reserves are adequate;
however, at December 31, 1999, if the Company had used quoted future market
rates at December 31, 1999 to estimate the long-term portion of the reserve
discounted at 10%, the Company would have recorded an additional reserve of
$41.3 million for the firm transportation commitment period. The estimated fair
value of the firm transportation liability is summarized as follows:
<TABLE>
<CAPTION>
YEAR UNDISCOUNTED DISCOUNTED
- ---- ------------ ----------
(MILLIONS OF DOLLARS)
<S> <C> <C>
2000........................................................ $ 43.8 $ 43.8
2001........................................................ 17.0 14.8
2002........................................................ 15.6 12.3
2003........................................................ 17.8 12.8
2004........................................................ 24.4 15.9
Thereafter.................................................. 50.0 26.0
------ ------
Total............................................. $168.6 $125.6
====== ======
</TABLE>
TRADING ACTIVITIES
The Company periodically enters into financial contracts in conjunction
with market-making or trading activities with the objective of achieving profits
through successful anticipation of movements in commodity prices and changes in
other market variables. Market-making positions are marked-to-market and gains
and losses are immediately included as revenue in the Consolidated Statement of
Income. In addition, the fair value of unsettled positions is immediately
included in the Consolidated Statement of Financial Position as a current asset
or current liability. The activity related to market-making or trading
activities did not have a significant effect on the Company's results of
operations for the year ended December 31, 1999. At December 31, 1999, the
Company's trading activity position did not have a material impact on the
results of operations or financial condition of the Company.
INTEREST RATE RISK AND INTEREST RATE SWAPS
The table below summarizes maturities for the Company's fixed-rate and
variable-rate debt. Variable rate debt consists of commercial paper and bankers'
acceptances that are generally tied to the London Interbank
35
<PAGE> 38
Offered Rate ("LIBOR"). If interest rates on the Company's variable rate debt
increase or decrease by one percentage point, the Company's annual pretax income
would decrease or increase by $1.4 million.
<TABLE>
<CAPTION>
MATURITY DATE
-------------------------------------------------
2000 2001 2002 2003 2004 THEREAFTER
------ ---- ------ ---- ---- ----------
(MILLIONS OF DOLLARS)
<S> <C> <C> <C> <C> <C> <C>
Variable-Rate................................. $135.1 $ -- $ -- $ -- $ -- $ --
Fixed-Rate.................................... 2.3 2.2 252.3 2.4 6.2 2,399.1
------ ---- ------ ---- ---- --------
Total............................... $137.4 $2.2 $252.3 $2.4 $6.2 $2,399.1
====== ==== ====== ==== ==== ========
</TABLE>
The Company periodically enters into rate swaps and contracts to hedge
certain interest rate transactions. As of December 31, 1999, the Company had no
interest rate swap positions open.
CREDIT RISK
Credit risk is the risk of loss as a result of non-performance by
counterparties of their contractual obligations. Because the loss can occur at
some point in the future, a potential exposure is added to the current
replacement value to arrive at a total expected credit exposure. The Company has
established methodologies to determine limits, monitor and report
creditworthiness and concentrations of credit to reduce such credit risk. At
December 31, 1999, the Company's largest credit risk associated with any single
financial counterparty, represented by the net fair value of open contracts, was
$7.1 million discounted.
In conjunction with the GPM Disposition, on March 31, 1999, the Company
entered into a swap transaction with Duke, which in effect transferred all
financial positions held by the GPM business segment to Duke. As a result, the
Company has eliminated all price/rate risk related to these positions and is
only subject to credit risk for amounts due from Duke or other counterparties
under the terms of the swap transactions with Duke or the underlying swap
transactions. At December 31, 1999, the Company's credit risk related to these
positions was immaterial.
Also in connection with the GPM Disposition, the Company entered into a
long-term sales agreement with Duke. The long-term sales agreement obligates the
Company to sell the majority of its domestic natural gas and existing NGL
production to Duke through March 2004. Prices received will be tied to the
current market price for each product. As a result, a significant portion of the
Company's credit risk will be with a single customer. Duke is currently
considered a good credit risk; however, periodic credit evaluations will
continue and be performed more often if circumstances dictate. The agreement
with Duke provides for a parental guaranty to cover its obligations under the
agreements and the Company has the right to demand a letter of credit and/or
other assurances under certain circumstances.
PERFORMANCE RISK
Performance risk results when a financial counterparty fails to fulfill its
contractual obligations such as commodity pricing or volume commitments.
Typically, such risk obligations are defined within the trading agreements. The
Company utilizes its credit risk methodology to manage performance risk.
FOREIGN OPERATIONS RISK
The Company's operations outside of the U.S. are subject to risks inherent
in foreign operations, including, without limitation, the loss of revenue,
property and equipment from hazards such as expropriation, nationalization, war,
insurrection and other political risks, increases in taxes and governmental
royalties, renegotiation of contracts with governmental entities, changes in
laws and policies governing operations of foreign-based companies, currency
restrictions and exchange rate fluctuations and other uncertainties arising out
of foreign government sovereignty over the Company's international operations.
Laws and policies of the U.S. affecting foreign trade and taxation may also
adversely affect the Company's international operations.
36
<PAGE> 39
FOREIGN CURRENCY RISK
The Company's Canadian subsidiary uses the Canadian dollar as its
functional currency, and the Latin American subsidiaries use the U.S. dollar as
their functional currency. To the extent that business transactions in these
countries are not denominated in the respective country's functional currency,
the Company is exposed to foreign currency exchange rate risk. In addition, in
these subsidiaries, certain asset and liability balances are denominated in
currencies other than the subsidiary's functional currency. These asset and
liability balances must be remeasured in the preparation of the subsidiary's
financial statements using a combination of current and historical exchange
rates, with any resulting remeasurement adjustments included in net income.
At December 31, 1999, the Company's Canadian subsidiary had outstanding
$650 million of fixed-rate notes and debentures denominated in U.S. dollars.
During 1999, the Company recognized a $38.0 million pretax non-cash gain
associated with remeasurement of this debt. The potential foreign currency
remeasurement impact on earnings from a five-percent change in the year-end
Canadian exchange rate would be approximately $32 million.
At December 31, 1999, Latin American subsidiaries had foreign deferred tax
liabilities denominated in the local currency, equivalent to $131.6 million in
Venezuela and $34.1 million in Guatemala. During 1999, the Company recognized
deferred tax benefits of $20.4 million and $8.9 million after tax, respectively,
associated with remeasurement of the Venezuelan and Guatemalan deferred tax
liabilities. The potential foreign currency remeasurement impact on net earnings
from a five percent change in the year-end Latin American exchange rates would
be approximately $9 million.
The Company periodically enters into foreign currency contracts to hedge
specific currency exposures from commercial transactions. The following table
summarizes the Company's open foreign currency positions at December 31, 1999:
<TABLE>
<CAPTION>
NOTIONAL AMOUNT FAIR VALUE
MATURITY YEAR (US$ MILLIONS) FORWARD RATE (US$ MILLIONS)
- ------------- --------------- ------------ --------------
<S> <C> <C> <C>
2000....................................... $ 8.0 C$1.3750 $(0.4)
2004....................................... 70.0 C$1.3630 (3.9)
----- -----
$78.0 $(4.3)
===== =====
</TABLE>
37
<PAGE> 40
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
<TABLE>
<CAPTION>
PAGE
----
<S> <C>
Responsibilities for Financial Statements................... 39
Reports of Independent Public Accountants................... 40
Consolidated Statements of Income and Comprehensive Income
for the Years Ended December 31, 1999, 1998 and 1997...... 42
Consolidated Statements of Financial Position as of December
31, 1999 and 1998......................................... 43
Consolidated Statements of Cash Flows for the Years Ended
December 31, 1999, 1998 and 1997.......................... 44
Consolidated Statements of Changes in Shareholders' Equity
for the Years Ended December 31, 1999, 1998 and 1997...... 45
Business Segment Information as of and for the Years Ended
December 31, 1999, 1998 and 1997.......................... 46
Notes to Consolidated Financial Statements.................. 47
Supplementary Information (Unaudited)....................... 74
</TABLE>
Black Butte Coal Company, A Joint Venture, and R-K Leasing Company Combined
Financial Statements as of December 31, 1999 and December 26, 1998,
(incorporated herein by reference to Exhibit 99.1 to the Company's Annual
Report on Form 10-K for the period ended December 31, 1999).
Black Butte Coal Company, A Joint Venture, and R-K Leasing Company Combined
Financial Statements as of December 27, 1997 (incorporated herein by reference
to Exhibit 99.2 to the Company's Annual Report on Form 10-K for the period
ended December 31, 1999).
38
<PAGE> 41
RESPONSIBILITIES FOR FINANCIAL STATEMENTS
The accompanying financial statements, which consolidate the accounts of
Union Pacific Resources Group Inc. and its subsidiaries, have been prepared in
conformity with generally accepted accounting principles.
The integrity and objectivity of data in these financial statements and
accompanying notes, including estimates and judgments related to matters not
concluded by year-end, are the responsibility of management, as is all other
information in this report. Management devotes ongoing attention to the review
and appraisal of its system of internal controls. This system is designed to
provide reasonable assurance, at an appropriate cost, that the Company's assets
are protected, that transactions and events are recorded properly and that
financial reports are reliable. The system is augmented by a staff of internal
auditors, careful attention to the selection and development of qualified
financial personnel, programs to further timely communication and monitoring of
policies, standards and delegated authorities and evaluation by independent
auditors during their examinations of the annual financial statements.
The Audit Committee of the Board of Directors, composed of four
non-employee directors, meets regularly with financial management, the internal
auditors and the independent auditors to review financial reporting and
accounting and financial controls of the Company. Both the independent auditors
and the internal auditors have unrestricted access to the Audit Committee and
meet regularly with the Audit Committee, without financial management
representatives present, to discuss the results of their examinations and their
opinions on the adequacy of internal controls and quality of financial
reporting.
George Lindahl III
Chairman, President and Chief
Executive Officer
Morris B. Smith
Vice President, Chief Financial
Officer
and Treasurer
39
<PAGE> 42
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
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. (a Utah Corporation) and
subsidiaries ("the Company") as of December 31, 1999 and 1998, and the related
consolidated statements of income and comprehensive income, changes in
shareholders' equity and cash flows for the years then ended. These financial
statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements based on
our audits.
We conducted our audits in accordance with auditing standards generally
accepted in the United States. Those standards require that we plan and perform
the audit to obtain reasonable assurance about whether the financial statements
are free of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements. An
audit also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis
for our opinion.
In our opinion, the financial statements referred to above present fairly,
in all material respects, the financial position of the Company as of December
31, 1999 and 1998, and the results of its operations and its cash flows for the
years then ended in conformity with accounting principles generally accepted in
the United States.
We have also audited the adjustments related to discontinued operations
described in Note 3 that were applied to restate the 1997 financial statements.
In our opinion, such adjustments are appropriate and have been properly applied.
ARTHUR ANDERSEN LLP
Fort Worth, Texas
March 3, 2000
40
<PAGE> 43
INDEPENDENT AUDITORS' REPORT
To the Board of Directors
Union Pacific Resources Group Inc.
Fort Worth, Texas
We have audited the accompanying consolidated statements of income, changes
in shareholders' equity and cash flows of Union Pacific Resources Group Inc.
("the Company") for the year ended December 31, 1997, (which have been restated
and are no longer presented herein). These financial statements are the
responsibility of the Company's management. Our responsibility is to express an
opinion on these financial statements based on our audit.
We conducted our audit in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audit provides a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in
all material respects, the results of its operations and its cash flows for the
year ended December 31, 1997 in conformity with generally accepted accounting
principles.
DELOITTE & TOUCHE LLP
Fort Worth, Texas
January 26, 1998
41
<PAGE> 44
UNION PACIFIC RESOURCES GROUP INC.
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
FOR THE YEARS ENDED DECEMBER 31, 1999, 1998 AND 1997
<TABLE>
<CAPTION>
1999 1998 1997
---------- ----------- ----------
(MILLIONS, EXCEPT PER SHARE AMOUNTS)
<S> <C> <C> <C>
Operating revenues:
Producing properties...................................... $1,473.3 $ 1,537.4 $1,293.5
Other oil and gas revenues................................ 133.7 162.5 84.7
Minerals (Note 14)........................................ 120.5 141.1 139.8
-------- --------- --------
Total operating revenues.......................... 1,727.5 1,841.0 1,518.0
-------- --------- --------
Operating expenses:
Production................................................ 400.6 444.3 300.8
Exploration............................................... 267.9 339.0 204.7
Minerals (Note 14)........................................ (2.8) 3.5 3.4
Depreciation, depletion and amortization (Note 6)......... 827.7 2,125.6 504.0
General and administrative................................ 86.9 104.8 71.2
Restructuring charge (Note 4)............................. 11.4 17.0 --
-------- --------- --------
Total operating expenses.......................... 1,591.7 3,034.2 1,084.1
-------- --------- --------
Operating income (loss)..................................... 135.8 (1,193.2) 433.9
Other income (expense) -- net (Note 16)..................... 31.7 (45.3) 24.5
Interest expense (Notes 3 and 9)............................ (218.7) (249.8) (39.5)
-------- --------- --------
Income (loss) from continuing operations before income
taxes..................................................... (51.2) (1,488.3) 418.9
Income tax expense (benefit) (Note 8)....................... (140.4) (605.2) 115.8
-------- --------- --------
Income (loss) from continuing operations, before
extraordinary items....................................... 89.2 (883.1) 303.1
Gain on sale of discontinued operations -- net of tax....... 157.0 -- --
Income (loss) from discontinued operations -- net of tax.... (23.8) (15.6) 29.9
-------- --------- --------
Income (loss) from discontinued operations (Note 3)......... 133.2 (15.6) 29.9
Extraordinary gain from early extinguishment of debt -- net
of tax (Note 9)........................................... 3.4 -- --
-------- --------- --------
Net income (loss)........................................... $ 225.8 $ (898.7) $ 333.0
-------- --------- --------
Comprehensive income -- net of tax: (Note 15)
Foreign currency translation adjustments.................. $ 22.5 $ (67.1) $ (5.3)
Minimum pension liability................................. (6.0) (3.9) (1.0)
-------- --------- --------
Comprehensive income (loss)................................. $ 242.3 $ (969.7) $ 326.7
======== ========= ========
Earnings (loss) per share -- basic and diluted: (Note 15)
Continuing operations..................................... $ 0.36 $ (3.57) $ 1.21
Discontinued operations................................... 0.54 (0.06) 0.12
Extraordinary item........................................ 0.01 -- --
-------- --------- --------
Total............................................. $ 0.91 $ (3.63) $ 1.33
-------- --------- --------
Weighted average shares outstanding -- diluted.............. 249.2 247.7 250.9
Cash dividends per share.................................... $ 0.20 $ 0.20 $ 0.20
</TABLE>
The accompanying accounting policies and notes to the Consolidated Financial
Statements
are an integral part of these statements.
42
<PAGE> 45
UNION PACIFIC RESOURCES GROUP INC.
CONSOLIDATED STATEMENTS OF FINANCIAL POSITION
AS OF DECEMBER 31, 1999 AND 1998
ASSETS
<TABLE>
<CAPTION>
1999 1998
--------- ---------
(MILLIONS OF DOLLARS)
<S> <C> <C>
Current assets:
Cash and temporary investments............................ $ 123.7 $ 8.8
Accounts receivable (net of allowance for doubtful
accounts of $8.5 million in 1999 and $9.8 million in
1998).................................................. 304.4 261.0
Inventories............................................... 54.7 64.6
Other current assets...................................... 13.1 107.0
--------- ---------
Total current assets.............................. 495.9 441.4
--------- ---------
Properties: (Note 6)
Cost...................................................... 11,006.6 11,078.2
Accumulated depreciation, depletion and amortization...... (5,535.6) (4,984.9)
--------- ---------
Total properties.................................. 5,471.0 6,093.3
Intangible and other assets................................. 180.0 180.8
Net assets of discontinued operations (Note 3).............. -- 926.9
--------- ---------
Total assets...................................... $ 6,146.9 $ 7,642.4
========= =========
LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities:
Accounts payable.......................................... $ 285.0 $ 270.5
Accrued taxes payable..................................... 68.6 64.9
Short-term debt (Note 9).................................. 2.3 853.8
Other current liabilities (Note 14)....................... 185.8 157.5
--------- ---------
Total current liabilities......................... 541.7 1,346.7
--------- ---------
Long-term debt (Note 9)..................................... 2,797.3 3,744.9
Deferred income taxes (Note 8).............................. 1,326.8 1,291.6
Retiree benefits obligations (Note 11)...................... 142.5 142.9
Other long-term liabilities (Notes 12, 13 and 14)........... 401.1 388.1
Shareholders' equity (see page 45).......................... 937.5 728.2
--------- ---------
Total liabilities and shareholders' equity........ $ 6,146.9 $ 7,642.4
========= =========
</TABLE>
The accompanying accounting policies and notes to the Consolidated Financial
Statements are an integral part of these statements.
43
<PAGE> 46
UNION PACIFIC RESOURCES GROUP INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR YEARS ENDED DECEMBER 31, 1999, 1998 AND 1997
<TABLE>
<CAPTION>
1999 1998 1997
--------- --------- ---------
(MILLIONS OF DOLLARS)
<S> <C> <C> <C>
Cash provided by operations:
Net income................................................ $ 225.8 $ (898.7) $ 333.0
(Income) loss from discontinued operations (Note 3)..... (133.2) 15.6 (29.9)
Gain on extinguishment of debt -- net of tax............ (3.4) -- --
--------- --------- ---------
Income (loss) from continuing operations.................. 89.2 (883.1) 303.1
Non-cash charges to income:
Depreciation, depletion and amortization................ 827.7 2,125.6 504.0
Deferred income tax (benefit) (Note 8).................. 1.4 (659.3) 110.9
Surrendered lease amortization.......................... 172.5 185.9 85.6
(Gains) losses on sales of assets -- net................ (148.0) (139.9) (18.8)
Other non-cash charges (credits) -- net................. (86.2) 194.7 (96.2)
Exploratory expenditures.................................. 44.1 115.2 76.9
Changes in current assets and liabilities................. 94.8 92.0 (109.3)
--------- --------- ---------
Cash provided by operations........................ 995.5 1,031.1 856.2
--------- --------- ---------
Investing activities:
Capital and exploratory expenditures (Note 7)............. (428.2) (1,194.5) (1,188.4)
Acquisition of Norcen (Note 2)............................ -- (2,634.3) --
Proceeds from sale of discontinued operations (Note 3).... 1,359.1 -- --
Proceeds from sales of assets (Note 3).................... 281.3 436.6 37.3
Proceeds from sale of investments......................... -- 48.4 --
Cash provided (used) by discontinued operations........... (203.6) 50.4 (221.8)
Other investing activities -- net......................... -- -- (17.7)
--------- --------- ---------
Cash provided (used) by investing activities....... 1,008.6 (3,293.4) (1,390.6)
--------- --------- ---------
Financing activities:
Dividends paid............................................ (49.6) (49.6) (50.0)
Repayment of debt......................................... (2,295.5) -- --
Proceeds from long-term debt issuance (Note 9)............ 500.0 1,025.0 --
Other debt financing -- net............................... -- 1,294.5 559.6
Repurchase of common stock................................ (12.6) (26.7) (52.3)
Reissuance of treasury stock.............................. 3.3 -- --
Other financings -- net (Note 9).......................... (34.8) (39.2) 30.4
--------- --------- ---------
Cash provided (used) by financing activities....... (1,889.2) 2,204.0 487.7
--------- --------- ---------
Net change in cash and temporary investments................ 114.9 (58.3) (46.7)
Balance at beginning of year................................ 8.8 67.1 113.8
--------- --------- ---------
Balance at end of year...................................... $ 123.7 $ 8.8 $ 67.1
========= ========= =========
Changes in current assets and liabilities:
Accounts receivable....................................... $ (37.2) $ 215.8 $ (33.2)
Inventories............................................... 9.9 (17.8) (1.5)
Other current assets...................................... 98.3 3.2 21.6
Accounts payable.......................................... 40.8 (153.4) (21.4)
Accrued taxes payable..................................... (55.2) 3.5 (73.4)
Other current liabilities................................. 38.2 40.7 (1.4)
--------- --------- ---------
Total.............................................. $ 94.8 $ 92.0 $ (109.3)
========= ========= =========
Supplemental cash flow disclosure:
Interest paid:
Continuing operations................................... $ 227.5 $ 216.0 $ 42.7
Discontinued operations................................. 7.4 21.1 13.6
Income taxes paid (recovered):
Continuing operations................................... (95.5) 81.0 121.0
Discontinued operations................................. -- (35.0) 8.7
</TABLE>
The accompanying accounting policies and notes to the Consolidated Financial
Statements
are an integral part of these statements.
44
<PAGE> 47
UNION PACIFIC RESOURCES GROUP INC.
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS' EQUITY
FOR THE YEARS ENDED DECEMBER 31, 1999, 1998 AND 1997
<TABLE>
<CAPTION>
1999 1998 1997
------ ------- --------
(MILLIONS OF DOLLARS)
<S> <C> <C> <C>
Common stock, no par value; authorized 400,000,000 shares:
251,951,140 shares issued and outstanding at December 31,
1999
250,685,204 shares issued and outstanding at December 31,
1998
251,888,575 shares issued and outstanding at December 31,
1997
Balance at beginning and end of year...................... $ -- $ -- $ --
------ ------- --------
Paid-in surplus (Note 15):
Balance at beginning of year.............................. 992.6 991.2 872.9
Conversion, award, forfeiture and appreciation of
retention shares........................................ 13.6 0.5 5.1
Issuance of ESOP shares................................... -- -- 107.3
Release of ESOP shares.................................... (11.8) -- --
Exercise of stock options................................. 3.3 0.6 5.5
Other..................................................... 1.1 0.3 0.4
------ ------- --------
Balance at end of year.................................... 998.8 992.6 991.2
------ ------- --------
Retained earnings:
Balance at beginning of year.............................. 9.1 957.4 674.4
Net income (loss)......................................... 225.8 (898.7) 333.0
------ ------- --------
Total.............................................. 234.9 58.7 1,007.4
Dividends declared on common stock........................ (49.6) (49.6) (50.0)
------ ------- --------
Balance at end of year.................................... 185.3 9.1 957.4
------ ------- --------
Unearned compensation (Note 15):
Balance at beginning of year.............................. (6.0) (11.8) (17.5)
Conversion, award, forfeiture and amortization of
retention shares -- net................................. 3.5 5.8 5.7
------ ------- --------
Balance at end of year.................................... (2.5) (6.0) (11.8)
------ ------- --------
ESOP (Note 15):
Balance at beginning of year.............................. (95.7) (102.0) --
Issuance of ESOP shares................................... -- -- (107.3)
Release of ESOP shares.................................... 16.2 6.3 5.3
------ ------- --------
Balance at end of year............................. (79.5) (95.7) (102.0)
------ ------- --------
Treasury stock (Note 15):
Balance at beginning of year.............................. (82.5) (55.8) (3.5)
Treasury stock repurchased or reissued, at cost -- net.... (9.3) (26.7) (52.3)
------ ------- --------
Balance at end of year: 4,276,989 shares at December 31,
1999
3,666,913 shares at December 31,
1998
2,379,625 shares at December 31,
1997............................ (91.8) (82.5) (55.8)
------ ------- --------
Comprehensive income:
Deferred foreign exchange adjustment (Note 15):
Balance at beginning of year............................ (84.4) (17.3) (12.0)
Foreign currency translation adjustment................. 22.5 (67.1) (5.3)
------ ------- --------
Balance at end of year.................................. (61.9) (84.4) (17.3)
------ ------- --------
Minimum pension liability (Note 11)
Balance at beginning of year............................ (4.9) (1.0) --
Minimum pension liability adjustment.................... (6.0) (3.9) (1.0)
------ ------- --------
Balance at end of year.................................. (10.9) (4.9) (1.0)
------ ------- --------
Total Comprehensive income......................... (72.8) (89.3) (18.3)
------ ------- --------
Total shareholders' equity......................... $937.5 $ 728.2 $1,760.7
====== ======= ========
</TABLE>
The accompanying accounting policies and notes to the Consolidated Financial
Statements
are an integral part of these statements.
45
<PAGE> 48
UNION PACIFIC RESOURCES GROUP INC.
BUSINESS SEGMENT INFORMATION
AS OF AND FOR THE YEARS ENDED DECEMBER 31, 1999, 1998 AND 1997
<TABLE>
<CAPTION>
1999 1998 1997
-------- --------- --------
(MILLIONS OF DOLLARS)
<S> <C> <C> <C>
Revenues(a):
Exploration and production................................ $1,607.0 $ 1,699.9 $1,378.2
Minerals.................................................. 120.5 141.1 139.8
-------- --------- --------
Total revenues.................................... $1,727.5 $ 1,841.0 $1,518.0
======== ========= ========
Depreciation, depletion and amortization:
Exploration and production................................ $ 816.0 $ 2,115.8 $ 499.3
Minerals.................................................. 5.5 4.1 0.9
Corporate................................................. 6.2 5.7 3.8
-------- --------- --------
Total depreciation, depletion and amortization.... $ 827.7 $ 2,125.6 $ 504.0
======== ========= ========
Operating income (loss):
Exploration and production................................ $ 122.5 $(1,199.2) $ 373.4
Minerals.................................................. 117.8 133.5 135.5
Corporate(b).............................................. (104.5) (127.5) (75.0)
-------- --------- --------
Total operating income (loss)..................... $ 135.8 $(1,193.2) $ 433.9
======== ========= ========
Fixed assets -- net:
Exploration and production................................ $5,367.4 $ 5,988.8 $2,827.1
Minerals.................................................. 7.4 10.2 14.1
Corporate................................................. 96.2 94.3 59.9
-------- --------- --------
Total fixed assets -- net......................... $5,471.0 $ 6,093.3 $2,901.1
======== ========= ========
Capital and exploratory expenditures:
Exploration and Production................................ $ 423.1 $ 3,796.2 $1,172.6
Minerals.................................................. -- 0.1 1.4
Corporate................................................. 5.1 32.5 14.4
-------- --------- --------
Total capital and exploratory expenditures........ $ 428.2 $ 3,828.8 $1,188.4
======== ========= ========
</TABLE>
GEOGRAPHIC INFORMATION
<TABLE>
<CAPTION>
1999 1998 1997
-------- --------- --------
(MILLIONS OF DOLLARS)
<S> <C> <C> <C>
Revenues(a):
United States............................................. $1,182.9 $ 1,455.9 $1,477.2
Canada.................................................... 332.1 259.0 28.9
Other international....................................... 212.5 126.1 11.9
-------- --------- --------
Total revenues.................................... $1,727.5 $ 1,841.0 $1,518.0
======== ========= ========
Fixed assets -- net:
United States............................................. $2,389.6 $ 2,965.2 $2,800.9
Canada.................................................... 1,918.8 1,854.0 89.8
Other international....................................... 1,162.6 1,274.1 10.4
-------- --------- --------
Total fixed assets -- net......................... $5,471.0 $ 6,093.3 $2,901.1
======== ========= ========
</TABLE>
- ---------------
(a) 1999, 1998 and 1997 revenues include income from equity affiliates of $78.5
million, $89.7 million and $74.4 million, respectively for the Minerals
segment.
(b) Segment operating loss for the Corporate segment consists primarily of
general and administrative expense and restructuring charge.
The Company's reportable segments are strategic business units or an
aggregation of business units with similar operations and management objectives.
The reportable segments are managed separately because each segment requires
different operational assets, technology and management strategies.
This information should be read in conjunction with the accompanying accounting
policies and notes
to the Consolidated Financial Statements.
46
<PAGE> 49
UNION PACIFIC RESOURCES GROUP INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
SIGNIFICANT ACCOUNTING POLICIES
Principles of Consolidation. The Consolidated Financial Statements include
the accounts of Union Pacific Resources Group Inc. (a Utah Corporation) and
subsidiaries (collectively, the "Company"), including its principal operating
subsidiary Union Pacific Resources Company ("UPRC"). The Company accounts for
investments in affiliated companies (20% to 50% owned) on the equity method of
accounting. The Company also consolidates its pro-rata share of oil and gas
joint ventures. All significant intercompany transactions are eliminated. The
Consolidated Financial Statements for previous periods include certain
reclassifications that were made to conform to the current presentation. Such
reclassifications have no effect on previously reported net income. Refer to the
accompanying notes to the financial statements for additional disclosure of the
Company's significant accounting policies.
As a result of the disposition of the Company's gathering, processing and
marketing ("GPM") business segment, the GPM business segment has been accounted
for as a discontinued operation. GPM results of operations have been excluded
from continuing operations in the Consolidated Statements of Income and Cash
Flows. GPM net assets have been segregated from continuing operations in the
accompanying statements of financial position and reported as net assets of
discontinued operations (See Note 3).
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 74).
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. At December 31, 1999 and 1998 hydrocarbon inventory was $13.5
million and $11.0 million, respectively, while materials and supplies inventory
was $41.1 million and $53.6 million, respectively.
Oil and Gas Properties. Oil and gas properties are accounted for using the
successful efforts method. Under this method, exploration costs (drilling costs
of unsuccessful exploration wells, geological and geophysical costs,
non-producing leasehold amortization and delay rentals) are charged to expense
when incurred. Costs to develop producing properties, including drilling costs
and applicable leasehold acquisition costs, are capitalized. Costs to drill
exploratory wells that result in additions to reserves are also capitalized.
Depreciation, depletion and amortization of producing properties, including
depreciation of well and support equipment and amortization of related lease
costs, are determined by using a unit of production method based upon estimated
proved reserves. Provisions for depreciation of property and equipment other
than producing properties are computed principally on the straight-line method
based on estimated service lives, which range from two to 15 years. Potential
impairment of producing properties is assessed annually on a field-by-field
basis. Significant unproved properties are not amortized, but are monitored for
impairment and assessed annually in detail. Aggregated acquisition costs of
individual insignificant unproved properties are amortized from the date of
acquisition on a composite basis, which considers past success experience and
average lease life (see Note 6).
47
<PAGE> 50
UNION PACIFIC RESOURCES GROUP INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Costs of future site restoration, dismantlement and abandonment for
producing properties are accrued as part of depreciation, depletion and
amortization expense for tangible equipment by assuming no salvage value in the
calculation of the unit of production rate. Additional costs are accrued for
offshore and Canadian wells based on internal engineering estimates using the
unit of production method with a charge to depreciation, depletion and
amortization expense. The balance of the abandonment accrual at December 31,
1999 and 1998 was $75.0 million and $62.1 million, respectively.
Gains or losses on retired, sold or abandoned properties that constitute
part of an amortization base are deferred by charging or crediting the
investment, net of proceeds, to accumulated depreciation, depletion and
amortization unless such non-recognition 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 are
recognized in other oil and gas revenues. Gains included in other oil and gas
revenues were $148.0 million, $139.9 million and $18.8 million in 1999, 1998 and
1997, respectively. Gains and losses from all other dispositions are recorded in
other income.
Goodwill. Intangible and other assets include goodwill of $68.6 million for
intangible value acquired from business combinations prior to 1971. Such
goodwill is not being amortized because it is considered to have continuing
value over an indefinite period. The value of goodwill is evaluated annually to
determine whether any potential impairment exists.
Revenue Recognition. Sales from producing wells are recognized on the
entitlement method of accounting which defers recognition of sales when, and to
the extent that, deliveries to customers exceed the Company's net revenue
interest in production. Similarly, when deliveries are below the Company's net
revenue interest in production, sales are recorded to reflect the full net
revenue interest. The Company's gas imbalance liability at December 31, 1999 and
1998 was $5.5 million and $5.2 million, respectively. Natural gas and crude oil
marketing revenue is included in other oil and gas revenue and recorded net of
the cost of product purchased.
Recently issued accounting standards. The Financial Accounting Standards
Board ("FASB") has issued Statement of Financial Accounting Standards ("SFAS")
No. 133, "Accounting for Derivative Instruments and Hedging Activities," and
SFAS No. 137, which defers the effective date of SFAS No. 133 to fiscal years
beginning after June 15, 2000. SFAS No. 133 requires that all derivatives be
recognized on the balance sheet and measured at fair value. If certain
conditions are met, a derivative may be specifically designated as a hedge and
be eligible for special accounting treatment. However, the special accounting
treatment afforded hedge transactions may delay the recognition of a portion of
the gain or loss on the derivative, which would later be recorded concurrent
with the gain or loss on the item being hedged. For derivatives not designated
as hedges, gains or losses are recognized in earnings in the period of change.
The impact of the statement on the Company will depend upon price volatility and
the level of open derivative positions at the end of a reporting period. The
Company plans to adopt SFAS No. 133 for the first quarter 2001 and is currently
evaluating the effects of this pronouncement. Adoption will require the Company
to begin recording unrealized gains and losses in the Consolidated Statement of
Financial Position and in the Consolidated Statement of Comprehensive Income.
1. NATURE OF OPERATIONS
The Company is an independent oil and gas company engaged primarily in the
exploration for and the development and production of natural gas and crude oil
in several major basins in the United States, Canada, Guatemala, Venezuela and
other international areas. The Company markets all of its crude oil production
together with significant volumes of crude oil produced by others. In 1998, the
Company marketed a substantial portion of its natural gas and natural gas
liquids ("NGLs"); however, in 1999 the Company entered into a long-term natural
gas sales agreement to sell a substantial portion of its domestic natural gas
and NGLs to Duke (hereinafter defined) (see Notes 3 and 5). The Company also
engages in the hard
48
<PAGE> 51
UNION PACIFIC RESOURCES GROUP INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
minerals business through non-operated joint ventures and royalty arrangements
in several coal, trona (natural soda ash) and industrial mineral 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 crude oil and natural gas, the
price of foreign imports, the level of consumer demand and the price and
availability of alternative fuels. The Company manages a portion of the
operating risk relating to hydrocarbon price volatility through hedging
activities (see Note 5).
2. ACQUISITIONS
Norcen Energy Resources Limited. On January 25, 1998, the Company and Union
Pacific Resources Inc. ("UPRI"), an Alberta corporation and a wholly-owned
subsidiary of the Company, entered into a pre-acquisition agreement
("Pre-acquisition Agreement") with Norcen Energy Resources Limited ("Norcen").
Under the Pre-acquisition Agreement, the Company and UPRI agreed to make an
offer (the "Tender Offer") for up to 100% of the common shares of Norcen,
subject to certain conditions. On March 3, 1998, the Company announced the
closing of the Tender Offer. In total, 95.5% of the outstanding common shares of
Norcen were tendered at a purchase price of U.S. $13.65 per share.
On March 5, 1998, the Company and UPRI completed the compulsory acquisition
of the remaining common shares outstanding which were not tendered. (The closing
of the Tender Offer and completion of the compulsory acquisition is referred to
as the "Norcen Acquisition.") The aggregate cash purchase price for the Norcen
Acquisition, including non-recurring transaction costs of $28.1 million, was
$2.634 billion. In addition, UPRI assumed the long-term debt obligations of
Norcen.
Norcen operations primarily consisted of crude oil and natural gas
exploration and development operations in western Canada, the Gulf of Mexico,
Guatemala and Venezuela.
The Company funded the purchase price of the Norcen Acquisition through the
issuance of commercial paper, supported by a U.S. $2.7 billion 364-Day
Competitive Advance/Revolving Credit Agreement dated March 2, 1998. In
accordance with Accounting Principles Board Opinion No. 16, "Business
Combinations," the Norcen Acquisition was accounted for as a purchase effective
March 3, 1998.
The following table represents the allocation of the total purchase price
of the assets acquired and liabilities assumed, based upon their fair values on
the date of the Norcen Acquisition and pushed down to the acquired Company. In
accordance with SFAS No. 109 "Accounting for Income Taxes", a deferred tax
liability was recognized for the differences between the allocated values and
the tax bases of the acquired assets and liabilities.
<TABLE>
<CAPTION>
MARCH 1998
---------------------
(MILLIONS OF DOLLARS)
<S> <C>
Working capital............................................. $ 114.4
Property, plant and equipment............................... 4,931.2
Other assets................................................ 228.2
Long-term debt.............................................. (1,012.0)
Deferred taxes.............................................. (1,495.7)
Other non-current liabilities............................... (131.8)
---------
Total purchase price.............................. $ 2,634.3
=========
</TABLE>
49
<PAGE> 52
UNION PACIFIC RESOURCES GROUP INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The following table presents unaudited pro forma Condensed Consolidated
Statements of Income of the Company for the twelve months ended December 31,
1998 and 1997, as though the Norcen Acquisition had occurred on January 1, 1997.
Certain adjustments were made to the financial information to conform to the
accounting policies and financial statement presentation of the Company.
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
----------------------------
1998 1997
------------ -----------
(MILLIONS OF DOLLARS, EXCEPT
PER SHARE AMOUNTS)
<S> <C> <C>
Revenues.................................................... $ 1,940.8 $2,169.3
Costs and expenses.......................................... 3,165.2 1,810.4
--------- --------
Operating income (loss)..................................... (1,224.4) 358.9
Interest expense............................................ (284.3) (240.1)
Other income (expense) -- net............................... (45.3) 24.5
--------- --------
Income (loss) before income taxes........................... (1,554.0) 143.3
Income tax (benefit) expense................................ (629.4) (24.5)
--------- --------
Income (loss) from continuing operations.................... $ (924.6) $ 118.8
========= ========
Earnings (loss) per share -- basic and diluted Continuing
operations................................................ $ (3.73) $ 0.47
</TABLE>
The unaudited pro forma condensed consolidated information presented above
is not necessarily indicative of the results of operations which would have
occurred had the Norcen Acquisition been consummated on January 1, 1997, nor is
it necessarily indicative of future results of operations.
Norcen Summarized Financial Information. As a result of the Norcen
Acquisition, and the amalgamation of Norcen with UPRI, UPRI assumed the
obligations of Norcen, including the public debt obligations of Norcen (the
"Debt Securities"). The Debt Securities include 6.8% Debentures due July 2,
2002, in the aggregate principal amount of $250 million, 7 3/8% Debentures due
May 15, 2006, in the aggregate principal amount of $250 million, and 7.8%
Debentures due July 2, 2008, in the aggregate principal amount of $150 million,
each of which have been fully and unconditionally guaranteed by the Company.
The following table presents summarized financial information for UPRI (as
successor to Norcen) as of and for the year ended December 31, 1999 and the two
months ended February 28, 1998, and ten months ended December 31, 1998. This
summarized financial information is being provided pursuant to Section G of
Topic 1 of Staff Accounting Bulletin No. 53 -- "Financial Statement Requirements
in Filings Involving the Guarantee of Securities by a Parent." The Company will
continue to provide such summarized financial information for UPRI as long as
the Debt Securities remain outstanding.
<TABLE>
<CAPTION>
YEAR ENDED UNAUDITED
DECEMBER 31, TEN MONTHS TWO MONTHS
1999 ENDED ENDED
--------------------- DECEMBER 31, FEBRUARY 28,
1998(a) 1998(b)
-------------------- --------------------
(MILLIONS OF (MILLIONS OF (MILLIONS OF
DOLLARS) DOLLARS) DOLLARS)
<S> <C> <C> <C>
Summarized Statement of Income
Information:
Operating revenues................... $343.0 $ 357.2 $104.0
Operating income (loss).............. (13.0) (784.5) 4.0
Net income (loss).................... $ 12.0 $(508.3)(c) $(30.0)(d)
</TABLE>
50
<PAGE> 53
UNION PACIFIC RESOURCES GROUP INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
<TABLE>
<CAPTION>
AT DECEMBER 31, 1999 AT DECEMBER 31, 1998
-------------------- --------------------
(MILLIONS OF DOLLARS)
<S> <C> <C>
Summarized Statement of Financial Position Information:
Current assets........................................ $ 40.5 $ 53.7
Non-current assets.................................... 1,844.8 1,882.3
Current liabilities................................... 83.9 279.8
Non-current liabilities and equity.................... $1,801.4 $1,656.2
</TABLE>
- ---------------
(a) Results for UPRI as of and for the ten months ended December 31, 1998,
include adjustments to reflect U.S. GAAP and the successful efforts method
of accounting. Adjustments to reflect the application of the purchase method
of accounting for the Norcen Acquisition are included effective March 3,
1998.
(b) Results for Norcen as of and for the two months ended February 28, 1998 have
not been restated in accordance with U.S. generally accepted accounting
principles ("GAAP") and reflect the full cost method of accounting for oil
and gas operations.
(c) Results reflect the impairment and write-down of certain oil and gas
properties.
(d) Net loss includes $40 million in costs incurred by Norcen in connection with
the Norcen Acquisition which were not reimbursed by the Company.
3. DIVESTITURES
Deleveraging Program. In 1998, the Company commenced a deleveraging program
which was designed to reduce the Company's debt. The deleveraging program, which
was initiated following the completion of the Norcen Acquisition, included the
sale of non-strategic properties and assets. The completed sales undertaken as
part of the Company's deleveraging program include the following:
<TABLE>
<CAPTION>
NON-STRATEGIC PROPERTIES OPERATING AREA SALES PRICE
- ------------------------ -------------- ---------------------
(MILLIONS OF DOLLARS)
<S> <C> <C>
1998
Denver-Julesburg Basin...................................... U.S. Onshore $ 41
Matagorda Island Blocks..................................... U.S. Offshore 158
Rockies Package............................................. U.S. Onshore 46
Eugene Island Blocks........................................ U.S. Offshore 8
Canadian Package............................................ Canada 145
Superior Propane............................................ Canada 48
----
1998 Total................................................ $446
----
1999
Caroline -- Swan Hill....................................... Canada $108
South Texas Package(a)...................................... U.S. Onshore 138
East Texas Package.......................................... U.S. Onshore 18
Rockies Package............................................. U.S. Onshore 10
Project Orange.............................................. Other 25
----
1999 Total................................................ 299
----
Total............................................. $745
====
</TABLE>
- ---------------
(a) As a result of the sale of the South Texas Package, the Company recorded a
fully reserved $20.6 million note receivable included in other current
assets. If the note is collected, the Company will record $20.6 million in
additional proceeds and gain on the South Texas sale.
Discontinued Operations. In November 1998, the Company entered into a
Merger and Purchase Agreement ("Agreement") with Duke Energy Field Services,
Inc. ("Duke") to sell its GPM business segment for $1.36 billion in cash. On
March 31, 1999, the Company closed on the sale (the "GPM
51
<PAGE> 54
UNION PACIFIC RESOURCES GROUP INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Disposition"). The GPM Disposition consisted primarily of the Company's
pipelines, gathering systems, natural gas processing plants and natural gas and
NGL marketing assets and operations. These operations included interests in
nineteen natural gas processing plants (together with approximately 7,200 miles
of pipelines that support these processing plants), as well as two non-operated
NGL fractionation plants. The Company retained its crude oil marketing business.
The Company recorded a $157.0 million after-tax gain on the GPM Disposition,
including $108.3 million for accrued taxes payable.
Summarized information relating to discontinued results of operations,
excluding the after-tax gain on the GPM Disposition are as follows:
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
--------------------------
1999 1998 1997
------ ------- -------
(MILLIONS OF DOLLARS)
<S> <C> <C> <C>
Operating revenues....................................... $ 21.5 $ 340.0 $ 406.7
Operating expenses....................................... (29.7) (263.4) (281.3)
Depreciation depletion and amortization.................. (20.4) (77.6) (64.1)
------ ------- -------
Operating income (loss).................................. (28.6) (1.0) 61.3
Other income (expense) -- net............................ -- -- (0.2)
Interest expense (a)..................................... (8.0) (21.1) (13.6)
------ ------- -------
Income (loss) before taxes............................... (36.6) (22.1) 47.5
Income tax (benefit) expense............................. (12.8) (6.5) 17.6
------ ------- -------
Net income (loss) from discontinued operations........... $(23.8) $ (15.6) $ 29.9
====== ======= =======
</TABLE>
- ---------------
(a) The Company allocated interest expense to the GPM business segment based on
the ratio of net assets of discontinued operations to total Company net
assets, excluding $3.6 billion of debt associated with the Norcen
Acquisition.
Summarized information relating to net assets of discontinued operations
are as follows:
<TABLE>
<CAPTION>
AT DECEMBER 31, 1998
---------------------
(MILLIONS OF DOLLARS)
<S> <C>
Current Assets:
Cash and temporary investments............................ $ 5.7
Accounts receivable -- net................................ 152.8
Inventories............................................... 46.8
Other current assets...................................... 5.2
--------
Total current assets.............................. 210.5
Properties -- net of accumulated depreciation............. 851.3
Intangible and other assets............................... 154.8
--------
Total assets...................................... $1,216.6
========
Current Liabilities:
Accounts payable.......................................... $ 158.0
Advance payment(a)........................................ 126.7
Other current liabilities................................. 2.0
--------
Total current liabilities......................... 286.7
Other long-term liabilities............................... 3.0
--------
Total liabilities................................. $ 289.7
========
Net assets of discontinued operations............. $ 926.9
========
</TABLE>
52
<PAGE> 55
UNION PACIFIC RESOURCES GROUP INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
- ---------------
(a) In June 1998, the Company entered into a third-party forward sales
arrangement covering a total of 567 MMcf of gas per day. At the time of the
arrangement, the Company received $250 million and became obligated to
deliver gas from October 1998 through March 1999. The Company recorded the
obligation associated with this transaction as an advance payment included
in net assets of discontinued operations. This current liability was
amortized and recorded on the Consolidated Statement of Income as part of
discontinued operations, as the gas was delivered over the remaining term of
the contract.
4. RESTRUCTURING CHARGES
During the first quarter of 1999, the Company reorganized its operating
groups, announced workforce reductions for its Canadian and U.S. operations and
established an early retirement program. As a result of these actions, the
Company recorded a $14.5 million restructuring charge. The charge included $7.3
million for severance costs and excess office space commitments, an additional
$4.2 million liability for pension and other postretirement benefits in
connection with the early retirement program and a $3.0 million valuation
allowance for specialty drilling equipment and supplies no longer required for
cancelled drilling programs. Payments of $7.2 million were made for severance
and office lease costs. The pension and other postretirement liabilities are
included in the balance of the Company's liabilities for those items (see Note
11). The valuation allowance for specialty drilling equipment and supplies was
recorded to the inventory accounts.
During 1998, the Company announced a workforce reduction for its domestic
operations and implemented programs to reduce overhead and other costs. The
$17.0 million restructuring charge included $7.6 million for workforce
reductions of approximately 140 U.S. employees, $5.0 million for a drilling rig
commitment and $4.4 million for excess office space commitments. At December 31,
1998, $14.6 million of the reserve remained. During 1999, net payments of $8.1
million were made and $3.1 million of the rig commitment charge was reversed as
a result of favorable settlement negotiations. At December 31, 1999, the $3.4
million remaining reserve represents excess office space commitments net of
sublease rentals.
5. FINANCIAL INSTRUMENTS
Hedging. The Company has established policies and procedures for managing
risk within its organization, including internal controls and governance by a
risk management committee. The level of risk assumed by the Company is based on
its objectives and earnings, and its capacity to manage risk. Limits are
established for each major category of risk, with exposures monitored and
managed by Company management and reviewed semi-annually by the risk management
committee. Major categories of the Company's risk are defined as follows:
Commodity Price Risk -- Non-Trading Activities. The Company uses derivative
financial instruments for non-trading purposes in the normal course of business
to manage and reduce risks associated with contractual commitments, price
volatility and other market variables. These instruments are generally put in
place to limit risk of adverse price movements; however, these same instruments
usually limit future gains from favorable price movements. Risk management
activities are generally accomplished pursuant to exchange-traded contracts or
over-the-counter swaps and options.
Recognition of realized gains/losses and option premium payments/receipts
relating to non-trading activities are deferred in the Consolidated Statement of
Income until the underlying physical product is sold. Unrealized gains/losses
are not recorded. Margin deposits, deferred gains/losses and net premiums are
included in other current assets or liabilities in the Consolidated Statement of
Financial Position. The cash flow impact is reflected in cash flows provided by
operations in the Consolidated Statement of Cash Flows.
Utilization of the Company's hedging program may result in crude oil and
natural gas prices varying from market prices. As a result of the hedging
program, revenues in 1999, 1998 and 1997 were $178.1 million, $9 million and $86
million lower, respectively than if the hedging program had not been in effect.
Since these transactions were hedges on production, these impacts were also
reflected in the average sales price of the associated products.
53
<PAGE> 56
UNION PACIFIC RESOURCES GROUP INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Commodity Price Risk -- Trading Activities. The Company periodically enters
into financial contracts in conjunction with market-making or trading activities
with the objective of achieving profits through successful anticipation of
movements in commodity prices and changes in other market variables. Market-
making positions are marked-to-market and gains and losses are immediately
included as revenue in the Consolidated Statement of Income. In addition, the
fair value of unsettled positions is immediately included in the Consolidated
Statement of Financial Position as a current asset or current liability. As of
December 31, 1999 and 1998, there were no transactions in place which would
materially affect the results of operations or financial condition of the
Company.
Interest Rate Swaps. The Company periodically enters into rate swaps and
contracts to hedge certain interest rate transactions. As of December 31, 1999
and 1998, there were no interest rate contracts outstanding which would
materially affect the results of operations or financial condition of the
Company. During 1998, the Company entered into rate lock contracts to hedge
interest rates related to a contemplated bond issuance. The bonds were not
issued and the Company recognized a $14.3 million pre-tax loss in 1998
associated with these contracts.
Foreign Currency. The financial statements of foreign subsidiaries, except
those subsidiaries located in countries which have highly inflationary
economies, utilize the local currency as their functional currency. The
financial statements of foreign subsidiaries located in countries which have
highly inflationary economies utilize the U.S. dollar as their functional
currency. Monetary assets and liabilities denominated in a currency other than
the functional currency are remeasured into the functional currency with the
corresponding gains/ losses included in the Consolidated Statement of Income.
The financial statements of those foreign subsidiaries which do not utilize the
U.S. dollar as their functional currency are translated into the U.S. dollar.
Assets and liabilities are translated at the current exchange rate, while
revenues and expenses are translated at the average exchange rate for the
reporting period. Translation gains/losses are not included in the Consolidated
Statement of Income but are recorded in a separate section of shareholders'
equity. The Company's Canadian subsidiary's functional currency is the Canadian
dollar. Generally, the functional currency of the Company's other foreign
subsidiaries is the U.S. dollar.
At December 31, 1999, the Company's Canadian subsidiary had outstanding
$650 million of fixed-rate notes and debentures denominated in U.S. dollars.
During 1999, the Company recognized a $38.0 million pretax non-cash gain
associated with remeasurement of this debt and a $46.5 million pretax non-cash
loss during 1998. The potential foreign currency remeasurement impact on
earnings from a five percent change in the year-end Canadian exchange rate would
be approximately $32 million.
Two of the Company's Latin American subsidiaries had foreign deferred tax
liabilities denominated in the local currency. At December 31, 1999 and 1998,
Venezuela had a $131.6 million and $159.6 million liability, respectively and
Guatemala had a $34.1 million and $58.0 million liability, respectively. During
1999 and 1998, the Company recognized after-tax deferred tax benefits associated
with the remeasurement of the deferred tax liabilities of $20.4 million and
$15.2 million in Venezuela, and $8.9 million and $7.3 million in Guatemala,
respectively. The potential foreign currency remeasurement impact on net
earnings from a five percent change in the year-end Latin American exchange
rates would be approximately $9 million.
The Company may periodically enter into foreign currency contracts to hedge
specific currency exposures from commercial transactions. As a result of the
Norcen Acquisition, the Company acquired foreign currency forward exchange
contracts with maturities through October 2000, and recorded a $15.5 million
deferred liability representing the fair value of these contracts. These
contracts were deemed to be hedges of UPRI's future U.S. dollar denominated
hydrocarbon sales. This deferred liability will be amortized over the contract
terms. The unrecognized loss on foreign currency contracts at December 31, 1999,
excluding the $1.4 million remaining unamortized deferred liability, was $2.9
million.
54
<PAGE> 57
UNION PACIFIC RESOURCES GROUP INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Concentrations of Credit Risk. Credit risk is the risk of loss as a result
of non-performance by counterparties pursuant to the terms of their contractual
obligations. Because the loss can occur at some point in the future, a potential
exposure is added to the current replacement value to arrive at a total expected
credit exposure. The Company has established methodologies to establish limits,
monitor and report creditworthiness and concentrations of credit to reduce such
credit risk. At December 31, 1999, the Company's largest credit risk associated
with any single counterparty, represented by the net fair value of open
contracts with such counterparty, was $7.1 million.
Financial instruments which subject the Company to concentrations of credit
risk consist principally of trade receivables and short-term cash investments.
The Company places its temporary excess cash investments in high quality
short-term instruments through several high-credit-quality financial
institutions. A significant portion of the Company's trade receivables relate to
customers in the oil and gas industry, and, as such, the Company is directly
affected by the economy of that industry. The Company derives a substantial
portion of its revenues from international operations in Canada and Latin
America. With the exception of one large customer, described below, 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.
In connection with the GPM Disposition, the Company entered into a
long-term sales agreement with Duke. The long-term sales agreement obligates the
Company to sell the majority of its domestic natural gas and existing NGL
production to Duke through March 2004. Prices received for the natural gas and
NGLs will be tied to the current market price for each product. As a result, a
significant portion of the Company's credit risk will be with a single customer.
Duke is currently considered a good credit risk; however, periodic credit
evaluations will continue and will be performed more often if circumstances
dictate. The agreement with Duke provides for a parental guaranty to cover its
obligations under the agreements and the Company has the right to demand a
letter of credit and/or other assurances under certain circumstances. During
1999, sales to Duke accounted for 31% of the Company's consolidated revenues and
38% of United States revenues. Approximately 25% of the Company's trade
receivables outstanding at December 31, 1999 were due from Duke which exposes
the Company to a concentration of credit risk.
Performance Risk. Performance risk results when a counterparty fails to
fulfill its contractual obligations with respect to commodity pricing or volume
commitments. Typically, such risk obligations are defined within the trading
agreements. The Company utilizes its credit risk methodology to manage
performance risk.
6. PROPERTIES
Major property classifications were as follows:
<TABLE>
<CAPTION>
AS OF DECEMBER 31,
---------------------
1999 1998
--------- ---------
(MILLIONS OF DOLLARS)
<S> <C> <C>
Producing properties........................................ $ 9,738.3 $ 9,429.9
Non-producing properties.................................... 983.3 1,241.5
Construction in progress.................................... 84.3 143.4
Other....................................................... 200.7 263.4
--------- ---------
Total............................................. $11,006.6 $11,078.2
========= =========
</TABLE>
55
<PAGE> 58
UNION PACIFIC RESOURCES GROUP INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Accumulated depreciation, depletion and amortization by major property
classifications were as follows:
<TABLE>
<CAPTION>
AS OF DECEMBER 31,
---------------------
1999 1998
--------- ---------
(MILLIONS OF DOLLARS)
<S> <C> <C>
Producing properties........................................ $5,160.0 $4,642.1
Non-producing properties.................................... 273.2 233.1
Other....................................................... 102.4 109.7
-------- --------
Total............................................. $5,535.6 $4,984.9
======== ========
</TABLE>
Based upon the Company's analysis of expected future net cash flows from
its crude oil and natural gas properties, certain properties were deemed to be
impaired due to lower hydrocarbon prices and/or downward revisions in reserve
estimates. As a result of its analysis, the Company adjusted the net book value
of such properties to their fair value with a charge to depreciation, depletion
and amortization of $70.6 million in 1999 for exploration and production
properties primarily located in the U.S. Onshore area and uranium properties.
During 1998, the Company adjusted the net book value of properties with a $1.2
billion charge, primarily on properties acquired in the Norcen Acquisition.
Fixed asset additions included capitalized interest of $0.4 million and $0.9
million in 1999 and 1998, respectively.
7. CAPITAL AND EXPLORATORY EXPENDITURES
Capital and exploratory expenditures include the following:
<TABLE>
<CAPTION>
FOR THE YEARS ENDED DECEMBER 31,
----------------------------------
1999 1998 1997
-------- ---------- ----------
(MILLIONS OF DOLLARS)
<S> <C> <C> <C>
Capital expenditures:
Producing properties.................................. $345.1 $3,056.9 $ 773.3
Non-producing properties.............................. 21.0 506.6 200.7
Exploratory drilling.................................. 12.9 117.5 121.7
Other................................................. 5.1 32.6 15.8
------ -------- --------
Total capital expenditures.................... 384.1 3,713.6 1,111.5
Exploratory expenditures:
Expensed geological and geophysical costs............. 19.5 63.1 35.2
Expensed dry hole costs............................... 24.6 52.1 41.7
------ -------- --------
Total exploratory expenditures................ 44.1 115.2 76.9
------ -------- --------
Total capital and exploratory expenditures.... $428.2 $3,828.8 $1,188.4
====== ======== ========
</TABLE>
8. INCOME TAXES
Deferred taxes are established for all temporary differences between the
book and tax bases of assets and liabilities. In addition, deferred tax balances
must be adjusted to reflect tax rates that will be in effect in the years in
which the temporary differences are expected to reverse. Non-U.S. subsidiaries
compute taxes at rates in effect in the various countries. Earnings of these
subsidiaries may also be subject to additional income and withholding taxes when
they are distributed as dividends. Deferred tax liabilities are not recognized
on profits that are expected to be permanently reinvested by the local
subsidiaries and thus not considered available for distribution to the parent
Company. The Company has undistributed earnings of its 100% owned foreign
subsidiaries that arose in 1999 and prior years.
56
<PAGE> 59
UNION PACIFIC RESOURCES GROUP INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Income (loss) from continuing operations before taxes is as follows:
<TABLE>
<CAPTION>
FOR THE YEARS ENDED DECEMBER 31,
---------------------------------
1999 1998 1997
-------- ----------- --------
(MILLIONS OF DOLLARS)
<S> <C> <C> <C>
Domestic................................................. $(45.2) $ (239.7) $405.9
Foreign.................................................. (6.0) (1,248.6) 13.0
------ --------- ------
Total.......................................... $(51.2) $(1,488.3) $418.9
====== ========= ======
</TABLE>
Components of income tax expense (benefit), from continuing operations,
were as follows:
<TABLE>
<CAPTION>
FOR THE YEARS ENDED DECEMBER 31,
--------------------------------
1999 1998 1997
--------- --------- --------
(MILLIONS OF DOLLARS)
<S> <C> <C> <C>
Current:
U.S. Federal........................................... $(151.4) $ 43.2 $ (0.4)
U.S. state............................................. 2.2 6.8 5.1
Foreign................................................ 7.4 4.1 0.2
------- ------- ------
Total current.................................. (141.8) 54.1 4.9
------- ------- ------
Deferred:
U.S. Federal........................................... 82.4 (155.7) 113.4
U.S. state............................................. (2.7) 3.4 (2.5)
Foreign................................................ (78.3) (507.0) --
------- ------- ------
Total deferred................................. 1.4 (659.3) 110.9
------- ------- ------
Total income tax expense (benefit)............. $(140.4) $(605.2) $115.8
======= ======= ======
</TABLE>
Deferred tax liabilities (assets), were as follows:
<TABLE>
<CAPTION>
AS OF DECEMBER 31,
---------------------
1999 1998
--------- ---------
(MILLIONS OF DOLLARS)
<S> <C> <C>
Excess tax over book items, including depreciation and
exploration costs......................................... $1,369.0 $1,528.2
State taxes -- net.......................................... 12.1 (15.0)
Long-term liabilities....................................... 116.3 (19.6)
Alternative minimum tax..................................... (79.8) (72.6)
Pension and other retirement benefits....................... (47.2) (52.6)
Net operating losses........................................ (91.3) (93.1)
Other....................................................... 47.7 16.3
-------- --------
Net deferred tax liability........................ $1,326.8 $1,291.6
======== ========
</TABLE>
57
<PAGE> 60
UNION PACIFIC RESOURCES GROUP INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
A reconciliation between U.S. statutory and consolidated effective tax
rates is as follows:
<TABLE>
<CAPTION>
FOR THE YEARS ENDED
DECEMBER 31,
-------------------
1999 1998 1997
----- ---- ----
<S> <C> <C> <C>
U.S. statutory Federal tax rate............................. 35.0% 35.0% 35.0%
Section 29 credits.......................................... 35.1 1.1 (4.3)
State taxes-- net........................................... (8.2) (0.4) 1.3
Foreign rate differentials.................................. -- 1.8 --
Foreign currency remeasurement.............................. 98.7 1.5 --
Non-tax effected foreign expense............................ (48.4) -- --
Non-taxable entity.......................................... 15.3 1.0 --
Tax settlements............................................. 78.3 -- (1.5)
Reserve adjustments......................................... 28.7 -- --
Tax return reconciliation adjustments....................... 34.1 -- --
Other....................................................... 7.0 0.6 (1.9)
----- ---- ----
Effective tax rate........................................ 275.6% 40.6% 28.6%
===== ==== ====
</TABLE>
The Company generates Section 29 tax credits from the sale of certain fuels
produced from non-conventional 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 must be sold before January 1, 2003. The
Company generated $17.9 million, $16.4 million and $18.8 million of Section 29
tax credits in 1999, 1998 and 1997, respectively. The Federal tax law provides
for the use of these credits against regular Federal income tax liability.
Accordingly, the Company utilized $6.9 million of Section 29 tax credits on its
1998 tax return. It is anticipated that all of the 1999 Section 29 tax credits
along with some of the prior year credits will be recognized in the Company's
1999 tax return. The Company recognized favorable tax adjustments relating to
prior year Federal tax returns in the amount of $17.4 million for 1999 and $4
million for 1998.
While the operations of the Company in Guatemala are subject to local
income taxes, no liability has arisen in recent years since sufficient
unrecovered costs, carried forward from previous years, have been available to
offset current taxable income. Guatemalan tax benefits, which can be carried
forward indefinitely, were $57.6 million at December 31, 1999. Other domestic
subsidiary net operating losses in existence at the time of the Norcen
Acquisition were merged with the Company when those subsidiaries were dissolved.
The Company plans to utilize the losses in 2000 or a future year.
On September 1, 1999, the Company and its former parent, Union Pacific
Corporation ("UPC"), settled certain outstanding issues pertaining to the
allocation of all Federal and state tax liabilities, including interest, for the
tax years 1968 through 1982. This settlement was made pursuant to the Tax
Allocation Agreement entered into as of October 6, 1995, between the Company and
UPC. This settlement resulted in the receipt by the Company from UPC on
September 3, 1999, of $29 million (including $20.5 million of interest income
recorded in other income) in full and final settlement of all amounts owed to or
by UPR with respect to tax years 1968 through 1982. The tax settlement with UPC
enabled the Company to reevaluate its deferred tax reserves, and as a result,
the Company recorded $11.9 million of deferred tax benefits related to the tax
years covered by the settlement. The Company and UPC also agreed to suspend
settlement rights under the Tax Allocation Agreement with respect to post-1982
tax years until July 1, 2001. UPC has informed the Company that all material
deficiencies prior to 1986 have been settled with the Internal Revenue Service
("IRS"). UPC is negotiating with the IRS Appeals Office concerning 1986 through
1989. The IRS has completed its examination of the Company's returns for 1990
through 1994; however, their audit remains open until resolution of the UPC
issues. The IRS has initiated steps to begin the process of examining the
Company's
58
<PAGE> 61
UNION PACIFIC RESOURCES GROUP INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
records for 1995 through 1998. The Company believes it has adequately provided
for Federal and state income taxes.
In 1997, Norcen received a reassessment from Canadian tax authorities in
the amount of $81.1 million concerning the deductibility of certain expenses and
foreign exchange losses claimed for income tax purposes during the period 1989
through 1993. In spite of Norcen's disagreement and appeal, the reassessment was
fully funded in 1997. As a result of the Norcen Acquisition, the Company valued
this issue at $17.0 million, net of any valuation allowance, as part of the
purchase price allocation. On March 8, 1999, UPRI entered into an agreement with
Canadian tax authorities to settle these claims out of court. Under the terms of
the settlement, the Company received a refund of approximately $54.6 million
dollars. The Company recorded $7.1 million of interest to other income and a
$27.9 million deferred income tax benefit related to the refund.
9. DEBT
The total debt of the Company is summarized below:
<TABLE>
<CAPTION>
AS OF DECEMBER 31,
INTEREST ---------------------
RATE 1999 1998
-------- --------- ---------
(MILLIONS OF DOLLARS)
<S> <C> <C> <C>
Commercial Paper and Bankers' Acceptances (Average of
5.55% and 5.98% at December 31, 1999 and 1998,
respectively)......................................... $ 135.1 $2,351.9
Debentures due July 2, 2002............................. 6.800% 250.0 250.0
Notes due May 15, 2005.................................. 6.500% 200.0 200.0
Debentures due May 15, 2006............................. 7.375% 250.0 250.0
Notes due October 15, 2006.............................. 7.000% 200.0 200.0
Notes due May 15, 2008.................................. 6.750% 169.5 200.0
Debentures due July 2, 2008............................. 7.800% 150.0 150.0
Notes due April 15, 2009................................ 7.300% 176.0 --
Debentures due May 15, 2018............................. 7.050% 200.0 200.0
Debentures due October 15, 2026......................... 7.500% 200.0 200.0
Debentures due May 15, 2028............................. 7.150% 395.0 425.0
Debentures due April 15, 2029........................... 7.950% 290.0 --
Debentures due November 1, 2096......................... 7.500% 150.0 150.0
Capital lease obligations (Note 10)..................... 16.0 17.4
(Discount) Premium on notes and debentures -- net....... 18.0 4.4
-------- --------
Total debt.................................... 2,799.6 4,598.7
Less: current portion......................... 2.3 853.8
-------- --------
Total long-term debt.......................... $2,797.3 $3,744.9
======== ========
</TABLE>
At year-end 1998, the Company had three debt facilities totaling an
aggregate of U.S. $2.5 billion. These facilities were comprised of a $1.0
billion 364-Day Competitive Advance/Revolving Credit Agreement (the "Bridge
Facility"), a $750 million 364-Day Competitive Advance/Revolving Credit
Agreement and a $750 million Competitive Advance/Revolving Credit Agreement
("Long-Term Facility") expiring in October 2003.
In April 1999, the Company issued $500 million of notes and debentures
comprised of $200 million 7.3% Notes due April 2009 and the $300 million 7.95%
Debentures due April 2029. The notes and debentures were issued under the
Company's existing $1.0 billion shelf registration statement, of which $500
million remains available.
59
<PAGE> 62
UNION PACIFIC RESOURCES GROUP INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
During the first half of 1999, commercial paper, supported in part by the
Company's Bridge Facility, was repaid using proceeds from property sales,
proceeds from the sale of the GPM business segment and the issuance of the
long-term notes and debentures. The Bridge Facility was terminated in April
1999. The $750 million 364-Day Competitive Advance/Revolving Credit Agreement
expired in October 1999, leaving the Company with the Long-Term Facility at
year-end 1999. The Long-Term Facility contains a covenant stipulating that the
ratio of consolidated debt to consolidated EBITDAX -- the sum of operating
income (before adjustments for income taxes, interest expense or extraordinary
gains or losses), depreciation, depletion and amortization and exploration
expenses -- cannot exceed 3.25:1.00. The Long-Term Facility also places other
restrictions on the Company regarding the creation of liens, incurrence of
additional indebtedness by subsidiaries, transactions with affiliates, sales of
stock of Union Pacific Resources Company (a wholly-owned subsidiary of the
Company) and certain mergers, consolidations and asset sales. The Company was in
compliance with the covenant provisions at year-end 1999 and 1998.
The 2005, 2008 and 2009 notes and the 2018, 2028 and 2029 debentures are
redeemable as a whole or in part, at the option of the Company at any time. The
redemption price is equal to the greater of (i) 100% of the principal amount of
the Debt Securities to be redeemed or (ii) the sum of the present values of the
remaining scheduled payments thereon, discounted to the redemption date on a
semi-annual basis at the Treasury Rate, plus a stated basis point spread and
accrued interest on the principal amount being redeemed to the redemption date.
There are no other notes or debentures redeemable prior to maturity. None of the
Company's notes and debentures are subject to a sinking fund requirement. At
December 31, 1999, the Company had an effective shelf registration statement on
file with the Securities and Exchange Commission that would permit the Company
or certain identified subsidiaries to offer up to $500 million in debt, equity
and/or other securities.
During 1999, the Company purchased on the open market and retired long-term
debt with a face value of $94.5 million at a discount prior to maturity. The
retirement of long-term debt due to the repurchases resulted in an extraordinary
gain of $3.4 million, net of $1.8 million of tax. The gain on the retirement was
classified as a gain from an extraordinary item on the Consolidated Statement of
Income.
At December 31, 1999, $135.1 million of commercial paper and bankers
acceptances was classified as long-term. This classification reflects the
Company's intent and ability to maintain these borrowings on a long-term basis,
supported by the Long-Term Facility through the issuance of additional
commercial paper and/or new term financings. Debt maturities through 2004,
excluding capital leases, are $135.1 million of bankers acceptances due in 2000
and $250 million of Debentures due July 2, 2002.
The fair value of the Company's long-term debt, excluding commercial paper
and bankers acceptances, debt discount/premium and capital lease obligations was
$2,467 million at December 31, 1999 and $2,088 million at December 31, 1998. The
fair value was estimated using quoted market prices. These fair values were
trading at a discount to the face value of 93.8% at both December 31, 1999 and
1998.
As a result of the Norcen Acquisition, the Company recorded a $31.5 million
debt premium, representing the excess of the fair value over the carrying value
of the debt acquired. The $25.2 million remaining debt premium, net of $7.2
million in debt discount related to prior debt issuances, are being amortized
over the life of the debt term.
The Company has guaranteed a portion of the OCI Wyoming, L.P debt facility.
At December 31, 1999, OCI Wyoming, L.P. had an outstanding debt facility balance
of $30 million, of which the Company has guaranteed $14.7 million. The Company's
portion of the debt is reflected in the balance for investment in affiliate on
the Consolidated Statement of Financial Position.
The Company utilizes letters of credit to support certain financing
instruments, performance contracts and insurance policies. The fair value of the
letters of credit at December 31, 1999 and 1998 was $41.3 million and $58.6
million, respectively.
60
<PAGE> 63
UNION PACIFIC RESOURCES GROUP INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
10. LEASE COMMITMENTS
The Company leases several office buildings, certain production platforms
and other property under operating leases. The Company also maintains a capital
lease for furniture and walls in its Fort Worth offices. Future minimum lease
payments for operating and capital leases with initial non-cancelable lease
terms in excess of one year as of December 31, 1999, were as follows:
<TABLE>
<CAPTION>
AS OF DECEMBER 31, 1999
----------------------------
CAPITAL OPERATING
LEASES LEASES TOTAL
------- --------- ------
(MILLIONS OF DOLLARS)
<S> <C> <C> <C>
2000...................................................... $ 2.8 $ 46.9 $ 49.7
2001...................................................... 2.9 44.4 47.3
2002...................................................... 2.9 42.6 45.5
2003...................................................... 2.9 32.2 35.1
2004...................................................... 6.6 3.9 10.5
Later years............................................... 0.8 6.9 7.7
----- ------ ------
Total future minimum lease payments....................... 18.9 $176.9 $195.8
====== ======
Less: amounts representing interest....................... (2.9)
-----
Present value of minimum capital lease obligations........ 16.0
-----
Less: Short-term portion of capital lease obligations..... (2.3)
-----
Long-term portion of capital lease obligations............ $13.7
=====
</TABLE>
Rent expense, net of sublease income, for operating leases with terms
exceeding one month was $60.2 million in 1999, $59.8 million in 1998, and $19.2
million in 1997. Sublease income for the next five years will be $30.5 million
in 2000, $29.8 million in 2001, $29.8 million in 2002, $28.5 million in 2003 and
$0.4 million in 2004. Capital leases included in corporate fixed assets were
$17.4 million and $18.1 million at December 31, 1998 and 1999, respectively.
11. RETIREMENT PLANS
The Company provides pension, health care and life insurance benefits to
all eligible retirees in the U.S. and pension benefits to all eligible retirees
in Canada. No such pension or other benefits are provided to employees of other
foreign subsidiaries.
U.S. Pension Benefits. Pension benefits for U.S. employees are based on
years of service and compensation during the last years of employment.
Contributions to the plans are calculated on the Projected Unit Credit actuarial
funding method and are not less than the minimum funding standards set forth in
the Employees Retirement Income Security Act of 1974, as amended. The portion of
the funded plan's assets held in fixed-income and short-term securities was
approximately 33% and 32% as of December 31, 1999 and 1998, respectively, with
the remainder primarily in equity securities.
Curtailments and Termination of Benefits. During 1999, the Company
announced reductions in force, a voluntary retirement incentive program ("VRIP")
and the sale of the GPM business segment. The separations due to these programs
triggered curtailment accounting and termination benefit accounting as a result
of the VRIP. The Company recognized curtailment gains of $11.4 million, offset
by costs of the termination of benefits of $10.5 million. These separations
caused a slight reduction in the Company's retiree benefits obligations due to
reduced expected future benefits for the employees affected by these programs.
Other U.S. Postretirement Benefits. Postretirement health and life
insurance benefits are provided to all eligible U.S. retirees. The Company does
not currently pre-fund health care and life insurance benefit costs.
61
<PAGE> 64
UNION PACIFIC RESOURCES GROUP INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Canadian Pension Benefits. Benefits provided under the Canadian defined
benefit plan are based on years of service and highest compensation over a
specified number of consecutive years. The provisions under the defined benefit
plan were modified to provide employees with a defined contribution plan option,
which has been retroactively elected by substantially all active employees.
Under the defined contribution plan, the Company matches a stated percentage of
employee contributions to the plan. Both the defined benefit payments and the
defined contribution Company match obligation are paid from assets held in
trust. The Company will make contributions to the plans, if necessary, to
maintain adequate assets in trust. Contributions are not expected to be
necessary for several years.
The following pension credits and funded status are based on historical
actuarial valuations.
<TABLE>
<CAPTION>
U.S. PENSION OTHER CANADIAN
BENEFITS U.S. BENEFITS PENSION BENEFITS
--------------- ------------- -----------------
1999 1998 1999 1998 1999 1998
------ ------ ----- ----- ------- -------
(MILLIONS OF DOLLARS)
<S> <C> <C> <C> <C> <C> <C>
Change in benefit obligation:
Benefit obligation at beginning of year..... $221.0 $202.6 $40.4 $42.9 $ 25.6 $ --
Acquisition................................. -- -- -- -- -- 26.1
Service cost................................ 5.1 6.1 0.7 1.0 -- 0.1
Interest cost............................... 15.3 14.3 2.8 3.0 1.8 1.4
Curtailments................................ (10.1) -- (1.3) -- -- --
Termination benefits........................ 9.5 -- 1.0 -- -- --
Plan amendments............................. 12.3 2.4 -- (5.4) -- --
Actuarial (gain) loss....................... (4.7) 12.6 (2.9) 0.1 0.2 (0.2)
Benefits paid............................... (19.4) (17.0) (2.7) (1.2) (2.7) (1.8)
------ ------ ----- ----- ------ ------
Benefit obligation at end of year........... $229.0 $221.0 $38.0 $40.4 $ 24.9 $ 25.6
====== ====== ===== ===== ====== ======
Change in plan assets:
Fair value of plan assets at beginning of
year...................................... $269.7 $240.9 $ -- $ -- $ 47.7 $ --
Acquisition................................. -- -- -- -- -- 50.3
Actual return on plan assets................ 32.4 40.0 -- -- 3.5 --
Employer contribution(a).................... 2.3 5.8 2.7 1.2 0.2 --
Benefits paid(b)............................ (19.4) (17.0) (2.7) (1.2) (3.6) (2.6)
Foreign currency exchange rate gain......... -- -- -- -- 2.9 --
------ ------ ----- ----- ------ ------
Fair value of plan assets at end of year.... $285.0 $269.7 $ -- $ -- $ 50.7 $ 47.7
====== ====== ===== ===== ====== ======
Plan assets (over) under benefit
obligation................................ $(56.0) $(48.7) $38.0 $40.4 $(25.8) $(22.1)
Unamortized net transition asset............ 13.2 15.8 -- -- -- --
Unrecognized prior service gain (cost)...... (18.9) (9.0) 6.0 8.0 -- --
Unrecognized net gain....................... 121.2 105.1 24.9 25.1 (3.2) (1.9)
------ ------ ----- ----- ------ ------
Net amount recognized....................... $ 59.5 $ 63.2 $68.9 $73.5 $(29.0) $(24.0)
====== ====== ===== ===== ====== ======
</TABLE>
- ---------------
(a) Represents payments relating to unfunded plans. In addition, the Company
periodically settles a portion of the unfunded supplemental pension plan
benefit obligations through the purchase of annuities.
(b) $0.9 million and $0.8 million of Canadian pension benefits paid in 1999 and
1998 respectively, represent payments to fund the defined contribution
Company match.
62
<PAGE> 65
UNION PACIFIC RESOURCES GROUP INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
<TABLE>
<CAPTION>
U.S. PENSION U.S. OTHER CANADIAN
BENEFITS BENEFITS PENSION BENEFITS
-------------- ------------- -----------------
1999 1998 1999 1998 1999 1998
------ ----- ----- ----- ------- -------
(MILLIONS OF DOLLARS)
<S> <C> <C> <C> <C> <C> <C>
Amounts recognized in the Statement of
Financial Position consist of:
Prepaid benefit cost....................... $ -- $ -- $ -- $ -- $(29.0) $(24.0)
Accrued benefit liability.................. 76.0 72.0 68.9 73.5
Intangible asset........................... (5.6) (3.9) -- -- -- --
Accumulated other comprehensive income..... (10.9) (4.9) -- -- -- --
------ ----- ----- ----- ------ ------
Net amount recognized........................ $ 59.5 $63.2 $68.9 $73.5 $(29.0) $(24.0)
====== ===== ===== ===== ====== ======
Weighted-average assumptions as of December
31
Discount rate................................ 7.75% 7.0% 7.75% 7.0% 7.25% 6.5%
Expected return on plan assets............... 9.0% 9.0% -- -- 7.25% 6.5%
Rate of compensation increase................ 5.75% 5.0% -- -- 5.75% 5.0%
</TABLE>
For measurement purposes, a 7.2% annual rate of increase in the per capita
cost of covered health care benefits was assumed for 1999. The rate was assumed
to gradually decrease to 5% in 2005 and remain at that level thereafter.
<TABLE>
<CAPTION>
CANADIAN
U.S. PENSION BENEFITS U.S. OTHER BENEFITS PENSION
------------------------ ------------------- -------------
1999 1998 1997 1999 1988 1997 1999 1998
------ ------ ------ ----- ---- ---- ----- -----
(MILLIONS OF DOLLARS)
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Service cost-benefits earned during the
period........................................ $ 5.1 $ 6.1 $ 5.5 $ 0.7 $1.0 $0.8 $ -- $ 0.1
Interest cost on the projected benefit
obligation.................................... 15.3 14.3 13.4 2.8 3.0 3.3 1.8 1.4
Expected return on plan assets.................. (19.0) (18.6) (17.1) -- -- -- (3.6) (2.7)
Amortization of net transition asset............ (2.6) (2.1) (2.0) -- -- -- -- --
Amortization of unrecognized prior service gain
(cost)........................................ 1.2 1.2 1.2 (0.6) (0.8) (0.8) -- --
Amortization of unrecognized net gain........... (2.3) (4.1) (4.9) (1.0) (1.7) (1.6) -- --
Settlement/curtailment/termination benefits..... 0.9 -- -- (3.7) -- -- -- --
------ ------ ------ ----- ---- ---- ----- -----
(Benefit) charge to operations................ $ (1.4) $ (3.2) $ (3.9) $(1.8) $1.5 $1.7 $(1.8) $(1.2)
====== ====== ====== ===== ==== ==== ===== =====
Other comprehensive income...................... $ 6.0 $ 3.9 $ 1.0 $ -- $-- $-- $ -- $ --
====== ====== ====== ===== ==== ==== ===== =====
</TABLE>
Assumed health care cost trend rates have a significant effect on the
amounts reported for the postretirement benefit plan. A one-percentage-point
change in assumed health care cost trend rates would have the following effects:
<TABLE>
<CAPTION>
1 PERCENTAGE 1 PERCENTAGE
POINT INCREASE POINT DECREASE
-------------- --------------
(MILLIONS OF DOLLARS)
<S> <C> <C>
Effect on total of service and interest cost components.... $0.4 $(0.3)
Effect on postretirement benefit obligation................ 3.5 (3.1)
</TABLE>
12. ENVIRONMENTAL EXPOSURE
Environmental expenditures related to treatment or cleanup are expensed
when incurred, while environmental expenditures which extend the life of the
property or prevent future contamination are capitalized in accordance with
generally accepted accounting principles. Liabilities for these expenditures are
recorded when it is probable that obligations have been incurred and the amounts
can be reasonably estimated, based on
63
<PAGE> 66
UNION PACIFIC RESOURCES GROUP INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
current law and existing technologies. Environmental accruals are recorded at
undiscounted amounts and exclude claims for recoveries from insurance or other
third parties.
The Company generates and disposes of hazardous and non-hazardous waste in
its current operations as well as formerly owned operations and is subject to
increasingly stringent Federal, state, local, provincial and international
environmental regulations. The Company has identified seven sites currently
subject to environmental response actions or on the Superfund National
Priorities List or state superfund lists, at which it is or may be liable for
remediation costs associated with alleged contamination or for violation of
environmental requirements. Certain Federal legislation imposes joint and
several liability for the remediation of various sites; consequently, the
Company's ultimate environmental liability may include costs relating to other
parties in addition to costs relating to its own activities at each site. In
addition, the Company is or may be liable for certain environmental remediation
matters involving existing or former facilities.
In March 1994, the Company sold its interest in the Wilmington, California
field and the Harbor Cogeneration Plant to the Port of Long Beach, California.
As part of the Wilmington sales agreement, the Company agreed to participate
with the Port of Long Beach in funding environmental remediation and site
preparation, as specified by the Port of Long Beach, up to a maximum of $105.5
million. As a result, a provision of $50.5 million for future environmental
costs and $55.0 million for future site preparation costs was established ($87.8
million in total remaining at December 31, 1999) and is categorized as other
current liabilities and long-term liabilities (see Note 14).
As of December 31, 1999 and 1998, liabilities totaling $65.2 million and
$74.7 million, respectively, had been accrued for future costs of all sites
where the Company's obligation is probable and where such costs reasonably can
be estimated; however, the ultimate cost could be lower or higher. This accrual
includes future costs for remediation and restoration of sites, as well as for
ongoing monitoring costs, but excludes any anticipated recoveries from third
parties. The accrual also includes $34.1 million for the obligation to
participate in the remediation of the Wilmington field properties. Cost
estimates were based on information available for each site, financial viability
of other Potentially Responsible Parties ("PRPs") and existing technology, laws
and regulations. The Company believes that it has accrued adequately for its
share of costs at sites subject to joint and several liabilities. The ultimate
liability for remediation is difficult to determine with certainty because of
the number of PRPs involved, site-specific cost sharing arrangements with other
PRPs, the degree of contamination by various wastes, the scarcity and quality of
volumetric data related to many of the sites and the speculative nature of
remediation costs.
Anticipated payments of environmental liabilities at December 31, 1999,
which will be funded by cash generated by operations, are as follows:
<TABLE>
<CAPTION>
AT DECEMBER 31, 1999
---------------------
(MILLIONS OF DOLLARS)
<S> <C>
2000...................................................... $17.0
2001...................................................... 13.2
2002...................................................... 12.5
2003...................................................... 10.0
2004...................................................... 8.0
Thereafter................................................ 4.5
-----
Total........................................... $65.2
=====
</TABLE>
The Company also is involved in reducing emissions, spills and migration of
hazardous materials. Remediation of identified sites and control of
environmental exposures required spending of $11.6 million in 1999 and $17.0
million in 1998. In 2000, the Company anticipates spending a total of $19
million for remediation, control and prevention. Based on current rules and
regulations, management does not expect
64
<PAGE> 67
UNION PACIFIC RESOURCES GROUP INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
future environmental obligations to have a material impact on the results of
operations, cash flows or financial condition of the Company.
13. COMMITMENTS AND CONTINGENCIES
The Company was a party to several long-term firm gas transportation
agreements that supported the gas marketing program within the GPM business
segment which was sold to Duke. Most of the GPM business segment's firm
long-term transportation contracts were transferred to Duke in the GPM
Disposition. As part of the GPM Disposition, the Company and Duke agreed that
the Company will keep Duke whole on certain transportation contracts
("keep-whole agreement"). The Company will pay Duke if transportation market
values fall below the contract transportation rates, while Duke agreed to pay
the Company if the market value exceeds the contract transportation rates. This
keep-whole agreement will be in effect until the earlier of (i) each contract's
expiration date, or (ii) March 2009. Transportation contracts transferred to
Duke in the GPM Disposition and included in the keep-whole agreement with Duke
relate to various pipelines. The significant contracts covered by the keep-whole
agreement include: (i) an agreement with Texas Gas Transmission Corporation for
a transportation rate of $0.331 per MMBtu for 90 MMBtud of gas from Carthage,
Texas to Lebanon, Ohio expiring October 31, 2008; (ii) an agreement with Pacific
Gas Transmission ("PGT") for a transportation rate of $0.328 per MMBtu for 25
MMBtud of gas from Kingsgate, British Columbia to the California/Oregon border
expiring October 31, 2023; and (iii) a second agreement with PGT expiring
October 31, 2023 for 106 MMBtud of which 47 MMBtud will expire on October 31,
2007. The keep-whole agreement excludes 45 MMBtud of the PGT amount through
October 31, 2002 then 20 MMBtud through the end of the contract.
The Company retained a contract with Kern River Gas Transportation Company
("Kern River") which expires on May 31, 2007. Under the transportation
agreement, the Company has the right to transport 75 MMcfd of gas on the Kern
River system. The current transportation rate is $0.69 per Mcf. This rate can
change based on Kern River's cost of service and upon rate regulation policies
of the FERC. The Company is a party to an additional agreement under which it
may acquire in 2001, at its option, an additional 25 MMcfd of transportation
rights on the Kern River system beginning in 2002. As a result of the GPM
Disposition, the Company entered into an agreement whereby Duke would operate
and handle volume nominations related to the Company's contract with Kern River.
Currently, Duke is utilizing the Company's volume transportation rights under
the Kern River contract and paying the Company market rates.
Included in the Consolidated Statements of Financial Position of the
Company is a reserve for the estimated fair value of the difference between the
total rate under the firm transportation agreements and estimated market rates
through March 2009. The reserve, which is included in other current liabilities
and other long-term liabilities, was $43.8 million and $81.8 million at December
31, 1999 and $17.5 million and $71.2 million at December 31, 1998, respectively.
The Company may adjust its reserve based on changes in current quoted future
market rates or estimated long-term rates. Such adjustments could be
significant. Management believes its reserves are adequate; however, at December
31, 1999, if the Company had used quoted future market rates at December 31,
1999 to estimate the long-term portion of the reserve discounted at 10%, the
Company would have recorded an additional reserve of $41.3 million for the firm
transportation commitment period.
65
<PAGE> 68
UNION PACIFIC RESOURCES GROUP INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Anticipated discounted and undiscounted payments for firm transportation
commitment at December 31, 1999, which will be funded by cash generated by
operations, are as follows:
<TABLE>
<CAPTION>
UNDISCOUNTED DISCOUNTED
------------ ----------
(MILLIONS OF DOLLARS)
<S> <C> <C>
2000.................................................. $ 43.8 $ 43.8
2001.................................................. 17.0 14.8
2002.................................................. 15.6 12.3
2003.................................................. 17.8 12.8
2004.................................................. 24.4 15.9
Thereafter............................................ 50.0 26.0
------ ------
Total....................................... $168.6 $125.6
====== ======
</TABLE>
In February 2000, the Company entered into a $70 million contract with
Noble Drilling (U.S.) Inc. for the services of a semisubmersible drilling rig
designed for operations in water depths up to 5,000 feet. Under this agreement,
the Company has a commitment to use the rig for 15 months over a five-year
period commencing January 1, 2000.
In connection with the disposition of significant pipeline, refining and
producing property assets, the Company has made certain representations and
warranties relating to the assets sold (covering, among other matters, the
condition and capabilities of certain assets and compliance with environmental
and other laws) and provided certain indemnities with respect to liabilities
associated with such assets. The Company has been advised of possible claims
which may be asserted by the purchasers of certain disposed assets for alleged
breaches of representations and warranties and under certain indemnities.
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 ultimate outcome of these
claims, the Company does not expect these matters to have a material adverse
effect on its results of operations, cash flows or consolidated financial
condition.
The Company, through one of its affiliates, is a party to a lease agreement
("base lease") for the leveraged lease financing of the Corpus Christi West
Plant Refinery ("West Plant") with an initial term expiring December 31, 2003,
and successive renewal periods lasting through January 31, 2011. At the
conclusion of the initial term of the base lease, any renewal period or January
31, 2011, the Company has the right to purchase the West Plant at the fair
market sales value. In connection with the sale by the Company of its refining
business in 1987 and 1989, the West Plant was subleased to CITGO Petroleum
Corporation ("CITGO") with sublease payments during the initial term equal to
the Company's base lease payments and during any renewal period equal to the
lesser of the base lease rental, which will be tied to the fair market rental
value, or $5 million annually. Additionally, CITGO has the option under the
sublease to purchase the West Plant from the Company at the conclusion of the
initial term or any renewal term at the fair market sales value, or on January
31, 2011 at a nominal price. If the fair market rental value of the base lease
during any renewal term exceeds CITGO's maximum obligation under the sublease,
or if CITGO purchases the West Plant on January 31, 2011 and the fair market
sales value of the West Plant is greater than the purchase amount specified in
the sublease, the Company will be obligated to pay the excess amounts. The
Company is unable at this time to determine the fair market rental value or the
fair market sales value of the West Plant, but will periodically evaluate the
potential effect of the obligation.
There are lawsuits pending against the Company and certain of its
subsidiaries which are described in Part I, Item 3 -- "Legal Proceedings" in
this Annual Report on Form 10-K. The Company intends to defend vigorously
against these lawsuits as well as any similar lawsuits. In the opinion of
management of the
66
<PAGE> 69
UNION PACIFIC RESOURCES GROUP INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Company, the outcome of these matters should not have a materially adverse
effect on results of operations, cash flows or consolidated financial condition.
The Company is a defendant in a number of lawsuits and is involved in
governmental proceedings arising in the ordinary course of business, including,
but not limited to, royalty claims, contract claims and environmental claims.
The Company has also been named as a defendant in various personal injury
claims, including numerous claims by employees of third party contractors
alleging exposure to asbestos and asbestos-containing materials while working at
the Corpus Christi refinery, which the Company sold in segments in 1987 and
1989. While the Company's management cannot predict the outcome of such
litigation and other proceedings, management does not expect these matters to
have a materially adverse effect on the consolidated results of operations,
financial condition or cash flows of the Company.
14. OTHER CURRENT AND LONG-TERM LIABILITIES
Other current liabilities include the following:
<TABLE>
<CAPTION>
AS OF DECEMBER 31
----------------------
1999 1998
--------- ---------
(MILLIONS OF DOLLARS)
<S> <C> <C>
Interest payable............................................ $ 40.6 $ 35.7
Short-term firm transportation commitments (Note 13)........ 43.8 17.5
Environmental (Note 12)..................................... 16.9 17.7
Dividends................................................... 12.4 12.4
Other....................................................... 72.1 74.2
------ ------
Total other current liabilities................... $185.8 $157.5
====== ======
</TABLE>
Other long-term liabilities include the following:
<TABLE>
<CAPTION>
AS OF DECEMBER 31
----------------------
1999 1998
--------- ---------
(MILLIONS OF DOLLARS)
<S> <C> <C>
Long-term firm transportation commitments (Note 13)......... $ 81.8 $ 71.2
Abandonment provision....................................... 70.7 58.1
Wilmington field site preparation........................... 53.7 53.7
Environmental (Note 12)..................................... 48.3 57.2
Equity investment -- Black Butte(a)......................... 38.6 37.8
Deferred compensation....................................... 19.6 25.9
Litigation and contingencies (Note 13)...................... 25.5 23.4
Deferred revenue............................................ 15.8 9.4
Other....................................................... 47.1 51.4
------ ------
Total other long-term liabilities................. $401.1 $388.1
====== ======
</TABLE>
- ---------------
(a) Black Butte
The Company has a 50% ownership interest in Black Butte Coal Company and
R-K Leasing Company ("Black Butte"), partnerships which operate a surface coal
mine complex in southwestern Wyoming. The
67
<PAGE> 70
UNION PACIFIC RESOURCES GROUP INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Company accounts for these partnerships under the equity method of accounting.
Summarized financial information for Black Butte is as follows:
<TABLE>
<CAPTION>
AS OF AND FOR YEARS ENDED
DECEMBER 31,
---------------------------
1999 1998 1997
------- ------- -------
(MILLIONS OF DOLLARS)
<S> <C> <C> <C>
Current assets............................................. $ 26.9 $ 30.4
Non-current assets......................................... 16.5 26.2
Current liabilities........................................ 18.4 21.0
Non-current liabilities and equity......................... 25.0 35.7
Sales...................................................... $216.1 $254.5 $159.7
Operating income........................................... 148.4 183.4 112.4
Partners' income........................................... 149.0 183.2 113.6
Cash distributions to partners -- net...................... 80.5 98.5 65.8
</TABLE>
During 1999 and 1998, Black Butte's sales to its largest customer under a
coal supply contract accounted for $73.4 million and $79.3 million of the
Company's consolidated operating income, respectively. This coal supply contract
will terminate by the end of 2000. 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 currently received under the contract with
incremental coal sales after 2000.
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, 1999 and 1998 were $54.6 million and $52.0 million,
respectively, of which the Company's share is $27.3 million and $26 million,
respectively. Anticipated cash expenditures for this reclamation liability are
expected to be incurred in years beginning after 2004.
A supplier of coal to Black Butte has been assessed by the Minerals
Management Service of the United States Department of the Interior for
underpayment of royalties and the State of Montana Department of Revenue for
underpayment of production taxes related to coal previously sold to Black Butte.
The supplier is contesting these claims; however, should the claims be
successful, the supplier will claim reimbursement from Black Butte. In 1998, the
Courts ruled in favor of the State of Montana. The supplier is appealing to the
Montana State Supreme Court, however, the Company recorded $15.2 million as its
proportionate share of the Montana Department of Revenue assessment related to
coal production taxes. The Company's proportionate share of the liability for
underpaid royalties and interest to the Minerals Management Service of the
United States Department of the Interior, if any, could range from zero to $6.7
million.
15. SHAREHOLDERS' EQUITY
Stock Option and Retention Stock Plans. Pursuant to the Company's stock
option and retention stock plans, 11,062,582 and 5,999,439 shares of Common
Stock were available for grant to employees and directors at the end of December
31, 1999 and 1998, respectively. In May 1999, the Company's shareholders
approved a 7.5 million increase in the number of shares available for grants and
awards to employees and directors. Shares may either be granted as options to
purchase Common Stock or as awards of retention stock. Options to purchase
Common Stock under the plans are generally granted with an exercise price equal
to the fair market value at the date of grant and are exercisable for a period
of up to 10 years from grant date. Option grants have been made to directors,
officers and employees and vest over periods up to 10 years from the grant date.
Retention stock is awarded under the plans to eligible employees, subject to
forfeiture if employment
68
<PAGE> 71
UNION PACIFIC RESOURCES GROUP INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
terminates during the prescribed retention period, generally one to five years
from grant, subject to accelerated vesting in some situations.
In the first quarter of 1999, options covering 1,171,439 shares of Company
common stock were granted to directors, officers and certain non-officer
executives of the Company, each with an exercise price of $9.44 per share, a
one-year vesting period and a ten-year term. In addition, 1,474,439 shares of
retention stock were awarded to officers and certain non-officer executives with
a vesting schedule of one-third per year over a three-year period commencing on
the first anniversary of the award date, subject to accelerated vesting upon the
achievement of certain Company common stock price objectives. These stock price
objectives were achieved in April and May 1999, resulting in the acceleration of
vesting of all such shares of retention stock. Of the Company's $17.0 million
compensation expense in 1999 that was recorded for retention stock, $14.8
million was recorded in connection with the vesting of the January 1999
retention stock awards.
The status of the Company's stock-based compensation programs is as
follows:
<TABLE>
<CAPTION>
WEIGHTED
COMPANY AVERAGE
SHARES EXERCISE PRICE
---------- --------------
<S> <C> <C>
Stock options:
Balance at December 31, 1996................................ 5,216,074 $19.97
Granted................................................... 1,111,750 25.63
Exercised................................................. (351,723) 16.05
Expired/surrendered....................................... (91,615) 24.75
----------
Balance at December 31, 1997................................ 5,884,486 21.20
Granted................................................... 2,951,375 17.01
Exercised................................................. (57,487) 9.49
Expired/surrendered....................................... (207,635) 15.18
----------
Balance at December 31, 1998................................ 8,570,739 19.84
Granted................................................... 2,459,900 12.28
Exercised................................................. (271,999) 12.24
Expired/surrendered....................................... (1,818,375) 18.27
----------
Balance at December 31, 1999................................ 8,940,265 18.32
==========
Exercisable December 31:
1997...................................................... 3,853,035 $18.72
1998...................................................... 4,496,736 19.93
1999...................................................... 4,925,741 20.47
</TABLE>
<TABLE>
<CAPTION>
REGULAR
----------
<S> <C>
Retention stock:
Unvested at December 31, 1996............................... 1,204,562
Awarded................................................... 209,114
Vested.................................................... (376,295)
Forfeited, surrendered and other.......................... (34,693)
----------
Unvested at December 31, 1997............................... 1,002,688
Awarded................................................... 45,580
Vested.................................................... (531,951)
Forfeited, surrendered and other.......................... (19,200)
----------
Unvested at December 31, 1998............................... 497,117
Awarded................................................... 1,792,257
Vested.................................................... (1,764,776)
Forfeited, surrendered and other.......................... (188,194)
----------
Unvested at December 31, 1999............................... 336,404
==========
</TABLE>
69
<PAGE> 72
UNION PACIFIC RESOURCES GROUP INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Weighted-average fair value on the dates of option grants and retention
share awards:
<TABLE>
<CAPTION>
RETENTION
OPTIONS(A) SHARES(B)
---------- ---------
<S> <C> <C>
1997........................................................ $8.74 $25.63
1998........................................................ 7.00 17.01
1999........................................................ 7.05 10.09
</TABLE>
- ---------------
(a) Calculated in accordance with the Black-Scholes option pricing model, using
the following weighted average assumptions:
<TABLE>
<CAPTION>
1999 1998 1997
------- ------- -------
<S> <C> <C> <C>
Expected volatility......................................... 61% 51% 28%
Expected dividend yield..................................... 1.59% 2.25% 0.8%
Expected weighted average option term....................... 8 years 5 years 4 years
Risk-free rate of return.................................... 6.4% 4.6% 5.7%
</TABLE>
(b) Represents market value on grant date.
Options to purchase Common Stock were as follows:
<TABLE>
<CAPTION>
AS OF DECEMBER 31, 1999
--------------------------------------------------------
OPTIONS OUTSTANDING OPTIONS EXERCISABLE
--------------------------------- --------------------
WEIGHTED WEIGHTED WEIGHTED
AVERAGE AVERAGE AVERAGE
NUMBER OF YEARS TO EXERCISE NUMBER OF EXERCISE
RANGE OF EXERCISE PRICES SHARES EXPIRATION PRICE SHARES PRICE
- ------------------------ --------- ---------- -------- --------- --------
<S> <C> <C> <C> <C> <C>
$ 8.79 -- $15.78................. 3,687,117 5.9 $13.58 1,518,420 $14.97
$17.04 -- $20.94................. 2,936,389 3.4 17.74 1,612,450 18.32
$22.50 -- $29.44................. 2,316,759 6.1 26.62 1,794,871 27.06
--------- ---------
$ 8.79 -- $29.44................. 8,940,265 5.1 18.32 4,925,741 20.47
========= =========
</TABLE>
Since the Company applies the intrinsic value method in accounting for its
stock option and retention stock plans, it generally records no compensation
cost for its stock option plans. This method calculates compensation expense on
the measurement date (usually the date of grant or award) as the excess of the
current market price of the underlying common stock of the Company over the
amount the employee is required to pay for the shares, if any. The expense is
recognized over the vesting period of the grant or award. Compensation cost
recognized relating to retention stock was $17.0 million, $6.5 million and $11.6
million in 1999, 1998 and 1997, respectively. Approximately $14.8 million of the
$17.0 million 1999 compensation costs was related to the vesting of the January
1999 retention stock awards. If compensation cost for the Company's stock option
plan had been determined based on the fair value at the grant dates for awards
under the plan, the Company's net income would have been reduced by $26.7
million in 1999, $13.8 million in 1998 and $8.0 million in 1997. Basic and
diluted earnings per share would have been reduced by $0.11 per share in 1999,
$0.06 per share in 1998 and $0.03 per share in 1997.
70
<PAGE> 73
UNION PACIFIC RESOURCES GROUP INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Earnings Per Share. Basic earnings per share ("EPS") excludes dilution and
is computed by dividing income available to common shareholders by the
weighted-average number of common shares outstanding for the period. Diluted EPS
reflects the potential dilution that could occur if securities or other
contracts to issue common stock were exercised or converted into common stock.
The reconciliation between basic earnings per share and diluted earnings per
share is as follows:
<TABLE>
<CAPTION>
AVERAGE PER
INCOME SHARES SHARE
--------------------- ---------- ------
(MILLIONS OF DOLLARS) (MILLIONS)
<S> <C> <C> <C>
FOR THE YEAR ENDED DECEMBER 31, 1999
Basic EPS
Net income.................................... $ 225.8 249.0 $ 0.91
Less: Income from discontinued operations..... 133.2 -- 0.54
Income from extraordinary gain.......... 3.4 -- 0.01
------- ------
Income from continuing operations available to
common shareholders........................ 89.2 -- 0.36
Effect of dilutive options...................... -- 0.2 --
------- ----- ------
Diluted EPS
Income from continuing operations available to
Common shareholders plus assumed
conversion................................. $ 89.2 249.2 $ 0.36
======= ===== ======
FOR THE YEAR ENDED DECEMBER 31, 1998
Basic EPS
Net loss...................................... $(898.7) 247.7 $(3.63)
Less: Loss from discontinued operations....... (15.6) -- (0.06)
------- ------
Loss from continuing operations available to
common shareholders........................ (883.1) -- (3.57)
Effect of dilutive options (a).................. -- -- --
------- ----- ------
Diluted EPS
Loss from continuing operations available to
Common shareholders plus assumed
conversion................................. $(883.1) 247.7 $(3.57)
======= ===== ======
FOR THE YEAR ENDED DECEMBER 31, 1997
Basic EPS
Net Income.................................... $ 333.0 250.1 $ 1.33
Less: income from discontinued operations..... 29.9 -- 0.12
------- ------
Income from continuing operations available to
common shareholders........................ 303.1 -- 1.21
Effect of dilutive options...................... -- 0.8 --
------- ----- ------
Diluted EPS
Income from continuing operations available to
Common shareholders plus assumed
conversion................................. $ 303.1 250.9 $ 1.21
======= ===== ======
</TABLE>
- ---------------
(a) Options outstanding, as discussed above, have been excluded from the 1998
calculation of diluted earnings per share due to anti-dilution.
71
<PAGE> 74
UNION PACIFIC RESOURCES GROUP INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Employee Stock Ownership Plan. Effective January 2, 1997, the Company
instituted an employee stock ownership plan ("ESOP") for eligible U.S.
employees. The ESOP purchased 3.7 million shares or $107.3 million of newly
issued common stock (the "ESOP Shares") from the Company, to be used to fund the
Company's matching obligation under its 401(k) Thrift Plan. All domestic regular
employees of the Company are eligible to participate in the ESOP.
The ESOP Shares, which are held in trust, were purchased with the proceeds
from a 30-year loan from the Company. Such shares were pledged as collateral for
the loan. As loan payments are made, shares are released from collateral, based
on the proportion of debt service paid. Scheduled principal and interest
requirements are $5.9 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 are included in the computation of earnings per
share as such ESOP Shares are released from collateral. Releases of ESOP Shares
will be allocated to participants' accounts and will be charged to compensation
expense at the fair market value of the shares on the date of the employer
match. Dividends on allocated ESOP Shares will be recorded as a reduction of
retained earnings; dividends on unallocated ESOP Shares will be recorded as a
reduction of the principal or accrued interest on the loan.
As of December 31, 1999, allocated and unallocated shares in the ESOP were
958,472 and 2,741,528, respectively. As of December 31, 1998, allocated and
unallocated shares were 483,216 and 3,216,784, respectively. The fair value of
unallocated ESOP shares at December 31, 1999 and 1998 was $35.0 million and
$29.2 million, respectively. During 1999, 1998 and 1997, compensation cost
related to the allocation of ESOP shares to participants' accounts was $4.4
million, $6.3 million and $5.3 million, respectively.
Preferred Stock and Shareholder Rights. The Company has 100 million shares
of no-par-value preferred stock authorized, none of which are outstanding. On
October 28, 1996, the Company's Board of Directors designated 3,000,000 of the
authorized preferred shares as non-redeemable Series A Junior Participating
Preferred Shares (the "Series A Preferred Stock"). Upon issuance, each
one-hundredth of a share of the Series A Preferred Stock will have dividend and
voting rights approximately equal to those of one share of the Company's common
stock. In addition, on October 28, 1996, the Board of Directors adopted a
shareholder rights plan with a "flip-in" threshold of 15% 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 ("Rights Agreement"). Under the Rights Agreement, the
Company declared a dividend of one right ("Right") for each outstanding share of
common stock to shareholders of record on November 7, 1996. Under certain
limited conditions as defined in the Rights Agreement, each Right entitles the
registered holder to purchase from the Company one one-hundredth of a share of
Series A Preferred Stock at $135 subject to adjustment. The Rights are not
exercisable until the Distribution Date (as defined in the Rights Agreement)
which will occur upon the earlier of (i) ten days following a public
announcement that an Acquiring Person (as defined in the Rights Agreement) has
acquired beneficial ownership of 15% or more of the Company's outstanding Common
Stock (the "Stock Acquisition Date") or (ii) ten business days following the
commencement of a tender offer or exchange offer that would result in a person
or group owning 15% or more of the Company's outstanding Common Stock.
The Rights have certain anti-takeover effects. The Rights will cause
substantial dilution to a person or group that attempts to acquire the Company
without conditioning the offer on a substantial number of Rights being redeemed.
In the event that at any time following the Stock Acquisition Date certain
events occur as defined in the Rights Agreement, each holder of a Right, except
the Acquiring Person, will thereafter have the right to receive, upon exercise,
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.
72
<PAGE> 75
UNION PACIFIC RESOURCES GROUP INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
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.
During 1999, the Company repurchased 869,681 shares at a cost of $12.6
million primarily in connection with the Company's retention stock program. Also
during 1999, the Company reissued 259,605 shares of repurchased stock for $3.3
million to settle deferred compensation liabilities for several former
executives. During 1998, the Company repurchased 837,500 shares at a cost of
$18.6 million and 449,788 shares at a cost of $8.1 million, in connection with
the Company's retention stock and options, respectively.
Other Comprehensive Income. The Company's other comprehensive income is as
follows:
<TABLE>
<CAPTION>
TAX
BEFORE-TAX BENEFIT NET-OF-TAX
AMOUNT (EXPENSE) AMOUNT
---------- ----------- ----------
(MILLIONS OF DOLLARS)
<S> <C> <C> <C>
1999
Foreign currency translation adjustment................ $ 49.6 $(27.1) $ 22.5
Minimum pension liability adjustment................... (6.0) -- (6.0)
------- ------ ------
Other comprehensive income............................. $ 43.6 $(27.1) $ 16.5
======= ====== ======
1998
Foreign currency translation adjustment................ $(149.6) $ 82.5 $(67.1)
Minimum pension liability adjustment................... (3.9) -- (3.9)
------- ------ ------
Other comprehensive income (loss)...................... $(153.5) $ 82.5 $(71.0)
======= ====== ======
</TABLE>
16. OTHER INCOME -- NET
Other income (expense) -- net consists of the following:
<TABLE>
<CAPTION>
FOR THE YEARS ENDED
DECEMBER 31,
------------------------
1999 1998 1997
------ ------ ------
(MILLIONS OF DOLLARS)
<S> <C> <C> <C>
Foreign currency gain (loss) -- net (Note 5)............... $ 44.2 $(35.5) $ --
Firm transportation contract valuation..................... (43.4) -- --
Interest income............................................ 30.5 11.1 4.4
Insurance settlement proceeds.............................. -- 3.3 10.0
Excess reserve releases.................................... -- -- 23.0
Gain (loss) on sales of investment......................... -- (1.4) 7.2
Pennzoil acquisition costs(a).............................. -- (2.0) (17.8)
Interest rate lock cost (Note 5)........................... -- (14.3) --
Other -- net............................................... 0.4 (6.5) (2.3)
------ ------ ------
Total other income -- net........................ $ 31.7 $(45.3) $ 24.5
====== ====== ======
</TABLE>
- ---------------
(a) Related to cost incurred with the unsuccessful takeover attempt of Pennzoil
Company.
73
<PAGE> 76
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.
<TABLE>
<CAPTION>
UNITED OTHER
STATES CANADA INTERNATIONAL WORLDWIDE
------- -------- ------------- ---------
<S> <C> <C> <C> <C>
NATURAL GAS (BCF)(a): 1997
Beginning of year........................... 2,300.8 77.6 -- 2,378.4
Revisions of previous estimates............. 13.4 (4.1) -- 9.3
Extensions, discoveries and other
additions................................ 574.5 13.8 -- 588.3
Purchases of reserves-in-place.............. 54.8 -- -- 54.8
Sales of reserves-in-place.................. (3.5) -- -- (3.5)
Production.................................. (400.8) (6.2) -- (407.0)
------- -------- ----- -------
Total proved, end of year........... 2,539.2 81.1 -- 2,620.3
======= ======== ===== =======
Proved developed reserves........... 2,156.5 60.5 -- 2,217.0
======= ======== ===== =======
NATURAL GAS (BCF): 1998
Beginning of year........................... 2,539.2 81.1 -- 2,620.3
Revisions of previous estimates............. 81.8 13.6 -- 95.4
Extensions, discoveries and other
additions................................ 276.7 100.7 10.0 387.4
Purchases of reserves-in-place.............. 210.4 998.3 37.2 1,245.9
Sales of reserves-in-place.................. (286.8) (97.3) -- (384.1)
Production.................................. (420.6) (102.6) (2.6) (525.8)
------- -------- ----- -------
Total proved, end of year........... 2,400.7 993.8 44.6 3,439.1
======= ======== ===== =======
Proved developed reserves........... 2,079.3 853.9 34.7 2,967.8
======= ======== ===== =======
NATURAL GAS (BCF): 1999
Beginning of year........................... 2,400.7 993.8 44.6 3,439.1
Revisions of previous estimates............. (45.1) (21.6) (13.3) (80.0)
Extensions, discoveries and other
additions................................ 280.5 147.2 5.5 433.2
Purchases of reserves-in-place.............. 11.8 1.5 -- 13.3
Sales of reserves-in-place.................. (13.4) (34.7) -- (48.1)
Production.................................. (362.5) (101.4) (2.8) (466.7)
------- -------- ----- -------
Total proved, end of year........... 2,272.0 984.8 34.0 3,290.8
======= ======== ===== =======
Proved developed reserves........... 1,890.7 770.9 29.9 2,691.5
======= ======== ===== =======
</TABLE>
74
<PAGE> 77
<TABLE>
<CAPTION>
UNITED OTHER
STATES CANADA INTERNATIONAL WORLDWIDE
------- -------- ------------- ---------
<S> <C> <C> <C> <C>
NATURAL GAS LIQUIDS (MMBBL)(a): 1997
Beginning of year........................... 100.6 6.9 -- 107.5
Revisions of previous estimates............. 1.1 0.8 -- 1.9
Extensions, discoveries and other
additions................................ 21.5 0.1 -- 21.6
Purchases of reserves-in-place.............. 0.9 -- -- 0.9
Sales of reserves-in-place.................. -- -- -- --
Production.................................. (13.2) (0.8) -- (14.0)
------- -------- ----- -------
Total proved, end of year........... 110.9 7.0 -- 117.9
======= ======== ===== =======
Proved developed reserves........... 96.3 7.0 -- 103.3
======= ======== ===== =======
NATURAL GAS LIQUIDS (MMBBL): 1998
Beginning of year........................... 110.9 7.0 -- 117.9
Revisions of previous estimates............. (10.1) 5.5 -- (4.6)
Extensions, discoveries and other
additions................................ 1.3 1.5 -- 2.8
Purchases of reserves-in-place.............. 2.7 18.2 -- 20.9
Sales of reserves-in-place.................. (29.6) (4.1) -- (33.7)
Production.................................. (10.4) (1.6) -- (12.0)
------- -------- ----- -------
Total proved, end of year........... 64.8 26.5 -- 91.3
======= ======== ===== =======
Proved developed reserves........... 54.9 24.0 -- 78.9
======= ======== ===== =======
NATURAL GAS LIQUIDS (MMBBL): 1999
Beginning of year........................... 64.8 26.5 -- 91.3
Revisions of previous estimates............. (2.4) (6.9) -- (9.3)
Extensions, discoveries and other
additions................................ 3.0 0.6 -- 3.6
Purchases of reserves-in-place.............. 0.4 -- -- 0.4
Sales of reserves-in-place.................. (0.4) (12.3) -- (12.7)
Production.................................. (9.6) (0.7) -- (10.3)
------- -------- ----- -------
Total proved, end of year........... 55.8 7.2 -- 63.0
======= ======== ===== =======
Proved developed reserves........... 53.6 6.2 -- 59.8
======= ======== ===== =======
CRUDE OIL, INCLUDING CONDENSATE (MMBBL): 1997
Beginning of year........................... 72.4 6.5 1.7 80.6
Revisions of previous estimates............. 4.9 0.2 -- 5.1
Extensions, discoveries and other
additions................................ 56.7 -- -- 56.7
Purchases of reserves-in-place.............. 5.8 -- -- 5.8
Sales of reserves-in-place.................. (0.1) -- -- (0.1)
Production.................................. (18.1) (0.6) (0.6) (19.3)
------- -------- ----- -------
Total proved, end of year........... 121.6 6.1 1.1 128.8
======= ======== ===== =======
Proved developed reserves........... 86.7 6.1 1.1 93.9
======= ======== ===== =======
CRUDE OIL, INCLUDING CONDENSATE (MMBBL): 1998
Beginning of year........................... 121.6 6.1 1.1 128.8
Revisions of previous estimates............. (6.7) (3.8) 1.8 (8.7)
Extensions, discoveries and other
additions................................ 12.6 4.9 16.7 34.2
Purchases of reserves-in-place.............. 14.3 114.9 142.6 271.8
Sales of reserves-in-place.................. (6.7) (12.9) -- (19.6)
Production.................................. (22.3) (12.9) (15.1) (50.3)
------- -------- ----- -------
Total proved, end of year........... 112.8 96.3 147.1 356.2
======= ======== ===== =======
Proved developed reserves........... 81.3 65.7 105.3 252.4
======= ======== ===== =======
</TABLE>
75
<PAGE> 78
<TABLE>
<CAPTION>
UNITED OTHER
STATES CANADA INTERNATIONAL WORLDWIDE
------- -------- ------------- ---------
<S> <C> <C> <C> <C>
CRUDE OIL, INCLUDING CONDENSATE (MMBBL): 1999
Beginning of year........................... 112.8 96.3 147.1 356.2
Revisions of previous estimates............. (10.7) (7.7) 16.9 (1.5)
Extensions, discoveries and other
additions................................ 8.7 15.0 2.0 25.7
Purchases of reserves-in-place.............. 0.1 -- 2.0 2.1
Sales of reserves-in-place.................. (0.4) (0.3) -- (0.7)
Production.................................. (15.9) (10.5) (16.3) (42.7)
------- -------- ----- -------
Total proved, end of year........... 94.6 92.8 151.7 339.1
======= ======== ===== =======
Proved developed reserves........... 64.6 60.1 92.1 216.8
======= ======== ===== =======
PROVED RESERVES EQUIVALENT, END OF 1997
(BCFE)(b)
Natural gas................................. 2,539.2 81.1 -- 2,620.3
Natural gas liquids......................... 665.4 42.0 -- 707.4
Crude oil, including condensate............. 729.6 36.6 6.6 772.8
------- -------- ----- -------
Total proved........................ 3,934.2 159.7 6.6 4,100.5
======= ======== ===== =======
Proved developed reserves........... 3,254.5 139.1 6.6 3,400.2
======= ======== ===== =======
PROVED RESERVES EQUIVALENT, END OF 1998
(BCFE)(b)
Natural gas................................. 2,400.7 993.8 44.6 3,439.1
Natural gas liquids......................... 388.8 159.0 -- 547.8
Crude oil, including condensate............. 676.8 577.8 882.6 2,137.2
------- -------- ----- -------
Total proved........................ 3,466.3 1,730.6 927.2 6,124.1
======= ======== ===== =======
Proved developed reserves........... 2,896.8 1,392.1 666.6 4,955.5
======= ======== ===== =======
PROVED RESERVES EQUIVALENT, END OF 1999
(BCFE)(B)
Natural gas................................. 2,272.0 984.8 34.0 3,290.8
Natural gas liquids......................... 334.8 43.2 -- 378.0
Crude oil, including condensate............. 567.6 556.8 910.2 2,034.6
------- -------- ----- -------
Total proved........................ 3,174.4 1,584.8 944.2 5,703.4
======= ======== ===== =======
Proved developed reserves........... 2,599.9 1,168.7 582.5 4,351.1
======= ======== ===== =======
</TABLE>
- ---------------
(a) Reserves at the end of 1997 include the plant share of equity gas processed
(natural gas and natural gas liquids, as appropriate, earned by gas
processing facilities through the processing of the Company's equity
production.
(b) Calculated using the ratio of one Bbl to six Mcf.
76
<PAGE> 79
B. DRILLING ACTIVITY
Drilling activity is summarized as follows:
<TABLE>
<CAPTION>
OTHER
UNITED STATES CANADA INTERNATIONAL WORLDWIDE
------------- ------ ------------- ---------
<S> <C> <C> <C> <C>
FOR THE YEAR ENDED DECEMBER 31, 1999(a)
Gross wells............................... 182 448 13 643
Gross productive wells.................... 163 430 7 600
Net wells:
Exploration............................. 7 49 2 58
Development............................. 97 330 4 431
--- --- -- ---
Total net wells................. 104 379 6 489
=== === == ===
Net productive wells:
Exploration............................. 2 41 -- 43
Development............................. 89 321 3 413
--- --- -- ---
Total net productive wells...... 91 362 3 456
=== === == ===
FOR THE YEAR ENDED DECEMBER 31, 1998
Gross wells............................... 318 273 45 636
Gross productive wells.................... 290 243 42 575
Net wells:
Exploration............................. 18 45 1 64
Development............................. 248 115 22 385
--- --- -- ---
Total net wells................. 266 160 23 449
=== === == ===
Net productive wells:
Exploration............................. 13 32 1 46
Development............................. 232 106 20 358
--- --- -- ---
Total net productive wells...... 245 138 21 404
=== === == ===
FOR THE YEAR ENDED DECEMBER 31, 1997
Gross wells............................... 811 6 -- 817
Gross productive wells.................... 714 6 -- 720
Net wells:
Exploration............................. 41 -- -- 41
Development............................. 521 4 -- 525
--- --- -- ---
Total net wells................. 562 4 -- 566
=== === == ===
Net productive wells:
Exploration............................. 19 -- -- 19
Development............................. 475 4 -- 479
--- --- -- ---
Total net productive wells...... 494 4 -- 498
=== === == ===
</TABLE>
- ---------------
(a) In addition, at December 31, 1999, 26 gross wells (17 net wells) were in
the process of being drilled.
77
<PAGE> 80
C. AVERAGE SALES PRICE AND COST
The average producing properties sales prices, after hedging results and
costs are set forth below:
<TABLE>
<CAPTION>
FOR THE YEARS ENDED
DECEMBER 31,
------------------------
1999 1998 1997
------ ------ ------
<S> <C> <C> <C>
Natural gas sales price (per Mcf)
United States............................................ $ 1.90 $ 1.84 $ 2.01
Canada................................................... 1.62 1.35 1.58
Other international...................................... 1.09 1.39 --
Total.................................................... 1.83 1.74 2.00
Natural gas liquids sales price (per Bbl)
United States............................................ $11.02 $ 8.14 $11.57
Canada................................................... 10.07 6.12 5.41
Other international...................................... -- -- --
Total.................................................... 10.95 7.88 11.23
Crude oil sales price (per Bbl)
United States............................................ $12.56 $13.23 $18.37
Canada................................................... 9.21 8.55 19.85
Other international...................................... 12.76 8.09 16.90
Total.................................................... 11.81 10.48 18.36
Production cost (per Mcf)
United States............................................ $ 0.46 $ 0.51 $ 0.51
Canada................................................... 0.48 0.41 0.29
Other international...................................... 0.79 0.54 0.77
Total production cost.................................... 0.51 0.49 0.51
</TABLE>
78
<PAGE> 81
D. AVERAGE DAILY PRODUCTION AND SALES VOLUME
The average producing properties daily production and sales volume are set
forth below:
<TABLE>
<CAPTION>
FOR THE YEARS ENDED
DECEMBER 31,
---------------------------
1999 1998 1997
------- ------- -------
<S> <C> <C> <C>
Natural gas (MMcfd)
United States........................................... 993.1 1,152.8 1,090.9
Canada.................................................. 277.8 281.2 17.6
Other international..................................... 7.9 7.1 --
------- ------- -------
Total natural gas....................................... 1,278.8 1,441.1 1,108.5
======= ======= =======
Natural gas liquids (MBBld)
United States........................................... 26.4 28.8 30.0
Canada.................................................. 2.0 4.3 1.7
Other international..................................... -- -- --
------- ------- -------
Total natural gas liquids............................... 28.4 33.1 31.7
======= ======= =======
Crude oil (MBBld)
United States........................................... 43.5 61.0 49.2
Canada.................................................. 28.8 35.4 1.7
Other international..................................... 44.8 41.5 2.0
------- ------- -------
Total crude oil......................................... 117.1 137.9 52.9
======= ======= =======
Total producing properties (MMcfed)
United States........................................... 1,412.6 1,692.0 1,565.8
Canada.................................................. 462.4 519.3 38.3
Other international..................................... 276.6 255.7 11.6
------- ------- -------
Total producing properties.............................. 2,151.6 2,467.0 1,615.7
======= ======= =======
</TABLE>
E. ACREAGE AND WELLS
Oil and gas leasehold acreage is as follows(a):
<TABLE>
<CAPTION>
AS OF DECEMBER 31,
--------------------------------------------------
OTHER
UNITED STATES CANADA INTERNATIONAL WORLDWIDE
------------- ------ ------------- ---------
(THOUSANDS OF ACRES)
<S> <C> <C> <C> <C>
1999
Gross developed........................... 2,266 1,618 554 4,438
Net developed............................. 1,391 942 135 2,468
Gross undeveloped......................... 2,038 5,297 5,777 13,112
Net undeveloped........................... 1,379 1,924 3,202 6,505
1998
Gross developed........................... 2,460 1,657 548 4,665
Net developed............................. 1,493 958 135 2,586
Gross undeveloped......................... 3,629 5,613 5,771 15,013
Net undeveloped........................... 2,469 2,185 3,194 7,848
</TABLE>
79
<PAGE> 82
Productive oil and gas wells are as follows:
<TABLE>
<CAPTION>
AS OF
DECEMBER 31,
1999
-------------
OIL GAS
----- -----
(WELLS)
<S> <C> <C>
Gross(b).................................................... 4,106 9,194
Net......................................................... 2,468 6,047
</TABLE>
- ---------------
(a) In addition, the Company has fee mineral ownership of approximately 9.4
million gross acres (8.5 million net acres), including 7.9 million gross
acres (7.7 million net acres) acquired through 19th century Congressional
Land Grant Acts. Substantial portions of this acreage are undeveloped and
are considered prospective for oil and gas.
(b) Approximately 2,265 are multiple completions, 2,011 of which are gas wells.
F. CAPITALIZED EXPLORATION AND PRODUCTION COSTS
Capitalized exploration and production costs are as follows(a):
<TABLE>
<CAPTION>
FOR THE YEARS ENDED DECEMBER 31,
-----------------------------------------------------
OTHER
UNITED STATES CANADA INTERNATIONAL WORLDWIDE
------------- --------- ------------- ---------
(MILLIONS OF DOLLARS)
<S> <C> <C> <C> <C>
1999
Proved properties..................... $ 1,243.3 $ 2,427.3 $1,100.5 $ 4,771.1
Unproved properties................... 257.1 271.6 454.6 983.3
Wells and related equipment........... 4,391.0 359.0 217.2 4,967.2
Uncompleted wells and equipment....... 75.6 3.4 -- 79.0
--------- --------- -------- ---------
Gross capitalized costs............. 5,967.0 3,061.3 1,772.3 10,800.6
Accumulated depreciation, depletion
and amortization.................... (3,676.8) (1,146.7) (609.7) (5,443.2)
--------- --------- -------- ---------
Net capitalized costs............... $ 2,290.2 $ 1,914.6 $1,162.6 $ 5,367.4
========= ========= ======== =========
1998
Proved properties..................... $ 1,103.3 $ 2,068.5 $1,047.6 $ 4,219.4
Unproved properties................... 396.8 389.2 455.5 1,241.5
Wells and related equipment........... 4,821.1 229.8 209.5 5,260.4
Uncompleted wells and equipment....... 142.7 -- -- 142.7
--------- --------- -------- ---------
Gross capitalized costs............. 6,463.9 2,687.5 1,712.6 10,864.0
Accumulated depreciation, depletion
and amortization.................... (3,603.2) (833.5) (438.5) (4,875.2)
--------- --------- -------- ---------
Net capitalized costs............... $ 2,860.7 $ 1,854.0 $1,274.1 $ 5,988.8
========= ========= ======== =========
</TABLE>
80
<PAGE> 83
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:
<TABLE>
<CAPTION>
FOR THE YEARS ENDED DECEMBER 31,
----------------------------------------------------
OTHER
UNITED STATES CANADA INTERNATIONAL WORLDWIDE
------------- -------- ------------- ---------
(MILLIONS OF DOLLARS)
<S> <C> <C> <C> <C>
1999
Costs incurred:
Proved acreage........................ $ 12.0 $ 0.8 $ 2.5 $ 15.3
Unproved acreage...................... 12.9 7.7 0.5 21.1
Exploration costs(a).................. 46.6 7.9 28.7 83.2
Development costs..................... 180.9 106.1 42.8 329.8
-------- -------- -------- --------
Total costs incurred(b)....... $ 252.4 $ 122.5 $ 74.5 $ 449.4
======== ======== ======== ========
1998
Costs incurred:
Proved acreage........................ $ 424.4 $1,733.7 $ 744.7 $2,902.8
Unproved acreage...................... 45.5 279.1 312.2 636.8
Exploration costs(a).................. 195.9 43.8 29.5 269.2
Development costs..................... 506.3 136.5 107.8 750.6
-------- -------- -------- --------
Total costs incurred(b)....... $1,172.1 $2,193.1 $1,194.2 $4,559.4
======== ======== ======== ========
1997
Costs incurred:
Proved acreage........................ $ 130.6 $ -- $ -- $ 130.6
Unproved acreage...................... 199.7 1.0 -- 200.7
Exploration costs(a).................. 231.9 5.0 -- 236.9
Development costs..................... 617.8 4.0 -- 621.8
-------- -------- -------- --------
Total costs incurred(b)....... $1,180.0 $ 10.0 $ -- $1,190.0
======== ======== ======== ========
</TABLE>
- ---------------
(a) Includes allocated exploration overhead costs of $17.9 million in 1999,
$24.2 million in 1998 and $23.5 million in 1997 and delay rentals of $8.3
million in 1999, $12.3 million in 1998 and $14.8 million in 1997.
(b) Excludes capital expenditures relating to discontinued operations of $33.7
million in 1999, $143.8 million in 1998 and $343.3 million in 1997.
81
<PAGE> 84
H. RESULTS OF OPERATIONS FOR PRODUCING ACTIVITIES(A)
The results of operations for producing activities is set forth below:
<TABLE>
<CAPTION>
OTHER
UNITED STATES CANADA INTERNATIONAL WORLDWIDE
------------- --------- ------------- ---------
(MILLIONS OF DOLLARS)
<S> <C> <C> <C> <C>
FOR THE YEAR ENDED DECEMBER 31, 1999
Revenues.............................. $ 1,062.4 $ 332.1 $ 212.5 $ 1,607.0
Production costs...................... (239.6) (81.7) (79.3) (400.6)
Exploration expenses.................. (148.7) (16.8) (102.4) (267.9)
Depreciation, depletion and
amortization........................ (558.0) (171.8) (86.2) (816.0)
--------- --------- ------- ---------
Total costs................. (946.3) (270.3) (267.9) (1,484.5)
--------- --------- ------- ---------
Pre-tax results....................... 116.1 61.8 (55.4) 122.5
Income taxes (benefit)................ 25.1 30.4 (18.4) 37.1
--------- --------- ------- ---------
Results of operations....... $ 91.0 $ 31.4 $ (37.0) $ 85.4
========= ========= ======= =========
FOR THE YEAR ENDED DECEMBER 31, 1998
Revenues.............................. $ 1,314.6 $ 259.2 $ 126.1 $ 1,699.9
Production costs...................... (317.0) (77.3) (50.0) (444.3)
Exploration expenses.................. (267.4) (25.3) (46.3) (339.0)
Depreciation, depletion and
amortization........................ (816.2) (915.3) (384.3) (2,115.8)
--------- --------- ------- ---------
Total costs................. (1,400.6) (1,017.9) (480.6) (2,899.1)
--------- --------- ------- ---------
Pre-tax results....................... (86.0) (758.7) (354.5) (1,199.2)
Income taxes (benefit)................ (48.3) (337.7) (95.0) (481.0)
--------- --------- ------- ---------
Results of operations....... $ (37.7) $ (421.0) $(259.5) $ (718.2)
========= ========= ======= =========
FOR THE YEAR ENDED DECEMBER 31, 1997
Revenues.............................. $ 1,337.3 $ 28.9 $ 12.0 $ 1,378.2
Production costs...................... (293.4) (4.1) (3.3) (300.8)
Exploration expenses.................. (197.6) (4.4) (2.7) (204.7)
Depreciation, depletion and
amortization........................ (481.7) (10.2) (7.4) (499.3)
--------- --------- ------- ---------
Total costs................. (972.7) (18.7) (13.4) (1,004.8)
--------- --------- ------- ---------
Pre-tax results....................... 364.6 10.2 (1.4) 373.4
Income taxes.......................... 108.9 -- -- 108.9
--------- --------- ------- ---------
Results of operations....... $ 255.7 $ 10.2 $ (1.4) $ 264.5
========= ========= ======= =========
</TABLE>
- ---------------
(a) General and administrative expenses, other income/expense and interest costs
have been excluded in computing these results of operations. Revenues
include net gains from sales of assets of $148.0 million in 1999, $139.6
million in 1998 and $18.3 million in 1997. Depreciation, depletion and
amortization includes asset impairments of $65.1 million in 1999, $1.2
billion in 1998 and $20.2 million in 1997.
82
<PAGE> 85
I. STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATES TO PROVED
OIL AND GAS RESERVES
The standardized measure of discounted cash flows relating to oil and gas
reserves are set forth below:
<TABLE>
<CAPTION>
UNITED OTHER
STATES CANADA INTERNATIONAL TOTAL
------- ------- ------------- -------
(MILLIONS OF DOLLARS)
<S> <C> <C> <C> <C>
AS OF DECEMBER 31, 1999
Future cash inflows from sales of oil and
gas........................................ $ 7,897 $ 3,970 $2,314 $14,181
Future production and development costs...... (1,461) (1,189) (756) (3,406)
Future income taxes.......................... (1,872) (1,096) (302) (3,270)
------- ------- ------ -------
Future net cash flows........................ 4,564 1,685 1,256 7,505
10% annual discount.......................... (1,748) (668) (430) (2,846)
------- ------- ------ -------
Standardized measure of discounted future net
cash flows................................. $ 2,816 $ 1,017 $ 826 $ 4,659
======= ======= ====== =======
AS OF DECEMBER 31, 1998
Future cash inflows from sales of oil and
gas........................................ $ 6,210 $ 2,642 $1,128 $ 9,980
Future production and development costs...... (1,619) (998) (641) (3,258)
Future income taxes.......................... (942) (536) (55) (1,533)
------- ------- ------ -------
Future net cash flows........................ 3,649 1,108 432 5,189
10% annual discount.......................... (1,394) (405) (165) (1,964)
------- ------- ------ -------
Standardized measure of discounted future net
cash flows................................. $ 2,255 $ 703 $ 267 $ 3,225
======= ======= ====== =======
AS OF DECEMBER 31, 1997
Future cash inflows from sales of oil and
gas........................................ $ 8,822 $ 355 $ 15 $ 9,192
Future production and development costs...... (2,032) (55) (4) (2,091)
Future income taxes.......................... (1,953) (86) (4) (2,043)
------- ------- ------ -------
Future net cash flows........................ 4,837 214 7 5,058
10% annual discount.......................... (1,926) (85) (1) (2,012)
------- ------- ------ -------
Standardized measure of discounted future net
cash flows................................. $ 2,911 $ 129 $ 6 $ 3,046
======= ======= ====== =======
</TABLE>
83
<PAGE> 86
An analysis of changes in the standardized measure of discounted future net
cash flows follows:
<TABLE>
<CAPTION>
FOR THE YEARS ENDED DECEMBER 31,
---------------------------------
1999 1998 1997
--------- --------- ---------
(MILLIONS OF DOLLARS)
<S> <C> <C> <C>
Beginning of year....................................... $ 3,225 $ 3,046 $ 4,239
Changes due to current year operations:
Additions and discoveries less related production and
other costs........................................ 544 438 1,000
Sales of oil and gas -- net of production costs....... (1,146) (1,160) (1,078)
Development costs..................................... 330 751 622
Purchases of reserves-in-place........................ 37 1,712 125
Sales of reserves-in-place............................ (136) (245) (4)
Changes due to revisions in:
Price................................................. 2,772 (1,110) (2,452)
Development costs..................................... (97) (911) (427)
Quantity estimates.................................... (249) 34 87
Income taxes.......................................... (1,118) 232 639
Other................................................. 102 38 (289)
Discount accretion...................................... 395 400 584
------- ------- -------
End of year............................................. $ 4,659 $ 3,225 $ 3,046
======= ======= =======
</TABLE>
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 on the New York Mercantile Exchange adjusted for appropriate regional
price differentials. Such weighted average prices for 1999, 1998 and 1997 were
$2.50 per Mcfe, $1.63 per Mcfe and $2.24 per Mcfe, respectively. Future
production hedged as of year-end is included in future net revenues at the
hedged price. Such prices may vary significantly from actual prices realized by
the Company for its future production. Future net revenues were discounted to
present value at 10%, 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 crude oil, natural gas and NGLs,
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.
84
<PAGE> 87
J. SELECTED QUARTERLY DATA
Selected unaudited quarterly data are as follows:
<TABLE>
<CAPTION>
FOR THE 1999 QUARTERS ENDED(A)
-----------------------------------------------------------------------
MARCH 31, 1999 JUNE 30, 1999 SEPTEMBER 30, 1999 DECEMBER 31, 1999
-------------- ------------- ------------------ -----------------
(MILLIONS OF DOLLARS, EXCEPT PER SHARE AMOUNTS)
<S> <C> <C> <C> <C>
Operating revenues............... $ 415.1 $386.7 $ 463.1 $ 462.6
Operating income................. 59.3 23.8 38.6 14.1
Income from continuing
operations..................... 42.3 15.3 20.7 10.9
Net income....................... 175.5 15.3 20.7 14.3
Per share:
Net income -- continuing
operations.................. $ 0.17 $ 0.06 $ 0.08 $ 0.04
Net income -- discontinued
operations.................. 0.54 -- -- --
Dividends...................... 0.05 0.05 0.05 0.05
Common stock price:
High........................... 12.1875 17.0 19.375 16.1250
Low............................ 7.6875 10.75 14.4375 10.9375
</TABLE>
<TABLE>
<CAPTION>
MARCH 31, 1999 JUNE 30, 1999 SEPTEMBER 30, 1999 DECEMBER 31, 1999
-------------- ------------- ------------------ -----------------
(MILLIONS OF DOLLARS)
<S> <C> <C> <C> <C>
Current assets................... $ 632.9 $ 507.2 $ 565.0 $ 495.9
Properties....................... 5,882.8 5,761.4 5,615.8 5,471.0
Intangible and other assets...... 169.5 174.2 177.1 180.0
-------- -------- -------- --------
Total assets..................... $6,685.2 $6,442.8 $6,357.9 $6,146.9
======== ======== ======== ========
Current liabilities.............. $1,252.7 $ 785.5 $ 732.7 $ 541.7
Deferred income taxes(c)......... 1,198.5 1,213.2 1,210.4 1,326.8
Long-term debt................... 2,755.4 3,029.7 2,966.1 2,797.3
Other long-term liabilities...... 600.4 526.8 528.6 543.6
Shareholders' equity(c).......... 878.2 887.6 920.1 937.5
-------- -------- -------- --------
Total liabilities and
shareholders' equity........... $6,685.2 $6,442.8 $6,357.9 $6,146.9
======== ======== ======== ========
</TABLE>
<TABLE>
<CAPTION>
FOR THE 1998 QUARTERS ENDED(B)
-----------------------------------------------------------------------
MARCH 31, 1998 JUNE 30, 1998 SEPTEMBER 30, 1998 DECEMBER 31, 1998
-------------- ------------- ------------------ -----------------
(MILLIONS OF DOLLARS, EXCEPT PER SHARE AMOUNTS)
<S> <C> <C> <C> <C>
Operating revenues............... $ 408.0 $ 501.7 $ 558.4 $ 372.9
Operating income (loss).......... 61.2 (13.2) 81.2 (1,322.4)
Income (loss) from continuing
operations..................... 24.7 (33.8) (13.1) (860.9)
Net income (loss)................ 31.2 (17.3) (17.3) (895.4)
Per share:
Net income (loss) -- continuing
operations.................. $ 0.10 $ (0.13) $ (0.06) $ (3.48)
Net income (loss).............. 0.13 (0.07) (0.07) (3.61)
Dividends...................... 0.05 0.05 0.05 0.05
Common stock price:
High........................... 24.5 25.25 18.5625 14.5
Low............................ 20.875 16.5625 8.3125 8.25
</TABLE>
85
<PAGE> 88
<TABLE>
<CAPTION>
MARCH 31, 1998(D) JUNE 30, 1998(D) SEPTEMBER 30, 1998(D) DECEMBER 31, 1998
----------------- ---------------- --------------------- -----------------
(MILLIONS OF DOLLARS)
<S> <C> <C> <C> <C>
Current assets............ $ 654.7 $ 525.0 $ 457.7 $ 441.4
Properties................ 8,094.2 8,056.3 7,612.5 6,093.3
Net assets from
discontinued
operations.............. 979.9 743.7 825.0 926.9
Intangible and other
assets.................. 236.8 160.7 165.8 180.8
-------- -------- -------- --------
Total assets.............. $9,965.6 $9,485.7 $9,061.0 $7,642.4
======== ======== ======== ========
Current liabilities....... $ 957.8 $ 610.5 $ 588.7 $1,346.7
Deferred income taxes..... 2,063.4 1,930.4 1,735.3 1,291.6
Long-term debt............ 4,708.7 4,751.9 4,585.7 3,744.9
Other long-term
liabilities............. 470.7 494.7 495.5 531.0
Shareholders' equity...... 1,765.0 1,698.2 1,655.8 728.2
-------- -------- -------- --------
Total liabilities and
shareholders' equity.... $9,965.6 $9,485.7 $9,061.0 $7,642.4
======== ======== ======== ========
</TABLE>
- ---------------
(a) First quarter 1999 net income reflects the sale of the Company's GPM
business segment for $157.0 million after-tax gain and an after-tax loss of
$23.8 million on discontinued operations.
(b) Second quarter 1998 results reflect the impact of purchase of the Norcen
Acquisition. Fourth quarter 1998 results reflect the decrease in hydrocarbon
prices and a $1.2 billion impairment of certain oil and gas assets.
(c) Certain amounts have been restated from amounts previously reported in the
Company's SEC Form 10-Q for the periods ended March 31, 1999, June 30, 1999
and September 30, 1999.
(d) Certain amounts have been restated for discontinued operations from amounts
previously reported in the Company's SEC Form 10-Q for the periods ended
March 31, 1998, June 30, 1998 and September 30, 1998 (See Note 3).
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.
86
<PAGE> 89
(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 Beneficial
Ownership -- Section 16(a) Reporting Compliance 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 Outside Directors 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 17, 2000, by each director and nominee for director, the five
most highly compensated current executive officers, a former chief executive
officer, a former executive officer, and directors and current executive
officers as a group is set forth in the Security Ownership of Certain Executive
Officers, Directors and Certain Beneficial Owners segment of the Proxy Statement
and is incorporated herein by reference.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
None.
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
(a)(1) and (2) Financial Statements and Schedules.
See "Index to Consolidated Financial Statements" set forth in Item 8 of
this Form 10-K.
No schedules are required to be filed because of the absence of conditions
under which they would be required or because the required information is set
forth in the financial statements referred to above.
(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. Management contracts or compensatory
plans, contracts or arrangements with directors and executive officers of the
Company are listed in Exhibits 10.3 through 10.14(b).
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION OF EXHIBIT
------- ----------------------
<C> <S>
2.1 -- Pre-acquisition agreement between Union Pacific Resources
Group Inc., Union Pacific Resources Inc. and Norcen
Energy Resources Limited, dated January 25, 1998
(incorporated herein by reference to Exhibit 2.1 to the
Company's Current Report on Form 8-K, filed on March 17,
1998)
3.1 -- Amended and Restated Articles of Incorporation of Union
Pacific Resources Group Inc. (Exhibit 3.1 to Form S-1 and
Exhibit 3.2 to the Company's Annual Report on Form 10-K
for the year ended December 31, 1996)
*3.2 -- Amended and Restated Bylaws of Union Pacific Resources
Group Inc.
4.1 -- Specimen of Certificate evidencing the Common Stock
(Exhibit 4 to Form S-1)
</TABLE>
87
<PAGE> 90
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION OF EXHIBIT
------- ----------------------
<C> <S>
4.2 -- Amended and Restated Rights Agreement, dated as of
December 1, 1998, between Union Pacific Resources Group
Inc. and Harris Trust and Savings Bank, as rights agent
(incorporated herein by reference to the Exhibit to the
Company's Report on Form 8-A12G/A filed on February 5,
1999)
4.3 -- Indenture, dated as of March 27, 1996, between Union
Pacific Resources Group Inc. and Texas Commerce Bank
National Association, as trustee (incorporated herein by
reference to Exhibit 4.1 to the Company's Form S-3
Registration Statement, Registration No. 333-2984, dated
May 23, 1996)
4.4(a) -- Terms Agreement, dated as of October 10, 1996, for
$200,000,000 7 1/2% Debentures due October 15, 2026
(incorporated herein by reference to Exhibit 4.4 to the
Company's Current Report on Form 8-K filed on March 17,
1998)
4.4(b) -- Form of 7 1/2% Rate Debenture due October 15, 2026
(incorporated herein by reference to Exhibit 4.7 to the
Company's Current Report on Form 8-K filed on March 17,
1998)
4.5(a) -- Terms Agreement, dated as of October 10, 1996, for
$200,000,000 7% Notes due October 15, 2006 (incorporated
herein by reference to Exhibit 4.5 to the Company's
Current Report on Form 8-K filed on March 17, 1998)
4.5(b) -- Form of 7% Rate Note due October 15, 2006 (incorporated
herein by reference to Exhibit 4.8 to the Company's
Current Report on Form 8-K filed on March 17, 1998)
4.6(a) -- Terms Agreement, dated as of October 31, 1996, for
$150,000,000 7 1/2% Debentures due November 1, 2096
(incorporated herein by reference to Exhibit 4.6 to the
Company's Current Report on Form 8-K filed on March 17,
1998)
4.6(b) -- Form of 7 1/2% Rate Note due November 1, 2096
(incorporated herein by reference to Exhibit 4.9 to the
Company's Current Report on Form 8-K filed on March 17,
1998)
4.7 -- Trust Indenture, dated as of May 7, 1996, providing for
the issue of Debt Securities in unlimited principal
amount, between Norcen Energy Resources Limited and
Montreal Trust Company of Canada, as trustee
(incorporated herein by reference to Exhibit 4.10 to the
Company's Current Report on Form 8-K filed on March 17,
1998)
4.8 -- First Supplemental Indenture, dated as of May 22, 1996,
to Trust Indenture dated as of May 7, 1996, providing for
the issue of 7 3/8% Debentures due May 15, 2006, in
aggregate principal amount of U.S. $250,000,000 between
Norcen Energy Resources Limited and Montreal Trust
Company of Canada, as trustee (incorporated herein by
reference to Exhibit 4.11 to the Company's Current Report
on Form 8-K filed on March 17, 1998)
4.9 -- Second Supplemental Indenture, dated as of June 26, 1996,
to Trust Indenture dated as of May 7, 1996, providing for
the issue of 7.8% Debentures due July 2, 2008, in
aggregate principal amount of U.S. $150,000,000 between
Norcen Energy Resources Limited and Montreal Trust
Company of Canada, as trustee (incorporated herein by
reference to Exhibit 4.12 to the Company's Current Report
on Form 8-K filed on March 17, 1998)
4.10 -- Third Supplemental Indenture, dated as of June 26, 1996,
to Trust Indenture dated as of May 7, 1996, providing for
the issue of 6.8% Debentures due July 2, 2002, in
aggregate principal amount of U.S. $250,000,000 between
Norcen Energy Resources Limited and Montreal Trust
Company of Canada, as trustee (incorporated herein by
reference to Exhibit 4.13 to the Company's Current Report
on Form 8-K filed on March 17, 1998)
</TABLE>
88
<PAGE> 91
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION OF EXHIBIT
------- ----------------------
<C> <S>
4.11 -- Fourth Supplemental Indenture, dated as of February 27,
1998, to Trust Indenture dated as of May 7, 1996,
providing for the Guarantee of all Securities Issued or
Previously Issued under the Trust Indenture between
Norcen Energy Resources Limited, Union Pacific Resources
Group Inc., as guarantor, and Montreal Trust Company of
Canada, as trustee (incorporated herein by reference to
Exhibit 4.14 to the Company's Current Report on Form 8-K
filed on March 17, 1998)
4.12(a) -- Terms Agreement for $200,000,000 6.50% Notes due May 15,
2005 (incorporated herein by reference to Exhibit 4.1 to
the Company's Current Report on Form 8-K filed on May 26,
1998)
4.12(b) -- Form of 6.50% Note due May 15, 2005 (incorporated herein
by reference to Exhibit 4.5 to the Company's Current
Report on Form 8-K filed on May 26, 1998)
4.13(a) -- Terms Agreement for $200,000,000 6.75% Notes due May 15,
2008 (incorporated herein by reference to Exhibit 4.2 to
the Company's Current Report on Form 8-K filed on May 26,
1998)
4.13(b) -- Form of 6.75% Note due May 15, 2008 (incorporated herein
by reference to Exhibit 4.6 to the Company's Current
Report on Form 8-K filed on May 26, 1998)
4.14(a) -- Terms Agreement for $200,000,000 7.05% Notes due May 15,
2018 (incorporated herein by reference to Exhibit 4.3 to
the Company's Current Report on Form 8-K filed on May 26,
1998)
4.14(b) -- Form of 7.05% Debenture due May 15, 2018 (incorporated
herein by reference to Exhibit 4.7 to the Company's
Current Report on Form 8-K filed on May 26, 1998)
4.15(a) -- Terms Agreement for $425,000,000 7.15% Notes due May 15,
2028 (incorporated herein by reference to Exhibit 4.4 to
the Company's Current Report on Form 8-K filed on May 26,
1998)
4.15(b) -- Form of 7.15% Debenture due May 15, 2028 (incorporated
herein by reference to Exhibit 4.8 to the Company's
Current Report on Form 8-K filed on May 26, 1998)
4.16(a) -- Terms Agreement for $200,000,000 7.30% Notes due April
15, 2009 (incorporated herein by reference to Exhibit 1.2
to the Company's Current Report on Form 8-K filed on
April 12, 1999)
4.16(b) -- Form of 7.30% Note due April 15, 2009 (incorporated
herein by reference to Exhibit 4.2 to the Company's
Current Report on Form 8-K filed on April 14, 1999)
4.17(a) -- Terms Agreement for $300,000.000 7.95% Debentures due
April 15, 2029 (incorporated herein by reference to
Exhibit 1.2 to the Company's Current Report on Form 8-K
filed on April 12, 1999)
4.17(b) -- Form of 7.95% Debenture due April 15, 2029 ($200 million)
(incorporated herein by reference to Exhibit 4.3 to the
Company's Current Report on Form 8-K filed on April 14,
1999)
4.17(c) -- Form of 7.95% Debenture due April 15, 2029 ($100 million)
(incorporated herein by reference to Exhibit 4.4 to the
Company's Current Report on Form 8-K filed on April 14,
1999)
4.18 -- Indenture, dated as of April 13, 1999, between Union
Pacific Resources Group Inc., Union Pacific Resources
Inc., UPR Capital Company and The Bank of New York as
trustee (incorporated herein by reference to Exhibit 4.1
to the Company's Current Report on Form 8-K filed on
April 14, 1999)
10.1 -- Tax Allocation Agreement, dated October 6, 1995 (Exhibit
10.3 to Form S-1)
10.2 -- Indemnification Agreement, dated October 1, 1995 (Exhibit
10.4 to Form S-1)
10.3 -- Pension Plan Agreement, dated October 1, 1995, by and
between Union Pacific Corporation and Union Pacific
Resources Group Inc. (Exhibit 10.7 to Form S-1)
</TABLE>
89
<PAGE> 92
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION OF EXHIBIT
------- ----------------------
<C> <S>
10.4 -- The Supplemental Pension Plan for Officers and Managers
of Union Pacific Corporation and Affiliates, with
amendments (incorporated herein by reference to Exhibit
10.11 to the Company's Annual Report on Form 10-K for the
year ended December 31, 1995)
10.5 -- The Supplemental Pension Plan for Exempt Salaried
Employees of Union Pacific Resources Company and
Affiliates, with amendments (incorporated herein by
reference to Exhibit 10.12 to the Company's Annual Report
on Form 10-K for the year ended December 31, 1995)
10.6 -- Executive Incentive Plan of Union Pacific Resources Group
Inc. as amended and restated June 1, 1997 (incorporated
herein by reference to Exhibit 10.2 to the Company's
Quarterly Report on Form 10-Q for the period ended March
31, 1997)
*10.7 -- 1995 Stock Option and Retention Stock Plan of Union
Pacific Resources Group Inc. as amended and restated,
effective December 7, 1999.
10.8(a) -- 1995 Directors Stock Incentive Plan, as amended and
restated, effective July 14, 1998 (incorporated herein by
reference to Exhibit 10.8(a) to the Company's Annual
Report on Form 10-K for the year ended December 31, 1998)
10.8(b) -- First Amendment, effective January 21, 1999, to 1995
Directors Stock Incentive Plan, as amended and restated,
effective July 14, 1998 (incorporated herein by reference
to Exhibit 10.8(b) to the Company's Annual Report on Form
10-K for the year ended December 31, 1998)
10.8(c) -- Second Amendment, effective May 18, 1999, to 1995
Directors Stock Incentive Plan, as amended and restated,
effective July 14, 1998 (incorporated by reference to
Exhibit 10.2 to the Company's Quarterly Report on Form
10-Q for the period ended June 30, 1999)
10.9 -- Union Pacific Resources Group Inc. Deferred Compensation
Plan for the Board of Directors, as amended and restated,
effective September 5, 1997 (incorporated herein by
reference to Exhibit 99.2 to the Company's Registration
Statement on Form S-8, dated September 15, 1997)
10.10 -- Union Pacific Resources Group Inc. Executive Deferred
Compensation Plan, effective September 5, 1997
(incorporated herein by reference to Exhibit 99.1 to the
Company's Registration Statement on Form S-8, dated
September 15, 1997)
10.11(a) -- Union Pacific Resources Group Inc. Executive Life
Insurance Plan, adopted February 26, 1997 (incorporated
herein by reference to Exhibit 10.16 to the Company's
Annual Report on Form 10-K for the year ended December
31, 1996)
*10.11(b) -- Description of Amendment, adopted December 6, 1999, to
the Union Pacific Resources Group Inc. Executive Life
Insurance Plan, adopted February 26, 1997.
10.12(a) -- Form of Agreement relating to Change in Control by and
between Union Pacific Resources Group Inc. and George
Lindahl III dated October 21, 1999, superseding and
replacing the agreement dated February 4, 1997
(incorporated herein by reference to Exhibit 10.1 to the
Company's Quarterly Report on Form 10-Q for the period
ended September 30, 1999)
10.12(b) -- Form of Agreement relating to Change in Control by and
between Union Pacific Resources Group Inc. and each of
Anne M. Franklin, Donald W. Niemiec, Morris B. Smith,
John B. Vering and Joseph A. LaSala, Jr., dated February
4, 1997 (incorporated herein by reference to Exhibit
10.17(c) to the Company's Annual Report on Form 10-K for
the year ended December 31, 1996)
10.12(c) -- Form of Agreement relating to Change in Control by and
between Union Pacific Resources Group Inc. and Thomas R.
Blank, dated July 13, 1998 (incorporated herein by
reference to Exhibit 10.4 to the Company's Quarterly
Report on Form 10-Q/A filed November 12, 1998)
</TABLE>
90
<PAGE> 93
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION OF EXHIBIT
------- ----------------------
<C> <S>
10.12(d) -- Form of Amendment, dated as of January 21, 1999, to
Change in Control Agreements between Union Pacific
Resources Group Inc. and Anne M. Franklin, Donald W.
Niemiec, Morris B. Smith, John B. Vering, Jack L.
Messman, V. Richard Eales and Joseph A. LaSala, Jr., all
dated February 4, 1997, and between Union Pacific
Resources Group Inc. and Thomas R. Blank dated July 13,
1998 (incorporated herein by reference to Exhibit
10.13(e) to the Company's Annual Report on Form 10-K for
the year ended December 31, 1998)
*10.12(e) -- Form of Agreement relating to Change in Control by and
between Union Pacific Resources Group Inc. and Kerry R.
Brittain, dated March 18, 1999.
*10.12(f) -- Form of Amendment, dated as of March 30, 1999, to Change
in Control Agreement between Union Pacific Resources
Group Inc. and Kerry R. Brittain, dated March 18, 1999.
10.12(g) -- Form of Agreement relating to Change in Control by and
between Union Pacific Resources Group Inc. and Jack L.
Messman, dated February 4, 1997 (incorporated herein by
reference to Exhibit 10.17(a) to the Company's Annual
Report on Form 10-K for the year ended December 31, 1996)
10.12(h) -- Form of Agreement relating to Change in Control by and
between Union Pacific Resources Group Inc. and V. Richard
Eales, dated February 7, 1997 (incorporated herein by
reference to Exhibit 10.17(b) to the Company's Annual
Report on From 10-K for the year ended December 31, 1996)
10.13 -- Settlement and Release Agreement by and between Union
Pacific Resources Group Inc. and V. Richard Eales,
effective September 1, 1999 (incorporated herein by
reference to Exhibit 10.2 to the Company's Quarterly
Report on Form 10-Q for the period ended September 30,
1999)
10.14(a) -- Conversion Agreement (Exhibit 10.13(a) to Form S-1)
10.14(b) -- Conversion Agreement for Drew Lewis (Exhibit 10.13(b) to
Form S-1)
10.15(a) -- Amended and Restated 1976 Coal Purchase Contract, dated
as of January 1, 1993, between Commonwealth Edison
Company and Black Butte Coal Company (Exhibit 10.19 to
Form S-1)
10.15(b) -- Amendment No. 1 to Amended and Restated 1976 Coal
Purchase Contract between Commonwealth Edison Company and
Black Butte Coal Company, effective as of January 1, 1996
(incorporated herein by reference to Exhibit 10.35 to the
Company's Annual Report on Form 10-K for the year ended
December 31, 1997)
10.15(c) -- Amendment No. 2 to Amended and Restated 1976 Coal
Purchase Contract between Commonwealth Edison Company and
Black Butte Coal Company, effective as of January 1, 1997
(incorporated herein by reference to Exhibit 10.36 to the
Company's Annual Report on Form 10-K for the year ended
December 31, 1997)
10.16(a) -- Transportation Agreement, dated December 15, 1989, by and
between Kern River Gas Transmission Company and Union
Pacific Fuels, Inc. (Exhibit 10.21 to Form S-1)
10.16(b) -- Amendments to Transportation Agreement, dated December
15, 1989, by and between Kern River Gas Transmission
Company and Union Pacific Fuels, Inc. (incorporated
herein by reference to Exhibit 10.16 to the Company's
Annual Report on Form 10-K for the year ended December
31, 1997)
*10.16(c) -- Assignment, dated March 1, 1999 by and between Kern River
Gas Transmission Company, Union Pacific Fuels, Inc. and
Union Pacific Resources Company assigning Transportation
Agreement, dated December 15, 1989, by and between Kern
River Gas Transmission Company and Union Pacific Fuels,
Inc. to Union Pacific Resources Company
</TABLE>
91
<PAGE> 94
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION OF EXHIBIT
------- ----------------------
<C> <S>
10.17 -- Gas Transportation Agreement, dated June 18, 1997, by and
between Union Pacific Fuels, Inc. and Texas Gas
Transmission Corporation (incorporated herein by
reference to Exhibit 10.17 to the Company's Annual Report
on Form 10-K for the year ended December 31, 1997)
10.19 -- Registration Rights Agreement, dated as of August 3,
1995, among Union Pacific Resources Group Inc., The
Anschutz Corporation and Anschutz Foundation
(incorporated herein by reference to Exhibit 10.19 to the
Company's Annual Report on Form 10-K for the year ended
December 31, 1995)
10.20(a) -- Agreement, dated as of August 3, 1995, by and among Union
Pacific Resources Group Inc., The Anschutz Corporation,
Anschutz Foundation and Mr. Philip F. Anschutz (the
"Anschutz Agreement") (incorporated herein by reference
to Exhibit 10.20 to the Company's Annual Report on Form
10-K for the year ended December 31, 1995)
10.20(b) -- Letter agreement, dated as of January 20, 1997, amending
the Anschutz Agreement (incorporated herein by reference
to Exhibit 10.25 to the Company's Annual Report on Form
10-K for the year ended December 31, 1996)
10.21(a) -- U.S. $750,000,000 Five-Year Competitive Advance/Revolving
Credit Agreement, dated as of October 27, 1998, among
Union Pacific Resources Group Inc. and Chase Bank of
Texas, N.A., as administrative agent, The Chase Manhattan
Bank of Canada, as Canadian sub-agent and the banks named
therein (incorporated herein by reference to Exhibit 10.3
to the Company's Quarterly Report on Form 10-Q/A filed
November 12, 1998)
10.21(b) -- U.S. $25,000,000 Revolving Loan Agreement, dated July 14,
1997, between Basic Petroleum International Limited and
Royal Bank of Canada (incorporated herein by reference to
Exhibit 10.33 to the Company's Annual Report on Form 10-K
for the year ended December 31, 1997)
10.21(c) -- U.S. $1,000,000,000 364-day Competitive Advance/Revolving
Credit Agreement, dated as of October 27, 1998, among
Union Pacific Resources Group Inc. and Chase Bank of
Texas, N.A., as administrative agent and the banks named
therein (incorporated herein by reference to Exhibit 10.1
to the Company's Quarterly Report on Form 10-Q/A filed
November 12, 1998)
10.21(d) -- U.S. $750,000,000 364-day Competitive Advance/Revolving
Credit Agreement, dated as of October 27, 1998, among
Union Pacific Resources Group Inc. and Chase Bank of
Texas, N.A., as administrative agent and the banks named
therein (incorporated herein by reference to Exhibit 10.2
to the Company's Quarterly Report on Form 10-Q/A filed
November 12, 1998)
10.22(a) -- Merger and Purchase Agreement, dated November 20, 1998,
among Union Pacific Resources Company, Union Pacific
Fuels, Inc., Duke Energy Field Services, Inc. and DEFS
Merger Sub Corp. (incorporated herein by reference to
Exhibit 10.23(a) to the Company's Annual Report on Form
10-K for the year ended December 31, 1998)
10.22(b) -- Amendment, No. 1, dated February 1, 1999, to Merger and
Purchase Agreement, dated November 20, 1998, among Union
Pacific Resources Company, Union Pacific Fuels, Inc.,
Duke Energy Field Services, Inc. and DEFS Merger Sub
Corp. (incorporated herein by reference to Exhibit
10.23(b) to the Company's Annual Report on Form 10-K for
the year ended December 31, 1998)
</TABLE>
92
<PAGE> 95
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION OF EXHIBIT
------- ----------------------
<C> <S>
10.22(c) -- Amendment No. 2, dated March 5, 1999, to Merger and
Purchase Agreement, dated November 20, 1998, among Union
Pacific Resources Company, Union Pacific Fuels, Inc.,
Duke Energy Services, Inc. and DEFS Merger Sub Corp.
(incorporated herein by reference to Exhibit 10.2 to the
Company's Current Report on Form 8-K filed April 12,
1999)
10.22(d) -- Amendment No. 3, dated March 30, 1999, to Merger and
Purchase Agreement, dated November 20, 1998, among Union
Pacific Resources Company, Union Pacific Fuels, Inc. Duke
Energy Field Services, Inc. and DEFS Merger Sub Corp.
(incorporated herein by reference to Exhibit 10.1 to the
Company's Quarterly Report on Form 10-Q for the period
ended March 31, 1999)
10.22(e) -- Amendment No. 4, dated March 30, 1999, to Merger and
Purchase Agreement, dated November 20, 1998, among Union
Pacific Resources Company, Union Pacific Fuels, Inc.,
Duke Energy Field Services, Inc. and DEFS Merger Sub
Corp. (incorporated herein by reference to Exhibit 10.1
to the Company's Quarterly Report on Form 10-Q) for the
period ended March 31, 1999)
*10.22(f) -- Amendment No. 5, dated May 21, 1999, to Merger and
Purchase Agreement, dated November 20, 1998, among Union
Pacific Resources Company, Union Pacific Fuels, Inc.,
Duke Energy Field Services, Inc. and DEFS Merger Sub
Corp.
*10.22(g) -- Amendment No. 6, dated February 16, 2000, to Merger and
Purchase Agreement, dated November 20, 1998, among Union
Pacific Resources Company, Union Pacific Fuels, Inc.,
Duke Energy Field Services, Inc. and DEFS Merger Sub
Corp.
*10.22(h) -- Master Natural Gas Liquids Purchase Agreement between
Union Pacific Resources Company and Union Pacific Fuels,
Inc., effective January 1, 1999.
*10.22(i) -- Natural Gas Purchase and Sale Agreement between Union
Pacific Resources Company and Union Pacific Fuels, Inc.,
effective January 1, 1999.
*12 -- Computation of ratio of earnings to fixed charges
*21 -- List of subsidiaries
*23.1 -- Consent of Arthur Andersen LLP dated as of March 23,
2000.
*23.2 -- Consent of Deloitte & Touche LLP dated as of March 23,
2000.
*23.3 -- Consent of Arthur Andersen LLP dated as of March 23, 2000
(Black Butte Coal Company Combined Financials Statements)
*24 -- Powers of Attorney for Directors
*27 -- Financial data schedules
*99.1 -- Black Butte Coal Company, A Joint Venture, and R-K
Leasing Company Combined Financial Statements as of
December 31, 1999 and December 26, 1998.
*99.2 -- Black Butte Coal Company, A Joint Venture, and R-K
Leasing Company Combined Financial Statements as of
December 27, 1997.
</TABLE>
(b) Reports on Form 8-K.
On January 28, 2000, the Company filed a Current Report on Form 8-K
announcing the Company's 1999 annual operating results, net income and certain
other financial and statistical information.
On February 17, 2000, the Company filed a Current Report on Form 8-K
updating its January 25, 2000 press release and the January 28, 2000 Current
Report on Form 8-K to include information with respect to reserves at year-end
1999 and finding and development costs for 1999.
93
<PAGE> 96
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 27th day of
March, 2000.
UNION PACIFIC RESOURCES GROUP INC.
By: /s/ MORRIS B. SMITH
---------------------------------------
Morris B. Smith,
Vice President, Chief Financial Officer
and Treasurer
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below, on this 27th day of March, 2000, by the following
persons on behalf of the registrant and in the capacities indicated.
<TABLE>
<S> <C>
/s/ GEORGE LINDAHL III Chairman, Chief Executive Officer and Director
- ----------------------------------------------------- (Principal Executive Officer)
George Lindahl III
/s/ MORRIS B. SMITH Vice President and Chief Financial Officer
- ----------------------------------------------------- (Principal Accounting and Financial Officer)
Morris B. Smith
* Director
- -----------------------------------------------------
H. Jesse Arnelle
* Director
- -----------------------------------------------------
Lynne V. Cheney
* Director
- -----------------------------------------------------
Preston M. Geren III
* Director
- -----------------------------------------------------
Lawrence M. Jones
* Director
- -----------------------------------------------------
Drew Lewis
* Director
- -----------------------------------------------------
Claudine B. Malone
* Director
- -----------------------------------------------------
John W. Poduska, Sr., Ph.D.
* Director
- -----------------------------------------------------
Michael E. Rossi
* Director
- -----------------------------------------------------
Jeff Sandefer
* Director
- -----------------------------------------------------
Samuel K. Skinner
* Director
- -----------------------------------------------------
James R. Thompson
*By: /s/ KATHY L. COX
-----------------------------------------------
(Kathy L. Cox, as attorney-in-fact)
</TABLE>
94
<PAGE> 97
INDEX TO EXHIBITS
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION OF EXHIBIT
------- ----------------------
<C> <S>
2.1 -- Pre-acquisition agreement between Union Pacific Resources
Group Inc., Union Pacific Resources Inc. and Norcen
Energy Resources Limited, dated January 25, 1998
(incorporated herein by reference to Exhibit 2.1 to the
Company's Current Report on Form 8-K, filed on March 17,
1998)
3.1 -- Amended and Restated Articles of Incorporation of Union
Pacific Resources Group Inc. (Exhibit 3.1 to Form S-1 and
Exhibit 3.2 to the Company's Annual Report on Form 10-K
for the year ended December 31, 1996)
*3.2 -- Amended and Restated Bylaws of Union Pacific Resources
Group Inc.
4.1 -- Specimen of Certificate evidencing the Common Stock
(Exhibit 4 to Form S-1)
4.2 -- Amended and Restated Rights Agreement, dated as of
December 1, 1998, between Union Pacific Resources Group
Inc. and Harris Trust and Savings Bank, as rights agent
(incorporated herein by reference to the Exhibit to the
Company's Report on Form 8-A12G/A filed on February 5,
1999)
4.3 -- Indenture, dated as of March 27, 1996, between Union
Pacific Resources Group Inc. and Texas Commerce Bank
National Association, as trustee (incorporated herein by
reference to Exhibit 4.1 to the Company's Form S-3
Registration Statement, Registration No. 333-2984, dated
May 23, 1996)
4.4(a) -- Terms Agreement, dated as of October 10, 1996, for
$200,000,000 7 1/2% Debentures due October 15, 2026
(incorporated herein by reference to Exhibit 4.4 to the
Company's Current Report on Form 8-K filed on March 17,
1998)
4.4(b) -- Form of 7 1/2% Rate Debenture due October 15, 2026
(incorporated herein by reference to Exhibit 4.7 to the
Company's Current Report on Form 8-K filed on March 17,
1998)
4.5(a) -- Terms Agreement, dated as of October 10, 1996, for
$200,000,000 7% Notes due October 15, 2006 (incorporated
herein by reference to Exhibit 4.5 to the Company's
Current Report on Form 8-K filed on March 17, 1998)
4.5(b) -- Form of 7% Rate Note due October 15, 2006 (incorporated
herein by reference to Exhibit 4.8 to the Company's
Current Report on Form 8-K filed on March 17, 1998)
4.6(a) -- Terms Agreement, dated as of October 31, 1996, for
$150,000,000 7 1/2% Debentures due November 1, 2096
(incorporated herein by reference to Exhibit 4.6 to the
Company's Current Report on Form 8-K filed on March 17,
1998)
4.6(b) -- Form of 7 1/2% Rate Note due November 1, 2096
(incorporated herein by reference to Exhibit 4.9 to the
Company's Current Report on Form 8-K filed on March 17,
1998)
4.7 -- Trust Indenture, dated as of May 7, 1996, providing for
the issue of Debt Securities in unlimited principal
amount, between Norcen Energy Resources Limited and
Montreal Trust Company of Canada, as trustee
(incorporated herein by reference to Exhibit 4.10 to the
Company's Current Report on Form 8-K filed on March 17,
1998)
4.8 -- First Supplemental Indenture, dated as of May 22, 1996,
to Trust Indenture dated as of May 7, 1996, providing for
the issue of 7 3/8% Debentures due May 15, 2006, in
aggregate principal amount of U.S. $250,000,000 between
Norcen Energy Resources Limited and Montreal Trust
Company of Canada, as trustee (incorporated herein by
reference to Exhibit 4.11 to the Company's Current Report
on Form 8-K filed on March 17, 1998)
</TABLE>
<PAGE> 98
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION OF EXHIBIT
------- ----------------------
<C> <S>
4.9 -- Second Supplemental Indenture, dated as of June 26, 1996,
to Trust Indenture dated as of May 7, 1996, providing for
the issue of 7.8% Debentures due July 2, 2008, in
aggregate principal amount of U.S. $150,000,000 between
Norcen Energy Resources Limited and Montreal Trust
Company of Canada, as trustee (incorporated herein by
reference to Exhibit 4.12 to the Company's Current Report
on Form 8-K filed on March 17, 1998)
4.10 -- Third Supplemental Indenture, dated as of June 26, 1996,
to Trust Indenture dated as of May 7, 1996, providing for
the issue of 6.8% Debentures due July 2, 2002, in
aggregate principal amount of U.S. $250,000,000 between
Norcen Energy Resources Limited and Montreal Trust
Company of Canada, as trustee (incorporated herein by
reference to Exhibit 4.13 to the Company's Current Report
on Form 8-K filed on March 17, 1998)
4.11 -- Fourth Supplemental Indenture, dated as of February 27,
1998, to Trust Indenture dated as of May 7, 1996,
providing for the Guarantee of all Securities Issued or
Previously Issued under the Trust Indenture between
Norcen Energy Resources Limited, Union Pacific Resources
Group Inc., as guarantor, and Montreal Trust Company of
Canada, as trustee (incorporated herein by reference to
Exhibit 4.14 to the Company's Current Report on Form 8-K
filed on March 17, 1998)
4.12(a) -- Terms Agreement for $200,000,000 6.50% Notes due May 15,
2005 (incorporated herein by reference to Exhibit 4.1 to
the Company's Current Report on Form 8-K filed on May 26,
1998)
4.12(b) -- Form of 6.50% Note due May 15, 2005 (incorporated herein
by reference to Exhibit 4.5 to the Company's Current
Report on Form 8-K filed on May 26, 1998)
4.13(a) -- Terms Agreement for $200,000,000 6.75% Notes due May 15,
2008 (incorporated herein by reference to Exhibit 4.2 to
the Company's Current Report on Form 8-K filed on May 26,
1998)
4.13(b) -- Form of 6.75% Note due May 15, 2008 (incorporated herein
by reference to Exhibit 4.6 to the Company's Current
Report on Form 8-K filed on May 26, 1998)
4.14(a) -- Terms Agreement for $200,000,000 7.05% Notes due May 15,
2018 (incorporated herein by reference to Exhibit 4.3 to
the Company's Current Report on Form 8-K filed on May 26,
1998)
4.14(b) -- Form of 7.05% Debenture due May 15, 2018 (incorporated
herein by reference to Exhibit 4.7 to the Company's
Current Report on Form 8-K filed on May 26, 1998)
4.15(a) -- Terms Agreement for $425,000,000 7.15% Notes due May 15,
2028 (incorporated herein by reference to Exhibit 4.4 to
the Company's Current Report on Form 8-K filed on May 26,
1998)
4.15(b) -- Form of 7.15% Debenture due May 15, 2028 (incorporated
herein by reference to Exhibit 4.8 to the Company's
Current Report on Form 8-K filed on May 26, 1998)
4.16(a) -- Terms Agreement for $200,000,000 7.30% Notes due April
15, 2009 (incorporated herein by reference to Exhibit 1.2
to the Company's Current Report on Form 8-K filed on
April 12, 1999)
4.16(b) -- Form of 7.30% Note due April 15, 2009 (incorporated
herein by reference to Exhibit 4.2 to the Company's
Current Report on Form 8-K filed on April 14, 1999)
4.17(a) -- Terms Agreement for $300,000.000 7.95% Debentures due
April 15, 2029 (incorporated herein by reference to
Exhibit 1.2 to the Company's Current Report on Form 8-K
filed on April 12, 1999)
4.17(b) -- Form of 7.95% Debenture due April 15, 2029 ($200 million)
(incorporated herein by reference to Exhibit 4.3 to the
Company's Current Report on Form 8-K filed on April 14,
1999)
</TABLE>
<PAGE> 99
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION OF EXHIBIT
------- ----------------------
<C> <S>
4.17(c) -- Form of 7.95% Debenture due April 15, 2029 ($100 million)
(incorporated herein by reference to Exhibit 4.4 to the
Company's Current Report on Form 8-K filed on April 14,
1999)
4.18 -- Indenture, dated as of April 13, 1999, between Union
Pacific Resources Group Inc., Union Pacific Resources
Inc., UPR Capital Company and The Bank of New York as
trustee (incorporated herein by reference to Exhibit 4.1
to the Company's Current Report on Form 8-K filed on
April 14, 1999)
10.1 -- Tax Allocation Agreement, dated October 6, 1995 (Exhibit
10.3 to Form S-1)
10.2 -- Indemnification Agreement, dated October 1, 1995 (Exhibit
10.4 to Form S-1)
10.3 -- Pension Plan Agreement, dated October 1, 1995, by and
between Union Pacific Corporation and Union Pacific
Resources Group Inc. (Exhibit 10.7 to Form S-1)
10.4 -- The Supplemental Pension Plan for Officers and Managers
of Union Pacific Corporation and Affiliates, with
amendments (incorporated herein by reference to Exhibit
10.11 to the Company's Annual Report on Form 10-K for the
year ended December 31, 1995)
10.5 -- The Supplemental Pension Plan for Exempt Salaried
Employees of Union Pacific Resources Company and
Affiliates, with amendments (incorporated herein by
reference to Exhibit 10.12 to the Company's Annual Report
on Form 10-K for the year ended December 31, 1995)
10.6 -- Executive Incentive Plan of Union Pacific Resources Group
Inc. as amended and restated June 1, 1997 (incorporated
herein by reference to Exhibit 10.2 to the Company's
Quarterly Report on Form 10-Q for the period ended March
31, 1997)
*10.7 -- 1995 Stock Option and Retention Stock Plan of Union
Pacific Resources Group Inc. as amended and restated,
effective December 7, 1999.
10.8(a) -- 1995 Directors Stock Incentive Plan, as amended and
restated, effective July 14, 1998 (incorporated herein by
reference to Exhibit 10.8(a) to the Company's Annual
Report on Form 10-K for the year ended December 31, 1998)
10.8(b) -- First Amendment, effective January 21, 1999, to 1995
Directors Stock Incentive Plan, as amended and restated,
effective July 14, 1998 (incorporated herein by reference
to Exhibit 10.8(b) to the Company's Annual Report on Form
10-K for the year ended December 31, 1998)
10.8(c) -- Second Amendment, effective May 18, 1999, to 1995
Directors Stock Incentive Plan, as amended and restated,
effective July 14, 1998 (incorporated by reference to
Exhibit 10.2 to the Company's Quarterly Report on Form
10-Q for the period ended June 30, 1999)
10.9 -- Union Pacific Resources Group Inc. Deferred Compensation
Plan for the Board of Directors, as amended and restated,
effective September 5, 1997 (incorporated herein by
reference to Exhibit 99.2 to the Company's Registration
Statement on Form S-8, dated September 15, 1997)
10.10 -- Union Pacific Resources Group Inc. Executive Deferred
Compensation Plan, effective September 5, 1997
(incorporated herein by reference to Exhibit 99.1 to the
Company's Registration Statement on Form S-8, dated
September 15, 1997)
10.11(a) -- Union Pacific Resources Group Inc. Executive Life
Insurance Plan, adopted February 26, 1997 (incorporated
herein by reference to Exhibit 10.16 to the Company's
Annual Report on Form 10-K for the year ended December
31, 1996)
*10.11(b) -- Description of Amendment, adopted December 6, 1999, to
the Union Pacific Resources Group Inc. Executive Life
Insurance Plan, adopted February 26, 1997.
</TABLE>
<PAGE> 100
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION OF EXHIBIT
------- ----------------------
<C> <S>
10.12(a) -- Form of Agreement relating to Change in Control by and
between Union Pacific Resources Group Inc. and George
Lindahl III dated October 21, 1999, superseding and
replacing the agreement dated February 4, 1997
(incorporated herein by reference to Exhibit 10.1 to the
Company's Quarterly Report on Form 10-Q for the period
ended September 30, 1999)
10.12(b) -- Form of Agreement relating to Change in Control by and
between Union Pacific Resources Group Inc. and each of
Anne M. Franklin, Donald W. Niemiec, Morris B. Smith,
John B. Vering and Joseph A. LaSala, Jr., dated February
4, 1997 (incorporated herein by reference to Exhibit
10.17(c) to the Company's Annual Report on Form 10-K for
the year ended December 31, 1996)
10.12(c) -- Form of Agreement relating to Change in Control by and
between Union Pacific Resources Group Inc. and Thomas R.
Blank, dated July 13, 1998 (incorporated herein by
reference to Exhibit 10.4 to the Company's Quarterly
Report on Form 10-Q/A filed November 12, 1998)
10.12(d) -- Form of Amendment, dated as of January 21, 1999, to
Change in Control Agreements between Union Pacific
Resources Group Inc. and Anne M. Franklin, Donald W.
Niemiec, Morris B. Smith, John B. Vering, Jack L.
Messman, V. Richard Eales and Joseph A. LaSala, Jr., all
dated February 4, 1997, and between Union Pacific
Resources Group Inc. and Thomas R. Blank dated July 13,
1998 (incorporated herein by reference to Exhibit
10.13(e) to the Company's Annual Report on Form 10-K for
the year ended December 31, 1998)
*10.12(e) -- Form of Agreement relating to Change in Control by and
between Union Pacific Resources Group Inc. and Kerry R.
Brittain, dated March 18, 1999.
*10.12(f) -- Form of Amendment, dated as of March 30, 1999, to Change
in Control Agreement between Union Pacific Resources
Group Inc. and Kerry R. Brittain, dated March 18, 1999.
10.12(g) -- Form of Agreement relating to Change in Control by and
between Union Pacific Resources Group Inc. and Jack L.
Messman, dated February 4, 1997 (incorporated herein by
reference to Exhibit 10.17(a) to the Company's Annual
Report on Form 10-K for the year ended December 31, 1996)
10.12(h) -- Form of Agreement relating to Change in Control by and
between Union Pacific Resources Group Inc. and V. Richard
Eales, dated February 7, 1997 (incorporated herein by
reference to Exhibit 10.17(b) to the Company's Annual
Report on From 10-K for the year ended December 31, 1996)
10.13 -- Settlement and Release Agreement by and between Union
Pacific Resources Group Inc. and V. Richard Eales,
effective September 1, 1999 (incorporated herein by
reference to Exhibit 10.2 to the Company's Quarterly
Report on Form 10-Q for the period ended September 30,
1999)
10.14(a) -- Conversion Agreement (Exhibit 10.13(a) to Form S-1)
10.14(b) -- Conversion Agreement for Drew Lewis (Exhibit 10.13(b) to
Form S-1)
10.15(a) -- Amended and Restated 1976 Coal Purchase Contract, dated
as of January 1, 1993, between Commonwealth Edison
Company and Black Butte Coal Company (Exhibit 10.19 to
Form S-1)
10.15(b) -- Amendment No. 1 to Amended and Restated 1976 Coal
Purchase Contract between Commonwealth Edison Company and
Black Butte Coal Company, effective as of January 1, 1996
(incorporated herein by reference to Exhibit 10.35 to the
Company's Annual Report on Form 10-K for the year ended
December 31, 1997)
</TABLE>
<PAGE> 101
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION OF EXHIBIT
------- ----------------------
<C> <S>
10.15(c) -- Amendment No. 2 to Amended and Restated 1976 Coal
Purchase Contract between Commonwealth Edison Company and
Black Butte Coal Company, effective as of January 1, 1997
(incorporated herein by reference to Exhibit 10.36 to the
Company's Annual Report on Form 10-K for the year ended
December 31, 1997)
10.16(a) -- Transportation Agreement, dated December 15, 1989, by and
between Kern River Gas Transmission Company and Union
Pacific Fuels, Inc. (Exhibit 10.21 to Form S-1)
10.16(b) -- Amendments to Transportation Agreement, dated December
15, 1989, by and between Kern River Gas Transmission
Company and Union Pacific Fuels, Inc. (incorporated
herein by reference to Exhibit 10.16 to the Company's
Annual Report on Form 10-K for the year ended December
31, 1997)
*10.16(c) -- Assignment, dated March 1, 1999 by and between Kern River
Gas Transmission Company, Union Pacific Fuels, Inc. and
Union Pacific Resources Company assigning Transportation
Agreement, dated December 15, 1989, by and between Kern
River Gas Transmission Company and Union Pacific Fuels,
Inc. to Union Pacific Resources Company
10.17 -- Gas Transportation Agreement, dated June 18, 1997, by and
between Union Pacific Fuels, Inc. and Texas Gas
Transmission Corporation (incorporated herein by
reference to Exhibit 10.17 to the Company's Annual Report
on Form 10-K for the year ended December 31, 1997)
10.19 -- Registration Rights Agreement, dated as of August 3,
1995, among Union Pacific Resources Group Inc., The
Anschutz Corporation and Anschutz Foundation
(incorporated herein by reference to Exhibit 10.19 to the
Company's Annual Report on Form 10-K for the year ended
December 31, 1995)
10.20(a) -- Agreement, dated as of August 3, 1995, by and among Union
Pacific Resources Group Inc., The Anschutz Corporation,
Anschutz Foundation and Mr. Philip F. Anschutz (the
"Anschutz Agreement") (incorporated herein by reference
to Exhibit 10.20 to the Company's Annual Report on Form
10-K for the year ended December 31, 1995)
10.20(b) -- Letter agreement, dated as of January 20, 1997, amending
the Anschutz Agreement (incorporated herein by reference
to Exhibit 10.25 to the Company's Annual Report on Form
10-K for the year ended December 31, 1996)
10.21(a) -- U.S. $750,000,000 Five-Year Competitive Advance/Revolving
Credit Agreement, dated as of October 27, 1998, among
Union Pacific Resources Group Inc. and Chase Bank of
Texas, N.A., as administrative agent, The Chase Manhattan
Bank of Canada, as Canadian sub-agent and the banks named
therein (incorporated herein by reference to Exhibit 10.3
to the Company's Quarterly Report on Form 10-Q/A filed
November 12, 1998)
10.21(b) -- U.S. $25,000,000 Revolving Loan Agreement, dated July 14,
1997, between Basic Petroleum International Limited and
Royal Bank of Canada (incorporated herein by reference to
Exhibit 10.33 to the Company's Annual Report on Form 10-K
for the year ended December 31, 1997)
10.21(c) -- U.S. $1,000,000,000 364-day Competitive Advance/Revolving
Credit Agreement, dated as of October 27, 1998, among
Union Pacific Resources Group Inc. and Chase Bank of
Texas, N.A., as administrative agent and the banks named
therein (incorporated herein by reference to Exhibit 10.1
to the Company's Quarterly Report on Form 10-Q/A filed
November 12, 1998)
</TABLE>
<PAGE> 102
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION OF EXHIBIT
------- ----------------------
<C> <S>
10.21(d) -- U.S. $750,000,000 364-day Competitive Advance/Revolving
Credit Agreement, dated as of October 27, 1998, among
Union Pacific Resources Group Inc. and Chase Bank of
Texas, N.A., as administrative agent and the banks named
therein (incorporated herein by reference to Exhibit 10.2
to the Company's Quarterly Report on Form 10-Q/A filed
November 12, 1998)
10.22(a) -- Merger and Purchase Agreement, dated November 20, 1998,
among Union Pacific Resources Company, Union Pacific
Fuels, Inc., Duke Energy Field Services, Inc. and DEFS
Merger Sub Corp. (incorporated herein by reference to
Exhibit 10.23(a) to the Company's Annual Report on Form
10-K for the year ended December 31, 1998)
10.22(b) -- Amendment, No. 1, dated February 1, 1999, to Merger and
Purchase Agreement, dated November 20, 1998, among Union
Pacific Resources Company, Union Pacific Fuels, Inc.,
Duke Energy Field Services, Inc. and DEFS Merger Sub
Corp. (incorporated herein by reference to Exhibit
10.23(b) to the Company's Annual Report on Form 10-K for
the year ended December 31, 1998)
10.22(c) -- Amendment No. 2, dated March 5, 1999, to Merger and
Purchase Agreement, dated November 20, 1998, among Union
Pacific Resources Company, Union Pacific Fuels, Inc.,
Duke Energy Services, Inc. and DEFS Merger Sub Corp.
(incorporated herein by reference to Exhibit 10.2 to the
Company's Current Report on Form 8-K filed April 12,
1999)
10.22(d) -- Amendment No. 3, dated March 30, 1999, to Merger and
Purchase Agreement, dated November 20, 1998, among Union
Pacific Resources Company, Union Pacific Fuels, Inc. Duke
Energy Field Services, Inc. and DEFS Merger Sub Corp.
(incorporated by reference to Exhibit 10.1 to the
Company's Quarterly Report on Form 10-Q for the period
ended March 31, 1999)
10.22(e) -- Amendment No. 4, dated March 30, 1999, to Merger and
Purchase Agreement, dated November 20, 1998, among Union
Pacific Resources Company, Union Pacific Fuels, Inc.,
Duke Energy Field Services, Inc. and DEFS Merger Sub
Corp. (incorporated by reference to Exhibit 10.1 to the
Company's Quarterly Report on Form 10-Q for the period
ended March 31, 1999)
*10.22(f) -- Amendment No. 5, dated May 21, 1999, to Merger and
Purchase Agreement, dated November 20, 1998, among Union
Pacific Resources Company, Union Pacific Fuels, Inc.,
Duke Energy Field Services, Inc. and DEFS Merger Sub
Corp.
*10.22(g) -- Amendment No. 6, dated February 16, 2000, to Merger and
Purchase Agreement, dated November 20, 1998, among Union
Pacific Resources Company, Union Pacific Fuels, Inc.,
Duke Energy Field Services, Inc. and DEFS Merger Sub
Corp.
*10.22(h) -- Master Natural Gas Liquids Purchase Agreement between
Union Pacific Resources Company and Union Pacific Fuels,
Inc., effective January 1, 1999.
*10.22(i) -- Natural Gas Purchase and Sale Agreement between Union
Pacific Resources Company and Union Pacific Fuels, Inc.,
effective January 1, 1999
*12 -- Computation of ratio of earnings to fixed charges
*21 -- List of subsidiaries
*23.1 -- Consent of Arthur Andersen LLP dated as of March 23, 2000
*23.2 -- Consent of Deloitte & Touche LLP dated as of March 23,
2000
*23.3 -- Consent of Arthur Andersen LLP dated as of March 23, 2000
(Black Butte Coal Company Combined Financial Statements)
*24 -- Powers of Attorney for Directors
*27 -- Financial data schedules
</TABLE>
<PAGE> 103
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION OF EXHIBIT
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<C> <S>
*99.1 -- Black Butte Coal Company, A Joint Venture, and R-K
Leasing Company Combined Financial Statements as of
December 31, 1999 and December 26, 1998
*99.2 -- Black Butte Coal Company, A Joint Venture, and R-K
Leasing Company Combined Financial Statements as of
December 27, 1997
</TABLE>
<PAGE> 1
EXHIBIT 3.2
AMENDED AND RESTATED BYLAWS
OF
UNION PACIFIC RESOURCES GROUP INC.
ARTICLE 1. OFFICES
1.1 Business Offices. The corporation may have such offices, either
within or without Utah, as the board of directors may designate or as the
business of the corporation may require from time to time.
1.2 Registered Office. The registered office of the corporation
required to be kept by the Utah Revised Business Corporation Act (the "Act")
shall be located within the State of Utah. The address of the registered office
may be changed from time to time.
ARTICLE 2. SHAREHOLDERS
2.1 Annual Meeting. The annual meeting of the shareholders shall be
held at such date and time as shall be fixed by the board of directors, for the
purpose of electing directors and for the transaction of such other business as
may come before the meeting.
2.2 Special Meetings. Special meetings of the shareholders, for any
purpose or purposes described in the meeting notice, may be called by (a) the
board of directors, (b) the chairman of the board of directors, (c) any person,
if authorized by resolution adopted by a majority of the entire board of
directors, (d) so long as Union Pacific Corporation beneficially owns (within
the meaning of Rule 13d-3 under the Securities Exchange Act of 1934, as amended
(the "Exchange Act")) more than 50% of the voting power of all of the shares of
the corporation entitled to vote generally in the election of directors, by
Union Pacific, and (e) any other person who, at such time, is authorized by the
Act to call a special meeting of shareholders. A request by a shareholder for a
special meeting, other than a request pursuant to section 2.2(d), must be
accompanied by a statement of purposes which includes at least the information
set out in clauses (i) through (vi) of section 2.8(e) of these bylaws.
2.3 Place of Meeting. The board of directors may designate any place,
either within or without the State of Utah, as the place of meeting for any
annual or any special meeting of the shareholders.
Adopted December 7, 1999
1
<PAGE> 2
2.4 Notice of Meeting.
(a) Content and Mailings Requirements. Written notice stating the
date, time and place of each annual or special shareholder meeting shall be
delivered no fewer than 10 nor more than 60 days before the date of the meeting,
either personally or by mail, by or at the direction of the president or the
board of directors, to each shareholder of record entitled to vote at such
meeting and to any other shareholder entitled by the Act or the articles of
incorporation to receive notice of the meeting. Notice of special shareholder
meetings shall include a description of the purpose or purposes for which the
meeting is called.
(b) Effective Date. Written notice shall be deemed to be effective
when mailed, if addressed to the shareholder's address shown in the
corporation's current record of shareholders or, if delivered personally, when
received.
(c) Effect of Adjournment. If any shareholder meeting is adjourned
to a different date, time or place, notice need not be given of the new date,
time and place, if the new date, time and place is announced at the meeting
before adjournment, unless the adjournment is for more than 30 days or if a new
record date for the adjourned meeting is or must be fixed.
2.5 Waiver of Notice.
(a) Written Waiver. A shareholder may waive any notice required by
the Act, the articles of incorporation or the bylaws, by a writing signed by the
shareholder entitled to the notice, which is delivered to the corporation
(either before or after the date and time stated in the notice) for inclusion in
the minutes or filing with the corporate records.
(b) Attendance at Meetings. A shareholder's attendance at a
meeting: (i) waives objection to lack of notice or defective notice of the
meeting, unless the shareholder at the beginning of the meeting objects to
holding the meeting or transacting business at the meeting because of lack of
notice or effective notice; and (ii) waives objection to consideration of a
particular matter at the meeting that is not within the purpose or purposes
described in the meeting notice, unless the shareholder objects to considering
the matter when it is presented.
2.6 Record Date.
(a) Fixing of Record Date. For the purpose of determining
shareholders entitled to notice of or to vote at any meeting of shareholders, or
shareholders entitled to receive payment of any distribution, or in order to
make a determination of shareholders for any other proper purpose, the board of
directors may fix in advance a date as the record date. Such record date shall
not be more than 70 days prior to the date on which the particular action
requiring such determination of shareholders is to be taken. If no record date
is so fixed by the board for the determination of shareholders entitled to
notice of, or to vote at, a meeting of shareholders, the record date for
determination of such shareholders shall be at the close of business on the day
before the first notice
2
<PAGE> 3
is delivered to shareholders. If no record date is fixed by the board for the
determination of shareholders entitled to receive a distribution, the record
date shall be the date the board authorizes the distribution.
(b) Effect of Adjournment. When a determination of shareholders
entitled to vote at any meeting of shareholders has been made as provided in
this section, such determination shall apply to any adjournment thereof unless
the board of directors fixes a new record date, which it must do if the meeting
is adjourned to a date more than 120 days after the date fixed for the original
meeting.
2.7 Shareholder List. After fixing a record date for a shareholders'
meeting, the corporation shall prepare a list of the names of its shareholders
entitled to be given notice of the meeting. The list must be arranged by voting
group and within each voting group by class or series of shares, must be
alphabetical within each class or series, and must show the address of, and the
number of shares held by, each shareholder. The shareholder list must be
available for inspection by any shareholder, beginning on the earlier of ten
days before the meeting for which the list was prepared or two business days
after notice of the meeting is given for which the list was prepared and
continuing through the meeting and any adjournment thereof. The list shall be
available at the corporation's principal office or at a place identified in the
meeting notice in the city where the meeting will be held.
2.8 Nature of Business.
(a) At any annual meeting of shareholders, only such business shall
be conducted as shall have been brought before the meeting (i) by or at the
direction of the board of directors or (ii) by any shareholder who complies with
the procedures set forth in this section 2.8.
(b) No business may be transacted at any annual meeting of
shareholders, other than business that is either (i) specified in the notice of
meeting (or any supplement thereto) given pursuant to section 2.4 of these
bylaws, (ii) otherwise properly brought before such meeting of shareholders by
or at the direction of the board of directors (or any duly authorized committee
thereof), (iii) so long as Union Pacific Corporation beneficially owns (within
the meaning of Rule 13d-3 under the Exchange Act) more than 50% of the voting
power of all of the shares of the corporation entitled to vote generally in the
election of directors, otherwise properly brought before such meeting by or at
the direction of Union Pacific, or (iv) otherwise properly brought before such
meeting by any shareholder (A) who is a shareholder of record on the date of the
giving of the notice provided for in this section 2.8 and on the record date for
the determination of shareholders entitled to vote at such annual meeting of
shareholders and (B) who complies with the notice procedures set forth in this
section 2.8.
(c) No business may be transacted at any special meeting of
shareholders, other than business that is specified in the notice of meeting (or
any supplement thereto) given pursuant to section 2.4 of these bylaws.
3
<PAGE> 4
(d) In addition to any other applicable requirements, for business
to be properly brought before a meeting of shareholders by a shareholder
pursuant to clause (iv) of section 2.8(b) such shareholder must have given
timely notice thereof in proper written form to the secretary of the
corporation. To be timely, a shareholder's notice to the secretary of the
corporation pursuant to clause (iv) of section 2.8(b) must be delivered to or
mailed and received at the principal executive offices of the corporation not
less than sixty (60) days nor more than ninety (90) days prior to the
anniversary date of the immediately preceding annual meeting of shareholders;
provided, however, that in the event that the annual meeting of shareholders is
called for a date that is not within thirty (30) days before or after such
anniversary date, notice by the shareholder in order to be timely must be so
received not later than the close of business on the tenth (10th) day following
the day on which notice of the date of the annual meeting of shareholders was
mailed or public disclosure of the date of the meeting of shareholders was made,
whichever first occurs.
(e) To be in proper written form, a shareholder's notice to the
secretary of the corporation pursuant to clause (iv) of section 2.8(b) must set
forth as to each matter such shareholder proposes to bring before the annual
meeting of shareholders (i) a brief description of the business desired to be
brought before the meeting of shareholders and the reasons for conducting such
business at such meeting of shareholders, (ii) the name and record address of
such shareholder, (iii) the class or series and number of shares of capital
stock of the corporation which are owned beneficially or of record by such
shareholder as of the record date for the meeting (if such date shall then have
been made publicly available and shall have occurred) and as of the date of such
notice, (iv) a description of all arrangements or understandings between such
shareholder and any other person or persons (including their names) in
connection with the proposal of such business by such shareholder and any
material interest of such shareholder in such business, (v) any other
information which would be required to be disclosed in a proxy statement or
other filings required to be made in connection with the solicitation of proxies
for the proposal pursuant to Section 14 of the Exchange Act, and the rules and
regulations promulgated thereunder if such shareholder were engaged in such a
solicitation, and (vi) a representation that such shareholder intends to appear
in person or by proxy at the meeting of shareholders to bring such business
before the meeting.
(f) No business shall be conducted at the annual meeting of
shareholders except business brought before the meeting of shareholders in
accordance with the procedures set forth in this section 2.8, provided, however,
that, once business has been properly brought before the meeting of shareholders
in accordance with such procedures, nothing in this section 2.8 shall be deemed
to preclude discussion by any shareholder of any such business.
(g) If the chairman of a meeting of shareholders determines that
business was not properly brought before a meeting of shareholders, the chairman
shall declare to the meeting that the business was not properly brought before
the meeting and such business shall not be transacted.
4
<PAGE> 5
2.9 Shareholder Quorum and Voting Requirements.
(a) Quorum. Shares entitled to vote as a voting group may take
action on a matter at a meeting only if a quorum of those shares exists with
respect to that matter. Unless the articles of incorporation or the Act provide
otherwise, a majority of the votes entitled to be cast on the matter by the
voting group, represented in person or by proxy, constitutes a quorum of that
voting group for action on that matter. If, however, such quorum shall not be
present or represented at any meeting of the shareholders, the shareholders
entitled to vote thereat, present in person or represented by proxy, shall have
power to adjourn the meeting from time to time, without notice other than
announcement at the meeting, until a quorum shall be present or represented.
Once a share is represented for any purpose at a meeting, it is deemed present
for quorum purposes for the remainder of the meeting and for any adjournment of
that meeting unless a new record date is or must be set for that adjourned
meeting.
(b) Voting Groups. If the articles of incorporation or the Act
provide for voting by a single voting group on a matter, action on that matter
is taken when voted upon by that voting group. If the articles of incorporation
or the Act provide for voting by two or more voting groups on a matter, action
on that matter is taken only when voted upon by each of those voting groups
counted separately. Action may be taken by one voting group on a matter even
though no action is taken by another voting group entitled to vote on the
matter.
(c) Shareholder Action. If a quorum exists, action on a matter,
other than the election of directors, by a voting group is approved if the votes
cast within the voting group favoring the action exceed the votes cast opposing
the action, unless the articles of incorporation or the Act require a greater
number of affirmative votes. Directors are elected by a plurality of the votes
cast by the shares entitled to vote in the election at a meeting at which a
quorum is present.
2.10 Proxies. At all meetings of the shareholders, a shareholder may
vote in person or by a proxy which is (a) executed in writing by the
shareholder, (b) executed in writing by the shareholder's duly authorized
attorney in fact, or (c) transmitted by telegram, teletype, electronically or
any other means, if and to the extent permitted by law. Such proxy shall be
filed with, or transmitted to, the secretary of the corporation or other person
authorized to tabulate votes before or at the time of the meeting. No proxy
shall be valid after 11 months from the date of its execution or transmission
unless otherwise provided in the proxy.
2.11 Voting of Shares. Except as provided by specific court order, no
shares of the corporation owned, directly or indirectly, by a second
corporation, domestic or foreign, shall be voted at any meeting or counted in
determining the total number of outstanding shares at any given time for
purposes of any meeting if a majority of the shares entitled to vote for the
election of directors of such second corporation are held by the corporation.
The prior sentence shall not limit the power of the corporation to vote any
shares, including its own shares, held by it in a fiduciary capacity.
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2.12 No Participation in Meetings by Telecommunication. No shareholder
may participate in an annual or special meeting by means of telecommunication. A
shareholder may participate in a meeting only if present in person or by proxy.
2.13 Action Without a Meeting. At such time as Union Pacific
Corporation no longer beneficially owns (within the meaning of Rule 13d-3 under
the Exchange Act) more than 50% of the voting power of all of the shares of the
corporation entitled to vote generally in the election of directors, subject to
the rights of the holders of any series of Preferred Stock then outstanding, any
action required or permitted to be taken by the shareholders of the corporation
must be effected at a duly called annual or special meeting of shareholders of
the corporation and may not be effected by any consent in writing by such
shareholders unless all of the shareholders entitled to vote thereon consent
thereto in writing. Prior to the time Union Pacific Corporation no longer
beneficially owns (within the meaning of Rule 13d-3 under the Exchange Act) more
than 50% of the voting power of all of the shares of the corporation entitled to
vote generally in the election of directors, the shareholders may act by consent
in writing to the extent and in the manner provided by law.
2.14 Nominations of Director Candidates.
(a) Subject to the rights of the holders of any series of Preferred
Stock then outstanding, only persons who are nominated in accordance with the
following procedures shall be eligible for election as directors of the
corporation. Nominations of persons for election to the board of directors may
be made at any annual meeting of shareholders, or at any special meeting of
shareholders called for the purpose of electing directors, (i) by or at the
direction of the board of directors (or any duly authorized committee thereof),
(ii) so long as Union Pacific Corporation beneficially owns (within the meaning
of Rule 13d-3 under the Exchange Act) more than 50% of the voting power of all
of the shares of the corporation entitled to vote generally in the election of
directors, by Union Pacific or (iii) by any shareholder of the corporation (A)
who is a shareholder of record on the date of the giving of the notice provided
for in this section 2.14 and on the record date for the determination of
shareholders entitled to vote at such meeting and (B) who complies with the
notice procedures set forth in this section 2.14.
(b) In addition to any other applicable requirements for a
nomination to be made by a shareholder pursuant to clause (iii) of section
2.14(a), such shareholder must have given timely notice thereof in proper
written form to the secretary of the corporation.
(c) To be timely, a shareholder's notice to the secretary of the
corporation pursuant to clause (iii) of the first paragraph of section 2.14(a)
must be delivered to or mailed and received at the principal executive offices
of the corporation (i) in the case of an annual meeting of shareholders, not
less than sixty (60) days nor more than ninety (90) days prior to the
anniversary date of the immediately preceding annual meeting of shareholders,
provided, however, that in the event that the annual meeting of shareholders is
called for a date that is not within thirty (30) days before or after such
anniversary date, notice by the shareholder in order to be timely must be so
received not later than the close of business on the tenth (10th) day following
the day on which notice of the date of
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the annual meeting of shareholders was mailed or public disclosure of the date
of the annual meeting was made, whichever first occurs, and (ii) in the case of
a special meeting of shareholders called for the purpose of electing directors,
not later than the close of business on the tenth (10th) day following the day
on which notice of the date of the special meeting of shareholders was mailed or
public disclosure of the date of the special meeting of shareholders was made,
whichever first occurs.
(d) To be in proper written form, a shareholder's notice to the
secretary of the corporation pursuant to clause (iii) of section 2.14(a) must
set forth (i) as to each person whom the shareholder proposes to nominate for
election as a director (A) the name, age, business address and residence address
of the person, (B) the principal occupation or employment of the person, (C) the
class or series and number of shares of capital stock of the corporation which
are owned beneficially or of record by the person as of the record date for the
meeting (if such date shall then have been made publicly available and shall
have occurred) and as of the date of such notice and (D) any other information
relating to the person that would be required to be disclosed in a proxy
statement or other filings required to be made in connection with solicitations
of proxies for election of directors pursuant to Section 14 of the Exchange Act,
and the rules and regulations promulgated thereunder; and (ii) as to the
shareholder giving the notice (A) the name and record address of such
shareholder, (B) the class or series and number of shares of capital stock of
the corporation which are owned beneficially or of record by such shareholder as
of the record date for the meeting (if such date shall then have been made
publicly available and shall have occurred) and as of the date of such notice,
(C) a description of all arrangements or understandings between such shareholder
and each proposed nominee and any other person or persons (including their
names) pursuant to which the nominations are to be made by such shareholder, (D)
a representation that such shareholder intends to appear in person or by proxy
at the meeting to nominate the persons named in its notice and (E) any other
information relating to such shareholder that would be required to be disclosed
in a proxy statement or other filings required to be made in connection with
solicitations of proxies for election of directors pursuant to section 14 of the
Exchange Act and the rules and regulations promulgated thereunder. Such notice
must be accompanied by a written consent of each proposed nominee to being named
as a nominee and to serve as a director if elected.
(e) No person shall be eligible for election as a director of the
corporation unless nominated in accordance with the procedures set forth in this
section 2.14. If the chairman of the meeting determines that a nomination was
not made in accordance with the foregoing procedures, the chairman shall declare
to the meeting that the nomination was defective and such defective nomination
shall be disregarded.
2.15 Organization. Meetings of shareholders shall be presided over by
the chairman of the board, or in his or her absence by the president, or in
their absence by a chairman chosen at the meeting. The secretary, or in the
absence of the secretary, an assistant secretary, shall act as secretary of the
meeting, but in the absence of the secretary and any assistant secretary the
chairman of the meeting may appoint any person to act as secretary of the
meeting.
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2.16 Adjournment. Any meeting of shareholders, annual or special, may
adjourn from time to time to reconvene at the same or some other place. At the
adjourned meeting the corporation may transact any business which might have
been transacted at the original meeting.
ARTICLE 3. BOARD OF DIRECTORS
3.1 General Powers. All corporate powers shall be exercised by or under
the authority of, and the business and affairs of the corporation shall be
managed under the direction of, the board of directors.
3.2 Number, Tenure and Qualifications. The number of directors of the
corporation shall be not less than five nor more than fifteen. The exact number
of directors within the minimum and maximum limitations specified in the
preceding sentence shall be fixed from time to time by either (a) the board of
directors pursuant to a resolution adopted by a majority of the entire board of
directors or (b) the affirmative vote of the holders of at least 80% of the
voting power of all of the shares of the corporation entitled to vote generally
in the election of directors voting together as a single class. Each director
shall hold office until the next annual meeting of shareholders or until the
director's earlier death, resignation or removal. However, if a director's term
expires, the director shall continue to serve until his or her successor shall
have been elected and qualified, or until there is a decrease in the number of
directors. Directors do not need to be residents of Utah or shareholders of the
corporation. No decrease in the number of directors constituting the board of
directors shall shorten the term of any incumbent director.
3.3 Regular Meetings. The board of directors may provide, by
resolution, the time and place for the holding of regular meetings without other
notice than such resolution.
3.4 Special Meetings. Special meetings of the board of directors may be
called by or at the request of the chairman of the board, the president or any
two directors. The person authorized to call special meetings of the board of
directors may fix any place as the place for holding any special meeting of the
board of directors.
3.5 Notice of Special Meetings. Notice of the date, time and place of
any special director meeting shall be given either orally or in writing. Such
notice may be given at any time prior to the commencement of the meeting. The
person giving such notice shall give such notice as far in advance of the
meeting as such person reasonably believes to be appropriate under the
circumstances. Oral notice shall be effective when communicated in a
comprehensible manner. Written notice is effective as to each director at the
earlier of: (a) when received; (b) five days after deposited in the United
States mail, addressed to the director's address shown in the records of the
corporation; or (c) the date shown on the return receipt if sent by registered
or certified mail, return receipt requested, and the receipt is signed by or on
behalf of the director. Any director may waive notice of any meeting before or
after the date and time of the meeting stated in the notice. Except as provided
in the next sentence, the waiver must be in writing and signed by the director
entitled to the notice. A director's
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attendance at or participation in a meeting shall constitute a waiver of notice
of such meeting, unless the director at the beginning of the meeting, or
promptly upon his or her arrival, objects to holding the meeting or transacting
business at the meeting because of lack of or defective notice, and does not
thereafter vote for or assent to action taken at the meeting. Unless required by
the articles of incorporation, neither the business to be transacted at, nor the
purpose of, any special meeting of the board of directors need be specified in
the notice or waiver of notice of such meeting.
3.6 Quorum and Voting.
(a) Quorum. A majority of the number of directors prescribed by
resolution adopted or vote pursuant to section 3.2 of these bylaws, or if no
number is prescribed, a majority of the number in office immediately before the
meeting begins, shall constitute a quorum for the transaction of business at any
meeting of the board of directors. If a quorum shall not be present at any
meeting of the board of directors, the directors present thereat may adjourn the
meeting from time to time, without notice other than announcement at the
meeting, until a quorum shall be present.
(b) Voting. The act of the majority of the directors present at a
meeting at which a quorum is present when the vote is taken shall be the act of
the board of directors unless the articles of incorporation or these bylaws
require a greater percentage.
(c) Presumption of Assent. A director who is present at a meeting
of the board of directors or a committee of the board of directors when
corporate action is taken is deemed to have assented to the action taken unless:
(i) the director objects at the beginning of the meeting, or promptly upon his
or her arrival, to holding or transacting business at the meeting and does not
thereafter vote for or assent to any action taken at the meeting; (ii) the
director contemporaneously requests that his or her dissent or abstention as to
any specific action be entered in the minutes of the meeting; or (iii) the
director causes written notice of his or her dissent or abstention as to any
specific action be received by the presiding officer of the meeting before its
adjournment or by the corporation promptly after adjournment of the meeting. The
right of dissent or abstention as to a specific action is not available to a
director who votes in favor of the action taken.
3.7 Meetings by Telecommunications. Any or all directors may
participate in a regular or special meeting by, or conduct the meeting through
the use of, any means of communication by which all directors participating may
hear each other during the meeting. A director participating in a meeting by
this means is deemed to be present in person at the meeting.
3.8 Action Without a Meeting. Any action required or permitted to be
taken by the board of directors at a meeting may be taken without a meeting if
all the directors consent to such action in writing. Action taken by written
consent is effective when the last director signs the consent, unless, prior to
such time, any director has revoked a consent by a signed writing received by
the corporation, or unless the consent specifies a different effective date. A
signed consent has the effect of an action taken at a meeting of directors and
may be described as such in any document.
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3.9 Resignation. A director may resign at any time by giving a written
notice of resignation to the corporation. Such a resignation is effective when
the notice is received by the corporation unless the notice specifies a later
effective date, and the acceptance of such resignation shall not be necessary to
make it effective.
3.10 Removal. Subject to the rights of the holders of any series of
Preferred Stock then outstanding and any requirement of law, any director, or
the entire board of directors, may be removed from office at any time only as
follows: (a) for cause by the affirmative vote of the holders of at least 80% of
the voting power of all of the shares of the corporation entitled to vote
generally in the election of directors, voting together as a single voting group
at a meeting of shareholders or (b) so long as Union Pacific Corporation
beneficially owns (within the meaning of Rule 13d-3 under the Exchange Act) more
than 50% of the voting power of all of the shares of the corporation entitled to
vote generally in the election of directors, with or without cause by the
affirmative vote of the holders of a majority of the voting power of all of the
shares of the corporation entitled to vote generally in the election of
directors, voting together as a single group at a meeting of shareholders.
3.11 Vacancies. Subject to the rights of the holders of any series of
Preferred Stock then outstanding, newly created directorships resulting from any
increase in the authorized number of directors and any vacancies in the board of
directors resulting from death, resignation, retirement, disqualification,
removal from office or other cause shall be filled by a majority vote of the
directors then in office even though less than a quorum, or by a sole remaining
director and not by the shareholders unless there shall at such time be no
directors in office; provided, however, that (A) if the vacant office was held
by a director elected by a separate voting group of shareholders then (i) if one
or more remaining directors were elected by the same voting group, only such
directors shall be entitled to vote to fill the vacancy; and (ii) if no
directors elected by such voting group are then in office, only the holders of
shares of that voting group shall be entitled to vote to fill the vacancy, and
(B) the vacancy may be filled by vote of the shareholders acting at an annual
meeting of shareholders. A vacancy that will occur at a specific later date (by
reason of a resignation effective at a later date) may be filled before the
vacancy occurs but the new director may not take office until the vacancy
occurs.
3.12 Organization. Meetings of the board of directors shall be presided
over by the chairman of the board, or in his absence by the president, or in
their absence by a chairman chosen at the meeting. The secretary, or in the
absence of the secretary, an assistant secretary, shall act as secretary of the
meeting, but in the absence of the secretary and any assistant secretary the
chairman of the meeting may appoint any person to act as secretary of the
meeting.
3.13 Compensation. By resolution of the board of directors, each
director may be paid his or her expenses, if any, of attendance at each meeting
of the board of directors and may be paid a stated salary as director or a fixed
sum for attendance at each meeting of the board of directors or both. Members of
committees may be allowed like compensation for attending committee meetings. No
such payment shall preclude any director from serving the corporation in any
other capacity and receiving compensation therefor.
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3.14 Committees.
(a) The board of directors may, by resolution passed by a majority
of the whole board, designate one or more committees, each committee to consist
of two or more of the directors of the corporation. The board may designate one
or more directors as alternate members of any committee, who may replace any
absent or disqualified member at any meeting of the committee. In the absence or
disqualification of a member of a committee, the member or members thereof
present at any meeting and not disqualified from voting, whether or not such
member or members constitute a quorum, may unanimously appoint another member of
the board to act at the meeting in place of any such absent or disqualified
member. Any such committee, to the extent provided in the resolution of the
board, shall have and may exercise all the powers and authority of the board in
the management of the business and affairs of the corporation, except as limited
by applicable law.
(b) Unless the board of directors otherwise provides, each
committee designated by the board may adopt, amend and repeal rules for the
conduct of its business. In the absence of a provision by the board or a
provision in the rules of such committee to the contrary, a majority of the
entire authorized number of members of such committee shall constitute a quorum
for the transaction of business, the vote of a majority of the members present
at a meeting at the time of such vote if a quorum is then present shall be the
act of such committee, and in other respects such committee shall conduct its
business in the same manner as the board conducts its business pursuant to
Article 3 of these bylaws.
ARTICLE 4. OFFICERS
4.1 Officers; Election. As soon as practicable after the annual meeting
of shareholders in each year, the board of directors shall elect a president and
a secretary and it may, if it so determines, elect from among its members a
chairman of the board and a vice chairman of the board. The board may also elect
one or more vice presidents, one or more assistant vice presidents, one or more
assistant secretaries, a treasurer and one or more assistant treasurers and such
other officers as the board may deem desirable or appropriate and may give any
of them such further designations or alternate titles as it considers desirable.
Any number of offices may be held by the same person.
4.2 Term of Office; Resignation; Removal; Vacancies. Except as
otherwise provided in the resolution of the board of directors electing any
officer, each officer shall hold office until the first meeting of the board
after the annual meeting of shareholders next succeeding his election, and until
his successor is elected and qualified or until his earlier resignation or
removal. Any officer may resign at any time upon written notice to the board or
to the president or to the secretary of the corporation. Such resignation shall
take effect at the time specified therein, and unless otherwise specified
therein no acceptance of such resignation shall be necessary to make it
effective. The board may remove any officer with or without cause at any time.
Any such removal shall be without prejudice to the contractual rights of such
officer, if any, with the corporation, but the election of an officer shall not
of itself create contractual rights. Any vacancy occurring in any office of the
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corporation by death, resignation, removal or other reason may be filled for the
unexpired portion of the term of that office by the board at any regular or
special meeting.
4.3 Chairman of the Board. The chairman of the board, if any, shall (i)
preside at all meetings of the board of directors and of the shareholders at
which he or she shall be present (ii) if so specified by the board of directors,
be the chief executive officer of the corporation and (iii) shall have and may
exercise such powers as may, from time to time, be assigned to him or her by the
board and as may be provided by law.
4.4 Vice Chairman of the Board. In the absence of the chairman of the
board, the vice chairman of the board, if any, shall preside at all meetings of
the board of directors and of the shareholders at which he or she shall be
present and shall have and may exercise such powers as may, from time to time,
be assigned to him or her by the board and as may be provided by law.
4.5 President. Subject to the board of directors, the president shall,
unless otherwise specified by the board of directors, be the chief executive
officer of the corporation and in addition shall perform such duties and have
such powers as are prescribed in these bylaws or as may from time to time be
assigned to him or her by the board or as may be provided by law. The president
shall have responsibility for general and active management of the business of
the corporation and shall see that all orders and resolutions of the board of
directors are carried into effect.
4.6 Vice-Presidents. In the absence of the president or in the event of
his inability or refusal to act, the vice-president (or in the event there be
more than one vice-president, the vice-presidents in the order designated, or in
the absence of any designation, then in the order of their election) shall
perform the duties of the president, and when so acting, shall have all the
powers of and be subject to all the restrictions upon the president. The
vice-presidents shall perform such other duties and have such other powers as
these bylaws or the board of directors may from time to time prescribe or as may
be provided by law.
4.7 Secretary. The secretary shall attend all meetings of the board of
directors and all meetings of the shareholders and record all the proceedings of
the meetings of the corporation and of the board of directors in a book to be
kept for that purpose and shall perform like duties for the standing committees
when required. The secretary shall give, or cause to be given, notice of all
meetings of the shareholders and special meetings of the board of directors, and
shall perform such other duties as may be prescribed by the board of directors
or the president, under whose supervision he or she shall be. The Secretary
shall have custody of the corporate seal of the corporation and he or she, or an
assistant secretary, shall have authority to affix the same to any instrument
requiring it and when so affixed, it may be attested by his or her signature or
by the signature of such assistant secretary. The board of directors may give
general authority to any other officer to affix the seal of the corporation and
to attest the affixing by his or her signature. The Secretary shall perform such
other duties and have such other powers as these bylaws or the board of
directors may from time to time prescribe or as may be provided by law.
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4.8 Assistant Secretary. The assistant secretary, or if there be more
than one, the assistant secretaries in the order determined by the board of
directors (or if there be no such determination, then in the order of their
election), shall, in the absence of the secretary or in the event of his or her
inability or refusal to act, perform the duties and exercise the powers of the
secretary and shall perform such other duties and have such other powers as
these bylaws or the board of directors may from time to time prescribe or as may
be provided by law.
4.9 Treasurer. The treasurer shall have the custody of the corporate
funds and securities and shall keep full and accurate accounts of receipts and
disbursements in books belonging to the corporation and shall deposit all moneys
and other valuable effects in the name and to the credit of the corporation in
such depositories as may be designated by or pursuant to resolution of the board
of directors. The treasurer shall disburse the funds of the corporation as may
be ordered by the board of directors, taking proper vouchers for such
disbursements, and shall render to the president and the board of directors, at
its regular meetings, or when the board of directors so requires, an account of
all his or her transactions as treasurer and of the financial condition of the
corporation. If required by the board of directors, he or she shall give the
corporation a bond (which shall be renewed every six years) in such sum and with
such surety or sureties as shall be satisfactory to the board of directors for
the faithful performance of the duties of his or her office and for the
restoration to the corporation, in case of his or her death, resignation,
retirement or removal from office, of all books, papers, vouchers, money and
other property of whatever kind in his or her possession or under his or her
control belonging to the corporation. He or she shall perform such other duties
and have such other powers as these bylaws or the board of directors may from
time to time prescribe or as may be provided by law.
4.10 Assistant Treasurer. The assistant treasurer or if there shall be
more than one, the assistant treasurers in the order determined by the board of
directors (or if there be no such determination, then in the order of their
election), shall, in the absence of the treasurer or in the event of his or her
inability or refusal to act, perform the duties and exercise the powers of the
treasurer and shall perform such other duties and have such other powers as
these bylaws or the board of directors may from time to time prescribe or as may
be provided by law.
4.11 Other Officers. The other officers, if any, of the corporation
shall have such powers and duties in the management of the corporation as shall
be stated in a resolution of the board of directors which is not inconsistent
with these bylaws and, to the extent not so stated, as generally pertain to
their respective offices, subject to the control of the board. The board may
require any officer, agent or employee to give security for the faithful
performance of his or her duties.
4.12 Salary Approval Necessary. No office or position shall be created
and no person shall be employed at a salary of more than $200,000 per annum, and
no salary shall be increased to an amount in excess of $200,000 per annum,
without the approval of the board of directors, nor shall special compensation
be paid to any officer or employee, unless authorized by the board of directors;
provided, however that this section shall be applicable only to salaried
positions.
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4.13 Delegation. Subject to section 3.1, the board of directors may
from time to time vest general or specific authority in the chief executive
officer, the president or the head of any business unit, department or office of
the corporation, or in such other officers of the corporation as the board of
directors shall designate, for the determination or disposition of any matter
which otherwise would be required to be considered by the board of directors
under the provisions of this Article 4.
ARTICLE 5. CONTRACTS AND EXPENDITURES
5.1 Capital Expenditures, etc. All capital expenditures and
investments, exploration and development programs, leases and property
dispositions must be authorized by the board of directors, except that general
or specific authority with regard to such matters may be delegated, subject to
section 3.1, to such officers of the corporation as the board of directors may
from time to time direct.
5.2 Operating Expenditures. Expenditures chargeable to operating
expenses may be made by or under the direction of the head of the business unit,
department or office of the corporation concerned, without explicit or further
authority from the board of directors, subject to direction, restriction or
prohibition by the chief executive officer or the president.
5.3 Contracts - General. No contract shall be made or entered into by
the corporation without the approval of the board of directors, except as
authorized by the board of directors or these bylaws.
5.4 Contracts - Operating Expenditures. Contracts for work, labor and
services and materials and supplies, the expenditures of which will be
chargeable to operating expenses, may be made and executed in the name and on
behalf of the corporation by the head of the business unit, department or office
of the corporation concerned, or by such person as he or she shall designate,
without explicit or further authority from the board of directors, subject to
direction, restriction or prohibition by the chief executive officer or the
president.
5.5 Contracts - Execution, etc. The president and each vice president
of the corporation shall severally have the power to execute on behalf of the
corporation any deed, bond, indenture, certificate, note, contract or other
instrument or agreement authorized or approved by, or pursuant to delegation
from, the board of directors and to cause the corporate seal to be thereto
affixed and attested by the secretary or an assistant secretary.
5.6 Delegation. Subject to section 3.1, the board of directors may from
time to time vest general or specific authority in such officers of the
corporation as the board of directors shall designate for the determination or
disposition of any matter which otherwise would be required to be considered by
the board of directors under the provisions of this Article 5.
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ARTICLE 6. INDEMNIFICATION OF DIRECTORS,
OFFICERS AND EMPLOYEES
6.1 The corporation shall indemnify to the full extent permitted by law
any person made or threatened to be made a party to any threatened, pending or
completed action, suit or proceeding, whether criminal, civil, administrative or
investigative, by reason of the fact that such person is or was a director,
officer or employee of the corporation or serves or served at the request of the
corporation any other enterprise as a director, officer or employee. The
indemnification provided in this section shall include the right to receive
payment in advance of any final disposition of any expenses incurred by any such
person in connection with any such action, suit or proceeding, consistent with
the provisions of then applicable law. For purposes of this Article 6, the term
"corporation" shall include any predecessor of the corporation and any
constituent corporation (including any constituent of a constituent) absorbed by
the corporation in a consolidation or merger; the term "other enterprise" shall
include any corporation, partnership, limited liability company, joint venture,
trust or employee benefit plan; service "at the request of the corporation"
shall include service as a director, officer or employee of the corporation
which imposes duties on, or involves services by, such director, officer or
employee with respect to an employee benefit plan, its participants or
beneficiaries; any excise taxes assessed on a person with respect to an employee
benefit plan shall be deemed to be indemnifiable expenses; and action by a
person with respect to an employee benefit plan in good faith which such person
reasonably believes to be in the interest of the participants and beneficiaries
of such plan shall be deemed to be action not opposed to the best interests of
the corporation. This section 6.1 shall not apply to any action, suit or
proceeding pending or threatened on the date of adoption hereof provided that
the right of the corporation to indemnify any person with respect thereto shall
not be limited hereby.
6.2 Any indemnification under section 6.1 (unless ordered by a court)
shall be made by the corporation only as authorized in the specific case upon a
determination by the persons authorized by the Act to make such determination
that indemnification of the director, officer or employee is proper in the
circumstances because such person has met the applicable standard of conduct
required by law.
6.3 The indemnification and advancement of expenses provided by section
6.1 shall not be deemed exclusive of any other rights to which any person
seeking indemnification may be entitled under any law, agreement, vote of
shareholders or disinterested directors or otherwise, both as to action in such
person's official capacity and as to action in another capacity while holding
such office, and shall continue as to a person who has ceased to be a director,
officer or employee and shall inure to the benefit of the heirs, executors and
administrators of such a person. Any amendment or repeal of any provision of
this section shall not limit the right of any person to indemnity with respect
to actions taken or omitted to be taken by such person prior to such amendment
or repeal.
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ARTICLE 7. STOCK
7.1 Issuance of Shares. The corporation may issue the number of shares
of each class or series of capital stock authorized by the articles of
incorporation. The issuance or sale by the corporation of any shares of its
authorized capital stock of any class shall be made only upon authorization by
the board of directors, unless otherwise provided by statute. The board of
directors may authorize the issuance of shares for consideration consisting of
any tangible or intangible property or benefit to the corporation, including
cash, promissory notes, services performed, contracts or arrangements for
services to be performed, or other securities of the corporation. Shares shall
be issued for such consideration as shall be fixed from time to time by the
board of directors.
7.2 Certificates for Shares.
(a) Content. Shares may but need not be represented by certificates
in such form as determined by the board of directors and stating on their face,
at a minimum, the name of the corporation and that it is formed under the laws
of the State of Utah, the name of the person to whom issued, and the number and
class of shares and the designation of the series, if any, the certificate
represents. Such certificates shall be signed (either manually or by facsimile)
by the chairman of the board, president or a vice-president and by the secretary
or an assistant secretary and may be sealed with a corporate seal or a facsimile
thereof. Each certificate for shares shall be consecutively numbered or
otherwise identified. In case any officer who has signed or whose facsimile
signature has been place upon a certificate shall have ceased to be such officer
before such certificate is issued, it may be issued by the corporation with the
same effect as if he were such officer at the date of issue.
(b) Legend as to Class or Series. If the corporation is authorized
to issue different classes of shares or different series within a class, the
designations, relative rights, preferences and limitations applicable to each
class and the variations in rights, preferences and limitations determined for
each series (and the authority of the board of directors to determine variations
for future series) must be summarized on the front or back of each certificate.
Alternatively, each certificate may state conspicuously on its front or back
that the corporation will furnish the shareholder this information on request in
writing and without charge.
(c) Shareholder List. The name and address of the person to whom
the shares represented thereby are issued, with the number of shares and date of
issue, shall be entered on the stock transfer books of the corporation.
(d) Transferring Shares. All certificates surrendered to the
corporation for transfer shall be cancelled and no new certificate shall be
issued until the former certificate for a like number of shares shall have been
surrendered and cancelled, except that in case of a lost, destroyed, or
mutilated certificate, a new one may be issued therefor upon such terms and
indemnity to the corporation as the board of directors may prescribe.
16
<PAGE> 17
7.3 Shares Without Certificates. The board of directors may authorize
the issuance of some or all of the shares of any or all of its classes or series
without certificates. Within a reasonable time after the issuance or transfer of
shares without certificates, the corporation shall send the shareholder a
written statement of the information required on certificates under section 7.2
of these bylaws.
7.4 Registration of the Transfer of Shares. Registration of the
transfer of shares of the corporation shall be made only on the stock transfer
books of the corporation. In order to register a transfer, the record owner
shall surrender the shares to the corporation for cancellation, properly
endorsed by the appropriate person or persons with reasonable assurances that
the endorsements are genuine and effective. Unless the corporation has
established a procedure by which a beneficial owner of shares held by a nominee
is to be recognized by the corporation as the owner, the person in whose name
shares stand in the books of the corporation shall be deemed by the corporation
to be the owner thereof for all purposes and the corporation shall not be bound
to recognize any equitable or other claim to or interest in such share or shares
on the part of any other person, whether or not it shall have express or other
notice thereof, except as otherwise provided by law.
ARTICLE 8. MISCELLANEOUS
8.1 Corporate Seal. The board of directors may provide a corporate seal
which may be circular in form and have inscribed thereon any designation
including the name of the corporation, the state of incorporation, and the words
"Corporate Seal."
8.2 Amendments. The corporation's board of directors may amend,
supplement or repeal the corporation's bylaws at any time, except as limited by
applicable law. Notwithstanding any other provision contained in the bylaws to
the contrary, from and after such time as Union Pacific Corporation no longer
beneficially owns (within the meaning of Rule 13d-3 under the Exchange Act) more
than 50% of the voting power of all of the shares of the Corporation entitled to
vote generally in the election of directors, the affirmative vote of the holders
of at least 80% of the voting power of all of the shares of the corporation
entitled to vote generally in the election of directors, voting together as a
single voting group, shall be required to approve the taking, approval, or
adoption by the shareholders of the Corporation of any action or resolution
which would (i) alter or amend, (ii) adopt any provision inconsistent with or
limiting the effect of, or (iii) repeal, article 6 and sections 2.2, 2.8, 2.13,
2.14, 3.2, 3.10, 3.11 and 8.4 and this section 8.2 of these bylaws.
8.3 Fiscal Year. The fiscal year of the corporation shall be
established by the board of directors.
8.4 Certain Definitions. As used herein the term "Union Pacific
Corporation" shall mean Union Pacific Corporation, a Utah corporation, any
successor to such corporation by consolidation or merger and any corporation to
which all or substantially all of such corporation's assets may be transferred.
As used herein the term "Union Pacific" shall mean Union Pacific Corporation;
provided, however, that if Union Pacific Corporation is not a shareholder of the
corporation then the term
17
<PAGE> 1
EXHIBIT 10.7
[UPR LOGO]
1995
STOCK OPTION AND RETENTION STOCK PLAN
OF
UNION PACIFIC RESOURCES GROUP INC.
AS AMENDED AND RESTATED
(EFFECTIVE DECEMBER 7, 1999)
<PAGE> 2
1995 STOCK OPTION AND RETENTION STOCK PLAN
OF UNION PACIFIC RESOURCES GROUP INC.
(AS AMENDED AND RESTATED EFFECTIVE DECEMBER 7, 1999)
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1. PURPOSE
This 1995 Stock Option and Retention Stock Plan of Union Pacific Resources Group
Inc. is to promote and closely align the interests of officers and employees
with those of the shareholders of Union Pacific Resources Group Inc. by
providing stock based compensation. The Plan is intended to strengthen Union
Pacific Resources Group Inc.'s ability to reward performance which enhances long
term shareholder value; to increase employee stock ownership through performance
based compensation plans; and to strengthen the company's ability to attract and
retain an outstanding employee and executive team.
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2. DEFINITIONS
The following terms shall have the following meanings:
"Act" means the Securities Exchange Act of 1934, as amended.
"Approved Leave of Absence" means a leave of absence of definite length
approved by the Vice President - People of the Company, or by any other officer
of the Company to whom the Committee delegates such authority.
"Award" means an award of Retention Shares pursuant to the Plan.
"Beneficiary" means any person or persons designated in writing by a
Participant to the Committee on a form prescribed by it for that purpose, which
designation shall be revocable at any time by the Participant prior to his or
her death, provided that, in the absence of such a designation or the failure of
the person or persons so designated to survive the Participant, "Beneficiary"
shall mean such Participant's estate; and further provided that no designation
of Beneficiary shall be effective unless it is received by the Company before
the Participant's death.
"Board" means the Board of Directors of the Company.
"Code" means the Internal Revenue Code of 1986, as amended, or the
corresponding provisions of any successor statute.
"Committee" means the Committee designated by the Board to administer
the Plan pursuant to Section 3.
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<PAGE> 3
"Common Stock" means the Common Stock of the Company.
"Company" means Union Pacific Resources Group Inc., a Utah corporation,
or any successor corporation.
"Option" means each non-qualified stock option, incentive stock option
and stock appreciation right granted under the Plan, including a Rollover
Option.
"Optionee" means the Chairman of the Board or any employee of the
Company or a Subsidiary (including directors who are also such employees) who is
granted an Option under the Plan.
"Participant" means the Chairman of the Board or any employee of the
Company or a Subsidiary (including directors who are also such employees) who is
granted an Award under the Plan.
"Plan" means this 1995 Stock Option and Retention Stock Plan of Union
Pacific Resources Group Inc., as amended from time to time.
"Retention Shares" means shares of Common Stock subject to an Award
granted under the Plan, including Rollover Retention Shares.
"Restriction Period" means the period defined in Section 9(a).
"Rollover Option" means an Option granted under the Plan in exchange
for UPC Stock Options.
"Rollover Retention Shares" means shares of Common Stock subject to an
Award granted under the Plan in exchange for UPC Retention Shares.
"Subsidiary" means any corporation, partnership, or limited liability
company of which the Company owns directly or indirectly at least a majority of
the outstanding shares of voting stock or other voting interest.
"UPC" means Union Pacific Corporation, a Utah corporation.
"UPC Plans" mean the 1993 Stock Option and Retention Stock Plan of
Union Pacific Corporation, the 1990 Retention Stock Plan of Union Pacific
Corporation, the 1988 Stock Option and Restricted Stock Plan of Union Pacific
Corporation and the 1982 Stock Option and Restricted Stock Plan of Union Pacific
Corporation.
"UPC Stock Option" means any option granted under any UPC Plan.
"UPC Retention Shares" means shares of common stock of UPC granted and
subject to restrictions under the UPC Plans.
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<PAGE> 4
"Vesting Condition" means any condition to the vesting of Retention
Shares established by the Committee pursuant to Section 9.
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3. ADMINISTRATION
The Plan shall be administered by the Committee which shall comprise not less
than three persons, who shall be members of the Board, none of whom shall be
employees of the Company or any Subsidiary. Any actions taken with respect to a
"covered employee" within the meaning of Code section 162(m) shall be taken by
two or more "outside directors" as required by Code section 162(m). The
Committee shall (i) grant Options to Optionees and make Awards of Retention
Shares to Participants, and (ii) determine the terms and conditions of such
Options and Awards of Retention Shares, all in accordance with the provisions of
the Plan. The Committee shall have full authority to construe and interpret the
Plan, to establish, amend and rescind rules and regulations relating to the
Plan, to administer the Plan, and to take all such steps and make all such
determinations in connection with the Plan and Options and Awards granted
thereunder as it may deem necessary or advisable. The Committee may delegate its
authority under the Plan to one or more officers or employees of the Company or
a Subsidiary, provided, however, that no delegation shall be made of authority
to take an action which is required by Rule 16b-3 promulgated under the Act to
be taken by "non-employee directors" in order that the Plan and transactions
thereunder meet the requirements of such Rule. Each Option and grant of
Retention Shares shall, if required by the Committee, be evidenced by an
agreement to be executed by the Company and the Optionee or Participant,
respectively, and contain provisions not inconsistent with the Plan. All
determinations of the Committee shall be by a majority of its members and shall
be evidenced by resolution, written consent or other appropriate action, and the
Committee's determinations shall be final. Each member of the Committee, while
serving as such, shall be considered to be acting in his or her capacity as a
director of the Company.
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4. ELIGIBILITY
To be eligible for selection by the Committee to participate in the Plan an
individual must be an employee of the Company or a Subsidiary, provided, that
the Chairman of the Board shall be eligible to receive Rollover Options.
Directors other than the Chairman of the Board who are not full-time salaried
employees shall not be eligible. In granting Options or Awards of Retention
Shares to eligible persons, the Committee shall take into account their duties,
their present and potential contributions to the success of the Company or a
Subsidiary, and such other factors as the Committee shall deem relevant in
connection with accomplishing the purpose of the Plan.
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<PAGE> 5
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5. STOCK SUBJECT TO THE PLAN
Subject to the provisions of Section 11 hereof, the maximum number and kind of
shares as to which Options or Retention Shares may at any time be granted under
the Plan are 23 million shares of Common Stock. No Participant may receive
Options (excluding Rollover Options) or Awards (excluding Rollover Retention
Shares) aggregating more than 25% of the shares of Common Stock available under
the Plan. Shares of Common Stock subject to Options or Awards under the Plan may
be either authorized but unissued shares or shares previously issued and
reacquired by the Company. Upon the expiration, termination or cancellation (in
whole or in part) of unexercised Options, shares of Common Stock subject thereto
shall again be available for option or grant as Retention Shares under the Plan.
Shares of Common Stock covered by an Option, or portion thereof, which is
surrendered upon the exercise of a stock appreciation right, shall thereafter be
unavailable for option or grant as Retention Shares under the Plan. Upon the
forfeiture (in whole or in part) of a grant of Retention Shares, the shares of
Common Stock subject to such forfeiture shall again be available for option or
grant as Retention Shares under the Plan if no dividends have been paid on the
forfeited shares, and otherwise shall be unavailable for such an option or
grant.
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6. TERMS AND CONDITIONS OF NON-QUALIFIED OPTIONS
All non-qualified options under the Plan shall be granted subject to the
following terms and conditions:
(a) OPTION PRICE. The option price per share with respect to each
option, other than Rollover Options, shall be determined by the Committee but
shall not be less than 100% of the fair market value of the Common Stock on the
date the option is granted, such fair market value to be determined in
accordance with the procedures to be established by the Committee. Rollover
Options shall each have an option price per share determined by the Committee,
provided that, unless the Committee determines otherwise in a specific case, the
aggregate gain or loss, as determined by the Committee, implicit in the Rollover
Options granted to each Optionee shall be equal to the aggregate gain or loss
implicit in the UPC Stock Options surrendered in exchange for such Rollover
Options.
(b) DURATION OF OPTIONS. Options shall be exercisable at such time or
times and under such conditions as set forth in the written agreement evidencing
such option, but in no event shall any option be exercisable subsequent to the
tenth anniversary of the date on which the option is granted or, in the case of
Rollover Options, of the date of grant of the UPC Stock Option for which such
Rollover Option was exchanged.
(c) EXERCISE OF OPTION. Except as provided in Section 6(h), 6(i) or
8(c), the shares of Common Stock covered by an option may not be purchased prior
to the first anniversary of the date on which the option is granted or, in the
case of Rollover Options, prior to the date of exercise of the UPC Stock Option
for which such Rollover Option was exchanged (unless the Committee shall
determine otherwise), or such longer period or periods, and subject to such
conditions, as the Committee may determine, but thereafter may be purchased at
one time or in such installments over the balance of the option period as may be
provided in the option,
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<PAGE> 6
provided, however, that no option (other than Rollover Options) shall be
exercisable before the earlier of (i) December 31, 1997, or (ii) one year after
UPC no longer owns at least 50% of the voting power of all shares of the Company
entitled to vote generally in the election of directors. Any shares not
purchased on the applicable installment date may, unless the Committee shall
have determined otherwise, be purchased thereafter at any time prior to the
final expiration of the option. To the extent that the right to purchase shares
has accrued thereunder, options may be exercised from time to time by written
notice to the Company stating the number of shares with respect to which the
option is being exercised.
(d) PAYMENT. Shares of Common Stock purchased under options shall, at
the time of purchase, be paid for in full, unless the Committee shall otherwise
determine. All, or any portion, of the option exercise price may, at the
discretion of the Committee, be paid by the surrender to the Company, at the
time of exercise, of shares of previously acquired Common Stock owned by the
Optionee, to the extent that such payment does not require the surrender of a
fractional share of such previously acquired Common Stock. Such previously
acquired shares shall be valued at fair market value on the date the option is
exercised in accordance with the procedures to be established by the Committee.
A holder of an option shall have none of the rights of a stockholder. If an
amount is payable by an Optionee to the Company or a Subsidiary under applicable
withholding tax laws in connection with the exercise of non-qualified options,
the Committee may, in its discretion and subject to such rules as it may adopt,
permit the Optionee to make such payment, in whole or in part, by electing to
authorize the Company to withhold or accept shares of Common Stock having a fair
market value not exceeding the minimum applicable amount to be paid under such
withholding tax laws (based on the minimum applicable statutory withholding
rates for federal and state tax purposes, including payroll taxes).
(e) RESTRICTIONS. The Committee shall determine, with respect to each
option, the nature and extent of the restrictions, if any, to be imposed on the
shares of Common Stock which may be purchased thereunder including restrictions
on the transferability of such shares acquired through the exercise of such
option. Without limiting the generality of the foregoing, the Committee may
impose conditions restricting absolutely or conditionally the transferability of
shares acquired through the exercise of options for such periods, and subject to
such conditions, including continued employment of the Optionee by the Company
or a Subsidiary, as the Committee may determine.
(f) PURCHASE FOR INVESTMENT. The Committee shall have the right to
require that each Optionee or other person who shall exercise an option under
the Plan represent and agree that any shares of Common Stock purchased pursuant
to such option will be purchased for investment and not with a view to the
distribution or resale thereof or that such shares will not be sold except in
accordance with such restrictions or limitations as may be set forth in the
written agreement granting such option.
(g) NON-TRANSFERABILITY OF OPTIONS. During an Optionee's lifetime, the
option may be exercised only by the Optionee. Options shall not be transferable,
except for exercise by the Optionee's legal representatives or heirs. An officer
of the Company may, with prior approval from the Committee (or its designee) as
to form, transfer an exercisable non-qualified Option or Rollover Option to (a)
a member or members of the officer's immediate family (spouse, children and
grandchildren, including step and adopted children and grandchildren), (b) a
trust, the
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<PAGE> 7
beneficiaries of which consist exclusively of members of the officer's immediate
family, (c) a partnership, the partners of which consist exclusively of members
of the officer's immediate family, or (d) any similar entity created for the
exclusive benefit of members of the officer's immediate family. The Committee or
its designee must approve the form of any transfer of a Grant to or for the
benefit of any immediate family member or members before such transfer shall be
recognized as valid hereunder. For purposes of the preceding sentence, any
remote, contingent interest of persons other than a member of the officer's
immediate family shall be disregarded. For purposes of this Section 6(g), the
term "officer" shall have the same meaning as that term is defined in Rule
16a-1(f) of the Act. A person's status as an officer shall be determined at the
time of the intended transfer.
(h) TERMINATION OF EMPLOYMENT. Upon the termination of an Optionee's
employment, for any reason other than death, the option shall be exercisable
only as to those shares of Common Stock which were then subject to the exercise
of such option, provided that (I) in the case of disability as described below,
any holding period required by Section 6(c) shall automatically be deemed to be
satisfied and (II) the Committee may determine that particular limitations and
restrictions under the Plan shall not apply, and such option shall expire
according to the following schedule (unless the Committee shall otherwise
determine):
(i) RETIREMENT. Option shall expire, unless exercised, five
(5) years after the Optionee's retirement from the Company or any
Subsidiary under the provisions of the Company's or a Subsidiary's
pension plan.
(ii) DISABILITY. Option shall expire, unless exercised, five
(5) years after the date the Optionee is eligible to receive disability
benefits under the provisions of the Company's or a Subsidiary's
long-term disability plan.
(iii) GROSS MISCONDUCT. Option shall expire upon receipt by
the Optionee of the notice of termination if he or she is terminated
for deliberate, willful or gross misconduct as determined by the
Company.
(iv) ALL OTHER TERMINATIONS. Option shall expire, unless
exercised, three (3) months after the date of such termination.
(i) DEATH OF OPTIONEE. Upon the death of an Optionee during his or her
period of employment, the option shall be exercisable only as to those shares of
Common Stock which were subject to the exercise of such option at the time of
his or her death, provided that (I) any holding period required by Section 6(c)
shall automatically be deemed to be satisfied and (II) the Committee may
determine that particular limitations and restrictions under the Plan shall not
apply, and such option shall expire, unless exercised by the Optionee's legal
representatives or heirs, five (5) years after the date of death (unless the
Committee shall provide for a shorter period at the time the option is granted).
In no event, however, shall any option be exercisable pursuant
to Sections 6(h) or (i) subsequent to the tenth anniversary of the date on which
it is granted or, in the case of a Rollover Option, of the date of grant of the
UPC Stock Option(s) for which such Rollover Option was exchanged.
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<PAGE> 8
(j) ROLLOVER OPTIONS. Rollover Options may be granted only in exchange
for UPC Stock Options and only during the period prior to 90 days after UPC no
longer owns at least 50% of the voting power of all of the shares of the Company
entitled to vote generally in the election of directors. The ratio for such
exchange shall be determined by the Committee, provided that the requirements of
Section 6(a) are met.
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7. TERMS AND CONDITIONS OF STOCK APPRECIATION RIGHTS
(a) GENERAL. The Committee may also grant a stock appreciation right in
connection with a non-qualified option, either at the time of grant or by
amendment. Such stock appreciation right shall cover the same shares covered by
such option (or such lesser number of shares of Common Stock as the Committee
may determine) and shall, except for the provisions of Section 6(d) hereof, be
subject to the same terms and conditions as the related non-qualified option.
(b) EXERCISE AND PAYMENT. Each stock appreciation right shall entitle
the Optionee to surrender to the Company unexercised the related option, or any
portion thereof, and to receive from the Company in exchange therefor an amount
equal to the excess of the fair market value of one share of Common Stock over
the option price per share times the number of shares covered by the option, or
portion thereof, which is surrendered. Payment shall be made in shares of Common
Stock valued at fair market value, or in cash, or partly in shares and partly in
cash, all as shall be determined by the Committee. The fair market value shall
be the value determined in accordance with procedures established by the
Committee. Stock appreciation rights may be exercised from time to time upon
actual receipt by the Company of written notice stating the number of shares of
Common Stock with respect to which the stock appreciation right is being
exercised, provided that if a stock appreciation right expires unexercised, it
shall be deemed exercised on the expiration date if any amount would be payable
with respect thereto. No fractional shares shall be issued but instead cash
shall be paid for a fraction or, if the Committee should so determine, the
number of shares shall be rounded downward to the next whole share. If an amount
is payable by an Optionee to the Company or a Subsidiary under applicable
withholding tax laws in connection with the exercise of stock appreciation
rights, the Committee may, in its discretion and subject to such rules as it may
adopt, permit the Optionee to make such payment, in whole or in part, by
electing to authorize the Company to withhold or accept shares of Common Stock
having a fair market value equal to the amount to be paid under such withholding
tax laws.
(c) RESTRICTIONS. The obligation of the Company to satisfy any stock
appreciation right exercised by an Optionee subject to Section 16 of the Act
shall be conditioned upon the prior receipt by the Company of an opinion of
counsel to the Company that any such satisfaction will not create an obligation
on the part of such Optionee pursuant to Section 16(b) of the Act to reimburse
the Company for any statutory profit which might be held to result from such
satisfaction.
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<PAGE> 9
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8. TERMS AND CONDITIONS OF INCENTIVE STOCK OPTIONS
(a) GENERAL. The Committee may also grant incentive stock options as
defined under section 422 of the Code. All incentive stock options issued under
the Plan shall, except for the provisions of Sections 6(g) (to the extent it
allows the Committee to permit options to be transferred to, or for the benefit
of, the Optionee's immediate family members), 6(h) and (i) and Section 7 hereof,
be subject to the same terms and conditions as the non-qualified options granted
under the Plan, and may be Rollover Options subject to Section 6(j) hereof;
provided, however, that no incentive stock option which is a Rollover Option
shall confer additional benefits (within the meaning of section 424(h)(3) of the
Code) upon the Optionee which the Optionee did not have under the UPC Stock
Option surrendered in exchange therefor. In addition, incentive stock options
shall be subject to the conditions of Sections 8(b), (c), (d) and (e).
(b) LIMITATION OF EXERCISE. The aggregate fair market value (determined
as of the date the incentive stock option is granted) of the shares of stock
with respect to which incentive stock options are exercisable for the first time
by such Optionee during any calendar year, under this Plan or any other stock
option plans adopted by the Company, its Subsidiaries or any predecessor
companies thereof, other than Rollover Options issued in exchange for UPC
Options which were exercisable by the Optionee at the time of exchange, shall
not exceed $100,000. If any incentive stock options become exercisable in any
year in excess of the $100,000 limitation, options representing such excess
shall become non-qualified options exercisable pursuant to the terms of Section
6 hereof and shall not be exercisable as incentive stock options.
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<PAGE> 10
(c) TERMINATION OF EMPLOYMENT. Upon the termination of an Optionee's
employment, for any reason other than death, his or her incentive stock option
shall be exercisable only as to those shares of Common Stock which were then
subject to the exercise of such option provided that (I) in the case of
disability as described below, any holding period required by Section 6(c) shall
automatically be deemed to be satisfied and (II) the Committee may determine
that particular limitations and restrictions under the Plan shall not apply, and
such option shall expire as an incentive stock option (but shall become a
non-qualified option exercisable pursuant to the terms of Section 6 hereof less
the period already elapsed under such Section), according to the following
schedule (unless the Committee shall provide for shorter periods at the time the
incentive stock option is granted):
(i) RETIREMENT. An incentive stock option shall expire, unless
exercised, three (3) months after the Optionee's retirement from the
Company or any Subsidiary under the provisions of the Company's or a
Subsidiary's pension plan.
(ii) DISABILITY. In the case of an Optionee who is disabled
within the meaning of section 22(e)(3) of the Code, an incentive stock
option shall expire, unless exercised, one (1) year after the earlier
of the date the Optionee terminates employment or the date the Optionee
is eligible to receive disability benefits under the provisions of the
Company's or a Subsidiary's long-term disability plan.
(iii) GROSS MISCONDUCT. An incentive stock option shall expire
upon receipt by the Optionee of the notice of termination if he or she
is terminated for deliberate, willful or gross misconduct as determined
by the Company.
(iv) ALL OTHER TERMINATIONS. An incentive stock option shall
expire, unless exercised, three (3) months after the date of such
termination.
(d) DEATH OF OPTIONEE. Upon the death of an Optionee during his or her
period of employment, the incentive stock option shall be exercisable as an
incentive stock option only as to those shares of Common Stock which were
subject to the exercise of such option at the time of death, provided that (I)
any holding period required by Section 6(c) shall automatically be deemed to be
satisfied, and (II) the Committee may determine that particular limitations and
restrictions under the Plan shall not apply, and such option shall expire,
unless exercised by the Optionee's legal representatives or heirs, five (5)
years after the date of death (unless the Committee shall provide for a shorter
period at the time the option is granted).
(e) LEAVE OF ABSENCE. A leave of absence, whether or not an Approved
Leave of Absence, shall be deemed a termination of employment for purposes of
Section 8.
In no event, however, shall any incentive stock option be
exercisable pursuant to Sections 8(c) or (d) subsequent to the tenth anniversary
of the date on which it was granted or, in the case of a Rollover Option, of the
date of grant of the UPC Stock Option(s) for which such Rollover Option was
exchanged.
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9. TERMS AND CONDITIONS OF AWARDS OF RETENTION STOCK
(a) GENERAL. Retention Shares (other than Rollover Retention Shares)
may be granted to reward the attainment of individual, Company or Subsidiary
goals, or to attract or retain officers or other employees of the Company or any
Subsidiary. With respect to each grant of Retention Shares under the Plan, the
Committee shall determine the period or periods, including any conditions for
determining such period or periods, during which the restrictions set forth in
Section 9(b) shall apply, provided that in no event, other than as provided in
Section 9(c) or unless the Committee shall determine otherwise, shall such
restrictions terminate prior to 1 year after the date of grant, except for
Rollover Retention Shares, in which case such restrictions shall not terminate
prior to 3 years after the date of grant of the UPC Retention Shares for which
such Rollover Retention Shares are exchanged (the "Restriction Period"), and may
also specify any other terms or conditions to the right of the Participant to
receive such Retention Shares ("Vesting Conditions"). Subject to Section 9(c)
and any such Vesting Condition, a grant of Retention Shares shall be effective
for the Restriction Period and may not be revoked.
(b) RESTRICTIONS. At the time of grant of Retention Shares to a
Participant, a certificate representing the number of shares of Common Stock
granted shall be registered in the Participant's name but shall be held by the
Company for his or her account. The Participant shall have the entire beneficial
ownership interest in, and all rights and privileges of a stockholder as to,
such Retention Shares, including the right to vote such Retention Shares and,
unless the Committee shall determine otherwise, the right to receive dividends
thereon, subject to the following: (i) subject to Section 9(c), the Participant
shall not be entitled to delivery of the stock certificate until the expiration
of the Restriction Period and the satisfaction of any Vesting Conditions; (ii)
none of the Retention Shares may be sold, transferred, assigned, pledged, or
otherwise encumbered or disposed of during the Restriction Period or prior to
the satisfaction of any Vesting Conditions; and (iii) all of the Retention
Shares shall be forfeited and all rights of the Participant to such Retention
Shares shall terminate without further obligation on the part of the Company
unless the Participant remains in the continuous employment of the Company or a
Subsidiary for the entire Restriction Period, except as provided by Sections
9(a) and 9(c), and any applicable Vesting Conditions have been satisfied. Any
shares of Common Stock or other securities or property received as a result of a
transaction listed in Section 11 shall be subject to the same restrictions as
such Retention Shares unless the Committee shall determine otherwise.
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<PAGE> 12
(c) TERMINATION OF EMPLOYMENT.
(i) DISABILITY AND RETIREMENT. Unless the Committee shall
determine otherwise at the time of grant of Retention Shares, if (A) a
Participant ceases to be an employee of the Company or a Subsidiary
prior to the end of a Restriction Period, by reason of disability under
the provisions of the Company's or a Subsidiary's long-term disability
plan or retirement under the provisions of the Company's or a
Subsidiary's pension plan either (i) at age 65 or (ii) prior to age 65
at the request of the Company or a Subsidiary, and (B) all Vesting
Conditions have been satisfied, the Retention Shares granted to such
Participant shall immediately vest and all restrictions applicable to
such shares shall lapse. A certificate for such shares shall be
delivered to the Participant in accordance with the provisions of
Section 9(d).
(ii) DEATH. Unless the Committee shall determine otherwise at
the time of grant of Retention Shares, if (A) a Participant ceases to
be an employee of the Company or a Subsidiary prior to the end of a
Restriction Period by reason of death, and (B) all Vesting Conditions
have been satisfied, the Retention Shares granted to such Participant
shall immediately vest in his or her Beneficiary, and all restrictions
applicable to such shares shall lapse. A certificate for such shares
shall be delivered to the Participant's Beneficiary in accordance with
the provisions of Section 9(d).
(iii) ALL OTHER TERMINATIONS. If a Participant ceases to be an
employee of the Company or a Subsidiary prior to the end of a
Restriction Period for any reason other than death, disability or
retirement as provided in Section 9(c)(i) and (ii), the Participant
shall immediately forfeit all Retention Shares then subject to the
restrictions of Section 9(b) in accordance with the provisions thereof,
except that the Committee may, if it finds that the circumstances in
the particular case so warrant, allow a Participant whose employment
has so terminated to retain any or all of the Retention Shares then
subject to the restrictions of Section 9(b) and all restrictions
applicable to such retained shares shall lapse. A certificate for such
retained shares shall be delivered to the Participant in accordance
with the provisions of Section 9(d).
(iv) VESTING CONDITIONS. Unless the Committee shall determine
otherwise at the time of grant of Retention Shares, if a Participant
ceases to be an employee of the Company or a Subsidiary for any reason
prior to the satisfaction of any Vesting Conditions, the Participant
shall immediately forfeit all Retention Shares then subject to the
restrictions of Section 9(b) in accordance with the provisions thereof,
except that the Committee may, if it finds that the circumstances in
the particular case so warrant, allow a Participant whose employment
has so terminated to retain any or all of the Retention Shares then
subject to the restrictions of Section 9(b) and all restrictions
applicable to such retained shares shall lapse. A certificate for such
retained shares shall be delivered to the Participant in accordance
with the provisions of Section 9(d).
(d) PAYMENT OF RETENTION SHARES. At the end of the Restriction Period
and after all Vesting Conditions have been satisfied, or at such earlier time as
provided for in Section 9(c) or as the Committee, in its sole discretion, may
otherwise determine, all restrictions applicable to the Retention Shares shall
lapse, and a stock certificate for a number of shares of Common Stock
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<PAGE> 13
equal to the number of Retention Shares, free of all restrictions, shall be
delivered to the Participant or his or her Beneficiary, as the case may be. If
an amount is payable by a Participant to the Company or a Subsidiary under
applicable withholding tax laws in connection with the lapse of such
restrictions, the Committee, in its sole discretion, may permit the Participant
to make such payment, in whole or in part, by authorizing the Company
to transfer to the Company Retention Shares otherwise deliverable to the
Participant having a fair market value not exceeding the minimum applicable
amount to be paid under such withholding tax laws (based on the minimum
applicable statutory withholding rates for federal and state tax purposes,
including payroll taxes).
(e) ROLLOVER RETENTION SHARES. Rollover Retention Shares may be granted
only in exchange for shares of UPC Retention Stock granted and subject to
restrictions under a UPC Plan and only during the period prior to 90 days after
UPC no longer owns at least 50% of the voting power of all of the shares of the
Company entitled to vote generally in the election of directors. Unless the
Committee shall determine otherwise in a specific case, the Rollover Retention
Shares shall, on the date of exchange, have the same value, as determined by the
Committee, as the shares of UPC surrendered in exchange for such Rollover
Retention Shares.
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10. REGULATORY APPROVALS AND LISTING
The Company shall not be required to issue to an Optionee, Participant or a
Beneficiary, as the case may be, any certificate for any shares of Common Stock
upon exercise of an option or for any Retention Shares granted under the Plan
prior to (i) the obtaining of any approval from any governmental agency which
the Company, in its sole discretion, shall determine to be necessary or
advisable, (ii) the admission of such shares to listing on any stock exchange on
which the Common Stock may then be listed, and (iii) the completion of any
registration or other qualification of such shares under any state or Federal
law or rulings or regulations of any governmental body which the Company, in its
sole discretion, shall determine to be necessary or advisable.
- --------------------------------------------------------------------------------
11. ADJUSTMENT IN EVENT OF CHANGES IN CAPITALIZATION
In the event of a recapitalization, stock split, stock dividend, combination or
exchange of shares, merger, consolidation, rights offering, separation,
spin-off, reorganization or liquidation, or any other change in the corporate
structure or shares of the Company, the Board, upon recommendation of the
Committee, may make such equitable adjustments as it may deem appropriate in the
number and kind of shares authorized by the Plan, in the option price of
outstanding Options, and in the number and kind of shares or other securities or
property subject to Options or covered by outstanding Awards.
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<PAGE> 14
- --------------------------------------------------------------------------------
12. TERM OF THE PLAN
No Options or Retention Shares shall be granted pursuant to the Plan after
September 27, 2005 but grants of Options and Retention Shares theretofore
granted may extend beyond that date and the terms and conditions of the Plan
shall continue to apply thereto.
- --------------------------------------------------------------------------------
13. TERMINATION OR AMENDMENT OF THE PLAN
The Board may at any time terminate the Plan with respect to any shares of
Common Stock not at that time subject to outstanding Options or Awards, and may
from time to time alter or amend the Plan or any part thereof (including, but
without limiting the generality of the foregoing, any amendment deemed necessary
to ensure that the Company may obtain any approval referred to in Section 10 or
to ensure that the grant of Options or Awards, the exercise of Options or
payment of Retention Shares or any other provision or the Plan complies with
Section 16(b) of the Act), provided that no change with respect to any Options
or Retention Shares theretofore granted may be made which would impair the
rights of an Optionee or Participant without the consent of such Optionee or
Participant and, further, that without the approval of stockholders, no
alteration or amendment may be made which would (i) increase the maximum number
of shares of Common Stock subject to the Plan as set forth in Section 5 (except
by operation of Section 11), (ii) extend the term of the Plan, (iii) change the
class of eligible persons who may receive Options or Awards of Retention Shares
under the Plan or (iv) increase the limitation set forth in Section 5 on the
maximum number of shares that any Participant may receive under the Plan.
- --------------------------------------------------------------------------------
14. LEAVE OF ABSENCE
Unless the Committee shall determine otherwise, a leave of absence other than an
Approved Leave of Absence shall be deemed a termination of employment for
purposes of the Plan. An Approved Leave of Absence shall not be deemed a
termination of employment for purposes of the Plan (except for purposes of
Section 8), but the period of such Leave of Absence shall not be counted toward
satisfaction of any Restriction Period or any holding period described in
Section 6(c).
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<PAGE> 15
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15. GENERAL PROVISIONS
(a) Neither the Plan nor the grant of any Option or Award nor any
action by the Company, any Subsidiary or the Committee shall be held or
construed to confer upon any person any right to be continued in the employ of
the Company or a Subsidiary. The Company and each Subsidiary expressly reserve
the right to discharge, without liability but subject to his or her rights under
the Plan, any Optionee or Participant whenever in the sole discretion of the
Company or a Subsidiary, as the case may be, its interest may so require.
(b) All questions pertaining to the construction, regulation, validity
and effect of the Plan shall be determined in accordance with the laws of the
State of Utah, without regard to conflict of laws doctrine.
(c) Notwithstanding any provision herein to the contrary, the
Committee, under terms and conditions as it may prescribe, may permit certain
Optionees (with respect to Non-Qualified Options and Stock Appreciation Rights)
and certain Participants (with respect to Awards of Retention Shares) to make
elections, engage in transactions or take any other action intended to defer the
receipt of compensation for federal income tax purposes with respect to such
Non-Qualified Options, Stock Appreciation Rights or Retention Shares. This
provision shall be effective on and after September 5, 1997.
(d) With respect to any amendment to the Plan which becomes effective
on or after January 21, 1999, if the Company, at any time, desires to engage in
a transaction which is intended to be accounted for as a pooling of interests
under Accounting Principles Board Opinion No. 16 (or any successor thereto), and
if the existence and/or operation of any such amendment would violate Paragraph
47(c) thereof (or any successor thereto), then any such amendment shall (in
whole or in part to the minimum extent necessary to avoid a violation) be deemed
to have no force or effect under law; provided, however, that this subsection
(d) shall apply only if the transaction is otherwise eligible to be accounted
for as a pooling of interests.
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<PAGE> 1
EXHIBIT 10.11 (b)
UNION PACIFIC RESOURCES GROUP INC.
EXECUTIVE LIFE INSURANCE PROGRAM MODIFICATION
The Executive Life Insurance Program (ELIP) originally provided for an executive
to have a death benefit of one half of his or her final salary at age 62. If an
executive retired prior to age 62, the Company provided a cash bonus in order to
cover the policy premiums until age 62. The provisions of the ELIP were modified
for executives who retire prior to the age of 62. As a result of this
modification, executives who retire prior to the age of 62 will be responsible
for the policy premiums, not the Company. This change was effective January 1,
2000. The executive will retain ownership of the policy after retirement and may
keep the policy in force, modify it or terminate it. Premiums that may be
required after January 1, 2000 to keep the policy in force will be the
responsibility of the executive.
<PAGE> 1
EXHIBIT 10.12(e)
AGREEMENT
THIS AGREEMENT, dated March 18, 1999, is made by and between UNION
PACIFIC RESOURCES GROUP INC., a Utah corporation (the "Company"), and KERRY R.
BRITTAIN (the "Executive").
WHEREAS, the Company considers it essential to the best interests of
its shareholders to facilitate the recruitment and foster the continuous
employment of senior executive officers; and
WHEREAS, the Board recognizes that, as is the case with many publicly
held corporations, the possibility of a Change in Control exists and that such
possibility, and the uncertainty and questions which it raises, may result in
the departure or distraction of the Company's senior executive officers to the
detriment of the Company and its shareholders; and
WHEREAS, the Board has determined that appropriate steps should be
taken to reinforce and encourage the continued attention and dedication of the
Company's senior executive officers, including the Executive, to their assigned
duties without distraction in the face of potentially disturbing circumstances
arising from the possibility of a Change in Control;
NOW, THEREFORE, in consideration of the premises and the mutual
covenants herein contained, the Company and the Executive hereby agree as
follows:
1. DEFINED TERMS. The definitions of capitalized terms used in this
Agreement are provided in the last Section hereof.
2. COMPANY'S COVENANTS SUMMARIZED. In order to induce the Executive to
remain in the employ of the Company and in consideration of the Executive's
covenants set forth in Section 3 hereof, the Company agrees, under the
conditions described herein, to pay the Executive the Severance Payments and the
other payments and benefits described herein in the event the
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<PAGE> 2
Executive's employment with the Company is (or, under the terms of this
Agreement, is deemed to have been) terminated following a Change in Control and
during the term of this Agreement. Except as provided herein, no amount or
benefit shall be payable under this Agreement unless there shall have been (or,
under the terms of this Agreement, there shall be deemed to have been) a
termination of the Executive's employment with the Company following a Change in
Control and during the term of this Agreement. This Agreement shall not be
construed as creating an express or implied contract of employment and, except
as otherwise agreed in writing between the Executive and the Company, the
Executive shall not have any right to be retained in the employment of the
Company.
3. THE EXECUTIVE'S COVENANTS. The Executive agrees that, subject to the
terms and conditions of this Agreement, in the event of a Potential Change in
Control during the term of this Agreement, the Executive will remain in the
employ of the Company until the earliest of (i) a date which is six (6) months
following the date of such Potential Change in Control, (ii) the date of a
Change in Control, (iii) the date of termination by the Executive of the
Executive's employment for Good Reason or by reason of death, Disability or
Retirement, or (iv) the termination by the Company of the Executive's employment
for any reason.
4. TERM OF AGREEMENT. This Agreement shall commence on the date hereof
and shall continue in effect for a period of thirty-six (36) months beyond the
month in which a Change in Control occurs (or, if later, thirty-six (36) months
beyond the consummation of the transaction the approval of which by the
Company's shareholders constitutes a Change in Control under Section 15(E)(III)
or (IV) hereof).
5. COMPENSATION OTHER THAN SEVERANCE PAYMENTS.
5.1 Following a Change in Control and during the term of this
Agreement, if the Executive fails to perform the Executive's full-time duties
with the Company as a result of incapacity due to physical or mental illness,
the Company shall pay the Executive's full salary to the
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<PAGE> 3
Executive at the rate in effect at the commencement of the relevant period,
together with all compensation and benefits payable to the Executive under the
terms of any compensation or benefits plan, program or arrangement maintained by
the Company during such period, until the Executive's employment is terminated
by the Company for Disability.
5.2 If the Executive's employment is terminated for any reason
following a Change in Control and during the term of this Agreement, the Company
shall pay the Executive's full salary to the Executive through the Date of
Termination at the rate in effect at the time the Notice of Termination is
given, together with all compensation and benefits to which the Executive is
entitled in respect of all periods preceding the Date of Termination under the
terms of the Company's compensation and benefits plans, programs or
arrangements.
5.3 If the Executive's employment is terminated for any reason
following a Change in Control and during the term of this Agreement, the Company
shall pay the Executive's normal post-termination compensation and benefits to
the Executive as such payments become due. Such post-termination compensation
and benefits shall be determined under, and paid in accordance with, the
Company's retirement, insurance and other compensation or benefit plans,
programs and arrangements.
6. SEVERANCE PAYMENTS.
6.1 Subject to Section 6.2 hereof, the Company shall pay the
Executive the payments described in this Section 6.1 (the "Severance Payments")
upon the termination of the Executive"s employment following a Change in Control
and during the term of this Agreement, in addition to any payments and benefits
to which the Executive is entitled under Section 5 hereof, unless such
termination is (i) by the Company for Cause, (ii) by reason of the Executive's
death or Disability, or (iii) by the Executive without Good Reason. For purposes
of this Agreement, the Executive's employment shall be deemed to have been
terminated by the Company without Cause or by the Executive with Good Reason
following a Change in Control if, following a Potential Change in Control, (i)
the Executive's employment is terminated without Cause prior to a Change
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<PAGE> 4
in Control and such termination was at the request or direction of a Person who
has entered into an agreement with the Company the consummation of which would
constitute a Change in Control, (ii) the Executive terminates his employment
with Good Reason prior to a Change in Control and the circumstance or event
which constitutes Good Reason occurs at the request or direction of such Person,
or (iii) the Executive's employment is terminated without Cause prior to a
Change in Control and such termination is otherwise in connection with or in
anticipation of a Change in Control which actually occurs. For purposes of any
determination regarding the applicability of the immediately preceding sentence,
any position taken by the Executive shall be presumed to be correct unless the
Company establishes to the Board by clear and convincing evidence that such
position is not correct. Notwithstanding the foregoing, if the Executive
terminates employment with the Company by means of a Discretionary Termination,
he shall be entitled to 50% of the Severance Benefits set forth in (A) - (F)
below.
(A) In lieu of any further salary payments to the
Executive for periods subsequent to the Date of Termination and in lieu
of any severance benefit otherwise payable to the Executive, the
Company shall pay to the Executive a lump sum severance payment, in
cash, equal to two (2) times the sum of (i) the greater of the
Executive's annual base salary in effect immediately prior to the
occurrence of the event or circumstance upon which the Notice of
Termination is based or the Executive's annual base salary in effect
immediately prior to the Change in Control, and (ii) the greater of the
average of the annual bonuses earned or received by the Executive from
the Company or its subsidiaries in respect of the two (2) consecutive
fiscal years immediately preceding that in which the Date of
Termination occurs or the average of the annual bonuses so earned or
received in respect of the two (2) consecutive fiscal years immediately
preceding that in which the Change in Control occurs.
(B) Notwithstanding any provision of any annual or
long-term incentive plan to the contrary, the Company shall pay to the
Executive a lump sum amount, in cash, equal to the sum of (i) any
incentive compensation which has been allocated or awarded to the
Executive for a completed fiscal year or other measuring period
preceding the Date of
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<PAGE> 5
Termination under any such plan but which, as of the Date of
Termination, is contingent only upon the continued employment of the
Executive to a subsequent date or otherwise has not been paid, and (ii)
a pro rata portion to the Date of Termination of the aggregate value of
all contingent incentive compensation awards to the Executive for all
then uncompleted periods under any such plan, calculated as to each
such award by multiplying the award that the Executive would have
earned on the last day of the performance award period, assuming the
achievement, at the target level, of the individual and corporate
performance goals established with respect to such award, by the
fraction obtained by dividing the number of full months and any
fractional portion of a month during such performance award period
through the Date of Termination by the total number of months contained
in such performance award period.
(C) Notwithstanding any provision of the Company's
supplemental pension and thrift plans (the "Supplemental Plans") to the
contrary, upon the termination of the Executive's employment by the
Executive for Good Reason or by the Company, in either case at any time
following the occurrence of a Change in Control and during the term of
this Agreement, the Executive shall be deemed to have an additional
twenty-four (24) months of benefit credit under each of the
Supplemental Plans and shall be entitled to receive such additional
credit either (1) as part of the benefit otherwise payable under the
Supplemental Plan or (2) as a lump sum.
(D) For the twenty-four (24) month period immediately
following the Date of Termination, the Company shall arrange to provide
the Executive with life, disability, accident and health insurance
benefits substantially similar to those which the Executive is
receiving immediately prior to the Notice of Termination (without
giving effect to any amendment to such benefits made subsequent to a
Change in Control which amendment adversely affects in any manner the
Executive's entitlement to or the amount of such benefits); provided,
however, that, unless the Executive consents to a different method
(after taking into account the effect of such method on the calculation
of "parachute payments" pursuant to Section 6.2 hereof), such health
insurance benefits shall be provided
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<PAGE> 6
though a third-party insurer. Benefits otherwise receivable by the
Executive pursuant to this Section 6.1(D) shall be reduced to the
extent comparable benefits are actually received by the Executive
without cost during the twenty-four (24) month period following the
Executive's termination of employment (and any such benefits actually
received by the Executive shall be reported to the Company by the
Executive).
(E) If the Executive would have become entitled to
benefits under the Company's post-retirement health care or life
insurance plans had the Executive's employment terminated at any time
during the period of twenty-four (24) months after the Date of
Termination, the Company shall provide such post-retirement health care
or life insurance benefits to the Executive commencing on the later of
(i) the date that such coverage would have first become available and
(ii) the date that like benefits described in subsection (D) of this
Section 6.1 terminate.
(F) From and after the occurrence of Change in
Control and notwithstanding any provision in the Company's 1995 Stock
Option and Retention Stock Plan (or any agreement entered into
thereunder or any successor stock compensation plan or agreement
thereunder) to the contrary, any Option held by the Executive shall be
fully exercisable and any restriction on any Retention Share held by
the Executive shall lapse or be deemed fully satisfied, as applicable.
6.2 (A) Whether or not the Executive becomes entitled to the
Severance Payments, if any payment or benefit received or to be received by the
Executive in connection with a Change in Control or the termination of the
Executive's employment (whether pursuant to the terms of this Agreement or any
other plan, arrangement or agreement with the Company, any Person whose actions
result in a Change in Control or any Person affiliated with the Company or such
Person) (all such payments and benefits, including the Severance payments, being
hereinafter called "Total Payments") will be subject (in whole or part) to the
Excise Tax, then the Company shall pay to the Executive an additional amount
(the "Gross-Up Payment") such that the net amount retained by the Executive,
after deduction of any Excise Tax on the Total Payments and
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<PAGE> 7
any federal, state and local income and employment tax and Excise Tax upon the
Gross-Up-Payment, shall be equal to the Total Payments. For purposes of
determining the amount of the Gross-Up Payment, the Executive shall be deemed to
pay federal income and employment taxes at the highest marginal rate of federal
income and employment taxation in the calendar year in which the Gross-Up
Payment is to be made and state and local income taxes at the highest marginal
rate of taxation in the state and locality of the Executive's residence on the
Date of Termination, net of the maximum reduction in federal income taxes which
could be obtained from deduction of such state and local taxes.
(B) For purposes of determining whether any of the
Total Payments will be subject to the Excise Tax and the amount of such Excise
Tax, (i) all of the Total Payments shall be treated as "parachute payments"
within the meaning of section 280G(b)(2) of the Code, unless in the opinion of
tax counsel (the "Tax Counsel") reasonably acceptable to the Executive and
selected by the accounting firm (the "Auditor") which was, immediately prior to
the Change in Control, the Company's independent auditor, such other payments or
benefits (in whole or in part) do not constitute parachute payments, including
by reason of section 280G(b)(4)(A) of the Code, (ii) all "excess parachute
payments" within the meaning of section 280G(b)(1) of the Code shall be treated
as subject to the Excise Tax unless, in the opinion of Tax Counsel, such excess
parachute payments (in whole or part) represent reasonable compensation for
services actually rendered, within the meaning of section 280G(b)(4)(B) of the
Code, in excess of the Base Amount allocable to such reasonable compensation, or
are otherwise not subject to the Excise Tax, and (iii) the value of any noncash
benefits or any deferred payment or benefit shall be determined by the Auditor
in accordance with the principles of section 280G(d)(3) and (4) of the Code.
Prior to the payment date set forth in Section 6.3 hereof, the Company shall
provide the Executive with its calculation of the amounts referred to in this
Section 6.2(B) and such supporting materials as are reasonably necessary for the
Executive to evaluate the Company's calculations. If the Executive disputes the
Company's calculations (in whole or in part), the reasonable opinion of Tax
Counsel with respect to the matter in dispute shall prevail.
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<PAGE> 8
(C) In the event that (i) amounts are paid to the
Executive pursuant to subsection (A) of this Section 6.2, and (ii) the Excise
Tax is subsequently determined to be less than the amount taken into account
hereunder at the time of termination of the Executive's employment, the
Executive shall repay to the Company, at the time that the amount of such
reduction in Excise Tax is finally determined, the portion of the Gross-Up
Payment attributable to such reduction plus interest on the amount of such
repayment at the rate provided in section 1274(b)(2)(B) of the Code. In the
event that the Excise Tax is determined to exceed the amount taken into account
hereunder at the time of the termination of the Executive's employment
(including by reason of any payment the existence or amount of which cannot be
determined at the time of the Gross-Up Payment), the Company shall make an
additional Gross-Up Payment to the Executive in respect of such excess (plus any
interest, penalties or additions payable by the Executive with respect to such
excess and such portion) at the time that the amount of such excess is finally
determined.
6.3 The payments provided for in subsections (A), (B) and, if
applicable, (C) of Section 6.1 hereof and Section 6.2 hereof shall be made not
later than the fifth day following the Date of Termination; provided, however,
that if the amounts of such payments, or, if applicable, the Excise Tax, cannot
be finally determined on or before such day, the Company shall pay to the
Executive on such day an estimate, as determined in good faith by the Executive
or, in the case of Gross-Up Payments under Section 6.2 hereof, in accordance
with Section 6.2 hereof, of the minimum amount of such payments to which the
Executive is clearly entitled and shall pay the remainder of such payments
(together with interest at the rate provided in section 1274(b)(2)(B) of the
Code) as soon as the amount thereof can be determined but in no event later than
the thirtieth (30th) day after the Date of Termination. In the event that the
amount of the estimated payments exceeds the amount subsequently determined to
have been due, such excess shall constitute a loan by the Company to the
Executive, payable on the fifth (5th) business day after demand by the Company
(together with interest at the rate provided in section 1274(b)(2) (B) of the
Code). At the time that payments are made under this Section, the Company shall
provide the Executive with a written statement setting forth the manner in which
such payments were calculated and the basis for such calculations including,
without limitation, any opinions or other advice the Company has
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<PAGE> 9
received from outside counsel, auditors or consultants (and any such opinions or
advice which are in writing shall be attached to the statement). In the event
the Company should fail to pay when due the amounts described in subsections
(A), (B) and, if applicable, (C) of Section 6.1 hereof or Section 6.2 hereof,
the Executive shall also be entitled to receive from the Company an amount
representing interest on any unpaid or untimely paid amounts from the due date,
as determined under this Section 6.3 (without regard to any extension of the
Date of Termination pursuant to Section 7.3 hereof), to the date of payment at a
rate equal to the prime rate of Citibank as in effect from time to time after
such due date.
6.4 The Company also shall pay to the Executive all legal fees
and expenses incurred by the Executive in disputing in good faith any issue
relating to the termination of the Executive's employment following a Change in
Control (including a termination of employment following a Potential Change in
Control if the Executive alleges in good faith that such termination will be
deemed to have occurred following a Change in Control pursuant to the second
sentence of Section 6.1 hereof) or in seeking in good faith to obtain or enforce
any benefit or right provided by this Agreement or in connection with any tax
audit or proceeding to the extent attributable to the application of section
4999 of the Code to any payment or benefit provided hereunder. Such payments
shall be made as such fees and expenses are incurred by the Executive, but in no
event later than five (5) business days after delivery of the Executive's
written requests for payment accompanied with such evidence of fees and expenses
incurred as the Company reasonably may require.
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7. TERMINATION PROCEDURES AND COMPENSATION DURING DISPUTE.
7.1 NOTICE OF TERMINATION. After a Change in Control and
during the term of this Agreement, any purported termination of the Executive's
employment (other than by reason of death) shall be communicated by written
Notice of Termination from one party hereto to the other party hereto in
accordance with Section 10 hereof. For purpose of this Agreement, a "Notice of
Termination" shall mean a notice which shall indicate the specific termination
provision in this Agreement relied upon and shall set forth in reasonable detail
the facts and circumstances claimed to provide a basis for termination of the
Executive's employment under the provision so indicated. Further, a Notice of
Termination for Cause is required to include a copy of a resolution duly adopted
by the affirmative vote of not less than three-quarters (3/4) of the entire
membership of the Board at a meeting of the Board which was called and held for
the purpose of considering such termination (after reasonable notice to the
Executive and an opportunity for the Executive, together with the Executive's
counsel, to be heard before the Board) finding that, in the good faith opinion
of the Board, the Executive was guilty of conduct set forth in clause (i) or
(ii) of the definition of Cause herein, and specifying the particulars thereof
in detail.
7.2 DATE OF TERMINATION. "Date of Termination," with respect
to any purported termination of the Executive's employment after a Change in
Control and during the term of this Agreement, shall mean (i) if the Executive's
employment is terminated for Disability, thirty (30) days after Notice of
Termination is given (provided that the Executive shall not have returned to the
full-time performance of the Executive's duties during such thirty (30) day
period), and (ii) if the Executive's employment is terminated for any other
reason, the date specified in the Notice of Termination (which, in the case of a
termination by the Company, shall not be less than thirty (30) days (except in
the case of a termination for Cause) and, in the case of a termination by the
Executive, shall not be less than fifteen (15) days nor more than sixty (60)
days, respectively, from the date such Notice of Termination is given).
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<PAGE> 11
7.3 DISPUTE CONCERNING TERMINATION. If within fifteen (15)
days after any Notice of Termination is given, or, if later, prior to the Date
of Termination (as determined without regard to this Section 7.3), the party
receiving such Notice of Termination notifies the other party that a dispute
exists concerning the termination, the Date of Termination shall be extended
until the earlier of (i) the date on which the term of this Agreement ends
(taking into account any extensions thereof that shall have occurred) or (ii)
the date on which the dispute is finally resolved, either by mutual written
agreement of the parties or by a final judgment, order or decree of a court of
competent jurisdiction (which is not appealable or with respect to which the
time for appeal therefrom has expired and no appeal has been perfected);
provided, however, that the Date of Termination shall be extended by a notice of
dispute given by the Executive only if such notice is given in good faith and
the Executive pursues the resolution of such dispute with reasonable diligence.
7.4 COMPENSATION DURING DISPUTE. If a purported termination
occurs following a Change in Control and during the term of this Agreement and
the Date of Termination is extended in accordance with Section 7.3 hereof, the
Company shall continue to pay the Executive the full compensation in effect when
the notice giving rise to the dispute was given (including, but not limited to,
salary) and continue the Executive as a participant in all compensation, benefit
and insurance plans in which the Executive was participating when the notice
giving rise to the dispute was given, until the Date of Termination, as
determined in accordance with Section 7.3 hereof. Amounts paid under this
Section 7.4 are in addition to all other amounts due under this Agreement s and
shall not be offset against or reduce any other amounts due under this
Agreement.
8. NO MITIGATION. The Company agrees that, if the Executive's
employment with the Company terminates during the term of this Agreement, the
Executive is not required to seek other employment or to attempt in any way to
reduce any amounts payable to the Executive by the Company pursuant to Section 6
hereof or Section 7.4 hereof. Further, the amount of any payment or benefit
provided for in this Agreement (other than Section 6.1(D) hereof) shall not be
reduced by
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<PAGE> 12
any compensation earned by the Executive as the result of employment by another
employer, by retirement benefits, by offset against any amount claimed to be
owed by the Executive to the Company, or otherwise.
9. SUCCESSORS; BINDING AGREEMENT.
9.1 In addition to any obligations imposed by law upon any
successor to the Company, the Company will require any successor (whether direct
or indirect, by purchase, merger, consolidation or otherwise) to all or
substantially all of the business and/or assets of the Company to expressly
assume and agree to perform this Agreement in the same manner and to the same
extent that the Company would be required to perform it if no such succession
had taken place. Failure of the Company to obtain such assumption and agreement
prior to the effectiveness of any such succession shall be a breach of this
Agreement and shall entitle the Executive to compensation from the Company in
the same amount and on the same terms as the Executive would be entitled to
hereunder if the Executive were to terminate the Executive"s employment for Good
Reason after a Change in Control, except that, for purposes of implementing the
foregoing, the date on which such succession becomes effective shall be deemed
the Date of Termination.
9.2 This Agreement shall inure to the benefit of and be
enforceable by the Executive's personal or legal representatives, executors,
administrators, successors, heirs, distributees, devisees and legatees. If the
Executive shall die while any amount would still be payable to the Executive
hereunder (other than amounts which, by their terms, terminate upon the death of
the Executive) if the Executive had continued to live, all such amounts, unless
otherwise provided herein, shall be paid in accordance with the terms of this
Agreement to the executors, personal representatives or administrators of the
Executive's estate.
10. NOTICES. For the purpose of this Agreement, notices and all other
communications provided for in the Agreement shall be in writing and shall be
deemed to have been duly given when delivered or mailed by United States
registered mail, return receipt requested, postage prepaid,
12
<PAGE> 13
addressed, if to the Executive, to the address shown for the Executive in the
personnel records of the Company and, if to the Company, to the address set
forth below, or to such other address as either party may have furnished to the
other in writing in accordance herewith, except that notice of change of address
shall be effective only upon actual receipt:
To the Company:
Union Pacific Resources Group Inc.
777 Main Street
Ft. Worth, TX 76102
Attention: Vice President and General Counsel
11. MISCELLANEOUS. No provision of this Agreement may be modified,
waived or discharged unless such waiver, modification or discharge is agreed to
in writing and signed by the Executive and such officer as may be specifically
designated by the Board. No waiver by either party hereto at any time of any
breach by the other party hereto of, or compliance with, any condition or
provision of this Agreement to be performed by such other party shall be deemed
a waiver of a similar or dissimilar provisions or conditions at the same or at
any prior or subsequent time. This Agreement supersedes any other agreements or
representations, oral or otherwise, express or implied, with respect to the
subject matter hereof (i.e., benefits payable to the Executive by reason of the
occurrence of a Change in Control) which have been made by either party. The
validity, interpretation, construction and performance of this Agreement shall
be governed by the laws of the State of Texas. All references to sections of the
Exchange Act or the Code shall be deemed also to refer to any successor
provisions to such sections. Any payments provided for hereunder shall be paid
net of any applicable withholding required under federal, state or local law and
any additional withholding to which the Executive has agreed. The obligations of
the Company and the Executive under Sections 6 and 7 hereof shall survive the
expiration of the term of this Agreement. All obligations of the Company under
this Agreement shall remain unfunded and unsecured for federal income tax
purposes and the Executive's right to any payments shall be that of a general
creditor of the Company. Nevertheless, the Company shall establish a so-called
"rabbi trust" for purposes of providing payments hereunder and, in the event of
a Potential Change in
13
<PAGE> 14
Control, the Company shall immediately transfer to such rabbi trust sufficient
funds to satisfy all payment obligations to the Executives hereunder.
12. VALIDITY. The invalidity or unenforceability of any provision of
this Agreement shall not affect the validity or enforceability of any other
provision of this Agreement, which shall remain in full force and effect.
13. COUNTERPARTS. This Agreement may be executed in several
counterparts, each of which shall be deemed to be an original but all of which
together will constitute one and the same instrument.
14. SETTLEMENT OF DISPUTES; ARBITRATION. All claims by the Executive
for benefits under this Agreement shall be directed to and determined by the
Board and shall be in writing. Any denial by the Board of a claim for benefits
under this Agreement shall be delivered to the Executive in writing and shall
set forth the specific reasons for the denial and the specific provisions of
this Agreement relied upon. The Board shall afford a reasonable opportunity to
the Executive for a review of the decision denying a claim and shall further
allow the Executive to appeal to the Board a decision of the Board within sixty
(60) days after notification by the Board that the Executive's claim has been
denied. Any further dispute, controversy or claim arising out of or relating to
this Agreement, or the interpretation or alleged breach thereof, shall be
settled by arbitration in accordance with the Center for Public Resources, Inc.
Non-Administered Arbitration Rules, by three arbitrators, none of whom shall be
appointed by either party. The arbitration shall be governed by United States
Arbitration Act 9 U.S.C. Section 1-16, and judgment upon the award rendered by
the arbitrators may be entered by any court having jurisdiction thereof. The
place of the arbitration shall be Ft. Worth, Texas. Judgment may be entered on
the arbitrator's award in any court having jurisdiction. Notwithstanding any
provision of this Agreement to the contrary, the Executive shall be entitled to
seek specific performance of the Executive's right to be paid until the Date of
Termination during the pendency of any dispute or controversy arising under or
in connection with this Agreement.
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<PAGE> 15
15. DEFINITIONS. For purposes of this Agreement, the following terms
shall have the meanings indicated below:
(A) "Base Amount" shall have the meaning set forth in
section 280G(b)(3) of the Code.
(B) "Beneficial Owner" shall have the meaning set
forth in Rule 13d-3 under the Exchange Act.
(C) "Board" shall mean the Board of Directors of the
Company.
(D) "Cause" for termination by the Company of the
Executive's employment shall mean (i) the willful and continued failure by the
Executive to substantially perform the Executive's duties with the Company
(other than any such failure resulting from the Executive's incapacity due to
physical or mental illness or any such actual or anticipated failure after the
issuance of a Notice of Termination for Good Reason by the Executive pursuant to
Section 7.1 hereof) after a written demand for substantial performance is
delivered to the Executive by the Board, which demand specifically identifies
the manner in which the Board believes that the Executive has not substantially
performed the Executive's duties, or (ii) the willful engaging by the Executive
in conduct which is demonstrably and materially injurious to the Company or its
subsidiaries, monetarily or otherwise. For purposes of clauses (i) and (ii) of
this definition, (x) no act, or failure to act, on the Executive"s part shall be
deemed "willful" unless done, or omitted to be done, by the Executive not in
good faith and without reasonable belief that the Executive's act, or failure to
act, was in the best interest of the Company and (y) in the event of a dispute
concerning the application of this provision, no claim by the Company that Cause
exists shall be given effect unless the Company establishes to the Board by
clear and convincing evidence that Cause exists.
(E) A "Change in Control" shall be deemed to have
occurred if the event set forth in any one of the following paragraphs shall
have occurred:
15
<PAGE> 16
(I) any Person is or becomes the Beneficial
Owner, directly or indirectly, of securities of the
Company (not including in the securities beneficially
owned by such Person any securities acquired directly
from the Company or its affiliates other than in
connection with the acquisition by the Company or its
affiliates of a business) representing 15% or more of
either the then outstanding shares of common stock of
the Company or the combined voting power of the
Company's then outstanding securities; or
(II) the following individuals cease for any
reason to constitute a majority of the number of
directors then serving: individuals who, on the date
hereof, constitute the Board and any new director
(other than a director whose initial assumption of
office is in connection with an actual or threatened
election contest, including but not limited to a
consent solicitation, relating to the election of
directors of the Company (as such terms are used in
Rule 14a-11 of Regulation 14A under the Exchange
Act)) whose appointment or election by the Board or
nomination for election by the Company's shareholders
was approved by a vote of at least two-thirds (2/3)
of the directors then still in office who either were
directors on the date hereof or whose appointment,
election or nomination for election was previously so
approved; or
(III) the shareholders of the Company
approve a merger or consolidation of the Company with
any other corporation or approve the issuance of
voting securities of the Company in connection with a
merger or consolidation of the Company (or any direct
or indirect subsidiary of the Company) pursuant to
applicable stock exchange requirements, other than
(i) a merger or consolidation which would result in
the voting securities of the Company outstanding
immediately prior to such merger or consolidation
continuing to represent (either by remaining
outstanding or by being
16
<PAGE> 17
converted into voting securities of the surviving
entity or any parent thereof), in combination with
the ownership of any trustee or other fiduciary
holding securities under an employee benefit plan of
the Company, at least 50% of the combined voting
power of the voting securities of the Company or such
surviving entity or any parent thereof outstanding
immediately after such merger or consolidation, or
(ii) a merger or consolidation effected to implement
a recapitalization of the Company (or similar
transaction) in which no Person is or becomes the
Beneficial Owner, directly or indirectly, of
securities of the Company (not including in the
securities Beneficially Owned by such Person any
securities acquired directly from the Company or its
affiliates other than in connection with the
acquisition by the Company or its affiliates of a
business) representing 15% or more of either the then
outstanding shares of common stock of the Company or
the combined voting power of the Company's then
outstanding securities; or
(IV) the shareholders of the Company approve
a plan of complete liquidation or dissolution of the
Company or an agreement for the sale or disposition
by the Company of all or substantially all of the
Company's assets, other than a sale or disposition by
the Company of all or substantially all of the
Company's assets to an entity, at least 50% of the
combined voting power of the voting securities of
which are owned by Persons in substantially the same
proportions as their ownership of the Company
immediately prior to such sale.
Notwithstanding the foregoing, no "Change in Control" shall be deemed to have
occurred if there is consummated any transaction or series of integrated
transactions immediately following which the record holders of the common stock
of the Company immediately prior to such transaction or series of transactions
continue to have substantially the same proportionate ownership in an entity
which owns all or substantially all of the assets of the Company immediately
following such transaction or series of transactions.
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<PAGE> 18
(F) "Code" shall mean the Internal Revenue Code of
1986, as amended from time to time.
(G) "Company" shall mean Union Pacific Resources
Group Inc. and, except in determining under Section 15(E) hereof whether or not
any Change in Control of the Company has occurred, shall include its
subsidiaries and any successor to its business and/or assets which assumes and
agrees to perform this Agreement by operation of law, or otherwise.
(H) "Date of Termination" shall have the meaning
stated in Section 7.2 hereof.
(I) "Disability" shall be deemed the reason for the
termination by the Company of the Executive's employment, if, as a result of the
Executive's incapacity due to physical or mental illness, the Executive shall
have been absent from the full-time performance of the Executive's duties with
the Company for a period of six (6) consecutive months, the Company shall have
given the Executive a Notice of Termination for Disability following such
consecutive six (6) month period, and within thirty (30) days after such Notice
of Termination is given, the Executive shall not have returned to the full-time
performance of the Executive's duties.
(J) "Discretionary Termination" shall mean a
voluntary termination of employment by the Executive at any time during the
30-day period immediately following the first anniversary of the Change in
Control.
(K) "Exchange Act" shall mean the Securities Exchange
Act of 1934, as amended from time to time.
(L) "Excise Tax" shall mean any excise tax imposed
under section 4999 of the Code.
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<PAGE> 19
(M) "Executive" shall mean the individual named in
the first paragraph of this Agreement.
(N) "Good Reason" for termination by the Executive of
the Executive's employment shall mean the occurrence (without the Executive's
express written consent) after any Change in Control, or after any Potential
Change in Control under the circumstances described in the second sentence of
Section 6.1 hereof (treating all references in paragraphs (I) and (VII) below to
a "Change in Control" as references to a "Potential Change in Control"), of any
one of the following acts by the Company, or failures by the Company to act,
unless, in the case of any act or failure to act described in paragraph (I),
(V), (VI) or (VII) below, such act or failure to act is corrected prior to the
Date of Termination specified in the Notice of Termination given in respect
thereof:
(I) the assignment to the Executive of any
duties inconsistent with the Executive's status as a
senior executive officer of the Company or a
substantial alteration in the nature or status of the
Executive's responsibilities from those in effect
immediately prior to the Change in Control other than
any such alteration primarily attributable to the
fact that the Company may no longer be a public
company;
(II) a reduction by the Company in the
Executive's compensation (annual base salary plus
bonus) as in effect on the date hereof or as the same
may be increased from time to time;
(III) the relocation of the Company's
principal executive offices to a location more than
50 miles from the location of such offices
immediately prior to the Change in Control or the
Company's requiring the Executive to be based
anywhere other than the Company's principal executive
offices except for required travel on the Company's
business to an extent substantially consistent with
the Executive's present business travel obligations;
19
<PAGE> 20
(IV) the failure by the Company to pay to
the Executive any portion of the Executive's current
compensation or to pay to the Executive any portion
of an installment of deferred compensation under any
deferred compensation program of the Company, within
seven (7) days of the date such compensation is due;
(V) the failure by the Company to continue
in effect any compensation plan in which the
Executive participates immediately prior to the
Change in Control which is material to the
Executive's total compensation, including but not
limited to the Company's stock option, restricted
stock, stock appreciation right, incentive
compensation, bonus and other plans or any substitute
plans adopted prior to the Change in Control, unless
an equitable arrangement (embodied in an ongoing
substitute or alternative plan) has been made with
respect to such plan, or the failure by the Company
to continue the Executive's participation therein (or
in such substitute or alternative plan) on a basis
not materially less favorable, both in terms of the
amount of benefits provided and the level of the
Executive's participation, relative to other
participants, as existed immediately prior to the
Change in Control;
(VI) the failure by the Company to continue
to provide the Executive with benefits substantially
similar to those enjoyed by the Executive under any
of the Company's pension, life insurance, medical,
health and accident, or disability plans in which the
Executive was participating immediately prior to the
Change in Control, the taking of any action by the
Company which would directly or indirectly materially
reduce any of such benefits or deprive the Executive
of any material fringe benefit enjoyed by the
Executive at the time of the Change in Control, or
the failure by the Company to maintain a vacation
policy with respect to the Executive
20
<PAGE> 21
that is at least as favorable as the vacation policy
(whether formal or informal) in place with respect to
the Executive immediately prior to the Change in
Control; or
(VII) any purported termination of the
Executive's employment which is not effected pursuant
to a Notice of Termination satisfying the
requirements of Section 7.1 hereof; for purposes of
this Agreement, no such purported termination shall
be effective.
The Executive's right to terminate the Executive's employment
for Good Reason shall not be affected by the Executive's incapacity due to
physical or mental illness. The Executive's continued employment shall not
constitute consent to, or a waiver of rights with respect to, any act or failure
to act constituting Good Reason hereunder.
For purposes of any determination regarding the existence of
Good Reason, any claim by the Executive that Good Reason exists shall be
presumed to be correct unless the Company establishes to the Board by clear and
convincing evidence that Good Reason does not exist.
(O) "Gross-Up Payment" shall have the meaning set
forth in Section 6.2 hereof.
(P) "Notice of Termination" shall have the meaning
stated in Section 7.1 hereof.
(Q) "Person" shall have the meaning given in Section
3(a)(9) of the Exchange Act, as modified and used in Sections 13(d) and 14(d)
thereof, except that such term shall not include (i) the Company or any of its
affiliated (as defined in Rule 12b-2 promulgated under the Exchange Act), (ii) a
trustee or other fiduciary holding securities under an employee benefit plan of
the Company or any of its affiliates, (iii) an underwriter temporarily holding
21
<PAGE> 22
securities pursuant to an offering of such securities, or (iv) a corporation
owned, directly or indirectly, by the shareholders of the Company in
substantially the same proportions as their ownership of stock of the Company.
(R) "Potential Change in Control" shall be deemed to
have occurred if the event set forth in any one of the following paragraphs
shall have occurred:
(I) the Company enters into an agreement,
the consummation of which would result in the
occurrence of a Change in Control;
(II) the Company or any Person publicly
announces an intention to take or to consider taking
actions which, if consummated, would constitute a
Change in Control;
(III) any Person becomes the Beneficial
Owner, directly or indirectly, or securities of the
Company representing 10% or more of either the then
outstanding shares of common stock of the Company or
the combined voting power of the Company's then
outstanding securities; or
(IV) the Board adopts a resolution to the
effect that, for purposes of this Agreement, a
Potential Change in Control has occurred.
22
<PAGE> 23
(S) "Retirement" shall be deemed the reason for the
termination of the Executive's employment if such employment is terminated in
accordance with the Company's retirement policy generally applicable to its
salaried employees, as in effect immediately prior to the Change in Control, or
in accordance with any retirement arrangement established with the Executive's
consent with respect to the Executive.
(T) "Severance Payments" shall mean those payments
described in Section 6.1 hereof.
(U) "Total Payments" shall mean those payments
described in Section 6.2 hereof.
UNION PACIFIC RESOURCES GROUP INC.
By:
-----------------------------------------
JACK L. MESSMAN
EXECUTIVE
By:
-----------------------------------------
KERRY R. BRITTAIN
-23-
<PAGE> 1
Exhibit 10.12 (f)
AMENDMENT
THIS AMENDMENT, dated as of March 30, 1999 ("Amendment"), between
UNION PACIFIC RESOURCES GROUP INC., a Utah corporation (the "Company"), and
KERRY R. BRITTAIN (the "Executive") amends the Agreement between the Company
and Executive entered into on March 18, 1999 (the "Agreement"). Defined terms
used herein shall have the meanings as set forth in the Agreement unless
otherwise defined herein.
1. The Agreement is hereby amended to add a new Section 5.4 to read in
its entirety as follows:
Notwithstanding any provision herein or any provision in the Company's
1995 Stock Option and Retention Stock Plan (or any agreement entered
into thereunder) to the contrary (except any contrary provision
dealing with a pooling of interests transaction), (A) upon a Change in
Control, any Option then held by the Executive (other than an Option
the exercisability of which is based exclusively on the attainment of
performance targets which, at the time of the Change in Control, have
not been met), shall be fully exercisable and any restriction on any
Retention Share then held by the Executive (other than a Retention
Share the vesting of which is based exclusively on the attainment of
performance targets, which, at the time of the Change in Control, have
not been met) shall lapse or be deemed fully satisfied, as applicable,
and (B) if, following a Change in Control and during the term of this
Agreement, the Executive is terminated by the Company for any reason
other than Cause or the Executive terminates with Good Reason, then,
with respect to any Option then held by the Executive, the Executive
(or his Beneficiary, if applicable) shall have the right to exercise
such Option at any time during the earlier of (i) the five-year period
following such termination or (ii) the term of the Option; provided,
however, that, with respect to any provision in (A) or (B) in this
Section 5.4, if it is intended that the transaction constituting a
Change in Control be accounted for as a pooling of interests under
Accounting Principles Board Opinion No. 16 (or any successor thereto),
and if the existence and/or operation of any such provision would
violate Paragraph 47(c) thereof (or any successor thereto), then any
such provision shall (in whole or in part to the minimum extent
necessary to avoid a violation) be deemed null and void ab initio
and/or any operation of such provision shall (in whole or in part to
the minimum extent necessary to avoid a violation) be deemed to have
no force or effect under law; provided further, however, that the
foregoing proviso shall apply only if the transaction is otherwise
eligible to be accounted for as a pooling of interests.
<PAGE> 2
Except as amended hereby, all other terms and provisions shall remain
in full force and effect
IN WITNESS WHEREOF, all parties hereto have executed this Amendment as
of the date and year first above written.
UNION PACIFIC RESOURCE GROUP INC.
By:
--------------------------------
JACK L. MESSMAN
EXECUTIVE
By:
KERRY R. BRITTAIN
<PAGE> 1
EXHIBIT 10.16(c)
ASSIGNMENT AND
CONSENT TO ASSIGNMENT
THIS ASSIGNMENT AND CONSENT TO ASSIGNMENT ("Assignment") is made and
entered into this 1st day of March, 1999, by and among UNION PACIFIC FUELS, INC.
("UPFI"), UNION PACIFIC RESOURCES COMPANY ("UPRC") and KERN RIVER GAS
TRANSMISSION COMPANY ("Kern River").
RECITALS:
WHEREAS, Kern River and UPFI are parties to that certain Transportation
Agreement dated December 15, 1989 (Contract 1005), as amended, and that certain
Transportation Agreement dated December 7, 1990 (collectively, the
"Transportation Agreements"); and
WHEREAS, UPFI desires to assign the Transportation Agreements to UPRC;
NOW, THEREFORE, in consideration of the mutual covenants and agreements
herein contained, Kern River, UPFI and UPRC do hereby agree as follows:
AGREEMENT:
1. UPFI hereby assigns to UPRC all of UPFI's rights, interest and
obligations arising out of and to be received or performed
under the Transportation Agreements.
2. UPRC accepts such assignment of UPFI's rights, interests and
obligations under the Transportation Agreements. UPRC will
have the rights and obligations of the "Shipper" under the
Transportation Agreements and will be bound by the obligations
of UPFI under the Transportation Agreements to the same extent
as UPRC would be bound if UPRC, rather than UPFI, were the
signatory to the Agreements and identified as "Shipper" in the
recitals, and to the same extent as if UPRC's name appeared in
the Transportation Agreements in each place where appears the
name "UPFI." UPRC will receive any refunds or adjustments due
to UPFI with respect to Assignment, and UPRC will fulfill the
obligations of UPFI with respect to the Transportation
Agreements that arose prior to the effective date of this
Assignment, including the obligations to pay demand charges
applicable to such service.
<PAGE> 2
3. Kern River consents to the assignment of the Transportation
Agreements from UPFI to UPRC, and Kern River relieves UPFI of
any responsibilities or obligations arising under the
Transportation Agreements for services after March 31, 1999.
4. In accordance with Section 17.1 of the Transportation
Agreements, this Assignment shall become effective on April 1,
1999; provided, however, UPRC may itself, or through an agent,
nominate under the Transportation Agreements on March 31,
1999, for the gas day April 1, 1999.
5. This Assignment shall be binding upon and inure to the benefit
of the parties hereto and any successors or assigns of such
parties.
6. This Assignment may be executed in any number of counterparts.
IN WITNESS WHEREOF, Kern River, UPFI and UPRC have caused this
Assignment to be duly executed as of the date first written above
KERN RIVER GAS TRANSMISSION
COMPANY
By:
------------------------------------------------
Name: Larry E. Larsen
Title: Vice President-Customer Services and Rates
UNION PACIFIC FUELS, INC.
By:
------------------------------------------------
Name: Troy M. Smith
Title: Manager, Transportation
UNION PACIFIC RESOURCES COMPANY
By:
------------------------------------------------
Name: Robert E. Lindsey
Title: Attorney-In-Fact
<PAGE> 1
EXHIBIT 10.22 (f)
AMENDMENT NO. 5
TO
MERGER AND PURCHASE AGREEMENT
THIS AMENDMENT NO. 5 TO MERGER AND PURCHASE AGREEMENT (the "Fifth Amendment") is
made as of the 21st day of May, 1999, among Union Pacific Resources Company, a
Delaware corporation, Duke Energy Fuels, LP, now a wholly owned entity of Buyer,
and Duke Energy Field Services, Inc., a Colorado corporation.
WHEREAS, the parties heretofore entered into a Merger and Purchase
Agreement dated November 20, 1998, which was amended by the Amendment No. 1
dated as of February 1, 1999, Amendment No. 2 dated as of March 5, 1999,
Amendment No. 3 dated as of March 30, 1999, and Amendment No. 4 dated as of
March 30, 1999 (collectively, the "Amended Agreement") (capitalized terms not
otherwise defined herein have the same meanings ascribed to such terms in the
Amended Agreement);
WHEREAS, the parties hereto desire to amend the Amended Agreement as
described below by entering into this Fifth Amendment;
NOW, THEREFORE, in consideration of the premises and the mutual
agreements, representations, warranties, provisions and covenants herein
contained, the parties hereto hereby agree as follows:
1. Schedule 7.08(a) and 7.08(d) are hereby amended and restated in
their entirety as attached hereto.
2. This Fifth Amendment is executed, and shall be considered, as an
amendment to the Amended Agreement and shall form a part thereof, and the
provisions of the Amended Agreement, as amended by this Fifth Amendment, are
hereby ratified and confirmed in all respects.
3. This Fifth Amendment may be executed in any number of counterparts,
each of which shall be deemed an original, and all of which taken together shall
constitute but one and the same instrument. This Agreement shall become binding
only when each party hereto has executed and delivered to the other parties one
or more counterparts.
IN WITNESS WHEREOF, the parties hereto have duly executed this Fifth
Amendment or have caused this Fifth Amendment to be duly executed by their
respective authorized officers as of the day and year first written above.
1
<PAGE> 2
UNION PACIFIC RESOURCES COMPANY
By: /s/ Joseph A. LaSala
-------------------------------------------
Name: Joseph A. LaSala
Title: Vice President, General Counsel
And Corporate Secretary
DUKE ENERGY FUELS, LP
By: Fuels Holding Company Operating LLC
Its: General Partner
By: /s/ J.W. Mogg
-------------------------------------------
Name: J. W. Mogg
Title: President and CEO
DUKE ENERGY FIELD SERVICES, INC.
By: /s/ J.W. Mogg
-------------------------------------------
Name: J. W. Mogg
Title: President
2
<PAGE> 1
EXHIBIT 10.22 (g)
AMENDMENT NO. 6
TO
MERGER AND PURCHASE AGREEMENT
THIS AMENDMENT NO. 6 TO MERGER AND PURCHASE AGREEMENT (the "Sixth Amendment") is
made as of the 16th day of February, 2000, among Union Pacific Resources
Company, a Delaware corporation, Duke Energy Fuels, LP, now a wholly owned
entity of Buyer, and Duke Energy Field Services, Inc., a Colorado corporation.
WHEREAS, the parties heretofore entered into a Merger and Purchase
Agreement dated November 20, 1998, which was amended by the Amendment No. 1
dated as of February 1, 1999, Amendment No. 2 dated as of March 5, 1999,
Amendment No. 3 dated as of March 30, 1999, Amendment No. 4 dated as of March
30, 1999, and Amendment No. 5 dated as of May 21, 1999 (collectively, the
"Amended Agreement") (capitalized terms not otherwise defined herein have the
same meanings ascribed to such terms in the Amended Agreement);
WHEREAS, the parties hereto desire to amend the Amended Agreement as
described below by entering into this Sixth Amendment;
NOW, THEREFORE, in consideration of the premises and the mutual
agreements, representations, warranties, provisions and covenants herein
contained, the parties hereto hereby agree as follows:
1. Within 5 days after the execution of this Sixth Amendment, Seller
shall pay Duke Energy Gathering and Processing, L.P. invoice #0200-CONR-200105
in the amount of $132,000. The parties agree that such payment is in complete
and full satisfaction of all obligations of Seller under Section 7.18 of the
Amended Agreement.
2. Within 5 days after execution of this Sixth Amendment, Seller shall
pay Edwards Cotton Valley, Inc. invoice #0200-EDWD-990180 in the amount of
$627,869.60. The parties agree that such payment is in full and complete
settlement of any and all claims or Damages, known or unknown, which have been
or may be asserted by Buyer in respect of the Edwards Plant (North Fayette
Treater) capacity, operations, capital requirements or completion costs
including, without limitation, the sour water stripper, filter separator, vapor
recovery unit, acid gas injection pump and gas to gas exchanger.
3. This Sixth Amendment is executed, and shall be considered, as an
amendment to the Amended Agreement and shall form a part thereof, and the
provisions of the Amended Agreement, as amended by this Sixth Amendment, are
hereby ratified and confirmed in all respects.
4. This Sixth Amendment may be executed in any number of counterparts,
each of which shall be deemed an original, and all of which taken together shall
constitute but one and the
<PAGE> 2
same instrument. This Agreement shall become binding only when each party hereto
has executed and delivered to the other parties one or more counterparts.
IN WITNESS WHEREOF, the parties hereto have duly executed this Sixth
Amendment or have caused this Sixth Amendment to be duly executed by their
respective authorized officers as of the day and year first written above.
UNION PACIFIC RESOURCES COMPANY
By: /s/ Joseph A. LaSala
----------------------------------------
Name: Joseph A. LaSala
Title: Vice President, General Counsel
And Corporate Secretary
DUKE ENERGY FUELS, LP
By: Fuels Holding Company Operating LLC
Its: General Partner
By: /s/ Mark A. Borer
----------------------------------------
Name: Mark A. Borer
Title: Senior Vice President
DUKE ENERGY FIELD SERVICES, INC.
By: /s/ Mark A. Borer
----------------------------------------
Name: Mark A. Borer
Title: Senior Vice President
2
<PAGE> 1
EXHIBIT 10.22(h)
MASTER NATURAL GAS LIQUIDS PURCHASE AGREEMENT
BETWEEN
UNION PACIFIC RESOURCES COMPANY
AND
UNION PACIFIC FUELS, INC.
<PAGE> 2
TABLE OF CONTENTS
<TABLE>
<CAPTION>
Page
<S> <C> <C>
ARTICLE I
DEFINITIONS...............................................................................1
1.1 General.................................................................1
1.2 Other Definitions.......................................................6
ARTICLE II
OBLIGATION TO SELL AND PURCHASE...........................................................6
2.1 General.................................................................6
2.2 NGLs Reserved by UPR....................................................7
2.3 Availability Report.....................................................7
2.4 Ratable Basis...........................................................7
2.5 UPFUELS Deficiency Quantity.............................................7
ARTICLE III
DELIVERIES AND TRANSPORTATION CONTRACTS...................................................8
3.1 General.................................................................8
3.2 Location of Delivery Point(s)...........................................8
3.3 Title and Risk of Loss..................................................9
3.4 General Rules for Transporting and Delivering NGLs at Delivery Points...9
3.5 Consolidation of Deliveries............................................10
3.6 Transportation Contracts...............................................10
ARTICLE IV
QUALITY..................................................................................11
4.1 Specifications.........................................................11
4.2 Failure to Conform.....................................................11
4.3 Offspec NGLs...........................................................12
4.4 Waiver.................................................................12
ARTICLE V
MEASUREMENT AND ANALYSES.................................................................12
5.1 General................................................................12
</TABLE>
<PAGE> 3
<TABLE>
<CAPTION>
Page
<S> <C> <C>
ARTICLE VI
PRICE.....................................................................................13
6.1 Purity Product Sales....................................................13
6.2 Raw NGL Mix Sales.......................................................13
6.3 Marketing Fee...........................................................14
6.4 Replacement of Index....................................................14
6.5 Sharing of Incentive Rates..............................................14
6.6 Lock-In of Fractionation Costs..........................................14
ARTICLE VII
ACCOUNTING, BILLING AND PAYMENT..........................................................15
7.1 Statements and Payment.................................................15
7.2 Disputed Payments......................................................15
7.3 Overdue Payments.......................................................16
7.4 Two Year Limit on Adjustments..........................................16
7.5 Audit..................................................................16
7.6 Letter of Credit; Credit Enhancement...................................16
ARTICLE VIII
DISCLAIMER AND WARRANTY..................................................................17
8.1 Warranty...............................................................17
8.2 Disclaimer.............................................................17
ARTICLE IX
FORCE MAJEURE............................................................................18
9.1 Suspension of Obligations..............................................18
9.2 Force Majeure Defined..................................................18
9.3 Exclusions.............................................................18
9.4 Labor Disputes.........................................................19
ARTICLE X
TAXES....................................................................................19
10.1 General................................................................19
10.2 Evidence of Exemption from Tax.........................................19
10.3 New Taxes..............................................................19
</TABLE>
<PAGE> 4
<TABLE>
<CAPTION>
Page
<S> <C> <C>
ARTICLE XI
TERM, DEFAULT AND REMEDIES...............................................................20
11.1 Term...................................................................20
11.2 Defaults...............................................................20
11.3 Consequences of Defaults...............................................22
11.4 Setoff Rights..........................................................22
ARTICLE XII
DISPUTE RESOLUTION PROCEDURES............................................................23
12.1 General Dispute Resolution Provisions..................................23
12.2 Special Provisions Applicable to Price Disputes........................26
ARTICLE XIII
NON-ASSIGNABILITY AND TRANSFER OF INTEREST BY PARTIES;
CHANGES OF CONTROL.......................................................................26
13.1 Non-Assignability......................................................26
13.2 Change of Control......................................................27
ARTICLE XIV
MISCELLANEOUS............................................................................27
14.1 No Continuing Waiver...................................................27
14.2 Government Regulation..................................................27
14.3 Exclusion of Consequential Damages.....................................28
14.4 Notices................................................................28
14.5 Choice of Law..........................................................29
14.6 Integration............................................................29
14.7 Confidentiality........................................................29
14.8 Construction of Agreement..............................................30
14.9 Representations and Warranties of UPR..................................31
14.10 Representations and Warranties of UPFUELS..............................31
14.11 No Third Party Beneficiaries...........................................32
14.12 Further Assurances.....................................................32
14.13 Exhibits...............................................................32
</TABLE>
<PAGE> 5
EXHIBITS
Exhibit "A"
Exhibit "B"
Exhibit "C"
Exhibit "D"
Exhibit "E"
SCHEDULES
Schedule 2.5
Schedule 3.6
Schedule 6.5
<PAGE> 6
MASTER NATURAL GAS LIQUIDS PURCHASE AGREEMENT
THIS NATURAL GAS LIQUIDS PURCHASE AGREEMENT (the "Agreement") is made
and entered into this 20th day of November, 1998, but effective as of the 1st
Day of January, 1999 ("Effective Date"), by and between UNION PACIFIC RESOURCES
COMPANY, a Delaware corporation (referred to as "UPR"), and UNION PACIFIC FUELS,
INC., a Delaware corporation (referred to as "UPFUELS"). UPR and UPFUELS are
sometimes referred to collectively as "Parties" or individually referred as a
"Party."
W I T N E S E T H:
WHEREAS, UPR has quantities of NGLs available for sale from certain gas
processing plants that it desires to sell to UPFUELS, and UPFUELS desires to
purchase such NGLs from UPR; and
WHEREAS, UPR and UPFUELS acknowledge that the purpose of this Agreement
is to provide for the marketing of UPR's NGLs recovered in UPFUELS' plants and
in third-party plants under terms that are fair and equitable for both Parties.
NOW, THEREFORE, in consideration of the premises and for the mutual
benefit of the Parties as well as for other good and valuable consideration,
UPFUELS and UPR agree as follows:
ARTICLE I
DEFINITIONS
1.1 GENERAL. As used in this Agreement, the following terms shall
have the following meanings:
"Affiliate" shall mean any Person Controlling, Controlled by,
or under common Control with another Person, whether directly or
through one or more intermediaries.
"Alternate Index" shall have the meaning specified in Section
6.4.
"Arithmetical Monthly Average Price" means the sum of the
Daily Prices for all Days in a Month on which OPIS publishes prices for
NGLs, divided by the number of Days on which OPIS publishes prices for
NGLs in such Month.
<PAGE> 7
"Barrel" shall mean forty-two (42) U.S. Gallons.
"Base Rate" shall mean the lesser of (i) two percent (2%)
above the per annum rate of interest announced from time to time as the
"prime rate" for commercial loans by Chase Manhattan Bank of New York,
as such "prime rate" may change from time to time, or (ii) the maximum
applicable non-usurious rate of interest.
"Business Day" shall mean a Day on which commercial banks in
Fort Worth, Texas are open for business.
"Component(s)" shall mean, as applicable, individual NGLs that
are Purity Products or the individual hydrocarbons contained in Raw NGL
Mix, including, but not limited to, Propane, Normal Butane, Isobutane,
Natural Gasoline and Ethane.
"Control," "Controlling," "Controlled" or terms of similar
import shall mean with respect to a corporation or limited liability
company, the right to exercise, directly or indirectly, more than fifty
(50%) percent of the voting rights attributable to the controlled
corporation or limited liability company, and, with respect to any
other Person, the possession, directly or indirectly, of the power to
direct or cause the direction of the management or policies of the
controlled entity.
"Conway T&F Costs" shall mean (i) all direct Transportation
Costs (including but not limited to Pipeline Transportation Costs),
reasonably incurred and necessary to transport Subject NGLs from the
relevant Delivery Point(s) to Conway or Bushton, Kansas, (ii)
fractionation fees incurred at Conway or Bushton, Kansas, in respect of
Subject NGLs pursuant to contracts with the fractionator(s) of the
Subject NGLs, including but not limited to any loss at such
fractionator(s) and (iii) all other reasonably incurred direct costs
and expenses (including but not limited to the Marketing Fee, if
applicable) necessary to transport, fractionate or market Subject NGLs
to, or at, Conway or Bushton, Kansas. It is understood and agreed that
(x) Conway T&F Costs shall not include any portion of UPFUELS' general
and administrative costs and expenses and (y) any Conway T&F Costs
directly or indirectly charged to UPR hereunder by an Affiliate of
UPFUELS shall not exceed the fair market value of the same or
comparable goods and services that would have been charged to UPR in an
arm's-length transaction between Persons who are not Affiliates.
"Daily Price" shall mean the arithmetical average, for any Day
on which OPIS publishes prices for NGLs, of the Daily high-low price
quoted by OPIS for any Component of the Subject NGLs that is sold at an
NGL Market Center. The Daily Price shall be determined on the basis of
(i) purity Ethane, and non-TET for all other Purity Products sold at
Mont Belvieu, Texas, or, as applicable, (ii) Conway/Group 140 - MAPCO
for sales at Conway or Bushton, Kansas. Specialty or other specific
OPIS price quotations for NGL Market Centers shall be disregarded.
2
<PAGE> 8
"Day" shall mean a period of 24 consecutive hours beginning at
7:00 a.m. local time where the relevant plant or Delivery Point(s) are
located and extending until 7:00 a.m. local time on the following Day,
or other mutually agreeable times for specific plants.
"Delivery Point(s)" shall mean, subject to the applicable
provisions of Article III, (i) the Existing Delivery Point(s) (as
defined in Section 2.1(a)), (ii) the locations where delivery of
Subject NGLs is made at the Existing Plants (as defined in Section
2.1(a)) and (iii) all other delivery points for Subject NGLs that are
mutually agreeable to the Parties, including but not limited to
Delivery Points described in 2.1(a)(iii).
"Effective Date" shall have the meaning set forth in the
preamble.
"Ethane" shall mean a liquid hydrocarbon which meets the
specifications (including allowable methane) set forth in Exhibit "A."
"Gallon" shall mean the unit of volume used for the purpose of
measurement of liquid. One (1) U.S. liquid Gallon contains two hundred
thirty-one (231) cubic inches when the liquid is at a temperature of
sixty degrees Fahrenheit (60(degree)/F) and at the vapor pressure of
the liquid being measured.
"Isobutane" shall mean a liquid hydrocarbon which meets the
specifications set forth in Exhibit "A."
"Local Sales" shall mean sales of Subject NGLs that do not
occur at an NGL Market Center.
"Marketing Fee" shall have the meaning set forth in Section
6.3.
"Mont Belvieu T&F Costs" shall mean (i) all direct
Transportation Costs (including but not limited to Pipeline
Transportation Costs) reasonably incurred and necessary to transport
Subject NGLs from the relevant Delivery Point(s) to Mont Belvieu,
Texas, (ii) fractionation fee(s) incurred at Mont Belvieu, Texas
pursuant to contracts with the fractionator(s) of the Subject NGLs
including but not limited to any loss at such fractionator(s) and (iii)
all other reasonably incurred direct costs and expenses (including but
not limited to the Marketing Fee, if applicable) necessary to
transport, fractionate or market Subject NGLs to, or fractionate them
at, Mont Belvieu, Texas. It is understood and agreed that (x) Mont
Belvieu T&F Costs shall not include any portion of UPFUELS' general and
administrative costs and expenses and (y) any Mont Belvieu T&F Costs
directly or indirectly charged to UPR hereunder by an Affiliate of
UPFUELS shall not exceed the fair market value of the same or
comparable goods and services that would have been charged to UPR in an
arm's-length transaction between Persons who are not Affiliates.
"Month" means the period commencing on the first Day of a
calendar month and ending on the first Day of the immediately following
calendar month.
3
<PAGE> 9
"Natural Gasoline" shall mean a liquid hydrocarbon which meets
the specifications set forth in Exhibit "A."
"Netback Price" shall mean (i) the Arithmetical Monthly
Average Price for the relevant Component of the Subject NGLs, if
UPFUELS resells such Components at an NGL Market Center or (ii) the
price obtained by UPFUELS in an arm's-length sale of Subject NGLs to a
third Person at a location other than an NGL Market Center, less (a)
reasonably incurred direct T&F Costs (including, as applicable, Mont
Belvieu or Conway T&F Costs) necessary to transport such NGLs to, or
fractionate them at, the point of resale by UPFUELS, (b) all other
reasonably incurred direct costs and expenses (including but not
limited to the Marketing Fee, if applicable) necessary to transport,
fractionate or market such NGLs to, or fractionate them at, the point
of resale by UPFUELS.
"NGLs" shall mean (i) Purity Products and (ii) Raw NGL Mix.
"NGL Market Center" shall mean the NGL market centers at
Conway, Kansas, and Mont Belvieu, Texas or any other NGL market center
whose prices for NGLs are quoted by OPIS.
"Normal Butane" shall mean a liquid hydrocarbon which meets
the specifications set forth in Exhibit "A."
"Offspec NGLs" shall have the meaning set forth in Section
4.1.
"OPIS" shall mean the Oil Price Information Service or its
successor.
"Party" and "Parties" shall have the meanings given such terms
in the preamble to this Agreement.
"Person" shall mean any individual or entity, including,
without limitation, any corporation, limited liability company,
partnership (whether general or limited), joint venture, association,
joint stock company, trust, business trust, cooperative, unincorporated
organization, government (including, without limitation, any board,
agency, political subdivision or other body thereof) or entities
similar to any of the foregoing that are organized under the laws of
foreign jurisdictions.
"Pipeline Capacity Constraint" shall mean an event of Force
Majeure or excess shipper demand affecting a pipeline that would
otherwise be capable of accepting delivery of and transporting Subject
NGLs.
"Pipeline Price" shall mean the price being paid for NGLs sold
at NGL Market Centers, less T&F Costs.
"Pipeline Transportation Costs" shall mean all reasonably
incurred direct costs and expenses necessary for the transportation of
Subject NGLs by pipeline. In those situations
4
<PAGE> 10
when it is necessary to transport Subject NGLs by truck or railcars
from the relevant Delivery Point(s) to a pipeline receipt point, such
costs and expenses (including rail car rentals) shall be included as
part of the applicable Pipeline Transportation Costs. It is understood
and agreed that (i) Pipeline Transportation Costs shall not include any
portion of UPFUELS' general and administrative costs and expenses and
(ii) any Pipeline Transportation Costs directly or indirectly charged
to UPR hereunder by an Affiliate of UPFUELS shall not exceed the fair
market value of the same or comparable goods and services that would
have been charged to UPR in an arm's-length transaction between Persons
who are not Affiliates.
"Propane" shall mean a liquid hydrocarbon which meets the
specifications set forth in Exhibit "A."
"Purity Products" shall mean purity products of Ethane,
Propane, Isobutane, Normal Butane and Natural Gasoline, or any
combination of any of the foregoing Components, if such combination has
been agreed upon by the Parties.
"Raw NGL Mix" shall mean the mixed liquid hydrocarbon stream
produced at a gas processing plant and delivered to UPFUELS at the
Delivery Point at the tailgate of said plant, or as may be otherwise
mutually agreed by the Parties.
"Subject NGLs" shall have the meaning set forth in Section
2.1(a).
"Taxes" shall mean any and all ad valorem, property,
occupation, severance, production, extraction, first use, conservation,
Btu or energy, gathering, transport, pipeline, utility, gross receipts,
gas or oil revenue, gas or oil import, privilege, sales, use,
consumption, excise, lease, transaction, environmental, and other
taxes, governmental charges, duties, licenses, fees, permits, and
assessments.
"T&F Costs" shall mean (i) all direct Transportation Costs,
(ii) fractionation fees incurred pursuant to contracts with the
fractionator(s) of the Subject NGLs, including but not limited to any
loss at such fractionator(s) and (iii) all other reasonably incurred
direct costs and expenses (including but not limited to the Marketing
Fee, if applicable) necessary to fractionate Subject NGLs. It is
understood and agreed that (i) T&F Costs shall not include any portion
of UPFUELS' general and administrative costs and expenses and (ii) any
T&F Costs directly or indirectly charged to UPR hereunder by an
Affiliate of UPFUELS shall not exceed the fair market value of the same
or comparable goods and services that would have been charged to UPR in
an arm's-length transaction between Persons who are not Affiliates.
"Transportation Costs" shall mean all reasonably incurred
direct costs and expenses necessary to transport Subject NGLs from the
Delivery Point(s) where they are received by UPFUELS to the location
where they are sold by UPFUELS, including, without limitation, (i)
railcar, barges, and truck costs and expenses (including rail car
rentals); (ii) NGL gains or losses that occur during transportation for
reasons other than the negligence or willful misconduct of UPFUELS and
(iii) all other direct costs and expenses reasonably incurred in
loading, unloading, transporting, terminaling, blending, treating,
odorizing, pumping,
5
<PAGE> 11
deficiency, storing (if required), and handling such NGLs. It is
understood and agreed that (x) Transportation Costs shall not include
any portion of UPFUELS' general and administrative costs and expenses
and (y) any Transportation Costs directly or indirectly charged to UPR
hereunder by an Affiliate of UPFUELS shall not exceed the fair market
value of the same or comparable goods and services that would have been
charged to UPR in an arm's-length transaction between Persons who are
not Affiliates.
"UPFUELS Deficiency Quantity" shall have the meaning set forth
in Section 2.5.
1.2 OTHER DEFINITIONS. Other terms may be defined elsewhere in the
text of this Agreement and shall have the meanings indicated throughout this
Agreement.
ARTICLE II
OBLIGATION TO SELL AND PURCHASE
2.1 GENERAL.
(a) UPR'S OBLIGATION TO SELL NGLS. Subject to the terms of
this Agreement (including, without limitation, an event of Force Majeure or any
other reason excusing the performance of UPR's obligations hereunder), UPR
agrees to sell and deliver, or cause to be sold and delivered, to UPFUELS any
NGLs owned by UPR , or which UPR has the right to sell, and are: (i) recovered
at the processing plants listed in Exhibit "B" (the "Existing Plants", being all
the processing plants at which NGLs owned by UPR, or which UPR has the right to
sell, are being recovered as of the Effective Date), (ii) delivered to the
Delivery Points listed in Exhibit "C" (the "Existing Delivery Points", being all
the delivery points at which NGLs owned by UPR, or which UPR has the right to
sell, are being delivered as of the Effective Date or (iii) delivered to a
delivery point which is not an Existing Plant or an Existing Delivery Point and
the natural gas from which such NGLs were derived is subject to a gathering or
processing agreement with UPFUELS on the Effective Date; such NGLs being
referred to as the "Existing Source NGLs". The Existing Source NGLs shall be
sometimes herein called the "Subject NGLs." Notwithstanding the foregoing, UPR
shall have no obligation to own, operate or maintain any interest in any
processing plant, fractionation plant or other facility for the production or
recovery of NGLs, or to incur any capital expenditure whatsoever related to the
production or recovery of NGLs, including but not limited to any capital
expenditures for the exploration, drilling or production of natural gas or other
gaseous hydrocarbon streams from which NGLs may be produced.
(b) UPFUELS' OBLIGATION TO PURCHASE NGLS. Subject to the terms
of this Agreement (including, without limitation, an event of Force Majeure or
any other reason excusing the performance of UPFUELS' obligations hereunder),
UPFUELS agrees to purchase from UPR 100% of the Subject NGLs made available for
sale hereunder at each Delivery Point provided for herein including but not
limited to the Delivery Points contemplated by Section 2.1 (a)(iii) above.
Notwithstanding the foregoing, UPFUELS shall have no obligation to own, operate
or maintain any
6
<PAGE> 12
interest in any processing plant, fractionation plant or other facility for the
production or recovery of NGLs, or to incur any capital expenditure whatsoever
related to the production or recovery of NGLs.
2.2 NGLS RESERVED BY UPR. Notwithstanding the provisions of
Section 2.1, UPR shall retain its right, title and interest to (i) all of its
condensate and sulphur which it takes in kind, without regard to where such
condensate and sulphur are produced or delivered and (ii) any NGLs owned or
controlled by UPR other than Subject NGLs.
2.3 AVAILABILITY REPORT. Beginning January 1999, and for each
subsequent Month during the term of this Agreement, UPR and UPFUELS shall
jointly develop an Availability Report (the "Availability Report") setting forth
the Parties' best estimate of the quantity, type of Purity Products and/or
Components of Subject NGLs that UPR will deliver to UPFUELS from each plant and
at each Delivery Point during the following Month. The Availability Report shall
be completed by the 25th Day of the Month prior to the Month during which such
Subject NGLs are to be delivered. The Monthly Availability Report shall be on a
Component-by- Component basis, and shall be deemed available for ratable
delivery throughout the Month. If the Parties cannot agree on an Availability
Report by the 25th Day of such Month, then the forecast for the relevant Month
shall be the actual deliveries of NGLs (by location and Component) for the
immediately preceding Month. The Parties shall use commercially reasonable
efforts to keep each other informed of significant Daily variations in the
quantities of Subject NGLs available for purchase and sale hereunder.
2.4 RATABLE BASIS. The Parties shall use reasonable efforts to
deliver and receive, as applicable, NGLs on a ratable Daily basis.
2.5 UPFUELS DEFICIENCY QUANTITY.
(a) UPFUELS DEFICIENCY QUANTITY. Unless performance is excused
by Force Majeure or another provision of this Agreement, if, during any Month,
UPFUELS fails to purchase at least 95% of all quantities of Subject NGLs that
UPR makes available at each Delivery Point (including but not limited to
Delivery Points at processing plants) for sale pursuant to Section 2.1(a)
(regardless of whether such quantities have been included in the Availability
Report), UPFUELS shall pay UPR, within ten (10) Days after receipt of UPR's
invoice, an amount equal to the product obtained by multiplying (i) the
difference between the quantity of Subject NGLs actually purchased by UPFUELS
and 95% of the quantity of Subject NGLs actually made available by UPR or such
higher volume as required to assure no interruption in plant operations due to
storage limitations, at each relevant Delivery Point (the "UPFUELS Deficiency
Quantity") by (ii) the positive total, if any, of (a) the price that UPFUELS
would have paid for the UPFUELS Deficiency Quantity under this Agreement plus
any applicable Marketing Fee less (b) the difference between (1) the price UPR
obtains in an arm's-length sale to a third Person of the UPFUELS Deficiency
Quantity, and (2) the
7
<PAGE> 13
T&F Costs and other costs incurred by UPR in connection with such arm's-length
sale or UPFUELS' failure to purchase the UPFUELS Deficiency Quantity, including
without limitation costs of storing the UPFUELS Deficiency Quantity, plus (c) an
amount, as liquidated damages, equal to one quarter of one cent per Gallon
($0.0025), multiplied by the UPFUELS Deficiency Quantity, to cover UPR's
administrative and operational costs and expenses. An example of the formula to
determine, and a sample calculation of, the UPFUELS Deficiency Quantity amount
is set forth on Schedule 2.5 attached hereto and made a part hereof. In the
event of a conflict between the provisions of this Agreement and Schedule 2.5,
the provisions of Schedule 2.5 shall control. The UPFUELS Deficiency Quantity
shall be released to UPR, at UPR's option for the remainder of such Month in
order to permit UPR to mitigate its losses through the sale of the UPFUELS
Deficiency Quantity to third Persons, and UPR shall use commercially reasonable
efforts to market the UPFUELS Deficiency Quantity.
(b) It is specifically understood and agreed that the
provisions of Section 2.5(a) are not intended to relieve UPFUELS of its
obligation under Section 2.1(b) to purchase 100% of all quantities of Subject
NGLs that UPR makes available at each processing plant and Delivery Point during
each Month of the term of this Agreement, but rather to prevent the shutdown or
curtailment of operations at processing plants at which Subject NGLs are
recovered due to the failure of UPFUELS to remove Subject NGLs available for
purchase at such plants and at the Delivery Points provided for herein.
(c) EXCLUSIVE CONSEQUENCES OF UPFUELS' FAILURE TO PURCHASE
SUBJECT NGLS. TO THE EXTENT THAT DAMAGES IN RESPECT OF UPFUELS' FAILURE TO TAKE
SUBJECT NGLs ARE LIQUIDATED, THE PARTIES ACKNOWLEDGE AND AGREE THAT ACTUAL
DAMAGES ARE DIFFICULT OR IMPOSSIBLE TO DETERMINE, OTHERWISE OBTAINING AN
ADEQUATE REMEDY IS INCONVENIENT AND THE LIQUIDATED DAMAGES PROVIDED FOR HEREIN
CONSTITUTE A REASONABLE APPROXIMATION OF THE HARM OR LOSS RESULTING FROM SUCH A
FAILURE. ALL OTHER REMEDIES OR DAMAGES AT LAW OR IN EQUITY RELATING TO SUCH
FAILURE ARE WAIVED, RELEASED AND RELINQUISHED IN RESPECT OF SUCH FAILURE. THE
PARTIES ACKNOWLEDGE THAT THE CONSEQUENCES OF THE FAILURE DESCRIBED IN THIS
ARTICLE II ARE DIFFICULT OR IMPOSSIBLE TO DETERMINE AND THAT THE REMEDIES SET
FORTH HEREIN RESPECTING SUCH FAILURE CONSTITUTE A REASONABLE APPROXIMATION OF
THE HARM OR LOSS THAT WOULD BE SUFFERED BY UPR AS A RESULT OF SUCH FAILURE.
ARTICLE III
DELIVERIES AND TRANSPORTATION CONTRACTS
3.1 GENERAL. The Subject NGLs shall be delivered by UPR (or at
UPR's direction) to UPFUELS or to UPFUELS' designated representative for the
account of UPFUELS, at the Delivery Point(s), subject to and in accordance with
the applicable terms and conditions of this Article III.
3.2 LOCATION OF DELIVERY POINT(S). The Delivery Point(s) for
Subject NGLs sold and delivered hereunder shall be determined as follows:
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(a) PIPELINE DELIVERY POINTS. If delivery is to be to or from
a pipeline, the Delivery Point shall be located, and delivery of NGLs shall be
deemed to occur, at the point at which such NGLs pass the pipeline meter. If
pipeline delivery is by in-line inventory transfer, delivery shall be deemed to
occur on the date and time that the relevant pipeline carrier advises UPR and
UPFUELS, by product transfer order, book transfer, or letter of transfer, that
NGLs shall be transferred to UPFUELS' account, and the Delivery Point shall be
the location of the NGLs in the pipeline of the pipeline carrier on the Day and
time that such in-line transfer of NGLs is deemed to occur. The Parties hereto
understand and agree that UPFUELS has no control over the operations of the
pipeline carrier and therefore cannot control when NGLs transferred to UPFUELS'
account by the pipeline carrier will, in fact, occur.
(b) RAILCAR, TRUCK AND BARGE DELIVERY POINTS. If delivery is
to be by or into a railcar, truck or barge owned, operated, leased, or hired by
UPFUELS, the Delivery Point shall be located, and delivery of NGLs shall be
deemed to occur, at the point at which the NGLs pass from the flange connecting
the loading facility to UPFUELS' owned, operated, leased, or hired railcar,
truck, or barge whether said railcar, truck, or barge is loaded by UPR or
UPFUELS directly or on behalf of UPR or UPFUELS through UPR's or UPFUELS' agent.
3.3 TITLE AND RISK OF LOSS. Title to the Subject NGLs delivered by
UPR to UPFUELS and risk of loss (other than those allowable gains and losses
specified herein) shall pass to UPFUELS at the Delivery Points. All charges,
royalties, lease burdens, expenses, fees, claims, damages, demands, injuries and
other costs or losses incurred in or attributable to production and transfer,
transportation (except as otherwise agreed by the Parties), and handling of the
Subject NGLs delivered in accordance with this Agreement prior to delivery to
UPFUELS at the Delivery Point(s) shall be the exclusive responsibility of UPR,
as between the Parties, and UPR shall indemnify, defend, and hold harmless
UPFUELS from all such charges, royalties, lease burdens, expenses, fees, taxes,
claims, damages, demands, injuries, and other costs or losses. All charges,
expenses, fees, taxes, claims, damages, demands, injuries and other costs or
losses incurred in or attributable to the purchase and transfer, transportation,
and handling of the Subject NGLs delivered in accordance with this Agreement at
and after delivery of the Subject NGLs at the Delivery Point(s) shall be the
exclusive responsibility of UPFUELS, as between the Parties, and UPFUELS shall
indemnify, defend, and hold harmless UPR from all such charges, expenses, fees,
taxes, claims, damages, demands, injuries, and other costs or losses, unless
such claims arise from UPFUELS' unknowing acceptance of Offspec NGLs delivered
at a plant operated by third Persons. In addition, each of the Parties hereto
shall indemnify and hold the other harmless from any losses and damages arising
out of the operations conducted hereunder by such indemnifying Party to the
extent resulting from the negligent acts or willful misconduct of such
indemnifying Party, its agents or its employees.
3.4 GENERAL RULES FOR TRANSPORTING AND DELIVERING NGLS AT DELIVERY
POINTS. The following rules shall be applicable to the transportation and
loading of NGLs at the Delivery Point(s) situated at facilities neither owned
nor operated by UPFUELS:
(a) The loading of NGLs at the applicable Delivery Point(s)
shall be performed in accordance with schedules mutually agreed to by the
Parties.
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(b) If UPFUELS' or UPFUELS' designees' owned or leased trucks
are used to transport NGLs from the Delivery Point, UPR or its designees agree
to load such trucks upon arrival at the Delivery Point. Notwithstanding the
foregoing, UPR or its designees shall have the right to refuse to load any truck
that fails to meet Department of Transportation or other laws, rules,
regulations or standards that are applicable from time to time.
3.5 CONSOLIDATION OF DELIVERIES. Notwithstanding anything
contained herein to the contrary, UPR shall be allowed to consolidate its
deliveries of NGLs behind one or more Delivery Points so long as (i) sufficient
notice is provided UPFUELS and (ii) such consolidation does not have any
economic effect on UPFUELS.
3.6 TRANSPORTATION CONTRACTS.
(a) GENERALLY. Contemporaneously with the execution and delivery of
this Agreement, UPFUELS has succeeded to the rights and obligations of UPFUELS,
an Affiliate of UPR, under the transportation contracts listed in Schedule 3.6
(the "Transportation Contracts"). UPFUELS agrees that the rights to allocated
pipeline capacity set forth in the Transportation Contracts shall be exclusively
committed to transportation of Subject NGLs. UPR shall reimburse UPFUELS for,
and/or indemnify UPFUELS against, costs and expenses that it incurs under the
Transportation Contracts for volume deficiencies associated with the minimum
volume commitment obligations to transport Subject NGLs thereunder. The
computation of any such deficiencies shall be included in the statement to be
delivered by UPFUELS to UPR pursuant to Section 7.1, and UPR agrees that such
costs may be offset by UPFUELS against payments due UPR hereunder.
(b) OBLIGATIONS OF UPFUELS REGARDING TRANSPORTATION CONTRACTS.
UPFUELS covenants and agrees as follows:
(i) PAYMENT AND PERFORMANCE OF OBLIGATIONS. UPFUELS will pay
all amounts due and owing by it under the Transportation Contracts, shall
observe, perform and comply with every covenant, term and condition set forth
therein and shall otherwise keep such Transportation Contracts in full force and
effect;
(ii) NOTICE OF DEFAULTS, DISPUTES AND LITIGATION. Promptly
after becoming aware of the same, UPFUELS shall notify UPR of any breach or
default under any of the Transportation Contracts, or any disputes or litigation
(whether administrative, judicial or arbitral) in connection with the
Transportation Contracts that could reasonably be expected to have an adverse
effect on (a) UPFUELS' ability to transport Subject NGLs thereunder or (b) the
prices for Subject NGLs realized by UPR hereunder, and shall keep UPR informed,
on an ongoing basis, of material developments in any such disputes or
litigation;
(iii) COMPLIANCE WITH LAWS. UPFUELS shall comply in all
material respects with all laws, rules and regulations applicable to the
performance of its obligations under the Transportation Contracts;
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(iv) PROHIBITION ON UNILATERALLY INCREASING TRANSPORTATION
COSTS; COMMERCIALLY REASONABLE EFFORTS TO MINIMIZE TRANSPORTATION COSTS. Without
the prior written consent of UPR (such consent not to be unreasonably withheld),
UPFUELS shall not take any act that would (a) increase transportation rates
under the Transportation Contracts (including but not limited to supporting an
increase in the rates of a transporter under the Transportation Contracts in a
rate case or other administrative proceeding), (b) result in higher UPR payments
under Section 3.6 in respect of volume deficiencies or (c) otherwise increase
Transportation Costs (including but not limited to Pipeline Transportation
Costs), and shall use all commercially reasonable efforts to minimize
Transportation Costs thereunder (it being understood and agreed, however, that
UPFUELS or its Affiliates may increase transportation rates if such rates (x)
are uniformly applied to all shippers and (y) are permitted under the
Transportation Contracts and applicable law);
(v) RESTRICTION ON AMENDMENT OF TRANSPORTATION CONTRACTS.
Without the prior written consent of UPR (such consent not to be unreasonably
withheld), UPFUELS shall not amend any Transportation Contract if such amendment
would result in higher transportation rates or would otherwise increase
Transportation Costs (including but not limited to Pipeline Transportation
Costs), whether by change in a receipt point or delivery point under such
Transportation Contract, or otherwise, and UPFUELS shall promptly advise UPR if
UPFUELS has received any proposed notice of rate increase, amendment or other
request from a transporter under any Transportation Contract or pipeline tariff
that would have the effect of increasing Transportation Costs; and
(vi) RESTRICTION ON TERMINATION OR ASSIGNMENT OF
TRANSPORTATION CONTRACTS. UPFUELS shall not terminate, assign, pledge, mortgage,
transfer or hypothecate all or any portion of its rights under any
Transportation Contract without the prior written consent of UPR, which consent
may be withheld in its sole discretion for any reason.
ARTICLE IV
QUALITY
4.1 SPECIFICATIONS. All NGLs sold by UPR and purchased by UPFUELS
hereunder shall meet (i) the specifications set forth in Exhibit "A," which is
attached hereto and made a part hereof for all purposes and (ii) the standards
set forth in GPA 84-2177, as amended from time to time, or other generally
accepted industry standards, as revised from time to time. UPFUELS shall have
the right to reject any NGLs which fail to meet such quality specifications
("Offspec NGLs"), subject, however, to the provisions of Section 4.2.
Notwithstanding the foregoing, UPFUELS shall not have the right to reject
Offspec NGLs produced at and delivered from a processing or fractionation plant
owned and/or operated by UPFUELS or its Affiliates.
4.2 FAILURE TO CONFORM. Should the NGLs delivered hereunder to
UPFUELS, or to UPFUELS' designated representative for the account of UPFUELS
from a plant owned and/or operated by a Person other than UPFUELS or its
Affiliates, fail at any time to conform to the specifications provided for in
Section 4.1, either Party may notify the other Party of any such failure, and,
upon receipt of such notice, UPR shall undertake and diligently pursue such acts
as may be
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necessary to correct such failure so as to deliver NGLs conforming to
the specifications set forth above. If it is not economical for UPR to correct
such failure, then UPR shall notify UPFUELS to such effect, and UPFUELS shall
sell the Offspec NGLs on the best terms and conditions available for such
Offspec NGLs at the time of sale, remitting to UPR actual realized value from
such sale less the applicable Marketing Fee, as determined in accordance with
the applicable provisions of Article VI.
4.3 OFFSPEC NGLS. Notwithstanding the foregoing, UPFUELS shall not
be entitled to a discounted price for any Offspec NGLs produced at and delivered
from a processing or fractionation plant owned and/or operated by UPFUELS or its
Affiliates if, immediately prior to the Effective Date of this Agreement, any
such plant was producing, or if not then producing, was capable of producing,
NGLs that met the applicable specifications provided for in Section 4.1, unless
the Subject NGLs were Offspec NGLs by reason of Force Majeure.
4.4 WAIVER. The knowing acceptance by UPFUELS of Offspec NGLs
other than as described in Section 4.2, above, from plants owned and/or operated
by a party other than UPFUELS or its Affiliates, shall constitute a waiver by
UPFUELS of any and all other rights and remedies available to UPFUELS under this
Agreement or otherwise with respect to UPR's tender of such Offspec NGLs, and
all risk of loss, damage or liability arising out of UPFUELS' ownership,
control, possession, or use of such Offspec NGLs shall pass to and be borne by
UPFUELS.
ARTICLE V
MEASUREMENT AND ANALYSES
5.1 GENERAL. On all deliveries into or out of railcars, the
quantity shall be determined by plant meter, official tank car capacity tables
or slip tube gauges in accordance with Gas Processors Association ("GPA")
Publication 8162, latest revision, as listed in order of preference, if
available. On all deliveries into or out of truck equipment, quantities shall be
determined by weighing, meter, rotary gauge, or other measuring devices that
meet industry standards, in accordance with GPA Publications 8162 and 8186,
latest revision, as listed in order of preference, if available. On all
deliveries into or out of pipelines, quantities shall be determined by pipeline
meter in accordance with the America Petroleum Institute ("API") Manual of
Petroleum Measurement Standards. For raw make mixtures, volumes of the component
products shall be determined on a mass (pound) measurement basis in accordance
with the latest edition of GPA Publications 8173 and 8182. On all deliveries
into or out of shore tanks, quantities shall be determined either by meter or
gauge from a static tank in accordance with the API Manual of Petroleum
Measurement Standards and based upon the practice of the relevant terminal. All
quantities shall be corrected to standard conditions of sixty degrees Fahrenheit
(60(degree)F) and equilibrium vapor pressure in accordance with the API Manual
of Petroleum Measurement Standards, Chapter 14, Section B. The quantity and
quality of NGLs covered by this Agreement shall be measured according to the
current versions of the applicable standards of API and the American Society for
Testing Materials, if available. Each Party shall be entitled to have its
representatives present during all loadings, unloadings, tests, and measurements
involving NGLs delivered hereunder. If the Parties cannot agree on measurement
or quality tests results, the measurements and quality tests required to
determine the volume of receipts or shipments
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or the conformity of the NGLs delivered to the specifications set forth herein
shall be made by an independent inspector selected jointly by the Parties, the
cost of which shall be shared equally by the Parties.
ARTICLE VI
PRICE
6.1 PURITY PRODUCT SALES.
(a) PURITY PRODUCT PRICES FOR SALES OTHER THAN LOCAL SALES.
For Purity Products other than Purity Products sold in Local Sales, UPFUELS
shall pay UPR 100% of the Netback Price, less the applicable Marketing Fee
determined in accordance with Section 6.3.
(b) PURITY PRODUCT PRICES IN LOCAL SALES. For Local Sales of
Purity Products, UPFUELS shall pay 100% of the Netback Price, less the
applicable Marketing Fee, but in no event shall UPFUELS pay less than the
Pipeline Price if a commercially reasonable pipeline connection exists for such
Purity Products. If a Pipeline Capacity Constraint exists, however, or if no
commercially reasonable pipeline connection exists for such Purity Products,
then the price for Local Sales of Purity Products shall be determined pursuant
to Section 6.1(a). UPFUELS shall notify UPR promptly in writing upon the
occurrence of a Pipeline Capacity Constraint, and shall use commercially
reasonable efforts to remove such Constraint. Upon removal of such Constraint,
the provisions of this Section 6.1(b) shall once again apply to Local Sales of
Purity Products.
6.2 RAW NGL MIX SALES.
(a) RAW NGL MIX SALES FOR SALES AT MONT BELVIEU. UPFUELS shall
pay UPR the Netback Price for Mont Belvieu, Texas (non-TET, non-specialty and
non-prompt, and Ethane as purity), less Mont Belvieu T&F Costs and the
applicable Marketing Fee, for the volumes of NGLs delivered to UPFUELS as
Components of Raw NGL Mix at the applicable Delivery Points
including Delivery Points at the tailgates of the plants listed in Exhibit "D."
(b) RAW NGL MIX SALES FOR SALES AT CONWAY. UPFUELS shall pay
UPR the Netback Price for Conway, Kansas, non-specialty and non-prompt, less
Conway T&F Costs and the applicable Marketing Fee, for the volumes of NGLs
delivered to UPFUELS as Components of Raw NGL Mix at the applicable Delivery
Points including Delivery Points at the tailgates of the plants listed in
Exhibit "E."
(c) RAW NGL MIX PRICES IN LOCAL SALES. For Local Sales of Raw
NGL Mix, UPFUELS shall pay 100% of the Netback Price, less the applicable
Marketing Fee, but in no event shall UPFUELS pay less than the Pipeline Price if
a commercially reasonable pipeline connection exists for such Raw NGL Mix. If a
Pipeline Capacity Constraint exists, however, or if no commercially reasonable
pipeline connection exists for such Raw NGL Mix, then the price for Local Sales
of Raw NGL Mix shall be determined pursuant to Section 6.2(a) or Section 6.2(b),
as
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applicable. UPFUELS shall notify UPR promptly in writing upon the occurrence
of a Pipeline Capacity Constraint, and shall use commercially reasonable efforts
to remove such Constraint. Upon removal of such Constraint, the provisions of
this Section 6.2(c) shall once again apply to Local Sales of Raw NGL Mix.
6.3 MARKETING FEE. The marketing fee for Subject NGLs hereunder
(the "Marketing Fee") shall be $0.005 per Gallon on Local Sales of Raw NGL Mix
and Purity Product and $.0025 per Gallon on Raw NGL Mix and Purity Product Sales
at NGL Market Centers.
6.4 REPLACEMENT OF INDEX. If for any reason the OPIS index for a
particular NGL or NGL Market Center should cease to be published, the Parties
agree to promptly and in good faith negotiate a mutually satisfactory Alternate
Index or substitute methodology for calculating the price for such NGL or such
NGL Market Center (the "Alternate Index"). If, on or before thirty (30) Days
after the index used to determine the price ceases to be published, the Parties
are unable to agree on an Alternate Index upon which to base the calculation of
the price, the Parties shall submit such determination to dispute resolution
procedures in accordance with the provisions of Article XII. From the date on
which the index used to determine the price for a particular NGL or NGL Market
Center ceases to be available, until the Alternate Index is determined, the
price for such NGL or NGL Market Center shall be the average of the prices in
effect during the twelve (12) Months preceding the Month in which the index upon
which the price was based ceased to be available, which price shall be effective
until the Alternative Index has been determined pursuant to Article XII. Upon
the determination of an Alternate Index, the price will be adjusted
retroactively to the date on which the index upon which the price previously was
based ceased to be available, plus interest thereon to accrue until all amounts
due and owing in respect of this Section 6.4 have been paid, at the Base Rate.
6.5 SHARING OF INCENTIVE RATES. Attached hereto as Schedule 6.5,
is a listing of all transportation and fractionation agreements affecting the
Subject NGLs as of the Effective Date, and the applicable transportation or
fractionation rates or formulas for each such agreement. The rates and formulas
set forth on Schedule 6.5 are hereinafter referred to as the "Baseline Rates."
To the extent that UPFUELS is able to obtain lower transportation or
fractionation rates or formulas than the Baseline Rates (such lower rates and
formulas being herein called the "Incentive Rates"), UPFUELS may retain, for its
own account, fifty percent (50%) of the difference between the Baseline Rates
and the Incentive Rates on sales of Subject NGLs made under such Incentive Rates
(the "Incentive Amount"). Any Incentive Amount shall be described in reasonable
detail on the statement delivered to UPR pursuant to Article VII.
6.6 LOCK-IN OF FRACTIONATION COSTS. At its option, UPR may
initiate negotiations with UPFUELS to lock in some or all of the fractionation
fees and associated fractionation costs included in T&F Costs charged to UPR
hereunder with respect to Subject NGLs. Such lock-in rates and costs shall be
mutually acceptable to UPR and UPFUELS and the lock-in period shall be for a
period of not less than six Months. Any agreement to lock in fractionation fees
and costs shall be in writing.
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ARTICLE VII
ACCOUNTING, BILLING AND PAYMENT
7.1 STATEMENTS AND PAYMENT. UPFUELS shall make payment and shall
provide UPR with a written and an electronically transmitted statement by not
later than the 25th Day of the Month for Subject NGLs delivered during the
preceding Month, provided statements from third party plant operators are
received by the tenth (10th) Day following the end of the Month (it being
understood that if such statements are received after such tenth (10th) Day,
UPFUELS shall pay UPR for the relevant Month based on estimates, which shall be
promptly adjusted in subsequent Months to reflect actual sales). Such statement
shall set forth (a) the quantities and Components of Subject NGLs delivered at
each Delivery Point (with such quantities to be based on plant settlement
volumes, where applicable), (b) the prices applicable to such Subject NGLs, as
provided herein, at each Delivery Point, (c) any Transportation Costs, Pipeline
Transportation Costs, T&F Costs, Marketing Fees, or Incentive Amounts retained
by UPFUELS pursuant to Section 6.5, each of which categories shall be described
in reasonable detail, (d) any amounts due in respect of volume deficiencies
under the Transportation Contracts for which UPR is liable pursuant to Section
3.6, together with copies of invoices and other supporting documentation of such
amounts reasonably satisfactory to UPR, and (e) such other information and
detail as may be mutually agreeable to the Parties and such payment shall be
remitted by wire transfer of immediately available funds into an account
designated by UPR. Any amounts due from UPR hereunder in respect of volume
deficiencies under the Transportation Contracts shall be paid within 15 Days of
UPR's receipt of UPFUELS' statement, or UPFUELS, at its discretion, may set off
such amounts against amounts due hereunder, subject in all respects to UPR's
rights to dispute the amount of such set off pursuant to Section 7.2. If the Day
on which payment is due hereunder does not fall on a Business Day, then UPFUELS'
payment shall be due on the preceding Business Day.
7.2 DISPUTED PAYMENTS. Should a statement be disputed by a Party
in good faith, the disputing Party will pay any undisputed amount and will
notify the other Party in writing of the disputed amount and the basis for the
dispute. Payment of the undisputed portion of a statement will not be deemed a
waiver of the paying Party's right to recoup any overpayment, and acceptance of
such payment will not be deemed a waiver of the accepting Party's right to
recover any underpayment. The Party that rendered the disputed statement will
promptly investigate the dispute and will submit a corrected statement, if
necessary, within thirty (30) Days after receiving notice of the dispute. If the
Parties cannot agree on the disputed amount within such 30-Day period, then
either Party may institute dispute resolution procedures in accordance with
Article XII. If upon resolution of the dispute (whether by agreement or
otherwise), a Party is determined to have underpaid the amount actually due, the
Party will remit the amount due, plus interest thereon from the date such amount
should have been paid until such amount has been received by the underpaid
Party, calculated at the rate stated in Section 7.3 herein. If upon resolution
of the dispute (whether by agreement or otherwise), a Party is determined to
have overpaid the amount actually due, the Party to whom such overpayment was
made will refund the excess paid, plus interest thereon calculated at the rate
stated in Section 7.3 herein.
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7.3 OVERDUE PAYMENTS. Subject in all respects to Section 7.2, if
either Party fails to pay the amount due the other Party when due hereunder as
set forth in Section 7.1, then interest on any such unpaid and overdue amount
shall accrue until paid at the Base Rate.
7.4 TWO YEAR LIMIT ON ADJUSTMENTS. Any statement, charge or
payment under this Agreement will be deemed final unless disputed in accordance
with Section 7.2 within 24 Months from the final Business Day of the calendar
year in which such statement, charge or payment was made or rendered except for
any adjustments to such statement, charge or payment due to adjustments of
settlement statements in respect of the Subject NGLs from third Person plant
operators, in which event any dispute regarding such adjustments must be made
within 24 Months of the final Business Day of the calendar year in which notice
of such adjustment was received. Any payment with respect to a retroactive
adjustment shall include an amount equal to interest on all amounts past due
from the date of the initial payment at the rate set forth in Section 7.3 above.
7.5 AUDIT. Each Party shall keep and maintain true and correct
books, records, files and accounts of all information reasonably related to the
transactions contemplated by this Agreement, including all measurement records,
all information used to determine prices and calculate invoices, all invoices,
statements and payment records (collectively, the "Records"). Each Party shall
have the right, upon reasonable notice of the other Party of not less than ten
(10) Business Days, to audit the Records of the other Party at any time during
reasonable business hours during the term of this Agreement and for a period of
24 Months after the Month of such Agreement's termination, to the extent
necessary to determine compliance by the other Party with the terms of this
Agreement, but such audit rights shall be limited to auditing such Records for
the then current and three preceding calendar years. Notwithstanding the
foregoing, if a governmental body asserts a claim, or conducts an audit, against
a Party arising from the purchase or sale of Subject NGLs and that Party
determines in its reasonable judgment that its response to such claim requires
or would benefit from an audit of the Records of the other Party, such audit may
be conducted during the term of this Agreement and for a period ending on the
fifth (5th) anniversary of the event or payment forming the basis of such
governmental claim. In order to accommodate such governmental audits, UPR and
UPFUELS will maintain the appropriate Records for a period of not less than five
(5) years. Each Party shall also have access to the Records of the other Party
for purposes of responding to claims, or requests for audits, asserted by a
non-governmental third Person and arising from the purchase or sale of Subject
NGLs.
7.6 LETTER OF CREDIT; CREDIT ENHANCEMENT.
(a) INITIAL LETTER OF CREDIT REQUIREMENT. If requested by UPR,
on or before the Effective Date, UPFUELS shall have executed and delivered, at
its sole cost and expense, one or more irrevocable standby letters of credit
(the "Letter of Credit," whether one or more), issued by one or more commercial
banks satisfactory to UPR, in an aggregate amount equal to the Initial Amount
(hereinafter defined), and otherwise in form, term and substance satisfactory to
UPR. The Initial Amount shall equal the product of (i) the average Daily
quantities of Subject NGLs designated for delivery by UPR in the initial
Availability Report delivered to UPFUELS in accordance with Section 2.3 of this
Agreement, (ii) the contract prices estimated in good faith by UPR to be payable
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in respect of Subject NGLs designated for delivery by UPR pursuant to clause (i)
and (iii) 65 Days. UPFUELS' delivery of the Letter of Credit shall be a
condition precedent to the performance of UPR's obligations hereunder.
(b) ADJUSTMENT OF INITIAL AMOUNT. Except as otherwise provided
in this Section 7.6(b), the Initial Amount shall not be subject to adjustment
until April 1999, when UPR shall review the Initial Amount and all other terms
of the Letter of Credit to determine whether such Initial Amount or such other
terms should be adjusted in view of all commercial factors relevant to the
assurance of UPFUELS' performance of its obligations under this Agreement,
including but not limited to (i) UPFUELS' creditworthiness, (ii) the general
level of prices for NGLs and other energy commodities and (iii) the condition of
the domestic and international economy. UPR shall thereafter review the amount
and other terms of the Letter of Credit not less frequently than each subsequent
October and April during the term of this Agreement. Nothing in this Section
7.6(b) shall be construed to limit UPR's right to review the amount of the
Letter of Credit on a more frequent basis, however, or to require such
additional credit enhancement as UPR deems necessary to provide adequate
assurances of UPFUELS' obligations hereunder. Notwithstanding the foregoing, the
Parties agree that no adjustment shall result in a Letter of Credit with an
obligation greater than the product of (x) the quantities of Subject NGLs
estimated in good faith to be delivered by UPR over a period of 65 Days, (y) the
contract price estimated in good faith by UPR to be payable in respect of such
Subject NGLs over such period and (z) 65 Days.
(c) MAINTENANCE OF LETTER OF CREDIT. If requested by UPR,
UPFUELS shall maintain the Letter of Credit at all times during the term of this
Agreement, and shall give UPR not less than 60 Days' written notice prior to the
expiration of any Letter of Credit. UPFUELS' failure to maintain the Letter of
Credit in the amounts and on the terms required hereunder, or to provide UPR
with any other credit enhancement required hereunder, shall be a UPFUELS Credit
Default, and shall entitle UPR to exercise the remedies set forth hereunder,
including but not limited to suspension of performance hereunder and the
termination of this Agreement.
ARTICLE VIII
DISCLAIMER AND WARRANTY
8.1 WARRANTY. UPR warrants title to, or the right to sell, all
Subject NGLs delivered to UPFUELS under this Agreement. UPR also warrants that
all such Subject NGLs shall be free from all liens, encumbrances and adverse
claims.
8.2 DISCLAIMER. EXCEPT AS MADE IN SECTION 8.1 (REGARDING UPR'S
TITLE), UPR MAKES NO OTHER WARRANTIES, EXPRESS, IMPLIED, STATUTORY OR OTHERWISE,
WITH RESPECT TO SUBJECT NGLs SOLD HEREUNDER, INCLUDING, WITHOUT LIMITATION,
WARRANTIES OF MERCHANTABILITY AND FITNESS FOR A PARTICULAR PURPOSE.
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ARTICLE IX
FORCE MAJEURE
9.1 SUSPENSION OF OBLIGATIONS. If either UPR or UPFUELS is
rendered unable, by reason of an event of Force Majeure, to perform, wholly or
in part, any obligation or commitment set forth in this Agreement, except for
the payment of monies owed, then upon that Party's giving notice (the initial
notice may be oral notice followed by written notice within five (5) Business
Days of such oral notice) and full particulars of the event of Force Majeure,
then the obligations of both Parties under this Agreement shall be suspended,
except for the payment of amounts owed under this Agreement, to the extent and
for the period of such Force Majeure event.
9.2 FORCE MAJEURE DEFINED. The term "Force Majeure" means an event
that (i) was not within the control of the Party claiming its occurrence; and
(ii) could not have been prevented or avoided by such Party through the exercise
of due diligence. Events of Force Majeure include, without limitation by
enumeration, acts of nature; lightning, hurricanes or storms, hurricane or storm
warnings which in UPFUELS' or UPR's judgment require and result in the
precautionary shut-down or evacuation of production facilities; earthquakes,
epidemics, fires, floods, landslides, washouts, freezing of wells or lines of
pipe used to supply Subject NGLs under this Agreement and other similar severe
natural calamities; events affecting processing or fractionation plants at which
Subject NGLs are being processed, that prevent the delivery of such Subject NGLs
to the Delivery Point(s) provided for in this Agreement; acts of public enemy;
wars; blockades; insurrections; riots; civil disturbances and arrests; strikes,
lockouts or other industrial disturbances; explosions, breakage, accidents to
wells, equipment, facilities or lines of pipe used to enable UPR to deliver or
UPFUELS to receive Subject NGLs under this Agreement; the inability or refusal
of any transporter of NGLs to receive, transport or deliver NGLs sold or
purchased hereunder (but only if (x) such inability or refusal results from an
event that is interrupting such Transporter's service to its firm customers and
(y) no available alternative for the transportation of the affected Subject NGLs
exists); imposition by a regulatory agency, court or other governmental
authority having jurisdiction of binding laws, conditions, limitations, orders,
rules or regulations that prohibit either Party from performing, provided such
governmental action has been resisted in good faith by all reasonable legal
means; temporary cleaning or testing of facilities (including but not limited
to, scheduled gas processing facility turnarounds and shutdowns for safety
maintenance) or any other cause of a similar type whether of the kind herein
enumerated or otherwise, not within the control of the Party claiming suspension
and which by the exercise of due diligence such Party is unable to overcome.
Force Majeure shall also include any event of Force Majeure occurring with
respect to the facilities or services of either UPR's or UPFUELS third Person
suppliers or customers receiving or delivering any product, fuel, feedstock or
other substance necessary to the performance of such Person's obligations to UPR
or UPFUELS, and shall also include curtailment or interruptions of deliveries or
service by such third Person suppliers or customers as a result of an event of
Force Majeure.
9.3 EXCLUSIONS. Force Majeure does not include loss of markets or
a change in market prices for NGLs.
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9.4 LABOR DISPUTES. The settlement of strikes or lockouts shall be
entirely within the discretion of the Party having the difficulty and the above
requirement of the use of diligence in restoring normal operating conditions
shall not require the settlement of strikes or lockouts by acceding to the terms
of the opposing Person when such course is inadvisable in the discretion of the
Party having the difficulty.
ARTICLE X
TAXES
10.1 GENERAL. UPR shall be liable for and shall pay, or cause to be
paid, or reimburse UPFUELS if UPFUELS has paid, for all Taxes applicable to
Subject NGLs upstream of the Delivery Point(s), including severance, production,
ad valorem and/or similar taxes, if applicable, levied on NGLs at or prior to
the Delivery Point(s). If UPFUELS is required to remit such Tax, the amount
thereof shall be deducted from any sums becoming due to UPR hereunder and shall
be itemized on the statement provided by UPFUELS in accordance with Section 7.1.
UPFUELS shall be liable for and shall pay, cause to be paid, or reimburse UPR if
UPR has paid, for all Taxes applicable to Subject NGLs at or downstream of the
Delivery Point(s). When laws, ordinances or regulations permit or impose upon
UPR the obligation to collect or pay Taxes applicable to Subject NGLs at or
downstream of the Delivery Point, UPR shall collect all such Taxes from UPFUELS,
which shall be in addition to the applicable price, and remit the same to the
appropriate governmental authority, unless UPFUELS furnishes a certificate of
exemption. UPR SHALL INDEMNIFY, DEFEND, AND HOLD HARMLESS UPFUELS FROM AND
AGAINST ANY LIABILITY WITH RESPECT TO THE TAXES FOR WHICH UPR IS LIABLE AND
UPFUELS SHALL INDEMNIFY, DEFEND, AND HOLD HARMLESS UPR FROM AND AGAINST ANY
LIABILITY WITH RESPECT TO THE TAXES FOR WHICH UPFUELS IS LIABLE.
10.2 EVIDENCE OF EXEMPTION FROM TAX. To claim an exemption from
payment of a Tax, a Party shall provide a certificate of exemption or other
reasonably satisfactory evidence of exemption from any Tax, and each Party
agrees to cooperate with the other Party in obtaining any such exemption.
10.3 NEW TAXES. If the performance of this Agreement causes, or
could reasonably be expected to cause, a material long term economic or
operational hardship to either Party due to the enactment of new Taxes after the
Effective Date, then upon written request of either Party, the Parties shall
renegotiate in good faith the burdensome terms and conditions of this Agreement
so as to make them fair and equitable. Such renegotiations shall occur within
thirty (30) Days of the date of the non-requesting Party's receipt of such
written request for such renegotiations. If the Parties are unable to agree on
new provisions to replace the burdensome terms and conditions of this Agreement
within ninety (90) Days of the non-requesting Party's receipt of such written
request, this Agreement shall terminate without necessity of further action on
the part of either Party.
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ARTICLE XI
TERM, DEFAULT AND REMEDIES
11.1 TERM.
11.1.1 GENERAL. This Agreement shall remain in full force and
effect for an initial term of five (5) years from the Effective Date, and from
year-to-year thereafter unless terminated by either Party by giving written
notice of termination no later than 180 Days prior to the last Day in the then
effective term, unless sooner terminated (i) as provided in Section 11.3.1, (ii)
pursuant to Section 10.3, (iii) pursuant to Section 11.1.2 or (iv) upon the
occurrence of a Change of Control with respect to either Party, as provided in
Section 13.2.
11.1.2 TERMINATION DUE TO INCREASE IN REGULATORY BURDENS. If
the performance of this Agreement causes, or could reasonably be expected to
cause, a material long term economic or operation hardship to either Party due
to the enactment of new regulations or other laws (excluding, however,
regulations and laws relating to new Taxes, as to which Section 10.3 governs)
after the Effective Date, then, upon written request of either Party, the
Parties shall renegotiate in good faith the burdensome terms and conditions of
this Agreement so as to make them fair and equitable. Such renegotiations shall
occur within thirty (30) Days of the date of the non-requesting Party's receipt
of such written request for renegotiation pursuant to this Section 11.1.2. If
the Parties are unable to agree on new provisions to replace the burdensome
terms and conditions of this Agreement within ninety (90) Days of the
non-requesting Party's receipt of such written request, this Agreement shall
terminate without necessity of further action on the part of either Party.
11.1.3 SURVIVAL OF OBLIGATIONS. Termination of this Agreement
shall in no way relieve any Party from any obligations or liabilities accrued
hereunder as of the date of termination, and all indemnity obligations of the
Parties shall survive the termination of this Agreement for the maximum period
prescribed by applicable law.
11.2 DEFAULTS.
11.2.1 UPFUELS DEFAULT DEFINED. Each of the following shall be
deemed a "UPFUELS Default": (i) UPFUELS' failure to pay or cause to be paid any
undisputed amount owing under this Agreement (including but not limited to
amounts due in respect of UPFUELS Deficiency Quantities) when due for a period
of fifteen (15) Days after the due date (a "UPFUELS Payment Default"); (ii) the
occurrence of one or more of the following events with respect to UPFUELS: (A)
the entry of a decree or order for relief against UPFUELS by a court of
competent jurisdiction in any involuntary case brought against UPFUELS under any
bankruptcy insolvency or other similar law (collectively, "Debtor Relief Laws")
generally affecting the rights of creditors and relief of debtors now or
hereafter in effect, (B) the appointment of a receiver, liquidator, assignee,
custodian, trustee, sequestrator or other similar agent under applicable Debtor
Relief Laws for UPFUELS or for any
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substantial part of its assets or property, (C) the ordering of the winding up
or liquidation of the UPFUELS' affairs, (D) the filing of a petition in any such
involuntary bankruptcy case, which petition remains undismissed for a period of
180 Days or which is not dismissed or suspended pursuant to Section 305 of the
Federal Bankruptcy Code (or any corresponding provision of any future United
States bankruptcy law), (E) the commencement by UPFUELS of a voluntary case
under any applicable Debtor Relief Law now or hereafter in effect, (F) the
consent by UPFUELS to the entry of an order for relief in an involuntary case
under any such law or to the appointment of or the taking of possession by a
receiver, liquidator, assignee, trustee, custodian, sequestrator or other
similar agent under any applicable Debtor Relief Laws for UPFUELS or for any
substantial part of its assets or property, or (G) the making by UPFUELS of any
general assignment for the benefit of its creditors (the events referred to in
clauses (A) through (G) being collectively referred to as a "UPFUELS Bankruptcy
Default"); (iii) the failure of UPFUELS to maintain the Letter of Credit, or any
other credit enhancement, if required under Section 7.6 (a "UPFUELS Credit
Default"); (iv) the inaccuracy, in any material respect, of any representation
or warranty made by UPFUELS in Section 14.10 of this Agreement (a "UPFUELS
Representation Default"); or (v) UPFUELS' failure to perform any covenant or
other obligation in this Agreement (other than those specified in clauses (i)
through (iv) of this Section 11.2.1), and if such failure is susceptible of cure
before UPR suffers any costs or losses as a result thereof, and such failure is
not remedied within thirty (30) Days of UPFUELS' receipt of a written notice
describing the particulars of such failure in reasonable detail (such failure
being herein called a "UPFUELS Covenant Default").
11.2.2 UPR DEFAULT DEFINED. Each of the following shall be deemed a "UPR
Default": (i) UPR's failure to pay or cause to be paid any undisputed amount
owing under this Agreement (including but not limited to amounts due in respect
of UPR Deficiency Quantities) when due for a period of fifteen (15) Days after
the due date (a "UPR Payment Default"); (ii) the occurrence of one or more of
the following events with respect to UPR: (A) the entry of a decree or order for
relief against UPR by a court of competent jurisdiction in any involuntary case
brought against UPR under any Debtor Relief Laws generally affecting the rights
of creditors and relief of debtors now or hereafter in effect, (B) the
appointment of a receiver, liquidator, assignee, custodian, trustee,
sequestrator or other similar agent under applicable Debtor Relief Laws for UPR
or for any substantial part of its assets or property, (C) the ordering of the
winding up or liquidation of UPR's affairs, (D) the filing of a petition in any
such involuntary bankruptcy case, which petition remains undismissed for a
period of 180 Days or which is not dismissed or suspended pursuant to Section
305 of the Federal Bankruptcy Code (or any corresponding provision of any future
United States bankruptcy law) (E) the commencement by UPR of a voluntary case
under any applicable Debtor Relief Laws now or hereafter in effect, (F) the
consent by UPR to the entry of an order for relief in an involuntary case under
any such law or to the appointment of or the taking of possession by a receiver,
liquidator, assignee, trustee, custodian, sequestrator or other similar agent
under any applicable Debtor Relief Laws for UPR or for any substantial part of
its assets or property, or (G) the making by UPR of any general assignment for
the benefit of its creditors (the events referred to in clauses (A) through (G)
being collectively referred to as a "UPR Bankruptcy Default"); (iii) the
inaccuracy, in any material respect, of any representation or warranty made by
UPR in Section 14.9 of this Agreement (a "UPR Representation Default"); or (iv)
UPR's failure to perform any covenant or other obligation in this Agreement
(other than those specified in clauses (i) through (iii) of this Section
11.2.2), and if such failure is susceptible of cure before UPFUELS suffers any
costs or losses
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as a result thereof, such failure is not remedied within thirty (30) Days of
UPR's receipt of a written notice describing the particulars of such failure in
reasonable detail (such failure being herein called a "UPR Covenant Default").
11.3 CONSEQUENCES OF DEFAULTS.
11.3.1 GENERAL. Except as explicitly provided in this
Agreement, and subject in all respects to the other terms and conditions hereof
including, without limitation, Section 2.5, the Party not in Default (herein
referred to as the "Unaffected Party") may take such actions as it may be
permitted to take under applicable law in consequence of a Default of the other
Party (herein sometimes called the "Defaulting Party"), including, without
limitation, the exercise of offset rights under Section 11.4, the right to
suspend further performance under this Agreement and, in the case of UPR, the
right to sell all or any part of the Subject NGLs to third Persons; provided,
however, that the right to terminate this Agreement shall only be applicable (A)
upon occurrence of a UPFUELS Bankruptcy Default or a UPR Bankruptcy Default
(whereupon this Agreement shall terminate automatically and immediately), (B)
upon occurrence of a UPFUELS Payment Default (whereupon this Agreement shall
immediately terminate, at UPR's election, if UPR had previously given at least
ten (10) Days' prior written notice to UPFUELS of UPR's intent to terminate this
Agreement), or (C) upon occurrence of a UPFUELS Credit Default under Section
7.6, if UPR had previously given at least ten (10) Days' prior written notice to
UPFUELS of UPR's intent to terminate this Agreement.
11.3.2 MITIGATION OF DAMAGES. An Unaffected Party shall use
commercially reasonable efforts to mitigate costs or losses as a result of a
Default, including, without limitation, exercising commercially reasonable
efforts to find alternative markets for Subject NGLs or alternative supplies of
NGLs, as applicable. Similarly, a Defaulting Party shall exercise commercially
reasonable efforts to minimize the harm suffered by the Unaffected Party in
consequence of such Default, including providing the Unaffected Party with
prompt notice of such Default so as to facilitate cover for Subject NGLs not
delivered or the sale of Subject NGLs not taken hereunder.
11.3.3 REMEDIES CUMULATIVE. Unless explicitly indicated to the
contrary in this Agreement, the remedies contemplated in this Section 11.3
(including, without limitation, termination of this Agreement) are cumulative
of, and may be exercised without prejudice to, any other remedies, whether at
law or in equity to which an Unaffected Party may be entitled under this
Agreement for any Default.
11.4 SETOFF RIGHTS. Except as specifically set forth in Section 7.1
and Article X, all payments under this Agreement will be made without setoff or
counterclaim; provided, however, that upon a Defaulting Party's failure to make
payment of undisputed amounts on the due date, the Unaffected Party may, at its
option and in its discretion, set off the unpaid amounts against any amounts
owed to the Defaulting Party under this Agreement or otherwise. The obligations
of the Unaffected Party to the Defaulting Party shall be deemed satisfied and
discharged to the extent of any such set off. The Unaffected Party will give the
Defaulting Party notice of any set off made under this Section 11.4 as soon as
practicable after the set off is made, but failure to give such notice shall not
affect the validity of the set off.
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ARTICLE XII
DISPUTE RESOLUTION PROCEDURES
12.1 GENERAL DISPUTE RESOLUTION PROVISIONS.
(a) EXECUTIVE MEDIATION. In the event of any dispute,
controversy or claim, whether based in contract, tort or otherwise, arising out
of or related to this Agreement or the scope, breach, termination, performance,
interpretation, construction, application, enforcement, or validity of this
Agreement (a "Dispute"), the Parties to this Agreement shall promptly seek to
resolve such Dispute by negotiations pursuant to this Section 12.1(a) between
senior executives of the Parties who have authority to settle the Dispute and
who have not been directly involved in the transactions giving rise to such
Dispute. When a Party believes there is a Dispute under this Agreement, that
Party will give the other Party written notice of the Dispute. Within thirty
(30) days after receipt of such notice, the receiving Party shall submit to the
other a written response. Both the notice and response shall include (i) a
statement of the Party's position and a summary of the evidence and arguments
supporting its position, and (ii) the name, title, fax number and telephone
number of the executive who will represent that Party. If a Dispute involves a
claim arising out of the actions of any Person not a signatory to this
Agreement, the receiving Party shall have such additional time as necessary, not
to exceed an additional sixty (60) Days, to investigate the Dispute before
submitting a written response. The executives shall meet at a mutually
acceptable time and place not later than fifteen (15) Days after the date of the
response and thereafter as often as they reasonably deem necessary to exchange
relevant information and to attempt to resolve the Dispute. If one of the
executives proposes to be accompanied by an attorney at any meeting, the other
executive shall be given at least five (5) working Days' notice of such
intention and may also be accompanied by an attorney. All negotiations and
communications pursuant to this Section 12.1(a) shall be treated and maintained
by the Parties as confidential information and shall be treated as compromise
and settlement negotiations for the purposes of the Federal Rules of Evidence
and state rules of evidence.
(b) INITIATION OF ARBITRATION. If the Dispute has not been
resolved within sixty (60) Days after the date of the response given pursuant to
Section 12.1(a) (or such additional time, if any, that the Parties mutually
agree in writing), or if the Party receiving a notice of Dispute denies the
applicability of the provisions of Section 12.1(a) or otherwise refuses to
participate under the provisions of Section 12.1(a), either Party may initiate
binding arbitration pursuant to the provisions of Section 12.1(c) below.
(c) ARBITRATION PROCEDURES. All Disputes not resolved by
agreement of the Parties shall be submitted to binding arbitration in accordance
with the following provisions of this paragraph. This arbitration agreement is
expressly made pursuant to and shall be governed by the Federal Arbitration Act,
9 U.S.C. section 1, et seq. (The "Arbitration Act"). It is further expressly
agreed that upon request of either Party a judgment shall be entered by any
court of competent jurisdiction upon any award made pursuant to an arbitration
hereunder. All Disputes shall be resolved by arbitration in accordance with the
American Arbitration Association's Commercial Arbitration
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Rules, as amended and effective as of November 1, 1993 (the "Rules"), except as
mutually agreed to the contrary by the Parties, and except as specified below.
(i) EXPEDITED PROCEDURES. Regardless of the amount in
dispute, the Expedited Procedures of the Rules shall not be
utilized without the agreement of both Parties. However, the
arbitrator shall hear and determine preliminary motions with
respect to any issues of law asserted by a Party to be
dispositive of any claim, in whole or in part, in the manner
of a court hearing and acting upon a motion to dismiss for
failure to state a claim or for summary judgment.
(ii) LOCATION. In the absence of agreement by both
Parties to another locale, the arbitration shall be held in
Fort Worth, Texas. In no event will the American Arbitration
Association or JAMS Endispute, Inc. ("JAMS") have the power to
decide the locale of the arbitration.
(iii) SELECTION OF ARBITRATOR. Arbitration shall be
initiated by formal written notice from either Party to the
other Party describing in reasonable detail the Dispute and
naming three Persons that the Party giving such notice (the
"Initiating Party") will accept as an arbitrator to resolve
the matter. Within ten (10) Days of receipt of said notice,
the Party receiving the notice (the "Receiving Party") shall
either agree to one of the three proposed arbitrators, or the
Parties will confer and attempt to agree upon another Person
to arbitrate the Dispute. If these steps do not result in the
selection of an arbitrator, then either the Initiating Party
or the Receiving Party may request that JAMS provide to both
the Initiating Party and the Receiving Party, in writing, a
panel of seven names from JAMS' panel of commercial
arbitrators. All members of the panel submitted by JAMS shall
be United States nationals who are attorneys licensed to
practice in the highest court of one or more states of the
United States of America or the District of Columbia who have
at least fifteen years of experience as a practicing attorney
primarily involving the oil and gas industry including, but
not limited to, the NGL industry, or who are judges or former
judges with at least fifteen years experience as a judge, and
JAMS shall be requested to cause the panel to state the
qualifications of each member of the panel satisfying these
requirements. Within five (5) Days of receipt of this panel,
the Initiating Party shall strike three names from the panel
and forward it to the Receiving Party. The Receiving Party
shall then strike three additional names from the panel and
forward the remaining name to JAMS (with a copy to the
Initiating Party) within five (5) Days of receipt of the
stricken panel. The name forwarded to JAMS shall be the
neutral arbitrator appointed to hear the Dispute. Either the
Initiating Party or Receiving Party may object to an entire
panel and request that JAMS provide a new panel by giving
written notice of the request and the reason therefor to JAMS
and the other Party within three (3) Days after receipt of
such panel. Such notice may be given by telecopy, by delivery
in hand, or by depositing same in the United States Postal
Service, properly addressed and stamped, as certified mail,
but only one such request
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may be made regardless of which Party initiates the request.
In no event may JAMS appoint an arbitrator.
(iv) ARBITRATOR'S DECISION FINAL. The decision of the
arbitrator, which shall be rendered within thirty (30) Days
after the conclusion of the hearings conducted pursuant to
this Section 12.1, shall be final and binding on both Parties;
provided that the arbitrator shall not have the authority or
power to award punitive or exemplary damages, and each of the
Parties expressly waives and relinquishes any right to recover
or receive punitive or exemplary damages in connection with
any Dispute. Any decision of the arbitrator, whether
preliminary or final, shall be in a writing signed by the
arbitrator and shall contain the findings of fact and
conclusions of law upon which the decision is based.
(v) SELECTION OF NEW ARBITRATOR. If for any reason,
the selected arbitrator is unable to perform his or her
duties, JAMS may, on proof satisfactory to it or based on the
agreement of the Initiating Party and Receiving Party, declare
the position vacant. In the event of such a vacancy, the
provisions of Section 12.1(c)(iii) shall be followed to select
a new arbitrator.
(vi) HEARINGS. The arbitrator shall set the date and
time of each hearing hereunder. The first hearing shall take
place within twenty-five (25) Days following the arbitrator's
appointment, and the arbitration proceedings shall be
concluded not later than ten (10) Days after the date of the
first hearing. JAMS shall give ten (10) Days' notice to the
Initiating Party and Receiving Party of such hearing unless
otherwise agreed.
(vii) STENOGRAPHIC RECORD. Either the Initiating
Party or the Receiving Party may request a stenographic record
be made of all hearings hereunder. The cost of such
stenographic record shall be shared equally by the Initiating
Party and the Receiving Party.
(viii) PRIVACY. The arbitrator will insure the
privacy of the hearings hereunder to the maximum extent
allowed by law. Both the Initiating Party and the Receiving
Party shall be entitled to attend all hearings. At the request
of either the Initiating Party or the Receiving Party, all
persons who are not executives of a Party shall be excluded
from the hearings, except for the attorneys for the Initiating
Party and Receiving Party, the stenographer (if any), and
Persons who are witnesses when actually called to testify.
Unless otherwise agreed by the Parties, and except as
reasonably required to enforce or implement or exercise any
right of appeal provided by law from the decision of the
arbitrator, the decision of the arbitrator and the evidence
and arguments presented to the arbitrator (to the extent not
otherwise generally known or regularly disseminated) shall be
maintained in confidence by the Parties.
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(ix) FEES AND EXPENSES. The Initiating Party and
Receiving Party shall share equally the arbitrator's fees and
expenses and any charges of JAMS. Otherwise, except for the
cost of the stenographic record, each of the Initiating Party
and the Receiving Party shall bear their own costs.
(d) ALTERNATE SELECTOR OF PANEL. If JAMS ceases to function or
is otherwise unable or unavailable to provide a panel from which the Parties can
select an arbitrator pursuant to Section 12.1(c), the Parties will utilize the
Center for Public Resources (New York, New York) to obtain a panel for such
purpose; and in such circumstance all references to JAMS in Section 12.1(c)
shall be deemed to refer to the Center for Public Resources.
12.2 SPECIAL PROVISIONS APPLICABLE TO PRICE DISPUTES. The
provisions of this Section 12.2 shall apply to disputes relating to the
determination of the price payable for Subject NGLs under Article VI, including,
without limitation, issues relating to the choice of an applicable Alternative
Index, (all such disputes being hereinafter called "Price Disputes"). The
arbitrator shall be selected in accordance with Section 12.1. Each Party shall
deliver to the other Party and to the arbitrator, within ten (10) Business Days
of the appointment of the arbitrator, a written proposal stating such Party's
proposed outcome, together with supporting materials and documentation. Within
forty-five (45) Days after his selection and appointment, the arbitrator shall
select and adopt either UPR's proposal or UPFUELS' proposal, without
modification or compromise. The arbitrator shall make his decision as follows:
(i) in any Price Dispute over an Index, the arbitrator shall decide which of the
proposed Indexes presented to the arbitrator, best represents the market price
for NGLs of like quantities and quality at the applicable Delivery Point(s), and
(ii) in all other Price Disputes, the arbitrator shall consider the terms and
conditions of this Agreement and the requirements of applicable Texas law,
including, without limitation, the Texas version of the Uniform Commercial Code
in effect at the period relevant to the Price Dispute under consideration. The
applicable contract price during the arbitration shall be the contract price
being paid on the Day before the demand for arbitration was made. Upon the
conclusion of the arbitration, the price in dispute, if it has changed as a
result of the arbitrator's decision, shall be adjusted retroactive to the date
the demand for arbitration was made. Unless explicitly provided otherwise in
this Section 12.2, the other provisions of this Article XII shall be applicable
to all arbitrations with respect to Price Disputes.
ARTICLE XIII
NON-ASSIGNABILITY AND TRANSFER OF INTEREST BY PARTIES;
CHANGES OF CONTROL
13.1 NON-ASSIGNABILITY. Neither this Agreement nor any obligation
of a Party under this Agreement are assignable without the express written
consent of the other Party, which consent may be withheld in its sole discretion
for any reason, except to wholly owned subsidiaries and Affiliates, in which
case the assigning Party shall not be relieved of responsibility for any of its
obligations under this Agreement.
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13.2 CHANGE OF CONTROL. A Party affected by such Change of Control
shall give the other Party written notice thereof not later than fifteen (15)
Days after the occurrence of such Change of Control. If a Change of Control
occurs with respect to either Party during the term of this Agreement, the other
Party shall have the right to terminate this Agreement by providing the Party
affected by such Change of Control with written notice as provided herein. Such
other Party shall provide the affected Party with written notice of termination
of this Agreement not later than thirty (30) Days after receipt of the affected
Party's notice hereunder, and termination of this Agreement pursuant to this
Section 13.2 shall be effective on the first Day of the Month following the
Month of the terminating Party's receipt of the affected Party's notice,
provided, however, that if the affected Party fails to timely give written
notice of the Change of Control, the other Party may give written notice of
termination of this Agreement at any time following its discovery or knowledge
of such Change of Control. "Change of Control" shall mean:
(a) any Person or "group" (as determined for purposes of Rule
13d-5 of the Securities and Exchange Commission under the Securities Exchange
Act of 1934 or under any successor rule or regulation, being herein referred to
as the "Regulation") shall have acquired "beneficial ownership" (as determined
for purposes of such Regulation) of a Party's securities (i) representing 25% or
more of the combined voting power of such Party's then-outstanding securities or
(ii) having voting power sufficient to elect a majority of the board of
directors or other similar governing body of a Party;
(b) any statutory merger, consolidation or share exchange
(other than a merger, consolidation or share exchange with an Affiliate) in
which either (i) a Party will not be the surviving corporation; or (ii) such
Party will be the surviving corporation and any outstanding shares of its common
stock will be converted into shares of any other company (other than an
Affiliate of such Party); or
(c) a Party's shareholders (i) approve any plan or proposal
for the disposition or other transfer of all or substantially all the assets of
such Party, whether by means of a merger,reorganization, liquidation or
dissolution or otherwise; or (ii) dispose of, or become obligated to dispose of,
25% or more of the outstanding capital stock of such Party by tender offer or
otherwise.
ARTICLE XIV
MISCELLANEOUS
14.1 NO CONTINUING WAIVER. The waiver by either Party of any breach
of any of the provisions of this Agreement shall not constitute a continuing
waiver of other breaches of the same or other provisions of this Agreement.
14.2 GOVERNMENT REGULATION. This Agreement is subject to all
present and future valid and applicable laws, orders, rules and regulations of
any regulatory body of the federal government or any state, county or local
governmental body having jurisdiction.
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14.3 EXCLUSION OF CONSEQUENTIAL DAMAGES. IN NO EVENT SHALL EITHER
PARTY BE LIABLE TO THE OTHER FOR ANY PUNITIVE, SPECIAL, CONSEQUENTIAL, OR
INDIRECT DAMAGES, INCLUDING, WITHOUT LIMITATION, DAMAGES FOR LOST PROFITS.
14.4 NOTICES. Unless otherwise explicitly provided herein, all
notices provided for in this Agreement shall be in writing and shall be (i)
delivered in person or by messenger, (ii) mailed by Federal Express or similar
private courier service, (iii) sent by United States certified mail (return
receipt requested), postage prepaid, (iv) by facsimile, telex or telecopier, or
(v) by any other commercially reasonable means, to the addresses of the Parties
set forth below or to such other addresses as either Party may designate in
writing to the other Party. All notices given hereunder shall be effective on
the date of actual receipt at the appropriate address. Notice given pursuant to
clause (iv) shall be effective (A) upon actual receipt if received during the
recipient's normal business hours, or (B) at the beginning of the next Business
Day after receipt if received after the recipient's normal business hours.
UPR: Notices and Correspondence:
Union Pacific Resources Company
P. O. Box 7, MS 4100
Fort Worth, Texas 76101-0007
Attention: _________________
Telephone: (817) 877-7543
Fax: (817) 877-7522
Invoices and Statements:
Union Pacific Resources Company
P. O. Box ________
Fort Worth, Texas 76____
Attention: _____________
Telephone: (817) ___-_____
Fax: (817) ___-____
UPFUELS: Notices and Correspondence:
UPFUELS
P.O. Box 901027 - M.S. 1310
Fort Worth, Texas 76101
Attention: Marketing Dept.
Telephone: (817) 255-6000
Fax: (817) 255-7185
28
<PAGE> 34
Invoices and Statements:
UPFUELS
P.O. Box 901027 - M.S. 1310
Fort Worth, Texas 76101
Attention: Marketing Dept.
Telephone: (817) 255-6000
Fax: (817) 255-7247
14.5 CHOICE OF LAW. THIS AGREEMENT SHALL BE GOVERNED BY AND
CONSTRUED IN ACCORDANCE WITH THE LAWS OF THE STATE OF TEXAS, WITHOUT REGARD TO
CONFLICTS OF LAWS PRINCIPLES THAT WOULD REQUIRE THE APPLICATION OF THE LAWS OF
ANOTHER JURISDICTION. THE VENUE OF ANY PROCEEDING TO COMPEL ARBITRATION SHALL BE
IN THE UNITED STATES FEDERAL COURT FOR THE NORTHERN DISTRICT OF TEXAS - FORT
WORTH DIVISION.
14.6 INTEGRATION. This Agreement sets forth all understandings of
UPFUELS and UPR with respect to the purchase and sale of Subject NGLs. All other
agreements, oral or written, concerning such purchase and sale are merged into
and superseded by this Agreement. No waiver of rights hereunder, or modification
or amendment hereof shall be effective unless in writing and signed by both
Parties.
14.7 CONFIDENTIALITY.
14.7.1 PARTIES' OBLIGATIONS. The terms of this Agreement,
including, but not limited to, the prices paid for Subject NGLs and information
exchanged or disclosed by the Parties pursuant to the dispute resolution
procedures of Article XII and all other information exchanged by the Parties
hereunder, will be kept confidential by the Parties unless (i) such information
becomes known to the public at large without breach of this Agreement, (ii) a
Party is obligated to disclose such information to a Transporter or other third
party for the purpose of effectuating the sale and transportation of NGLs
pursuant to this Agreement, (iii) a Party is obligated to disclose such
information to meet applicable securities or commodity exchange requirements,
(iv) a Party is obligated to disclose such information to meet regulatory filing
requirements, (v) a Party is obligated to disclose such information to comply
with mandatory document production requirements under federal or state Rules of
Civil Procedure, a subpoena or other order of judicial or administrative
tribunal, (vi) a Party is obligated to disclose such information to comply with
contractual requirements with third Parties or (vii) a Party is obligated to
disclose such information to comply with a request made by a commercial bank
lender or an investment bank underwriting an offering of securities by a Party.
14.7.2 HANDLING OF REQUEST FOR DISCLOSURE. If either Party
believes that it may be required to disclose information concerning this
Agreement that is to be kept confidential pursuant to Section 14.7.1 (iii) -
(vi), the disclosing Party will notify the other Party in writing as soon as
practicable in advance of disclosure, specifying the nature of the request and
the information to be
29
<PAGE> 35
disclosed. To the extent permitted under statutes, rules, regulations or
contractual provisions applicable to the disclosure request, the Party required
to make disclosure will assert any available privilege permitting non-disclosure
of the information that is to be kept confidential hereunder, or request
confidential treatment of the disclosed information, including exemption from
public disclosure under applicable "open records" and "freedom of information"
statutes. The Party disclosing information required to be kept confidential
under this Section 14.7 shall use commercially reasonable efforts to obtain from
the Person to whom disclosure of such information is made an agreement, to be
signed by such Person and any employee, agent, officer, director or independent
contractor of such Person to whom disclosure shall be made, such agreement to
have terms and conditions substantially the same as those set forth in this
Section 14.7.
14.7.3 RESPONSIBILITY FOR CONFIDENTIALITY. Each Party will be
deemed solely responsible and liable for the actions of its employees,
independent contractors, officers, and agents for maintaining the
confidentiality commitments of this Article, but will be required in that regard
only to exercise such care in maintaining the confidentiality of this Agreement
as it normally exercises in preserving the confidentiality of its other
commercially sensitive documents.
14.8 CONSTRUCTION OF AGREEMENT.
14.8.1 GENERAL PRINCIPLES. In construing this Agreement, the
following principles shall be followed:
(a) no consideration shall be given to the fact or presumption
that one Party had a greater or lesser hand in drafting this Agreement;
(b) examples shall not be construed to limit, expressly or by
implication, the matter they illustrate;
(c) the words "includes," "including" and their respective
syntactical variants mean "includes, but is not limited to" and corresponding
syntactical variant expressions;
(d) the plural shall be deemed to include the singular and
vice versa, as applicable;
(e) the term "Party" shall refer to all Affiliates of such
Party unless the context specifically indicates to the contrary; and
(f) each exhibit, attachment, and schedule to this Agreement
is a part of this Agreement, but, except as provided in Section 2.5 (a) as it
relates to Schedule 2.5, if there is any conflict or inconsistency between the
main body of this Agreement and any exhibit, attachment, or schedule, the
provisions of the main body of this Agreement shall prevail.
14.8.2 SEVERABILITY. If any provision of this Agreement is
held to be illegal, invalid, or unenforceable under the present or future laws
effective during the term of this Agreement, (i) such provision will be fully
severable, (ii) this Agreement will be construed and enforced as if such
illegal,
30
<PAGE> 36
invalid, or unenforceable provision had never comprised a part of this
Agreement, and (iii) the remaining provisions of this Agreement will remain in
full force and effect and will not be affected by the illegal, invalid, or
unenforceable provision or by its severance from this Agreement. Furthermore, in
lieu of such illegal, invalid, or unenforceable provision, there will be added
automatically as a part of this Agreement a provision as similar in terms to
such illegal, invalid, or unenforceable provision as may be possible and may be
legal, valid and enforceable.
14.8.3 RELATIONSHIP OF PARTIES. This Agreement does not create
a partnership, joint venture, or relationship of trust or agency between the
Parties.
14.9 REPRESENTATIONS AND WARRANTIES OF UPR. UPR hereby represents
and warrants to UPFUELS that on and as of the date hereof:
(a) It is duly formed and validly existing and in good
standing under the laws of the state or jurisdiction of formation, with all
requisite corporate power and authority to carry on the business in which it is
engaged and to perform its obligations under this Agreement;
(b) The execution and delivery of this Agreement have been
duly authorized and approved by all requisite corporate action;
(c) It has all the requisite corporate power and authority to
enter into this Agreement and perform its obligations hereunder;
(d) The execution and delivery of this Agreement do not, and
consummation of the transactions contemplated herein will not, breach or violate
(i) any of the material provisions of its articles of incorporation, bylaws or
other organizational documents, (ii) any material agreement pursuant to which it
or its properties are bound or (iii) to its knowledge, any material applicable
laws; and
(e) This Agreement is valid, binding, and enforceable against
it in accordance with its terms, subject to bankruptcy, moratorium, insolvency
and other laws generally affecting creditor's rights and general principles of
equity (whether applied in a proceeding in a court of law or equity).
14.10 REPRESENTATIONS AND WARRANTIES OF UPFUELS. UPFUELS hereby
represents and warrants to UPR that on and as of the date hereof:
(a) It is duly formed and validly existing and in good
standing under the laws of the state or jurisdiction of formation, with all
requisite corporate power and authority to carry on the business in which it is
engaged and to perform its respective obligations under this Agreement;
(b) The execution and delivery of this Agreement have been
duly authorized and approved by all requisite corporate action;
31
<PAGE> 37
(c) It has all the requisite corporate power and authority to
enter into this Agreement and perform its obligations hereunder;
(d) The execution and delivery of this Agreement do not, and
consummation of the transactions contemplated herein will not, breach or violate
(i) any of the material provisions of its articles of incorporation, bylaws or
other organizational documents, (ii) any material agreement pursuant to which it
or its properties are bound or (iii) to its knowledge, any material applicable
laws; and
(e) This Agreement is valid, binding, and enforceable against
it in accordance with its terms, subject to bankruptcy, moratorium, insolvency
and other laws generally affecting creditor's rights and general principles of
equity (whether applied in a proceeding in a court of law or equity).
14.11 NO THIRD PARTY BENEFICIARIES. Any agreement herein contained,
express or implied, shall be only for the benefit of the Parties and their
respective successors and permitted assigns, and such agreements or assumptions
shall not inure to the benefit of any other Person whatsoever, it being the
intention of the Parties that no Person shall be deemed a third party
beneficiary of this Agreement.
14.12 FURTHER ASSURANCES. Each Party shall take such acts and
execute and deliver such documents in form and substance reasonably satisfactory
to each of them, in order to effectuate the purposes of this Agreement.
14.13 EXHIBITS. The Parties expect that the Exhibits and Schedules
to this Agreement will be agreed upon and completed prior to the Effective Date
and the Parties agree that the absence of a completed Exhibit or Schedule at the
time this Agreement is executed by the Parties shall not affect the
enforceability of this Agreement at any time. In the event an Exhibit or
Schedule is not completed at the time this Agreement is executed, a pro forma
Exhibit or Schedule shall be attached setting forth the form and content of the
Exhibit or Schedule to be completed.
32
<PAGE> 38
IN WITNESS WHEREOF, this Agreement is executed on the 20th day of
November, 1998, but effective as of the Effective Date.
UNION PACIFIC RESOURCES COMPANY
By: /s/ V. RICHARD EALES
--------------------------------------
Name: V. Richard Eales
------------------------------------
Title: Executive Vice President
-----------------------------------
UNION PACIFIC FUELS, INC.
By: /s/ D. W. NIEMIC
--------------------------------------
Name: D. W. Niemic
------------------------------------
Title: President
-----------------------------------
<PAGE> 1
EXHIBIT 10.22(i)
NATURAL GAS PURCHASE AND SALE AGREEMENT
DATED EFFECTIVE
JANUARY 1, 1999
BETWEEN
UNION PACIFIC RESOURCES COMPANY
AND
UNION PACIFIC FUELS, INC.
<PAGE> 2
TABLE OF CONTENTS
<TABLE>
<CAPTION>
Page
<S> <C> <C> <C>
I. DEFINITIONS.................................................................................................1
1.1 .....................................................................................................1
II. COMMITMENT OF GAS AND OBLIGATION TO PURCHASE................................................................5
2.1 Committed Gas...................................................................................5
2.2 Excluded Gas....................................................................................5
2.2.1 Farmout Acreage...............................................................6
2.2.2 Pre-Effective Date Commitments................................................6
2.2.3 Operational Reservations......................................................6
2.2.4 Curtailed or Shut-In Gas......................................................7
2.2.5 Facility Gas..................................................................8
2.2.6 New Source of Supply Gas......................................................8
2.2.7 Lien Gas......................................................................8
2.3 First-of-the-Month Availability Report..........................................................9
2.3.1 Revised Availability Report..................................................10
2.3.2 Estimates of Additional Quantities of Committed Gas..........................10
2.3.3 UPFUELS Information..........................................................10
2.3.4 Production Information.......................................................10
III. TRANSPORTATION AND PENALTIES...............................................................................11
3.1 Upstream Gathering and Transportation Agreements...............................................11
3.2 Transporter's Tariff...........................................................................11
3.3 Imbalances Generally...........................................................................11
3.3.1 Liability for Imbalance Charges..............................................12
3.4 Operational Flow Orders........................................................................12
3.5 Operational Balancing Agreements...............................................................13
IV. QUANTITY, DELIVERY & PURCHASE OF COMMITTED GAS.............................................................13
4.1 Purchase and Sale Obligation...................................................................13
4.1.1 UPR's Delivery Obligation.............................................................13
4.1.2 UPFUELS' Take Obligation..............................................................13
4.2 Certain Defaults Related to the Delivery and Taking of Committed Gas...........................13
4.2.1 UPR Over-Delivery Default.............................................................13
4.2.2 UPR Under-Delivery Default............................................................14
4.2.3 Material UPR Delivery Default.........................................................14
4.2.4 UPFUELS Take Default..................................................................15
4.2.5 Material UPFUELS Take Default.........................................................15
4.2.6 Exclusive Consequences of UPR Delivery Defaults and UPFUELS Take Defaults.............15
4.3 Provision Regarding Output Contract Laws.......................................................16
</TABLE>
2
<PAGE> 3
<TABLE>
<S> <C> <C> <C>
V. TITLE AND RESPONSIBILITY...................................................................................16
5.1 UPR Responsibility.............................................................................16
5.2 UPFUELS Responsibility.........................................................................17
VI. QUALITY, MEASUREMENT AND TESTS.............................................................................17
6.1 Quality Specifications.........................................................................17
6.2 Volume and Heating Value.......................................................................18
6.3 Test Data and Charts...........................................................................18
VII. PRICE......................................................................................................18
7.1 Price for Committed Gas Generally..............................................................18
7.2 Split Connect Price............................................................................19
7.3 Locked Price Option............................................................................19
7.3.1 Request for a Locked Price...................................................20
7.3.2 Procedures...................................................................20
7.3.3 Locked Quantities............................................................20
7.3.4 Irrevocability...............................................................21
7.3.5 Availability of Committed Gas................................................21
7.3.6 Cessation of Futures Trading.................................................21
7.3.7 Applicability of Other Provisions of this Agreement to Committed Gas Sold
Under a Locked Price..................................................................21
7.3.8 Liquidation of Hedge Positions...............................................21
7.4 Replacement of Indexes; Redetermination of Indexes, Split Connect Indexes and Index Price
Adjustments....................................................................................22
7.5 Provisions Relating to Pricing Exhibit; Procedures for Change of Exhibit.......................22
VIII. ACCOUNTING, BILLING AND PAYMENT............................................................................23
8.1 Statements.....................................................................................23
8.2 Payment........................................................................................23
8.3 Disputed Payments..............................................................................23
8.4 Overdue Payments...............................................................................24
8.5 Two Year Limit on Adjustments..................................................................24
8.6 Audit..........................................................................................24
8.7 Letter of Credit; Credit Enhancement...........................................................25
IX. DISCLAIMER AND WARRANTY....................................................................................26
9.1 Warranty.......................................................................................26
9.2 Disclaimer.....................................................................................26
X. FORCE MAJEURE..............................................................................................26
10.1 Suspension of Obligations......................................................................26
10.2 Force Majeure Defined..........................................................................26
10.3 Exclusions.....................................................................................27
</TABLE>
3
<PAGE> 4
<TABLE>
<S> <C> <C> <C>
10.4 Labor Disputes.................................................................................27
10.5 ...................................................................................................27
XI. TERM, DEFAULT AND REMEDIES.................................................................................27
11.1 Term...........................................................................................27
11.2 Defaults.......................................................................................28
11.3 Consequences of Defaults.......................................................................29
11.4 Setoff Rights..................................................................................30
XII. DISPUTE RESOLUTION PROCEDURES..............................................................................30
12.1 General Dispute Resolution Provisions..........................................................30
12.2 Special Provisions Applicable to Price Disputes................................................33
12.3 Special Provisions Applicable to Disputes for Less Than One Million Dollars....................34
XIII. NON-ASSIGNABILITY AND TRANSFER OF INTEREST BY UPR;CHANGES OF CONTROL.......................................34
13.1 Non-Assignability..............................................................................34
13.2 Transfer of Interest...........................................................................34
13.3 Change of Control..............................................................................35
XIV. MISCELLANEOUS..............................................................................................36
14.1 No Continuing Waiver...........................................................................36
14.2 Government Regulation..........................................................................36
14.3 Exclusion of Consequential Damages.............................................................36
14.4 Notices........................................................................................36
14.5 Choice of Law..................................................................................38
14.6 Integration....................................................................................38
14.7 Confidentiality................................................................................38
14.8 Taxes..........................................................................................39
14.9 Construction of Agreement......................................................................39
14.10 Representations and Warranties of UPR..........................................................40
14.11 Representations and Warranties of UPFUELS......................................................41
14.12 No Third Party Beneficiaries...................................................................41
14.13 Further Assurances.............................................................................41
14.14 Exhibits.......................................................................................41
</TABLE>
4
<PAGE> 5
EXHIBITS
Exhibit A Delivery Points, Indexes and Index Price Adjustments
Exhibit B Form of Availability Report
Exhibit C Pre-Effective Date Commitments
Exhibit D Price Lock Confirmation
5
<PAGE> 6
NATURAL GAS PURCHASE AND SALE AGREEMENT
This Natural Gas Purchase and Sale Agreement is made and entered into
this 20th day of November, 1998, but effective as of the 1st day of January,
1999 ("Effective Date"), between UNION PACIFIC RESOURCES COMPANY, a Delaware
corporation (referred to herein as "UPR"), and UNION PACIFIC FUELS, INC., a
Delaware corporation ("UPFUELS"), both UPR and UPFUELS sometimes referred to
collectively as "Parties" or individually as a "Party."
R E C I T A L S
UPR is the owner and producer of Natural Gas and desires to sell
Natural Gas to UPFUELS, and UPFUELS is a marketer of Natural Gas, provides
products and services associated with the production, transportation and
marketing of Natural Gas, and desires to purchase Natural Gas from UPR.
NOW, THEREFORE, for and in consideration of the mutual covenants and
agreements contained in this Agreement, UPR and UPFUELS agree as follows:
I. DEFINITIONS
1.1 General. The following terms shall have the meanings set forth
below. Other terms are defined elsewhere in this Agreement.
"Affiliate" shall mean any Person Controlling, Controlled by, or under
common Control with another Person, whether directly or through one or more
intermediaries. For purposes of this Agreement field-wide and individual well
units created pursuant to 52 O.S. Section 287.8 (and like statutes in
jurisdictions other than Oklahoma) shall not be deemed Affiliates of UPFUELS or
UPR.
"Agreement" shall mean the provisions of this document as it may be
amended from time to time.
"Availability Report" shall have the meaning set forth in Section 2.3.
"Btu" (British Thermal Unit) shall mean the amount of heat energy
required to raise the temperature of one pound of water from fifty-nine degrees
Fahrenheit (59(0)F) to sixty degrees Fahrenheit (60(0)F), as determined on a dry
basis.
"Business Day" shall mean a day on which commercial banks are open for
business in Fort Worth, Texas.
<PAGE> 7
"Committed Gas" shall have the meaning set forth in Section 2.1.
"Contract Price" shall mean the First-of-the-Month Index Price, the
Daily Index Price, the Split Connect Price, or the Locked Price, as applicable.
"Control," "Controlling," "Controlled" or terms of similar import shall
mean with respect to a corporation or limited liability company, the right to
exercise, directly or indirectly, more than fifty (50%) percent of the voting
rights attributable to the controlled corporation or limited liability company,
and, with respect to any other Person, the possession, directly or indirectly,
of the power to direct or cause the direction of the management or policies of
the controlled entity.
"Daily Index" shall mean, with respect to a particular Delivery
Point(s), that published daily Index which has been determined by mutual
agreement (or, if there is no published Index for the relevant Delivery
Point(s), then such other Indexes as may be selected by mutual agreement) to
best represent the spot market price for Gas at such Delivery Point(s) for a
particular Day.
"Daily Index Price" shall have the meaning set forth in Section 7.1.
"Day" shall mean that period of 24 consecutive hours beginning and
ending at 9:00 a.m. Central Clock Time, or such other time as may be specified
in the Tariff of a Transporter.
"Default" shall mean a UPFUELS Default or a UPR Default, as applicable.
"Delivery Point(s)" shall mean the point(s) at which the title to Gas
delivered under this Agreement passes from UPR to UPFUELS. The Delivery Point(s)
of Committed Gas as of the Effective Date are listed on Exhibit A of this
Agreement.
"Effective Date" shall have the meaning given such term in the preamble
to this Agreement.
"Excluded Gas" shall have the meaning set forth in Section 2.2.
"FERC" means the Federal Energy Regulatory Commission or any successor
government authority.
"First-of-the-Month Price" shall have the meaning set forth in Section
7.1.
"Gas" or "Natural Gas" means the effluent vapor stream in its natural
state produced from wells, including all hydrocarbon and nonhydrocarbon
constituents, and including, without limitation, casinghead Gas produced with
crude oil, and residue Gas resulting from the processing of Gas well Gas or
casinghead Gas.
"Imbalance Charges" shall mean any imbalance charges (including but not
limited to imbalance penalties, penalties or other charges assessed for
violating OFOs and cash-out costs) assessed against UPFUELS or UPR by a
Transporter due to under-deliveries or over-deliveries of Gas.
2
<PAGE> 8
"Index(es)" shall mean, with respect to a particular Delivery Point(s),
that published index which has been determined by mutual agreement (or, if there
is no published index for the relevant Delivery Point(s), then such other
indexes as may be selected by mutual agreement) to best represent the 30-Day
spot market price for Gas at the Delivery Point(s). The initial Indexes
applicable to each Delivery Point are set forth on Exhibit A.
"Index Price" shall mean the First-of-the-Month Price, the Daily Index
Price or the Split Connect Price, as applicable, after any applicable Index
Price Adjustments, as set forth on Exhibit A.
"Index Price Adjustments" shall mean, with respect to an Index Price
for any Delivery Point(s), adjustments necessary to reflect transportation of
Gas to the relevant Delivery Point(s). The initial Index Price Adjustments
applicable to each of the Delivery Points as of the Effective Date are listed on
Exhibit A.
"Locked Price" shall have the meaning set forth in Section 7.3.
"MMBtu" means one million (1,000,000) Btu.
"Material UPFUELS Take Default" shall have the meaning set forth in
Section 4.2.5
"Material UPR Delivery Default" shall have the meaning set forth in
Section 4.2.3.
"Month" means the period commencing at 9:00 a.m. Central Clock Time on
the first Day of a calendar month and ending at 9:00 a.m. Central Clock Time on
the first Day of the immediately following calendar month.
"New Source of Supply Gas" shall mean any Gas Owned or Controlled by
UPR other than Committed Gas.
"OFO" shall have the meaning set forth in Section 3.4.
"Owned or Controlled" shall have the meaning set forth in Section 2.1.
"Party" and "Parties" shall have the meanings given such terms in the
preamble to this Agreement.
"Person" shall mean any individual or entity, including, without
limitation, any corporation, limited liability company, partnership (whether
general or limited), joint venture, association, joint stock company, trust,
business trust, cooperative, unincorporated organization, government (including,
without limitation, any board, agency, political subdivision or other body
thereof) or entities similar to any of the foregoing that are organized under
the laws of foreign jurisdictions.
3
<PAGE> 9
"Pre-Effective Date Commitment" shall mean, for quantities of Gas
produced under normal operating conditions in excess of 200 Mcf per Day at any
Delivery Point (i) any contracts existing on the Effective Date with third
Persons who are not Affiliates of UPR for the sale of Gas Owned or Controlled by
UPR or its Affiliates, including, without limitation, such contracts listed on
Exhibit C to be provided within 30 Days after execution and (ii) any joint
operating agreement, unit operating agreement or similar agreement to which UPR
is a party, and pursuant to which Gas Owned or Controlled by UPR is being sold
on the Effective Date.
"Reference Rate" shall mean the lesser of (i) two percent (2%) above
the per annum rate of interest announced from time to time as the "prime rate"
for commercial loans by Chase Manhattan Bank of New York (or its successor), as
such "prime rate" may change from time to time, or (ii) the maximum applicable
nonusurious rate of interest.
"Split Connect Committed Gas" shall have the meaning set forth in
Section 7.2(a).
"Split Connect Index" shall have the meaning set forth in Section
7.2(a).
"Split Connect Price" shall have the meaning set forth in Section
7.2(a).
"Tariff" means (i) the tariff of a Transporter, as such tariff is filed
and in effect from time to time with the FERC or any other state or Federal
governmental authority, or (ii) if a Transporter does not have such a tariff on
file with the FERC or any other state or Federal governmental authority, such
Transporter's operating policies and procedures, as they may be in effect from
time to time.
"Taxes" shall mean any and all ad valorem, property, occupation,
severance, production, extraction, first use, conservation, Btu or energy,
gathering, transport, pipeline, utility, gross receipts, gas or oil revenue, gas
or oil import, privilege, sales, use, consumption, excise, lease, transaction,
environmental, and other taxes, governmental charges, duties, licenses, fees,
permits, and assessments.
"Transporter" shall mean an interstate or intrastate pipeline,
including, without limitation, a gathering pipeline, that transports Gas.
"UPFUELS Default" shall have the meaning set forth in Section 11.2(a).
"UPR Default" shall have the meaning set forth in Section 11.2(b).
II. COMMITMENT OF GAS AND OBLIGATION TO PURCHASE
2.1 COMMITTED GAS. During the term of this Agreement, and subject to
any limitations herein set forth, UPR agrees to sell to UPFUELS and UPFUELS
agrees to purchase from UPR under the terms of this Agreement all deliverable
Committed Gas, as defined in the third sentence of this Section 2.1. Subject to
the terms and conditions of this Agreement, UPR's obligation to sell all
deliverable Committed Gas, and UPFUELS' obligation to purchase all Committed Gas
made available
4
<PAGE> 10
by UPR, are firm obligations. Committed Gas is defined as all Gas Owned or
Controlled by UPR (including, without limitation, UPR's Affiliates) in the
United States on the Effective Date, or Owned or Controlled thereafter during
the term of this Agreement, from the Delivery Point(s) in existence on the
Effective Date as set forth on Exhibit A, including, without limitation, Gas
produced from state or federal waters on the Outer Continental Shelf and Gas
which is committed to a gathering or processing agreement with UPFUELS on the
Effective Date, but excluding (i) Gas Owned or Controlled by UPR in Alaska and
Hawaii and (ii) Excluded Gas, as defined in Section 2.2. Committed Gas includes,
without limitation, (x) Gas Owned or Controlled by UPR and produced from wells
in existence on the Effective Date, (y) Gas Owned or Controlled by UPR from
wells acquired, drilled or recompleted subsequent to the Effective Date which
are produced at the Delivery Point(s) set forth on Exhibit A and (z) make-up Gas
accruing to, and capable of being delivered by, UPR after the Effective Date as
a result of production or pipeline imbalances regardless of whether the
imbalances occurred before or after the Effective Date. The phrase "Owned or
Controlled" as used in this Agreement, shall mean produced or producible Gas
that is either: (i) owned by UPR as and when it is produced at the wellhead
(including, without limitation, residue Gas), (ii) purchased by UPR and resold
by UPR to UPFUELS (such Gas being called "Third-Party Gas"), but only if such
Third-Party Gas is (a) being gathered and commingled with Gas Owned or
Controlled by UPR (within the meaning of clauses (i) or (iii) of this Section
2.1) and all such Gas is subsequently gathered, processed or otherwise treated
in connection with the marketing of such Gas, or (b) residue Gas, which has been
commingled with and processed together with Gas Owned or Controlled by UPR
(within the meaning of clauses (i) or (iii) of this Section 2.1), or (iii) Gas
for which UPR has the written authority of the third party owner(s) thereof to
act as such owner(s)' representative, agent, or attorney-in-fact in marketing
such Gas (including, without limitation, under a joint operating agreement
pursuant to which UPR is the operator), but only for the duration of such
authorization.
2.2 EXCLUDED GAS. Excluded Gas is defined as (a) New Source of Supply
Gas; (b) Gas produced from or allocable to acreage farmed out by UPR to a third
Person who is not an Affiliate of UPR, and that is not committed to any
gathering or processing contract with UPFUELS, as more particularly set forth in
Section 2.2.1; (c) Gas that is committed to a Pre-Effective Date Commitment; (d)
Gas required to fulfill UPR's obligations under (i) the royalty provisions of
its oil, Gas and mineral leases, (ii) other provisions of its oil, Gas and
mineral leases, and (iii) agreements customarily found in the oil and Gas
exploration industry to which UPR is a party, including obligations pursuant to
calls on production, rights of first refusal, reversionary rights to convert
retained overriding royalties into working interests and similar rights in favor
of third Persons of the sort customarily found in joint operating agreements,
unit operating agreements, agreements for easements, farmins or similar
drill-to-earn agreements, or other agreements typically entered into in
connection with Gas exploration and production activities that affect UPR's oil,
Gas and mineral leases or the wells situated thereon from time to time; (e) Gas
subject to the operational reservations set forth in Section 2.2.3, (f) Gas
curtailed or shut-in pursuant to Section 2.2.4; (g) Gas that UPR may require, in
its sole discretion, to use in any facility owned by UPR or an Affiliate, or in
which UPR or an Affiliate owns an interest, as more particularly set forth in
Section 2.2.5; (h) New Source of Supply Gas, as more particularly set forth in
Section 2.2.6, (i) Lien Gas and Gas affected by other transactions described in
Section 2.2.7 and (j) such other Gas as UPR and UPFUELS may mutually agree in
writing.
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2.2.1 FARMOUT ACREAGE. During the term of this Agreement, UPR
shall be entitled to farm out to any third Person any acreage covered by an oil,
Gas and mineral lease or mineral fee interest held by UPR. If there is
production from acreage subject to a farmout, Gas produced from such acreage
shall be Committed Gas, but only if such acreage is also committed to a
gathering or processing agreement with UPFUELS on the date of such farmout.
Except as specifically provided in the immediately preceding sentence, Gas
produced from farmout acreage shall not be Committed Gas under this Agreement.
2.2.2 PRE-EFFECTIVE DATE COMMITMENTS. UPR agrees to exercise
reasonable efforts to terminate any Pre-Effective Date Commitment at the
earliest opportunity in accordance with the terms and conditions of such
Commitment if, in the reasonable judgment of UPR, such termination will not
result in adverse economic consequences to UPR.
2.2.3 OPERATIONAL RESERVATIONS. UPR reserves to itself, its
successors, assigns and Affiliates the following rights (together with
quantities of Gas sufficient to satisfy such rights):
(a) To operate UPR's leaseholds, lands and/or interests
therein, free from any control by UPFUELS, in such manner as UPR deems advisable
for the development and operation of UPR's leases (or on any unit, including,
without limitation, field-wide units), including the right (but never the
obligation) to transport Gas from one of UPR's leases to another in accordance
with Section 2.2.3(f), to drill new wells, enhance production, to repair and
rework UPR's wells, to renew and extend (in whole or in part) any lease, to
abandon any well or surrender any lease (in whole or in part) for any reason, to
abandon, modify, extend or dispose of any production facilities owned or
installed (in whole or in part) by UPR, to treat Gas, to use Gas as compressor
fuel, for ethane injection and recovery operations to generate power in
connection with leasehold operations, to lift oil by repressuring, recycling or
pressure maintenance operations and to otherwise operate such leases and fields
free from any control by UPFUELS;
(b) To remove from the Committed Gas all liquids, liquid
hydrocarbons, oil and/or condensate and any other non-methane constituents, both
by lease separation and/or, prior to delivery into a main transmission line, by
processing plant. It is specifically understood and agreed that such processing
rights may be exercised either before or, if the Transporter allows, after
delivery of the Committed Gas to UPFUELS at the Delivery Point(s). In addition,
if any Delivery Point is located on an offshore platform, UPR may inject
condensate into the Committed Gas stream delivered hereunder for transportation
and redelivery to UPR at a separation facility located onshore if (i) the
Transporter agrees that UPR may do so and (ii) UPR bears all charges of the
Transporter attributable to the injection, transportation and redelivery of such
condensate. The liquids, liquid hydrocarbons, oil and/or condensate removed (or
the propanes, butanes, motor fuel or other products obtained) therefrom
(collectively, "Removed Products") shall not be deemed Committed Gas, nor shall
such Removed Products otherwise be subject to this Agreement and, when UPR is
exercising its right to process the Committed Gas, title to the liquefiable
hydrocarbons and other Removed Products shall remain at all times in UPR. In
addition, by not later than ninety (90) Days after the Effective Date, UPR and
UPFUELS will establish reasonable accounting and billing procedures so that (i)
UPFUELS will pay only for the quantities of residue Committed Gas remaining
after processing and
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(ii) all charges of Transporter will be equitably allocated between UPFUELS and
UPR, with UPR paying all costs attributable to the exercise of its processing
rights and UPFUELS paying all costs attributable to the Committed Gas purchased
by it. Where UPR elects to process Gas, UPR shall use commercially reasonable
efforts to reserve the right to take residue Gas in kind; and residue Gas taken
in kind shall be deemed Committed Gas subject to this Agreement, with the
Delivery Point(s) for same being at the tailgate of the processing plant;
(c) To produce Gas without waste and in accordance with
prudent oil and Gas filed practices, it being understood and agreed that UPR
shall not be required to produce any well at a rate in excess of the rate fixed
by law or regulation or in excess of the rate of flow which UPR determines, in
its discretion, exercised in good faith as a prudent operator, should be
produced from such well;
(d) To pool or unitize UPR's leases with other leases of UPR
or others located in the field in which UPR's wells are located (it being
understood that the Gas attributable or allocated to UPR's interest in the pool
or unit so created will remain Committed Gas unless otherwise provided in this
Agreement);
(e) To deliver Gas required to be delivered to third Persons
under the common law governing relationships between cotenants, or under Gas
balancing agreements or similar arrangements affecting any of UPR's wells or
oil, Gas and mineral leases.
(f) To use Gas in connection with the operation of a well in
which UPR has an interest located on a lease other than the lease producing such
Gas, and requiring gathering or transportation downstream of the applicable
Delivery Point, it being understood and agreed that such Gas will not constitute
Committed Gas but will appear in the Availability Report as a separate category.
2.2.4 CURTAILED OR SHUT-IN GAS.
(a) UPR, in its sole discretion, may curtail or shut in Gas
that would otherwise be Committed Gas due to prices that, in UPR's sole opinion,
are unacceptable. UPR shall give UPFUELS notice of any curtailment or shut-in of
Committed Gas pursuant to this Section 2.2.4 before delivery of the Availability
Report pursuant to Section 2.3. Each notice delivered under this Section 2.2.4
shall be in writing and shall identify the quantities of Gas that UPR intends to
curtail or shut in, the Delivery Point(s) affected, and the expected duration of
such curtailment or shut-in period. UPR shall not, however, shut in or curtail
any quantities of Committed Gas hereunder during any Month in which such
quantities have been included in the Availability Report. UPR shall notify
UPFUELS at least two (2) Business Days prior to any applicable deadline in
Transporter(s)' Tariffs for nominations (or nomination changes) of UPR's intent
to resume sales of Committed Gas for which UPR had previously given UPFUELS
notice of UPR's intention to shut in or curtail deliveries pursuant to this
Section 2.2.4.
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(b) In addition to the rights reserved by UPR pursuant to
Section 2.2.4(a), UPR may, at any time, without penalty, curtail or shut in Gas
due to operational circumstances that require such actions in accordance with
prudent oil and gas field practices, notwithstanding the fact that such
quantities were included in the Availability Report; provided, however, if such
operational circumstance was known to UPR and UPR did not use commercially
reasonable efforts to notify UPFUELS of such, then the volume of Gas curtailed
or shut in shall be used in the applicable calculation to determine whether or
not a UPR Under-Delivery Default has occurred. UPR shall identify all foreseen,
forecast or known operational circumstances that may result in operational
variances in the Availability Report(s) where possible and as soon as reasonably
practicable if such information becomes available after the delivery of the
Availability Report(s). It is understood that such notice may be oral if
required by circumstances, to be promptly followed by written confirmation. UPR
shall notify UPFUELS as provided in Section 2.2.4(a) of UPR's intent to resume
sales of previously curtailed or shut-in Committed Gas.
2.2.5 FACILITY GAS. UPR retains the right to use Gas which it
Owns or Controls for use in any facility, including but not limited to, use in
chemical, manufacturing or mining facilities (a) owned, directly or indirectly,
by UPR or any of its Affiliates, or (b) if such facilities are owned by a
corporation, limited liability company, general partnership or joint venture,
facilities in which UPR or any of its Affiliates owns an interest. Gas used by
UPR or its Affiliates pursuant to this Section 2.2.5. shall not constitute
Committed Gas but will appear in an Availability Report as a separate category.
2.2.6 NEW SOURCE OF SUPPLY GAS. New Source of Supply Gas shall
not constitute Committed Gas hereunder.
2.2.7 LIEN GAS.
(a) GENERALLY. Notwithstanding anything stated herein to the
contrary, UPR shall in no way be prohibited or precluded from assigning or
granting a security interest, lien or other encumbrance (collectively, referred
to as "Liens") to secure the repayment of obligations that UPR owes to
commercial banks, insurance companies or other financial or trade creditors
(collectively, "Lenders") on any of the properties owned by UPR from which
Committed Gas is produced.
(b) CERTAIN RIGHTS. UPR shall use commercially reasonable
efforts to obtain from its Lenders an agreement that their Liens shall be
subordinate or otherwise subject to UPFUELS' rights and obligations under this
Agreement. If UPR notifies UPFUELS in writing that UPR has been unsuccessful in
obtaining such an agreement from its Lenders, UPFUELS hereby agrees to
subordinate its rights and interests hereunder and shall execute and deliver to
such Lenders such instruments or agreements in form and substance reasonably
satisfactory to Lenders and UPFUELS, as may be necessary to evidence UPFUELS'
subordination of its rights and interests in such Committed Gas. The Committed
Gas in which UPFUELS' rights are so subordinated shall be herein referred to as
"Lien Gas." Notwithstanding anything stated herein to the contrary, Lien Gas
shall remain Committed Gas hereunder so long as Lenders permit such Committed
Gas to be sold to UPFUELS, notwithstanding any provisions in the documents
creating or evidencing the Liens that
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assign or purport to assign the Committed Gas to Lenders; but such Lien Gas
shall be released from the terms of this Agreement if Lenders foreclose their
Lien, or exercise any other remedy under the documents creating the Lien that
would result in the transfer of the title and the benefits of ownership of the
Lien Gas to such Lenders. UPR shall use commercially reasonable efforts in
cooperating with UPFUELS to (i) subject such Lien Gas to the terms of this
Agreement as Committed Gas hereunder, or (ii) continue sales of Lien Gas under
this Agreement, or under another contract with terms and conditions
substantially the same as those of this Agreement.
(c) OTHER TRANSACTIONS. It is specifically understood and
agreed that UPR may enter into financing transactions involving Committed Gas
with a third Person other than those pursuant to which a Lien is created,
including, without limitation, transactions such as prepayments, conveyances of
production payments, or conveyances of overriding royalty interests, so long as
the Gas burdened by such transaction shall continue to be sold to UPFUELS as
Committed Gas under the terms and conditions of this Agreement.
2.3 FIRST-OF-THE-MONTH AVAILABILITY REPORT. In each Month during the
term of this Agreement, UPR shall submit to UPFUELS an Availability Report (the
"Availability Report") setting forth UPR's best estimate of the quantity of
Committed Gas that UPR will deliver to UPFUELS from each Delivery Point during
the following Month. The Parties agree that the Availability Report will include
an estimate of any plant fuel and shrinkage volumes that reflect the volume loss
from the wellhead to the plant tailgate for Committed Gas that is processed.
UPFUELS will provide UPR with a written Monthly report on plant fuel and
shrinkage volumes (or, if applicable, shrinkage factor) for the preceding Month
by not later than two (2) Business Days before the date the First-of-the-Month
Availability Report is due under this Section 2.3 for the following Month. A
form of the Availability Report is attached hereto as Exhibit B. If the quantity
of Committed Gas available for delivery from a Source of Supply is expressed as
a single Monthly quantity, and unless the Availability Report states otherwise,
it shall be presumed that such quantity will be delivered at as constant a daily
rate of flow as is commercially reasonable throughout the Month. Except as
provided below in this Section 2.3, the Availability Report shall be delivered
to UPFUELS no later than the eighth (8th) Business Day before the relevant
Transporter's First-of-the-Month nomination deadline for the Month of delivery
of Committed Gas, and it shall identify the estimated quantity of Committed Gas
that will be delivered at each Delivery Point on each Day of the Month. The
Parties will endeavor to develop the systems required to implement the
electronic delivery of the Availability Report, provided UPR and UPFUELS are in
agreement in respect to the expenditure of funds required to develop the
systems. UPR and UPFUELS will each have Gas control personnel accessible
twenty-four hours a Day, seven Days a week.
2.3.1 REVISED AVAILABILITY REPORT. The Parties shall confer at
either Party's initiative during each Month to reforecast the quantities of
Committed Gas scheduled to be delivered or purchased pursuant to the
First-of-the-Month Availability Report. Without limiting the generality of the
foregoing, UPR shall promptly notify UPFUELS of any changes in the quantities of
Committed Gas scheduled to be delivered or taken pursuant to the
First-of-the-Month Availability Report, as well as any condition or event that
is reasonably likely to change such quantities estimated to be delivered in such
Report. Such changes shall be deemed timely delivered for purposes of
determining liability
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for Imbalance Charges pursuant to this Agreement if delivered to UPFUELS by not
later than 9:00 a.m. on the Business Day before revised nominations are due to
be delivered by UPFUELS to the first downstream Transporters pursuant to such
Transporters' respective Tariffs.
2.3.2 ESTIMATES OF ADDITIONAL QUANTITIES OF COMMITTED GAS.
Without limiting the generality of Section 2.3.1, the Parties recognize that
additional quantities of Committed Gas not included in the Availability Report
may become available for delivery to UPFUELS at various times after the first
Day of an applicable Month. At least two (2) Business Days before the Day that
UPR wishes to begin deliveries of such additional quantities of Committed Gas,
UPR shall provide UPFUELS with a written notice setting forth (i) the Delivery
Points at which UPR wishes to make such deliveries and (ii) the additional
monthly quantities that UPR estimates will be delivered to each such Delivery
Point during the Month. The Contract Price for the additional monthly quantities
shall be determined in accordance with Article VII, and UPFUELS shall purchase
such additional monthly quantities in accordance with Section 4.1.2.
2.3.3 UPFUELS INFORMATION. Where UPR is a Delivery Point
operator and Committed Gas flows through that Point, and upon UPR's request,
UPFUELS will exercise reasonable efforts to provide UPR with information
required by UPR in its role as Delivery Point operator, including, without
limitation, UPFUELS' downstream transportation contract number, the identity of
the downstream shipper, whether UPFUELS purchases Gas flowing through such
Delivery Point from other suppliers, and, if so, the quantity of Gas purchased
from each such supplier. The Parties acknowledge that the purpose of this
Section 2.3.3 is not to require UPFUELS to furnish information that UPR would
otherwise be able to collect on its own, but rather to obligate UPFUELS to use
reasonable efforts to furnish information not readily accessible to UPR.
2.3.4 PRODUCTION INFORMATION. Both Parties shall use
commercially reasonable efforts to notify the other Party of any take or
delivery deficiencies. The Parties recognize that each may have access to
certain information necessary to confirm gas flows and agree to share such
information on a commercially reasonable basis. With respect to non-operated UPR
properties, subject to the concurrence of the operator of such property, UPR
shall instruct the operator to send duplicate copies of production notices to
UPFUELS. With respect to such non-operated UPR properties, for purposes of
Section 4.2.4, a UPFUELS Take Default shall be deemed to occur upon the receipt
of such notice from either UPR or its operator. UPFUELS shall have until the
conclusion of the Day to which such notice applies or the conclusion of the Day
such notice is received, whichever is later, to remedy such UPFUELS Take
Default. If UPFUELS does not remedy the UPFUELS Take Default by the end of such
Day then the penalties set forth in Section 4.2.4 shall apply. With respect to
properties where UPFUELS is a shipper on a Transporter or receives Gas from a
facility operated by UPFUELS or an Affiliate of UPFUELS, a UPFUELS Take Default
will be deemed to have occurred upon the receipt of oral, written or electronic
notice from a Transporter or the Affiliate of the failure of any Gas flows and
shall notify UPR of such UPFUELS Take Default. If Gas is produced into a
Delivery Point(s) where UPFUELS has an OBA or similar agreement in place, then
no UPFUELS Take Default shall be deemed to have occurred so long as UPFUELS pays
UPR for all Gas delivered pursuant to this Agreement at such Delivery Point.
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III. TRANSPORTATION AND PENALTIES
3.1 UPSTREAM GATHERING AND TRANSPORTATION AGREEMENTS. UPR shall be
responsible for arranging, nominating and paying for, all upstream
transportation and gathering services (and associated charges) necessary for UPR
to deliver Committed Gas to the Delivery Point(s). In respect of any upstream
gathering or transportation service agreement(s) managed by Union Pacific Fuels,
Inc. before the Effective Date (the "G&T Agreements"), UPR shall have the
option, exercisable at any time during the term of this Agreement upon delivery
of written notice to UPFUELS sixty (60) days prior to the Effective Date, to
shift responsibility for the management and operation of such service agreements
to UPFUELS as of the Effective Date (or effective as of a later date if UPR does
not exercise its option on or before the Effective Date), without payment of
further consideration to UPFUELS. If UPR exercises the option reserved in the
preceding sentence, the Parties agree to execute and deliver any agreements
(such agreements to contain terms and conditions consistent with this Agreement
that are customarily found in like agreements between natural gas industry
participants) that such Parties reasonably deem necessary to implement the
shifting of such responsibility to UPFUELS pursuant to UPR's exercise of such
option. Management and operation of such G&T Agreements will include, without
limitation, nominations, scheduling, confirmations and the payment of invoices,
subject to reimbursement by UPR. Actual and reasonable transportation costs paid
by UPFUELS to an upstream gatherer or transporter on UPR's behalf will be netted
against amounts UPFUELS is obligated to pay UPR for Committed Gas delivered
under this Agreement.
3.2 TRANSPORTER'S TARIFF. The Tariff of the Transporter immediately
downstream of the Delivery Point shall define and set forth the manner in which
the Committed Gas purchased and sold under this Agreement is measured and
transported. UPR and UPFUELS recognize that the receipt and delivery into
Transporter's pipeline facilities of Committed Gas purchased and sold under this
Agreement shall be subject to the relevant Transporter's Tariff. UPR shall
designate on the relevant Availability Report the Transporter's Tariff that will
apply to Split Connect Committed Gas; provided, however, that the Transporter so
designated must have been selected by UPR in its designation of a Split Connect
Index pursuant to Section 7.2(a).
3.3 IMBALANCES GENERALLY. The Parties recognize that imbalances may
occur on Transporters. Accordingly, UPFUELS and UPR agree to make every
reasonable effort to promptly eliminate or minimize such imbalances. UPFUELS
shall have primary responsibility for eliminating or minimizing imbalances
downstream of the Delivery Point(s), it being understood, however, that UPR
shall cooperate with UPFUELS' efforts in all reasonable respects. For purposes
of this Agreement, (a) an imbalance resulting from an under-delivery is defined
as an instance whether the Monthly quantity of Committed Gas delivered to a
given Delivery Point is less than the Monthly quantity of Committed Gas
designated for delivery at that Delivery Point in UPR's Availability Report, as
modified throughout the Month by timely revisions of the Availability Report in
accordance with Sections 2.3.1 and 2.3.2 above and (b) an over-delivery is
defined as an instance where the Monthly quantity of Committed Gas delivered to
a given Delivery Point is greater than the Monthly quantity of Committed Gas
designated for delivery at that Delivery Point in UPR's Availability Report, as
modified throughout the Month by timely revisions of the Availability Report in
accordance with Sections 2.3.1. and 2.3.2. If the applicable Transporter
requires balancing on a Daily basis, the definitions of under-delivery and
over-delivery shall be modified to reflect Daily
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balancing as opposed to Monthly balancing. Over-deliveries by UPR into a
Transporter at one Delivery Point will be netted against under-deliveries into
that Transporter by UPR at a different Delivery Point to the extent permitted
under that Transporter's Tariff, provided that such Delivery Point(s) have the
same index publication and pipeline location. Under-deliveries by UPR on one
Transporter will not be netted against over-deliveries by UPR to a different
Transporter absent the Parties' mutual consent, and under-deliveries or
over-deliveries by UPR will not be netted against over-deliveries or
under-deliveries by other UPFUELS suppliers of Gas.
3.3.1 LIABILITY FOR IMBALANCE CHARGES. Imbalance Charges
(including, but not limited to, any cash-out costs) under this Agreement will be
assessed on a Transporter-by-Transporter basis using the applicable terms of the
relevant Transporter's Tariff and any OBA (as defined in Section 3.5) applicable
and as if UPR were the shipper and UPFUELS were the Transporter, and without
regard to whether the relevant Transporter has actually assessed such Imbalance
Charges against UPR or UPFUELS. In instances of Split Connect Committed Gas, the
Tariff of the Transporter downstream of the Delivery Point as selected by UPR on
Exhibit A and associated with the Index selected by UPR in the
First-of-the-Month Availability Report shall be used for purposes of this
Section 3.3.1. If an imbalance occurs during any Month, the cause of any
Imbalance Charge due hereunder shall be determined. If it is determined that the
Imbalance Charge was imposed as a result of acts or omissions by UPR, then UPR
shall pay such Imbalance Charge and/or indemnify UPFUELS against any such
Imbalance Charge.
3.4 OPERATIONAL FLOW ORDERS. UPR and UPFUELS recognize that Transporter
at the Delivery Point(s) may be authorized to issue Operational Flow Orders
("OFOs"), or the equivalent, under Transporter's Tariff. UPR and UPFUELS also
recognize that such Transporter may issue an OFO that obligates UPR or UPFUELS
to take action that may be contrary to the terms of this Agreement, including,
without limitation, the delivery and taking of Gas in quantities contrary to
those set forth in Availability Reports and prior nominations. UPR and UPFUELS
agree to use commercially reasonable efforts to prevent the issuance of such an
OFO. If an OFO is issued, UPR and UPFUELS agree that compliance with any duly
authorized OFO will not constitute a violation of this Agreement, provided that:
(i) the Party receiving an OFO notifies the other Party as soon as possible and
(ii) the Parties use commercially reasonable efforts to minimize the operational
and economic consequences of compliance with the OFO by all means at their
disposal. If an OFO can be construed as calling for the shutting-in of UPR
production, the Parties will cooperate to take steps alternative to such a
shut-in. Neither Party shall be excused from its performance obligations under
this Agreement as a result of any OFO being issued by a pipeline which is not a
Transporter at the Delivery Point or if the OFO issued by the Delivery Point
Transporter only requires curtailment of interruptible transportation service
while other higher priority services continue to flow. In addition, nothing in
this Section 3.4 shall be construed as requiring either Party to bear adverse
economic consequences under an OFO unless such adverse economic consequences are
the direct result of any act or omission by such Party.
3.5 OPERATIONAL BALANCING AGREEMENTS. The Parties shall use
commercially reasonable efforts to maintain an operational balancing agreement
(an "OBA"), at each point of delivery into a transporting pipeline or at such
other points the Parties deem advisable. In respect to any point at
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which an OBA is not in effect, upon UPR's request, UPFUELS will assume the
responsibility for negotiating and implementing an OBA on terms and conditions
acceptable to UPR and UPFUELS.
IV. QUANTITY, DELIVERY & PURCHASE OF COMMITTED GAS
4.1 PURCHASE AND SALE OBLIGATION.
4.1.1 UPR'S DELIVERY OBLIGATION. Commencing on the Effective
Date and continuing through the term hereof, UPR agrees to sell and deliver, or
cause to be sold and delivered (excepting an event of Force Majeure or any other
reason excusing the performance of UPR's obligation to sell and deliver
Committed Gas hereunder, and subject in all respects to the provisions of
Section 4.2.6) to UPFUELS at the Delivery Point(s) one hundred percent (100%) of
deliverable Committed Gas, including, without limitation, (i) one hundred
percent (100%) of the quantities of Gas delivered in accordance with UPR's
Availability Report as set forth in Section 2.3 and adjusted in accordance with
Section 2.3.1, and (ii) one hundred percent (100%) of additional Committed Gas
as set forth in Section 2.3.2. It is specifically understood and agreed that UPR
shall have no obligation to deliver quantities of Committed Gas for which UPR
has given notice of its intention to curtail or shut-in pursuant to Section
2.2.4.
4.1.2 UPFUELS' TAKE OBLIGATION. Commencing on the Effective
Date and continuing through the term hereof, UPFUELS agrees to take and purchase
(excepting an event of Force Majeure or any other reason excusing the
performance of UPFUELS' obligation to purchase and take Committed Gas hereunder,
and subject in all respects to the provisions of Section 4.2.6) from UPR at the
Delivery Point(s) one hundred percent (100%) of deliverable Committed Gas,
including, without limitation (i) one hundred percent (100%) of Committed Gas
delivered in accordance with UPR's Availability Report as set forth in Section
2.3 and adjusted in accordance with Section 2.3.1, (ii) one hundred percent
(100%) of additional Committed Gas as set forth in Section 2.3.2. It is
specifically understood and agreed that UPFUELS shall have no obligation to take
quantities of Committed Gas for which UPR has given notice of its intention to
curtail or shut-in pursuant to Section 2.2.4.
4.2 CERTAIN DEFAULTS RELATED TO THE DELIVERY AND TAKING OF COMMITTED
GAS.
4.2.1 UPR OVER-DELIVERY DEFAULT. If, for any Day during any
Month, UPR delivers quantities of Committed Gas (including, without limitation,
additional quantities of Committed Gas delivered pursuant to Section 2.3.1 or
2.3.2) at all Delivery Point(s) on a Transporter that share a common Contract
Price under this Agreement and such aggregate deliveries exceed 105% of the
quantity of Committed Gas designated for delivery at such Delivery Point(s) in
the initial Availability Report for such Month (such excess Committed Gas being
herein called the "Excess Quantities", and the delivery of such Excess
Quantities being herein called a "UPR Over-Delivery Default"), then, as the sole
and exclusive remedy for such UPR Over-Delivery Default, UPFUELS shall pay an
amount equal to the product of (i) such Excess Quantities and (ii) the price
determined pursuant to the Daily Index, after any applicable Index Price
Adjustments.
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4.2.2 UPR UNDER-DELIVERY DEFAULT. If, for any Day during any
Month, UPR fails for any reason (other than Force Majeure or any other reason
excusing performance of UPR's obligation to deliver Committed Gas hereunder) to
deliver ninety-five percent (95%) of the quantities set forth in UPR's
First-of-the-Month Availability Report delivered pursuant to Section 2.3 at all
Delivery Point(s) on a Transporter that share a common Contract Price under this
Agreement (such quantities being referred to herein as the "Minimum Quantities,"
and such failure to deliver such Minimum Quantities being herein defined as a
"UPR Under-Delivery Default"), then, as the sole and exclusive remedy for such
UPR Under-Delivery Default, UPR shall pay UPFUELS, in accordance with the
provisions of Article VIII, an amount equal to the product of (x) the positive
difference, if any, between (A) the Daily Index Price applicable to the relevant
Delivery Point(s) on the Day of such UPR Under-Delivery Default and (B) the
Contract Price that UPFUELS would have paid for the quantities of Committed Gas
not delivered by UPR at such Delivery Point(s) on such Day and (y) the
difference between the Minimum Quantities and the quantities actually delivered
by UPR at such Delivery Point(s) on such Day. Notwithstanding the foregoing
provisions of this Section 4.2.2, the Parties acknowledge that no payment may be
due from UPR in respect of a UPR Under-Delivery Default if the Daily Index Price
is the applicable Contract Price. If a UPR Under-Delivery Default occurs solely
as the result of UPR's sale of Committed Gas to third Persons for reasons not
excused by this Agreement, then, in addition to any applicable remedy set forth
above for such Under-Delivery Default, UPR shall pay UPFUELS, in accordance with
Article VIII, an amount equal to the product of (A) twenty percent (20%) of the
Contract Price applicable to the relevant Delivery Point(s) on the Day of such
Default and (B) the difference between the Minimum Quantities and the quantities
actually delivered by UPR at such Delivery Point on such Day. UPR's payment
hereunder shall not be recoupable. Nothing herein shall be construed as
relieving UPR from Imbalance Charges for which it is liable under Section 3.3.1.
4.2.3 MATERIAL UPR DELIVERY DEFAULT. "Material UPR Delivery
Default" shall mean UPR's failure for any reason (including but not limited to
selling Committed Gas to third Persons, but excepting Force Majeure or any other
reason excusing performance of UPR's obligation to deliver Committed Gas
hereunder) to deliver (i) ninety percent (90%) of deliverable Committed Gas, as
set forth in UPR's Availability Report, adjusted in accordance with Sections
2.3.1 and 2.3.2, during any calendar year or (ii) ninety percent (90%) of
deliverable Committed Gas, as set forth in UPR's Availability Report, adjusted
in accordance with Sections 2.3.1 and 2.3.2, during any calendar quarter. In the
event of a Material UPR Delivery Default, UPR shall pay UPFUELS an amount equal
to the product of (x) 120% of the Contract Price that would have applied to the
Committed Gas that UPR failed to deliver and (y) the quantity of Committed Gas
that UPR failed to deliver during the applicable calendar year or calendar
quarter.
4.2.4 UPFUELS TAKE DEFAULT. A "UPFUELS Take Default" shall
occur if, during any Month, UPFUELS fails for any reason (other than Force
Majeure or any other reason excusing performance of UPFUELS' obligation to take
Committed Gas hereunder) to take one hundred percent (100%) of deliverable
Committed Gas required to be taken in accordance with Section 4.1.2, in which
event (i) such untaken Committed Gas shall be released to UPR for the remainder
of such Month, with UPR to use commercially reasonable efforts to market such
Gas, and (ii) as the sole and exclusive remedy for such UPFUELS Take Default,
UPFUELS shall pay UPR, in accordance with
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the provisions of Article VIII, an amount equal to: (a) the Contract Price
applicable to the relevant Delivery Point(s) on the Day of such UPFUELS Take
Default times the quantity of Committed Gas UPR is not able to market despite
commercially reasonable efforts to do so, and (b) for the quantities UPR is able
to market, UPFUELS shall pay UPR, an amount equal to the product of (A) the
higher of (1) the Daily Index Price applicable to the relevant Delivery Point(s)
on the Day of such UPFUELS Take Default times twenty percent (20%) or (2) 120%
of the positive difference, if any, between (x) the Contract Price less (y) the
Daily Index Price applicable to the relevant Delivery Point(s) on the Day of
such UPFUELS Take Default, and (B) the quantity of Committed Gas that UPFUELS
failed to take at such Delivery Point(s) on such Day. UPFUELS' payment hereunder
shall not be recoupable. Nothing herein shall be construed as relieving UPFUELS
for Imbalance Charges for which it is liable under Section 3.3.1.
4.2.5 MATERIAL UPFUELS TAKE DEFAULT. UPR may, in its
discretion, terminate this Agreement if a Material UPFUELS Take Default occurs
and UPR gives UPFUELS written notice of UPR's intention to terminate this
Agreement within sixty (60) Days after the last Day of the calendar year or
calendar quarter, as applicable, in which a Material UPFUELS Take Default
occurs, such termination to be effective on the last Day of the Month following
the Month in which such termination notice is delivered to UPFUELS. UPR's right
to terminate this Agreement for a Material UPFUELS Take Default shall be waived
if UPR fails to deliver to UPFUELS the notice described in the preceding
sentence of this Section within the 60-Day period set forth therein. After the
occurrence of a Material UPFUELS Take Default, UPR's sole and exclusive remedies
shall be (i) the recovery of any accrued and unpaid amounts due from UPFUELS
under Section 4.2.4 through the date of such Material UPFUELS Take Default, plus
interest accrued thereon in accordance with Section 8.4, and (ii) termination of
this Agreement pursuant to this Section. "Material UPFUELS Take Default" shall
mean UPFUELS' failure for any reason (other than Force Majeure or any other
reason excusing performance of UPFUELS' obligation to take Committed Gas
hereunder) to take (i) ninety percent (90%) of deliverable Committed Gas as set
forth in UPR's Availability Report, as adjusted in accordance with Sections
2.3.1 and 2.3.2, during any calendar year or (ii) ninety percent (90%) of
deliverable Committed Gas as set forth in UPR's Availability Report, as adjusted
in accordance with Sections 2.3.1 and 2.3.2, during any calendar quarter.
4.2.6 EXCLUSIVE CONSEQUENCES OF UPR DELIVERY DEFAULTS AND
UPFUELS TAKE DEFAULTS. The sole consequences of (i) a UPR Over-Delivery Default
are set forth in Section 4.2.1, (ii) a UPR Under-Delivery Default are set forth
in Section 4.2.2 and (iii) a Material UPR Delivery Default are set forth in
Section 4.2.3; provided, however, that if UPR shall fail to make any payment
required under any of such Sections when due, such failure shall constitute a
UPR Payment Default as provided in Section 11.2(b). The sole consequences of a
UPFUELS Take Default under this Agreement are set forth in Section 4.2.4
provided, however, that if UPFUELS shall fail to make any payment required
thereunder when due, such failure shall constitute a UPFUELS Payment Default as
provided in Section 11.2(a). The sole consequences of a Material UPFUELS Take
Default under this Agreement are set forth in Section 4.2.5. TO THE EXTENT THAT
DAMAGES IN RESPECT OF DEFAULTS ARE LIQUIDATED, THE PARTIES ACKNOWLEDGE AND AGREE
THAT ACTUAL DAMAGES ARE DIFFICULT OR IMPOSSIBLE TO DETERMINE, OTHERWISE
OBTAINING AN ADEQUATE REMEDY IS INCONVENIENT AND THE LIQUIDATED
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DAMAGES PROVIDED FOR HEREIN CONSTITUTE A REASONABLE APPROXIMATION OF THE HARM OR
LOSS RESULTING FROM SUCH A DEFAULT. ALL OTHER REMEDIES OR DAMAGES AT LAW OR IN
EQUITY RELATING TO A UPR OVER-DELIVERY DEFAULT, A UPR UNDER-DELIVERY DEFAULT, A
MATERIAL UPR DELIVERY DEFAULT, A UPFUELS TAKE DEFAULT AND A MATERIAL UPFUELS
TAKE DEFAULT ARE WAIVED, RELEASED AND RELINQUISHED IN RESPECT OF SUCH DEFAULTS.
THE PARTIES ACKNOWLEDGE THAT THE CONSEQUENCES OF THE DEFAULTS DESCRIBED IN THIS
ARTICLE IV ARE DIFFICULT OR IMPOSSIBLE TO DETERMINE AND THAT THE CONSEQUENCES
SET FORTH HEREIN RESPECTING SUCH EVENTS CONSTITUTE A REASONABLE APPROXIMATION OF
THE HARM OR LOSS THAT WOULD BE SUFFERED BY EITHER PARTY AS A RESULT OF SUCH A
DEFAULT BY THE OTHER PARTY.
4.3 PROVISION REGARDING OUTPUT CONTRACT LAWS. The Parties acknowledge
that deliveries of Committed Gas hereunder may increase or decrease
significantly from Month to Month as a consequence of the routine conduct of the
Parties' operations and a variety of factors affecting the market for Gas
generally. Accordingly, the Parties agree that (a) the obligations of UPR (i) to
sell and deliver Committed Gas and (ii) of UPFUELS to purchase and receive
Committed Gas, and (b) the methods used by UPFUELS and UPR pursuant to Section
2.3 to estimate the quantities of Committed Gas to be sold by UPFUELS and
purchased by UPR from Month to Month hereunder, are all commercially reasonable
means, arrived at by both Parties, acting in good faith, to minimize the
severity of such increases and decreases in deliveries, consistent with the
commercial realities of producing and marketing the Committed Gas and the
realities of Gas markets generally. The Parties agree that Section 2.306 of the
Texas Business and Commerce Code, or any provision of any law with similar
provisions (collectively, "Output Contract Laws"), is inapplicable to this
Agreement and the transactions hereby contemplated. To the extent that any
Output Contract Laws are held to apply to this Agreement and the transactions
hereby contemplated, the Parties hereby WAIVE, RELEASE AND RELINQUISH any
defenses to the enforcement of this Agreement arising from such Output Contract
Laws, and any claims that may be asserted by either Party arising from such
Output Contract Laws.
V. TITLE AND RESPONSIBILITY
5.1 UPR RESPONSIBILITY. Title to Committed Gas delivered by UPR to
UPFUELS shall pass to UPFUELS at the Delivery Points. All charges, royalties,
lease burdens, expenses, fees, claims, damages, demands, injuries and other
costs or losses incurred in or attributable to production and transfer,
transportation (except as otherwise agreed by the Parties), and handling of
Committed Gas delivered in accordance with this Agreement prior to delivery to
UPFUELS at the Delivery Point(s) shall be the exclusive responsibility of UPR,
as between the Parties, and UPR shall indemnify, defend, and hold harmless
UPFUELS from all such charges, royalties, lease burdens, expenses, fees, claims,
damages, demands, injuries, and other costs or losses.
5.2 UPFUELS RESPONSIBILITY. All charges, expenses, fees, claims,
damages, demands, injuries and other costs or losses incurred in or attributable
to the purchase and transfer, transportation, and handling of the Committed Gas
delivered in accordance with this Agreement at
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and after delivery of Committed Gas at the Delivery Point(s) shall be the
exclusive responsibility of UPFUELS, as between the Parties, and UPFUELS shall
indemnify, defend, and hold harmless UPR from all such charges, expenses, fees,
claims, damages, demands, injuries, and other costs or losses.
VI. QUALITY, MEASUREMENT AND TESTS
6.1 QUALITY SPECIFICATIONS. UPFUELS agrees to purchase Committed Gas
delivered by UPR to the Delivery Point(s) meeting the quality and pressure
specifications set forth in the Tariff of the Transporter immediately downstream
of the Delivery Point(s). If Committed Gas delivered by UPR to the Delivery
Point(s) is rejected by such Transporter for failure to meet its quality
specifications (such Committed Gas being herein sometimes called "Nonconforming
Gas"), UPFUELS shall be relieved of the obligation to purchase such Committed
Gas. If such Transporter accepts Nonconforming Gas tendered by UPR for UPFUELS'
account at the Delivery Point(s), UPR shall be deemed to have complied with the
quality specifications of this Agreement. UPR may bring such Nonconforming Gas
into conformity with the requirements of this Section 6.1 and, if such efforts
are successful, such Nonconforming Gas shall once again be Committed Gas and
subject in all respects to the terms and conditions of this Agreement. If it
would be uneconomical for UPR to bring such Nonconforming Gas into conformity
with the requirements of this Section 6.1, however, UPR shall notify UPFUELS in
writing of that fact (providing in such notice UPR's reasons for such conclusion
and the facts in support thereof), whereupon UPFUELS may, in its discretion (a)
accept such Nonconforming Gas for delivery at a price mutually acceptable to UPR
and UPFUELS, (b) have such Gas brought into conformity with Section 6.1 at its
sole cost and expense or (c) release such Nonconforming Gas from this Agreement.
Where UPFUELS may ship or redeliver Committed Gas to more than one Transporter,
UPFUELS will, if available, select a Transporter under whose standards such
Committed Gas would not be Nonconforming Gas. Without limiting the generality of
the foregoing provisions, it is expressly agreed and understood that either
Party may, but neither shall be obligated to, install and operate facilities
(including but not limited to compression facilities) to bring Committed Gas
into conformity with Transporter specifications. Any such facilities shall be
installed, operated and maintained at the sole cost, risk and expense of the
Party which elected to install such facilities, and either Party may discontinue
the operation of such facilities if, in the sole judgment of the Party
installing same, such operation is uneconomical. If neither Party elects to
install or continue the operation of such facilities, Nonconforming Gas shall be
released from the terms of this Agreement within thirty (30) Days of either
Party's written request for such a release. THE PROVISIONS OF THIS SECTION 6.1
SET FORTH THE SOLE REMEDIES FOR THE DELIVERY OR NON-ACCEPTANCE, AS APPLICABLE,
OF NONCONFORMING GAS, AND ALL OTHER REMEDIES ARE SPECIFICALLY WAIVED, RELEASED
AND RELINQUISHED BY THE PARTIES.
6.2 VOLUME AND HEATING VALUE. UPFUELS and UPR agree that the volume and
heating value of Committed Gas sold and delivered under this Agreement will be
measured at or near the Delivery Point(s) by the relevant Transporter, using
equipment owned or controlled by, and measuring procedures employed by, such
Transporter. The measurements made by such Transporter shall be accepted by
UPFUELS and UPR (subject to adjustment if prior measurements are determined to
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be inaccurate or incomplete), so long as the measuring equipment and procedures
used conform to Transporter's Tariffs and to generally recognized industry
standards. In addition, either Party may, at its sole expense and subject to
Transporter's approval, install check meters.
6.3 TEST DATA AND CHARTS. UPR and UPFUELS shall preserve all original
test data, charts and other similar records in a Party's possession for a period
of at least three years.
VII. PRICE
7.1 PRICE FOR COMMITTED GAS GENERALLY. Except as otherwise specifically
provided in this Article VII, UPFUELS shall pay UPR the Index Prices which , at
UPR's election, shall be either the First-of-the-Month Price or the Daily Index
Price for Committed Gas delivered at each Delivery Point. The
"First-of-the-Month Price" of Committed Gas at a given Delivery Point shall be
the price reported in the first issue of the designated commercial publication
of the relevant Index that is published in the Month of delivery of Committed
Gas at the relevant Delivery Point(s), such price to be shown in the applicable
table, heading and entry, after any Index Price Adjustments. The "Daily Index
Price" of Committed Gas at a given Delivery Point shall mean the price reported
in the issue of the designated commercial publication of the relevant Daily
Index published for the relevant Day that is applicable to the Delivery Point(s)
where Committed Gas is delivered hereunder, after any Index Price Adjustment.
UPR shall make its election between the First-of-the-Month Price and the Daily
Index Price for each Month in the First-of-the-Month Availability Report for
such Month delivered pursuant to Section 2.3. If UPR fails to make an election
between the First-of-the-Month Price and the Daily Index Price in the
Availability Report for any Delivery Point(s) for any Month, the
First-of-the-Month Price shall apply to the Committed Gas delivered at such
Delivery Point(s) for that Month, except as otherwise specifically provided
elsewhere in this Article VII. If multiple Indexes are applicable to a Delivery
Point for which UPR has failed to make an election under this Section 7.1, the
Index previously selected by UPR shall apply to the Committed Gas delivered at
such Delivery Point for that Month, except as otherwise specifically provided
elsewhere in this Article VII. Although the Parties will strive to reduce to
writing agreements replacing an existing Index with a new Index, the Parties
recognize that market conditions may require prompt action. Consequently, oral
agreements replacing an existing Index with a new Index will be effective until
reduced to writing. Subject in all respects to Section 7.4, the Parties agree to
exercise commercially reasonable efforts to reduce such oral agreements to
writing within thirty (30) Days after the date of the initial request for a
replacement Index. The First-of-the-Month Price shall be calculated each Month
during the term of this Agreement and, if selected by UPR for a particular Month
as to any Delivery Point, shall remain in effect during the entire Month unless
the Parties agree in writing to change the First-of-the-Month Price during the
course of the Month.
7.2 SPLIT CONNECT PRICE.
(a) GENERALLY. If Committed Gas is capable of being delivered
into Delivery Points located on more than one pipeline system ("Split Connect
Committed Gas"), UPR shall select up to three Indexes (any or all of which shall
be listed on Exhibit A for each relevant Delivery Point to use for the
First-of-the-Month Price or Daily Index Price, as applicable, and the
corresponding
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Index Price Adjustments applicable to such Split Connect Committed Gas (such
Indexes being herein called the "Split Connect Indexes"). "Split Connect Price"
shall mean the arithmetical average of the prices determined by the applicable
Split Connect Indexes. Each Split Connect Index selected by UPR must correspond
to a separate pipeline system into which the Split Connect Committed Gas is
capable of being delivered, and such selection will remain in effect for a
period of no less than five full Months or seven full Months, as the case may
be, with the five-Month period to run each year from November 1 through March 31
and the seven-Month period from April 1 through October 31. UPR shall make its
selection of Split Connect Indexes and Index Price Adjustments by choosing in
the First-of-the-Month Availability Report pursuant to Section 2.3 either (x)
all of the First-of-the-Month Split Connect Indexes and Index Price Adjustments
or (y) all of the Daily Split Connect Indexes and Index Price Adjustments set
forth in Exhibit A with respect to any Delivery Point at which Split Connect
Committed Gas is to be delivered. If UPR fails to make an election between the
First-of-the-Month Split Connect Indexes and related Index Price Adjustments and
the Daily Split Connect Indexes and Index Price Adjustments in any such
Availability Report, the First-of-the-Month Indexes and related Index Price
Adjustments shall apply to the Committed Gas delivered at such Delivery Point(s)
for that Month, except as otherwise specifically provided elsewhere in this
Article VII.
(b) CAPACITY CONSTRAINTS. The Parties acknowledge that, from
time to time, constraints on available Transporter capacity on a Monthly basis
for firm markets in certain pipeline systems may limit the quantities of Split
Connect Committed Gas that may be delivered into such systems, which in turn
would affect the Split Connect Price payable to UPR hereunder. The existence of
such capacity constraints shall be determined on the basis that capacity
constraints actually exist, announced pipeline constraints or curtailments and
by the success of UPFUELS' efforts to nominate Committed Gas for delivery into
the applicable pipeline. If UPFUELS notifies UPR at least one (1) Business Day
before the beginning of the Month that a capacity constraint exists on a
specified pipeline system, then the Split Connect Price applicable to such
capacity-constrained Split Connect Committed Gas that Transporter shall be
determined by the Parties. If the Parties cannot agree that the capacity
constraints exist, or cannot agree on the Split Connect Price within thirty (30)
Days after UPFUELS' notification to UPR of the existence of a capacity
constraint, then the disagreement shall be resolved in accordance with the
dispute resolution procedures set forth in Article XII.
7.3 LOCKED PRICE OPTION. In lieu of an Index Price provided for
pursuant to Sections 7.1 or 7.2, UPR may request that a fixed price (the "Locked
Price") be substituted for the Index Price for a period as short as one Month or
as long as twelve Months. The Index Price Adjustments used to calculate the
Contract Price under Sections 7.1 or 7.2 shall not be affected by the
substitution of a Locked Price. The Parties acknowledge that a Locked Price will
be based on New York Mercantile Exchange (or other exchange selected by UPFUELS)
posting for the Natural Gas futures contract applicable to the Month(s) selected
by UPR and prevailing at the time of UPR's request for a Locked Price plus a
differential adjustment required to equate the posted price with the market
price of Committed Gas delivered at the applicable Delivery Point.
7.3.1 REQUEST FOR A LOCKED PRICE. UPR may request a quote of a
Locked Price by telephone on any Business Day, between the hours of 8:30 a.m.
and 2:00 p.m., local Fort Worth,
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Texas time, up to and including the second Business Day prior to the beginning
of a Month to which the Locked Price shall apply. UPR's request shall identify
the Delivery Point(s) subject to the request for a Locked Price, the Month(s)
for which UPR requests a Locked Price and the quantity of Committed Gas
estimated to be delivered from the applicable Delivery Point(s) that will be
subject to the Locked Price. UPR and UPFUELS acknowledge and agree that all
telephone conversations between the Parties relating to a Locked Price may be
recorded by UPFUELS or UPR, or both, for purposes of establishing the terms and
conditions associated with a Locked Price. UPR and UPFUELS also agree that the
taped conversation may be used to establish the terms and conditions associated
with a Locked Price if the Parties are unable to agree on such terms and
conditions subsequent to the conversation in question.
7.3.2 PROCEDURES. As soon as possible after UPR's telephonic
request, but in any event by no later than the end of the Business Day following
UPR's request, UPFUELS' Authorized Trader (as designated pursuant to Section
14.4) shall determine if it is able to offer a Locked Price and, if it is able,
the Locked Price (expressed in MMBtus) it is willing to offer, and shall notify
UPR's Authorized Trader (as designated pursuant to Section 14.4) of such Price.
UPFUELS' notice shall be addressed to UPR's Authorized Trader, and shall
separately state the differential, if any, applicable to the Locked Price. If
UPR accepts the Locked Price, including any adjustments thereto required to
reflect the market value at the Delivery Point(s) of the Committed Gas sold
pursuant to the Locked Price, then UPFUELS shall forward to UPR's Authorized
Trader a "Price Lock Confirmation," in substantially the form attached hereto as
Exhibit D, specifying the terms to which the Parties have agreed. Such Price
Lock Confirmation shall be forwarded to UPR's Authorized Trader as soon as
possible following UPR's acceptance of the Locked Price. The terms set forth in
the Price Lock Confirmation shall be binding upon the Parties unless UPR's
Authorized Trader notifies UPFUELS' Authorized Trader in writing that UPR
disputes one or more of the terms set forth in said Price Lock Confirmation
within two (2) Business Days of UPR's Authorized Trader's receipt of the Price
Lock Confirmation.
7.3.3 LOCKED QUANTITIES. UPR may request that all, or any
portion of, the Committed Gas available for delivery from one or more Delivery
Point(s) during the Month(s) designated by UPR be subject to a Locked Price
determined under this Section 7.3, provided that UPR's request shall designate a
specific quantity of Committed Gas. UPFUELS shall be entitled to decline to
offer a Locked Price on such quantities at its sole discretion. If a Locked
Price has been established for a portion of the quantities of Committed Gas
available for delivery from one or more Delivery Point(s) for a given period,
UPR shall be entitled to make one or more additional requests for a Locked Price
on all or any additional quantities of the remaining Committed Gas available for
delivery from such Delivery Point(s) during the designated period.
7.3.4 IRREVOCABILITY. Unless UPR and UPFUELS agree otherwise
in writing, a Locked Price shall remain effective for the entire period
designated in the Price Lock Confirmation and shall not be increased or
decreased.
7.3.5 AVAILABILITY OF COMMITTED GAS. UPR shall not be entitled
to curtail production and delivery, and UPFUELS shall not be entitled to curtail
takes, of Committed Gas
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subject to a Locked Price pursuant to this Section 7.3 for any reason including,
without limitation, force majeure. If UPR and UPFUELS establish a Locked Price
for less than one hundred percent (100%) of the Committed Gas available for
delivery from one or more Delivery Point(s) or establish more than one Locked
Price for Committed Gas available for delivery from one or more Delivery
Point(s), the first Committed Gas delivered on each Day and during the
applicable Month shall be deemed to be subject to the first Locked Price
established, followed by quantities of Committed Gas subject to additional
Locked Prices in the order established, followed by quantities of Committed Gas
not subject to a Locked Price.
7.3.6 CESSATION OF FUTURES TRADING. If Natural Gas futures
contracts cease to be traded on the New York Mercantile Exchange or on any other
mercantile exchange acceptable to UPFUELS in its sole discretion, then after
such cessation UPFUELS shall be relieved of any and all obligation to
established Locked Prices hereunder, upon providing UPR with written notice that
such cessation has occurred, and that UPFUELS no longer wishes to provide UPR
with a Locked Price hereunder.
7.3.7 APPLICABILITY OF OTHER PROVISIONS OF THIS AGREEMENT TO
COMMITTED GAS SOLD UNDER A LOCKED PRICE. Except as specifically provided in the
Price Lock Confirmation, the terms of this Agreement shall continue to apply to
Committed Gas sold pursuant to a Locked Price, except that UPR's obligation to
deliver Committed Gas subject to a Locked Price shall be a Monthly obligation
and not a Daily obligation. Accordingly, for purposes of this Agreement, UPR
shall have complied with its obligation to deliver quantities of Committed Gas
subject to a Locked Price if it delivers such quantities at the applicable
Delivery Point(s) during the course of the Month, without regard to variations
in quantities delivered on any particular Day. However, nothing herein shall
relieve UPR from Imbalance Charges for which it is liable under Section 3.3.1.
7.3.8 LIQUIDATION OF HEDGE POSITIONS. The Parties acknowledge
that a hedge position is a financial transaction which requires liquidation if
physical delivery or receipt of the Locked Price Gas is interrupted for any
reason (including without limitation Force Majeure). Such interruption may
require liquidation of the entire position, which may not be partially
liquidated to accommodate only the duration, or anticipated duration, of the
interruption. In the event any hedge position is undertaken by UPFUELS in
reliance upon an agreed Locked Price, and delivery of the Locked Price Gas is
interrupted for any reason, including without limitation Force Majeure, then UPR
shall be liable to UPFUELS for any actual, direct loss incurred by UPFUELS in
liquidating such hedge position in a commercially reasonable manner. A loss is
incurred when all costs of undertaking the position exceed the net liquidation
proceeds. In the event such liquidation yields a profit (i.e. net liquidation
proceeds exceed all costs of undertaking the position), then UPR shall be paid
or credited with such profit. UPFUELS in the exercise of its sole discretion,
shall determine: (i) whether the anticipated or estimated duration of the
interruption justifies liquidation of the entire hedge position, and (ii)
whether the affected hedge position may be feasibly or economically liquidated
in part only. The decision of UPFUELS with regard to such matters shall be
controlling.
7.4 REPLACEMENT OF INDEXES; REDETERMINATION OF INDEXES, SPLIT CONNECT
INDEXES AND INDEX PRICE ADJUSTMENTS. If, during the term of this Agreement, (i)
an Index used to determine
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the Index Price for any Delivery Point ceases to be available, (ii) either Party
believes that another Index more accurately reflects existing market conditions
with respect to any Delivery Point(s) than the Index currently being used with
respect to such Delivery Point(s), or (iii) either Party believes that the Index
Price Adjustments with respect to any Index Price for any Delivery Point(s) no
longer accurately reflects all differentials reasonably necessary to adjust the
Index Price for Gas to accurately reflect the market price for Gas of like
quantities and quality at such Delivery Point(s), then either Party may request
the other to reconsider the currently-applicable Index or Index Price
Adjustment. If the Parties cannot agree on a replacement Index or an appropriate
change to the Index Price Adjustment in question within thirty (30) Days after
such request, then the dispute resolution provisions of Article XII shall apply.
The Parties shall review the appropriateness of, and make selection of or
request changes to, all Index(es), Split Connect Indexes, and Index Price
Adjustments prior to February 15 and September 15 of each year, and shall not
request any change in Index pursuant to clause (ii) or in Index Price Adjustment
pursuant to clause (iii) more than once in each applicable five or seven-Month
period. Any disputes regarding Indexes or Index Price Adjustments remaining
unresolved by the following April or November, as applicable, shall be
consolidated and submitted to the dispute resolution procedures set forth in
Article XII.
7.5 PROVISIONS RELATING TO PRICING EXHIBIT; PROCEDURES FOR CHANGE OF
EXHIBIT. The attached Exhibit A accurately sets forth the Parties agreement
regarding the Indexes, Split Connect Indexes, Index Price Adjustments and
Delivery Points applicable to Committed Gas as of the Effective Date, and such
Indexes, Index Price Adjustments and Delivery Points shall not change for a
period of sixty (60) Days after the Effective Date except for (i) the deletion
of Delivery Points no longer needed for the delivery of Committed Gas, (ii) the
replacement of any Index that ceases to be available during such period, (iii)
changes in an Index Price Adjustment, or (iv) changes or amendments to
Transporter Tariffs or agreements with Transporters that affect actual costs of
transportation including, without limitation, changes in fuel retention
percentages insofar as such costs are a part of an Index Price Adjustment.
Either Party may propose a change in Exhibit A after the end of such 60-Day
period, subject to the limitations of Section 7.4, by giving the other Party no
less than thirty (30) Days' written notice before the first Day of the Month
such change is proposed to be effective (the "Price Effective Date"). If the
other Party agrees in writing to such change, the change shall be effective on
the Price Effective Date. If the other Party does not agree in writing to the
proposed change by the tenth (10th) Day prior to the proposed Price Effective
Date, then the proposed change shall not be effective, and either Party may seek
to resolve the dispute pursuant to Article XII.
VIII. ACCOUNTING, BILLING AND PAYMENT
8.1 STATEMENTS. UPFUELS shall provide UPR with a written and
electronically transmitted statement by not later than the 15th Day of the Month
for Committed Gas delivered during the preceding Month. Such statement shall set
forth (a) the quantities of Committed Gas received at each Delivery Point(s),
(b) the Contract Price applicable to such Committed Gas (indicating, where
appropriate, the applicability of the First-of-the-Month Price, the Daily Index
Price, the Split Connect Price or the Locked Price), as provided herein, at each
of such Delivery Point(s), (c) any amount (i) due UPR in respect of any UPFUELS
Take Defaults under Sections 4.2.4 or 4.2.5
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(including reasonably satisfactory evidence of such amounts), or (ii) due
UPFUELS in respect of any UPR Delivery Defaults under Sections 4.2.1, 4.2.2 or
4.2.3 (including reasonably satisfactory evidence of such amounts) and (d) any
amounts (i) due UPR in respect of an Imbalance Charge for which UPFUELS is
responsible (including reasonably satisfactory evidence of such amounts) or (ii)
due UPFUELS in respect of Imbalance Charge for which UPFUELS is responsible
(including reasonably satisfactory evidence of such amounts), together with an
invoice for payment based thereon less any amounts due UPFUELS pursuant to
clauses (c) and (d) above. If actual quantities delivered at each of such
Delivery Point(s) are not available by the 15th Day of the Month, UPFUELS may
furnish statements and invoices based on UPR's Availability Report pursuant to
Sections 2.3, 2.3.1 and 2.3.2 which statements and invoices shall be adjusted to
reflect actual deliveries as soon as practicable after such actual deliveries
become known. Within five (5) Business Days of the request of either Party, the
other Party shall provide, to the extent it has a legal right of access thereto
and/or such statement is then available, a copy of the Transporter's allocation
or imbalance statement applicable to the Committed Gas for the requested period.
UPR will cooperate with UPFUELS in helping UPFUELS obtain all information
necessary or desirable to prepare UPFUELS' statements and invoice in accordance
with this Section 8.1.
8.2 PAYMENT. By no later than the 25th Day of the Month following the
Month in which Committed Gas was delivered, UPFUELS shall pay UPR, by wire
transfer of immediately available funds into an account designated by UPR, all
amounts due under this Agreement for Committed Gas delivered during the previous
Month. If the Day on which payment is due hereunder does not fall on a Business
Day, then UPFUELS' payment shall be due on the preceding Business Day.
8.3 DISPUTED PAYMENTS. Should a statement be disputed by a Party in
good faith, the disputing Party will pay any undisputed amount and will notify
the other Party in writing of the disputed amount and the basis for the dispute.
Payment of the undisputed portion of a statement will not be deemed a waiver of
the paying Party's right to recoup any overpayment, and acceptance of such
payment will not be deemed a waiver of the accepting Party's right to recover
any underpayment. The Party that rendered the disputed statement will promptly
investigate the dispute and will submit a corrected statement, if necessary,
within thirty (30) Days after receiving notice of the dispute. If the Parties
cannot agree on the disputed amount within such 30-Day period, then either Party
may institute dispute resolution procedures in accordance with Article XII. If
upon resolution of the dispute (whether by agreement or otherwise), a Party is
determined to have underpaid the amount actually due, the Party will remit the
amount due, plus interest thereon from the date such amount should have been
paid until such amount has been received by the underpaid Party, calculated at
the rate stated in Section 8.4 herein. If upon resolution of the dispute
(whether by agreement or otherwise), a Party is determined to have overpaid the
amount actually due, the Party to whom such overpayment was made will refund the
excess paid, plus interest thereon from the date such amount was received by the
overpaid Party until such amount has been received by the underpaid Party,
calculated at the rate stated in Section 8.4 herein.
8.4 OVERDUE PAYMENTS. Subject in all respects to Section 8.3, if either
Party fails to pay the amount due the other Party when due hereunder as set
forth in Section 8.2, then interest on any such unpaid and overdue amount shall
accrue until paid at the Reference Rate.
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8.5 TWO YEAR LIMIT ON ADJUSTMENTS. Any statement, charge or payment
under this Agreement will be deemed final unless disputed in accordance with
Section 8.3 within 24 Months from the final Business Day of the calendar year in
which such statement, charge or payment was made or rendered, except for any
adjustments to such statement, charge or payment due to volume adjustments of
Committed Gas delivered at the Delivery Point(s) and other adjustments caused by
Transporters' statements affecting payments for Committed Gas or Imbalance
Charges, in which event any dispute regarding such adjustments must be made
within 24 months of the final Business Day of the calendar year in which notice
of such adjustment was received. Any payment with respect to a retroactive
adjustment shall include an amount equal to interest on all amounts past due
from the date of the initial payment at the rate set forth in Section 8.4 above.
8.6 AUDIT. Each Party shall keep and maintain true and correct books,
records, files and accounts of all information reasonably related to the
transactions contemplated by this Agreement, including all measurement records,
all information used to determine prices and calculate invoices, all invoices,
statements and payment records (collectively, the "Records"). Each Party shall
have the right, upon reasonable written notice to the other Party of not less
than ten (10) Business Days, to audit the Records of the other Party at any time
during reasonable business hours during the term of this Agreement and for a
period of 24 Months after the Month of such Agreement's termination, to the
extent necessary to determine compliance by the other Party with the terms of
this Agreement, but such audit rights shall be limited to auditing such Records
for the then current and three (3) preceding calendar years. Notwithstanding the
foregoing, if a governmental body asserts a claim, or conducts an audit, against
a Party arising from the purchase or sale of Committed Gas and that Party
determines in its reasonable judgment that its response to such claim requires
or would benefit from an audit of the Records of the other Party, such audit may
be conducted during the term of this Agreement and for a period ending on the
fifth anniversary of the event or payment forming the basis of such governmental
claim. In order to accommodate such governmental audits, UPR and UPFUELS will
maintain the appropriate Records for a period of not less than five (5) years.
Each Party shall also have access to the Records of the other Party for purposes
of responding to claims, or requests for audits, asserted by a non-governmental
third Person and arising from the purchase or sale of Committed Gas.
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8.7 LETTER OF CREDIT; CREDIT ENHANCEMENT.
(a) INITIAL LETTER OF CREDIT REQUIREMENT. Subject to Section
8.7(d), on or before the Effective Date, UPFUELS' Affiliate, Duke Energy Trading
and Marketing, L.L.C. ("DETM") shall have executed and delivered, at its sole
cost and expense, one or more irrevocable standby letters of credit (the "Letter
of Credit," whether one or more), issued by one or more commercial banks
satisfactory to UPR, in an aggregate amount equal to the Initial Amount
(hereinafter defined), and otherwise in form, term and substance satisfactory to
UPR. The Initial Amount shall equal the product of (i) the average Daily
quantities of Committed Gas designated for delivery by UPR in the initial
Availability Report delivered to UPFUELS in accordance with Section 2.3 of this
Agreement, (ii) the Contract Price estimated in good faith by UPR to be payable
in respect of Committed Gas designated for delivery by UPR pursuant to clause
(i) and (iii) sixty-five (65) Days. DETM's delivery of the Letter of Credit
shall be a condition precedent to the performance of UPR's obligations
hereunder.
(b) ADJUSTMENT OF INITIAL AMOUNT. Except as otherwise provided
in this Section 8.7(b), the Initial Amount shall not be subject to adjustment
until April 1999, when UPR shall review the Initial Amount and all other terms
of the Letter of Credit to determine whether such Initial Amount or such other
terms should be adjusted in view of all commercial factors relevant to the
assurance of UPFUELS' performance of its obligations under this Agreement,
including but not limited to (i) DETM's creditworthiness, (ii) the general level
of prices for Gas and other energy commodities and (iii) the condition of the
domestic and international economy. UPR shall thereafter review the amount and
other terms of the Letter of Credit not less frequently than each subsequent
October and April during the term of this Agreement. Nothing in this Section
8.7(b) shall be construed to limit UPR's right to review the amount of the
Letter of Credit on a more frequent basis, however, or to require such
additional credit enhancement as UPR deems necessary to provide adequate
assurances of UPFUELS' obligations hereunder. Notwithstanding the foregoing, the
Parties agree that no adjustment shall result in a Letter of Credit with an
obligation greater than the product of (x) the quantities of Committed Gas
estimated in good faith to be delivered by UPR over a period of sixty-five (65)
Days, (y) the Contract Price estimated in good faith by UPR to be payable in
respect of such Committed Gas over such period and (z) sixty-five (65) Days.
(c) MAINTENANCE OF LETTER OF CREDIT. DETM shall maintain the
Letter of Credit at all times during the term of this Agreement, and shall give
UPR not less than sixty (60) Days' written notice by registered mail prior to
the expiration of any Letter of Credit. DETM's failure to maintain the Letter of
Credit in the amounts and on the terms required hereunder, or to provide UPR
with any other credit enhancement required hereunder, shall be a DETM Credit
Default, and shall entitle UPR to exercise the remedies set forth in Article XI,
including but not limited to suspension of performance hereunder and the
termination of this Agreement.
(d) Notwithstanding the foregoing provisions of this Section
8.7, UPR shall not require DETM to maintain a Letter of Credit as long as DETM
maintains a credit rating of no lower than BBB by Standard and Poors or Baa2 by
Moody's.
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IX. DISCLAIMER AND WARRANTY
9.1 WARRANTY. UPR warrants title to, or the right to sell, all Gas
delivered to UPFUELS under this Agreement. UPR also warrants that all such Gas
shall be free from all liens, encumbrances and adverse claims, other than (i)
Liens as permitted under Section 2.2.7, and (ii) liens mandated by Section 9-319
of the Texas Business and Commerce Code and the statutes, if any, in other
jurisdictions with like lien provisions of mandatory application.
9.2 DISCLAIMER. EXCEPT AS MADE IN SECTION 9.1 (REGARDING UPR'S TITLE),
UPR MAKES NO OTHER WARRANTIES, EXPRESS, IMPLIED, STATUTORY OR OTHERWISE, WITH
RESPECT TO COMMITTED GAS SOLD HEREUNDER, INCLUDING, WITHOUT LIMITATION,
WARRANTIES OF MERCHANTABILITY AND FITNESS FOR A PARTICULAR PURPOSE.
X. FORCE MAJEURE
10.1 SUSPENSION OF OBLIGATIONS. If either UPR or UPFUELS is rendered
unable, by reason of an event of Force Majeure, to perform, wholly or in part,
any obligation or commitment set forth in this Agreement, except for the payment
of monies owed, then upon that Party's giving notice (the initial notice may be
oral notice followed by written notice within five (5) Business Days of such
oral notice) and full particulars of the event of Force Majeure, then the
obligations of both Parties under this Agreement shall be suspended, except for
the payment of amounts owed under this Agreement, to the extent and for the
period of such Force Majeure event.
10.2 FORCE MAJEURE DEFINED. The term "Force Majeure" means an event
that (i) was not within the control of the Party claiming its occurrence; and
(ii) could not have been prevented or avoided by such Party through the exercise
of due diligence. Events of Force Majeure include, without limitation by
enumeration: acts of nature; lightning, hurricanes or storms, hurricane or storm
warnings which in UPR's judgment require and result in the precautionary
shut-down or evacuation of production facilities; earthquakes, epidemics, fires,
floods, landslides, washouts, freezing of wells or lines of pipe used to supply
Committed Gas under this Agreement and other similar severe natural calamities;
events of force majeure affecting processing or fractionation plants at which
Committed Gas is being processed, if such events prevent the delivery of such
Committed Gas to the Delivery Point(s) provided for in this Agreement; acts of
public enemy; wars; blockades; insurrections; riots; civil disturbances and
arrests; strikes, lockouts or other industrial disturbances; explosions,
breakage, accidents to wells, equipment, facilities or lines of pipe used to
enable UPR to deliver or UPFUELS to receive Committed Gas under this Agreement;
the inability or refusal of any Transporter of Gas to receive, transport or
deliver Gas sold or purchased hereunder (but only if (x) such inability or
refusal results from an event that is interrupting such Transporter's service to
its firm customers and (y) no available alternative for the transportation of
the affected Committed Gas exists); imposition by a regulatory agency, court or
other governmental authority having jurisdiction, of binding laws, conditions,
limitations, orders, rules or regulations that prevent or prohibit either Party
from performing its obligations hereunder, provided such governmental action has
been resisted in good faith by all reasonable legal means; or any other cause of
a similar type whether of the kind herein
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enumerated or otherwise, not within the control of the Party claiming suspension
and which by the exercise of due diligence such Party is unable to overcome.
Force Majeure shall also include the inability to acquire, or delays in
acquiring, at reasonable cost and after the exercise of reasonable diligence,
any servitudes, right-of-way grants, permits or licenses required to be obtained
to enable a Party hereto to fulfill its obligations hereunder.
10.3 EXCLUSIONS. Force Majeure does not include loss of markets, a
change in market prices for Gas or the interruption of interruptible
transportation service.
10.4 LABOR DISPUTES. The settlement of strikes or lockouts shall be
entirely within the discretion of the Party having the difficulty and the above
requirement of the use of diligence in restoring normal operating conditions
shall not require the settlement of strikes or lockouts by acceding to the terms
of the opposing Person(s) when such course is inadvisable in the discretion of
the Party having the difficulty.
10.5 MARKETING OF FORCE MAJEURE GAS. If UPFUELS is unable to take
Committed Gas from any Delivery Point(s) due to the occurrence of Force Majeure,
UPR, acting in a commercially reasonable manner, may market and sell such
Committed Gas from the affected Delivery Point(s) to any third parties free from
this Agreement and without any obligation to UPFUELS during the continuance of
the Force Majeure. As soon as the Force Majeure that rendered UPFUELS unable to
take Committed Gas is remedied or terminated, UPR's obligation to thereafter
commence selling the Committed Gas to UPFUELS shall commence following the
expiration of any agreement between UPR and third parties for the purchase of
Committed Gas that UPFUELS was unable to take and that UPR subsequently marketed
and sold to such parties as permitted by this Section 10.5. It is specifically
understood and agreed that any such agreement between UPR and third parties
shall terminate no later than the last Day of the Month in which the Force
Majeure event occurred; provided, however, if the Force Majeure event has not
been remedied two (2) Business Days prior to the end of such Month, or the force
majeure event is not scheduled (two Business Days prior to the end of such
Month) to be remedied by the first Business Day of the next succeeding Month,
UPR may contract with third parties to sell such Gas in the next succeeding
Month. UPR shall use commercially reasonable efforts to terminate any such
agreement within a shorter period so that the Committed Gas being sold
thereunder will be available for sales to UPFUELS once UPR receives notice from
UPFUELS pursuant to this Section 10.5 that such Force Majeure has been remedied
or terminated.
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XI. TERM, DEFAULT AND REMEDIES
11.1 TERM.
(a) GENERAL. This Agreement shall remain in full force and
effect until the first to occur of: (i) the fifth (5th) anniversary of the
Effective Date (it being understood that, subject to the other terms and
conditions of this Agreement, this Agreement shall be automatically extended
from year to year after such fifth anniversary, unless terminated by either
Party upon written notice delivered to the other Party at least 180 Days prior
to the last Day of the then-effective term); (ii) termination of this Agreement
by UPR for a Material UPFUELS Take Default pursuant to Section 4.2.5; (iii)
termination of this Agreement for other Defaults enumerated in Section 11.3(a),
or (iv) upon the occurrence of a Change of Control with respect to either Party,
as provided in Section 13.3.
(b) SURVIVAL OF OBLIGATIONS. Termination of this Agreement
shall in no way relieve any Party from any obligations or liabilities accrued
hereunder as of the date of termination, and any imbalances in receipts or
deliveries shall be corrected to zero within sixty (60) Days after such date. In
addition, all indemnity obligations of the Parties shall survive the termination
of this Agreement for the maximum period prescribed by applicable law.
11.2 DEFAULTS.
(a) UPFUELS DEFAULT DEFINED. Each of the following shall be
deemed a "UPFUELS Default": (i) UPFUELS' failure to pay or cause to be paid any
undisputed amount owing under this Agreement when due (including, without
limitation, payments due from UPFUELS in respect of a UPFUELS Take Default or
UPFUELS Material Take Default and any interest accrued on any amounts payable
hereunder in accordance with Section 8.4) for a period of three (3) Business
Days after the due date (a "UPFUELS Payment Default"); (ii) a Material UPFUELS
Take Default (as defined in Section 4.2.5); (iii) the occurrence of one or more
of the following events with respect to UPFUELS: (A) the entry of a decree or
order for relief against UPFUELS by a court of competent jurisdiction in any
involuntary case brought against UPFUELS under any bankruptcy insolvency or
other similar law (collectively, "Debtor Relief Laws") generally affecting the
rights of creditors and relief of debtors now or hereafter in effect, (B) the
appointment of a receiver, liquidator, assignee, custodian, trustee,
sequestrator or other similar agent under applicable Debtor Relief Laws for
UPFUELS or for any substantial part of its assets or property, (C) the ordering
of the winding up or liquidation of the UPFUELS' affairs, (D) the filing of a
petition in any such involuntary bankruptcy case, which petition remains
undismissed for a period of 180 Days or which is not dismissed or suspended
pursuant to Section 305 of the Federal Bankruptcy Code (or any corresponding
provision of any future United States bankruptcy law) (E) the commencement by
UPFUELS of a voluntary case under any applicable Debtor Relief Law now or
hereafter in effect, (F) the consent by UPFUELS to the entry of an order for
relief in an involuntary case under any such law or to the appointment of or the
taking of possession by a receiver, liquidator, assignee, trustee, custodian,
sequestrator or other similar agent under any applicable Debtor Relief Laws for
UPFUELS or for any substantial part of its assets or property, or (G) the making
by UPFUELS of any general assignment for the benefit of
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its creditors (the events referred to in clauses (A) through (G) being
collectively referred to as a "UPFUELS Bankruptcy Default"); (iv) the failure of
DETM to maintain the Letter of Credit, or any other credit enhancement, required
under Section 8.7 (a " DETM Credit Default"); (v) the inaccuracy, in any
material respect, of any representation or warranty made by UPFUELS in Section
14.11 (a "UPFUELS Representation Default"); or (vi) UPFUELS' failure to perform
any covenant or other obligation in this Agreement (other than those specified
in clauses (i) through (v) of this Section 11.2(a)), and if such failure is
susceptible of cure before UPR suffers any costs or losses as a result thereof,
such failure is not remedied within thirty (30) Days of UPFUELS' receipt of a
written notice describing the particulars of such failure in reasonable detail
(such failure being herein called a "UPFUELS Covenant Default").
(b) UPR DEFAULT DEFINED. Each of the following shall be deemed
a "UPR Default": (i) UPR's failure to pay or cause to be paid any undisputed
amount owing under this Agreement when due (including, without limitation,
payments due from UPR in respect of a UPR Delivery Default; and any interest
accrued thereon in accordance with Section 8.4) for a period of sixty (60) Days
after the due date (a "UPR Payment Default"); (ii) a UPR Over-Delivery Default
(as defined in Section 4.2.1), a UPR Under-Delivery Default (as defined in
Section 4.2.2) or a Material UPR Delivery Default (as defined in Section
4.2.3.), (iii) the occurrence of one or more of the following events with
respect to UPR: (A) the entry of a decree or order for relief against UPR by a
court of competent jurisdiction in any involuntary case brought against UPR
under any Debtor Relief Laws generally affecting the rights of creditors and
relief of debtors now or hereafter in effect, (B) the appointment of a receiver,
liquidator, assignee, custodian, trustee, sequestrator or other similar agent
under applicable Debtor Relief Laws for UPR or for any substantial part of its
assets or property, (C) the ordering of the winding up or liquidation of UPR's
affairs, (D) the filing of a petition in any such involuntary bankruptcy case,
which petition remains undismissed for a period of 180 Days or which is not
dismissed or suspended pursuant to Section 305 of the Federal Bankruptcy Code
(or any corresponding provision of any future United States bankruptcy law) (E)
the commencement by UPR of a voluntary case under any applicable Debtor Relief
Law now or hereafter in effect, (F) the consent by UPR to the entry of an order
for relief in an involuntary case under any such law or to the appointment of or
the taking of possession by a receiver, liquidator, assignee, trustee,
custodian, sequestrator or other similar agent under any applicable Debtor
Relief Laws for UPR or for any substantial part of its assets or property, or
(G) the making by UPR of any general assignment for the benefit of its creditors
(the events referred to in clauses (A) through (G) being collectively referred
to as a "UPR Bankruptcy Default"); (iv) the inaccuracy, in any material respect,
of any representation or warranty made by UPR in Section 14.10 (a "UPR
Representation Default"); or (v) UPR's failure to perform any covenant or other
obligation in this Agreement (other than those specified in clauses (i) through
(iv) of this Section 11.2(b)), and if such failure is susceptible of cure before
UPFUELS suffers any costs or losses as a result thereof, such failure is not
remedied within thirty (30) Days of UPR's receipt of a written notice describing
the particulars of such failure in reasonable detail (such failure being herein
called a "UPR Covenant Default").
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11.3 CONSEQUENCES OF DEFAULTS.
(a) GENERAL. Except as explicitly provided in this Agreement,
and subject in all respects to the other terms and conditions hereof (including,
without limitation, Section 4.2.6), the Party not in Default (herein referred to
as an "Unaffected Party") may take such actions as it may be permitted to take
under applicable law in consequence of a Default of the other Party (herein
sometimes called the "Defaulting Party"), including, without limitation, the
exercise of setoff rights under Section 11.4, the right to suspend further
performance under this Agreement and, in the case of UPR, the right to sell all
or any part of the Committed Gas to third Persons; provided, however, that the
right to terminate this Agreement shall only be applicable (A) upon occurrence
of a UPFUELS Bankruptcy Default or a UPR Bankruptcy Default (whereupon this
Agreement shall terminate automatically and immediately), (B) upon occurrence of
a UPFUELS Payment Default (whereupon this Agreement shall immediately terminate,
at UPR's election, if UPR had previously given at least ten (10) Days' prior
written notice to UPFUELS of UPR's intent to terminate this Agreement), (C) upon
occurrence of a Material UPFUELS Take Default, as provided in Section 4.2.5 or
(D) upon occurrence of a UPFUELS Credit Default under Section 8.8, if UPR had
previously given at least ten (10) Days' prior written notice to UPFUELS of
UPR's intent to terminate this Agreement.
(b) MITIGATION OF DAMAGES. An Unaffected Party shall use
commercially reasonable efforts to mitigate costs or losses as a result of a
Default, including, without limitation, exercising commercially reasonable
efforts to find alternative markets for Committed Gas or alternative supplies of
Gas, as applicable. Similarly, a Defaulting Party shall exercise commercially
reasonable efforts to minimize the harm suffered by an Unaffected Party in
consequence of such Default, including providing the Unaffected Party with
prompt notice of such Default so as to facilitate cover for Committed Gas not
delivered or the resale of Committed Gas not taken hereunder.
(c) REMEDIES CUMULATIVE. Unless explicitly indicated to the
contrary in this Agreement, the remedies contemplated in this Section 11.3
(including, without limitation, termination of this Agreement) are cumulative
of, and may be exercised without prejudice to, any other remedies, whether at
law or in equity to which an Unaffected Party may be entitled under this
Agreement for any Default.
11.4 SETOFF RIGHTS. Except as specifically set forth in Sections 8.1
and 14.8, all payments under this Agreement will be made without setoff or
counterclaim; provided, however, that upon a Defaulting Party's failure to make
payment of undisputed amounts on the due date, the Unaffected Party may, at its
option and in its discretion, setoff against any amounts owed to the Defaulting
Party under this Agreement or otherwise. The obligations of the Unaffected Party
to the Defaulting Party shall be deemed satisfied and discharged to the extent
of any such setoff. The Unaffected Party will give the Defaulting Party notice
of any setoff made under this Section 11.4 as soon as practicable after the
setoff is made, but failure to give such notice shall not affect the validity of
the setoff.
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XII. DISPUTE RESOLUTION PROCEDURES
12.1 GENERAL DISPUTE RESOLUTION PROVISIONS.
(a) EXECUTIVE MEDIATION. In the event of any dispute,
controversy or claim, whether based in contract, tort or otherwise, arising out
of or related to this Agreement or the scope, breach, termination, performance,
interpretation, construction, application, enforcement, or validity of this
Agreement (a "Dispute"), the Parties to this Agreement shall promptly seek to
resolve such Dispute by negotiations pursuant to this Section 12.1(a) between
senior executives of the Parties who have authority to settle the Dispute and
who have not been directly involved in the transactions giving rise to such
Dispute. When a Party believes there is a Dispute under this Agreement, that
Party will give the other Party written notice of the Dispute. Within thirty
(30) Days after receipt of such notice, the receiving Party shall submit to the
other a written response. Both the notice and response shall include (i) a
statement of the Party's position and a summary of the evidence and arguments
supporting its position, and (ii) the name, title, fax number and telephone
number of the executive who will represent that Party. If a Dispute involves a
claim arising out of the actions of any Person not a signatory to this
Agreement, the receiving Party shall have such additional time as necessary, not
to exceed an additional sixty (60) Days, to investigate the Dispute before
submitting a written response. The executives shall meet at a mutually
acceptable time and place not later than fifteen (15) Days after the date of the
response and thereafter as often as they reasonably deem necessary to exchange
relevant information and to attempt to resolve the Dispute. If one of the
executives proposes to be accompanied by an attorney at any meeting, the other
executive shall be given at least five (5) Business Days' notice of such
intention and may also be accompanied by an attorney. All negotiations and
communications pursuant to this Section 12.1(a) shall be treated and maintained
by the Parties as confidential information and shall be treated as compromise
and settlement negotiations for the purposes of the Federal Rules of Evidence
and state rules of evidence.
(b) INITIATION OF ARBITRATION. If the Dispute has not been
resolved within sixty (60) Days after the date of the response given pursuant to
Section 12.1(a) (or such additional time, if any, that the Parties mutually
agree in writing), or if the Party receiving a notice of Dispute denies the
applicability of the provisions of Section 12.1(a) or otherwise refuses to
participate under the provisions of Section 12.1(a), either Party may initiate
binding arbitration pursuant to the provisions of Section 12.1(c) below.
(c) ARBITRATION PROCEDURES. All Disputes not resolved by
agreement of the Parties shall be submitted to binding arbitration in accordance
with the following provisions of this paragraph. This arbitration agreement is
expressly made pursuant to and shall be governed by the Federal Arbitration Act,
9 U.S.C. section 1, et seq. (The "Arbitration Act"). It is further expressly
agreed that upon request of either Party a judgment shall be entered by any
court of competent jurisdiction upon any award made pursuant to an arbitration
hereunder. All Disputes shall be resolved by arbitration in accordance with the
American Arbitration Association's Commercial Arbitration Rules, as amended and
effective as of November 1, 1993 (the "Rules"), except as mutually agreed to the
contrary by the Parties, and except as specified below.
(i) EXPEDITED PROCEDURES. Regardless of the amount in
dispute, the Expedited Procedures of the Rules shall not be utilized
without the agreement of both Parties. However, the arbitrator shall
hear and determine preliminary motions with respect to any issues of
law asserted by a party to be dispositive of any claim, in whole or in
part, in the
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manner of a court hearing and acting upon a motion to dismiss for
failure to state a claim or for summary judgment.
(ii) LOCATION. In the absence of agreement by both
Parties to another locale, the arbitration shall be held in Fort Worth,
Texas. In no event will the American Arbitration Association or JAMS
Endispute, Inc. ("JAMS") have the power to decide the locale of the
arbitration.
(iii) SELECTION OF ARBITRATOR. Arbitration shall be
initiated by formal written notice from either Party to the other Party
describing in reasonable detail the Dispute and naming three persons
that the Party giving such notice (the "Initiating Party") will accept
as an arbitrator to resolve the matter. Within ten (10) Days of receipt
of said notice, the Party receiving the notice (the "Receiving Party")
shall either agree to one of the three proposed arbitrators, or the
Parties will confer and attempt to agree upon another person to
arbitrate the Dispute. If these steps do not result in the selection of
an arbitrator, then either the Initiating Party or the Receiving Party
may request that JAMS provide to both the Initiating Party and the
Receiving Party, in writing, a panel of seven names from JAMS' panel of
commercial arbitrators. All members of the panel submitted by JAMS
shall be United States nationals who are attorneys licensed to practice
in the highest court of one or more states of the United States of
America or the District of Columbia who have at least fifteen years of
experience as a practicing attorney primarily involving the oil and gas
industry or who are judges or former judges with at least fifteen years
experience as a judge, and JAMS shall be requested to cause the panel
to state the qualifications of each member of the panel satisfying
these requirements. Within five (5) Days of receipt of this panel, the
Initiating Party shall strike three names from the panel and forward it
to the Receiving Party. The Receiving Party shall then strike three
additional names from the panel and forward the remaining name to JAMS
(with a copy to the Initiating Party) within five (5) Days of receipt
of the stricken panel. The name forwarded to JAMS shall be the neutral
arbitrator appointed to hear the Dispute. Either the Initiating Party
or Receiving Party may object to an entire panel and request that JAMS
provide a new panel by giving written notice of the request and the
reason therefor to JAMS and the other party within three (3) Days after
receipt of such panel. Such notice may be given by telecopy, by
delivery in hand, or by depositing same in the United States Postal
Service, properly addressed and stamped, as certified mail, but only
one such request may be made regardless of which Party initiates the
request. In no event may JAMS appoint an arbitrator.
(iv) ARBITRATOR'S DECISION FINAL. The decision of the
arbitrator, which shall be rendered within thirty (30) Days after the
conclusion of the hearings conducted pursuant to this Section 12.1,
shall be final and binding on both Parties; provided that the
arbitrator shall not have the authority or power to award punitive or
exemplary damages, and each of the Parties expressly waives and
relinquishes any right to recover or receive punitive or exemplary
damages in connection with any Dispute. Any decision of the arbitrator,
whether preliminary or final, shall be in a writing signed by the
arbitrator and shall contain the findings of fact and conclusions of
law upon which the decision is based.
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<PAGE> 38
(v) SELECTION OF NEW ARBITRATOR. If for any reason,
the selected arbitrator is unable to perform his or her duties, JAMS
may, on proof satisfactory to it or based on the agreement of the
Initiating Party and Receiving Party, declare the position vacant. In
the event of such a vacancy, the provisions of Section 12.1(c)(iii)
shall be followed to select a new arbitrator.
(vi) HEARINGS. The arbitrator shall set the date and
time of each hearing hereunder. The first hearing shall take place
within twenty-five (25) Days following the arbitrator's appointment,
and the arbitration proceeding shall be concluded not later than ten
(10) Days after the date of the first hearing. JAMS shall give ten (10)
Days' notice to the Initiating Party and Receiving Party of the first
hearing unless otherwise agreed.
(vii) STENOGRAPHIC RECORD. Either the Initiating
Party or the Receiving Party may request a stenographic record be made
of all hearings hereunder. The cost of such stenographic record shall
be shared equally by the Initiating Party and the Receiving Party.
(viii) PRIVACY. The arbitrator will ensure the
privacy of the hearings hereunder to the maximum extent allowed by law.
Both the Initiating Party and the Receiving Party shall be entitled to
attend all hearings. At the request of either the Initiating Party or
the Receiving Party, all persons who are not executives of a Party
shall be excluded from the hearings, except for the attorneys for the
Initiating Party and Receiving Party, the stenographer (if any), and
persons who are witnesses when actually called to testify. Unless
otherwise agreed by the Parties, and except as reasonably required to
enforce or implement or exercise any right of appeal provided by law
from the decision of the arbitrator, the decision of the arbitrator and
the evidence and arguments presented to the arbitrator (to the extent
not otherwise generally known or regularly disseminated) shall be
maintained in confidence by the Parties.
(ix) FEES AND EXPENSES. The Initiating Party and
Receiving Party shall share equally the arbitrator's fees and expenses
and any charges of JAMS. Otherwise, except for the cost of the
stenographic record, each of the Initiating Party and the Receiving
Party shall bear their own costs.
(d) ALTERNATE SELECTOR OF PANEL. If JAMS ceases to function or is
otherwise unable or unavailable to provide a panel from which the Parties can
select an arbitrator pursuant to Section 12.1(c), the Parties will utilize the
Center for Public Resources (New York, New York) to obtain a panel for such
purpose; and in such circumstance all references to JAMS in Section 12.1(c)
shall be deemed to refer to the Center for Public Resources.
12.2 SPECIAL PROVISIONS APPLICABLE TO PRICE DISPUTES. The provisions of
this Section 12.2 shall apply to disputes relating to the determination of the
Contract Price, including, without limitation, issues relating to the choice of
an applicable Index, Index Price or the determination of Index Price Adjustments
(all such disputes being hereinafter called "Price Disputes").
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<PAGE> 39
The arbitrator shall be selected in accordance with Section 12.1. Each Party
shall submit its proposed outcome to the arbitrator within ten (10) Business
Days after the arbitrator's selection. Within forty-five (45) Days after his
selection and appointment, the arbitrator shall select and adopt either UPR's
proposal or UPFUELS' proposal, without modification or compromise. The
arbitrator shall make his decision as follows: (i) in any Price Dispute over an
Index, the arbitrator shall decide which of the proposed Indexes presented to
the arbitrator best represents the 30-Day spot market price for Gas of like
quantities and quality at the applicable Delivery Point(s), (ii) in any Price
Dispute over Index Price Adjustments, the arbitrator shall decide which proposed
Index Price Adjustment presented to the arbitrator best represents the
differentials reasonably necessary to adjust the Index Price for Gas to
accurately reflect the 30-Day spot market price for Gas of like quantities and
quality at the Delivery Point(s) in question, and (iii) in all other Price
Disputes, the arbitrator shall consider the terms and conditions of this
Agreement and the requirements of applicable Texas law, including, without
limitation, the Texas version of the Uniform Commercial Code in effect at the
period relevant to the Price Dispute under consideration. The applicable
Contract Price during the arbitration shall be the Contract Price being paid on
the day before the Price Effective Date. Upon the conclusion of the arbitration,
such Contract Price, if it has changed as a result of the arbitrator's decision,
shall be adjusted retroactive to the Price Effective Date. Unless explicitly
provided otherwise in this Section 12.2, the other provisions of this Article
XII shall be applicable to all Price Disputes.
12.3 SPECIAL PROVISIONS APPLICABLE TO DISPUTES FOR LESS THAN ONE
MILLION DOLLARS. The provisions of this Section 12.3 shall apply to disputes,
which are not Price Disputes, relating to matters with a value of less than one
million dollars ($1,000,000) (all such disputes being hereinafter called
"Special Disputes"). The arbitrator shall be selected, and fees and expenses
paid, in accordance with Section 12.1. Each Party shall submit its proposed
outcome to the arbitrator within ten (10) Business Days after the arbitrator's
selection. Within forty-five (45) Days after his selection and appointment, the
arbitrator shall select and adopt either UPR's proposal or UPFUELS' proposal,
without modification or compromise. The arbitrator shall consider the terms and
conditions of this Agreement and the requirements of applicable Texas law,
including, without limitation, the Texas version of the Uniform Commercial Code
in effect at the period relevant to the Special Dispute under consideration.
XIII. NON-ASSIGNABILITY AND TRANSFER OF INTEREST BY UPR;
CHANGES OF CONTROL
13.1 NON-ASSIGNABILITY. Except as provided in Section 13.2 below,
neither this Agreement nor any obligation of a Party under this Agreement are
assignable without the prior written consent of the other Party, which consent
may be withheld in its sole discretion for any reason, except to Affiliates, in
which case the assigning Party shall remain liable for its obligations
hereunder.
13.2 TRANSFER OF INTEREST. UPR shall have the right to convey interest
in oil and gas leases from which Committed Gas is being produced, together with
all associated real and personal property and fixtures (such interests being
herein referred to as the "UPR Interests") to a Person who is not an Affiliate
without the consent of UPFUELS. At UPR's option, the affected UPR Interests
shall
34
<PAGE> 40
either remain subject to this Agreement, and Gas produced from such UPR
Interests shall remain Committed Gas for all purposes under this Agreement, or
shall remain Committed Gas pursuant to a separate agreement executed by UPFUELS
and UPR's successor in interest and containing terms and conditions
substantially identical to this Agreement. If UPR elects to convey UPR Interests
subject to this Agreement, the documents evidencing the conveyance of such UPR
Interests shall specifically identify this Agreement and obligate UPR's
successor in interest to ratify and adopt this Agreement insofar as it applies
to the UPR Interests acquired by UPR's successor in interest. If UPR elects to
require its successor in interest to execute an agreement substantially
identical to this Agreement, such agreement shall be executed contemporaneously
with the documents evidencing the conveyance of such UPR Interests.
Notwithstanding the foregoing, UPR shall have the right to convey UPR Interests
to a Person who is not an Affiliate free and clear of this Agreement if such UPR
Interests, when combined with any other UPR Interests contemporaneously conveyed
to such Person, produced an average of 200 MMBtu per Day, or less, over the six
Month period ending ninety (90) Days prior to the effective date of the
conveyance of the relevant UPR Interests.
13.3 CHANGE OF CONTROL. A Party affected by a Change of Control shall
give the other Party written notice thereof not later than fifteen (15) Days
after the occurrence of such Change of Control. If a Change of Control occurs
with respect to either Party during the term of this Agreement, the other Party
shall have the right to terminate this Agreement by providing the Party affected
by such Change of Control with written notice as provided herein. Such other
Party shall provide the affected Party with written notice of termination of
this Agreement not later than thirty (30) Days after receipt of the affected
Party's notice hereunder, and termination of this Agreement pursuant to this
Section 13.3 shall be effective on the first Day of the Month following the
Month in which the Party affected by the Change of Control receives terminating
Party's notice; provided, however, that if the affected Party fails to timely
give written notice of the Change of Control, the other Party may give written
notice of termination of this Agreement at any time following its discovery or
knowledge of such Change of Control. "Change of Control" shall mean:
(a) with respect solely to, a Party or its Affiliates, any
person or "group" (as determined for purposes of Rule 13d-5 of the Securities
and Exchange Commission under the Securities Exchange Act of 1934 or under any
successor rule or regulation, being herein referred to as the "Regulation")
shall have acquired "beneficial ownership" (as determined for purposes of such
Regulation) of a Party's or its Affiliate's securities (i) representing 25% or
more of the combined voting power of such Party's or Party's Affiliates
then-outstanding securities or (ii) having voting power sufficient to elect a
majority of the board of directors or other similar governing body of such Party
or its Affiliates;
(b) any statutory merger, consolidation or exchange of such
Party's, or its Affiliate's shares or interests (other than a merger,
consolidation or share exchange with an Affiliate of such Party) in which either
(i) such Party, or its Affiliates, will not be the surviving Person; or (ii)
such Party, or its Affiliates will be the surviving Person and any outstanding
shares of its common stock or member interests, as the case may be, will be
converted into shares, member interests or other ownership interests of any
other Person (other than an Affiliate of such Party); or
35
<PAGE> 41
(c) a Party's shareholders, or a Party's Affiliate (i) approve
any plan or proposal for the disposition or other transfer of all or
substantially all the assets of such Party, whether by means of a merger,
reorganization, liquidation or dissolution or otherwise; or (ii) with respect
solely to UPR, UPFUELS, or Affiliates of either UPR or UPFUELS, dispose of, or
become obligated to dispose of, 25% or more of the outstanding capital stock or
interests of such Party or Party's Affiliate by tender offer or otherwise.
(d) Notwithstanding the foregoing Sections 13.3(a), (b), or
(c), no Change of Control shall be deemed to have occurred with respect to
UPFUELS as long as UPFUELS' ultimate parent, Duke Energy Corporation ("Duke")
has directly or indirectly, control, and more than fifty percent (50%) of the
combined voting power of UPFUELS or voting power sufficient to elect a majority
of the governing body of UPFUELS, and Duke or Mobil Oil Corporation,
individually or in any combination, have, directly or indirectly, control, and
more than fifty percent (50%) of the combined voting power of member interests
of UPFUELS' affiliate, Duke Energy Trading and Marketing, L.L.C. ("DETM") or
voting power sufficient to elect a majority of the management committee or other
governing body of DETM.
(e) It is specifically understood and agreed that a Party may
not avoid the application of this Section 13.3 directly, or by any indirect
means, whether by use of one or more Affiliates, agents or designees, by
contract or otherwise.
XIV. MISCELLANEOUS
14.1 NO CONTINUING WAIVER. The waiver by either Party of any breach of
any of the provisions of this Agreement shall not constitute a continuing waiver
of other breaches of the same or other provisions of this Agreement.
14.2 GOVERNMENT REGULATION. This Agreement is subject to all present
and future valid and applicable laws, orders, rules and regulations of any
regulatory body of the federal government or any state, county or local
governmental body having jurisdiction.
14.3 EXCLUSION OF CONSEQUENTIAL DAMAGES. IN NO EVENT SHALL EITHER PARTY
BE LIABLE TO THE OTHER FOR ANY PUNITIVE, SPECIAL, CONSEQUENTIAL, OR INDIRECT
DAMAGES, INCLUDING, WITHOUT LIMITATION, DAMAGES FOR LOST PROFITS.
14.4 NOTICES. Unless otherwise explicitly provided herein, all notices
provided for in this Agreement shall be in writing and shall be (i) delivered in
person or by messenger, (ii) mailed by Federal Express or similar private
courier service, (iii) sent by United States certified mail (return receipt
requested), postage prepaid, (iv) by facsimile, telex or telecopier, or (v) by
any other commercially reasonable means, to the addresses of the Parties set
forth below or to such other addresses as either Party may designate in writing
to the other Party. All notices given hereunder shall be effective on the date
of actual receipt at the appropriate address. Notice given pursuant to clause
(iv) shall be effective (A) upon actual receipt if received during recipient's
normal business
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<PAGE> 42
hours, or (B) at the beginning of the next Business Day after receipt if
received after the recipient's normal business hours.
UPR: NOTICES AND CORRESPONDENCE:
Union Pacific Resources Company
P. O. Box 7, MS 4100
Fort Worth, Texas 76101-0007
Attention: _________________
Telephone: (817) 877-7543
Fax: (817) 877-7522
INVOICES AND STATEMENTS:
Union Pacific Resources Company
P. O. Box ________
Fort Worth, Texas 76____
Attention: _____________
Telephone: (817) ___-_____
Fax: (817) ___-____
UPR AUTHORIZED TRADERS:
[names, addresses, telephone and fax numbers;
consider including E-Mail]
UPFUELS: NOTICES AND CORRESPONDENCE:
UPFUELS
P. O. Box 901027
Fort Worth, Texas 76101
Attention: Marketing Department
Telephone: (817) 255-6000
Fax: (___) ___-_____
INVOICES AND STATEMENTS:
UPFUELS
P. O. Box 901027
Fort Worth, Texas 76101
Attention: Marketing Department
Telephone: (817) 255-6000
Fax: (___) ___-_____
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<PAGE> 43
UPFUELS AUTHORIZED TRADERS:
[names, addresses, telephone and fax numbers;
consider including E-Mail]
14.5 CHOICE OF LAW. THIS AGREEMENT SHALL BE GOVERNED BY AND CONSTRUED
IN ACCORDANCE WITH THE LAWS OF THE STATE OF TEXAS, WITHOUT REGARD TO CONFLICTS
OF LAWS PRINCIPLES THAT WOULD REQUIRE THE APPLICATION OF THE LAWS OF ANOTHER
JURISDICTION. THE VENUE OF ANY PROCEEDING TO COMPEL ARBITRATION SHALL BE IN THE
UNITED STATES FEDERAL COURT FOR THE NORTHERN DISTRICT OF TEXAS - FORT WORTH
DIVISION.
14.6 INTEGRATION. This Agreement sets forth all understandings of
UPFUELS and UPR with respect to the purchase and sale of Committed Gas. All
other agreements, oral or written, concerning such purchase and sale are merged
into and superseded by this Agreement. No waiver of rights hereunder, or
modification or amendment hereof shall be effective unless in writing and signed
by both Parties.
14.7 CONFIDENTIALITY.
(a) PARTIES' OBLIGATIONS. The terms of this Agreement,
including, but not limited to, the Contract Price and information exchanged or
disclosed by the Parties pursuant to the dispute resolution procedures of
Article XII and all other information exchanged by the Parties hereunder, will
be kept confidential by the Parties unless (i) such information becomes known to
the public at large without breach of this Agreement, (ii) a Party is obligated
to disclose such information to a Transporter or other third Person for the
purpose of effectuating the sale and transportation of Gas pursuant to this
Agreement, (iii) a Party is obligated to disclose such information to meet
applicable securities or commodity exchange requirements, (iv) a Party is
obligated to disclose such information to meet regulatory filing requirements,
(v) a Party is obligated to disclose such information to comply with mandatory
document production requirements under federal or state Rules of Civil
Procedure, a subpoena or other order of judicial or administrative tribunal,
(vi) as agreed in writing by the non-disclosing Party, or (vii) a Party is
obligated to disclose such information to comply with a request made by a Lender
or an investment bank underwriting an offering of securities by a Party.
(b) HANDLING OF REQUEST FOR DISCLOSURE. If either Party
believes that it may be required to disclose information concerning this
Agreement that is to be kept confidential pursuant to Section 14.7(a) (iii) -
(vi), the disclosing Party will notify the other Party in writing as soon as
practicable in advance of disclosure, specifying the nature of the request and
the information to be disclosed. To the extent permitted under statutes, rules,
regulations or contractual provisions applicable to the disclosure request, the
Party required to make disclosure will assert any available privilege permitting
non-disclosure of the information that is to be kept confidential hereunder, or
request confidential treatment of the disclosed information, including exemption
from public disclosure under applicable "open records" and "freedom of
information" statutes. The Party disclosing information required to be kept
confidential under Section 14.7 shall use commercially
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<PAGE> 44
reasonable efforts to obtain from the Person to whom disclosure of such
information is made an agreement, to be signed by such Person and any employee,
agent, officer, director or independent contractor of such Person to whom
disclosure shall be made, such agreement to have terms and conditions
substantially the same as those set forth in this Section 14.7.
(c) RESPONSIBILITY FOR CONFIDENTIALITY. Each Party will be
deemed solely responsible and liable for the actions of its employees,
independent contractors, officers, and agents for maintaining the
confidentiality commitments of this Article, but will be required in that regard
only to exercise such care in maintaining the confidentiality of this Agreement
as it normally exercises in preserving the confidentiality of its other
commercially sensitive documents.
14.8 TAXES.
(a) UPR RESPONSIBILITY. The Contract Price to be paid by
UPFUELS to UPR for Committed Gas purchased and sold hereunder is inclusive of
the reimbursement of one hundred percent (100%) of all state severance Tax
reimbursement, as well as all other production, severance, ad valorem, and/or
similar Taxes levied on or applicable to the Committed Gas at or prior to the
Delivery Point(s). UPR shall be liable for all Taxes applicable to the Committed
Gas upstream of the Delivery Point(s), and shall pay, cause to be paid, or
reimburse UPFUELS if UPFUELS has paid, such Taxes. If UPFUELS is required to pay
such Taxes, UPFUELS shall describe such Taxes in reasonable detail on the
statement provided to UPR pursuant to Section 8.1, and shall be entitled to
deduct the amount of such Taxes from amounts paid to UPR thereunder. UPR shall
indemnify, defend and hold harmless UPFUELS from all claims, damages, demands
and other costs or losses in respect of Taxes for which UPR is liable. If
UPFUELS is required by law to collect any such Taxes and UPR claims an exemption
from such Taxes, UPR shall, upon UPFUELS' request, furnish UPFUELS with a copy
of UPR's exemption certificate, or other reasonably satisfactory evidence of
UPR's exemption.
(b) UPFUELS RESPONSIBILITY. The Contract Price does not
include Taxes applicable to the Committed Gas at and after delivery of the
Committed Gas at the Delivery Point(s). UPFUELS shall be liable for all Taxes
applicable to the Committed Gas at and downstream of the Delivery Point(s), and
shall pay, cause to be paid, or reimburse UPR if UPR has paid, such Taxes. If
UPR is required to pay such Taxes, UPR shall provide UPFUELS with an invoice
describing such Taxes in reasonable detail, and shall be reimbursed therefor
within ten (10) Business Days of the date of such invoice, or may deduct the
amount of such Taxes from amounts payable to UPFUELS under this Agreement.
UPFUELS shall indemnify, defend and hold harmless UPR from all claims, damages,
demands and other costs or losses in respect of Taxes for which UPFUELS is
liable. If UPR is required by law to collect any such Taxes and UPFUELS claims
an exemption from such Taxes, UPFUELS shall, upon UPR's request, furnish UPR
with a copy of UPFUELS' exemption certificate, or other reasonably satisfactory
evidence of UPFUELS' exemption.
14.9 CONSTRUCTION OF AGREEMENT.
(a) GENERAL PRINCIPLES. In construing this Agreement, the
following principles shall be followed:
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<PAGE> 45
(1) no consideration shall be given to the fact or
presumption that one Party had a greater or lesser hand in drafting this
Agreement;
(2) examples shall not be construed to limit,
expressly or by implication, the matter they illustrate;
(3) the words "includes," "including" and their
respective syntactical variants mean "includes, but is not limited to" and
corresponding syntactical variant expressions;
(4) the plural shall be deemed to include the
singular and vice versa, as applicable;
(5) the term "Party" shall refer to all Affiliates of
such Party unless the context specifically indicates to the contrary; and
(6) each exhibit, attachment, and schedule to this
Agreement is a part of this Agreement, but if there is any conflict or
inconsistency between the main body of this Agreement and any exhibit,
attachment, or schedule, the provisions of the main body of this Agreement shall
prevail.
(b) SEVERABILITY. If any provision of this Agreement is held
to be illegal, invalid, or unenforceable under the present or future laws
effective during the term of this Agreement, (i) such provision will be fully
severable, (ii) this Agreement will be construed and enforced as if such
illegal, invalid, or unenforceable provision had never comprised a part of this
Agreement, and (iii) the remaining provisions of this Agreement will remain in
full force and effect and will not be affected by the illegal, invalid, or
unenforceable provision or by its severance from this Agreement. Furthermore, in
lieu of such illegal, invalid, or unenforceable provision, there will be added
automatically as a part of this Agreement a provision agreeable to both Parties
which is as similar in terms to such illegal, invalid, or unenforceable
provision as may be possible and may be legal, valid and enforceable.
(c) RELATIONSHIP OF PARTIES. This Agreement does not create a
partnership, joint venture, or relationship of trust or agency between the
Parties.
14.10 REPRESENTATIONS AND WARRANTIES OF UPR. UPR hereby represents and
warrants to UPFUELS that on and as of the date hereof:
(a) It is duly formed and validly existing and, to the extent
it is a corporation, in good standing under the laws of the state or
jurisdiction of formation, with all requisite corporate power and authority to
carry on the business in which it is engaged and to perform its obligations
under this Agreement;
(b) The execution and delivery of this Agreement have been
duly authorized and approved by all requisite corporate action;
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<PAGE> 46
(c) It has all the requisite corporate power and authority to
enter into this Agreement and perform its obligations hereunder;
(d) The execution and delivery of this Agreement do not, and
consummation of the transactions contemplated herein will not, violate (i) any
of the material provisions of its articles of incorporation, bylaws or other
organizational documents, (ii) any material agreement pursuant to which it or
its properties are bound or (iii) to its knowledge, any material applicable
laws; and
(e) This Agreement is valid, binding, and enforceable against
it in accordance with its terms, subject to bankruptcy, moratorium, insolvency
and other laws generally affecting creditor's rights and general principles of
equity (whether applied in a proceeding in a court of law or equity).
14.11 REPRESENTATIONS AND WARRANTIES OF UPFUELS. UPFUELS hereby
represents and warrants to UPR that on and as of the date hereof:
(a) It is duly formed and validly existing and in good
standing under the laws of the state or jurisdiction of formation, with all
requisite corporate power and authority to carry on the business in which it is
engaged and to perform its obligations under this Agreement;
(b) The execution and delivery of this Agreement have been
duly authorized and approved by all requisite corporate action;
(c) It has all the requisite corporate power and authority to
enter into this Agreement and perform its obligations hereunder;
(d) The execution and delivery of this Agreement do not, and
consummation of the transactions contemplated herein will not, breach or violate
(i) any of the material provisions of its articles of incorporation, bylaws or
other organizational documents, (ii) any material agreement pursuant to which it
or its properties are bound or (iii) to its knowledge, any material applicable
laws; and
(e) This Agreement is valid, binding, and enforceable against
it in accordance with its terms, subject to bankruptcy, moratorium, insolvency
and other laws generally affecting creditor's rights and general principles of
equity (whether applied in a proceeding in a court of law or equity).
14.12 NO THIRD PARTY BENEFICIARIES. Any agreement herein contained,
express or implied, shall be only for the benefit of the Parties and their
respective successors and permitted assigns, and such agreements or assumptions
shall not inure to the benefit of any other Person whatsoever, it being the
intention of the Parties that no Person shall be deemed a third-party
beneficiary of this Agreement.
14.13 FURTHER ASSURANCES. Each Party shall take such acts and execute
and deliver such documents in form and substance reasonably satisfactory to each
of them, in order to effectuate the purposes of this Agreement.
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14.14 EXHIBITS. The Parties expect that the Exhibits to this Agreement
will be agreed upon and completed prior to the Effective Date and the Parties
agree that the absence of a completed Exhibit at the time this Agreement is
executed by the Parties shall not affect the enforceability of this Agreement at
any time. In the event an Exhibit is not completed at the time this Agreement is
executed, a pro forma Exhibit shall be attached setting forth the form and
content of the Exhibit to be completed.
IN WITNESS WHEREOF, this Agreement is executed on the 20th day of
November, 1998, but effective as of the Effective Date.
UNION PACIFIC RESOURCES COMPANY UNION PACIFIC FUELS, INC.
By: By:
---------------------------- ---------------------------
Name: V. Richard Eales Name: D.W. Niemic
-------------------------- -------------------------
Title: Executive Vice President Title: President
------------------------- ------------------------
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<PAGE> 1
EXHIBIT 12
UNION PACIFIC RESOURCES GROUP INC.
COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES
(AMOUNTS IN MILLIONS, EXCEPT RATIOS)
(UNAUDITED)
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
--------------------------------------------------------------
1999 1998 1997 1996 1995
<S> <C> <C> <C> <C> <C>
Earnings from continuing operations before income taxes .... $ (51.2) $ (1,488.3) $ 418.9 $ 366.1 $ 368.3
Add (deduct) distributions greater (to extent less) than
income of unconsolidated affiliates ................. 0.9 (5.8) (3.8) (4.2) 2.3
Fixed charges from below ................................... 226.1 262.3 49.0 45.9 17.8
Capitalized interest included in fixed charges ............. (0.4) (0.9) (2.0) -- (0.8)
-------- ---------- -------- -------- --------
Earnings available for fixed charges................ $ 175.4 $ (1,232.7) $ 462.1 $ 407.8 $ 387.6
======== ========== ======== ======== ========
Fixed charges:
Interest expense .................................... $ 218.7 $ 249.8 $ 39.5 $ 38.9 $ 9.5
Portion of rentals representing an interest factor... 7.0 11.6 7.5 7.0 7.5
Interest capitalized ................................ 0.4 0.9 2.0 -- 0.8
-------- ---------- -------- -------- --------
Total fixed charges ........................ $ 226.1 $ 262.3 $ 49.0 $ 45.9 $ 17.8
======== ========== ======== ======== ========
Ratio of earnings to fixed charges ......................... 0.8 (4.7) 9.4 8.9 21.8
======== ========== ======== ======== ========
</TABLE>
For the year ended December 31, 1999, earnings are insufficient by $50.7
million in order to cover fixed charges.
For the year ended December 31, 1998, earnings are insufficient by $1,495
million in order to cover fixed charges.
<PAGE> 1
EXHIBIT 21
LIST OF SUBSIDIARIES
UNION PACIFIC RESOURCES GROUP INC.
Union Pacific Resources Company
Union Pacific International Petroleum Company
Basic Resources International (Bahamas) Limited
Union Pacific Resources (Bahamas) Limited
Union Pacific Resources Argentina S.A.
Union Pacific Resources Venezuela, S.A.
UP Petroleo III Ltd.
Union Pacific Oil and Gas Holding Company
Union Pacific Refining, Inc.
Union Pacific Resources Inc.
Union Pacific Resources Pipeline Company
Golden Spike Gathering, Inc.
Union Pacific Crude Pipeline, Inc.
UPR Energy Marketing, Inc.
UPR Energy Services Inc.
UPR Operating Company
Big Island Trona Company
Bitter Creek Coal Company
Hanna Basin Coal Company
Rock Springs Royalty Company
Union Pacific Realty Company
Upland Industries Corporation
Union Pacific Land Resources Corporation
<PAGE> 1
EXHIBIT 23.1
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the incorporation by
reference in Registration Statements No. 333-62181 of Union Pacific Resources
Group Inc. on Form S-3 and No. 333-22613 and No. 333-35641 of Union Pacific
Resources Group Inc. on Form S-8, of our report dated March 3, 2000 included in
this Annual Report on Form 10-K of Union Pacific Resources Group Inc. for the
year ended December 31, 1999.
ARTHUR ANDERSEN LLP
Fort Worth, Texas
March 23, 2000
<PAGE> 1
EXHIBIT 23.2
INDEPENDENT AUDITOR'S CONSENT
We consent to the incorporation by reference in Registration Statements No.
333-62181 of Union Pacific Resources Group Inc. on Form S-3 and Nos. 333-22613
and 333-35641 of Union Pacific Resources Group Inc. on Form S-8, of our report
dated January 26, 1998 appearing in this Annual Report on Form 10-K of Union
Pacific Resources Group Inc. for the year ended December 31, 1999.
DELOITTE & TOUCHE, LLP
Fort Worth, Texas
March 23, 2000
<PAGE> 1
EXHIBIT 23.3
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the incorporation by
reference in Registration Statements No. 333-62181 of Union Pacific Resources
Group Inc. on Form S-3 and No. 333-22613 and No. 333-35641 of Union Pacific
Resources Group, Inc. on Form S-8, of our report dated February 2, 2000 on the
combined financial statements of Black Butte Coal Company, A Joint Venture, and
R-K Leasing Company as of December 31, 1999 and December 26, 1998 and for the
fiscal years then ended, included in this Annual Report on Form 10-K of Union
Pacific Resources Group, Inc.
/s/ ARTHUR ANDERSEN LLP
Denver, Colorado
March 23, 2000
<PAGE> 1
EXHIBIT 24
POWER OF ATTORNEY
UNION PACIFIC RESOURCES GROUP INC.
KNOW ALL MEN BY THESE PRESENTS, that H. JESSE ARNELLE, a Director of Union
Pacific Resources Group Inc., a Utah Corporation (the "Corporation"), hereby
appoints GEORGE LINDAHL, III, JOSEPH A. LASALA, JR., and KATHY L. COX, and each
of them acting individually, his true and lawful attorney, each with power to
act without the other and full power of substitution, to execute, deliver and
file, for and on his behalf, and in his name and in his capacity as Director, an
Annual Report on Form 10-K for the year ended December 31, 1999 (or other
appropriate form) for filing with the Securities and Exchange Commission and any
other documents in support thereof or supplemental or amendatory thereto, hereby
granting to such attorneys and each of them full power and authority to do and
perform each and every act and thing whatsoever as such attorney or attorneys
may deem necessary or advisable to carry out fully the intent of the foregoing
as the undersigned might or could do personally or in his capacity as Director,
hereby ratifying and confirming all acts and things which such attorney or
attorneys may do or cause to be done by virtue of this power of attorney.
IN WITNESS WHEREOF, the undersigned has executed this power of attorney as
of this 20th day of January, 2000.
/s/ H. Jesse Arnelle
---------------------
H. JESSE ARNELLE
<PAGE> 2
POWER OF ATTORNEY
UNION PACIFIC RESOURCES GROUP INC.
KNOW ALL MEN BY THESE PRESENTS, that LYNNE V. CHENEY, a Director of Union
Pacific Resources Group Inc., a Utah Corporation (the "Corporation"), hereby
appoints GEORGE LINDAHL, III, JOSEPH A. LASALA, JR., and KATHY L. COX, and each
of them acting individually, his true and lawful attorney, each with power to
act without the other and full power of substitution, to execute, deliver and
file, for and on his behalf, and in his name and in his capacity as Director, an
Annual Report on Form 10-K for the year ended December 31, 1999 (or other
appropriate form) for filing with the Securities and Exchange Commission and any
other documents in support thereof or supplemental or amendatory thereto, hereby
granting to such attorneys and each of them full power and authority to do and
perform each and every act and thing whatsoever as such attorney or attorneys
may deem necessary or advisable to carry out fully the intent of the foregoing
as the undersigned might or could do personally or in his capacity as Director,
hereby ratifying and confirming all acts and things which such attorney or
attorneys may do or cause to be done by virtue of this power of attorney.
IN WITNESS WHEREOF, the undersigned has executed this power of attorney as
of this 20th day of January, 2000.
/s/ Lynne V. Cheney
--------------------
LYNNE V. CHENEY
<PAGE> 3
POWER OF ATTORNEY
UNION PACIFIC RESOURCES GROUP INC.
KNOW ALL MEN BY THESE PRESENTS, that PRESTON M. GEREN III, a Director of
Union Pacific Resources Group Inc., a Utah Corporation (the "Corporation"),
hereby appoints GEORGE LINDAHL, III, JOSEPH A. LASALA, JR., and KATHY L. COX,
and each of them acting individually, his true and lawful attorney, each with
power to act without the other and full power of substitution, to execute,
deliver and file, for and on his behalf, and in his name and in his capacity as
Director, an Annual Report on Form 10-K for the year ended December 31, 1999 (or
other appropriate form) for filing with the Securities and Exchange Commission
and any other documents in support thereof or supplemental or amendatory
thereto, hereby granting to such attorneys and each of them full power and
authority to do and perform each and every act and thing whatsoever as such
attorney or attorneys may deem necessary or advisable to carry out fully the
intent of the foregoing as the undersigned might or could do personally or in
his capacity as Director, hereby ratifying and confirming all acts and things
which such attorney or attorneys may do or cause to be done by virtue of this
power of attorney.
IN WITNESS WHEREOF, the undersigned has executed this power of attorney as
of this 20th day of January, 2000.
/s/ Preston M. Geren III
-------------------------
PRESTON M. GEREN III
<PAGE> 4
POWER OF ATTORNEY
UNION PACIFIC RESOURCES GROUP INC.
KNOW ALL MEN BY THESE PRESENTS, that LAWRENCE M. JONES, a Director of Union
Pacific Resources Group Inc., a Utah Corporation (the "Corporation"), hereby
appoints GEORGE LINDAHL, III, JOSEPH A. LASALA, JR., and KATHY L. COX, and each
of them acting individually, his true and lawful attorney, each with power to
act without the other and full power of substitution, to execute, deliver and
file, for and on his behalf, and in his name and in his capacity as Director, an
Annual Report on Form 10-K for the year ended December 31, 1999 (or other
appropriate form) for filing with the Securities and Exchange Commission and any
other documents in support thereof or supplemental or amendatory thereto, hereby
granting to such attorneys and each of them full power and authority to do and
perform each and every act and thing whatsoever as such attorney or attorneys
may deem necessary or advisable to carry out fully the intent of the foregoing
as the undersigned might or could do personally or in his capacity as Director,
hereby ratifying and confirming all acts and things which such attorney or
attorneys may do or cause to be done by virtue of this power of attorney.
IN WITNESS WHEREOF, the undersigned has executed this power of attorney as
of this 20th day of January, 2000.
/s/ Lawrence M. Jones
----------------------
LAWRENCE M. JONES
<PAGE> 5
POWER OF ATTORNEY
UNION PACIFIC RESOURCES GROUP INC.
KNOW ALL MEN BY THESE PRESENTS, that DREW LEWIS, a Director of Union
Pacific Resources Group Inc., a Utah Corporation (the "Corporation"), hereby
appoints GEORGE LINDAHL, III, JOSEPH A. LASALA, JR., and KATHY L. COX, and each
of them acting individually, his true and lawful attorney, each with power to
act without the other and full power of substitution, to execute, deliver and
file, for and on his behalf, and in his name and in his capacity as Director, an
Annual Report on Form 10-K for the year ended December 31, 1999 (or other
appropriate form) for filing with the Securities and Exchange Commission and any
other documents in support thereof or supplemental or amendatory thereto, hereby
granting to such attorneys and each of them full power and authority to do and
perform each and every act and thing whatsoever as such attorney or attorneys
may deem necessary or advisable to carry out fully the intent of the foregoing
as the undersigned might or could do personally or in his capacity as Director,
hereby ratifying and confirming all acts and things which such attorney or
attorneys may do or cause to be done by virtue of this power of attorney.
IN WITNESS WHEREOF, the undersigned has executed this power of attorney as
of this 20th day of January, 2000.
/s/ Drew Lewis
---------------
DREW LEWIS
<PAGE> 6
POWER OF ATTORNEY
UNION PACIFIC RESOURCES GROUP INC.
KNOW ALL MEN BY THESE PRESENTS, that CLAUDINE B. MALONE, a Director of
Union Pacific Resources Group Inc., a Utah Corporation (the "Corporation"),
hereby appoints GEORGE LINDAHL, III, JOSEPH A. LASALA, JR., and KATHY L. COX,
and each of them acting individually, his true and lawful attorney, each with
power to act without the other and full power of substitution, to execute,
deliver and file, for and on his behalf, and in his name and in his capacity as
Director, an Annual Report on Form 10-K for the year ended December 31, 1999 (or
other appropriate form) for filing with the Securities and Exchange Commission
and any other documents in support thereof or supplemental or amendatory
thereto, hereby granting to such attorneys and each of them full power and
authority to do and perform each and every act and thing whatsoever as such
attorney or attorneys may deem necessary or advisable to carry out fully the
intent of the foregoing as the undersigned might or could do personally or in
his capacity as Director, hereby ratifying and confirming all acts and things
which such attorney or attorneys may do or cause to be done by virtue of this
power of attorney.
IN WITNESS WHEREOF, the undersigned has executed this power of attorney as
of this 20th day of January, 2000.
/s/ Claudine B. Malone
-----------------------
CLAUDINE B. MALONE
<PAGE> 7
POWER OF ATTORNEY
UNION PACIFIC RESOURCES GROUP INC.
KNOW ALL MEN BY THESE PRESENTS, that JOHN W. PODUSKA, SR., PH.D., a
Director of Union Pacific Resources Group Inc., a Utah Corporation (the
"Corporation"), hereby appoints GEORGE LINDAHL, III, JOSEPH A. LASALA, JR., and
KATHY L. COX, and each of them acting individually, his true and lawful
attorney, each with power to act without the other and full power of
substitution, to execute, deliver and file, for and on his behalf, and in his
name and in his capacity as Director, an Annual Report on Form 10-K for the year
ended December 31, 1999 (or other appropriate form) for filing with the
Securities and Exchange Commission and any other documents in support thereof or
supplemental or amendatory thereto, hereby granting to such attorneys and each
of them full power and authority to do and perform each and every act and thing
whatsoever as such attorney or attorneys may deem necessary or advisable to
carry out fully the intent of the foregoing as the undersigned might or could do
personally or in his capacity as Director, hereby ratifying and confirming all
acts and things which such attorney or attorneys may do or cause to be done by
virtue of this power of attorney.
IN WITNESS WHEREOF, the undersigned has executed this power of attorney as
of this 20th day of January, 2000.
/s/ John W. Poduska, Sr., Ph.D.
--------------------------------
JOHN W. PODUSKA, SR., PH.D.
<PAGE> 8
POWER OF ATTORNEY
UNION PACIFIC RESOURCES GROUP INC.
KNOW ALL MEN BY THESE PRESENTS, that MICHAEL E. ROSSI, a Director of Union
Pacific Resources Group Inc., a Utah Corporation (the "Corporation"), hereby
appoints GEORGE LINDAHL, III, JOSEPH A. LASALA, JR., and KATHY L. COX, and each
of them acting individually, his true and lawful attorney, each with power to
act without the other and full power of substitution, to execute, deliver and
file, for and on his behalf, and in his name and in his capacity as Director, an
Annual Report on Form 10-K for the year ended December 31, 1999 (or other
appropriate form) for filing with the Securities and Exchange Commission and any
other documents in support thereof or supplemental or amendatory thereto, hereby
granting to such attorneys and each of them full power and authority to do and
perform each and every act and thing whatsoever as such attorney or attorneys
may deem necessary or advisable to carry out fully the intent of the foregoing
as the undersigned might or could do personally or in his capacity as Director,
hereby ratifying and confirming all acts and things which such attorney or
attorneys may do or cause to be done by virtue of this power of attorney.
IN WITNESS WHEREOF, the undersigned has executed this power of attorney as
of this 20th day of January, 2000.
/s/ Michael E. Rossi
---------------------
MICHAEL E. ROSSI
<PAGE> 9
POWER OF ATTORNEY
UNION PACIFIC RESOURCES GROUP INC.
KNOW ALL MEN BY THESE PRESENTS, that SAMUEL K. SKINNER, a Director of Union
Pacific Resources Group Inc., a Utah Corporation (the "Corporation"), hereby
appoints GEORGE LINDAHL, III, JOSEPH A. LASALA, JR., and KATHY L. COX, and each
of them acting individually, his true and lawful attorney, each with power to
act without the other and full power of substitution, to execute, deliver and
file, for and on his behalf, and in his name and in his capacity as Director, an
Annual Report on Form 10-K for the year ended December 31, 1999 (or other
appropriate form) for filing with the Securities and Exchange Commission and any
other documents in support thereof or supplemental or amendatory thereto, hereby
granting to such attorneys and each of them full power and authority to do and
perform each and every act and thing whatsoever as such attorney or attorneys
may deem necessary or advisable to carry out fully the intent of the foregoing
as the undersigned might or could do personally or in his capacity as Director,
hereby ratifying and confirming all acts and things which such attorney or
attorneys may do or cause to be done by virtue of this power of attorney.
IN WITNESS WHEREOF, the undersigned has executed this power of attorney as
of this 20th day of January, 2000.
/s/ Samuel K. Skinner
----------------------
SAMUEL K. SKINNER
<PAGE> 10
POWER OF ATTORNEY
UNION PACIFIC RESOURCES GROUP INC.
KNOW ALL MEN BY THESE PRESENTS, that JAMES R. THOMPSON, a Director of Union
Pacific Resources Group Inc., a Utah Corporation (the "Corporation"), hereby
appoints GEORGE LINDAHL, III, JOSEPH A. LASALA, JR., and KATHY L. COX, and each
of them acting individually, his true and lawful attorney, each with power to
act without the other and full power of substitution, to execute, deliver and
file, for and on his behalf, and in his name and in his capacity as Director, an
Annual Report on Form 10-K for the year ended December 31, 1999 (or other
appropriate form) for filing with the Securities and Exchange Commission and any
other documents in support thereof or supplemental or amendatory thereto, hereby
granting to such attorneys and each of them full power and authority to do and
perform each and every act and thing whatsoever as such attorney or attorneys
may deem necessary or advisable to carry out fully the intent of the foregoing
as the undersigned might or could do personally or in his capacity as Director,
hereby ratifying and confirming all acts and things which such attorney or
attorneys may do or cause to be done by virtue of this power of attorney.
IN WITNESS WHEREOF, the undersigned has executed this power of attorney as
of this 20th day of January, 2000.
/s/ James R. Thompson
----------------------
JAMES R. THOMPSON
<PAGE> 11
POWER OF ATTORNEY
UNION PACIFIC RESOURCES GROUP INC.
KNOW ALL MEN BY THESE PRESENTS, that JAMES R. THOMPSON, a Director of Union
Pacific Resources Group Inc., a Utah Corporation (the "Corporation"), hereby
appoints GEORGE LINDAHL, III, JOSEPH A. LASALA, JR., and KATHY L. COX, and each
of them acting individually, his true and lawful attorney, each with power to
act without the other and full power of substitution, to execute, deliver and
file, for and on his behalf, and in his name and in his capacity as Director, an
Annual Report on Form 10-K for the year ended December 31, 1999 (or other
appropriate form) for filing with the Securities and Exchange Commission and any
other documents in support thereof or supplemental or amendatory thereto, hereby
granting to such attorneys and each of them full power and authority to do and
perform each and every act and thing whatsoever as such attorney or attorneys
may deem necessary or advisable to carry out fully the intent of the foregoing
as the undersigned might or could do personally or in his capacity as Director,
hereby ratifying and confirming all acts and things which such attorney or
attorneys may do or cause to be done by virtue of this power of attorney.
IN WITNESS WHEREOF, the undersigned has executed this power of attorney as
of this 20th day of January, 2000.
/s/ Jeff Sandefer
------------------
JEFF SANDEFER
<TABLE> <S> <C>
<ARTICLE> 5
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM THE UNION
PACIFIC RESOURCES GROUP INC. CONSOLIDATED STATEMENT OF FINANCIAL POSITION AT THE
END OF DECEMBER 31, 1999 THE RELATED CONSOLIDATED STATEMENT OF INCOME FOR YEAR
ENDED DECEMBER 31, 1999 AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH
FINANCIAL STATEMENTS.
</LEGEND>
<MULTIPLIER> 1,000,000
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> DEC-31-1999
<PERIOD-START> JAN-01-1999
<PERIOD-END> DEC-31-1999
<CASH> 124
<SECURITIES> 0
<RECEIVABLES> 313
<ALLOWANCES> 9
<INVENTORY> 55
<CURRENT-ASSETS> 496
<PP&E> 11,007
<DEPRECIATION> 5,536
<TOTAL-ASSETS> 6,147
<CURRENT-LIABILITIES> 542
<BONDS> 2,797
0
0
<COMMON> 0
<OTHER-SE> 938
<TOTAL-LIABILITY-AND-EQUITY> 6,147
<SALES> 1,594
<TOTAL-REVENUES> 1,728
<CGS> 0
<TOTAL-COSTS> 1,592
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 219
<INCOME-PRETAX> (51)
<INCOME-TAX> (140)
<INCOME-CONTINUING> 89
<DISCONTINUED> 133
<EXTRAORDINARY> 4
<CHANGES> 0
<NET-INCOME> 226
<EPS-BASIC> 0.91
<EPS-DILUTED> 0.91
</TABLE>
<PAGE> 1
EXHIBIT 99.1
BLACK BUTTE COAL COMPANY,
A JOINT VENTURE,
AND R-K LEASING COMPANY
Combined Financial Statements
As of December 31, 1999
and December 26, 1998
<PAGE> 2
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Venturers and Partners of
Black Butte Coal Company, A Joint Venture,
and R-K Leasing Company:
We have audited the accompanying combined balance sheets of Black Butte Coal
Company, A Joint Venture, and R-K Leasing Company (collectively, the "Company"),
as of December 31, 1999, and December 26, 1998, and the related combined
statements of earnings, joint venture and partnership capital (deficit), and
cash flows for the fiscal years then ended. These combined financial statements
are the responsibility of the Company's management. Our responsibility is to
express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the combined financial statements referred to above present
fairly, in all material respects, the combined financial position of Black Butte
Coal Company, A Joint Venture, and R-K Leasing Company, as of December 31, 1999,
and December 26, 1998, and the combined results of their operations and their
cash flows for the fiscal years then ended in conformity with generally accepted
accounting principles.
ARTHUR ANDERSEN
Denver, Colorado,
February 2, 2000.
<PAGE> 3
BLACK BUTTE COAL COMPANY, A JOINT VENTURE
AND R-K LEASING COMPANY
COMBINED STATEMENTS OF EARNINGS
FOR THE FISCAL YEARS ENDED DECEMBER 31, 1999 AND DECEMBER 26, 1998
<TABLE>
<CAPTION>
1999 1998
------------- -------------
<S> <C> <C>
COAL SALES $ 241,365,217 $ 274,734,855
OPERATING EXPENSES:
Mining and processing 23,941,519 19,085,136
Coal purchases 60,473,628 62,859,448
Royalties 5,138,406 4,729,666
Management fee 1,381,534 1,261,036
Production taxes and other taxes 6,992,094 6,609,003
------------- -------------
97,927,181 94,544,289
------------- -------------
MARGIN 143,438,036 180,190,566
CONTRACT CANCELLATION PAYMENTS (Note 5) 5,002,828 3,197,805
------------- -------------
Operating income 148,440,864 183,388,371
------------- -------------
OTHER INCOME (EXPENSE):
Interest income 216,112 94,921
Interest expense (351) (17,649)
Gain (loss) on sale of equipment 596,853 (275,655)
Other (215,141) 24,282
------------- -------------
597,473 (174,101)
------------- -------------
Net earnings $ 149,038,337 $ 183,214,270
============= =============
</TABLE>
The accompanying notes are an integral part of these combined statements.
<PAGE> 4
BLACK BUTTE COAL COMPANY, A JOINT VENTURE,
AND R-K LEASING COMPANY
COMBINED BALANCE SHEETS
DECEMBER 31, 1999 AND DECEMBER 26, 1998
<TABLE>
<CAPTION>
ASSETS 1999 1998
------ ------------- -------------
<S> <C> <C>
CURRENT ASSETS:
Cash and cash equivalents $ 6,596,715 $ 1,825,005
Accounts receivable:
Trade 13,087,418 20,177,502
Affiliates 14,644 54,989
------------- -------------
Total accounts receivable 13,102,062 20,232,491
Inventories:
Coal 1,851,159 2,633,441
Parts and supplies 154,261 56,770
------------- -------------
Total inventories 2,005,420 2,690,211
Stripping costs applicable to future periods 5,028,867 5,479,142
Other 1,247,519 1,276,174
------------- -------------
Total current assets 27,980,583 31,503,023
------------- -------------
PROPERTY, PLANT AND EQUIPMENT, at cost 167,637,748 171,544,894
Less: Accumulated depreciation and amortization 154,358,311 149,841,934
------------- -------------
Net property, plant and equipment 13,279,437 21,702,960
------------- -------------
DEFERRED DEVELOPMENT COSTS, less accumulated
amortization of $6,522,567 and $6,081,174 439,970 881,363
OTHER ASSETS 1,664,603 2,574,872
------------- -------------
$ 43,364,593 $ 56,662,218
============= =============
LIABILITIES AND JOINT VENTURE AND PARTNERSHIP DEFICIT
CURRENT LIABILITIES:
Accounts payable:
Trade $ 5,990,628 $ 8,397,276
Affiliates 334,588 717,151
------------- -------------
Total accounts payable 6,325,216 9,114,427
Current portion of accrued production taxes 2,748,370 2,436,718
Accrued royalties 339,612 572,549
Current portion of accrued reclamation costs (Note 1) 1,472,000 2,433,622
Other 301,338 339,962
------------- -------------
Total current liabilities 11,186,536 14,897,278
ACCRUED PRODUCTION TAXES 972,818 974,800
ACCRUED RECLAMATION AND OTHER MINING COSTS (Note 1) 55,109,282 52,410,414
OTHER NONCURRENT LIABILITIES 7,192,181 6,063,070
------------- -------------
Total liabilities 74,460,817 74,345,562
------------- -------------
COMMITMENTS AND CONTINGENCIES (Notes 3, 5 and 7)
JOINT VENTURE AND PARTNERSHIP DEFICIT (31,096,224) (17,683,344)
------------- -------------
$ 43,364,593 $ 56,662,218
============= =============
</TABLE>
The accompanying notes are an integral part of these combined balance sheets.
<PAGE> 5
BLACK BUTTE COAL COMPANY, A JOINT VENTURE
AND R-K LEASING COMPANY
COMBINED STATEMENTS OF JOINT VENTURE AND PARTNERSHIP CAPITAL (DEFICIT)
FOR THE FISCAL YEARS ENDED DECEMBER 31, 1999 AND DECEMBER 26, 1998
<TABLE>
<CAPTION>
Bitter Creek Union Pacific
KCP, Inc. Coal Minerals Total
------------- ------------- ------------- -------------
<S> <C> <C> <C> <C>
BALANCE, December 27, 1997 $ (2,005,930) $ (13,545,983) $ 11,528,485 $ (4,023,428)
Capital contributions 9,219,256 8,250,000 969,256 18,438,512
Net earnings (loss) 91,240,923 94,827,288 (2,853,941) 183,214,270
Withdrawals (107,297,812) (106,770,886) (1,244,000) (215,312,698)
------------- ------------- ------------- -------------
BALANCE, December 26, 1998 (8,843,563) (17,239,581) 8,399,800 (17,683,344)
Capital contributions 11,200,000 10,250,000 950,000 22,400,000
Net earnings (loss) 74,157,860 76,336,393 (1,455,916) 149,038,337
Withdrawals (92,423,718) (90,747,499) (1,680,000) (184,851,217)
------------- ------------- ------------- -------------
BALANCE, December 31, 1999 $ (15,909,421) $ (21,400,687) $ 6,213,884 $ (31,096,224)
============= ============= ============= =============
</TABLE>
The accompanying notes are an integral part of these combined statements.
<PAGE> 6
BLACK BUTTE COAL COMPANY, A JOINT VENTURE,
AND R-K LEASING COMPANY
COMBINED STATEMENTS OF CASH FLOWS
FOR THE FISCAL YEARS ENDED DECEMBER 31, 1999 AND DECEMBER 26, 1998
<TABLE>
<CAPTION>
1999 1998
------------- -------------
<S> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
Net earnings $ 149,038,337 $ 183,214,270
Adjustments to reconcile net earnings to net cash provided
by operating activities:
Depreciation and amortization 9,406,116 11,427,382
(Gain) loss on sale of equipment (596,853) 275,655
Change in operating assets and liabilities:
Accounts receivable 7,130,429 (4,111,801)
Inventories 684,791 480,415
Stripping costs applicable to future periods 450,275 1,738,615
Other current assets 28,655 236,376
Other assets 910,269 983,158
Accounts payable (2,789,211) 2,406,825
Accrued production taxes 309,670 393,131
Accrued royalties (232,937) 35,303
Accrued reclamation and other mining costs 2,584,246 1,574,518
Other current liabilities (38,625) 45,894
Other noncurrent liabilities 1,129,111 1,422,295
------------- -------------
Net cash provided by operating activities 168,014,273 200,122,036
------------- -------------
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures (1,388,846) (2,298,349)
Proceeds from sale of equipment 597,500 34,650
------------- -------------
Net cash used in investing activities (791,346) (2,263,699)
------------- -------------
CASH FLOWS FROM FINANCING ACTIVITIES:
Capital contributions by venture partners 22,400,000 18,438,512
Capital withdrawn by venture partners (184,851,217) (215,312,698)
------------- -------------
Net cash used in financing activities (162,451,217) (196,874,186)
------------- -------------
NET INCREASE IN CASH AND CASH EQUIVALENTS 4,771,710 984,151
CASH AND CASH EQUIVALENTS, beginning of year 1,825,005 840,854
------------- -------------
CASH AND CASH EQUIVALENTS, end of year $ 6,596,715 $ 1,825,005
============= =============
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION:
Cash paid during the year for interest $ 351 $ 17,649
============= =============
</TABLE>
The accompanying notes are an integral part of these combined statements.
<PAGE> 7
BLACK BUTTE COAL COMPANY, A JOINT VENTURE,
AND R-K LEASING COMPANY
NOTES TO COMBINED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:
Basis of Presentation
The accompanying combined financial statements include the accounts of Black
Butte Coal Company, A Joint Venture, and R-K Leasing Company (collectively the
"Company") which are affiliated through common ownership. Significant
intercompany accounts and transactions have been eliminated.
General
Black Butte Coal Company is a joint venture formed January 1, 1974, by Bitter
Creek Coal Company (a subsidiary of Union Pacific Resources Company) and KCP,
Inc., formerly Kiewit Coal Properties Inc. ("KCP") for the purpose of
developing, mining and selling coal from properties known as the Black Butte
Properties, a surface mine in Sweetwater County, Wyoming. The joint venture
expires on the earliest of (i) January 2004, (ii) when the coal reserves of the
Black Butte Properties have been fully mined, or (iii) when the venturers
mutually agree to terminate the venture. With the exception of a provision
regarding certain new tonnage sold, the joint venture agreement provides for the
venturers to share equally in net profits and net losses unless the capital
contributions of both venturers are not on an equal basis, in which case the
share of net profits shall be in proportion to each venturer's interest in the
total venture capital. Capital contributions and withdrawals shall be made
pursuant to the terms of the joint venture agreement, as amended from time to
time, and generally is based on the working capital needs of the joint venture
as mutually determined by the venturers. During fiscal 1999 and 1998, each
venturer maintained a 50% ownership interest in Black Butte Coal Company.
R-K Leasing Company is a partnership between Union Pacific Minerals and KCP,
formed for the purpose of leasing various types of real and personal property
including buildings, heavy machinery and equipment. All partnership leases are
operating leases with Black Butte Coal Company, A Joint Venture. The partnership
expires March 1, 2014, or upon the complete satisfaction of any long-term
indebtedness incurred by the partnership, or upon termination or expiration of
all equipment or other leases which may be entered into by the partnership,
whichever occurs later. The partnership agreement provides for the partners to
share net earnings in proportion to each partner's interest in total partnership
capital. During fiscal 1999 and 1998, each partner maintained a 50% ownership
interest in R-K Leasing Company.
The Company's coal is sold primarily to electric utilities, which burn coal in
order to generate steam to produce electricity. Approximately 99.5 percent and
92 percent of the Company's coal sales were made under long-term contracts
during fiscal year 1999 and 1998, respectively. The remainder of the Company's
sales are made on the spot market where prices are substantially lower than
those received from the long-term contracts.
<PAGE> 8
-2-
The coal industry is highly competitive. The Company competes not only with
other domestic and foreign coal suppliers, some of whom are larger and have
greater capital resources than the Company, but also with alternative methods of
generating electricity and alternative energy sources. Many of the Company's
competitors are served by two railroads and, due to the competition, often
benefit from lower transportation costs than the Company which is served by a
single railroad. Additionally, many competitors have lower stripping ratios than
the Company, often resulting in lower comparative costs of production.
The Company is also required to comply with various federal, state and local
laws concerning protection of the environment. The Company believes its
compliance with environmental protection and land restoration laws will not
affect its competitive position since its competitors are similarly affected by
such laws.
KCP owns a 50 percent interest in Decker Coal Company ("Decker") which sells
coal to the Company.
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 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 the reporting period.
Actual results could differ from those estimates.
Cash and Cash Equivalents
Cash equivalents consist of highly liquid instruments purchased with an original
maturity of three months or less and are carried at cost which approximates
market due to the short maturities.
Inventories
Inventories of coal, parts and supplies are valued at the lower-of-cost or
market. Cost is computed on a currently adjusted average basis.
Stripping Costs Applicable to Future Periods
Costs incurred in the removal of earth to expose coal reserves are deferred and
charged to operations when the coal is mined, according to the average stripping
ratio for the mine. The average stripping ratio is based on the ratio of the
estimated tons of earth to be removed to the estimated recoverable tons of coal.
Depreciation and Amortization
Depreciation and amortization on mining equipment, automobiles and trucks and
furniture, fixtures and equipment is provided on the straight-line method based
on estimated useful lives of 2 to 25 years. Depreciation on railroad trackage,
buildings and improvements, mining facilities and tipple is charged to
operations based on the ratio of tons of coal mined to total tons of coal
committed under sales contracts. When assets are disposed, the cost and related
accumulated depreciation or amortization are removed from the accounts and the
net amount, less any proceeds from disposal, is charged or credited to income.
Deferred Development Costs
Development costs incurred to bring new mineral properties into production have
been capitalized. These costs are charged to operations, by property, based upon
the ratio of tons of coal mined to total tons of coal committed under sales
contracts.
<PAGE> 9
-3-
Reclamation
The Company follows the policy of providing an accrual for reclamation of mined
properties, based on the estimated total cost of restoration of such properties
to meet compliance with laws governing strip mining, by applying per-ton
reclamation rates to coal mined. These reclamation rates are determined using
the remaining estimated reclamation costs and tons of coal committed under sales
contracts. The Company reviews its reclamation cost estimates annually and
revises the reclamation rates on a prospective basis, as necessary.
Income Taxes
Provision for federal and state income taxes has not been made in the combined
financial statements since the liability is that of the venturers and partners
and not that of the joint venture or the partnership.
Coal Sales
Coal sales include routine billing and escalation amounts. Claims for additional
contract compensation are not recorded until the year in which such claims are
allowed.
Fiscal Yearend
During 1999, the Company elected to change from a 52-53 week fiscal year, which
ended on the last Saturday in December, to a calendar year. There were 52 weeks
in fiscal 1998 and 52 weeks and 6 days in fiscal 1999.
Reclassifications
Certain prior year amounts have been reclassified to conform with the current
year financial statement presentation.
2. PROPERTY, PLANT AND EQUIPMENT:
A summary of property, plant and equipment cost at December 31, 1999 and
December 26, 1998, is as follows:
<TABLE>
<CAPTION>
1999 1998
------------ ------------
<S> <C> <C>
Land $ 484,821 $ 484,821
Railroad spurs 307,310 307,310
Buildings and improvements 12,017,306 12,017,306
Mine facilities 53,144,851 53,144,851
Mine equipment 101,006,748 104,914,327
Automobiles and trucks 536,405 535,972
Furniture, fixtures and office equipment 140,307 140,307
------------ ------------
$167,637,748 $171,544,894
============ ============
</TABLE>
3. PENSION PLAN:
The Company has an obligation to make contributions to the Black Butte Coal
Company Pension Plan (the "Plan"), which covers all employees except salaried
and office personnel. The amount of required contributions is determined
actuarially each year. No contributions were required in 1999 or 1998. The
components of the net periodic pension cost (benefit) at December 31, 1999 and
December 26, 1998, were as follows:
<PAGE> 10
-4-
<TABLE>
<CAPTION>
1999 1998
--------- ---------
<S> <C> <C>
Service cost $ 20,000 $ 20,000
Interest cost on projected benefit obligation 666,960 635,411
Expected return on plan assets (834,519) (730,329)
Amortization of transition asset and
recognized net actuarial (gain) loss (29,683) (458)
--------- ---------
Net periodic pension benefit $(177,242) $ (75,376)
========= =========
</TABLE>
The funded status of the Plan at December 31, 1999 and December 26, 1998, and
the related changes for the fiscal years then ended, were as follows:
<TABLE>
1999 1998
------------ ------------
<S> <C> <C>
Change in projected benefit obligation
Benefit obligation at beginning of year $ 10,336,891 $ 9,171,585
Service cost 20,000 20,000
Interest cost 666,960 635,411
Actuarial (gain)/loss (1,973,772) 740,929
Benefits paid (261,199) (231,034)
------------ ------------
Benefit obligation at end of year 8,788,880 10,336,891
------------ ------------
Change in plan assets
Fair value of plan assets at beginning of year 10,516,787 9,206,629
Actual return on plan assets 1,187,010 1,541,192
Benefits paid (261,199) (231,034)
------------ ------------
Fair value of plan assets at end of year $ 11,442,598 $ 10,516,787
------------ ------------
Funded status at end of year $ 2,653,718 $ 179,896
Unrecognized transition asset (177,529) (266,294)
Unrecognized net actuarial (gain) loss (811,586) 1,573,759
------------ ------------
Prepaid pension cost $ 1,664,603 $ 1,487,361
============ ============
</TABLE>
The projected benefit obligation was determined using an assumed discount rate
of 8.0 percent and 6.5 percent in 1999 and 1998, respectively, and no increases
in compensation were assumed. The expected long-term rate of return on plan
assets was 8 percent in both 1999 and 1998. At December 31, 1999 and December
26, 1998, plan assets were invested in guaranteed insurance contracts and mutual
funds. On December 31, 1992, the Plan and all benefits under the Plan were
frozen and all participants became fully vested. The prepaid pension cost at
December 31, 1999 and December 26, 1998, was included in other assets in the
accompanying combined balance sheets.
<PAGE> 11
-5-
4. SALES:
Coal sales to significant customers and the respective percentage of total coal
sales in fiscal years 1999 and 1998 were as follows:
<TABLE>
<CAPTION>
1999 1998
---------------------------------- -------------------------------------
Amount % Amount %
------ --- ------ ---
<S> <C> <C> <C> <C>
Commonwealth Edison Company $ 197,570,749 82% $234,912,238 86%
PacifiCorp $ 25,528,430 11% $ 23,310,370 8%
</TABLE>
5. COMMITMENTS:
Mineral Properties
The Company has acquired land, leases, or assignment of leases for approximately
58,427 acres of coal reserves. One agreement provides for royalty and overriding
royalty payments based on the tons of coal mined or sold from the various
properties, including certain minimum tons over the life of the agreements. The
Company has included an accrual of approximately $7 million in other non-current
liabilities for estimated potential additional amounts. These lease agreements
expire or are due for renegotiation from 2000 through 2006.
Sales Contracts
In prior years, the Company and Commonwealth Edison Company ("Commonwealth")
entered into various agreements which stipulated Commonwealth's coal purchase
and payment terms. On December 6, 1999, the Company and Commonwealth signed
amendments stipulating revised semi-monthly payment amounts in lieu of
Commonwealth's remaining purchase commitments. The semi-monthly payment amounts
are equal to the profit margin which would have been earned by the Company had
Commonwealth maintained their original purchase commitments. As a result of
these amendments, Commonwealth paid the Company $997,938 during 1999 for the
profit margin on a portion of December commitments. This amount was included in
contract cancellation payments in the 1999 combined statement of earnings. After
2000, all of Commonwealth's obligations to purchase coal from or make contract
settlement payments to the Company will terminate.
In addition to the cancellation of the Commonwealth purchase commitments
discussed above, during fiscal 1999 and 1998, the Company received $4,004,890
and $3,197,805, respectively, in consideration for the cancellation by another
customer of ten and eight months, respectively, of purchase commitments under a
sales contract.
The Company also has other sales commitments, including those with Sierra
Pacific, Solvay Minerals Inc., Idaho Power and PacifiCorp, that provide for the
delivery of approximately 18.2 million tons through 2005. On January 1, 1999,
the Company signed a seven-year agreement with Idaho Power and PacifiCorp to
provide for the delivery of up to 2.75 million tons per year through 2005, which
is included in the aforementioned sales commitments.
The sales contracts provide that the per ton sales price of coal will be
adjusted on a current basis for changes in indices and certain cost items.
Certain escalation costs are billed at the close of each contract year. In the
event that these customers do not fulfill the contractual responsibilities, the
Company would pursue the available legal remedies.
<PAGE> 12
-6-
In the opinion of management, the Company has sufficient coal reserves to cover
the above sales commitments. Sales to these customers account for substantially
all of the Company's revenue.
As the current sales agreements expire, a higher proportion of the Company's
sales will occur on the spot market where prices are substantially lower than
those in the aforementioned agreements.
6. TRANSACTIONS WITH RELATED PARTIES:
Management Fee
Under the terms of the joint venture agreement, a management fee is to be paid
to KCP for its costs of managing the Company. These fees were $1,381,534 and
$1,261,036 in fiscal 1999 and 1998, respectively. The management fee is three
percent of gross coal sales on mined coal and three percent of the margin on
coal purchased from an affiliate. Accrued management fees to KCP as of December
31, 1999 and December 26, 1998, were $88,418 and $111,274, respectively and are
included in accounts payable - affiliates in the accompanying combined balance
sheets.
Royalties
In connection with certain leases of mineral properties described in Note 5,
royalties of $2,286,237 and $2,062,138 in 1999 and 1998, respectively, were
earned by affiliates of the venturers and included in royalties expense in the
accompanying combined statements of earnings. Accrued royalties to affiliates of
the venturers as of December 31, 1999 and December 26, 1998 were $114,350 and
$242,118, respectively.
Purchased Coal
The Company purchased coal of approximately $26.2 million in 1999 and $20.2
million in 1998 from Decker Coal Company, which is partially owned by KCP.
Other
Other amounts due to affiliates of the Company for working capital and related
items and included in accounts payable - affiliates in the accompanying December
31, 1999 and December 26, 1998 combined balance sheets were $246,170 and
$605,877, respectively.
7. OTHER MATTERS:
The Minerals Management Service, an agency of the United States Interior
Department ("MMS") and the Montana Department of Revenue ("MDOR") have conducted
audits and issued assessments to a KCP affiliate (the "Supplier") for additional
royalties and production taxes, respectively, in connection with coal produced
and sold under contract to the Company prior to 1993. The MMS and MDOR claim
that the contracts were not at arm's length, and the Supplier appealed such
assessments. The Supplier has previously appealed to the Director of the MMS,
and intends to pursue additional appeals in the event of any adverse decisions
from the Director of the MMS, if and when that occurs. During 1998, a Montana
state district court ruled in favor of the MDOR. However, the Supplier appealed
that decision to the Montana Supreme Court, where the case is pending. At
December 31, 1999, the estimated additional royalties and production taxes
assessed by the MMS and MDOR that would affect the Company, including interest,
are approximately $13.4 million and $30.3 million, respectively. In the event of
any adverse outcome, the Supplier will obtain reimbursement from the Company
pursuant to certain indemnifications in the coal contract with such Supplier.
<PAGE> 13
-7-
The Company has not reflected any estimated liability related to any of these
assessments in its combined balance sheets or statements of earnings. Any
estimated liabilities related to these assessments are recorded in the
respective financial statements of the venture partners.
The Company is also involved in various lawsuits, claims, regulatory, and
environmental proceedings incidental to its business.
The Company previously insured for Black Lung disease with a captive insurance
company. This captive insurance company was liquidated in 1996. The Company is
now self-insured and has established an accrued liability of approximately
$658,000 for estimated claims for Black Lung as of December 31, 1999 and
December 26, 1998.
<PAGE> 1
EXHIBIT 99.2
BLACK BUTTE COAL COMPANY,
A JOINT VENTURE,
AND R-K LEASING COMPANY
Combined Financial Statements
As of December 27, 1997
<PAGE> 2
BLACK BUTTE COAL COMPANY, A JOINT VENTURE,
AND R-K LEASING COMPANY
COMBINED STATEMENT OF EARNINGS
FOR THE FISCAL YEAR ENDED DECEMBER 27, 1997
<TABLE>
<CAPTION>
1997
------------
<S> <C>
COAL SALES $178,746,106
OPERATING EXPENSES:
Mining and processing 17,278,100
Coal purchases 44,840,861
Royalties 4,043,837
Management fee 1,053,563
Production taxes and other taxes 5,249,360
------------
72,465,721
------------
MARGIN 106,280,385
CONTRACT CANCELLATION PAYMENTS 6,152,650
------------
Operating income 112,433,035
------------
OTHER INCOME (EXPENSE):
Interest income 116,254
Interest expense --
Gain on sale of equipment 685,998
Other 377,231
------------
1,179,483
------------
Net earnings $113,612,518
============
</TABLE>
The accompanying notes are an integral part of these combined statements.
<PAGE> 3
BLACK BUTTE COAL COMPANY, A JOINT VENTURE,
AND R-K LEASING COMPANY
COMBINED BALANCE SHEET
DECEMBER 27, 1997
<TABLE>
<CAPTION>
ASSETS 1997
-------------
<S> <C>
CURRENT ASSETS:
Cash and cash equivalents $ 840,854
Accounts receivable:
Trade 16,091,779
Affiliates 28,911
-------------
Total accounts receivable 16,120,690
Inventories:
Coal 3,031,151
Parts and supplies 139,475
-------------
Total inventories 3,170,626
Stripping costs applicable to future periods 7,217,757
Other 179,171
-------------
Total current assets 27,529,098
-------------
PROPERTY, PLANT AND EQUIPMENT, at cost 181,961,729
Less: Accumulated depreciation and amortization 150,422,806
-------------
Net property, plant and equipment 31,538,923
-------------
DEFERRED DEVELOPMENT COSTS, less accumulated
amortization of $5,527,798 1,432,739
OTHER ASSETS 4,891,409
-------------
$ 65,392,169
=============
LIABILITIES AND JOINT VENTURE AND PARTNERSHIP DEFICIT
CURRENT LIABILITIES:
Accounts payable:
Trade $ 10,267,367
Affiliates 1,081,010
-------------
Total accounts payable 11,348,377
Current portion of accrued production taxes 2,233,400
Accrued royalties 537,246
Current portion of accrued reclamation costs 2,657,068
Other 294,069
-------------
Total current liabilities 17,070,160
ACCRUED PRODUCTION TAXES 784,987
ACCRUED RECLAMATION AND OTHER MINING COSTS 51,560,450
OTHER NONCURRENT LIABILITIES --
-------------
Total liabilities 69,415,597
-------------
COMMITMENTS AND CONTINGENCIES
JOINT VENTURE AND PARTNERSHIP DEFICIT (4,023,428)
-------------
$ 65,392,169
=============
</TABLE>
The accompanying notes are an integral part of these combined balance sheets.
<PAGE> 4
BLACK BUTTE COAL COMPANY, A JOINT VENTURE,
AND R-K LEASING COMPANY
COMBINED STATEMENTS OF JOINT VENTURE AND PARTNERSHIP CAPITAL (DEFICIT)
FOR THE FISCAL YEAR ENDED DECEMBER 27, 1997
<TABLE>
<CAPTION>
Bitter Creek Union Pacific
KCP, Inc. Coal Minerals Total
------------- ------------- ------------- -------------
<S> <C> <C> <C> <C>
BALANCE, December 28, 1996 $ 7,876,978 $ (6,557,291) $ 14,383,837 $ 15,703,524
Capital contributions 6,128,000 5,750,000 378,000 12,256,000
Net earnings (loss) 56,380,154 58,860,716 (1,628,352) 113,612,518
Withdrawals (72,391,062) (71,599,408) (1,605,000) (145,595,470)
------------- ------------- ------------- -------------
BALANCE, December 27, 1997 (2,005,930) (13,545,983) 11,528,485 (4,023,428)
</TABLE>
The accompanying notes are an integral part of these combined statements.
<PAGE> 5
BLACK BUTTE COAL COMPANY, A JOINT VENTURE,
AND R-K LEASING COMPANY
COMBINED STATEMENT OF CASH FLOWS
FOR THE FISCAL YEAR ENDED DECEMBER 27, 1997
<TABLE>
<CAPTION>
1997
-------------
<S> <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
Net earnings $ 113,612,518
Adjustments to reconcile net earnings to net cash provided
by operating activities:
Depreciation and amortization 7,314,101
(Gain) on sale of equipment (685,998)
Change in operating assets and liabilities:
Accounts receivable 9,641,166
Inventories 1,051,933
Stripping costs applicable to future periods 1,293,044
Other current assets 158,996
Other assets 734,216
Accounts payable 262,477
Accrued production taxes (394,314)
Accrued royalties (113,590)
Accrued reclamation and other mining costs 999,488
Other liabilities (724,830)
-------------
Net cash provided by operating activities 133,149,207
-------------
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures (615,781)
Proceeds from sale of equipment 720,402
-------------
Net cash used in investing activities 104,621
-------------
CASH FLOWS FROM FINANCING ACTIVITIES:
Capital contributions by venture partners 12,256,000
Capital withdrawn by venture partners (145,595,470)
-------------
Net cash used in financing activities (133,339,470)
-------------
NET DECREASE IN CASH AND CASH EQUIVALENTS (85,642)
CASH AND CASH EQUIVALENTS, beginning of year 926,496
-------------
CASH AND CASH EQUIVALENTS, end of year $ 840,854
=============
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION:
Cash paid during the year for interest $ --
=============
</TABLE>
The accompanying notes are an integral part of these combined statements.
<PAGE> 6
BLACK BUTTE COAL COMPANY, A JOINT VENTURE,
AND R-K LEASING COMPANY
NOTES TO COMBINED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:
Basis of Presentation
The accompanying combined financial statements include the accounts of Black
Butte Coal Company, A Joint Venture, and R-K Leasing Company (collectively the
"Company") which are affiliated through ownership. Significant intercompany
accounts and transactions have been eliminated.
General
Black Butte Coal Company is a joint venture formed January 1, 1974, by Bitter
Creek Coal and KCP, Inc., formerly Kiewit Coal Properties Inc. ("KCP") for the
purpose of developing, mining and selling coal from properties known as the
Black Butte Properties, a surface mine in Sweetwater County, Wyoming. The joint
venture expires on the earliest of (i) January 2004, (ii) when the coal reserves
of the Black Butte Properties have been fully mined, or (iii) when the venturers
mutually agree to terminate the venture. With the exception of a provision
regarding certain new tonnage sold, the joint venture agreement provides for the
venturers to share equally in net profits and net losses unless the capital
contributions of both venturers are not on an equal basis, in which case the
share of net profits shall be in proportion to each venturer's interest in the
total venture capital.
R-K Leasing Company is a partnership between Union Pacific Minerals and KCP,
formed for the purpose of leasing various types of real and personal property
including buildings, heavy machinery and equipment. All partnership leases are
operating leases with Black Butte Coal Company, A Joint Venture. The partnership
expires March 1, 2014, or upon the complete satisfaction of any long-term
indebtedness incurred by the partnership, or upon termination or expiration of
all equipment or other leases which may be entered into by the partnership,
whichever is the later event. The partnership agreement provides for the
partners to share net earnings in proportion to each partner's interest in total
partnership capital.
The Company's coal is sold primarily to electric utilities, which burn coal in
order to generate steam to produce electricity. Approximately 89% of the
Company's coal sales were made under long-term contracts during fiscal year
1997. The remainder of the Company's sales are made on the spot market where
prices are substantially lower than those received from the long-term contracts.
The coal industry is highly competitive. The Company competes not only with
other domestic and foreign coal suppliers, some of whom are larger and have
greater capital resources than the Company, but also with alternative methods of
generating electricity and alternative energy sources. Many of the Company's
competitors are served by two railroads and, due to the competition, often
benefit from lower transportation costs than the Company which is served by a
single railroad. Additionally, many competitors have lower stripping ratios than
the Company, often resulting in lower comparative costs of production.
<PAGE> 7
-2-
The Company is also required to comply with various federal, state and local
laws concerning protection of the environment. The Company believes its
compliance with environmental protection and land restoration laws will not
affect its competitive position since its competitors are similarly affected by
such laws.
KCP owns a 50% interest in Decker Coal Company ("Decker") which sells coal to
the Company.
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 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 the reporting period.
Actual results could differ from those estimates.
Cash and Cash Equivalents
Cash equivalents generally consist of highly liquid instruments purchased with a
maturity of three months or less and are carried at cost which approximates
market due to the short maturities.
Inventories
Inventories of coal, parts and supplies are valued at the lower-of-cost or
market. Cost is computed on a currently adjusted average basis.
Stripping Costs Applicable to Future Periods
Costs incurred in the removal of earth in order to expose coal reserves are
charged to operations when related coal is delivered.
Depreciation and Amortization
Depreciation on railroad spurs, buildings and improvements, mine facilities and
equipment is charged to operations based upon the ratio of tons of coal
delivered to total tons of coal estimated to be delivered through 2004.
Depreciation of other assets is provided on the straight-line method based upon
estimated useful lives of 2 to 10 years. In the case of disposals, the assets
and related accumulated depreciation and amortization are removed from the
accounts and the net amount, less proceeds from disposal, is charged or credited
to income.
Unrecovered Development Costs:
Development costs incurred to bring new mineral properties into production have
been capitalized. These costs are charged to operations, by property, based upon
the ration of tons of coal delivered to total tons of coal estimated to be
delivered through 2004.
Reclamation
The Company follows the policy of providing an accrual for reclamation of mined
properties, based on the estimated total cost of restoration of such properties
in compliance with laws governing strip mining. It is at least reasonably
possible that the estimated cost of restoration will be revised in the
near-term.
Income Taxes
Provision for federal and state income taxes has not been made in the financial
statements since the liability is that of the venturers and partners and not
that of the joint venture and the partnership.
Coal Sales
Coal sales include routine billing and escalation amounts. Claims for additional
contract compensation are not recorded until the year in which such claims are
allowed.
<PAGE> 8
-3-
Fiscal Year-end
The Company is on a 52-53 week fiscal year which ends on the last Saturday in
December. There were 52 weeks in 1997.
2. PROPERTY, PLANT AND EQUIPMENT:
A summary of property, plant and equipment cost at December 27, 1997 is as
follows:
<TABLE>
<CAPTION>
1997
------------
<S> <C>
Land $ 484,821
Railroad spurs 307,310
Buildings and improvements 12,967,458
Mine facilities 62,150,661
Mine equipment 105,316,879
Automobiles and trucks 504,566
Furniture, fixtures and office equipment 230,034
------------
$181,961,729
============
</TABLE>
3. PENSION PLAN:
The Company has an obligation to make contributions to the Black Butte Coal
Company Pension Plan, which covers all employees except salaried and office
personnel. The amount of required contributions is determined actuarially each
year. No contributions were required in 1997. The net periodic pension cost
(benefit) at December 27, 1997 was as follows:
<TABLE>
<CAPTION>
1997
-----------
<S> <C>
Service cost $ 20,000
Interest cost on projected benefit obligation 596,810
Actual return on plan assets (1,132,684)
Net amortization and deferral 466,338
-----------
Net periodic pension benefit $ (49,536)
===========
</TABLE>
The funded status of the Plan at December 27, 1997 was as follows:
<TABLE>
<CAPTION>
1997
-----------
<S> <C>
Change in projected benefit obligation
Plan assets, at fair value $ 9,206,629
Projected benefit obligation 9,171,585
-----------
Plan assets in excess of projected benefit obligation 35,044
Unrecognized net loss 1,732,000
Unrecognized transition asset (355,059)
-----------
Prepaid pension costs $ 1,411,985
===========
</TABLE>
The projected benefit obligation was determined using an assumed discount rate
of 7% in 1997, no increases in compensation were assumed. The expected long-term
rate of return on plan assets was 8% in 1997. At December 27, 1997, plan assets
were invested in guaranteed insurance contracts and mutual funds. On
<PAGE> 9
-4-
December 31, 1992, the Plan and all benefits under the Plan were frozen and all
participants became fully vested.
4. SALES:
Sales to significant customers were as follows:
<TABLE>
<CAPTION>
1997
------------
<S> <C>
Commonwealth Edison Company $145,814,000
============
PacifiCorp $ 19,847,000
============
Idaho Power $ 7,277,000
============
Sierra Pacific $ 291,000
============
Solvay Minerals Inc. $ 5,506,000
============
</TABLE>
5. COMMITMENTS:
Mineral Properties
The Company has acquired land, leases, or assignment of leases for approximately
58,427 acres of coal reserves. The various agreements provide for royalty and
overriding royalty payments based on the tons of coal mined or sold from the
various properties. These lease agreements expire or are due for renegotiation
from 1998 through 2006.
Sales Contracts
The Company and Commonwealth Edison Company ("Commonwealth") have entered into
various agreements which stipulated delivery and payment terms for the sale of
coal. The agreements, as amended effective January 1, 1993, provide for the
delivery of 40 million tons during the period 1998 through 2004, with annual
shipments ranging from 4 million to 10.4 million tons. This quantity included 12
million tons of coal reserves previously sold to Commonwealth.
To satisfy the delivery obligations for 1998-2004 under the renegotiated
Commonwealth agreements, the Company has agreed to buy coal from three mines,
two of which are unaffiliated mines located in the Powder River Basin area of
Wyoming and one which is an affiliate of KCP. These contracts call for the
Powder River Basin Mines to deliver 24 million tons of coal from 1998 to 2000
with annual amounts ranging from 6.5 to 10.4 million tons and for the affiliate
mine to deliver 2 million tons in 1998 and 1.8 million tons in 2000. The Company
expects to fulfill its obligations to deliver 12 million tons of coal during
2002 to 2004 by purchasing that coal from an alternate source mine, but no
agreement has yet been signed.
The Company also has other sales commitments, including those with Sierra
Pacific, Solvay Minerals Inc., Idaho Power and PacificCorp, that provide for the
delivery of approximately 5.8 million tons through 2005.
The sales contracts provide that the per ton sales price of coal will be
adjusted on a current basis for changes in indices and certain cost items.
Certain escalation costs are billed at the close of each contract year.
In the event that these customers do not fulfill the contractual
responsibilities, the Company would pursue the available legal remedies.
In the opinion of management, the Company has sufficient coal reserves to cover
the above sales
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commitments. Sales to these customers account for substantially all of the
Company's revenue.
As the current sales agreements expire, a higher proportion of the Company's
sales will occur on the spot market where prices are substantially lower than
those in the aforementioned agreements.
6. TRANSACTIONS WITH RELATED PARTIES:
Management Fee
Under the terms of the joint venture agreement, a management fee is to be paid
to KCP for its costs of managing the Company. This fee was $1,053,563 in 1997.
The management fee is 3% of gross coal sales on mined coal and 3% of the margin
on coal purchased from an affiliate. Accrued management fees to KCP as of
December 27, 1997 were $185,981.
Royalties
In connection with certain leases described in Note 5(a), royalties of
$1,237,104 in 1997, were earned by affiliates of the venturers. Accrued
royalties to affiliates of the venturers as of December 27, 1997 were $129,135.
Engineering Service Fee:
Kiewit Mining Group, Inc. provides various engineering services to the Company.
The service fee for 1997 was $353,875.
Purchased Coal
The Company purchased coal of approximately $19.1 million from Decker in 1997.
7. OTHER MATTERS:
The Minerals Management Service has conducted an audit and issued an assessment
to a Decker which claims that there has been an underpayment of royalties for
coal sold by Decker to the Company . Pursuant to the contract between Decker and
the Company, the Company would reimburse Decker for these royalties. The
potential liability for royalties and interest approximate $11.8 million.
Additionally, the State of Montana Department of Revenue has issued assessments
to Decker which claim additional production taxes for coal sold by Decker to the
Company. Pursuant to the contract between Decker and the Company, the Company
would reimburse Decker for these production taxes. The potential liability for
production taxes and interest approximates $26. Million. Decker is vigorously
contesting these assessments.
The Company is also involved in various lawsuits, claims, regulatory, and
environmental proceedings incidental to its business
Management believes that nay resulting liability from the above matters should
not materially affect the Company's financial position, but could, however, have
a material effect on future results of operations and future cash flows.
In 1997, the Company issued letters of credit to a lessor amounting to
$1,115,000.
The Company previously insured for Black Lung disease with a captive insurance
company. This captive insurance company was liquidated in 1996, whereupon the
Company received a refund of premiums paid, plus interest totaling $8,202,126.
The Company is now self-insured and has set up a reserve of $657,862 for
estimated claims for Black Lung. It is at least reasonably possible that this
claims estimate will be revised in
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the near-term. The difference between the refund received and the reserve
established has been reflected as "Insurance costs refunded, net" in the
Statement of Earnings.
The Company established a reserve for certain non-mobile assets that are not
considered salable. As of December 27, 1997 the reserve was $3,136,000, which is
included in noncurrent accrued reclamation and other mining costs.
In 1997 the Company received $6,152,650 in consideration for the cancellation by
a customer of one year of purchase commitments under a sales contract.
