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, 2002
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. [ ]
Indicate by check mark whether the Registrant is an accelerated filer (as
defined in Rule 12b-2 of the Act).
YES X NO ___
----
Aggregate market value of the voting common equity held by
non-affiliates of the Registrant computed by reference to
the price at which the common equity was last sold, or the
average bid and asked price of such common equity, as of
the last business day of the Registrant's most recently
completed second fiscal quarter ............................. $3,011,384,455
Number of shares of Common Stock outstanding as of
February 17, 2003 .......................................... 117,299,334
Documents Incorporated by Reference:
(1) Proxy Statement for Annual Meeting of Shareholders to be held May 15, 2003
- Referenced in Part III of this report.
TABLE OF CONTENTS
Page
Definitions of Oil and Gas Terms and Conventions Used Herein............. 4
PART I
Item 1. Business..................................................... 5
General...................................................... 5
Available Information........................................ 5
Mission and Strategies....................................... 5
Business Activities.......................................... 6
Operations by Geographic Area................................ 8
Marketing of Production...................................... 9
Competition, Markets and Regulations......................... 9
Risks Associated with Business Activities.................... 11
Item 2. Properties................................................... 13
Proved Reserves.............................................. 14
Finding Cost and Reserve Replacement......................... 14
Description of Properties.................................... 15
Selected Oil and Gas Information............................. 19
Item 3. Legal Proceedings............................................ 22
Item 4. Submission of Matters to a Vote of Security Holders.......... 22
PART II
Item 5. Market for Registrant's Common Stock and Related
Stockholder Matters......................................... 22
Item 6. Selected Financial Data...................................... 23
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations......................... 24
2002 Financial and Operating Performance..................... 24
2003 Outlook................................................. 25
Critical Accounting Estimates................................ 26
New Accounting Pronouncements................................ 27
Results of Operations........................................ 28
Capital Commitments, Capital Resources and Liquidity......... 33
2
TABLE OF CONTENTS
Page
Item 7A. Quantitative and Qualitative Disclosures About Market Risk... 36
Quantitative Disclosures..................................... 36
Qualitative Disclosures...................................... 40
Item 8. Financial Statements and Supplementary Data.................. 41
Index to Consolidated Financial Statements................... 41
Independent Auditors' Report................................. 42
Consolidated Financial Statements............................ 43
Notes to Consolidated Financial Statements................... 48
Unaudited Supplementary Information.......................... 81
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
Item 11. Executive Compensation....................................... 87
Item 12. Security Ownership of Certain Beneficial Owners
and Management.............................................. 87
Item 13. Certain Relations and Related Transactions................... 87
Item 14. Controls and Procedures...................................... 87
PART IV
Item 15. Exhibits, Financial Statement Schedules and Reports
on Form 8-K................................................. 88
Signatures................................................... 94
Certifications............................................... 95
Exhibit Index................................................ 97
3
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; "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 unit and is a
measure of the amount of energy required to raise the temperature of one pound
of water one degree Fahrenheit; "LIBOR" means London Interbank Offered Rate,
which is a market rate of interest; "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; and "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.
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
currency amounts are expressed in U.S. dollars.
4
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. 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; Capetown, South Africa; and Tunis, Tunisia. At
December 31, 2002, the Company had 979 employees, 491 of whom were employed in
field and plant operations.
Available Information
Pioneer files annual, quarterly, and current reports, proxy statements,
and other documents with the SEC under the Securities Exchange Act of 1934. The
public may read and copy any materials that Pioneer files with the SEC at the
SEC's Public Reference Room at 450 Fifth Street, N.W., Washington, DC 20549. The
public may obtain information on the operation of the Public Reference Room by
calling the SEC at 1-800-SEC-0330. Also, the SEC maintains an Internet website
that contains reports, proxy and information statements, and other information
regarding issuers, including Pioneer, that file electronically with the SEC. The
public can obtain any documents that Pioneer files with the SEC at
http://www.sec.gov.
The Company also makes available free of charge on or through its
Internet website (http://www.pioneernrc.com) its Annual Report on Form 10-K,
Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and, if applicable,
amendments to those reports filed or furnished pursuant to Section 13(a) of the
Exchange Act as soon as reasonably practicable after it electronically files
such material with, or furnishes it to, the SEC.
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 65 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,
combined with: (i) production from the Company's Canyon Express gas project
which began production in September 2002; (ii) the initial production from the
Company's Falcon gas discovery in the deepwater Gulf of Mexico and the Sable oil
discovery in South Africa expected during the second quarter of 2003; and (iii)
initial production from the Company's Devils Tower oil discovery in the
deepwater Gulf of Mexico expected during the first quarter of 2004, will
generate the operating cash flows that will provide Pioneer with continued
financial flexibility. These 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.
5
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
fluctuating oil, NGL and gas commodity prices and relatively stable supplier
costs during the three years ended December 31, 2002. During and just prior to
2000, the Organization of Petroleum Exporting Countries ("OPEC") 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. During 2002, world oil
prices increased in response to political unrest and supply disruptions in the
Middle East and Venezuela. During the third and fourth quarters of 2002, North
American gas prices improved as market fundamentals strengthened. The Company's
outlook for 2003 commodity prices is uncertain. Significant factors that will
impact 2003 commodity prices include the final resolution of issues currently
impacting Iraq and Venezuela; the extent to which members of OPEC and other oil
exporting nations are able to manage oil supply through export quotas; and
overall North American gas supply and demand fundamentals. To mitigate the
impact of volatile commodity prices on the Company's net asset value, Pioneer
periodically enters into commodity hedge contracts. See Note J of Notes to
Consolidated Financial Statements included in "Item 8. Financial Statements and
Supplementary Data" for information regarding the impact to oil and gas revenues
during 2002, 2001 and 2000 from the Company's hedging activities and the
Company's open hedge positions at December 31, 2002.
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/or
oil and gas production activities in Alaska, 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 2002,
the Company's average daily oil, NGL and gas production decreased primarily due
to normal production declines, reduced Argentine demand for gas, the Company's
curtailment of Argentine drilling activities during the first half of 2002 and
the December 2001 sale of the Company's Rycroft/Spirit River field in Canada.
During 2001 and 2000, 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 2002, 2001 and
2000 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, 2002, the Company
drilled 1,810 gross (1,279.7 net) wells, 88.5 percent of which were successfully
completed as productive wells, at a total drilling cost (net to the Company's
6
interest) of $1.6 billion. During 2002, the Company drilled 229 gross (153.2
net) wells. Drilling and facility costs (net to the Company's interest) totaled
$439.3 million during 2002, 79 percent of which was spent on development
activities including $221.6 million towards completing the Canyon Express,
Falcon and Devils Tower deepwater Gulf of Mexico projects and the Sable project
offshore South Africa. The Company's current 2003 capital expenditure budget is
expected to range from $450 million to $550 million. Excluding the 2002 Falcon
field and West Panhandle field acquisitions, the Company's 2003 capital
expenditure budget is comparable to 2002 costs incurred for oil and gas
producing activities. Development expenditures to complete the Falcon, Devils
Tower and Sable projects will decline to approximately $35 million during 2003,
while aggressive development drilling programs in the Company's core Spraberry
oil field, Hugoton and West Panhandle gas fields, the United States Gulf Coast,
Argentina and Canada will resume with approximately twice as many wells
anticipated in 2003 versus 2002. The Company has allocated the budgeted 2003
capital expenditures as follows: 65 percent to development drilling and facility
activities and 35 percent 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, 2002 include proved undeveloped
reserves and proved developed reserves that are behind pipe of 154.2 million
Bbls of oil and NGLs and 647.7 Bcf of gas. Development of those reserves will
require future capital expenditures. 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; the 1999 Aconcagua, 2000 Devils Tower, 2001
Falcon and 2003 Harrier discoveries in the deepwater Gulf of Mexico; the 2001
Olowi permit discovery located in the Southern Gabon basin; and the 2002 Borj El
Khadra permit discovery in the Ghadames basin onshore Southern Tunisia. The
Company currently anticipates that its 2003 exploration efforts will be
approximately 35 percent of total 2003 expenditures and will be concentrated
domestically in Alaska and the Gulf of Mexico, and internationally in Gabon,
South Africa and Tunisia. Exploratory drilling involves greater risks of dry
holes or 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 2002, 2001 and 2000, the Company's divestitures consisted of the
early termination of derivative hedge contracts and the sales of oil and gas
properties and other assets for net proceeds of $118.9 million, $113.5 million
and $102.7 million, respectively, which resulted in 2002, 2001 and 2000 net
divestiture gains of $4.4 million, $7.7 million and $34.2 million, respectively.
The Company's 2002 net proceeds from asset divestitures were primarily derived
from the early termination of interest rate and commodity hedges and the sale of
certain gas properties in Oklahoma. The Company's 2001 divestitures were
primarily derived from the 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 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-strategic United States oil and
gas properties located in Oklahoma, New Mexico and Louisiana. The net cash
proceeds from the 2002, 2001 and 2000 asset dispositions were primarily used to
fund additions to oil and gas properties or to reduce the Company's outstanding
indebtedness. See Note M 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 or other assets from time to time to increase capital resources
available for other activities, to achieve operating and administrative
efficiencies and to improve profitability.
7
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 2002, the Company
expended $195.5 million of acquisition capital to purchase additional interests
in, and other assets associated with, its Falcon field development project in
the deepwater Gulf of Mexico and its West Panhandle gas field and unproved
property interests in the Gulf of Mexico, the Alaskan North Slope, the Borj El
Khadra permit in Tunisia and other areas. The Company purchased, through two
transactions, an additional 30 percent working interest in the Falcon field
development and a 25 percent working interest in associated acreage in the
deepwater Gulf of Mexico for a combined purchase price of $61.1 million. As a
result of these transactions, the Company owns a 75 percent working interest and
operates the Falcon field development and related exploration blocks.
The Company also completed the purchase of the remaining 23 percent of the
rights that the Company did not already own in its core area West Panhandle gas
field, 100 percent of the West Panhandle reserves attributable to field fuel,
100 percent of the related West Panhandle field gathering system and ten blocks
surrounding the Company's deepwater Gulf of Mexico Falcon discovery. In
connection with these transactions, the Company recorded a $100.4 million
increase to proved oil and gas properties, a $3.8 million increase to unproved
oil and gas properties and $1.9 million of assets held for resale; retired a
capital cost obligation for $60.8 million; settled a $20.9 million gas balancing
receivable; assumed trade and environmental obligations amounting to $5.8
million in the aggregate; and paid $140.2 million of cash.
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 affiliated limited partnerships.
Additionally, $77.9 million was spent during 2001 to acquire additional working
interests in the deepwater Gulf of Mexico Aconcagua discovery, the related
Canyon Express gathering system and the Devils Tower project; 21 deepwater 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 deepwater 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 deepwater Gulf of
Mexico discovery and the related Canyon Express gathering system during 2000.
See Note D of Notes to Consolidated Financial Statements included in "Item
8. Financial Statements and Supplementary Data" for additional information
regarding the Company's acquisitions.
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.
Operations by Geographic Area
The Company operates in one industry segment. During 2002, 2001 and 2000,
the Company had oil and gas producing activities in the United States, Argentina
and Canada, and had exploration and/or development 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.
8
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 2002, the Company's primary purchasers of
oil were ExxonMobil Corporation ("ExxonMobil") and Plains Marketing LP
("Plains"), 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 of the Company's 2002
combined oil, NGL and gas revenues were attributable to sales to each of
ExxonMobil, Plains, Williams and Anadarko. 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 J 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 2002, 2001 and 2000 from the Company's
commodity hedging activities and the Company's open commodity hedge positions at
December 31, 2002.
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. Enterprises that sell securities in public
markets are subject to regulatory oversight by agencies such as the United
States Securities and Exchange Commission. This regulatory oversight imposes on
the Company the responsibility for establishing and maintaining disclosure
controls and procedures that will ensure that material information relating to
the Company and its consolidated subsidiaries is made known to the Company's
management and that the financial statements and other financial information
included in this Report do not contain any untrue statement of a material fact,
or omit to state a material fact, necessary to make the statements made in this
Report not misleading.
Oil and gas exploration and production operations are also subject to
various types of regulation by local, state, federal and foreign agencies.
Additionally, the Company's operations are 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 tax with respect to
9
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 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
10
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. A significant downward trend in commodity
prices 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.
Unproved properties. At December 31, 2002 and 2001, the Company carried
unproved property costs of $219.1 million and $187.8 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
11
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.
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, 2002, the
Company owns interests in 11 natural gas processing plants and five treating
facilities. The Company operates seven of the plants and all five 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 the high premium costs associated with
obtaining such insurance.
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.
Debt restrictions and availability. The Company is a borrower under fixed
term senior notes and a corporate credit facility. The terms of the Company's
borrowings under the senior notes and the corporate credit facility 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 E of Notes to Consolidated Financial Statements included in "Item 8.
12
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, 2002, approximately 20 percent
of the Company's proved reserves of oil, NGLs and gas were located outside the
United States (16 percent in Argentina, three 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
Estimates 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, 2002 was based on reserve reports audited by
Netherland, Sewell & Associates, Inc. for the Company's major properties in
Canada, South Africa and the United States, reserve reports audited by Gaffney,
Cline & Associates, Inc. for the Company's properties located in the Neuquen
Basin in Argentina, and reserve reports prepared by the Company's engineers for
all other properties. The reserve audits conducted by Netherland, Sewell &
Associates, Inc. and Gaffney, Cline & Associates, Inc., in aggregate,
represented 71 percent of the Company's estimated proved quantities of reserves
as of December 31, 2002. The information in this Report about the Company's oil,
NGL and gas reserves as of December 31, 2001 and 2000 was 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
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
13
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 2002, 2001 or 2000 to any federal authority or agency, other than the
SEC.
Proved Reserves
The Company's proved reserves totaled 736.7 million BOE at December 31,
2002, 671.4 million BOE at December 31, 2001 and 628.2 million BOE at December
31, 2000, representing $4.1 billion, $2.5 billion and $5.6 billion,
respectively, of Standardized Measure or $5.1 billion, $2.5 billion and $7.0
billion, respectively, on a pre-tax basis. The ten percent increase in reserve
volumes and 65 percent increase in Standardized Measure during 2002 were
attributable to an increase in commodity prices, the purchase of incremental
interests in two core assets and the Company's successful capital investments.
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.
On a BOE basis, 67 percent of the Company's total proved reserves at
December 31, 2002 were proved developed reserves. Based on reserve information
as of December 31, 2002, and using the Company's production information for
2002, the reserve-to-production ratio associated with the Company's proved
reserves was 18 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, 2002:
PROVED OIL AND GAS RESERVES AND AVERAGE DAILY PRODUCTION
2002 Average
Proved Reserves as of December 31, 2002 Daily Production (a)
-------------------------------------------------- --------------------------------
Oil Standardized Oil
& NGLs Gas Measure & NGLs Gas
(MBbls) (MMcf) MBOE (000) (Bbls) (Mcf) BOE
--------- --------- -------- ------------ -------- -------- --------
United States......... 337,631 1,483,971 584,960 $ 3,456,691 43,949 232,360 82,677
Argentina............. 31,532 532,081 120,211 340,106 8,680 78,220 21,716
Canada................ 2,361 119,328 22,249 199,012 1,070 48,365 9,131
South Africa.......... 8,475 - 8,475 121,363 - - -
Tunisia............... 845 - 845 9,380 - - -
--------- --------- -------- ---------- -------- -------- --------
Total................. 380,844 2,135,380 736,740 $ 4,126,552 53,699 358,945 113,524
========= ========= ======== ========== ======== ======== ========
- ----------------
(a) The 2002 average daily production was calculated using a 365-day year and
without making pro forma adjustments for any acquisitions, divestitures or
drilling activity that occurred during the year.
Finding Cost and Reserve Replacement
The Company's acquisition and finding costs per BOE for 2002, 2001 and
2000 were $6.30, $7.49 and $4.66 per BOE, respectively. The average acquisition
and finding cost for the three-year period from 2000 to 2002 was $6.24 per BOE,
representing a 32 percent increase over the 2001 three-year average rate of
$4.74 per BOE. This increase was largely attributable to the $221.6 million of
development capital that the Company spent during 2002 to develop its Canyon
Express, Falcon and Devils Tower development projects in the deepwater Gulf of
Mexico and its Sable development project offshore South Africa.
During 2002, the Company replaced 258 percent of its annual production on
a BOE basis (384 percent for oil and NGLs and 144 percent for gas). 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). The Company's 2002 reserve replacement
percentage was the result of revisions of previous estimates and revisions
related to changes in commodity prices, asset purchases and new discoveries and
field extensions. The Company's 2001 reserve replacement percentage was
14
primarily impacted by asset purchases and new discoveries and field extensions
while the 2000 reserve replacement percentage was primarily impacted by
revisions related to changes in commodity prices.
Description of Properties
As of December 31, 2002, the Company has production and/or development
and exploration operations in the United States, Argentina, Canada, South Africa
and Tunisia, and exploration opportunities in Gabon.
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. The Company also has unproved properties in Alaska. Approximately 82
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 2002, the Company
expended $533.6 million in domestic acquisition, exploration and development
drilling activities. The Company has budgeted approximately $300 million for
domestic acquisition, exploration and development drilling expenditures for
2003.
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, many
of which are reflected in the Company's proved undeveloped reserves, and the
ability to reduce operating expenses through economies of scale.
During 2002, the Company placed 89 Spraberry wells on production, drilled
one developmental dry hole and, at December 31, 2002, had two wells in progress.
The Company plans to drill approximately 150 development wells in the Spraberry
field during 2003.
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.
The Company's Hugoton operated wells are capable of producing
approximately 97 MMcf of wet gas per day (i.e., gas production at the wellhead
before processing and before reduction for royalties), although actual
production in the Hugoton field is limited by allowables set by state
regulators. The Company estimates that it and other major producers in the
Hugoton field produced at or near capacity in 2002. During 2002, the Company
completed four development wells in the Hugoton field and plans for 2003 include
approximately 30 wells to be drilled.
The Company is continuing to evaluate 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.
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,
15
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 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. In 2002, the Company
purchased the remaining rights it did not already own in the field as well as
the gathering system. The Company now controls the wells, production equipment,
gathering system and gas processing plant for the field.
During 2002, the Company placed 40 new wells on production, drilled three
developmental dry holes and had four wells in progress at December 31, 2002. The
Company plans to drill approximately 100 wells in the West Panhandle field
during 2003.
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 2002, the Company successfully drilled six development and four
exploratory wells in the deepwater Gulf of Mexico and one successful exploratory
well and one successful development well on the shelf. The Company also drilled
two exploratory dry holes in the deepwater Gulf of Mexico and one exploratory
dry hole on the shelf during 2002.
In the deepwater Gulf of Mexico, the Company has sanctioned three major
development projects, one of which is now on production and two that were in
progress at December 31, 2002:
o Canyon Express - The TotalFinaElf-operated Aconcagua and the
Marathon-operated Camden Hills discoveries in Mississippi Canyon were
jointly developed as part of the Canyon Express gas project. Production
start-up occurred in late September; however, several operational and
mechanical difficulties were encountered which has resulted in the Company
not reaching its estimated net production level of 110 to 120 MMcf of gas
per day until late January 2003.
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 and three development wells. 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 in progress, the eight producing wells on Devils Tower have
been drilled and are awaiting completion and production is anticipated to
begin during the first quarter of 2004. The wells will be brought on
sequentially with peak production expected to reach 12,000 to 15,000 BOEs
per day net to the Company's 25 percent working interest.
o Falcon - The Company-operated Falcon project is on pace to be on production
in April 2003. Two development wells were drilled and completed during 2002
and the final stages of the facilities fabrication and installation are
currently underway. Peak production from Falcon is anticipated at rates of
approximately 130 MMcf of gas per day net to the Company's 75 percent
working interest.
During 2002, the Company also participated in two appraisal sidetrack
wells on the Marathon-operated deepwater Gulf of Mexico Ozona Deep prospect, of
which one was a discovery. The 2002 discovery sidetrack appraisal well further
extended the 2001 Ozona Deep discovery that originally encountered approximately
345 feet of net oil pay in two intervals. The Company is currently evaluating
possible tie-back opportunities to existing facilities in the area, the
economics of which will determine future activities. The Company also
successfully drilled its Dominion-operated Triton prospect near Devils Tower.
Proved reserves were recorded for this prospect and it will be completed as a
subsea tieback to Devils Tower. Exploration drilling near the Falcon discovery
began in December 2002 with the Lightning prospect and in January 2003 on the
H2.5 and Harrier prospects. The Lightning and H2.5 exploratory wells were
unsuccessful; however, the Harrier prospect was announced as a discovery in late
January 2003. It is anticipated that the Harrier well will be completed with a
subsea tieback to Falcon within nine to 15 months. During 2003, the Company also
plans to drill its Buff prospect, which is also near the Falcon discovery.
16
During January 2003, the Company announced a joint exploration agreement
with Woodside Energy (USA) Inc. ("Woodside"), a subsidiary of Woodside Energy
Ltd. of Australia, for a two-year drilling program over the shallow- water Texas
shelf region of the Gulf of Mexico. Under the agreement, Woodside has taken a 50
percent working interest in 47 offshore exploration blocks operated by the
Company. The agreement covers eight prospects and 19 leads and includes five
exploratory wells to be drilled in 2003 and three in 2004. Most of the wells to
be drilled under the agreement will target gas plays below 15,000 feet. The
eight wells to be drilled by the parties in 2003 and 2004 are on prospects
generated and leased by the Company since 1997. Additionally, the Company and
Woodside will evaluate for potential inclusion in the drilling program shallower
gas prospects on the Gulf of Mexico shelf on other blocks covered by the leases.
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 six development wells at Pawnee during 2002, had one well in
progress at year end and plans to drill seven wells in 2003.
Alaska area. During the fourth quarter of 2002, the Company signed an
agreement with Armstrong Resources LLC under which the Company was assigned a 70
percent working interest and operatorship in ten state leases on Alaska's North
Slope. The leases cover approximately 14,000 undeveloped acres between the
Kuparuk River unit and Thetis Island. The Company plans to drill up to three
exploratory wells during the first quarter of 2003. The wells will test an area
that the Company believes is prospective for oil in the same sands as the
offsetting Kuparuk River unit eight to ten miles to the southeast. The Kuparuk
River unit was discovered in 1969 and is estimated to hold 2.5 billion barrels
of recoverable oil. No wells have been drilled on the acreage covered by the
Company's leases to date, but wells drilled just outside the perimeter of the
acreage have encountered the primary target Kuparuk "C" sands and were
oil-bearing. The acreage is offshore in approximately five to ten feet of water.
Drilling plans call for grounded sea ice pad locations that will be accessed via
ice roads from Oliktok Point dock. All sea ice operations are expected to be
completed by the end of March 2003.
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 other significant
development projects, the Sable oil field located in shallow water offshore
South Africa and the Adam discovery in southern Tunisia, are scheduled for first
production in mid-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,
2002, approximately 16 percent, three percent, one percent and one tenth of one
percent of the Company's proved reserves are located in Argentina, Canada, South
Africa and Tunisia, respectively.
Argentina. The Company's share of Argentine production during 2002
averaged 21.7 MBOE per day, or approximately 19 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 to the east of the Andes Mountains. Oil and gas are produced
primarily from the Al Norte de la Dorsal, the Al Sur de la Dorsal, the Dadin,
the Loma Negra, the Anticlinal Campamento and the Estacion Fernandez Oro blocks,
in each of which the Company has a 100 percent working interest. Most of the gas
produced from these blocks is processed in the Company's recently completed Loma
Negra gas processing plant. The Company also operates and has a 50 percent
working interest in the Lago Fuego field which is located in Tierra del Fuego,
an island in the extreme southern portion of Argentina, approximately 1,500
miles south of Buenos Aires.
Most of the Company's non-operated production in Argentina is located in
Tierra del Fuego where oil, gas and NGLs are produced from six separate fields
in which the Company has a 35 percent working interest. The Company also has a
14.4 percent working interest in the Confluencia field which is located in the
Neuquen Basin.
During 2002, the Company expended $35.1 million on Argentine development
and exploration activities. The Company drilled 14 development wells and 17
extension/exploratory wells, of which 13 development wells and nine
extension/exploratory wells were successful. Also during 2002, the Company
completed its gas processing plant at Loma Negra and completed a 35 mile gas
pipeline that connects the Loma Negra plant to a main gas transmission line that
accesses the Buenos Aires gas market. The Company plans to spend approximately
$45 million on oil and gas development and exploration opportunities in
Argentina during 2003.
17
Canada. The Company's Canadian producing properties are located primarily
in Alberta and British Columbia, Canada. Production during 2002 averaged 9.1
MBOE per day, or approximately eight 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.
During 2002, the Company expended $33.5 million on Canadian development,
exploration and acquisition activities. The Company drilled 17 development wells
and 12 exploratory wells, primarily in the Chinchaga and Martin Creek areas, of
which 13 development wells and 9 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 plans to spend
approximately $45 million on oil and gas development and exploration
opportunities in Canada during 2003.
Africa. In Africa, the Company has entered into agreements to explore for
oil and gas in South Africa, Gabon and Tunisia. The amended South African
agreements cover over five million acres along the southern coast of South
Africa, generally in water depths less than 650 feet. The Gabon agreement covers
313,937 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 2.9 million acres onshore southern Tunisia which
the Company operates with a 50 percent working interest and the second includes
the Anadarko-operated Anaguid permit covering 1.2 million acres onshore southern
Tunisia in which the Company has a 38.7 percent working interest and the
AGIP-operated Borj El Khadra permit covering 1.2 million acres onshore southern
Tunisia in which the Company has a 40 percent working interest. During 2002, the
Company expended $70.3 million of acquisition, development and exploration
drilling and seismic capital in South Africa, Gabon and Tunisia.
South Africa. In South Africa, the Company spent $37.1 million of
drilling and seismic capital to drill four successful development wells on its
Petro SA-operated Sable development project. During 2003, the Company plans to
complete its Sable development project with production anticipated to begin
during the second quarter of 2003. Production for the first year is expected to
average approximately 12,100 Bbls of oil per day net to the Company's 40 percent
working interest. In addition, the Company currently plans to drill three
exploration wells in South Africa during 2003.
Gabon. In Gabon, the Company spent $23.6 million of drilling and
seismic capital to drill and test three additional exploratory wells 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. To date, the Company has drilled and tested four successful offshore
wells which have established significant oil in place. Full development of the
field is expected to involve substantial capital investment underscoring the
importance of confirming reservoir characteristics and productivity. Pioneer is
currently seeking bids for the development of an early production system
covering a limited field area which would allow the Company to gain additional
information needed to design a full field development plan. The Company is also
seeking improved fiscal terms from the government.
Tunisia. In Tunisia, the Company spent $8.2 million of acquisition,
drilling and seismic capital primarily to acquire a 40 percent interest in and
drill an exploration well on the AGIP-operated Borj El Khadra permit. This well
encountered several oil and gas productive zones that tested up to 6,000 Bbls of
oil per day. The Company plans to complete the construction of a 15 kilometer
flowline from the discovery to an AGIP-operated facility during the third
quarter of 2003, allowing production to begin from the initial well shortly
thereafter. A development well is scheduled to be drilled in the fourth quarter
of 2003. In addition to this development project, plans for Tunisia in 2003
include an exploration well to be drilled on the Company-operated Jorf permit,
two exploration wells to be drilled on the Anadarko-operated Anaguid permit and
an additional exploration well to be drilled on the AGIP-operated Borj El Khadra
permit.
18
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, 2002, 2001 and 2000.
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 being
indicative of future results.
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, 2002, 2001 and 2000:
PRODUCTION, PRICE AND COST DATA (a)
Year Ended December 31,
--------------------------------------------------------------------------------------------------------------
2002 2001 2000
----------------------------------- ---------------------------------- ----------------------------------
United United United
States Argentina Canada Total States Argentina Canada Total States Argentina Canada Total
------ --------- ------ ------- ------ --------- ------ ------- ------- --------- ------ -------
Production information:
Annual production:
Oil (MBbls).... 8,555 2,914 45 11,514 8,629 3,566 303 12,498 8,989 3,238 308 12,535
NGLs (MBbls)... 7,487 254 345 8,086 7,232 200 368 7,800 7,883 193 303 8,379
Gas (MMcf)..... 84,811 28,551 17,653 131,015 77,609 31,830 18,426 127,865 83,930 35,695 16,219 135,844
Total (MBOE)... 30,177 7,926 3,333 41,436 28,796 9,071 3,742 41,609 30,861 9,380 3,314 43,555
Average daily production:
Oil (Bbls)..... 23,437 7,984 124 31,545 23,641 9,769 831 34,241 24,561 8,847 841 34,249
NGLs (Bbls).... 20,512 696 946 22,154 19,815 547 1,008 21,370 21,538 527 829 22,894
Gas (Mcf)...... 232,360 78,220 48,365 358,945 212,629 87,204 50,481 350,314 229,316 97,526 44,315 371,157
Total (BOE).... 82,677 21,716 9,131 113,524 78,894 24,851 10,253 113,997 84,318 25,628 9,056 119,002
Average prices, including hedge results:
Oil (per Bbl).. $ 23.66 $ 20.63 $22.26 $ 22.89 $ 24.34 $23.79 $ 21.87 $ 24.12 $ 22.07 $29.09 $27.50 $ 24.01
NGLs (per Bbl). $ 13.77 $ 14.56 $16.77 $ 13.92 $ 16.88 $19.29 $ 21.11 $ 17.14 $ 20.05 $22.91 $24.32 $ 20.27
Gas (per Mcf).. $ 3.16 $ .48 $ 2.50 $ 2.49 $ 4.10 $ 1.31 $ 2.86 $ 3.23 $ 3.50 $ 1.19 $ 2.88 $ 2.81
Revenue (per BOE)$ 19.00 $ 9.79 $15.27 $ 16.94 $ 22.56 $14.36 $ 17.94 $ 20.36 $ 21.04 $15.03 $18.85 $ 19.58
Average prices, excluding hedge results:
Oil (per Bbl).. $ 23.85 $ 20.33 $22.26 $ 22.95 $ 24.56 $22.40 $ 21.87 $ 23.88 $ 28.76 $29.09 $27.50 $ 28.81
NGLs (per Bbl). $ 13.77 $ 14.56 $16.77 $ 13.92 $ 16.88 $19.29 $ 21.11 $ 17.14 $ 20.05 $22.91 $24.32 $ 20.27
Gas (per Mcf).. $ 3.02 $ .48 $ 2.40 $ 2.38 $ 3.96 $ 1.31 $ 3.27 $ 3.20 $ 3.73 $ 1.19 $ 3.45 $ 3.03
Revenue (per BOE)$ 18.65 $ 9.68 $14.77 $ 16.63 $ 22.26 $13.81 $ 19.95 $ 20.21 $ 23.63 $15.03 $21.65 $ 21.63
Average costs:
Production costs (per BOE):
Lease operating $ 3.21 $ 1.61 $ 2.64 $ 2.87 $ 2.76 $ 2.64 $ 3.01 $ 2.76 $ 2.45 $ 2.30 $ 2.53 $ 2.42
Taxes:
Production... .71 .13 - .54 .98 .28 - .74 .99 .30 - .77
Ad valorem... .75 - - .54 .71 - - .49 .41 - - .29
Field fuel..... .85 - - .62 1.27 - - .88 1.01 - - .71
Workover....... .28 .01 .59 .25 .20 .01 .32 .17 .17 - .42 .15
------ ------ ----- ------ ------ ----- ------ ------ ------ ----- ----- ------
Total....... $ 5.80 $ 1.75 $ 3.23 $ 4.82 $ 5.92 $ 2.93 $ 3.33 $ 5.04 $ 5.03 $ 2.60 $ 2.95 $ 4.34
Depletion expense
(per BOE)..... $ 4.64 $ 5.00 $ 8.36 $ 5.01 $ 4.46 $ 5.67 $ 7.71 $ 5.02 $ 3.95 $ 5.56 $ 7.58 $ 4.57
- ---------------
(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.
19
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,
2002, 2001 and 2000:
PRODUCTIVE WELLS (a)
Gross Productive Wells Net Productive Wells
-------------------------- -------------------------
Oil Gas Total Oil Gas Total
------ ------ ------ ------ ------ -------
As of December 31, 2002:
United States................ 3,448 1,952 5,400 2,745 1,855 4,600
Argentina.................... 694 208 902 534 142 676
Canada....................... 1 246 247 1 197 198
South Africa................. 4 - 4 2 - 2
Tunisia...................... 1 - 1 - - -
------ ------ ------ ------ ------ ------
Total..................... 4,148 2,406 6,554 3,282 2,194 5,476
====== ====== ====== ====== ====== ======
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
====== ====== ====== ====== ====== ======
- ---------------
(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, 2002, the Company owned interests in 111 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, 2002:
LEASEHOLD ACREAGE
Developed Acreage Undeveloped Acreage
------------------------ ------------------------ Royalty
Gross Acres Net Acres Gross Acres Net Acres Acreage
----------- ---------- ----------- ---------- ---------
As of December 31, 2002:
United States:
Onshore................... 996,896 871,234 198,729 156,815 229,686
Offshore.................. 125,786 53,120 604,287 506,712 10,500
---------- ---------- ----------- ---------- --------
1,122,682 924,354 803,016 663,527 240,186
Argentina.................... 710,000 299,000 1,002,000 925,000 -
Canada....................... 152,000 116,000 356,000 276,000 12,000
South Africa................. 9,600 3,840 5,368,400 4,009,160 -
Gabon........................ - - 313,937 313,937 -
Tunisia...................... - - 5,308,498 2,402,667 -
---------- ---------- ----------- ---------- --------
Total..................... 1,994,282 1,343,194 13,151,851 8,590,291 252,186
========== ========== =========== ========== ========
20
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, 2002, 2001 and 2000. This
information should not be considered indicative of future performance, nor
should it be assumed that there was 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 holes.
DRILLING ACTIVITIES
Gross Wells Net Wells
-------------------------- --------------------------
Year Ended December 31, Year Ended December 31,
-------------------------- --------------------------
2002 2001 2000 2002 2001 2000
------ ------ ------ ------ ------ ------
United States:
Productive wells:
Development................. 148 228 159 83.0 114.6 91.3
Exploratory................. 6 20 11 2.0 11.0 4.7
Dry holes:
Development................. 4 15 3 3.7 14.6 1.9
Exploratory................. 3 8 3 2.1 5.1 1.6
----- ----- ----- ----- ------ ------
161 271 176 90.8 145.3 99.5
----- ----- ----- ----- ------ ------
Argentina:
Productive wells:
Development................. 13 19 28 13.0 17.7 26.7
Exploratory................. 9 26 38 9.0 25.5 37.6
Dry holes:
Development................. 1 1 2 1.0 1.0 2.0
Exploratory................. 8 16 16 8.0 14.0 14.5
----- ----- ----- ----- ------ ------
31 62 84 31.0 58.2 80.8
----- ----- ----- ----- ------ ------
Canada:
Productive wells:
Development................. 13 24 17 10.4 20.3 17.9
Exploratory................. 9 12 12 9.0 10.2 9.9
Dry holes:
Development................. 4 2 4 4.0 2.0 2.5
Exploratory................. 3 13 2 3.0 11.8 1.9
----- ----- ----- ----- ------ ------
29 51 35 26.4 44.3 32.2
----- ----- ----- ----- ------ ------
Africa:
Productive wells:
Development................. 4 - - 1.6 - -
Exploratory................. 4 3 - 3.4 2.4 -
Dry holes:
Development................. - - - - - -
Exploratory................. - 3 1 - 1.9 1.0
----- ----- ----- ----- ------ ------
8 6 1 5.0 4.3 1.0
----- ----- ----- ----- ------ ------
Total....................... 229 390 296 153.2 252.1 213.5
===== ===== ===== ===== ====== ======
Success ratio (a)............... 90% 85% 90% 86% 80% 88%
- ---------------
(a) Represents the ratio of those wells that were successfully completed as
producing wells or wells capable of producing to total wells drilled and
evaluated.
21
The following table sets forth information about the Company's wells upon
which drilling was in progress on December 31, 2002:
Gross Wells Net Wells
----------- ---------
United States:
Development......................................... 7 6.5
Exploratory......................................... - -
----- ------
7 6.5
----- ------
Argentina:
Development......................................... 3 3.0
Exploratory......................................... 6 6.0
----- ------
9 9.0
----- ------
Canada:
Development......................................... 4 4.0
Exploratory......................................... 4 4.0
----- ------
8 8.0
----- ------
Total............................................ 24 23.5
===== ======
ITEM 3. LEGAL PROCEEDINGS
The Company is party to various legal proceedings, which are described
under "Legal actions" in Note I 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 2002.
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 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 2002 or 2001. The Company's
board of directors has no current plans to declare dividends during the
foreseeable future.
High Low
-------- --------
Year ended December 31, 2002:
Fourth quarter....................................... $ 27.50 $ 21.70
Third quarter........................................ $ 26.23 $ 19.50
Second quarter....................................... $ 26.05 $ 20.00
First quarter........................................ $ 22.30 $ 16.10
Year ended December 31, 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
On February 14, 2003, the last reported sales price of the Company's
common stock, as reported in the New York Stock Exchange composite transactions,
was $24.25 per share.
As of February 14, 2003, the Company's common stock was held by
approximately 30,951 holders of record.
22
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,
----------------------------------------------------
2002 2001 2000 1999 1998
-------- -------- -------- -------- --------
(in millions, except per share data)
Statement of Operations Data:
Revenues and other income:
Oil and gas................................ $ 701.8 $ 847.0 $ 852.7 $ 644.6 $ 711.5
Interest and other (a)..................... 11.2 21.8 25.8 89.7 10.4
Gain (loss) on disposition of assets, net.. 4.4 7.7 34.2 (24.2) (.4)
------- ------ ------- ------- -------
717.4 876.5 912.7 710.1 721.5
------- ------ ------- ------- -------
Costs and expenses:
Oil and gas production..................... 199.6 209.7 189.3 159.5 223.5
Depletion, depreciation and amortization... 216.4 222.6 214.9 236.1 337.3
Impairment of properties and facilities.... - - - 17.9 459.5
Exploration and abandonments............... 85.9 127.9 87.5 66.0 121.9
General and administrative................. 48.4 37.0 33.3 40.2 82.6
Reorganization............................. - - - 8.5 33.2
Interest................................... 95.8 131.9 162.0 170.3 164.3
Other (b).................................. 17.2 39.6 67.2 34.7 30.0
------- ------ ------- ------- -------
663.3 768.7 754.2 733.2 1,452.3
------- ------ ------- ------- -------
Income (loss) before income taxes and
extraordinary items........................ 54.1 107.8 158.5 (23.1) (730.8)
Income tax benefit (provision)............... (5.1) (4.0) 6.0 .6 (15.6)
------- ------ ------- ------- -------
Income (loss) before extraordinary items..... 49.0 103.8 164.5 (22.5) (746.4)
Extraordinary items (c)...................... (22.3) (3.8) (12.3) - -
------- ------ ------- ------- -------
Net income (loss)............................ $ 26.7 $ 100.0 $ 152.2 $ (22.5) $ (746.4)
======= ======= ======= ======= =======
Income (loss) before extraordinary items
per share:
Basic...................................... $ .44 $ 1.05 $ 1.65 $ (.22) $ (7.46)
======= ======= ======= ======= =======
Diluted.................................... $ .43 $ 1.04 $ 1.65 $ (.22) $ (7.46)
======= ======= ======= ======= =======
Net income (loss) per share:
Basic...................................... $ .24 $ 1.01 $ 1.53 $ (.22) $ (7.46)
======= ======= ======= ======= =======
Diluted.................................... $ .23 $ 1.00 $ 1.53 $ (.22) $ (7.46)
======= ======= ======= ======= =======
Dividends per share ......................... $ - $ - $ - $ - $ .10
======= ======= ======= ======= =======
Weighted average shares outstanding:
Basic...................................... 112.5 98.5 99.4 100.3 100.1
======= ======= ======= ======= =======
Diluted.................................... 114.3 99.7 99.8 100.3 100.1
======= ======= ======= ======= =======
Statement of Cash Flows Data:
Cash flows from operating activities......... $ 332.2 $ 475.6 $ 430.1 $ 255.2 $ 314.1
Cash flows from investing activities......... $ (508.1) $ (422.7) $ (194.5) $ 199.0 $ (517.0)
Cash flows from financing activities......... $ 170.9 $ (64.0) $ (244.1) $ (479.1) $ 190.9
Balance Sheet Data (as of December 31):
Working capital (deficit).................... $ (127.5) $ 27.4 $ (25.1) $ (13.7) $ (324.8)
Property, plant and equipment, net........... $3,168.4 $2,784.3 $2,515.0 $2,503.0 $3,034.1
Total assets................................. $3,455.1 $3,271.1 $2,954.4 $2,929.5 $3,481.3
Long-term obligations........................ $1,796.9 $1,743.7 $1,804.5 $1,914.5 $2,101.2
Total stockholders' equity................... $1,374.9 $1,285.4 $ 904.9 $ 774.6 $ 789.1
- ---------------
(a) 1999 includes $41.8 million of option fees and liquidated damages and $30.2
million of income associated with an excise tax refund.
(b) Other expense for 2002 includes $6.9 million and $2.6 million for the
remeasurement of Argentine peso-denominated net monetary assets and
Canadian gas marketing losses, respectively. 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
noncash 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.
(c) The Company's extraordinary items represent losses from the early
extinguishment of debt. See Notes B and E of Notes to Consolidated
Financial Statements included in "Item 8. Financial Statements and
Supplementary Data" for information regarding the Company's extraordinary
items.
23
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
2002 Financial and Operating Performance
The year ended December 31, 2002 was highlighted by favorable commodity
prices and continued strengthening of North American gas fundamentals; the
issuance of 11.5 million shares of common stock to fund strategic acquisitions
in the Company's core areas of the West Panhandle gas field and the Gulf of
Mexico Falcon field development project; initial production from the Canyon
Express gas project; continued development of the deepwater Gulf of Mexico
Devils Tower and Falcon fields and the Sable oil field offshore South Africa;
indications that the Argentine economy and currency may be stabilizing;
continued evaluation of the Gabon discovery; an oil discovery in Tunisia; the
acquisition of undeveloped property interests in Alaska; the completion of a
public offering of $150 million of 7-1/2 percent senior notes that will mature
in 2012; and repurchases of $61.0 million of higher yielding funded debt to
reduce the Company's future costs of capital.
During the years ended December 31, 2002, 2001 and 2000, the Company
recorded net income of $26.7 million, $100.0 million and $152.2 million ($.23,
$1.00 and $1.53 per diluted share), respectively. Compared to 2001, the
Company's 2002 total revenues and other income decreased by $159.0 million, or
18 percent, including a $145.2 million decrease in oil and gas revenues. The
decrease in oil and gas revenues was due to decreases of five percent, 19
percent and 23 percent in average oil, NGL and gas prices, respectively,
including the effects of commodity price hedges.
Compared to 2001, the Company's 2002 total costs and expenses decreased
by $105.4 million, or 14 percent. The decrease in total costs and expenses was
primarily reflective of a $42.0 million decrease in exploration and abandonments
expense, primarily due to the allocation of a larger percentage of the Company's
2002 capital budget to the development of the Company's Canyon Express, Falcon,
Devils Tower and Sable projects; a $36.1 million decrease in interest expense,
primarily due to declining underlying market interest rates, interest savings
associated with the replacement of higher yielding senior notes and capital cost
obligations with lower yielding senior notes and corporate credit facility
indebtedness, interest rate hedge gains and increased interest capitalized on
significant capital projects; and a $22.3 million decrease in other expense,
primarily due to declines in derivative mark-to-market provisions, gas marketing
losses and bad debt expense.
During the year ended December 31, 2002, the Company's net cash provided
by operating activities decreased to $332.2 million, as compared to $475.6
million during 2001 and $430.1 million during 2000. The decrease in net cash
provided by operating activities during 2002 was primarily due to declines in
oil, NGL and gas prices as discussed above.
During 2002, successful capital investment activities increased the
Company's proved reserves to 736.7 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 258 percent of
production at an acquisition and finding cost per BOE of $6.30. During the three
years ended December 31, 2002, Pioneer has replaced 210 percent of production at
an acquisition and finding cost per BOE of $6.24. Costs incurred for the year
ended December 31, 2002 totaled $672.5 million, including $195.5 million of
proved and unproved property acquisitions and $477.0 million of exploration and
development drilling and seismic expenditures.
During the year ended December 31, 2002, the Company purchased, through
two transactions, an additional 30 percent working interest in the Falcon field
development and a 25 percent working interest in associated acreage in the
deepwater Gulf of Mexico for a combined purchase price of $61.1 million. As a
result of these transactions, the Company owns a 75 percent working interest in
and operates the Falcon field development and related exploration blocks. Also
during 2002, the Company completed the purchase of the remaining 23 percent of
the rights that the Company did not already own in its core area West Panhandle
gas field, 100 percent of the West Panhandle reserves attributable to field
fuel, 100 percent of the related West Panhandle field gathering system and ten
blocks surrounding the Company's deepwater Gulf of Mexico Falcon discovery. In
connection with these transactions, the Company recorded $100.4 million to
proved oil and gas properties, $3.8 million to unproved oil and gas properties
and $1.9 million to assets held for resale; retired a capital cost obligation
for $60.8 million; settled a $20.9 million gas balancing receivable; assumed
trade and environmental obligations amounting to $5.8 million in the aggregate;
and paid $140.2 million of cash.
24
See "Results of Operations" and "Capital Commitments, Capital Resources
and Liquidity", 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.
2003 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. World oil prices increased during 2002 in response to
political unrest and supply disruptions in the Middle East and Venezuela. During
the third and fourth quarters of 2002, North American gas prices improved as
market fundamentals strengthened. The Company's outlook for 2003 commodity
prices is uncertain. Significant factors that will impact 2003 commodity prices
include the final resolution of issues currently impacting Iraq and Venezuela,
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 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, 2002, the Company had hedged 22,236 barrels per day
("Bblpd") of 2003 oil production under swap contracts with a weighted average
fixed price to be received of $24.45 per Bbl. The Company had also hedged
230,000 Mcf per day of 2003 gas production under swap contracts with a weighted
average fixed price to be received of $3.76 per MMBtu. During January 2003, the
Company increased its 2003 commodity hedge positions by entering into 6,000
Bblpd of March oil swap contracts with average per Bbl fixed prices of $33.51.
Additionally, at December 31, 2002 the Company has deferred oil hedge losses of
$.5 million that will be recognized as reductions to oil revenue during the last
eight months of 2003 and $72.5 million of gas hedge gains that will be
recognized as increases to gas revenue during 2003. See Note J 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, 2002. Also see "Item 7A. Quantitative and
Qualitative Disclosures About Market Risk" for disclosures about the Company's
commodity related derivative financial instruments.
First quarter 2003. Based on current estimates, the Company expects that
its first quarter worldwide production will average 120 to 128 MBOE per day.
Included in the mid-point of the estimate is 95 MMcf per day, net to the Company
from Canyon Express. First quarter production costs are expected to average
$5.10 to $5.40 per BOE based on recent NYMEX strip prices for oil and gas.
Depreciation, depletion and amortization expense is expected to average $5.75 to
$6.00 per BOE, and total exploration and abandonment expense is expected to be
$20 million to $50 million. General and administrative expense is expected to be
$16 million to $17 million during the first quarter of 2003, $2 million to $3
million of which relates to estimated additional performance-based compensation
costs. Interest expense is expected to be $24 million to $26 million. Interest
capitalized during the first quarter of 2003 will be significantly less than
interest capitalized during the first three quarters of 2002 as the Company's
largest capital project for which interest was being capitalized, the Canyon
Express development project, was put into production during September 2002.
Additionally, during February 2003, the Company entered into interest rate swap
contracts to hedge a portion of the fair value of its 9-5/8 percent senior
notes. Under the terms of the interest rate swap contracts, the Company will
receive a fixed annual rate of 9-5/8 percent on $250 million notional amount and
will pay the counterparties a variable rate on the notional amount equal to the
six-month LIBOR, reset semi-annually, plus a weighted average margin of 566.4
basis points. Income taxes, principally in Argentina, are expected to be
approximately $2 million as the Company benefits from the carryforward of net
operating losses in the United States and Canada.
Production growth. The Company expects that its annual 2003 worldwide
production will be approximately 165 MBOE per day, an increase of 45 percent
over 2002 levels. The growth in production during 2003 includes initial
production during the second quarter from the Company's deepwater Gulf of Mexico
Falcon gas project and the Sable oil project in South Africa, coupled with peak
rates of production from Canyon Express and increases in production from the
Company's core properties in the United States, Argentina and Canada due to an
aggressive development drilling program with approximately twice as many wells
anticipated in 2003 versus 2002.
Capital expenditures. During 2003, the Company's budget for oil and gas
producing activities is expected to range from $450 million to $550 million, of
which approximately 35 percent has been budgeted for exploration expenditures
and 65 percent has been budgeted for development drilling and facility costs.
The Company's 2003 capital budget is allocated approximately 60 percent to the
25
United States, nine percent to Argentina and Canada and 22 percent to Africa.
The Company's 2003 capital budget includes $35 million of remaining development
capital to complete the Falcon and Devils Tower development projects in the
deepwater Gulf of Mexico and the Sable oil project offshore South Africa.
Aggressive development drilling programs in the Company's core Spraberry oil
field, Hugoton and West Panhandle gas fields, the United States Gulf Coast,
Argentina and Canada will resume with approximately twice as many wells
anticipated in 2003 versus 2002. During 2003, the Company has planned
exploration drilling in the Gulf of Mexico, the onshore Gulf Coast area, Alaska,
Canada, Gabon, Tunisia and South Africa. During the years ended December 31,
2004 and 2005, the Company expects to expend approximately $172 million and $151
million, respectively, of capital for development drilling and facility costs
related to its proved undeveloped reserves.
Critical Accounting Estimates
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 estimates, 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
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 earnings 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
earnings of future periods as a component of depletion expense. During 2002,
2001 and 2000, the Company recognized exploration, abandonment, geological and
geophysical expense of $85.9 million, $127.9 million and $87.6 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 as of
December 31, 2002 was based on evaluations audited by independent petroleum
engineers with respect to the Company's major properties and prepared by the
Company's engineers with respect to all other properties. The Company's proved
reserve information included in this Report as of December 31, 2001 and 2000 was
based on evaluations prepared by the Company's engineers. Estimates prepared by
other third parties may be higher or lower than those included herein.
Because these estimates depend on many assumptions, all of which may
substantially differ from future actual results, reserve estimates will 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
26
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 will increase, reducing future 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 sheets as of December 31, 2002
and 2001 reflect 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; (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. Many assumptions are utilized in the assessments that may prove to be
materially incorrect in the future.
New Accounting Pronouncements
During June 2001, the Financial Accounting Standards Board ("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 incurred if a reasonable estimate of fair value can be made. Under
the provisions of SFAS 143, asset retirement obligations 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 that were assumed in
business combinations, which were recorded at their estimated fair values. The
Company adopted the provisions of SFAS 143 on January 1, 2003.
The adoption of SFAS 143 resulted in a January 1, 2003 cumulative effect
adjustment to record (i) a $13.8 million increase in the carrying values of
27
proved properties, (ii) a $26.3 million decrease in accumulated depreciation,
depletion, and amortization of property, plant and equipment, (iii) a $1.0
million increase in current abandonment liabilities and (iv) a $22.4 million
increase in noncurrent abandonment liabilities. The net impact of items (i)
through (iv) was to record a gain of $16.7 million, net of tax, as a cumulative
effect adjustment of a change in accounting principle in the Company's
consolidated statements of operations upon adoption on January 1, 2003.
During April 2002, the FASB issued Statement of Financial Accounting
Standards No. 145, "Rescission of FASB Statements No. 4, 44 and 64, Amendment of
FASB Statement No. 13 and Technical Corrections" ("SFAS 145"). Prior to the
adoption of the provisions of SFAS 145, gains or losses on the early
extinguishment of debt were required to be classified in a company's periodic
consolidated statements of operations as extraordinary gains or losses, net of
associated income taxes, after the determination of income or loss from
continuing operations. SFAS 145 requires, except in the case of events or
transactions of a highly unusual and infrequent nature, gains or losses from the
early extinguishment of debt to be classified as components of a company's
income or loss from continuing operations. The Company adopted the provisions of
SFAS 145 on January 1, 2003. The adoption of the provisions of SFAS 145 is not
expected to affect the Company's future financial position or liquidity. Upon
adoption of the provisions of SFAS 145, gains or losses from the early
extinguishment of debt recognized in the Company's consolidated statements of
operations for the years ended December 31, 2002, 2001 and 2000 will be
reclassified to other revenues or other expense and included in the
determination of the income (loss) from continuing operations of those periods.
Results of Operations
Oil and gas revenues. Revenues from oil and gas operations totaled $701.8
million during 2002, as compared to $847.0 million during 2001 and $852.7
million during 2000, representing a 17 percent decrease from 2001 to 2002. The
revenue decrease from 2001 to 2002 was due to year-on-year worldwide average
gas, NGL and oil price declines of 23 percent, 19 percent and five percent,
respectively, including the effects of gas and oil price hedges; and an eight
percent decline in worldwide oil production, offset by worldwide NGL and gas
production increases of four percent and two percent, respectively. The revenue
decrease from 2000 to 2001 was due to a four percent decline in BOE production
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 declines in 2001 sales
volumes were primarily attributable to normal well production declines.
28
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,
------------------------------
2002 2001 2000
-------- -------- --------
Production:
Oil (MBbls)................................... 11,514 12,498 12,535
NGLs (MBbls).................................. 8,086 7,800 8,379
Gas (MMcf).................................... 131,015 127,865 135,843
Total (MBOE).................................. 41,436 41,609 43,555
Average daily production:
Oil (Bbls).................................... 31,545 34,241 34,249
NGLs (Bbls)................................... 22,154 21,370 22,894
Gas (Mcf)..................................... 358,945 350,314 371,157
Total (BOE)................................... 113,524 113,997 119,002
Average reported prices:
Oil (per Bbl)
United States............................... $ 23.66 $ 24.34 $ 22.07
Argentina................................... $ 20.63 $ 23.79 $ 29.09
Canada...................................... $ 22.26 $ 21.87 $ 27.50
Worldwide................................... $ 22.89 $ 24.12 $ 24.01
NGL (per Bbl)
United States............................... $ 13.77 $ 16.88 $ 20.05
Argentina................................... $ 14.56 $ 19.29 $ 22.91
Canada...................................... $ 16.77 $ 21.11 $ 24.32
Worldwide................................... $ 13.92 $ 17.14 $ 20.27
Gas (per Mcf)
United States............................... $ 3.16 $ 4.10 $ 3.50
Argentina................................... $ .48 $ 1.31 $ 1.19
Canada...................................... $ 2.50 $ 2.86 $ 2.88
Worldwide................................... $ 2.49 $ 3.23 $ 2.81
Annual percentage increase (decrease) in
average worldwide reported prices:
Oil......................................... (5) - 56
NGL......................................... (19) (15) 74
Gas......................................... (23) 15 48
Hedging activities. The commodity 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
commodity price risk associated with certain capital projects. The effective
portions of changes in the fair values of the Company's commodity price hedge
derivatives are deferred as increases or decreases to stockholders' equity until
the underlying hedged transaction occurs. Consequently, changes in the effective
portions of commodity price hedge derivatives add volatility to the Company's
reported stockholders' equity until the hedge derivative matures or is
terminated. See Note J 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 2002, 2001 and 2000 from the Company's
hedging activities, the Company's open hedge positions at December 31, 2002 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 $11.2 million, $21.8 million and $25.8 during 2002, 2001 and
2000, respectively. The Company's interest and other income was comprised of
revenue that was not directly attributable to oil and gas producing activities
or oil and gas property divestitures. See Note L of Notes to Consolidated
Financial Statements included in "Item 8. Financial Statements and Supplementary
Data" for additional information regarding interest and other income.
29
Gain (loss) on disposition of assets. During the year ended December 31,
2002, the Company realized $118.9 million of cash proceeds from asset
divestitures and, associated therewith, recorded net gains of $4.4 million. The
proceeds derived from asset divestitures during 2002 included $91.3 million from
the early termination of hedge derivatives, $20.9 million from the cash
settlement of a gas balancing receivable, $4.7 million from the sale of certain
gas properties located in Oklahoma and $2.0 million from the sale of other
corporate assets. The Company recorded a gain of $2.8 million associated with
the sale of the gas properties in Oklahoma and a gain of $1.6 million from the
sale of other corporate assets. The proceeds from the early termination of hedge
derivatives represent deferred hedge gains and losses that will be recognized as
increases or decreases to future interest expenses or future oil and gas
revenues. See Note J of Notes to Consolidated Financial Statements included in
"Item 8. Financial Statements and Supplementary Data" for information regarding
the amortization of deferred hedge gains and losses.
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 $3.4 million from the sale of other
corporate assets. 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, a loss
of $1.1 million from the sales of oil and gas properties and a gain of $.7
million from the sale of other corporate assets.
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.
The net cash proceeds from asset divestitures during 2002, 2001 and 2000
were used, together with net cash flows provided by operating activities, to
fund additions to oil and gas properties and to reduce outstanding indebtedness.
See Note M 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 decreased in 2002 by
four percent and increased in 2001 by 16 percent. 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 decrease in production costs during 2002 was primarily due to decreases in
field fuel expense and production taxes as a result of lower North American
average gas prices and lower Argentine lease operating expenses resulting from
lower Argentine expenses on a U.S. dollar equivalent basis due to the
devaluation of the Argentine peso versus the U.S. dollar, partially offset by
moderately higher workover expenses, ad valorem taxes (which are computed using
prior year average annual commodity prices) and declines in the third party gas
processing and treating margin component of lease operating expense. The
increase in production costs during 2001 was primarily due to increases in field
fuel expense as a result of higher North American average gas prices, higher ad
valorem taxes and to declines in the third party gas processing and treating
margin component of lease operating expenses. The following table provides the
components of the Company's production costs during the years ended December 31,
2002, 2001 and 2000:
Year Ended December 31,
-------------------------------
2002 2001 2000
------- ------- -------
(per BOE)
Lease operating expenses............ $ 2.87 $ 2.76 $ 2.42
Taxes:
Production........................ .54 .74 .77
Ad valorem ....................... .54 .49 .29
Field fuel expenses................. .62 .88 .71
Workover expenses................... .25 .17 .15
------ ------ ------
Total production costs........ $ 4.82 $ 5.04 $ 4.34
====== ====== ======
30
Depletion, depreciation and amortization expense. The Company's total
depletion, depreciation and amortization expense per BOE was $5.22, $5.35 and
$4.93 for the years ended December 31, 2002, 2001 and 2000, respectively.
Depletion expense, the largest component of depletion, depreciation and
amortization, was $5.01, $5.02 and $4.57 per BOE during the years ended December
31, 2002, 2001 and 2000, respectively, and depreciation and amortization of
other property and equipment was $.21, $.33 and $.36 per BOE during each of the
respective years. The decrease in depreciation and amortization of other
property and equipment during 2002 was primarily comprised of decreases
associated with fully amortized information technology assets. During 2001, the
increase in per BOE depletion expense was primarily associated with decreases in
United States production, which had 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.
Exploration, abandonments, geological and geophysical costs. Exploration,
abandonments, geological and geophysical costs totaled $85.9 million, $127.9
million and $87.6 million for the years ended December 31, 2002, 2001 and 2000,
respectively. The following table sets forth the components of the Company's
2002, 2001 and 2000 exploration and abandonments/geological and geophysical
costs:
United Other
States Argentina Canada Foreign Total
-------- --------- -------- -------- --------
(in thousands)
Year Ended December 31, 2002:
Geological and geophysical costs........ $ 22,761 $ 4,138 $ 3,544 $ 7,223 $ 37,666
Exploratory dry holes................... 32,557 3,294 1,220 (539) 36,532
Leasehold abandonments and other........ 7,637 2,874 1,077 108 11,696
------- ------- ------- ------- -------
$ 62,955 $ 10,306 $ 5,841 $ 6,792 $ 85,894
======= ======= ======= ======= =======
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
======= ======= ======= ======= =======
The decrease in 2002 exploration, abandonments, geological and
geophysical costs reflected a decline in Argentine exploration activities as the
Company monitored and assessed the economic environment and risks associated
with Argentina; a decline in exploratory dry holes and geological and
geophysical costs in Africa, as the Company assessed its exploratory successes
in Gabon and Tunisia; and the allocation of a larger percentage of the Company's
2002 capital budget to the development of its significant discoveries in the
Gulf of Mexico and offshore South Africa. The increase in 2001 exploration
costs, as compared to 2000, was primarily due to increased geological and
geophysical costs that were supportive of exploratory drilling, increased
exploratory drilling in the Gulf of Mexico and Argentina and an exploratory dry
hole drilled in Tunisia. Approximately 20 percent of the Company's 2002 costs
incurred for oil and gas producing activities were exploration costs as compared
to 34 percent in 2001 and 38 percent in 2000.
General and administrative expenses. The Company's general and
administrative expenses totaled $48.4 million ($1.17 per BOE), $37.0 million
($.89 per BOE) and $33.3 million ($.76 per BOE) during the years ended December
31, 2002, 2001 and 2000, respectively. The increase in administrative expense
during 2002 as compared to 2001 was primarily due to the elimination of
operating overhead being charged by the Company to the 42 affiliated
partnerships that were merged into a wholly-owned subsidiary of the Company
during December 2001 (see "Financial and Operating Performance" and Note D of
Notes to Consolidated Financial Statements included in "Item 8. Financial
Statements and Supplementary Data" for additional information regarding the 2001
merger). Additionally, the Company awarded 645,445 shares of restricted stock to
directors, officers and key employees as part of the Company's compensation
program. The Company recorded $16.2 million of deferred compensation associated
with the restricted stock awards, which amount will be amortized to compensation
expense during the vesting periods of the awards. Amortization of the deferred
costs of the restricted stock increased general and administrative expenses by
$1.9 million in 2002. See Note G of Notes to Consolidated Financial Statements
included in "Item 8. Financial Statements and Supplementary Data" for
31
information regarding the restricted stock awards and their vesting periods. The
increase in general and administrative expense during 2001, as compared to 2000,
was primarily due to an increase in compensation expense.
Interest expense. Interest expense was $95.8 million, $132.0 million
and $162.0 million for the years ended December 31, 2002, 2001 and 2000,
respectively. The decline in 2002 interest expense as compared to 2001, was
primarily due to incremental interest savings of $18.0 million from the
Company's interest rate hedging program; a $6.3 million increase in interest
capitalized; interest savings from the retirement of the Company's outstanding
11-5/8 percent and 10-5/8 percent senior subordinated notes during the third
quarter of 2001 and $38.7 million of the Company's 9-5/8 percent senior notes
during the fourth quarter of 2001; interest savings from the repurchase of $47.1
million of 9-5/8 percent senior notes and $13.9 million of 8-7/8 percent senior
notes during 2002; interest savings from the repayment of the $45.2 million West
Panhandle gas field capital obligation in July 2002 which bore interest at an
annual rate of 20 percent; and interest savings from reductions in underlying
market interest rates. The decrease in interest expense for 2001 as compared to
2000 was primarily due to incremental interest savings of $7.0 million from the
Company's interest rate hedging program; a $6.0 million increase in interest
capitalized; and interest savings associated with the redemption of the
Company's outstanding 11-5/8 percent and 10-5/8 percent senior subordinated
notes and $38.7 million of the Company's 9-5/8 percent senior notes.
As is discussed in "2003 Outlook" above, capitalized interest will
decline during 2003, as compared to 2002 levels, primarily due to the completion
of the Canyon Express development project during September 2002 and the
anticipated completion of the Falcon and Sable development projects during the
second quarter of 2003. Additionally, 2003 interest expense will be impacted by
fair value hedges of the Company's 9-5/8 percent senior notes that were
initiated by the Company during February 2003 and for which more detailed
information is provided in "2003 Outlook" and in "Item 7A. Quantitative and
Qualitative Disclosures About Market Risk". See Note E of Notes to Consolidated
Financial Statements included in "Item 8. Financial Statements and Supplementary
Data" for additional information about the Company's long-term debt, interest
expense and extraordinary items.
Other expenses. Other expenses were $17.3 million during 2002, as
compared to $39.6 million during 2001 and $67.2 million during 2000. Other
expenses during 2002 were primarily comprised of a $6.9 million charge from the
remeasurement of the Company's Argentine peso-denominated net monetary assets
and liabilities and $2.5 million of marketing losses incurred to transport and
sell purchased Canadian gas to a Chicago, Illinois sales point. See Note B and
Note I of Notes to Consolidated Financial Statements included in "Item 8.
Financial Statements and Supplementary Data" for additional information
regarding currency remeasurement and gas transportation commitments.
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; $6.0 million of bad debt
expense related to derivative contracts with Enron North America Corp. and $4.6
million of other expenses.
The primary component of other expense during 2000 was $58.5 million of
mark-to-market losses on derivative contracts that did not qualify for hedge
accounting treatment, including $43.9 million of losses on derivative contracts
that matured during 2000 and $14.6 million of losses associated with the
Company's Btu swap agreements that mature at the end of December 2004. During
2001, the Company entered into offsetting swap agreements that had fixed the
prices that are to be received and paid by the Company under the Btu swap
agreements. Consequently, the Btu swap agreements are no longer sensitive to
changes in oil or gas commodity prices.
Income tax provisions (benefits). The Company recognized consolidated
income tax provisions of $5.1 million and $4.0 million during 2002 and 2001,
respectively, and a consolidated income tax benefit of $6.0 million during 2000.
The Company's consolidated tax provision for the year ended December 31, 2002
was comprised of current U.S. state and local taxes of $.2 million, current
foreign taxes of $2.1 million and deferred foreign tax provisions of $2.8
million. The Company's consolidated tax provision for the year ended December
31, 2001 was comprised of current U.S. state and local taxes of $1.1 million,
current foreign taxes of $10.5 million and deferred foreign tax benefits of $7.6
million. The Company's consolidated tax benefit in 2000 was comprised of a $10.6
million deferred tax benefit in Argentina, partially offset by $4.6 million of
current taxes paid in Argentina.
32
Due to uncertainties regarding the Company's ability to realize certain
of its net operating loss carryovers and tax credit carryovers prior to their
scheduled expirations, the Company has established a valuation allowance of
$277.2 million against those carryovers. Although the Company believes it is
more likely than not that the carrying values of its remaining deferred tax
assets will be realized through future taxable earnings or alternative tax
planning strategies, 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 2003 will be
minimal in the United States and Canada and approximately 35 percent in
Argentina. 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 tax, deferred tax asset valuation reserves and net
operating loss carryforward expirations.
Extraordinary items. During 2002, the Company repurchased $47.1 million
of its 9-5/8 percent senior notes, $13.9 million of its 8-7/8 percent senior
notes and repaid a $45.2 million West Panhandle field capital cost obligation.
Associated with the 2002 debt extinguishments, the Company recognized an
extraordinary loss, net of taxes, of $22.3 million. During 2001, the Company
redeemed the remaining $22.5 million of its outstanding 11-5/8 percent senior
subordinated notes, $6.8 million of its outstanding 10-5/8 percent senior
subordinated notes and repurchased $38.7 million of its 9-5/8 percent senior
notes. Associated with these debt extinguishments, the Company recognized an
extraordinary loss, net of taxes, of $3.8 million. During 2000, the Company
replaced its prior credit facility, which was scheduled to mature in August
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. See "New Accounting
Pronouncements", above, for information regarding future changes in the
classification of the Company's extraordinary gains and losses.
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. Funding for
exploration, development and acquisitions of oil and gas properties and
repayment of contractual obligations 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. Funding for the Company's working capital obligations is provided by
internally-generated cash flow.
Oil and gas properties. The Company's cash expenditures for additions to
oil and gas properties during 2002, 2001 and 2000 totaled $614.7 million, $529.7
million and $299.7 million, respectively. The Company's 2002 expenditures for
additions to oil and gas properties were funded by $332.2 million of net cash
provided by operating activities, $118.9 million of proceeds from the
disposition of assets and a portion of the proceeds from the issuance of 11.5
million shares of the Company's common stock during April 2002. 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 assets. The Company's 2000 capital expenditures
were internally funded by net cash provided by operating activities.
The Company strives to maintain its indebtedness at reasonable levels in
order to provide sufficient financial flexibility to take advantage of future
opportunities. The Company's capital budget for 2003 is expected to range from
$450 million to $550 million. The Company believes that net cash provided by
operating activities during 2003 will be sufficient to fund the 2003 capital
expenditures budget.
Contractual obligations, including off-balance sheet obligations. The
Company's contractual obligations include long-term debt, operating leases, Btu
swap agreements, terminated commodity hedges and other contracts. From time to
time, the Company enters into off-balance sheet arrangements and transactions
that can give rise to material off- balance sheet obligations of the Company. As
of December 31, 2002, the material off-balance sheet arrangements and
transactions that the Company has entered into include (i) $27.2 million of
undrawn letters of credit issued under the Company's $575 million corporate
credit facility and (ii) operating lease agreements under which the Company's
future minimum lease commitments are summarized in the table below and in Note I
of Notes to Consolidated Financial Statements included in "Item 8. Financial
Statements and Supplementary Data". 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 and gas transportation commitments. See "Item
33
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, 2002 and Note I of Notes to
Consolidated Financial Statements included in "Item 8. Financial Statements and
Supplementary Data" for additional information regarding gas transportation
commitments. The following table summarizes the Company's payments due by period
for fixed and determinable contractual obligations:
Payments Due by Year
------------------------------------------------------------
2003 2004 2005 2006-2007 Thereafter
--------- --------- --------- --------- ------------
(in thousands)
Long-term debt (a)............. $ - $ - $ 406,704 $ 161,130 $1,100,702
Operating leases (b)........... 19,364 41,553 39,375 58,924 36,338
Btu swap agreements (c)........ 7,168 7,190 - - -
Terminated commodity hedges.... 484 340 - - -
-------- -------- -------- -------- ---------
$ 27,016 $ 49,083 $ 446,079 $ 220,054 $1,137,040
======== ======== ======== ======== =========
- ------------
(a) See Note E of Notes to Consolidated Financial Statements included in "Item
8. Financial Statements and Supplementary Data".
(b) See Note I of Notes to Consolidated Financial Statements included in "Item
8. Financial Statements and Supplementary Data".
(c) See Note J of Notes to Consolidated Financial Statements included in "Item
8. Financial Statements and Supplementary Data".
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 2003.
Operating activities. Net cash provided by operating activities during
2002, 2001 and 2000 were $332.2 million, $475.6 million and $430.1 million,
respectively. Net cash provided by operating activities in 2002 decreased by
$143.4 million, or 30 percent, as compared to that of 2001. The decrease in 2002
net cash provided by operating activities was principally due to declines in
commodity prices, offset partially by declines in interest expense. Net cash
provided by operating activities in 2001 increased by $45.5 million, or 11
percent, as compared to that of 2000. The increase in 2001 was primarily due to
higher commodity prices as compared to 2000, declines in interest expense and an
increase in trade receivable collections.
Financing activities. During the year ended December 31, 2002, the
Company's financing activities provided $170.9 million of cash, comprised of
$236.0 million of proceeds, net of issuance costs, from the sale of 11.5 million
shares of the Company's common stock; $48.0 million of net borrowings of
long-term debt; and $14.4 million of proceeds from the exercise of long-term
incentive plan stock options and employee stock purchases. Partially offsetting
these cash proceeds from financing activities were $124.2 million of payments of
noncurrent liabilities and $3.3 million of debt issuance costs during 2002. In
contrast, during the years ended December 31, 2001 and 2000, the Company used
$64.0 million and $244.1 million, respectively, of net cash in financing
activities. During the years ended December 31, 2001 and 2000, the Company used
$5.1 million and $177.3 million of cash, respectively, to repay long-term debt;
$53.4 million and $29.8 million, respectively, to repay noncurrent liabilities;
$13.0 million and $27.3 million, respectively, to purchase treasury stock; and,
during the year ended December 31, 2000, $13.8 million for deferred loan and
debt issuance costs. Partially offsetting the above described net cash uses from
financing activities were $7.5 million and $4.2 million of net cash provided
from the exercise of long-term incentive plan stock options and employee stock
purchases during the years ended December 31, 2001 and 2000, respectively.
Over the three year period ended December 31, 2002, the Company has used
$134.4 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, 2002, from 69 percent as of 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 the years ended December 31, 2002 and 2001, the Company entered into
interest rate swap contracts to hedge the fair value of its 6-1/2 percent senior
notes, its 8-7/8 percent senior notes and its 8-1/4 percent senior notes. The
Company also entered into interest rate swaps to hedge a portion of its interest
rate risk under the Credit Agreement. In 2002 and 2001, the Company terminated
its open interest rate swap portfolios to lock in the substantial fair value of
the derivatives. As of December 31, 2002, the Company had $35.7 million of
34
deferred gains associated with the interest rate swap terminations recorded as
an increase in the carrying value of the Company's long-term debt. During the
years ended December 31, 2002, 2001 and 2000, net gains from the Company's
interest rate swaps have reduced interest expense by $25.3 million, $7.3 million
and $.3 million, respectively. See Note J 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 interest rate hedging activities.
As is further described in "Results of Operations" above, during the year
ended December 31, 2002, the Company repurchased $47.1 million of its 9-5/8
percent senior notes, $13.9 million of its 8-7/8 percent senior notes and repaid
a $45.2 million West Panhandle gas field capital cost obligation. Additionally,
during the year ended December 31, 2001, the Company redeemed its remaining
11-5/8 percent and 10-5/8 percent senior subordinated notes and $38.7 million of
its 9-5/8 percent senior notes.
At December 31, 2002, the Company had a $575.0 million corporate credit
facility with a syndicate of banks that matures on March 1, 2005. Outstanding
borrowings under the corporate credit facility totaled $260.0 million as of
December 31, 2002. In addition, the Company has five outstanding senior note
issuances at December 31, 2002. Such debt issuances consist of (i) $136.1
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) $339.2 million aggregate remaining principal amount of
9-5/8 percent senior notes due in 2010; (v) $150 million aggregate principal
amount of 7-1/2 percent senior notes due in 2012; and (vi) $250 million
aggregate principal amount of 7-1/5 percent senior notes due in 2028. Certain of
the obligations above contain restrictive covenants, each of which the Company
is in compliance.
The weighted average interest rate on the Company's indebtedness for the
year ended December 31, 2002 was 5.74 percent as compared to 7.52 percent for
the year ended December 31, 2001 and 8.68 percent for the year ended December
31, 2000, taking into account the effect of interest rate swaps. See Note E 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, 2002 and 2001.
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 2002, 2001 and 2000, proceeds from
the sale of non-strategic assets totaled $118.9 million, $113.5 million and
$102.7 million, respectively. The Company's 2002, 2001 and 2000 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 2002 and 2001 were used to fund a portion of the Company's
2002 and 2001 capital expenditures and for general corporate obligations. The
net cash proceeds from the 2000 asset divestitures were used to reduce the
Company's outstanding indebtedness (see "Results of Operations", above, and Note
M of Notes to Consolidated Financial Statements included in "Item 8. Financial
Statements and Supplementary Data").
Book capitalization and liquidity. The Company's total debt was $1.67
billion as of December 31, 2002, as compared to total debt of $1.58 billion on
December 31, 2001 and 2000. The Company's total book capitalization at December
31, 2002 was $3.04 billion, consisting of total debt of $1.67 billion and
stockholders' equity of $1.37 billion. The Company's debt to total
capitalization was 55 percent at December 31, 2002. The Company's ratio of
current assets to current liabilities was .54 at December 31, 2002 and 1.12 at
December 31, 2001. The decline in the Company's ratio of current assets to
current liabilities was primarily due to a $170.7 million difference in the fair
value of 2003 maturing derivatives at December 31, 2002 as compared to the fair
value of 2002 maturing derivatives at December 31, 2001. Including $27.2 million
of undrawn and outstanding letters of credit, the Company has $287.8 million of
unused borrowing capacity available under its Credit Agreement as of December
31, 2002.
35
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, 2002
and 2001, and from which the Company may incur future gains or losses from
changes in market interest rates, foreign exchange rates or commodity 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 2002. During 2002, the Company was a party to
forward foreign exchange contracts, commodity and interest rate swap contracts
and commodity collar contracts. See Note J 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 2002:
Derivative Contract Assets (Liabilities)
--------------------------------------------------
Foreign
Interest Exchange
Commodity Rate Rate Total
---------- -------- -------- ---------
(in thousands)
Fair value of contracts outstanding
as of December 31, 2001.............. $ 180,554 $ (19,637) $ 61 $ 160,978
Changes in contract fair values (1)...... (183,285) 62,786 203 (120,296)
Contract realizations:
Maturities........................... (48,212) (11,155) (249) (59,616)
Termination - cash settlements....... (58,685) (31,994) - (90,679)
Termination - future obligations..... 1,303 - - 1,303
Termination - future receivables..... (479) - - (479)
-------- -------- ----- --------
Fair value of contracts outstanding
as of December 31, 2002.............. $(108,804) $ - $ 15 $(108,789)
======== ======== ===== ========
- ---------------
(1) At inception, new derivative contracts entered into by the Company have no
intrinsic value.
Quantitative Disclosures
Interest rate sensitivity. The following tables provide information, in
U. S. dollar equivalent amounts, about other financial instruments that the
Company was a party to as of December 31, 2002 and 2001 and that are or were
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 was obligated to
periodically pay on the debt as of December 31, 2002 and 2001. For variable rate
debt, the average interest rate represents the average rates being paid on the
debt projected forward proportionate to the forward yield curves for the
six-month London Interbank Offered Rate.
36
Interest Rate Sensitivity
Derivative and Other Financial Instruments as of December 31, 2002 (1)
Liability
2003 2004 2005 2006 2007 Thereafter Total Fair Value
-------- -------- -------- -------- -------- ---------- ---------- -----------
(in thousands except interest rates)
Total Debt:
U.S. dollar denominated
maturities:
Fixed rate debt............ $ - $ - $146,704 $ - $161,130 $1,100,702 $1,408,536 $(1,484,009)
Weighted average
interest rate (%)........ 7.94 7.94 7.87 7.83 7.81 7.77
Variable rate debt......... $ - $ - $260,000 $ - $ - $ - $ 260,000 $ (260,000)
Average interest rate (%).. 2.89 4.08 5.27
- ------------
(1) During February 2003, the Company entered into interest rate swap contracts
to hedge a portion of the fair value of its 9-5/8 percent senior notes.
Under the terms of the interest rate swap contracts, the Company will
receive a fixed annual rate of 9-5/8 percent on $250 million notional
amount and will pay the counterparties a variable rate on the notional
amount equal to the six-month LIBOR, reset semi- annually, plus a weighted
average margin of 566.4 basis points.
The accompanying Interest Rate Sensitivity table as of December 31, 2001
also provides information about interest rate swap agreements that the Company
was a party to as of that date. These interest rate swap agreements were
terminated during the year ended December 31, 2002 and no longer represent
market risk to the Company. The interest rate swap agreements as of December 31,
2001 hedged (i) the fair value of the Company's 8-1/4 percent senior notes; (ii)
the fair value of the Company's 6-1/2 percent senior notes; and (iii) a portion
of the interest rate risk associated with the Company's Credit Agreement.
Interest Rate Sensitivity
Derivative and Other Financial Instruments as of December 31, 2001
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:
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
37
Foreign exchange rate 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, 2002 and 2001 and
that were sensitive to changes in foreign exchange rates.
Foreign Exchange Rate Sensitivity
Derivative and Other Financial Instruments as of December 31, 2002
Asset
2003 Total Fair Value (1)
-------- -------- --------------
(in thousands except interest rates)
Foreign Exchange Rate Hedge Derivatives:
Notional amount of foreign
currency forward contracts.................... $ 2,000 $ 2,000 $ 15
Fixed Canadian to U.S. dollar rate paid........ .6258
- --------------
(1) The Company's foreign currency forward contract matured as a $15 thousand
asset during January 2003.
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, 2002 and 2001 and that were sensitive
to changes in oil and gas prices. As of December 31, 2002 and 2001, all of the
Company's derivative financial instruments that were sensitive to changes in oil
and gas prices qualified 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.
See Notes B, C and J 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 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.
Oil Price Sensitivity
Derivative Financial Instruments as of December 31, 2002
Liability
2003 2004 Fair Value
-------- -------- ------------
Oil Hedge Derivatives (1):
Average daily notional Bbl volumes:
Swap contracts (2)............................ 22,236 14,000 $ (19,912)
Weighted average fixed price per Bbl......... $ 24.45 $ 23.11
Average forward NYMEX oil prices per Bbl (3).... $ 31.55 $ 25.75
- ---------------
(1) See Note J 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 2003 and 2004.
(2) During January 2003, the Company increased its 2003 oil hedge positions by
entering into 6,000 Bbls per day of March 2003 oil swap contracts with
average per Bbl fixed prices of $33.51.
(3) The average forward NYMEX oil prices per Bbl are based on February 18, 2003
market quotes.
38
Oil Price Sensitivity
Derivative Financial Instruments as of December 31, 2001
Asset
2002 2003 Fair Value
-------- -------- ----------
Oil Hedge Derivatives (1):
Average daily notional Bbl volumes:
Swap contracts.................................. 9,463 2,975 $ 23,423
Weighted average fixed price per Bbl........... $ 26.23 $ 24.02
Collar contracts................................ 2,975 $ 5,506
Weighted average short call ceiling price
per Bbl...................................... $ 28.61
Weighted average long put floor price
per Bbl...................................... $ 25.00
Average forward NYMEX oil prices (1).............. $ 21.86 $ 21.54
- ---------------
(1) The average forward NYMEX oil prices are based on February 28, 2002 market
quotes.
Gas Price Sensitivity
Derivative Financial Instruments as of December 31, 2002
2006 & Liability
2003 2004 2005 2007 Fair Value
-------- -------- -------- --------- ----------
Gas Hedge Derivatives (1) (2):
Average daily notional MMBtu volumes:
Swap contracts................................... 230,000 180,000 10,000 20,000 $ (88,892)
Weighted average fixed price per MMBtu.......... $ 3.76 $ 3.81 $ 3.70 $ 3.75
Average forward NYMEX gas prices per MMBtu (3)..... $ 5.53 $ 4.80 $ 4.31 $ 4.12
- --------------
(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 J of Notes to Consolidated Financial Statements included in "Item
8. Financial Statements and Supplementary Data" for hedge volumes and
weighted average prices per MMBtu by calendar quarter for 2003, 2004, 2005,
2006 and 2007.
(3) The average forward NYMEX gas prices per MMBtu are based on February 18,
2003 market quotes.
Gas Price Sensitivity
Derivative Financial Instruments as of December 31, 2001
Asset
2002 2003 2004 2005 Fair Value
-------- -------- -------- -------- ----------
Gas Hedge Derivatives (1) (2):
Average daily notional MMBtu volumes:
Swap contracts.................................. 165,205 117,500 165,000 50,000 $ 137,606
Weighted average fixed price per MMBtu......... $ 4.19 $ 3.62 $ 3.84 $ 3.63
Collar contracts................................ 20,000 $ 14,019
Weighted average short call ceiling price
per MMBtu................................... $ 6.00
Weighted average long put floor price
per MMBtu................................... $ 4.50
Average forward NYMEX gas prices per MMBtu (2).... $ 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) The average forward NYMEX gas prices per MMBtu are based on February 28,
2002 market quotes.
39
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 E of Notes to Consolidated Financial Statements
included in "Item 8. Financial Statements and Supplementary Data" for a
discussion of the Company's debt instruments.
Derivative financial instruments. The Company has, from time to time,
entered into interest rate, foreign exchange rate and commodity price derivative
contracts to hedge interest rate, foreign exchange rate and commodity price
risks in accordance with policies and guidelines approved by the Company's board
of directors. In accordance with those policies and guidelines, the Company's
executive management determines the appropriate timing and extent of hedge
transactions. 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, 2002, 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 vis a vis 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, 2002.
40
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Index to Consolidated Financial Statements
Page
Consolidated Financial Statements of Pioneer Natural Resources Company:
Independent Auditors' Report......................................... 42
Consolidated Balance Sheets as of December 31, 2002 and 2001......... 43
Consolidated Statements of Operations for the Years Ended
December 31, 2002, 2001 and 2000.................................. 44
Consolidated Statements of Stockholders' Equity for the Years
Ended December 31, 2002, 2001 and 2000............................ 45
Consolidated Statements of Cash Flows for the Years Ended
December 31, 2002, 2001, and 2000................................. 46
Consolidated Statements of Comprehensive Income (Loss) for the
Years Ended December 31, 2002, 2001 and 2000...................... 47
Notes to Consolidated Financial Statements........................... 48
Unaudited Supplementary Information.................................. 81
41
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, 2002 and 2001, 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, 2002. 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, 2002 and 2001, and the
consolidated results of its operations and its cash flows for each of the three
years in the period ended December 31, 2002, 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 24, 2003
42
PIONEER NATURAL RESOURCES COMPANY
CONSOLIDATED BALANCE SHEETS
(in thousands, except share data)
ASSETS
December 31,
--------------------------
2002 2001
----------- -----------
Current assets:
Cash and cash equivalents....................................... $ 8,490 $ 14,334
Accounts receivable:
Trade, net of reserves for doubtful accounts of $4,744
and $5,553 as of December 31, 2002 and 2001, respectively... 97,774 81,616
Affiliates.................................................... 448 595
Inventories..................................................... 10,648 14,549
Deferred income taxes........................................... 13,900 6,400
Other current assets:
Derivative assets, net of valuation reserves of $3,351 and
$3,153 as of December 31, 2002 and 2001, respectively....... 3,150 127,074
Other......................................................... 12,683 11,075
---------- ----------
Total current assets........................................ 147,093 255,643
---------- ----------
Property, plant and equipment, at cost:
Oil and gas properties, using the successful efforts method
of accounting:
Proved properties............................................. 4,252,897 3,691,783
Unproved properties........................................... 219,073 187,785
Accumulated depletion, depreciation and amortization............ (1,303,541) (1,095,310)
----------- ----------
3,168,429 2,784,258
----------- ----------
Deferred income taxes............................................. 76,840 84,319
Other property and equipment, net................................. 22,784 21,560
Other assets, net:
Derivative assets, net of valuation reserves of $1,136 and
$1,069 as of December 31, 2002 and 2001, respectively......... 793 54,486
Other........................................................... 39,177 70,787
---------- ----------
$ 3,455,116 $ 3,271,053
========== ==========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable:
Trade......................................................... $ 117,582 $ 92,760
Affiliates.................................................... 7,192 6,405
Interest payable................................................ 37,458 37,410
Other current liabilities:
Derivative obligations........................................ 83,638 36,830
Other......................................................... 28,722 54,804
---------- ----------
Total current liabilities................................... 274,592 228,209
---------- ----------
Long-term debt.................................................... 1,668,536 1,577,304
Noncurrent derivative obligations................................. 42,490 32,438
Other noncurrent liabilities...................................... 85,841 133,945
Deferred income taxes............................................. 8,760 13,768
Stockholders' equity:
Preferred stock, $.01 par value; 100,000,000 shares
authorized; zero and one share issued and outstanding
as of December 31, 2002 and 2001, respectively................ - -
Common stock, $.01 par value; 500,000,000 shares authorized;
119,592,344 shares issued at December 31, 2002; and
107,422,467 shares issued at December 31, 2001................ 1,196 1,074
Additional paid-in capital...................................... 2,714,567 2,462,272
Treasury stock, at cost; 2,339,806 shares at December 31,
2002 and 3,486,073 shares at December 31, 2001................ (32,219) (48,002)
Deferred compensation........................................... (14,292) -
Accumulated deficit............................................. (1,298,440) (1,323,343)
Accumulated other comprehensive income:
Deferred hedge gains, net..................................... 9,555 201,046
Cumulative translation adjustment............................. (5,470) (7,658)
---------- ----------
Total stockholders' equity.................................. 1,374,897 1,285,389
Commitments and contingencies
---------- ----------
$ 3,455,116 $ 3,271,053
========== ==========
The accompanying notes are an integral part of these
consolidated financial statements.
43
PIONEER NATURAL RESOURCES COMPANY
CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands, except per share data)
Year Ended December 31,
-----------------------------------
2002 2001 2000
--------- --------- ---------
Revenues and other income:
Oil and gas.......................................... $ 701,780 $ 847,022 $ 852,738
Interest and other................................... 11,222 21,778 25,775
Gain on disposition of assets, net................... 4,432 7,681 34,184
-------- -------- --------
717,434 876,481 912,697
-------- -------- --------
Costs and expenses:
Oil and gas production............................... 199,570 209,664 189,265
Depletion, depreciation and amortization............. 216,375 222,632 214,938
Exploration and abandonments......................... 85,894 127,906 87,550
General and administrative........................... 48,402 36,968 33,262
Interest............................................. 95,815 131,958 161,952
Other................................................ 17,256 39,588 67,231
-------- -------- --------
663,312 768,716 754,198
-------- -------- --------
Income before income taxes and extraordinary items..... 54,122 107,765 158,499
Income tax benefit (provision)......................... (5,063) (4,016) 6,000
-------- -------- --------
Income before extraordinary items...................... 49,059 103,749 164,499
Extraordinary items - loss on early extinguishment
of debt, net of tax.................................. (22,346) (3,753) (12,318)
-------- -------- --------
Net income............................................. $ 26,713 $ 99,996 $ 152,181
======== ======== ========
Income per share:
Basic:
Income before extraordinary items................. $ .44 $ 1.05 $ 1.65
Extraordinary items............................... (.20) (.04) (.12)
-------- -------- --------
Net income........................................ $ .24 $ 1.01 $ 1.53
======== ======== ========
Diluted:
Income before extraordinary items................. $ .43 $ 1.04 $ 1.65
Extraordinary items............................... (.20) (.04) (.12)
-------- -------- --------
Net income........................................ $ .23 $ 1.00 $ 1.53
======== ======== ========
Weighted average shares outstanding:
Basic............................................. 112,542 98,529 99,378
======== ======== ========
Diluted........................................... 114,288 99,714 99,763
======== ======== ========
The accompanying notes are an integral part of these
consolidated financial statements.
44
PIONEER NATURAL RESOURCES COMPANY
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
(in thousands)
Accumulated Other
Comprehensive Income
-----------------------------
Deferred Invest- Total
Additional Deferred Hedge ment Trans- Stock-
Common Paid-in Treasury Compen- Accumulated Gains & Gains & lation holders'
Stock Capital Stock sation Deficit Losses Losses Adjustment Equity
------- ---------- -------- --------- ----------- -------- -------- ---------- ----------
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
------ --------- ------- -------- ---------- -------- ------- ------- ---------
Issuance of common stock.......... 115 235,885 - - - - - - 236,000
Adjustment to common stock
issued for 2001 partnership
acquisitions.................... - (175) - - - - - - (175)
Exercise of stock options and
employee stock purchases......... - 416 15,783 - (1,810) - - - 14,389
Deferred compensation:
Compensation deferred........... 7 16,169 - (16,176) - - - - -
Deferred compensation included
in net income.................. - - - 1,884 - - - - 1,884
Net income........................ - - - - 26,713 - - - 26,713
Other comprehensive income (loss):
Deferred hedge gains and losses,
net of tax:
Deferred hedge losses........ - - - - - (179,067) - - (179,067)
Net gains included in net
income...................... - - - - - (12,424) - - (12,424)
Currency translation adjustment. - - - - - - - 2,188 2,188
------ --------- ------- ------- ---------- -------- ------- ------- ---------
Balance at December 31, 2002...... $ 1,196 $2,714,567 $(32,219) $(14,292) $(1,298,440) $ 9,555 $ - $ (5,470) $1,374,897
====== ========= ======= ======= ========== ======== ======= ======= =========
The accompanying notes are an integral part of these
consolidated financial statements.
45
PIONEER NATURAL RESOURCES COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
Year Ended December 31,
-------------------------------------
2002 2001 2000
--------- --------- -----------
Cash flows from operating activities:
Net income.................................................. $ 26,713 $ 99,996 $ 152,181
Adjustments to reconcile net income to net cash
provided by operating activities:
Depletion, depreciation and amortization............... 216,375 222,632 214,938
Exploration expenses, including dry holes.............. 64,617 103,595 66,959
Deferred income taxes.................................. 2,788 (7,649) (10,600)
Gain on disposition of assets, net..................... (4,432) (7,681) (34,184)
Loss on early extinguishment of debt, net of tax....... 22,346 3,753 12,318
Interest related amortization.......................... (5,809) 8,689 12,699
Commodity hedge related amortization................... 26,490 6,199 -
Other noncash items.................................... 9,301 14,944 59,776
Change in operating assets and liabilities, net of
effects from acquisitions:
Accounts receivable.................................... (23,922) 41,295 (7,486)
Inventory.............................................. 3,023 (4,256) (2,789)
Other current assets................................... (1,836) (6,304) (9,896)
Accounts payable....................................... (342) (541) 26,260
Interest payable....................................... 48 (733) 2,097
Other current liabilities.............................. (3,115) 1,661 (52,177)
-------- -------- ----------
Net cash provided by operating activities.............. 332,245 475,600 430,096
-------- -------- ----------
Cash flows from investing activities:
Cash acquired in acquisitions, net of fees paid............. - 11,119 -
Proceeds from disposition of assets......................... 118,850 113,453 102,736
Additions to oil and gas properties......................... (614,698) (529,723) (299,682)
Other property dispositions (additions), net................ (12,283) (17,590) 2,445
-------- -------- ----------
Net cash used in investing activities.................. (508,131) (422,741) (194,501)
-------- -------- ----------
Cash flows from financing activities:
Borrowings under long-term debt............................. 529,805 328,331 922,607
Principal payments on long-term debt........................ (481,783) (333,410) (1,099,935)
Common stock issuance proceeds, net of issuance costs....... 236,000 - -
Payments of other noncurrent liabilities.................... (124,245) (53,437) (29,759)
Exercise of stock options and employee stock purchases...... 14,389 7,504 4,164
Purchase of treasury stock.................................. - (13,028) (27,298)
Deferred loan fees/issuance costs........................... (3,293) - (13,847)
-------- -------- ----------
Net cash provided by (used in) financing activities.... 170,873 (64,040) (244,068)
-------- -------- ----------
Net decrease in cash and cash equivalents .................... (5,013) (11,181) (8,473)
Effect of exchange rate changes on cash and cash equivalents.. (831) (644) (156)
Cash and cash equivalents, beginning of year.................. 14,334 26,159 34,788
-------- -------- ----------
Cash and cash equivalents, end of year........................ $ 8,490 $ 14,334 $ 26,159
======== ======== ==========
The accompanying notes are an integral part of these
consolidated financial statements.
46
PIONEER NATURAL RESOURCES COMPANY
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(in thousands)
Year ended December 31,
------------------------------------
2002 2001 2000
---------- ---------- ----------
Net income............................................ $ 26,713 $ 99,996 $ 152,181
Other comprehensive income (loss):
Deferred hedge gains and losses, net of tax:
Transition adjustment............................ - (197,444) -
Deferred hedge gains (losses).................... (179,067) 393,004 -
Net (gains) losses included in net income........ (12,424) 5,486 -
Gains and losses on available for sale securities:
Unrealized holding gains (losses)................ - (45) 33,828
Gains included in net income..................... - (8,109) (25,674)
Currency translation adjustment..................... 2,188 (11,173) (6,910)
--------- ---------- ---------
Other comprehensive income (loss).............. (189,303) 181,719 1,244
--------- --------- ---------
Comprehensive income (loss)........................... $ (162,590) $ 281,715 $ 153,425
========= ========= =========
The accompanying notes are an integral part of these
consolidated financial statements.
47
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2002, 2001 and 2000
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. The Company is an oil and gas exploration and production company with
ownership interests in oil and gas properties located in the United States,
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. As of
December 31, 2002, the Company had $.2 million of trading securities recorded to
other assets. The Company had no investments in trading securities as of
December 31, 2001.
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, 2002 or 2001.
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, 2002 or 2001.
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.
Early in January 2002, the Argentine government severed the direct
one-to-one U.S. dollar to Argentine peso relationship that had existed for many
years. The following bullet points disclose the significant Argentine
assumptions utilized in the preparation of the 2002 and 2001 financial
statements:
48
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2002, 2001 and 2000
o As of December 31, 2002 and 2001, the Company used exchange rates of 3.37
pesos to $1 and 1.7 pesos to $1, respectively, to remeasure the
peso-denominated monetary assets and liabilities of the Company's Argentine
subsidiaries.
o As part of the December 31, 2001 remeasurement process, the Company
estimated that the recovery or settlement values to be realized on
pre-devaluation, 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 lower than the
Company's carrying cost on an equivalent U.S. dollar basis as of December
31, 2001.
o The Company reviewed its Argentine proved and unproved properties for
impairment as of December 31, 2002 and 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 December 31, 2002
assumptions utilized to determine future net cash flows had oil and natural
gas liquids ("NGLs") prices at world market prices adjusted for export
taxes and local market discounts. Gas prices were assumed to return to
predevaluation U.S. dollar levels after a period of time to allow for
inflation. Expenses were initially assumed to be equivalent to reported
expenses in 2002, but to gradually increase to 15 percent above 2002
levels. 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 of the
Company's Argentine subsidiaries as of December 31, 2002 resulted in the Company
recognizing a $6.9 million charge during 2002. The December 31, 2001
remeasurement of the Company's Argentine subsidiaries' peso-denominated monetary
net assets and the adjustment to reduce the subsidiaries' carrying values 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;
(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.
New accounting pronouncements. During June 2001, the Financial Accounting
Standards Board ("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 incurred if a reasonable estimate of fair value can be
made. Under the provisions of SFAS 143, asset retirement obligations 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 that were assumed in business combinations, which were recorded at
their estimated fair values. The Company adopted the provisions of SFAS 143 on
January 1, 2003.
The adoption of SFAS 143 resulted in a January 1, 2003 cumulative effect
adjustment to record (i) a $13.8 million increase in the carrying values of
proved properties, (ii) a $26.3 million decrease in accumulated depreciation,
depletion,
49
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2002, 2001 and 2000
and amortization of property, plant and equipment, (iii) a $1.0 million increase
in current abandonment liabilities and (iv) a $22.4 million increase in
noncurrent abandonment liabilities. The net impact of items (i) through (iv) was
to record a gain of $16.7 million, net of tax, as a cumulative effect adjustment
of a change in accounting principle in the Company's consolidated statements of
operations upon adoption on January 1, 2003.
During April 2002, the FASB issued Statement of Financial Accounting
Standards No. 145, "Rescission of FASB Statements No. 4, 44 and 64, Amendment of
FASB Statement No. 13 and Technical Corrections" ("SFAS 145"). Prior to the
adoption of the provisions of SFAS 145, gains or losses on the early
extinguishment of debt were required to be classified in a company's periodic
consolidated statements of operations as extraordinary gains or losses, net of
associated income taxes, after the determination of income or loss from
continuing operations. SFAS 145 requires, except in the case of events or
transactions of a highly unusual and infrequent nature, gains or losses from the
early extinguishment of debt to be classified as components of a company's
income or loss from continuing operations. The Company adopted the provisions of
SFAS 145 on January 1, 2003. The adoption of the provisions of SFAS 145 is not
expected to affect the Company's future financial position or liquidity. Upon
adoption of the provisions of SFAS 145, gains or losses from the early
extinguishment of debt recognized in the Company's consolidated statements of
operations for the years ended December 31, 2002, 2001 and 2000 will be
reclassified to other revenues or other expense and included in the
determination of the income (loss) from continuing operations of those periods.
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. The Company has established lower of cost or
market allowances to reduce the carrying values of its equipment inventories in
the amounts of $3.6 million and $6.8 million as of December 31, 2002 and 2001,
respectively.
Inventories - commodities. Commodities are carried at the lower of
average cost or market. When sold from inventory, commodities are removed 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
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 11 natural gas processing plants and five
treating facilities. The Company operates seven of the plants and all five
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,
2002, 2001 and 2000 were $28.4 million, $32.7 million and $36.3 million,
respectively. The third party expenses attributable to the plants and treating
facilities for those same periods were $9.3 million, $9.7 million and $9.0
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.
50
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2002, 2001 and 2000
Capitalized costs relating to proved properties are depleted using the
unit-of-production method based on proved reserves. 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
completed and proved reserves are established or, if unsuccessful, 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, 2002 and 2001, the Company has
recognized plugging and abandonment liabilities of $34.7 million and $39.5
million, respectively. See "New accounting pronouncements" for a discussion of
the provisions of SFAS 143 that will be adopted by the Company on January 1,
2003.
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, if any, are aggregated and an overall impairment
allowance is provided based on the Company's historical experience.
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 Company's
entitlement assets and entitlement liabilities and their associated volumes as
of December 31, 2002 and 2001 (in millions):
51
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2002, 2001 and 2000
December 31,
---------------------------------
2002 2001
--------------- ---------------
Amount MMcf Amount MMcf
------ ------ ------ ------
Entitlement assets....................... $ 9.7 4,240 $ 30.9 25,335
Entitlement liabilities.................. $ 15.1 14,302 $ 20.3 15,197
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 were classified as
components of the commodity prices, interest or foreign exchange rates that the
derivative instrument hedged. Derivative instruments that were not hedges were
recorded at fair value, as assets or liabilities. Changes in the fair values of
non-hedge derivative instruments were recognized as other income or other
expense during the periods in which their fair values changed.
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 Accumulated other comprehensive
income ("AOCI") - deferred hedge gains, net in the stockholders' equity section
of the Company's Consolidated Balance Sheets 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) on 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
52
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2002, 2001 and 2000
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 expectation of hedge effectiveness must be
supported by matching the essential terms of the hedged asset, liability or
forecasted transaction to the derivative hedge contract or by effectiveness
assessments using statistical measurements. The Company's policy is to assess
actual hedge effectiveness at the end of each calendar quarter.
See Note J for a description of the specific types of derivative
transactions in which the Company participates.
Stock-based compensation. The Company has a long-term incentive plan (the
"Long-Term Incentive Plan") under which the Company grants stock-based
compensation. The Long-Term Incentive Plan is described more fully in Note G.
The Company accounts for stock-based compensation granted under the Long-Term
Incentive Plan using the intrinsic value method prescribed by Accounting
Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees"
("APB 25") and related interpretations. Stock-based compensation expenses were
not recognized in net income, as all options granted under the Long-Term
Incentive Plan had exercise prices equal to the market value of the underlying
common stock on the dates of grant. The following table illustrates the effect
on net income and earnings per share if the Company had applied the fair value
recognition provisions of Statement of Financial Accounting Standards No. 123,
"Accounting for Stock-Based Compensation" ("SFAS 123") to stock-based employee
compensation:
Year ended December 31,
--------------------------------
2003 2002 2001
-------- -------- --------
(in thousands, except per share amounts)
Net income, as reported............................... $ 26,713 $ 99,996 $152,181
Deduct: Total stock-based employee compensation
expense determined under fair value based
method for all awards, net of related tax effects... (9,807) (6,533) (4,163)
------- ------- -------
Pro forma net income.................................. $ 16,906 $ 93,463 $148,018
======= ======= =======
Net income per share:
Basic - as reported................................. $ .24 $ 1.01 $ 1.53
======= ======= =======
Basic - pro forma................................... $ .15 $ .95 $ 1.49
======= ======= =======
Diluted - as reported............................... $ .23 $ 1.00 $ 1.53
======= ======= =======
Diluted - pro forma................................. $ .15 $ .94 $ 1.48
======= ======= =======
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 assets 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
53
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2002, 2001 and 2000
recorded in the accompanying Consolidated Statements of Stockholders' Equity for
the period through accumulated other comprehensive income (loss).
The exchange rates used to translate the financial statements of the
Company's Canadian subsidiary in the preparation of these consolidated financial
statements appear below:
December 31,
-----------------------
2002 2001 2000
----- ----- -----
Translation:
U.S. Dollar from Canadian Dollar - Balance Sheets.............. .6362 .6277 .6671
U.S. Dollar from Canadian Dollar - Statements of Operations.... .6371 .6356 .6650
Reclassifications. Certain reclassifications have been made to the 2001
and 2000 amounts to conform to the 2002 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, 2002 and 2001:
2002 2001
--------------------- ----------------------
Carrying Fair Carrying Fair
Value Value Value Value
--------- --------- --------- ----------
(in thousands)
Derivative contract assets (liabilities):
Commodity price hedges.................... $(108,837) $(108,837) $ 151,290 $ 151,290
Btu swap contracts........................ $ (13,363) $ (13,363) $ (19,422) $ (19,422)
Interest rate swaps....................... $ - $ - $ (19,637) $ (19,637)
Foreign currency contracts................ $ 15 $ 15 $ 61 $ 61
Financial assets:
Trading securities........................ $ 236 $ 236 $ - $ -
5-1/2% note receivable due 2008........... $ 2,247 $ 2,283 $ - $ -
Financial liabilities - long-term debt:
Line of credit............................ $(260,000) $(260,000) $(294,000) $(294,000)
8-7/8% senior notes due 2005.............. $(146,704) $(147,318) $(161,998) $(159,000)
8-1/4% senior notes due 2007.............. $(161,130) $(164,925) $(153,672) $(154,215)
6-1/2% senior notes due 2008.............. $(362,592) $(359,205) $(332,613) $(329,280)
9-5/8% senior notes due 2010.............. $(338,197) $(406,901) $(385,110) $(421,508)
7-1/2% senior notes due 2012.............. $(150,000) $(160,635) $ - $ -
7-1/5% senior notes due 2028.............. $(249,913) $(245,025) $(249,911) $(204,175)
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.
Commodity price swap and collar contracts, interest rate swaps and
foreign currency swap contracts. The fair value of commodity price swap and
collar contracts, interest rate swaps and foreign currency 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 to settle the derivative contracts. During the year ended
December 31, 2002, the Company terminated all of its interest rate swaps and the
Company's foreign currency contracts matured. See Note J 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.
54
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2002, 2001 and 2000
Financial assets. As of December 31, 2002, the Company had an investment
in bonds that were classified as trading securities and a note receivable. The
Company divested the bonds during January 2003. The fair value of the 5-1/2
percent note receivable was determined based on underlying market rates of
interest.
Long-term debt. The carrying amount of borrowings outstanding under the
Company's corporate credit facility approximates fair value because these
instruments bear interest at variable market rates. The fair values of each of
the senior note issuances were determined based on quoted market prices for each
of the issues. See Note E for additional information regarding the Company's
long-term debt.
NOTE D. Acquisitions
Falcon acquisitions. During the year ended December 31, 2002, the Company
purchased, through two transactions, an additional 30 percent working interest
in the Falcon field development and a 25 percent working interest in associated
acreage in the deepwater Gulf of Mexico for a combined purchase price of $61.1
million. As a result of these transactions, the Company owns a 75 percent
working interest in and operates the Falcon field development and related
exploration blocks.
West Panhandle acquisitions. During July 2002, the Company completed the
purchase of the remaining 23 percent of the rights that the Company did not
already own in its core area West Panhandle gas field, 100 percent of the West
Panhandle reserves attributable to field fuel, 100 percent of the related West
Panhandle field gathering system and ten blocks surrounding the Company's
deepwater Gulf of Mexico Falcon discovery. In connection with these
transactions, the Company recorded $100.4 million to proved oil and gas
properties, $3.8 million to unproved oil and gas properties and $1.9 million to
assets held for resale; retired a capital cost obligation for $60.8 million;
settled a $20.9 million gas balancing receivable; assumed trade and
environmental obligations amounting to $5.8 million in the aggregate; and paid
$140.2 million of cash. The capital cost obligation retired by the Company for
$60.8 million represented an obligation for West Panhandle gas field capital
additions that was not able to be prepaid and bore interest at an annual rate of
20 percent. The portion of the purchase price allocated to the retirement of the
capital cost obligation was based on a discounted cash flow analysis using a
market discount rate for obligations with similar terms. The capital cost
obligation had a carrying value of $45.2 million, resulting in an extraordinary
loss of $15.6 million from the early extinguishment of this obligation.
Affiliated partnership mergers. During 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 Natural Resources USA, Inc.
("Pioneer USA"), a wholly-owned subsidiary of the Company, 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
5.7 million shares of the Company's common stock valued at $18.35 per share. In
connection with this transaction, the Company recorded $92.9 million to proved
oil and gas properties, $13.6 million to cash and $.3 million to 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.
During 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 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.
Other acquisitions. During the year ended December 31, 2002, in addition
to the Falcon and West Panhandle acquisitions referred to above, the Company
spent approximately $25.5 million to acquire additional unproved acreage in the
United States, including 34 Gulf of Mexico shelf blocks, six deepwater Gulf of
Mexico blocks, a 70 percent
55
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2002, 2001 and 2000
working interest in ten state leases on Alaska's North Slope and property
interests in other areas of the United States. Also during 2002, the Company
acquired unproved and proved oil and gas property interests in Canada for 2.3
million and $.5 million, respectively, and $1.8 million of additional unproved
property interests in Tunisia. During 2001, the Company spent $77.9 million 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 deepwater 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 spent $65.0 million to
acquire additional working interests in the United States Gulf of Mexico
discovery at Devils Tower and the Chinchaga gas field in Canada, an interest in
the Camden Hills deepwater Gulf of Mexico discovery and the Canyon Express
gathering system.
NOTE E. Long-term Debt
Long-term debt, including the effects of fair value hedges and discounts,
consisted of the following components at December 31, 2002 and 2001:
December 31,
---------------------------
2002 2001
---------- -----------
(in thousands)
Line of credit............................... $ 260,000 $ 294,000
8-7/8% senior notes due 2005................. 146,704 161,998
8-1/4% senior notes due 2007................. 161,130 153,672
6-1/2% senior notes due 2008................. 362,592 332,613
9-5/8% senior notes due 2010................. 338,197 385,110
7-1/2% senior notes due 2012................. 150,000 -
7-1/5% senior notes due 2028................. 249,913 249,911
--------- ---------
$1,668,536 $1,577,304
========= =========
Maturities of long-term debt at December 31, 2002 are as follows (in
thousands):
2003 and 2004................... $ -
2005............................ $ 406,704
2006............................ $ -
2007............................ $ 161,130
Thereafter...................... $1,100,702
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 (4.25 percent at
December 31, 2002) 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 (1.16 percent at December 31, 2002), 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") (1.38 percent at December 31, 2002 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 rating 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 charges and
expenses (the "Total Leverage Ratio"). As of December 31, 2002, the Eurodollar
Margin was 137.5 basis points.
56
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2002, 2001 and 2000
The Credit Agreement imposes certain restrictive covenants on the
Company, including the maintenance of a Total Leverage Ratio not to exceed 3.75
to 1.00; 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 was in compliance with all of its debt covenants as of December 31,
2002.
As of December 31, 2002 and 2001, the Company had $27.2 million and $27.9
million of undrawn letters of credit issued under the Credit Agreement,
respectively, and unused Credit Agreement borrowing capacity of $287.8 million
and $253.1 million, respectively.
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. Interest on the Company's senior notes is payable
semiannually. Pioneer USA has fully and unconditionally guaranteed the senior
note issuances. See Note R for a discussion of Pioneer USA debt guarantees and
Consolidating Financial Statements.
During April 2002, the Company issued $150.0 million of 7-1/2 percent
senior notes due April 15, 2012 (the "7-1/2 percent senior notes"). The 7-1/2
percent senior notes were issued at a price equal to 100 percent of their
principal amount and resulted in net proceeds to the Company, after underwriting
discounts, commissions and costs of issuance, of $146.7 million. The net
proceeds from the issuance of the 7-1/2 percent senior notes were used to reduce
outstanding borrowings under the Credit Agreement. The 7-1/2 percent senior
notes and 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 in compliance with
all of its senior note covenants as of December 31, 2002.
Early extinguishment of debt and capital cost obligation. During the year
ended December 31, 2002, the Company repurchased $47.1 million of its
outstanding 9-5/8 percent senior notes, $13.9 million of its outstanding 8-7/8
percent senior notes and repaid a $45.2 million capital cost obligation. The
Company recognized extraordinary losses, net of taxes, of $6.7 million and $15.6
million associated with these debt extinguishments, respectively. See Note D for
additional information regarding the capital cost obligation that was repaid
during the year ended December 31, 2002.
During 2001, the Company redeemed the remaining $22.5 million of
outstanding 11-5/8 percent senior subordinated discount notes and $6.8 million
of outstanding 10-5/8 percent senior subordinated notes. Additionally, the
Company repurchased $38.7 million of its 9-5/8 percent senior notes during 2001.
Associated with these debt extinguishments, 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.
See Note B for a discussion of the classification of gains and losses on
the early extinguishment of debt after the adoption of SFAS 145 on January 1,
2003.
Interest expense. The following amounts have been incurred and charged to
interest expense for the years ended December 31, 2002, 2001 and 2000:
57
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2002, 2001 and 2000
Year ended December 31,
-------------------------------------
2002 2001 2000
--------- --------- -----------
(in thousands)
Cash payments for interest................................ $ 113,827 $ 129,992 $ 147,156
Accretion/amortization of discounts or premiums on loans.. 5,488 7,937 7,995
Amortization of deferred hedge gains (see Note J)......... (14,108) (2,750) -
Amortization of capitalized loan fees..................... 2,436 2,252 2,769
Kansas ad valorem tax (see Note I)........................ 375 1,250 1,935
Net change in accruals.................................... 48 (732) 2,097
-------- -------- ---------
Interest incurred....................................... 108,066 137,949 161,952
Less interest capitalized............................... (12,251) (5,991) -
-------- -------- ---------
Interest expense..................................... $ 95,815 $ 131,958 $ 161,952
======== ======== ========
NOTE F. Related Party Transactions
Activities with affiliated partnerships. Prior to 1992, the Company,
through its wholly-owned subsidiaries, sponsored 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. During 2001, the Company completed the merger of
42 of the limited partnerships into Pioneer USA. During 2000, the Company
completed the merger of the 13 employee partnerships into Pioneer USA. See Note
D for additional information regarding the mergers.
During 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 drilled in those
years. 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 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, 2002, 2001
and 2000:
2002 2001 2000
------ ------ ------
(in thousands)
Receipt of lease operating and supervision charges
in accordance with standard industry operating
agreements........................................... $1,495 $9,281 $9,222
Reimbursement of general and administrative expenses.... $ 127 $1,265 $1,550
NOTE G. 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
58
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2002, 2001 and 2000
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 $805 thousand, $652 thousand and $611 thousand for 2002, 2001
and 2000, respectively.
401(k) plan. The Pioneer Natural Resources USA, Inc. 401(k) and Matching
Plan (the "401(k) Plan") is a defined contribution plan established under the
Internal Revenue Code Section 401. The 401(k) Plan was formed by the merger of
the Pioneer Natural Resources USA, Inc. 401(k) Plan and the Pioneer Natural
Resources USA, Inc. Matching Plan on January 1, 2002. 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. Matching contributions are made to
the 401(k) Plan 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 the participant's contributions,
their Matching Contributions and allocations of the 401(k) Plan's earnings.
Participants are fully vested in their account balances except for Matching
Contributions and their proportionate share of 401(k) Plan earnings attributable
to Matching Contributions, which proportionately vest over a four year period
that begins with the participant's date of hire. During the years ended December
31, 2002, 2001 and 2000, the Company recognized compensation expense of $4.1
million, $3.4 million and $3.4 million, respectively, as a result of Matching
Contributions.
Long-Term Incentive Plan
In August 1997, the Company's stockholders approved 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 less 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.
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, 2002
and 2001:
December 31,
--------------------------
2002 2001
----------- -----------
Shares outstanding................................................ 117,252,538 103,936,394
Outstanding exercisable options or exercisable within 60 days..... 5,024,173 4,658,155
----------- -----------
122,276,711 108,594,549
=========== ===========
Maximum shares/options allowed under the Long-Term Incentive Plan. 12,227,671 10,859,455
Less: Outstanding awards under Long-Term Incentive Plan.......... (7,432,414) (6,377,520)
Outstanding options under predecessor incentive plans...... (488,671) (548,551)
----------- -----------
Shares/options available for future grant......................... 4,306,586 3,933,384
=========== ===========
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 (i) 100 percent restricted stock, (ii) 100 percent stock
options, (iii) 100 percent cash, or (iv) a combination of 50/50 of any two, 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 1,643,212; 1,627,071 and 1,439,035 options under the Long-Term Incentive
Plan during 2002, 2001 and 2000, respectively.
59
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2002, 2001 and 2000
Restricted stock awards. During the year ended December 31, 2002, the
Company issued 654,445 restricted shares of the Company's common stock. The
restricted awards were issued as compensation to directors, officers and key
employees of the Company. The restricted share awards include 18,545 shares that
were granted to directors of the Company on May 13, 2002. Director awards for
3,302 shares vest on a quarterly pro-rata basis during the year ended May 13,
2003 and director awards for 15,243 shares vest on May 13, 2005. The remaining
635,900 restricted shares were awarded to officers and key employees of the
Company on August 12, 2002 and vest on August 12, 2005. The Company recorded
$16.2 million of deferred compensation in the stockholder's equity section of
the accompanying Consolidated Balance Sheet associated with the restricted stock
awards, which amount will be amortized to compensation expense over the vesting
periods of the awards. During the year ended December 31, 2002, amortization of
the restricted stock awards increased the Company's compensation expense by $1.9
million.
The following table reflects the outstanding restricted stock awards and
activity related thereto for 2002:
For the Year Ended
December 31, 2002
---------------------
Weighted
Number Average
of Shares Price
--------- --------
Restricted Stock Awards:
Restricted shares outstanding at beginning of year........ - $ -
Shares granted............................................ 654,445 $ 24.72
Lapse of restrictions..................................... (1,652) $ 24.60
--------
Restricted shares outstanding at end of year................. 652,793 $ 24.72
========
There were no restricted stock awards to directors or employees during the
years ended December 31, 2001 and 2000.
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 and net income per share would have been
less than reported amounts. See Note B comparisons of net income and net income
per share as reported and as adjusted for the pro forma effects of determining
compensation expense in accordance with SFAS 123.
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 2002, 2001 and 2000:
For the Year Ended December 31,
----------------------------
2002 2001 2000
------- ------- --------
Risk-free interest rate............. 2.80% 4.13% 5.66%
Expected life....................... 5 years 5 years 5 years
Expected volatility................. 45% 49% 50%
Expected dividend yield............. - - -
60
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2002, 2001 and 2000
A summary of the Company's stock option plans as of December 31, 2002,
2001 and 2000, 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, 2002 December 31, 2001 December 31, 2000
--------------------- --------------------- ---------------------
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.. 6,926,071 $ 18.16 6,510,559 $ 18.10 6,241,889 $ 19.45
Options granted............... 1,643,212 $ 21.14 1,627,071 $ 18.29 1,439,035 $ 10.32
Options forfeited............. (154,717) $ 26.27 (566,189) $ 25.83 (798,058) $ 18.05
Options exercised............. (1,146,274) $ 12.19 (645,370) $ 11.14 (372,307) $ 10.78
---------- ---------- ----------
Outstanding, end of year........ 7,268,292 $ 19.60 6,926,071 $ 18.16 6,510,559 $ 18.10
========== ========== ==========
Exercisable at end of year...... 4,269,659 $ 20.15 4,005,762 $ 20.82 3,897,187 $ 23.47
========== ========== ==========
Weighted average fair value of
options granted during the
year............................ $ 8.87 $ 8.65 $ 4.88
========= ========= =========
The following table summarizes information about the Company's stock
options outstanding at December 31, 2002:
Options Outstanding Options Exercisable
------------------------------------------------------- --------------------------------------
Number Weighted Average Weighted Weighted
Range of Outstanding at Remaining Average Number Exercisable Average
Exercise Prices December 31, 2002 Contractual Life Exercise Price at December 31, 2002 Exercise Price
- --------------- ----------------- ---------------- -------------- -------------------- --------------
$ 5-11 800,715 3.9 years $ 8.35 619,504 $ 8.49
$ 12-18 3,805,527 4.9 years $ 16.69 1,714,584 $ 15.42
$ 19-26 1,288,548 4.9 years $ 24.13 562,069 $ 23.44
$ 27-30 1,323,242 1.1 years $ 29.59 1,323,242 $ 29.59
$ 31-52 50,260 2.6 years $ 39.88 50,260 $ 39.88
----------- -----------
7,268,292 4,269,659
=========== ===========
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 H. Issuance of Common Stock
During April 2002, the Company completed a public offering of 11.5
million shares of its common stock at $21.50 per share. Associated therewith,
the Company received $236.0 million of net proceeds after the payment of
issuance costs. The Company used the net proceeds from the public offering to
fund the acquisition of the Falcon assets and associated acreage in the
deepwater Gulf of Mexico and the West Panhandle gas field acquisitions. See Note
D for information regarding these acquisitions.
61
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2002, 2001 and 2000
NOTE I. 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 $18.2 million.
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.
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. Oral arguments were heard by the
court in April 2002, and although the court has not yet entered a judgment or
findings, it could do so at any time. 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. Although the amount of any resulting
liability could have a material adverse effect on the Company's results of
operations for the quarterly reporting period in which such liability is
recorded, 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 annual results of operations.
62
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2002, 2001 and 2000
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, one of the
Company's predecessor entities 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.
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 $30.2 million were made against the Company. Through December 31,
2002, the Company has settled $21.7 million of the original claim amounts, of
which $11.8 million was settled during 2002. The carrying value of the
obligation settled during 2002 exceeded the settlement paid by the Company by
$3.5 million. Accordingly, the Company recognized other income of $3.5 million
during 2002. As of December 31, 2002 and December 31, 2001, the Company had on
deposit $10.6 million and $24.5 million, respectively, including accrued
interest, in an escrow account and had corresponding obligations for the
remaining claims recorded in other current liabilities in the accompanying
Consolidated Balance Sheets. The Company believes that the escrowed amounts,
plus accrued interest, will be sufficient to settle the remaining claims.
Lease agreements. The Company leases offshore production facilities,
equipment and office facilities under noncancellable operating leases on which
rental expense for the years ended December 31, 2002, 2001 and 2000 was
approximately $6.7 million, $6.6 million and $7.0 million, respectively. Future
minimum lease commitments under noncancellable operating leases at December 31,
2002 are as follows (in thousands):
2003.......................................... $ 19,364
2004.......................................... $ 41,553
2005.......................................... $ 39,375
2006.......................................... $ 32,266
2007.......................................... $ 26,258
Thereafter.................................... $ 36,338
63
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2002, 2001 and 2000
Transportation agreements. The Company's wholly-owned Canadian subsidiary
is a party to pipeline transportation service agreements, with remaining terms
of approximately 13 years, whereby it has committed to transport a specified
volume of gas each year from Canada to a point in Chicago, Illinois. Such gas
volumes are comprised of a significant portion of the Company's Canadian net
production, augmented with certain volumes purchased at market prices in Canada.
The committed volumes to be transported under the pipeline transportation
service agreements are approximately 84 MMcf of gas per day during 2003 and
decline to approximately 80 MMcf of gas per day by the end of the commitment
term. The net gas marketing gains or losses resulting from purchasing third
party gas in Canada and selling it in Chicago are recorded as other income or
other expense in the accompanying Consolidated Statements of Operations.
Associated with these agreements, the Company recognized $2.6 million and $9.9
million of gas marketing losses in other expenses during 2002 and 2001,
respectively.
NOTE J. 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 hedges. The Company monitors capital markets and trends to
identify opportunities to enter into interest rate swaps to minimize its costs
of capital. As of December 31, 2002, the Company was not a party to any fair
value hedges. As of December 31, 2001, the carrying value of the Company's fair
value hedges was a liability of $19.6 million.
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 and 8-1/4 percent senior notes, respectively. The terms of the interest
rate swap agreements matched the notional amounts and scheduled maturities of
the bonds; required the counterparties to pay the Company a fixed annual
interest rate equal to the stated bond coupon rates on the notional amounts; and
required the Company to pay the counterparties variable annual interest rates on
the notional amounts equal to the periodic six-month LIBOR plus weighted
average margin rates of 178.2 basis points and 238.1 basis points on the 8-7/8
percent senior notes and 8-1/4 percent senior notes; respectively. During
September 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.
During April 2002 the Company entered into interest rate swap agreements
to hedge the fair value of the Company's 8-7/8 percent senior notes and, during
November 2001, the Company entered into interest rate swap agreements to hedge
the fair value of its 6-1/2 percent senior notes and 8-1/4 percent senior notes.
The terms of the interest rate swap agreements matched the notional amounts and
scheduled maturities of the bonds; required the counterparties to pay the
Company fixed annual interest rates equal to the stated bond coupon rates on the
notional amounts; and required the Company to pay the counterparties variable
annual interest rates on the notional amounts equal to the periodic six-month
LIBOR plus weighted average margin rates of 397 basis points, 202.2 basis
points, and 337 basis points on the 8-7/8 percent senior notes, 6-1/2 percent
senior notes and 8-1/4 percent senior notes; respectively. During September
2002, the Company terminated these interest rate swaps for $36.3 million of cash
proceeds, including accrued interest.
As of December 31, 2002, the carrying value of the Company's long-term
debt in the accompanying Consolidated Balance Sheets included $35.7 million of
incremental liability attributable to the unamortized deferred hedge gains
realized from the terminations of the Company's fair value hedge agreements
during 2002 and 2001. The amortization of these deferred hedge gains reduced the
Company's reported interest expense by $14.1 million and $2.8 million during the
years ended December 31, 2002 and 2001, respectively.
64
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2002, 2001 and 2000
The following table sets forth the scheduled amortization of deferred
hedge gains on terminated fair value hedges that will be recognized as
reductions in the Company's future interest expense:
First Second Third Fourth Outstanding
Quarter Quarter Quarter Quarter Total
------- ------- ------- ------- -----------
(in thousands)
2003 hedge gain amortization........... $ 5,937 $ 5,564 $ 4,735 $ 4,161 $ 20,397
2004 hedge gain amortization........... $ 3,518 $ 3,122 $ 2,458 $ 2,105 11,203
Remaining net gains to be amortized
through 2008......................... 4,072
-------
$ 35,672
=======
The terms of the fair value hedges described above perfectly matched 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 hedges. The Company utilizes, from time to time, 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 has also utilized 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
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, 2002:
Yearly
First Second Third Fourth Outstanding
Quarter Quarter Quarter Quarter Total
------- ------- ------- ------- -----------
Daily oil production:
2003 - Swap Contracts
Volume (Bbl).................... 19,900 23,000 23,000 23,000 22,236
Price per Bbl................... $ 24.59 $ 24.44 $ 24.40 $ 24.40 $ 24.45
2004 - Swap Contracts
Volume (Bbl).................... 14,000 14,000 14,000 14,000 14,000
Price per Bbl................... $ 23.11 $ 23.11 $ 23.11 $ 23.11 $ 23.11
The Company reports average oil prices per Bbl including the effects of
oil quality adjustments and the net effect of 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,
-----------------------------
2002 2001 2000
------- ------- -------
Average price reported per Bbl...................... $ 22.89 $ 24.12 $ 24.01
Average price realized per Bbl...................... $ 22.95 $ 23.88 $ 28.81
Addition (reduction) to revenue (in millions)....... $ (.8) $ 3.0 $ (60.1)
65
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2002, 2001 and 2000
Natural gas liquids prices. During the years ended December 31, 2002,
2001 and 2000, 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, 2002:
Yearly
First Second Third Fourth Outstanding
Quarter Quarter Quarter Quarter Average
--------- --------- --------- --------- -----------
Daily gas production:
2003 - Swap Contracts
Volume (Mcf)............... 230,000 230,000 230,000 230,000 230,000
Index price per MMBtu...... $ 3.76 $ 3.76 $ 3.76 $ 3.76 $ 3.76
2004 - Swap Contracts
Volume (Mcf)............... 180,000 180,000 180,000 180,000 180,000
Index price per MMBtu...... $ 3.81 $ 3.81 $ 3.81 $ 3.81 $ 3.81
2005 - Swap Contracts
Volume (Mcf)............... 10,000 10,000 10,000 10,000 10,000
Index price per MMBtu...... $ 3.70 $ 3.70 $ 3.70 $ 3.70 $ 3.70
2006 - Swap Contracts
Volume (Mcf)............... 20,000 20,000 20,000 20,000 20,000
Index price per MMBtu...... $ 3.75 $ 3.75 $ 3.75 $ 3.75 $ 3.75
2007 - Swap Contracts
Volume (Mcf)............... 20,000 20,000 20,000 20,000 20,000
Index price per MMBtu...... $ 3.75 $ 3.75 $ 3.75 $ 3.75 $ 3.75
The Company reports average gas prices per Mcf including the effects of
Btu content, gas processing and shrinkage adjustments and the net effect of 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,
----------------------------
2002 2001 2000
------ ------ ------
Average price reported per Mcf...................... $ 2.49 $ 3.23 $ 2.81
Average price realized per Mcf...................... $ 2.38 $ 3.20 $ 3.03
Addition/(reduction) to revenue (in millions)....... $ 13.6 $ 3.0 $(29.0)
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 provided for an aggregate notional amount of $55
million of debt; commenced on May 21, 2001 and matured on May 20, 2002; required
the counterparties to pay the Company a variable rate equal to the periodic
six-month LIBOR plus 125 basis points; and, required the Company to pay the
counterparties a weighted average annual rate of 5.43 percent on the notional
amount. The Company recognized interest expense of $447 thousand and $185
thousand associated with these interest rate swap agreements during the years
ended December 31, 2002 and 2001, respectively. The Company recognized no
ineffectiveness associated with changes in the fair values of these derivative
instruments.
66
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2002, 2001 and 2000
Foreign currency rates. During 2001, the Company entered into forward
agreements to exchange an aggregate $24.8 million U.S. dollars for Canadian
dollars at a weighted average exchange rate of .6266 U.S. dollars for 1.0
Canadian dollar. These agreements were designated as hedges of the Company's
exchange rate risk associated with Canadian sales of gas under U.S. dollar
denominated sales agreements. The Company recognized settlement gains of $249
thousand associated with these forward agreements during the year ended December
31, 2002, which increased the Company's reported gas price. The Company did not
recognize any ineffectiveness associated with changes in the fair values of
these derivative instruments. Except for one forward agreement that represented
an asset of $15 thousand to the Company on December 31, 2002, these agreements
matured during the year ended December 31, 2002.
Hedge ineffectiveness and excluded items. During the years ended
December 31, 2002 and 2001, the Company recognized other expense of $1.7 million
and $9.1 million, respectively, 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 three
month period ended March 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 records the effective portions
of deferred cash flow hedge gains and losses in AOCI - deferred hedge gains,
net. Once the underlying hedged transaction occurs the deferred hedge gain or
loss is reclassified from AOCI - deferred hedge gains, net to earnings. If it is
determined that the underlying hedged transaction is not likely to occur, the
deferred hedge gain or loss is reclassified from AOCI - deferred hedge gains,
net to other income or other expense during the period in which it is determined
that the underlying hedged transaction is not likely to occur. As of December
31, 2002 and 2001, AOCI - deferred hedge gains, net represented net deferred
gains of $9.6 million and $201.0 million, respectively. The AOCI - deferred
hedge gains, net balance as of December 31, 2002 was comprised of $107.8 million
of unrealized deferred hedge losses on the effective portions of open commodity
cash flow hedges and $117.4 million of net deferred gains on terminated cash
flow hedges. The AOCI - deferred hedge gains, net balance as of December 31,
2001 was comprised of $177.7 million of unrealized deferred 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 decrease in AOCI - deferred hedge gains, net during the year ended
December 31, 2002 was primarily attributable to increases in future commodity
prices relative to the commodity prices stipulated in the hedge agreements and
the reclassification of deferred hedge gains to net income as derivatives
matured by their terms. The unrealized deferred hedge gains and losses
associated with open cash flow hedges remain subject to market price
fluctuations until the positions are either settled under the terms of the hedge
agreements or terminated prior to settlement. The net deferred gains and losses
on terminated cash flow hedges are fixed.
During the twelve month period ending December 31, 2003, the Company
expects to reclassify $73.6 million of net deferred losses associated with open
cash flow hedges and $72.1 million of net deferred gains on terminated cash flow
hedges from AOCI - deferred hedge gains, net to oil and gas revenue.
The following table sets forth the scheduled reclassifications of
deferred hedge gains on terminated cash flow hedges that will be recognized in
the Company's future oil and gas revenues:
First Second Third Fourth Total
Quarter Quarter Quarter Quarter Year
-------- --------- -------- -------- ---------
(in thousands)
2003 deferred hedge gains......... $ 18,123 $ 18,043 $ 18,021 $ 17,864 $ 72,051
2004 deferred hedge gains......... $ 11,206 $ 11,156 $ 11,226 $ 11,175 44,763
2005 deferred hedge gains......... $ 149 $ 153 $ 156 $ 158 616
--------
$ 117,430
========
67
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2002, 2001 and 2000
Non-hedge Derivatives
Btu swap agreements. The Company is a party to Btu swap agreements that
mature at the end of 2004. The Btu swap agreements do not qualify for hedge
accounting treatment. The Company recorded mark-to-market adjustments to
decrease the carrying value of the Btu swap liability by $.7 million during the
year ended December 31, 2001 and to increase the carrying value of the Btu swap
liability by $14.6 million during the year ended December 31, 2000.
During the year ended December 31, 2001, the Company entered into
offsetting Btu swap agreements that 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 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 a mark-to-market adjustment to increase the
carrying value of the foreign exchange swap liabilities by $1.9 million during
the year ended December 31, 2000.
Other non-hedge commodity derivatives. During the year ended December 31,
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 the year ended
December 31, 2000, did not qualify for hedge accounting treatment. The Company
recorded mark-to-market adjustments to increase the carrying value of the
associated contract liability by $42.0 million during the year ended December
31, 2000.
NOTE K. 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 one or more of
the years ended December 31, 2002, 2001 and 2000:
Percentage of Consolidated
Oil, NGL and Gas Revenues
---------------------------------
2002 2001 2000
-------- -------- --------
Williams Energy Services............. 7 11 13
Anadarko Petroleum Corporation....... 7 10 6
At December 31, 2002, the amounts receivable from Williams Energy
Services and Anadarko Petroleum Corporation were $13.4 million and $11.7
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, 2002 and 2001, the Company has $7.6 million of derivative assets
for which Enron North America Corp was the Company's counterparty. Associated
therewith, the Company recognized bad debt expense of $.4 million and $6.0
million during the years ended December 31, 2002 and 2001, respectively, which
amounts are included in other expense in the accompanying Consolidated
Statements of Operations.
68
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2002, 2001 and 2000
NOTE L. Interest and Other Income
The Company recorded interest and other income of $11.2 million, $21.8
million and $25.8 million during the years ended December 31, 2002, 2001 and
2000. The major categories of the Company's interest and other income are
summarized in the following table:
Year Ended December 31,
--------------------------------
2002 2001 2000
-------- -------- --------
(in thousands)
Kansas ad valorem escrow adjustments (see Note I)...... $ 3,500 $ 1,100 $ 1,000
Excise tax income...................................... 2,398 4,126 6,915
Production payment income.............................. - 5,552 1,262
Interest income........................................ 642 2,128 3,906
Seismic data sales..................................... 87 1,841 1,148
Foreign exchange gains................................. 142 223 220
Other income........................................... 4,453 6,808 11,324
------- ------- -------
$ 11,222 $ 21,778 $ 25,775
======= ======= =======
NOTE M. Asset Divestitures
During the years ended December 31, 2002, 2001 and 2000, the Company
completed asset divestitures for net proceeds of $118.9 million, $113.5 million
and $102.7 million, respectively. Associated therewith, the Company recorded
gains on disposition of assets of $4.4 million, $7.7 million and $34.2 million
during the years ended December 31, 2002, 2001 and 2000, respectively.
Hedge derivative divestitures. During the years ended December 31, 2002
and 2001, the Company terminated, prior to their scheduled maturity, hedge
derivatives for cash sales proceeds of $91.3 million and $85.4 million,
respectively. Net gains from these divestitures were deferred and are being
amortized over the original contract lives of the terminated derivatives as
reductions to interest expense or increases to oil and gas revenues. See Note J
for more information regarding deferred gains on terminated hedge derivatives.
Available for sale securities divestitures. During the year ended
December 31, 2000, the Company sold 3,370,982 shares of common stock of a
non-affiliated entity for $59.7 million, recording an associated gain on
disposition of assets of $34.3 million. During 2001, the Company sold its
remaining 613,250 shares of the non-affiliated entity for $12.7 million of cash
proceeds and recognized an associated gain on disposition of assets of $8.1
million.
Other United States divestitures. During the year ended December 31,
2002, the Company received $20.9 million of proceeds from the cash settlement of
a gas balancing receivable, $4.7 million from the sale of certain gas properties
located in Oklahoma and $1.8 million from the sale of other corporate assets.
Associated with these divestitures, the Company recorded net gains of $4.2
million.
During the year ended December 31, 2001, the Company sold other corporate
assets for $3.0 million of proceeds. Associated with the sale of these assets,
the Company recorded a net gain of $.4 million.
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.
Other international divestitures. During the year ended December 31,
2002, other Canadian and Argentine corporate assets were sold for $.2 million.
The Company recorded $.2 million of net gains associated with those
69
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2002, 2001 and 2000
divestitures. During the year ended December 31, 2001, the Company 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.
NOTE N. Other Expense
The following table provides the components of the Company's other
expense during the years ended December 31, 2002, 2001 and 2000:
Years Ended December 31,
--------------------------------
2002 2001 2000
-------- -------- --------
(in thousands)
Derivative ineffectiveness and mark-to-market
provisions (see Note J)................................ $ 1,664 $ 11,458 $ 58,518
Gas marketing losses (see Note I)......................... 2,556 9,850 -
Foreign currency remeasurement and exchange losses (a).... 7,623 8,474 80
Bad debt expense (see Note K)............................. 129 6,152 65
Other charges............................................. 5,284 3,654 8,568
------- ------- -------
$ 17,256 $ 39,588 $ 67,231
======= ======= =======
- ----------
(a) 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 has remeasured its Argentine peso-denominated
monetary net assets as of December 31, 2002 and 2001 and adjusted its lease
and well equipment inventory balances to market values as of December 31,
2001. Associated therewith, the Company recognized charges of $6.9 million
and $7.7 million during 2002 and 2001, respectively.
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 $2.3 million, $11.7 million
and $4.6 million were made during the years ended December 31, 2002, 2001 and
2000, respectively. During the years ended December 31, 2002, 2001 and 2000, the
Company's income tax provision (benefit) and amounts separately allocated were
attributable to the following items:
Year Ended December 31,
--------------------------------
2002 2001 2000
-------- -------- --------
(in thousands)
Income (loss) before extraordinary items....... $ 5,063 $ 4,016 $ (6,000)
Changes in other comprehensive income:
Deferred hedge gains and losses.............. (2,561) 2,293 -
Cumulative translation adjustment............ (20) (121) (200)
------- ------- -------
$ 2,482 $ 6,188 $ (6,200)
======= ======= =======
70
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2002, 2001 and 2000
Income tax provision (benefit) attributable to income (loss) before
extraordinary items consists of the following:
Year Ended December 31,
-----------------------------------
2002 2001 2000
--------- --------- ---------
(in thousands)
Current:
U.S. state and local................ $ 209 $ 1,080 $ -
Foreign............................. 2,066 10,585 4,600
-------- -------- --------
2,275 11,665 4,600
-------- -------- --------
Deferred:
Foreign............................. 2,788 (7,649) (10,600)
-------- -------- --------
Total................................. $ 5,063 $ 4,016 $ (6,000)
======== ======== ========
Income (loss) before income taxes and extraordinary items consists of the
following:
Year Ended December 31,
-----------------------------------
2002 2001 2000
--------- --------- ---------
(in thousands)
Income (loss) before income taxes
and extraordinary items:
U.S. federal........................ $ 58,821 $ 140,045 $ 138,941
Foreign............................. (4,699) (32,280) 19,558
-------- -------- --------
$ 54,122 $ 107,765 $ 158,499
======== ======== ========
Reconciliations of the United States federal statutory rate to the
Company's effective rate for income (loss) before extraordinary items are as
follows:
2002 2001 2000
------- ------ ------
U.S. federal statutory tax rate....... 35.0 35.0 35.0
Valuation allowance................... (23.7) (27.5) (30.9)
Rate differential on foreign
operations........................... (.1) (3.2) (2.9)
Other................................. (1.8) (.6) (5.0)
------- ------ ------
Consolidated effective tax rate....... 9.4 3.7 (3.8)
======= ====== ======
The tax effects of temporary differences that give rise to significant
portions of the deferred tax assets and deferred tax liabilities are as follows:
December 31,
----------------------
2002 2001
--------- ---------
(in thousands)
Deferred tax assets:
Net operating loss carryforwards..................... $ 299,495 $ 341,206
Alternative minimum tax credit carryforwards......... 1,565 1,565
Other................................................ 143,894 44,745
-------- --------
Total deferred tax assets.......................... 444,954 387,516
Valuation allowance.................................. (277,217) (183,122)
-------- --------
Net deferred tax assets............................ 167,737 204,394
-------- --------
Deferred tax liabilities:
Oil and gas properties, principally due to
differences in basis, depletion and the
deduction of intangible drilling costs
for tax purposes................................... 80,364 115,524
Other................................................ 5,393 11,919
-------- --------
Total deferred tax liabilities..................... 85,757 127,443
-------- --------
Net deferred tax asset............................. $ 81,980 $ 76,951
======== ========
71
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2002, 2001 and 2000
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 a valuation allowance of
$277.2 million against the carryforwards at December 31, 2002. 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, 2002, the Company had NOLs for United States, Canadian,
South African, Gabonese and Tunisian income tax purposes of $742.7 million,
$37.4 million, $40.3 million, $13.4 million and $8.7 million, respectively,
which are available to offset future regular taxable income in each respective
tax jurisdiction, if any. Additionally, at December 31, 2002, the Company has
alternative minimum tax net operating loss carryforwards ("AMT NOLs") in the
United States of $637.5 million, which are available to reduce future
alternative minimum taxable income, if any. These carryforwards expire as
follows:
U.S.
---------------------- Canada South Africa Gabon Tunisia
Expiration Date NOL AMT NOL NOL NOL NOL NOL
--------------- --------- --------- -------- --------- --------- --------
(in thousands)
December 31, 2005...... $ - $ - $ 31,637 $ - $ - $ -
December 31, 2006...... - - 5,738 - - -
December 31, 2007...... 13,320 - - - - -
December 31, 2008...... 112,508 104,574 - - - -
December 31, 2009...... 129,226 102,727 - - - -
December 31, 2010...... 124,859 110,961 - - - -
December 31, 2011...... 6,521 4,045 - - - -
December 31, 2012...... 68,334 58,723 - - - -
December 31, 2018...... 127,656 98,290 - - - -
December 31, 2019...... 145,999 144,837 - - - -
December 31, 2020...... 14,235 13,297 - - - -
Indefinite............. - - - 40,304 13,397 8,712
-------- -------- ------- -------- -------- -------
Total............... $ 742,658 $ 637,454 $ 37,375 $ 40,304 $ 13,397 $ 8,712
======== ======== ======= ======== ======== =======
The Company believes $160.0 million of the U.S. 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.
72
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2002, 2001 and 2000
United Other Headquarters Consolidated
States Argentina Canada Foreign and Other Total
---------- --------- --------- --------- ------------ ------------
(in thousands)
Year Ended December 31, 2002:
Oil and gas revenues..................... $ 573,289 $ 77,615 $ 50,876 $ - $ - $ 701,780
Interest and other....................... - - - - 11,222 11,222
Gain (loss) on disposition of assets..... 3,248 (3) 995 - 192 4,432
--------- -------- -------- -------- ---------- ---------
576,537 77,612 51,871 - 11,414 717,434
--------- -------- -------- -------- ---------- ---------
Production costs......................... 174,929 13,870 10,771 - - 199,570
Depletion, depreciation and amortization. 140,107 39,659 27,857 - 8,752 216,375
Exploration and abandonments............. 62,955 10,306 5,841 6,792 - 85,894
General and administrative............... - - - - 48,402 48,402
Interest................................. - - - - 95,815 95,815
Other.................................... - - - - 17,256 17,256
--------- -------- -------- -------- ---------- ---------
377,991 63,835 44,469 6,792 170,225 663,312
--------- -------- -------- -------- ---------- ---------
Income (loss) before income taxes and
extraordinary items.................... 198,546 13,777 7,402 (6,792) (158,811) 54,122
Income tax benefit (provision)........... (69,491) (4,822) (3,118) 2,377 69,991 (5,063)
--------- -------- -------- -------- ---------- ---------
Income (loss) before extraordinary items. $ 129,055 $ 8,955 $ 4,284 $ (4,415) $ (88,820) $ 49,059
========= ======== ======== ======== ========== =========
Cost incurred for long-lived assets...... $ 533,560 $ 35,121 $ 33,506 $ 70,268 $ - $ 672,455
========= ======== ======== ======== ========== =========
Segment assets (as of December 31)....... $2,375,505 $ 680,063 $ 176,110 $ 118,070 $ 105,368 $3,455,116
========= ======== ======== ======== ========== =========
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
========= ======== ======== ======== ========== =========
73
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2002, 2001 and 2000
NOTE Q. Income Per Share Before Extraordinary Items
Basic income per share before extraordinary items is computed by dividing
income before extraordinary items by the weighted average number of common
shares outstanding for the period. The computation of diluted income 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 Company.
The following table is a reconciliation of the basic and diluted weighted
average common shares outstanding for the years ended December 31, 2002, 2001
and 2000:
Year Ended December 31,
--------------------------------
2002 2001 2000
-------- -------- --------
(in thousands)
Weighted average common shares outstanding:
Basic......................................... 112,542 98,529 99,378
Dilutive common stock options (a)............. 1,725 1,185 385
Restricted stock awards (b)................... 21 - -
-------- -------- --------
Diluted....................................... 114,288 99,714 99,763
======== ======== ========
- ---------------
(a) Common stock options to purchase 1,925,743 shares, 3,595,880 shares and
4,911,749 shares of common stock were outstanding but not included in the
computations of diluted net income per share for 2002, 2001 and 2000,
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.
(b) During the year ended December 31, 2002, the Company issued 654,445
restricted shares of the Company's common stock. The restricted shares were
issued as compensation to directors, officers and key employees of the
Company. The restricted shares include 18,545 shares that were granted to
directors of the Company on May 13, 2002. Director awards for 3,302 shares
vest on a quarterly pro-rata basis during the year ended May 13, 2003, and
director awards for 15,243 shares vest on May 13, 2005. The remaining
635,900 restricted shares were awarded to officers and key employees of the
Company on August 12, 2002 and vest on August 12, 2005.
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
E 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, 2002 and 2001, and Consolidating Statements of Operations and Comprehensive
Income (Loss) and Consolidating Condensed Statements of Cash Flows for the years
ended December 31, 2002, 2001 and 2000 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.
74
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2002, 2001 and 2000
CONSOLIDATING CONDENSED BALANCE SHEET
As of December 31, 2002
Pioneer
Natural
Resources Non-
Company Pioneer Guarantor The
(Parent) USA Subsidiaries Eliminations Company
----------- ----------- ------------ ------------ -----------
(in thousands)
ASSETS
Current assets:
Cash and cash equivalents............... $ 6 $ 1,783 $ 6,701 $ $ 8,490
Other current assets.................... 1,727,828 (1,480,657) (108,568) 138,603
---------- ---------- --------- ----------
Total current assets................ 1,727,834 (1,478,874) (101,867) 147,093
---------- ---------- --------- ----------
Property, plant and equipment, at cost:
Oil and gas properties, using the
successful efforts method of
accounting:
Proved properties..................... - 3,024,845 1,228,052 4,252,897
Unproved properties................... - 43,969 175,104 219,073
Accumulated depletion, depreciation
and amortization...................... - (947,091) (356,450) (1,303,541)
---------- ---------- --------- ----------
- 2,121,723 1,046,706 3,168,429
---------- ---------- ---------- ----------
Deferred income taxes..................... 75,311 - 1,529 76,840
Other property and equipment, net......... - 19,000 3,784 22,784
Other assets, net......................... 16,067 14,231 9,672 39,970
Investment in subsidiaries................ 1,247,042 136,159 - (1,383,201) -
---------- ---------- --------- ----------
$ 3,066,254 $ 812,239 $ 959,824 $ 3,455,116
========== ========== ========= ==========
LIABILITIES AND STOCKHOLDERS' EQUITY
Total current liabilities................. $ 30,785 $ 216,065 $ 27,742 $ $ 274,592
Long-term debt, less current maturities... 1,668,536 - - 1,668,536
Other noncurrent liabilities.............. - 147,970 (19,639) 128,331
Deferred income taxes..................... - - 8,760 8,760
Stockholders' equity...................... 1,366,933 448,204 942,961 (1,383,201) 1,374,897
Commitments and contingencies............. - - - -
---------- ---------- --------- ----------
$ 3,066,254 $ 812,239 $ 959,824 $ 3,455,116
========== ========== ========= ==========
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
========== ========== ========= ==========
75
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2002, 2001 and 2000
CONSOLIDATING CONDENSED STATEMENT OF OPERATIONS
AND COMPREHENSIVE LOSS
For the Year Ended December 31, 2002
(in thousands)
Pioneer
Natural
Resources Non- Consolidated
Company Pioneer Guarantor Income Tax The
(Parent) USA Subsidiaries Provision Eliminations Company
--------- --------- ------------ ------------ ------------ ---------
Revenues and other income:
Oil and gas........................... $ - $ 527,189 $ 174,591 $ - $ $ 701,780
Interest and other.................... - 8,214 3,008 - 11,222
Gain on disposition of assets, net.... - 3,230 1,202 - 4,432
-------- -------- -------- --------- --------
- 538,633 178,801 - 717,434
-------- -------- -------- --------- --------
Costs and expenses:
Oil and gas production................ - 165,669 33,901 - 199,570
Depletion, depreciation and
amortization......................... - 139,822 76,553 - 216,375
Exploration and abandonments.......... - 62,982 22,912 - 85,894
General and administrative............ 1,323 37,723 9,356 - 48,402
Interest.............................. 17,451 76,820 1,544 - 95,815
Equity (income) loss from subsidiary.. (52,580) 8,374 - - 44,206 -
Other................................. 405 4,879 11,972 - 17,256
-------- -------- -------- --------- --------
(33,401) 496,269 156,238 - 663,312
-------- -------- -------- --------- --------
Income before income taxes.............. 33,401 42,364 22,563 - 54,122
Income tax provision.................... - - (5,063) - (5,063)
-------- -------- -------- --------- --------
Income before extraordinary items....... 33,401 42,364 17,500 - 49,059
Extraordinary items - loss on early
extinguishment of debt................ (6,688) - (15,658) - (22,346)
-------- -------- -------- --------- --------
Net income.............................. 26,713 42,364 1,842 - 26,713
Other comprehensive income (loss):
Deferred hedge gains, net:
Deferred hedge losses............... (4) (156,396) (22,667) - (179,067)
Net (gains) losses included in net
income............................ 447 (10,352) (2,519) - (12,424)
Translation adjustment................ - - 2,188 - 2,188
-------- -------- -------- --------- --------
Comprehensive income (loss)............. $ 27,156 $(124,384) $ (21,156) $ - $(162,590)
======== ======== ======== ========= ========
76
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2002, 2001 and 2000
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 and other income:
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, net:
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
======== ======== ======== ======== ========
77
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2002, 2001 and 2000
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 and other income:
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, 2002, 2001 and 2000
CONSOLIDATING CONDENSED STATEMENT OF CASH FLOWS
For the Year Ended December 31, 2002
(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...... $ (327,185) $ 406,939 $ 252,491 $ 332,245
--------- -------- -------- ---------
Cash flows from investing activities:
Proceeds from disposition of assets...................... 31,994 86,703 153 118,850
Additions to oil and gas properties...................... - (365,981) (248,717) (614,698)
Other property (additions) retirements, net.............. - (13,171) 888 (12,283)
--------- -------- -------- ---------
Net cash provided by (used in) investing activities.. 31,994 (292,449) (247,676) (508,131)
--------- -------- -------- ---------
Cash flows from financing activities:
Borrowings under long-term debt.......................... 529,805 - - 529,805
Principal payments on long-term debt..................... (481,783) - - (481,783)
Issuance of common stock................................. 236,000 - - 236,000
Payments of noncurrent liabilities....................... - (123,607) (638) (124,245)
Deferred loan fees/issuance costs........................ (3,293) - - (3,293)
Exercise of stock options and employee stock purchases... 14,389 - - 14,389
--------- -------- -------- ---------
Net cash provided by (used in) financing activities.. 295,118 (123,607) (638) 170,873
--------- -------- -------- ---------
Net increase (decrease) in cash and cash equivalents....... (73) (9,117) 4,177 (5,013)
Effect of exchange rate changes on cash and cash
equivalents.............................................. - - (831) (831)
Cash and cash equivalents, beginning of period............. 79 10,900 3,355 14,334
--------- -------- -------- ---------
Cash and cash equivalents, end of period................... $ 6 $ 1,783 $ 6,701 $ 8,490
========= ======== ======== =========
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
========= ======== ======== =========
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, 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
UNAUDITED SUPPLEMENTARY INFORMATION
Years Ended December 31, 2002, 2001 and 2000
Capitalized Costs
December 31,
-------------------------
2002 2001
----------- -----------
(in thousands)
Oil and Gas Properties:
Proved................................................. $ 4,252,897 $ 3,691,783
Unproved............................................... 219,073 187,785
---------- ----------
4,471,970 3,879,568
Less accumulated depletion............................. (1,303,541) (1,095,310)
----------- ----------
Net capitalized costs for oil and gas properties....... $ 3,168,429 $ 2,784,258
========== ==========
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, 2002:
United States...................... $ 156,736 $ 34,048 $ 72,831 $ 269,945 $ 533,560
Argentina.......................... 12 51 14,530 20,528 35,121
Canada............................. 457 2,329 9,992 20,728 33,506
South Africa....................... - - 2,789 34,300 37,089
Gabon.............................. - - 23,585 - 23,585
Tunisia............................ - 1,843 6,320 - 8,163
Other foreign...................... - - 1,431 - 1,431
-------- -------- --------- --------- --------
Total costs incurred............. $ 157,205 $ 38,271 $ 131,478 $ 345,501 $ 672,455
======== ======== ========= ========= ========
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
Gabon.............................. - - 11,387 - 11,387
Tunisia............................ - 1,835 3,652 - 5,487
Other foreign...................... - - 4,471 - 4,471
-------- -------- --------- --------- --------
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
Gabon.............................. - - 1,326 - 1,326
Other foreign...................... - - 2,095 - 2,095
-------- -------- --------- --------- --------
Total costs incurred............. $ 35,980 $ 31,225 $ 130,770 $ 141,765 $ 339,740
======== ======== ========= ========= ========
81
PIONEER NATURAL RESOURCES COMPANY
UNAUDITED SUPPLEMENTARY INFORMATION
Years Ended December 31, 2002, 2001 and 2000
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 as of December
31, 2002, which are located principally in the United States, Argentina, Canada,
South Africa and Tunisia, were based on evaluations audited by independent
petroleum engineers with respect to the Company's major properties and prepared
by the Company's engineers with respect to all other properties. The estimates
of the Company's proved oil and gas reserves as of December 31, 2001 and 2000
were 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 2002, 2001 and 2000
utilize respective oil prices of $29.67, $18.88 and $25.71 per Bbl (reflecting
adjustments for oil quality); respective NGL prices of $19.01, $11.58 and $16.74
per Bbl; and, respective gas prices of $3.37, $2.21 and $7.50 per Mcf
(reflecting adjustments for Btu content, 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.
82
PIONEER NATURAL RESOURCES COMPANY
UNAUDITED SUPPLEMENTARY INFORMATION
Years Ended December 31, 2002, 2001 and 2000
Oil and Gas Producing Activities:
2002 2001 2000
------------------------------ ----------------------------- -----------------------------
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............... 279,146 1,474,090 524,829 266,802 1,354,327 492,523 259,066 1,314,842 478,206
Revisions of previous estimates.. 61,529 5,983 62,525 (1,179) 41,039 5,661 19,295 63,912 29,947
Purchases of minerals-in-place... 8,634 83,361 22,528 24,943 63,113 35,462 1,237 28,071 5,916
New discoveries and extensions... 4,364 5,349 5,255 4,442 93,220 19,979 4,819 66,486 15,900
Production....................... (16,042) (84,812) (30,177) (15,862) (77,609) (28,796) (16,872) (83,930) (30,860)
Sales of minerals-in-place....... - - - - - - (743) (35,054) (6,586)
-------- --------- ------- ------- --------- ------- ------- --------- -------
Balance, December 31............. 337,631 1,483,971 584,960 279,146 1,474,090 524,829 266,802 1,354,327 492,523
ARGENTINA
Balance, January 1............... 35,669 471,150 114,193 35,843 408,282 103,890 29,797 415,620 99,067
Revisions of previous estimates.. (4,954) 47,829 3,017 (932) 4,460 (189) 1,411 (15,558) (1,182)
Purchases of minerals-in-place... - - - 170 31,700 5,453 - - -
New discoveries and extensions... 3,985 41,652 10,927 4,354 58,538 14,110 8,066 43,914 15,385
Production....................... (3,168) (28,550) (7,926) (3,766) (31,830) (9,071) (3,431) (35,694) (9,380)
-------- --------- ------- ------- --------- ------- ------- --------- -------
Balance, December 31............. 31,532 532,081 120,211 35,669 471,150 114,193 35,843 408,282 103,890
CANADA
Balance, January 1............... 2,659 132,061 24,669 4,066 132,919 26,219 3,970 145,251 28,179
Revisions of previous estimates.. 24 (1,150) (167) 212 15,067 2,723 429 (10,013) (1,240)
Purchases of minerals-in-place... - - - - - - 140 7,768 1,435
New discoveries and extensions... 68 6,070 1,080 81 5,644 1,022 138 6,132 1,160
Production....................... (390) (17,653) (3,333) (671) (18,426) (3,742) (611) (16,219) (3,315)
Sales of minerals-in-place....... - - - (1,029) (3,143) (1,553) - - -
-------- --------- ------- ------- --------- ------- ------- --------- -------
Balance, December 31............. 2,361 119,328 22,249 2,659 132,061 24,669 4,066 132,919 26,219
SOUTH AFRICA
Balance, January 1............... 7,685 - 7,685 5,552 - 5,552 - - -
Revisions of previous estimates.. 790 - 790 - - - - - -
Purchases of minerals-in-place... - - - 2,133 - 2,133 - - -
New discoveries and extensions... - - - - - - 5,552 - 5,552
-------- --------- ------- ------- --------- ------- ------- --------- -------
Balance, December 31............. 8,475 - 8,475 7,685 - 7,685 5,552 - 5,552
TUNISIA
Balance, January 1............... - - - - - - - - -
New discoveries and extensions... 845 - 845 - - - - - -
-------- --------- ------- ------- --------- ------- ------- --------- -------
Balance, December 31............. 845 - 845 - - - - - -
TOTAL
Balance, January 1............... 325,159 2,077,301 671,376 312,263 1,895,528 628,184 292,833 1,875,713 605,452
Revisions of previous
estimates (a).................. 57,389 52,662 66,165 (1,899) 60,566 8,195 21,135 38,341 27,525
Purchases of minerals-in-place... 8,634 83,361 22,528 27,246 94,813 43,048 1,377 35,839 7,351
New discoveries and extensions... 9,262 53,071 18,107 8,877 157,402 35,111 18,575 116,532 37,997
Production....................... (19,600) (131,015) (41,436) (20,299) (127,865) (41,609) (20,914) (135,843) (43,555)
Sales of minerals-in-place....... - - - (1,029) (3,143) (1,553) (743) (35,054) (6,586)
-------- --------- ------- ------- --------- ------- ------- --------- -------
Balance, December 31............. 380,844 2,135,380 736,740 325,159 2,077,301 671,376 312,263 1,895,528 628,184
======== ========= ======= ======= ========= ======= ======= ========= =======
Proved Developed Reserves:
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
-------- --------- ------- ------- --------- ------- ------- --------- -------
January 1.................... 227,227 1,464,324 471,281 232,531 1,507,826 483,836 235,165 1,538,310 491,551
======== ========= ======= ======= ========= ======= ======= ========= =======
United States.................. 209,948 1,067,701 387,899 196,893 1,027,750 368,184 206,922 1,081,592 387,188
Argentina...................... 22,180 402,640 89,287 28,248 341,967 85,243 22,679 345,281 80,226
Canada......................... 2,042 90,003 17,042 2,086 94,607 17,854 2,930 80,953 16,422
-------- --------- ------- ------- --------- ------- ------- --------- -------
December 31.................. 234,170 1,560,344 494,228 227,227 1,464,324 471,281 232,531 1,507,826 483,836
======== ========= ======= ======= ========= ======= ======= ========= =======
- -------------
(a) The revisions of previous estimates above, include revisions attributable
to changes in commodity prices totaling a 28,643 MBOE increase, a 24,970
MBOE decrease and a 14,009 MBOE increase for the years ended December 31,
2002, 2001 and 2000, respectively.
83
PIONEER NATURAL RESOURCES COMPANY
UNAUDITED SUPPLEMENTARY INFORMATION
Years Ended December 31, 2002, 2001 and 2000
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, 2002 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 a liability equal to approximately $226 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.
84
PIONEER NATURAL RESOURCES COMPANY
UNAUDITED SUPPLEMENTARY INFORMATION
Years Ended December 31, 2002, 2001 and 2000
For the Year Ended December 31,
-----------------------------------------
2002 2001 2000
----------- ----------- -----------
(in thousands)
UNITED STATES Oil and gas producing activities:
Future cash inflows.................................. $15,161,717 $ 8,222,573 $18,660,169
Future production costs.............................. (4,830,294) (3,231,730) (4,907,134)
Future development costs............................. (864,386) (735,984) (479,290)
Future income tax expense............................ (2,325,946) (598,612) (3,777,157)
---------- ---------- ----------
7,141,091 3,656,247 9,496,588
10% annual discount factor.............................. (3,684,400) (1,691,118) (4,780,133)
---------- ---------- ----------
Standardized measure of discounted future cash flows.... $ 3,456,691 $ 1,965,129 $ 4,716,455
========== ========== ==========
ARGENTINA
Oil and gas producing activities:
Future cash inflows.................................. $ 986,716 $ 1,070,664 $ 1,183,652
Future production costs.............................. (175,938) (227,435) (215,853)
Future development costs............................. (84,669) (144,604) (114,606)
Future income tax expense............................ (143,845) (45,140) (81,705)
---------- ---------- ----------
582,264 653,485 771,488
10% annual discount factor.............................. (242,158) (262,334) (264,126)
---------- ---------- ----------
Standardized measure of discounted future cash flows.... $ 340,106 $ 391,151 $ 507,362
========== ========== ==========
CANADA
Oil and gas producing activities:
Future cash inflows.................................. $ 502,260 $ 301,002 $ 1,029,007
Future production costs.............................. (89,246) (73,601) (104,189)
Future development costs............................. (22,294) (27,050) (35,443)
Future income tax expense............................ (87,363) (10,771) (306,399)
---------- ---------- ----------
303,357 189,580 582,976
10% annual discount factor.............................. (104,345) (59,995) (168,441)
---------- ---------- ----------
Standardized measure of discounted future cash flows.... $ 199,012 $ 129,585 $ 414,535
========== ========== ==========
SOUTH AFRICA
Oil and gas producing activities:
Future cash inflows.................................. $ 256,436 $ 149,777 $ 126,134
Future production costs.............................. (92,820) (73,697) (65,232)
Future development costs............................. (23,200) (54,281) (47,970)
Future income tax expense............................ (4,465) - -
---------- ---------- ----------
135,951 21,799 12,932
10% annual discount factor.............................. (14,588) (7,338) (5,782)
---------- ---------- ----------
Standardized measure of discounted future cash flows.... $ 121,363 $ 14,461 $ 7,150
========== ========== ==========
TUNISIA
Oil and gas producing activities:
Future cash inflows.................................. $ 23,460 $ - $ -
Future production costs.............................. (2,396) - -
Future development costs............................. (3,570) - -
Future income tax expense............................ (6,447) - -
---------- ---------- ----------
11,047 - -
10% annual discount factor.............................. (1,667) - -
---------- ---------- ----------
Standardized measure of discounted future cash flows.... $ 9,380 $ - $ -
========== ========== ==========
TOTAL
Oil and gas producing activities:
Future cash inflows.................................. $16,930,589 $ 9,744,016 $20,998,962
Future production costs.............................. (5,190,694) (3,606,463) (5,292,408)
Future development costs............................. (998,119) (961,919) (677,309)
Future income tax expense............................ (2,568,066) (654,523) (4,165,261)
---------- ---------- ----------
8,173,710 4,521,111 10,863,984
10% annual discount factor.............................. (4,047,158) (2,020,785) (5,218,482)
---------- ---------- ----------
Standardized measure of discounted future cash flows.... $ 4,126,552 $ 2,500,326 $ 5,645,502
========== ========== ==========
85
PIONEER NATURAL RESOURCES COMPANY
UNAUDITED SUPPLEMENTARY INFORMATION
Years Ended December 31, 2002, 2001 and 2000
For the Year Ended December 31,
----------------------------------------
Oil and Gas Producing Activities 2002 2001 2000
----------- ----------- -----------
(in thousands)
Oil and gas sales, net of production costs............... $ (489,338) $ (631,365) $ (663,473)
Net changes in prices and production costs............... 2,042,575 (4,528,168) 3,829,794
Extensions and discoveries............................... 152,253 184,454 525,361
Development costs incurred during the period............. 262,469 239,156 101,350
Sales of minerals-in-place............................... - (23,372) (72,624)
Purchases of minerals-in-place........................... 187,460 201,535 187,097
Revisions of estimated future development costs.......... (387,404) (429,365) (200,734)
Revisions of previous quantity estimates................. 527,987 40,771 344,454
Accretion of discount.................................... 250,033 701,943 293,726
Changes in production rates, timing and other............ 99,722 (274,689) (262,784)
---------- ---------- ----------
Change in present value of future net revenues........... 2,645,757 (4,519,100) 4,082,167
Net change in present value of future income taxes....... (1,019,531) 1,373,924 (1,373,924)
---------- ---------- ----------
1,626,226 (3,145,176) 2,708,243
Balance, beginning of year............................... 2,500,326 5,645,502 2,937,259
--------- ---------- ----------
Balance, end of year..................................... $4,126,552 $ 2,500,326 $ 5,645,502
========= ========== ==========
Selected Quarterly Financial Results
Quarter
----------------------------------------------
First Second Third Fourth
--------- ---------- --------- --------
(in thousands, except per share data)
2002
Operating revenues........................... $ 165,539 $ 172,430 $ 168,317 $ 195,494
Total revenues and other income.............. $ 166,658 $ 174,338 $ 178,753 $ 197,685
Costs and expenses........................... $ 169,027 $ 158,916 $ 157,953 $ 177,416
Net income (loss):
Before extraordinary items................ $ (1,959) $ 13,985 $ 18,611 $ 18,422
Extraordinary items, net of tax (a)....... - (2,843) (19,501) (2)
-------- -------- -------- --------
Net income (loss)......................... $ (1,959) $ 11,142 $ (890) $ 18,420
======== ======== ======== ========
Net income (loss) per share:
Basic:
Before extraordinary items.............. $ (.02) $ .13 $ .16 $ .16
Extraordinary items..................... - (.03) (.17) -
-------- -------- -------- --------
Net income (loss)....................... $ (.02) $ .10 $ (.01) $ .16
======== ======== ======== ========
Diluted:
Before extraordinary items.............. $ (.02) $ .12 $ .16 $ .16
Extraordinary items..................... - (.02) (.17) -
-------- -------- -------- --------
Net income (loss)....................... $ (,02) $ .10 $ (.01) $ .16
======== ======== ======== ========
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)
======== ======== ======== ========
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 15, 2003 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 15, 2003 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 15, 2003 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 15, 2003 and is incorporated herein by reference.
ITEM 14. CONTROLS AND PROCEDURES
(a) Evaluation of disclosure controls and procedures. Within 90 days prior to
the filing date of this Report, the Company's principal executive officer
("CEO") and principal financial officer ("CFO") carried out an evaluation of the
effectiveness of the Company's disclosure controls and procedures. Based on
those evaluations, the Company's CEO and CFO believe (i) that the Company's
disclosure controls and procedures are designed to ensure that information
required to be disclosed by the Company in the reports it files under the
Securities Exchange Act of 1934 is recorded, processed, summarized and reported
within the time periods specified in the SEC's rules and forms and that such
information is accumulated and communicated to the Company's management,
including the CEO and CFO, as appropriate to allow timely decisions regarding
required disclosure; and (ii) that the Company's disclosure controls and
procedures are effective.
(b) Changes in internal controls. There have been no significant changes in the
Company's internal controls or in other factors that could significantly affect
the Company's internal controls subsequent to the evaluation referred to in Item
14. (a), above, nor have there been any corrective actions with regard to
significant deficiencies or material weaknesses.
87
PART IV
ITEM 15. 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, 2002 and 2001
Consolidated Statements of Operations for the years ended December 31,
2002, 2001 and 2000
Consolidated Statements of Stockholders' Equity for the years ended
December 31, 2002, 2001 and 2000
Consolidated Statements of Cash Flows for the years ended December 31,
2002, 2001 and 2000
Consolidated Statements of Comprehensive Income (Loss) for the years
ended December 31, 2002, 2001 and 2000
Notes to Consolidated Financial Statements
Unaudited Supplementary Information
(b) Reports on Form 8-K
During the three months ended December 31, 2002, the Company filed one
Current Report on Form 8-K dated October 24, 2002. The Company's October 24,
2002 Form 8-K provided, under Items 7 and 9, (i) the Company's news release
dated October 24, 2002 that announced the Company's financial and operating
results for the three and nine month periods ended September 30, 2002, an
operational update and the Company's fourth quarter 2002 financial outlook; and
(ii) tables summarizing, as of October 23, 2002, the Company's open oil hedge
positions, open gas hedge positions and deferred hedge gains and losses on
terminated commodity hedges.
(c) Exhibits
The exhibits to this Report required to be filed pursuant to Item 15(c)
are listed below 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.
88
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 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 - 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).
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).
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).
89
Exhibit
Number Description
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).
10.13 - Guarantee dated as of January 13, 1998, by Pioneer USA relating to
the $350,000,000 in aggregate principal amount of 6.50% Senior Notes
Due 2008 issued under the indenture identified above as Exhibit 10.9
(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 dated as of January 13, 1998, by Pioneer USA relating to
the $250,000,000 in aggregate principal amount of 7.20% Senior Notes
Due 2028 issued under the indenture identified above as Exhibit 10.9
(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 Inc. ("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).
90
Exhibit
Number Description
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 - Second Amendment 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 - Third Amendment 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 - First Amendment 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 - Second Amendment 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 - 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).
10.28H - 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).
10.29H - 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).
10.30H* - Pioneer USA 40l(k) and Matching Plan, Amended and Restated Effective
as of January 1, 2002.
91
Exhibit
Number Description
10.31 - 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).
10.32 - Form of 9-5/8% Senior Notes Due 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 10.31 (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).
10.33 - 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
10.31 (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).
10.34 - $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).
10.35 - Agreement and Plan of Merger dated as of November 28, 2000 by and
among the Company, Pioneer USA, 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).
10.36 - Agreement and Plan of Merger dated as of September 20, 2001, among
the Company, Pioneer USA 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).
10.37 - Underwriting Agreement dated April 16, 2002, among the Company,
Pioneer USA and Credit Suisse First Boston Corporation (incorporated
by reference to Exhibit 99.1 to the Company's Current Report on Form
8-K, File No. 001-13245, filed with the SEC on April 17, 2002).
10.38 - Terms Agreement dated April 16, 2002, among the Company, Pioneer
USA, Credit Suisse First Boston Corporation, Banc of America
Securities LLC, J.P. Morgan Securities Inc. and Lehman Brothers Inc.
as representatives of the underwriters (incorporated by reference to
Exhibit 99.2 to the Company's Current Report on Form 8-K, File No.
001-13245, filed with the SEC on April 17, 2002).
10.39 - Third Supplemental Indenture dated as of April 30, 2002, among the
Company, Pioneer USA as the subsidiary guarantor and The Bank of New
York, as Trustee (incorporated by reference to Exhibit 10.4 to the
Company's Quarterly Report on Form 10-Q for the three months ended
March 31, 2002, File No. 001-13245, filed with the SEC on May 14,
2002).
10.40 - Form of 7.50% Senior Notes Due 2012 of the Company (incorporated by
reference to Exhibit 99.1 to the Company's Current Report on Form
8-K, File No. 001-13245, filed with the SEC on April 29, 2002).
92
Exhibit
Number Description
10.41 - Guarantee dated as of April 30, 2002, by Pioneer USA relating to the
$150,000,000 in aggregate principal amount of 7.50% Senior Notes Due
2012 issued under the indenture identified above as Exhibit 10.39
(incorporated by reference to Exhibit 10.6 to the Company's
Quarterly Report on Form 10-Q for the three months ended March 31,
2002, File No. 001-13245, filed with the SEC on May 14, 2002).
21.1* - Subsidiaries of the registrant.
23.1* - Consent of Ernst & Young LLP.
23.2* - Consent of Netherland, Sewell & Associates, Inc.
23.3* - Consent of Gaffney, Cline & Associates, Inc.
- ---------------
* Filed herewith
H Executive Compensation Plan or Arrangement previously filed pursuant to Item
14(c).
93
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: February 20, 2003 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, February 20, 2003
- ---------------------------- President, Chief Executive
Scott D. Sheffield Officer and Assistant
Secretary
(principal executive officer)
/s/ Timothy L. Dove Executive Vice President, February 20, 2003
- ---------------------------- Chief Financial Officer and
Timothy L. Dove Assistant Secretary
/s/ Richard P. Dealy Vice President and Chief February 20, 2003
- ---------------------------- Accounting Officer
Richard P. Dealy
/s/ James R. Baroffio Director February 20, 2003
- ----------------------------
James R. Baroffio
/s/ Edison C. Buchanan Director February 20, 2003
- ----------------------------
Edison C. Buchanan
/s/ R. Hartwell Gardner Director February 20, 2003
- ----------------------------
R. Hartwell Gardner
/s/ James L. Houghton Director February 20, 2003
- ----------------------------
James L. Houghton
/s/ Jerry P. Jones Director February 20, 2003
- ----------------------------
Jerry P. Jones
/s/ Linda K. Lawson Director February 20, 2003
- ----------------------------
Linda K. Lawson
/s/ Charles E. Ramsey, Jr. Director February 20, 2003
- ----------------------------
Charles E. Ramsey, Jr.
/s/ Robert A. Solberg Director February 20, 2003
- ----------------------------
Robert A. Solberg
94
CERTIFICATIONS
I, Scott D. Sheffield, certify that:
1. I have reviewed this annual report on Form 10-K of Pioneer Natural Resources
Company (the "Company"):
2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to make
the statements made, in light of circumstances under which such statements were
made, not misleading with respect to the period covered by this annual report;
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
Company as of, and for, the periods presented in this annual report;
4. The Company's other certifying officer and I are responsible for establishing
and maintaining disclosure controls and procedures (as defined in Exchange Act
Rules 13a-14 and 15d-14) for the Company and we have:
a) designed such disclosure controls and procedures to ensure that material
information relating to the Company, including its consolidated subsidiaries, is
made known to us by others within those entities, particularly during the period
in which this annual report is being prepared;
b) evaluated the effectiveness of the Company's disclosure controls and
procedures as of a date within 90 days prior to the filing date of this annual
report (the "Evaluation Date"); and
c) presented in this annual report our conclusions about the effectiveness of
the disclosure controls and procedures based on our evaluation as of the
Evaluation Date;
5. The Company's other certifying officer and I have disclosed, based on our
most recent evaluation, to the Company's auditors and the audit committee of the
Company's board of directors (or persons performing the equivalent function):
a) all significant deficiencies in the design or operation of internal controls
which could adversely affect the Company's ability to record, process, summarize
and report financial data and have identified for the Company's auditors any
material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the Company's internal controls; and
6. The Company's other certifying officer and I have indicated in this annual
report whether or not there were significant changes in internal controls or in
other factors that could significantly affect internal controls subsequent to
the date of our most recent evaluation, including any corrective actions with
regard to significant deficiencies and material weaknesses.
February 20, 2003
/s/ Scott D. Sheffield
-------------------------------------------------
Scott D. Sheffield, Chairman, President
and Chief Executive Officer
95
I, Timothy L. Dove, certify that:
1. I have reviewed this annual report on Form 10-K of Pioneer Natural Resources
Company (the "Company"):
2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to make
the statements made, in light of circumstances under which such statements were
made, not misleading with respect to the period covered by this annual report;
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
Company as of, and for, the periods presented in this annual report;
4. The Company's other certifying officer and I are responsible for establishing
and maintaining disclosure controls and procedures (as defined in Exchange Act
Rules 13a-14 and 15d-14) for the Company and we have:
a) designed such disclosure controls and procedures to ensure that material
information relating to the Company, including its consolidated subsidiaries, is
made known to us by others within those entities, particularly during the period
in which this annual report is being prepared;
b) evaluated the effectiveness of the Company's disclosure controls and
procedures as of a date within 90 days prior to the filing date of this annual
report (the "Evaluation Date"); and
c) presented in this annual report our conclusions about the effectiveness of
the disclosure controls and procedures based on our evaluation as of the
Evaluation Date;
5. The Company's other certifying officer and I have disclosed, based on our
most recent evaluation, to the Company's auditors and the audit committee of the
Company's board of directors (or persons performing the equivalent function):
a) all significant deficiencies in the design or operation of internal controls
which could adversely affect the Company's ability to record, process, summarize
and report financial data and have identified for the Company's auditors any
material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the Company's internal controls; and
6. The Company's other certifying officer and I have indicated in this annual
report whether or not there were significant changes in internal controls or in
other factors that could significantly affect internal controls subsequent to
the date of our most recent evaluation, including any corrective actions with
regard to significant deficiencies and material weaknesses.
February 20, 2003
/s/ Timothy L. Dove
-------------------------------------------
Timothy L. Dove, Executive Vice President
and Chief Financial Officer
96
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 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 - 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).
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).
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).
97
Exhibit Index Page
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).
10.13 - Guarantee dated as of January 13, 1998, by Pioneer USA
relating to the $350,000,000 in aggregate principal amount of
6.50% Senior Notes Due 2008 issued under the indenture
identified above as Exhibit 10.9 (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 dated as of January 13, 1998, by Pioneer USA
relating to the $250,000,000 in aggregate principal amount of
7.20% Senior Notes Due 2028 issued under the indenture
identified above as Exhibit 10.9 (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 Inc. ("Mesa") (incorporated by
reference to Exhibit 10(v) to Mesa's Annual Report on Form
10-K for the period ended December 31, 1991).
98
Exhibit Index Page
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 - Second Amendment 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 - Third Amendment 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 - First Amendment 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 - Second Amendment 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 - 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).
99
Exhibit Index Page
10.28H - 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).
10.29H - 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).
10.30H* - Pioneer USA 40l(k) and Matching Plan, Amended and Restated
Effective as of January 1, 2002.
10.31 - 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).
10.32 - Form of 9-5/8% Senior Notes Due 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 10.31 (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).
10.33 - 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 10.31 (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).
10.34 - $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).
10.35 - Agreement and Plan of Merger dated as of November 28, 2000 by
and among the Company, Pioneer USA, 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).
100
Exhibit Index Page
10.36 - Agreement and Plan of Merger dated as of September 20, 2001,
among the Company, Pioneer USA 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).
10.37 - Underwriting Agreement dated April 16, 2002, among the Company,
Pioneer USA and Credit Suisse First Boston Corporation
(incorporated by reference to Exhibit 99.1 to the Company's
Current Report on Form 8-K, File No. 001-13245, filed with the
SEC on April 17, 2002).
10.38 - Terms Agreement dated April 16, 2002, among the Company,
Pioneer USA, Credit Suisse First Boston Corporation, Banc of
America Securities LLC, J.P. Morgan Securities Inc. and Lehman
Brothers Inc. as representatives of the underwriters
(incorporated by reference to Exhibit 99.2 to the Company's
Current Report on Form 8-K, File No. 001-13245, filed with the
SEC on April 17, 2002).
10.39 - Third Supplemental Indenture dated as of April 30, 2002, among
the Company, Pioneer USA as the subsidiary guarantor and The
Bank of New York, as Trustee (incorporated by reference to
Exhibit 10.4 to the Company's Quarterly Report on Form 10-Q for
the three months ended March 31, 2002, File No. 001-13245,
filed with the SEC on May 14, 2002).
10.40 - Form of 7.50% Senior Notes Due 2012 of the Company
(incorporated by reference to Exhibit 99.1 to the Company's
Current Report on Form 8-K, File No. 001-13245, filed with the
SEC on April 29, 2002).
10.41 - Guarantee dated as of April 30, 2002, by Pioneer USA relating
to the $150,000,000 in aggregate principal amount of 7.50%
Senior Notes Due 2012 issued under the indenture identified
above as Exhibit 10.39 (incorporated by reference to Exhibit
10.6 to the Company's Quarterly Report on Form 10-Q for the
three months ended March 31, 2002, File No. 001-13245, filed
with the SEC on May 14, 2002).
21.1* - Subsidiaries of the registrant.
23.1* - Consent of Ernst & Young LLP.
23.2* - Consent of Netherland, Sewell & Associates, Inc.
23.3* - Consent of Gaffney, Cline & Associates, Inc.
- ---------------
* Filed herewith
H Executive Compensation Plan or Arrangement previously filed pursuant to Item
14(c).
101