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, 2004
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
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(Exact name of registrant as specified in its charter)
Delaware 75-2702753
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(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
5205 N. O'Connor Blvd., Suite 900, Irving, Texas 75039
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(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
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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 ............................... $4,174,193,054
Number of shares of Common Stock outstanding as of
February 17, 2005.............................................. 143,669,263
Documents Incorporated by Reference:
(1) Proxy Statement for Annual Meeting of Shareholders to be held May 12, 2005
- 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
Evergreen Merger......................................... 5
Mission and Strategies................................... 5
Business Activities...................................... 6
Operations by Geographic Area............................ 8
Marketing of Production.................................. 8
Competition, Markets and Regulations..................... 9
Risks Associated with Business Activities................ 11
Item 2. Properties............................................... 14
Proved Reserves.......................................... 14
Description of Properties................................ 15
Selected Oil and Gas Information......................... 21
Item 3. Legal Proceedings........................................ 25
Item 4. Submission of Matters to a Vote of Security Holders...... 25
PART II
Item 5. Market for Registrant's Common Stock, Related
Stockholder Matters and Issuer Purchases of Equity
Securities............................................... 25
Securities Authorized for Issuance under Equity
Compensation Plans....................................... 26
Purchases of Equity Securities by the Issuer and
Affiliated Purchasers.................................... 27
Item 6. Selected Financial Data.................................. 28
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations...................... 29
2004 Highlights and Events............................... 29
2004 Financial and Operating Performance................. 30
Evergreen Merger......................................... 30
2005 Outlook and Activities.............................. 30
Field Fuel Reporting..................................... 33
Critical Accounting Estimates............................ 33
Results of Operations.................................... 35
Capital Commitments, Capital Resources and Liquidity..... 43
New Accounting Pronouncement............................. 46
2
TABLE OF CONTENTS (CONT.)
Page
Item 7A. Quantitative and Qualitative Disclosures About
Market Risk............................................... 47
Quantitative Disclosures.................................. 48
Qualitative Disclosures................................... 52
Item 8. Financial Statements and Supplementary Data............... 55
Index to Consolidated Financial Statements................ 55
Report of Independent Registered Public Accounting Firm... 56
Consolidated Financial Statements......................... 57
Notes to Consolidated Financial Statements................ 62
Unaudited Supplementary Information....................... 105
Item 9. Changes in and Disagreements With Accountants on
Accounting and Financial Disclosure....................... 112
Item 9A. Controls and Procedures................................... 112
Item 9B. Other Information......................................... 114
PART III
Item 10. Directors and Executive Officers of the Registrant........ 114
Item 11. Executive Compensation.................................... 114
Item 12. Security Ownership of Certain Beneficial Owners
and Management............................................ 114
Item 13. Certain Relationships and Related Transactions............ 114
Item 14. Principal Accountant Fees and Services.................... 114
PART IV
Item 15. Exhibits, Financial Statement Schedules................... 115
Signatures................................................ 121
Exhibit Index............................................. 122
Cautionary Statement Concerning Forward-Looking Statements
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.
3
Definitions of Oil and Gas Terms and Conventions Used Herein
Within this Report, the following oil and gas terms and conventions have
specific meanings:
o "Bbl" means a standard barrel containing 42 United States gallons.
o "Bcf" means one billion cubic feet.
o "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. 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.
o "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.
o "GAAP" means accounting principles that are generally accepted in the
United States.
o "LIBOR" means London Interbank Offered Rate, which is a market rate of
interest.
o "MBbl" means one thousand Bbls.
o "MBOE" means one thousand BOEs.
o "MMBOE" means one million BOEs.
o "Mcf" means one thousand cubic feet and is a measure of natural gas
volume.
o "MMBtu" means one million Btus.
o "MMcf" means one million cubic feet.
o "NGL" means natural gas liquid.
o "NYMEX" means The New York Mercantile Exchange.
o "NYSE" means The New York Stock Exchange.
o "Pioneer" or the "Company" means Pioneer Natural Resources Company and
its subsidiaries.
o "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.
o "SEC" means the United States Securities and Exchange Commission.
o "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 SEC, using prices and costs in
effect at the specified date and a 10 percent discount rate.
o 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 the 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.
o Unless otherwise indicated, all currency amounts are expressed in
U.S. dollars.
4
PART I
ITEM 1. BUSINESS
General
Pioneer is a Delaware corporation whose common stock is listed and traded
on the NYSE. The Company is a large independent oil and gas exploration and
production company with operations in the United States, Argentina, Canada,
Equatorial Guinea, 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 Anchorage, Alaska; Denver,
Colorado; Midland, Texas; Buenos Aires, Argentina; Calgary, Canada; Libreville,
Gabon; Capetown, South Africa and Tunis, Tunisia. At December 31, 2004, the
Company had 1,550 employees, 889 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, D.C. 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 (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.
Evergreen Merger
On September 28, 2004, Pioneer completed its merger with Evergreen
Resources, Inc. ("Evergreen"). Pioneer acquired the common stock of Evergreen
for a total purchase price of approximately $1.8 billion, which was comprised of
cash and Pioneer common stock. At the merger date, Evergreen's proved reserves
were 262.2 MMBOE. Evergreen was a publicly-traded independent oil and gas
company primarily engaged in the production, development, exploration and
acquisition of North American unconventional natural gas. Evergreen was based in
Denver, Colorado and was one of the leading developers of coal bed methane
reserves in the United States. Evergreen's operations were principally focused
on developing and expanding its coal bed methane field located in the Raton
Basin in southern Colorado. Evergreen also had operations in the Piceance Basin
in western Colorado, the Uinta Basin in eastern Utah and the Western Canada
Sedimentary Basin. See Note C of Notes to Consolidated Financial Statements
included in "Item 8. Financial Statements and Supplementary Data" for more
information regarding the Evergreen merger.
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. Since the fourth quarter of 2004, the strategy is also enhanced by
the newly acquired Raton gas field. Underlying these fields are approximately 75
percent of the Company's proved oil and gas reserves as of December 31, 2004.
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 area and Devils Tower projects which began
production in September 2002, March 2003 and May 2004, respectively, and the
5
Sable oil discovery in South Africa which began production in August 2003,
should generate the operating cash flows to fund the Company's $900 million to
$950 million capital budget for 2005 and allow the Company to further enhance
its financial flexibility during 2005.
During 2004, the Company utilized capital from its long-lived Spraberry,
Hugoton and West Panhandle fields and shorter-lived deepwater Gulf of Mexico
projects to partially fund the merger with Evergreen and to selectively reinvest
in assets that the Company believes will offer superior investment returns.
Similarly, during 2005, the Company will continue to: (i) selectively explore
for and develop proved reserve discoveries in areas that it believes will offer
superior reserve growth and profitability potential; (ii) evaluate opportunities
to acquire oil and gas properties under terms that will complement the Company's
exploration and development drilling activities; (iii) invest in the personnel
and technology necessary to maximize the Company's exploration and development
successes; and (iv) enhance liquidity, allowing the Company to take advantage of
future exploration, development and acquisition opportunities. The Company is
committed to continuing to enhance shareholder investment returns through
adherence to these strategies.
Business Activities
The Company is an independent oil and gas exploration and 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 generally been characterized
by rising oil, NGL and gas commodity prices during 2004 and recent years. During
2004, the Company has also been affected by increasing costs, particularly the
cost of steel and higher drilling and well servicing rig rates. World oil prices
have increased in response to political unrest and supply disruptions in Iraq
and Venezuela while North American gas prices have improved as supply and demand
fundamentals have strengthened. Significant factors that will impact 2005
commodity prices include the final resolution of issues currently impacting Iraq
and the Middle East in general, the extent to which members of the Organization
of Petroleum Exporting Countries ("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 "Item 7A. Quantitative and Qualitative Disclosures About
Market Risk" and Note K 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,
2004, 2003 and 2002 from the Company's hedging activities and the Company's open
hedge positions at December 31, 2004.
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,
the Raton gas field located in southern Colorado 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, Equatorial Guinea, 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, Colorado, 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
6
year ended December 31, 2004, the Company's average daily production, on a BOE
basis, increased as a result of (i) gas production beginning in January 2004
from the Company's Harrier gas field in the deepwater Gulf of Mexico, (ii) oil
production beginning in May 2004 from the Company's Devils Tower oil field in
the deepwater Gulf of Mexico, (iii) gas production beginning in June 2004 from
the Company's Raptor and Tomahawk gas fields in the deepwater Gulf of Mexico,
(iv) a full year of gas production from the Company's Falcon field in the
deepwater Gulf of Mexico, (v) a full year of oil production from the Company's
Adam field in Tunisia, (vi) a full year of oil production from the Company's
Sable field offshore South Africa, (vii) increased production from Argentina and
(viii) fourth quarter production from the properties added in the Evergreen
merger. These increases more than offset normal production declines. 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 beginning in 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 in the third quarter of
2002, (iv) oil production beginning in May 2003 from the Company's Adam field in
Tunisia and (v) oil production beginning in 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. Production, price and cost information with respect to
the Company's properties for each of the years ended December 31, 2004, 2003 and
2002 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, 2004, the Company
drilled 1,035 gross (876.8 net) wells, 87 percent of which were successfully
completed as productive wells, at a total drilling cost (net to the Company's
interest) of $1.6 billion. During 2004, the Company drilled 423 gross (384.8
net) wells. The Company's current 2005 capital expenditure budget is expected to
range from $900 million to $950 million. The Company has allocated the budgeted
2005 capital expenditures as follows: approximately 75 percent to development
drilling and facility activities and the balance of approximately 25 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, 2004 include proved undeveloped
reserves and proved developed reserves that are behind pipe of 161.1 MMBOE of
oil and NGLs and 1,356.6 Bcf of gas. Development of these proved 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 proved reserves and unproved prospects
provides attractive development and exploration opportunities for at least the
next three to five years.
Exploratory activities. 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, 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; and the 2002 Borj El Khadra permit discovery in the
Ghadames basin onshore Southern Tunisia. The Company currently anticipates that
its 2005 exploration efforts will be approximately 25 percent of total 2005
capital expenditures and will be concentrated domestically in the Gulf of Mexico
and Alaska, and internationally in Africa, Argentina and Canada. 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, 2004, 2003 and 2002, the Company expended $2.6 billion (including $2.5
billion associated with the Evergreen merger), $151.0 million and $195.5
million, respectively, of acquisition capital to purchase proved oil and gas
7
properties, including additional interests in its existing assets, and to
acquire new prospects for future exploitation and exploration activities. See
Note C of Notes to Consolidated Financial Statements included in "Item 8.
Financial Statements and Supplementary Data" for a description of the Company's
acquisitions during 2004, 2003 and 2002.
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 increasing
financial flexibility through reduced debt levels.
During the years ended December 31, 2004, 2003 and 2002, 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
$1.7 million, $35.7 million and $118.9 million, respectively, which resulted in
net divestiture gains of $39 thousand, $1.3 million and $4.4 million,
respectively. The net cash proceeds were primarily used to fund additions to oil
and gas properties or to reduce the Company's outstanding indebtedness. See Note
O 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, 2004, the Company had oil and gas producing and development
activities in the United States, Argentina, Canada, South Africa and Tunisia,
and had exploration activities in the United States, Argentina, Canada,
Equatorial Guinea, Gabon, South Africa and Tunisia. See Note S 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. In Argentina, the
Company receives significantly lower prices for its production as a result of
the Argentine government's imposed price limitations. See "Qualitative
Disclosures" in "Item 7A. Quantitative and Qualitative Disclosures About Market
Risk" for additional discussion of Argentine foreign currency, operations and
price risk.
Significant purchasers. During the year ended December 31, 2004, the
Company's primary purchasers of oil, NGLs and gas were Williams Power Company,
Inc. (12 percent), Occidental Energy Marketing, Inc. (six percent),
ConocoPhillips (six percent), Enterprise Products Operating L.P. (five percent)
and Plains Marketing LP (four percent). 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 derivative 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
8
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 K 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, 2004, 2003 and 2002 from the Company's commodity hedging activities
and the Company's open commodity hedge positions at December 31, 2004.
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 returns on investment. The principal competitive
factors in the acquisition of oil and gas properties include the staff and data
necessary to identify, investigate and purchase such properties and the
financial resources necessary to acquire and develop 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
9
are inherent in oil and gas operations, and there can be no assurance that
significant costs and liabilities, including potential criminal penalties, will
not be incurred. Moreover, it is possible that other developments, such as
stricter environmental laws and regulations or claims for damages to property or
persons resulting from the Company's operations, could result in substantial
costs and liabilities.
The Comprehensive Environmental Response, Compensation, and Liability Act
("CERCLA"), also known as the "Superfund" law, imposes liability, without regard
to fault or the legality of the original conduct, on certain classes of persons
with respect to the release of a "hazardous substance" into the environment.
These persons include the owner or operator of the disposal site or sites where
the release occurred and companies that disposed or arranged for the disposal of
hazardous substances released at the site. Persons who are or were responsible
for releases of hazardous substances under CERCLA may be subject to joint and
several liability for the costs of cleaning up the hazardous substances that
have been released into the environment and for damages to natural resources,
and it is not uncommon for neighboring landowners and other third parties to
file claims for personal injury and property damage allegedly caused by the
hazardous substances released into the environment.
The Company generates wastes, including hazardous wastes, that are subject
to the federal Resource Conservation and Recovery Act ("RCRA") and comparable
state statutes. The United States Environmental Protection Agency and various
state agencies have limited the approved methods of disposal for certain
hazardous and non-hazardous wastes. Furthermore, certain wastes generated by the
Company's oil and gas operations that are currently exempt from treatment as
hazardous wastes may in the future be designated as hazardous wastes, and
therefore be subject to more rigorous and costly operating and disposal
requirements.
The Company currently owns or leases, and has in the past owned or leased,
properties that for many years have been used for the exploration and production
of oil and gas 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 and foreign
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
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.
10
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, regulatory manager and
regulatory 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
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
goodwill and the recognition of deferred tax asset valuation allowances 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, 2004 and 2003, the Company carried
unproved property costs of $470.4 million and $179.8 million, respectively.
Generally accepted accounting principles require periodic evaluation of these
costs on a project-by-project basis in comparison to their estimated fair 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 costs to develop the reserves, 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
11
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, 2004, 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, adverse weather
effects and pollution and other environmental damage, any of which could result
in substantial losses to the Company due to injury or loss of life, damage to or
destruction of wells, production facilities or other property, clean-up
responsibilities, regulatory investigations and penalties and suspension of
operations. Although the Company currently maintains insurance coverage that it
considers reasonable and that is similar to that maintained by comparable
companies in the oil and gas industry, it is not fully insured against certain
of these risks, either because such insurance is not available or because of the
high premium costs associated with obtaining such insurance.
Environmental. The oil and gas business is subject to environmental
hazards, such as oil spills, 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 Regulations - 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 variable rate credit facilities. The terms of the
Company's borrowings under the senior notes and the credit facilities 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 F 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, 2004 and the terms associated
therewith.
The Company's ability to obtain additional financing is also impacted by
the Company's debt credit ratings. See "Item 7. Management's Discussion and
Analysis of Financial Condition and Results of Operations" for a discussion of
the Company's debt credit ratings.
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 Regulations" above
for additional discussion regarding competition.
12
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 Regulations" above for additional discussion regarding government
regulation.
International operations. At December 31, 2004, approximately 15 percent of
the Company's proved reserves of oil, NGLs and gas were located outside the
United States (12 percent in Argentina, two percent in Canada and one percent in
Africa). The success and profitability of international operations may be
adversely affected by risks associated with international activities, including
economic and labor conditions, political instability, tax laws (including host-
country import-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", "Qualitative Disclosures" in "Item 7A. Quantitative and
Qualitative Disclosures About Market Risk" 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.
Petroleum engineering is a subjective process of estimating underground
accumulations of oil and gas that cannot be measured in an exact manner.
Estimates of economically recoverable oil and gas reserves and of future net
cash flows necessarily depend upon a number of variable factors and assumptions,
including the following:
o historical production from the area compared with production from other
producing areas,
o the quality and quantity of available data,
o the interpretation of that data,
o the assumed effects of regulations by governmental agencies,
o assumptions concerning future oil and gas prices and
o assumptions concerning future operating costs, severance, ad valorem
and excise taxes, development costs and workover and remedial costs.
Because all reserve estimates are to some degree subjective, each of the
following items may differ materially from those assumed in estimating reserves:
o the quantities of oil and gas that are ultimately recovered,
o the production and operating costs incurred,
o the amount and timing of future development expenditures and
o future oil and gas sales prices.
Furthermore, different reserve engineers may make different estimates of
reserves and cash flows based on the same available data. The Company's actual
production, revenues and expenditures with respect to reserves will likely be
different from estimates and the difference may be material.
As required by the SEC, the estimated discounted future net cash flows from
proved reserves are generally based on prices and costs as of the date of the
estimate, while actual future prices and costs may be materially higher or
lower. Actual future net cash flows also will be affected by factors such as:
o the amount and timing of actual production,
o supply and demand of oil and gas,
o increases or decreases in consumption and
o changes in governmental regulations or taxation.
13
The Company reports all proved reserves held under production sharing
arrangements and concessions utilizing the "economic interest" method, which
excludes the host country's share of proved reserves. Estimated quantities of
production sharing arrangements reported under the "economic interest" method
are subject to fluctuations in the price of oil and gas and recoverable
operating expenses and capital costs. If costs remain stable, reserve quantities
attributable to recovery of costs will change inversely to changes in commodity
prices.
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. Therefore, the
estimates of discounted future net cash flows or Standardized Measure in this
Report should not be construed as accurate estimates of the current market value
of the Company's proved reserves.
ITEM 2. PROPERTIES
The information included in this Report about the Company's oil, NGL and
gas reserves as of December 31, 2004 and 2003 was based on reserve reports
audited by Netherland, Sewell & Associates, Inc. ("NSA") 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 audits conducted by NSA in aggregate represented 88 percent and 87
percent of the Company's estimated proved quantities of reserves as of December
31, 2004 and 2003, respectively. The information included in this Report about
the Company's oil, NGL and gas reserves as of December 31, 2002 was, in part,
based on reserve reports audited by independent petroleum engineers and reserve
reports prepared by the Company's engineers. These reserve audits conducted
represented 71 percent of the Company's estimated proved quantities of reserves
as of December 31, 2002.
The Company did not provide estimates of total proved oil and gas reserves
during the years ended December 31, 2004, 2003 or 2002 to any federal authority
or agency, other than the SEC. The Company's reserve estimates do not include
any probable or possible reserves.
Proved Reserves
The Company's proved reserves totaled 1.0 billion BOE, 789.1 MMBOE and
736.7 MMBOE at December 31, 2004, 2003 and 2002, respectively, representing $6.6
billion, $4.6 billion and $4.1 billion, respectively, of Standardized Measure or
$9.1 billion, $6.0 billion and $5.1 billion, respectively, on a pre-tax basis.
The 30 percent and 45 percent increases in proved reserve volumes and
Standardized Measure, respectively, during 2004 were primarily due to:
o Evergreen merger - 262.2 MMBOE,
o other 2004 acquisitions - 16.0 MMBOE,
o extensions and discoveries in:
- Argentina - 25.8 MMBOE,
- United States - 10.5 MMBOE,
- Canada - 2.3 MMBOE and
- Africa - .5 MMBOE,
o negative revisions of 14.3 MMBOE primarily due to:
- 16.6 MMBOE due to the cancellation of the Gabon project as a result
of increasing costs,
- negative well performance in the Portezuelo Oeste gas field in
Argentina, offset by
- increased commodity prices extending the estimated economic life of
various properties,
o production (including field fuel) during 2004 of 68.7 MMBOE and
o divestitures of 1.1 MMBOE.
The seven percent 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
14
reserves resulting from the Company's expanded development drilling program.
Partially offsetting these reserve additions was 2003 production of 56.5 MMBOE,
including field fuel.
On a BOE basis, 65 percent of the Company's total proved reserves at
December 31, 2004 were proved developed reserves. Based on reserve information
as of December 31, 2004, 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 15 years on a BOE basis. The following table provides
information regarding the Company's proved reserves and average daily sales
volumes by geographic area as of and for the year ended December 31, 2004:
PROVED OIL AND GAS RESERVES AND AVERAGE DAILY SALES VOLUMES
2004 Average Daily
Proved Reserves as of December 31, 2004 (a) Sales Volumes (b)
------------------------------------------------- ----------------------------------
Oil Standardardized Oil
& NGLs Gas Measure & NGLs Gas
(MBbls) (MMcf) MBOE (in thousands) (Bbls) (Mcf) BOE
--------- --------- ---------- ----------- -------- --------- ---------
United States..... 363,257 3,000,335 863,313 $ 5,581,303 46,375 521,839 133,349
Argentina......... 33,168 560,374 126,564 647,292 10,080 121,654 30,356
Canada............ 4,095 119,869 24,073 276,467 1,054 41,867 8,031
Africa............ 8,271 - 8,271 138,013 11,676 - 11,676
--------- --------- ---------- ---------- -------- --------- --------
Total............. 408,791 3,680,578 1,022,221 $ 6,643,075 69,185 685,360 183,412
========= ========= ========== ========== ======== ========= ========
- ----------------
(a) The gas reserves contain 271.7 Bcf of gas that will be produced and
utilized as field fuel. Field fuel is gas consumed to operate field
equipment (primarily compressors) prior to the gas being delivered to a
sales point.
(b) The 2004 average daily sales volumes (i) do not include the field fuel
produced, which averaged 4,374 BOE per day and (ii) were calculated using a
366-day year and without making pro forma adjustments for any acquisitions,
divestitures or drilling activity that occurred during the year.
The following table represents the estimated timing and cash flows of
developing the Company's proved undeveloped reserves as of December 31, 2004:
Estimated
Future Future Future Future
Production Cash Production Development Future Net
Years Ended December 31, (MBOE) Inflows Costs Costs Cash Flows
---------- ----------- ----------- ----------- ----------
($ in thousands)
2005............................... 8,534 $ 240,171 $ 28,271 $ 394,289 $ (182,389)
2006............................... 20,625 569,708 70,596 347,878 151,234
2007............................... 21,801 616,401 87,791 214,855 313,755
2008............................... 22,120 613,047 90,579 183,546 338,922
2009............................... 22,716 595,765 95,363 161,118 339,284
Thereafter......................... 257,752 8,085,106 2,133,005 204,888 5,747,213
--------- ---------- --------- --------- ---------
353,548 $10,720,198 $2,505,605 $1,506,574 $6,708,019
========= ========== ========= ========= =========
Description of Properties
As of December 31, 2004, the Company has production, development and/or
exploration operations in the United States, Argentina, Canada, Equatorial
Guinea, Gabon, South Africa and Tunisia.
Domestic. The Company's domestic operations are located in the Permian
Basin, Mid-Continent, Rocky Mountains, Alaska, Gulf of Mexico and onshore Gulf
Coast areas of the United States. Approximately 75 percent of the Company's
domestic proved reserves at December 31, 2004 are located in the Spraberry,
Hugoton, West Panhandle and Raton fields. These mature fields generate
substantial operating cash flow and some have a large portfolio of low risk
15
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, 2004,
the Company expended $2.9 billion in domestic acquisition, exploration and
development drilling activities, $2.5 billion of which related to the Evergreen
merger. The Company has budgeted approximately $700 million for domestic
exploration and development drilling expenditures for 2005.
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. The oil and gas is 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 wells 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 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, 2004, the Company placed 104 Spraberry
wells on production and had 16 wells in progress as of December 31, 2004. The
Company plans to drill approximately 150 development wells in the Spraberry
field during 2005.
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 gas in the Hugoton field has an average energy content
of 1,025 Btu. 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
90.5 MMcf of wet gas per day (i.e., gas production at the wellhead before
processing or field fuel use 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,
2004. During 2004, the Company placed 17 development wells on production and had
one well in progress as of December 31, 2004. The plans for 2005 include
drilling approximately 18 development wells and one potential new horizontal
well.
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 and is produced from approximately 600 wells on more than
250,000 gross acres covering over 375 square miles. The Company controls 100
percent of the wells, production equipment, gathering system and gas processing
plant for the field.
During the year ended December 31, 2004, the Company placed 78 development
wells on production and drilled three development wells and two extension wells
which were determined to be unsuccessful. The West Panhandle field had 11
development wells in progress as of December 31, 2004. The Company plans to
drill approximately 90 wells in the West Panhandle field during 2005.
16
Rocky Mountain area. The Company is one of the leading U.S. producers of
coal bed methane ("CBM") with the Raton, Piceance and Uinta Basin assets
acquired from Evergreen which are situated in Colorado and Utah. Exploration for
CBM in the Raton Basin began in the late 1970s and continued through the late
1980s, with several companies drilling and testing more than 100 wells during
this period. The absence of a pipeline to transport gas from the Raton Basin
prevented full scale development until January 1995, when Colorado Interstate
Gas Company completed the construction of the Picketwire lateral. The Company
owns approximately 385,000 gross acres in the center of the Raton Basin with
current production from coal seams of the Vermejo and Raton formations. The
Company also owns approximately 171,000 acres covering highly prospective
regions of the Piceance and Uinta Basins. Currently, production is established
from various tight sandstone, coal and shale formations. The Company has
approximately 1,300 wells in these fields with an average daily gross measured
production of 191 MMcf. In the fourth quarter of 2004, the Company placed 49
development wells on production and drilled two successful extension wells.
Plans for 2005 include the drilling of approximately 300 development wells and
20 extension wells to establish additional prospective areas and reserves.
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.
In the deepwater Gulf of Mexico, the Company has three major projects, all
of which were producing or capable of producing at December 31, 2004:
o Canyon Express - The Canyon Express 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 2005.
o Falcon Corridor - The Falcon Corridor project started with the
Company's Falcon field discovery during 2001, followed by the 2003
Harrier, Raptor and Tomahawk discoveries. The Company owned a 45
percent working interest in the initial Falcon discovery and
surrounding areas. During 2002, the Company purchased an
additional 30 percent working interest in the project and became
the operator. During 2003, the Company acquired the remaining 25
percent working interest in the project and established first
Falcon production during March 2003.
In the first quarter of 2003, the Company drilled its Harrier
discovery, which was completed as a one-well subsea tie-back to
the Falcon field facilities and placed on production in January
2004. In addition, during the third quarter of 2003, the Company
successfully drilled the Tomahawk and Raptor prospects, which were
also developed as single-well subsea tie-backs to the Falcon field
facilities and placed on production in June 2004. To accommodate
the incremental production from Harrier, Tomahawk and Raptor, as
well as potential throughput associated with additional planned
exploration, an additional parallel pipeline connecting the Falcon
field to the Falcon Nest platform on the Gulf of Mexico shelf was
added, doubling its capacity. In early September 2004, the Company
shut in production from the Harrier field as a result of early
water encroachment. The Company initiated a sidetrack well in late
September to access an adjacent fault block in the field which was
successful, encountering over 400 feet of gas-bearing sand. In
order to capture the maximum reserves from the Raptor and Tomahawk
fields, the Company delayed production from the Harrier sidetrack
until the Tomahawk field was fully depleted in December 2004. Once
the Harrier sidetrack was placed on production, the Falcon field
production rate was reduced to continue to allow Raptor to fully
deplete. Raptor is anticipated to be depleted during the first
half of 2005, at which time production from Falcon will be
increased. The Company operates all of the producing fields in the
17
Falcon Corridor. Sidetrack operations are being evaluated for the
Raptor field in 2005 to further increase reserve recovery. In
addition, the Company plans to drill one or two Falcon Corridor
exploration prospects during the first half of 2005.
o Devils Tower Area - 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 spar has slots for eight dry tree wells and up to four
subsea tie-back risers and is capable of handling 60 MBbls of oil
per day and 60 MMcf of gas per day. Three Devils Tower wells were
completed and placed on production prior to being shut-in during
mid-September due to Hurricane Ivan. The Devils Tower spar
sustained significant damage during Hurricane Ivan, and production
from the three wells did not resume until late October 2004. A
fourth well began producing at the end of November. The damage to
the platform rig sustained during Hurricane Ivan delayed
completion activities related to the four additional wells
previously drilled to develop the field. Rig repairs took 120
days, and completion activities for continued field development
began late in January 2005. Pioneer maintains business
interruption insurance and has filed a claim related to four wells
that were expected to be completed but were delayed due to the
effects of the hurricane. In the fourth quarter of 2004, the
Company recorded approximately $7.5 million of estimated business
interruption recovery related to its estimated 2004 production
loss and should have additional insurance recoveries associated
with 2005 operational impact from Hurricane Ivan. In addition,
three subsea tie-back wells in the Goldfinger and Triton satellite
discoveries in the Devils Tower area are expected to be jointly
tied back to the Devils Tower spar with first production expected
in late 2005. Production is expected to continue to increase as
additional wells are individually completed from the spar over the
next six months. The Company holds a 25 percent working interest
in each of the above projects.
In addition to the development and exploration projects in the deepwater
Gulf of Mexico described above, the Company participated in three subsalt
deepwater prospects during the first half of 2004, of which one well was
successful and two were noncommercial. A sidetrack well in the Dominion-operated
Thunder Hawk discovery at Mississippi Canyon Block 734 encountered in excess of
300 feet of net oil pay in two high-quality reservoir zones. Murphy Exploration
and Production Company is now the operator and has commenced drilling an
additional well to further delineate the field. The Company owns a 12.5 percent
working interest in the discovery. The Company also anticipates drilling an
appraisal well during 2005 on its 2002 Ozona Deep discovery.
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 originally scheduled to be drilled in 2003 and three in 2004.
Most of the wells to be drilled under the agreement target gas plays below
15,000 feet. The first three wells under this joint agreement were unsuccessful.
The fourth well, Midway, 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 quarter of 2005. 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 Company has a
37.5 percent working interest in this well. The fifth well that was originally
scheduled to be drilled in 2003 and the three wells originally scheduled to be
drilled in 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 2005 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 10 development wells and two extension wells on production at
Pawnee during 2004 and had two development wells and one extension well in
progress at year end. The Company plans to drill approximately 12 wells in this
area during 2005.
Alaska area. The Company spent $34.7 million of acquisition and seismic
capital during 2004 to add to its leasehold position and expand its North Slope
seismic data coverage. In June 2004, Pioneer announced that it agreed to a joint
exploration program in the National Petroleum Reserve-Alaska ("NPR-A") located
on the North Slope with ConocoPhillips and Anadarko Petroleum Corporation. At
the federal lease sale held in June 2004, P ioneer was the high co-bidder on 63
18
tracts covering approximately 717,000 acres in the NPR-A Northwest Planning
Area. Pioneer will participate with a 20 percent to 30 percent working interest
in the acreage operated by ConocoPhillips. Pioneer also acquired a 20 percent
interest in 167,000 total acres in the adjacent NPR-A Northeast Planning Area
and in federal offshore blocks, including seismic and geologic data. In December
2004, Pioneer signed an exploration agreement with ConocoPhillips and Anadarko
acquiring a 20 percent interest in approximately 452,000 additional acres and
gaining the rights to extensive seismic and geologic data in the NPR-A Northeast
Planning Area. Pioneer expects to participate in a multi-year exploration
program within NPR-A and anticipates that two exploration wells will be drilled
during the first half of 2005.
During the first quarter of 2005, Pioneer will also participate with a 40
percent working interest in an exploration well to evaluate the Kerr-McGee
Corporation - Tuvaaq prospect. In addition, Pioneer holds a 50 percent working
interest in a 130,000-acre position adjacent to and south of the giant Prudhoe
Bay and Kuparuk Units and has a new 3-D seismic survey underway for completion
during the first quarter of 2005.
During 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 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 rate of approximately 1,300 barrels per
day. In January 2004, the Company farmed-into a large acreage block to the
southwest of the Company's discovery. In the fourth quarter of 2004, Pioneer
completed an extensive technical and economic evaluation of the resource
potential within this area. As a result of this evaluation, the Company is
performing front-end engineering and permitting activities to further define the
scope of the project. If the additional work confirms favorable development
economics, Pioneer will seek to obtain regulatory approval to develop the field
in 2006 targeting first oil in 2008.
International. The Company's international operations are located in the
Neuquen and Austral Basins areas of Argentina, the Chinchaga, Martin Creek,
Lookout Butte and Carbon areas of Canada, the Sable oil field offshore South
Africa and in southern Tunisia. Additionally, the Company has other development
and exploration activities in the shallow waters offshore South Africa and oil
development and exploration activities in Tunisia. As of December 31, 2004,
approximately 12 percent, two percent and one percent of the Company's proved
reserves are located in Argentina, Canada and Africa, respectively.
Argentina. The Company's Argentine production during the year ended
December 31, 2004 averaged 30.4 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 - Ni, the Dos Hermanas, the Anticlinal Campamento and the
Estacion Fernandez Oro blocks, 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, 2004, the Company expended $102.5
million on Argentine development and exploration activities. The Company drilled
44 development wells and 31 extension/exploratory wells, of which 43 development
wells and 21 extension/exploratory wells were successful. During 2004, the
Company shot seismic covering approximately 330,000 acres. The Company plans to
be more active in Argentina in 2005 with $133 million budgeted for oil and gas
development and exploration activities.
Canada. The Company's Canadian producing properties are located primarily
in Alberta and British Columbia, Canada. Production during the year ended
December 31, 2004 averaged 8.0 MBOE per day, or approximately four percent of
the Company's equivalent production. The Company continues to focus its
traditional conventional development, exploration and acquisition activities in
19
the core areas of northeast British Columbia and southern Alberta while
expanding these activities to include a CBM focus in southern Alberta. The
Canadian assets are geographically concentrated, predominately shallow gas and
primarily operated by the Company in the following areas: Chinchaga, Martin
Creek, Lookout Butte and Carbon.
Production from the Chinchaga area of northeast British Columbia is
relatively dry gas from formation depths averaging 3,400 feet. In the Martin
Creek area of British Columbia the production is relatively dry gas from various
reservoirs ranging from 3,700 to 4,300 feet. The Lookout Butte area in southwest
Alberta produces gas and condensate from the Mississippian Turner Valley
formation at approximately 12,000 feet. The Carbon area in south central Alberta
produces gas, CBM, condensate and minor oil from Cretaceous to Devonian
formations at depths ranging from 400 to 6,500 feet.
During the year ended December 31, 2004, the Company expended $120.6
million (approximately $56.4 million associated with the Evergreen merger) on
Canadian exploration, development and acquisition activities. The Company
drilled three development wells and 51 exploratory/extension wells, primarily in
the Chinchaga, Martin Creek and Carbon areas, of which all three developments
wells and 27 exploratory/extension wells were successful. The majority of these
wells were drilled in the Chinchaga and Martin Creek areas during the first
quarter of 2004 as these areas are only accessible for drilling during the
winter months. The remainder of these wells were drilled during the summer and
fall in the Carbon area that is accessible for operations throughout the year.
The Company plans to spend approximately $60 million on oil, gas and CBM
development and exploration opportunities in Canada during 2005.
The Company previously announced its intention to divest of its Martin
Creek and Lookout Butte assets in 2005. The expectation is that sales proceeds
will exceed $100 million based on today's commodity price environment, however,
no assurance can be given that purchasers will bid for these assets at prices
that are acceptable to the Company.
Africa. In Africa, the Company has entered into agreements to explore for
oil and gas in South Africa, Equatorial Guinea, 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 three
categories: (i) three permits covering 2.9 million acres which the Company
operates with an average 55 percent working interest, (ii) the Anadarko-operated
Anaguid and Jenein Nord permits covering over 1.5 million acres in which the
Company has a 45 percent working interest and (iii) the ENI-operated Adam
Concession and Borj El Khadra permit covering 212,420 acres and 969,755 acres,
respectively, in which the Company has a 28 percent and 40 percent working
interest, respectively. All permits are onshore southern Tunisia. During the
year ended December 31, 2004, the Company expended $74.9 million of acquisition,
development and exploration drilling and seismic capital in South Africa, Gabon,
Equatorial Guinea, Tunisia and other prospective areas.
South Africa. The Company spent $9.5 million of capital associated with its
Petro SA-operated Sable oil field. The Sable oil field began producing in August
2003. The Company has a 40 percent working interest in the Sable field. In 2005,
the Company currently plans to spend approximately $1 million in South Africa
for production enhancement opportunities at Sable.
In 2005, the Company expects its South African gas project to be sanctioned
by all parties. If approved, this project will allow the Company to sell its gas
from the Sable field and provide commercialization opportunities for previous
gas discoveries.
Equatorial Guinea. The Company spent $13.0 million of acquisition and
drilling capital during 2004 to acquire a 50 percent working interest in 244,881
acres of Block H offshore Equatorial Guinea. The Bravo 1 well was drilled in
June 2004 and determined to be noncommercial. The Company has several other
prospects on the block that are being evaluated for future drilling, one of
which is expected to be drilled during 2005.
Gabon. The Company spent $20.7 million of capital during 2004 to drill five
exploration wells, one of which was initially evaluated as successful in
extending the planned development area to the south. The remaining four wells
were unsuccessful. Despite the successful extension well, in October 2004, the
Company canceled the development of the Olowi field due to a substantial
increase in projected development costs which resulted in the project not
20
offering competitive returns. The Company's current Gabonese permit expires in
April 2005. The Company has verbally requested an extension to the permit to
allow more time for the Company to determine the best manner to exit Gabon,
however, no assurance can be given that such extension will be granted. In 2004,
the Company recognized an impairment charge of approximately $39.7 million.
Tunisia. The Company spent $17.0 million of acquisition, drilling and
seismic capital during the year ended December 31, 2004 primarily to drill one
successful development well in its Adam oil field, one successful development
well in its Hawa oil field and one successful exploratory well in its Dalia oil
field, all within the ENI-operated Adam Concession. Production from the Adam
Concession began in May 2003. The capital budget for Tunisia in 2005 of
approximately $24 million includes an exploration well in the Adam concession,
one exploration well on the Company-operated El Hamra permit and two appraisal
wells on the Anaguid permit.
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, 2004, 2003 and 2002.
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, 2004, 2003 and 2002:
21
PRODUCTION, PRICE AND COST DATA
Year Ended December 31,
-------------------------------------------------------------------------------------------------------------------
2004 2003 2002
------------------------------------- ------------------------------------------ ----------------------------------
United United United
States Argentina Canada Africa Total States Argentina Canada Africa Total States Argentina Canada Total
------ --------- ------ ------ ------- ------- --------- ------- ------ -------- ------- --------- ------- --------
Production
information:
Annual sales
volumes:
Oil (MBbls)... 9,750 3,123 50 4,274 17,197 8,952 3,171 40 723 12,886 8,555 2,914 45 11,514
NGLs (MBbls).. 7,224 566 336 - 8,126 7,423 481 331 - 8,235 7,487 254 345 8,086
Gas (MMcf)....190,994 44,525 15,323 - 250,842 154,400 34,357 15,209 - 203,966 77,199 28,550 17,653 123,402
Total (MBOE).. 48,806 11,110 2,939 4,274 67,129 42,108 9,378 2,906 723 55,115 28,908 7,926 3,333 40,167
Average daily
sales volumes:
Oil (Bbls).... 26,637 8,534 137 11,676 46,984 24,525 8,687 111 1,981 35,304 23,437 7,984 124 31,545
NGLs (Bbls)... 19,738 1,546 917 - 22,201 20,338 1,318 906 - 22,562 20,512 696 946 22,154
Gas (Mcf).....521,839 121,654 41,867 - 685,360 423,013 94,128 41,669 - 558,810 211,502 78,220 48,365 338,087
Total (BOE)...133,349 30,356 8,031 11,676 183,412 115,364 25,694 7,962 1,981 151,001 79,201 21,716 9,131 110,048
Average prices,
including hedge
results:
Oil (per Bbl).$ 29.41 $ 28.06 $ 44.83 $38.12 $ 31.38 $ 25.25 $ 25.62 $29.10 $29.52 $ 25.59 $23.66 $ 20.63 $22.26 $ 22.89
NGLs (per
Bbl).........$ 25.07 $ 29.91 $ 30.87 $ - $ 25.65 $ 19.04 $ 22.85 $24.80 $ - $ 19.50 $13.77 $ 14.56 $16.77 $ 13.92
Gas (per Mcf).$ 5.15 $ .66 $ 4.64 $ - $ 4.33 $ 4.47 $ .56 $ 4.93 $ - $ 3.84 $ 3.16 $ .48 $ 3.41 $ 2.58
Revenue (per
BOE).........$ 29.75 $ 12.07 $ 28.49 $38.12 $ 27.30 $ 25.10 $ 11.87 $29.05 $29.52 $ 23.11 $19.01 $ 9.79 $20.12 $ 17.29
Average prices,
excluding hedge
results:
Oil (per Bbl).$ 39.59 $ 29.82 $ 44.83 $38.71 $ 37.61 $ 29.58 $ 26.31 $29.10 $30.07 $ 28.80 $23.85 $ 20.33 $22.26 $ 22.95
NGLs (per
Bbl).........$ 25.07 $ 29.91 $ 30.87 $ - $ 25.65 $ 19.04 $ 22.85 $24.80 $ - $ 19.50 $13.77 $ 14.56 $16.77 $ 13.92
Gas (per Mcf).$ 5.72 $ .66 $ 5.75 $ - $ 4.83 $ 4.92 $ .56 $ 5.30 $ - $ 4.25 $ 3.01 $ .48 $ 3.32 $ 2.52
Revenue (per
BOE).......$ 34.01 $ 12.56 $ 31.89 $38.71 $ 30.77 $ 27.69 $ 12.10 $30.98 $30.07 $ 25.24 $18.66 $ 9.68 $19.63 $ 16.97
Average costs
(per BOE):
Production costs:
Lease
operating.$ 3.45 $ 2.75 $ 9.69 $ 7.37 $ 3.86 $ 3.20 $ 2.57 $ 9.49 $ 3.87 $ 3.42 $ 3.42 $ 1.61 $ 7.50 $ 3.40
Taxes:
Ad valorem. .58 - - - .42 .53 - - - .41 .78 - - .56
Production. .83 .23 - - .64 .79 .20 - .12 .64 .74 .13 - .56
Workover..... .25 .01 .95 - .23 .16 .01 .43 - .15 .29 .01 .59 .26
------ ------ ------ ----- ------ ------ ----- ----- ----- ------ ----- ------ ----- ------
Total.....$ 5.11 $ 2.99 $ 10.64 $ 7.37 $ 5.15 $ 4.68 $ 2.78 $ 9.92 $ 3.99 $ 4.62 $ 5.23 $ 1.75 $ 8.09 $ 4.78
====== ====== ====== ===== ====== ====== ====== ===== ===== ====== ===== ====== ===== =======
Depletion
expense.......$ 8.61 $ 5.56 $ 10.93 $11.19 $ 8.37 $ 7.08 $ 4.96 $ 9.98 $10.69 $ 6.92 $ 4.85 $ 5.00 $ 8.36 $ 5.17
====== ====== ====== ===== ====== ====== ====== ===== ===== ====== ===== ====== ===== =======
- ---------------------------------------------------------------------------------
o 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.
o During 2004, the Company changed its treatment of field fuel, which is gas
consumed to operate field equipment, to exclude the field fuel gas from
sales volumes, oil and gas revenues and production costs. In prior years,
the field fuel gas was included in sales volumes, oil and gas revenues and
production costs. The prior period amounts have been adjusted to reflect
the Company's current treatment of field fuel. Accordingly, the gas sales
volumes above represent gas available for sale. These amounts will not
agree to the reserve volume tables in the "Unaudited Supplemental Data"
section included in "Item 8. Financial Statements and Supplemenal Data"
because field fuel volumes are included in production volumes in the
reserve volume tables. See Note B of Notes to Consolidated Financial
Statements included in "Item 8. Financial Statements and Supplemental Data"
for additional discussion.
o During 2004, the Company changed its treatment of Canadian gas
transportation costs to include these costs as a component of oil and gas
production costs. In prior years, transportation costs were recorded as a
reduction to oil and gas revenues. The prior period amounts have been
adjusted to reflect the Company's current treatment of Canadian gas
transportation costs. See Note B of Notes to Consolidated Financial
Statements included in "Item 8. Financial Statements and Supplemental Data"
for additional discussion.
o The Company's lower average prices received for its Argentine commodities,
as compared to the prices received in other countries, is due to price
limitations imposed by the Argentine government in an effort to keep fuel
and energy prices for Argentine consumers at pre-devaluation levels. These
limitations have kept the prices received for oil and gas sales in
Argentina well below world market levels. Beginning in 2004, the government
has allowed gas prices to increase gradually over time, but other than
those specific increases already established for gas prices in 2005, no
specific predictions can be made about the future of oil or gas prices in
Argentina. See "Qualitative Disclosures" in "Item 7A. Quantitative and
Qualitative Disclosures About Market Risk" for additional discussion of
Argentine foreign currency, operations and price risk.
- --------------------------------------------------------------------------------
22
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,
2004, 2003 and 2002:
PRODUCTIVE WELLS (a)
Gross Productive Wells Net Productive Wells
----------------------------- -----------------------------
Oil Gas Total Oil Gas Total
------- ------- ------- ------- ------- --------
As of December 31, 2004:
United States............... 3,999 3,990 7,989 3,288 3,563 6,851
Argentina................... 744 226 970 607 168 775
Canada...................... 38 489 527 25 358 383
Africa...................... 9 - 9 3 - 3
------- ------- ------- ------- ------- -------
Total.................... 4,790 4,705 9,495 3,923 4,089 8,012
======= ======= ======= ======= ======= =======
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...................... 7 - 7 2 - 2
------- ------- ------- ------- ------- -------
Total.................... 4,371 2,474 6,845 3,523 2,258 5,781
======= ======= ======= ======= ======= =======
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
======= ======= ======= ======= ======= =======
- ---------------
(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. If any well in which one of the multiple
completions is an oil completion, then the well is classified as an oil
well. As of December 31, 2004, the Company owned interests in 335 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, 2004:
LEASEHOLD ACREAGE
Developed Acreage Undeveloped Acreage
------------------------- ------------------------- Royalty
Gross Acres Net Acres Gross Acres Net Acres Acreage
----------- ---------- ----------- ---------- ---------
United States:
Onshore................ 1,340,476 1,148,765 458,955 349,065 286,048
Offshore............... 114,573 53,078 2,122,351 1,130,895 10,500
---------- ---------- ---------- ---------- ---------
1,455,049 1,201,843 2,581,306 1,479,960 296,548
Argentina................. 728,000 333,000 1,139,000 1,056,000 -
Canada.................... 280,000 198,000 504,000 371,000 30,000
Africa.................... 222,020 63,318 11,406,804 6,611,566 -
---------- ---------- ---------- ---------- ---------
Total.................. 2,685,069 1,796,161 15,631,110 9,518,526 326,548
========== ========== ========== ========== =========
23
The following table sets forth the expiration dates of the leases on the
Company's gross and net undeveloped acres as of December 31, 2004:
Acres Expiring (a)
----------------------------
Gross Net
----------- ------------
2005 (b)............................ 3,928,789 3,038,128
2006................................ 3,073,584 1,580,639
2007................................ 5,118,053 2,441,124
2008................................ 190,249 172,005
2009................................ 576,433 183,463
Thereafter.......................... 2,744,002 2,103,167
----------- -----------
Total............................ 15,631,110 9,518,526
=========== ===========
- --------------
(a) Acres expiring are based on contractual lease maturities.
(b) Acres subject to expiration during 2005 include 1.8 million gross and net
acres in South Africa block 14, 1.7 million gross acres (.8 million net
acres) in Tunisia, 314 thousand gross and net acres in Gabon and 179
thousand gross acres (131 thousand net acres) in North America. The Company
may extend these leases prior to their expiration based upon 2005 planned
activities or for other business reasons. However, no assurance can be
given that such lease extensions will be granted. In certain of these
leases, the extension is only subject to the Company's election to extend
and the fulfillment of certain capital expenditure commitments. See
"Description of Properties" above for information regarding the Company's
drilling operations.
Drilling activities. The following table sets forth the number of gross and
net productive and dry hole wells in which the Company had an interest that were
drilled during the years ended December 31, 2004, 2003 and 2002. 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,
-------------------------- --------------------------
2004 2003 2002 2004 2003 2002
------ ------ ------ ----- ------ ------
United States:
Productive wells:
Development................... 268 244 148 243.1 210.5 83.0
Exploratory................... 8 4 6 5.3 4.0 2.0
Dry holes:
Development................... 3 6 4 3.0 6.0 3.7
Exploratory................... 6 6 3 3.0 3.6 2.1
----- ----- ----- ----- ------ ------
285 260 161 254.4 224.1 90.8
----- ----- ----- ----- ------ ------
Argentina:
Productive wells:
Development................... 43 29 13 41.7 29.0 13.0
Exploratory................... 21 21 9 21.0 21.0 9.0
Dry holes:
Development................... 1 2 1 1.0 2.0 1.0
Exploratory................... 10 9 8 9.5 9.0 8.0
----- ----- ----- ----- ------ ------
75 61 31 73.2 61.0 31.0
----- ----- ----- ----- ------ ------
Canada:
Productive wells:
Development................... 3 7 13 3.0 7.0 10.4
Exploratory................... 27 16 9 24.5 14.9 9.0
Dry holes:
Development................... - 7 4 - 6.5 4.0
Exploratory................... 24 26 3 23.3 21.1 3.0
----- ----- ----- ----- ------ ------
54 56 29 50.8 49.5 26.4
----- ----- ----- ----- ------ ------
Africa:
Productive wells:
Development................... 2 1 4 .6 .3 1.6
Exploratory................... 2 1 4 1.4 .4 3.4
Dry holes:
Development................... - - - - - -
Exploratory................... 5 4 - 4.4 3.5 -
----- ----- ----- ----- ------ ------
9 6 8 6.4 4.2 5.0
----- ----- ----- ----- ------ ------
Total.......................... 423 383 229 384.8 338.8 153.2
===== ===== ===== ===== ====== ======
Success ratio (a)................. 88% 84% 90% 89% 85% 86%
- ---------------
(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.
</