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