UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2001
Commission File Number: 1-13245
Pioneer Natural Resources Company
(Exact name of registrant as specified in its charter)
Delaware 75-2702753
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
5205 N. O'Connor Blvd., Suite 1400, Irving, Texas 75039
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code:
(972) 444-9001
Securities registered pursuant to Section 12(b) of the Act:
Name of each exchange
Title of each class on which registered
------------------- -----------------------
Common Stock............................. New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark whether the Registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the Registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days. YES X NO
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein and will not be contained, to the best
of Registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [ X ]
Aggregate market value of the voting stock held by non-affiliates
of the Registrant as of February 25, 2002................... $2,017,546,447
Number of shares of Common Stock outstanding as of
February 25, 2002........................................... 104,052,756
Documents Incorporated by Reference:
(1) Proxy Statement for Annual Meeting of Shareholders to be held May 14, 2002
- Referenced in Part III of this report.
TABLE OF CONTENTS
Page
Toronto Stock Exchange Cross Reference Sheet........................... 4
Definitions of Oil and Gas Terms and Conventions Used Herein........... 5
PART I
Item 1. Business.................................................... 6
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General..................................................... 6
Mission and Strategies...................................... 6
Business Activities......................................... 6
Operations by Geographic Area............................... 9
Marketing of Production..................................... 9
Competition, Markets and Regulations........................ 9
Risks Associated with Business Activities................... 11
Item 2. Properties.................................................. 13
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Proved Reserves............................................. 14
Alternate Reserve Case...................................... 14
Finding Cost and Reserve Replacement........................ 15
Description of Properties................................... 16
Selected Oil and Gas Information............................ 20
Item 3. Legal Proceedings........................................... 24
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Item 4. Submission of Matters to a Vote of Security Holders......... 24
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PART II
Item 5. Market for Registrant's Common Stock and Related
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Stockholder Matters....................................... 24
-------------------
Item 6. Selected Financial Data..................................... 25
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Item 7. Management's Discussion and Analysis of Financial
------- -------------------------------------------------
Condition and Results of Operations....................... 26
-----------------------------------
2001 Performance............................................ 26
2002 Outlook................................................ 27
Critical Accounting Policies................................ 28
New Accounting Pronouncement................................ 29
Results of Operations....................................... 30
Capital Commitments, Capital Resources and Liquidity........ 34
2
TABLE OF CONTENTS
Page
Item 7A. Quantitative and Qualitative Disclosures About Market Risk.. 37
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Quantitative Disclosures.................................... 37
Qualitative Disclosures..................................... 42
Item 8. Financial Statements and Supplementary Data................. 43
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Index to Consolidated Financial Statements.................. 43
Independent Auditors' Report................................ 44
Consolidated Financial Statements........................... 45
Notes to Consolidated Financial Statements.................. 50
Unaudited Supplementary Information......................... 82
Item 9. Changes in and Disagreements With Accountants on Accounting
and Financial Disclosure.................................... 87
------------------------
PART III
Item 10. Directors and Executive Officers of the Registrant.......... 87
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Item 11. Executive Compensation...................................... 87
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Item 12. Security Ownership of Certain Beneficial Owners
-------- -----------------------------------------------
and Management............................................ 87
--------------
Item 13. Certain Relations and Related Transactions.................. 87
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PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports
-------- ---------------------------------------------------
on Form 8-K............................................... 87
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Signatures.................................................. 93
Exhibit Index............................................... 94
3
PIONEER NATURAL RESOURCES COMPANY
CROSS REFERENCE SHEET
Pursuant to National Policy Statement No. 47 (Canada)
(Annual Information Form ("AIF"))
Item Number and Caption of AIF Heading or Location in Form 10-K
------------------------------ --------------------------------
1. Incorporation Item 1. Business
2. General Development of the Business Item 1. Business
3. Narrative Description of the Business Item 1. Business
Item 2. Properties
4. Selected Consolidated Financial Item 6. Selected Financial Data
Information Item 8. Financial Statements and
Supplementary Data
5. Management's Discussion and Analysis Item 7. Management's Discussion
and Analysis of
Financial Condition
and Results of
Operations
Item 7A. Quantitative and
Qualitative Disclosures
About Market Risk
6. Market for Securities Item 5. Market for Registrant's
Common Stock and Related
Stockholder Matters
7. Directors and Officers Item 10. Directors and Executive
Officers of the
Registrant
8. Additional Information Item 10. Directors and Executive
Officers of the
Registrant
Item 11. Executive Compensation
Item 12. Security Ownership of
Certain Beneficial Owners
and Management
Item 13. Certain Relationships and
Related Transactions
4
Parts I and II of this annual report on Form 10-K (the "Report") contain
forward looking statements that involve risks and uncertainties. Accordingly, no
assurances can be given that the actual events and results will not be
materially different than the anticipated results described in the forward
looking statements. See "Item 1. Business - Competition, Markets and Regulation"
and "Item 1. Business - Risks Associated with Business Activities" for a
description of various factors that could materially affect the ability of
Pioneer Natural Resources Company to achieve the anticipated results described
in the forward looking statements.
Definitions of Oil and Gas Terms and Conventions Used Herein
Within this Report, the following oil and gas terms and conventions have
specific meanings: "Bbl" means a standard barrel containing 42 United States
gallons; "Bcf" means one billion cubic feet; "Tcf" means one trillion cubic
feet; "Bcfe" means a billion cubic feet equivalent and is a standard convention
used to express oil and gas volumes on a comparable gas equivalent basis; "BOE"
means a barrel of oil equivalent and is a standard convention used to express
oil and gas volumes on a comparable oil equivalent basis; "Btu" means British
thermal; "MMBtu" means one million Btu's; "MBbl" means one thousand Bbls; "MBOE"
means one thousand BOE; "MMBOE" means one million BOE; "Mcf" means one thousand
cubic feet and is a measure of natural gas volume; "MMcf" means one million
cubic feet; "NGL" means natural gas liquid; "NYMEX" means The New York
Mercantile Exchange; "proved reserves" mean the estimated quantities of crude
oil, natural gas and natural gas liquids which geological and engineering data
demonstrate with reasonable certainty to be recoverable in future years from
known reservoirs under existing economic and operating conditions, i.e., prices
and costs as of the date the estimate is made. Prices include consideration of
changes in existing prices provided only by contractual arrangements, but not on
escalations based upon future conditions.
(i) Reservoirs are considered proved if economic producibility is
supported by either actual production or conclusive formation test. The area of
a reservoir considered proved includes (A) that portion delineated by drilling
and defined by gas-oil and/or oil-water contacts, if any; and (B) the
immediately adjoining portions not yet drilled, but which can be reasonably
judged as economically productive on the basis of available geological and
engineering data. In the absence of information on fluid contacts, the lowest
known structural occurrence of hydrocarbons controls the lower proved limit of
the reservoir.
(ii) Reserves which can be produced economically through application of
improved recovery techniques (such as fluid injection) are included in the
"proved" classification when successful testing by a pilot project, or the
operation of an installed program in the reservoir, provides support for the
engineering analysis on which the project or program was based.
(iii) Estimates of proved reserves do not include the following: (A) oil
that may become available from known reservoirs but is classified separately as
"indicated additional reserves"; (B) crude oil, natural gas, and natural gas
liquids, the recovery of which is subject to reasonable doubt because of
uncertainty as to geology, reservoir characteristics, or economic factors; (C)
crude oil, natural gas, and natural gas liquids, that may occur in undrilled
prospects; and (D) crude oil, natural gas, and natural gas liquids, that may be
recovered from oil shales, coal, gilsonite and other such sources.
"Standardized Measure" means the after-tax present value of estimated
future net revenues of proved reserves, determined in accordance with the rules
and regulations of the United States Securities and Exchange Commission (the
"SEC"), using prices and costs in effect at the specified date and a 10 percent
discount rate; "acquisition and finding cost per BOE" means total costs incurred
divided by the summation of proved reserves attributable to revisions of
previous estimates, purchases of minerals in place and new discoveries and
extensions; "reserve replacement percentage" means, expressed as a percentage,
the summation of annual proved reserves, on a BOE basis, attributable to
revisions of previous estimates, purchases of minerals in place and new
discoveries and extensions divided by annual production of oil, NGLs and gas, on
a BOE basis; and "WTI" means West Texas Intermediate and is a benchmark grade of
oil in the United States.
Gas equivalents are determined under the relative energy content method
by using the ratio of 6.0 Mcf of gas to 1.0 Bbl of oil or NGL.
With respect to information on the working interest in wells, drilling
locations and acreage, "net" wells, drilling locations and acres are determined
by multiplying "gross" wells, drilling locations and acres by Pioneer Natural
Resources Company's working interest in such wells, drilling locations or acres.
Unless otherwise specified, wells, drilling locations and acreage statistics
quoted herein represent gross wells, drilling locations or acres; and, all
dollar amounts are expressed in U.S. dollars.
5
PART I
ITEM 1. BUSINESS
General
Pioneer Natural Resources Company ("Pioneer", or the "Company") is a
Delaware corporation whose common stock is listed and traded on the New York
Stock Exchange and Toronto Stock Exchange. Pioneer is an oil and gas exploration
and production company with ownership interests in oil and gas properties
located in the United States, Argentina, Canada, Gabon, South Africa and
Tunisia.
The Company's executive offices are located at 5205 N. O'Connor Blvd.,
Suite 1400, Irving, Texas 75039; the Company's telephone number is (972)
444-9001. The Company maintains other offices in Midland, Texas; Buenos Aires,
Argentina; Calgary, Canada; and Capetown, South Africa. At December 31, 2001,
the Company had 926 employees, 469 of whom were employed in field and plant
operations.
Mission and Strategies
The Company's mission is to provide shareholders with superior investment
returns through strategies that maximize Pioneer's long-term profitability and
net asset value. The strategies employed to achieve this mission are predicated
on maintaining financial flexibility and capital allocation discipline.
Historically, these strategies have been anchored by the Company's long-lived
Spraberry oil field and Hugoton and West Panhandle gas fields' reserves and
production. Underlying these fields are approximately 64 percent of the
Company's proved oil and gas reserves which have a remaining productive life in
excess of 40 years. The stable base of oil and gas production from these fields,
together with the soon-to-be-realized production growth from the Company's 1998
Sable oil field discovery in South Africa, the 1999 Aconcagua, 2000 Devils Tower
and 2001 Falcon discoveries in the deepwater Gulf of Mexico (the "Big 4"), will
generate the operating cash flows that will provide Pioneer with continued
financial flexibility. The Big 4 exploration successes represent the results of
the Company's ability to selectively reinvest capital from the long-lived
Spraberry, Hugoton and West Panhandle fields to areas offering superior
investment returns. Similarly, the Company will continue to: (a) selectively
explore for and develop proved reserve discoveries in areas that offer superior
reserve growth and profitability potential; (b) invest in the personnel and
technology necessary to maximize the Company's exploration and development
successes, and (c) enhance liquidity, allowing the Company to take advantage of
future exploration, development and acquisition opportunities. The Company is
committed to continuing to enhance shareholder investment returns through
adherence to these strategies.
Business Activities
The Company is an independent oil and gas exploration and development
company. Pioneer's purpose is to competitively and profitably explore for,
develop and produce oil, NGL and gas reserves. In so doing, the Company sells
homogenous oil, NGL and gas units which, except for geographic and relatively
minor qualitative differentials, cannot be significantly differentiated from
units offered for sale by the Company's competitors. Competitive advantage is
gained in the oil and gas exploration and development industry through superior
capital investment decisions, technological innovation and price and cost
management.
Petroleum industry. The petroleum industry has been characterized by
volatile oil, NGL and gas commodity prices and relatively stable supplier costs
during the three years ended December 31, 2001. During 1999 and 2000, the
Organization of Petroleum Exporting Countries and certain other oil exporting
nations reduced their oil export volumes. Those reductions in oil export volumes
had a positive impact on world oil prices, as did overall gas supply and demand
fundamentals on North American gas prices. During 2001, world oil and North
American gas supply and demand fundamentals shifted, primarily as a result of an
economic recession curtailing demand, causing reductions in world oil and North
American gas prices. To mitigate the impact of volatile commodity prices on the
Company's net asset value, Pioneer periodically enters into commodity hedge
contracts. See Note H of Notes to Consolidated Financial Statements included in
6
"Item 8. Financial Statements and Supplementary Data" for information regarding
the impact to oil and gas revenues during 2001, 2000 and 1999 from the Company's
hedging activities and the Company's open hedge positions at December 31, 2001
and related prices.
The Company. The Company's asset base is anchored by the Spraberry oil
field located in West Texas, the Hugoton gas field located in Southwest Kansas
and the West Panhandle gas field located in the Texas Panhandle. Complementing
these areas, the Company has exploration and development opportunities and oil
and gas production activities in the United States Gulf of Mexico and onshore
Gulf Coast areas, and internationally in Argentina, Canada, Gabon, South Africa
and Tunisia. Combined, these assets create a portfolio of resources and
opportunities that are well balanced among oil, NGLs and gas; and that are also
well balanced between long-lived, dependable production and exploration and
development opportunities. Additionally, the Company has a team of dedicated
employees that represent the professional disciplines and sciences that will
allow Pioneer to maximize the long-term profitability and net asset value
inherent in its physical assets.
The Company provides administrative, financial and management support to
United States and foreign subsidiaries that explore for, develop and produce
oil, NGL and gas reserves. Production operations are principally located
domestically in Texas, Kansas, Louisiana and the Gulf of Mexico, and
internationally in Argentina and Canada.
Production. The Company focuses its efforts towards maximizing its
average daily production of oil, NGL and gas through development drilling,
production enhancement activities and acquisitions of producing properties while
minimizing the controllable costs associated with the production activities.
During 2001, 2000 and 1999, the Company's average daily oil, NGL and gas
production decreased primarily as a result of oil and gas property divestitures
that were supportive of the Company's debt reduction goal. Production, price and
cost information with respect to the Company's properties for each of 2001, 2000
and 1999 is set forth under "Item 2. Properties - Selected Oil and Gas
Information - Production, Price and Cost Data".
Drilling activities. The Company seeks to increase its oil and gas
reserves, production and cash flow through exploratory and development drilling
and by conducting other production enhancement activities, such as well
recompletions. During the five years ended December 31, 2001, the Company
drilled 2,150 gross (1,510.2 net) wells, 90 percent of which were successfully
completed as productive wells, at a total cost (net to the Company's interest)
of $1.5 billion. During 2001, the Company drilled 390 gross (252.1 net) wells
for a total cost (net to the Company's interest) of approximately $423.6
million, 60 percent of which was spent on development wells and related
facilities. The Company's current 2002 capital expenditure budget is $375
million, which represents a spending decrease of approximately 42 percent from
2001 total costs incurred for oil and gas production activities. The Company has
allocated the budgeted 2002 capital expenditures as follows: $285 million to
development drilling and facility activities, and $90 million to exploration
activities.
The Company believes that its current property base provides a
substantial inventory of prospects for future reserve, production and cash flow
growth. The Company's proved reserves as of December 31, 2001 include proved
undeveloped reserves and proved developed reserves that are behind pipe and that
require future capital expenditures, of 104.4 million Bbls of oil and NGLs and
659 Bcf of gas. The timing of the development of these reserves will be
dependent upon the commodity price environment, the Company's expected operating
cash flows and the Company's financial condition. The Company believes that its
current portfolio of undeveloped prospects provides attractive development and
exploration opportunities for at least the next three to five years.
Exploratory activities. Since 1998, the Company has devoted significant
efforts and resources on hiring and developing a highly skilled exploration
staff as well as acquiring and drilling a portfolio of exploration
opportunities. The Company's commitment to exploration has resulted in
significant discoveries during this time period, such as the 1998 Sable oil
field discovery in South Africa and the 1999 Aconcagua, 2000 Devils Tower and
2001 Falcon discoveries in the deepwater Gulf of Mexico. During 2002, the
Company plans to spend a higher percentage of its capital on the development of
these high-impact projects (see "Item 2. Properties - Description of
Properties"). Consequently, the Company currently anticipates that its 2002
exploration efforts will be reduced to approximately 23 percent of total
budgeted 2002 expenditures and will be concentrated domestically in the Gulf of
Mexico and the onshore Gulf Coast area, and internationally in Gabon, South
Africa and Tunisia. Exploratory drilling involves greater risks of dry holes or
7
failure to find commercial quantities of hydrocarbons than development drilling
or enhanced recovery activities. See "Item 1. Business - Risks Associated with
Business Activities - Drilling activities" below.
Asset divestitures. The Company regularly reviews its asset base for the
purpose of identifying non-core assets, the disposition of which would increase
capital resources available for other activities and create organizational and
operational efficiencies. While the Company generally does not dispose of assets
solely for the purpose of reducing debt, such dispositions can have the result
of furthering the Company's objective of financial flexibility through reduced
debt levels.
During 2001, 2000 and 1999, the Company's divestitures consisted of the
sale of oil and gas properties and other assets for net proceeds of $113.5
million, $102.7 million and $420.5 million (of which $390.5 million in 1999 was
cash proceeds), respectively, which resulted in 2001 and 2000 net divestiture
gains of $7.7 million and $34.2 million, respectively, and a 1999 net
divestiture loss of $24.2 million. The Company's 2001 net proceeds from asset
divestitures were primarily derived from early termination of interest rate and
commodity hedges, the sale of the Company's remaining investment in the common
stock of a non-affiliated entity and the sale of certain non-strategic oil
properties in Canada. The assets that the Company divested during 2000 were
primarily comprised of an investment in a non-affiliated entity and non-core
United States oil and gas properties located in Oklahoma, New Mexico and
Louisiana. The Company's 1999 divestitures were comprised of non-core United
States and Canadian oil and gas properties, gas plants and other assets. The net
cash proceeds from the 2001, 2000 and 1999 asset dispositions were primarily
used to reduce the Company's outstanding bank indebtedness. See Note K of Notes
to Consolidated Financial Statements included in "Item 8. Financial Statements
and Supplementary Data" for specific information regarding the Company's asset
divestitures.
The Company anticipates that it will continue to sell non-strategic
properties from time to time to increase capital resources available for other
activities, to achieve operating and administrative efficiencies and to improve
profitability.
Acquisition activities. The Company regularly seeks to acquire properties
that complement its operations, provide exploration and development
opportunities and potentially provide superior returns on investment. In
addition, the Company pursues strategic acquisitions that will allow the Company
to expand into new geographical areas that feature producing properties and
provide exploration/exploitation opportunities. During 2001, the Company
expended $170.8 million of capital to acquire proved and unproved oil and gas
properties. Excluding cash and other working capital acquired, the Company paid
$92.9 million, through the issuance of common stock, to complete the agreement
and plan of merger among Pioneer, Pioneer Natural Resources USA, Inc. and 42
Parker & Parsley limited partnerships (see Note E of Notes to Consolidated
Financial Statements included in "Item 8. Financial Statements and Supplementary
Data"). Additionally, $77.9 million was spent during 2001 to acquire additional
working interests in the United States Gulf of Mexico Aconcagua discovery, the
related Canyon Express gathering system and the Devils Tower project; 21 deep-
water Gulf of Mexico blocks; 250,000 acres in the Anticlinal Campamento, Dos
Hermanas and La Calera areas of the Neuquen Basin in Argentina; and a 30 percent
interest in the Anaguid permit in the Ghadames basin onshore Southern Tunisia.
During 2000, the Company expended $67.2 million to acquire proved and unproved
oil and gas properties. Strategic acquisitions of proved properties during 2000
included incremental working interests in the United States Gulf of Mexico
discovery at Devils Tower and the Company's Canadian Chinchaga gas field. The
Company also acquired an interest in the Camden Hills Gulf of Mexico discovery
and the related Canyon Express gathering system during 2000. During 1999, the
Company acquired Argentine proved and unproved oil and gas properties that
complement its existing operations in Argentina. The Company paid $38.8 million
of cash for the Argentine assets during the fourth quarter of 1999.
The Company periodically evaluates and pursues acquisition opportunities
(including opportunities to acquire particular oil and gas properties or related
assets; entities owning oil and gas properties or related assets; and,
opportunities to engage in mergers, consolidations or other business
combinations with such entities) and at any given time may be in various stages
of evaluating such opportunities. Such stages may take the form of internal
financial analysis, oil and gas reserve analysis, due diligence, the submission
of an indication of interest, preliminary negotiations, negotiation of a letter
of intent or negotiation of a definitive agreement.
8
Operations by Geographic Area
The Company operates in one industry segment. During 2001, 2000 and 1999,
the Company principally had oil and gas producing activities in the United
States, Argentina and Canada; and, had exploration activities in the United
States Gulf Coast area, the Gulf of Mexico, Argentina, Canada, Gabon, South
Africa and Tunisia. See Note P of Notes to Consolidated Financial Statements
included in "Item 8. Financial Statements and Supplementary Data" for geographic
operating segment information, including results of operations and segment
assets.
Marketing of Production
General. Production from the Company's properties is marketed using
methods that are consistent with industry practices. Sales prices for oil, NGL
and gas production are negotiated based on factors normally considered in the
industry, such as the spot price for gas or the posted price for oil, price
regulations, distance from the well to the pipeline, well pressure, estimated
reserves, commodity quality and prevailing supply conditions.
Significant purchasers. During 2001, the Company's primary purchaser of
oil was ExxonMobil Corporation ("ExxonMobil"), the Company's primary purchaser
of NGLs was Williams Energy Services ("Williams") and the Company's primary
purchaser of gas was Anadarko Petroleum Corporation ("Anadarko"). Approximately
seven percent, 11 percent and 10 percent of the Company's 2001 combined oil, NGL
and gas revenues were attributable to sales to ExxonMobil, Williams and
Anadarko, respectively. The Company is of the opinion that the loss of any one
purchaser would not have an adverse effect on its ability to sell its oil, NGL
and gas production.
Hedging activities. The Company periodically enters into commodity
derivative contracts (swaps and collars) in order to (i) reduce the effect of
the volatility of price changes on the commodities the Company produces and
sells, (ii) support the Company's annual capital budgeting and expenditure plans
and (iii) lock in prices to protect the economics related to certain capital
projects. See "Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations" for a description of the Company's hedging
activities, "Item 7A. Quantitative and Qualitative Disclosures About Market
Risk" and Note H of Notes to Consolidated Financial Statements included in "Item
8. Financial Statements and Supplementary Data" for information concerning the
impact to oil and gas revenues during 2001, 2000 and 1999 from the Company's
hedging activities and the Company's open hedge positions at December 31, 2001
and related prices.
Competition, Markets and Regulation
Competition. The oil and gas industry is highly competitive. A large
number of companies and individuals engage in the exploration for and
development of oil and gas properties, and there is a high degree of competition
for oil and gas properties suitable for development or exploration. Acquisitions
of oil and gas properties have been an important element of the Company's
growth. The Company intends to continue to acquire oil and gas properties that
complement its operations, provide exploration and development opportunities and
potentially provide superior return on investment. The principal competitive
factors in the acquisition of oil and gas properties include the staff and data
necessary to identify, investigate and purchase such properties and the
financial resources necessary to acquire and develop them. Many of the Company's
competitors are substantially larger and have financial and other resources
greater than those of the Company.
Markets. The Company's ability to produce and market oil and gas
profitably depends on numerous factors beyond the Company's control. The effect
of these factors cannot be accurately predicted or anticipated. Although the
Company cannot predict the occurrence of events that may affect oil and gas
prices or the degree to which oil and gas prices will be affected, the prices
for any oil or gas that the Company produces will generally approximate current
market prices in the geographic region.
Governmental regulation. Oil and gas exploration and production
operations are subject to various types of regulation by local, state, federal
and foreign agencies. The Company's operations are also subject to state
conservation laws and regulations, including provisions for the unitization or
pooling of oil and gas properties, the establishment of maximum rates of
production from wells and the regulation of spacing, plugging and abandonment of
wells. States and foreign governments generally impose a production or severance
9
tax with respect to production and sale of oil and gas within their respective
jurisdictions. The regulatory burden on the oil and gas industry increases the
Company's cost of doing business and, consequently, affects its profitability.
Additional proposals and proceedings that might affect the oil and gas
industry are considered from time to time by Congress, the Federal Energy
Regulatory Commission, state regulatory bodies, the courts and foreign
governments. The Company cannot predict when or if any such proposals might
become effective or their effect, if any, on the Company's operations.
Environmental and health controls. The Company's operations are subject
to numerous federal, state, local and foreign laws and regulations relating to
environmental and health protection. These laws and regulations may require the
acquisition of a permit before drilling commences, restrict the type, quantities
and concentration of various substances that can be released into the
environment in connection with drilling and production activities, limit or
prohibit drilling activities on certain lands lying within wilderness, wetlands
and other protected areas and impose substantial liabilities for pollution
resulting from oil and gas operations. These laws and regulations may also
restrict air emissions or other discharges resulting from the operation of
natural gas processing plants, pipeline systems and other facilities that the
Company owns. Although the Company believes that compliance with environmental
laws and regulations will not have a material adverse effect on its results of
operations or financial condition, risks of substantial costs and liabilities
are inherent in oil and gas operations, and there can be no assurance that
significant costs and liabilities, including potential criminal penalties, will
not be incurred. Moreover, it is possible that other developments, such as
stricter environmental laws and regulations or claims for damages to property or
persons resulting from the Company's operations, could result in substantial
costs and liabilities.
The Comprehensive Environmental Response, Compensation, and Liability Act
("CERCLA"), also known as the "Superfund" law, imposes liability, without regard
to fault or the legality of the original conduct, on certain classes of persons
with respect to the release of a "hazardous substance" into the environment.
These persons include the owner or operator of the disposal site or sites where
the release occurred and companies that disposed or arranged for the disposal of
hazardous substances released at the site. Persons who are or were responsible
for releases of hazardous substances under CERCLA may be subject to joint and
several liability for the costs of cleaning up the hazardous substances that
have been released into the environment and for damages to natural resources,
and it is not uncommon for neighboring landowners and other third parties to
file claims for personal injury and property damage allegedly caused by the
hazardous substances released into the environment.
The Company generates wastes, including hazardous wastes, that are
subject to the federal Resource Conservation and Recovery Act ("RCRA") and
comparable state statutes. The United States Environmental Protection Agency and
various state agencies have limited the approved methods of disposal for certain
hazardous and non-hazardous wastes. Furthermore, certain wastes generated by the
Company's oil and gas operations that are currently exempt from treatment as
"hazardous wastes" may in the future be designated as "hazardous wastes," and
therefore be subject to more rigorous and costly operating and disposal
requirements.
The Company currently owns or leases, and has in the past owned or
leased, properties that for many years have been used for the exploration and
production of oil and gas. Although the Company has used 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 or on or under other locations where such wastes have been
taken for disposal. In addition, some of these properties have been operated by
third parties whose treatment and disposal or release of hydrocarbons or other
wastes was not under the Company's control. These properties and the wastes
disposed thereon may be subject to CERCLA, RCRA and analogous state laws. Under
such laws, the Company could be required to remove or remediate previously
disposed wastes or property contamination or to perform remedial plugging
operations to prevent future contamination.
Federal regulations require certain owners or operators of facilities
that store or otherwise handle oil, such as the Company, to prepare and
implement spill prevention control plans, countermeasure plans and facility
response plans relating to the possible discharge of oil into surface waters.
The Oil Pollution Prevention Act of 1990 ("OPA") amends certain provisions of
the federal Water Pollution Control Act of 1972, commonly referred to as the
Clean Water Act ("CWA"), and other statutes as they pertain to the prevention of
10
and response to oil spills into navigable waters. The OPA subjects owners of
facilities to strict joint and several liability for all containment and cleanup
costs and certain other damages arising from a spill, including, but not limited
to, the costs of responding to a release of oil to surface waters. The CWA
provides penalties for any discharges of petroleum products in reportable
quantities and imposes substantial liability for the costs of removing a spill.
OPA requires responsible parties to establish and maintain evidence of financial
responsibility to cover removal costs and damages resulting from an oil spill.
OPA calls for a financial responsibility of $35 million to cover pollution
cleanup for offshore facilities. State laws for the control of water pollution
also provide varying civil and criminal penalties and liabilities in the case of
releases of petroleum or its derivatives into surface waters or into the ground.
The Company does not believe that the OPA, CWA or related state laws are any
more burdensome to it than they are to other similarly situated oil and gas
companies.
Many states in which the Company operates have recently begun to regulate
naturally occurring radioactive materials ("NORM") and NORM wastes that are
generated in connection with oil and gas exploration and production activities.
NORM wastes typically consist of very low-level radioactive substances that
become concentrated in pipe scale and in production equipment. State regulations
may require the testing of pipes and production equipment for the presence of
NORM, the licensing of NORM-contaminated facilities and the careful handling and
disposal of NORM wastes. The Company believes that the growing regulation of
NORM will have a minimal effect on the Company's operations because the Company
generates only a very small quantity of NORM on an annual basis.
The Company does not believe that its environmental risks are materially
different from those of comparable companies in the oil and gas industry.
Nevertheless, no assurance can be given that environmental laws will not, in the
future, result in a curtailment of production or processing or a material
increase in the costs of production, development, exploration or processing or
otherwise adversely affect the Company's results of operations and financial
condition.
The Company employs an environmental manager and environmental
specialists charged with monitoring environmental and regulatory compliance. The
Company performs an environmental review as part of the due diligence work on
potential acquisitions, including acquisitions of oil and gas properties. The
Company is not aware of any material environmental legal proceedings pending
against it or any material environmental liabilities to which it may be subject.
Risks Associated with Business Activities
The nature of the business activities conducted by the Company subjects
it to certain hazards and risks. The following is a summary of some of the
material risks relating to the Company's business activities.
Commodity prices. The Company's revenues, profitability, cash flow and
future rate of growth are highly dependent on prices of oil and gas, which are
affected by numerous factors beyond the Company's control. Oil and gas prices
historically have been very volatile. Commodity prices were favorable during
2000 and the first quarter of 2001, but have since trended downwards. A
significant downward trend in commodity prices, comparable to the commodity
prices experienced in 1998, would have a material adverse effect on the
Company's revenues, profitability and cash flow and could, under certain
circumstances, result in a reduction in the carrying value of the Company's oil
and gas properties and an increase in the Company's deferred tax asset valuation
allowance.
Drilling activities. Drilling involves numerous risks, including the risk
that no commercially productive oil or gas reservoirs will be encountered. The
cost of drilling, completing and operating wells is often uncertain and drilling
operations may be curtailed, delayed or canceled as a result of a variety of
factors, including unexpected drilling conditions, pressure or irregularities in
formations, equipment failures or accidents, adverse weather conditions and
shortages or delays in the delivery of equipment. The Company's future drilling
activities may not be successful and, if unsuccessful, such failure could have
an adverse effect on the Company's future results of operations and financial
condition. While all drilling, whether developmental or exploratory, involves
these risks, exploratory drilling involves greater risks of dry holes or failure
to find commercial quantities of hydrocarbons. Because of the percentage of the
Company's capital budget devoted to higher risk exploratory projects, it is
likely that the Company will continue to experience exploration and abandonment
expense.
11
Unproved properties. At December 31, 2001 and 2000, the Company carried
unproved property costs of $187.8 million and $229.2 million, respectively.
United States generally accepted accounting principles require periodic
evaluation of these costs on a project-by-project basis in comparison to their
estimated value. These evaluations will be affected by the results of
exploration activities, commodity price outlooks, planned future sales or
expiration of all or a portion of the leases, contracts and permits appurtenant
to such projects. If the quantity of potential reserves determined by such
evaluations is not sufficient to fully recover the cost invested in each
project, the Company will recognize noncash charges in the earnings of future
periods. During 1999 the Company recognized an impairment provision of $17.9
million to reduce the carrying value of certain of its East Texas unproved gas
properties (see Note L of Notes to Consolidated Financial Statements included in
"Item 8. Financial Statements and Supplementary Data").
Acquisitions. Acquisitions of producing oil and gas properties have been
a key element of the Company's growth. The Company's growth following the full
development of its existing property base could be impeded if it is unable to
acquire additional oil and gas properties on a profitable basis. The success of
any acquisition will depend on a number of factors, including the ability to
estimate accurately the recoverable volumes of reserves, rates of future
production and future net revenues attainable from the reserves and to assess
possible environmental liabilities. All of these factors affect whether an
acquisition will ultimately generate cash flows sufficient to provide a suitable
return on investment. Even though the Company performs a review of the
properties it seeks to acquire that it believes is consistent with industry
practices, such reviews are often limited in scope.
Divestitures. The Company regularly reviews its property base for the
purpose of identifying non-strategic assets, the disposition of which would
increase capital resources available for other activities and create
organizational and operational efficiencies. Various factors could materially
affect the ability of the Company to dispose of non-strategic assets, including
the availability of purchasers willing to purchase the non-strategic assets at
prices acceptable to the Company.
Operation of natural gas processing plants. As of December 31, 2001, the
Company owns interests in nine natural gas processing plants and four treating
facilities. The Company operates six of the plants and all four treating
facilities. There are significant risks associated with the operation of natural
gas processing plants. Gas and NGLs are volatile and explosive and may include
carcinogens. Damage to or misoperation of a natural gas processing plant or
facility could result in an explosion or the discharge of toxic gases, which
could result in significant damage claims in addition to interrupting a revenue
source.
Operating hazards and uninsured losses. The Company's operations are
subject to all the risks normally incident to the oil and gas exploration and
production business, including blowouts, cratering, explosions and pollution and
other environmental damage, any of which could result in substantial losses to
the Company due to injury or loss of life, damage to or destruction of wells,
production facilities or other property, clean-up responsibilities, regulatory
investigations and penalties and suspension of operations. Although the Company
currently maintains insurance coverage that it considers reasonable and that is
similar to that maintained by comparable companies in the oil and gas industry,
it is not fully insured against certain of these risks, either because such
insurance is not available or because of high premium costs.
Environmental. The oil and gas business is subject to environmental
hazards, such as oil spills, gas leaks and ruptures and discharges of toxic
substances or gases that could expose the Company to substantial liability due
to pollution and other environmental damage. A variety of federal, state and
foreign laws and regulations govern the environmental aspects of the oil and gas
business. Noncompliance with these laws and regulations may subject the Company
to penalties, damages or other liabilities, and compliance may increase the cost
of the Company's operations. Such laws and regulations may also affect the costs
of acquisitions. See "Item 1. Business - Competition, Markets and Regulation -
Environmental and health controls".
The Company does not believe that its environmental risks are materially
different from those of comparable companies in the oil and gas industry.
Nevertheless, no assurance can be given that future environmental laws will not
result in a curtailment of production or processing or a material increase in
the costs of production, development, exploration or processing or otherwise
adversely affect the Company's operations and financial condition. Pollution and
similar environmental risks generally are not fully insurable.
12
Debt restrictions and availability. The Company is a borrower under fixed
term senior notes and a line of credit. The terms of the Company's borrowings
under the senior notes and the line of credit specify scheduled debt repayments
and require the Company to comply with certain associated covenants and
restrictions. The Company's ability to comply with the debt repayment terms,
associated covenants and restrictions is dependent on, among other things,
factors outside the Company's direct control, such as commodity prices, interest
rates and competition for available debt financing. See Note D of Notes to
Consolidated Financial Statements included in "Item 8. Financial Statements and
Supplementary Data" for information regarding the Company's outstanding debt and
the terms associated therewith.
Competition. The oil and gas industry is highly competitive. The Company
competes with other companies, producers and operators for acquisitions and in
the exploration, development, production and marketing of oil and gas. Some of
these competitors have substantially greater financial and other resources than
the Company. See "Item 1. Business - Competition, Markets and Regulation".
Government regulation. The Company's business is regulated by a variety
of federal, state, local and foreign laws and regulations. There can be no
assurance that present or future regulations will not adversely affect the
Company's business and operations. See "Item 1. Business - Competition, Markets
and Regulation".
International operations. At December 31, 2001, approximately 22 percent
of the Company's proved reserves of oil, NGLs and gas were located outside the
United States (17 percent in Argentina, four percent in Canada and one percent
in South Africa). The success and profitability of international operations may
be adversely affected by risks associated with international activities,
including economic and labor conditions, political instability, tax laws
(including host-country export, excise and income taxes and United States taxes
on foreign subsidiaries) and changes in the value of the U.S. dollar versus the
local currencies in which oil and gas producing activities may be denominated.
To the extent that the Company is involved in international activities, changes
in exchange rates can adversely affect the Company's future consolidated
financial position, results of operations and liquidity. See Critical Accounting
Policies included in "Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations" and Note B of Notes to Consolidated
Financial Statements included in "Item 8. Financial Statements and Supplementary
Data" for information specific to Argentina's economic and political situation.
Estimates of reserves and future net revenues. Numerous uncertainties
exist in estimating quantities of proved reserves and future net revenues
therefrom. The estimates of proved reserves and related future net revenues set
forth in this Report are based on various assumptions, which may ultimately
prove to be inaccurate. Therefore, such estimates should not be construed as
accurate estimates of the current market value of the Company's proved reserves.
ITEM 2. PROPERTIES
The information included in this Report about the Company's oil, NGL and
gas reserves as of December 31, 2001, 2000 and 1999, including Standardized
Measure, is based on proved reserves as determined by the Company's engineers.
Numerous uncertainties exist in estimating quantities of proved reserves
and in projecting future rates of production and timing of development
expenditures, including many factors beyond the Company's control. This Report
contains estimates of the Company's proved oil and gas reserves and the related
future net revenues, which are based on various assumptions, including those
prescribed by the SEC. Actual future production, oil and gas prices, revenues,
taxes, capital expenditures, operating expenses, geologic success and quantities
of recoverable oil and gas reserves may vary substantially from those assumed in
the estimates and could materially affect the estimated quantities and related
Standardized Measure of proved reserves set forth in this Report. In addition,
the Company's reserves may be subject to downward or upward revisions based on
production performance, purchases or sales of properties, results of future
development, prevailing oil and gas prices and other factors. Therefore,
estimates of the Standardized Measure of proved reserves should not be construed
as accurate estimates of the current market value of the Company's proved
reserves.
Standardized Measure is a reporting convention that provides a common
basis for comparing oil and gas companies subject to the rules and regulations
of the SEC. It requires the use of oil and gas spot prices prevailing as of the
13
date of computation. Consequently, it may not reflect the prices ordinarily
received or that will be received for oil and gas because of seasonal price
fluctuations or other varying market conditions. Standardized Measures as of any
date are not necessarily indicative of future results of operations.
Accordingly, estimates included herein of future net revenues may be materially
different from the net revenues that are ultimately received.
The Company did not provide estimates of total proved oil and gas
reserves during 2001, 2000 or 1999 to any federal authority or agency, other
than the SEC.
Proved Reserves
The Company's proved reserves totaled 671.4 million BOE at December 31,
2001, 628.2 million BOE at December 31, 2000 and 605.5 million BOE at December
31, 1999, representing $2.5 billion, $5.6 billion and $2.9 billion,
respectively, of Standardized Measure. The seven percent increase in proved
reserve volumes during 2001 was primarily attributable to the Company's
successful capital investments, while the 56 percent decrease in Standardized
Measure during 2001 was primarily due to decreases in commodity prices. The four
percent increase in proved reserve volumes in 2000 was primarily attributable to
the Company's successful capital investments, while the 93 percent increase in
Standardized Measure during 2000 was primarily due to increases in commodity
prices.
On a BOE basis, 70 percent of the Company's total proved reserves at
December 31, 2001 are proved developed reserves. Based on reserve information as
of December 31, 2001, and using the Company's reserve report production
information for 2002, the reserve-to-production ratio associated with the
Company's proved reserves is 14 years on a BOE basis. The following table
provides information regarding the Company's proved reserves and average daily
production by geographic area as of and for the year ended December 31, 2001.
PROVED OIL AND GAS RESERVES AND AVERAGE DAILY PRODUCTION
2001 Average
Proved Reserves as of December 31, 2001 Daily Production (a)
---------------------------------------------- -----------------------------
Oil Standardized Oil
& NGLs Gas Measure & NGLs Gas
(MBbls) (MMcf) MBOE (000) (Bbls) (Mcf) BOE
------- --------- -------- ------------ ------- -------- --------
United States......... 279,146 1,474,090 524,829 $ 1,965,129 43,456 212,629 78,894
Argentina............. 35,669 471,150 114,193 391,151 10,316 87,204 24,850
Canada................ 2,659 132,061 24,669 129,585 1,839 50,481 10,253
South Africa.......... 7,685 - 7,685 14,461 - - -
-------- --------- -------- ---------- ------- -------- --------
Total................. 325,159 2,077,301 671,376 $ 2,500,326 55,611 350,314 113,997
======== ========= ======== ========== ======= ======== ========
----------------
(a) The 2001 average daily production is calculated using a 365-day year and
without making pro forma adjustments for any acquisitions, divestitures or
drilling activity that occurred during the year.
Alternate Reserve Case
In addition to the proved reserve table above, the Company calculated an
alternative reserve case, as presented below, utilizing an assumed WTI Cushing,
Oklahoma spot oil price of $22.00 per Bbl and an assumed Henry Hub, Louisiana
spot gas price of $3.50 per Mcf as compared to the year-end proved reserve
calculation which used a WTI Cushing, Oklahoma spot oil price of $19.76 per Bbl
and a Henry Hub, Louisiana spot gas price of $2.73 per Mcf. The alternative
reserve case has all of the same assumptions as the proved reserve case at year
end, other than pricing.
14
Alternative Reserve Case as of December 31, 2001
------------------------------------------------
Alternate
Oil Standardized
& NGLs Gas Measure
(MBbls) (MMcf) MBOE (000)
------- --------- -------- ------------
United States......... 287,500 1,499,328 537,388 $ 2,616,332
Argentina............. 35,669 471,150 114,194 433,478
Canada................ 2,625 128,592 24,057 182,116
South Africa.......... 7,685 - 7,685 28,589
------- --------- -------- ----------
Total................. 333,479 2,099,070 683,324 $ 3,260,515
======= ========= ======== ==========
The alternative reserve case represents the minimum pricing assumptions
that the Company used to make investment decisions during 2001. Such investment
decisions required, among other items, a discounted return on investment greater
than 150 percent prior to approval.
In addition to the alternate reserve case above, the Company estimates
that the potential incremental value from other exploration and extension
opportunities on the Canyon Express, Devils Tower and Falcon deepwater Gulf of
Mexico discoveries and Sable discovery in South Africa to be as much as $285
million using the same alternate reserve case assumptions. The Company also
calculated an alternate discount rate for the Company's long-lived Spraberry,
Hugoton and West Panhandle fields. The Company estimates that the incremental
value of these long-lived reserves using an eight percent discount rate versus a
ten percent discount rate under the same alternate reserve case parameters is
approximately $165 million.
No assurance can be given that future commodity prices will be similar to
the prices utilized in the alternate reserve case since commodity prices have
historically been very volatile. Furthermore, oil and gas reserve quantity
estimates are subject to numerous uncertainties inherent in the estimation of
quantities of reserves and in the projection of future rates of production and
the timing of development expenditures. The accuracy of such estimates is a
function of the quality of available data and of engineering and geological
interpretation and judgment. Results of subsequent drilling, testing and
production may cause either upward or downward revision of previous estimates.
In addition, the volumes considered to be commercially recoverable fluctuate
with changes in prices and operating costs. The Company emphasizes that reserve
estimates are inherently imprecise and that estimates of undrilled prospects and
new discoveries are significantly more imprecise than those of currently
producing oil and gas properties. Accordingly, these estimates are expected to
change as additional information becomes available in the future.
The Company's stockholders and other users of this information should not
assume that the Alternate Standardized Measure is the current market value of
the Company's estimated reserves. The Company calculated the Alternate
Standardized Measure based on estimated reserves calculated using the price and
cost assumptions referred to above. Actual future prices and costs may be
materially higher or lower than the prices and costs as of the date of the
estimate. Additionally, the Alternate Standardized Measure does not include
estimates of the Company's future administrative expense or borrowing costs, the
incurrence of which are ordinary expenditures for the conduct of business.
Finding Cost and Reserve Replacement
The Company's acquisition and finding costs per BOE for 2001, 2000 and
1999 were $7.49, $4.66 and $2.21 per BOE, respectively. The average acquisition
and finding cost for the three-year period from 1999 to 2001 was $4.74 per BOE,
representing a 32 percent decrease over the 2000 three-year average rate of
$6.94 per BOE.
During 2001, the Company replaced 208 percent of its annual production on
a BOE basis (169 percent for oil and NGLs and 245 percent for gas). During 2000,
the Company replaced 167 percent of its annual production on a BOE basis (196
percent for oil and NGLs and 140 percent for gas). During 1999, the Company
replaced 178 percent of its annual production on a BOE basis (262 percent for
oil and NGLs and 99 percent for gas). The Company's 2001 reserve replacement
15
percentage was primarily impacted by asset purchases and new discoveries and
field extensions while the 2000 and 1999 reserve replacement percentages were
primarily impacted by changes in commodity prices.
Description of Properties
As of December 31, 2001, the Company has production, development and
exploration operations in the United States, Argentina, Canada and South Africa,
and exploration opportunities in Gabon and Tunisia.
Domestic. The Company's domestic operations are located in the Permian
Basin, Mid Continent, Gulf of Mexico and onshore Gulf Coast areas of the United
States. Approximately 81 percent of the Company's domestic proved reserves are
located in the Spraberry, Hugoton and West Panhandle fields. The mature
Spraberry, Hugoton and West Panhandle fields generate substantial operating cash
flow and have a portfolio of low risk infill drilling opportunities. The cash
flows generated from these fields provide funding for the Company's other
development and exploration activities both domestically and internationally.
During 2001, the Company expended $334.2 million in domestic acquisition,
exploration and development drilling activities. The Company has budgeted
approximately $260 million for domestic acquisition, exploration and development
drilling expenditures for 2002.
Spraberry field. The Spraberry field was discovered in 1949 and
encompasses eight counties in West Texas. The field is approximately 150 miles
long and 75 miles wide at its widest point. The oil produced is West Texas
Intermediate Sweet, and the gas produced is casinghead gas with an average
energy content of 1,400 Btu per Mcf. The oil and gas are produced from three
formations, the upper and lower Spraberry and the Dean, at depths ranging from
6,700 feet to 9,200 feet. The center of the Spraberry field was unitized in the
late 1950's and early 1960's by the major oil companies; however, until the late
1980's there was very limited development activity in the field. Since 1989, the
Company has focused its development drilling activities in the unitized portion
of the Spraberry field due to the dormant condition of the properties. The
Company believes the area offers excellent opportunities to enhance oil and gas
reserves because of the hundreds of undeveloped infill drilling locations, all
of which are reflected in the Company's proved undeveloped reserves, and the
ability to reduce operating expenses through economies of scale.
During 2001, the Company placed 131 Spraberry wells on production,
drilled one developmental dry hole and, at December 31, 2001, had 17 wells in
progress. The Company is continuing to evaluate its 2002 Spraberry drilling
program and has postponed the program until drilling costs align more favorably
with commodity prices.
Hugoton field. The Hugoton field in southwest Kansas is one of the
largest producing gas fields in the continental United States. The gas is
produced from the Chase and Council Grove formations at depths ranging from
2,700 feet to 3,000 feet. The Company's Hugoton properties represent
approximately 13 percent of the proved reserves in the field and are located on
approximately 257,000 gross acres (237,000 net acres), covering approximately
400 square miles. The Company has working interests in approximately 1,200 wells
in the Hugoton field, about 1,000 of which it operates, and partial royalty
interests in approximately 500 wells. The Company owns substantially all of the
gathering and processing facilities, primarily the Satanta plant, that service
its production from the Hugoton field. Such ownership allows the Company to
control the production, gathering, processing and sale of its gas and associated
NGLs.
Production in the Hugoton field is subject to allowables set by state
regulators, but the Company's Hugoton operated wells are capable of producing
approximately 106 MMcf of wet gas per day (i.e., gas production at the wellhead
before processing and before reduction for royalties). The Company estimates
that it and other major producers in the Hugoton field produced at or near
capacity in 2001. During 2001, the Company completed 12 development wells in the
Hugoton field. The Company does not plan to drill any Hugoton development wells
in 2002 given the recent downturn in gas prices.
The Company is evaluating the feasibility of infill drilling into the
Council Grove Formation and may submit an application to the Kansas Corporation
Commission to allow infill drilling. Such infill drilling may increase
production from the Company's Hugoton properties. However, until an application
has been approved, the Company will not reflect any of the infill drilling
locations as proved undeveloped reserves. There can be no assurance that the
application will be filed or approved, or as to the timing of such approval if
granted.
16
West Panhandle field. The West Panhandle properties are located in the
panhandle region of Texas where initial production commenced in 1918. These
stable, long-lived reserves are attributable to the Red Cave, Brown Dolomite,
Granite Wash and fractured Granite formations at depths no greater than 3,500
feet. The Company's gas in the West Panhandle field has an average energy
content of 1,300 Btu per Mcf and is produced from approximately 600 wells on
more than 241,000 gross (185,000 net) acres covering over 375 square miles. The
Company's wellhead gas produced from the West Panhandle field contains a high
quantity of NGLs, yielding relatively greater NGL volumes than realized from the
Company's 1,025 Btu per Mcf content wellhead gas in its Hugoton field. The
Company operates the wells, production equipment and, since May 2001, the
Colorado Interstate Gas Company - (a subsidiary of El Paso Energy Corp.) owned
gathering system. Production from the West Panhandle field is processed through
the Company-owned and operated Fain natural gas processing plant.
During 2001, the Company placed 29 new wells on production and had one
additional well in progress at December 31, 2001. The Company is evaluating its
plans for 2002 given the recent declines in oil and gas prices and has not
determined how many, if any, wells will be drilled in the West Panhandle field
during 2002.
Gulf of Mexico area. In the Gulf of Mexico, the Company is focused on
reserve and production growth through a portfolio of shelf and deepwater
development projects, high-impact, higher-risk deepwater exploration drilling,
shelf exploration drilling and exploitation opportunities inherent in the
properties the Company currently has producing on the shelf. To accomplish this,
the Company has devoted most of its domestic exploration efforts to these two
areas, as well as its investment in and utilization of 3-D seismic technology.
During 2001, the Company successfully drilled one development and four
exploratory wells in the deepwater Gulf of Mexico and four development and four
exploration wells on the shelf. The Company also drilled two exploratory dry
holes in the deepwater Gulf of Mexico and three exploratory dry holes on the
shelf during 2001 and had one shelf and two deepwater development wells and one
shelf and one deepwater exploration well in progress as of December 31, 2001.
In the deepwater Gulf of Mexico, the Company has sanctioned three major
development projects that are in progress at December 31, 2001:
o Canyon Express - The TotalFinaElf-operated Aconcagua and the
Marathon-operated Camden Hills discoveries in Mississippi Canyon are being
jointly developed as part of the Canyon Express gas project. Facilities
construction and well completions are underway and installation is
in-progress for the TotalFinaElf-operated Canyon Express subsea gathering
system with production scheduled to begin during July 2002. Wells will be
brought on sequentially and are expected to achieve a peak rate of
approximately 110 MMcf of gas per day and 180 Bbls of condensate per day
net to the Company. During the fourth quarter of 2001, the Company acquired
an incremental 12.5 percent interest in the Aconcagua field and a 5.5
percent interest in the Canyon Express subsea gathering system for $25.5
million. The Company's ownership positions in this project are now
comprised of a 23.5 percent equity interest in the Canyon Express subsea
gathering system, a 37.5 percent working interest in Aconcagua and a 33
percent working interest in Camden Hills.
o Devils Tower - At the Dominion-operated Devils Tower development project in
Mississippi Canyon, the Company successfully drilled two wells to explore
for new reserves in previously undrilled reservoirs and to further extend
the previously tested zones. During 2001, the project was sanctioned as a
spar development project with the owners leasing a spar from a third party
for the life of the field. Construction of the spar is underway, two
development wells and one extension well were in progress as of December
31, 2001, and production is anticipated to begin during the second quarter
of 2003. One additional development well will be drilled during 2002. The
wells will be brought on sequentially with peak production expected to
reach 8,000 to 10,000 BOEs per day net to the Company's 25 percent working
interest.
o Falcon - The Mariner-operated Falcon project, which was recently
sanctioned, was successfully drilled and sidetracked during 2001. The
Company owns a 45 percent working interest in this discovery and was the
successful bidder on 21 deepwater Gulf of Mexico blocks, 12 of which are
near the Falcon discovery that the Company shares with its partner,
Mariner. Two additional development wells are planned for Falcon during
2002. Initial production from Falcon is anticipated during the first
quarter of 2003 at expected rates of 79 MMcf of gas per day and 220 Bbls of
condensate per day net to the Company's interest.
17
In addition to the development projects described above in the deepwater
Gulf of Mexico, the Company drilled the Dominion-operated Turnberry prospect
during 2001. The well encountered hydrocarbon bearing sands; however, sidetrack
operations on the Turnberry discovery were unsuccessful and evaluations of the
initial wellbore using a 3-D seismic survey are in progress to determine if the
discovery has commercial quantities of hydrocarbons. If commercial quantities of
hydrocarbons cannot be confirmed during the first quarter of 2002, the Company
will recognize a $9.3 million charge to exploration and abandonments for the
costs of the initial exploratory well. The Company also drilled its Argo
prospect during 2001 which was unsuccessful.
During the fourth quarter of 2001, the Company participated in the
drilling of the Marathon-operated Ozona Deep prospect that was successfully
drilled. The well encountered approximately 345 feet of net oil pay in two
intervals and one or two appraisal wells are planned for Ozona Deep in the first
half of 2002. In addition to the development projects discussed above and Ozona
Deep, the Company plans to drill one or two additional exploratory wells in the
deepwater Gulf of Mexico during 2002.
On the Gulf of Mexico shelf, the Company participated in drilling five
prospects during 2001 in addition to initiating an extensive production
optimization program at the Company's Inland Bay fields in south Louisiana.
First, the Texaco-operated Cyrus prospect was sanctioned during 2001 and
development plans are underway with production expected to commence during the
fourth quarter of 2002 at expected initial rates of 2.3 MMcf of gas per day and
360 Bbls of condensate per day net to the Company's 5.7 percent working
interest. Second, the Aviara-operated Oneida prospect was successfully drilled
and is currently being completed. Initial production is anticipated during the
second quarter of 2002 at expected rates of 1.1 MMcf of gas per day and 30 Bbls
of condensate per day net to the Company's 13.7 percent working interest. Third,
the Company participated in the Spinnaker-operated Stirrup prospect during 2001,
in which the Company owns a 25 percent working interest. An initial discovery
well was drilled and tested at gross rates over 21 MMcf of gas per day and 130
Bbls of condensate per day. A second and third well were successfully drilled
and platform construction, as well as completion operations, have commenced. The
Company anticipates first production in April 2002 at expected initial rates of
2.7 MMcf of gas per day and 20 Bbls of condensate per day net to the Company's
interest. Finally, the Company drilled its Cruiser and Malta prospects during
2001 that were plugged and abandoned since commercial quantities of hydrocarbons
were not present.
The Company has also initiated an effort to reevaluate all of its current
producing properties on the shelf to determine if there are additional
recompletion opportunities or development or exploration drilling opportunities
on those properties. The Company drilled an exploratory dry hole in one of its
Inland Bay fields and has initiated workover and recompletion programs in these
fields. The Company has been applying new technology to the fields in an attempt
to identify untapped potential in the multiple pay zones of these fields that
may have been missed over the years. Results in the program have been
encouraging with a production increase of approximately 1,500 BOE per day having
been achieved during 2001. The program will be continued during 2002, but to a
lesser extent, given lower commodity prices. In addition to this project, the
Company plans to drill a limited number of exploratory prospects on the shelf
during 2002.
Onshore Gulf Coast area. The Company has focused its drilling efforts in
this area on the Pawnee field in the Edwards Reef trend in South Texas. The
Company drilled eight development wells at Pawnee during 2001 and plans to drill
three more in the first quarter of 2002. Since the Company began this successful
program, net production has more than tripled, increasing from 11 MMcf per day
at the end of 1999 to 37 MMcf per day at the end of 2001. The Company is also
continuing its development drilling in East Texas and is drilling an exploration
well in North Louisiana. Activities in these areas will be scaled back during
2002 given the lower commodity price environment.
International. The Company's international operations are located in the
Neuquen and Austral Basins areas of Argentina and the Chinchaga, Martin Creek
and Lookout Butte areas of Canada. Additionally, the Company's fourth
significant development project, the Sable oil field located in shallow water
offshore South Africa, is scheduled for first production in early 2003. The
Company has also entered into agreements to explore for oil and gas reserves in
South Africa, Gabon and Tunisia. As of December 31, 2001, approximately 17
percent, four percent and one percent of the Company's proved reserves are
located in Argentina, Canada and South Africa, respectively.
18
Argentina. The Company's share of Argentine production during 2001
averaged 24.9 MBOE per day, or approximately 22 percent of the Company's
equivalent production. The Company's operated production in Argentina is
concentrated in the Neuquen Basin which is located about 925 miles southwest of
Buenos Aires and just to the east of the Andes Mountains. Oil and gas are
produced primarily from the Loma Negra/NI Block, the Neuquen del Medio Block,
the Al Sur de la Dorsal Block and the Estacion Fernandez Oro Block, in each of
which the Company has a 100 percent working interest. During 2001, the Company
acquired a 100 percent working interest in the Anticlinal Campamento producing
field as well as two exploration blocks, Cerro Vagon and Dos Hermanas. The
Company also increased its interest in the La Calera and Bajo Baguales
exploration blocks during 2001.
The production concession in the Austral Basin is located in Tierra del
Fuego, which is an island in the extreme southern portion of Argentina,
approximately 1,500 miles south of Buenos Aires. Oil, gas and NGLs are produced
from six separate fields in which the Company has a 35 percent working interest.
Currently, production is being sent to the mainland through oil tankers and gas
pipelines and exported to Chile through pipelines. Also in the Austral Basin is
the Company-operated Lago Fuego Block, which started operations during 2001.
Production from this block is mainly gas and NGLs which are sold to the city of
Ushuaia and other local markets. The Company holds a 50 percent working interest
in the Lago Fuego Block.
During 2001, the Company expended $98.1 million on Argentine acquisition,
exploration and development activities and drilled 20 development wells and 42
extension/exploratory wells in Argentina, of which 19 development wells and 26
extension/exploratory wells were successful. The Company plans to spend
approximately $15 million in Argentina during 2002 to principally complete
construction of its Loma Negra gas plant. Other significant capital projects
have been suspended at this time due to the economic instability in Argentina
and the resulting devaluation of the Argentine peso.
Canada. The Company's Canadian producing properties are located primarily
in Alberta and British Columbia, Canada. Production during 2001 averaged 10.3
MBOE per day, or approximately nine percent of the Company's equivalent
production. The Company continues to focus its development, exploration and
acquisition activities in the core areas of northeast British Columbia and
southwest Alberta. The Canadian assets are geographically concentrated,
predominantly shallow gas and more than 95 percent operated by the Company in
the following areas: Chinchaga, Martin Creek and Lookout Butte.
Production from the Chinchaga area in northeast British Columbia is
relatively dry gas from formation depths averaging 3,400 feet. In the Martin
Creek area of British Columbia, production is relatively dry gas from various
reservoirs ranging from 3,700 feet to 4,300 feet. The Lookout Butte area in
southwest Alberta produces gas and condensate from the Mississippian Turner
Valley formation at approximately 12,000 feet. The Company sold its interest in
the Rycroft/Spirit River area waterflood in northwest Alberta in December 2001
for approximately $12.0 million.
During 2001, the Company expended $37.5 million on Canadian exploration
and development activities and drilled 26 development wells and 25 exploratory
wells primarily in the Chinchaga and Martin Creek areas, of which 24 development
wells and 12 exploratory wells were successful. Most of these wells were drilled
during the first quarter as these areas are only accessible for drilling during
the winter months. The Company, as operator, plans to drill approximately 19
wells and expand facility and compressor capacity to 50 MMcf of gas per day at
the Company-owned Chinchaga plant during 2002. The Company expects to
participate in an additional four wells operated by another company in the same
area. The Company plans to spend approximately $25 million on oil and gas
development and exploration opportunities in Canada during 2002.
Africa. In Africa, the Company has entered into agreements to explore for
oil and gas in South Africa, Gabon and Tunisia. The South African agreements
cover over 13 million acres along the southern coast of South Africa, generally
in water depths less than 650 feet. The Gabon agreement covers over 314,000
acres off the coast of Gabon, generally in water depths less than 100 feet. The
Tunisian agreements can be separated into two categories. The first includes
three permits covering 2.7 million acres onshore southern Tunisia which the
Company operates with a 50 percent working interest. The second includes the
Anadarko-operated Anaguid permit covering 1.1 million acres onshore southern
Tunisia in which the Company has a 30 percent working interest. During 2001, the
Company expended $59.9 million of acquisition, development and exploration
drilling and seismic capital in South Africa, Gabon and Tunisia. The Company
19
drilled four exploratory wells in South Africa during 2001, of which two were
successful. In addition, a successful exploratory well was drilled off the coast
of Gabon and a dry hole was drilled in Tunisia.
South Africa. In South Africa, the Company spent $39.3 million of
drilling and seismic capital to drill two wells on its Company-operated
Boomslang prospect, in which the Company has a 49 percent working interest,
drill a gas appraisal well on the Soekor-operated E-BB tract, in which the
Company has a 40 percent working interest, and acquire two 3-D seismic surveys.
The initial Boomslang well was successful while the appraisal well was
unsuccessful. One of the two seismic surveys was acquired over the Boomslang
trend area where several other prospects have been identified. The Company will
continue to evaluate the commercial feasibility of the Boomslang prospect using
this new 3-D data. In addition, the Company drilled and tested the E-BB2 gas
well in the center of the Bredasdorp Basin. Results of this well and other wells
drilled in this trend are being assessed as part of a larger gas development
project that is currently being evaluated. The Company also acquired a 3-D
seismic survey in the Port Elizabeth Trough Area of Block 14 during 2001. During
2002, the seismic data acquired in 2001 will be analyzed and the results from
the aforementioned exploration activities will continue to be evaluated. The
Company currently plans to drill two exploration wells during 2002.
During 2002, the Company plans to complete its Sable development project
in South Africa with production anticipated to begin in early 2003. Development
drilling is underway, floating production facility upgrades are in progress and
subsea trees are being manufactured. Production for the first year is expected
to average approximately 11,600 Bbls of oil per day net to the Company's 40
percent working interest.
Gabon. In Gabon, the Company spent $11.4 million of drilling and seismic
capital to drill and test the initial exploratory well on its Bigorneau South
prospect, located offshore in the Southern Gabon Basin on its Olowi permit.
Pioneer is the operator of the permit with a 100 percent working interest. The
Company has entered its application to enter the Second Exploration Period on
the Olowi Permit, which requires two additional exploratory wells to be drilled
over a two-year period. Seismic evaluations continue on this discovery and the
Company plans to drill two exploration wells and one appraisal well during 2002.
Tunisia. Plans for Tunisia in 2002 include a 3-D seismic survey to be
shot over the three operated permits as well as a seismic survey in the
Anadarko-operated Anaguid permit. Based on the results and interpretation of
such seismic surveys, the Company expects to drill two to three wells in Tunisia
during 2002.
Selected Oil and Gas Information
The following tables set forth selected oil and gas information for the
Company as of and for each of the years ended December 31, 2001, 2000 and 1999.
Because of normal production declines, increased or decreased drilling
activities and the effects of past and future acquisitions or divestitures, the
historical information presented below should not be interpreted as indicative
of future results.
20
Production, price and cost data. The following table sets forth
production, price and cost data with respect to the Company's properties for the
years ended December 31, 2001, 2000 and 1999.
PRODUCTION, PRICE AND COST DATA (a)
Year Ended December 31,
---------------------------------------------------------------------------------------------------------------
2001 2000 1999
------------------------------------ ------------------------------------ -----------------------------------
United United United
States Argentina Canada Total States Argentina Canada Total States Argentina Canada Total
------- --------- ------ ------- ------- --------- ------ ------- ------- --------- ------ -------
Production information:
Annual production:
Oil (MBbls).... 8,629 3,566 303 12,498 8,989 3,238 308 12,535 11,448 2,352 1,654 15,454
NGLs (MBbls)... 7,232 200 368 7,800 7,883 193 303 8,379 8,714 217 306 9,237
Gas (MMcf)..... 77,609 31,830 18,426 127,865 83,930 35,695 16,219 135,844 106,094 34,477 17,886 158,457
Total (MBOE)... 28,796 9,071 3,742 41,609 30,861 9,380 3,314 43,555 37,845 8,315 4,941 51,101
Average daily production:
Oil (Bbls)..... 23,641 9,769 831 34,241 24,561 8,847 841 34,249 31,366 6,443 4,530 42,339
NGLs (Bbls).... 19,815 547 1,008 21,370 21,538 527 829 22,894 23,875 594 839 25,308
Gas (Mcf)...... 212,629 87,204 50,481 350,314 229,316 97,526 44,315 371,157 290,670 94,457 49,003 434,130
Total (BOE).... 78,894 24,851 10,253 113,997 84,318 25,628 9,056 119,002 103,686 22,780 13,536 140,002
Average prices, including hedge results:
Oil (per Bbl).. $ 24.34 $ 23.79 $21.87 $ 24.12 $ 22.07 $29.09 $ 27.50 $ 24.01 $ 15.03 $18.41 $13.28 $ 15.36
NGLs (per Bbl). $ 16.88 $ 19.29 $21.11 $ 17.14 $ 20.05 $22.91 $ 24.32 $ 20.27 $ 11.61 $11.30 $12.62 $ 11.64
Gas (per Mcf).. $ 4.10 $ 1.31 $ 2.86 $ 3.23 $ 3.50 $ 1.19 $ 2.88 $ 2.81 $ 2.17 $ 1.10 $ 1.82 $ 1.90
Revenue (per BOE)$ 22.56 $ 14.36 $17.94 $ 20.36 $ 21.04 $15.03 $ 18.85 $ 19.58 $ 13.28 $10.07 $11.81 $ 12.62
Average prices, excluding hedge results:
Oil (per Bbl).. $ 24.56 $ 22.40 $21.87 $ 23.88 $ 28.76 $29.09 $ 27.50 $ 28.81 $ 16.20 $18.41 $13.28 $ 16.23
NGLs (per Bbl). $ 16.88 $ 19.29 $21.11 $ 17.14 $ 20.05 $22.91 $ 24.32 $ 20.27 $ 11.61 $11.30 $12.62 $ 11.64
Gas (per Mcf).. $ 3.96 $ 1.31 $ 3.27 $ 3.20 $ 3.73 $ 1.19 $ 3.45 $ 3.03 $ 2.07 $ 1.10 $ 1.84 $ 1.84
Revenue (per BOE)$ 22.26 $ 13.81 $19.95 $ 20.21 $ 23.63 $15.03 $ 21.65 $ 21.63 $ 13.37 $10.07 $11.90 $ 12.69
Average costs:
Production costs (per BOE):
Lease operating $ 2.76 $ 2.64 $ 3.01 $ 2.76 $ 2.45 $ 2.30 $ 2.53 $ 2.42 $ 2.02 $ 2.04 $ 3.02 $ 2.11
Taxes:
Production... .98 .28 - .74 .99 .30 - .77 .49 .16 - .39
Ad valorem... .71 - - .49 .41 - - .29 .41 - - .31
Field fuel..... 1.27 - - .88 1.01 - - .71 .28 - - .21
Workover....... .20 .01 .32 .17 .17 - .42 .15 .09 - .34 .10
----- ----- ---- ----- ----- ---- ----- ----- ----- ----- ---- -----
Total....... $ 5.92 $ 2.93 $ 3.33 $ 5.04 $ 5.03 $ 2.60 $ 2.95 $ 4.34 $ 3.29 $ 2.20 $ 3.36 $ 3.12
Depletion expense
(per BOE)..... $ 4.46 $ 5.67 $ 7.71 $ 5.02 $ 3.95 $ 5.56 $ 7.58 $ 4.57 $ 4.06 $ 4.68 $ 5.18 $ 4.27
---------------
(a) These amounts represent the Company's historical results from operations
without making pro forma adjustments for any acquisitions, divestitures or
drilling activity that occurred during the respective years.
21
Productive wells. The following table sets forth the number of productive
oil and gas wells attributable to the Company's properties as of December 31,
2001, 2000 and 1999.
PRODUCTIVE WELLS (a)
Gross Productive Wells Net Productive Wells
------------------------ ------------------------
Oil Gas Total Oil Gas Total
------ ------ ------ ------ ------ ------
As of December 31, 2001:
United States............... 3,485 1,931 5,416 2,116 1,613 3,729
Argentina................... 669 162 831 454 132 586
Canada...................... 4 299 303 3 240 243
------ ------ ------ ------ ------ ------
Total.................... 4,158 2,392 6,550 2,573 1,985 4,558
====== ====== ====== ====== ====== ======
As of December 31, 2000:
United States............... 3,577 1,847 5,424 2,166 1,550 3,716
Argentina................... 575 211 786 434 154 588
Canada...................... 95 234 329 45 175 220
------ ------ ------ ------ ------ ------
Total.................... 4,247 2,292 6,539 2,645 1,879 4,524
====== ====== ====== ====== ====== ======
As of December 31, 1999:
United States............... 3,835 2,244 6,079 2,558 1,736 4,294
Argentina................... 514 199 713 376 142 518
Canada...................... 157 196 353 66 135 201
------ ------ ------ ------ ------ ------
Total.................... 4,506 2,639 7,145 3,000 2,013 5,013
====== ====== ====== ====== ====== ======
---------------
(a) Productive wells consist of producing wells and wells capable of
production, including shut-in wells. One or more completions in the same
well bore are counted as one well. Any well in which one of the multiple
completions is an oil completion is classified as an oil well. As of
December 31, 2001, the Company owned interests in 76 gross wells containing
multiple completions.
Leasehold acreage. The following table sets forth information about the
Company's developed, undeveloped and royalty leasehold acreage as of December
31, 2001.
LEASEHOLD ACREAGE
Developed Acreage Undeveloped Acreage
------------------------ ------------------------- Royalty
Gross Acres Net Acres Gross Acres Net Acres Acreage
----------- --------- ----------- ---------- ---------
As of December 31, 2001:
United States................ 914,114 720,189 818,715 655,332 219,130
Argentina.................... 674,000 278,000 1,154,000 991,000 -
Canada....................... 153,000 110,000 350,000 252,000 -
South Africa................. 9,600 3,840 13,625,400 12,266,160 -
Gabon........................ - - 313,937 313,937 -
Tunisia...................... - - 4,083,072 1,806,013 -
---------- ---------- ----------- ---------- --------
Total..................... 1,750,714 1,112,029 20,345,124 16,284,442 219,130
========== ========== =========== ========== ========
Drilling activities. The following table sets forth the number of gross
and net productive and dry wells in which the Company had an interest that were
drilled during the years ended December 31, 2001, 2000 and 1999. This
information should not be considered indicative of future performance, nor
should it be assumed that there is necessarily any correlation between the
number of productive wells drilled and the oil and gas reserves generated
thereby or the costs to the Company of productive wells compared to the costs of
dry wells.
22
DRILLING ACTIVITIES
Gross Wells Net Wells
------------------------- -------------------------
Year Ended December 31, Year Ended December 31,
------------------------- -------------------------
2001 2000 1999 2001 2000 1999
----- ----- ----- ----- ----- -----
United States:
Productive wells:
Development................... 228 159 199 114.6 91.3 131.3
Exploratory................... 20 11 7 11.0 4.7 4.6
Dry holes:
Development................... 15 3 1 14.6 1.9 .8
Exploratory................... 8 3 7 5.1 1.6 2.7
----- ----- ----- ----- ----- -----
271 176 214 145.3 99.5 139.4
----- ----- ----- ----- ----- -----
Argentina:
Productive wells:
Development................... 19 28 19 17.7 26.7 16.6
Exploratory................... 26 38 25 25.5 37.6 24.1
Dry holes:
Development................... 1 2 3 1.0 2.0 3.0
Exploratory................... 16 16 8 14.0 14.5 6.5
----- ----- ----- ----- ----- -----
62 84 55 58.2 80.8 50.2
----- ----- ----- ----- ----- -----
Canada:
Productive wells:
Development................... 24 17 34 20.3 17.9 18.8
Exploratory................... 12 12 - 10.2 9.9 -
Dry holes:
Development................... 2 4 - 2.0 2.5 -
Exploratory................... 13 2 1 11.8 1.9 .3
----- ----- ----- ----- ----- -----
51 35 35 44.3 32.2 19.1
----- ----- ----- ----- ----- -----
Other foreign:
Productive wells:
Development................... - - - - - -
Exploratory................... 3 - - 2.4 - -
Dry holes:
Development................... - - - - - -
Exploratory................... 3 1 - 1.9 1.0 -
----- ----- ----- ----- ----- -----
6 1 - 4.3 1.0 -
----- ----- ----- ----- ----- -----
Total......................... 390 296 304 252.1 213.5 208.7
===== ===== ===== ===== ===== =====
Success ratio (a)................. 85% 90% 93% 80% 88% 94%
---------------
(a) Represents those wells that were successfully completed as producing wells
or wells capable of producing.
The following table sets forth information about the Company's wells that
were in progress at December 31, 2001.
Gross Wells Net Wells
----------- ---------
United States:
Development..................................... 21 1.6
Exploratory..................................... 3 1.2
----- ------
24 2.8
----- ------
Argentina:
Development..................................... 1 1.0
Exploratory..................................... 3 3.0
----- ------
4 4.0
----- ------
Canada:
Development..................................... 5 5.0
Exploratory..................................... 1 1.0
----- ------
6 6.0
----- ------
Total........................................ 34 12.8
===== ======
23
ITEM 3. LEGAL PROCEEDINGS
The Company is party to various legal proceedings, which are described
under "Legal actions" in Note G of Notes to Consolidated Financial Statements
included in "Item 8. Financial Statements and Supplementary Data". The Company
is also party to other litigation incidental to its business. The claims for
damages from such other legal actions are not in excess of 10 percent of the
Company's current assets and the Company believes none of these actions to be
material.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
The Company did not submit any matters to a vote of security holders
during the fourth quarter of 2001.
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON STOCK AND RELATED STOCKHOLDER
MATTERS
The Company's common stock is listed and traded on the New York Stock
Exchange and the Toronto Stock Exchange under the symbol "PXD". The following
table sets forth, for the periods indicated, the high and low sales prices for
the Company's common stock, as reported in the New York Stock Exchange composite
transactions. The Company's $575 million credit agreement restricts the Company
from paying or declaring dividends on common stock and certain other payments in
excess of an aggregate $50 million annually. The Company's Board of Directors
did not declare dividends to the holders of the Company's common stock during
2001 or 2000.
High Low
--------- ---------
2001
Fourth quarter................................. $ 19.70 $ 13.22
Third quarter.................................. $ 19.38 $ 12.62
Second quarter................................. $ 23.05 $ 14.30
First quarter.................................. $ 20.24 $ 15.45
2000
Fourth quarter................................. $ 20.63 $ 12.44
Third quarter.................................. $ 16.06 $ 10.63
Second quarter................................. $ 15.63 $ 9.00
First quarter.................................. $ 10.75 $ 6.75
On February 25, 2002, the last reported sales price of the Company's
common stock, as reported in the New York Stock Exchange composite transactions,
was $19.49 per share.
As of February 25, 2002, the Company's common stock was held by
approximately 38,866 holders of record.
24
ITEM 6. SELECTED FINANCIAL DATA
The following selected consolidated financial data for the Company should
be read in conjunction with "Item 7. Management's Discussion and Analysis of
Financial Condition and Results of Operations" and "Item 8. Financial Statements
and Supplementary Data".
Year Ended December 31,
-----------------------------------------------------
2001 2000 1999 1998 1997 (a)
-------- -------- -------- -------- ---------
(in millions, except per share data)
Statement of Operations Data:
Revenues:
Oil and gas................................ $ 847.0 $ 852.7 $ 644.6 $ 711.5 $ 536.8
Interest and other (b)..................... 21.8 25.8 89.7 10.4 4.3
Gain (loss) on disposition of assets, net.. 7.7 34.2 (24.2) (.4) 4.9
------- ------ ------- ------- --------
876.5 912.7 710.1 721.5 546.0
------- ------ ------- ------- --------
Costs and expenses:
Oil and gas production..................... 209.7 189.3 159.5 223.5 144.2
Depletion, depreciation and amortization... 222.6 214.9 236.1 337.3 212.4
Impairment of properties and facilities.... - - 17.9 459.5 1,356.4
Exploration and abandonments............... 127.9 87.5 66.0 121.9 77.2
General and administrative................. 37.0 33.3 40.2 82.6 48.8
Reorganization............................. - - 8.5 33.2 -
Interest................................... 131.9 162.0 170.3 164.3 77.5
Other (c).................................. 39.6 67.2 34.7 30.0 7.1
------- ------ ------- ------- --------
768.7 754.2 733.2 1,452.3 1,923.6
------- ------ ------- ------- --------
Income (loss) before income taxes and
extraordinary items........................ 107.8 158.5 (23.1) (730.8) (1,377.6)
Income tax benefit (provision)............... (4.0) 6.0 .6 (15.6) 500.3
------- ------ ------- ------- --------
Income (loss) before extraordinary items..... 103.8 164.5 (22.5) (746.4) (877.3)
Extraordinary items.......................... (3.8) (12.3) - - (13.4)
------- ------ ------- ------- --------
Net income (loss)............................ $ 100.0 $ 152.2 $ (22.5) $ (746.4) $ (890.7)
======= ======= ======= ======= ========
Income (loss) before extraordinary items
per share:
Basic...................................... $ 1.05 $ 1.65 $ (.22) $ (7.46) $ (16.88)
======= ======= ======= ======= ========
Diluted.................................... $ 1.04 $ 1.65 $ (.22) $ (7.46) $ (16.88)
======= ======= ======= ======= ========
Net income (loss) per share:
Basic...................................... $ 1.01 $ 1.53 $ (.22) $ (7.46) $ (17.14)
======= ======= ======= ======= ========
Diluted.................................... $ 1.00 $ 1.53 $ (.22) $ (7.46) $ (17.14)
======= ======= ======= ======= ========
Dividends per share ......................... $ - $ - $ - $ .10 $ .10
======= ======= ======= ======= ========
Weighted average shares outstanding:
Basic...................................... 98.5 99.4 100.3 100.1 52.0
======= ====== ======= ======= =======
Diluted.................................... 99.7 99.8 100.3 100.1 52.0
======= ====== ======= ======= =======
Statement of Cash Flows Data:
Cash flows from operating activities......... $ 475.6 $ 430.1 $ 255.2 $ 314.1 $ 228.2
Cash flows from investing activities......... $ (422.7) $ (194.5) $ 199.0 $ (517.0) $ (341.2)
Cash flows from financing activities......... $ (64.0) $ (244.1) $ (479.1) $ 190.9 $ 166.0
Balance Sheet Data (as of December 31):
Working capital (deficit) (d)................ $ 27.4 $ (25.1) $ (13.7) $ (324.8) $ 46.6
Property, plant and equipment, net........... $2,784.3 $2,515.0 $2,503.0 $3,034.1 $ 3,515.8
Total assets................................. $3,271.1 $2,954.4 $2,929.5 $3,481.3 $ 4,153.0
Long-term obligations........................ $1,743.7 $1,804.5 $1,914.5 $2,101.2 $ 2,124.0
Total stockholders' equity................... $1,285.4 $ 904.9 $ 774.6 $ 789.1 $ 1,548.8
---------------
(a) Includes amounts relating to the acquisition of Mesa Inc. and Chauvco
Resources Ltd. in August and December 1997, respectively.
(b) 1999 includes $41.8 million of option fees and liquidated damages and $30.2
million of income associated with an excise tax refund.
(c) Other expense for 2001 includes $11.5 million, $9.9 million and $7.7
million of charges for changes in the fair values of derivatives excluded
from hedge accounting treatment; Canadian gas marketing losses; and the
remeasurement of Argentine peso-denominated net monetary assets and
adjustments to reduce the carrying value of Argentine lease and well
equipment inventory to market value, respectively. Other expense for 2000,
1999 and 1998 include non-cash mark-to-market charges for changes in the
fair values of non-hedge financial instruments of $58.5 million, $27.0
million and $21.2 million, respectively.
(d) The 1998 working capital deficit includes $306.5 million of current
maturities of long-term debt.
25
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
2001 Performance
The year ended December 31, 2001 was highlighted by a very successful
drilling program which further complements the foundation for significant
production growth established by the Company's drilling program in 2000; the
continuation of the Company's financial and operating discipline that resulted
in a further decline in the Company's ratio of debt to book capitalization from
64 percent as of December 31, 2000 to 55 percent as of December 31, 2001; a
$45.5 million, or 11 percent, increase in net cash provided by operating
activities as compared to that of the preceding year; the repurchase of an
additional 830,400 shares of the Company's common stock at an average per share
cost of $15.69; and a highly successful hedging program.
During the years ended December 31, 2001 and 2000, the Company recorded
net income of $100.0 and $152.2 million ($1.00 and $1.53 per diluted share),
respectively, as compared to a net loss of $22.5 million ($.22 per share) during
the year ended December 31, 1999. Compared to 2000, the Company's 2001 total
revenues decreased by $36.2 million, or four percent, including a $5.7 million
decrease in oil and gas revenues. The decrease in oil and gas revenues was due
to a four percent decline in BOE sales volumes, partially offset by increases in
average oil and gas prices. Compared to 2000, the Company's 2001 total costs and
expenses increased by $14.5 million, or 1.9 percent. The modest increase in
total costs and expenses included a $40.4 million increase in exploration and
abandonments, which is primarily due to the Company's increased exploration
program in 2001; a $30.0 million decrease in interest expense, primarily due to
reductions in market interest rates and the interest savings associated with the
early extinguishment of the remaining 11-5/8 percent and 10-5/8 percent senior
subordinated notes and $38.7 million of the 9-5/8 percent senior notes; and a
$27.6 million decrease in other expense, primarily due to declines in non-hedge
derivative mark-to-market charges.
During the year ended December 31, 2001, the Company increased net cash
provided by operating activities to $475.6 million, as compared to $430.1
million during 2000 and $255.2 million during 1999. The disciplined investment
of net cash provided by operating activities, together with proceeds from the
divestiture of non-strategic assets of $113.5 million and $102.7 million during
2001 and 2000, respectively, have allowed the Company to reduce its outstanding
indebtedness by $168.6 million during the two years ended December 31, 2001.
During 2001, the Company's successful capital investment activities
increased proved reserves to 671 MMBOE, reflecting the effects of strategic
acquisitions of properties in the Company's core operating areas and a
successful drilling program which resulted in the replacement of 208 percent of
production at an acquisition and finding cost per BOE of $7.49. During the three
years ended December 31, 2001, Pioneer has replaced 184 percent of production at
an acquisition and finding cost per BOE of $4.74. Costs incurred for the year
ended December 31, 2001 totaled $646.6 million, including $170.8 million of
proved and unproved property acquisitions and $475.8 million of exploration and
development drilling and seismic expenditures.
During December 2001, the limited partners of 42 of the Company's 46
affiliated partnerships approved an agreement and plan of merger among Pioneer,
Pioneer Natural Resources USA, Inc. ("Pioneer USA"), a wholly-owned subsidiary
of Pioneer, and the participating partnerships. As a result, those partnerships
merged with and into Pioneer USA. This strategic acquisition was funded by the
issuance of 5.7 million shares of common stock valued at $104.3 million and
increased proved reserves in the Company's Spraberry oil field by approximately
29 MMBOE.
During 2001, the Company participated in discoveries at Falcon, Stirrup,
Oneida and Ozona Deep prospects in the Gulf of Mexico and in the Olowi Block
offshore Gabon. Additionally, exploration drilling confirmed the presence of gas
offshore South Africa. The Company's development activities are increasingly
focused on its "Big 4" development projects: the Canyon Express, Devils Tower
and Falcon projects in the deepwater Gulf of Mexico and the Sable project in the
shallow waters offshore South Africa. The Company has budgeted approximately
$180 million of 2002 development expenditures for the Big 4 projects. See "Item
2. Properties" for additional information regarding the Company's finding costs
and reserve replacement, property descriptions and drilling activities.
26
See "Results of Operations", below, for more in-depth discussions of the
Company's oil and gas producing activities, including discussions pertaining to
oil and gas production volumes, prices, hedging activities, costs and expenses,
capital commitments, capital resources and liquidity.
2002 Outlook
Commodity prices. During 2001, commodity prices declined from
historically high levels at the beginning of the year to historically moderate
levels by year end. The Company's outlook for 2002 commodity prices is
uncertain. Significant factors that will impact 2002 commodity prices include
the extent to which members of the Organization of Petroleum Exporting Countries
and other oil exporting nations are able to manage oil supply through export
quotas and the overall North American gas supply and demand fundamentals.
Pioneer will continue to moderate its debt levels, follow cost management
measures and strategically hedge oil and gas price risk to mitigate the impact
of price volatility on its oil, NGL and gas revenues.
As of December 31, 2001, the Company had hedged 9,463 barrels per day
("Bblpd") of 2002 oil production under swap contracts with a weighted average
fixed price to be received of $26.23 per Bbl and 6,000 Bblpd of first and second
quarter 2002 oil production under collar contracts with a minimum or "floor"
price to be received of $25.00 per Bbl and a maximum or "ceiling" price to be
received of $28.61 per Bbl. The Company had also hedged 165,205 Mcf per day
("Mcfpd") of 2002 gas production under swap contracts with a weighted average
fixed price to be received of $4.19 per MMBtu and 20,000 Mcfpd of 2002 gas
production under collar contracts with a floor price of $4.50 per MMBtu and a
ceiling price of $6.00 per MMBtu. During January and February 2002, the Company
increased its 2002 commodity hedge positions by entering into 4,000 Bblpd of
July through December oil swap contracts with average per Bbl fixed prices of
$21.55, 50,000 Mcfpd of April through December costless collar contracts having
floor prices of $2.40 per MMBtu and average ceiling prices of $3.08 per MMBtu
and 50,000 Mcfpd of August through December costless collar contracts having
floor prices of $2.50 per MMBtu and ceiling prices of $3.25 per MMBtu.
Additionally, the Company has deferred oil hedge gains of $3.9 million that will
be recognized as oil revenue during the first six months of 2002 and $46.2
million of deferred gas hedge losses that will be recognized as gas revenue
during 2002. See Note H of Notes to Consolidated Financial Statements included
in "Item 8. Financial Statements and Supplementary Data" for additional
information regarding the Company's open hedge positions at December 31, 2001
and their related prices. Also see "Item 7A. Quantitative and Qualitative
Disclosures About Market Risk" for additional disclosure about the Company's
commodity related derivative financial instruments.
First quarter 2002. Based on current estimates, the Company expects that
its first quarter worldwide production will average 108,000 to 110,000 BOE per
day. First quarter production costs are expected to average $4.60 to $4.90 per
BOE based on recent NYMEX strip prices for oil and gas. Depreciation, depletion
and amortization expense is expected to average $5.15 to $5.30 per BOE, and
total exploration and abandonment expense is expected to be $15 million to $30
million. General and administrative expense is expected to be $11 million to $12
million during the first quarter of 2002, which is higher than in prior quarters
due to a reduction in overhead reimbursements from the 42 affiliated limited
partnerships that were acquired in December 2001. Interest expense is expected
to be $30 million to $32 million during the first quarter of 2002. Cash taxes
are expected to range from $1 million to $2 million, as the Company benefits
from the carryforward of prior years' net operating losses in the United States
and Canada. For the first quarter of 2002, costs incurred for oil and gas
producing activities is expected to range from $90 million to $100 million.
Pioneer continues to monitor the political and economic environment in
Argentina. The Company's production forecasts have been adjusted to reflect the
postponement of drilling in the country. In addition, the devaluation of the
Argentine peso is expected to result in a near-term reduction in revenues,
partially offset by a reduction in operating and administrative costs; and the
recognition of remeasurement gains or losses, the impact of which cannot
currently be accurately estimated. For the fourth quarter of 2001, Argentina
represented 15 percent, or $18.9 million, of Pioneer's net cash flow from
oil and gas operations.
Production growth. The Company expects that its annual 2002 worldwide
production will be approximately 42 to 44 MMBOE, including approximately 3 MMBOE
of initial production from Canyon Express facilities during the last half of the
year. Worldwide production in 2003 and 2004 is expected to increase as
production commences from the Company's deepwater Gulf of Mexico Falcon gas and
27
Devils Tower oil projects and the Sable oil project in South Africa, coupled
with a full year of production from Canyon Express. The Company currently
anticipates that daily production rates, on a BOE basis, will increase by 55
percent to 60 percent from the first quarter of 2002 to mid-2003, once these
projects are all producing.
Capital expenditures. During 2002, the Company plans to decrease costs
incurred for oil and gas producing activities to approximately $375 million, of
which approximately $90 million, or 24 percent, has been budgeted for
exploration expenditures and $285 million, or 76 percent, has been budgeted for
development drilling and facility costs. The Company's 2002 capital budget is
allocated approximately 72 percent to the United States, four percent to
Argentina, seven percent to Canada and 17 percent to Africa. The Company's 2002
capital budget for the United States includes $135 million of development
capital for the Canyon Express, Falcon and Devils Tower deepwater Gulf of Mexico
projects. During 2002, the Company has planned exploration drilling in the Gulf
of Mexico, the onshore Gulf Coast area, Canada, Gabon, Tunisia and South Africa.
During the years ended December 31, 2003 and 2004, the Company expects to expend
approximately $130 million and $115 million, respectively, of capital for
development drilling and facility costs related to its proved undeveloped
reserves.
Critical Accounting Policies
The Company prepares its consolidated financial statements for inclusion
in this Report in accordance with accounting principles that are generally
accepted in the United States ("GAAP"). See Note B of Notes to Consolidated
Financial Statements included in "Item 8. Financial Statements and Supplementary
Data" for a comprehensive discussion of the Company's significant accounting
policies. GAAP represents a comprehensive set of accounting and disclosure rules
and requirements, the application of which requires management judgements and
estimates including, in certain circumstances, choices between acceptable GAAP
alternatives. Following is a discussion of the Company's most critical
accounting policies, judgements and uncertainties that are inherent in the
Company's application of GAAP:
Accounting for oil and gas producing activities. The accounting for and
disclosure of oil and gas producing activities requires the Company's management
to choose between GAAP alternatives and to make judgements about estimates of
future uncertainties.
Successful efforts method of accounting. The Company utilizes the
successful efforts method of accounting for oil and gas producing activities as
opposed to the alternate acceptable full cost method. In general, the Company
believes that, during periods of active exploration, net assets and net income
(loss) are more conservatively measured under the successful efforts method of
accounting for oil and gas producing activities than under the full cost method.
The critical difference between the successful efforts method of accounting and
the full cost method is as follows: under the successful efforts method,
exploratory dry holes and geological and geophysical exploration costs are
charged against net income (loss) during the periods in which they occur;
whereas, under the full cost method of accounting, such costs and expenses are
capitalized as assets, pooled with the costs of successful wells and charged
against the net income (loss) of future periods as a component of depletion
expense. During 2001, the Company recognized exploration and abandonment expense
of $127.9 million, $87.6 million and $66.0 million, respectively, under the
successful efforts method.
Proved reserve estimates. Estimates of the Company's proved reserves
included in this Report are prepared in accordance with GAAP and SEC guidelines.
The accuracy of a reserve estimate is a function of:
o the quality and quantity of available data;
o the interpretation of that data;
o the accuracy of various mandated economic assumptions; and
o the judgment of the persons preparing the estimate.
The Company's proved reserve information included in this Report is based
on estimates it prepared. Estimates prepared by others may be higher or lower
than the Company's estimates.
28
Because these estimates depend on many assumptions, all of which may
substantially differ from actual results, reserve estimates may be different
from the quantities of oil and gas that are ultimately recovered. In addition,
results of drilling, testing and production after the date of an estimate may
justify material revisions to the estimate.
The Company's stockholders should not assume that the present value of
future net cash flows is the current market value of the Company's estimated
proved reserves. In accordance with SEC requirements, the Company based the
estimated discounted future net cash flows from proved reserves on prices and
costs on the date of the estimate. Actual future prices and costs may be
materially higher or lower than the prices and costs as of the date of the
estimate.
The Company's estimates of proved reserves materially impact depletion
expense. If the estimates of proved reserves decline, the rate at which the
Company records depletion expense increases, reducing net income. Such a decline
may result from lower market prices, which may make it uneconomic to drill for
and produce higher cost fields. In addition, the decline in proved reserve
estimates may impact the outcome of the Company's assessment of its oil and gas
producing properties for impairment.
Impairment of proved oil and gas properties. The Company reviews its
long-lived proved properties to be held and used whenever management judges that
events or circumstances indicate that the recorded carrying value of the
properties may not be recoverable. Management assesses whether or not an
impairment provision is necessary based upon management's outlook of future
commodity prices and net cash flows that may be generated by the properties.
Proved oil and gas properties are reviewed for impairment by depletable pool,
which is the lowest level at which depletion of proved properties is calculated.
Impairment of unproved oil and gas properties. Management periodically
assesses individually significant unproved oil and gas properties for
impairment, on a project-by-project basis. Management's assessment of the
results of exploration activities, commodity price outlooks, planned future
sales or expiration of all or a portion of such projects impact the amount and
timing of impairment provisions.
Assessments of functional currencies. Management determines the
functional currencies of the Company's subsidiaries based on an assessment of
the currency of the economic environment in which a subsidiary primarily
realizes and expends its operating revenues, costs and expenses. The U.S. dollar
is the functional currency of all of the Company's international operations
except Canada. The assessment of functional currencies can have a significant
impact on periodic results of operations and financial position.
Argentine economic and currency measures. The accounting for and
remeasurement of the Company's Argentine balance sheet as of December 31, 2001
reflects management's assumptions regarding some uncertainties unique to
Argentina's current economic situation. See Note B of Notes to Consolidated
Financial Statements included in "Item 8. Financial Statements and Supplementary
Data" for a description of the assumptions utilized in the preparation of these
financial statements. The Argentine economic and political situation continues
to evolve and the Argentine government may enact future regulations or policies
that, when finalized and adopted, may materially impact, among other items, (i)
the realized prices the Company receives for the commodities it produces and
sells as a result of new export taxes or higher production taxes; (ii) the
timing of repatriations of excess cash flow to the Company's corporate
headquarters in the United States; (iii) the Company's asset valuations; and
(iv) peso-denominated monetary assets and liabilities.
Deferred tax asset valuations. Management periodically assesses the
probability of recovery of recorded deferred tax assets based on its assessment
of future earnings outlooks by tax jurisdiction. Such estimates are inherently
imprecise since many assumptions are utilized in the assessments that may prove
to be incorrect in the future.
New Accounting Pronouncement
The Financial Accounting Standards Board ("FASB") periodically issues
Statements of Financial Accounting Standards, which represent changes in or
additions to GAAP. During the year ended December 31, 2001, the FASB issued
Statement of Financial Accounting Standards No. 143, "Accounting for Asset
Retirement Obligations" ("SFAS 143"). SFAS 143 amends Statement of Financial
Accounting Standards No. 19, "Financial Accounting and Reporting by Oil and Gas
Producing Companies" ("SFAS 19") to require that the fair value of a liability
for an asset retirement obligation be recognized in the period in which it is
29
incurred if a reasonable estimate of fair value can be made. Under the
provisions of SFAS 143, such asset retirement costs are capitalized as part of
the carrying value of the long-lived asset. Under the provisions of SFAS 19,
asset retirement obligations are recognized using a cost-accumulation approach.
The Company currently records significant asset retirement obligations through
the unit-of-production method, except for such liabilities assumed in business
combinations, which are recorded at their estimated fair values. The provisions
of SFAS 143 are effective for financial statements issued for fiscal years
beginning after June 15, 2002. The Company plans to adopt the provisions of SFAS
143 no later than January 1, 2003. The Company does not expect that the adoption
of SFAS 143 will have a significant impact on its future financial position or
results of operations.
Results of Operations
Oil and gas revenues. Revenues from oil and gas operations totaled $847.0
million during 2001, as compared to $852.7 million during 2000 and $644.6
million during 1999, representing a .7 percent decrease from 2000 to 2001 and a
32 percent increase from 1999 to 2000. The revenue decrease from 2000 to 2001 is
due to a four percent decline in BOE sales volumes and a 15 percent decline in
NGL price, partially offset by a 15 percent increase in gas price, including the
effects of gas hedges. The revenue increase from 1999 to 2000 reflects
year-to-year increases in average reported commodity prices, including the
effects of commodity hedges, of 56 percent, 74 percent and 48 percent for oil,
NGL and gas, respectively, partially offset by a 15 percent decrease in BOE
production. The declines in production were primarily attributable to normal
well production declines and 1999 asset divestitures. Excluding the production
associated with assets divested during 2000 and 1999, BOE production declined by
approximately one percent during 2000 as compared to 1999.
The following table provides production and price data relevant to the
analysis of the Company's revenues from oil and gas operations:
Year ended December 31,
------------------------------
2001 2000 1999
-------- -------- --------
Production:
Oil (MBbls)................................. 12,498 12,535 15,454
NGLs (MBbls)................................ 7,800 8,379 9,237
Gas (MMcf).................................. 127,865 135,843 158,457
Total (MBOE)................................ 41,609 43,555 51,101
Average daily production:
Oil (Bbls).................................. 34,241 34,249 42,339
NGLs (Bbls)................................. 21,370 22,894 25,308
Gas (Mcf)................................... 350,314 371,157 434,130
Total (BOE)................................. 113,997 119,002 140,002
Average reported prices:
Oil (per Bbl)
United States............................. $ 24.34 $ 22.07 $ 15.03
Argentina................................. $ 23.79 $ 29.09 $ 18.41
Canada.................................... $ 21.87 $ 27.50 $ 13.28
Worldwide................................. $ 24.12 $ 24.01 $ 15.36
NGL (per Bbl)
United States............................. $ 16.88 $ 20.05 $ 11.61
Argentina................................. $ 19.29 $ 22.91 $ 11.30
Canada.................................... $ 21.11 $ 24.32 $ 12.62
Worldwide................................. $ 17.14 $ 20.27 $ 11.64
Gas (per Mcf)
United States............................. $ 4.10 $ 3.50 $ 2.17
Argentina................................. $ 1.31 $ 1.19 $ 1.10
Canada.................................... $ 2.86 $ 2.88 $ 1.82
Worldwide................................. $ 3.23 $ 2.81 $ 1.90
Percentage increase (decrease) in average
worldwide reported prices:
Oil....................................... - 56 17
NGL....................................... (15) 74 31
Gas....................................... 15 48 4
30
Hedging activities. The oil and gas prices that the Company reports are
based on the market price received for the commodities adjusted by the results
of the Company's hedging activities. The Company utilizes commodity derivative
contracts (swaps and collars) in order to (i) reduce the effect of price
volatility on the commodities the Company produces and sells, (ii) support the
Company's annual capital budgeting and expenditure plans and (iii) reduce price
risk associated with certain capital projects. See Note H of Notes to
Consolidated Financial Statements included in "Item 8. Financial Statements and
Supplementary Data" for information concerning the impact to oil and gas
revenues during 2001, 2000 and 1999 from the Company's hedging activities, the
Company's open hedge positions at December 31, 2001 and their related prices and
descriptions of the Company's hedge and non-hedge commodity derivatives. Also
see "Item 7A. Quantitative and Qualitative Disclosures About Market Risk" for
additional disclosure about the Company's commodity related derivative financial
instruments.
Interest and other revenue. The Company recorded interest and other
income totaling $21.8 million, $25.8 million and $89.7 during 2001, 2000 and
1999 respectively. The Company's interest and other income is comprised of
revenue that is not directly attributable to oil and gas producing activities or
oil and gas property divestitures. The significant decrease in interest and
other income during 2000 is primarily attributable to a non-recurring excise tax
refund of $30.2 million and a non-recurring option fee of $41.8 million
recognized by the Company during 1999. See Note J of Notes to Consolidated
Financial Statements included in "Item 8. Financial Statements and Supplementary
Data" for additional information regarding interest and other income.
Gain (loss) on disposition of assets. During the year ended December 31,
2001, the Company realized $113.5 million of cash proceeds from asset
divestitures and, associated therewith, recorded net gains of $7.7 million. The
proceeds derived from asset divestitures during 2001 included $85.4 million from
the early termination of hedge derivatives, $12.7 million from the sale of the
Company's remaining holdings in the common stock of a non-affiliated entity,
$12.0 million from the sale of certain oil properties in Canada and $3.3 million
from the sale of other corporate assets. The proceeds from the early termination
of hedge derivatives represent deferred hedge gains that will be recognized as
increases to oil and gas revenues in future periods (see Note H of Notes to
Consolidated Financial Statements included in "Item 8. Financial Statements and
Supplementary Data"). The Company recorded a gain of $8.1 million from the sale
of the remaining holdings in the common stock of the non-affiliated entity and a
loss of $1.1 million and a gain of $.7 million from the sales of oil and gas
properties and other corporate assets, respectively.
During 2000, the Company completed the divestiture of certain assets for
proceeds of $102.7 million. Associated therewith, the Company recorded a net
gain on disposition of assets of $34.2 million. The 2000 divestitures included
the sale of common stock of a non-affiliated entity for net proceeds of $59.7
million, from which the Company recognized a gain on disposition of assets of
$34.3 million. The Company also sold certain oil and gas producing properties
and other assets during 2000 for proceeds of $43.0 million, from which the
Company recognized a loss on disposition of assets of $.1 million.
During 1999, the Company realized proceeds from asset divestitures of
$420.5 million and recognized a net loss on disposition of assets of $24.2
million.
The net cash proceeds from asset divestitures during 2001, 2000 and 1999
were used, together with net cash flows provided by operating activities, to
finance strategic additions to oil and gas properties, to reduce outstanding
indebtedness and other for general corporate needs. See Note K of Notes to
Consolidated Financial Statements included in "Item 8. Financial Statements and
Supplementary Data" for additional information regarding asset divestitures.
Production costs. Total production costs per BOE increased in 2001 and
2000 by 16 percent and 39 percent, respectively. In general, lease operating
expenses and workover expenses represent the components of production costs over
which the Company has management control, while production taxes, ad valorem
taxes and field fuel expenses are directly related to commodity price changes.
The increase in production costs during 2001 is primarily due to increases in
field fuel expense as a result of higher North American average gas prices,
higher ad valorem taxes which are computed using prior year average annual
commodity prices and to declines in the third party gas processing and treating
margin component of lease operating expenses. The increase in per BOE production
costs in 2000 as compared to 1999 is primarily due to significant increases in
those expenses that are directly related to commodity prices and, to a lesser
31
extent, inflation in field service expenses. The following table provides the
components of the Company's production costs during the years ended December 31,
2001, 2000 and 1999:
Year Ended December 31,
--------------------------
2001 2000 1999
------ ------ ------
(per BOE)
Lease operating expenses.................... $ 2.76 $ 2.42 $ 2.11
Taxes:
Production................................ .74 .77 .39
Ad valorem ............................... .49 .29 .31
Field fuel expenses......................... .88 .71 .21
Workover expenses........................... .17 .15 .10
----- ----- -----
Total production costs................ $ 5.04 $ 4.34 $ 3.12
===== ===== =====
Depletion, depreciation and amortization expense. The Company's total
depletion, depreciation and amortization expense per BOE was $5.35, $4.93 and
$4.62 for the years ended December 31, 2001, 2000 and 1999, respectively.
Depletion expense, the largest component of depletion, depreciation and
amortization, was $5.02, $4.57 and $4.27 per BOE during the years ended December
31, 2001, 2000 and 1999, respectively, and depreciation and amortization of
other property and equipment was $.33, $.36 and $.35 per BOE during each of the
respective years. During 2001, the increase in per BOE depletion expense is
primarily associated with decreases in United States production, which has a
lower cost basis relative to combined Argentine and Canadian per BOE cost basis,
and to downward revisions to proved reserves as a result of lower commodity
prices. The increase in per BOE depletion expense during 2000 is primarily due
to an increase in the Company's Argentine and Canadian proved property basis as
a result of reclassifying unproved property basis associated with the Company's
exploration and extension drilling success to proved property and to a higher
proportionate share of the Company's production being produced from Argentina.
Impairment of oil and gas properties. The Company reviews its proved
properties for impairment whenever events or circumstances indicate a decline in
the recoverability of the carrying value of the Company's assets may have
occurred.
The Company periodically assesses its unproved properties to determine
whether they have been impaired. An unproved property may be impaired if the
Company does not intend to drill the prospect as a result of downward revisions
to potential reserves, if the results of exploration or the Company's outlook
for future commodity prices indicate that the potential reserves are not
sufficient to generate net cash flows to recover the investment required by the
project, or if the Company intends to sell the property for less than its
carrying value. The Company regularly assesses its unproved oil and gas
properties for impairment and, during the year ended December 31, 1999,
recognized a non-cash impairment charge of $17.9 million to reduce the carrying
value of its unproved East Texas gas properties. See Critical Accounting
Policies above and Notes B and L of Notes to Consolidated Financial Statements
included in "Item 8. Financial Statements and Supplementary Data" for additional
information pertaining to the Company's accounting policies regarding
assessments of impairment and specific information about the 1999 impairment of
unproved properties.
Exploration and abandonments/geological and geophysical costs.
Exploration and abandonments/geological and geophysical costs totaled $127.9
million, $87.6 million and $66.0 million for the years ended December 31, 2001,
32
2000 and 1999, respectively. The following table sets forth the components of
the Company's 2001, 2000 and 1999 exploration and abandonments/geological and
geophysical costs:
United Other
States Argentina Canada Foreign Total
-------- --------- -------- --------- --------
(in thousands)
Year Ended December 31, 2001:
Geological and geophysical costs....... $ 29,620 $ 6,541 $ 2,373 $ 13,678 $ 52,212
Exploratory dry holes.................. 34,883 6,040 5,473 10,432 56,828
Leasehold abandonments and other....... 5,546 11,276 2,036 8 18,866
------ ------ ------- ------- -------
$ 70,049 $ 23,857 $ 9,882 $ 24,118 $127,906
======= ======= ======= ======= =======
Year Ended December 31, 2000:
Geological and geophysical costs....... $ 22,033 $ 6,881 $ 2,273 $ 7,761 $ 38,948
Exploratory dry holes.................. 11,745 6,987 887 8,396 28,015
Leasehold abandonments and other....... 7,089 11,520 1,971 7 20,587
------ ------ ------- ------- -------
$ 40,867 $ 25,388 $ 5,131 $ 16,164 $ 87,550
======= ======= ======= ======= =======
Year Ended December 31, 1999:
Geological and geophysical costs....... $ 17,207 $ 3,399 $ 315 $ 7,498 $ 28,419
Exploratory dry holes.................. 15,591 3,441 978 (275) 19,735
Leasehold abandonments and other....... 8,427 7,169 2,216 8 17,820
------ ------ ------- ------- -------
$ 41,225 $ 14,009 $ 3,509 $ 7,231 $ 65,974
======= ======= ======= ======= =======
The increase in 2001 exploration costs, as compared to 2000, is primarily
due to increased geological and geophysical costs that are supportive of future
exploratory drilling, increased exploratory drilling in the Gulf of Mexico and
Argentina and an exploratory dry hole drilled in Tunisia. The increase in 2000
exploration costs, as compared to 1999, is primarily due to increased geological
and geophysical costs, unproved leasehold abandonments associated with
exploratory dry holes in Argentina and dry hole costs associated with
exploratory drilling in South Africa. Approximately 34 percent of the Company's
2001 costs incurred for oil and gas producing activities were exploration costs
as compared to 38 percent in 2000 and 32 percent in 1999.
Administrative and reorganization expenses. The Company's administrative
expense totaled $37.0 million ($.89 per BOE), $33.3 million ($.76 per BOE) and
$40.2 million ($.79 per BOE) during the years ended December 31, 2001, 2000 and
1999. The increase in administrative expense during 2001, as compared to 2000,
is primarily due to an increase in compensation expense. The decline in per BOE
administrative expense during 2000 was due to the reorganization measures
initiated by the Company during 1998 and completed in 1999. Those reorganization
measures included the centralization in Irving, Texas of certain operational and
administrative functions previously based in Midland, Texas; the closings of the
Company's regional offices in Oklahoma City, Oklahoma, Corpus Christi, Texas,
and Houston, Texas; workforce reductions; and, other initiatives. As a direct
result of those measures, the Company recognized reorganization charges of $8.5
million during 1999. See Note M of Notes to Consolidated Financial Statements
included in "Item 8. Financial Statements and Supplementary Data" for specific
information regarding reorganization costs paid during 2001, 2000 and 1999, and
unpaid reorganization costs as of December 31, 2001, 2000 and 1999.
Interest expense. Interest expense was $132.0 million, $162.0 million
and $170.3 million for the years ended December 31, 2001, 2000 and 1999,
respectively. Interest expense decreased during 2001, as compared to 2000, due
to a decrease in the Company's weighted average borrowing rate and the interest
savings associated with the early extinguishment of the Company's outstanding
11-5/8 percent and 10-5/8 percent senior notes and $38.7 million of the
Company's 9-5/8 percent senior notes. Interest expense decreased during 2000, as
compared to 1999, primarily due to a decrease in the Company's weighted average
debt outstanding for the year. This decline was offset, to a certain extent, by
higher interest rates in 2000 as compared to 1999.
Other expenses. Other expenses were $39.6 million during 2001, as
compared to $67.2 million during 2000 and $34.6 million during 1999. Other
expenses in 2001 include $11.4 million of commodity derivative settlements that
did not qualify for hedge treatment under Statement of Financial Accounting
Standards No. 133, "Accounting for Derivative Instruments and Hedging
Activities"; $9.9 million of marketing losses incurred to transport and sell
purchased Canadian gas to a Chicago, Illinois sales point; $7.7 million of
losses from the remeasurement of the Company's Argentine peso-denominated net
monetary assets and an adjustment to reduce the carrying value of Argentine
lease and well equipment inventory to market value (see Note B of Note to
33
Consolidated Financial Statements included in "Item 8. Financial Statements and
Supplementary Data" for additional information regarding currency
remeasurement); $6.0 million of bad debt expense related to derivative contracts
with Enron North America Corp. and $4.6 million of other expenses.
The increase in other expenses during 2000, as compared to 1999, is
primarily attributable to increases in mark-to-market provisions on non-hedge
derivative financial instruments. Such mark-to-market provisions during 2000
included $42.0 million associated with non-hedge commodity derivatives that
matured in December 2000, $14.6 million associated with the Company's non-hedge
Btu swap agreements and $1.9 million associated with a series of non-hedge
forward foreign exchange swap agreements that matured in December 2000.
Mark-to-market provisions in 1999 included $21.2 million associated with
non-hedge commodity derivatives and $11.9 million associated with an investment
in the common stock of a non-affiliated public entity, partially offset by $5.9
million of mark-to-market income recognized on a series of forward foreign
exchange swap agreements and income of $.2 million associated with the Company's
Btu swap agreements.
During 2001, the Company entered into offsetting swap agreements that
have fixed the prices that are to be received and paid by the Company under the
Btu swap agreements. Consequently, the fair values of the Company's Btu swap
agreements, which represent a discounted liability to the Company of $19.4
million as of December 31, 2001, are no longer sensitive to the changes in oil
or gas commodity prices. See "Item 7A. Quantitative and Qualitative Disclosures
About Market Risk" and Notes C and H of Notes to Consolidated Financial
Statements included in "Item 8. Financial Statements and Supplementary Data" for
specific disclosures pertaining to the Company's derivative financial
instruments.
Income tax provisions (benefits). The Company recognized a consolidated
income tax provision of $4.0 million during 2001 and consolidated income tax
benefits of $6.0 million and $.6 million during 2000 and 1999. The Company's
consolidated tax provision for the year ended December 31, 2001 is comprised of
current U.S. state and local taxes of $1.1 million; current foreign tax
provision of $10.5 million; and deferred foreign tax benefits of $7.6 million.
The Company's consolidated tax benefit in 2000 is comprised of a $10.6 million
deferred tax benefit in Argentina, partially offset by $4.6 million of current
taxes paid in Argentina. Due to uncertainties regarding the Company's ability to
realize net operating loss carryovers and tax credit carryovers prior to their
scheduled expirations, the Company did not recognize deferred income tax
benefits associated with its operating results for 1999. Although realization is
not assured for the Company's remaining deferred tax assets, the Company
believes it is more likely than not that they will be realized through future
taxable earnings or alternative tax planning strategies. However, the net
deferred tax assets could be reduced further if the Company's estimate of
taxable income in future periods is significantly reduced or alternative tax
planning strategies are no longer viable. As a result of this situation, it is
likely that the Company's effective tax rate in 2002 will be minimal. See Note O
of Notes to Consolidated Financial Statements included in "Item 8. Financial
Statements and Supplementary Data" for information regarding the Company's
income taxes and deferred tax asset valuation reserves.
Extraordinary items. The Company redeemed the remaining $22.5 million of
its outstanding 11-5/8 percent senior subordinated discount notes due July 1,
2006 and $6.8 million of its outstanding 10-5/8 percent senior subordinated
notes due July 1, 2006 during July 2001, and redeemed $38.7 million of its 9-5/8
percent senior notes due April 1, 2010 during the fourth quarter of 2001.
Associated with these redemptions, the Company recognized an extraordinary loss,
net of taxes, of $3.8 million during 2001. During 2000, the Company replaced its
prior credit facility, which was scheduled to mature August 7, 2002, with a new
$575 million corporate credit facility due March 1, 2005 (the "Credit
Agreement"). Associated therewith, the Company recognized a $12.3 million
extraordinary loss on early extinguishment of debt.
Capital Commitments, Capital Resources and Liquidity
Capital commitments. The Company's primary needs for cash are for
exploration, development and acquisitions of oil and gas properties, repayment
of contractual obligations and working capital obligations.
Oil and gas properties. The Company's cash expenditures for additions to
oil and gas properties during 2001, 2000 and 1999 totaled $529.7 million, $299.7
million and $179.7 million, respectively. The Company's 2001 expenditures were
internally funded by $475.6 million of net cash provided by operating activities
and a portion of the Company's $113.5 million of proceeds from disposition of
34
assets. The Company's 2000 and 1999 capital expenditures were internally funded
by net cash provided by operating activities.
The Company strives to maintain its indebtedness at moderate levels in
order to provide sufficient financial flexibility to take advantage of future
opportunities. The Company's $375 million capital budget for 2002 includes $180
million of expenditures for the development of the Company's Canyon Express,
Devils Tower, Falcon and Sable projects which may cause capital expenditures to
exceed internally generated cash flows. To the extent that the Company's capital
expenditures during 2002 exceed cash provided by operating activities, the
Company may increase its outstanding indebtedness by utilizing unused borrowing
capacity under its Credit Agreement or, alternatively, the Company may use other
sources of capital as described in "Capital resources" below.
Contractual obligations. The Company's contractual obligations include
long-term debt, operating leases, Btu swap agreements, terminated commodity
hedges and other contracts. Contractual obligations for which the ultimate
settlement amounts are not fixed and determinable include derivative contracts
that are sensitive to future changes in commodity prices, currency exchange
rates and interest rates. See "Item 7A. Quantitative and Qualitative Disclosures
About Market Risk" for a table of changes in the fair value of the Company's
derivative contract assets and liabilities during the year ended December 31,
2001. The following table summarizes the Company's payments due by period for
fixed and determinable contractual obligations:
Payments Due by Year
------------------------------------------------
2002 2003-2004 2005-2006 Thereafter
-------- --------- ---------- -----------
(in thousands)
Long-term debt (a)................. $ - $ - $ 445,998 $1,121,306
Operating leases (b)............... 5,942 63,919 46,230 28,538
Btu swap agreements (c)............ 7,175 14,358 - -
Terminated commodity hedges (c).... 30,209 - - -
------- ------- -------- ---------
$ 43,326 $ 78,277 $ 492,228 $1,149,844
======= ======= ======== =========
------------
(a) See Note D of Notes to Consolidated Financial Statements included in
"Item 8. Financial Statements and Supplementary Data".
(b) See Note G of Notes to Consolidated Financial Statements included in
"Item 8. Financial Statements and Supplementary Data".
(c) See Note H of Notes to Consolidated Financial Statements included in
"Item 8. Financial Statements and Supplementary Data".
Working capital. Funding for the Company's working capital obligations is
provided by internally-generated cash flow. Funding for the repayment of
principal and interest on outstanding debt and the Company's capital expenditure
program may be provided by any combination of internally-generated cash flow,
proceeds from the disposition of non-strategic assets or alternative financing
sources as discussed in "Capital resources" below.
Capital resources. The Company's primary capital resources are net cash
provided by operating activities, proceeds from financing activities and
proceeds from sales of non-strategic assets. The Company expects that these
resources will be sufficient to fund its capital commitments in 2002.
Operating activities. Net cash provided by operating activities during
2001, 2000 and 1999 were $475.6 million, $430.1 million and $255.2 million,
respectively. During 2001, net cash provided by operating activities increased
by $45.5 million, or 11 percent, as compared to that of 2000. The increase in
2001 is primarily due to higher commodity prices as compared to 2000 and an
increase in trade receivable collections. Net cash provided by operating
activities increased 69 percent during 2000 from that of 1999, primarily as a
result of favorable commodity prices and cost management measures. Net cash
provided by operating activities during 1999 decreased 19 percent from that of
1998 primarily as a result of declines in production volumes due to oil and gas
property divestitures, partially offset by increases in commodity prices and
decreases in production and administrative costs.
Financing activities. During the years ended December 31, 2001, 2000 and
1999, the Company has used $64.0 million, $244.1 million and $479.1 million,
respectively, of net cash in financing activities. Over the three year period
ended December 31, 2001, the Company has used $620.8 million of cash for net
reductions in long-term borrowings and has reduced its ratio of debt to book
capitalization to 55 percent as of December 31, 2001, from 69 percent as of
35
December 31, 1999. Additionally, the Company has entered into financing
transactions with the intent of reducing its costs of capital and increasing
liquidity through the extension of debt maturities.
During 2001, the Company entered into interest rate swap contracts to
hedge the fair value of its 6-1/2 percent senior notes due in 2008, its 8-7/8
percent senior notes due in 2005 and its 8-1/4 percent senior notes due in 2007.
The Company also entered into interest rate swaps to hedge a portion of its
interest rate risk under the Credit Agreement. These swap contracts reduced the
Company's interest expense by $7.3 million during 2001. See Note H of Notes to
Consolidated Financial Statements included in "Item 8. Financial Statements and
Supplemental Data" and "Item 7A. Quantitative and Qualitative Disclosures About
Market Risk" for more information about the Company's hedging activities.
As is further described in "Results of Operations" above, during 2001,
the Company redeemed its remaining 11-5/8 percent and 10-5/8 percent senior
subordinated notes due July 1, 2006, and $38.7 million of its 9-5/8 percent
senior notes due April 1, 2010.
At December 31, 2001, the Company had a $575 million corporate credit
facility with a syndicate of banks that matures on March 1, 2005. Outstanding
borrowings under the corporate credit facility totaled $294 million as of
December 31, 2001. In addition, the Company has five outstanding senior note
issuances at December 31, 2001. Such debt issuances consist of (i) $150 million
aggregate principal amount of 8-7/8 percent senior notes due in 2005; (ii) $150
million aggregate principal amount of 8-1/4 percent senior notes due in 2007;
(iii) $350 million aggregate principal amount of 6-1/2 percent senior notes due
in 2008; (iv) $385 million aggregate remaining principal amount of 9-5/8 percent
senior notes due in 2010; and, (iv) (v) $250 million aggregate principal amount
of 7-1/5 percent senior notes due in 2028. Certain of the obligations above
contain restrictive covenants which the Company is in compliance with as of
December 31, 2000.
The weighted average interest rate on the Company's indebtedness for the
year ended December 31, 2001 was 7.52 percent as compared to 8.68 percent for
the year ended December 31, 2000 and 7.81 percent for the year ended December
31, 1999, taking into account the effect of interest rate swaps. See Note D of
Notes to Consolidated Financial Statements included in "Item 8. Financial
Statements and Supplementary Data" for more specific information regarding the
Company's long-term debt as of December 31, 2001 and 2000.
As the Company pursues its strategy, it may utilize various financing
sources, including fixed and floating rate debt, convertible securities,
preferred stock or common stock. The Company may also issue securities in
exchange for oil and gas properties, stock or other interests in other oil and
gas companies or related assets. Additional securities may be of a class
preferred to common stock with respect to such matters as dividends and
liquidation rights and may also have other rights and preferences as determined
by the Company's Board of Directors.
Sales of non-strategic assets. During 2001, 2000 and 1999, proceeds from
the sale of non-strategic assets totaled $113.5 million, $102.7 million and
$420.5 million (1999 includes $30 million of non-cash proceeds), respectively.
The Company's 2001, 2000 and 1999 asset divestitures were comprised of hedge
derivatives, common stock of a non-affiliated entity, and non-strategic United
States and Canadian oil and gas properties, gas plants and other assets. The
cash proceeds received from asset divestitures during 2001 were used to fund a
portion of the Company's 2001 capital expenditures and for general corporate
obligations. The net cash proceeds from the 2000 and 1999 asset divestitures
were used to reduce the Company's outstanding indebtedness (see "Results of
Operations", above, and Note K of Notes to Consolidated Financial Statements
included in "Item 8. Financial Statements and Supplementary Data").
Book capitalization and liquidity. Total debt remained constant at $1.6
billion as of December 31, 2001, as compared to total debt of $1.6 billion and
$1.7 billion on December 31, 2000 and 1999, respectively. The Company's total
book capitalization at December 31, 2001 was $2.9 billion, consisting of total
debt of $1.6 billion and stockholders' equity of $1.3 billion. Consequently, the
Company's debt to total capitalization decreased to 55 percent at December 31,
2001 from 64 percent at December 31, 2000. At December 31, 2001, the Company had
$14.3 million of cash and cash equivalents on hand, compared to $26.2 million at
December 31, 2000. The Company's ratio of current assets to current liabilities
was 1.12 at December 31, 2001 and .88 at December 31, 2000. Including $27.9
million of undrawn and outstanding letters of credit, the Company has $253.1
million of unused borrowing capacity available under its Credit Agreement as of
December 31, 2001.
36
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The following quantitative and qualitative information is provided about
financial instruments to which the Company was a party as of December 31, 2001
and 2000, and from which the Company may incur future gains or losses from
changes in market interest rates, foreign exchange rates, commodity prices or
common stock prices. Although certain derivative contracts that the Company is a
party to do not qualify as hedges, the Company does not enter into derivative or
other financial instruments for trading purposes.
The fair value of the Company's derivative contracts are determined based
on counterparties' estimates and valuation models. The Company has not changed
its valuation method during 2001. During 2001, the Company only entered into
costless swap and collar contracts. See Note H of Notes to Consolidated
Financial Statements included in "Item 8. Financial Statements and Supplementary
Data" for additional information regarding the Company's derivative contracts,
including deferred gains and losses on terminated derivative contracts. The
following table reconciles the changes that occurred in the fair values of the
Company's open derivative contracts during 2001:
Derivative Contract Assets (Liabilities)
-------------------------------------------
Foreign
Interest Exchange
Commodity Rate Rate Total
--------- -------- -------- ---------
(in thousands)
Fair value of contracts outstanding
as of December 31, 2000.............. $(165,560) $ 6,216 $ - $(159,344)
Changes in contract fair value........... 396,921 (159) 61 396,823
Contract realizations:
Maturities........................... (3,601) (4,524) - (8,125)
Termination - cash settlements....... (64,240) (21,170) - (85,410)
Termination - future obligations..... 22,311 - - 22,311
Termination - future receivables.... (5,277) - - (5,277)
-------- ------- ---- --------
Fair value of contracts outstanding
as of December 31, 2001.............. $ 180,554 $(19,637) $ 61 $ 160,978
======== ======= ===== ========
Quantitative Disclosures
Interest rate sensitivity. The following tables provide information, in
U. S. dollar equivalent amounts, about derivative financial instruments and
other financial instruments to which the Company was a party as of December 31,
2001 and 2000, which are sensitive to changes in interest rates. For debt
obligations, the tables present maturities by expected maturity dates together
with the weighted average interest rates expected to be paid on the debt, given
current contractual terms and market conditions. For fixed rate debt, the
weighted average interest rate represents the contractual fixed rates that the
Company is obligated to periodically pay on the debt as of December 31, 2001 and
2000. For variable rate debt, the average interest rate represents the average
rates being paid on the debt projected forward proportionate to the forward
yield curve for the six-month London Interbank Offered Rate as of February 28,
2002 for the Interest Rate Sensitive table as of December 31, 2001 and the
forward yield curve for United States treasury securities for the Interest Rate
Sensitivity table as of December 31, 2000.
The accompanying tables also provide information about interest rate swap
agreements entered into by the Company during 2001 and 2000. The interest rate
swap agreements as of December 31, 2001 hedge (i) the fair value of the
Company's 8-1/4 percent senior notes due August 15, 2007; (ii) the fair value of
the Company's 6-1/2 percent senior notes due January 15, 2008; and (iii) a
portion of the interest rate risk associated with the Company's Credit
Agreement. The Interest Rate Sensitivity table as of December 31, 2000 includes
information about interest rate swap agreements that the Company terminated
during 2001 but which, as of December 31, 2000, hedged the fair value of the
Company's 8-7/8 percent senior notes due April 15, 2005.
37
Interest Rate Sensitivity
Derivative And Other Financial Instruments as of December 31, 2001
Asset
(Liability)
2002 2003 2004 2005 2006 Thereafter Total Fair Value
--------- --------- --------- --------- --------- ---------- ---------- -----------
(in thousands except interest rates)
Total Debt:
U.S. dollar denominated
maturities:
Fixed rate debt.......... $ - $ - $ - $161,998 $ - $1,121,306 $1,283,304 $(1,268,178)
Weighted average
interest rate.......... 8.06% 8.06% 8.06% 7.98% 7.95% 7.95%
Variable rate debt....... $ - $ - $ - $294,000 $ - $ - $ 294,000 $ (294,000)
Average interest rates... 4.38% 6.12% 6.90% 7.27%
Interest Rate Hedge Derivatives (1):
8-1/4% senior notes hedge:
Notional debt amount..... $150,000 $150,000 $150,000 $150,000 $150,000 $ 150,000 $ 150,000 $ (2,965)
Fixed rate receivable.... 8.25% 8.25% 8.25% 8.25% 8.25% 8.25%
Variable rate payable.... 6.50% 8.24% 9.02% 9.39% 9.64% 9.79%
6-1/2% senior notes hedge:
Notional debt amount..... $350,000 $350,000 $350,000 $350,000 $350,000 $ 350,000 $ 350,000 $ (16,229)
Fixed rate receivable.... 6.50% 6.50% 6.50% 6.50% 6.50% 6.50%
Variable rate payable.... 5.15% 6.89% 7.67% 8.04% 8.29% 8.44%
Credit Agreement hedge:
Notional debt amount..... $ 55,000 $ 55,000 $ (443)
Fixed rate payable....... 5.43%
Variable rate receivable. 4.38%
---------------
(1) The Company's 8-1/4% senior notes hedge matures August 15, 2007; the 6-1/2%
senior notes hedge matures January 15, 2008; and the Credit Agreement hedge
matures May 20, 2002.
Interest Rate Sensitivity
Derivative And Other Financial Instruments as of December 31, 2000
Asset
(Liability)
2001 2002 2003 2004 2005 Thereafter Total Fair Value
--------- --------- --------- --------- --------- ---------- ---------- -----------
(in thousands except interest rates)
Total Debt:
U.S. dollar denominated
maturities:
Fixed rate debt.......... $ - $ - $ - $ - $150,000 $1,203,776 $1,353,776 $(1,290,250)(1)
Weighted average
interest rate.......... 8.10% 8.10% 8.10% 8.10% 8.03% 8.00%
Variable rate debt....... $ - $ - $ - $ - $225,000 $ - $ 225,000 $ (225,000)
Average interest rates... 6.64% 6.27% 6.18% 6.24% 6.31%
Interest Rate Hedge Derivatives (2):
Notional amount of interest
rate swap................ $150,000 $150,000 $150,000 $150,000 $150,000 $ - $ 150,000 $ 6,216
Fixed interest rate
received................... 8.88% 8.88% 8.88% 8.88% 8.88%
Variable interest rate paid. 7.17% 6.77% 6.67% 6.74% 6.81%
---------------
(1) Excludes $30.9 million of debt instruments for which fair values were
insignificant and no estimate of fair value was performed as of December
31, 2000.
(2) The Company's interest rate hedge derivatives as of December 31, 2000 had a
scheduled maturity of April 15, 2005.
38
Foreign exchange rate sensitivity. The following table provides
information, in U.S. dollar equivalent amounts, about derivative financial
instruments that the Company was a party to as of December 31, 2001 and that
were sensitive to changes in foreign exchange rates.
Foreign Exchange Rate Sensitivity
Derivative And Other Financial Instruments as of December 31, 2001
Asset
2002 Total Fair Value
-------- --------- ----------
(in thousands except interest rates)
Foreign Exchange Rate Hedge Derivatives:
Notional amount of foreign
currency forward contracts.................... $ 24,752 $ 24,752 $ 61
Fixed Canadian to U.S.
dollar rate paid.............................. .6266
Average forward Canadian
dollar to U.S. dollar
exchange rate as of February 28, 2002......... .6250
Commodity price sensitivity. The following tables provide information, in
U.S. dollar equivalent amounts, about derivative financial instruments that the
Company was a party to as of December 31, 2001 and 2000 and that are sensitive
to changes in oil and gas prices. The tables segregate hedge derivative
contracts from those that do not qualify as hedges.
Commodity hedge instruments. The Company hedges commodity price risk with
swap and collar contracts. Swap contracts provide a fixed price for a notional
amount of sales volumes. Collar contracts provide minimum ("floor") and maximum
("ceiling") prices for the Company on a notional amount of sales volumes,
thereby allowing some price participation if the relevant index price closes
above the floor price.
Commodity non-hedge instruments. The Company is a party to Btu swap
contracts. These contracts do not qualify for hedge accounting. Under the terms
of the Btu swap contracts, the Company receives 10 percent of the NYMEX oil
price and pays the NYMEX gas price on a notional 13,036 MMBtu daily gas volume.
During 2000, the Company entered into Btu swap contracts that offset its
variable position in the Btu swap contracts for the 2001 volumes, but continued
to participate for 2002 through 2004 volumes. Accordingly, these derivative
instruments are presented in both the accompanying oil and gas tables for the
year ended December 31, 2000. During 2001, the Company entered into Btu swap
contracts that offset its remaining variable positions in the Btu swap contracts
for 2002 through 2004 volumes. Consequently, the Company has no remaining market
risk associated with Btu swap contracts as of December 31, 2001. As of December
31, 2001, the carrying value of the Btu swap contracts represented a discounted
liability of $19.4 million.
See Notes B, C and H of Notes to Consolidated Financial Statements
included in "Item 8. Financial Statements and Supplementary Data" for a
description of the accounting procedures followed by the Company relative to
hedge and non-hedge derivative financial instruments and for specific
information regarding the terms of the Company's derivative financial
instruments that are sensitive to changes in oil and gas prices.
39
Oil Price Sensitivity
Derivative Financial Instruments as of December 31, 2001 (3)
Asset
2002 2003 Fair Value
-------- -------- ----------
Oil Hedge Derivatives (1):
Average daily notional Bbl volumes:
Swap contracts.................................. 9,463 2,975 $ 23,423
Weighted average per Bbl fixed price........... $ 26.23 $ 24.02
Collar contracts................................ 2,975 $ 5,506
Weighted average short call per Bbl
ceiling price................................ $ 28.61
Weighted average long put per Bbl
floor price.................................. $ 25.00
Average forward NYMEX oil prices (2).............. $ 21.86 $ 21.54
---------------
(1) See Note H of Notes to Consolidated Financial Statements included in "Item
8. Financial Statements and Supplementary Data" for hedge volumes and
weighted average prices by calendar quarter for 2002 and 2003.
(2) The average forward NYMEX oil prices are based on February 28, 2002 market
quotes.
(3) During January 2002, the Company entered into 4,000 Bbls per day of July
through December 2002 swap contracts with average per Bbl fixed prices of
$21.55. These financial instruments are not included in the table.
Oil Price Sensitivity
Derivative Financial Instruments as of December 31, 2000
Asset
(Liability)
2001 2002 2003 2004 Fair Value
------- ------- ------- ------- ----------
Oil Hedge Derivatives:
Average daily notional Bbl volumes:
Swap contracts.................................. 6,510 $ 8,819
Weighted average per Bbl fixed price........... $ 29.27
Collar contracts................................ 4,479 $ (1,820)
Weighted average short call per Bbl
ceiling price................................ $ 25.15
Weighted average long put per Bbl
floor price.................................. $ 20.57
Oil Non-hedge Derivatives (1):
Daily notional MMBtu volumes under swap
of NYMEX gas price for 10 percent of
NYMEX WTI price................................ 13,036 13,036 13,036 13,036 $ (25,507)
Average forward NYMEX gas prices (2)........... $ 4.05 $ 4.61 $ 4.29 $ 4.35
Average forward NYMEX oil prices (2)........... $ 27.69 $ 24.15 $ 22.21 $ 21.54
---------------
(1) Since the oil non-hedge derivatives were sensitive to changes in both oil
and gas market prices, they are duplicated in the Oil Price Sensitivity and
the Natural Gas Price Sensitivity tables as of December 31, 2000.
(2) The average forward NYMEX oil and gas prices are based on February 20, 2001
market quotes, except for the 2001 prices that represent locked-in prices
associated with the Company's Btu swaps.
40
Natural Gas Price Sensitivity
Derivative Financial Instruments as of December 31, 2001 (4)
Asset
2002 2003 2004 2005 Fair Value
-------- -------- -------- -------- ----------
Natural Gas Hedge Derivatives (1) (2):
Average daily notional MMBtu volumes:
Swap contracts.................................. 165,205 117,500 165,000 50,000 $ 137,606
Weighted average per MMBtu fixed price......... $ 4.19 $ 3.62 $ 3.84 $ 3.63
Collar contracts................................ 20,000 $ 14,019
Weighted average short call per MMBtu
ceiling price............................... $ 6.00
Weighted average long put per MMBtu
floor price................................. $ 4.50
Average forward NYMEX gas prices (3).............. $ 2.68 $ 3.21 $ 3.42 $ 3.52
--------------
(1) To minimize basis risk, the Company enters into basis swaps for a portion
of its gas hedges to convert the index price of the hedging instrument from
a NYMEX index to an index which reflects the geographic area of production.
The Company considers these basis swaps as part of the associated swap and
option contracts and, accordingly, the effects of the basis swaps have been
presented together with the associated contracts.
(2) See Note H of Notes to Consolidated Financial Statements included in "Item
8. Financial Statements and Supplementary Data" for hedge volumes and
weighted average prices by calendar quarter for 2002, 2003, 2004 and 2005.
(3) The average forward NYMEX gas prices are based on February 28, 2002 market
quotes.
(4) During January and February 2002, the Company terminated 2003, 2004 and
2005 gas swap contracts for 117,500 MMBtu per day, 110,000 MMBtu per day
and 20,000 MMBtu per day, respectively. Associated therewith, the Company
received $51.4 million of cash proceeds representing deferred hedge gains.
These deferred hedge gains will be recorded as increments to gas revenues
as follows: $23.5 million during 2003, $26.7 million in 2004 and $1.2
million in 2005. During February 2002, the Company entered into 50,000
MMBtu per day of April through December 2002 costless collar contracts
having floor prices of $2.40 per MMBtu and ceiling prices of $3.08 per
MMBtu and 50,000 MMBtu per day of August through December 2002 costless
collars having floor prices of $2.50 per Mcf and ceiling prices of $3.25
per MMBtu. These changes in financial instruments are not reflected in the
table.
Natural Gas Price Sensitivity
Derivative Financial Instruments as of December 31, 2000
Asset
(Liability)
2001 2002 2003 2004 Fair Value
------- ------- ------- ------- ----------
Natural Gas Hedge Derivatives (1):
Average daily notional MMBtu volumes:
Swap contracts.................................. 76,346 $ (79,771)
Weighted average per MMBtu fixed price......... $ 4.59
Collar contracts................................ 54,482 $ (67,281)
Weighted average short call per MMBtu
ceiling price............................... $ 2.73
Weighted average long put per MMBtu
contingent floor price...................... $ 2.11
Natural Gas Non-hedge Derivatives (2):
Daily notional MMBtu volumes under
agreement to swap NYMEX gas price
for 10 percent of NYMEX WTI price............... 13,036 13,036 13,036 13,036 $ (25,507)
Average forward NYMEX gas prices (3)........... $ 4.05 $ 4.61 $ 4.29 $ 4.35
Average forward NYMEX oil prices (3)........... $ 27.69 $ 24.15 $ 22.21 $ 21.54
--------------
(1) To minimize basis risk, the Company enters into basis swaps for a portion
of its gas hedges to convert the index price of the hedging instrument from
a NYMEX index to an index which reflects the geographic area of production.
The Company considers these basis swaps as part of the associated swap and
option contracts and, accordingly, the effects of the basis swaps have been
presented together with the associated contracts.
(2) Since the oil non-hedge derivatives were sensitive to changes in both oil
and gas market prices, they are duplicated in the Oil Price Sensitivity and
the Natural Gas Price Sensitivity tables as of December 31, 2000.
(3) The average forward NYMEX oil and gas prices are based on February 20, 2001
market quotes, except for the 2001 prices that represent locked-in prices
associated with the Company's Btu swaps.
41
Other price sensitivity. As of December 31, 2000, the Company owned
613,215 shares of a non-affiliated entity having an aggregate fair value of
$12.7 million. During 2001, the Company sold its shares for $12.7 million (see
Notes C, E and K of Notes to Consolidated Financial Statements included in "Item
8. Financial Statements and Supplementary Data" for more information regarding
the shares sold).
Qualitative Disclosures
Non-derivative financial instruments. The Company is a borrower under
fixed rate and variable rate debt instruments that give rise to interest rate
risk. The Company's objective in borrowing under fixed or variable rate debt is
to satisfy capital requirements while minimizing the Company's costs of capital.
To realize its objectives, the Company borrows under fixed and variable rate
debt instruments, based on the availability of capital, market conditions and
hedge opportunities. See Note D of Notes to Consolidated Financial Statements
included in "Item 8. Financial Statements and Supplementary Data" for a
discussion relative to the Company's debt instruments.
As described in "Other price sensitivity" above, the Company owned
613,215 shares of a non-affiliated entity. The Company does not routinely
acquire shares of common stock of publicly traded entities for investment
purposes. The shares were received by the Company in partial consideration for
assets sold to the non-affiliated entity.
Derivative financial instruments. The Company has entered into interest
rate, foreign exchange rate and commodity price derivative contracts to hedge
interest rate, foreign exchange rate and commodity price risks. Although the
Company is a party to certain derivative contracts that do not qualify for hedge
accounting treatment, the Company's policy is to limit its participation in
derivative contracts to those that, in the opinion of management, reduce the
Company's overall economic risk.
As of December 31, 2001 and 2000, the Company was a party to the Btu swap
contracts that are described more fully in Quantitative Disclosures, above, and
Note H of Notes to Consolidated Financial Statements included in "Item 8.
Financial Statements and Supplementary Data". These financial instruments do not
qualify as hedges of commodity price risk under generally accepted accounting
standards.
As of December 31, 2001, the Company's primary risk exposures associated
with financial instruments to which it is a party include oil and gas price
volatility, volatility in the exchange rates of the Canadian dollar and
Argentine peso against the U.S. dollar and interest rate volatility. The
Company's primary risk exposures associated with financial instruments have not
changed significantly since December 31, 2001.
42
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Index to Consolidated Financial Statements
Page
Consolidated Financial Statements of Pioneer Natural Resources Company:
Independent Auditors' Report......................................... 44
Consolidated Balance Sheets as of December 31, 2001 and 2000......... 45
Consolidated Statements of Operations for the Years Ended
December 31, 2001, 2000 and 1999.................................. 46
Consolidated Statements of Stockholders' Equity for the Years
Ended December 31, 2001, 2000 and 1999............................ 47
Consolidated Statements of Cash Flows for the Years Ended
December 31, 2001, 2000, and 1999................................. 48
Consolidated Statements of Comprehensive Income (Loss) for the
Years Ended December 31, 2001, 2000 and 1999...................... 49
Notes to Consolidated Financial Statements........................... 50
Unaudited Supplementary Information.................................. 82
43
INDEPENDENT AUDITORS' REPORT
The Board of Directors and Shareholders
Pioneer Natural Resources Company:
We have audited the accompanying consolidated balance sheets of Pioneer
Natural Resources Company as of December 31, 2001 and 2000, and the related
consolidated statements of operations, stockholders' equity, cash flows and
comprehensive income (loss) for each of the three years in the period ended
December 31, 2001. 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 consolidated financial statements referred to above
present fairly, in all material respects, the consolidated financial position of
Pioneer Natural Resources Company at December 31, 2001 and 2000, and the
consolidated results of its operations and its cash flows for each of the three
years in the period ended December 31, 2001, in conformity with accounting
principles generally accepted in the United States.
As discussed in Note B to the consolidated financial statements, in 2001
Pioneer Natural Resources Company adopted Statement of Financial Accounting
Standards No. 133, "Accounting for Derivative Instruments and Hedging
Activities".
Ernst & Young LLP
Dallas, Texas
January 25, 2002
44
PIONEER NATURAL RESOURCES COMPANY
CONSOLIDATED BALANCE SHEETS
(in thousands, except share data)
ASSETS
December 31,
-------------------------
2001 2000
----------- -----------
Current assets:
Cash and cash equivalents........................................ $ 14,334 $ 26,159
Accounts receivable:
Trade, net of reserves for doubtful accounts of
$5,553 and $4,766 as of December 31, 2001 and
2000, respectively........................................... 81,616 123,497
Affiliates..................................................... 595 2,157
Inventories...................................................... 14,549 14,842
Deferred income taxes............................................ 6,400 4,800
Other current assets:
Derivative assets, net of $3,153 valuation reserve
as of December 31, 2001...................................... 127,074 11,608
Other.......................................................... 11,075 8,328
---------- ----------
Total current assets......................................... 255,643 191,391
---------- ----------
Property, plant and equipment, at cost:
Oil and gas properties, using the successful efforts
method of accounting:
Proved properties.............................................. 3,691,783 3,187,889
Unproved properties............................................ 187,785 229,205
Accumulated depletion, depreciation and amortization............. (1,095,310) (902,139)
---------- ----------
2,784,258 2,514,955
---------- ----------
Deferred income taxes.............................................. 84,319 84,400
Other property and equipment, net.................................. 21,560 25,624
Other assets, net:
Derivative assets, net of $1,069 valuation reserve as
of December 31, 2001........................................... 54,486 46,192
Other............................................................ 70,787 91,873
---------- ----------
$ 3,271,053 $ 2,954,435
========== ==========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable:
Trade.......................................................... $ 92,760 $ 96,646
Affiliates..................................................... 6,405 5,629
Interest payable................................................. 37,410 38,142
Other current liabilities:
Derivative obligations......................................... 36,830 24,957
Other.......................................................... 54,804 51,140
---------- ----------
Total current liabilities.................................... 228,209 216,514
---------- ----------
Long-term debt..................................................... 1,577,304 1,578,776
Noncurrent derivative obligations.................................. 32,438 65,974
Other noncurrent liabilities....................................... 133,945 159,766
Deferred income taxes.............................................. 13,768 28,500
Stockholders' equity:
Preferred stock, $.01 par value; 100,000,000 shares
authorized; one share issued and outstanding................... - -
Common stock, $.01 par value; 500,000,000 shares
authorized; 107,422,467 shares issued at December 31,
2001; and 101,268,754 shares issued at December 31, 2000....... 1,074 1,013
Additional paid-in capital....................................... 2,462,272 2,352,608
Treasury stock, at cost; 3,486,073 shares at December 31,
2001 and 2,853,107 shares at December 31, 2000................. (48,002) (37,682)
Accumulated deficit.............................................. (1,323,343) (1,422,703)
Accumulated other comprehensive income:
Deferred hedge gains, net...................................... 201,046 -
Unrealized gain on available for sale securities............... - 8,154
Cumulative translation adjustment.............................. (7,658) 3,515
---------- ----------
Total stockholders' equity................................... 1,285,389 904,905
Commitments and contingencies
---------- ----------
$ 3,271,053 $ 2,954,435
========== ==========
The accompanying notes are an integral part of these consolidated
financial statements.
45
PIONEER NATURAL RESOURCES COMPANY
CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands, except per share data)
Year Ended December 31,
---------------------------------
2001 2000 1999
--------- --------- ---------
Revenues:
Oil and gas............................................... $ 847,022 $ 852,738 $ 644,646
Interest and other........................................ 21,778 25,775 89,657
Gain (loss) on disposition of assets, net................. 7,681 34,184 (24,168)
-------- -------- --------
876,481 912,697 710,135
-------- -------- --------
Costs and expenses:
Oil and gas production.................................... 209,664 189,265 159,530
Depletion, depreciation and amortization.................. 222,632 214,938 236,047
Impairment of oil and gas properties...................... - - 17,894
Exploration and abandonments.............................. 127,906 87,550 65,974
General and administrative................................ 36,968 33,262 40,241
Reorganization............................................ - - 8,534
Interest.................................................. 131,958 161,952 170,344
Other..................................................... 39,588 67,231 34,631
-------- -------- --------
768,716 754,198 733,195
-------- -------- --------
Income (loss) before income taxes and extraordinary items... 107,765 158,499 (23,060)
Income tax benefit (provision).............................. (4,016) 6,000 600
-------- -------- --------
Income (loss) before extraordinary items.................... 103,749 164,499 (22,460)
Extraordinary items - loss on early extinguishment
of debt, net of tax....................................... (3,753) (12,318) -
-------- -------- --------
Net income (loss)........................................... $ 99,996 $ 152,181 $ (22,460)
======== ======== ========
Income (loss) per share:
Basic:
Income (loss) before extraordinary items............... $ 1.05 $ 1.65 $ (.22)
Extraordinary items.................................... (.04) (.12) -
-------- -------- --------
Net income (loss)...................................... $ 1.01 $ 1.53 $ (.22)
======== ======== ========
Diluted:
Income (loss) before extraordinary items............... $ 1.04 $ 1.65 $ (.22)
Extraordinary items.................................... (.04) (.12) -
-------- -------- --------
Net income (loss)...................................... $ 1.00 $ 1.53 $ (.22)
======== ======== ========
Weighted average shares outstanding:
Basic.................................................. 98,529 99,378 100,307
======== ======== ========
Diluted................................................ 99,714 99,763 100,307
======== ======== ========
The accompanying notes are an integral part of these consolidated
financial statements.
46
PIONEER NATURAL RESOURCES COMPANY
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
(in thousands)
Accumulated Other
Comprehensive Income
------------------------------------------------
Deferred
Additional Hedge Investment Total
Common Paid-in Treasury Accumulated Gains & Gains & Translation Stockholders'
Stock Capital Stock Deficit Losses Losses Adjustment Equity
------ ---------- -------- ----------- --------- ---------- ----------- ------------
Balance at January 1, 1998......... $1,008 $2,347,996 $(10,388) $(1,552,442) $ - $ - $ 2,903 $ 789,077
Exercise of stock options and
employee stock purchases......... 1 249 - - - - - 250
Issuance of stock options under
long-term incentive plan......... - 25 - - - - - 25
Restricted shares awarded.......... - 178 4 - - - - 182
Adjustment to dividends............ - - - 18 - - - 18
Realized translation adjustment.... - - - - - - (836) (836)
Net loss........................... - - - (22,460) - - - (22,460)
Other comprehensive income:
Currency translation adjustment.. - - - - - - 8,358 8,358
----- --------- ------- ---------- -------- -------- ------- ---------
Balance at December 31, 1999....... 1,009 2,348,448 (10,384) (1,574,884) - - 10,425 774,614
----- --------- ------- ---------- -------- -------- ------- ---------
Exercise of stock options and
employee stock purchases......... 4 4,160 - - - - - 4,164
Purchase of treasury stock......... - - (27,298) - - - - (27,298)
Net income......................... - - - 152,181 - - - 152,181
Other comprehensive income (loss):
Unrealized gains on available
for sale securities:
Unrealized holdings gains...... - - - - - 33,828 - 33,828
Gains included in net income... - - - - - (25,674) - (25,674)
Currency translation adjustment.. - - - - - (6,910) (6,910)
----- --------- ------- ---------- -------- -------- ------- ---------
Balance at December 31, 2000....... 1,013 2,352,608 (37,682) (1,422,703) - 8,154 3,515 904,905
----- --------- ------- ---------- -------- -------- ------- ---------
Common stock issued for
partnership acquisitions......... 57 104,236 - - - - - 104,293
Exercise of stock options and
employee stock purchases......... 4 5,428 2,708 (636) - - - 7,504
Purchase of treasury stock......... - - (13,028) - - - - (13,028)
Net income......................... - - - 99,996 - - - 99,996
Other comprehensive income (loss):
Deferred hedge gains and losses:
Transition adjustment.......... - - - - (197,444) - - (197,444)
Deferred hedge gains........... - - - - 393,004 - - 393,004
Net losses included in net
income........................ - - - - 5,486 - - 5,486
Unrealized gains and losses on
available for sale securities:
Unrealized holdings losses..... - - - - - (45) - (45)
Gains included in net income... - - - - - (8,109) - (8,109)
Currency translation adjustment.. - - - - - - (11,173) (11,173)
----- --------- ------- ---------- -------- -------- ------- ---------
Balance at December 31, 2001....... $1,074 $2,462,272 $(48,002) $(1,323,343) $ 201,046 $ - $ (7,658) $1,285,389
===== ========= ======= ========== ======== ======== ======= =========
The accompanying notes are an integral part of these consolidated
financial statements.
47
PIONEER NATURAL RESOURCES COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
Year Ended December 31,
-----------------------------------
2001 2000 1999
--------- ----------- ---------
Cash flows from operating activities:
Net income (loss)........................................... $ 99,996 $ 152,181 $ (22,460)
Adjustments to reconcile net income (loss) to net cash
provided by operating activities:
Depletion, depreciation and amortization............... 222,632 214,938 236,047
Impairment of oil and gas properties................... - - 17,894
Exploration expenses, including dry holes.............. 103,595 66,959 50,030
Deferred income taxes.................................. (7,649) (10,600) -
(Gain) loss on disposition of assets, net.............. (7,681) (34,184) 24,168
Loss on early extinguishment of debt, net of tax....... 3,753 12,318 -
Other noncash items.................................... 29,832 72,475 (866)
Change in operating assets and liabilities, net of
effects from acquisitions:
Accounts receivable.................................... 41,295 (7,486) (7,393)
Inventory.............................................. (4,256) (2,789) (952)
Other current assets................................... (6,304) (9,896) (2,335)
Accounts payable....................................... (541) 26,260 (18,683)
Interest payable....................................... (733) 2,097 2,851
Other current liabilities.............................. 1,661 (52,177) (23,067)
-------- ---------- --------
Net cash provided by operating activities.............. 475,600 430,096 255,234
-------- ---------- --------
Cash flows from investing activities:
Cash acquired in acquisition, net of fees paid.............. 11,119 - -
Proceeds from disposition of assets......................... 113,453 102,736 390,531
Additions to oil and gas properties......................... (529,723) (299,682) (179,669)
Other property dispositions (additions), net................ (17,590) 2,445 (11,867)
-------- ---------- --------
Net cash provided by (used in) investing activities.... (422,741) (194,501) 198,995
-------- ---------- --------
Cash flows from financing activities:
Borrowings under long-term debt............................. 328,331 922,607 355,493
Principal payments on long-term debt........................ (333,410) (1,099,935) (793,919)
Payments of other noncurrent liabilities.................... (53,437) (29,759) (34,002)
Purchase of treasury stock.................................. (13,028) (27,298) -
Deferred loan fees/issuance costs........................... - (13,847) (6,891)
Exercise of stock options and employee stock purchases...... 7,504 4,164 250
-------- ---------- --------
Net cash used in financing activities.................. (64,040) (244,068) (479,069)
-------- ---------- --------
Net decrease in cash and cash equivalents .................... (11,181) (8,473) (24,840)
Effect of exchange rate changes on cash and cash equivalents.. (644) (156) 407
Cash and cash equivalents, beginning of year.................. 26,159 34,788 59,221
-------- ---------- --------
Cash and cash equivalents, end of year........................ $ 14,334 $ 26,159 $ 34,788
======== ========== ========
The accompanying notes are an integral part of these consolidated
financial statements.
48
PIONEER NATURAL RESOURCES COMPANY
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(in thousands)
Year ended December 31,
---------------------------------
2001 2000 1999
--------- --------- ---------
Net income (loss)....................................... $ 99,996 $ 152,181 $ (22,460)
Other comprehensive income:
Deferred hedge gains and losses:
Transition adjustment.............................. (197,444) - -
Deferred hedge gains............................... 393,004 - -
Net losses included in net income.................. 5,486 - -
Gains and losses on available for sale securities:
Unrealized holding gains and losses................ (45) 33,828 -
Gains included in net income....................... (8,109) (25,674) -
Translation adjustment:
Currency translation adjustment.................... (11,173) (6,910) 8,358
Realized translation adjustment.................... - - (836)
-------- -------- --------
Other comprehensive income....................... 181,719 1,244 7,522
-------- -------- --------
Comprehensive income (loss)............................. $ 281,715 $ 153,425 $ (14,938)
======== ======== ========
The accompanying notes are an integral part of these consolidated
financial statements.
49
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2001, 2000 and 1999
NOTE A. Organization and Nature of Operations
Pioneer Natural Resources Company (the "Company") is a Delaware
corporation whose common stock is listed and traded on the New York Stock
Exchange and the Toronto Stock Exchange. The Company is an oil and gas
exploration and production company with ownership interests in oil and gas
properties located principally in the Mid Continent, Southwestern and onshore
and offshore Gulf Coast regions of the United States and in Argentina, Canada,
South Africa, Gabon and Tunisia.
NOTE B. Summary of Significant Accounting Policies
Principles of consolidation. The consolidated financial statements
include the accounts of the Company and its wholly-owned subsidiaries since
their acquisition or formation, and the Company's interest in the affiliated oil
and gas partnerships for which it serves as general partner through certain of
its wholly-owned subsidiaries. The Company proportionately consolidates less
than 100 percent-owned oil and gas partnerships in accordance with industry
practice. The Company owns less than a 20 percent interest in the oil and gas
partnerships that it proportionately consolidates. All material intercompany
balances and transactions have been eliminated.
Investments in non-affiliated equity securities that have a readily
determinable fair value are classified as "trading securities" if management's
current intent is to hold them for only a short period of time; otherwise, they
are accounted for as "available-for-sale" securities. The Company reevaluates
the classification of investments in non-affiliated equity securities at each
balance sheet date. The carrying value of trading securities and
available-for-sale securities are adjusted to fair value as of each balance
sheet date.
Unrealized holding gains are recognized for trading securities in
interest and other revenue, and unrealized holding losses are recognized in
other expense during the periods in which changes in fair value occur. The
Company did not have any investments in trading securities as of December 31,
2001 or 2000.
Unrealized holding gains and losses are recognized for available-for-sale
securities as credits or charges to stockholders' equity and other comprehensive
income (loss) during the periods in which changes in fair value occur. Realized
gains and losses on the divestiture of available-for-sale securities are
determined using the average cost method. The Company did not have any
investments in available-for-sale securities as of December 31, 2001. See Notes
C and K below for the fair value and a description of the available-for-sale
securities held as of December 31, 2000.
Investments in non-affiliated equity securities that do not have a
readily determinable fair value are measured at the lower of their original cost
or the net realizable value of the investment. The Company did not have any
equity security investments that did not have a readily determinable fair value
as of December 31, 2001 or 2000.
Use of estimates in the preparation of financial statements. Preparation
of the accompanying consolidated 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, the
disclosure of contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenues and expenses during the
reporting periods. Depletion of oil and gas properties is determined using
estimates of proved oil and gas reserves. There are numerous uncertainties
inherent in the estimation of quantities of proved reserves and in the
projection of future rates of production and the timing of development
expenditures. Similarly, evaluations for impairment of proved and unproved oil
and gas properties are subject to numerous uncertainties including, among
others, estimates of future recoverable reserves; commodity price outlooks;
foreign laws, restrictions and currency exchange rates; and export and excise
taxes.
50
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2001, 2000 and 1999
Early in January 2002, the Argentine government severed the direct
one-to-one U.S. dollar to Argentine peso relationship that has existed for many
years. The following bullet points disclose the significant Argentine
assumptions utilized in the preparation of the 2001 financial statements:
o As of December 31, 2001, the Company used an exchange rate of 1.7 pesos to
$1 to remeasure the peso-denominated monetary assets and liabilities of the
Company's Argentine subsidiaries.
o As part of the remeasurement process, the Company generally estimated that
the recovery or settlement values to be realized on peso-denominated
receivables and payables would be approximately 1.2 pesos to $1.
o After remeasuring inventory at historical exchange rates, the Company
reduced the carrying value of its Argentine lease and well equipment to
market values. The market value of the inventory was estimated to be 15
percent higher than the historical peso balance, but on an equivalent U.S.
dollar basis, lower than the Company's carrying cost.
o The Company reviewed its Argentine proved and unproved properties for
impairment as of December 31, 2001. The Company's assessments were based on
the Company's expectations of future commodity prices to be received and
expenses to be paid in Argentina. The assumptions utilized to determine
future net cash flows had oil and natural gas liquids ("NGLs") prices
returning to world market prices after a short-term period to allow for
price inflation. Similarly, gas prices also were assumed to return to
predevaluation U.S. dollar levels after a short-term period to allow for
inflation. Expenses were assumed to devalue with the peso, but to gradually
increase to 80 percent of predevaluation amounts. Based upon these
assumptions, the Company determined that the carrying value of its proved
and unproved properties was fully recoverable.
The remeasurement of the peso-denominated monetary net assets and the
adjustment to reduce the carrying amount of lease and well equipment inventory
to market values resulted in the Company recognizing a $7.7 million charge in
2001. Numerous uncertainties exist surrounding the ultimate resolution of
Argentina's economic and political instability and actual results could differ
from those estimates and assumptions utilized.
The Argentine economic and political situation continues to evolve and
the Argentine government may enact future regulations or policies that, when
finalized and adopted, may materially impact, among other items, (i) the
realized prices the Company receives for the commodities it produces and sells
as a result of new export taxes or higher production taxes; (ii) the timing of
repatriations of excess cash flow to the Company's corporate headquarters in the
United States; (iii) the Company's asset valuations; and (iv) peso-denominated
monetary assets and liabilities.
Cash equivalents. Cash and cash equivalents include cash on hand and
depository accounts held by banks.
Inventories - equipment. Lease and well equipment to be used in future
production and drilling activities are carried at the lower of cost or market,
on a first-in, first-out basis.
Inventories - commodities. Commodities are carried at the lower of
average cost or market. When sold from inventory, commodities are charged to
expense on a first-in, first-out basis.
Oil and gas properties. The Company utilizes the successful efforts
method of accounting for its oil and gas properties. Under this method, all
costs associated with productive wells and nonproductive development wells are
capitalized while nonproductive exploration costs and geological and geophysical
expenditures are expensed. The Company also expenses the costs associated with
exploratory wells that find oil and gas reserves if a determination that proved
reserves have been found cannot be made within one year of the exploration well
51
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2001, 2000 and 1999
being drilled. The Company capitalizes interest on expenditures for significant
development projects until such projects are ready for their intended use.
The Company owns interests in nine natural gas processing plants and four
treating facilities. The Company operates six of the plants and all four
treating facilities. The Company's ownership in the natural gas processing
plants and treating facilities is primarily to accommodate handling the
Company's gas production and thus are considered a component of the capital and
operating costs of the respective fields that they service. To the extent that
there is excess capacity at a plant or treating facility, the Company attempts
to process third party gas volumes for a fee to keep the plant or treating
facility at capacity. All revenues and expenses derived from third party gas
volumes processed through the plants and treating facilities are reported as
components of oil and gas production costs. The third party revenues generated
from the plant and treating facilities for the three years ended December 31,
2001, 2000 and 1999 were $28.2 million, $36.3 million and $32.7 million,
respectively. The third party expenses attributable to the plants and treating
facilities for those same periods were $9.2 million, $9.0 million and $9.7
million, respectively. The capitalized costs of the plants and treating
facilities are included in proved oil and gas properties and are depleted using
the unit-of-production method along with the other capitalized costs of the
field that they service.
Capitalized costs relating to proved properties are depleted using the
unit-of-production method based on proved reserves as determined by the
Company's engineers. Costs of significant nonproducing properties, wells in the
process of being drilled and development projects are excluded from depletion
until such time as the related project is developed and proved reserves are
established or impairment is determined.
Capitalized costs of individual properties sold or abandoned are charged
to accumulated depletion, depreciation and amortization with the proceeds from
the sales of individual properties credited to property costs. No gain or loss
is recognized until the entire amortization base is sold. However, gain or loss
is recognized from the sale of less than an entire amortization base if the
disposition is significant enough to materially impact the depletion rate of the
remaining properties in the amortization base.
If significant, the Company accrues the estimated future costs to plug
and abandon wells under the unit-of-production method. The charge, if any, is
reflected in the accompanying Consolidated Statements of Operations as
abandonment expense while the liability is reflected in the accompanying
Consolidated Balance Sheets as other liabilities. Plugging and abandonment
liabilities assumed in a business combination accounted for as a purchase are
recorded at fair value. At December 31, 2001 and 2000, the Company has
recognized plugging and abandonment liabilities of $39.5 million and $42.0
million, respectively.
The Company reviews its long-lived assets to be held and used, including
proved oil and gas properties accounted for under the successful efforts method
of accounting, whenever events or circumstances indicate that the carrying value
of those assets may not be recoverable. An impairment loss is indicated if the
sum of the expected future cash flows is less than the carrying amount of the
assets. In this circumstance, the Company recognizes an impairment loss for the
amount by which the carrying amount of the asset exceeds the estimated fair
value of the asset.
Unproved oil and gas properties that are individually significant are
periodically assessed for impairment by comparing their cost to their estimated
value on a project-by-project basis. The estimated value is affected by the
results of exploration activities, commodity price outlooks, planned future
sales or expiration of all or a portion of such projects. If the quantity of
potential reserves determined by such evaluations is not sufficient to fully
recover the cost invested in each project, the Company will recognize an
impairment loss at that time by recording an allowance. The remaining unproved
oil and gas properties are aggregated and an overall impairment allowance is
provided based on the Company's historical experience.
52
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2001, 2000 and 1999
Treasury stock. Treasury stock purchases are recorded at cost. Upon
reissuance, the cost of treasury shares held is reduced by the average purchase
price per share of the aggregate treasury shares held.
Environmental. The Company's environmental expenditures are expensed or
capitalized depending on their future economic benefit. Expenditures that relate
to an existing condition caused by past operations and that have no future
economic benefits are expensed. Expenditures that extend the life of the related
property or mitigate or prevent future environmental contamination are
capitalized. Liabilities are recorded when environmental assessment and/or
remediation is probable and the costs can be reasonably estimated. Such
liabilities are undiscounted unless the timing of cash payments for the
liability are fixed or reliably determinable.
Revenue recognition. The Company uses the entitlements method of
accounting for oil, NGL and gas revenues. Sales proceeds in excess of the
Company's entitlement are included in other liabilities and the Company's share
of sales taken by others is included in other assets in the accompanying
Consolidated Balance Sheets. The following table presents the entitlement assets
and entitlement liabilities and their associated volumes as of December 31, 2001
and 2000 (in millions):
December 31,
---------------------------------
2001 2000
--------------- ---------------
Amount MMcf Amount MMcf
------ ------ ------ ------
Entitlement assets............................ $ 30.9 25,335 $ 33.7 26,780
Entitlement liabilities....................... $ 20.3 15,197 $ 19.0 13,830
Stock-based compensation. The Company accounts for employee stock-based
compensation using the intrinsic value method prescribed by Accounting
Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees"
("APB 25"). Accordingly, no compensation expense is recognized for stock options
granted to employees or directors when the exercise price of options granted is
equal to or above the quoted market price of the Company's common stock on the
date of grant. The Company has disclosed the pro forma net income (loss) and net
income (loss) per share amounts as required by Statement of Financial Accounting
Standards No.123, "Accounting for Stock-Based Compensation" ("SFAS 123") in Note
F below.
Derivatives and hedging. Prior to January 1, 2001, the following criteria
were required to be met in order for the Company to account for a derivative
instrument as a hedge of an existing asset or liability, or of a forecasted
transaction: an asset, liability or forecasted transaction must have existed
that exposed the Company to price, interest rate or foreign exchange rate risk
that was not offset in another asset or liability; the derivative instrument
must have reduced that price, interest rate or foreign exchange rate risk; and,
the derivative instrument must have been designated as a hedge at the inception
of the instrument and throughout the hedge period. Additionally, in order to
qualify as a hedge, there must have been clear correlation between changes in
the fair value or expected cash flows of the derivative instrument and the fair
value or expected cash flows of the hedged asset or liability, or forecasted
transaction, such that changes in the derivative instrument offset the effect of
price, interest rate or foreign exchange rate changes on the exposed items.
Prior to January 1, 2001, gains or losses realized from derivative
instruments that qualified as hedges were deferred as assets or liabilities
until the underlying hedged asset, liability or transaction monetized, matured
or was otherwise recognized under generally accepted accounting principles. When
recognized in net income (loss), hedge gains and losses are classified as
components of the commodity prices, interest or foreign exchange rates that the
derivative instrument hedged. Derivative instruments that are not hedges are
recorded at fair value, as assets or liabilities. Changes in the fair values of
non-hedge derivative instruments are recognized as other income or other expense
during the periods in which their fair values change. See Note H for a
description of the specific types of derivative transactions in which the
Company participates.
53
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2001, 2000 and 1999
In June 1998, the Financial Accounting Standards Board issued Statement
of Financial Accounting Standards No. 133, "Accounting for Derivative
Instruments and Hedging Activities" ("SFAS 133") as amended, the provisions of
which the Company adopted effective January 1, 2001.
SFAS 133 requires the accounting recognition of all derivative
instruments as either assets or liabilities at fair value. Derivative
instruments that are not hedges must be adjusted to fair value through net
income (loss). Under the provisions of SFAS 133, changes in the fair value of
derivative instruments that are fair value hedges are offset against changes in
the fair value of the hedged assets, liabilities, or firm commitments, through
net income (loss). Effective changes in the fair value of derivative instruments
that are cash flow hedges are recognized in other comprehensive income (loss) in
stockholders' equity until such time as the hedged items are recognized in net
income (loss). Ineffective portions of a derivative instrument's change in fair
value are immediately recognized in net income (loss).
The adoption of SFAS 133 resulted in a January 1, 2001 transition
adjustment to (i) reclassify $57.8 million of deferred losses on terminated
hedge positions from other assets (including $11.6 million of other current
assets), (ii) increase other current assets, other assets and other current
liabilities by $7.0 million, $6.2 million and $146.6 million, respectively, to
record the fair value of open hedge derivatives, (iii) increase the carrying
value of hedged long-term debt by $6.2 million and (iv) reduce stockholders'
equity by $197.4 million for the net impact of items (i) through (iii) above.
The $197.4 million reduction in stockholders' equity was reflected as a
transition adjustment in other comprehensive income (loss) as of January 1,
2001.
Under the provisions of SFAS 133, the Company may designate a derivative
instrument as hedging the exposure to changes in the fair value of an asset or a
liability or an identified portion thereof that is attributable to a particular
risk (a "fair value hedge") or as hedging the exposure to variability in
expected future cash flows that are attributable to a particular risk (a "cash
flow hedge"). Both at the inception of a hedge and on an ongoing basis, a fair
value hedge must be expected to be highly effective in achieving offsetting
changes in fair value attributable to the hedged risk during the periods that a
hedge is designated. Similarly, a cash flow hedge must be expected to be highly
effective in achieving offsetting cash flows attributable to the hedged risk
during the term of the hedge. The Company's policy is to assess actual hedge
effectiveness at the end of each calendar quarter.
Foreign currency translation. The U.S. dollar is the functional currency
for all of the Company's international operations except Canada. Accordingly,
monetary assets and liabilities denominated in a foreign currency are remeasured
to U.S. dollars at the exchange rate in effect at the end of each reporting
period; revenues and costs and expenses denominated in a foreign currency are
remeasured at the average of the exchange rates that were in effect during the
period in which the revenues and costs and expenses were recognized. The
resulting gains or losses from remeasuring foreign currency denominated balances
into U.S. dollars are recorded in other income or other expense, respectively.
Non-monetary assets and liabilities denominated in a foreign currency are
remeasured at the historic exchange rates that were in effect when the asset or
liabilities were acquired or incurred.
The functional currency of the Company's Canadian operations is the
Canadian dollar. The financial statements of the Company's Canadian subsidiary
entities are translated to U. S. dollars as follows: all assets and liabilities
are translated using the exchange rate in effect at the end of each reporting
period; revenues and costs and expenses are translated using the average of the
exchange rates that were in effect during the period in which the revenues and
costs and expenses were recognized. The resulting gains or losses from
translating non-U.S. dollar denominated balances are recorded in the
accompanying Consolidated Statements of Stockholders' Equity for the period
through accumulated other comprehensive income (loss).
54
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2001, 2000 and 1999
The exchange rates used in the preparation of these consolidated
financial statements appear below:
December 31,
------------------------
2001 2000 1999
------ ------ ------
Translation:
U.S. Dollar from Canadian Dollar - Balance Sheets................. .6277 .6671 .6915
U.S. Dollar from Canadian Dollar - Statements of Operations....... .6356 .6650 .6700
Reclassifications. Certain reclassifications have been made to the 2000
and 1999 amounts to conform to the 2001 presentation.
NOTE C. Disclosures About Fair Value of Financial Instruments
The following table presents the carrying amounts and estimated fair
values of the Company's financial instruments as of December 31, 2001 and 2000
(in thousands):
2001 2000
--------------------- ---------------------
Carrying Fair Carrying Fair
Value Value Value Value
--------- --------- --------- ---------
Financial assets:
Investment in non-affiliated entity........... $ - $ - $ 12,724 $ 12,724
Financial liabilities - long-term debt:
Practicable to estimate fair value:
Line of credit............................. $ 294,000 $ 294,000 $ 225,000 $ 225,000
8-7/8% senior notes due 2005............... $ 161,998 $ 159,000 $ 149,546 $ 153,000
8-1/4% senior notes due 2007............... $ 153,672 $ 154,215 $ 150,661 $ 148,125
6-1/2% senior notes due 2008............... $ 332,613 $ 329,280 $ 348,691 $ 315,000
9-5/8% senior notes due 2010............... $ 385,110 $ 421,508 $ 423,577 $ 480,375
7-1/5% senior notes due 2028............... $ 249,911 $ 204,175 $ 249,910 $ 193,750
Other...................................... $ - $ - $ 31,391 $ -
Derivative contract assets (liabilities):
Interest rate swaps........................ $ (19,637) $ (19,637) $ - $ 6,216
Foreign currency contracts................. $ 61 $ 61 $ - $ -
Commodity price hedges..................... $ 151,290 $ 151,290 $ (52,253) $(192,306)
Btu swap contracts......................... $ (19,422) $ (19,422) $ (25,507) $ (25,507)
Cash and cash equivalents, accounts receivable, other current assets,
accounts payable, interest payable and other current liabilities. The carrying
amounts approximate fair value due to the short maturity of these instruments.
Investments in non-affiliated entity. As of December 31, 2000, the
Company owned 613,215 common shares of Prize Energy Corp. ("Prize") common stock
("Prize Common"). The Prize Common had a fair value of $12.7 million on December
31, 2000, including $8.2 million of unrealized holding gains, and is included in
other assets in the accompanying Consolidated Balance Sheet as of December 31,
2000. During 2001, the Company sold its remaining shares of Prize Common (see
Note K for additional information regarding the Prize Common divestiture).
Long-term debt. The carrying amount of borrowings outstanding under the
Company's corporate credit facility (see Note D) approximates fair value because
these instruments bear interest at variable market rates. The fair values of
each of the senior note issuances were based on quoted market prices for each of
these issues. Other long-term debt was insignificant and no estimate of fair
value was performed.
Interest rate swaps, foreign currency swap contracts and commodity price
swap and collar contracts. The fair value of interest rate swaps, foreign
currency contracts and commodity price swap and collar contracts are estimated
from quotes provided by the counterparties to these derivative contracts and
represent the estimated amounts that the Company would expect to receive or pay
55
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2001, 2000 and 1999
to settle the derivative contracts. See Note H for a description of each of
these derivatives, including whether the derivative contract qualifies for hedge
accounting treatment or is considered a speculative derivative contract.
NOTE D. Long-term Debt
Long-term debt, including the effects of fair value hedges and discounts,
consisted of the following components at December 31, 2001 and 2000:
December 31,
------------------------
2001 2000
---------- -----------
(in thousands)
Line of credit.................................... $ 294,000 $ 225,000
8-7/8% senior notes due 2005...................... 161,998 149,546
8-1/4% senior notes due 2007...................... 153,672 150,661
6-1/2% senior notes due 2008...................... 332,613 348,691
9-5/8% senior notes due 2010...................... 385,110 423,577
7-1/5% senior notes due 2028...................... 249,911 249,910
Other............................................. - 31,391
--------- ---------
$1,577,304 $1,578,776
========= =========
Maturities of long-term debt at December 31, 2001 are as follows (in
thousands):
2002 through 2004................................. $ -
2005.............................................. $ 455,998
2006.............................................. $ -
Thereafter........................................ $1,121,306
Line of credit. During May 2000, the Company entered into a $575.0
million corporate credit facility (the "Credit Agreement") with a syndication of
banks (the "Banks") that matures on March 1, 2005. Advances under the Credit
Agreement bear interest, at the option of the Company, based on (a) a base rate
equal to the higher of the Bank of America, N.A. prime rate (4.75 percent at
December 31, 2001) or a rate per annum based on the weighted average of the
rates on overnight Federal funds transactions with members of the Federal
Reserve System (1.52 percent at December 31, 2001), plus 50 basis points; plus a
eurodollar margin (the "Eurodollar Margin") less 125 basis points, (b) a
Eurodollar rate, substantially equal to the London Interbank Offered Rate
("LIBOR") (1.88 percent at December 31, 2001 for 90 day borrowings), plus a
Eurodollar Margin, or (c) a fixed rate (for aggregate advances not exceeding $50
million) as quoted by the Banks pursuant to a request by the Company. The
Eurodollar Margin is based on a grid of the Company's debt ratings and ratio of
total debt to earnings before gain or loss on the disposition of assets;
interest expense; income taxes; depreciation, depletion and amortization
expense; exploration and abandonment expense and other noncash expenses (the
"Total Leverage Ratio"). As of December 31, 2001, the Eurodollar Margin is 125
basis points.
The Credit Agreement imposes certain restrictive covenants on the
Company, including the maintenance of a Total Leverage Ratio not to exceed 4.00
to 1.00 through September 30, 2002 and 3.75 to 1.00 thereafter; maintenance of
an annual ratio of the net present value of the Company's oil and gas properties
to total debt of at least 1.25 to 1.00; a limitation on the Company's total
debt; and, restrictions on certain payments. The Company is in compliance with
the debt covenants as of December 31, 2001.
As of December 31, 2001 and 2000, the Company had $27.9 million of
undrawn letters of credit issued under the Credit Agreement and unused Credit
Agreement borrowing capacity of $253.1 million and $322.1 million, respectively.
56
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2001, 2000 and 1999
Senior notes. The Company's senior notes are general unsecured
obligations ranking equally in right of payment with all other senior unsecured
indebtedness of the Company and are senior in right of payment to all existing
and future subordinated indebtedness of the Company. The Company is a holding
company that conducts all of its operations through subsidiaries; consequently,
the senior notes issuances are structurally subordinated to all obligations of
its subsidiaries. Pioneer Natural Resources USA, Inc. ("Pioneer USA"), a
wholly-owned subsidiary, has fully and unconditionally guaranteed the senior
note issuances. See Note R for a discussion of Pioneer USA debt guarantees and
Consolidating Financial Statements. Interest on the Company's senior notes is
payable semiannually.
During April 2000, the Company issued $425.0 million of 9-5/8 percent
senior notes Due April 1, 2010 (the "9-5/8 percent senior notes"). The 9-5/8
percent senior notes were issued at a discount of .353 percent and resulted in
net proceeds to the Company, after underwriting discounts, commissions and costs
of issuance, of $415.4 million. The net proceeds from the issuance of the 9-5/8
percent senior notes were used to reduce outstanding borrowings under the
Company's revolving credit facility. The 9-5/8 percent senior notes contain
various restrictive covenants, including restrictions on the incurrence of
additional indebtedness and certain payments defined within the associated
indenture. The Company is in compliance with the debt covenants as of December
31, 2001.
Early extinguishment of debt. During July 2001, the Company redeemed the
remaining $22.5 million of outstanding 11-5/8 percent senior subordinated
discount notes due July 1, 2006 and $6.8 million of outstanding 10-5/8 percent
senior subordinated notes due July 1, 2006. Additionally, during the quarter
ended December 31, 2001, the Company redeemed $38.7 million of the 9-5/8 percent
senior notes. Associated with these redemptions, the Company recognized an
extraordinary loss, net of taxes, of $3.8 million during the year ended December
31, 2001. In May 2000, the Company recognized an extraordinary loss of $12.3
million, net of tax, from the early extinguishment of its prior revolving credit
facility.
Interest expense. The following amounts have been charged to interest
expense for the years ended December 31, 2001, 2000 and 1999:
2001 2000 1999
-------- -------- --------
(in thousands)
Cash payments for interest................................. $129,992 $147,156 $150,929
Accretion/amortization of discounts or premiums on loans... 7,937 7,995 8,401
Interest capitalized....................................... (5,991) - -
Amortization of deferred hedge gains (see Note H).......... (2,750) - -
Amortization of capitalized loan fees...................... 2,252 2,769 2,686
Kansas ad valorem tax accrual (see Note G)................. 1,250 1,935 1,433
Net change in accruals..................................... (732) 2,097 6,895
------- ------- -------
$131,958 $161,952 $170,344
======= ======= =======
NOTE E. Related Party Transactions
Activities with affiliated partnerships. The Company, through its
wholly-owned subsidiaries, has in the past sponsored certain affiliated
partnerships, including 44 drilling partnerships, three public income
partnerships and 13 affiliated employee partnerships, all of which were formed
primarily for the purpose of drilling and completing wells or acquiring
producing properties. In 1992, the Company discontinued sponsoring public and
private oil and gas development drilling partnerships, income partnerships and
affiliated employee partnerships.
In December 2001, the limited partners of 42 of the Company's affiliated
partnerships approved an agreement and plan of merger ("Plan of Merger") among
the Company, Pioneer USA and the partnerships. The Plan of Merger was accounted
for as a purchase business combination. In consideration for the partnerships'
net assets, the limited partners received 5,683,557 shares of the Company's
common stock valued at $18.35 per share. In connection with this transaction,
57
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2001, 2000 and 1999
the Company acquired net proved reserves of approximately 29 million barrels of
oil equivalent, $13.6 million of cash held on deposit by the partnerships and
$.3 million of other net assets. The cash acquired from the partnerships, net of
$2.5 million of cash transaction costs, is included in cash acquired in
acquisitions, net of fees paid in the accompanying Consolidated Statement of
Cash Flows for the year ended December 31, 2001. Except for the cash acquired,
this transaction represents a noncash investing activity of the Company that was
funded by the issuance of common stock.
In December 2000, the Company received the approval of the partners of 13
employee partnerships to merge with Pioneer USA for a purchase price of $2.0
million. Of the total purchase price, $317 thousand was paid to current Company
employees. Additionally, during 2000, the Company purchased all of the direct
oil and gas interests held by the Company's Chairman of the Board and Chief
Executive Officer for $195 thousand.
During each of the years 1994, 1993 and 1992, the Company formed a Direct
Investment Partnership for the purpose of permitting selected key employees to
invest directly, on an unpromoted basis, in wells that the Company drills. In
November 2000, the Company exercised its right under the Direct Investment
Partnership agreements to purchase each partner's interest in their respective
Direct Investment Partnership. The Company paid $4.3 million to complete the
purchase, of which $887 thousand was paid to current Company employees.
The Company, through a wholly-owned subsidiary, serves as operator of
properties in which it and its affiliated partnerships have an interest.
Accordingly, the Company receives producing well overhead, drilling well
overhead and other fees related to the operation of the properties. The
affiliated partnerships also reimburse the Company for their allocated share of
general and administrative charges.
The activities with affiliated partnerships are summarized for the
following related party transactions for the years ended December 31, 2001, 2000
and 1999:
2001 2000 1999
------ ------ ------
(in thousands)
Receipt of lease operating and supervision charges
in accordance with standard industry operating
agreements.............................................. $9,281 $9,222 $9,059
Reimbursement of general and administrative expenses....... $1,265 $1,550 $ 744
Prize divestiture. The Company sold certain oil and gas properties, gas
plants and other assets to Prize during 1999. Associated with these
transactions, the Company received $245.0 million of proceeds. During 1999, the
board of directors of Prize was partially comprised of Mr. Philip P. Smith, the
Chief Executive Officer; Mr. Kenneth A. Hersh; and Mr. Lon C. Kile. Messrs.
Smith and Hersh were members of the Board of Directors of the Company and
resigned their positions with the Company during the second quarter of 1999.
Similarly, Mr. Lon C. Kile resigned his position as Executive Vice President of
the Company to accept the position of President and Chief Operating Officer of
Prize. The sale of the assets to Prize was initiated through an auction process
which, upon receipt of Prize's initial offer, was placed under the supervision
of a special independent committee (comprised of outside directors unrelated to
Prize) of the Company's Board of Directors. The independent committee reviewed
and considered all offers presented to the Company for the purchase of the
assets acquired by Prize. The Prize offer was approved by the special
independent committee as being the best offer presented (see Note K for
additional information regarding the Company's investment in Prize and the
divestiture of assets to Prize).
Consulting fee. Effective January 1, 1999, the Company entered into an
amended and restated agreement with Rainwater, Inc., whereby the Company pays
Rainwater, Inc. $300,000 per year and reimburses Rainwater, Inc. for certain
expenses in consideration for certain consulting and financial analysis services
provided to the Company by Rainwater, Inc. and its representatives. The term of
this agreement expires on December 31, 2003. During 2001, 2000 and 1999,
consulting and financial analysis services provided to the Company totaled
58
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2001, 2000 and 1999
$300,000, $300,000 and $325,000, respectively, plus expenses. Richard E.
Rainwater, who resigned from the Company's Board of Directors during 2000, is
the sole shareholder of Rainwater, Inc.
NOTE F. Incentive Plans
Retirement Plans
Deferred compensation retirement plan. In August 1997, the Compensation
Committee of the Board of Directors approved a deferred compensation retirement
plan for the officers and certain key employees of the Company. Each officer and
key employee is allowed to contribute up to 25 percent of their base salary. The
Company will then provide a matching contribution of 100 percent of the
officer's and key employee's contribution limited to the first 10 percent of the
officer's base salary and eight percent of the key employee's base salary. The
Company's matching contribution vests immediately. A trust fund has been
established by the Company to accumulate the contributions made under this
retirement plan. The Company's matching contributions were $652 thousand, $611
thousand and $508 thousand for 2001, 2000 and 1999, respectively.
401(k) plan. The Pioneer Natural Resources USA, Inc. 401(k) Plan (the
"401(k) Plan") is a defined contribution plan established under the Internal
Revenue Code Section 401. All regular full-time and part-time employees of
Pioneer USA are eligible to participate in the 401(k) Plan on the first day of
the month following their date of hire. Participants may contribute an amount of
not less than two percent nor more than 12 percent of their annual salary into
the 401(k) Plan. Each participant's account is credited with the participant's
contributions and an allocation of the 401(k) Plan's earnings. Participants are
fully vested in their account balances.
Matching plan. The Pioneer Natural Resources USA, Inc. Matching Plan (the
"Matching Plan") is a money purchase pension plan which accumulates benefits to
participants. All regular full-time and part-time employees of Pioneer USA
become eligible to participate in the Matching Plan concurrent with their
eligibility to participate in the 401(k) Plan. All Matching Plan contributions
are made in cash by Pioneer USA in amounts equal to 200 percent of a
participant's contributions to the 401(k) Plan that are not in excess of five
percent of the participant's basic compensation (the "Matching Contribution").
Each participant's account is credited with their Matching Contribution and an
allocation of Matching Plan earnings. Participants proportionately vest in their
account balances over a four year period, at the end of which they are fully
vested in their account balances. During the years ended December 31, 2001, 2000
and 1999, the Company recognized compensation expense of $3.4 million, $3.4
million and $3.1 million, respectively, as a result of Matching Contributions.
Long-Term Incentive Plan
In August 1997, the Company's stockholders approved a long-term incentive
plan (the "Long-Term Incentive Plan"), which provides for the granting of
incentive awards in the form of stock options, stock appreciation rights,
performance units and restricted stock to directors, officers and employees of
the Company. The Long-Term Incentive Plan provides for the issuance of a maximum
number of shares of common stock equal to 10 percent of the total number of
shares of common stock equivalents outstanding plus the total number of shares
of common stock subject to outstanding awards under any stock-based plan for the
directors, officers or employees of the Company.
59
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2001, 2000 and 1999
The following table calculates the number of shares or options available
for grant under the Company's Long- Term Incentive Plan as of December 31, 2001
and 2000:
December 31,
-------------------------
2001 2000
----------- -----------
Shares outstanding.................................................. 103,936,394 98,415,647
Outstanding exercisable options or exercisable within 60 days....... 4,658,155 4,355,144
----------- -----------
108,594,549 102,770,791
Maximum shares/options allowed under the Long-Term Incentive Plan... 10,859,455 10,277,079
Less: Outstanding awards under Long-Term Incentive Plan............ (6,377,520) (5,514,057)
Outstanding options under predecessor incentive plans........ (548,551) (996,502)
----------- -----------
Shares/options available for future grant........................... 3,933,384 3,766,520
=========== ===========
Stock option awards. The Company has a program of awarding semi-annual
stock options to its officers and employees and gives its non-employee directors
a choice to receive stock options or cash as their annual compensation. This
program provides for stock option awards at an exercise price based upon the
closing sales price of the Company's common stock on the day prior to the date
of grant. Employee stock option awards vest over an 18 month or three year
schedule and provide a five year exercise period from each vesting date.
Non-employee directors' stock options vest quarterly and provide for a five year
exercise period from each vesting date. The Company granted 1,627,071, 1,439,035
and 1,945,135 options under the Long-Term Incentive Plan during 2001, 2000 and
1999, respectively.
Restricted stock awards. There were no restricted stock awards to
employees or non-employee directors during the years ended December 31, 2001 and
2000. During 1999, the Company awarded an aggregate of 6,200 shares of
restricted stock at an average price per share of $29.56.
Other stock based plans. Prior to the formation of the Company in 1997,
the Company's predecessor companies had long-term incentive plans in place that
allowed the predecessor companies to grant incentive awards similar to the
provisions of the Long-Term Incentive Plan. Upon formation of the Company, all
awards under these plans were assumed by the Company with the provision that no
additional awards be granted under the predecessor plans.
SFAS 123 disclosures. The Company applies APB 25 and related
interpretations in accounting for its stock option awards. Accordingly, no
compensation expense has been recognized for its stock option awards. If
compensation expense for the stock option awards had been determined consistent
with SFAS 123, the Company's net income (loss) and net income (loss) per share
would have been adjusted to the pro forma amounts indicated below:
For the Year Ended December 31,
----------------------------------
2001 2000 1999
-------- -------- --------
(in thousands, except per share amounts)
Net income (loss)........................ $ 93,463 $148,018 $(25,269)
Basic net income (loss) per share........ $ .95 $ 1.49 $ (.25)
Diluted net income (loss) per share...... $ .94 $ 1.48 $ (.25)
Under SFAS 123, the fair value of each stock option grant is estimated on
the date of grant using the Black-Scholes option pricing model with the
following weighted average assumptions used for grants in 2001, 2000 and 1999:
For the Year Ended December 31,
-------------------------------
2001 2000 1999
------- ------- -------
Risk-free interest rate.................. 4.13% 5.66% 6.59%
Expected life............................ 5 years 5 years 6 years
Expected volatility...................... 49% 50% 48%
Expected dividend yield.................. - - -
60
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2001, 2000 and 1999
A summary of the Company's stock option plans as of December 31, 2001,
2000 and 1999, and changes during the years ended on those dates, are presented
below:
For the Year Ended For the Year Ended For the Year Ended
December 31, 2001 December 31, 2000 December 31, 1999
--------------------- --------------------- ---------------------
Weighted Weighted Weighted
Number Average Number Average Number Average
of Shares Price of Shares Price of Shares Price
---------- -------- ---------- -------- ---------- --------
Non-statutory stock options:
Outstanding, beginning of year.. 6,510,559 $ 18.10 6,241,889 $ 19.45 4,580,030 $ 24.83
Options granted............... 1,627,071 $ 18.29 1,439,035 $ 10.32 1,945,135 $ 9.10
Options forfeited............. (566,189) $ 25.83 (798,058) $ 18.05 (256,576) $ 38.29
Options exercised............. (645,370) $ 11.14 (372,307) $ 10.78 (26,700) $ 5.81
---------- ---------- ----------
Outstanding, end of year........ 6,926,071 $ 18.16 6,510,559 $ 18.10 6,241,889 $ 19.45
========== ========== ==========
Exercisable at end of year...... 4,005,762 $ 20.82 3,897,187 $ 23.47 4,038,341 $ 24.62
========== ========== ==========
Weighted average fair value of options
granted during the year......... $ 8.65 $ 4.88 $ 4.21
========= ========= =========
The following table summarizes information about the Company's stock
options outstanding at December 31, 2001:
Options Outstanding Options Exercisable
----------------------------------------------------- -------------------------------------
Number Weighted Average Weighted Weighted
Range of Outstanding at Remaining Average Number Exercisable Average
Exercise Prices December 31, 2001 Contractual Life Exercise Price at December 31, 2001 Exercise Price
--------------- ----------------- ---------------- -------------- -------------------- --------------
$ 5-11 1,224,082 4.9 years $ 7.93 535,792 $ 8.35
$12-18 3,693,822 5.3 years $ 15.93 1,464,241 $ 14.85
$19-26 588,951 3.0 years $ 23.46 586,513 $ 23.47
$27-30 1,327,242 2.1 years $ 29.59 1,327,242 $ 29.59
$31-82 91,974 2.3 years $ 45.00 91,974 $ 45.00
----------- -----------
6,926,071 4,005,762
=========== ===========
Employee Stock Purchase Plan
The Company has an Employee Stock Purchase Plan (the "ESPP") that allows
eligible employees to annually purchase the Company's common stock at a
discounted price. Officers of the Company are not eligible to participate in the
ESPP. Contributions to the ESPP are limited to 15 percent of an employee's pay
(subject to certain ESPP limits) during the nine month offering period.
Participants in the ESPP purchase the Company's common stock at a price that is
15 percent below the closing sales price of the Company's common stock on either
the first day or the last day of each annual offering period, whichever closing
sales price is lower.
NOTE G. Commitments and Contingencies
Severance agreements. The Company has entered into severance agreements
with its officers, subsidiary company officers and certain key employees.
Salaries and bonuses for the Company's officers are set by the Compensation
Committee for the parent company officers and by the Management Committee for
subsidiary company officers and key employees. These committees can grant
increases or reductions to base salary at their discretion. The current annual
salaries for the parent company officers, the subsidiary company officers and
key employees covered under such agreements total approximately $16.0 million.
61
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2001, 2000 and 1999
Indemnifications. The Company has indemnified its directors and certain
of its officers, employees and agents with respect to claims and damages arising
from acts or omissions taken in such capacity, as well as with respect to
certain litigation.
Legal actions. The Company is party to various legal actions incidental
to its business, including, but not limited to, the proceedings described below.
The majority of these lawsuits primarily involve claims for damages arising from
oil and gas leases and ownership interest disputes. The Company believes that
the ultimate disposition of these legal actions will not have a material adverse
effect on the Company's consolidated financial position, liquidity, capital
resources or future results of operations. The Company will continue to evaluate
its litigation matters on a quarter-by-quarter basis and will adjust its
litigation reserves as appropriate to reflect the then current status of
litigation.
Masterson. In February 1992, the current lessors of an oil and gas lease
(the "Gas Lease") dated April 30, 1955, between R.B. Masterson et al., as
lessor, and Colorado Interstate Gas Company ("CIG"), as lessee, sued CIG in
Federal District Court in Amarillo, Texas, claiming that CIG had underpaid
royalties due under the Gas Lease. Under the agreements with CIG, the Company,
as successor to MESA Inc. ("Mesa"), has an entitlement to gas produced from the
Gas Lease. In August 1992, CIG filed a third-party complaint against the Company
for any such royalty underpayment which may be allocable to the Company.
Plaintiffs alleged that the underpayment was the result of CIG's use of an
improper gas sales price upon which to calculate royalties and that the proper
price should have been determined pursuant to a "favored-nations" clause in a
July 1, 1967 amendment to the Gas Lease. The plaintiffs also sought a
declaration by the court as to the proper price to be used for calculating
future royalties.
The plaintiffs alleged royalty underpayments of approximately $500
million (including interest at 10 percent) dating from July 1, 1967. In March
1995, the court made certain pretrial rulings that eliminated approximately $400
million of the plaintiff's claims (which related to periods prior to October 1,
1989), but which also reduced a number of the Company's defenses. The Company
and CIG filed stipulations with the court whereby the Company would have been
liable for between 50 percent and 60 percent, depending on the time period
covered, of an adverse judgment against CIG for post-February 1988 underpayments
of royalties.
On March 22, 1995, a jury trial began and on May 4, 1995, the jury
returned its verdict. Among its findings, the jury determined that CIG had
underpaid royalties for the period after September 30, 1989, in the amount of
approximately $140,000. Although the plaintiffs argued that the
"favored-nations" clause entitled them to be paid for all of their gas at the
highest price voluntarily paid by CIG to any other lessor, the jury determined
that the plaintiffs were estopped from claiming that the "favored-nations"
clause provides for other than a pricing-scheme to pricing-scheme comparison.
In light of this determination, and the plaintiff's stipulation that a
pricing-scheme to pricing-scheme comparison would not result in any "trigger
prices" or damages, defendants asked the court for a judgment that plaintiffs
take nothing. The court, on June 7, 1995, entered final judgment that plaintiffs
recover no monetary damages. The plaintiffs filed a motion for a new trial on
June 22, 1995. The court, on July 18, 1997, denied plaintiffs' motion. The
plaintiffs appealed to the Fifth Circuit Court of Appeals and on September 8,
2000, the Fifth Circuit Court affirmed the take nothing judgment of the trial
court.
On June 7, 1996, the plaintiffs filed a separate suit against CIG and the
Company in state court in Amarillo, Texas, similarly claiming underpayment of
royalties under the "favored-nations" clause, but based upon the above-
described pricing-scheme to pricing-scheme comparison on a well-by-well monthly
basis. The plaintiffs also claimed underpayment of royalties since June 7, 1995
under the "favored-nations" clause based upon either the pricing-scheme to
pricing-scheme method or their previously alleged higher price method. The
Company believed it had several defenses to this action and contested it
vigorously.
In January 2002, the Mastersons, CIG and the Company entered into a
Settlement Agreement and Lease Amendment. The Lease Amendment, among other
things, eliminated the "favored-nations" clause, defined market value at the
62
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2001, 2000 and 1999
well, and provided specific relinquishment terms. The facts of the Settlement
Agreement were jointly presented to the court and the case was dismissed with
prejudices February 1, 2002.
Alford. The Company is party to a 1993 class action lawsuit filed in the
26th Judicial District Court of Stevens County, Kansas by two classes of royalty
owners, one for each of the Company's gathering systems connected to the
Company's Satanta gas plant. The case was relatively inactive for several years.
In early 2000, the plaintiffs amended their pleadings to add claims regarding
the field compression installed by the Company in the 1990's. The lawsuit now
has two material claims. First, the plaintiffs assert that the expenses related
to the field compression are a "cost of production" for which plaintiffs cannot
be charged their proportionate share under the applicable oil and gas leases.
Second, the plaintiffs claim they are entitled to 100 percent of the value of
the helium extracted at the Company's Satanta gas plant. If the plaintiffs were
to prevail on the above two claims in their entirety, it is possible that the
Company's liability could reach $25 million, plus prejudgment interest. However,
the Company believes it has valid defenses to plaintiffs' claims, has paid the
plaintiffs properly under their respective oil and gas leases, and intends to
vigorously defend itself.
The Company believes the cost of the field compression is not a "cost of
production", but is rather an expense of transporting the gas to the Company's
Satanta gas plant for processing, where valuable hydrocarbon liquids and helium
are extracted from the gas. The plaintiffs benefit from such extractions and the
Company believes that charging the plaintiffs with their proportionate share of
such transportation and processing expenses is consistent with Kansas law. The
Company has also vigorously defended against plaintiffs' claims to 100 percent
of the value of the helium extracted, and believes that in accordance with
applicable law, it has properly accounted to the plaintiffs for their fractional
royalty share of the helium under the specified royalty clauses of the
respective oil and gas leases.
The factual evidence in the case was presented to the 26th Judicial
District Court without a jury in December 2001. No judgment or findings have
been entered, and the court has set the matter for oral arguments in April 2002.
Judgment could be entered anytime after April 2002. The Company strongly denies
the existence of any material underpayment to plaintiffs and believes it
presented strong evidence at trial to support its positions. The Company has not
yet determined the amount of damages, if any, that would be payable if the
lawsuit was determined adversely to the Company. However, the amount of any
resulting liability could have a material adverse effect on the Company's
results of operations for the period in which such liability is recorded, but
the Company does not expect that any such liability will have a material adverse
effect on its consolidated financial position as a whole or on its liquidity,
capital resources or future results of operations.
Kansas ad valorem tax. The Natural Gas Policy Act of 1978 ("NGPA") allows
a "severance, production or similar" tax to be included as an add-on, over and
above the maximum lawful price for gas. Based on a Federal Energy Regulatory
Commission ("FERC") ruling that Kansas ad valorem tax was such a tax, Mesa
collected the Kansas ad valorem tax in addition to the otherwise maximum lawful
price. The FERC's ruling was appealed to the United States Court of Appeals for
the District of Columbia ("D.C. Circuit"), which held in June 1988 that the FERC
failed to provide a reasoned basis for its findings and remanded the case to the
FERC for further consideration.
On December 1, 1993, the FERC issued an order reversing its prior ruling,
but limiting the effect of its decision to Kansas ad valorem taxes for sales
made on or after June 28, 1988. The FERC clarified the effective date of its
decision by an order dated May 18, 1994. The order clarified that the effective
date applies to tax bills rendered after June 28, 1988, not sales made on or
after that date. Numerous parties filed appeals on the FERC's action in the D.C.
Circuit. Various gas producers challenged the FERC's orders on two grounds: (1)
that the Kansas ad valorem tax, properly understood, does qualify for
reimbursement under the NGPA; and (2) the FERC's ruling should, in any event,
have been applied prospectively. Other parties challenged the FERC's orders on
the grounds that the FERC's ruling should have been applied retroactively to
December 1, 1978, the date of the enactment of the NGPA and producers should
have been required to pay refunds accordingly.
63
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2001, 2000 and 1999
The D.C. Circuit issued its decision on August 2, 1996, which holds that
producers must make refunds of all Kansas ad valorem tax collected with respect
to production since October 4, 1983, as opposed to June 28, 1988. Petitions for
rehearing were denied on November 6, 1996. Various gas producers subsequently
filed a petition for writ of certiori with the United States Supreme Court
seeking to limit the scope of the potential refunds to tax bills rendered on or
after June 28, 1988 (the effective date originally selected by the FERC).
Williams Natural Gas Company filed a cross-petition for certiori seeking to
impose refund liability back to December 1, 1978. Both petitions were denied on
May 12, 1997.
The Company and other producers filed petitions for adjustment with the
FERC on June 24, 1997. The Company was seeking waiver or set-off from FERC with
respect to that portion of the refund associated with (i) non-recoupable
royalties, (ii) non-recoupable Kansas property taxes based, in part, upon the
higher prices collected, and (iii) interest for all periods. On September 10,
1997, FERC denied this request, and on October 10, 1997, the Company and other
producers filed a request for rehearing. Pipelines were given until November 10,
1997 to file claims on refunds sought from producers and refunds totaling
approximately $30 million were made against the Company. The Company is unable
at this time to predict the final outcome of this matter or the amount, if any,
that will ultimately be refunded. As of December 31, 2001 and 2000, the Company
had on deposit $24.5 million and $28.1 million, respectively, including accrued
interest, in an escrow account and had corresponding obligations for this
litigation recorded in other current liabilities in the accompanying
Consolidated Balance Sheets. During 2001 and 2000, the Company paid $4.7 million
and $3.9 million, respectively, in partial settlement of original claims
presented under this litigation.
Lease agreements. The Company leases equipment and office facilities
under noncancellable operating leases on which rental expense for the years
ended December 31, 2001, 2000 and 1999 was approximately $6.6 million, $7.0
million and $6.9 million, respectively. Future minimum lease commitments under
noncancellable operating leases at December 31, 2001, including leases of
offshore production facilities, are as follows (in thousands):
2002................................................ $ 5,942
2003................................................ $ 32,067
2004................................................ $ 31,852
2005................................................ $ 29,700
2006................................................ $ 16,530
Thereafter.......................................... $ 28,538
NOTE H. Derivative Financial Instruments
Hedge Derivatives
The Company, from time to time, uses derivative instruments to manage
interest rate, commodity price and currency exchange rate risks.
Fair value hedging strategy. The Company monitors capital markets and
trends to identify opportunities to enter into interest rate swaps to minimize
its costs of capital. During April 2000 and May 2001, the Company entered into
interest rate swap agreements to hedge the fair value of the Company's 8-7/8
percent Senior Notes due April 15, 2005 and 8-1/4 percent Senior Notes due
August 15, 2007, respectively. The terms of the 8-7/8 percent interest rate swap
agreements provided for an aggregate notional amount of $150 million of debt;
had a scheduled maturity on April 15, 2005; required the counterparties to pay
the Company a fixed annual rate of 8-7/8 percent on the notional amount; and,
required the Company to pay the counterparties a variable annual rate on the
notional amount equal to the periodic three-month LIBOR plus a weighted average
margin rate of 178.2 basis points. The terms of the Company's 8-1/4 percent
interest rate swap agreements provided for an aggregate notional amount of $150
million of debt; had a scheduled maturity on August 15, 2007; required the
counterparties to pay the Company a fixed annual rate of 8-1/4 percent on the
64
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2001, 2000 and 1999
notional amount; and, required the Company to pay the counterparties a variable
rate on the notional amounts equal to LIBOR plus a weighted average margin rate
of 238.1 basis points. On September 21, 2001, the Company terminated its 8-7/8
percent and 8-1/4 percent interest rate swaps for $23.3 million of cash
proceeds, including accrued interest. As of December 31, 2001, the carrying
value of the senior notes include $18.4 million attributable to the unamortized
portion of these deferred hedge gains. The remaining portions of the deferred
hedge gains will be amortized as reductions to interest expense over the
remaining original terms of the interest rate swaps.
During November 2001, The Company entered into new interest rate swap
agreements to hedge the fair value of the Company's 6-1/2 percent Senior Notes
due January 15, 2008 and 8-1/4 percent Senior Notes due August 15, 2007,
respectively. The terms of the 6-1/2 percent interest rate swap agreements
provide for an aggregate notional amount of $350 million of debt; have a
scheduled maturity on January 15, 2008; require the counterparties to pay the
Company a fixed annual rate of 6-1/2 percent on the notional amount; and,
require the Company to pay the counterparties a variable annual rate on the
notional amount equal to the periodic six-month LIBOR plus a weighted average
margin rate of 202.2 basis points. The terms of the Company's new 8-1/4 percent
interest rate swap agreements provide for an aggregate notional amount of $150
million of debt; have a scheduled maturity on August 15, 2007; require the
counterparties to pay the Company a fixed annual rate of 8-1/4 percent on the
notional amount; and, require the Company to pay the counterparties a variable
rate on the notional amounts equal to the periodic six-month LIBOR plus a
weighted average margin rate of 337.0 basis points.
The terms of the fair value hedges described above perfectly match the
terms of the underlying senior notes. Thus, the Company did not exclude any
component of the derivatives' gains or losses from the measurement of hedge
effectiveness.
Cash flow hedging strategy. The Company utilizes commodity swap and
collar contracts to (i) reduce the effect of price volatility on the commodities
the Company produces and sells, (ii) support the Company's annual capital
budgeting and expenditure plans and (iii) reduce commodity price risk associated
with certain capital projects. The Company also utilizes interest rate swap
agreements to reduce the effect of interest rate volatility on the Company's
variable rate line of credit indebtedness and forward currency exchange
agreements to reduce the effect of U.S. dollar to Canadian dollar exchange rate
volatility.
Oil. All material sales contracts governing the Company's oil production
have been tied directly or indirectly to the New York Mercantile Exchange
("NYMEX") prices. The following table sets forth the Company's outstanding oil
hedge contracts and the weighted average NYMEX prices for those contracts as of
December 31, 2001:
Yearly
First Second Third Fourth Outstanding
Quarter Quarter Quarter Quarter Average
------------- ------------- ------------ ------------- -------------
Daily oil production:
2002 - Swap Contracts
Volume (Bbl).............. 17,000 8,000 8,000 5,000 9,463
Price per Bbl............. $ 27.41 $ 26.35 $ 24.76 $ 24.45 $ 26.23
2002 - Collar Contracts
Volume (Bbl).............. 6,000 6,000 - - 2,975
Price per Bbl............. $25.00-$28.61 $25.00-$28.61 $ - $ - $25.00-$28.61
2003 - Swap Contracts
Volume (Bbl).............. 6,000 6,000 - - 2,975
Price per Bbl............. $ 24.02 $ 24.02 $ - $ - $ 24.02
65
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2001, 2000 and 1999
The Company reports average oil prices per Bbl including the effects of
oil quality, gathering and transportation costs and the net effect of the oil
hedges. The following table sets forth the Company's oil prices, both reported
(including hedge results) and realized (excluding hedge results), and the net
effect of settlements of oil price hedges to revenue:
Year Ended December 31,
---------------------------
2001 2000 1999
------- ------- -------
Average price reported per Bbl.................... $ 24.12 $ 24.01 $ 15.36
Average price realized per Bbl.................... $ 23.88 $ 28.81 $ 16.23
Addition (reduction) to revenue (in millions)..... $ 3.0 $ (60.1) $ (13.4)
Natural gas liquids prices. During the years ended December 31, 2001,
2000 and 1999, the Company did not enter into any NGL hedge contracts.
Gas prices. The Company employs a policy of hedging a portion of its gas
production based on the index price upon which the gas is actually sold in order
to mitigate the basis risk between NYMEX prices and actual index prices. The
following table sets forth the Company's outstanding gas hedge contracts and the
weighted average index prices for those contracts as of December 31, 2001:
Yearly
First Second Third Fourth Outstanding
Quarter Quarter Quarter Quarter Average
----------- ----------- ----------- ---------- -----------
Daily gas production:
2002 - Swap Contracts
Volume (Mcf).................... 140,000 140,000 190,000 190,000 165,205
Index price per MMBtu........... $ 4.28 $ 4.28 $ 4.13 $ 4.14 $ 4.19
2002 - Collar Contracts
Volume (Mcf).................... 20,000 20,000 20,000 20,000 20,000
Index price per MMBtu........... $4.50-$6.00 $4.50-$6.00 $4.50-$6.00 $4.50-$6.00 $4.50-$6.00
2003 - Swap Contracts
Volume (Mcf).................... 117,500 117,500 117,500 117,500 117,500
Index price per MMBtu........... $ 3.62 $ 3.62 $ 3.62 $ 3.62 $ 3.62
2004 - Swap Contracts
Volume (Mcf).................... 165,000 165,000 165,000 165,000 165,000
Index price per MMBtu........... $ 3.84 $ 3.84 $ 3.84 $ 3.84 $ 3.84
2005 - Swap Contracts
Volume (Mcf).................... 50,000 50,000 50,000 50,000 50,000
Index price per MMBtu........... $ 3.63 $ 3.63 $ 3.63 $ 3.63 $ 3.63
The Company reports average gas prices per Mcf including the effects of
Btu content, gathering and transportation costs, gas processing and shrinkage
and the net effect of the gas hedges. The following table sets forth the
Company's gas prices, both reported (including hedge results) and realized
(excluding hedge results), and the net effect of settlements of gas price hedges
to revenue:
Year Ended December 31,
---------------------------
2001 2000 1999
------- ------- -------
Average price reported per Mcf................... $ 3.23 $ 2.81 $ 1.90
Average price realized per Mcf................... $ 3.20 $ 3.03 $ 1.84
Addition/(reduction) to revenue (in millions).... $ 3.0 $ (29.0) $ 9.4
66
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2001, 2000 and 1999
Interest rates. During the year ended December 31, 2001, the Company
entered into interest rate swap agreements and designated the swap agreements as
being cash flow hedges of the interest rate volatility associated with a portion
of the Company's variable rate line of credit indebtedness. The terms of the
interest rate swap agreements provide for an aggregate notional amount of $55
million of debt; commenced on May 21, 2001 and mature on May 20, 2002; require
the counterparties to pay the Company a variable rate equal to the six-month
LIBOR plus 125 basis points; and, require the Company to pay the counterparties
a weighted average rate of 5.43 percent on the notional amount. The Company
recognizes no ineffectiveness associated with changes in the fair values of
these derivative instruments.
Foreign currency rates. During the fourth quarter of 2001, the Company
entered into forward agreements to exchange an aggregate $24.8 million U.S.
dollars during 2002 for Canadian dollars at a weighted average exchange rate of
..6266 U.S. dollars for 1.0 Canadian dollar. These agreements are designated as
hedges of the exchange rate risk associated with forecasted Canadian sales of
gas under U.S. dollar denominated sales agreements. The Company does not expect
to recognize any ineffectiveness associated with changes in the fair values of
these derivative instruments.
Hedge ineffectiveness and excluded items. During the year ended December
31, 2001, the Company recognized other expense of $9.1 million related to the
ineffective portions of its cash flow hedging instruments. Additionally, based
on SFAS 133 interpretive guidance that was in effect prior to April 2001, the
Company excluded from the measurement of hedge effectiveness changes in the time
and volatility value components of collar contracts designated as cash flow
hedges. Associated therewith, the Company recorded other expense of $2.4 million
during the year ended December 31, 2001. In April 2001, the Company discontinued
the exclusion of time value and volatility from the measurement of hedge
effectiveness.
Accumulated other comprehensive income - deferred hedge gains and losses,
net. As described in Note B, the Company recorded a transition adjustment
associated with the January 1, 2001 adoption of the provisions of SFAS 133 which
reduced stockholders' equity by $197.4 million. The adjustment to stockholders'
equity was comprised of the fair value of the Company's derivative instruments
that were designated as commodity cash flow hedges, whose fair value amounted to
a liability of $139.6 million as of January 1, 2001, and deferred losses
realized from the early termination of cash flow hedges of $57.8 million. These
adjustments to stockholders' equity were classified as Accumulated other
comprehensive income ("AOCI") - deferred hedge gains and losses at transition.
As of December 31, 2001, AOCI - deferred hedge gains and losses represents a net
deferred gain of $201.0 million. The AOCI - deferred hedge gains and losses
balance as of December 31, 2001 was comprised of $177.7 million of unrealized
deferred hedge gains on the effective portions of open commodity, interest rate
and forward currency rate cash flow hedges and $23.3 million of net deferred
gains on terminated cash flow hedges. The increase in AOCI - deferred hedge
gains and losses since January 1, 2001 is primarily attributable to the Company
entering into additional oil and gas hedging agreements for future periods,
coupled with a decrease in future commodity prices at year end as compared to
the commodity prices stipulated in the new and existing hedge agreements. The
unrealized deferred hedge gains associated with open cash flow hedges remain
subject to market price fluctuations until the position is either settled under
the terms of the hedge agreement or terminated prior to settlement. The net
deferred gains on terminated cash flow hedges is fixed.
During the twelve month period ending December 31, 2002, the Company
expects to reclassify $126.3 million of deferred gains associated with open cash
flow hedges and $42.3 million of net deferred losses on terminated cash flow
hedges from AOCI - deferred hedge gains and losses to oil and gas revenue. The
following table sets forth the scheduled reclassifications of deferred hedge
gains and (losses) on terminated cash flow hedges that will be recognized in the
Company's future oil and gas revenues:
67
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2001, 2000 and 1999
First Second Third Fourth Total
Quarter Quarter Quarter Quarter Year
--------- --------- --------- --------- --------
(in thousands)
2002:
Oil revenue................. $ 2,302 $ 1,640 $ - $ - $ 3,942
Gas revenue................. (11,390) (11,516) (11,643) (11,643) (46,192)
-------- ------- ------- ------- -------
$ (9,088) $ (9,876) $(11,643) $(11,643) $(42,250)
2003 gas revenue.............. $ 12,320 $ 12,300 $ 12,276 $ 12,117 $ 49,013
2004 gas revenue.............. $ 4,195 $ 4,146 $ 4,137 $ 4,084 $ 16,562
Non-hedge Derivatives
Btu swap agreements. The Company is a party to certain Btu swap
agreements that mature at the end of 2004. The Btu swap agreements do not
qualify as hedges. The Company has recorded mark-to-market adjustments to
decrease the carrying value of the Btu swap liability by $.7 million and $.2
million during the years ended December 31, 2001 and 1999, respectively, and to
increase the carrying value of the Btu swap liability by $14.6 million during
the year ended December 31, 2000.
During 2001, the Company entered into offsetting Btu swap agreements that
have fixed the Company's remaining obligations associated with the Btu swap
agreements. The undiscounted future settlement obligations of the Company under
the Btu swap agreements are $7.2 million per year for each of 2002, 2003 and
2004.
Foreign currency agreements. Prior to their maturity in 2000, the Company
was a party to a series of forward foreign exchange rate swap agreements that
exchanged Canadian dollars for U.S. dollars. These contracts did not qualify as
hedges. The Company recorded mark-to-market adjustments to increase the carrying
value of the foreign exchange swap liabilities by $1.9 million during 2000 and
to decrease the carrying value of the foreign exchange swap liabilities by $5.9
million during 1999.
Other non-hedge commodity derivatives. During 1999, the Company sold call
options that provided the counterparties an option to exercise calls either on
10,000 Bbls per day of oil, at a strike price of $20.00 per Bbl, or on 100,000
MMBtu per day of gas, at a weighted average strike price of $2.75 per MMBtu.
These contracts, which matured during 2000, did not qualify for hedge accounting
treatment. The Company recorded mark-to-market adjustments to increase the
carrying value of the contract liability by $42.0 million and $21.2 million
during the years ended December 31, 2000 and 1999, respectively.
NOTE I. Major Customers and Derivative Counterparties
Sales to major customers. The Company's share of oil and gas production
is sold to various purchasers. The Company is of the opinion that the loss of
any one purchaser would not have an adverse effect on the ability of the Company
to sell its oil and gas production.
The following customers individually accounted for 10 percent or more of
the consolidated oil, NGL and gas revenues of the Company during the years ended
December 31, 2001, 2000 and 1999:
Percentage of Consolidated
Oil, NGL and Gas Revenues
----------------------------
2001 2000 1999
------ ------ ------
Williams Energy Services...................... 11 13 11
Anadarko Petroleum Corporation................ 10 6 5
68
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2001, 2000 and 1999
At December 31, 2001, the amounts receivable from Williams Energy
Services and Anadarko Petroleum Corporation were $9.0 million and $8.0 million,
respectively, which are included in the caption "Accounts receivable - trade" in
the accompanying Consolidated Balance Sheet.
Derivative counterparties. The Company uses credit and other financial
criteria to evaluate the credit standing of, and to select, counterparties to
its derivative instruments. Although the Company does not obtain collateral or
otherwise secure the fair value of its derivative instruments, associated credit
risk is mitigated by the Company's credit risk policies and procedures. As of
December 31, 2001, the Company has $7.8 million of derivative assets for which
Enron North America Corp is the Company's counterparty. Associated therewith,
the Company recognized a $6.0 million bad debt expense during the fourth quarter
of 2001, which is included in other expense in the accompanying Consolidated
Statement of Operations for the year ended December 31, 2001.
NOTE J. Interest and Other Income
The Company recorded interest and other income of $21.8 million, $25.8
million and $89.7 million during the years ended December 31, 2001, 2000 and
1999. The major categories of the Company's interest and other income are
summarized in the following table:
Year Ended December 31,
------------------------------
2001 2000 1999
------- ------- --------
(in thousands)
Purchase option fees (a)................. $ - $ - $ 41,808
Excise tax income (b).................... 4,126 6,915 30,200
Production payment income................ 5,552 1,262 670
Interest income.......................... 2,128 3,906 2,145
Seismic data sales....................... 1,841 1,148 79
Foreign exchange gains................... 223 220 2,629
Other income............................. 7,908 12,324 12,126
------ ------ -------
$21,778 $25,775 $ 89,657
====== ====== =======
---------------
(a) In December 1998, the Company announced the sale of an exclusive and
irrevocable option to purchase certain oil and gas properties of the
Company. The option holder was unable to complete the purchase and the
option expired unexecuted on March 31, 1999. In payment for the option and
related liquidated damages, the option holder paid the Company $41.8
million, which was recorded as other income in 1999.
(b) During 1999, the Company received an excise tax refund of $30.2 million
which had not previously been recognized as an asset, due to uncertainties
surrounding the collectability of the refund. Accordingly, the Company
recognized the tax refund as other income during 1999.
NOTE K. Asset Divestitures
During the years ended December 31, 2001, 2000 and 1999, the Company
completed asset divestitures for net proceeds of $113.5 million, $102.7 million
and $420.5 million (of which $390.5 million in 1999 was cash proceeds),
respectively. Associated therewith, the Company recorded gains on disposition of
assets of $7.7 million and $34.2 million during the years ended December 31,
2001 and 2000, and a loss on disposition of assets of $24.2 million during the
year ended December 31, 1999.
69
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2001, 2000 and 1999
Prize divestitures. On June 29, 1999, the Company completed a sale of
certain United States oil and gas producing properties, gas plants and other
assets to Prize. The oil and gas producing assets sold to Prize included
properties located in the United States Gulf Coast, Mid Continent and Permian
Basin areas.
In accordance with the terms of the purchase and sale agreement (the
"Prize Divestiture"), the Company received net sales proceeds of $245.0 million,
comprised of $215.0 million of cash and 2,307.693 shares of Prize Preferred
having a 1999 liquidation preference and fair value of $30.0 million. During
1999, the Company recognized a loss of $46.4 million from the Prize Divestiture.
Prior to February 9, 2000, Prize was a closely held, non-public entity and the
fair market value of the Prize Preferred was not readily determinable. On
February 9, 2000, Prize Common began to publicly trade on the American Stock
Exchange. At that time, the Company's Prize Preferred was exchanged for
3,984,197 shares of Prize Series A 6% Convertible Preferred Stock ("Prize Senior
A Preferred"). On March 31, 2000, the Company and Prize converted the Company's
3,984,197 shares of Prize Senior A Preferred to 3,984,197 shares of Prize
Common, received cash in lieu of 33,964 shares of preferred in-kind dividends
and sold to Prize 1,346,482 shares of the Prize Common for a combined cash total
of $18.6 million. During 2000, the Company sold an additional 2,024,500 shares
of Prize Common in the open market for $41.1 million, recording an associated
gain on disposition of assets of $34.3 million. During 2001, the Company sold
its remaining 613,250 shares of Prize Common for $12.7 million of cash proceeds
and recognized an associated gain on disposition of assets of $8.1 million. The
cash proceeds provided from the sale of the Prize Common are included in
proceeds from disposition of assets in the accompanying Consolidated Statements
of Cash Flows for the years ended December 31, 2001 and 2000.
Other United States divestitures. During the year ended December 31,
2001, the Company received $81.6 million of proceeds, representing deferred
hedge gains, from the early termination of derivatives that are designated as
hedges of United States interest rate and commodity price risks. See Note H for
information regarding the Company's derivative instruments and deferred hedge
gains and losses.
During the year ended December 31, 2000, the Company sold an office
building in Midland, Texas, certain other assets and non-strategic oil and gas
properties primarily located in the United States Gulf Coast and Mid Continent
areas. Associated with these divestitures, the Company realized net divestment
proceeds of $43.0 million and recorded a net loss on disposition of assets of
$.4 million. In addition to the Prize Divestiture, the Company completed 1999
divestitures of non-strategic United States oil and gas properties located in
the South Texas Gulf Coast, West Texas Permian Basin and North Dakota areas, an
East Texas gas facility and certain other assets for net cash proceeds of $116.2
million during 1999, resulting in net gains on divestitures of assets of $31.0
million.
International divestitures. During the year ended December 31, 2001, the
Company received $3.8 million of proceeds, representing deferred hedge gains
that will be recorded as increments to 2003 gas revenues, from the early
termination of derivatives that are designated as hedges of 2003 Canadian gas
price risk. During 2001, the Company also received $12.0 million of proceeds
from the sale of certain oil properties in Canada and $.4 million of proceeds
from the sale of other international assets. Associated with these transactions,
the Company recognized a net loss of $.8 million on disposition of these assets.
During 1999, the Company completed the divestitures of certain non-strategic
Canadian oil and gas properties, gas plants and other related assets. In
accordance with the terms of the Canadian divestitures, the Company received net
cash proceeds of $59.3 million and recognized a net loss of $8.8 million.
NOTE L. Impairment of Long-Lived Assets
During the year ended December 31, 1999, the Company assessed its
unproved oil and gas properties for impairment and, based thereon, recognized an
unproved property impairment provision of $17.9 million. The unproved property
impairment provision recognized during 1999 reduced the carrying value of
certain East Texas gas properties.
70
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2001, 2000 and 1999
NOTE M. Reorganization
During 1998, the Company announced the reorganization of its domestic
operations by combining six domestic operating regions, as well as other cost
reduction initiatives intended to allow the Company to realize greater
operational and administrative efficiencies. Specific cost reduction initiatives
included the relocation of most of the Company's administrative services from
Midland, Texas to Irving, Texas; the closings of the Company's regional offices
in Oklahoma City, Oklahoma, Corpus Christi, Texas and Houston, Texas; and the
termination of 350 employees. The consolidation of administrative services to
Irving and the closing of the Corpus Christi, Texas office were completed in
1998. The Company completed the closings of the Houston, Texas and Oklahoma
City, Oklahoma offices during 1999 and further centralized certain operational
functions in Irving, Texas. As a result of these reorganization initiatives, the
Company recognized reorganization charges of $8.5 million during 1999.
The following table provides a description of the components of the
reorganization charges and unpaid portions of the charges as of December 31,
2001, 2000 and 1999. The unpaid office closing amount at December 31, 2001
relates to a lease commitment on an office building in Oklahoma City, Oklahoma.
Unpaid
Total Portion as of
Charges Payments December 31,
-------- --------- -------------
(in thousands)
2001:
Office closings................ $ - $ 326 $ 156
======= ======== =======
2000:
Office closings................ $ - $ 1,155 $ 482
Relocation..................... - 230 -
------- -------- -------
$ - $ 1,385 $ 482
======= ======== =======
1999:
Employee terminations.......... $ 3,125 $ 7,805 $ -
Office closings................ 340 2,233 1,637
Relocation..................... 4,998 4,768 230
Other.......................... 71 71 -
------- -------- -------
$ 8,534 $ 14,877 $ 1,867
======= ======== =======
NOTE N. Other Expense
The following table provides the components of the Company's other
expense during the years ended December 31, 2001, 2000 and 1999:
Years Ended December 31,
-----------------------------
2001 2000 1999
------- ------- -------
(in thousands)
Derivative ineffectiveness and mark-to-market
provisions (see Note H)............................... $11,458 $58,518 $15,089
Trading security mark-to-market provisions (a)........... - - 11,875
Gas marketing losses (b)................................. 9,850 - -
Foreign currency remeasurement and exchange losses (c)... 8,474 80 175
Bad debt expense (recovery) (see Note I)................. 6,152 65 (729)
Other charges............................................ 3,654 8,568 8,221
------ ------ ------
$39,588 $67,231 $34,631
====== ====== ======
---------------
(a) During 1999, the Company owned four million shares of common stock of a
non-affiliated public entity for trading purposes. Prior to the disposition
of the shares in 1999, the Company recognized an $11.9 million decline in
the fair value of the investment as a charge to other expense.
71
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2001, 2000 and 1999
(b) The Company's Canadian operations periodically purchase third party gas
volumes for transport to and resale at a Chicago sales point. Associated
therewith, the Company recognized $9.9 million of gas marketing losses in
other expenses during 2001.
(c) The Company's operations in Argentina, Canada and Africa periodically
recognize monetary assets and liabilities in currencies other than their
functional currencies (see Note B for information regarding the functional
currencies of subsidiary entities). Associated therewith, the Company
realizes foreign currency remeasurement and transaction gains and losses.
In early January 2002, the Argentine government severed the one-to-one
relationship between the value of the Argentine peso and the U.S. dollar,
which is the functional currency of the Company's Argentine operations.
Consequently, the Company remeasured the peso denominated monetary net
assets and adjusted the lease and well equipment inventory balances to
market values which resulted in a charge of $7.7 million in 2001.
NOTE O. Income Taxes
The Company accounts for income taxes in accordance with the provisions
of Statement of Financial Accounting Standards No. 109, "Accounting for Income
Taxes". The Company and its eligible subsidiaries file a consolidated United
States federal income tax return. Certain subsidiaries are not eligible to be
included in the consolidated United States federal income tax return and
separate provisions for income taxes have been determined for these entities or
groups of entities. The tax returns and the amount of taxable income or loss are
subject to examination by United States federal, state and foreign taxing
authorities. Current and estimated tax payments of $11.7 million, $4.6 million
and $800 thousand were made in 2001, 2000 and 1999, respectively. In addition,
the Company received an income tax refund of $1.4 million in 1999. During 2001,
2000 and 1999, the Company's income tax provision (benefit) and amounts
separately allocated were attributable to the following items:
Year Ended December 31,
-----------------------------
2001 2000 1999
------- -------- --------
(in thousands)
Income (loss) before extraordinary item........ $ 4,016 $ (6,000) $ (600)
Changes in other comprehensive income:
Deferred hedge gains and losses.............. 2,293 - -
Cumulative translation adjustment............ (121) (200) 1,600
------- ------- -------
$ 6,188 $ (6,200) $ 1,000
======= ======= =======
Income tax provision (benefit) attributable to income (loss) before
extraordinary item consists of the following:
Year Ended December 31,
---------------------------------
2001 2000 1999
--------- --------- ---------
(in thousands)
Current:
U.S. state and local................... $ 1,080 $ - $ 400
Foreign................................ 10,585 4,600 (1,000)
-------- -------- --------
11,665 4,600 (600)
-------- -------- --------
Deferred:
U.S. federal........................... - - 14,700
Foreign................................ (7,649) (10,600) (14,700)
-------- -------- --------
(7,649) (10,600) -
-------- -------- --------
Total.................................... $ 4,016 $ (6,000) $ (600)
======== ======== ========
72
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2001, 2000 and 1999
Income (loss) before income taxes and extraordinary item consists of the
following:
Year Ended December 31,
------------------------------
2001 2000 1999
-------- -------- --------
(in thousands)
Income (loss) before income taxes and extraordinary item:
U.S. federal............................................. $140,045 $138,941 $(23,594)
Foreign.................................................. (32,280) 19,558 534
------- ------- -------
$107,765 $158,499 $(23,060)
======= ======= =======
Reconciliations of the United States federal statutory rate to the
Company's effective rate for income (loss) before extraordinary item are as
follows:
2001 2000 1999
-------- -------- --------
U.S. federal statutory tax rate............................ 35.0 35.0 (35.0)
Valuation allowance........................................ (27.5) (30.9) 102.0
Rate differential on foreign operations.................... (3.2) (2.9) (68.1)
Other...................................................... (.6) (5.0) (1.5)
------ ------ ------
Consolidated effective tax rate............................ 3.7 (3.8) (2.6)
====== ====== ======
The tax effects of temporary differences that give rise to significant
portions of the deferred tax assets and deferred tax liabilities were as
follows:
December 31,
-----------------------
2001 2000
--------- ---------
(in thousands)
Deferred tax assets:
Net operating loss carryforwards................................ $ 341,206 $ 350,916
Alternative minimum tax credit carryforwards.................... 1,565 1,565
Other........................................................... 106,365 105,792
-------- --------
Total deferred tax assets..................................... 449,136 458,273
Valuation allowance............................................. (244,742) (283,400)
-------- --------
Net deferred tax assets....................................... 204,394 174,873
-------- --------
Deferred tax liabilities:
Oil and gas properties, principally due to differences in
basis and depletion and the deduction of intangible
drilling costs for tax purposes............................... 115,524 82,551
Other........................................................... 11,919 31,622
-------- --------
Total deferred tax liabilities................................ 127,443 114,173
-------- --------
Net deferred tax asset........................................ $ 76,951 $ 60,700
======== ========
Realization of deferred tax assets associated with net operating loss
carryforwards ("NOLs") and other credit carryforwards is dependent upon
generating sufficient taxable income prior to their expiration. The Company
believes that there is a risk that certain of these NOLs and other credit
carryforwards may expire unused and, accordingly, has established a valuation
allowance of $244.7 million against them. Although realization is not assured
for the remaining deferred tax asset, the Company believes it is more likely
than not that they will be realized through future taxable earnings or
alternative tax planning strategies. However, the net deferred tax assets could
be reduced further if the Company's estimate of taxable income in future periods
is significantly reduced or alternative tax planning strategies are no longer
viable.
At December 31, 2001, the Company had NOLs for United States, Canadian,
South African and Tunisian income tax purposes of $881.8 million, $40.6 million,
$39.2 million and $4.6 million, respectively, which are available to offset
future regular taxable income in each respective tax jurisdiction, if any.
Additionally, at December 31, 2001, the Company has alternative minimum tax net
73
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2001, 2000 and 1999
operating loss carryforwards ("AMT NOLs") in the United States of $766.8
million, which are available to reduce future alternative minimum taxable
income, if any. These carryforwards expire as follows:
U.S.
---------------------- Canada South Africa Tunisia
Expiration Date NOL AMT NOL NOL NOL NOL
--------------- --------- --------- --------- ------------ --------
(in thousands)
December 31, 2002.......... $ 5,109 $ 2,695 $ - $ - $ -
December 31, 2003.......... 838 - - - -
December 31, 2005.......... 11,049 10,762 34,822 - -
December 31, 2006.......... 30,834 12,254 5,738 - -
December 31, 2007.......... 104,107 101,151 - - -
December 31, 2008.......... 112,508 106,558 - - -
December 31, 2009.......... 129,227 102,727 - - -
December 31, 2010.......... 124,859 110,961 - - -
December 31, 2011.......... 6,521 4,045 - - -
December 31, 2012.......... 68,542 58,930 - - -
December 31, 2018.......... 127,925 98,559 - - -
December 31, 2019.......... 145,999 144,836 - - -
December 31, 2020.......... 14,235 13,296 - - -
Indefinite................. - - - 39,161 4,569
-------- -------- -------- ------- -------
Total................... $ 881,753 $ 766,774 $ 40,560 $ 39,161 $ 4,569
======== ======== ======== ======= =======
The Company believes $180.0 million of the NOLs and AMT NOLs are subject
to Section 382 of the Internal Revenue Code and are limited in each taxable year
to approximately $20.0 million.
NOTE P. Geographic Operating Segment Information
The Company has operations in only one industry segment, that being the
oil and gas exploration and production industry; however, the Company is
organizationally structured along geographic operating segments, or regions. The
Company has reportable operations in the United States, Argentina and Canada.
Other foreign is primarily comprised of operations in South Africa, Gabon and
Tunisia.
The following table provides the geographic operating segment data
required by Statement of Financial Accounting Standards No. 131, "Disclosure
about Segments of an Enterprise and Related Information", as well as results of
operations of oil and gas producing activities required by Statement of
Financial Accounting Standards No. 69, "Disclosures about Oil and Gas Producing
Activities". Geographic operating segment income tax benefits (provisions) have
been determined based on statutory rates existing in the various tax
jurisdictions where the Company has oil and gas producing activities. The
"Headquarters and Other" table column includes revenues, expenses, additions to
properties, plants and equipment and assets that are not routinely included in
the earnings measures or attributes internally reported to management on a
geographic operating segment basis.
74
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2001, 2000 and 1999
United Other Headquarters Consolidated
States Argentina Canada Foreign and Other Total
---------- --------- --------- --------- ------------ ------------
(in thousands)
Year Ended December 31, 2001:
Oil and gas revenues..................... $ 649,635 $ 130,241 $ 67,146 $ - $ - $ 847,022
Interest and other....................... - - - - 21,778 21,778
Gain (loss) on disposition of assets..... 224 - (1,339) - 8,796 7,681
--------- -------- -------- -------- --------- ---------
649,859 130,241 65,807 - 30,574 876,481
--------- -------- -------- -------- --------- ---------
Production costs......................... 170,578 26,614 12,472 - - 209,664
Depletion, depreciation and amortization. 128,477 51,391 28,868 - 13,896 222,632
Exploration and abandonments............. 70,049 23,857 9,882 24,118 - 127,906
General and administrative............... - - - - 36,968 36,968
Interest................................. - - - - 131,958 131,958
Other.................................... - - - - 39,588 39,588
--------- -------- -------- -------- --------- ---------
369,104 101,862 51,222 24,118 222,410 768,716
--------- -------- -------- -------- --------- ---------
Income (loss) before income taxes and
extraordinary items.................... 280,755 28,379 14,585 (24,118) (191,836) 107,765
Income tax benefit (provision)........... (98,264) (9,933) (6,216) 8,441 101,956 (4,016)
-------- ------- ------- ------- -------- ---------
Income (loss) before extraordinary items. $ 182,491 $ 18,446 $ 8,369 $ (15,677) $ (89,880) $ 103,749
========= ======== ======== ======== ========= =========
Cost incurred for long-lived assets...... $ 454,229 $ 98,311 $ 36,048 $ 57,972 $ - $ 646,560
========= ======== ======== ======== ========= =========
Segment assets (as of December 31)....... $2,212,540 $ 710,702 $ 187,841 $ 53,314 $ 106,656 $3,271,053
========= ======== ======== ======== ========= =========
Year Ended December 31, 2000:
Oil and gas revenues..................... $ 649,273 $ 140,990 $ 62,475 $ - $ - $ 852,738
Interest and other....................... - - - - 25,775 25,775
Gain on disposition of assets............ 4,690 - 335 - 29,159 34,184
--------- -------- -------- -------- --------- ---------
653,963 140,990 62,810 - 54,934 912,697
--------- -------- -------- -------- --------- ---------
Production costs......................... 155,075 24,417 9,773 - - 189,265
Depletion, depreciation and amortization. 121,932 52,141 25,132 - 15,733 214,938
Exploration and abandonments............. 40,867 25,388 5,131 16,164 - 87,550
General and administrative............... - - - - 33,262 33,262
Interest................................. - - - - 161,952 161,952
Other.................................... - - - - 67,231 67,231
--------- -------- -------- -------- --------- ---------
317,874 101,946 40,036 16,164 278,178 754,198
--------- -------- -------- -------- --------- ---------
Income (loss) before income taxes and
extraordinary item..................... 336,089 39,044 22,774 (16,164) (223,244) 158,499
Income tax benefit (provision)........... (117,631) (13,665) (10,162) 5,657 141,801 6,000
--------- -------- -------- -------- --------- ---------
Income (loss) before extraordinary item.. $ 218,458 $ 25,379 $ 12,612 $ (10,507) $ (81,443) $ 164,499
========= ======== ======== ======== ========= =========
Cost incurred for long-lived assets...... $ 204,122 $ 68,430 $ 43,591 $ 23,597 $ - $ 339,740
========= ======== ======== ======== ========= =========
Segment assets (as of December 31)....... $1,899,633 $ 702,868 $ 227,250 $ 16,552 $ 108,132 $2,954,435
========= ======== ======== ======== ========= =========
Year Ended December 31, 1999:
Oil and gas revenues..................... $ 502,585 $ 83,697 $ 58,364 $ - $ - $ 644,646
Interest and other....................... - - - - 89,657 89,657
Loss on disposition of assets............ (14,736) - (8,836) - (596) (24,168)
--------- -------- -------- -------- --------- ---------
487,849 83,697 49,528 - 89,061 710,135
--------- -------- -------- -------- --------- ---------
Production costs......................... 124,654 18,268 16,608 - - 159,530
Depletion, depreciation and amortization. 153,775 38,874 25,601 - 17,797 236,047
Impairment of oil and gas properties..... 17,894 - - - - 17,894
Exploration and abandonments............. 41,225 14,009 3,509 7,231 - 65,974
General and administrative............... - - - - 40,241 40,241
Reorganization........................... - - - - 8,534 8,534
Interest................................. - - - - 170,344 170,344
Other.................................... - - - - 34,631 34,631
--------- -------- -------- -------- --------- ---------
337,548 71,151 45,718 7,231 271,547 733,195
--------- -------- -------- -------- --------- ---------
Income (loss) before income taxes........ 150,301 12,546 3,810 (7,231) (182,486) (23,060)
Income tax benefit (provision)........... (52,605) (4,140) (1,699) 2,531 56,513 600
--------- -------- -------- -------- --------- ---------
Net income (loss)........................ $ 97,696 $ 8,406 $ 2,111 $ (4,700) $ (125,973) $ (22,460)
========= ======== ======== ======== ========= =========
Cost incurred for long-lived assets...... $ 105,663 $ 76,654 $ 11,552 $ 7,257 $ - $ 201,126
========= ======== ======== ======== ========= =========
Segment assets (as of December 31)....... $1,865,441 $ 734,382 $ 218,526 $ 8,289 $ 102,835 $2,929,473
========= ======== ======== ======== ========= =========
75
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2001, 2000 and 1999
NOTE Q. Income (Loss) Per Share Before Extraordinary Items
Basic income (loss) per share before extraordinary items is computed by
dividing income (loss) before extraordinary items by the weighted average number
of common shares outstanding for the period. The computation of diluted income
(loss) per share before extraordinary items reflects the potential dilution that
could occur if securities or other contracts to issue common stock were
exercised or converted into common stock or resulted in the issuance of common
stock that would then share in the earnings of the entity.
The following table is a reconciliation of the basic and diluted income
(loss) per share before extraordinary items computations for the years ended
December 31, 2001, 2000 and 1999:
Year Ended December 31,
-------------------------------------
2001 2000 1999
--------- --------- ---------
(in thousands, except per share amounts)
Basic and diluted income (loss) before extraordinary items.... $ 103,749 $ 164,499 $ (22,460)
Weighted average common shares outstanding:
Basic....................................................... 98,529 99,378 100,307
Dilutive common stock options (a)........................... 1,185 385 -
-------- -------- --------
Diluted..................................................... 99,714 99,763 100,307
======== ======== ========
Income (loss) per share before extraordinary items:
Basic....................................................... $ 1.05 $ 1.65 $ (.22)
Diluted..................................................... $ 1.04 $ 1.65 $ (.22)
---------------
(a) Common stock options to purchase 3,595,880 shares, 4,911,749 shares and
5,274,964 shares of common stock were outstanding but not included in the
computations of diluted net income (loss) per share for 2001, 2000 and
1999, respectively, because the exercise prices of the options were greater
than the average market price of the common shares and would be
anti-dilutive to the computations. In-the-money options representing
158,556 weighted average equivalent shares of common stock were not
included in the computation of diluted net loss per share for 1999, since
they have a dilutive effect to the period's net loss.
NOTE R. Pioneer USA
Pioneer USA is a wholly-owned subsidiary of the Company that has fully
and unconditionally guaranteed certain debt securities of the Company (see Note
D above). The Company has not prepared financial statements and related
disclosures for Pioneer USA under separate cover because management of the
Company has determined that such information is not material to investors. In
accordance with practices accepted by the United States Securities and Exchange
Commission, the Company has prepared Consolidating Condensed Financial
Statements in order to quantify the assets of Pioneer USA as a subsidiary
guarantor. The following Consolidating Condensed Balance Sheets as of December
31, 2001 and 2000, and Consolidating Statements of Operations and Comprehensive
Income (Loss) and Consolidating Condensed Statements of Cash Flows for the years
ended December 31, 2001, 2000 and 1999 present financial information for Pioneer
Natural Resources Company as the Parent on a stand-alone basis (carrying any
investments in subsidiaries under the equity method), financial information for
Pioneer USA on a stand-alone basis (carrying any investment in non-guarantor
subsidiaries under the equity method), financial information for the non-
guarantor subsidiaries of the Company on a consolidated basis, the consolidation
and elimination entries necessary to arrive at the information for the Company
on a consolidated basis, and the financial information for the Company on a
consolidated basis. Pioneer USA is not restricted from making distributions to
the Company.
76
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2001, 2000 and 1999
CONSOLIDATING CONDENSED BALANCE SHEET
As of December 31, 2001
Pioneer
Natural
Resources Non-
Company Pioneer Guarantor The
(Parent) USA Subsidiaries Eliminations Company
---------- ----------- ------------ ------------ -----------
(in thousands)
ASSETS
Current assets:
Cash and cash equivalents............... $ 79 $ 10,900 $ 3,355 $ $ 14,334
Other current assets.................... 1,540,985 (1,125,968) (173,708) 241,309
--------- ---------- -------- ----------
Total current assets................ 1,541,064 (1,115,068) (170,353) 255,643
--------- ---------- -------- ----------
Property, plant and equipment, at cost:
Oil and gas properties, using the
successful efforts method of accounting:
Proved properties..................... - 2,688,962 1,002,821 3,691,783
Unproved properties................... - 25,222 162,563 187,785
Accumulated depletion, depreciation and
amortization.......................... - (815,323) (279,987) (1,095,310)
--------- ---------- -------- ----------
- 1,898,861 885,397 2,784,258
--------- ---------- -------- ----------
Deferred income taxes..................... 82,811 - 1,508 84,319
Other property and equipment, net......... - 17,881 3,679 21,560
Other assets, net......................... 15,911 81,356 28,006 125,273
Investment in subsidiaries................ 1,060,457 87,636 - (1,148,093) -
--------- ---------- -------- ----------
$2,700,243 $ 970,666 $ 748,237 $ 3,271,053
========= ========== ========= ==========
LIABILITIES AND STOCKHOLDERS' EQUITY
Total current liabilities................. $ 30,745 $ 176,442 $ 21,022 $ $ 228,209
Long-term debt, less current maturities... 1,577,304 - - 1,577,304
Other noncurrent liabilities.............. 19,582 124,552 22,249 166,383
Deferred income taxes..................... - - 13,768 13,768
Stockholders' equity...................... 1,072,612 669,672 691,198 (1,148,093) 1,285,389
Commitments and contingencies............. - - - -
--------- ---------- --------- ----------
$2,700,243 $ 970,666 $ 748,237 $ 3,271,053
========= ========== ========= ==========
CONSOLIDATING CONDENSED BALANCE SHEET
As of December 31, 2000
Pioneer
Natural
Resources Non-
Company Pioneer Guarantor The
(Parent) USA Subsidiaries Eliminations Company
---------- ----------- ------------ ------------ -----------
(in thousands)
ASSETS
Current assets:
Cash and cash equivalents............... $ 15 $ 18,387 $ 7,757 $ $ 26,159
Other current assets.................... 2,006,496 (1,245,546) (595,718) 165,232
--------- ---------- --------- ----------
Total current assets................ 2,006,511 (1,227,159) (587,961) 191,391
--------- ---------- --------- ----------
Property, plant and equipment, at cost:
Oil and gas properties, using the
successful efforts method of accounting:
Proved properties..................... - 2,291,872 896,017 3,187,889
Unproved properties................... - 28,103 201,102 229,205
Accumulated depletion, depreciation and
amortization.......................... - (692,250) (209,889) (902,139)
--------- ---------- --------- ----------
- 1,627,725 887,230 2,514,955
--------- ---------- --------- ----------
Deferred income taxes..................... 84,400 - - 84,400
Other property and equipment, net......... - 20,823 4,801 25,624
Other assets, net......................... 18,877 89,632 29,556 138,065
Investment in subsidiaries................ 347,370 100,192 - (447,562) -
--------- ---------- --------- ----------
$2,457,158 $ 611,213 $ 333,626 $ 2,954,435
========= ========== ========= ==========
LIABILITIES AND STOCKHOLDERS' EQUITY
Total current liabilities................. $ 37,889 $ 140,415 $ 38,210 $ $ 216,514
Long-term debt, less current maturities... 1,578,776 - - 1,578,776
Other noncurrent liabilities.............. - 190,476 35,264 225,740
Deferred income taxes..................... - - 28,500 28,500
Stockholders' equity...................... 840,493 280,322 231,652 (447,562) 904,905
Commitments and contingencies.............
--------- ---------- --------- -----------
$2,457,158 $ 611,213 $ 333,626 $ 2,954,435
========= ========== ========= ==========
77
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2001, 2000 and 1999
CONSOLIDATING CONDENSED STATEMENT OF OPERATIONS
AND COMPREHENSIVE INCOME
For the Year Ended December 31, 2001
(in thousands)
Pioneer
Natural
Resources Non- Consolidated
Company Pioneer Guarantor Income Tax The
(Parent) USA Subsidiaries Provision Eliminations Company
--------- --------- ------------ ------------ ------------ ---------
Revenues:
Oil and gas........................... $ - $ 626,964 $ 220,058 $ - $ $ 847,022
Interest and other.................... 368 14,415 6,995 - 21,778
Gain (loss) on disposition of
assets, net......................... - 8,524 (843) - 7,681
-------- -------- -------- -------- --------
368 649,903 226,210 - 876,481
-------- -------- -------- -------- --------
Costs and expenses:
Oil and gas production................ - 168,287 41,377 - 209,664
Depletion, depreciation and amortization - 135,838 86,794 - 222,632
Exploration and abandonments.......... - 73,649 54,257 - 127,906
General and administrative............ 804 25,476 10,688 - 36,968
Interest.............................. 31,261 83,473 17,224 - 131,958
Equity (income) loss from subsidiary.. (135,459) 5,588 - - 129,871 -
Other................................. - 9,247 30,341 - 39,588
-------- -------- -------- -------- --------
(103,394) 501,558 240,681 - 768,716
-------- -------- -------- -------- --------
Income (loss) before income taxes....... 103,762 148,345 (14,471) - 107,765
Income tax provision.................... - (783) (3,220) (13) (4,016)
-------- -------- -------- -------- --------
Income (loss) before extraordinary items 103,762 147,562 (17,691) (13) 103,749
Extraordinary items - loss on early
extinguishment of debt................ (3,753) - - - (3,753)
-------- -------- -------- -------- --------
Net income (loss)....................... 100,009 147,562 (17,691) (13) 99,996
Other comprehensive income:
Deferred hedge gains and losses:
Transition adjustment............... - (172,007) (25,437) - (197,444)
Deferred hedge gains (losses)....... (578) 364,051 29,531 - 393,004
Net (gains) losses included in net
income............................ 135 (8,595) 13,946 - 5,486
Gains and losses on available for
sale securities:
Unrealized holdings losses.......... - (45) - - (45)
Gains included in net income........ - (8,109) - - (8,109)
Translation adjustment................ - - (11,173) - (11,173)
-------- -------- -------- -------- --------
Comprehensive income.................... $ 99,566 $ 322,857 $ (10,824) $ (13) $ 281,715
======== ======== ======== ======== ========
CONSOLIDATING CONDENSED STATEMENT OF OPERATIONS
AND COMPREHENSIVE INCOME
For the Year Ended December 31, 2000
(in thousands)
Pioneer
Natural
Resources Non- Consolidated
Company Pioneer Guarantor Income Tax The
(Parent) USA Subsidiaries Provision Eliminations Company
--------- --------- ------------ ------------ ------------ ---------
Revenues:
Oil and gas........................... $ - $ 616,030 $ 236,708 $ - $ $ 852,738
Interest and other.................... 29 13,808 11,938 - 25,775
Gain (loss) on disposition of
assets, net......................... (6,172) 36,946 3,410 - 34,184
-------- -------- -------- -------- --------
(6,143) 666,784 252,056 - 912,697
-------- -------- -------- -------- --------
Costs and expenses:
Oil and gas production................ - 150,281 38,984 - 189,265
Depletion, depreciation and amortization - 129,996 84,942 - 214,938
Exploration and abandonments.......... - 43,938 43,612 - 87,550
General and administrative............ 283 22,519 10,460 - 33,262
Interest.............................. (53,180) 151,026 64,106 - 161,952
Equity (income) loss from subsidiary.. (117,704) (6,313) - - 124,017 -
Other................................. - 63,459 3,772 - 67,231
-------- -------- -------- -------- --------
(170,601) 554,906 245,876 - 754,198
-------- -------- -------- -------- --------
Income before income taxes.............. 164,458 111,878 6,180 - 158,499
Income tax benefit (provision).......... - (4) 5,963 41 6,000
-------- -------- -------- -------- --------
Income before extraordinary item........ 164,458 111,874 12,143 41 164,499
Extraordinary item - loss on early
extinguishment of debt................ (12,318) - - - (12,318)
-------- -------- -------- -------- --------
Net income.............................. 152,140 111,874 12,143 41 152,181
Other comprehensive income (loss):
Unrealized gains on available for
sale securities:
Unrealized holdings gains........... - 33,828 - - 33,828
Gains included in net income........ - (25,674) - - (25,674)
Translation adjustment................ - - (6,910) - (6,910)
-------- -------- -------- -------- --------
Comprehensive income.................... $ 152,140 $ 120,028 $ 5,233 $ 41 $ 153,425
======== ======== ======== ======== ========
78
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2001, 2000 and 1999
CONSOLIDATING CONDENSED STATEMENT OF OPERATIONS
AND COMPREHENSIVE LOSS
For the Year Ended December 31, 1999
(in thousands)
Pioneer
Natural
Resources Non- Consolidated
Company Pioneer Guarantor Income Tax The
(Parent) USA Subsidiaries Provision Eliminations Company
--------- --------- ------------ ------------ ------------ ---------
Revenues:
Oil and gas........................... $ - $ 470,059 $ 174,587 $ - $ $ 644,646
Interest and other.................... 406 52,232 37,019 - 89,657
Gain (loss) on disposition of
assets, net......................... - 19,379 (43,547) - (24,168)
-------- -------- -------- -------- --------
406 541,670 168,059 - 710,135
-------- -------- -------- -------- --------
Costs and expenses:
Oil and gas production................ - 120,074 39,456 - 159,530
Depletion, depreciation and amortization - 157,294 78,753 - 236,047
Impairment of oil and gas properties.. - 17,894 - - 17,894
Exploration and abandonments.......... - 43,133 22,841 - 65,974
General and administrative............ 1,051 27,260 11,930 - 40,241
Reorganization........................ - 8,534 - - 8,534
Interest.............................. (33,404) 145,184 58,564 - 170,344
Equity income (loss) from subsidiary.. 39,672 (5,179) - - (34,493) -
Other................................. 799 38,166 (4,334) - 34,631
-------- -------- -------- -------- --------
8,118 552,360 207,210 - 733,195
-------- -------- -------- -------- --------
Loss before income taxes................ (7,712) (10,690) (39,151) - (23,060)
Income tax benefit (provision).......... - (444) 15,792 (14,748) 600
-------- -------- -------- -------- --------
Net loss................................ (7,712) (11,134) (23,359) (14,748) (22,460)
Other comprehensive income:
Translation adjustment................ - - 8,358 - 8,358
-------- -------- -------- -------- --------
Comprehensive loss...................... $ (7,712) $ (11,134) $ (15,001) $ (14,748) $ (14,102)
======== ======== ======== ======== ========
79
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2001, 2000 and 1999
CONSOLIDATING CONDENSED STATEMENT OF CASH FLOWS
For the Year Ended December 31, 2001
(in thousands)
Pioneer
Natural
Resources Non-
Company Pioneer Guarantor The
(Parent) USA Subsidiaries Company
----------- --------- ------------ -----------
Cash flows from operating activities:
Net cash provided by (used in) operating activities...... $ (10,503) $ 307,776 $ 178,327 $ 475,600
---------- -------- -------- ----------
Cash flows from investing activities:
Cash acquired in acquisition, net of fees paid........... - 11,119 - 11,119
Proceeds from disposition of assets...................... 21,170 75,816 16,467 113,453
Additions to oil and gas properties...................... - (336,753) (192,970) (529,723)
Other property additions, net............................ - (10,717) (6,873) (17,590)
---------- -------- -------- ----------
Net cash provided by (used in) investing activities 21,170 (260,535) (183,376) (422,741)
---------- -------- -------- ----------
Cash flows from financing activities:
Borrowings under long-term debt.......................... 328,331 - - 328,331
Principal payments on long-term debt..................... (333,410) - - (333,410)
(Payments of) borrowings under noncurrent liabilities.... - (54,728) 1,291 (53,437)
Purchase of treasury stock............................... (13,028) - - (13,028)
Exercise of stock options and employee stock purchases... 7,504 - - 7,504
---------- -------- -------- ----------
Net cash provided by (used in) financing activities (10,603) (54,728) 1,291 (64,040)
---------- -------- -------- ----------
Net increase (decrease) in cash and cash equivalents....... 64 (7,487) (3,758) (11,181)
Effect of exchange rate changes on cash and cash equivalents - - (644) (644)
Cash and cash equivalents, beginning of period............. 15 18,387 7,757 26,159
---------- -------- -------- ----------
Cash and cash equivalents, end of period................... $ 79 $ 10,900 $ 3,355 $ 14,334
========== ======== ======== ==========
CONSOLIDATING CONDENSED STATEMENT OF CASH FLOWS
For the Year Ended December 31, 2000
(in thousands)
Pioneer
Natural
Resources Non-
Company Pioneer Guarantor The
(Parent) USA Subsidiaries Company
----------- --------- ------------ -----------
Cash flows from operating activities:
Net cash provided by operating activities................ $ 213,491 $ 118,300 $ 98,305 $ 430,096
---------- -------- -------- ----------
Cash flows from investing activities:
Proceeds from disposition of assets...................... - 92,342 10,394 102,736
Additions to oil and gas properties...................... - (179,861) (119,821) (299,682)
Other property (additions) dispositions, net............. - (10,004) 12,449 2,445
---------- -------- -------- ----------
Net cash used in investing activities............. - (97,523) (96,978) (194,501)
---------- -------- -------- ----------
Cash flows from financing activities:
Borrowings under long-term debt.......................... 922,607 - - 922,607
Principal payments on long-term debt..................... (1,099,107) (828) - (1,099,935)
Payment of noncurrent liabilities........................ - (24,261) (5,498) (29,759)
Purchase of treasury stock............................... (27,298) - - (27,298)
Deferred loan fees/issuance costs........................ (13,847) - - (13,847)
Exercise of stock options and employee stock purchases... 4,164 - - 4,164
---------- -------- -------- ----------
Net cash used in financing activities............. (213,481) (25,089) (5,498) (244,068)
---------- -------- -------- ----------
Net increase (decrease) in cash and cash equivalents....... 10 (4,312) (4,171) (8,473)
Effect of exchange rate changes on cash and cash equivalents - - (156) (156)
Cash and cash equivalents, beginning of period............. 5 22,699 12,084 34,788
---------- -------- -------- ----------
Cash and cash equivalents, end of period................... $ 15 $ 18,387 $ 7,757 $ 26,159
========== ======== ======== ==========
80
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2001, 2000 and 1999
CONSOLIDATING CONDENSED STATEMENT OF CASH FLOWS
For the Year Ended December 31, 1999
(in thousands)
Pioneer
Natural
Resources Non-
Company Pioneer Guarantor The
(Parent) USA Subsidiaries Company
----------- --------- ------------ -----------
Cash flows from operating activities:
Net cash provided by (used in) operating activities...... $ 152,485 $(230,625) $ 333,374 $ 255,234
---------- -------- -------- ----------
Cash flows from investing activities:
Proceeds from disposition of assets...................... - 328,182 62,349 390,531
Additions to oil and gas properties...................... - (74,257) (105,412) (179,669)
Other property additions, net............................ - (8,335) (3,532) (11,867)
---------- -------- -------- ----------
Net cash provided by (used in) investing activities - 245,590 (46,595) 198,995
---------- -------- -------- ----------
Cash flows from financing activities:
Borrowings under long-term debt.......................... 355,493 - - 355,493
Principal payments on long-term debt..................... (504,493) (1,192) (288,234) (793,919)
Payment of noncurrent liabilities........................ - (29,006) (4,996) (34,002)
Deferred loan fees/issuance costs........................ (6,891) - - (6,891)
Exercise of stock options and employee stock purchases... 250 - - 250
---------- -------- -------- ----------
Net cash used in financing activities............. (155,641) (30,198) (293,230) (479,069)
---------- -------- -------- ----------
Net decrease in cash and cash equivalents.................. (3,156) (15,233) (6,451) (24,840)
Effect of exchange rate changes on cash and cash equivalents - - 407 407
Cash and cash equivalents, beginning of period............. 3,161 37,932 18,128 59,221
---------- -------- -------- ----------
Cash and cash equivalents, end of period................... $ 5 $ 22,699 $ 12,084 $ 34,788
========== ======== ======== ==========
81
PIONEER NATURAL RESOURCES COMPANY
UNAUDITED SUPPLEMENTARY INFORMATION
Years Ended December 31, 2001, 2000 and 1999
Capitalized Costs
December 31,
-----------------------
2001 2000
---------- ----------
(in thousands)
Oil and Gas Properties:
Proved................................................. $3,691,783 $3,187,889
Unproved............................................... 187,785 229,205
--------- ---------
3,879,568 3,417,094
Less accumulated depletion............................. (1,095,310) (902,139)
---------- ---------
Net capitalized costs for oil and gas properties....... $2,784,258 $2,514,955
========= =========
Costs Incurred for Oil and Gas Producing Activities
Property
Acquisition Costs Total
-------------------- Exploration Development Costs
Proved Unproved Costs Costs Incurred
--------- -------- ----------- ----------- ---------
(in thousands)
Year Ended December 31, 2001:
United States...................... $ 132,793 $ 19,572 $ 129,639 $ 172,225 $ 454,229
Argentina.......................... 13,182 2,465 36,237 46,427 98,311
Canada............................. 29 97 12,707 23,215 36,048
South Africa....................... 706 125 21,936 13,860 36,627
Other foreign (a).................. - 1,835 19,510 - 21,345
-------- ------- --------- --------- --------
Total costs incurred............. $ 146,710 $ 24,094 $ 220,029 $ 255,727 $ 646,560
======== ======= ========= ========= ========
Year Ended December 31, 2000:
United States...................... $ 26,102 $ 28,199 $ 65,023 $ 84,798 $ 204,122
Argentina.......................... 1,169 520 35,406 31,335 68,430
Canada............................. 8,709 2,506 6,744 25,632 43,591
South Africa....................... - - 20,176 - 20,176
Other foreign (b).................. - - 3,421 - 3,421
-------- ------- --------- --------- --------
Total costs incurred............. $ 35,980 $ 31,225 $ 130,770 $ 141,765 $ 339,740
======== ======= ========= ========= ========
Year Ended December 31, 1999:
United States...................... $ 937 $ 3,185 $ 42,337 $ 59,204 $ 105,663
Argentina.......................... 36,312 2,517 12,597 25,228 76,654
Canada............................. 174 (7,375) 1,431 17,322 11,552
South Africa....................... - - 2,178 - 2,178
Other foreign (b).................. 151 - 4,928 - 5,079
-------- ------- --------- --------- --------
Total costs incurred............. $ 37,574 $ (1,673) $ 63,471 $ 101,754 $ 201,126
======== ======= ========= ========= ========
---------------
(a) Primarily comprised of costs to drill an exploratory well in Gabon and one
in Tunisia as well as additional geological and geophysical costs in both
areas.
(b) Primarily comprised of geological and geophysical costs in Gabon.
82
PIONEER NATURAL RESOURCES COMPANY
UNAUDITED SUPPLEMENTARY INFORMATION
Years Ended December 31, 2001, 2000 and 1999
Results of Operations
Information about the Company's results of operations for oil and gas
producing activities is presented in Note P of the accompanying Notes to
Consolidated Financial Statements.
Reserve Quantity Information
The estimates of the Company's proved oil and gas reserves, which are
located principally in the United States, Argentina, Canada and South Africa,
are prepared by the Company's engineers. Reserves were estimated in accordance
with guidelines established by the SEC and the Financial Accounting Standards
Board, which require that reserve estimates be prepared under existing economic
and operating conditions with no provision for price and cost escalations except
by contractual arrangements. The reserve estimates for 2001, 2000 and 1999
utilize respective oil prices of $18.88, $25.71 and $24.33 per Bbl (reflecting
adjustments for oil quality and gathering and transportation costs); respective
NGL prices of $11.58, $16.74 and $17.59 per Bbl; and, respective gas prices of
$2.21, $7.50 and $1.83 per Mcf (reflecting adjustments for Btu content,
gathering and transportation costs and gas processing and shrinkage).
Oil and gas reserve quantity estimates are subject to numerous
uncertainties inherent in the estimation of quantities of proved reserves and in
the projection of future rates of production and the timing of development
expenditures. The accuracy of such estimates is a function of the quality of
available data and of engineering and geological interpretation and judgment.
Results of subsequent drilling, testing and production may cause either upward
or downward revision of previous estimates. Further, the volumes considered to
be commercially recoverable fluctuate with changes in prices and operating
costs. The Company emphasizes that reserve estimates are inherently imprecise
and that estimates of new discoveries are more imprecise than those of currently
producing oil and gas properties. Accordingly, these estimates are expected to
change as additional information becomes available in the future.
83
PIONEER NATURAL RESOURCES COMPANY
UNAUDITED SUPPLEMENTARY INFORMATION
Years Ended December 31, 2001, 2000 and 1999
Oil and Gas Producing Activities:
2001 2000 1999
----------------------------- ----------------------------- ------------------------------
Oil Oil Oil
& NGLs Gas & NGLs Gas & NGLs Gas
Total Proved Reserves: (MBBLS) (MMCF) MBOE (MBBLS) (MMCF) MBOE (MBBLS) (MMCF) MBOE
------- --------- ------- ------- --------- ------- ------- --------- --------
UNITED STATES
Balance, January 1............... 266,802 1,354,327 492,523 259,066 1,314,842 478,206 269,638 1,545,644 527,246
Revisions of previous estimates:
Related to price changes....... (18,022) (50,385) (26,419) 10,972 29,055 15,814 70,536 99,604 87,137
Other.......................... 16,843 91,424 32,080 8,323 34,857 14,133 (18,887) 97,229 (2,682)
Purchases of minerals-in-place... 24,943 63,113 35,462 1,237 28,071 5,916 - - -
New discoveries and extensions... 4,442 93,220 19,979 4,819 66,486 15,900 149 1,351 374
Production....................... (15,862) (77,609) (28,796) (16,872) (83,930) (30,860) (20,163) (106,095) (37,845)
Sales of minerals-in-place....... - - - (743) (35,054) (6,586) (42,207) (322,891) (96,024)
------- --------- ------- ------- --------- ------- ------- --------- --------
Balance, December 31............. 279,146 1,474,090 524,829 266,802 1,354,327 492,523 259,066 1,314,842 478,206
ARGENTINA
Balance, January 1............... 35,843 408,282 103,890 29,797 415,620 99,067 24,219 428,334 95,608
Revisions of previous estimates:
Related to price changes....... - - - - - - - - -
Other.......................... (932) 4,460 (189) 1,411 (15,558) (1,182) (2,441) (12,470) (4,520)
Purchases of minerals-in-place... 170 31,700 5,453 - - - 4,406 17,483 7,320
New discoveries and extensions... 4,354 58,538 14,110 8,066 43,914 15,385 6,182 16,750 8,974
Production....................... (3,766) (31,830) (9,071) (3,431) (35,694) (9,380) (2,569) (34,477) (8,315)
------- --------- ------- ------- --------- ------- ------- --------- --------
Balance, December 31............. 35,669 471,150 114,193 35,843 408,282 103,890 29,797 415,620 99,067
CANADA
Balance, January 1............... 4,066 132,919 26,219 3,970 145,251 28,179 12,447 249,230 53,985
Revisions of previous estimates:
Related to price changes....... (1) 8,701 1,449 (119) (10,116) (1,805) 169 (1,113) (18)
Other.......................... 213 6,366 1,274 548 103 565 4,696 (61,243) (5,509)
Purchases of minerals-in-place... - - - 140 7,768 1,435 - - -
New discoveries and extensions... 81 5,644 1,022 138 6,132 1,160 - - -
Production....................... (671) (18,426) (3,742) (611) (16,219) (3,315) (1,960) (17,886) (4,941)
Sales of minerals-in-place....... (1,029) (3,143) (1,553) - - - (11,382) (23,737) (15,338)
------- --------- ------- ------- --------- ------- ------- --------- --------
Balance, December 31............. 2,659 132,061 24,669 4,066 132,919 26,219 3,970 145,251 28,179
SOUTH AFRICA
Balance, January 1............... 5,552 - 5,552 - - - - - -
Purchases of minerals-in-place... 2,133 - 2,133 - - - - - -
New discoveries and extensions... - - - 5,552 - 5,552 - - -
------- --------- ------- ------- --------- ------- ------- --------- --------
Balance, December 31............. 7,685 - 7,685 5,552 - 5,552 - - -
TOTAL
Balance, January 1............... 312,263 1,895,528 628,184 292,833 1,875,713 605,452 306,304 2,223,208 676,839
Revisions of previous estimates:
Related to price changes....... (18,023) (41,684) (24,970) 10,853 18,939 14,009 70,705 98,491 87,119
Other.......................... 16,124 102,250 33,165 10,282 19,402 13,516 (16,632) 23,516 (12,711)
Purchases of minerals-in-place... 27,246 94,813 43,048 1,377 35,839 7,351 4,406 17,483 7,320
New discoveries and extensions... 8,877 157,402 35,111 18,575 116,532 37,997 6,331 18,101 9,348
Production....................... (20,299) (127,865) (41,609) (20,914) (135,843) (43,555) (24,692) (158,458) (51,101)
Sales of minerals-in-place....... (1,029) (3,143) (1,553) (743) (35,054) (6,586) (53,589) (346,628) (111,362)
------- --------- ------- ------- --------- ------- ------- --------- --------
Balance, December 31............. 325,159 2,077,301 671,376 312,263 1,895,528 628,184 292,833 1,875,713 605,452
======= ========= ======= ======= ========= ======= ======= ========= ========
Proved Developed Reserves:
United States.................. 206,922 1,081,592 387,188 209,636 1,118,976 396,133 240,588 1,422,430 477,659
Argentina...................... 22,679 345,281 80,226 22,931 358,124 82,618 22,172 368,940 83,662
Canada......................... 2,930 80,953 16,422 2,598 61,210 12,800 12,193 210,405 47,261
------- --------- ------- ------- --------- ------- ------- --------- --------
January 1.................... 232,531 1,507,826 483,836 235,165 1,538,310 491,551 274,953 2,001,775 608,582
======= ========= ======= ======= ========= ======= ======= ========= ========
United States.................. 196,893 1,027,750 368,184 206,922 1,081,592 387,188 209,636 1,118,976 396,133
Argentina...................... 28,248 341,967 85,243 22,679 345,281 80,226 22,931 358,124 82,618
Canada......................... 2,086 94,607 17,854 2,930 80,953 16,422 2,598 61,210 12,800
------- --------- ------- ------- --------- ------- ------- --------- --------
December 31.................. 227,227 1,464,324 471,281 232,531 1,507,826 483,836 235,165 1,538,310 491,551
======= ========= ======= ======= ========= ======= ======= ========= ========
84
PIONEER NATURAL RESOURCES COMPANY
UNAUDITED SUPPLEMENTARY INFORMATION
Years Ended December 31, 2001, 2000 and 1999
Standardized Measure of Discounted Future Net Cash Flows
The standardized measure of discounted future net cash flows is computed
by applying year-end prices of oil and gas (with consideration of price changes
only to the extent provided by contractual arrangements) to the estimated future
production of proved oil and gas reserves less estimated future expenditures
(based on year-end costs) to be incurred in developing and producing the proved
reserves, discounted using a rate of 10 percent per year to reflect the
estimated timing of the future cash flows. Future income taxes are calculated by
comparing undiscounted future cash flows to the tax basis of oil and gas
properties plus available carryforwards and credits and applying the current tax
rates to the difference. The discounted future net cash flows estimated in the
table below do not include the effects of the Company's commodity hedging
contracts. Utilizing December 31, 2001 commodity prices held constant over each
hedge contract's term, the net present value of the Company's hedge contracts
discounted at 10 percent was an asset equal to approximately $230 million.
Discounted future cash flow estimates like those shown below are not
intended to represent estimates of the fair value of oil and gas properties.
Estimates of fair value should also consider probable reserves, anticipated
future oil and gas prices, interest rates, changes in development and production
costs and risks associated with future production. Because of these and other
considerations, any estimate of fair value is necessarily subjective and
imprecise.
For the Year Ended December 31,
----------------------------------------
2001 2000 1999
----------- ----------- ------------
(in thousands)
UNITED STATES Oil and gas producing activities:
Future cash inflows.................................. $ 8,222,573 $18,660,169 $ 8,143,587
Future production costs.............................. (3,231,730) (4,907,134) (2,823,316)
Future development costs............................. (735,984) (479,290) (288,801)
Future income tax expense............................ (598,612) (3,777,157) (855,875)
---------- ---------- -----------
3,656,247 9,496,588 4,175,595
10% annual discount factor.............................. (1,691,118) (4,780,133) (1,837,826)
---------- ---------- -----------
Standardized measure of discounted future cash flows.... $ 1,965,129 $ 4,716,455 $ 2,337,769
========== ========== ===========
ARGENTINA
Oil and gas producing activities:
Future cash inflows.................................. $ 1,070,664 $ 1,183,652 $ 1,075,904
Future production costs.............................. (227,435) (215,853) (199,513)
Future development costs............................. (144,604) (114,606) (79,336)
Future income tax expense............................ (45,140) (81,705) (87,274)
---------- ---------- -----------
653,485 771,488 709,781
10% annual discount factor.............................. (262,334) (264,126) (240,681)
---------- ---------- -----------
Standardized measure of discounted future cash flows.... $ 391,151 $ 507,362 $ 469,100
========== ========== ===========
CANADA
Oil and gas producing activities:
Future cash inflows.................................. $ 301,002 $ 1,029,007 $ 354,662
Future production costs.............................. (73,601) (104,189) (91,913)
Future development costs............................. (27,050) (35,443) (54,571)
Future income tax expense............................ (10,771) (306,399) (2,522)
---------- ---------- -----------
189,580 582,976 205,656
10% annual discount factor.............................. (59,995) (168,441) (75,266)
---------- ---------- -----------
Standardized measure of discounted future cash flows.... $ 129,585 $ 414,535 $ 130,390
========== ========== ===========
SOUTH AFRICA
Oil and gas producing activities:
Future cash inflows.................................. $ 149,777 $ 126,134 $ -
Future production costs.............................. (73,697) (65,232) -
Future development costs............................. (54,281) (47,970) -
Future income tax expense............................ - - -
---------- ---------- -----------
21,799 12,932 -
10% annual discount factor.............................. (7,338) (5,782) -
---------- ---------- -----------
Standardized measure of discounted future cash flows.... $ 14,461 $ 7,150 $ -
========== ========== ===========
TOTAL
Oil and gas producing activities:
Future cash inflows.................................. $ 9,744,016 $20,998,962 $ 9,574,153
Future production costs.............................. (3,606,463) (5,292,408) (3,114,742)
Future development costs............................. (961,919) (677,309) (422,708)
Future income tax expense............................ (654,523) (4,165,261) (945,671)
---------- ---------- -----------
4,521,111 10,863,984 5,091,032
10% annual discount factor.............................. (2,020,785) (5,218,482) (2,153,773)
----------- ---------- -----------
Standardized measure of discounted future cash flows.... $ 2,500,326 $ 5,645,502 $ 2,937,259
========== ========== ===========
85
PIONEER NATURAL RESOURCES COMPANY
UNAUDITED SUPPLEMENTARY INFORMATION
Years Ended December 31, 2001, 2000 and 1999
For the Year Ended December 31,
---------------------------------------
Oil and Gas Producing Activities 2001 2000 1999
----------- ----------- -----------
(in thousands)
Oil and gas sales, net of production costs........... $ (631,365) $ (663,473) $ (485,116)
Net changes in prices and production costs........... (4,528,168) 3,829,794 1,571,584
Extensions and discoveries........................... 184,454 525,361 60,695
Development costs incurred during the period......... 239,156 101,350 84,526
Sales of minerals-in-place........................... (23,372) (72,624) (468,376)
Purchases of minerals-in-place....................... 201,535 187,097 56,309
Revisions of estimated future development costs...... (429,365) (200,734) (199,569)
Revisions of previous quantity estimates............. 40,771 344,454 387,616
Accretion of discount................................ 701,943 293,726 164,881
Changes in production rates, timing and other........ (274,689) (262,784) 115,901
---------- ---------- ---------
Change in present value of future net revenues....... (4,519,100) 4,082,167 1,288,451
Net change in present value of future income taxes... 1,373,924 (1,373,924) -
---------- ---------- ---------
(3,145,176) 2,708,243 1,288,451
Balance, beginning of year........................... 5,645,502 2,937,259 1,648,808
---------- ---------- ---------
Balance, end of year................................. $ 2,500,326 $ 5,645,502 $2,937,259
========== ========== =========
Selected Quarterly Financial Results
Quarter
---------------------------------------------
First Second Third Fourth
--------- --------- --------- ---------
(in thousands, except per share data)
2001
Operating revenues........................... $ 257,986 $ 218,611 $ 198,088 $ 172,337
Total revenues............................... $ 270,446 $ 231,038 $ 204,471 $ 170,526
Costs and expenses........................... $ 202,127 $ 200,092 $ 178,864 $ 187,633
Net income (loss):
Before extraordinary items................ $ 67,919 $ 28,338 $ 23,228 $ (15,736)
Extraordinary items, net of tax (a)....... - - 1,374 (5,127)
-------- -------- -------- --------
Net income (loss)......................... $ 67,919 $ 28,338 $ 24,602 $ (20,863)
======== ======== ======== ========
Net income (loss) per share:
Basic:
Before extraordinary items.............. $ .69 $ .29 $ .24 $ (.16)
Extraordinary items..................... - - .01 (.05)
-------- -------- -------- --------
Net income (loss)....................... $ .69 $ .29 $ .25 $ (.21)
======== ======== ======== ========
Diluted:
Before extraordinary items.............. $ .68 $ .28 $ .24 $ (.16)
Extraordinary items..................... - - .01 (.05)
-------- -------- -------- --------
Net income (loss)....................... $ .68 $ .28 $ .25 $ (.21)
======== ======== ======== ========
2000
Operating revenues........................... $ 174,375 $ 197,947 $ 228,587 $ 251,829
Total revenues............................... $ 186,502 $ 198,354 $ 257,945 $ 269,896
Costs and expenses........................... $ 172,032 $ 203,697 $ 192,557 $ 185,912
Net income (loss):
Before extraordinary item................. $ 14,770 $ (3,743) $ 69,288 $ 84,184
Extraordinary item, net of tax (a)........ - (12,318) - -
-------- -------- -------- --------
Net income (loss)......................... $ 14,770 $ (16,061) $ 69,288 $ 84,184
======== ======== ======== ========
Net income (loss) per share:
Basic:
Before extraordinary item............... $ .15 $ (.04) $ .70 $ .86
Extraordinary item...................... - (.12) - -
-------- -------- -------- --------
Net income (loss)....................... $ .15 $ (.16) $ .70 $ .86
======== ======== ======== ========
Diluted:
Before extraordinary item............... $ .15 $ (.04) $ .69 $ .85
Extraordinary item...................... - (.12) - -
-------- -------- -------- --------
Net income (loss)....................... $ .15 $ (.16) $ .69 $ .85
======== ======== ======== ========
----------
(a) During July 2001, the Company redeemed the remaining $22.5 million of
outstanding 11-5/8 percent senior subordinated discount notes due July 1,
2006 and $6.8 million of outstanding 10-5/8 percent senior subordinated
notes due July 1, 2006 and recognized an extraordinary gain, net of taxes,
of $1.3 million associated with these redemptions. Additionally, during the
quarter ended December 31, 2001, the Company redeemed $38.7 million of the
9-5/8 percent senior notes and recognized an extraordinary loss, net of
taxes, of $5.1 million associated with this redemption. As a result of the
early extinguishment of a revolving credit facility, the Company recognized
an extraordinary loss of $12.3 million, net of taxes, during May 2000 (see
Note D of the accompanying Notes to Consolidated Financial Statements).
86
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
The information required in response to this item is set forth in the
Company's definitive proxy statement for the annual meeting of stockholders to
be held on May 14, 2002 and is incorporated herein by reference.
ITEM 11. EXECUTIVE COMPENSATION
The information required in response to this item is set forth in the
Company's definitive proxy statement for the annual meeting of stockholders to
be held on May 14, 2002 and is incorporated herein by reference.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT
The information required in response to this item is set forth in the
Company's definitive proxy statement for the annual meeting of stockholders to
be held on May 14, 2002 and is incorporated herein by reference.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The information required in response to this item is set forth in the
Company's definitive proxy statement for the annual meeting of stockholders to
be held on May 14, 2002 and is incorporated herein by reference.
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
(a) Listing of Financial Statements and Exhibits
Financial Statements
The following consolidated financial statements of the Company are
included in "Item 8. Financial Statements and Supplementary Data":
Independent Auditors' Report
Consolidated Balance Sheets as of December 31, 2001 and 2000
Consolidated Statements of Operations for the years ended December 31,
2001, 2000 and 1999 Consolidated Statements of Stockholders' Equity for
the years ended December 31, 2001, 2000 and 1999 Consolidated Statements
of Cash Flows for the years ended December 31, 2001, 2000 and 1999
Consolidated Statements of Comprehensive Income (Loss) for the years
ended December 31,
2001, 2000 and 1999
Notes to Consolidated Financial Statements
Unaudited Supplementary Information
All other statements and schedules for which provision is made in the
applicable accounting regulations of the SEC have been omitted because they are
not required under related instructions or are inapplicable, or the information
is shown in the financial statements and related notes.
87
Exhibits
Exhibit
Number Description
3.1 - Amended and Restated Certificate of Incorporation of the Company
(incorporated by reference to Exhibit 3.1 to the Company's
Registration Statement on Form S-4, dated June 27, 1997,
Registration No. 333-26951).
3.2 - Restated Bylaws of the Company (incorporated by reference to Exhibit
3.2 to the Company's Registration Statement on Form S-4, dated June
27, 1997, Registration No. 333-26951).
3.3 - Certificate of Designations of Special Preferred Voting Stock
(incorporated by reference to Exhibit 3.3 of the Company's
Registration Statement on Form S-3, Registration No. 333-42315,
filed with the SEC on December 17, 1997).
3.4 - Terms and Conditions of Exchangeable Shares (incorporated by
reference to Annex F to the Definitive Joint Management Information
Circular and Proxy Statement of the Company and Chauvco Resources
Ltd., File No. 001-13245, filed with the SEC on November 17, 1997).
3.5 - Certificate of Designation of Series A Junior Participating
Preferred Stock (incorporated by reference to Exhibit A to Exhibit
4.1 to the Company's Registration Statement on Form 8-A, File No.
001-13245, filed with the SEC on July 24, 2001).
4.1 - Form of Certificate of Common Stock, par value $.01 per share, of
the Company (incorporated by reference to Exhibit 4.1 to the
Company's Registration Statement on Form S-4, dated June 27, 1997,
Registration No. 333-26951).
4.2 - Form of Certificate of Special Preferred Voting Stock (incorporated
by reference to Exhibit 4.1 to the Company's Current Report on Form
8-K, File No. 001-13245, filed with the SEC on January 2, 1998).
4.3 - Form of Certificate of Exchangeable Shares (incorporated by
reference to Exhibit 4.2 to the Company's Current Report on Form
8-K, File No. 001-13245, filed with the SEC on January 2, 1998).
4.4 - Rights Agreement dated July 24, 2001, between the Company and
Continental Stock Transfer & Trust Company, as Rights Agent
(incorporated by reference to Exhibit 4.1 to the Company's
Registration Statement on Form 8-A, File No. 001-13245, filed with
the SEC on July 24, 2001).
9.1 - Voting and Exchange Trust Agreement, dated as of December 18, 1997,
among the Company, Pioneer Natural Resources (Canada) Ltd. ("Pioneer
Canada") and Montreal Trust Company of Canada, as Trustee
(incorporated by reference to Exhibit 2.4 to the Company's Current
Report on Form 8-K, File No. 001-13245, filed with the SEC on
January 2, 1998).
10.1 - Indenture, dated April 12, 1995, between Pioneer USA (successor to
Parker & Parsley Petroleum Company ("Parker & Parsley"), and The
Chase Manhattan Bank (National Association), as Trustee
(incorporated by reference to Exhibit 4.1 to Parker & Parsley's
Current Report on Form 8-K, dated April 12, 1995, File No.
001-10695).
10.2 - First Supplemental Indenture, dated as of August 7, 1997, among
Parker & Parsley, The Chase Manhattan Bank, as Trustee, and Pioneer
USA, with respect to the indenture identified above as Exhibit 10.1
(incorporated by reference to Exhibit 10.5 to the Company's
Quarterly Report on Form 10-Q for the period ended September 30,
1997, File No. 001-13245).
88
Exhibit
Number Description
10.3 - Second Supplemental Indenture, dated as of December 30, 1997, among
Pioneer USA, a Delaware corporation, Pioneer NewSub1, Inc., a Texas
corporation, and The Chase Manhattan Bank, a New York banking
association, as Trustee, with respect to the indenture identified
above as Exhibit 10.1 (incorporated by reference to Exhibit 10.17 to
the Company's Current Report on Form 8-K, File No. 001-13245, filed
with the SEC on January 2, 1998).
10.4 - Third Supplemental Indenture, dated as of December 30, 1997, among
Pioneer NewSub1, Inc. (as successor to Pioneer USA), a Texas
corporation, Pioneer DebtCo, Inc., a Texas corporation, and The
Chase Manhattan Bank, a New York banking association, as Trustee,
with respect to the indenture identified above as Exhibit 10.1
(incorporated by reference to Exhibit 10.18 to the Company's Current
Report on Form 8-K, File No. 001-13245, filed with the SEC on
January 2, 1998).
10.5 - Fourth Supplemental Indenture, dated as of December 30, 1997, among
Pioneer DebtCo, Inc. (as successor to Pioneer NewSub1, Inc., as
successor to Pioneer USA), a Texas corporation, the Company, a
Delaware corporation, Pioneer USA, a Delaware corporation, and The
Chase Manhattan Bank, a New York banking association, as Trustee,
with respect to the indenture identified above as Exhibit 10.1
(incorporated by reference to Exhibit 10.19 to the Company's Current
Report on Form 8-K, File No. 001-13245, filed with the SEC on
January 2, 1998).
10.6 - Guarantee, dated as of December 30, 1997, by Pioneer USA relating to
the $150,000,000 in aggregate principal amount of 8-7/8% Senior
Notes due 2005 and $150,000,000 in aggregate principal amount of
8-1/4% Senior Notes due 2007 issued under the indenture identified
above as Exhibit 10.1 (incorporated by reference to Exhibit 10.20 to
the Company's Current Report on Form 8-K, File No. 001-13245, filed
with the SEC on January 2, 1998).
10.7 - Form of 8-7/8% Senior Notes Due 2005, dated as of April 12, 1995, in
the aggregate principal amount of $150,000,000, together with
Officers' Certificate dated April 12, 1995, establishing the terms
of the 8-7/8% Senior Notes Due 2005 pursuant to the indenture
identified above as Exhibit 10.1 (incorporated by reference to
Exhibit 4.2 to Parker & Parsley's Quarterly Report on Form 10-Q for
the period ended June 30, 1995, File No. 001-10695).
10.8 - Form of 8-1/4% Senior Notes due 2007, dated as of August 22, 1995,
in the aggregate principal amount of $150,000,000, together with
Officers' Certificate dated August 22, 1995, establishing the terms
of the 8-1/4% Senior Notes due 2007 pursuant to the indenture
identified above as Exhibit 10.1 (incorporated by reference to
Exhibit 1.2 to Parker & Parsley's Current Report on Form 8-K, dated
August 17, 1995, File No. 001-10695).
10.9 - Indenture, dated January 13, 1998, between the Company and The Bank
of New York, as Trustee (incorporated by reference to Exhibit 99.1
to the Company's and Pioneer USA's Current Report on Form 8-K, File
No. 001-13245, filed with the SEC on January 14, 1998).
10.10 - First Supplemental Indenture, dated as of January 13, 1998, among
the Company, Pioneer USA, as the Subsidiary Guarantor, and The Bank
of New York, as Trustee, with respect to the indenture identified
above as Exhibit 10.9 (incorporated by reference to Exhibit 99.2 to
the Company's and Pioneer USA's Current Report on Form 8-K, File No.
001-13245, filed with the SEC on January 14, 1998).
10.11 - Form of 6.50% Senior Notes Due 2008 of the Company (incorporated by
reference to Exhibit 99.3 to the Company's and Pioneer USA's Current
Report on Form 8-K, File No. 001-13245, filed with the SEC on
January 14, 1998).
10.12 - Form of 7.20% Senior Notes Due 2028 of the Company (incorporated by
reference to Exhibit 99.4 to the Company's and Pioneer USA's Current
Report on Form 8-K, File No. 001-13245, filed with the SEC on
January 14, 1998).
89
Exhibit
Number Description
10.13 - Guarantee (2008 Notes), dated as of January 13, 1998, entered into
by Pioneer USA (incorporated by reference to Exhibit 99.5 to the
Company's and Pioneer USA's Current Report on Form 8-K, File No.
001-13245, filed with the SEC on January 14, 1998).
10.14 - Guarantee (2028 Notes), dated as of January 13, 1998, entered into
by Pioneer USA (incorporated by reference to Exhibit 99.6 to the
Company's and Pioneer USA's Current Report on Form 8-K, File No.
001-13245, filed with the SEC on January 14, 1998).
10.15H - 1991 Stock Option Plan of Mesa (incorporated by reference to Exhibit
10(v) to Mesa's Annual Report on Form 10-K for the period ended
December 31, 1991).
10.16H - 1996 Incentive Plan of Mesa (incorporated by reference to Exhibit
10.28 to the Company's Registration Statement on Form S-4, dated
June 27, 1997, Registration No. 333-26951).
10.17H - Parker & Parsley Long-Term Incentive Plan, dated February 19, 1991
(incorporated by reference to Exhibit 4.1 to Parker & Parsley's
Registration Statement on Form S-8, Registration No. 33-38971).
10.18H - First Amendment to the Parker & Parsley Long-Term Incentive Plan,
dated August 23, 1991 (incorporated by reference to Exhibit 10.2 to
Parker & Parsley's Registration Statement on Form S-1, dated
February 28, 1992, Registration No. 33-46082).
10.19H - The Company's Long-Term Incentive Plan (incorporated by reference to
Exhibit 4.1 to the Company's Registration Statement on Form S-8,
Registration No. 333-35087).
10.20H - First Amendment to the Company's Long-Term Incentive Plan, effective
as of November 23, 1998 (incorporated by reference to Exhibit 10.72
to the Company's Annual Report on Form 10-K for the period ended
December 31, 1999, File No. 1-13245).
10.21H - Amendment No. 2 to the Company's Long-Term Incentive Plan, effective
as of May 20, 1999 (incorporated by reference to Exhibit 10.73 to
the Company's Annual Report on Form 10-K for the period ended
December 31, 1999, File No. 1-13245).
10.22H - Amendment No. 3 to the Company's Long-Term Incentive Plan, effective
as of February 17, 2000 (incorporated by reference to Exhibit 10.76
to the Company's Annual Report on Form 10-K for the period ended
December 31, 1999, File No. 1-13245).
10.23H - The Company's Employee Stock Purchase Plan (incorporated by
reference to Exhibit 4.1 to the Company's Registration Statement on
Form S-8, Registration No. 333-35165).
10.24H - Amendment No. 1 to the Company's Employee Stock Purchase Plan, dated
December 9, 1998 (incorporated by reference to the Company's Annual
Report on Form 10-K for the year ended December 31, 1998, File No.
001-13245).
10.25H - Amendment No. 2 to the Company's Employee Stock Purchase Plan, dated
December 14, 1999 (incorporated by reference to Exhibit 10.74 to the
Company's Annual Report on Form 10-K for the period ended December
31, 1999, File No. 1-13245).
10.26H - The Company's Deferred Compensation Retirement Plan (incorporated by
reference to Exhibit 4.1 to the Company's Registration Statement on
Form S-8, Registration No. 333-39153).
10.27H - Pioneer USA 401(k) Plan (incorporated by reference to Exhibit 4.1 to
the Company's Registration Statement on Form S-8, Registration No.
333-39249).
90
Exhibit
Number Description
10.28H - Pioneer USA Matching Plan (incorporated by reference to Exhibit
10.42 to the Company's Annual Report on Form 10-K for the year ended
December 31, 1997, File No. 001-13245).
10.29H - Omnibus Amendment to Nonstatutory Stock Option Agreements, included
as part of the Parker & Parsley Long-Term Incentive Plan, dated as
of November 16, 1995, between Parker & Parsley and Named Executive
Officers identified on Schedule 1 setting forth additional details
relating to the Parker & Parsley Long-Term Incentive Plan
(incorporated by reference to Parker & Parsley's Annual Report on
Form 10-K for the year ended December 31, 1995, File No. 001-10695).
10.30H - Severance Agreement, dated as of August 8, 1997, between the Company
and Scott D. Sheffield, together with a schedule identifying
substantially identical agreements between the Company and each of
the other named executive officers identified on Schedule I for the
purpose of defining the payment of certain benefits upon the
termination of the officer's employment under certain circumstances
(incorporated by reference to Exhibit 10.7 to the Company's
Quarterly Report on Form 10-Q for the period ended September 30,
1997, File No. 001-13245).
10.31H - Indemnification Agreement, dated as of August 8, 1997, between the
Company and Scott D. Sheffield, together with a schedule identifying
substantially identical agreements between the Company and each of
the Company's other directors and named executive officers
identified on Schedule I (incorporated by reference to Exhibit 10.8
to the Company's Quarterly Report on Form 10-Q for the period ended
September 30, 1997, File No. 001-13245).
10.32 - "B" Contract Production Allocation Agreement, dated July 29, 1991,
and effective as of January 1, 1991, between Colorado Interstate Gas
Company and Mesa Operating Limited Partnership (incorporated by
reference to Exhibit 10(r) to Mesa's Annual Report on Form 10-K for
the period ended December 31, 1991).
10.33 - Amendment to "B" Contract Production Allocation Agreement effective
as of January 1, 1993, between Colorado Interstate Gas Company and
Mesa Operating Limited Partnership (incorporated by reference to
Exhibit 10.24 to Mesa's Registration Statement on Form S-1,
Registration No. 33-51909).
10.34 - Voting and Shareholders Agreement dated as of February 8, 2000
between Prize Energy Corp. and its stockholders (incorporated by
reference to Exhibit 10.1 to the Company's statement on Schedule 13D
relating to the common stock of Prize Energy Corp., filed with the
SEC on February 18, 2000, File No. 005-54797).
10.35 - Second Supplemental Indenture, dated as of April 11, 2000, among the
Company, Pioneer USA, as the subsidiary guarantor and the Bank of
New York, as trustee, with respect to the Indenture, dated January
13, 1998, between the Company and The Bank of New York, as trustee
(incorporated by reference to Exhibit 10.1 to the Company's
Quarterly Report on Form 10-Q, filed with the SEC on May 11, 2000).
10.36 - Form of 9-5/8% Senior Notes Due April 1, 2010, dated as of April 11,
2000, in the aggregate principal amount of $425,000,000, together
with Trustee's Certificate of Authentication dated April 11, 2000,
establishing the terms of the 9-5/8% Senior Notes Due April 1, 2010
pursuant to the Second Supplemental Indenture identified above as
Exhibit 10.35 (incorporated by reference to Exhibit 10.2 to the
Company's Quarterly Report on Form 10-Q, filed with the SEC on May
11, 2000).
10.37 - Guarantee, dated as of April 11, 2000, by Pioneer USA as the
subsidiary guarantor relating to the $425,000,000 aggregate
principal amount of 9-5/8% Senior Notes Due April 1, 2010 issued
under the Second Supplemental Indenture identified above as Exhibit
10.35 (incorporated by reference to Exhibit 10.3 to the Company's
Quarterly Report on Form 10-Q, filed with the SEC on May 11, 2000).
91
Exhibit
Number Description
10.38 - $575,000,000 Credit Agreement dated as of May 31, 2000, among the
Company, as the borrower, Bank of America, N.A., as the
Administrative Agent, Credit Suisse First Boston, as the
Documentation Agent, the Chase Manhattan Bank, as the Syndicated
Agent and certain Lenders (incorporated by reference to Exhibit 10.4
to the Company's Quarterly Report on Form 10-Q, filed with the SEC
on August 9, 2000).
10.39 - Agreement and Plan of Merger dated as of November 28, 2000 by and
among Pioneer Natural Resources Company, Pioneer Natural Resources
USA, Inc., Parker & Parsley Employees Producing Properties 87-A,
Ltd., Parker & Parsley Employees Producing Properties 87-B Ltd., P&P
Employees Producing Properties 88-A, L.P., P&P Employees 89-A Conv.,
L.P., P&P Employees 89-B Conv., L.P., P&P Employees Private 89,
L.P., P&P Employees 90-A Conv., L.P., P&P Employees 90-B Conv.,
L.P., P&P Employees 90-C Conv., L.P., P&P Employees Private 90,
L.P., P&P Employees 90 Spraberry Private Development, L.P., P&P
Employees 91-A Conv., L.P. and P&P Employees 91-B Conv., L.P.
(incorporated by reference to Exhibit 10.53 to the Company's Annual
Report on Form 10-K for the period ended December 31, 2000, File No.
1-13245).
10.40 - Agreement and Plan of Merger dated as of September 20, 2001, among
the Company, Pioneer Natural Resources USA, Inc. and the Parker &
Parsley partnerships named therein (incorporated by reference to
Exhibit 2.1 to the Company's Registration Statement on Form S-4,
Registration No. 333-59094, filed with the SEC on April 17, 2001).
21.1* - Subsidiaries of the registrant.
23.1* - Consent of Ernst & Young LLP.
---------------
* Filed herewith
H Executive Compensation Plan or Arrangement previously filed pursuant to Item
14(c).
(b) Reports on Form 8-K
During the three months ended December 31, 2001, the Company did not file
any current reports on Form 8-K.
(c) Exhibits
The exhibits to this Report required to be filed pursuant to Item 14(c)
are listed under "Item 14. Exhibits, Financial Statement Schedules and Reports
on Form 8-K - Listing of Financial Statements and Exhibits - Exhibits" above and
in the "Index to Exhibits" attached hereto.
(d) Financial Statement Schedules
No financial statement schedules are required to be filed as part of
this Report or they are inapplicable.
92
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.
PIONEER NATURAL RESOURCES COMPANY
Date: March 6, 2002 By: /s/ Scott D. Sheffield
------------------------------------------
Scott D. Sheffield, Chairman of the Board,
Chief Executive Officer, President and
Assistant Secretary
Pursuant to the requirements of the Securities Exchange Act of 1934, this
Report has been signed below by the following persons on behalf of the
Registrant and in the capacities and on the dates indicated.
Signature Title Date
/s/ Scott D. Sheffield Chairman of the Board, President, March 6, 2002
---------------------------- Chief Executive Officer and
Scott D. Sheffield Assistant Secretary
(principal executive officer)
/s/ Timothy L. Dove Executive Vice President, Chief March 6, 2002
---------------------------- Financial Officer and Assistant
Timothy L. Dove Secretary
/s/ Richard P. Dealy Vice President and Chief March 6, 2002
---------------------------- Accounting Officer
Richard P. Dealy
/s/ James R. Baroffio Director March 6, 2002
----------------------------
James R. Baroffio
/s/ R. Hartwell Gardner Director March 6, 2002
----------------------------
R. Hartwell Gardner
/s/ James L. Houghton Director March 6, 2002
----------------------------
James L. Houghton
/s/ Jerry P. Jones Director March 6, 2002
----------------------------
Jerry P. Jones
/s/ Charles E. Ramsey, Jr. Director March 6, 2002
----------------------------
Charles E. Ramsey, Jr.
93
PIONEER NATURAL RESOURCES COMPANY
Exhibit Index Page
3.1 - Amended and Restated Certificate of Incorporation of the
Company (incorporated by reference to Exhibit 3.1 to the
Company's Registration Statement on Form S-4, dated June 27,
1997, Registration No. 333-26951).
3.2 - Restated Bylaws of the Company (incorporated by reference
to Exhibit 3.2 to the Company's Registration Statement on
Form S-4, dated June 27, 1997, Registration No. 333-26951).
3.3 - Certificate of Designations of Special Preferred Voting Stock
(incorporated by reference to Exhibit 3.3 of the Company's
Registration Statement on Form S-3, Registration No. 333-42315,
filed with the SEC on December 17, 1997).
3.4 - Terms and Conditions of Exchangeable Shares (incorporated by
reference to Annex F to the Definitive Joint Management
Information Circular and Proxy Statement of the Company and
Chauvco Resources Ltd., File No. 001-13245, filed with the
SEC on November 17, 1997).
3.5 - Certificate of Designation of Series A Junior Participating
Preferred Stock (incorporated by reference to Exhibit A to
Exhibit 4.1 to the Company's Registration Statement on Form
8-A, File No. 001-13245, filed with the SEC on July 24, 2001).
4.1 - Form of Certificate of Common Stock, par value $.01 per share,
of the Company (incorporated by reference to Exhibit 4.1 to
the Company's Registration Statement on Form S-4, dated June
27, 1997, Registration No. 333-26951).
4.2 - Form of Certificate of Special Preferred Voting Stock
(incorporated by reference to Exhibit 4.1 to the Company's
Current Report on Form 8-K, File No. 001-13245, filed with
the SEC on January 2, 1998).
4.3 - Form of Certificate of Exchangeable Shares (incorporated by
reference to Exhibit 4.2 to the Company's Current Report on
Form 8-K, File No. 001-13245, filed with the SEC on January
2, 1998).
4.4 - Rights Agreement dated July 24, 2001, between the Company and
Continental Stock Transfer & Trust Company, as Rights Agent
(incorporated by reference to Exhibit 4.1 to the Company's
Registration Statement on Form 8-A, File No. 001-13245, filed
with the SEC on July 24, 2001).
9.1 - Voting and Exchange Trust Agreement, dated as of December 18,
1997, among the Company, Pioneer Natural Resources (Canada)
Ltd. ("Pioneer Canada") and Montreal Trust Company of Canada,
as Trustee (incorporated by reference to Exhibit 2.4 to the
Company's Current Report on Form 8-K, File No. 001-13245,
filed with the SEC on January 2, 1998).
10.1 - Indenture, dated April 12, 1995, between Pioneer USA (successor
to Parker & Parsley Petroleum Company ("Parker & Parsley"),
and The Chase Manhattan Bank (National Association), as Trustee
(incorporated by reference to Exhibit 4.1 to Parker & Parsley's
Current Report on Form 8-K, dated April 12, 1995, File No.
001-10695).
10.2 - First Supplemental Indenture, dated as of August 7, 1997, among
Parker & Parsley, The Chase Manhattan Bank, as Trustee, and
Pioneer USA, with respect to the indenture identified above as
Exhibit 10.1 (incorporated by reference to Exhibit 10.5 to the
Company's Quarterly Report on Form 10-Q for the period ended
September 30, 1997, File No. 001-13245).
94
PIONEER NATURAL RESOURCES COMPANY
Exhibit Index Page
10.3 - Second Supplemental Indenture, dated as of December 30, 1997,
among Pioneer USA, a Delaware corporation, Pioneer NewSub1,
Inc., a Texas corporation, and The Chase Manhattan Bank, a
New York banking association, as Trustee, with respect to the
indenture identified above as Exhibit 10.1 (incorporated by
reference to Exhibit 10.17 to the Company's Current Report on
Form 8-K, File No. 001-13245, filed with the SEC on January 2,
1998).
10.4 - Third Supplemental Indenture, dated as of December 30, 1997,
among Pioneer NewSub1, Inc. (as successor to Pioneer USA), a
Texas corporation, Pioneer DebtCo, Inc., a Texas corporation,
and The Chase Manhattan Bank, a New York banking association,
as Trustee, with respect to the indenture identified above as
Exhibit 10.1 (incorporated by reference to Exhibit 10.18 to the
Company's Current Report on Form 8-K, File No. 001-13245, filed
with the SEC on January 2, 1998).
10.5 - Fourth Supplemental Indenture, dated as of December 30, 1997,
among Pioneer DebtCo, Inc. (as successor to Pioneer NewSub1,
Inc., as successor to Pioneer USA), a Texas corporation, the
Company, a Delaware corporation, Pioneer USA, a Delaware
corporation, and The Chase Manhattan Bank, a New York banking
association, as Trustee, with respect to the indenture
identified above as Exhibit 10.1 (incorporated by reference
to Exhibit 10.19 to the Company's Current Report on Form 8-K,
File No. 001-13245, filed with the SEC on January 2, 1998).
10.6 - Guarantee, dated as of December 30, 1997, by Pioneer USA
relating to the $150,000,000 in aggregate principal amount of
8-7/8% Senior Notes due 2005 and $150,000,000 in aggregate
principal amount of 8-1/4% Senior Notes due 2007 issued under
the indenture identified above as Exhibit 10.1 (incorporated
by reference to Exhibit 10.20 to the Company's Current Report
on Form 8-K, File No. 001-13245, filed with the SEC on
January 2, 1998).
10.7 - Form of 8-7/8% Senior Notes Due 2005, dated as of April 12,
1995, in the aggregate principal amount of $150,000,000,
together with Officers' Certificate dated April 12, 1995,
establishing the terms of the 8-7/8% Senior Notes Due 2005
pursuant to the indenture identified above as Exhibit 10.1
(incorporated by reference to Exhibit 4.2 to Parker & Parsley's
Quarterly Report on Form 10-Q for the period ended June 30,
1995, File No. 001-10695).
10.8 - Form of 8-1/4% Senior Notes due 2007, dated as of August 22,
1995, in the aggregate principal amount of $150,000,000,
together with Officers' Certificate dated August 22, 1995,
establishing the terms of the 8-1/4% Senior Notes due 2007
pursuant to the indenture identified above as Exhibit 10.1
(incorporated by reference to Exhibit 1.2 to Parker & Parsley's
Current Report on Form 8-K, dated August 17, 1995, File No.
001-10695).
10.9 - Indenture, dated January 13, 1998, between the Company and
The Bank of New York, as Trustee (incorporated by reference
to Exhibit 99.1 to the Company's and Pioneer USA's Current
Report on Form 8-K, File No. 001-13245, filed with the SEC
on January 14, 1998).
10.10 - First Supplemental Indenture, dated as of January 13, 1998,
among the Company, Pioneer USA, as the Subsidiary Guarantor,
and The Bank of New York, as Trustee, with respect to the
indenture identified above as Exhibit 10.9 (incorporated by
reference to Exhibit 99.2 to the Company's and Pioneer USA's
Current Report on Form 8-K, File No. 001-13245, filed with the
SEC on January 14, 1998).
10.11 - Form of 6.50% Senior Notes Due 2008 of the Company
(incorporated by reference to Exhibit 99.3 to the Company's
and Pioneer USA's Current Report on Form 8-K, File No.
001-13245, filed with the SEC on January 14, 1998).
95
PIONEER NATURAL RESOURCES COMPANY
Exhibit Index Page
10.12 - Form of 7.20% Senior Notes Due 2028 of the Company
(incorporated by reference to Exhibit 99.4 to the Company's
and Pioneer USA's Current Report on Form 8-K, File No.
001-13245, filed with the SEC on January 14, 1998).
10.13 - Guarantee (2008 Notes), dated as of January 13, 1998, entered
into by Pioneer USA (incorporated by reference to Exhibit
99.5 to the Company's and Pioneer USA's Current Report on
Form 8-K, File No. 001-13245, filed with the SEC on January
14, 1998).
10.14 - Guarantee (2028 Notes), dated as of January 13, 1998, entered
into by Pioneer USA (incorporated by reference to Exhibit
99.6 to the Company's and Pioneer USA's Current Report on
Form 8-K, File No. 001-13245, filed with the SEC on January 14,
1998).
10.15H - 1991 Stock Option Plan of Mesa (incorporated by reference to
Exhibit 10(v) to Mesa's Annual Report on Form 10-K for the
period ended December 31, 1991).
10.16H - 1996 Incentive Plan of Mesa (incorporated by reference to
Exhibit 10.28 to the Company's Registration Statement on Form
S-4, dated June 27, 1997, Registration No. 333-26951).
10.17H - Parker & Parsley Long-Term Incentive Plan, dated February 19,
1991 (incorporated by reference to Exhibit 4.1 to Parker &
Parsley's Registration Statement on Form S-8, Registration No.
33-38971).
10.18H - First Amendment to the Parker & Parsley Long-Term Incentive
Plan, dated August 23, 1991 (incorporated by reference to
Exhibit 10.2 to Parker & Parsley's Registration Statement on
Form S-1, dated February 28, 1992, Registration No. 33-46082).
10.19H - The Company's Long-Term Incentive Plan (incorporated by
reference to Exhibit 4.1 to the Company's Registration
Statement on Form S-8, Registration No. 333-35087).
10.20H - First Amendment to the Company's Long-Term Incentive Plan,
effective as of November 23, 1998 (incorporated by reference
to Exhibit 10.72 to the Company's Annual Report on Form 10-K
for the period ended December 31, 1999, File No. 1-13245).
10.21H - Amendment No. 2 to the Company's Long-Term Incentive Plan,
effective as of May 20, 1999 (incorporated by reference to
Exhibit 10.73 to the Company's Annual Report on Form 10-K for
the period ended December 31, 1999, File No. 1-13245).
10.22H - Amendment No. 3 to the Company's Long-Term Incentive Plan,
effective as of February 17, 2000 (incorporated by reference to
Exhibit 10.76 to the Company's Annual Report on Form 10-K for
the period ended December 31, 1999, File No. 1-13245).
10.23H - The Company's Employee Stock Purchase Plan (incorporated by
reference to Exhibit 4.1 to the Company's Registration
Statement on Form S-8, Registration No. 333-35165).
10.24H - Amendment No. 1 to the Company's Employee Stock Purchase Plan,
dated December 9, 1998 (incorporated by reference to the
Company's Annual Report on Form 10-K for the year ended
December 31, 1998, File No. 001-13245).
10.25H - Amendment No. 2 to the Company's Employee Stock Purchase Plan,
dated December 14, 1999 (incorporated by reference to Exhibit
10.74 to the Company's Annual Report on Form 10-K for the
period ended December 31, 1999, File No. 1-13245).
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PIONEER NATURAL RESOURCES COMPANY
Exhibit Index Page
10.26H - The Company's Deferred Compensation Retirement Plan
(incorporated by reference to Exhibit 4.1 to the Company's
Registration Statement on Form S-8, Registration No.
333-39153).
10.27H - Pioneer USA 401(k) Plan (incorporated by reference to
Exhibit 4.1 to the Company's Registration Statement on
Form S-8, Registration No. 333-39249).
10.28H - Pioneer USA Matching Plan (incorporated by reference to
Exhibit 10.42 to the Company's Annual Report on Form 10-K
for the year ended December 31, 1997, File No. 001-13245).
10.29H - Omnibus Amendment to Nonstatutory Stock Option Agreements,
included as part of the Parker & Parsley Long-Term Incentive
Plan, dated as of November 16, 1995, between Parker & Parsley
and Named Executive Officers identified on Schedule 1 setting
forth additional details relating to the Parker & Parsley
Long-Term Incentive Plan (incorporated by reference to Parker
& Parsley's Annual Report on Form 10-K for the year ended
December 31, 1995, File No. 001-10695).
10.30H - Severance Agreement, dated as of August 8, 1997, between the
Company and Scott D. Sheffield, together with a schedule
identifying substantially identical agreements between the
Company and each of the other named executive officers
identified on Schedule I for the purpose of defining the
payment of certain benefits upon the termination of the
officer's employment under certain circumstances (incorporated
by reference to Exhibit 10.7 to the Company's Quarterly
Report on Form 10-Q for the period ended September 30,
1997, File No. 001-13245).
10.31H - Indemnification Agreement, dated as of August 8, 1997,
between the Company and Scott D. Sheffield, together with a
schedule identifying substantially identical agreements
between the Company and each of the Company's other
directors and named executive officers identified on
Schedule I (incorporated by reference to Exhibit 10.8 to
the Company's Quarterly Report on Form 10-Q for the period
ended September 30, 1997, File No. 001-13245).
10.32 - "B" Contract Production Allocation Agreement, dated July 29,
1991, and effective as of January 1, 1991, between Colorado
Interstate Gas Company and Mesa Operating Limited Partnership
(incorporated by reference to Exhibit 10(r) to Mesa's Annual
Report on Form 10-K for the period ended December 31, 1991).
10.33 - Amendment to "B" Contract Production Allocation Agreement
effective as of January 1, 1993, between Colorado Interstate
Gas Company and Mesa Operating Limited Partnership
(incorporated by reference to Exhibit 10.24 to Mesa's
Registration Statement on Form S-1, Registration No. 33-51909).
10.34 - Voting and Shareholders Agreement dated as of February 8, 2000
between Prize Energy Corp. and its stockholders (incorporated
by reference to Exhibit 10.1 to the Company's statement on
Schedule 13D relating to the common stock of Prize Energy Corp.,
filed with the SEC on February 18, 2000, File No. 005-54797).
10.35 - Second Supplemental Indenture, dated as of April 11, 2000,
among the Company, Pioneer USA, as the subsidiary guarantor and
the Bank of New York, as trustee, with respect to the Indenture,
dated January 13, 1998, between the Company and The Bank of
New York, as trustee (incorporated by reference to Exhibit
10.1 to the Company's Quarterly Report on Form 10-Q, filed with
the SEC on May 11, 2000).
97
PIONEER NATURAL RESOURCES COMPANY
Exhibit Index Page
10.36 - Form of 9-5/8% Senior Notes Due April 1, 2010, dated as of
April 11, 2000, in the aggregate principal amount of
$425,000,000, together with Trustee's Certificate of
Authentication dated April 11, 2000, establishing the terms
of the 9-5/8% Senior Notes Due April 1, 2010 pursuant to
the Second Supplemental Indenture identified above as Exhibit
10.35 (incorporated by reference to Exhibit 10.2 to the
Company's Quarterly Report on Form 10-Q, filed with the SEC
on May 11, 2000).
10.37 - Guarantee, dated as of April 11, 2000, by Pioneer USA as the
subsidiary guarantor relating to the $425,000,000 aggregate
principal amount of 9-5/8% Senior Notes Due April 1, 2010
issued under the Second Supplemental Indenture identified
above as Exhibit 10.35 (incorporated by reference to Exhibit
10.3 to the Company's Quarterly Report on Form 10-Q, filed
with the SEC on May 11, 2000).
10.38 - $575,000,000 Credit Agreement dated as of May 31, 2000, among
the Company, as the borrower, Bank of America, N.A., as the
Administrative Agent, Credit Suisse First Boston, as the
Documentation Agent, the Chase Manhattan Bank, as the
Syndicated Agent and certain Lenders (incorporated by
reference to Exhibit 10.4 to the Company's Quarterly Report
on Form 10-Q, filed with the SEC on August 9, 2000).
10.39 - Agreement and Plan of Merger dated as of November 28, 2000
by and among Pioneer Natural Resources Company, Pioneer Natural
Resources USA, Inc., Parker & Parsley Employees Producing
Properties 87-A, Ltd., Parker & Parsley Employees Producing
Properties 87-B Ltd., P&P Employees Producing Properties 88-A,
L.P., P&P Employees 89-A Conv., L.P., P&P Employees 89-B Conv.,
L.P., P&P Employees Private 89, L.P., P&P Employees 90-A Conv.,
L.P., P&P Employees 90-B Conv., L.P., P&P Employees 90-C Conv.,
L.P., P&P Employees Private 90, L.P., P&P Employees 90 Spraberry
Private Development, L.P., P&P Employees 91-A Conv., L.P. and
P&P Employees 91-B Conv., L.P. (incorporated by reference to
Exhibit 10.53 to the Company's Annual Report on Form 10-K for
the period ended December 31, 2000, File No. 1-13245).
10.40 - Agreement and Plan of Merger dated as of September 20, 2001,
among the Company, Pioneer Natural Resources USA, Inc. and the
Parker & Parsley partnerships named therein (incorporated by
reference to Exhibit 2.1 to the Company's Registration
Statement on Form S-4, Registration No. 333-59094, filed with
the SEC on April 17, 2001).
21.1* - Subsidiaries of the registrant. 99
23.1* - Consent of Ernst & Young LLP. 100
---------------
* Filed herewith
H Executive Compensation Plan or Arrangement previously filed pursuant to Item
14(c).
98