UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
/ X / ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2003
or
/ / TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from _______ to ________
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 900, 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 as of the last business day of the Registrant's most recently
completed second fiscal quarter ........................... $ 3,053,790,906
Number of shares of Common Stock outstanding as of
January 30, 2004........................................... 119,345,550
Documents Incorporated by Reference:
(1) Proxy Statement for Annual Meeting of Shareholders to be held May 13, 2004
- 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..................................... 8
Competition, Markets and Regulations........................ 8
Risks Associated with Business Activities................... 10
Item 2. Properties.................................................. 13
Proved Reserves............................................. 13
Finding Cost and Reserve Replacement........................ 14
Description of Properties................................... 14
Selected Oil and Gas Information............................ 19
Item 3. Legal Proceedings........................................... 23
Item 4. Submission of Matters to a Vote of Security Holders......... 23
PART II
Item 5. Market for Registrant's Common Stock and Related
Stockholder Matters......................................... 23
Securities Authorized for Issuance under Equity
Compensation Plans.......................................... 24
Item 6. Selected Financial Data..................................... 25
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations....................... 26
2003 Highlights............................................. 26
2003 Financial and Operating Performance.................... 26
2004 Outlook................................................ 27
Critical Accounting Estimates............................... 29
Results of Operations....................................... 31
Capital Commitments, Capital Resources and Liquidity........ 37
New Accounting Development.................................. 40
2
TABLE OF CONTENTS
Page
Item 7A. Quantitative and Qualitative Disclosures About
Market Risk................................................. 40
Quantitative Disclosures.................................... 40
Qualitative Disclosures..................................... 43
Item 8. Financial Statements and Supplementary Data................. 43
Index to Consolidated Financial Statements.................. 43
Independent Auditors' Report................................ 44
Consolidated Financial Statements........................... 45
Notes to Consolidated Financial Statements.................. 50
Unaudited Supplementary Information......................... 88
Item 9. Changes in and Disagreements With Accountants on
Accounting and Financial Disclosure......................... 94
Item 9A. Controls and Procedures..................................... 94
PART III
Item 10. Directors and Executive Officers of the Registrant.......... 94
Item 11. Executive Compensation...................................... 94
Item 12. Security Ownership of Certain Beneficial Owners and
Management and Related Stockholder Matters.................. 94
Item 13. Certain Relationships and Related Transactions.............. 94
Item 14. Principal Accountant Fees and Services...................... 94
PART IV
Item 15. Exhibits, Financial Statement Schedules, and Reports
on Form 8-K................................................. 95
Signatures.................................................. 100
Exhibit Index............................................... 101
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
Regulations" 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; "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 Btus; "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; "Bcf" means
one billion 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 (the "Company" or "Pioneer") 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 900, 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; Tunis, Tunisia; and
Libreville, Gabon. At December 31, 2003, the Company had 1,014 employees, 505 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 as of December 31, 2003. These fields have
a remaining productive life in excess of 40 years. The stable base of oil and
gas production from these fields, combined with the deepwater Gulf of Mexico
Canyon Express, Falcon and Harrier gas projects which began production in
September 2002, March 2003 and January 2004, respectively, and the Sable oil
discovery in South Africa which began production in August 2003 will generate
the operating cash flows that will allow the Company to improve its financial
flexibility in 2004. These activities will be further enhanced by initial
production in mid-2004 from the Company's Devils Tower oil discovery and the
Raptor and Tomahawk gas discoveries, all located in the deepwater Gulf of
Mexico.
The above exploration successes represent some of the results of the
Company's decision 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) evaluate opportunities to
acquire oil and gas properties under terms that will complement the Company's
exploration and development drilling activities; (c) invest in the personnel and
technology necessary to maximize the Company's exploration and development
successes; and (d) 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 production
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, 2003. 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 2002,
world oil prices increased in response to political unrest and supply
disruptions in the Middle East and Venezuela while North American gas prices
improved as market fundamentals strengthened. During 2003, world oil and North
American gas supply and demand fundamentals continued to strengthen. Significant
factors that will impact 2004 commodity prices include the final resolution of
issues currently impacting Iraq and the Middle East in general, the extent to
which members of OPEC and other oil exporting nations are able to continue to
manage oil supply through export quotas and overall North American gas supply
and demand fundamentals. To mitigate the impact of commodity price volatility on
the Company's net asset value, Pioneer utilizes 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 the years ended December 31, 2003, 2002
and 2001 from the Company's hedging activities and the Company's open hedge
positions at December 31, 2003.
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 the Gulf of Mexico, the onshore Gulf Coast
area and in Alaska, 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, Canada, South Africa and Tunisia.
Production. The Company focuses its efforts towards maximizing its average
daily production of oil, NGLs and gas through development drilling, production
enhancement activities and acquisitions of producing properties while minimizing
the controllable costs associated with the production activities. During the
year ended December 31, 2003, the Company's average daily oil, NGL and gas
production increased as a result of (i) a full year of gas production from the
Company's Canyon Express gas project in the deepwater Gulf of Mexico, (ii) gas
production since March 2003 from the Company's Falcon gas field in the deepwater
Gulf of Mexico, (iii) increased production from Argentina primarily resulting
from the resumption of oil drilling activities since the third quarter of 2002,
(iv) oil production since May 2003 from the Company's Adam field in Tunisia and
(v) oil production since August 2003 from the Company's Sable field offshore
South Africa. These increases more than offset normal production declines.
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, 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 the years ended
6
December 31, 2003, 2002 and 2001 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 three years ended December 31, 2003, the Company
drilled 1,002 gross (744.1 net) wells, 86 percent of which were successfully
completed as productive wells, at a total drilling cost (net to the Company's
interest) of $1.5 billion. During 2003, the Company drilled 383 gross (338.8
net) wells. The Company's current 2004 capital expenditure budget is expected to
range from $550 million to $600 million. Excluding the 2003 acquisitions, the
Company's 2004 capital expenditure budget is comparable to 2003 costs incurred
for oil and gas producing activities. The Company has allocated the budgeted
2004 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, 2003 include proved undeveloped
reserves and proved developed reserves that are behind pipe of 188.9 million
Bbls of oil and NGLs and 670.8 Bcf of gas. Development of these 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 and reserves
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 to 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, Tomahawk and Raptor 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 2004 exploration
efforts will be approximately 35 percent of total 2004 capital expenditures and
will be concentrated domestically in the Gulf of Mexico, and internationally in
Argentina, Canada, Gabon 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.
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 the years ended December
31, 2003, 2002 and 2001, the Company expended $151.0 million, $195.5 million and
$170.8 million, respectively, of acquisition capital to purchase additional
interests in, and other assets associated with, its existing assets and to
acquire new prospects for future exploration activities. See Note D of Notes to
Consolidated Financial Statements included in "Item 8. Financial Statements and
Supplementary Data" for a description of the Company's acquisitions during 2003,
2002 and 2001.
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.
Asset divestitures. The Company regularly reviews its asset 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. 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.
7
During the years ended December 31, 2003, 2002 and 2001, 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
$35.7 million, $118.9 million and $113.5 million, respectively, which resulted
in 2003, 2002 and 2001 net divestiture gains of $1.3 million, $4.4 million and
$7.7 million, respectively. The net cash proceeds from the 2003, 2002 and 2001
asset dispositions were primarily used to fund additions to oil and gas
properties or to reduce the Company's outstanding indebtedness. See Note N 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.
Operations by Geographic Area
The Company operates in one industry segment. During the three years ended
December 31, 2003, the Company had oil and gas producing and development
activities in the United States, Argentina, Canada, Gabon, South Africa and
Tunisia, and had exploration activities in the United States, Argentina, Canada,
Gabon, South Africa and Tunisia. See Note R of Notes to Consolidated Financial
Statements included in "Item 8. Financial Statements and Supplementary Data" for
geographic operating segment information, including results of operations and
segment assets.
Marketing of Production
General. Production from the Company's properties is marketed using methods
that are consistent with industry practices. Sales prices for oil, NGL and gas
production are negotiated based on factors normally considered in the industry,
such as the index or 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 the year ended December 31, 2003, the
Company's primary purchasers of oil were ExxonMobil Corporation ("ExxonMobil")
and Plains Marketing LP ("Plains"), the Company's primary purchaser of NGLs was
Enterprise Products Operating L.P. ("Enterprise") and the Company's primary
purchasers of gas were Williams Energy Services ("Williams") and Conoco
Phillips. Approximately 16 percent, eight percent and seven percent of the
Company's 2003 combined oil, NGL and gas revenues were attributable to sales to
Williams, Conoco Phillips and Enterprise, respectively, and approximately five
percent of combined oil, NGL and gas revenues of 2003 were attributable to sales
to ExxonMobil and Plains. 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 utilizes commodity swap and collar
contracts in order to (i) reduce the effect of price volatility on the
commodities the Company produces and sells, (ii) support the Company's annual
capital budgeting and expenditure plans and (iii) reduce commodity price risk
associated with certain capital projects. 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 on oil and gas revenues during the years ended
December 31, 2003, 2002 and 2001 from the Company's commodity hedging activities
and the Company's open commodity hedge positions at December 31, 2003.
Competition, Markets and Regulations
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
8
financial resources necessary to acquire and develop the properties. 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, NGLs 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 these commodity
prices or the degree to which these prices will be affected, the prices for any
commodity that the Company produces will generally approximate current market
prices in the geographic region of the production.
Governmental regulations. Enterprises that sell securities in public
markets are subject to regulatory oversight by agencies such as the SEC. 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
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 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 future 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
9
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 reserves. 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
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 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. Certain state regulations 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 regulation of NORM has minimal effect on the Company's
operations because the Company generates only small quantities 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 result
in a curtailment of production or processing, a material increase in the costs
of production, development, exploration or processing or otherwise adversely
affect the Company's future results of operations and financial condition.
The Company employs an environmental director 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. 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 oil and gas prices, which are
affected by numerous factors beyond the Company's control. Oil and gas prices
10
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 the
recognition of a deferred tax asset valuation allowance or an increase to the
Company's deferred tax asset valuation allowances, depending on the Company's
tax attributes in each country in which it has activities.
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, 2003 and 2002, the Company carried
unproved property costs of $179.8 million and $219.1 million, respectively.
Generally accepted accounting principles require periodic evaluation of these
costs on a project-by-project basis in comparison to their estimated value.
These evaluations will be affected by the results of exploration activities,
commodity price outlooks, planned future sales or expiration of all or a portion
of the leases, contracts and permits appurtenant to such projects. If the
quantity of potential reserves determined by such evaluations is not sufficient
to fully recover the cost invested in each project, the Company will recognize
noncash charges in the earnings of future periods.
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 reserves 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, 2003, the
Company owned 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 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.
11
Environmental. The oil and gas business is subject to environmental
hazards, such as oil spills, produced water 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" above
for additional discussion related to environmental risks.
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, a material increase in the
costs of production, development, exploration or processing or otherwise
adversely affect the Company's future 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.
Financial Statements and Supplementary Data" for information regarding the
Company's outstanding debt as of December 31, 2003 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" above
for additional discussion regarding competition.
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" above for additional discussion regarding government regulation.
International operations. At December 31, 2003, approximately 21 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 Africa and two percent
in Canada). 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 may adversely affect the Company's future results of operations
and financial condition. 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.
12
ITEM 2. PROPERTIES
The information included in this Report about the Company's oil, NGL and
gas reserves as of December 31, 2003 was based on reserve reports audited by
Netherland, Sewell & Associates, Inc. for the Company's major properties in the
United States, Argentina, Canada and South Africa and reserve reports prepared
by the Company's engineers for all other properties. The reserve audit conducted
by Netherland, Sewell & Associates, Inc. in aggregate represented 87 percent of
the Company's estimated proved quantities of reserves as of December 31, 2003.
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 the
United States, Canada and South Africa, 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 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 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 exploration and
development activities, 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
assets.
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 production because of seasonal price
fluctuations or other varying market conditions. Standardized Measures as of any
date are not necessarily indicative of future results of operations.
Accordingly, estimates included herein of future net revenues may be materially
different from the net revenues that are ultimately received.
The Company did not provide estimates of total proved oil and gas reserves
during the years ended December 31, 2003, 2002 or 2001 to any federal authority
or agency, other than the SEC.
Proved Reserves
The Company's proved reserves totaled 789.1 million BOE at December 31,
2003, 736.7 million BOE at December 31, 2002 and 671.4 million BOE at December
31, 2001, representing $4.6 billion, $4.1 billion and $2.5 billion,
respectively, of Standardized Measure or $6.0 billion, $5.1 billion and $2.5
billion, respectively, on a pre-tax basis. The seven and 11 percent increases in
proved reserve volumes and Standardized Measure, respectively, during 2003 were
primarily due to two core area acquisitions, discoveries in Gabon, the deepwater
Gulf of Mexico and Tunisia and positive reserve revisions due to increased
commodity prices extending the estimated economic life of various properties,
increased recoverable reserve estimates based on well performance and the
addition of reserves resulting from the Company' expanded development drilling
program. The ten and 65 percent increases in proved reserve volumes and
Standardized Measure, respectively, 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.
On a BOE basis, 65 percent of the Company's total proved reserves at
December 31, 2003 were proved developed reserves. Based on reserve information
as of December 31, 2003, and using the Company's production information for the
year then ended, the reserve-to-production ratio associated with the Company's
proved reserves was 14.0 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, 2003:
13
2003 Average
Proved Reserves as of December 31, 2003 Daily Production (a)
------------------------------------------------- ---------------------------------
Oil Standardized Oil
& NGLs Gas Measure & NGLs Gas
(MBbls) (MMcf) MBOE (in thousands) (Bbls) (Mcf) BOE
--------- --------- ---------- ----------- -------- --------- --------
United States......... 362,751 1,553,976 621,747 $ 3,797,488 44,863 445,609 119,129
Argentina............. 33,469 549,856 125,112 443,118 10,005 94,128 25,694
Canada................ 2,407 93,829 18,045 218,419 1,017 41,669 7,962
Africa................ 24,154 - 24,154 124,228 1,981 - 1,981
--------- --------- ---------- --------- -------- --------- --------
Total................. 422,781 2,197,661 789,058 $ 4,583,253 57,866 581,406 154,766
========= ========= ========== ========== ======== ========= ========
- ----------------
(a) The 2003 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 the years ended
December 31, 2003, 2002 and 2001 were $6.64, $6.30 and $7.49 per BOE,
respectively. The average acquisition and finding cost for the three-year period
ended December 31, 2003 was $6.76 per BOE, representing an eight percent
increase over the 2002 three-year average rate of $6.24 per BOE.
During the year ended December 31, 2003, the Company replaced 193 percent
of its annual production on a BOE basis (299 percent for oil and NGLs and 129
percent for gas). 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). The
Company's 2003 and 2002 reserve replacement percentages were the result of
revisions of previous estimates including revisions related to changes in
commodity prices, asset purchases and new discoveries and field extensions. The
Company's 2001 reserve replacement percentage was primarily impacted by asset
purchases and new discoveries and field extensions.
Description of Properties
As of December 31, 2003, the Company has production, development and/or
exploration operations in the United States, Argentina, Canada, Gabon, South
Africa and Tunisia.
Domestic. The Company's domestic operations are located in the Permian
Basin, Mid-Continent, Gulf of Mexico and onshore Gulf Coast areas of the United
States. The Company also has unproved properties in Alaska. Approximately 83
percent of the Company's domestic proved reserves at December 31, 2003 are
located in the Spraberry, Hugoton and West Panhandle fields. These mature fields
generate substantial operating cash flow and have a large 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 the year ended December 31, 2003,
the Company expended $563.0 million in domestic acquisition, exploration and
development drilling activities. The Company has budgeted approximately $427
million for domestic exploration and development drilling expenditures for 2004.
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 primarily from three formations,
the upper and lower Spraberry and the Dean, at depths ranging from 6,700 feet to
9,200 feet. Recently, the Company has been adding the Wolfcamp formation at
depths ranging from 9,300 feet to 10,300 feet to selected completions with
successful results. The center of the Spraberry field was unitized in the late
1950s and early 1960s by the major oil companies; however, until the late 1980s
there was very limited development activity in the field. The Company believes
14
the area offers excellent opportunities to enhance oil and gas reserves because
of the numerous 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 the year ended December 31, 2003, the Company placed 123 Spraberry
wells on production and drilled one developmental dry hole. The Company plans to
drill approximately 114 development wells in the Spraberry field during 2004.
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 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 NGL production.
The Company's Hugoton operated wells are capable of producing approximately
90 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 during the year ended December 31, 2003. During 2003, the Company
placed 18 development wells on production, drilled one developmental dry hole
and had one well in progress as of December 31, 2003 in the Hugoton field. The
plans for 2004 include drilling approximately 20 development wells.
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 submitted and 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,
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. The Company controls the
wells, production equipment, gathering system and gas processing plant for the
field.
During the year ended December 31, 2003, the Company placed 71 new
development wells on production, drilled four development wells that were
plugged and abandoned due to noncommerciality and had 24 development wells and
two extension wells in progress at December 31, 2003. The Company plans to drill
approximately 111 wells in the West Panhandle field during 2004.
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 the Gulf of
Mexico shelf and deepwater as well as investments in and utilization of 3-D
seismic technology. During the year ended December 31, 2003, the Company
successfully drilled three exploratory wells in the deepwater Gulf of Mexico and
one successful development well on the shelf. The Company also drilled four
exploratory dry holes on the shelf and two exploratory dry holes in the
deepwater Gulf of Mexico during 2003 and had four exploratory wells in the
deepwater Gulf of Mexico and one exploratory well on the shelf in progress as of
December 31, 2003.
15
In the deepwater Gulf of Mexico, the Company has three major projects, two
of which are now on production and one that was in progress at December 31,
2003:
o Canyon Express - The Canyon Express development project is a joint
development of three deepwater Gulf of Mexico gas discoveries, including
the Company's TotalFinaElf-operated Aconcagua and Marathon-operated Camden
Hills fields, where the Company holds 37.5 percent and 33.3 percent working
interests, respectively. The Company participated in the discovery of the
Aconcagua gas field in 1999 during the early stages of building its
exploration program, and later added Camden Hills to its portfolio to
enhance its ownership in the project. The Canyon Express project was
approved for development in June 2000 and reached first production in
September 2002. The Canyon Express gathering system is the first in the
area and provides the Company and its partners with the opportunity to
collect gathering and handling revenues from the use of the system by any
future discoveries in the area. The Company has plans to drill and complete
an additional development well at Aconcagua during 2004.
o Falcon Area - The Company-operated Falcon two-well field was completed
ahead of schedule and placed on production in March 2003. During the first
quarter of 2003, the Company drilled its Harrier discovery, along with two
exploratory dry holes. The Company also acquired the remaining 25 percent
working interest in the Falcon field, Harrier discovery and surrounding
prospects that it did not already own in March 2003. In addition, during
the third quarter of 2003, the Company successfully drilled the Tomahawk
and Raptor prospects. All three discoveries, Harrier, Tomahawk and Raptor,
will be developed as single-well subsea tie-backs to the Falcon field
facilities which were designed to be expandable. To accommodate this
incremental production and potential throughput associated with additional
planned exploration, an additional parallel pipeline connecting the Falcon
field to the Falcon platform on the Gulf of Mexico shelf has been added,
doubling its capacity to 400 MMcf of gas per day. The Company placed the
Harrier field on production in early January 2004 and plans to place
Tomahawk and Raptor on production in mid-2004. In addition to the
development operations discussed above, the Company has budgeted to drill
up to three additional Falcon area prospects in 2004.
o Devils Tower - The Dominion-operated Devils Tower development project was
sanctioned in 2001 as a spar development project with the owners leasing a
spar from a third party for the life of the field. The hull of the spar was
constructed in Indonesia and was successfully transported to the United
States during the first quarter of 2003 where the topsides were added in
the fourth quarter of 2003. The spar has slots for eight dry tree wells and
up to two subsea tie-back risers and is capable of handling 60 MBbls of oil
per day and 60 MMcf of gas per day. Eight Devils Tower wells and one subsea
tie-back well, the Triton field, have been drilled and are awaiting
completion. In addition, the Company has drilled an appraisal well at
Triton that was successful subsequent to year end and an exploration well
is in progress on its Goldfinger prospect. Devils Tower production is
expected to begin in mid-2004 and will be phased in as the wells are
individually completed from the spar. The Company holds a 25 percent
working interest in each of the above projects.
During 2002, the Company also participated in the Marathon-operated
deepwater Gulf of Mexico Ozona Deep discovery. The Company is currently
negotiating a tie-back agreement to an existing facility in the area, the
economics of which will determine future activities. In late 2003, the Company
spudded an exploratory well on the BP-operated Juno prospect with a 25 percent
working interest and an exploratory well on the Unocal-operated Myrtle Beach
prospect with a 10 percent working interest, each of which remains in progress
with results expected to be known in February 2004. The Company also plans to
spud an exploratory well on the Dominion-operated Thunder Hawk prospect during
2004. The Company has a 12.5 percent working interest in Thunder Hawk.
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 acquired a 50
percent working interest in 47 offshore exploration blocks operated by the
Company. The agreement covers eight prospects and 19 leads and included 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
first three wells under this joint agreement were unsuccessful. The fourth well,
Midway, subsequent to December 31, 2003 encountered 30 feet of net gas pay and
is expected to be tied back to an existing production platform with first
production anticipated during the second half of 2004. Three other intervals
with an additional 60 feet of gas bearing sands were also encountered and will
require additional analysis to determine future commercial potential. The
16
Company has a 37.5 percent working interest in this well. The fifth well to be
drilled in 2003 and the three wells scheduled for 2004 under the agreement,
which has been extended for one additional year, were mutually agreed to be
deferred until more technical work can be performed on the prospects by both
companies. Additionally, the Company and Woodside are evaluating shallower gas
prospects on the Gulf of Mexico shelf for possible inclusion in the 2004
drilling program.
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 placed five development wells and one extension well on production at
Pawnee during 2003, had two wells in progress at year end and plans to drill
approximately ten wells in 2004.
Alaska area. During the fourth quarter of 2002, the Company acquired a 70
percent working interest and operatorship in ten state leases on Alaska's North
Slope. Associated therewith, the Company drilled three exploratory wells during
the first quarter of 2003 to test a possible extension of the productive sands
in the Kuparuk River field into the shallow waters offshore. Although all three
of the wells found the sands filled with oil, they were too thin to be
considered commercial on a stand-alone basis. However, the wells also
encountered thick sections of oil-bearing Jurassic-aged sands, and the first
well flowed at a sustained rate of approximately 1,300 barrels per day. The test
results are continuing to be evaluated to determine the commercial viability of
the Jurassic reservoir. Subsequent to year end, the Company farmed-into a large
acreage block to the southwest of the Company's discovery. During 2004, the
Company plans to evaluate seismic data over the area to the southwest of its
discovery, analyze results from other wells drilled in the area and determine
the location of future exploration wells to further test the discovery.
In addition, the Company was the high bidder on 53 tracts covering an
additional 159,000 acres on the North Slope in the most recent state lease sale,
establishing a leasehold over a variety of prospects. The Company has opened an
office in Anchorage and is putting together a team of employees that will focus
their efforts on enhancing the Company's position in Alaska.
International. The Company's international operations are located in the
Neuquen and Austral Basins areas of Argentina, the Chinchaga, Martin Creek and
Lookout Butte areas of Canada, the Sable oil field offshore South Africa and in
southern Tunisia. Additionally, the Company has other significant oil
development and exploration activities in the shallow waters offshore Gabon, gas
exploration activities in the shallow waters offshore South Africa and oil
development and exploration activities in Tunisia. As of December 31, 2003,
approximately 16 percent, two percent and three percent of the Company's proved
reserves are located in Argentina, Canada and Africa, respectively.
Argentina. The Company's share of Argentine production during the year
ended December 31, 2003 averaged 25.7 MBOE per day, or approximately 17 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 Dos Hermanas, 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 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 the year ended December 31, 2003, the Company expended $52.1 million
on Argentine development, exploration and acquisition activities. The Company
drilled 31 development wells and 30 extension/exploratory wells, of which 29
development wells and 21 extension/exploratory wells were successful. Also
during 2003, the Company acquired an additional 150,000 acres in the Ojo de
Agua, Cutral Co Sur and Collun Cura blocks in the Neuquen Basin and shot seismic
covering approximately 258,000 acres. The Company plans to be more active in
Argentina in 2004 with approximately $113 million budgeted for oil and gas
development and exploration opportunities.
17
Canada. The Company's Canadian producing properties are located primarily
in Alberta and British Columbia, Canada. Production during the year ended
December 31, 2003 averaged 8.0 MBOE per day, or approximately five 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 the year ended December 31, 2003, the Company expended $53.0 million
on Canadian exploration, development, and acquisition activities. The Company
drilled 14 development wells and 42 exploratory/extension wells, primarily in
the Chinchaga and Martin Creek areas, of which seven development wells and 16
exploratory/extension wells were successful. Most of these wells were drilled
during the first quarter of 2003 as these areas are only accessible for drilling
during the winter months. The Company plans to spend approximately $31 million
on oil and gas development and exploration opportunities in Canada during 2004.
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 Adam concession and Borj El Khadra permit covering 212,420 acres
and 969,755 acres, respectively, onshore southern Tunisia in which the Company
has a 28 percent and 40 percent working interest, respectively. During the year
ended December 31, 2003, the Company expended $52.9 million of acquisition,
development and exploration drilling and seismic capital in South Africa, Gabon
and Tunisia.
South Africa. In South Africa, the Company spent $32.8 million of capital
to complete its Petro SA-operated Sable development project and to drill three
exploratory wells that were dry holes. The Sable oil field began producing in
August 2003. The Company has a 40% working interest in the Sable field. In 2004,
the Company currently plans to spend approximately $9 million in South Africa
for production enhancement opportunities at Sable and for an exploration well
late in the year.
Gabon. In Gabon, the Company spent $4.4 million of development and seismic
capital to further evaluate its Bigorneau South discovery, 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
four successful offshore wells which have established significant oil in place.
The Company recently received ministerial approval for improved terms associated
with the Olowi permit. Subsequent to year end, the Company has commenced a
multi-well drilling program to further define the scale of a development plan,
initially focusing on the Lower Gamba, and to test a new exploratory prospect.
The Company is also soliciting bids from possible new partners in the project.
Tunisia. In Tunisia, the Company spent $15.6 million of acquisition,
drilling and seismic capital during the year ended December 31, 2003 primarily
to drill one successful development well in its Adam concession, one successful
exploratory well in its AGIP-operated Hawa oil field and one exploratory well
that was a dry hole in its Company-operated Jorf permit. The Hawa oil field
started production in January 2004. In addition, the Company also drilled two
exploratory wells on its Anadarko-operated Anaguid permit that remain in
progress as of December 31, 2003. The Company also completed the construction of
a 15 kilometer flowline from the Adam discovery to an AGIP-operated facility,
allowing production to begin in May 2003. The capital budget of approximately
$14 million for Tunisia in 2004 includes an exploration well and development
well in the Adam concession, two exploration wells on the Company- operated El
Hamra permit and two appraisal wells on the Anaguid 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, 2003, 2002 and 2001.
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, 2003, 2002 and 2001:
19
PRODUCTION, PRICE AND COST DATA (a)
Year Ended December 31,
-----------------------------------------------------------------------------------------------------------
2003 2002 2001
------------------------------------- ----------------------------------- ---------------------------------
United United United
States Argentina Canada Africa Total States Argentina Canada Total States Argentina Canada Total
------ --------- ------ ------ ------- ------- --------- ------- -------- ------- --------- ------- -------
Production information:
Annual production:
Oil (MBbls)....... 8,952 3,171 40 723 12,886 8,555 2,914 45 11,514 8,629 3,566 303 12,498
NGLs (MBbls)...... 7,423 481 331 - 8,235 7,487 254 345 8,086 7,232 200 368 7,800
Gas (MMcf)........ 162,647 34,357 15,209 - 212,213 84,811 28,551 17,653 131,015 77,609 31,830 18,426 127,865
Total (MBOE)...... 43,483 9,378 2,906 723 56,490 30,177 7,926 3,333 41,436 28,796 9,071 3,742 41,609
Average daily production:
Oil (Bbls)........ 24,525 8,687 111 1,981 35,304 23,437 7,984 124 31,545 23,641 9,769 831 34,241
NGLs (Bbls)....... 20,338 1,318 906 - 22,562 20,512 696 946 22,154 19,815 547 1,008 21,370
Gas (Mcf)......... 445,609 94,128 41,669 - 581,406 232,360 78,220 48,365 358,945 212,629 87,204 50,481 350,314
Total (BOE)....... 119,129 25,694 7,962 1,981 154,766 82,677 21,716 9,131 113,524 78,893 24,851 10,253 113,997
Average prices, including hedge results:
Oil (per Bbl)..... $25.25 $25.62 $29.10 $29.52 $25.59 $23.66 $20.63 $22.26 $22.89 $24.34 $23.79 $21.87 $24.12
NGLs (per Bbl).... $19.04 $22.85 $24.80 $ - $19.50 $13.77 $14.56 $16.77 $13.92 $16.88 $19.29 $21.11 $17.14
Gas (per Mcf)..... $ 4.49 $ .56 $ 3.90 $ - $ 3.81 $ 3.16 $ .48 $ 2.50 $ 2.49 $ 4.10 $ 1.31 $ 2.86 $ 3.23
Revenue (per BOE). $25.24 $11.87 $23.61 $29.52 $22.99 $19.00 $ 9.79 $15.27 $16.94 $22.56 $14.36 $17.94 $20.36
Average prices, excluding hedge results:
Oil (per Bbl)..... $29.58 $26.31 $29.10 $30.07 $28.80 $23.85 $20.33 $22.26 $22.95 $24.56 $22.40 $21.87 $23.88
NGLs (per Bbl).... $19.04 $22.85 $24.80 $ - $19.50 $13.77 $14.56 $16.77 $13.92 $16.88 $19.29 $21.11 $17.14
Gas (per Mcf)..... $ 4.93 $ .56 $ 4.26 $ - $ 4.17 $ 3.02 $ .48 $ 2.40 $ 2.38 $ 3.96 $ 1.31 $ 3.27 $ 3.20
Revenue (per BOE). $25.71 $12.10 $25.54 $30.07 $25.07 $18.65 $ 9.68 $14.77 $16.63 $22.26 $13.81 $19.95 $20.21
Average costs (per BOE):
Production costs:
Lease operating... $ 3.10 $ 2.57 $ 4.06 $ 3.87 $ 3.07 $ 3.21 $ 1.61 $ 2.64 $ 2.87 $ 2.76 $ 2.64 $ 3.01 $ 2.76
Taxes:
Production...... .76 .20 - .12 .62 .71 .13 - .54 .98 .28 - .74
Ad valorem...... .51 - - - .40 .75 - - .54 .71 - - .49
Field fuel........ .94 - - - .72 .85 - - .62 1.27 - - .88
Workover.......... .15 .01 .43 - .14 .28 .01 .59 .25 .20 .01 .32 .17
----- ----- ----- ---- ------ ----- ----- ----- ----- ----- ----- ----- -----
Total.......... $ 5.46 $ 2.78 $ 4.49 $ 3.99 $ 4.95 $ 5.80 $ 1.75 $ 3.23 $ 4.82 $ 5.92 $ 2.93 $ 3.33 $ 5.04
Depletion expense.. $ 6.85 $ 4.96 $ 9.98 $10.69 $ 6.75 $ 4.64 $ 5.00 $ 8.36 $ 5.01 $ 4.46 $ 5.67 $ 7.71 $ 5.02
- ---------------
(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.
20
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,
2003, 2002 and 2001:
PRODUCTIVE WELLS (a)
Gross Productive Wells Net Productive Wells
-------------------------- -------------------------
Oil Gas Total Oil Gas Total
------ ------ ------ ------ ------ ------
As of December 31, 2003:
United States........... 3,691 2,012 5,703 2,978 1,907 4,885
Argentina............... 669 194 863 539 141 680
Canada.................. 4 268 272 4 210 214
Africa.................. 8 - 8 3 - 3
------ ------ ------ ------ ------ ------
Total................ 4,372 2,474 6,846 3,524 2,258 5,782
====== ====== ====== ====== ====== ======
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
Africa.................. 5 - 5 2 - 2
------ ------ ------ ------ ------ ------
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
====== ====== ====== ====== ====== ======
- ---------------
(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, 2003, the Company owned interests in 132 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, 2003:
LEASEHOLD ACREAGE
Developed Acreage Undeveloped Acreage
-------------------------- -------------------------- Royalty
Gross Acres Net Acres Gross Acres Net Acres Acreage
------------ ---------- ----------- ----------- ---------
As of December 31, 2003:
United States:
Onshore................. 1,011,370 869,974 125,095 79,224 229,650
Offshore................ 120,333 58,838 828,311 562,604 10,500
---------- ---------- ---------- ---------- --------
1,131,703 928,812 953,406 641,828 240,150
Argentina.................. 713,000 319,000 1,154,000 1,094,000 -
Canada..................... 161,000 123,000 431,000 310,000 15,000
Africa..................... 222,020 63,318 10,778,415 6,109,136 -
---------- ---------- ---------- ---------- --------
Total................... 2,227,723 1,434,130 13,316,821 8,154,964 255,150
========== ========== ========== ========== ========
21
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, 2003, 2002 and 2001. 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,
-------------------------- --------------------------
2003 2002 2001 2003 2002 2001
------ ------ ------ ------ ------ ------
United States:
Productive wells:
Development.............. 244 148 228 210.5 83.0 114.6
Exploratory.............. 4 6 20 4.0 2.0 11.0
Dry holes:
Development.............. 6 4 15 6.0 3.7 14.6
Exploratory.............. 6 3 8 3.6 2.1 5.1
----- ----- ----- ----- ------ ------
260 161 271 224.1 90.8 145.3
----- ----- ----- ----- ------ ------
Argentina:
Productive wells:
Development.............. 29 13 19 29.0 13.0 17.7
Exploratory.............. 21 9 26 21.0 9.0 25.5
Dry holes:
Development.............. 2 1 1 2.0 1.0 1.0
Exploratory.............. 9 8 16 9.0 8.0 14.0
----- ----- ----- ----- ------ ------
61 31 62 61.0 31.0 58.2
----- ----- ----- ----- ------ ------
Canada:
Productive wells:
Development.............. 7 13 24 7.0 10.4 20.3
Exploratory.............. 16 9 12 14.9 9.0 10.2
Dry holes:
Development.............. 7 4 2 6.5 4.0 2.0
Exploratory.............. 26 3 13 21.1 3.0 11.8
----- ----- ----- ----- ------ ------
56 29 51 49.5 26.4 44.3
----- ----- ----- ----- ------ ------
Africa:
Productive wells:
Development.............. 1 4 - .3 1.6 -
Exploratory.............. 1 4 3 .4 3.4 2.4
Dry holes:
Development.............. - - - - - -
Exploratory.............. 4 - 3 3.5 - 1.9
----- ----- ----- ----- ------ ------
6 8 6 4.2 5.0 4.3
----- ----- ----- ----- ------ ------
Total..................... 383 229 390 338.8 153.2 252.1
===== ===== ===== ===== ====== ======
Success ratio (a)............ 84% 90% 85% 85% 86% 80%
- ---------------
(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.
22
The following table sets forth information about the Company's wells upon
which drilling was in progress as of December 31, 2003:
Gross Wells Net Wells
----------- ---------
United States:
Development................................. 28 27.1
Exploratory................................. 11 5.8
----- ------
39 32.9
----- ------
Argentina:
Development................................. 3 3.0
Exploratory................................. 10 10.0
----- ------
13 13.0
----- ------
Canada:
Development................................. 6 5.6
Exploratory................................. 11 10.1
----- ------
17 15.7
----- ------
Africa:
Development................................. - -
Exploratory................................. 2 .8
----- ------
2 .8
----- ------
Total..................................... 71 62.4
===== ======
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. Except for the
specific legal actions described in Note I of Notes to Consolidated Financial
Statements included in "Item 8. Financial Statements and Supplemental Data", the
Company believes that the probable damages from such other legal actions will
not be in excess of 10 percent of the Company's current assets.
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 2003.
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
board of directors did not declare dividends to the holders of the Company's
common stock during the years ended December 31, 2003 or 2002. See "2004
Outlook" included in "Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations" for discussion related to future dividends.
23
The following table sets forth quarterly high and low prices of the
Company's common stock for the years ended December 31, 2003 and 2002.
High Low
-------- --------
Year ended December 31, 2003:
Fourth quarter................................ $ 32.90 $ 25.00
Third quarter................................. $ 26.52 $ 22.76
Second quarter................................ $ 28.44 $ 22.85
First quarter................................. $ 27.44 $ 23.27
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
On January 30, 2004, the last reported sales price of the Company's common
stock, as reported in the New York Stock Exchange composite transactions, was
$31.92 per share.
As of January 30, 2004, the Company's common stock was held by
approximately 29,118 holders of record.
Securities Authorized for Issuance under Equity Compensation Plans
The following table summarizes information about the Company's equity
compensation plans as of December 31, 2003:
(b)
Number of securities
(a) remaining available
Number of for future issuance
securities to be under equity
issued upon Weighted average compensation plans
exercise of exercise price of (excluding securities
outstanding options outstanding options reflected in first column)
------------------- ------------------- --------------------------
Equity compensation plans approved by
security holders (c):
Pioneer Natural Resources Company:
Long-Term Incentive Plan............. 4,857,064 $ 19.63 6,305,591
Employee Stock Purchase Plan......... - $ - 589,884
Predecessor plans....................... 417,052 $ 25.95 -
--------- ----------
5,274,116 6,895,475
========= ==========
- ---------------
(a) There are no outstanding warrants or equity rights awarded under the
Company's equity compensation plans.
(b) The Company's Long-Term Incentive Plan provides for the issuance of a
maximum number of shares of common stock equal to 10 percent of the total
number of shares of common stock equivalents outstanding less the total
number of shares of common stock subject to outstanding awards under any
stock-based plan for the directors, officers or employees of the Company.
The number of remaining securities available for future issuance under the
Company's Employee Stock Purchase Plan is based on the original authorized
issuance of 750,000 shares less 160,116 cumulative shares issued through
December 31, 2003. See Note G of Notes to Consolidated Financial Statements
included in "Item 8. Financial Statements and Supplementary Data" for a
description of each of the Company's equity compensation plans.
(c) There are no equity compensation plans that have not been approved by
security holders.
24
ITEM 6. SELECTED FINANCIAL DATA
The following selected consolidated financial data as of and for each of
the five years ended December 31, 2003 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,
-----------------------------------------------------
2003 2002 2001 2000 1999
-------- -------- -------- -------- ---------
(in millions, except per share data)
Statement of Operations Data:
Revenues and other income:
Oil and gas................................ $1,298.6 $ 701.8 $ 847.0 $ 852.7 $ 644.6
Interest and other (a)..................... 12.3 11.2 21.8 25.8 89.7
Gain (loss) on disposition of assets, net.. 1.3 4.4 7.7 34.2 (24.2)
------- ------- ------- ------- -------
Total revenues and other income 1,312.2 717.4 876.5 912.7 710.1
------- ------- ------- ------- -------
Costs and expenses:
Oil and gas production..................... 279.5 199.6 209.7 189.3 159.5
Depletion, depreciation and amortization... 390.8 216.4 222.6 214.9 236.1
Impairment of properties and facilities.... - - - - 17.9
Exploration and abandonments............... 132.8 85.9 127.9 87.5 66.0
General and administrative................. 60.5 48.4 37.0 33.3 40.2
Reorganization............................. - - - - 8.5
Accretion of discount on asset retirement
obligations.............................. 5.0 - - - -
Interest................................... 91.4 95.8 131.9 162.0 170.3
Other (b).................................. 21.4 39.5 43.4 79.5 34.7
------- ------- ------- ------- -------
Total costs and expenses 981.4 685.6 772.5 766.5 733.2
------- ------- ------- ------- -------
Income (loss) before income taxes and cumulative
effect of change in accounting principle... 330.8 31.8 104.0 146.2 (23.1)
Income tax benefit (provision) (c)........... 64.4 (5.1) (4.0) 6.0 .6
------- ------- ------- ------- -------
Income (loss) before cumulative effect of change
in accounting principle.................... 395.2 26.7 100.0 152.2 (22.5)
Cumulative effect of change in accounting
principle, net of tax (d).................. 15.4 - - - -
------- ------- ------- ------- -------
Net income (loss)............................ $ 410.6 $ 26.7 $ 100.0 $ 152.2 $ (22.5)
======= ======= ======= ======= =======
Income (loss) before cumulative effect of
change in accounting principle per share:
Basic.................................... $ 3.37 $ .24 $ 1.01 $ 1.53 $ (.22)
======= ======= ======= ======= =======
Diluted.................................. $ 3.33 $ .23 $ 1.00 $ 1.53 $ (.22)
======= ======= ======= ======= =======
Net income (loss) per share:
Basic.................................... $ 3.50 $ .24 $ 1.01 $ 1.53 $ (.22)
======= ======= ======= ======= =======
Diluted.................................. $ 3.46 $ .23 $ 1.00 $ 1.53 $ (.22)
======= ======= ======= ======= =======
Weighted average shares outstanding:
Basic...................................... 117.2 112.5 98.5 99.4 100.3
======= ======= ======= ======= =======
Diluted.................................... 118.5 114.3 99.7 99.8 100.3
======= ======= ======= ======= =======
Balance Sheet Data (as of December 31):
Total assets................................. $3,951.6 $3,455.1 $3,271.1 $2,954.4 $2,929.5
Long-term liabilities........................ $1,749.9 $1,796.9 $1,743.7 $1,804.5 $1,914.5
Total stockholders' equity................... $1,759.8 $1,374.9 $1,285.4 $ 904.9 $ 774.6
- ---------------
(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 2003, 2002, 2001 and 2000 include losses on the early
extinguishment of debt of $1.5 million, $22.3 million, $3.8 million and
$12.3 million, respectively. Other expense for 2000 and 1999 include
noncash mark-to-market charges for changes in the fair values of non-hedge
financial instruments of $58.5 million and $27.0 million, respectively. See
Note O of Notes to Consolidated Financial Statements included in "Item 8.
Financial Statements and Supplementary Data".
(c) The Company's income tax benefit for 2003 includes a $197.7 million
adjustment to reduce United Sates deferred tax asset valuation allowances.
See Note P of Notes to Consolidated Financial Statements included in "Item
8. Financial Statements and Supplementary Data".
(d) The Company's cumulative effect of change in accounting principle relates
to the adoption of SFAS No. 143. See Notes B and L of Notes to Consolidated
Financial Statements included in "Item 8. Financial Statements and
Supplementary Data".
25
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
2003 Highlights
Pioneer's financial and operating results for the year ended December 31,
2003 included the following highlights:
o Production volumes increased 36 percent in 2003 as compared to 2002,
principally due to the completion of the Canyon Express, Falcon and Sable
development projects.
o Oil and gas revenue increased 85 percent in 2003 as a result of the
increased production volumes and increases in North American gas and
worldwide oil prices.
o Pre-tax income increased to $330.8 million from $31.8 million in 2002.
o Pioneer's solid progress towards its strategic objectives over the past
four years and improving key economic indicators, together with other
relevant factors and associated evaluations, led the Company to reverse its
allowances against United States deferred tax assets during 2003. The
reversal of the allowances against United States deferred tax assets
resulted in the recognition of a deferred tax benefit of $197.7 million
during 2003 of which $104.7 million was reversed in the third quarter of
2003 (see Note P of Notes to Consolidated Financial Statements included in
"Item 8. Financial Statements and Supplementary Data" for additional
information regarding the reversal of the allowances against the Company's
United States deferred tax assets).
o Net cash provided by operating activities increased 130 percent to $763.7
million in 2003 as compared to $332.2 million in 2002.
o The Company replaced its $575 million revolving credit facility with a new
five-year $700 million revolving credit agreement with terms similar to
investment grade companies.
o The Company participated in exploration discoveries in the Harrier,
Tomahawk and Raptor fields in the deepwater Gulf of Mexico and the Hawa
field in Tunisia.
o The Company completed a strategic acquisition of the remaining 25 percent
working interest that the Company did not already own in the Falcon field,
Harrier field and surrounding satellite prospects.
o The Company was the high bidder on 53 tracts covering an additional 159,000
acres on the Alaskan North Slope.
o The Company succeeded in obtaining ministerial approval for improved terms
asso