UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
/ X / ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2003
or
/ / TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from _______ to ________
Commission File Number: 1-13245
Pioneer Natural Resources Company
(Exact name of registrant as specified in its charter)
Delaware 75-2702753
------------------------------------ ---------------------
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
5205 N. O'Connor Blvd., Suite 900, Irving, Texas 75039
- ------------------------------------------------ --------------
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: (972) 444-9001
Securities registered pursuant to Section 12(b) of the Act:
Name of each exchange
Title of each class on which registered
------------------- -----------------------
Common Stock................................. New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark whether the Registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the Registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days. YES X NO
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to the
best of Registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [ ]
Indicate by check mark whether the Registrant is an accelerated filer (as
defined in Rule 12b-2 of the Act).
YES X NO ___
----
Aggregate market value of the voting common equity held by non-affiliates of the
Registrant computed by reference to the price at which the common equity was
last sold as of the last business day of the Registrant's most recently
completed second fiscal quarter ........................... $ 3,053,790,906
Number of shares of Common Stock outstanding as of
January 30, 2004........................................... 119,345,550
Documents Incorporated by Reference:
(1) Proxy Statement for Annual Meeting of Shareholders to be held May 13, 2004
- Referenced in Part III of this report.
TABLE OF CONTENTS
Page
Definitions of Oil and Gas Terms and Conventions Used Herein........... 4
PART I
Item 1. Business.................................................... 5
General..................................................... 5
Available Information....................................... 5
Mission and Strategies...................................... 5
Business Activities......................................... 6
Operations by Geographic Area............................... 8
Marketing of Production..................................... 8
Competition, Markets and Regulations........................ 8
Risks Associated with Business Activities................... 10
Item 2. Properties.................................................. 13
Proved Reserves............................................. 13
Finding Cost and Reserve Replacement........................ 14
Description of Properties................................... 14
Selected Oil and Gas Information............................ 19
Item 3. Legal Proceedings........................................... 23
Item 4. Submission of Matters to a Vote of Security Holders......... 23
PART II
Item 5. Market for Registrant's Common Stock and Related
Stockholder Matters......................................... 23
Securities Authorized for Issuance under Equity
Compensation Plans.......................................... 24
Item 6. Selected Financial Data..................................... 25
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations....................... 26
2003 Highlights............................................. 26
2003 Financial and Operating Performance.................... 26
2004 Outlook................................................ 27
Critical Accounting Estimates............................... 29
Results of Operations....................................... 31
Capital Commitments, Capital Resources and Liquidity........ 37
New Accounting Development.................................. 40
2
TABLE OF CONTENTS
Page
Item 7A. Quantitative and Qualitative Disclosures About
Market Risk................................................. 40
Quantitative Disclosures.................................... 40
Qualitative Disclosures..................................... 43
Item 8. Financial Statements and Supplementary Data................. 43
Index to Consolidated Financial Statements.................. 43
Independent Auditors' Report................................ 44
Consolidated Financial Statements........................... 45
Notes to Consolidated Financial Statements.................. 50
Unaudited Supplementary Information......................... 88
Item 9. Changes in and Disagreements With Accountants on
Accounting and Financial Disclosure......................... 94
Item 9A. Controls and Procedures..................................... 94
PART III
Item 10. Directors and Executive Officers of the Registrant.......... 94
Item 11. Executive Compensation...................................... 94
Item 12. Security Ownership of Certain Beneficial Owners and
Management and Related Stockholder Matters.................. 94
Item 13. Certain Relationships and Related Transactions.............. 94
Item 14. Principal Accountant Fees and Services...................... 94
PART IV
Item 15. Exhibits, Financial Statement Schedules, and Reports
on Form 8-K................................................. 95
Signatures.................................................. 100
Exhibit Index............................................... 101
3
Parts I and II of this annual report on Form 10-K (the "Report") contain
forward-looking statements that involve risks and uncertainties. Accordingly, no
assurances can be given that the actual events and results will not be
materially different than the anticipated results described in the forward
looking statements. See "Item 1. Business - Competition, Markets and
Regulations" and "Item 1. Business - Risks Associated with Business Activities"
for a description of various factors that could materially affect the ability of
Pioneer Natural Resources Company to achieve the anticipated results described
in the forward-looking statements.
Definitions of Oil and Gas Terms and Conventions Used Herein
Within this Report, the following oil and gas terms and conventions have
specific meanings: "Bbl" means a standard barrel containing 42 United States
gallons; "BOE" means a barrel of oil equivalent and is a standard convention
used to express oil and gas volumes on a comparable oil equivalent basis; "Btu"
means British thermal unit and is a measure of the amount of energy required to
raise the temperature of one pound of water one degree Fahrenheit; "LIBOR" means
London Interbank Offered Rate, which is a market rate of interest; "MMBtu" means
one million Btus; "MBbl" means one thousand Bbls; "MBOE" means one thousand BOE;
"MMBOE" means one million BOE; "Mcf" means one thousand cubic feet and is a
measure of natural gas volume; "MMcf" means one million cubic feet; "Bcf" means
one billion cubic feet; "NGL" means natural gas liquid; "NYMEX" means The New
York Mercantile Exchange; "proved reserves" mean the estimated quantities of
crude oil, natural gas, and natural gas liquids which geological and engineering
data demonstrate with reasonable certainty to be recoverable in future years
from known reservoirs under existing economic and operating conditions, i.e.,
prices and costs as of the date the estimate is made. Prices include
consideration of changes in existing prices provided only by contractual
arrangements, but not on escalations based upon future conditions.
(i) Reservoirs are considered proved if economic producibility is supported
by either actual production or conclusive formation test. The area of a
reservoir considered proved includes (A) that portion delineated by drilling and
defined by gas-oil and/or oil-water contacts, if any; and (B) the immediately
adjoining portions not yet drilled, but which can be reasonably judged as
economically productive on the basis of available geological and engineering
data. In the absence of information on fluid contacts, the lowest known
structural occurrence of hydrocarbons controls the lower proved limit of the
reservoir.
(ii) Reserves which can be produced economically through application of
improved recovery techniques (such as fluid injection) are included in the
"proved" classification when successful testing by a pilot project, or the
operation of an installed program in the reservoir, provides support for the
engineering analysis on which the project or program was based.
(iii) Estimates of proved reserves do not include the following: (A) oil
that may become available from known reservoirs but is classified separately as
"indicated additional reserves"; (B) crude oil, natural gas, and natural gas
liquids, the recovery of which is subject to reasonable doubt because of
uncertainty as to geology, reservoir characteristics, or economic factors; (C)
crude oil, natural gas, and natural gas liquids, that may occur in undrilled
prospects; and (D) crude oil, natural gas, and natural gas liquids, that may be
recovered from oil shales, coal, gilsonite and other such sources.
"Standardized Measure" means the after-tax present value of estimated
future net revenues of proved reserves, determined in accordance with the rules
and regulations of the United States Securities and Exchange Commission (the
"SEC"), using prices and costs in effect at the specified date and a 10 percent
discount rate; "acquisition and finding cost per BOE" means total costs incurred
divided by the summation of proved reserves attributable to revisions of
previous estimates, purchases of minerals-in-place and new discoveries and
extensions; and "reserve replacement percentage" means, expressed as a
percentage, the summation of annual proved reserves, on a BOE basis,
attributable to revisions of previous estimates, purchases of minerals-in-place
and new discoveries and extensions divided by annual production of oil, NGLs and
gas, on a BOE basis.
Gas equivalents are determined under the relative energy content method by
using the ratio of 6.0 Mcf of gas to 1.0 Bbl of oil or NGL.
With respect to information on the working interest in wells, drilling
locations and acreage, "net" wells, drilling locations and acres are determined
by multiplying "gross" wells, drilling locations and acres by Pioneer Natural
Resources Company's working interest in such wells, drilling locations or acres.
Unless otherwise specified, wells, drilling locations and acreage statistics
quoted herein represent gross wells, drilling locations or acres; and, all
currency amounts are expressed in U.S. dollars.
4
PART I
ITEM 1. BUSINESS
General
Pioneer Natural Resources Company (the "Company" or "Pioneer") is a
Delaware corporation whose common stock is listed and traded on the New York
Stock Exchange. Pioneer is an oil and gas exploration and production company
with ownership interests in oil and gas properties located in the United States,
Argentina, Canada, Gabon, South Africa and Tunisia.
The Company's executive offices are located at 5205 N. O'Connor Blvd.,
Suite 900, Irving, Texas 75039. The Company's telephone number is (972)
444-9001. The Company maintains other offices in Midland, Texas; Buenos Aires,
Argentina; Calgary, Canada; Capetown, South Africa; Tunis, Tunisia; and
Libreville, Gabon. At December 31, 2003, the Company had 1,014 employees, 505 of
whom were employed in field and plant operations.
Available Information
Pioneer files annual, quarterly and current reports, proxy statements and
other documents with the SEC under the Securities Exchange Act of 1934. The
public may read and copy any materials that Pioneer files with the SEC at the
SEC's Public Reference Room at 450 Fifth Street, N.W., Washington, DC 20549. The
public may obtain information on the operation of the Public Reference Room by
calling the SEC at 1-800-SEC-0330. Also, the SEC maintains an Internet website
that contains reports, proxy and information statements, and other information
regarding issuers, including Pioneer, that file electronically with the SEC. The
public can obtain any documents that Pioneer files with the SEC at
http://www.sec.gov.
The Company also makes available free of charge on or through its Internet
website (http://www.pioneernrc.com) its Annual Report on Form 10-K, Quarterly
Reports on Form 10-Q, Current Reports on Form 8-K and, if applicable, amendments
to those reports filed or furnished pursuant to Section 13(a) of the Exchange
Act as soon as reasonably practicable after it electronically files such
material with, or furnishes it to, the SEC.
Mission and Strategies
The Company's mission is to provide shareholders with superior investment
returns through strategies that maximize Pioneer's long-term profitability and
net asset value. The strategies employed to achieve this mission are predicated
on maintaining financial flexibility and capital allocation discipline.
Historically, these strategies have been anchored by the Company's long-lived
Spraberry oil field and Hugoton and West Panhandle gas fields' reserves and
production. Underlying these fields are approximately 65 percent of the
Company's proved oil and gas reserves as of December 31, 2003. These fields have
a remaining productive life in excess of 40 years. The stable base of oil and
gas production from these fields, combined with the deepwater Gulf of Mexico
Canyon Express, Falcon and Harrier gas projects which began production in
September 2002, March 2003 and January 2004, respectively, and the Sable oil
discovery in South Africa which began production in August 2003 will generate
the operating cash flows that will allow the Company to improve its financial
flexibility in 2004. These activities will be further enhanced by initial
production in mid-2004 from the Company's Devils Tower oil discovery and the
Raptor and Tomahawk gas discoveries, all located in the deepwater Gulf of
Mexico.
The above exploration successes represent some of the results of the
Company's decision to selectively reinvest capital from the long-lived
Spraberry, Hugoton and West Panhandle fields to areas offering superior
investment returns. Similarly, the Company will continue to: (a) selectively
explore for and develop proved reserve discoveries in areas that offer superior
reserve growth and profitability potential; (b) evaluate opportunities to
acquire oil and gas properties under terms that will complement the Company's
exploration and development drilling activities; (c) invest in the personnel and
technology necessary to maximize the Company's exploration and development
successes; and (d) enhance liquidity, allowing the Company to take advantage of
future exploration, development and acquisition opportunities. The Company is
committed to continuing to enhance shareholder investment returns through
adherence to these strategies.
5
Business Activities
The Company is an independent oil and gas exploration and production
company. Pioneer's purpose is to competitively and profitably explore for,
develop and produce oil, NGL and gas reserves. In so doing, the Company sells
homogenous oil, NGL and gas units which, except for geographic and relatively
minor qualitative differentials, cannot be significantly differentiated from
units offered for sale by the Company's competitors. Competitive advantage is
gained in the oil and gas exploration and development industry through superior
capital investment decisions, technological innovation and price and cost
management.
Petroleum industry. The petroleum industry has been characterized by
fluctuating oil, NGL and gas commodity prices and relatively stable supplier
costs during the three years ended December 31, 2003. During and just prior to
2000, the Organization of Petroleum Exporting Countries ("OPEC") and certain
other oil exporting nations reduced their oil export volumes. Those reductions
in oil export volumes had a positive impact on world oil prices, as did overall
gas supply and demand fundamentals on North American gas prices. During 2002,
world oil prices increased in response to political unrest and supply
disruptions in the Middle East and Venezuela while North American gas prices
improved as market fundamentals strengthened. During 2003, world oil and North
American gas supply and demand fundamentals continued to strengthen. Significant
factors that will impact 2004 commodity prices include the final resolution of
issues currently impacting Iraq and the Middle East in general, the extent to
which members of OPEC and other oil exporting nations are able to continue to
manage oil supply through export quotas and overall North American gas supply
and demand fundamentals. To mitigate the impact of commodity price volatility on
the Company's net asset value, Pioneer utilizes commodity hedge contracts. See
Note J of Notes to Consolidated Financial Statements included in "Item 8.
Financial Statements and Supplementary Data" for information regarding the
impact to oil and gas revenues during the years ended December 31, 2003, 2002
and 2001 from the Company's hedging activities and the Company's open hedge
positions at December 31, 2003.
The Company. The Company's asset base is anchored by the Spraberry oil
field located in West Texas, the Hugoton gas field located in Southwest Kansas
and the West Panhandle gas field located in the Texas Panhandle. Complementing
these areas, the Company has exploration and development opportunities and/or
oil and gas production activities in the Gulf of Mexico, the onshore Gulf Coast
area and in Alaska, and internationally in Argentina, Canada, Gabon, South
Africa and Tunisia. Combined, these assets create a portfolio of resources and
opportunities that are well balanced among oil, NGLs and gas, and that are also
well balanced between long-lived, dependable production and exploration and
development opportunities. Additionally, the Company has a team of dedicated
employees that represent the professional disciplines and sciences that will
allow Pioneer to maximize the long-term profitability and net asset value
inherent in its physical assets.
The Company provides administrative, financial and management support to
United States and foreign subsidiaries that explore for, develop and produce
oil, NGL and gas reserves. Production operations are principally located
domestically in Texas, Kansas, Louisiana and the Gulf of Mexico, and
internationally in Argentina, Canada, South Africa and Tunisia.
Production. The Company focuses its efforts towards maximizing its average
daily production of oil, NGLs and gas through development drilling, production
enhancement activities and acquisitions of producing properties while minimizing
the controllable costs associated with the production activities. During the
year ended December 31, 2003, the Company's average daily oil, NGL and gas
production increased as a result of (i) a full year of gas production from the
Company's Canyon Express gas project in the deepwater Gulf of Mexico, (ii) gas
production since March 2003 from the Company's Falcon gas field in the deepwater
Gulf of Mexico, (iii) increased production from Argentina primarily resulting
from the resumption of oil drilling activities since the third quarter of 2002,
(iv) oil production since May 2003 from the Company's Adam field in Tunisia and
(v) oil production since August 2003 from the Company's Sable field offshore
South Africa. These increases more than offset normal production declines.
During 2002, the Company's average daily oil, NGL and gas production decreased
primarily due to normal production declines, reduced Argentine demand for gas,
the Company's curtailment of Argentine drilling activities during the first half
of 2002 and the December 2001 sale of the Company's Rycroft/Spirit River field
in Canada. During 2001, the Company's average daily oil, NGL and gas production
decreased primarily as a result of oil and gas property divestitures that were
supportive of the Company's debt reduction goal. Production, price and cost
information with respect to the Company's properties for each of the years ended
6
December 31, 2003, 2002 and 2001 is set forth under "Item 2. Properties -
Selected Oil and Gas Information - Production, Price and Cost Data".
Drilling activities. The Company seeks to increase its oil and gas
reserves, production and cash flow through exploratory and development drilling
and by conducting other production enhancement activities, such as well
recompletions. During the three years ended December 31, 2003, the Company
drilled 1,002 gross (744.1 net) wells, 86 percent of which were successfully
completed as productive wells, at a total drilling cost (net to the Company's
interest) of $1.5 billion. During 2003, the Company drilled 383 gross (338.8
net) wells. The Company's current 2004 capital expenditure budget is expected to
range from $550 million to $600 million. Excluding the 2003 acquisitions, the
Company's 2004 capital expenditure budget is comparable to 2003 costs incurred
for oil and gas producing activities. The Company has allocated the budgeted
2004 capital expenditures as follows: 65 percent to development drilling and
facility activities and 35 percent to exploration activities.
The Company believes that its current property base provides a substantial
inventory of prospects for future reserve, production and cash flow growth. The
Company's proved reserves as of December 31, 2003 include proved undeveloped
reserves and proved developed reserves that are behind pipe of 188.9 million
Bbls of oil and NGLs and 670.8 Bcf of gas. Development of these reserves will
require future capital expenditures. The timing of the development of these
reserves will be dependent upon the commodity price environment, the Company's
expected operating cash flows and the Company's financial condition. The Company
believes that its current portfolio of undeveloped prospects and reserves
provides attractive development and exploration opportunities for at least the
next three to five years.
Exploratory activities. Since 1998, the Company has devoted significant
efforts and resources to hiring and developing a highly skilled exploration
staff as well as acquiring and drilling a portfolio of exploration
opportunities. The Company's commitment to exploration has resulted in
significant discoveries during this time period, such as the 1998 Sable oil
field discovery in South Africa; the 1999 Aconcagua, 2000 Devils Tower, 2001
Falcon and 2003 Harrier, Tomahawk and Raptor discoveries in the deepwater Gulf
of Mexico; the 2001 Olowi permit discovery located in the Southern Gabon basin;
and the 2002 Borj El Khadra permit discovery in the Ghadames basin onshore
Southern Tunisia. The Company currently anticipates that its 2004 exploration
efforts will be approximately 35 percent of total 2004 capital expenditures and
will be concentrated domestically in the Gulf of Mexico, and internationally in
Argentina, Canada, Gabon and Tunisia. Exploratory drilling involves greater
risks of dry holes or failure to find commercial quantities of hydrocarbons than
development drilling or enhanced recovery activities. See "Item 1. Business -
Risks Associated with Business Activities - Drilling activities" below.
Acquisition activities. The Company regularly seeks to acquire properties
that complement its operations, provide exploration and development
opportunities and potentially provide superior returns on investment. In
addition, the Company pursues strategic acquisitions that will allow the Company
to expand into new geographical areas that feature producing properties and
provide exploration/exploitation opportunities. During the years ended December
31, 2003, 2002 and 2001, the Company expended $151.0 million, $195.5 million and
$170.8 million, respectively, of acquisition capital to purchase additional
interests in, and other assets associated with, its existing assets and to
acquire new prospects for future exploration activities. See Note D of Notes to
Consolidated Financial Statements included in "Item 8. Financial Statements and
Supplementary Data" for a description of the Company's acquisitions during 2003,
2002 and 2001.
The Company periodically evaluates and pursues acquisition opportunities
(including opportunities to acquire particular oil and gas properties or related
assets; entities owning oil and gas properties or related assets; and
opportunities to engage in mergers, consolidations or other business
combinations with such entities) and at any given time may be in various stages
of evaluating such opportunities. Such stages may take the form of internal
financial analysis, oil and gas reserve analysis, due diligence, the submission
of an indication of interest, preliminary negotiations, negotiation of a letter
of intent or negotiation of a definitive agreement.
Asset divestitures. The Company regularly reviews its asset base for the
purpose of identifying non-strategic assets, the disposition of which would
increase capital resources available for other activities and create
organizational and operational efficiencies. While the Company generally does
not dispose of assets solely for the purpose of reducing debt, such dispositions
can have the result of furthering the Company's objective of financial
flexibility through reduced debt levels.
7
During the years ended December 31, 2003, 2002 and 2001, the Company's
divestitures consisted of the early termination of derivative hedge contracts
and the sales of oil and gas properties and other assets for net proceeds of
$35.7 million, $118.9 million and $113.5 million, respectively, which resulted
in 2003, 2002 and 2001 net divestiture gains of $1.3 million, $4.4 million and
$7.7 million, respectively. The net cash proceeds from the 2003, 2002 and 2001
asset dispositions were primarily used to fund additions to oil and gas
properties or to reduce the Company's outstanding indebtedness. See Note N of
Notes to Consolidated Financial Statements included in "Item 8. Financial
Statements and Supplementary Data" for specific information regarding the
Company's asset divestitures.
The Company anticipates that it will continue to sell non-strategic
properties or other assets from time to time to increase capital resources
available for other activities, to achieve operating and administrative
efficiencies and to improve profitability.
Operations by Geographic Area
The Company operates in one industry segment. During the three years ended
December 31, 2003, the Company had oil and gas producing and development
activities in the United States, Argentina, Canada, Gabon, South Africa and
Tunisia, and had exploration activities in the United States, Argentina, Canada,
Gabon, South Africa and Tunisia. See Note R of Notes to Consolidated Financial
Statements included in "Item 8. Financial Statements and Supplementary Data" for
geographic operating segment information, including results of operations and
segment assets.
Marketing of Production
General. Production from the Company's properties is marketed using methods
that are consistent with industry practices. Sales prices for oil, NGL and gas
production are negotiated based on factors normally considered in the industry,
such as the index or spot price for gas or the posted price for oil, price
regulations, distance from the well to the pipeline, well pressure, estimated
reserves, commodity quality and prevailing supply conditions.
Significant purchasers. During the year ended December 31, 2003, the
Company's primary purchasers of oil were ExxonMobil Corporation ("ExxonMobil")
and Plains Marketing LP ("Plains"), the Company's primary purchaser of NGLs was
Enterprise Products Operating L.P. ("Enterprise") and the Company's primary
purchasers of gas were Williams Energy Services ("Williams") and Conoco
Phillips. Approximately 16 percent, eight percent and seven percent of the
Company's 2003 combined oil, NGL and gas revenues were attributable to sales to
Williams, Conoco Phillips and Enterprise, respectively, and approximately five
percent of combined oil, NGL and gas revenues of 2003 were attributable to sales
to ExxonMobil and Plains. The Company is of the opinion that the loss of any one
purchaser would not have an adverse effect on its ability to sell its oil, NGL
and gas production.
Hedging activities. The Company utilizes commodity swap and collar
contracts in order to (i) reduce the effect of price volatility on the
commodities the Company produces and sells, (ii) support the Company's annual
capital budgeting and expenditure plans and (iii) reduce commodity price risk
associated with certain capital projects. See "Item 7. Management's Discussion
and Analysis of Financial Condition and Results of Operations" for a description
of the Company's hedging activities, "Item 7A. Quantitative and Qualitative
Disclosures About Market Risk" and Note J of Notes to Consolidated Financial
Statements included in "Item 8. Financial Statements and Supplementary Data" for
information concerning the impact on oil and gas revenues during the years ended
December 31, 2003, 2002 and 2001 from the Company's commodity hedging activities
and the Company's open commodity hedge positions at December 31, 2003.
Competition, Markets and Regulations
Competition. The oil and gas industry is highly competitive. A large number
of companies and individuals engage in the exploration for and development of
oil and gas properties, and there is a high degree of competition for oil and
gas properties suitable for development or exploration. Acquisitions of oil and
gas properties have been an important element of the Company's growth. The
Company intends to continue to acquire oil and gas properties that complement
its operations, provide exploration and development opportunities and
potentially provide superior return on investment. The principal competitive
factors in the acquisition of oil and gas properties include the staff and data
necessary to identify, investigate and purchase such properties and the
8
financial resources necessary to acquire and develop the properties. Many of the
Company's competitors are substantially larger and have financial and other
resources greater than those of the Company.
Markets. The Company's ability to produce and market oil, NGLs and gas
profitably depends on numerous factors beyond the Company's control. The effect
of these factors cannot be accurately predicted or anticipated. Although the
Company cannot predict the occurrence of events that may affect these commodity
prices or the degree to which these prices will be affected, the prices for any
commodity that the Company produces will generally approximate current market
prices in the geographic region of the production.
Governmental regulations. Enterprises that sell securities in public
markets are subject to regulatory oversight by agencies such as the SEC. This
regulatory oversight imposes on the Company the responsibility for establishing
and maintaining disclosure controls and procedures that will ensure that
material information relating to the Company and its consolidated subsidiaries
is made known to the Company's management and that the financial statements and
other financial information included in this Report do not contain any untrue
statement of a material fact, or omit to state a material fact, necessary to
make the statements made in this Report not misleading.
Oil and gas exploration and production operations are also subject to
various types of regulation by local, state, federal and foreign agencies.
Additionally, the Company's operations are subject to state conservation laws
and regulations, including provisions for the unitization or pooling of oil and
gas properties, the establishment of maximum rates of production from wells and
the regulation of spacing, plugging and abandonment of wells. States and foreign
governments generally impose a production or severance tax with respect to
production and sale of oil and gas within their respective jurisdictions. The
regulatory burden on the oil and gas industry increases the Company's cost of
doing business and, consequently, affects its profitability.
Additional proposals and proceedings that might affect the oil and gas
industry are considered from time to time by Congress, the Federal Energy
Regulatory Commission, state regulatory bodies, the courts and foreign
governments. The Company cannot predict when or if any such proposals might
become effective or their effect, if any, on the Company's operations.
Environmental and health controls. The Company's operations are subject to
numerous federal, state, local and foreign laws and regulations relating to
environmental and health protection. These laws and regulations may require the
acquisition of a permit before drilling commences, restrict the type, quantities
and concentration of various substances that can be released into the
environment in connection with drilling and production activities, limit or
prohibit drilling activities on certain lands lying within wilderness, wetlands
and other protected areas and impose substantial liabilities for pollution
resulting from oil and gas operations. These laws and regulations may also
restrict air emissions or other discharges resulting from the operation of gas
processing plants, pipeline systems and other facilities that the Company owns.
Although the Company believes that compliance with environmental laws and
regulations will not have a material adverse effect on its future results of
operations or financial condition, risks of substantial costs and liabilities
are inherent in oil and gas operations, and there can be no assurance that
significant costs and liabilities, including potential criminal penalties, will
not be incurred. Moreover, it is possible that other developments, such as
stricter environmental laws and regulations or claims for damages to property or
persons resulting from the Company's operations, could result in substantial
costs and liabilities.
The Comprehensive Environmental Response, Compensation, and Liability Act
("CERCLA"), also known as the "Superfund" law, imposes liability, without regard
to fault or the legality of the original conduct, on certain classes of persons
with respect to the release of a "hazardous substance" into the environment.
These persons include the owner or operator of the disposal site or sites where
the release occurred and companies that disposed or arranged for the disposal of
hazardous substances released at the site. Persons who are or were responsible
for releases of hazardous substances under CERCLA may be subject to joint and
several liability for the costs of cleaning up the hazardous substances that
have been released into the environment and for damages to natural resources,
and it is not uncommon for neighboring landowners and other third parties to
file claims for personal injury and property damage allegedly caused by the
hazardous substances released into the environment.
The Company generates wastes, including hazardous wastes, that are subject
to the federal Resource Conservation and Recovery Act ("RCRA") and comparable
state statutes. The United States Environmental Protection Agency and various
9
state agencies have limited the approved methods of disposal for certain
hazardous and non-hazardous wastes. Furthermore, certain wastes generated by the
Company's oil and gas operations that are currently exempt from treatment as
hazardous wastes may in the future be designated as hazardous wastes, and
therefore be subject to more rigorous and costly operating and disposal
requirements.
The Company currently owns or leases, and has in the past owned or leased,
properties that for many years have been used for the exploration and production
of oil and gas reserves. Although the Company has used operating and disposal
practices that were standard in the industry at the time, hydrocarbons or other
wastes may have been disposed of or released on or under the properties owned or
leased by the Company or on or under other locations where such wastes have been
taken for disposal. In addition, some of these properties have been operated by
third parties whose treatment and disposal or release of hydrocarbons or other
wastes was not under the Company's control. These properties and the wastes
disposed thereon may be subject to CERCLA, RCRA and analogous state laws. Under
such laws, the Company could be required to remove or remediate previously
disposed wastes or property contamination or to perform remedial plugging
operations to prevent future contamination.
Federal regulations require certain owners or operators of facilities that
store or otherwise handle oil, such as the Company, to prepare and implement
spill prevention control plans, countermeasure plans and facility response plans
relating to the possible discharge of oil into surface waters. The Oil Pollution
Prevention Act of 1990 ("OPA") amends certain provisions of the federal Water
Pollution Control Act of 1972, commonly referred to as the Clean Water Act
("CWA"), and other statutes as they pertain to the prevention of and response to
oil spills into navigable waters. The OPA subjects owners of facilities to
strict joint and several liability for all containment and cleanup costs and
certain other damages arising from a spill, including, but not limited to, the
costs of responding to a release of oil to surface waters. The CWA provides
penalties for any discharges of petroleum products in reportable quantities and
imposes substantial liability for the costs of removing a spill. OPA requires
responsible parties to establish and maintain evidence of financial
responsibility to cover removal costs and damages resulting from an oil spill.
OPA calls for a financial responsibility of $35 million to cover pollution
cleanup for offshore facilities. State laws for the control of water pollution
also provide varying civil and criminal penalties and liabilities in the case of
releases of petroleum or its derivatives into surface waters or into the ground.
The Company does not believe that the OPA, CWA or related state laws are any
more burdensome to it than they are to other similarly situated oil and gas
companies.
Many states in which the Company operates regulate naturally occurring
radioactive materials ("NORM") and NORM wastes that are generated in connection
with oil and gas exploration and production activities. NORM wastes typically
consist of very low-level radioactive substances that become concentrated in
pipe scale and in production equipment. Certain state regulations require the
testing of pipes and production equipment for the presence of NORM, the
licensing of NORM-contaminated facilities and the careful handling and disposal
of NORM wastes. The regulation of NORM has minimal effect on the Company's
operations because the Company generates only small quantities of NORM on an
annual basis.
The Company does not believe that its environmental risks are materially
different from those of comparable companies in the oil and gas industry.
Nevertheless, no assurance can be given that environmental laws will not result
in a curtailment of production or processing, a material increase in the costs
of production, development, exploration or processing or otherwise adversely
affect the Company's future results of operations and financial condition.
The Company employs an environmental director and environmental specialists
charged with monitoring environmental and regulatory compliance. The Company
performs an environmental review as part of the due diligence work on potential
acquisitions. The Company is not aware of any material environmental legal
proceedings pending against it or any material environmental liabilities to
which it may be subject.
Risks Associated with Business Activities
The nature of the business activities conducted by the Company subjects it
to certain hazards and risks. The following is a summary of some of the material
risks relating to the Company's business activities.
Commodity prices. The Company's revenues, profitability, cash flow and
future rate of growth are highly dependent on oil and gas prices, which are
affected by numerous factors beyond the Company's control. Oil and gas prices
10
historically have been very volatile. A significant downward trend in commodity
prices would have a material adverse effect on the Company's revenues,
profitability and cash flow and could, under certain circumstances, result in a
reduction in the carrying value of the Company's oil and gas properties and the
recognition of a deferred tax asset valuation allowance or an increase to the
Company's deferred tax asset valuation allowances, depending on the Company's
tax attributes in each country in which it has activities.
Drilling activities. Drilling involves numerous risks, including the risk
that no commercially productive oil or gas reservoirs will be encountered. The
cost of drilling, completing and operating wells is often uncertain and drilling
operations may be curtailed, delayed or canceled as a result of a variety of
factors, including unexpected drilling conditions, pressure or irregularities in
formations, equipment failures or accidents, adverse weather conditions and
shortages or delays in the delivery of equipment. The Company's future drilling
activities may not be successful and, if unsuccessful, such failure could have
an adverse effect on the Company's future results of operations and financial
condition. While all drilling, whether developmental or exploratory, involves
these risks, exploratory drilling involves greater risks of dry holes or failure
to find commercial quantities of hydrocarbons. Because of the percentage of the
Company's capital budget devoted to higher risk exploratory projects, it is
likely that the Company will continue to experience exploration and abandonment
expense.
Unproved properties. At December 31, 2003 and 2002, the Company carried
unproved property costs of $179.8 million and $219.1 million, respectively.
Generally accepted accounting principles require periodic evaluation of these
costs on a project-by-project basis in comparison to their estimated value.
These evaluations will be affected by the results of exploration activities,
commodity price outlooks, planned future sales or expiration of all or a portion
of the leases, contracts and permits appurtenant to such projects. If the
quantity of potential reserves determined by such evaluations is not sufficient
to fully recover the cost invested in each project, the Company will recognize
noncash charges in the earnings of future periods.
Acquisitions. Acquisitions of producing oil and gas properties have been a
key element of the Company's growth. The Company's growth following the full
development of its existing property base could be impeded if it is unable to
acquire additional oil and gas reserves on a profitable basis. The success of
any acquisition will depend on a number of factors, including the ability to
estimate accurately the recoverable volumes of reserves, rates of future
production and future net revenues attainable from the reserves and to assess
possible environmental liabilities. All of these factors affect whether an
acquisition will ultimately generate cash flows sufficient to provide a suitable
return on investment. Even though the Company performs a review of the
properties it seeks to acquire that it believes is consistent with industry
practices, such reviews are often limited in scope.
Divestitures. The Company regularly reviews its property base for the
purpose of identifying non-strategic assets, the disposition of which would
increase capital resources available for other activities and create
organizational and operational efficiencies. Various factors could materially
affect the ability of the Company to dispose of non-strategic assets, including
the availability of purchasers willing to purchase the non-strategic assets at
prices acceptable to the Company.
Operation of natural gas processing plants. As of December 31, 2003, the
Company owned interests in 11 natural gas processing plants and five treating
facilities. The Company operates seven of the plants and all five treating
facilities. There are significant risks associated with the operation of natural
gas processing plants. Gas and NGLs are volatile and explosive and may include
carcinogens. Damage to or misoperation of a gas processing plant or facility
could result in an explosion or the discharge of toxic gases, which could result
in significant damage claims in addition to interrupting a revenue source.
Operating hazards and uninsured losses. The Company's operations are
subject to all the risks normally incident to the oil and gas exploration and
production business, including blowouts, cratering, explosions and pollution and
other environmental damage, any of which could result in substantial losses to
the Company due to injury or loss of life, damage to or destruction of wells,
production facilities or other property, clean-up responsibilities, regulatory
investigations and penalties and suspension of operations. Although the Company
currently maintains insurance coverage that it considers reasonable and that is
similar to that maintained by comparable companies in the oil and gas industry,
it is not fully insured against certain of these risks, either because such
insurance is not available or because of the high premium costs associated with
obtaining such insurance.
11
Environmental. The oil and gas business is subject to environmental
hazards, such as oil spills, produced water spills, gas leaks and ruptures and
discharges of toxic substances or gases that could expose the Company to
substantial liability due to pollution and other environmental damage. A variety
of federal, state and foreign laws and regulations govern the environmental
aspects of the oil and gas business. Noncompliance with these laws and
regulations may subject the Company to penalties, damages or other liabilities,
and compliance may increase the cost of the Company's operations. Such laws and
regulations may also affect the costs of acquisitions. See "Item 1. Business -
Competition, Markets and Regulation - Environmental and health controls" above
for additional discussion related to environmental risks.
The Company does not believe that its environmental risks are materially
different from those of comparable companies in the oil and gas industry.
Nevertheless, no assurance can be given that future environmental laws will not
result in a curtailment of production or processing, a material increase in the
costs of production, development, exploration or processing or otherwise
adversely affect the Company's future operations and financial condition.
Pollution and similar environmental risks generally are not fully insurable.
Debt restrictions and availability. The Company is a borrower under fixed
term senior notes and a corporate credit facility. The terms of the Company's
borrowings under the senior notes and the corporate credit facility specify
scheduled debt repayments and require the Company to comply with certain
associated covenants and restrictions. The Company's ability to comply with the
debt repayment terms, associated covenants and restrictions is dependent on,
among other things, factors outside the Company's direct control, such as
commodity prices, interest rates and competition for available debt financing.
See Note E of Notes to Consolidated Financial Statements included in "Item 8.
Financial Statements and Supplementary Data" for information regarding the
Company's outstanding debt as of December 31, 2003 and the terms associated
therewith.
Competition. The oil and gas industry is highly competitive. The Company
competes with other companies, producers and operators for acquisitions and in
the exploration, development, production and marketing of oil and gas. Some of
these competitors have substantially greater financial and other resources than
the Company. See "Item 1. Business - Competition, Markets and Regulation" above
for additional discussion regarding competition.
Government regulation. The Company's business is regulated by a variety of
federal, state, local and foreign laws and regulations. There can be no
assurance that present or future regulations will not adversely affect the
Company's business and operations. See "Item 1. Business - Competition, Markets
and Regulation" above for additional discussion regarding government regulation.
International operations. At December 31, 2003, approximately 21 percent of
the Company's proved reserves of oil, NGLs and gas were located outside the
United States (16 percent in Argentina, three percent in Africa and two percent
in Canada). The success and profitability of international operations may be
adversely affected by risks associated with international activities, including
economic and labor conditions, political instability, tax laws (including
host-country export, excise and income taxes and United States taxes on foreign
subsidiaries) and changes in the value of the U.S. dollar versus the local
currencies in which oil and gas producing activities may be denominated. To the
extent that the Company is involved in international activities, changes in
exchange rates may adversely affect the Company's future results of operations
and financial condition. See Critical Accounting Estimates included in "Item 7.
Management's Discussion and Analysis of Financial Condition and Results of
Operations" and Note B of Notes to Consolidated Financial Statements included in
"Item 8. Financial Statements and Supplementary Data" for information specific
to Argentina's economic and political situation.
Estimates of reserves and future net revenues. Numerous uncertainties exist
in estimating quantities of proved reserves and future net revenues therefrom.
The estimates of proved reserves and related future net revenues set forth in
this Report are based on various assumptions, which may ultimately prove to be
inaccurate. Therefore, such estimates should not be construed as accurate
estimates of the current market value of the Company's proved reserves.
12
ITEM 2. PROPERTIES
The information included in this Report about the Company's oil, NGL and
gas reserves as of December 31, 2003 was based on reserve reports audited by
Netherland, Sewell & Associates, Inc. for the Company's major properties in the
United States, Argentina, Canada and South Africa and reserve reports prepared
by the Company's engineers for all other properties. The reserve audit conducted
by Netherland, Sewell & Associates, Inc. in aggregate represented 87 percent of
the Company's estimated proved quantities of reserves as of December 31, 2003.
The information included in this Report about the Company's oil, NGL and gas
reserves as of December 31, 2002 was based on reserve reports audited by
Netherland, Sewell & Associates, Inc. for the Company's major properties in the
United States, Canada and South Africa, reserve reports audited by Gaffney,
Cline & Associates, Inc. for the Company's properties located in the Neuquen
Basin in Argentina and reserve reports prepared by the Company's engineers for
all other properties. The reserve audits conducted by Netherland, Sewell &
Associates, Inc. and Gaffney, Cline & Associates, Inc., in aggregate,
represented 71 percent of the Company's estimated proved quantities of reserves
as of December 31, 2002. The information in this Report about the Company's oil,
NGL and gas reserves as of December 31, 2001 was based on proved reserves as
determined by the Company's engineers.
Numerous uncertainties exist in estimating quantities of proved reserves
and in projecting future rates of production and timing of development
expenditures, including many factors beyond the Company's control. This Report
contains estimates of the Company's proved oil and gas reserves and the related
future net revenues, which are based on various assumptions, including those
prescribed by the SEC. Actual future production, oil and gas prices, revenues,
taxes, capital expenditures, operating expenses and quantities of recoverable
oil and gas reserves may vary substantially from those assumed in the estimates
and could materially affect the estimated quantities and related Standardized
Measure of proved reserves set forth in this Report. In addition, the Company's
reserves may be subject to downward or upward revisions based on production
performance, purchases or sales of properties, results of future exploration and
development activities, prevailing oil and gas prices and other factors.
Therefore, estimates of the Standardized Measure of proved reserves should not
be construed as accurate estimates of the current market value of the Company's
assets.
Standardized Measure is a reporting convention that provides a common basis
for comparing oil and gas companies subject to the rules and regulations of the
SEC. It requires the use of oil and gas spot prices prevailing as of the date of
computation. Consequently, it may not reflect the prices ordinarily received or
that will be received for oil and gas production because of seasonal price
fluctuations or other varying market conditions. Standardized Measures as of any
date are not necessarily indicative of future results of operations.
Accordingly, estimates included herein of future net revenues may be materially
different from the net revenues that are ultimately received.
The Company did not provide estimates of total proved oil and gas reserves
during the years ended December 31, 2003, 2002 or 2001 to any federal authority
or agency, other than the SEC.
Proved Reserves
The Company's proved reserves totaled 789.1 million BOE at December 31,
2003, 736.7 million BOE at December 31, 2002 and 671.4 million BOE at December
31, 2001, representing $4.6 billion, $4.1 billion and $2.5 billion,
respectively, of Standardized Measure or $6.0 billion, $5.1 billion and $2.5
billion, respectively, on a pre-tax basis. The seven and 11 percent increases in
proved reserve volumes and Standardized Measure, respectively, during 2003 were
primarily due to two core area acquisitions, discoveries in Gabon, the deepwater
Gulf of Mexico and Tunisia and positive reserve revisions due to increased
commodity prices extending the estimated economic life of various properties,
increased recoverable reserve estimates based on well performance and the
addition of reserves resulting from the Company' expanded development drilling
program. The ten and 65 percent increases in proved reserve volumes and
Standardized Measure, respectively, during 2002 were attributable to an increase
in commodity prices, the purchase of incremental interests in two core assets
and the Company's successful capital investments.
On a BOE basis, 65 percent of the Company's total proved reserves at
December 31, 2003 were proved developed reserves. Based on reserve information
as of December 31, 2003, and using the Company's production information for the
year then ended, the reserve-to-production ratio associated with the Company's
proved reserves was 14.0 years on a BOE basis. The following table provides
information regarding the Company's proved reserves and average daily production
by geographic area as of and for the year ended December 31, 2003:
13
2003 Average
Proved Reserves as of December 31, 2003 Daily Production (a)
------------------------------------------------- ---------------------------------
Oil Standardized Oil
& NGLs Gas Measure & NGLs Gas
(MBbls) (MMcf) MBOE (in thousands) (Bbls) (Mcf) BOE
--------- --------- ---------- ----------- -------- --------- --------
United States......... 362,751 1,553,976 621,747 $ 3,797,488 44,863 445,609 119,129
Argentina............. 33,469 549,856 125,112 443,118 10,005 94,128 25,694
Canada................ 2,407 93,829 18,045 218,419 1,017 41,669 7,962
Africa................ 24,154 - 24,154 124,228 1,981 - 1,981
--------- --------- ---------- --------- -------- --------- --------
Total................. 422,781 2,197,661 789,058 $ 4,583,253 57,866 581,406 154,766
========= ========= ========== ========== ======== ========= ========
- ----------------
(a) The 2003 average daily production was calculated using a 365-day year and
without making pro forma adjustments for any acquisitions, divestitures or
drilling activity that occurred during the year.
Finding Cost and Reserve Replacement
The Company's acquisition and finding costs per BOE for the years ended
December 31, 2003, 2002 and 2001 were $6.64, $6.30 and $7.49 per BOE,
respectively. The average acquisition and finding cost for the three-year period
ended December 31, 2003 was $6.76 per BOE, representing an eight percent
increase over the 2002 three-year average rate of $6.24 per BOE.
During the year ended December 31, 2003, the Company replaced 193 percent
of its annual production on a BOE basis (299 percent for oil and NGLs and 129
percent for gas). During 2002, the Company replaced 258 percent of its annual
production on a BOE basis (384 percent for oil and NGLs and 144 percent for
gas). During 2001, the Company replaced 208 percent of its annual production on
a BOE basis (169 percent for oil and NGLs and 245 percent for gas). The
Company's 2003 and 2002 reserve replacement percentages were the result of
revisions of previous estimates including revisions related to changes in
commodity prices, asset purchases and new discoveries and field extensions. The
Company's 2001 reserve replacement percentage was primarily impacted by asset
purchases and new discoveries and field extensions.
Description of Properties
As of December 31, 2003, the Company has production, development and/or
exploration operations in the United States, Argentina, Canada, Gabon, South
Africa and Tunisia.
Domestic. The Company's domestic operations are located in the Permian
Basin, Mid-Continent, Gulf of Mexico and onshore Gulf Coast areas of the United
States. The Company also has unproved properties in Alaska. Approximately 83
percent of the Company's domestic proved reserves at December 31, 2003 are
located in the Spraberry, Hugoton and West Panhandle fields. These mature fields
generate substantial operating cash flow and have a large portfolio of low risk
infill drilling opportunities. The cash flows generated from these fields
provide funding for the Company's other development and exploration activities
both domestically and internationally. During the year ended December 31, 2003,
the Company expended $563.0 million in domestic acquisition, exploration and
development drilling activities. The Company has budgeted approximately $427
million for domestic exploration and development drilling expenditures for 2004.
Spraberry field. The Spraberry field was discovered in 1949 and encompasses
eight counties in West Texas. The field is approximately 150 miles long and 75
miles wide at its widest point. The oil produced is West Texas Intermediate
Sweet, and the gas produced is casinghead gas with an average energy content of
1,400 Btu per Mcf. The oil and gas are produced primarily from three formations,
the upper and lower Spraberry and the Dean, at depths ranging from 6,700 feet to
9,200 feet. Recently, the Company has been adding the Wolfcamp formation at
depths ranging from 9,300 feet to 10,300 feet to selected completions with
successful results. The center of the Spraberry field was unitized in the late
1950s and early 1960s by the major oil companies; however, until the late 1980s
there was very limited development activity in the field. The Company believes
14
the area offers excellent opportunities to enhance oil and gas reserves because
of the numerous undeveloped infill drilling locations, many of which are
reflected in the Company's proved undeveloped reserves, and the ability to
reduce operating expenses through economies of scale.
During the year ended December 31, 2003, the Company placed 123 Spraberry
wells on production and drilled one developmental dry hole. The Company plans to
drill approximately 114 development wells in the Spraberry field during 2004.
Hugoton field. The Hugoton field in southwest Kansas is one of the largest
producing gas fields in the continental United States. The gas is produced from
the Chase and Council Grove formations at depths ranging from 2,700 feet to
3,000 feet. The Company's Hugoton properties are located on approximately
257,000 gross acres (237,000 net acres), covering approximately 400 square
miles. The Company has working interests in approximately 1,200 wells in the
Hugoton field, about 1,000 of which it operates, and partial royalty interests
in approximately 500 wells. The Company owns substantially all of the gathering
and processing facilities, primarily the Satanta plant, that service its
production from the Hugoton field. Such ownership allows the Company to control
the production, gathering, processing and sale of its gas and NGL production.
The Company's Hugoton operated wells are capable of producing approximately
90 MMcf of wet gas per day (i.e., gas production at the wellhead before
processing and before reduction for royalties), although actual production in
the Hugoton field is limited by allowables set by state regulators. The Company
estimates that it and other major producers in the Hugoton field produced at or
near capacity during the year ended December 31, 2003. During 2003, the Company
placed 18 development wells on production, drilled one developmental dry hole
and had one well in progress as of December 31, 2003 in the Hugoton field. The
plans for 2004 include drilling approximately 20 development wells.
The Company is continuing to evaluate the feasibility of infill drilling
into the Council Grove Formation and may submit an application to the Kansas
Corporation Commission to allow infill drilling. Such infill drilling may
increase production from the Company's Hugoton properties. However, until an
application has been submitted and approved, the Company will not reflect any of
the infill drilling locations as proved undeveloped reserves. There can be no
assurance that the application will be filed or approved, or as to the timing of
such approval if granted.
West Panhandle field. The West Panhandle properties are located in the
panhandle region of Texas where initial production commenced in 1918. These
stable, long-lived reserves are attributable to the Red Cave, Brown Dolomite,
Granite Wash and fractured Granite formations at depths no greater than 3,500
feet. The Company's gas in the West Panhandle field has an average energy
content of 1,300 Btu per Mcf and is produced from approximately 600 wells on
more than 241,000 acres covering over 375 square miles. The Company's wellhead
gas produced from the West Panhandle field contains a high quantity of NGLs,
yielding relatively greater NGL volumes than realized from the Company's 1,025
Btu per Mcf content wellhead gas in its Hugoton field. The Company controls the
wells, production equipment, gathering system and gas processing plant for the
field.
During the year ended December 31, 2003, the Company placed 71 new
development wells on production, drilled four development wells that were
plugged and abandoned due to noncommerciality and had 24 development wells and
two extension wells in progress at December 31, 2003. The Company plans to drill
approximately 111 wells in the West Panhandle field during 2004.
Gulf of Mexico area. In the Gulf of Mexico, the Company is focused on
reserve and production growth through a portfolio of shelf and deepwater
development projects, high-impact, higher-risk deepwater exploration drilling,
shelf exploration drilling and exploitation opportunities inherent in the
properties the Company currently has producing on the shelf. To accomplish this,
the Company has devoted most of its domestic exploration efforts to the Gulf of
Mexico shelf and deepwater as well as investments in and utilization of 3-D
seismic technology. During the year ended December 31, 2003, the Company
successfully drilled three exploratory wells in the deepwater Gulf of Mexico and
one successful development well on the shelf. The Company also drilled four
exploratory dry holes on the shelf and two exploratory dry holes in the
deepwater Gulf of Mexico during 2003 and had four exploratory wells in the
deepwater Gulf of Mexico and one exploratory well on the shelf in progress as of
December 31, 2003.
15
In the deepwater Gulf of Mexico, the Company has three major projects, two
of which are now on production and one that was in progress at December 31,
2003:
o Canyon Express - The Canyon Express development project is a joint
development of three deepwater Gulf of Mexico gas discoveries, including
the Company's TotalFinaElf-operated Aconcagua and Marathon-operated Camden
Hills fields, where the Company holds 37.5 percent and 33.3 percent working
interests, respectively. The Company participated in the discovery of the
Aconcagua gas field in 1999 during the early stages of building its
exploration program, and later added Camden Hills to its portfolio to
enhance its ownership in the project. The Canyon Express project was
approved for development in June 2000 and reached first production in
September 2002. The Canyon Express gathering system is the first in the
area and provides the Company and its partners with the opportunity to
collect gathering and handling revenues from the use of the system by any
future discoveries in the area. The Company has plans to drill and complete
an additional development well at Aconcagua during 2004.
o Falcon Area - The Company-operated Falcon two-well field was completed
ahead of schedule and placed on production in March 2003. During the first
quarter of 2003, the Company drilled its Harrier discovery, along with two
exploratory dry holes. The Company also acquired the remaining 25 percent
working interest in the Falcon field, Harrier discovery and surrounding
prospects that it did not already own in March 2003. In addition, during
the third quarter of 2003, the Company successfully drilled the Tomahawk
and Raptor prospects. All three discoveries, Harrier, Tomahawk and Raptor,
will be developed as single-well subsea tie-backs to the Falcon field
facilities which were designed to be expandable. To accommodate this
incremental production and potential throughput associated with additional
planned exploration, an additional parallel pipeline connecting the Falcon
field to the Falcon platform on the Gulf of Mexico shelf has been added,
doubling its capacity to 400 MMcf of gas per day. The Company placed the
Harrier field on production in early January 2004 and plans to place
Tomahawk and Raptor on production in mid-2004. In addition to the
development operations discussed above, the Company has budgeted to drill
up to three additional Falcon area prospects in 2004.
o Devils Tower - The Dominion-operated Devils Tower development project was
sanctioned in 2001 as a spar development project with the owners leasing a
spar from a third party for the life of the field. The hull of the spar was
constructed in Indonesia and was successfully transported to the United
States during the first quarter of 2003 where the topsides were added in
the fourth quarter of 2003. The spar has slots for eight dry tree wells and
up to two subsea tie-back risers and is capable of handling 60 MBbls of oil
per day and 60 MMcf of gas per day. Eight Devils Tower wells and one subsea
tie-back well, the Triton field, have been drilled and are awaiting
completion. In addition, the Company has drilled an appraisal well at
Triton that was successful subsequent to year end and an exploration well
is in progress on its Goldfinger prospect. Devils Tower production is
expected to begin in mid-2004 and will be phased in as the wells are
individually completed from the spar. The Company holds a 25 percent
working interest in each of the above projects.
During 2002, the Company also participated in the Marathon-operated
deepwater Gulf of Mexico Ozona Deep discovery. The Company is currently
negotiating a tie-back agreement to an existing facility in the area, the
economics of which will determine future activities. In late 2003, the Company
spudded an exploratory well on the BP-operated Juno prospect with a 25 percent
working interest and an exploratory well on the Unocal-operated Myrtle Beach
prospect with a 10 percent working interest, each of which remains in progress
with results expected to be known in February 2004. The Company also plans to
spud an exploratory well on the Dominion-operated Thunder Hawk prospect during
2004. The Company has a 12.5 percent working interest in Thunder Hawk.
During January 2003, the Company announced a joint exploration agreement
with Woodside Energy (USA), Inc. ("Woodside"), a subsidiary of Woodside Energy
Ltd. of Australia, for a two-year drilling program over the shallow-water Texas
shelf region of the Gulf of Mexico. Under the agreement, Woodside acquired a 50
percent working interest in 47 offshore exploration blocks operated by the
Company. The agreement covers eight prospects and 19 leads and included five
exploratory wells to be drilled in 2003 and three in 2004. Most of the wells to
be drilled under the agreement will target gas plays below 15,000 feet. The
first three wells under this joint agreement were unsuccessful. The fourth well,
Midway, subsequent to December 31, 2003 encountered 30 feet of net gas pay and
is expected to be tied back to an existing production platform with first
production anticipated during the second half of 2004. Three other intervals
with an additional 60 feet of gas bearing sands were also encountered and will
require additional analysis to determine future commercial potential. The
16
Company has a 37.5 percent working interest in this well. The fifth well to be
drilled in 2003 and the three wells scheduled for 2004 under the agreement,
which has been extended for one additional year, were mutually agreed to be
deferred until more technical work can be performed on the prospects by both
companies. Additionally, the Company and Woodside are evaluating shallower gas
prospects on the Gulf of Mexico shelf for possible inclusion in the 2004
drilling program.
Onshore Gulf Coast area. The Company has focused its drilling efforts in
this area on the Pawnee field in the Edwards Reef trend in South Texas. The
Company placed five development wells and one extension well on production at
Pawnee during 2003, had two wells in progress at year end and plans to drill
approximately ten wells in 2004.
Alaska area. During the fourth quarter of 2002, the Company acquired a 70
percent working interest and operatorship in ten state leases on Alaska's North
Slope. Associated therewith, the Company drilled three exploratory wells during
the first quarter of 2003 to test a possible extension of the productive sands
in the Kuparuk River field into the shallow waters offshore. Although all three
of the wells found the sands filled with oil, they were too thin to be
considered commercial on a stand-alone basis. However, the wells also
encountered thick sections of oil-bearing Jurassic-aged sands, and the first
well flowed at a sustained rate of approximately 1,300 barrels per day. The test
results are continuing to be evaluated to determine the commercial viability of
the Jurassic reservoir. Subsequent to year end, the Company farmed-into a large
acreage block to the southwest of the Company's discovery. During 2004, the
Company plans to evaluate seismic data over the area to the southwest of its
discovery, analyze results from other wells drilled in the area and determine
the location of future exploration wells to further test the discovery.
In addition, the Company was the high bidder on 53 tracts covering an
additional 159,000 acres on the North Slope in the most recent state lease sale,
establishing a leasehold over a variety of prospects. The Company has opened an
office in Anchorage and is putting together a team of employees that will focus
their efforts on enhancing the Company's position in Alaska.
International. The Company's international operations are located in the
Neuquen and Austral Basins areas of Argentina, the Chinchaga, Martin Creek and
Lookout Butte areas of Canada, the Sable oil field offshore South Africa and in
southern Tunisia. Additionally, the Company has other significant oil
development and exploration activities in the shallow waters offshore Gabon, gas
exploration activities in the shallow waters offshore South Africa and oil
development and exploration activities in Tunisia. As of December 31, 2003,
approximately 16 percent, two percent and three percent of the Company's proved
reserves are located in Argentina, Canada and Africa, respectively.
Argentina. The Company's share of Argentine production during the year
ended December 31, 2003 averaged 25.7 MBOE per day, or approximately 17 percent
of the Company's equivalent production. The Company's operated production in
Argentina is concentrated in the Neuquen Basin which is located about 925 miles
southwest of Buenos Aires and to the east of the Andes Mountains. Oil and gas
are produced primarily from the Al Norte de la Dorsal, the Al Sur de la Dorsal,
the Dadin, the Loma Negra, the Dos Hermanas, the Anticlinal Campamento and the
Estacion Fernandez Oro blocks, in each of which the Company has a 100 percent
working interest. Most of the gas produced from these blocks is processed in the
Company's Loma Negra gas processing plant. The Company also operates and has a
50 percent working interest in the Lago Fuego field which is located in Tierra
del Fuego, an island in the extreme southern portion of Argentina, approximately
1,500 miles south of Buenos Aires.
Most of the Company's non-operated production in Argentina is located in
Tierra del Fuego where oil, gas and NGLs are produced from six separate fields
in which the Company has a 35 percent working interest. The Company also has a
14.4 percent working interest in the Confluencia field which is located in the
Neuquen Basin.
During the year ended December 31, 2003, the Company expended $52.1 million
on Argentine development, exploration and acquisition activities. The Company
drilled 31 development wells and 30 extension/exploratory wells, of which 29
development wells and 21 extension/exploratory wells were successful. Also
during 2003, the Company acquired an additional 150,000 acres in the Ojo de
Agua, Cutral Co Sur and Collun Cura blocks in the Neuquen Basin and shot seismic
covering approximately 258,000 acres. The Company plans to be more active in
Argentina in 2004 with approximately $113 million budgeted for oil and gas
development and exploration opportunities.
17
Canada. The Company's Canadian producing properties are located primarily
in Alberta and British Columbia, Canada. Production during the year ended
December 31, 2003 averaged 8.0 MBOE per day, or approximately five percent of
the Company's equivalent production. The Company continues to focus its
development, exploration and acquisition activities in the core areas of
northeast British Columbia and southwest Alberta. The Canadian assets are
geographically concentrated, predominantly shallow gas and more than 95 percent
operated by the Company in the following areas: Chinchaga, Martin Creek and
Lookout Butte.
Production from the Chinchaga area in northeast British Columbia is
relatively dry gas from formation depths averaging 3,400 feet. In the Martin
Creek area of British Columbia, production is relatively dry gas from various
reservoirs ranging from 3,700 feet to 4,300 feet. The Lookout Butte area in
southwest Alberta produces gas and condensate from the Mississippian Turner
Valley formation at approximately 12,000 feet.
During the year ended December 31, 2003, the Company expended $53.0 million
on Canadian exploration, development, and acquisition activities. The Company
drilled 14 development wells and 42 exploratory/extension wells, primarily in
the Chinchaga and Martin Creek areas, of which seven development wells and 16
exploratory/extension wells were successful. Most of these wells were drilled
during the first quarter of 2003 as these areas are only accessible for drilling
during the winter months. The Company plans to spend approximately $31 million
on oil and gas development and exploration opportunities in Canada during 2004.
Africa. In Africa, the Company has entered into agreements to explore for
oil and gas in South Africa, Gabon and Tunisia. The amended South African
agreements cover over five million acres along the southern coast of South
Africa, generally in water depths less than 650 feet. The Gabon agreement covers
313,937 acres off the coast of Gabon, generally in water depths less than 100
feet. The Tunisian agreements can be separated into two categories: the first
includes three permits covering 2.9 million acres onshore southern Tunisia which
the Company operates with a 50 percent working interest and the second includes
the Anadarko-operated Anaguid permit covering 1.2 million acres onshore southern
Tunisia in which the Company has a 38.7 percent working interest and the
AGIP-operated Adam concession and Borj El Khadra permit covering 212,420 acres
and 969,755 acres, respectively, onshore southern Tunisia in which the Company
has a 28 percent and 40 percent working interest, respectively. During the year
ended December 31, 2003, the Company expended $52.9 million of acquisition,
development and exploration drilling and seismic capital in South Africa, Gabon
and Tunisia.
South Africa. In South Africa, the Company spent $32.8 million of capital
to complete its Petro SA-operated Sable development project and to drill three
exploratory wells that were dry holes. The Sable oil field began producing in
August 2003. The Company has a 40% working interest in the Sable field. In 2004,
the Company currently plans to spend approximately $9 million in South Africa
for production enhancement opportunities at Sable and for an exploration well
late in the year.
Gabon. In Gabon, the Company spent $4.4 million of development and seismic
capital to further evaluate its Bigorneau South discovery, located offshore in
the Southern Gabon Basin on its Olowi permit. Pioneer is the operator of the
permit with a 100 percent working interest. To date, the Company has drilled
four successful offshore wells which have established significant oil in place.
The Company recently received ministerial approval for improved terms associated
with the Olowi permit. Subsequent to year end, the Company has commenced a
multi-well drilling program to further define the scale of a development plan,
initially focusing on the Lower Gamba, and to test a new exploratory prospect.
The Company is also soliciting bids from possible new partners in the project.
Tunisia. In Tunisia, the Company spent $15.6 million of acquisition,
drilling and seismic capital during the year ended December 31, 2003 primarily
to drill one successful development well in its Adam concession, one successful
exploratory well in its AGIP-operated Hawa oil field and one exploratory well
that was a dry hole in its Company-operated Jorf permit. The Hawa oil field
started production in January 2004. In addition, the Company also drilled two
exploratory wells on its Anadarko-operated Anaguid permit that remain in
progress as of December 31, 2003. The Company also completed the construction of
a 15 kilometer flowline from the Adam discovery to an AGIP-operated facility,
allowing production to begin in May 2003. The capital budget of approximately
$14 million for Tunisia in 2004 includes an exploration well and development
well in the Adam concession, two exploration wells on the Company- operated El
Hamra permit and two appraisal wells on the Anaguid permit.
18
Selected Oil and Gas Information
The following tables set forth selected oil and gas information for the
Company as of and for each of the years ended December 31, 2003, 2002 and 2001.
Because of normal production declines, increased or decreased drilling
activities and the effects of past and future acquisitions or divestitures, the
historical information presented below should not be interpreted as being
indicative of future results.
Production, price and cost data. The following table sets forth production,
price and cost data with respect to the Company's properties for the years ended
December 31, 2003, 2002 and 2001:
19
PRODUCTION, PRICE AND COST DATA (a)
Year Ended December 31,
-----------------------------------------------------------------------------------------------------------
2003 2002 2001
------------------------------------- ----------------------------------- ---------------------------------
United United United
States Argentina Canada Africa Total States Argentina Canada Total States Argentina Canada Total
------ --------- ------ ------ ------- ------- --------- ------- -------- ------- --------- ------- -------
Production information:
Annual production:
Oil (MBbls)....... 8,952 3,171 40 723 12,886 8,555 2,914 45 11,514 8,629 3,566 303 12,498
NGLs (MBbls)...... 7,423 481 331 - 8,235 7,487 254 345 8,086 7,232 200 368 7,800
Gas (MMcf)........ 162,647 34,357 15,209 - 212,213 84,811 28,551 17,653 131,015 77,609 31,830 18,426 127,865
Total (MBOE)...... 43,483 9,378 2,906 723 56,490 30,177 7,926 3,333 41,436 28,796 9,071 3,742 41,609
Average daily production:
Oil (Bbls)........ 24,525 8,687 111 1,981 35,304 23,437 7,984 124 31,545 23,641 9,769 831 34,241
NGLs (Bbls)....... 20,338 1,318 906 - 22,562 20,512 696 946 22,154 19,815 547 1,008 21,370
Gas (Mcf)......... 445,609 94,128 41,669 - 581,406 232,360 78,220 48,365 358,945 212,629 87,204 50,481 350,314
Total (BOE)....... 119,129 25,694 7,962 1,981 154,766 82,677 21,716 9,131 113,524 78,893 24,851 10,253 113,997
Average prices, including hedge results:
Oil (per Bbl)..... $25.25 $25.62 $29.10 $29.52 $25.59 $23.66 $20.63 $22.26 $22.89 $24.34 $23.79 $21.87 $24.12
NGLs (per Bbl).... $19.04 $22.85 $24.80 $ - $19.50 $13.77 $14.56 $16.77 $13.92 $16.88 $19.29 $21.11 $17.14
Gas (per Mcf)..... $ 4.49 $ .56 $ 3.90 $ - $ 3.81 $ 3.16 $ .48 $ 2.50 $ 2.49 $ 4.10 $ 1.31 $ 2.86 $ 3.23
Revenue (per BOE). $25.24 $11.87 $23.61 $29.52 $22.99 $19.00 $ 9.79 $15.27 $16.94 $22.56 $14.36 $17.94 $20.36
Average prices, excluding hedge results:
Oil (per Bbl)..... $29.58 $26.31 $29.10 $30.07 $28.80 $23.85 $20.33 $22.26 $22.95 $24.56 $22.40 $21.87 $23.88
NGLs (per Bbl).... $19.04 $22.85 $24.80 $ - $19.50 $13.77 $14.56 $16.77 $13.92 $16.88 $19.29 $21.11 $17.14
Gas (per Mcf)..... $ 4.93 $ .56 $ 4.26 $ - $ 4.17 $ 3.02 $ .48 $ 2.40 $ 2.38 $ 3.96 $ 1.31 $ 3.27 $ 3.20
Revenue (per BOE). $25.71 $12.10 $25.54 $30.07 $25.07 $18.65 $ 9.68 $14.77 $16.63 $22.26 $13.81 $19.95 $20.21
Average costs (per BOE):
Production costs:
Lease operating... $ 3.10 $ 2.57 $ 4.06 $ 3.87 $ 3.07 $ 3.21 $ 1.61 $ 2.64 $ 2.87 $ 2.76 $ 2.64 $ 3.01 $ 2.76
Taxes:
Production...... .76 .20 - .12 .62 .71 .13 - .54 .98 .28 - .74
Ad valorem...... .51 - - - .40 .75 - - .54 .71 - - .49
Field fuel........ .94 - - - .72 .85 - - .62 1.27 - - .88
Workover.......... .15 .01 .43 - .14 .28 .01 .59 .25 .20 .01 .32 .17
----- ----- ----- ---- ------ ----- ----- ----- ----- ----- ----- ----- -----
Total.......... $ 5.46 $ 2.78 $ 4.49 $ 3.99 $ 4.95 $ 5.80 $ 1.75 $ 3.23 $ 4.82 $ 5.92 $ 2.93 $ 3.33 $ 5.04
Depletion expense.. $ 6.85 $ 4.96 $ 9.98 $10.69 $ 6.75 $ 4.64 $ 5.00 $ 8.36 $ 5.01 $ 4.46 $ 5.67 $ 7.71 $ 5.02
- ---------------
(a) These amounts represent the Company's historical results from operations
without making pro forma adjustments for any acquisitions, divestitures or
drilling activity that occurred during the respective years.
20
Productive wells. The following table sets forth the number of productive
oil and gas wells attributable to the Company's properties as of December 31,
2003, 2002 and 2001:
PRODUCTIVE WELLS (a)
Gross Productive Wells Net Productive Wells
-------------------------- -------------------------
Oil Gas Total Oil Gas Total
------ ------ ------ ------ ------ ------
As of December 31, 2003:
United States........... 3,691 2,012 5,703 2,978 1,907 4,885
Argentina............... 669 194 863 539 141 680
Canada.................. 4 268 272 4 210 214
Africa.................. 8 - 8 3 - 3
------ ------ ------ ------ ------ ------
Total................ 4,372 2,474 6,846 3,524 2,258 5,782
====== ====== ====== ====== ====== ======
As of December 31, 2002:
United States........... 3,448 1,952 5,400 2,745 1,855 4,600
Argentina............... 694 208 902 534 142 676
Canada.................. 1 246 247 1 197 198
Africa.................. 5 - 5 2 - 2
------ ------ ------ ------ ------ ------
Total................ 4,148 2,406 6,554 3,282 2,194 5,476
====== ====== ====== ====== ====== ======
As of December 31, 2001:
United States........... 3,485 1,931 5,416 2,116 1,613 3,729
Argentina............... 669 162 831 454 132 586
Canada.................. 4 299 303 3 240 243
------ ------ ------ ------ ------ ------
Total................ 4,158 2,392 6,550 2,573 1,985 4,558
====== ====== ====== ====== ====== ======
- ---------------
(a) Productive wells consist of producing wells and wells capable of
production, including shut-in wells. One or more completions in the same
well bore are counted as one well. Any well in which one of the multiple
completions is an oil completion is classified as an oil well. As of
December 31, 2003, the Company owned interests in 132 gross wells
containing multiple completions.
Leasehold acreage. The following table sets forth information about the
Company's developed, undeveloped and royalty leasehold acreage as of December
31, 2003:
LEASEHOLD ACREAGE
Developed Acreage Undeveloped Acreage
-------------------------- -------------------------- Royalty
Gross Acres Net Acres Gross Acres Net Acres Acreage
------------ ---------- ----------- ----------- ---------
As of December 31, 2003:
United States:
Onshore................. 1,011,370 869,974 125,095 79,224 229,650
Offshore................ 120,333 58,838 828,311 562,604 10,500
---------- ---------- ---------- ---------- --------
1,131,703 928,812 953,406 641,828 240,150
Argentina.................. 713,000 319,000 1,154,000 1,094,000 -
Canada..................... 161,000 123,000 431,000 310,000 15,000
Africa..................... 222,020 63,318 10,778,415 6,109,136 -
---------- ---------- ---------- ---------- --------
Total................... 2,227,723 1,434,130 13,316,821 8,154,964 255,150
========== ========== ========== ========== ========
21
Drilling activities. The following table sets forth the number of gross and
net productive and dry wells in which the Company had an interest that were
drilled during the years ended December 31, 2003, 2002 and 2001. This
information should not be considered indicative of future performance, nor
should it be assumed that there was any correlation between the number of
productive wells drilled and the oil and gas reserves generated thereby or the
costs to the Company of productive wells compared to the costs of dry holes.
DRILLING ACTIVITIES
Gross Wells Net Wells
-------------------------- --------------------------
Year Ended December 31, Year Ended December 31,
-------------------------- --------------------------
2003 2002 2001 2003 2002 2001
------ ------ ------ ------ ------ ------
United States:
Productive wells:
Development.............. 244 148 228 210.5 83.0 114.6
Exploratory.............. 4 6 20 4.0 2.0 11.0
Dry holes:
Development.............. 6 4 15 6.0 3.7 14.6
Exploratory.............. 6 3 8 3.6 2.1 5.1
----- ----- ----- ----- ------ ------
260 161 271 224.1 90.8 145.3
----- ----- ----- ----- ------ ------
Argentina:
Productive wells:
Development.............. 29 13 19 29.0 13.0 17.7
Exploratory.............. 21 9 26 21.0 9.0 25.5
Dry holes:
Development.............. 2 1 1 2.0 1.0 1.0
Exploratory.............. 9 8 16 9.0 8.0 14.0
----- ----- ----- ----- ------ ------
61 31 62 61.0 31.0 58.2
----- ----- ----- ----- ------ ------
Canada:
Productive wells:
Development.............. 7 13 24 7.0 10.4 20.3
Exploratory.............. 16 9 12 14.9 9.0 10.2
Dry holes:
Development.............. 7 4 2 6.5 4.0 2.0
Exploratory.............. 26 3 13 21.1 3.0 11.8
----- ----- ----- ----- ------ ------
56 29 51 49.5 26.4 44.3
----- ----- ----- ----- ------ ------
Africa:
Productive wells:
Development.............. 1 4 - .3 1.6 -
Exploratory.............. 1 4 3 .4 3.4 2.4
Dry holes:
Development.............. - - - - - -
Exploratory.............. 4 - 3 3.5 - 1.9
----- ----- ----- ----- ------ ------
6 8 6 4.2 5.0 4.3
----- ----- ----- ----- ------ ------
Total..................... 383 229 390 338.8 153.2 252.1
===== ===== ===== ===== ====== ======
Success ratio (a)............ 84% 90% 85% 85% 86% 80%
- ---------------
(a) Represents the ratio of those wells that were successfully completed as
producing wells or wells capable of producing to total wells drilled and
evaluated.
22
The following table sets forth information about the Company's wells upon
which drilling was in progress as of December 31, 2003:
Gross Wells Net Wells
----------- ---------
United States:
Development................................. 28 27.1
Exploratory................................. 11 5.8
----- ------
39 32.9
----- ------
Argentina:
Development................................. 3 3.0
Exploratory................................. 10 10.0
----- ------
13 13.0
----- ------
Canada:
Development................................. 6 5.6
Exploratory................................. 11 10.1
----- ------
17 15.7
----- ------
Africa:
Development................................. - -
Exploratory................................. 2 .8
----- ------
2 .8
----- ------
Total..................................... 71 62.4
===== ======
ITEM 3. LEGAL PROCEEDINGS
The Company is party to various legal proceedings, which are described
under "Legal actions" in Note I of Notes to Consolidated Financial Statements
included in "Item 8. Financial Statements and Supplementary Data". The Company
is also party to other litigation incidental to its business. Except for the
specific legal actions described in Note I of Notes to Consolidated Financial
Statements included in "Item 8. Financial Statements and Supplemental Data", the
Company believes that the probable damages from such other legal actions will
not be in excess of 10 percent of the Company's current assets.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
The Company did not submit any matters to a vote of security holders during
the fourth quarter of 2003.
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON STOCK AND RELATED STOCKHOLDER
MATTERS
The Company's common stock is listed and traded on the New York Stock
Exchange under the symbol "PXD". The following table sets forth, for the periods
indicated, the high and low sales prices for the Company's common stock, as
reported in the New York Stock Exchange composite transactions. The Company's
board of directors did not declare dividends to the holders of the Company's
common stock during the years ended December 31, 2003 or 2002. See "2004
Outlook" included in "Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations" for discussion related to future dividends.
23
The following table sets forth quarterly high and low prices of the
Company's common stock for the years ended December 31, 2003 and 2002.
High Low
-------- --------
Year ended December 31, 2003:
Fourth quarter................................ $ 32.90 $ 25.00
Third quarter................................. $ 26.52 $ 22.76
Second quarter................................ $ 28.44 $ 22.85
First quarter................................. $ 27.44 $ 23.27
Year ended December 31, 2002:
Fourth quarter................................ $ 27.50 $ 21.70
Third quarter................................. $ 26.23 $ 19.50
Second quarter................................ $ 26.05 $ 20.00
First quarter................................. $ 22.30 $ 16.10
On January 30, 2004, the last reported sales price of the Company's common
stock, as reported in the New York Stock Exchange composite transactions, was
$31.92 per share.
As of January 30, 2004, the Company's common stock was held by
approximately 29,118 holders of record.
Securities Authorized for Issuance under Equity Compensation Plans
The following table summarizes information about the Company's equity
compensation plans as of December 31, 2003:
(b)
Number of securities
(a) remaining available
Number of for future issuance
securities to be under equity
issued upon Weighted average compensation plans
exercise of exercise price of (excluding securities
outstanding options outstanding options reflected in first column)
------------------- ------------------- --------------------------
Equity compensation plans approved by
security holders (c):
Pioneer Natural Resources Company:
Long-Term Incentive Plan............. 4,857,064 $ 19.63 6,305,591
Employee Stock Purchase Plan......... - $ - 589,884
Predecessor plans....................... 417,052 $ 25.95 -
--------- ----------
5,274,116 6,895,475
========= ==========
- ---------------
(a) There are no outstanding warrants or equity rights awarded under the
Company's equity compensation plans.
(b) The Company's Long-Term Incentive Plan provides for the issuance of a
maximum number of shares of common stock equal to 10 percent of the total
number of shares of common stock equivalents outstanding less the total
number of shares of common stock subject to outstanding awards under any
stock-based plan for the directors, officers or employees of the Company.
The number of remaining securities available for future issuance under the
Company's Employee Stock Purchase Plan is based on the original authorized
issuance of 750,000 shares less 160,116 cumulative shares issued through
December 31, 2003. See Note G of Notes to Consolidated Financial Statements
included in "Item 8. Financial Statements and Supplementary Data" for a
description of each of the Company's equity compensation plans.
(c) There are no equity compensation plans that have not been approved by
security holders.
24
ITEM 6. SELECTED FINANCIAL DATA
The following selected consolidated financial data as of and for each of
the five years ended December 31, 2003 for the Company should be read in
conjunction with "Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations" and "Item 8. Financial Statements and
Supplementary Data".
Year Ended December 31,
-----------------------------------------------------
2003 2002 2001 2000 1999
-------- -------- -------- -------- ---------
(in millions, except per share data)
Statement of Operations Data:
Revenues and other income:
Oil and gas................................ $1,298.6 $ 701.8 $ 847.0 $ 852.7 $ 644.6
Interest and other (a)..................... 12.3 11.2 21.8 25.8 89.7
Gain (loss) on disposition of assets, net.. 1.3 4.4 7.7 34.2 (24.2)
------- ------- ------- ------- -------
Total revenues and other income 1,312.2 717.4 876.5 912.7 710.1
------- ------- ------- ------- -------
Costs and expenses:
Oil and gas production..................... 279.5 199.6 209.7 189.3 159.5
Depletion, depreciation and amortization... 390.8 216.4 222.6 214.9 236.1
Impairment of properties and facilities.... - - - - 17.9
Exploration and abandonments............... 132.8 85.9 127.9 87.5 66.0
General and administrative................. 60.5 48.4 37.0 33.3 40.2
Reorganization............................. - - - - 8.5
Accretion of discount on asset retirement
obligations.............................. 5.0 - - - -
Interest................................... 91.4 95.8 131.9 162.0 170.3
Other (b).................................. 21.4 39.5 43.4 79.5 34.7
------- ------- ------- ------- -------
Total costs and expenses 981.4 685.6 772.5 766.5 733.2
------- ------- ------- ------- -------
Income (loss) before income taxes and cumulative
effect of change in accounting principle... 330.8 31.8 104.0 146.2 (23.1)
Income tax benefit (provision) (c)........... 64.4 (5.1) (4.0) 6.0 .6
------- ------- ------- ------- -------
Income (loss) before cumulative effect of change
in accounting principle.................... 395.2 26.7 100.0 152.2 (22.5)
Cumulative effect of change in accounting
principle, net of tax (d).................. 15.4 - - - -
------- ------- ------- ------- -------
Net income (loss)............................ $ 410.6 $ 26.7 $ 100.0 $ 152.2 $ (22.5)
======= ======= ======= ======= =======
Income (loss) before cumulative effect of
change in accounting principle per share:
Basic.................................... $ 3.37 $ .24 $ 1.01 $ 1.53 $ (.22)
======= ======= ======= ======= =======
Diluted.................................. $ 3.33 $ .23 $ 1.00 $ 1.53 $ (.22)
======= ======= ======= ======= =======
Net income (loss) per share:
Basic.................................... $ 3.50 $ .24 $ 1.01 $ 1.53 $ (.22)
======= ======= ======= ======= =======
Diluted.................................. $ 3.46 $ .23 $ 1.00 $ 1.53 $ (.22)
======= ======= ======= ======= =======
Weighted average shares outstanding:
Basic...................................... 117.2 112.5 98.5 99.4 100.3
======= ======= ======= ======= =======
Diluted.................................... 118.5 114.3 99.7 99.8 100.3
======= ======= ======= ======= =======
Balance Sheet Data (as of December 31):
Total assets................................. $3,951.6 $3,455.1 $3,271.1 $2,954.4 $2,929.5
Long-term liabilities........................ $1,749.9 $1,796.9 $1,743.7 $1,804.5 $1,914.5
Total stockholders' equity................... $1,759.8 $1,374.9 $1,285.4 $ 904.9 $ 774.6
- ---------------
(a) 1999 includes $41.8 million of option fees and liquidated damages and $30.2
million of income associated with an excise tax refund.
(b) Other expense for 2003, 2002, 2001 and 2000 include losses on the early
extinguishment of debt of $1.5 million, $22.3 million, $3.8 million and
$12.3 million, respectively. Other expense for 2000 and 1999 include
noncash mark-to-market charges for changes in the fair values of non-hedge
financial instruments of $58.5 million and $27.0 million, respectively. See
Note O of Notes to Consolidated Financial Statements included in "Item 8.
Financial Statements and Supplementary Data".
(c) The Company's income tax benefit for 2003 includes a $197.7 million
adjustment to reduce United Sates deferred tax asset valuation allowances.
See Note P of Notes to Consolidated Financial Statements included in "Item
8. Financial Statements and Supplementary Data".
(d) The Company's cumulative effect of change in accounting principle relates
to the adoption of SFAS No. 143. See Notes B and L of Notes to Consolidated
Financial Statements included in "Item 8. Financial Statements and
Supplementary Data".
25
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
2003 Highlights
Pioneer's financial and operating results for the year ended December 31,
2003 included the following highlights:
o Production volumes increased 36 percent in 2003 as compared to 2002,
principally due to the completion of the Canyon Express, Falcon and Sable
development projects.
o Oil and gas revenue increased 85 percent in 2003 as a result of the
increased production volumes and increases in North American gas and
worldwide oil prices.
o Pre-tax income increased to $330.8 million from $31.8 million in 2002.
o Pioneer's solid progress towards its strategic objectives over the past
four years and improving key economic indicators, together with other
relevant factors and associated evaluations, led the Company to reverse its
allowances against United States deferred tax assets during 2003. The
reversal of the allowances against United States deferred tax assets
resulted in the recognition of a deferred tax benefit of $197.7 million
during 2003 of which $104.7 million was reversed in the third quarter of
2003 (see Note P of Notes to Consolidated Financial Statements included in
"Item 8. Financial Statements and Supplementary Data" for additional
information regarding the reversal of the allowances against the Company's
United States deferred tax assets).
o Net cash provided by operating activities increased 130 percent to $763.7
million in 2003 as compared to $332.2 million in 2002.
o The Company replaced its $575 million revolving credit facility with a new
five-year $700 million revolving credit agreement with terms similar to
investment grade companies.
o The Company participated in exploration discoveries in the Harrier,
Tomahawk and Raptor fields in the deepwater Gulf of Mexico and the Hawa
field in Tunisia.
o The Company completed a strategic acquisition of the remaining 25 percent
working interest that the Company did not already own in the Falcon field,
Harrier field and surrounding satellite prospects.
o The Company was the high bidder on 53 tracts covering an additional 159,000
acres on the Alaskan North Slope.
o The Company succeeded in obtaining ministerial approval for improved terms
associated with the Olowi permit in Gabon and booked 16.6 MMBOE of proved
reserves in Gabon during 2003.
o The Company's successful capital investment programs resulted in the
replacement of 193 percent and 216 percent of production during the one-
and three-year periods ended December 31, 2003, respectively, resulting in
total proved reserves of 789.1 MMBOE at December 31, 2003.
o The Company reported acquisition and finding costs per BOE of $6.64 and
$6.76 during the one- and three-year periods ended December 31, 2003,
respectively.
2003 Financial and Operating Performance
During the years ended December 31, 2003, 2002 and 2001, the Company
recorded net income of $410.6 million, $26.7 million and $100.0 million ($3.46,
$.23 and $1.00 per diluted share), respectively. Compared to 2002, the Company's
2003 total revenues and other income increased by $594.8 million, or 83 percent,
including a $596.9 million increase in oil and gas revenues. The increase in oil
26
and gas revenues was due to increases in production volumes and increases of 12
percent, 40 percent and 53 percent in average oil, NGL and gas prices,
respectively, including the effects of commodity price hedges.
Compared to 2002, the Company's total costs and expenses increased by
$295.8 million, or 43 percent, during the year ended December 31, 2003. The
increase in total costs and expenses was primarily reflective of a $46.9 million
increase in exploration and abandonments expense, primarily due to increased
exploration/extension drilling in the Gulf of Mexico, Argentina, Canada and
South Africa, a $174.5 million increase in depletion, depreciation and
amortization expense, primarily driven by increases in depletion associated with
increased production volumes from higher-cost-basis Gulf of Mexico and South
Africa properties and an $80.0 million increase in oil and gas production costs,
which primarily resulted from increases in production volumes, the strengthening
of both the Argentine peso and Canadian dollar and commodity prices that
impacted variable lease operating expenses and production taxes, partially
offset by an $18.3 million decrease in other expense, primarily due to $22.3
million of losses recognized during 2002 associated with debt extinguished prior
to its stated maturity.
During the year ended December 31, 2003, the Company's net cash provided by
operating activities increased to $763.7 million, as compared to $332.2 million
during 2002 and $475.6 million during 2001. The increase in net cash provided by
operating activities during 2003 was primarily due to increases in oil, NGL and
gas production volumes and prices, as discussed above.
During the year ended December 31, 2003, successful capital investment
activities increased the Company's proved reserves to 789.1 MMBOE, reflecting
the effects of strategic acquisitions of properties in the Company's core
operating areas and a successful drilling program which resulted in the
replacement of 193 percent of production at an acquisition and finding cost per
BOE of $6.64. During the three years ended December 31, 2003, Pioneer has
replaced 216 percent of production at an acquisition and finding cost per BOE of
$6.76. Costs incurred for the year ended December 31, 2003 totaled $723.0
million, including $151.0 million of proved and unproved property acquisitions
and $572.0 million of exploration and development drilling and seismic
expenditures.
See "Results of Operations" and "Capital Commitments, Capital Resources and
Liquidity", below, for more in- depth discussions of the Company's oil and gas
producing activities, including discussions pertaining to oil and gas production
volumes, prices, hedging activities, costs and expenses, capital commitments,
capital resources and liquidity.
2004 Outlook
Commodity prices. World oil prices increased during the year ended December
31, 2003 in response to political unrest and supply disruptions in the Middle
East as well as other supply and demand factors. North American gas prices also
increased during 2003 in response to continued strong supply and demand
fundamentals. The Company's outlook for 2004 commodity prices is cautiously
optimistic. Significant factors that will impact 2004 commodity prices include
developments in Iraq and other Middle East countries, the extent to which
members of the Organization of Petroleum Exporting Countries and other oil
exporting nations are able to manage oil supply through export quotas and
variations in key North American gas supply and demand indicators. Pioneer will
continue to strategically hedge oil and gas price risk to mitigate the impact of
price volatility on its oil, NGL and gas revenues.
As of December 31, 2003, the Company had hedged 18,973 barrels per day
of 2004 oil production under swap contracts with a weighted average fixed price
to be received of $25.84 per Bbl. The Company had also hedged 283,962 Mcf per
day of 2004 gas production under swap contracts with a weighted average fixed
price to be received of $4.16 per MMBtu. During January 2004, the Company
increased its 2004 commodity hedge positions by entering into 32,967 Mcf per day
of first quarter gas swap contracts with average per MMBtu fixed prices of
$7.11. Additionally, at December 31, 2003 the Company had net deferred gains on
terminated oil hedge contracts of $1.0 million that will be recognized as
increases to oil revenue during 2004 and $42.9 million of net deferred gains on
terminated gas hedge contracts that will be recognized as increases to gas
revenue during 2004. See Note J of Notes to Consolidated Financial Statements
included in "Item 8. Financial Statements and Supplementary Data" for additional
information regarding the Company's commodity hedge positions at December 31,
2003. Also see "Item 7A. Quantitative and Qualitative Disclosures About Market
Risk" for disclosures about the Company's commodity related derivative financial
instruments.
27
Capital expenditures. During 2004, the Company's budget for oil and gas
capital activities is expected to range from $550 million to $600 million, of
which approximately 65 percent has been budgeted for development drilling and
facility costs and 35 percent for exploration expenditures. The Company's 2004
capital budget is allocated approximately 70 percent to the United States, 19
percent to Argentina and the remaining 11 percent is budgeted for expenditures
in Canada, Gabon, Tunisia, South Africa and other foreign areas. Pioneer expects
to drill approximately 400 exploration and development wells during 2004. During
2004 and 2005, the Company expects to expend approximately $219 million and $348
million, respectively, of capital for development drilling and facility costs
related to its proved undeveloped reserves.
Production growth. The Company expects that its annual 2004 worldwide
production will range from 65 MMBOE to 73 MMBOE, or approximately 178 MBOE to
200 MBOE per day, an increase of 15 percent to 29 percent over 2003 levels. The
bottom end of the range includes a full year of production from the Company's
deepwater Gulf of Mexico Falcon and Harrier gas fields, the Sable oil field in
South Africa and the Hawa field in Tunisia, coupled with increases in production
from the Company's 2004 capital program and the inherent variability in
production results. The Company expects, based on quoted futures prices, to
generate cash flow significantly in excess of its capital program and has
considered the potential to invest a portion of the excess cash for additional
development drilling or core area acquisitions in arriving at the top end of the
2004 production range.
The outlook for continued production growth in 2005 is strong considering
that first production from several new projects is not expected until well into
2004. The Company will have its first full year of production from the Devils
Tower, Tomahawk and Raptor deepwater fields during 2005, and the Company
believes it has sufficient development inventory to support production growth in
the United States, Argentina, Canada and Tunisia. As a result, Pioneer currently
expects production in 2005 to match 2004 at a minimum, with considerable upside
given the potential investment of excess cash flow to develop new exploration
successes and/or acquire additional assets in core areas during 2004 and 2005.
Longer term, with several discoveries to develop for 2006 and beyond, a
pipeline of exploration opportunities, potential for continued core area
acquisitions, continuing strong commodity prices and significant excess cash
flow, Pioneer has targeted five-year average compounded annual production growth
of ten percent.
Costs and expenses. The Company expects that its costs and expenses that
are highly correlated with production volumes, such as production costs and
depletion expense, will increase in absolute amounts during 2004. Additionally,
the Company expects that depletion expense will increase on a per BOE basis
during 2004 as compared to 2003 due to new production from Harrier, Tomahawk,
Raptor and Devils Tower fields in the deepwater Gulf of Mexico and increased
production from the Sable oil field offshore South Africa. The per BOE cost
bases of these fields are higher than that of Pioneer's average producing
property in 2003. Additionally, the average per BOE lifting costs of Devils
Tower and Sable oil field production are expected to exceed the Company's
average 2003 per BOE lifting costs. The Company expects average per BOE
production taxes to decline during 2004 as compared to 2003 as the production
from the aforementioned properties are not burdened by such taxes. Ad valorem
taxes are highly correlated with prior year commodity prices. As a consequence
of increases in oil, NGL and gas prices during 2003, ad valorem taxes are
expected to be higher in 2004, as compared to 2003. The Company anticipates an
increase in general and administrative expenses during 2004 due to additional
staffing and the amortization of restricted stock that is being awarded to
officers and employees in lieu of stock options, which were awarded in prior
years.
Capital allocation. Four years ago, the Company made a commitment to move
its financial position to investment grade standards, and significant
improvement has been accomplished during that period with year-end 2003 debt to
book capitalization reaching 46.9 percent as compared to 69.3 percent at the end
of 1999. The Company has established a targeted range for debt to book
capitalization of 37 percent to 43 percent. Given the expanding financial
strength of the Company and expectations for significant cash flow in excess of
its capital budget, the Company expects to use a portion of its excess cash flow
in 2004 to further reduce long-term debt by a minimum of $100 million.
Additionally, the Company' s Board of Directors have approved a plan to begin a
dividend program of $.20 per common share, payable in two semi-annual
installments of $.10 per common share, beginning in 2004.
28
During 2004 through 2006, the Company anticipates, based upon year-end
futures prices, that it will have significant excess cash flow even after
funding its typical annual capital budgets, planned dividends and achieving its
leverage targets. The Company considers it a high priority to utilize a portion
of the excess cash flow to fund the development of new exploration successes and
to selectively acquire additional assets in its core areas. The Company will
also consider using a portion of the excess cash flow for share repurchases.
First quarter 2004. Based on current estimates, the Company expects that
its first quarter 2004 production will average 168,000 to 183,000 BOEs per day,
reflecting the incremental production from Harrier which began producing in
January, the variability of oil cargo shipments in Tunisia and South Africa and
the seasonal decline in gas demand during Argentina's summer season. First
quarter production costs are expected to average $5.00 to $5.50 per BOE based on
current NYMEX strip prices for oil and gas. Deprecation, depletion and
amortization expense is expected to average $7.75 to $8.25 per BOE as a greater
proportion of the Company's production is being produced from higher-cost basis
deepwater Gulf of Mexico and South Africa properties. Total exploration and
abandonment expense is expected to be $25 million to $85 million. The first
quarter range includes a number of high-impact deepwater Gulf of Mexico wells
that are in progress, up to five wells expected in Gabon to further refine
development plans and test a new exploration target, increased exploration
drilling in Argentina and the winter drilling program in Canada. General and
administrative expense is expected to be $17 million to $20 million, $2 million
to $3 million of which relates to estimated performance- based compensation
costs. Interest expense is expected to be $21 million to $23 million and
accretion of discount on asset retirement obligations is expected to be
approximately $2 million. The Company recognizes deferred income taxes
reflecting its tax position in each of its areas of operation. However, cash
income taxes are expected to be only $3 million to $5 million, principally
related to Argentine income taxes and nominal alternative minimum tax in the
United States. Other than in Argentina, the Company continues to benefit from
the carryforward of net operating losses and other positive tax attributes.
Critical Accounting Estimates
The Company prepares its consolidated financial statements for inclusion in
this Report in accordance with accounting principles that are generally accepted
in the United States ("GAAP"). See Note B of Notes to Consolidated Financial
Statements included in "Item 8. Financial Statements and Supplementary Data" for
a comprehensive discussion of the Company's significant accounting policies.
GAAP represents a comprehensive set of accounting and disclosure rules and
requirements, the application of which requires management judgments and
estimates including, in certain circumstances, choices between acceptable GAAP
alternatives. Following is a discussion of the Company's most critical
accounting estimates, judgments and uncertainties that are inherent in the
Company's application of GAAP:
Accounting for oil and gas producing activities. The accounting for and
disclosure of oil and gas producing activities requires the Company's management
to choose between GAAP alternatives and to make judgments about estimates of
future uncertainties.
Successful efforts method of accounting. The Company utilizes the
successful efforts method of accounting for oil and gas producing activities as
opposed to the alternate acceptable full cost method. In general, the Company
believes that, during periods of active exploration, net assets and net income
are more conservatively measured under the successful efforts method of
accounting for oil and gas producing activities than under the full cost method.
The critical difference between the successful efforts method of accounting and
the full cost method is as follows: under the successful efforts method,
exploratory dry holes and geological and geophysical exploration costs are
charged against earnings during the periods in which they occur; whereas, under
the full cost method of accounting, such costs and expenses are capitalized as
assets, pooled with the costs of successful wells and charged against the
earnings of future periods as a component of depletion expense. During the years
ended December 31, 2003, 2002 and 2001, the Company recognized exploration,
abandonment, geological and geophysical expense of $132.8 million, $85.9 million
and $127.9 million, respectively, under the successful efforts method.
Proved reserve estimates. Estimates of the Company's proved reserves
included in this Report are prepared in accordance with GAAP and SEC guidelines.
The accuracy of a reserve estimate is a function of:
o the quality and quantity of available data;
o the interpretation of that data;
29
o the accuracy of various mandated economic assumptions; and
o the judgment of the persons preparing the estimate.
The Company's proved reserve information included in this Report as of
December 31, 2003 and 2002 was based on evaluations audited by independent
petroleum engineers with respect to the Company's major properties and prepared
by the Company's engineers with respect to all other properties. The Company's
proved reserve information included in this Report as of December 31, 2001 was
based on evaluations prepared by the Company's engineers. Estimates prepared by
other third parties may be higher or lower than those included herein.
Because these estimates depend on many assumptions, all of which may
substantially differ from future actual results, reserve estimates will be
different from the quantities of oil and gas that are ultimately recovered. In
addition, results of drilling, testing and production after the date of an
estimate may justify material revisions to the estimate.
It should not be assumed that the present value of future net cash flows
included in this Report as of December 31, 2003 is the current market value of
the Company's estimated proved reserves. In accordance with SEC requirements,
the Company based the estimated present value of future net cash flows from
proved reserves on prices and costs on the date of the estimate. Actual future
prices and costs may be materially higher or lower than the prices and costs as
of the date of the estimate.
The Company's estimates of proved reserves materially impact depletion
expense. If the estimates of proved reserves decline, the rate at which the
Company records depletion expense will increase, reducing future net income.
Such a decline may result from lower market prices, which may make it uneconomic
to drill for and produce higher cost fields. In addition, a decline in proved
reserve estimates may impact the outcome of the Company's assessment of its oil
and gas producing properties for impairment.
Impairment of proved oil and gas properties. The Company reviews its
long-lived proved properties to be held and used whenever management determines
that events or circumstances indicate that the recorded carrying value of the
properties may not be recoverable. Management assesses whether or not an
impairment provision is necessary based upon its outlook of future commodity
prices and net cash flows that may be generated by the properties. Proved oil
and gas properties are reviewed for impairment by depletable pool, which is the
lowest level at which depletion of proved properties is calculated.
Impairment of unproved oil and gas properties. Management periodically
assesses individually significant unproved oil and gas properties for
impairment, on a project-by-project basis. Management's assessment of the
results of exploration activities, commodity price outlooks, planned future
sales or expiration of all or a portion of such projects impact the amount and
timing of impairment provisions.
Suspended wells. The Company suspends the costs of exploratory wells that
discover hydrocarbons pending a final determination of the commercial potential
of the related oil and gas fields. The ultimate disposition of these well costs
is dependent on the results of future drilling activity and development
decisions. If the Company decides not to pursue additional appraisal activities
or development of these fields, the costs of these wells will be charged to
exploration and abandonment expense. At December 31, 2003, the Company had $88.6
million of suspended exploratory well costs included in property, plant and
equipment.
Assessments of functional currencies. Management determines the functional
currencies of the Company's subsidiaries based on an assessment of the currency
of the economic environment in which a subsidiary primarily realizes and expends
its operating revenues, costs and expenses. The U.S. dollar is the functional
currency of all of the Company's international operations except Canada. The
assessment of functional currencies can have a significant impact on periodic
results of operations and financial position.
Argentine economic and currency measures. The accounting for and
remeasurement of the Company's Argentine balance sheets as of December 31, 2003
and 2002 reflect management's assumptions regarding some uncertainties unique to
Argentina's current economic situation. See Note B of Notes to Consolidated
Financial Statements included in "Item 8. Financial Statements and Supplementary
Data" for a description of the assumptions utilized in the preparation of these
financial statements. The Argentine economic and political situation continues
30
to evolve and the Argentine government may enact future regulations or policies
that, when finalized and adopted, may materially impact, among other items, (i)
the realized prices the Company receives for the commodities it produces and
sells; (ii) the timing of repatriations of excess cash flow to the Company's
corporate headquarters in the United States; (iii) the Company's asset
valuations; and (iv) peso-denominated monetary assets and liabilities.
Deferred tax asset valuation allowances. From 1998 until 2003, the Company
maintained a valuation allowance against a portion of its deferred tax asset
position in the United States. SFAS 109 requires that the Company continually
assess both positive and negative evidence to determine whether it is more
likely than not that the deferred tax assets can be realized prior to their
expiration. In the third quarter of 2003 and as of December 31, 2003, the
Company concluded that it is more likely than not that it will realize its gross
deferred tax asset position in the United States after giving consideration to
relevant facts and circumstances.
Accordingly, during the third quarter of 2003, the Company reversed its
remaining valuation allowance in the United States, resulting in the recognition
of a deferred tax benefit of $104.7 million. For 2003 in total, the Company
reversed $197.7 million of United States valuation allowances resulting in a net
deferred tax benefit for the year. Further, the third quarter 2003 reversal of
the allowance increased stockholders' equity by $32.6 million as the Company
recognized the tax effects of previous stock option exercises and deferred
hedging gains and losses in other comprehensive income. See Note P of Notes to
Consolidated Financial Statements included in "Item 8. Financial Statements and
Supplementary Data" for additional information regarding the Company's United
States deferred tax assets and a specific discussion of the relevant facts and
circumstances that were assessed.
Pioneer will continue to monitor Company-specific, oil and gas industry and
worldwide economic factors and will reassess the likelihood that the Company's
net operating loss carryforwards and other deferred tax attributes in each
jurisdiction will be utilized prior to their expiration. There can be no
assurances that facts and circumstances will not materially change and require
the Company to reestablish a United States deferred tax asset valuation
allowance in a future period. As of December 31, 2003, the Company does not
believe there is sufficient positive evidence to reverse its valuation
allowances related to foreign tax jurisdictions.
Litigation and environmental contingencies. The Company makes judgments and
estimates in recording liabilities for ongoing litigation and environmental
remediation. Actual costs can vary from such estimates for a variety of reasons.
The costs to settle litigation can vary from estimates based on differing
interpretations of laws and opinions and assessments on the amount of damages.
Similarly, environmental remediation liabilities are subject to change because
of changes in laws, regulations, additional information obtained relating to the
extent and nature of site contamination and improvements in technology. Under
generally accepted accounting principles in the United States ("GAAP"), a
liability is recorded for these types of contingencies if the Company determines
the loss to be both probable and reasonably estimated. See Note I of Notes to
Consolidated Financial Statements included in "Item 8. Financial Statements and
Supplementary Data" for additional information regarding the Company's
commitments and contingencies.
Results of Operations
Oil and gas revenues. Revenues from oil and gas operations totaled $1.3
billion during 2003, as compared to $701.8 million during 2002 and $847.0
million during 2001, representing an 85 percent increase from 2002 to 2003. The
revenue increase from 2002 to 2003 was due to a 36 percent increase in BOE
production, a 12 percent increase in oil prices, a 40 percent increase in NGL
prices and a 53 percent increase in gas prices, including the effects of
commodity price hedges. The increased production is principally attributable to
incremental gas production from the deepwater Gulf of Mexico Canyon Express and
Falcon field projects, initial oil production in South Africa and Tunisia and
increased oil and gas production in Argentina, offset by normal production
declines. The revenue decrease from 2001 to 2002 was principally due to
year-on-year worldwide average oil, NGL and gas price declines of five percent,
19 percent and 23 percent, respectively, including the effects of commodity
price hedges, and an eight percent decline in worldwide oil production,
partially offset by worldwide NGL and gas production increases of four percent
and two percent, respectively.
31
The following table provides production volumes and average reported
prices, including the results of hedging activities, by geographic area and in
total, for the years ended December 31, 2003, 2002 and 2001:
Year ended December 31,
-------------------------------------
2003 2002 2001
-------- -------- --------
Average daily production:
Oil (Bbls)
United States................................... 24,525 23,437 23,641
Argentina....................................... 8,687 7,984 9,769
Canada.......................................... 111 124 831
Africa.......................................... 1,981 - -
-------- -------- --------
Worldwide....................................... 35,304 31,545 34,241
NGLs (Bbls)
United States................................... 20,338 20,512 19,815
Argentina....................................... 1,318 696 547
Canada.......................................... 906 946 1,008
-------- -------- --------
Worldwide....................................... 22,562 22,154 21,370
Gas (Mcf)
United States................................... 445,609 232,360 212,629
Argentina....................................... 94,128 78,220 87,204
Canada.......................................... 41,669 48,365 50,481
-------- -------- --------
Worldwide....................................... 581,406 358,945 350,314
Total (BOE)
United States................................... 119,129 82,677 78,893
Argentina....................................... 25,694 21,716 24,851
Canada.......................................... 7,962 9,131 10,253
Africa.......................................... 1,981 - -
-------- -------- --------
Worldwide....................................... 154,766 113,524 113,997
Average reported prices:
Oil (per Bbl)
United States................................... $ 25.25 $ 23.66 $ 24.34
Argentina....................................... $ 25.62 $ 20.63 $ 23.79
Canada.......................................... $ 29.10 $ 22.26 $ 21.87
Africa.......................................... $ 29.52 $ - $ -
Worldwide....................................... $ 25.59 $ 22.89 $ 24.12
NGL (per Bbl)
United States................................... $ 19.04 $ 13.77 $ 16.88
Argentina....................................... $ 22.85 $ 14.56 $ 19.29
Canada.......................................... $ 24.80 $ 16.77 $ 21.11
Worldwide....................................... $ 19.50 $ 13.92 $ 17.14
Gas (per Mcf)
United States................................... $ 4.49 $ 3.16 $ 4.10
Argentina....................................... $ .56 $ .48 $ 1.31
Canada.......................................... $ 3.90 $ 2.50 $ 2.86
Worldwide....................................... $ 3.81 $ 2.49 $ 3.23
Annual percentage increase (decrease) in average
worldwide reported prices:
Oil............................................. 12 (5) -
NGL............................................. 40 (19) (15)
Gas............................................. 53 (23) 15
Hedging activities. The oil and gas prices that the Company reports are
based on the market price received for the commodities adjusted by the results
of the Company's cash flow hedging activities. The Company utilizes commodity
swap and collar contracts in order to (i) reduce the effect of price volatility
on the commodities the Company produces and sells, (ii) support the Company's
annual capital budgeting and expenditure plans and (iii) reduce commodity price
risk associated with certain capital projects. The effective portions of changes
in the fair values of the Company's commodity price hedges are deferred as
increases or decreases to stockholders' equity until the underlying hedged
transaction occurs. Consequently, changes in the effective portions of commodity
price hedges add volatility to the Company's reported stockholders' equity until
32
the hedge derivative matures or is terminated. See Note J of Notes to
Consolidated Financial Statements included in "Item 8. Financial Statements and
Supplementary Data" for information concerning the impact to oil and gas
revenues during the years ended December 31, 2003, 2002 and 2001 from the
Company's hedging activities, the Company's open hedge positions at December 31,
2003 and descriptions of the Company's hedge and non-hedge commodity
derivatives. Also see "Item 7A. Quantitative and Qualitative Disclosures About
Market Risk" for additional disclosure about the Company's commodity related
derivative financial instruments.
Interest and other income. The Company recorded interest and other income
totaling $12.3 million, $11.2 million and $21.8 during the years ended December
31, 2003, 2002 and 2001, respectively. The Company's interest and other income
was comprised of revenue that was not directly attributable to oil and gas
producing activities or oil and gas property divestitures. See Note M of Notes
to Consolidated Financial Statements included in "Item 8. Financial Statements
and Supplementary Data" for additional information regarding interest and other
income.
Gain on disposition of assets. During the years ended December 31, 2003,
2002 and 2001, the Company completed asset divestitures for net proceeds of
$35.7 million, $118.9 million and $113.5 million, respectively. Associated
therewith, the Company recorded gains on disposition of assets of $1.3 million,
$4.4 million and $7.7 million during the years ended December 31, 2003, 2002 and
2001, respectively.
The net cash proceeds from asset divestitures during the years ended
December 31, 2003, 2002 and 2001 were used, together with net cash flows
provided by operating activities, to fund additions to oil and gas properties
and to reduce outstanding indebtedness. See Note N of Notes to Consolidated
Financial Statements included in "Item 8. Financial Statements and Supplementary
Data" for additional information regarding asset divestitures.
Oil and gas production costs. The Company recorded production costs of
$279.5 million, $199.6 million and $209.7 million during the years ended
December 31, 2003, 2002 and 2001, respectively. The increase in total production
costs during 2003 as compared to 2002 is primarily attributable to the increase
in production volumes, while the decrease in total production costs during 2002
as compared to 2001 is principally attributable to lower production tax and
field fuel expenses due to lower commodity prices.
Total production costs per BOE increased during the year ended December 31,
2003 by three percent and decreased during the year ended December 31, 2002 by
four percent. In general, lease operating expenses and workover expenses
represent the components of oil and gas production costs over which the Company
has management control, while production taxes, ad valorem taxes and field fuel
expenses are directly related to commodity price changes. The increase in
production costs per BOE during 2003 was primarily due to increases in per BOE
lease operating expenses, field fuel expenses and production taxes, partially
offset by decreases in per BOE ad valorem taxes and workover expenses. The
increase in per BOE lease operating expenses was due to the strengthening of
both the Argentine peso and the Canadian dollar, Argentine inflation and higher
average lifting costs incurred on South African Sable oil field production,
while the increases in per BOE field fuel expenses and production taxes
primarily resulted from increases in North American gas prices and world oil
prices. The decrease in per BOE ad valorem taxes is primarily due to the
incremental production from the deepwater Gulf of Mexico, Argentina, South
Africa and Tunisia fields which are not subject to ad valorem taxes.
The decrease in production costs during 2002 was primarily due to decreases
in field fuel expense and production taxes as a result of lower North American
average gas prices and lower Argentine lease operating expenses resulting from
lower Argentine expenses on a U.S. dollar equivalent basis due to the
devaluation of the Argentine peso versus the U.S. dollar, partially offset by
moderately higher workover expenses, ad valorem taxes (which are computed using
prior year average annual commodity prices) and declines in the third party gas
processing and treating margin component of lease operating expense.
33
The following tables provide the components of the Company's total
production costs per BOE and total production costs per BOE by geographic area
for the years ended December 31, 2003, 2002 and 2001:
Year Ended December 31,
-----------------------------
2003 2002 2001
------- ------- -------
Lease operating expenses................. $ 3.07 $ 2.87 $ 2.76
Taxes:
Production............................. .62 .54 .74
Ad valorem ............................ .40 .54 .49
Field fuel expenses...................... .72 .62 .88
Workover expenses........................ .14 .25 .17
------ ------ ------
Total production costs............. $ 4.95 $ 4.82 $ 5.04
====== ====== ======
Year Ended December 31,
-----------------------------
2003 2002 2001
------- ------- -------
Total production costs:
United States.......................... $ 5.46 $ 5.80 $ 5.92
Argentina.............................. $ 2.78 $ 1.75 $ 2.93
Canada................................. $ 4.49 $ 3.23 $ 3.33
Africa................................. $ 3.99 $ - $ -
Worldwide.............................. $ 4.95 $ 4.82 $ 5.04
Depletion, depreciation and amortization expense. The Company's total
depletion, depreciation and amortization expense per BOE was $6.92, $5.22 and
$5.35 for the years ended December 31, 2003, 2002 and 2001, respectively.
Depletion expense, the largest component of depletion, depreciation and
amortization, was $6.75, $5.01 and $5.02 per BOE during the years ended December
31, 2003, 2002 and 2001, respectively, and depreciation and amortization of
other property and equipment was $.17, $.21 and $.33 per BOE during each of the
respective years. During 2003, the increase in per BOE depletion expense was due
to increases in higher cost-basis deepwater Gulf of Mexico and South African
production volumes and downward revisions to proved reserves in Canada.
The following table provides depletion expense per BOE by geographic area
for the years ended December 31, 2003, 2002 and 2001:
Year Ended December 31,
-----------------------------
2003 2002 2001
------- ------- -------
Depletion expense:
United States.......................... $ 6.85 $ 4.64 $ 4.46
Argentina.............................. $ 4.96 $ 5.00 $ 5.67
Canada................................. $ 9.98 $ 8.36 $ 7.71
Africa................................. $ 10.69 $ - $ -
Worldwide.............................. $ 6.75 $ 5.01 $ 5.02
34
Exploration, abandonments, geological and geophysical costs. Exploration,
abandonments, geological and geophysical costs totaled $132.8 million, $85.9
million and $127.9 million during the years ended December 31, 2003, 2002 and
2001, respectively. The following table sets forth the components of the
Company's exploration, abandonments, geological and geophysical costs by
geographic region for the years ended December 31, 2003, 2002 and 2001:
Africa
United and
States Argentina Canada Other Total
-------- --------- -------- --------- --------
(in thousands)
Year Ended December 31, 2003:
Geological and geophysical costs........ $ 40,783 $ 7,689 $ 4,426 $ 3,903 $ 56,801
Exploratory dry holes................... 27,015 2,672 10,963 20,250 60,900
Leasehold abandonments and other........ 4,934 7,715 2,302 108 15,059
------- ------- ------- ------- -------
$ 72,732 $ 18,076 $ 17,691 $ 24,261 $132,760
======= ======= ======= ======= =======
Year Ended December 31, 2002:
Geological and geophysical costs........ $ 22,761 $ 4,138 $ 3,544 $ 7,223 $ 37,666
Exploratory dry holes................... 32,557 3,294 1,220 (539) 36,532
Leasehold abandonments and other........ 7,637 2,874 1,077 108 11,696
------- ------- ------- ------- -------
$ 62,955 $ 10,306 $ 5,841 $ 6,792 $ 85,894
======= ======= ======= ======= =======
Year Ended December 31, 2001:
Geological and geophysical costs........ $ 29,620 $ 6,541 $ 2,373 $ 13,678 $ 52,212
Exploratory dry holes................... 34,883 6,040 5,473 10,432 56,828
Leasehold abandonments and other........ 5,546 11,276 2,036 8 18,866
------- ------- ------- ------- -------
$ 70,049 $ 23,857 $ 9,882 $ 24,118 $127,906
======= ======= ======= ======= =======
The increase in 2003 exploration, abandonments, geological and geophysical
expense, as compared to 2002, was primarily due to increased geological and
geophysical expenditures supportive of exploration activities in the Gulf of
Mexico and Alaska and a $24.4 million increase in exploratory dry hole expense.
The increase in exploratory dry hole expense during 2003 was primarily due to an
increase in Canadian exploratory drilling activities and three unsuccessful
wells drilled in South Africa and one unsuccessful well drilled in Tunisia.
The decrease in 2002 exploration, abandonments, geological and geophysical
expense reflected a decline in Argentine exploration activities as the Company
monitored and assessed the economic environment and risks associated with
Argentina; a decline in exploratory dry holes and geological and geophysical
expense in Africa, as the Company assessed its exploratory successes in Gabon
and Tunisia; and the allocation of a larger percentage of the Company's 2002
capital budget to the development of its significant discoveries in the Gulf of
Mexico and offshore South Africa.
Approximately 38 percent of the Company's 2003 costs incurred for oil and
gas producing activities were exploration costs as compared to 20 percent in
2002 and 34 percent in 2001.
General and administrative expenses. The Company's general and
administrative expenses totaled $60.5 million ($1.07 per BOE), $48.4 million
($1.17 per BOE) and $37.0 million ($.89 per BOE) during the years ended December
31, 2003, 2002 and 2001, respectively. The increase in general and
administrative expense during 2003, as compared to 2002, was primarily due to
increases in administrative staff and performance-related compensation costs,
including the amortization of restricted stock awarded to officers, directors
and key employees during 2003 and 2002.
The increase in administrative expense during the year ended December 31,
2002 as compared to 2001 was primarily due to the elimination of operating
overhead being charged by the Company to the 42 affiliated partnerships that
were merged into a wholly-owned subsidiary of the Company during December 2001
and amortization of restricted stock awarded in 2002.
See Notes D and G of Notes to Consolidated Financial Statements included in
"Item 8. Financial Statements and Supplementary Data" for information regarding
the affiliated partnership mergers and the restricted stock awards in 2003 and
2002 and their vesting periods, respectively.
35
Accretion of discount on asset retirement obligations. During the year
ended December 31, 2003 the Company recorded accretion of discount on asset
retirement obligations of $5.0 million. The provisions of Statement of Financial
Accounting Standards No. 143, "Accounting for Asset Retirement Obligations"
("SFAS 143") require that the accretion of discount on asset retirement
obligations be classified in the consolidated statement of operations separate
from interest expense. Prior to 2003 and the adoption of SFAS 143, the Company
classified accretion of discount on asset retirement obligations as a component
of interest expense. The Company's interest expense during each of the years
ended December 31, 2002 and 2001 included $2.6 million of accretion of discount
on asset retirement obligations that was calculated prior to the adoption of
SFAS 143 based on asset retirement obligations recorded in purchased business
combinations. See "Cumulative effect of change in accounting principle" below
and Notes B and L of Notes to Consolidated Financial Statements included in
"Item 8. Financial Statements and Supplementary Data" for additional information
regarding the Company's adoption of SFAS 143.
Interest expense. Interest expense was $91.4 million, $95.8 million and
$132.0 million during the years ended December 31, 2003, 2002 and 2001,
respectively, while the weighted average interest rate on the Company's
indebtedness for the year ended December 31, 2003 was 5.3 percent as compared to
5.7 percent and 7.5 percent for the years ended December 31, 2002 and 2001,
respectively, taking into account the effect of interest rate swaps. The
decrease in interest expense for 2003 as compared to 2002 was primarily due to
$4.8 million of interest savings associated with the July 2002 repayment of a
$45.2 million West Panhandle gas field capital obligation (the "West Panhandle
Capital Obligation") which bore interest at an annual rate of 20 percent; $4.1
million of incremental savings from the Company's interest rate hedging program;
a $2.6 million decrease in accretion expense (see "Accretion of discount on
asset retirement obligations", above); and lower underlying market interest
rates and outstanding debt. Partially offsetting the decreases in interest
expense was a $6.8 million decrease in interest capitalized during 2003 as
compared to 2002 due to the completion of the Canyon Express and Falcon field
development projects.
The decline in 2002 interest expense as compared to 2001, was primarily due
to incremental interest savings of $18.0 million from the Company's interest
rate hedging program; a $6.3 million increase in interest capitalized; interest
savings from the retirement of the Company's outstanding 11-5/8 percent and
10-5/8 percent senior subordinated notes during the third quarter of 2001and
$38.7 million of the Company's 9-5/8 percent senior notes during the fourth
quarter of 2001; interest savings from the repurchase of $47.1 million of 9-5/8
percent senior notes and $13.9 million of 8-7/8 percent senior notes during
2002; interest savings from the repayment of West Panhandle Capital Obligation;
and interest savings from reductions in underlying market interest rates.
See Note E of Notes to Consolidated Financial Statements included in "Item
8. Financial Statements and Supplementary Data" for additional information about
the Company's long-term debt and interest expense.
Other expenses. Other expenses were $21.3 million during the year ended
December 31, 2003, as compared to $39.6 million during 2002 and $43.3 million
during 2001. See Note O of Notes to Consolidated Financial Statements included
in "Item 8. Financial Statements and Supplementary Data" for a detail of the
components included in other expenses.
Income tax provisions (benefits). The Company recognized a consolidated
income tax benefit of $64.4 million during the year ended December 31, 2003 and
consolidated income tax provisions of $5.1 million and $4.0 million during the
years ended December 31, 2002 and 2001, respectively. The Company's consolidated
tax benefit in 2003 was comprised of a $.1 million current United States federal
tax provision, an $11.1 million current foreign income tax provision, $76.3
million of deferred United States federal and state tax benefits and $.7 million
of deferred foreign tax provisions. The 2003 deferred United States federal and
state tax benefits include a $197.7 million benefit from the reversal of the
Company's valuation allowances against United States deferred tax assets, of
which $104.7 million was reversed in the third quarter of 2003. As a result of
the reversal of the valuation allowances against the Company's United States
deferred tax assets, the effective tax rate on the Company's future earnings in
the United States will approximate statutory rates.
36
The Company's consolidated tax provision for 2002 was comprised of current
United States state and local taxes of $.2 million, current foreign taxes of
$2.1 million and deferred foreign tax provisions of $2.8 million. The Company's
consolidated tax provision for 2001 was comprised of current U.S. state and
local taxes of $1.1 million, current foreign taxes of $10.5 million and deferred
foreign tax benefits of $7.6 million.
See "Critical Accounting Estimates" above and Note P of Notes to
Consolidated Financial Statements included in "Item 8. Financial Statements and
Supplementary Data" for additional information regarding the Company's tax
position.
Cumulative effect of change in accounting principle. As previously
discussed, the Company adopted the provisions of SFAS 143 on January 1, 2003 and
recognized a $15.4 million benefit from the cumulative effect of change in
accounting principle, net of $1.3 million of associated Argentine deferred
income taxes during the year ended December 31, 2003.
On January 1, 2003, the Company also adopted the provisions of Statement of
Financial Accounting Standards No. 145, "Rescission of FASB Statements No. 4, 44
and 64, Amendment of FASB Statement No. 13 and Technical Corrections" ("SFAS
145"), the provisions of which did not result in a cumulative effect adjustment.
In accordance with the provisions of SFAS 145, the Company reclassified to other
expense extraordinary losses from the early extinguishment of debt of $22.3
million and $3.8 million realized during the years ended December 31, 2002 and
2001, respectively.
See Note B of Notes to Consolidated Financial Statements included in "Item
8. Financial Statements and Supplementary Data" for additional information
regarding the Company's adoption of SFAS 143 and SFAS 145.
Capital Commitments, Capital Resources and Liquidity
Capital commitments. The Company's primary needs for cash are for
exploration, development and acquisitions of oil and gas properties, repayment
of contractual obligations and working capital funding. Funding for exploration,
development and acquisitions of oil and gas properties and repayment of
contractual obligations may be provided by any combination of
internally-generated cash flow, proceeds from the disposition of non-strategic
assets or alternative financing sources as discussed in "Capital resources"
below. Funding for the Company's working capital obligations is provided by
internally-generated cash flows.
Oil and gas properties. The Company's cash expenditures for additions to
oil and gas properties during the years ended December 31, 2003, 2002 and 2001
totaled $688.1 million, $614.7 million and $529.7 million, respectively. The
Company's 2003 expenditures for additions to oil and gas properties were
internally funded by $763.7 million of net cash provided by operating
activities. The Company's 2002 expenditures for additions to oil and gas
properties were funded by $332.2 million of net cash provided by operating
activities, $118.9 million of proceeds from the disposition of assets and a
portion of the proceeds from the issuance of 11.5 million shares of the
Company's common stock during April 2002. The Company's 2001 expenditures were
internally funded by $475.6 million of net cash provided by operating activities
and a portion of the Company's $113.5 million of proceeds from disposition of
assets.
The Company strives to maintain its indebtedness at reasonable levels in
order to provide sufficient financial flexibility to take advantage of future
opportunities. The Company's capital budget for 2004 is expected to range from
$550 million to $600 million. The Company believes that net cash provided by
operating activities during 2004 will be sufficient to fund the 2004 capital
expenditures budget as well as reduce long-term debt by a minimum of $100
million and fund the recently approved plan to begin an annual dividend program
of $.20 per common share beginning in 2004. For additional information regarding
the Company's plans for 2004, see "2004 Outlook" above.
Contractual obligations, including off-balance sheet obligations. The
Company's contractual obligations include long-term debt, operating leases,
drilling commitments, derivative obligations and other liabilities. From time to
time, the Company enters into off-balance sheet arrangements and transactions
that can give rise to material off-balance sheet obligations of the Company. As
of December 31, 2003, the material off-balance sheet arrangements and
transactions that the Company has entered into include (i) $47.6 million of
undrawn letters of credit, (ii) operating lease agreements, (iii) drilling
commitments and (iv) contractual obligations for which the ultimate settlement
amounts are not fixed and determinable such as derivative contracts that are
37
sensitive to future changes in commodity prices and gas transportation
commitments. See "Item 7A. Quantitative and Qualitative Disclosures About Market
Risk" for a table of changes in the fair value of the Company's derivative
contract assets and liabilities during the year ended December 31, 2003 and Note
I of Notes to Consolidated Financial Statements included in "Item 8. Financial
Statements and Supplementary Data" for additional information regarding future
minimum lease payments and gas transportation commitments.
The following table summarizes by period the Company's payments due for
contractual obligations estimated as of December 31, 2003:
Payments Due by Year
-------------------------------------------------
2005 and 2007 and
2004 2006 2008 Thereafter
--------- --------- --------- ----------
(in thousands)
Long-term debt (a).................. $ - $ 135,239 $ 669,750 $ 750,472
Operating leases (b)................ 35,515 81,669 44,950 24,174
Drilling commitments (c)............ 13,601 6,902 602 -
Derivative obligations (d).......... 161,574 41,640 7,185 -
Other liabilities (e)............... 38,798 36,201 32,790 76,650
-------- -------- -------- --------
$ 249,488 $ 301,651 $ 755,277 $ 851,296
======== ======== ======== ========
- ------------
(a) See Note E of Notes to Consolidated Financial Statements included in "Item
8. Financial Statements and Supplementary Data".
(b) See Note I of Notes to Consolidated Financial Statements included in "Item
8. Financial Statements and Supplementary Data".
(c) Drilling commitments represent future minimum expenditure commitments under
contracts that the Company was a party to on December 31, 2003 for drilling
rig services and well commitments.
(d) Derivative obligations represent net liabilities for oil and gas commodity
derivatives that were valued as of December 31, 2003. These liabilities
include $8.8 million of current liabilities that are fixed in amount and
are not subject to continuing market risk. The ultimate settlement amounts
of the remaining portions of the Company's derivative obligations are
unknown because they are subject to continuing market risk. See "Item 7A.
Quantitative and Qualitative Disclosures About Market Risk" and Note J of
Notes to Consolidated Financial Statements included in "Item 8. Financial
Statements and Supplementary Data" for additional information regarding the
Company's derivative obligations.
(e) The Company's other liabilities represent current and noncurrent other
liabilities that are comprised of benefit obligations, litigation
contingencies, asset retirement obligations and other obligations for which
neither the ultimate settlement amounts nor their timings can be precisely
determined in advance. See Notes G, I and L of Notes to Consolidated
Financial Statements included in "Item 8. Financial Statements and
Supplementary Data" for additional information regarding the Company's
benefit obligations, litigation contingencies and asset retirement
obligations.
Capital resources. The Company's primary capital resources are net cash
provided by operating activities, proceeds from financing activities and
proceeds from sales of non-strategic assets. The Company expects that these
resources will be sufficient to fund its capital commitments in 2004.
Operating activities. Net cash provided by operating activities during the
years ended December 31, 2003, 2002 and 2001 were $763.7 million, $332.2 million
and $475.6 million, respectively. Net cash provided by operating activities in
2003 increased by $431.5 million, or 130 percent, as compared to that of 2002.
The increase in 2003 was primarily due to increased production volumes and
higher commodity prices as compared to 2002. Net cash provided by operating
activities in 2002 decreased by $143.4 million, or 30 percent, as compared to
that of 2001. The decrease in 2002 net cash provided by operating activities was
principally due to declines in commodity prices, offset partially by declines in
interest expense.
Investing activities. Net cash used in investing activities during the
years ended December 31, 2003, 2002 and 2001were $662.3 million, $508.1 million
and $422.7 million. The $154.2 million increase in cash used in investing
activities during 2003 as compared to 2002 was primarily due to a $73.4 million
increase in additions to oil and gas properties and an $83.2 million decrease in
proceeds from disposition of assets. The cash proceeds from asset divestitures
during 2003 were used to reduce outstanding indebtedness. The cash proceeds from
asset divestitures during 2002 and 2001 were used to fund a portion of the
Company's 2002 and 2001 capital expenditures and for general corporate
obligations. See "Results of Operations", above, and Note N of Notes to
Consolidated Financial Statements included in "Item 8. Financial Statements and
Supplementary Data" for additional information regarding asset divestitures.
38
Financing activities. Net cash used in financing activities totaled $91.7
million and $64.0 million during the years ended December 31, 2003 and 2001.
During the year ended December 31, 2002, financing activities provided $170.9
million of net cash. During 2003, financing activities were comprised of $105.5
million of net principle payments on long-term debt, $14.1 million of payments
of other noncurrent liabilities, $2.8 million of loan fees and $2.3 million of
treasury stock purchases, partially offset by $33.0 million of proceeds from the
exercise of long-term incentive plan stock options and employee stock purchases.
During 2002, the Company's financing activities were comprised of $236.0 million
of proceeds, net of issuance costs, from the sale of 11.5 million shares of the
Company's common stock; $48.0 million of net borrowings of long-term debt; and
$14.4 million of proceeds from the exercise of long-term incentive plan stock
options and employee stock purchases, partially offset by $124.2 million of
payments of other noncurrent liabilities and $3.3 million of debt issuance
costs. During 2001, the Company's financing activities were comprised of $5.1
million to repay long-term debt, $53.4 million to repay other noncurrent
liabilities and $13.0 million to purchase treasury stock, partially offset by
$7.5 million of net cash provided from the exercise of long-term incentive plan
stock options and employee stock purchases.
Over the three year period ended December 31, 2003, the Company has entered
into financing transactions with the intent of reducing its cost of capital and
increasing liquidity through the extension of debt maturities. See Notes E and J
of Notes to Consolidated Financial Statements included in "Item 8. Financial
Statements and Supplemental Data" and "Item 7A. Quantitative and Qualitative
Disclosures About Market Risk" for more information about the Company's debt
instruments and interest rate hedging activities.
The Company's future debt level is dependent primarily on net cash provided
by operating activities, proceeds from financing activities and proceeds
generated from asset dispositions. The Company believes it has substantial
borrowing capacity to meet any unanticipated cash requirements, and during low
commodity price periods, the Company has the flexibility to increase borrowings
and/or modify its capital spending to meet its contractual obligations and
maintain its debt ratings.
As the Company pursues its strategy, it may utilize various financing
sources, including fixed and floating rate debt, convertible securities,
preferred stock or common stock. The Company may also issue securities in
exchange for oil and gas properties, stock or other interests in other oil and
gas companies or related assets. Additional securities may be of a class
preferred to common stock with respect to such matters as dividends and
liquidation rights and may also have other rights and preferences as determined
by the Company's Board of Directors.
Liquidity. The Company's principal source of short-term liquidity is its
revolving credit facility. During December 2003, the Company entered into a new
five-year revolving credit agreement (the "New Credit Facility") that matures in
December 2008. The New Credit Facility replaced the Company's $575 million
revolving credit facility (the "Prior Credit Facility") that had a scheduled
maturity in March 2005. The terms of the New Credit Facility provide for initial
aggregate loan commitments of $700 million from a syndication of participating
banks (the "Lenders"). Aggregate loan commitments under the New Credit Facility
may be increased to a maximum aggregate amount of $1 billion if the Lenders
increase their loan commitments or loan commitments of new financial
institutions are added to the New Credit Facility. Outstanding borrowings under
the New Credit Facility totaled $160 million as of December 31, 2003. Including
$28.8 million of undrawn and outstanding letters of credit under the New Credit
Facility, the Company has $511.2 million of unused borrowing capacity as of
December 31, 2003.
Book capitalization and current ratio. The Company's book capitalization at
December 31, 2003 was $3.3 billion, consisting of debt of $1.6 billion and
stockholders' equity of $1.7 billion. The Company's debt to book capitalization
was 46.9 percent at December 31, 2003 as compared to 54.8 percent at December
31, 2002. The Company's ratio of current assets to current liabilities was .48
at December 31, 2003 and .54 at December 31, 2002. The decline in the Company's
ratio of current assets to current liabilities was primarily due to increases in
current hedge derivative obligations and trade payables. As more fully discussed
in "2004 Outlook" above, the Company has targeted a range for debt to book
capitalization of between 37 percent and 43 percent.
39
New Accounting Development
In its recent review of registrants' filings, the staff of the SEC has
taken the position that Statement of Financial Accounting Standards No. 142,
"Goodwill and Other Intangible Assets" ("SFAS 142"), requires oil and gas
entities to separately report on their balance sheets the costs of leasehold
mineral interests, including related accumulated depletion, as intangible assets
and provide related disclosures. The Company has historically included producing
leasehold costs in the proved properties caption on its balance sheet since the
value of the leases is inseparable from the value of the related oil and gas
reserves. This classification is consistent with the provisions of Statement of
Financial Accounting Standards No. 19, "Financial Accounting and Reporting by
Oil and Gas Producing Companies", and standard industry practice. Almost all
costs included in the unproved properties caption on the balance sheet are
leasehold mineral interests that are regularly evaluated for impairment based on
lease term and drilling activity. The SEC staff has referred the question of
SFAS 142 applicability for consideration by the Emerging Issues Task Force. If
the provisions of SFAS 142 are determined to be applicable to oil and gas
leasehold mineral interests, reclassifications within property, plant and
equipment on the Consolidated Balance Sheets and additional disclosures may be
required. As of December 31, 2003, the Company has not determined the amount of
such reclassifications, if applicable. The Company does not believe that the
provisions of SFAS 142, if determined to be applicable, will have a material
impact on its financial position, results of operations or liquidity.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The following quantitative and qualitative information is provided about
financial instruments to which the Company was a party as of December 31, 2003
and 2002, and from which the Company may incur future gains or losses from
changes in market interest rates, foreign exchange rates or commodity prices.
Although certain derivative contracts that the Company is a party to do not
qualify as hedges, the Company does not enter into derivative or other financial
instruments for trading purposes.
The fair value of the Company's derivative contracts are determined based
on counterparties' estimates and valuation models. The Company did not change
its valuation method during the year ended December 31, 2003. During 2003, the
Company was a party to forward foreign exchange contracts, commodity and
interest rate swap contracts and commodity collar contracts. See Note J of Notes
to Consolidated Financial Statements included in "Item 8. Financial Statements
and Supplementary Data" for additional information regarding the Company's
derivative contracts, including deferred gains and losses on terminated
derivative contracts. The following table reconciles the changes that occurred
in the fair values of the Company's open derivative contracts during 2003:
Derivative Contract Assets (Liabilities)
-------------------------------------------------
Foreign
Interest Exchange
Commodity Rate Rate Total
---------- --------- -------- ----------
(in thousands)
Fair value of contracts outstanding
as of December 31, 2002.............. $ (108,804) $ - $ 15 $(108,789)
Changes in contract fair values (a)...... (282,530) 21,497 3 (261,030)
Contract realizations:
Maturities........................... 136,425 (3,230) (18) 133,177
Termination - cash settlements....... 125 (18,267) - (18,142)
Termination - future net obligations. 53,362 - - 53,362
-------- -------- ----- --------
Fair value of contracts outstanding
as of December 31, 2003.............. $ (201,422) $ - $ - $(201,422)
========= ======== ===== ========
- ---------------
(a) At inception, new derivative contracts entered into by the Company have no
intrinsic value.
Quantitative Disclosures
Interest rate sensitivity. The following tables provide information about
other financial instruments that the Company was a party to as of December 31,
2003 and 2002 and that are or were sensitive to changes in interest rates. For
debt obligations, the tables present maturities by expected maturity dates, the
weighted average interest rates expected to be paid on the debt given current
40
contractual terms and market conditions and the debt's estimated fair value. For
fixed rate debt, the weighted average interest rate represents the contractual
fixed rates that the Company was obligated to periodically pay on the debt as of
December 31, 2003 and 2002. For variable rate debt, the average interest rate
represents the average rates being paid on the debt projected forward
proportionate to the forward yield curve for the six-month LIBOR.
Interest Rate Sensitivity
Debt Obligations as of December 31, 2003
Liability
Year Ended December 31, Fair Value at
---------------------------------------------------------------- December 31,
2004 2005 2006 2007 2008 Thereafter Total 2003
------- -------- -------- -------- -------- ---------- ----------- ------------
(in thousands, except interest rates)
Total Debt:
Fixed rate maturities...... $ - $135,239 $ - $155,253 $354,497 $ 750,472 $1,395,461 $(1,549,026)
Weighted average
interest rate (%)........ 7.93 7.86 7.83 7.81 8.34 8.37
Variable rate maturities... $ - $ - $ - $ - $160,000 $ - $ 160,000 $ (160,000)
Average interest rate (%).. 2.87 4.28 5.27 5.91 6.28 -
Interest Rate Sensitivity
Debt Obligations as of December 31, 2002
Liability
Year Ended December 31, Fair Value at
---------------------------------------------------------------- December 31,
2003 2004 2005 2006 2007 Thereafter Total 2002
------- -------- -------- -------- -------- ---------- ---------- -------------
(in thousands, except interest rates)
Total Debt:
Fixed rate maturities..... $ - $ - $146,704 $ - $161,130 $1,100,702 $1,408,536 $(1,484,009)
Weighted average
interest rate (%)....... 7.94 7.94 7.87 7.83 7.81 7.77
Variable rate maturities.. $ - $ - $260,000 $ - $ - $ - $ 260,000 $ (260,000)
Average interest rate (%). 2.89 4.08 5.27 - - -
Foreign exchange rate sensitivity. There were no outstanding foreign
exchange rate hedge derivatives at December 31, 2003. As of December 31, 2002,
the Company was a party to a foreign exchange rate derivative that matured
during January 2003 as an $18 thousand asset of the Company.
Commodity price sensitivity. The following tables provide information about
the Company's oil and gas derivative financial instruments that were sensitive
to changes in oil and gas prices as of December 31, 2003 and 2002. As of
December 31, 2003 and 2002, all of the Company's oil and gas derivative
financial instruments qualified as hedges.
Commodity hedge instruments. The Company hedges commodity price risk with
swap and collar contracts. Swap contracts provide a fixed price for a notional
amount of sales volumes. Collar contracts provide minimum ("floor") and maximum
("ceiling") prices for the Company on a notional amount of sales volumes,
thereby allowing some price participation if the relevant index price closes
above the floor price.
See Notes B, C and J of Notes to Consolidated Financial Statements included
in "Item 8. Financial Statements and Supplementary Data" for a description of
the accounting procedures followed by the Company relative to hedge derivative
financial instruments and for specific information regarding the terms of the
Company's derivative financial instruments that are sensitive to changes in oil
and gas prices.
41
Oil Price Sensitivity
Derivative Financial Instruments as of December 31, 2003
Liability
Year Ended December 31, Fair Value at
---------------------------------------------------- December 31,
2004 2005 2006 2007 2008 2003
-------- -------- -------- -------- -------- -------------
Oil Hedge Derivatives (a):
Average daily notional Bbl volumes:
Swap contracts........................ 18,973 17,000 5,000 1,000 5,000 $ (50,240)
Weighted average fixed price per Bbl.. $ 25.84 $ 24.93 $ 26.19 $ 26.00 $ 26.09
Average forward NYMEX oil prices (b).. $ 30.12 $ 28.03 $ 27.09 $ 26.55 $ 26.60
- ---------------
(a) See Note J of Notes to Consolidated Financial Statements included in "Item
8. Financial Statements and Supplementary Data" for hedge volumes and
weighted average prices per Bbl by calendar quarter.
(b) The average forward NYMEX oil prices per Bbl are based on January 30, 2004
market quotes.
Oil Price Sensitivity
Derivative Financial Instruments as of December 31, 2002
Liability
Year Ended December 31, Fair Value at
----------------------- December 31,
2003 2004 2002
---------- ---------- -------------
Oil Hedge Derivatives:
Average daily notional Bbl volumes:
Swap contracts.................................... 22,236 14,000 $ (19,912)
Weighted average fixed price per Bbl.............. $ 24.45 $ 23.11
Average forward NYMEX oil prices (a).............. $ 31.55 $ 25.75
- ---------------
(a) The average forward NYMEX oil prices are based on February 18, 2003 market
quotes.
Gas Price Sensitivity
Derivative Financial Instruments as of December 31, 2003
Liability
Year Ended December 31, Fair Value at
-------------------------------------- December 31,
2004 2005 2006 2007 2003
-------- ------- ------- ------- --------------
Gas Hedge Derivatives (a):
Average daily notional Mcf volumes (b):
Swap contracts (c)............................... 283,962 60,000 70,000 20,000 $ (151,182)
Weighted average fixed price per MMBtu........... $ 4.16 $ 4.24 $ 4.16 $ 3.51
Average forward NYMEX gas prices (d)............. $ 4.66 $ 5.04 $ 4.74 $ 4.60
- --------------
(a) To minimize basis risk, the Company enters into basis swaps for a portion
of its gas hedges to convert the index price of the hedging instrument from
a NYMEX index to an index which reflects the geographic area of production.
The Company considers these basis swaps as part of the associated swap and
collar contracts and, accordingly, the effects of the basis swaps have been
presented together with the associated contracts.
(b) See Note J of Notes to Consolidated Financial Statements included in "Item
8. Financial Statements and Supplementary Data" for hedge volumes and
weighted average prices per MMBtu by calendar quarter.
(c) During January 2004, the Company increased its 2004 gas hedge positions by
entering into 32,967 Mcf per day of first quarter 2004 gas swap contracts
with weighted average per MMBtu fixed prices of $7.11.
(d) The average forward NYMEX gas prices per MMBtu are based on January 30,
2004 market quotes.
42
Gas Price Sensitivity
Derivative Financial Instruments as of December 31, 2002
Year Ended December 31, Liability
---------------------------------------- Fair Value at
2006 & December 31,
2003 2004 2005 2007 2002
-------- -------- -------- ------- -------------
Gas Hedge Derivatives (a):
Average daily notional Mcf volumes:
Swap contracts................................... 230,000 180,000 10,000 20,000 $ (88,892)
Weighted average fixed price per MMBtu.......... $ 3.76 $ 3.81 $ 3.70 $ 3.75
Average forward NYMEX gas prices (b)............... $ 5.53 $ 4.80 $ 4.31 $ 4.12
- ---------------
(a) To minimize basis risk, the Company enters into basis swaps for a portion
of its gas hedges to convert the index price of the hedging instrument from
a NYMEX index to an index which reflects the geographic area of production.
The Company considers these basis swaps as part of the associated swap and
collar contracts and, accordingly, the effects of the basis swaps have been
presented together with the associated contracts.
(b) The average forward NYMEX gas prices per MMBtu are based on February 18,
2003 market quotes.
Qualitative Disclosures
Non-derivative financial instruments. The Company is a borrower under fixed
rate and variable rate debt instruments that give rise to interest rate risk.
The Company's objective in borrowing under fixed or variable rate debt is to
satisfy capital requirements while minimizing the Company's costs of capital.
See Note E of Notes to Consolidated Financial Statements included in "Item 8.
Financial Statements and Supplementary Data" for a discussion of the Company's
debt instruments.
Derivative financial instruments. The Company utilizes interest rate,
foreign exchange rate and commodity price derivative contracts to hedge interest
rate, foreign exchange rate and commodity price risks in accordance with
policies and guidelines approved by the Company's board of directors. In
accordance with those policies and guidelines, the Company's executive
management determines the appropriate timing and extent of hedge transactions.
As of December 31, 2003, the Company's primary risk exposures associated
with financial instruments to which it is a party include oil and gas price
volatility, volatility in the exchange rates of the Canadian dollar and
Argentine peso vis a vis the U.S. dollar and interest rate volatility. The
Company's primary risk exposures associated with financial instruments have not
changed significantly since December 31, 2003.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Index to Consolidated Financial Statements
Page
Consolidated Financial Statements of
Pioneer Natural Resources Company:
Independent Auditors' Report....................................... 44
Consolidated Balance Sheets as of December 31, 2003 and 2002....... 45
Consolidated Statements of Operations for the Years Ended
December 31, 2003, 2002 and 2001................................ 46
Consolidated Statements of Stockholders' Equity for the
Years Ended December 31, 2003, 2002 and 2001.................... 47
Consolidated Statements of Cash Flows for the Years Ended
December 31, 2003, 2002 and 2001................................ 48
Consolidated Statements of Comprehensive Income (Loss) for
the Years Ended December 31, 2003, 2002 and 2001................ 49
Notes to Consolidated Financial Statements......................... 50
Unaudited Supplementary Information................................ 88
43
INDEPENDENT AUDITORS' REPORT
The Board of Directors and Shareholders
Pioneer Natural Resources Company:
We have audited the accompanying consolidated balance sheets of Pioneer
Natural Resources Company (the "Company") as of December 31, 2003 and 2002, and
the related consolidated statements of operations, stockholders' equity, cash
flows and comprehensive income (loss) for each of the three years in the period
ended December 31, 2003. These financial statements are the responsibility of
the Company's management. Our responsibility is to express an opinion on these
financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally
accepted in the United States. Those standards require that we plan and perform
the audit to obtain reasonable assurance about whether the financial statements
are free of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements. An
audit also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis
for our opinion.
In our opinion, the consolidated financial statements referred to above
present fairly, in all material respects, the consolidated financial position of
the Company at December 31, 2003 and 2002, and the consolidated results of its
operations and its cash flows for each of the three years in the period ended
December 31, 2003, in conformity with accounting principles generally accepted
in the United States.
As discussed in Note B to the consolidated financial statements, in 2003
the Company adopted Statement of Financial Accounting Standards No. 143,
"Accounting for Asset Retirement Obligations". Also, as discussed in Note B to
the consolidated financial statements, in 2001 the Company adopted Statement of
Financial Accounting Standards No. 133, "Accounting for Derivative Instruments
and Hedging Activities".
Ernst & Young LLP
Dallas, Texas
January 26, 2004
44
PIONEER NATURAL RESOURCES COMPANY
CONSOLIDATED BALANCE SHEETS
(in thousands, except share data)
ASSETS
December 31,
-------------------------
2003 2002
----------- -----------
Current assets:
Cash and cash equivalents.......................................... $ 19,299 $ 8,490
Accounts receivable:
Trade, net of allowance for doubtful accounts of $4,727 and
$4,744 as of December 31, 2003 and 2002, respectively.......... 111,033 97,774
Due from affiliates.............................................. 447 448
Inventories........................................................ 17,509 10,648
Prepaid expenses................................................... 11,083 5,485
Deferred income taxes.............................................. 40,514 13,900
Other current assets:
Derivatives...................................................... 423 2,508
Other, net of allowance for doubtful accounts of $4,486
and $3,351 as of December 31, 2003 and 2002, respectively...... 4,807 7,840
---------- ----------
Total current assets........................................... 205,115 147,093
---------- ----------
Property, plant and equipment, at cost:
Oil and gas properties, using the successful efforts method
of accounting:
Proved properties................................................ 4,983,558 4,252,897
Unproved properties.............................................. 179,825 219,073
Accumulated depletion, depreciation and amortization............... (1,676,136) (1,303,541)
---------- ----------
Total property, plant and equipment............................ 3,487,247 3,168,429
---------- ----------
Deferred income taxes................................................ 192,344 76,840
Other property and equipment, net.................................... 28,080 22,784
Other assets:
Derivatives........................................................ 209 643
Other, net of allowance for doubtful accounts of $92 and
$1,227 as of December 31, 2003 and 2002, respectively............ 38,577 39,327
---------- ----------
$ 3,951,572 $ 3,455,116
========== ==========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable:
Trade............................................................ $ 177,614 $ 117,582
Due to affiliates................................................ 8,804 7,192
Interest payable................................................... 37,034 37,458
Income taxes payable............................................... 5,928 -
Other current liabilities:
Derivatives...................................................... 161,574 83,638
Other............................................................ 38,798 28,722
---------- ----------
Total current liabilities...................................... 429,752 274,592
---------- ----------
Long-term debt....................................................... 1,555,461 1,668,536
Derivatives.......................................................... 48,825 42,490
Deferred income taxes................................................ 12,121 8,760
Other liabilities.................................................... 145,641 85,841
Stockholders' equity:
Common stock, $.01 par value; 500,000,000 shares authorized;
119,665,784 and 119,592,344 shares issued at December 31,
2003 and 2002, respectively...................................... 1,197 1,196
Additional paid-in capital......................................... 2,734,403 2,714,567
Treasury stock, at cost; 378,012 and 2,339,806 shares at
December 31, 2003 and 2002, respectively......................... (5,385) (32,219)
Deferred compensation.............................................. (9,933) (14,292)
Accumulated deficit................................................ (887,848) (1,298,440)
Accumulated other comprehensive income (loss):
Net deferred hedge gains (losses), net of tax.................... (104,130) 9,555
Cumulative translation adjustment................................ 31,468 (5,470)
---------- ----------
Total stockholders' equity..................................... 1,759,772 1,374,897
---------- ----------
Commitments and contingencies
---------- ----------
$ 3,951,572 $ 3,455,116
========== ==========
The accompanying notes are an integral part of these consolidated
financial statements.
45
PIONEER NATURAL RESOURCES COMPANY
CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands, except per share data)
Year Ended December 31,
--------------------------------------
2003 2002 2001
---------- ---------- ----------
Revenues and other income:
Oil and gas................................................. $1,298,647 $ 701,780 $ 847,022
Interest and other.......................................... 12,292 11,222 21,778
Gain on disposition of assets, net.......................... 1,256 4,432 7,681
--------- --------- ---------
1,312,195 717,434 876,481
--------- --------- ---------
Costs and expenses:
Oil and gas production...................................... 279,526 199,570 209,664
Depletion, depreciation and amortization.................... 390,840 216,375 222,632
Exploration and abandonments................................ 132,760 85,894 127,906
General and administrative.................................. 60,545 48,402 36,968
Accretion of discount on asset retirement obligations....... 5,040 - -
Interest.................................................... 91,388 95,815 131,958
Other....................................................... 21,320 39,602 43,341
--------- --------- ---------
981,419 685,658 772,469
--------- --------- ---------
Income before income taxes and cumulative effect of
change in accounting principle.............................. 330,776 31,776 104,012
Income tax benefit (provision)................................ 64,403 (5,063) (4,016)
--------- --------- ---------
Income before cumulative effect of change in
accounting principle........................................ 395,179 26,713 99,996
Cumulative effect of change in accounting principle,
net of tax.................................................. 15,413 - -
--------- --------- ---------
Net income.................................................... $ 410,592 $ 26,713 $ 99,996
========= ========= =========
Net income per share:
Basic:
Income before cumulative effect of change in
accounting principle................................... $ 3.37 $ .24 $ 1.01
Cumulative effect of change in accounting principle,
net of tax............................................. .13 - -
--------- --------- ---------
Net income............................................... $ 3.50 $ .24 $ 1.01
========= ========= =========
Diluted:
Income before cumulative effect of change in accounting
principle.............................................. $ 3.33 $ .23 $ 1.00
Cumulative effect of change in accounting principle,
net of tax............................................. .13 - -
--------- --------- ---------
Net income............................................... $ 3.46 $ .23 $ 1.00
========= ========= =========
Weighted average shares outstanding:
Basic.................................................... 117,185 112,542 98,529
========= ========= =========
Diluted.................................................. 118,513 114,288 99,714
========= ========= =========
The accompanying notes are an integral part of these consolidated
financial statements.
46
PIONEER NATURAL RESOURCES COMPANY
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
(in thousands)
Accumulated Other
Comprehensive Income (Loss)
------------------------------
Net
Deferred
Hedge
Gains Invest- Cumulative Total
Additional Deferred (Losses) ment Trans- Stock-
Common Paid-in Treasury Compen- Accumulated Net Gains & lation holders'
Stock Capital Stock sation Deficit of tax Losses Adjustment Equity
------- ---------- -------- --------- ----------- -------- -------- ---------- ----------
Balance at January 1, 2001........ $ 1,013 $2,352,608 $(37,682) $ - $(1,422,703) $ - $ 8,154 $ 3,515 $ 904,905
Common stock issued for
partnership acquisitions........ 57 104,236 - - - - - - 104,293
Stock options exercised and
employee stock purchases........ 4 5,428 2,708 - (636) - - - 7,504
Purchase of treasury stock........ - - (13,028) - - - - - (13,028)
Net income........................ - - - - 99,996 - - - 99,996
Other comprehensive income (loss):
Net deferred hedge gains (losses):
Transition adjustment......... - - - - - (197,444) - - (197,444)
Net deferred hedge gains...... - - - - - 395,297 - - 395,297
Tax provisions related to
deferred hedge gains......... - - - - - (2,293) - - (2,293)
Net hedge losses included in
net income................... - - - - - 5,486 - - 5,486
Net unrealized gains (losses)
on available for sale securities:
Net unrealized available for sale
securities holding losses.... - - - - - - (45) - (45)
Net available for sale securities
gains included in net income. - - - - - - (8,109) - (8,109)
Translation adjustment.......... - - - - - - - (11,173) (11,173)
------ -------- ------- ------ ---------- -------- ------- ------- ---------
Balance at December 31, 2001...... 1,074 2,462,272 (48,002) - (1,323,343) 201,046 - (7,658) 1,285,389
------ --------- ------- ------ ---------- -------- ------- ------- ---------
Issuance of common stock.......... 115 235,885 - - - - - - 236,000
Adjustment to common stock issued
for 2001 partnership
acquisitions.................... - (175) - - - - - - (175)
Stock options exercised and
employee stock purchases........ - 416 15,783 - (1,810) - - - 14,389
Deferred compensation:
Compensation deferred........... 7 16,169 - (16,176) - - - - -
Deferred compensation included
in net income.................. - - - 1,884 - - - - 1,884
Net income........................ - - - - 26,713 - - - 26,713
Other comprehensive income (loss):
Net deferred hedge gains (losses):
Net deferred hedge losses..... - - - - - (181,628) - - (181,628)
Tax benefits related to
deferred hedge losses........ - - - - - 2,561 - - 2,561
Net hedge gains included
in net income................ - - - - - (12,424) - - (12,424)
Translation adjustment.......... - - - - - - - 2,188 2,188
------ --------- ------- ------- ---------- -------- ------- ------- ---------
Balance at December 31, 2002...... 1,196 2,714,567 (32,219) (14,292) (1,298,440) 9,555 - (5,470) 1,374,897
------ --------- ------- ------- ---------- -------- ------- ------- ---------
Stock options exercised and
employee stock purchases......... 1 4,100 29,183 - - - - - 33,284
Purchase of treasury stock........ - - (2,349) - - - - - (2,349)
Tax benefits related to
stock-based compensation......... - 14,666 - - - - - - 14,666
Deferred compensation:
Compensation deferred........... - 1,070 - (1,070) - - - - -
Deferred compensation included
in net income.................. - - - 5,429 - - - - 5,429
Net income........................ - - - - 410,592 - - - 410,592
Other comprehensive income (loss):
Net deferred hedge gains (losses),
net of tax:
Net deferred hedge losses..... - - - - - (282,165) - - (282,165)
Tax benefits related to net
deferred hedge losses........ - - - - - 51,064 - - 51,064
Net hedge losses included in
net income................... - - - - - 117,416 - - 117,416
Translation adjustment.......... - - - - - - - 36,938 36,938
------ --------- ------- ------- --------- -------- ------ ------- ---------
Balance at December 31, 2003...... $ 1,197 $2,734,403 $ (5,385) $ (9,933) $ (887,848) $(104,130) $ - $ 31,468 $1,759,772
====== ========= ======= ======= ========== ======== ====== ======= =========
The accompanying notes are an integral part of these
consolidated financial statements.
47
PIONEER NATURAL RESOURCES COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
Year Ended December 31,
--------------------------------------
2003 2002 2001
---------- ---------- ----------
Cash flows from operating activities:
Net income..................................................... $ 410,592 $ 26,713 $ 99,996
Adjustments to reconcile net income to net cash
provided by operating activities:
Depletion, depreciation and amortization.................. 390,840 216,375 222,632
Exploration expenses, including dry holes................. 97,690 64,617 103,595
Deferred income taxes..................................... (75,588) 2,788 (7,649)
Gain on disposition of assets, net........................ (1,256) (4,432) (7,681)
Accretion of discount on asset retirement obligations..... 5,040 - -
Interest related amortization............................. (20,610) (5,809) 8,689
Commodity hedge related amortization...................... (71,816) 26,490 6,199
Cumulative effect of change in accounting principle,
net of tax............................................. (15,413) - -
Other noncash items....................................... 10,395 31,647 18,697
Change in operating assets and liabilities, net of effects
from acquisitions:
Accounts receivable, net.................................. (10,983) (23,922) 41,295
Inventories............................................... (7,734) 3,023 (4,256)
Prepaid expenses.......................................... (5,598) 2,330 (4,328)
Other current assets, net................................. (602) (4,166) (1,976)
Accounts payable.......................................... 58,603 (342) (541)
Interest payable.......................................... (424) 48 (733)
Income taxes payable...................................... 5,928 (530) 530
Other current liabilities................................. (5,385) (2,585) 1,131
--------- --------- ---------
Net cash provided by operating activities................. 763,679 332,245 475,600
--------- --------- ---------
Cash flows from investing activities:
Cash acquired in acquisitions, net of fees paid................ - - 11,119
Proceeds from disposition of assets............................ 35,698 118,850 113,453
Additions to oil and gas properties............................ (688,133) (614,698) (529,723)
Other property additions, net.................................. (9,865) (12,283) (17,590)
--------- --------- ---------
Net cash used in investing activities..................... (662,300) (508,131) (422,741)
--------- --------- ---------
Cash flows from financing activities:
Borrowings under long-term debt................................ 264,725 529,805 328,331
Principal payments on long-term debt........................... (370,262) (481,783) (333,410)
Common stock issuance proceeds, net of issuance costs.......... - 236,000 -
Payment of other liabilities................................... (14,055) (124,245) (53,437)
Stock options exercised and employee stock purchases........... 33,020 14,389 7,504
Purchase of treasury stock..................................... (2,349) - (13,028)
Deferred loan fees/debt issuance costs......................... (2,799) (3,293) -
--------- --------- ---------
Net cash provided by (used in) financing activities....... (91,720) 170,873 (64,040)
--------- --------- ---------
Net increase (decrease) in cash and cash equivalents ............ 9,659 (5,013) (11,181)
Effect of exchange rate changes on cash and cash equivalents..... 1,150 (831) (644)
Cash and cash equivalents, beginning of year..................... 8,490 14,334 26,159
--------- --------- ---------
Cash and cash equivalents, end of year........................... $ 19,299 $ 8,490 $ 14,334
========= ========= =========
The accompanying notes are an integral part of these consolidated
financial statements.
48
PIONEER NATURAL RESOURCES COMPANY
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(in thousands)
Year ended December 31,
--------------------------------------
2003 2002 2001
---------- ---------- ----------
Net income...................................................... $ 410,592 $ 26,713 $ 99,996
Other comprehensive income (loss):
Net deferred hedge gains (losses), net of tax:
Transition adjustment...................................... - - (197,444)
Net deferred hedge gains (losses).......................... (282,165) (181,628) 395,297
Tax benefits (provisions) related to net deferred
hedge (gains) losses..................................... 51,064 2,561 (2,293)
Net hedge (gains) losses included in net income............ 117,416 (12,424) 5,486
Net unrealized gains (losses) on available for sale
securities:
Net unrealized available for sale securities
holding losses........................................... - - (45)
Net available for sale securities gains included
in net income............................................ - - (8,109)
Translation adjustment........................................ 36,938 2,188 (11,173)
--------- --------- ----------
Other comprehensive income (loss)....................... (76,747) (189,303) 181,719
--------- --------- ---------
Comprehensive income (loss)..................................... $ 333,845 $ (162,590) $ 281,715
========= ========= =========
The accompanying notes are an integral part of these consolidated
financial statements.
49
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2003, 2002 and 2001
NOTE A. Organization and Nature of Operations
Pioneer Natural Resources Company (the "Company" or "Pioneer") is a
Delaware corporation whose common stock is listed and traded on the New York
Stock Exchange. The Company is an oil and gas exploration and production company
with ownership interests in oil and gas properties located in the United States,
Argentina, Canada, South Africa, Gabon and Tunisia.
NOTE B. Summary of Significant Accounting Policies
Principles of consolidation. The consolidated financial statements include
the accounts of the Company and its wholly-owned subsidiaries since their
acquisition or formation, and the Company's interest in the affiliated oil and
gas partnerships for which it serves as general partner through certain of its
wholly-owned subsidiaries. The Company proportionately consolidates less than
100 percent-owned oil and gas partnerships in accordance with industry practice.
The Company owns less than a 20 percent interest in the oil and gas partnerships
that it proportionately consolidates. All material intercompany balances and
transactions have been eliminated.
Investments in unaffiliated equity securities that have a readily
determinable fair value are classified as "trading securities" if management's
current intent is to hold them for only a short period of time; otherwise, they
are accounted for as "available-for-sale" securities. The Company reevaluates
the classification of investments in unaffiliated equity securities at each
balance sheet date. The carrying value of trading securities and
available-for-sale securities are adjusted to fair value as of each balance
sheet date.
Unrealized holding gains are recognized for trading securities in interest
and other revenue, and unrealized holding losses are recognized in other expense
during the periods in which changes in fair value occur.
Unrealized holding gains and losses are recognized for available-for-sale
securities as credits or charges to stockholders' equity and other comprehensive
income (loss) during the periods in which changes in fair value occur. Realized
gains and losses on the divestiture of available-for-sale securities are
determined using the average cost method. The Company had no investments in
available-for-sale securities as of December 31, 2003 or 2002.
Investments in unaffiliated equity securities that do not have a readily
determinable fair value are measured at the lower of their original cost or the
net realizable value of the investment. The Company had no significant equity
security investments that did not have a readily determinable fair value as of
December 31, 2003 or 2002.
Use of estimates in the preparation of financial statements. Preparation of
the accompanying consolidated financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities, the
disclosure of contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenues and expenses during the
reporting periods. Depletion of oil and gas properties is determined using
estimates of proved oil and gas reserves. There are numerous uncertainties
inherent in the estimation of quantities of proved reserves and in the
projection of future rates of production and the timing of development
expenditures. Similarly, evaluations for impairment of proved and unproved oil
and gas properties are subject to numerous uncertainties including, among
others, estimates of future recoverable reserves; commodity price outlooks;
foreign laws, restrictions and currency exchange rates; and export and excise
taxes.
Argentina devaluation. Early in January 2002, the Argentine government
severed the direct one-to-one U.S. dollar to Argentine peso relationship that
had existed for many years. As of December 31, 2003 and 2002, the Company used
exchange rates of 2.93 pesos to $1 and 3.37 pesos to $1, respectively, to
remeasure the peso-denominated monetary assets and liabilities of the Company's
50
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2003, 2002 and 2001
Argentine subsidiaries. The remeasurement of the peso-denominated monetary net
assets of the Company's Argentine subsidiaries as of December 31, 2003 and 2002
resulted in a charge of $.3 million and $6.9 million, respectively.
As a result of certain Argentine stability laws and regulations enacted
since the devaluation of the Argentine peso which impact the price the Company
receives for the oil and gas it produces, the Company has continually reviewed
its Argentine proved and unproved properties for impairment during 2003 and
2002. Based on estimates of future commodity prices and operating costs, the
Company believes that the future cash flows from its oil and gas assets will be
sufficient to fully recover its proved property basis. The Company also plans to
continue its exploration efforts on all of its remaining unproved acreage. Based
upon the Company's improved economic outlook for Argentina, the Company has
significantly increased its capital budget for exploration and development
activities in 2004 as compared to the capital budgets in 2003 and 2002.
While the Argentine economic and political situation continues to improve,
the Argentine government may enact future regulations or policies that, when
finalized and adopted, may materially impact, among other items, (i) the
realized prices the Company receives for the commodities it produces and sells;
(ii) the timing of repatriations of excess cash flow to the Company's corporate
headquarters in the United States; (iii) the Company's asset valuations; (iv)
the Company's level of future investments in Argentina; and (v) peso-denominated
monetary assets and liabilities. While conditions are improving, numerous
uncertainties exist surrounding the ultimate resolution of Argentina's economic
and political stability and actual results could differ from those estimates and
assumptions utilized.
New accounting pronouncements. On January 1, 2003, the Company adopted the
provisions of Statement of Financial Accounting Standards No. 143, "Accounting
for Asset Retirement Obligations" ("SFAS 143"). SFAS 143 amended Statement of
Financial Accounting Standards No. 19, "Financial Accounting and Reporting by
Oil and Gas Producing Companies" ("SFAS 19") to require that the fair value of a
liability for an asset retirement obligation be recognized in the period in
which it is incurred if a reasonable estimate of fair value can be made. Under
the provisions of SFAS 143, asset retirement obligations were capitalized as
part of the carrying value of the long-lived asset. Under the provisions of SFAS
19, asset retirement obligations are recognized using a cost-accumulation
approach. Prior to the adoption of SFAS 143, the Company recorded asset
retirement obligations through the unit-of-production method, except for such
asset retirement obligations that were assumed in business combinations, which
were recorded at their estimated fair values.
The adoption of SFAS 143 resulted in a January 1, 2003 cumulative effect
adjustment to record (i) a $13.8 million increase in the carrying values of
proved properties, (ii) a $26.3 million decrease in accumulated depreciation,
depletion, and amortization of property, plant and equipment, (iii) a $1.0
million increase in current abandonment liabilities, (iv) a $22.4 million
increase in noncurrent abandonment liabilities and (v) a $1.3 million increase
in Argentine deferred income tax liabilities. The net impact of items (i)
through (v) was to record a gain of $15.4 million, net of tax, as a cumulative
effect adjustment of a change in accounting principle in the Company's
Consolidated Statements of Operations upon adoption on January 1, 2003.
The following pro forma data summarizes the Company's net income and net
income per share for the years ended December 31, 2003, 2002 and 2001 as if the
Company had adopted the provisions of SFAS 143 on January 1, 2001, including
aggregate pro forma asset retirement obligations on that date of $60.2 million:
51
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2003, 2002 and 2001
Year ended December 31,
----------------------------------------
2003 2002 2001
--------- --------- ---------
(in thousands, except per share amounts)
Net income, as reported........................ $ 410,592 $ 26,713 $ 99,996
Pro forma adjustments to reflect retroactive
adoption of SFAS 143........................ (15,413) 4,743 1,672
-------- -------- --------
Pro forma net income........................... $ 395,179 $ 31,456 $ 101,668
======== ======== ========
Net income per share:
Basic - as reported......................... $ 3.50 $ .24 $ 1.01
======== ======== ========
Basic - pro forma........................... $ 3.37 $ .28 $ 1.03
======== ======== ========
Diluted - as reported....................... $ 3.46 $ .23 $ 1.00
======== ======== ========
Diluted - pro forma......................... $ 3.33 $ .28 $ 1.02
======== ======== ========
On January 1, 2003, the Company adopted the provisions of Statement of
Financial Accounting Standards No. 145, "Rescission of FASB Statements No. 4, 44
and 64, Amendment of FASB Statement No. 13 and Technical Corrections" ("SFAS
145"). Prior to SFAS 145, gains or losses on the early extinguishment of debt
were required to be classified in a company's periodic consolidated statements
of operations as extraordinary gains or losses, net of associated income taxes,
after the determination of income or loss from continuing operations. SFAS 145
requires, except in the case of events or transactions of a highly unusual and
infrequent nature, that gains or losses from the early extinguishment of debt be
classified, on both a prospective and retrospective basis, as components of a
company's income or loss from continuing operations. The adoption of the
provisions of SFAS 145 did not affect the Company's financial position or
liquidity. Under the provisions of SFAS 145, gains or losses from the early
extinguishment of debt will be recognized in the Company's Consolidated
Statements of Operations as components of other income or other expense and will
be included in the determination of the income (loss) from continuing operations
of those periods. Accordingly, extraordinary losses from the early
extinguishment of debt of $22.3 million and $3.8 million recorded during the
years ended December 31, 2002 and 2001, respectively, have been reclassified to
other expense.
During January 2003, the Financial Accounting Standards Board issued
Interpretation No. 46, "Consolidation of Variable Interest Entities" ("FIN 46"),
which requires the consolidation of certain entities that are determined to be
variable interest entities ("VIE's"). An entity is considered to be a VIE when
either (i) the entity lacks sufficient equity to carry on its principal
operations, (ii) the equity owners of the entity cannot make decisions about the
entity's activities or (iii) the entity's equity neither absorbs losses or
benefits from gains.
The Company has reviewed its financial arrangements and has not identified
any material VIEs that should be consolidated by the Company in accordance with
FIN 46.
Cash equivalents. Cash and cash equivalents include cash on hand and
depository accounts held by banks.
Inventories - equipment. Lease and well equipment to be used in future
production and drilling activities are carried at the lower of cost or market,
on a first-in, first-out basis. The Company has established lower of cost or
market allowances to reduce the carrying values of its equipment inventories in
the amounts of $.6 million and $3.6 million as of December 31, 2003 and 2002,
respectively.
Inventories - commodities. Commodities are carried at the lower of average
cost or market. When sold from inventory, commodities are removed on a first-in,
first-out basis.
Oil and gas properties. The Company utilizes the successful efforts method
of accounting for its oil and gas properties. Under this method, all costs
associated with productive wells and nonproductive development wells are
52
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2003, 2002 and 2001
capitalized while nonproductive exploration costs and geological and geophysical
expenditures are expensed. The Company also expenses the costs associated with
exploratory wells that find oil and gas reserves if a determination that proved
reserves have been found cannot be made within one year of the exploration well
being drilled unless other drilling or exploration activities to evaluate the
discovery are firmly planned. The Company capitalizes interest on expenditures
for significant development projects until such projects are ready for their
intended use.
The Company owns interests in 11 natural gas processing plants and five
treating facilities. The Company operates seven of the plants and all five
treating facilities. The Company's ownership in the natural gas processing
plants and treating facilities is primarily to accommodate handling the
Company's gas production and thus are considered a component of the capital and
operating costs of the respective fields that they service. To the extent that
there is excess capacity at a plant or treating facility, the Company attempts
to process third party gas volumes for a fee to keep the plant or treating
facility at capacity. All revenues and expenses derived from third party gas
volumes processed through the plants and treating facilities are reported as
components of oil and gas production costs. The third party revenues generated
from the plant and treating facilities for the three years ended December 31,
2003, 2002 and 2001 were $39.5 million, $28.4 million and $32.7 million,
respectively. The third party expenses attributable to the plants and treating
facilities for the same respective periods were $11.3 million, $9.3 million and
$9.7 million. The capitalized costs of the plants and treating facilities are
included in proved oil and gas properties and are depleted using the
unit-of-production method along with the other capitalized costs of the field
that they service.
Capitalized costs relating to proved properties are depleted using the
unit-of-production method based on proved reserves. Costs of significant
nonproducing properties, wells in the process of being drilled and development
projects are excluded from depletion until such time as the related project is
completed and proved reserves are established or, if unsuccessful, impairment is
determined.
Capitalized costs of individual properties sold or abandoned are charged to
accumulated depletion, depreciation and amortization with the proceeds from the
sales of individual properties credited to property costs. No gain or loss is
recognized until the entire amortization base is sold. However, gain or loss is
recognized from the sale of less than an entire amortization base if the
disposition is significant enough to materially impact the depletion rate of the
remaining properties in the amortization base.
The Company reviews its long-lived assets to be held and used, including
proved oil and gas properties accounted for under the successful efforts method
of accounting, whenever events or circumstances indicate that the carrying value
of those assets may not be recoverable. An impairment loss is indicated if the
sum of the expected future cash flows is less than the carrying amount of the
assets. In this circumstance, the Company recognizes an impairment loss for the
amount by which the carrying amount of the asset exceeds the estimated fair
value of the asset.
Unproved oil and gas properties that are individually significant are
periodically assessed for impairment by comparing their cost to their estimated
value on a project-by-project basis. The estimated value is affected by the
results of exploration activities, commodity price outlooks, planned future
sales or expiration of all or a portion of such projects. If the quantity of
potential reserves determined by such evaluations is not sufficient to fully
recover the cost invested in each project, the Company will recognize an
impairment loss at that time by recording an allowance. The remaining unproved
oil and gas properties, if any, are aggregated and an overall impairment
allowance is provided based on the Company's historical experience.
Treasury stock. Treasury stock purchases are recorded at cost. Upon
reissuance, the cost of treasury shares held is reduced by the average purchase
price per share of the aggregate treasury shares held.
Environmental. The Company's environmental expenditures are expensed or
capitalized depending on their future economic benefit. Expenditures that relate
to an existing condition caused by past operations and that have no future
53
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2003, 2002 and 2001
economic benefits are expensed. Expenditures that extend the life of the related
property or mitigate or prevent future environmental contamination are
capitalized. Liabilities are recorded when environmental assessment and/or
remediation is probable and the costs can be reasonably estimated. Such
liabilities are undiscounted unless the timing of cash payments for the
liability are fixed or reliably determinable.
Revenue recognition. The Company uses the entitlements method of accounting
for oil, NGL and gas revenues. Sales proceeds in excess of the Company's
entitlement are included in other liabilities and the Company's share of sales
taken by others is included in other assets in the accompanying Consolidated
Balance Sheets. The following table presents the Company's entitlement assets
and entitlement liabilities and their associated volumes as of December 31, 2003
and 2002 ($ in millions):
December 31,
------------------------------------
2003 2002
---------------- ----------------
Amount MMcf Amount MMcf
------ ------ ------ ------
Entitlement assets...................... $ 10.5 3,929 $ 9.7 4,240
Entitlement liabilities................. $ 15.8 14,793 $ 15.1 14,302
Derivatives and hedging. In June 1998, the Financial Accounting Standards
Board issued Statement of Financial Accounting Standards No. 133, "Accounting
for Derivative Instruments and Hedging Activities" ("SFAS 133") as amended, the
provisions of which the Company adopted effective January 1, 2001.
SFAS 133 requires the accounting recognition of all derivative instruments
as either assets or liabilities at fair value. Derivative instruments that are
not hedges must be adjusted to fair value through net income (loss). Under the
provisions of SFAS 133, changes in the fair value of derivative instruments that
are fair value hedges are offset against changes in the fair value of the hedged
assets, liabilities, or firm commitments through net income (loss). Effective
changes in the fair value of derivative instruments that are cash flow hedges
are recognized in "accumulated other comprehensive income (loss) ("AOCI") - net
deferred hedge gains (losses), net of tax" in the stockholders' equity section
of the Company's Consolidated Balance Sheets until such time as the hedged items
are recognized in net income (loss). Ineffective portions of a derivative
instrument's change in fair value are immediately recognized in net income
(loss).
The adoption of SFAS 133 resulted in a January 1, 2001 transition
adjustment to (i) reclassify $57.8 million of deferred losses on terminated
hedge positions from other assets (including $11.6 million of other current
assets), (ii) increase other current assets, other assets and other current
liabilities by $7.0 million, $6.2 million and $146.6 million, respectively, to
record the fair value of open hedge derivatives, (iii) increase the carrying
value of hedged long-term debt by $6.2 million and (iv) reduce stockholders'
equity by $197.4 million for the net impact of items (i) through (iii) above.
The $197.4 million reduction in stockholders' equity was reflected as a
transition adjustment in other comprehensive income (loss) on January 1, 2001.
Under the provisions of SFAS 133, the Company may designate a derivative
instrument as hedging the exposure to changes in the fair value of an asset or a
liability or an identified portion thereof that is attributable to a particular
risk (a "fair value hedge") or as hedging the exposure to variability in
expected future cash flows that are attributable to a particular risk (a "cash
flow hedge"). Both at the inception of a hedge and on an ongoing basis, a fair
value hedge must be expected to be highly effective in achieving offsetting
changes in fair value attributable to the hedged risk during the periods that a
hedge is designated. Similarly, a cash flow hedge must be expected to be highly
effective in achieving offsetting cash flows attributable to the hedged risk
during the term of the hedge. The expectation of hedge effectiveness must be
supported by matching the essential terms of the hedged asset, liability or
forecasted transaction to the derivative hedge contract or by effectiveness
assessments using statistical measurements. The Company's policy is to assess
actual hedge effectiveness at the end of each calendar quarter.
54
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2003, 2002 and 2001
See Note J for a description of the specific types of derivative
transactions in which the Company participates.
Stock-based compensation. The Company has a long-term incentive plan (the
"Long-Term Incentive Plan") under which the Company grants stock-based
compensation. The Long-Term Incentive Plan is described more fully in Note G.
The Company accounts for stock-based compensation granted under the Long-Term
Incentive Plan using the intrinsic value method prescribed by Accounting
Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees"
("APB 25") and related interpretations. Stock-based compensation expenses
associated with option grants were not recognized in the Company's net income
during the years ended December 31, 2003, 2002 and 2001, as all options granted
under the Long-Term Incentive Plan had exercise prices equal to the market value
of the underlying common stock on the dates of grant. Stock-based compensation
expense associated with restricted stock awards is deferred and amortized to
earnings ratably over the vesting periods of the awards. The following table
illustrates the pro forma effect on net income and earnings per share as if the
Company had applied the fair value recognition provisions of Statement of
Financial Accounting Standards No. 123, "Accounting for Stock-Based
Compensation" to stock-based compensation during the years ended December 31,
2003, 2002 and 2001:
Year ended December 31,
-------------------------------------
2003 2002 2001
--------- --------- ---------
(in thousands, except per share amounts)
Net income, as reported................................... $ 410,592 $ 26,713 $ 99,996
Plus: Total stock-based employee compensation expense
included in net income for all awards, net of tax (a)... 3,447 1,884 -
Deduct: Total stock-based employee compensation
expense determined under fair value based
method for all awards, net of tax (a)................... (11,429) (11,691) (6,533)
-------- -------- --------
Pro forma net income...................................... $ 402,610 $ 16,906 $ 93,463
======== ======== ========
Net income per share:
Basic - as reported..................................... $ 3.50 $ .24 $ 1.01
======== ======== ========
Basic - pro forma....................................... $ 3.44 $ .15 $ .95
======== ======== ========
Diluted - as reported................................... $ 3.46 $ .23 $ 1.00
======== ======== ========
Diluted - pro forma..................................... $ 3.40 $ .15 $ .94
======== ======== ========
- -----------
(a) Total stock-based employee compensation expense included in net income is
net of a tax benefit of $2.0 million during the year ended December 31,
2003. Total stock-based employee compensation expense determined under the
fair value based method for the year ended December 31, 2003 is net of a
$4.6 million tax benefit. No tax benefits were recognized for the pro forma
compensation expense amounts during the years ended December 31, 2002 or
2001. See Note P for additional information regarding the Company's income
taxes.
Foreign currency translation. The U.S. dollar is the functional currency
for all of the Company's international operations except Canada. Accordingly,
monetary assets and liabilities denominated in a foreign currency are remeasured
to U.S. dollars at the exchange rate in effect at the end of each reporting
period; revenues and costs and expenses denominated in a foreign currency are
remeasured at the average of the exchange rates that were in effect during the
period in which the revenues and costs and expenses were recognized. The
resulting gains or losses from remeasuring foreign currency denominated balances
into U.S. dollars are recorded in other income or other expense, respectively.
Nonmonetary assets and liabilities denominated in a foreign currency are
remeasured at the historic exchange rates that were in effect when the assets or
liabilities were acquired or incurred.
55
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2003, 2002 and 2001
The functional currency of the Company's Canadian operations is the
Canadian dollar. The financial statements of the Company's Canadian subsidiary
entities are translated to U.S. dollars as follows: all assets and liabilities
are translated using the exchange rate in effect at the end of each reporting
period; revenues and costs and expenses are translated using the average of the
exchange rates that were in effect during the period in which the revenues and
costs and expenses were recognized. The resulting gains or losses from
translating non-U.S. dollar denominated balances are recorded in the
accompanying Consolidated Statements of Stockholders' Equity for the period
through accumulated other comprehensive income (loss).
The following table presents the exchange rates used to translate the
financial statements of the Company's Canadian subsidiary in the preparation of
the consolidated financial statements as of and for the years ended December 31,
2003, 2002 and 2001:
December 31,
---------------------------
2003 2002 2001
------- ------- -------
U.S. Dollar from Canadian Dollar - Balance Sheets................ .7710 .6362 .6277
U.S. Dollar from Canadian Dollar - Statements of Operations...... .7161 .6371 .6356
Reclassifications. Certain reclassifications have been made to the 2002 and
2001 amounts in order to conform with the 2003 presentation.
NOTE C. Disclosures About Fair Value of Financial Instruments
The following table presents the carrying amounts and estimated fair values
of the Company's financial instruments as of December 31, 2003 and 2002:
2003 2002
----------------------- -----------------------
Carrying Fair Carrying Fair
Value Value Value Value
---------- ---------- ---------- ----------
(in thousands)
Derivative contract assets (liabilities):
Commodity price hedges............................ $ (201,422) $ (201,422) $ (108,837) $ (108,837)
Unrealized terminated commodity price hedges...... $ (1,490) $ (1,490) $ 512 $ 512
Btu swap contracts................................ $ (6,856) $ (6,856) $ (13,363) $ (13,363)
Foreign currency contracts........................ $ - $ - $ 15 $ 15
Financial assets:
Trading securities................................ $ 7,596 $ 7,596 $ 5,144 $ 5,144
5-1/2% note receivable due 2008................... $ 2,086 $ 2,086 $ 2,247 $ 2,283
Financial liabilities - long-term debt:
Line of credit.................................... $ (160,000) $ (160,000) $ (260,000) $ (260,000)
8-7/8% senior notes due 2005...................... $ (135,239) $ (141,426) $ (146,704) $ (147,318)
8-1/4% senior notes due 2007...................... $ (155,253) $ (171,188) $ (161,130) $ (164,925)
6-1/2% senior notes due 2008...................... $ (354,497) $ (378,725) $ (362,592) $ (359,205)
9-5/8% senior notes due 2010...................... $ (350,558) $ (424,385) $ (338,197) $ (406,901)
7-1/2% senior notes due 2012...................... $ (150,000) $ (162,990) $ (150,000) $ (160,635)
7-1/5% senior notes due 2028...................... $ (249,914) $ (270,312) $ (249,913) $ (245,025)
Cash and cash equivalents, accounts receivable, other current assets,
accounts payable, interest payable and other current liabilities. The carrying
amounts approximate fair value due to the short maturity of these instruments.
56
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2003, 2002 and 2001
Commodity price swap and collar contracts, interest rate swaps and foreign
currency swap contracts. The fair value of commodity price swap and collar
contracts, interest rate swaps and foreign currency contracts are estimated from
quotes provided by the counterparties to these derivative contracts and
represent the estimated amounts that the Company would expect to receive or pay
to settle the derivative contracts. During the year ended December 31, 2003, the
Company terminated all of its interest rate swap contracts and the foreign
currency contracts matured. See Note J for a description of each of these
derivatives, including whether the derivative contract qualifies for hedge
accounting treatment or is considered a speculative derivative contract.
Financial assets. As of December 31, 2002, the Company had an investment in
bonds that were classified as trading securities and a note receivable. The
Company divested the bonds during January 2003. The fair value of the 5-1/2
percent note receivable was determined based on underlying market rates of
interest.
Long-term debt. The carrying amount of borrowings outstanding under the
Company's corporate credit facility approximates fair value because these
instruments bear interest at variable market rates. The fair values of each of
the senior note issuances were determined based on quoted market prices for each
of the issues. See Note E for additional information regarding the Company's
long-term debt.
NOTE D. Acquisitions
Falcon acquisitions. During the year ended December 31, 2002, the Company
purchased, through two transactions, an additional 30 percent working interest
in the Falcon field development and a 25 percent working interest in associated
acreage in the deepwater Gulf of Mexico for a combined purchase price of $61.1
million. As a result of these transactions, the Company owned a 75 percent
working interest in and operated the Falcon field development and related
exploration blocks at December 31, 2002. On March 28, 2003, the Company
purchased the remaining 25 percent working interest that it did not already own
in the Falcon field, the Harrier field and surrounding satellite prospects in
the deepwater Gulf of Mexico for $120.4 million, including $114.1 million of
cash, $1.7 million of asset retirement obligations assumed and $4.6 million of
closing adjustments.
West Panhandle acquisitions. During July 2002, the Company completed the
purchase of the remaining 23 percent of the rights that the Company did not
already own in its core area West Panhandle gas field, 100 percent of the West
Panhandle reserves attributable to field fuel, 100 percent of the related West
Panhandle field gathering system and ten blocks surrounding the Company's
deepwater Gulf of Mexico Falcon discovery. In connection with these
transactions, the Company recorded $100.4 million to proved oil and gas
properties, $3.8 million to unproved oil and gas properties and $1.9 million to
assets held for resale; retired a capital cost obligation for $60.8 million;
settled a $20.9 million gas balancing receivable; assumed trade and
environmental obligations amounting to $5.8 million in the aggregate; and paid
$140.2 million of cash. The capital cost obligation retired by the Company for
$60.8 million represented an obligation for West Panhandle gas field capital
additions that was not able to be prepaid and bore interest at an annual rate of
20 percent. The portion of the purchase price allocated to the retirement of the
capital cost obligation was based on a discounted cash flow analysis using a
market discount rate for obligations with similar terms. The capital cost
obligation had a carrying value of $45.2 million, resulting in a loss of $15.6
million from the early extinguishment of this obligation.
Affiliated partnership mergers. During 2001, the limited partners of 42 of
the Company's affiliated partnerships approved an agreement and plan of merger
("Plan of Merger") among the Company, Pioneer Natural Resources USA, Inc.
("Pioneer USA"), a wholly-owned subsidiary of the Company, and the partnerships.
The Plan of Merger was accounted for as a purchase business combination. In
consideration for the partnerships' net assets, the limited partners received
5.7 million shares of the Company's common stock valued at $18.35 per share. In
connection with this transaction, the Company recorded $92.9 million to proved
oil and gas properties, $13.6 million to cash and $.3 million to other net
assets. The cash acquired from the partnerships, net of $2.5 million of cash
transaction costs, is included in "cash acquired in acquisitions, net of fees
57
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2003, 2002 and 2001
paid" in the accompanying Consolidated Statement of Cash Flows for the year
ended December 31, 2001. Except for the cash acquired, this transaction
represents a noncash investing activity of the Company that was funded by the
issuance of common stock.
Other acquisitions. During 2003, in addition to the incremental 25 percent
working interest acquired in the Falcon area, the Company spent $30.6 million to
acquire producing properties in the Spraberry field and unproved properties in
Alaska, the Gulf of Mexico, Argentina, Canada and Tunisia. During 2002, in
addition to the Falcon and West Panhandle acquisitions referred to above, the
Company spent $25.5 million to acquire additional unproved acreage in the United
States, including 34 Gulf of Mexico shelf blocks, six deepwater Gulf of Mexico
blocks, a 70 percent working interest in ten state leases on Alaska's North
Slope and property interests in other areas of the United States. Also during
2002, the Company acquired unproved and proved oil and gas property interests in
Canada for $2.3 million and $.5 million, respectively, and $1.8 million of
additional unproved property interests in Tunisia. During 2001, the Company
spent $77.9 million to acquire additional working interests in the Gulf of
Mexico Aconcagua discovery, the related Canyon Express gathering system and the
Devils Tower project; 21 deepwater Gulf of Mexico blocks; 250,000 acres in the
Anticlinal Campamento, Dos Hermanas and La Calera areas of the Neuquen Basin in
Argentina; and a 30 percent interest in the Anaguid permit in the Ghadames basin
onshore Southern Tunisia.
NOTE E. Long-term Debt
Long-term debt, including the effects of fair value hedges and discounts,
consisted of the following components at December 31, 2003 and 2002:
December 31,
----------------------------
2003 2002
----------- -----------
(in thousands)
Lines of credit................................... $ 160,000 $ 260,000
8-7/8% senior notes due 2005...................... 135,239 146,704
8-1/4% senior notes due 2007...................... 155,253 161,130
6-1/2% senior notes due 2008...................... 354,497 362,592
9-5/8% senior notes due 2010...................... 350,558 338,197
7-1/2% senior notes due 2012...................... 150,000 150,000
7-1/5% senior notes due 2028...................... 249,914 249,913
---------- ----------
Total long-term debt......................... $ 1,555,461 $ 1,668,536
========== ==========
Maturities of long-term debt at December 31, 2003 are as follows (in
thousands):
2004.............................................. $ -
2005.............................................. $ 135,239
2006.............................................. $ -
2007.............................................. $ 155,253
2008.............................................. $ 514,497
Thereafter........................................ $ 750,472
Lines of credit. During December 2003, the Company entered into a new
five-year unsecured revolving credit agreement (the "New Credit Facility") that
matures in December 2008. The New Credit Facility replaced the Company's $575
million revolving credit facility (the "Prior Credit Facility") that had a
scheduled maturity in March 2005. The terms of the New Credit Facility provide
for initial aggregate loan commitments of $700 million from a syndication of
participating banks (the "Lenders"). Aggregate loan commitments under the New
Credit Facility may be increased to a maximum aggregate amount of $1 billion if
the Lenders increase their loan commitments or loan commitments of new financial
institutions are added to the New Credit Facility.
58
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2003, 2002 and 2001
Borrowings under the New Credit Facility may be in the form of revolving
loans or swing line loans. Aggregate outstanding swing line loans may not exceed
$80 million. Revolving loans issued under the New Credit Facility bear interest,
at the option of the Company, based on (a) a rate per annum equal to the higher
of the prime rate announced from time to time by JPMorgan Chase Bank (4.0
percent per annum at December 31, 2003) or the weighted average of the rates on
overnight Federal funds transactions with members of the Federal Reserve System
during the last preceding business day plus 50 basis point (1.5 percent per
annum at December 31, 2003) or (b) a base Eurodollar rate, substantially equal
to LIBOR (1.2 percent per annum at December 31, 2003), plus a margin (the
"Applicable Margin") that is based on a grid of the Company's debt rating (125
basis points per annum at December 31, 2003). Swing line loans bear interest at
a rate per annum equal to the "ASK" rate for Federal funds periodically
published by the Dow Jones Market Service. As of December 31, 2003, the Company
had $160 million of Eurodollar rate revolving loans outstanding under the New
Credit Facility.
Advances under the Prior Credit Facility bore interest, at the option of
the Company, based on (a) a base rate equal to the higher of the Bank of
America, N.A. prime rate or a rate per annum based on the weighted average of
the rates on overnight Federal funds transactions with members of the Federal
Reserve System, plus 50 basis points; plus a eurodollar margin less 125 basis
points, (b) a Eurodollar rate, substantially equal to LIBOR, plus a eurodollar
margin, or (c) a fixed rate (for aggregate advances not exceeding $50 million)
as quoted by the banks pursuant to a request by the Company.
The New Credit Facility imposes certain restrictive covenants on the
Company, including the maintenance of a ratio of the Company's earnings before
gain or loss on the disposition of assets, interest expense, income taxes,
depreciation, depletion and amortization expense, exploration and abandonments
expense and other noncash charges and expenses to consolidated interest expense
of at least 3.5 to 1.0; maintenance of a ratio of total debt to book
capitalization less intangible assets (other than intangible oil and gas
assets), accumulated other comprehensive income and certain noncash asset
write-downs not to exceed .60 to 1.0; and, maintenance of an annual ratio of the
net present value of the Company's oil and gas properties to total debt of at
least 1.25 to 1.00 until the Company has an investment grade rating. The Company
was in compliance with all of its debt covenants as of December 31, 2003.
As of December 31, 2003 and 2002, the Company had $47.6 million and $45.4
million of undrawn letters of credit, respectively, of which $28.8 million on
December 31, 2003 and $27.2 million on December 31, 2002 were undrawn
commitments under the New Credit Facility and Prior Credit Facility,
respectively. As of December 31, 2003 and 2002, the Company had unused borrowing
capacity of $511.2 million and $287.8 million under the New Credit Facility and
Prior Credit Facility, respectively.
Senior notes. The Company's senior notes are general unsecured obligations
ranking equally in right of payment with all other senior unsecured indebtedness
of the Company and are senior in right of payment to all existing and future
subordinated indebtedness of the Company. The Company is a holding company that
conducts all of its operations through subsidiaries; consequently, the senior
notes are structurally subordinated to all obligations of its subsidiaries.
Interest on the Company's senior notes is payable semi-annually. Pioneer USA has
fully and unconditionally guaranteed the senior note issuances. See Note S for a
discussion of Pioneer USA debt guarantees and Consolidating Financial
Statements.
During April 2002, the Company issued $150.0 million of 7-1/2 percent
senior notes due April 15, 2012 (the "7-1/2 percent senior notes"). The 7-1/2
percent senior notes were issued at a price equal to 100 percent of their
principal amount and resulted in net proceeds to the Company, after underwriting
discounts, commissions and costs of issuance, of $146.7 million. The net
proceeds from the issuance of the 7-1/2 percent senior notes were used to reduce
outstanding borrowings under the Prior Credit Facility. The 7-1/2 percent senior
notes and 9-5/8 percent senior notes contain various restrictive covenants,
including restrictions on the incurrence of additional indebtedness and certain
59
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2003, 2002 and 2001
payments defined within the associated indenture. The Company was in compliance
with all of its senior note covenants as of December 31, 2003.
As of December 31, 2003 and 2002, the aggregate carrying value of the
Company's 8-7/8, 8-1/4, 6-1/2 and 9-5/8 percent senior notes included $27.4
million and $35.7 million, respectively, of incremental carrying value
attributable to the unamortized net deferred hedge gains realized from
terminated fair value hedge interest rate swap contracts. See Note J for
additional information regarding terminated fair value hedge interest rate swap
contracts.
Early extinguishment of debt and capital cost obligation. During 2003, the
Company repurchased $5.1 million of its 8-7/8 percent senior notes and repaid
the Prior Credit Facility prior to its scheduled maturity. The Company
recognized $1.5 million of charges to other expense associated with the
aforementioned debt extinguishments.
During 2002, the Company repurchased $47.1 million of the 9-5/8 percent
senior notes, $13.9 million of the 8-7/8 percent senior notes and repaid a $45.2
million capital cost obligation. The Company recognized a charge to other
expense of $22.3 million associated with these debt extinguishments.
During 2001, the Company redeemed the remaining $22.5 million of 11-5/8
percent senior subordinated discount notes and $6.8 million of 10-5/8 percent
senior subordinated notes. Additionally, the Company repurchased $38.7 million
of the 9-5/8 percent senior notes. Associated with these debt extinguishments,
the Company recognized a charge to other expense of $3.8 million.
See Note B for a discussion of the classification of gains and losses on
the early extinguishment of debt after the adoption of SFAS 145 on January 1,
2003.
Interest expense. The following amounts have been incurred and charged to
interest expense for the years ended December 31, 2003, 2002 and 2001:
Year Ended December 31,
-----------------------------------
2003 2002 2001
--------- --------- ---------
(in thousands)
Cash payments for interest................................... $ 117,870 $ 113,827 $ 129,992
Accretion/amortization of discounts or premiums on loans..... 2,873 5,488 7,937
Amortization of deferred hedge gains (see Note J)............ (26,114) (14,108) (2,750)
Amortization of capitalized loan fees........................ 2,528 2,436 2,252
Kansas ad valorem tax (see Note I)........................... 103 375 1,250
Net change in accruals....................................... (424) 48 (732)
-------- -------- --------
Interest incurred.......................................... 96,836 108,066 137,949
Less interest capitalized.................................. (5,448) (12,251) (5,991)
-------- -------- --------
Total interest expense.................................. $ 91,388 $ 95,815 $ 131,958
======== ======== ========
NOTE F. Related Party Transactions
Activities with affiliated partnerships. Prior to 1992, the Company,
through its wholly-owned subsidiaries, sponsored 44 drilling partnerships and
three public income partnerships, all of which were formed primarily for the
purpose of drilling and completing wells or acquiring producing properties.
During 2001, the Company completed the merger of 42 of the limited partnerships
into Pioneer USA. See Note D for additional information regarding the mergers.
The Company, through a wholly-owned subsidiary, serves as operator of
properties in which it and its affiliated partnerships have an interest.
Accordingly, the Company receives producing well overhead, drilling well
60
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2003, 2002 and 2001
overhead and other fees related to the operation of the properties. The
affiliated partnerships also reimburse the Company for their allocated share of
general and administrative charges.
The activities with affiliated partnerships are summarized for the
following related party transactions for the years ended December 31, 2003, 2002
and 2001:
2003 2002 2001
------ ------ ------
(in thousands)
Receipt of lease operating and supervision charges
in accordance with standard industry operating
agreements................................................ $1,473 $1,495 $9,281
Reimbursement of general and administrative expenses......... $ 148 $ 127 $1,265
NOTE G. Incentive Plans
Retirement Plans
Deferred compensation retirement plan. In August 1997, the Compensation
Committee of the Board of Directors approved a deferred compensation retirement
plan for the officers and certain key employees of the Company. Each officer and
key employee is allowed to contribute up to 25 percent of their base salary and
100 percent of their annual bonus. The Company will provide a matching
contribution of 100 percent of the officer's and key employee's contribution
limited to the first 10 percent of the officer's base salary and eight percent
of the key employee's base salary. The Company's matching contribution vests
immediately. A trust fund has been established by the Company to accumulate the
contributions made under this retirement plan. The Company's matching
contributions were $851 thousand, $805 thousand and $652 thousand for the years
ended December 31, 2003, 2002 and 2001, respectively.
401(k) plan. The Pioneer Natural Resources USA, Inc. 401(k) and Matching
Plan (the "401(k) Plan") is a defined contribution plan established under the
Internal Revenue Code Section 401. The 401(k) Plan was formed by the merger of
the Pioneer Natural Resources USA, Inc. 401(k) Plan and the Pioneer Natural
Resources USA, Inc. Matching Plan on January 1, 2002. All regular full-time and
part-time employees of Pioneer USA are eligible to participate in the 401(k)
Plan on the first day of the month following their date of hire. Participants
may contribute an amount of not less than two percent nor more than 30 percent
of their annual salary into the 401(k) Plan. Matching contributions are made to
the 401(k) Plan in cash by Pioneer USA in amounts equal to 200 percent of a
participant's contributions to the 401(k) Plan that are not in excess of five
percent of the participant's basic compensation (the "Matching Contribution").
Each participant's account is credited with the participant's contributions,
their Matching Contributions and allocations of the 401(k) Plan's earnings.
Participants are fully vested in their account balances except for Matching
Contributions and their proportionate share of 401(k) Plan earnings attributable
to Matching Contributions, which proportionately vest over a four year period
that begins with the participant's date of hire. During the years ended December
31, 2003, 2002 and 2001, the Company recognized compensation expense of $4.5
million, $4.1 million and $3.4 million, respectively, as a result of Matching
Contributions.
Long-Term Incentive Plan
In August 1997, the Company's stockholders approved a Long-Term Incentive
Plan which provides for the granting of incentive awards in the form of stock
options, stock appreciation rights, performance units and restricted stock to
directors, officers and employees of the Company. The Long-Term Incentive Plan
provides for the issuance of a maximum number of shares of common stock equal to
10 percent of the total number of shares of common stock equivalents outstanding
less the total number of shares of common stock subject to outstanding awards
under any stock- based plan for the directors, officers or employees of the
Company.
61
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2003, 2002 and 2001
The following table calculates the number of shares or options available
for grant under the Company's Long- Term Incentive Plan as of December 31, 2003
and 2002:
December 31,
--------------------------
2003 2002
----------- -----------
Shares outstanding.................................................... 119,287,772 117,252,538
Outstanding options exercisable or exercisable within 60 days......... 3,279,024 5,024,173
----------- -----------
122,566,796 122,276,711
=========== ===========
Maximum shares/options allowed under the Long-Term Incentive Plan..... 12,256,680 12,227,671
Less: Outstanding awards under the Long-Term Incentive Plan.......... (5,534,037) (7,432,414)
Outstanding options under predecessor incentive plans.......... (417,052) (488,671)
----------- -----------
Shares/options available for future grant............................. 6,305,591 4,306,586
=========== ===========
Stock option awards. The Company has a program of awarding semi-annual
stock options to its officers and employees and gives its non-employee directors
a choice to receive (i) 100 percent restricted stock, (ii) 100 percent stock
options, (iii) 100 percent cash, or (iv) a combination of 50/50 of any two, as
their annual compensation. This program provides for stock option awards at an
exercise price based upon the closing sales price of the Company's common stock
on the day prior to the date of grant. Employee stock option awards vest over an
18 month or three year schedule and provide a five year exercise period from
each vesting date. Non-employee directors' stock options vest quarterly and
provide for a five year exercise period from each vesting date. The Company
granted 1,353,988, 1,643,212 and 1,627,071 options under the Long-Term Incentive
Plan during the years ended December 31, 2003, 2002 and 2001, respectively.
Restricted stock awards. During the year ended December 31, 2003, the
Company issued 77,625 restricted shares of the Company's common stock. The
restricted share awards were issued as compensation to directors, officers and
key employees of the Company. The restricted share awards included 4,425 shares
that were granted to directors of the Company on May 14, 2003. Director awards
vest on a quarterly prorata basis during the year ended May 14, 2004. The
remaining 73,200 restricted shares were awarded to officers and key employees of
the Company. Of the shares awarded, 9,500 shares vest on January 26, 2006 and
the remaining 63,700 shares vest on September 30, 2006.
During the year ended December 31, 2002, the Company issued 654,445
restricted shares of the Company's common stock. The restricted share awards
were issued as compensation to directors, officers and key employees of the
Company. The restricted share awards included 18,545 shares that were granted to
directors of the Company on May 13, 2002. Director awards for 3,302 shares
vested on a quarterly prorata basis during the year ended May 13, 2003 and
director awards for 15,243 shares vest on May 13, 2005. The remaining 635,900
restricted shares were awarded to officers and key employees of the Company on
August 12, 2002 and vest on August 12, 2005.
The Company recorded $1.1 million and $16.2 million of deferred
compensation associated with restricted stock awards in the stockholders' equity
section of the accompanying Consolidated Balance Sheets during the years ended
December 31, 2003 and 2002, respectively. Such amounts will be amortized to
compensation expense over the vesting periods of the awards. During the years
ended December 31, 2003 and 2002, amortization of the restricted stock awards
increased the Company's compensation expense by $5.4 million and $1.9 million,
respectively.
62
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2003, 2002 and 2001
The following table reflects the outstanding restricted stock awards and
activity related thereto for the years ended December 31, 2003 and 2002:
Year Ended Year Ended
December 31, 2003 December 31, 2002
--------------------- ---------------------
Weighted Weighted
Number Average Number Average
of Shares Price of Shares Price
--------- -------- --------- --------
Restricted Stock Awards:
Restricted shares outstanding at beginning
of year........................................ 652,793 $ 24.72 - $ -
Shares granted................................... 77,625 $ 25.39 654,445 $ 24.72
Shares forfeited................................. (36,500) $ 24.72 - $ -
Lapse of restrictions............................ (16,945) $ 25.59 (1,652) $ 24.60
-------- -------
Restricted shares outstanding at end of year..... 676,973 $ 24.79 652,793 $ 24.72
======== =======
There were no restricted stock awards to directors or employees during the
year ended December 31, 2001.
Other stock based plans. Prior to the formation of the Company in 1997, the
Company's predecessor companies had long-term incentive plans in place that
allowed the predecessor companies to grant incentive awards similar to the
provisions of the Long-Term Incentive Plan. Upon formation of the Company, all
awards under these plans were assumed by the Company with the provision that no
additional awards be granted under the predecessor plans.
SFAS 123 disclosures. The Company applies APB 25 and related
interpretations in accounting for its stock option awards. Accordingly, no
compensation expense has been recognized for its stock option awards. If
compensation expense for the stock option awards had been determined consistent
with SFAS 123, the Company's net income and net income per share would have been
less than the reported amounts. See Note B for a comparison of net income and
net income per share as reported and as adjusted for the pro forma effects of
determining compensation expense in accordance with SFAS 123.
Under SFAS 123, the fair value of each stock option grant is estimated on
the date of grant using the Black- Scholes option pricing model with the
following weighted average assumptions used for grants during the years ended
December 31, 2003, 2002 and 2001:
Year Ended December 31,
---------------------------
2003 2002 2001
------- ------- -------
Risk-free interest rate............. 3.06% 2.80% 4.13%
Expected life....................... 5 years 5 years 5 years
Expected volatility................. 36% 45% 49%
Expected dividend yield............. - - -
63
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2003, 2002 and 2001
A summary of the Company's stock option plans as of December 31, 2003, 2002
and 2001, and changes during the years then ended, are presented below:
Year Ended Year Ended Year Ended
December 31, 2003 December 31, 2002 December 31, 2001
--------------------- --------------------- ---------------------
Weighted Weighted Weighted
Number Average Number Average Number Average
of Shares Price of Shares Price of Shares Price
---------- -------- ---------- -------- ---------- --------
Non-statutory stock options:
Outstanding, beginning of year.. 7,268,292 $ 19.60 6,926,071 $ 18.16 6,510,559 $ 18.10
Options granted............... 1,353,988 $ 24.84 1,643,212 $ 21.14 1,627,071 $ 18.29
Options forfeited............. (1,286,370) $ 29.22 (154,717) $ 26.27 (566,189) $ 25.83
Options exercised............. (2,061,794) $ 15.68 (1,146,274) $ 12.19 (645,370) $ 11.14
---------- ---------- ----------
Outstanding, end of year........ 5,274,116 $ 20.13 7,268,292 $ 19.60 6,926,071 $ 18.16
========== ========== ==========
Exercisable at end of year...... 2,581,256 $ 17.56 4,269,659 $ 20.15 4,005,762 $ 20.82
========== ========== ==========
Weighted average fair value of options
granted during the year......... $ 8.95 $ 8.87 $ 8.65
========= ========= =========
The following table summarizes information about the Company's stock
options outstanding and options exercisable at December 31, 2003:
Options Outstanding Options Exercisable
----------------------------------------------------- -------------------------------------
Number Weighted Average Weighted Weighted
Range of Outstanding at Remaining Average Number Exercisable Average
Exercise Prices December 31, 2003 Contractual Life Exercise Price at December 31, 2003 Exercise Price
- --------------- ----------------- ---------------- -------------- -------------------- --------------
$ 5-11 432,765 2.8 years $ 8.70 432,765 $ 8.70
$ 12-18 2,343,782 4.3 years $ 17.10 1,431,111 $ 16.34
$ 19-26 2,327,499 5.4 years $ 24.55 547,310 $ 23.72
$ 27-30 139,358 1.6 years $ 28.44 139,358 $ 28.44
$ 31-43 30,712 3.1 years $ 40.06 30,712 $ 40.06
----------- -----------
5,274,116 2,581,256
=========== ===========
Employee Stock Purchase Plan
The Company has an Employee Stock Purchase Plan (the "ESPP") that allows
eligible employees to annually purchase the Company's common stock at a
discounted price. Officers of the Company are not eligible to participate in the
ESPP. Contributions to the ESPP are limited to 15 percent of an employee's pay
(subject to certain ESPP limits) during the nine month offering period.
Participants in the ESPP purchase the Company's common stock at a price that is
15 percent below the closing sales price of the Company's common stock on either
the first day or the last day of each offering period, whichever closing sales
price is lower.
Postretirement Benefit Obligations
As of December 31, 2003 and 2002, the Company had recorded $15.6 million
and $19.7 million, respectively, of unfunded accumulated postretirement benefit
obligations in the Company's accompanying Consolidated Balance Sheets. These
obligations are comprised of five plans of which four relate to predecessor
entities that the Company acquired in prior years. These plans had no assets as
of December 31, 2003 or 2002. Other than the Company's retirement plan, the
participants of these plans are not current employees of the Company.
64
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2003, 2002 and 2001
The accumulated postretirement benefit obligations pertaining to these
plans were determined by independent actuaries for four plans representing $11.2
million of unfunded accumulated postretirement benefit obligations as of
December 31, 2003 and by the Company for one plan representing $4.4 million of
unfunded accumulated postretirement benefit obligations as of December 31, 2003.
Interest costs at an annual rate of six percent of the periodic undiscounted
accumulated postretirement benefit obligations were employed in the valuations
of the benefit obligations. Certain of the aforementioned plans provide for
medical and dental cost subsidies for plan participants. Annual medical cost
escalation trends of 12 percent in 2004, declining to five percent in 2011 and
thereafter, and annual dental cost escalation trends of 7.5 percent in 2004,
declining to five percent in 2009 and thereafter, were employed to estimate the
accumulated postretirement benefit obligations associated with the medical and
dental cost subsidies.
The following table reconciles changes in the Company's unfunded
accumulated postretirement benefit obligations during the years ended December
31, 2003 and 2002:
Year Ended December 31,
--------------------------------
2003 2002 2001
-------- -------- --------
(in thousands)
Beginning accumulated postretirement benefit obligations..... $ 19,743 $ 19,750 $ 20,064
Benefit payments........................................... (1,472) (1,702) (2,009)
Service costs.............................................. 205 205 205
Net actuarial gains........................................ (4,410) - -
Accretion of discounts..................................... 1,490 1,490 1,490
------- ------- -------
Ending accumulated postretirement benefit obligations........ $ 15,556 $ 19,743 $ 19,750
======= ======= =======
Estimated benefit payments and service costs associated with the plans for
the year ended December 31, 2004 are $1.4 million and $.3 million, respectively.
NOTE H. Issuance of Common Stock
During April 2002, the Company completed a public offering of 11.5 million
shares of its common stock at $21.50 per share. Associated therewith, the
Company received $236.0 million of net proceeds after the payment of issuance
costs. The Company used the net proceeds from the public offering to fund the
2002 acquisition of Falcon assets and associated acreage in the deepwater Gulf
of Mexico and the West Panhandle gas field acquisitions. See Note D for
information regarding these acquisitions.
NOTE I. Commitments and Contingencies
Severance agreements. The Company has entered into severance agreements
with its officers, subsidiary company officers and certain key employees.
Salaries and bonuses for the Company's officers are set by the Company's board
of directors for the parent company officers and by the Company's management
committee for subsidiary company officers and key employees. The Company's board
of directors and management committee can grant increases or reductions to base
salary at their discretion. The current annual salaries for the parent company
officers, the subsidiary company officers and key employees covered under such
agreements total approximately $19.9 million.
Indemnifications. The Company has indemnified its directors and certain of
its officers, employees and agents with respect to claims and damages arising
from acts or omissions taken in such capacity, as well as with respect to
certain litigation.
Legal actions. The Company is party to various legal actions incidental to
its business, including, but not limited to, the proceedings described below.
The majority of these lawsuits primarily involve claims for damages arising from
oil and gas leases and ownership interest disputes. The Company believes that
the ultimate disposition of these legal actions will not have a material adverse
65
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2003, 2002 and 2001
effect on the Company's consolidated financial position, liquidity, capital
resources or future results of operations. The Company will continue to evaluate
its litigation matters on a quarter-by- quarter basis and will adjust its
litigation reserves as appropriate to reflect the then current status of
litigation.
Alford. The Company is party to a 1993 class action lawsuit filed in the
26th Judicial District Court of Stevens County, Kansas by two classes of royalty
owners, one for each of the Company's gathering systems connected to the
Company's Satanta gas plant. The case was relatively inactive for several years.
In early 2000, the plaintiffs amended their pleadings and it now contains two
material claims. First, the plaintiffs assert that they were improperly charged
expenses (primarily field compression), which are a "cost of production", and
for which the plaintiffs, as royalty owners, are not responsible. Second, the
plaintiffs claim they are entitled to 100 percent of the value of the helium
extracted at the Company's Satanta gas plant. If the plaintiffs were to prevail
on the above two claims in their entirety, it is possible that the Company's
liability (both for periods covered by the lawsuit and from the last date
covered by the lawsuit to the present - because the deductions continue to be
taken and the plaintiffs continue to be paid for a royalty share of the helium)
could reach $65.0 million, plus prejudgment interest. However, the Company
believes it has valid defenses to the plaintiffs' claims, has paid the
plaintiffs properly under their respective oil and gas leases and other
agreements, and intends to vigorously defend itself.
The Company does not believe the costs it has deducted are a "cost of
production". The costs being deducted are post production costs incurred to
transport the gas to the Company's Satanta gas plant for processing, where the
valuable hydrocarbon liquids and helium are extracted from the gas. The
plaintiffs benefit from such extractions and the Company believes that charging
the plaintiffs with their proportionate share of such transportation and
processing expenses is consistent with Kansas law and with the parties'
agreements.
The Company has also vigorously defended against plaintiffs' claims to 100
percent of the value of the helium extracted, and believes that in accordance
with applicable law, it has properly accounted to the plaintiffs for their
fractional royalty share of the helium under the specified royalty clauses of
the respective oil and gas leases.
The factual evidence in the case was presented to the 26th Judicial
District Court without a jury in December 2001. Oral arguments were heard by the
court in April 2002, and although the court has not yet entered a judgment or
findings, it could do so at any time. The Company strongly denies the existence
of any material underpayment to the plaintiffs and believes it presented strong
evidence at trial to support its positions. Although the amount of any resulting
liability could have a material adverse effect on the Company's results of
operations for the quarterly reporting period in which such liability is
recorded, the Company does not expect that any such liability will have a
material adverse effect on its consolidated financial position as a whole or on
its liquidity, capital resources or future annual results of operations.
Kansas ad valorem tax. The Natural Gas Policy Act of 1978 ("NGPA") allows a
"severance, production or similar" tax to be included as an add-on, over and
above the maximum lawful price for gas. Based on a Federal Energy Regulatory
Commission ("FERC") ruling that Kansas ad valorem tax was such a tax, one of the
Company's predecessor entities collected the Kansas ad valorem tax in addition
to the otherwise maximum lawful price. The FERC's ruling was appealed to the
United States Court of Appeals for the District of Columbia ("D.C. Circuit"),
which held in June 1988 that the FERC failed to provide a reasonable basis for
its findings and remanded the case to the FERC for further consideration.
On December 1, 1993, the FERC issued an order reversing its prior ruling,
but limited the effect of its decision to Kansas ad valorem taxes for sales made
on or after June 28, 1988. The FERC clarified the effective date of its decision
by an order dated May 18, 1994. The order clarified that the effective date
applies to tax bills rendered after June 28, 1988, not sales made on or after
that date. Numerous parties filed appeals on the FERC's action in the D.C.
Circuit. Various gas producers challenged the FERC's orders on two grounds: (1)
that the Kansas ad valorem tax, properly understood, does qualify for
66
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2003, 2002 and 2001
reimbursement under the NGPA; and (2) the FERC's ruling should, in any event,
have been applied prospectively. Other parties challenged the FERC's orders on
the grounds that the FERC's ruling should have been applied retroactively to
December 1, 1978, the date of the enactment of the NGPA and producers should
have been required to pay refunds accordingly.
The D.C. Circuit issued its decision on August 2, 1996, which holds that
producers must make refunds of all Kansas ad valorem tax collected with respect
to production since October 4, 1983, as opposed to June 28, 1988. Petitions for
rehearing were denied on November 6, 1996. Various gas producers subsequently
filed a petition for writ of certiori with the United States Supreme Court
seeking to limit the scope of the potential refunds to tax bills rendered on or
after June 28, 1988 (the effective date originally selected by the FERC).
Williams Natural Gas Company filed a cross-petition for certiori seeking to
impose refund liability back to December 1, 1978. Both petitions were denied on
May 12, 1997.
The Company and other producers filed petitions for adjustment with the
FERC on June 24, 1997. The Company was seeking a waiver or set-off from the FERC
with respect to that portion of the refund associated with (i) nonrecoupable
royalties, (ii) nonrecoupable Kansas property taxes based, in part, upon the
higher prices collected and (iii) interest for all periods. On September 10,
1997, FERC denied this request, and on October 10, 1997, the Company and other
producers filed a request for rehearing. Pipelines were given until November 10,
1997 to file claims on refunds sought from producers and refund claims totaling
approximately $30.2 million were made against the Company. Through December 31,
2003, the Company has settled $21.6 million of the original claim amounts. As of
December 31, 2003 and 2002, the Company had on deposit $10.7 million and $10.6
million, respectively, including accrued interest, in an escrow account and had
corresponding obligations for the remaining claim recorded in other current
liabilities in the accompanying Consolidated Balance Sheets. On December 1,
2003, an administrative law judge issued a Partial Initial Decision denying the
Company's request to allow any waiver or set-off from the refunds and stating
that the Company must pay the FERC interest rate on the refund claims instead of
the escrow interest rate. The Company has accrued an additional $1.5 million
obligation for the difference between the escrow interest rate and the FERC
interest rate, although the Company intends to vigorously appeal the decision.
The Company believes that the accrued obligations will be sufficient to resolve
the remaining claims.
Lease agreements. The Company leases offshore production facilities,
equipment and office facilities under noncancellable operating leases. Rental
expenses associated with these operating leases for the years ended December 31,
2003, 2002 and 2001 were approximately $15.5 million, $6.7 million and $6.6
million, respectively. Future minimum lease commitments under noncancellable
operating leases at December 31, 2003 are as follows (in thousands):
2004.................................................. $ 35,515
2005.................................................. $ 43,442
2006.................................................. $ 38,227
2007.................................................. $ 27,612
2008.................................................. $ 17,338
Thereafter............................................ $ 24,174
Drilling commitments. The Company periodically enters into contractual
arrangements under which the Company is committed to expend funds to drill wells
in the future. The Company also enters into agreements to secure drilling rig
services which require the Company to make future minimum payments to the rig
operators. The Company records drilling commitments in the periods in which well
capital is expended or rig services are provided.
Transportation agreements. The Company's wholly-owned Canadian subsidiary
is a party to pipeline transportation service agreements, with remaining terms
of approximately 12 years, whereby it has committed to transport a specified
volume of gas each year from Canada to a point in Chicago. Such gas volumes are
comprised of a significant portion of the Company's Canadian net production,
augmented with certain volumes purchased at market prices in Canada. The
67
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2003, 2002 and 2001
committed volumes to be transported under the pipeline transportation service
agreements are approximately 78 MMcf of gas per day during 2004 and decline to
approximately 75 MMcf of gas per day by the end of the commitment term. The net
gas marketing gains or losses resulting from purchasing third party gas in
Canada and selling it in Chicago are recorded as other income or other expense
in the accompanying Consolidated Statements of Operations. Associated with these
agreements, the Company recognized $922 thousand, $2.6 million and $9.9 million
of gas marketing losses in other expenses during the years ended December 31,
2003, 2002 and 2001, respectively.
NOTE J. Derivative Financial Instruments
Hedge Derivatives
The Company utilizes derivative instruments to manage commodity price,
interest rate and foreign exchange rate risks.
Fair value hedges. The Company monitors the debt capital markets and
interest rate trends to identify opportunities to enter into and terminate
interest rate swap contracts with the objective of minimizing costs of capital.
During the three year period ending December 31, 2003, the Company, from time to
time, entered into interest rate swap contracts to hedge a portion of the fair
value of its senior notes. The terms of the interest rate swap contracts were
for notional amounts that matched the scheduled maturity of the bonds, required
the counterparties to pay the Company a fixed annual interest rate equal to the
stated bond coupon rates on the notional amounts and required the Company to pay
the counterparties variable annual interest rates on the notional amounts equal
to the periodic six-month LIBOR plus a weighted average margin.
During the years ended December 31, 2003, 2002 and 2001, the Company
recognized interest savings associated with its interest rate swap contracts of
$29.3 million, $25.3 million and $7.3 million, respectively. During the years
ended December 31, 2003, 2002 and 2001, the Company terminated interest rate
swap contracts for cash proceeds, including accrued interest, of $21.5 million,
$36.3 million and $23.3 million, respectively. The proceeds attributable to the
fair value of the remaining terms of the terminated contracts amounted to $18.3
million, $32.0 million and $21.2 million and are included in "Proceeds from
disposition of assets" in the accompanying Consolidated Statements of Cash Flows
during the years ended December 31, 2003, 2002 and 2001, respectively. As of
December 31, 2003 and 2002, the Company was not a party to any fair value
hedges.
As of December 31, 2003, the carrying value of the Company's long-term debt
in the accompanying Consolidated Balance Sheets included $27.4 million of
incremental carrying value attributable to the unamortized net deferred hedge
gains realized from terminated fair value hedge interest rate swap contracts.
The amortization of these net deferred hedge gains reduced the Company's
reported interest expense by $26.1 million, $14.1 million and $2.8 million
during the years ended December 31, 2003, 2002 and 2001, respectively.
The following table sets forth the scheduled amortization of net deferred
hedge gains and losses on terminated fair value hedges as of December 31, 2003
that will be recognized as increases in the case of losses, or decreases in the
case of gains, to the Company's future interest expense:
First Second Third Fourth Yearly
Quarter Quarter Quarter Quarter Total
------- ------- ------- ------- --------
(in thousands)
2004 net hedge gain amortization.. $ 7,308 $ 6,116 $ 5,489 $ 4,555 $ 23,468
2005 net hedge gain amortization.. $ 4,264 $ 2,816 $ 2,313 $ 1,575 10,968
Remaining net losses to be
amortized through 2010.......... (7,062)
-------
$ 27,374
=======
68
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2003, 2002 and 2001
The terms of the fair value hedges described above perfectly matched the
terms of the underlying senior notes. The Company did not exclude any component
of the derivatives' gains or losses from the measurement of hedge effectiveness.
Cash flow hedges. The Company utilizes commodity swap and collar contracts
to (i) reduce the effect of price volatility on the commodities the Company
produces and sells, (ii) support the Company's annual capital budgeting and
expenditure plans and (iii) reduce commodity price risk associated with certain
capital projects. The Company has also utilized interest rate swap contracts to
reduce the effect of interest rate volatility on the Company's variable rate
line of credit indebtedness and forward currency exchange contracts to reduce
the effect of U.S. dollar to Canadian dollar exchange rate volatility.
Oil prices. All material sales contracts governing the Company's oil
production have been tied directly or indirectly to NYMEX prices. The following
table sets forth the Company's outstanding oil hedge contracts and the weighted
average NYMEX prices for those contracts as of December 31, 2003:
Yearly
First Second Third Fourth Outstanding
Quarter Quarter Quarter Quarter Average
------- ------- ------- ------- -----------
Daily oil production:
2004 - Swap Contracts
Volume (Bbl)............. 24,000 24,000 14,000 14,000 18,973
Price per Bbl............ $ 26.59 $ 26.51 $ 24.65 $ 24.65 $ 25.84
2005 - Swap Contracts
Volume (Bbl)............. 17,000 17,000 17,000 17,000 17,000
Price per Bbl............ $ 24.93 $ 24.93 $ 24.93 $ 24.93 $ 24.93
2006 - Swap Contracts
Volume (Bbl)............. 5,000 5,000 5,000 5,000 5,000
Price per Bbl............ $ 26.19 $ 26.19 $ 26.19 $ 26.19 $ 26.19
2007 - Swap Contracts
Volume (Bbl)............. 1,000 1,000 1,000 1,000 1,000
Price per Bbl............ $ 26.00 $ 26.00 $ 26.00 $ 26.00 $ 26.00
2008 - Swap Contracts
Volume (Bbl)............. 5,000 5,000 5,000 5,000 5,000
Price per Bbl............ $ 26.09 $ 26.09 $ 26.09 $ 26.09 $ 26.09
The Company reports average oil prices per Bbl including the effects of oil
quality adjustments and the net effect of oil hedges. The following table sets
forth the Company's oil prices, both reported (including hedge results) and
realized (excluding hedge results), and the net effect of settlements of oil
price hedges on oil revenue for the years ended December 31, 2003, 2002 and
2001:
Year Ended December 31,
-----------------------------
2003 2002 2001
------- ------- -------
Average price reported per Bbl........................ $ 25.59 $ 22.89 $ 24.12
Average price realized per Bbl........................ $ 28.80 $ 22.95 $ 23.88
Addition (reduction) to oil revenue (in millions)..... $ (41.3) $ (.8) $ 3.0
69
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2003, 2002 and 2001
Natural gas liquids prices. During the years ended December 31, 2003, 2002
and 2001, the Company did not enter into any NGL hedge contracts. There were no
outstanding NGL hedge contracts at December 31, 2003.
Gas prices. The Company employs a policy of hedging a portion of its gas
production based on the index price upon which the gas is actually sold, or
based on NYMEX prices if NYMEX prices are highly correlated with the index
price, in order to mitigate the basis risk between NYMEX prices and actual index
prices. The following table sets forth the Company's outstanding gas hedge
contracts and the weighted average index prices for those contracts as of
December 31, 2003:
Yearly
First Second Third Fourth Outstanding
Quarter Quarter Quarter Quarter Average
-------- -------- -------- -------- ------------
Daily gas production:
2004 - Swap Contracts
Volume (Mcf).................... 295,934 280,000 280,000 280,000 283,962
Index price per MMBtu........... $ 4.27 $ 4.11 $ 4.11 $ 4.11 $ 4.16
2005 - Swap Contracts
Volume (Mcf).................... 60,000 60,000 60,000 60,000 60,000
Index price per MMBtu........... $ 4.24 $ 4.24 $ 4.24 $ 4.24 $ 4.24
2006 - Swap Contracts
Volume (Mcf).................... 70,000 70,000 70,000 70,000 70,000
Index price per MMBtu........... $ 4.16 $ 4.16 $ 4.16 $ 4.16 $ 4.16
2007 - Swap Contracts
Volume (Mcf).................... 20,000 20,000 20,000 20,000 20,000
Index price per MMBtu........... $ 3.51 $ 3.51 $ 3.51 $ 3.51 $ 3.51
The Company reports average gas prices per Mcf including the effects of Btu
content, gas processing and shrinkage adjustments and the net effect of gas
hedges. The following table sets forth the Company's gas prices, both reported
(including hedge results) and realized (excluding hedge results), and the net
effect of settlements of gas price hedges on gas revenue:
Year Ended December 31,
--------------------------
2003 2002 2001
------ ------ ------
Average price reported per Mcf....................... $ 3.81 $ 2.49 $ 3.23
Average price realized per Mcf....................... $ 4.17 $ 2.38 $ 3.20
Addition (reduction) to gas revenue (in millions).... $(76.1) $ 13.6 $ 3.0
Hedge ineffectiveness and excluded items. During the years ended December
31, 2003, 2002 and 2001, the Company recognized other expense of $2.8 million,
$1.7 million and $9.1 million, respectively, related to the ineffective portions
of its cash flow hedging instruments. Additionally, based on SFAS 133
interpretive guidance that was in effect prior to April 2001, the Company
excluded from the measurement of hedge effectiveness changes in the time and
volatility value components of collar contracts designated as cash flow hedges.
Associated therewith, the Company recorded other expense of $2.4 million during
the three month period ended March 31, 2001. In April 2001, the Company
discontinued the exclusion of time value and volatility from the measurement of
hedge effectiveness.
Accumulated other comprehensive income (loss) - net deferred hedge gains
(losses), net of tax. As of December 31, 2003 and 2002, AOCI - net deferred
hedge gains (losses), net of tax represented net deferred losses of $104.1
70
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2003, 2002 and 2001
million and net deferred gains of $9.6 million, respectively. The AOCI - net
deferred hedge gains (losses), net of tax balance as of December 31, 2003 was
comprised of $200.6 million of net deferred hedge losses on the effective
portions of open commodity cash flow hedges, $45.1 million of net deferred gains
on terminated cash flow hedges and $51.4 million of associated net deferred tax
benefits. The AOCI - net deferred hedge gains (losses), net of tax balance as of
December 31, 2002 was comprised of $108.1 million of net deferred hedge losses
on the effective portions of open commodity cash flow hedges, $117.4 million of
net deferred gains on terminated cash flow hedges and $.3 million of associated
net deferred tax benefits. The decrease in AOCI - net deferred hedge gains
(losses), net of tax during the year ended December 31, 2003 was primarily
attributable to increases in future commodity prices relative to the commodity
prices stipulated in the hedge agreements and the reclassification of net
deferred hedge gains to net income as derivatives matured by their terms,
partially offset by a $51.1 million increase in associated deferred income tax
benefits (see Note P for information regarding the Company's United States
deferred tax valuation allowance). The net deferred hedge gains and losses
associated with open cash flow hedges remain subject to market price
fluctuations until the positions are either settled under the terms of the hedge
contracts or terminated prior to settlement. The net deferred gains and losses
on terminated cash flow hedges are fixed.
During the twelve month period ending December 31, 2004, the Company
expects to reclassify $151.9 million of net deferred losses associated with open
cash flow hedges and $43.9 million of net deferred gains on terminated cash flow
hedges from AOCI - net deferred hedge gains (losses), net of tax to oil and gas
revenue. The Company also expects to reclassify approximately $39.6 million of
deferred income tax benefits during the twelve months ended December 31, 2004
from AOCI-net deferred hedge gains (losses), net of tax to income tax benefit
(provision).
The following table sets forth the scheduled reclassifications of net
deferred hedge gains on terminated cash flow hedges as of December 31, 2003,
that will be recognized in the Company's future oil and gas revenues:
First Second Third Fourth Yearly
Quarter Quarter Quarter Quarter Total
------- ------- ------- ------- --------
(in thousands)
2004 net deferred hedge gains..... $10,978 $10,932 $11,001 $10,954 $ 43,865
2005 net deferred hedge gains..... $ 307 $ 310 $ 315 $ 317 1,249
-------
$ 45,114
=======
Non-hedge Derivatives
Btu swap contracts. The Company is a party to Btu swap contracts that
mature at the end of 2004. The Btu swap contracts do not qualify for hedge
accounting treatment. The Company recorded mark-to-market adjustments to
decrease the carrying value of the Btu swap liability by $.7 million during the
year ended December 31, 2001. During the year ended December 31, 2001, the
Company entered into offsetting Btu swap contracts that fixed the Company's
remaining obligations associated with the Btu swap contracts. The remaining
undiscounted future settlement obligations of the Company under the Btu swap
contracts are $7.2 million for 2004.
NOTE K. Major Customers and Derivative Counterparties
Sales to major customers. The Company's share of oil and gas production is
sold to various purchasers who must be prequalified under the Company's credit
risk policies and procedures. The Company is of the opinion that the loss of any
one purchaser would not have an adverse effect on the ability of the Company to
sell its oil and gas production.
The following customers individually accounted for 10 percent or more of
the consolidated oil, NGL and gas revenues of the Company during one or more of
the years ended December 31, 2003, 2002 and 2001:
71
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2003, 2002 and 2001
Percentage of Consolidated
Oil, NGL and Gas Revenues
----------------------------
2003 2002 2001
------ ------ ------
Williams Energy Services................ 16 7 11
Anadarko Petroleum Corporation.......... 4 7 10
At December 31, 2003, the amount receivable from Anadarko Petroleum
Corporation was $1.5 million which is included in the caption "Accounts
receivable - trade, net" in the accompanying Consolidated Balance Sheet. The
Company had no accounts receivable - trade, net from Williams Energy Services at
December 31, 2003.
Derivative counterparties. The Company uses credit and other financial
criteria to evaluate the credit standing of, and to select, counterparties to
its derivative instruments. Although the Company does not obtain collateral or
otherwise secure the fair value of its derivative instruments, associated credit
risk is mitigated by the Company's credit risk policies and procedures. As of
December 31, 2003 and 2002, the Company had $7.6 million of derivative assets
for which Enron North America Corp was the Company's counterparty. Associated
therewith, the Company recognized bad debt expense of $.4 million and $6.0
million as components of other expense in the accompanying Consolidated
Statements of Operations during the years ended December 31, 2002 and 2001,
respectively.
NOTE L. Asset Retirement Obligations
As referred to in Note B, the Company adopted the provisions of SFAS 143 on
January 1, 2003. The Company's asset retirement obligations primarily relate to
the future plugging and abandonment of proved properties and related facilities.
The Company does not provide for a market risk premium associated with asset
retirement obligations because a reliable estimate cannot be determined. The
Company has no assets that are legally restricted for purposes of settling asset
retirement obligations. The following table summarizes the Company's asset
retirement obligation transactions recorded in accordance with the provisions of
SFAS 143 during the year ended December 31, 2003 and in accordance with the
provisions of SFAS 19 during the years ended December 31, 2002 and 2001:
Year Ended December 31,
---------------------------------
2003 2002 2001
-------- -------- ---------
(in thousands)
Beginning asset retirement obligations........... $ 34,692 $ 39,461 $ 41,983
Cumulative effect adjustment.................. 23,393 - -
New wells placed on production and
changes in estimates....................... 46,664 293 -
Acquisition liabilities assumed............... 1,791 - 981
Liabilities settled........................... (8,069) (6,832) (3,287)
Accretion expense............................. 5,040 2,562 2,590
Currency translation.......................... 1,525 (792) (2,806)
------- ------- --------
Ending asset retirement obligations ............. $105,036 $ 34,692 $ 39,461
======= ======= ========
72
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2003, 2002 and 2001
NOTE M. Interest and Other Income
The following table provides the components of the Company's interest and
other income during the years ended December 31, 2003, 2002 and 2001:
Year Ended December 31,
--------------------------------
2003 2002 2001
-------- -------- --------
(in thousands)
Kansas ad valorem escrow adjustments (see Note I)..... $ - $ 3,500 $ 1,100
Retirement obligation revaluations.................... 4,410 - -
Excise tax income..................................... 2,369 2,398 4,126
Production payment income............................. - - 5,552
Interest income....................................... 981 642 2,128
Seismic data sales.................................... 424 87 1,841
Foreign exchange gains................................ 657 142 223
Other income.......................................... 3,451 4,453 6,808
------- ------- -------
Total interest and other income.................. $ 12,292 $ 11,222 $ 21,778
======= ======= =======
NOTE N. Asset Divestitures
During the years ended December 31, 2003, 2002 and 2001, the Company
completed asset divestitures for net proceeds of $35.7 million, $118.9 million
and $113.5 million, respectively. Associated therewith, the Company recorded
gains on disposition of assets of $1.3 million, $4.4 million and $7.7 million
during the years ended December 31, 2003, 2002 and 2001, respectively.
Hedge derivative divestitures. During the years ended December 31, 2003,
2002 and 2001, the Company terminated, prior to their scheduled maturity, hedge
derivatives for cash sales proceeds of $18.3 million, $91.3 million and $85.4
million, respectively. Net gains from these divestitures were deferred and are
being amortized over the original contract lives of the terminated derivatives
as reductions to interest expense or increases to oil and gas revenues. See Note
J for more information regarding deferred gains on terminated hedge derivatives.
Available for sale securities divestitures. During the year ended December
31, 2001, the Company sold its remaining 613,250 shares of common stock of an
unaffiliated entity for $12.7 million of cash proceeds and recognized an
associated gain on disposition of assets of $8.1 million.
Other United States divestitures. During the year ended December 31, 2003,
the Company received $15.2 million of cash proceeds from the sale of unproved
property interests and $.9 million of cash proceeds from the sale of other U.S.
corporate assets. Associated with these divestitures, the Company recorded $1.5
million of net gains. During the year ended December 31, 2002, the Company
received $20.9 million of proceeds from the cash settlement of a gas balancing
receivable, $4.7 million from the sale of certain gas properties located in
Oklahoma and $1.8 million from the sale of other corporate assets. Associated
with these divestitures, the Company recorded net gains of $4.2 million.
Other international divestitures. During the year ended December 31, 2001,
the Company received $12.0 million of proceeds from the sale of certain oil
properties in Canada and $.4 million of proceeds from the sale of other
international assets. Associated with these transactions, the Company recognized
a net loss of $.8 million.
73
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2003, 2002 and 2001
NOTE O. Other Expense
The following table provides the components of the Company's other expense
during the years ended December 31, 2003, 2002 and 2001:
Years Ended December 31,
--------------------------------
2003 2002 2001
-------- -------- --------
(in thousands)
Derivative ineffectiveness and mark-to-market
provisions (see Note J)................................ $ 2,831 $ 1,664 $ 11,458
Gas marketing losses (see Note I)......................... 922 2,556 9,850
Foreign currency remeasurement and exchange losses (a).... 2,672 7,623 8,474
Bad debt expense (see Note K)............................. 354 129 6,152
Loss on early extinguishment of debt (see Note E)......... 1,457 22,346 3,753
Kansas ad valorem escrow adjustments (see Note I)......... 1,776 - -
Argentine personal asset tax.............................. 1,996 - -
Other charges............................................. 9,312 5,284 3,654
------- ------- -------
Total other expense.................................. $ 21,320 $ 39,602 $ 43,341
======= ======= =======
- ----------
(a) The Company's operations in Argentina, Canada and Africa periodically
recognize monetary assets and liabilities in currencies other than their
functional currencies (see Note B for information regarding the functional
currencies of subsidiary entities). Associated therewith, the Company
realizes foreign currency remeasurement and transaction gains and losses.
NOTE P. Income Taxes
The Company accounts for income taxes in accordance with the provisions of
Statement of Financial Accounting Standards No. 109, "Accounting for Income
Taxes" ("SFAS 109"). The Company and its eligible subsidiaries file a
consolidated United States federal income tax return. Certain subsidiaries are
not eligible to be included in the consolidated United States federal income tax
return and separate provisions for income taxes have been determined for these
entities or groups of entities. The tax returns and the amount of taxable income
or loss are subject to examination by United States federal, state and foreign
taxing authorities. Current and estimated tax payments of $5.3 million, $2.3
million and $11.7 million were made during the years ended December 31, 2003,
2002 and 2001, respectively.
From 1998 until 2003, the Company maintained a valuation allowance against
a portion of its deferred tax asset position in the United States. SFAS 109
requires that the Company continually assess both positive and negative evidence
to determine whether it is more likely than not that deferred tax assets can be
realized prior to their expiration. In the third quarter of 2003 and as of
December 31, 2003, the Company has concluded that it is more likely than not
that it will realize its gross deferred tax asset position in the United States
after giving consideration to the following specific facts:
o Over the past several years, the Company has been steadily improving its
portfolio of assets, including significant proved reserve discoveries and
follow-up development projects that have recently started to produce.
Specifically, Pioneer completed development activities and began production
operations on its Canyon Express gas project in September 2002 and on its
Company-operated Falcon field gas project in March 2003. The production
performance to-date and the reservoir data that has been accumulated on
these projects provide assurance that these projects will recover the
reserves as predicted.
o During 2003, the Company announced additional Falcon area discoveries in
the Harrier, Tomahawk and Raptor fields and during January 2004, the
Harrier development project was completed and began production operations.
The Company expects first production from the Tomahawk and Raptor fields in
74
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2003, 2002 and 2001
mid-2004. The Company also expects to complete its other significant Gulf
of Mexico development project, Devils Tower, in mid-2004.
o Commodity market supply and demand fundamentals continued to stabilize
during the third and fourth quarters of 2003 as evidenced by quoted futures
prices that suggest that North American gas prices will remain relatively
flat over the next five years and that worldwide oil prices may decline
modestly over that time span compared to relatively high current levels for
each commodity.
o The Company's future revenues are further protected against price declines
through its significant hedging program. The Company has hedged portions of
its oil price risk through 2008 and portions of its gas price risk through
2007. See Note J for information regarding the Company's hedge positions.
o The Company generated record pretax income for the third quarter of 2003
and net income in each of the years ended December 31, 2003, 2002, 2001 and
2000. The Company also generated taxable income during 2003, including the
deduction of 100 percent of its intangible drilling costs. The Company
believes that these trends will continue for the foreseeable future.
o The Company performed various economic evaluations in the third quarter of
2003 to determine if the Company would be able to realize all of its
deferred tax assets, including its net operating loss carryforwards, prior
to any expiration. These evaluations were based on the Company's reserve
projections of existing producing properties and recent discoveries being
developed. These evaluations employed varying price assumptions, some of
which included a significant reduction in commodity prices, and factored in
limitations on the use of the Company's net operating loss carryforwards.
The evaluations did not include assumptions of increases in proved reserves
through future exploration or acquisitions. The evaluations indicated that
the deferred tax assets are realizable in the future.
Accordingly, during the third quarter of 2003, the Company reversed its
remaining valuation allowance in the United States, resulting in the recognition
of a deferred tax benefit of $104.7 million. For 2003 in total, the Company
reversed $197.7 million of United States valuation allowances resulting in a net
deferred tax benefit for the year. Further, the third quarter reversal of the
allowance increased stockholders' equity by $32.6 million as the Company
recognized the tax effects of previous stock option exercises and deferred
hedging gains and losses in other comprehensive income.
Pioneer will continue to monitor Company-specific, oil and gas industry and
worldwide economic factors and will reassess the likelihood that the Company's
net operating loss carryforwards and other deferred tax attributes will be
utilized prior to their expiration. There can be no assurances that facts and
circumstances will not materially change and require the Company to reestablish
a United States deferred tax asset valuation allowance in a future period. As of
December 31, 2003, the Company does not believe there is sufficient positive
evidence to reverse its valuation allowances related to foreign tax
jurisdictions.
75
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2003, 2002 and 2001
During the years ended December 31, 2003, 2002 and 2001, the Company's
income tax provision (benefit) and amounts separately allocated were
attributable to the following items:
Year Ended December 31,
-----------------------------------
2003 2002 2001
---------- --------- ---------
(in thousands)
Income before cumulative effect of change in
accounting principle................................... $ (64,403) $ 5,063 $ 4,016
Cumulative effect of change in accounting principle...... 1,312 - -
Changes in stockholders' equity:
Net deferred hedge gains and losses.................... (51,064) (2,561) 2,293
Tax benefits related to stock-based compensation....... (14,666) - -
Translation adjustment................................. (324) (20) (121)
--------- -------- --------
$ (129,145) $ 2,482 $ 6,188
========= ======== ========
Income tax provision (benefit) attributable to income before cumulative
effect of change in accounting principle consists of the following:
Year Ended December 31,
---------------------------------
2003 2002 2001
--------- --------- ---------
(in thousands)
Current:
U.S. federal............................ $ 100 $ - $ -
U.S. state and local.................... - 209 1,080
Foreign................................. 11,085 2,066 10,585
-------- -------- --------
11,185 2,275 11,665
-------- -------- --------
Deferred:
U.S. federal............................ (69,020) - -
U.S. state and local.................... (7,291) - -
Foreign................................. 723 2,788 (7,649)
-------- -------- --------
(75,588) 2,788 (7,649)
-------- -------- --------
$ (64,403) $ 5,063 $ 4,016
======== ======== ========
Income before income taxes and cumulative effect of change in accounting
principle consists of the following:
Year Ended December 31,
---------------------------------
2003 2002 2001
--------- --------- ---------
(in thousands)
Income before income taxes and cumulative effect of
change in accounting principle:
U.S. federal........................................... $ 335,170 $ 36,475 $ 136,292
Foreign................................................ (4,394) (4,699) (32,280)
-------- -------- --------
$ 330,776 $ 31,776 $ 104,012
======== ======== ========
76
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2003, 2002 and 2001
Reconciliations of the United States federal statutory tax rate to the
Company's effective tax rate for income before cumulative effect of change in
accounting principle are as follows:
2003 2002 2001
------- ------ -------
U.S. federal statutory tax rate................... 35.0 35.0 35.0
U.S. valuation allowance reversal................. (59.8) (44.1) (38.5)
Foreign valuation allowances (a).................. 13.1 28.2 11.2
Rate differential on foreign operations........... (.9) (.5) (3.3)
Argentine inflation adjustment (a)................ (12.4) - -
Other............................................. 5.5 (2.7) (.6)
------- ------- -------
Consolidated effective tax rate................... (19.5) 15.9 3.8
======= ======= =======
- -----------
(a) The Company has applied an inflation adjustment to its 2002 Argentine
income tax return based on developing case law. The Company believes that
it is more likely than not that the adjustment will be denied by the
Argentine taxing authorities and has provided a $40.8 million valuation
allowance against this tax benefit.
The tax effects of temporary differences that give rise to significant
portions of the deferred tax assets and deferred tax liabilities are as follows:
December 31,
-----------------------
2003 2002
--------- ---------
(in thousands)
Deferred tax assets:
Net operating loss carryforwards.............................. $ 300,296 $ 299,495
Alternative minimum tax credit carryforwards.................. 1,457 1,565
Net deferred hedge gains and losses........................... 56,842 41,544
Asset retirement obligations.................................. 29,040 12,402
Other......................................................... 92,561 89,948
-------- --------
Total deferred tax assets................................... 480,196 444,954
Valuation allowances.......................................... (94,910) (277,217)
-------- --------
Net deferred tax assets..................................... 385,286 167,737
-------- --------
Deferred tax liabilities:
Oil and gas properties, principally due to differences
in basis, depletion and the deduction of intangible
drilling costs for tax purposes............................. 161,532 80,364
Other......................................................... 3,017 5,393
-------- --------
Total deferred tax liabilities.............................. 164,549 85,757
-------- --------
Net deferred tax asset...................................... $ 220,737 $ 81,980
======== ========
At December 31, 2003, the Company had NOLs for United States, Argentine,
Canadian, Gabonese, South African and Tunisian income tax purposes of $746.6
million, $3.9 million, $26.3 million, $17.0 million, $47.7 million and $9.0
million, respectively, which are available to offset future regular taxable
income in each respective tax jurisdiction, if any. Additionally, at December
31, 2003, the Company has alternative minimum tax net operating loss
carryforwards ("AMT NOLs") in the United States of $653.0 million, which are
available to reduce future alternative minimum taxable income, if any. These
carryforwards expire as follows:
77
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2003, 2002 and 2001
U.S. South
--------------------- Argentina Canada Gabon Africa Tunisia
Expiration Date NOL AMT NOL NOL NOL NOL NOL NOL
- --------------- -------- --------- -------- -------- --------- -------- -------
(in thousands)
December 31, 2005.... $ - $ - $ - $ 19,288 $ - $ - $ -
December 31, 2006.... 33,011 27,133 - 7,048 - - -
December 31, 2007.... 181,049 156,447 3,928 - - - -
December 31, 2008.... 102,271 106,558 - - - - -
December 31, 2009.... 37,974 21,551 - - - - -
December 31, 2010.... 25,144 15,253 - - - - -
December 31, 2012.... 68,334 58,723 - - - - -
December 31, 2018.... 127,970 98,604 - - - - -
December 31, 2019.... 142,518 141,355 - - - - -
December 31, 2020.... 14,387 13,449 - - - - -
December 31, 2021.... 13,895 13,895 - - - - -
Indefinite........... - - - - 17,036 47,704 8,980
------- -------- ------- ------- -------- ------- ------
$746,553 $ 652,968 $ 3,928 $ 26,336 $ 17,036 $ 47,704 $ 8,980
======= ======== ======= ======= ======== ======= ======
The Company believes $140.0 million of the U.S. NOLs and AMT NOLs are
subject to Section 382 of the Internal Revenue Code and are limited in each
taxable year to approximately $20.0 million.
NOTE Q. Income Per Share Before Cumulative Effect of Change in Accounting
Principle
Basic income per share before cumulative effect of change in accounting
principle is computed by dividing income before cumulative effect of change in
accounting principle by the weighted average number of common shares outstanding
for the period. The computation of diluted income per share before cumulative
effect of change in accounting principle reflects the potential dilution that
could occur if securities or other contracts to issue common stock that are
dilutive to income before cumulative effect of change in accounting principle
were exercised or converted into common stock or resulted in the issuance of
common stock that would then share in the earnings of the Company.
The following table is a reconciliation of the basic and diluted weighted
average common shares outstanding for the years ended December 31, 2003, 2002
and 2001:
Year Ended December 31,
--------------------------------
2003 2002 2001
-------- -------- --------
(in thousands)
Weighted average common shares outstanding:
Basic............................................ 117,185 112,542 98,529
Dilutive common stock options (a)................ 1,112 1,725 1,185
Restricted stock awards.......................... 216 21 -
-------- -------- --------
Diluted.......................................... 118,513 114,288 99,714
======== ======== ========
- ---------------
(a) Common stock options to purchase 976,506 shares, 1,925,743 shares and
3,595,880 shares of common stock were outstanding but not included in the
computations of diluted net income per share for the years ended December
31, 2003, 2002 and 2001, respectively, because the exercise prices of the
options were greater than the average market price of the common shares and
would be anti-dilutive to the computations.
78
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2003, 2002 and 2001
NOTE R. Geographic Operating Segment Information
The Company has operations in only one industry segment, that being the oil
and gas exploration and production industry; however, the Company is
organizationally structured along geographic operating segments, or regions. The
Company has reportable operations in the United States, Argentina and Canada.
Other foreign is primarily comprised of operations in Gabon, South Africa and
Tunisia.
The following table provides the geographic operating segment data required
by Statement of Financial Accounting Standards No. 131, "Disclosure about
Segments of an Enterprise and Related Information", as well as results of
operations of oil and gas producing activities required by Statement of
Financial Accounting Standards No. 69, "Disclosures about Oil and Gas Producing
Activities" as of and for the years ended December 31, 2003, 2002 and 2001.
Geographic operating segment income tax benefits (provisions) have been
determined based on statutory rates existing in the various tax jurisdictions
where the Company has oil and gas producing activities. The "Headquarters and
Other" table column includes revenues, expenses, additions to properties, plants
and equipment and assets that are not routinely included in the earnings
measures or attributes internally reported to management on a geographic
operating segment basis.
79
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2003, 2002 and 2001
United Other Headquarters Consolidated
States Argentina Canada Foreign and Other Total
----------- --------- -------- --------- ------------ ------------
(in thousands)
Year Ended December 31, 2003:
Oil and gas revenues................... $ 1,097,365 $ 111,315 $ 68,624 $ 21,343 $ - $1,298,647
Interest and other..................... - - - - 12,292 12,292
Gain (loss) on disposition of
assets, net.......................... 1,458 - 1 - (203) 1,256
---------- -------- ------ ------- --------- ---------
1,098,823 111,315 68,625 21,343 12,089 1,312,195
---------- -------- ------- ------- --------- ---------
Oil and gas production................. 237,484 26,110 13,045 2,887 - 279,526
Depletion, depreciation and
amortization......................... 298,005 46,518 28,991 7,729 9,597 390,840
Exploration and abandonments........... 72,732 18,076 17,691 24,261 - 132,760
General and administrative............. - - - - 60,545 60,545
Accretion of discount on asset
retirement obligations............... - - - - 5,040 5,040
Interest............................... - - - - 91,388 91,388
Other.................................. - - - - 21,320 21,320
---------- -------- ------- ------- --------- ---------
608,221 90,704 59,727 34,877 187,890 981,419
---------- -------- ------- ------- --------- ---------
Income (loss) before income taxes and
cumulative effect of change in
accounting principle................. 490,602 20,611 8,898 (13,534) (175,801) 330,776
Income tax benefit (provision)......... (179,070) (7,214) (3,426) 4,738 249,375 64,403
---------- -------- ------- ------- --------- ---------
Income (loss) before cumulative effect
of change in accounting principle.... $ 311,532 $ 13,397 $ 5,472 $ (8,796) $ 73,574 $ 395,179
========== ======== ======= ======= ========= =========
Cost incurred for long-lived assets.... $ 563,013 $ 52,138 $ 53,030 $ 54,819 $ - $ 723,000
========== ======== ======= ======= ========= =========
Segment assets (as of December 31,
2003)................................ $ 2,631,240 $ 689,781 $224,925 $159,747 $ 245,879 $3,951,572
========== ======== ======= ======= ========= =========
Year Ended December 31, 2002:
Oil and gas revenues................... $ 573,289 $ 77,615 $ 50,876 $ - $ - $ 701,780
Interest and other..................... - - - - 11,222 11,222
Gain (loss) on disposition of
assets, net.......................... 3,248 (3) 995 - 192 4,432
---------- -------- ------- ------- --------- ---------
576,537 77,612 51,871 - 11,414 717,434
---------- -------- ------- ------- --------- ---------
Oil and gas production................. 174,929 13,870 10,771 - - 199,570
Depletion, depreciation and
amortization......................... 140,107 39,659 27,857 - 8,752 216,375
Exploration and abandonments........... 62,955 10,306 5,841 6,792 - 85,894
General and administrative............. - - - - 48,402 48,402
Interest............................... - - - - 95,815 95,815
Other.................................. - - - - 39,602 39,602
---------- -------- ------- ------- --------- ---------
377,991 63,835 44,469 6,792 192,571 685,658
---------- -------- ------- ------- --------- ---------
Income (loss) before income taxes...... 198,546 13,777 7,402 (6,792) (181,157) 31,776
Income tax benefit (provision)......... (69,491) (4,822) (3,118) 2,377 69,991 (5,063)
---------- -------- ------- ------- --------- ---------
Net income (loss)...................... $ 129,055 $ 8,955 $ 4,284 $ (4,415) $ (111,166) $ 26,713
========== ======== ======= ======= ========= =========
Cost incurred for long-lived assets.... $ 533,560 $ 35,121 $ 33,506 $ 70,268 $ - $ 672,455
========== ======== ======= ======= ========= =========
Segment assets (as of December 31,
2002)................................ $ 2,375,505 $ 680,063 $176,110 $118,070 $ 105,368 $3,455,116
========== ======== ======= ======= ========= =========
Year Ended December 31, 2001:
Oil and gas revenues................... $ 649,635 $ 130,241 $ 67,146 $ - $ - $ 847,022
Interest and other..................... - - - - 21,778 21,778
Gain (loss) on disposition of
assets, net.......................... 224 - (1,339) - 8,796 7,681
---------- -------- ------- ------- --------- ---------
649,859 130,241 65,807 - 30,574 876,481
---------- -------- ------- ------- --------- ---------
Oil and gas production................. 170,578 26,614 12,472 - - 209,664
Depletion, depreciation and
amortization......................... 128,477 51,391 28,868 - 13,896 222,632
Exploration and abandonments........... 70,049 23,857 9,882 24,118 - 127,906
General and administrative............. - - - - 36,968 36,968
Interest............................... - - - - 131,958 131,958
Other.................................. - - - - 43,341 43,341
---------- -------- ------- ------- --------- ---------
369,104 101,862 51,222 24,118 226,163 772,469
---------- -------- ------- ------- --------- ---------
Income (loss) before income taxes...... 280,755 28,379 14,585 (24,118) (195,589) 104,012
Income tax benefit (provision)......... (98,264) (9,933) (6,216) 8,441 101,956 (4,016)
---------- -------- ------- ------- --------- ---------
Net income (loss)...................... $ 182,491 $ 18,446 $ 8,369 $(15,677) $ (93,633) $ 99,996
========== ======== ======= ======= ========= =========
Cost incurred for long-lived assets.... $ 454,229 $ 98,311 $ 36,048 $ 57,972 $ - $ 646,560
========== ======== ======= ======= ========= =========
Segment assets (as of December 31,
2001)................................ $ 2,212,540 $ 710,702 $187,841 $ 53,314 $ 106,656 $3,271,053
========== ======== ======= ======= ========= =========
80
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2003, 2002 and 2001
NOTE S. Pioneer USA
Pioneer USA is a wholly-owned subsidiary of the Company that has fully and
unconditionally guaranteed certain debt securities of the Company (see Note E
above). In accordance with practices accepted by the SEC, the Company has
prepared Consolidating Condensed Financial Statements in order to quantify the
assets and results of operations of Pioneer USA as a subsidiary guarantor. The
following Consolidating Condensed Balance Sheets as of December 31, 2003 and
2002, and Consolidating Statements of Operations and Comprehensive Income (Loss)
and Consolidating Condensed Statements of Cash Flows for the years ended
December 31, 2003, 2002 and 2001 present financial information for Pioneer
Natural Resources Company as the Parent on a stand-alone basis (carrying any
investments in subsidiaries under the equity method), financial information for
Pioneer USA on a stand-alone basis (carrying any investment in non-guarantor
subsidiaries under the equity method), financial information for the
non-guarantor subsidiaries of the Company on a consolidated basis, the
consolidation and elimination entries necessary to arrive at the information for
the Company on a consolidated basis, and the financial information for the
Company on a consolidated basis. Pioneer USA is not restricted from making
distributions to the Company.
81
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2003, 2002 and 2001
CONSOLIDATING CONDENSED BALANCE SHEET
As of December 31, 2003
(in thousands)
Non-
Pioneer Guarantor Consolidated
Parent USA Subsidiaries Eliminations Total
----------- ---------- ------------ ------------ -----------
ASSETS
Current assets:
Cash and cash equivalents............... $ 369 $ 4,225 $ 14,705 $ - $ 19,299
Other current assets, net............... 1,654,575 (1,354,256) (114,503) - 185,816
---------- ---------- --------- ---------- ----------
Total current assets................ 1,654,944 (1,350,031) (99,798) - 205,115
---------- ---------- --------- ---------- ----------
Property, plant and equipment, at cost:
Oil and gas properties, using the
successful efforts method of accounting:
Proved properties..................... - 3,508,365 1,475,193 - 4,983,558
Unproved properties................... - 25,460 154,365 - 179,825
Accumulated depletion, depreciation and
amortization.......................... - (1,208,700) (467,436) - (1,676,136)
---------- ---------- --------- ---------- ----------
Total property, plant and equipment - 2,325,125 1,162,122 - 3,487,247
---------- ---------- ---------- ---------- ----------
Deferred income taxes..................... 190,492 - 1,852 - 192,344
Other property and equipment, net......... - 23,890 4,190 - 28,080
Other assets, net......................... 14,836 17,076 6,874 - 38,786
Investment in subsidiaries................ 1,604,534 167,515 - (1,772,049) -
---------- ---------- --------- ---------- ----------
$ 3,464,806 $ 1,183,575 $1,075,240 $(1,772,049) $ 3,951,572
========== ========== ========= ========== ==========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities....................... $ 29,978 $ 347,720 $ 52,054 $ - $ 429,752
Long-term debt............................ 1,555,461 - - - 1,555,461
Other liabilities......................... - 226,055 (31,589) - 194,466
Deferred income taxes..................... - - 12,121 - 12,121
Stockholders' equity...................... 1,879,367 609,800 1,042,654 (1,772,049) 1,759,772
Commitments and contingencies.............
---------- ---------- --------- ---------- ----------
$ 3,464,806 $ 1,183,575 $1,075,240 $(1,772,049) $ 3,951,572
========== ========== ========= ========== ==========
CONSOLIDATING CONDENSED BALANCE SHEET
As of December 31, 2002
(in thousands)
Non-
Pioneer Guarantor Consolidated
Parent USA Subsidiaries Eliminations Total
----------- ---------- ------------ ------------ -----------
ASSETS
Current assets:
Cash and cash equivalents............... $ 6 $ 1,783 $ 6,701 $ - $ 8,490
Other current assets, net............... 1,727,828 (1,480,657) (108,568) - 138,603
---------- ---------- --------- ---------- ----------
Total current assets.................. 1,727,834 (1,478,874) (101,867) - 147,093
---------- ---------- --------- ---------- ----------
Property, plant and equipment, at cost:
Oil and gas properties, using the
successful efforts method of accounting:
Proved properties..................... - 3,024,845 1,228,052 - 4,252,897
Unproved properties................... - 43,969 175,104 - 219,073
Accumulated depletion, depreciation and
amortization ........................ - (947,091) (356,450) - (1,303,541)
---------- ---------- --------- ---------- ----------
Total property, plant and equipment - 2,121,723 1,046,706 - 3,168,429
---------- ---------- --------- ---------- ----------
Deferred income taxes..................... 75,311 - 1,529 - 76,840
Other property and equipment, net......... - 19,000 3,784 - 22,784
Other assets, net......................... 16,067 14,231 9,672 - 39,970
Investment in subsidiaries................ 1,247,042 136,159 - (1,383,201) -
---------- ---------- --------- ---------- ----------
$ 3,066,254 $ 812,239 $ 959,824 $(1,383,201) $ 3,455,116
========== ========== ========= ========== ==========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities....................... $ 30,785 $ 216,065 $ 27,742 $ - $ 274,592
Long-term debt............................ 1,668,536 - - - 1,668,536
Other liabilities......................... - 147,970 (19,639) - 128,331
Deferred income taxes..................... - - 8,760 - 8,760
Stockholders' equity...................... 1,366,933 448,204 942,961 (1,383,201) 1,374,897
Commitments and contingencies.............
---------- ---------- --------- ---------- ----------
$ 3,066,254 $ 812,239 $ 959,824 $(1,383,201) $ 3,455,116
========== ========== ========= ========== ==========
82
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2003, 2002 and 2001
CONSOLIDATING CONDENSED STATEMENT OF OPERATIONS
AND COMPREHENSIVE INCOME (LOSS)
For the Year Ended December 31, 2003
(in thousands)
Non- Consolidated
Pioneer Guarantor Income Tax Consolidated
Parent USA Subsidiaries Provision Eliminations Total
---------- ---------- ------------ ----------- ------------ -----------
Revenues and other income:
Oil and gas........................... $ - $1,008,668 $ 289,979 $ - $ - $1,298,647
Interest and other.................... - 7,303 4,989 - - 12,292
Gain (loss) on disposition of
assets, net......................... - 1,403 (147) - - 1,256
--------- --------- -------- --------- -------- ---------
- 1,017,374 294,821 - - 1,312,195
--------- --------- -------- --------- -------- ---------
Costs and expenses:
Oil and gas production................ - 215,886 63,640 - - 279,526
Depletion, depreciation and
amortization........................ - 293,665 97,175 - - 390,840
Exploration and abandonments.......... - 71,391 61,369 - - 132,760
General and administrative............ 971 47,763 11,811 - - 60,545
Accretion of discount on asset
retirement obligations.............. - 3,804 1,236 - - 5,040
Interest.............................. 23,964 66,012 1,412 - - 91,388
Equity (income) loss from subsidiary.. (362,094) 17,024 - - 345,070 -
Other................................. 1,465 7,387 12,468 - - 21,320
--------- --------- -------- --------- -------- ---------
(335,694) 722,932 249,111 - 345,070 981,419
--------- --------- -------- --------- -------- ---------
Income before income taxes and
cumulative effect of change in
accounting principle.................. 335,694 294,442 45,710 - (345,070) 330,776
Income tax benefit (provision).......... - - (10,495) 74,898 - 64,403
--------- --------- -------- --------- -------- ---------
Income before cumulative effect of
change in accounting principle........ 335,694 294,442 35,215 74,898 (345,070) 395,179
Cumulative effect of change in
accounting principle, net of tax...... - 11,859 3,554 - - 15,413
--------- --------- -------- --------- -------- ---------
Net income.............................. 335,694 306,301 38,769 74,898 (345,070) 410,592
Other comprehensive income (loss):
Net deferred hedge gains (losses),
net of tax:
Net deferred hedge losses........... - (265,142) (17,023) - - (282,165)
Tax benefits related to net deferred
hedge losses..................... - - 249 50,815 - 51,064
Net hedge losses included in net
income........................... - 109,223 8,193 - - 117,416
Translation adjustment................ - - 36,938 - - 36,938
--------- --------- -------- --------- -------- ---------
Comprehensive income (loss)............. $ 335,694 $ 150,382 $ 67,126 $ 125,713 $(345,070) $ 333,845
========= ========= ======== ========= ======== =========
83
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2003, 2002 and 2001
CONSOLIDATING CONDENSED STATEMENT OF OPERATIONS
AND COMPREHENSIVE INCOME (LOSS)
For the Year Ended December 31, 2002
(in thousands)
Non- Consolidated
Pioneer Guarantor Income Tax Consolidated
Parent USA Subsidiaries Provision Eliminations Total
---------- ---------- ------------ ----------- ------------ -----------
Revenues and other income:
Oil and gas........................... $ - $ 527,189 $ 174,591 $ - $ - $ 701,780
Interest and other.................... - 8,214 3,008 - - 11,222
Gain on disposition of assets, net.... - 3,230 1,202 - - 4,432
--------- --------- -------- -------- ------- ---------
- 538,633 178,801 - - 717,434
--------- --------- -------- -------- ------- ---------
Costs and expenses:
Oil and gas production................ - 165,669 33,901 - - 199,570
Depletion, depreciation and
amortization........................ - 139,822 76,553 - - 216,375
Exploration and abandonments.......... - 62,982 22,912 - - 85,894
General and administrative............ 1,323 37,723 9,356 - - 48,402
Interest.............................. 17,451 76,820 1,544 - - 95,815
Equity (income) loss from subsidiary.. (52,580) 8,374 - - 44,206 -
Other................................. 7,093 4,879 27,630 - - 39,602
--------- --------- -------- -------- ------- ---------
(26,713) 496,269 171,896 - 44,206 685,658
--------- --------- -------- -------- ------- ---------
Income before income taxes.............. 26,713 42,364 6,905 - (44,206) 31,776
Income tax provision.................... - - (5,063) - - (5,063)
--------- --------- -------- -------- ------- ---------
Net income.............................. 26,713 42,364 1,842 - (44,206) 26,713
Other comprehensive income (loss):
Net deferred hedge gains (losses):
Net deferred hedge losses........... (4) (156,396) (25,228) - - (181,628)
Tax benefits related to net deferred
hedge losses...................... - - 2,561 - - 2,561
Net hedge (gains) losses included in
net income........................ 447 (10,352) (2,519) - - (12,424)
Translation adjustment................ - - 2,188 - - 2,188
--------- --------- -------- -------- ------- ---------
Comprehensive income (loss)............. $ 27,156 $ (124,384) $ (21,156) $ - $(44,206) $ (162,590)
========= ========= ======== ======== ======= =========
84
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2003, 2002 and 2001
CONSOLIDATING CONDENSED STATEMENT OF OPERATIONS
AND COMPREHENSIVE INCOME (LOSS)
For the Year Ended December 31, 2001
(in thousands)
Non- Consolidated
Pioneer Guarantor Income Tax Consolidated
Parent USA Subsidiaries Provision Eliminations Total
---------- ---------- ------------ ----------- ------------ -----------
Revenues and other income:
Oil and gas........................... $ - $ 626,964 $ 220,058 $ - $ - $ 847,022
Interest and other.................... 368 14,415 6,995 - - 21,778
Gain (loss) on disposition of
assets, net......................... - 8,524 (843) - - 7,681
--------- --------- -------- -------- -------- ---------
368 649,903 226,210 - - 876,481
--------- --------- -------- -------- -------- ---------
Costs and expenses:
Oil and gas production................ - 168,287 41,377 - - 209,664
Depletion, depreciation and
amortization........................ - 135,838 86,794 - - 222,632
Exploration and abandonments.......... - 73,649 54,257 - - 127,906
General and administrative............ 804 25,476 10,688 - - 36,968
Interest.............................. 31,261 83,473 17,224 - - 131,958
Equity (income) loss from subsidiary.. (135,459) 5,588 - - 129,871 -
Other................................. 3,753 9,247 30,341 - - 43,341
--------- --------- -------- -------- -------- ---------
(99,641) 501,558 240,681 - 129,871 772,469
--------- --------- -------- -------- -------- ---------
Income (loss) before income taxes....... 100,009 148,345 (14,471) - (129,871) 104,012
Income tax provision.................... - (783) (3,220) (13) - (4,016)
--------- --------- -------- -------- -------- ---------
Net income (loss)....................... 100,009 147,562 (17,691) (13) (129,871) 99,996
Other comprehensive income (loss):
Net deferred hedge gains (losses):
Transition adjustment............... - (172,007) (25,437) - - (197,444)
Net deferred hedge gains (losses)... (578) 364,051 31,824 - - 395,297
Tax provisions related to net
deferred hedge gains.............. - - (2,293) - - (2,293)
Net hedge (gains) losses included in
net income available for sale
securities........................ 135 (8,595) 13,946 - - 5,486
Net unrealized gains (losses) on
available for sale securities:
Net unrealized available for sale
securities holding losses......... - (45) - - - (45)
Net available for sale securities
gains included in net income...... - (8,109) - - - (8,109)
Translation adjustment................ - - (11,173) - - (11,173)
--------- --------- -------- -------- -------- ---------
Comprehensive income (loss)............. $ 99,566 $ 322,857 $ (10,824) $ (13) $(129,871) $ 281,715
========= ========= ======== ======== ======== =========
85
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2003, 2002 and 2001
CONSOLIDATING CONDENSED STATEMENT OF CASH FLOWS
For the Year Ended December 31, 2003
(in thousands)
Non-
Pioneer Guarantor Consolidated
Parent USA Subsidiaries Total
---------- ---------- ------------ ------------
Cash flows from operating activities:
Net cash provided by operating activities................ $ 59,761 $ 491,890 $ 212,028 $ 763,679
--------- --------- --------- ----------
Cash flows from investing activities:
Proceeds from disposition of assets...................... 18,267 16,749 682 35,698
Additions to oil and gas properties...................... - (478,280) (209,853) (688,133)
Other property (additions) dispositions, net............. - (14,748) 4,883 (9,865)
--------- --------- --------- ----------
Net cash provided by (used in) investing
activities...................................... 18,267 (476,279) (204,288) (662,300)
--------- --------- --------- ----------
Cash flows from financing activities:
Borrowings under long-term debt.......................... 264,725 - - 264,725
Principal payments on long-term debt..................... (370,262) - - (370,262)
Payment of other liabilities............................. - (13,169) (886) (14,055)
Deferred loan fees....................................... (2,799) - - (2,799)
Purchase of treasury stock............................... (2,349) - - (2,349)
Stock options exercised and employee stock purchases..... 33,020 - - 33,020
--------- --------- --------- ----------
Net cash used in financing activities............. (77,665) (13,169) (886) (91,720)
--------- --------- --------- ----------
Net increase in cash and cash equivalents.................. 363 2,442 6,854 9,659
Effect of exchange rate changes on cash and cash
equivalents.............................................. - - 1,150 1,150
Cash and cash equivalents, beginning of period............. 6 1,783 6,701 8,490
--------- --------- --------- ----------
Cash and cash equivalents, end of period................... $ 369 $ 4,225 $ 14,705 $ 19,299
========= ========= ========= ==========
CONSOLIDATED CONDENSED STATEMENT OF CASH FLOWS
For the Year Ended December 31, 2002
(in thousands)
Non-
Pioneer Guarantor Consolidated
Parent USA Subsidiaries Total
---------- ---------- ------------ ------------
Cash flows from operating activities:
Net cash provided by (used in) operating activities...... $ (327,185) $ 406,939 $ 252,491 $ 332,245
--------- --------- --------- ----------
Cash flows from investing activities:
Proceeds from disposition of assets...................... 31,994 86,703 153 118,850
Additions to oil and gas properties...................... - (365,981) (248,717) (614,698)
Other property (additions) dispositions, net............. - (13,171) 888 (12,283)
--------- --------- --------- ----------
Net cash provided by (used in) investing activities.. 31,994 (292,449) (247,676) (508,131)
--------- --------- --------- ----------
Cash flows from financing activities:
Borrowings under long-term debt.......................... 529,805 - - 529,805
Principal payments on long-term debt..................... (481,783) - - (481,783)
Common stock issuance proceeds, net of issuance costs.... 236,000 - - 236,000
Payment of other liabilities............................. - (123,607) (638) (124,245)
Deferred loan fees/issuance costs........................ (3,293) - - (3,293)
Stock options exercised and employee stock purchases..... 14,389 - - 14,389
--------- --------- --------- ----------
Net cash provided by (used in) financing activities.. 295,118 (123,607) (638) 170,873
--------- --------- --------- ----------
Net increase (decrease) in cash and cash equivalents....... (73) (9,117) 4,177 (5,013)
Effect of exchange rate changes on cash and cash
equivalents.............................................. - - (831) (831)
Cash and cash equivalents, beginning of period............. 79 10,900 3,355 14,334
--------- --------- --------- ----------
Cash and cash equivalents, end of period................... $ 6 $ 1,783 $ 6,701 $ 8,490
========= ========= ========= ==========
86
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2001, 2000 and 1999
CONSOLIDATING CONDENSED STATEMENT OF CASH FLOWS
For the Year Ended December 31, 2001
(in thousands)
Non-
Pioneer Guarantor Consolidated
Parent USA Subsidiaries Total
---------- ---------- ------------ ------------
Cash flows from operating activities:
Net cash provided by (used in) operating activities...... $ (10,503) $ 307,776 $ 178,327 $ 475,600
--------- --------- --------- ----------
Cash flows from investing activities:
Cash acquired in acquisition, net of fees paid........... - 11,119 - 11,119
Proceeds from disposition of assets...................... 21,170 75,816 16,467 113,453
Additions to oil and gas properties...................... - (336,753) (192,970) (529,723)
Other property additions, net............................ - (10,717) (6,873) (17,590)
--------- --------- --------- ----------
Net cash provided by (used in) investing activities.. 21,170 (260,535) (183,376) (422,741)
--------- --------- --------- ----------
Cash flows from financing activities:
Borrowings under long-term debt.......................... 328,331 - - 328,331
Principal payments on long-term debt..................... (333,410) - - (333,410)
Borrowing under (payment of) other liabilities........... - (54,728) 1,291 (53,437)
Purchase of treasury stock............................... (13,028) - - (13,028)
Stock options exercised and employee stock purchases..... 7,504 - - 7,504
--------- --------- --------- ----------
Net cash provided by (used in) financing activities.. (10,603) (54,728) 1,291 (64,040)
--------- --------- --------- ----------
Net increase (decrease) in cash and cash equivalents....... 64 (7,487) (3,758) (11,181)
Effect of exchange rate changes on cash and cash
equivalents.............................................. - - (644) (644)
Cash and cash equivalents, beginning of period............. 15 18,387 7,757 26,159
--------- --------- --------- ----------
Cash and cash equivalents, end of period................... $ 79 $ 10,900 $ 3,355 $ 14,334
========= ========= ========= ==========
87
PIONEER NATURAL RESOURCES COMPANY
UNAUDITED SUPPLEMENTARY INFORMATION
Years Ended December 31, 2003, 2002 and 2001
Capitalized Costs
December 31,
----------------------------
2003 2002
----------- -----------
(in thousands)
Oil and Gas Properties:
Proved.......................................................... $ 4,983,558 $ 4,252,897
Unproved........................................................ 179,825 219,073
---------- ----------
Capitalized costs for oil and gas properties.................... 5,163,383 4,471,970
Less accumulated depletion...................................... (1,676,136) (1,303,541)
----------- -----------
Net capitalized costs for oil and gas properties................ $ 3,487,247 $ 3,168,429
========== ==========
Costs Incurred for Oil and Gas Producing Activities (a)
Property
Acquisition Costs Total
----------------------- Exploration Development Costs
Proved Unproved Costs Costs Incurred
--------- --------- ---------- ------------ ---------
(in thousands)
Year Ended December 31, 2003:
United States...................... $ 130,876 $ 12,264 $ 191,809 $ 228,064 $ 563,013
Argentina.......................... 97 1,787 24,893 25,361 52,138
Canada............................. 63 5,028 24,899 23,040 53,030
Africa and other................... - 910 33,212 20,697 54,819
-------- -------- -------- -------- --------
Total costs incurred............. $ 131,036 $ 19,989 $ 274,813 $ 297,162 $ 723,000
======== ======== ======== ======== ========
Year Ended December 31, 2002:
United States...................... $ 156,736 $ 34,048 $ 72,831 $ 269,945 $ 533,560
Argentina.......................... 12 51 14,530 20,528 35,121
Canada............................. 457 2,329 9,992 20,728 33,506
Africa and other................... - 1,843 34,125 34,300 70,268
-------- -------- -------- -------- --------
Total costs incurred............. $ 157,205 $ 38,271 $ 131,478 $ 345,501 $ 672,455
======== ======== ======== ======== ========
Year Ended December 31, 2001:
United States...................... $ 132,793 $ 19,572 $ 129,639 $ 172,225 $ 454,229
Argentina.......................... 13,182 2,465 36,237 46,427 98,311
Canada............................. 29 97 12,707 23,215 36,048
Africa and other................... 706 1,960 41,446 13,860 57,972
-------- -------- -------- -------- --------
Total costs incurred............. $ 146,710 $ 24,094 $ 220,029 $ 255,727 $ 646,560
======== ======== ======== ======== ========
- -------------
(a) The Company has not included asset retirement obligation accruals in the
costs incurred for oil and gas producing activities presented in the table
above. During the years ended December 31, 2003 and 2001, the Company
accrued $46.7 million and $1.0 million of asset retirement obligations,
respectively, associated with new wells and changes in estimates. The
Company did not accrue any increases to asset retirement obligations during
the year ended December 31, 2002. See Notes B and L for additional
information regarding the Company's asset retirement obligations.
88
PIONEER NATURAL RESOURCES COMPANY
UNAUDITED SUPPLEMENTARY INFORMATION
Years Ended December 31, 2003, 2002 and 2001
Results of Operations
Information about the Company's results of operations for oil and gas
producing activities by geographic operating segment is presented in Note R of
the accompanying Notes to Consolidated Financial Statements.
Reserve Quantity Information
The estimates of the Company's proved oil and gas reserves as of December
31, 2003 and 2002, which are located in the United States, Argentina, Canada,
Gabon, South Africa and Tunisia, were based on evaluations audited by
independent petroleum engineers with respect to the Company's major properties
and prepared by the Company's engineers with respect to all other properties.
The estimates of the Company's proved oil and gas reserves as of December 31,
2001 were prepared by the Company's engineers. Reserves were estimated in
accordance with guidelines established by the SEC and the Financial Accounting
Standards Board, which require that reserve estimates be prepared under existing
economic and operating conditions with no provision for price and cost
escalations except by contractual arrangements. The reserve estimates as of
December 31, 2003, 2002 and 2001 utilize respective oil prices of $31.10, $29.67
and $18.88 per Bbl (reflecting adjustments for oil quality), respective NGL
prices of $20.26, $19.01 and $11.58 per Bbl, and respective gas prices of $4.23,
$3.37 and $2.21 per Mcf (reflecting adjustments for Btu content, gas processing
and shrinkage).
Oil and gas reserve quantity estimates are subject to numerous
uncertainties inherent in the estimation of quantities of proved reserves and in
the projection of future rates of production and the timing of development
expenditures. The accuracy of such estimates is a function of the quality of
available data and of engineering and geological interpretation and judgment.
Results of subsequent drilling, testing and production may cause either upward
or downward revision of previous estimates. Further, the volumes considered to
be commercially recoverable fluctuate with changes in prices and operating
costs. The Company emphasizes that reserve estimates are inherently imprecise
and that estimates of new discoveries are more imprecise than those of currently
producing oil and gas properties. Accordingly, these estimates are expected to
change as additional information becomes available in the future.
The following table provides a rollforward of total proved reserves by
geographic area and in total for the years ended December 31, 2003, 2002 and
2001, as well as proved developed reserves by geographic area and in total as of
the beginning and end of each respective year:
89
PIONEER NATURAL RESOURCES COMPANY
UNAUDITED SUPPLEMENTARY INFORMATION
Years Ended December 31, 2003, 2002 and 2001
Oil and Gas Producing Activities:
2003 2002 2001
------------------------------ ----------------------------- -----------------------------
Oil Oil Oil
& NGLs Gas & NGLs Gas & NGLs Gas
Total Proved Reserves: (MBbls) (MMcf) MBOE (MBbls) (MMcf) MBOE (MBbls) (MMcf) MBOE
-------- --------- ------- -------- --------- ------ ------- --------- -------
UNITED STATES
Balance, January 1............... 337,631 1,483,971 584,960 279,146 1,474,090 524,829 266,802 1,354,327 492,523
Revisions of previous estimates.. 36,823 94,759 52,616 61,529 5,983 62,525 (1,179) 41,039 5,661
Purchases of minerals-in-place... 4,422 57,124 13,942 8,634 83,361 22,528 24,943 63,113 35,462
New discoveries and extensions... 250 80,769 13,712 4,364 5,349 5,255 4,442 93,220 19,979
Production....................... (16,375) (162,647) (43,483) (16,042) (84,812) (30,177) (15,862) (77,609) (28,796)
-------- --------- ------- ------- --------- ------- ------- --------- -------
Balance, December 31............. 362,751 1,553,976 621,747 337,631 1,483,971 584,960 279,146 1,474,090 524,829
ARGENTINA
Balance, January 1............... 31,532 532,081 120,211 35,669 471,150 114,193 35,843 408,282 103,890
Revisions of previous estimates.. 2,027 44,064 9,372 (4,954) 47,829 3,017 (932) 4,460 (189)
Purchases of minerals-in-place... - - - - - - 170 31,700 5,453
New discoveries and extensions... 3,562 8,068 4,907 3,985 41,652 10,927 4,354 58,538 14,110
Production....................... (3,652) (34,357) (9,378) (3,168) (28,550) (7,926) (3,766) (31,830) (9,071)
-------- --------- ------- -------- --------- ------- ------- -------- -------
Balance, December 31............. 33,469 549,856 125,112 31,532 532,081 120,211 35,669 471,150 114,193
CANADA
Balance, January 1............... 2,361 119,328 22,249 2,659 132,061 24,669 4,066 132,919 26,219
Revisions of previous estimates.. 344 (14,920) (2,143) 24 (1,150) (167) 212 15,067 2,723
New discoveries and extensions... 73 4,630 845 68 6,070 1,080 81 5,644 1,022
Production....................... (371) (15,209) (2,906) (390) (17,653) (3,333) (671) (18,426) (3,742)
Sales of minerals-in-place....... - - - - - - (1,029) (3,143) (1,553)
-------- --------- ------- -------- --------- ------- ------- --------- -------
Balance, December 31............. 2,407 93,829 18,045 2,361 119,328 22,249 2,659 132,061 24,669
AFRICA
Balance, January 1............... 9,320 - 9,320 7,685 - 7,685 5,552 - 5,552
Revisions of previous estimates.. (1,817) - (1,817) 790 - 790 - - -
Purchases of minerals-in-place... - - - - - - 2,133 - 2,133
New discoveries and extensions... 17,374 - 17,374 845 - 845 - - -
Production....................... (723) - (723) - - - - - -
-------- --------- ------- -------- --------- ------- ------- --------- -------
Balance, December 31............. 24,154 - 24,154 9,320 - 9,320 7,685 - 7,685
TOTAL
Balance, January 1............... 380,844 2,135,380 736,740 325,159 2,077,301 671,376 312,263 1,895,528 628,184
Revisions of previous
estimates (a).................. 37,377 123,903 58,028 57,389 52,662 66,165 (1,899) 60,566 8,195
Purchases of minerals-in-place... 4,422 57,124 13,942 8,634 83,361 22,528 27,246 94,813 43,048
New discoveries and extensions... 21,259 93,467 36,838 9,262 53,071 18,107 8,877 157,402 35,111
Production....................... (21,121) (212,213) (56,490) (19,600) (131,015) (41,436) (20,299) (127,865) (41,609)
Sales of minerals-in-place....... - - - - - - (1,029) (3,143) (1,553)
-------- --------- ------- -------- --------- ------- ------- --------- --------
Balance, December 31............. 422,781 2,197,661 789,058 380,844 2,135,380 736,740 325,159 2,077,301 671,376
======== ========= ======= ======== ========= ======= ======= ========= ========
Proved Developed Reserves:
United States.................. 209,948 1,067,701 387,899 196,893 1,027,750 368,184 206,922 1,081,592 387,188
Argentina...................... 22,180 402,640 89,287 28,248 341,967 85,243 22,679 345,281 80,226
Canada......................... 2,042 90,003 17,042 2,086 94,607 17,854 2,930 80,953 16,422
-------- ---------- ------- -------- --------- ------- ------- --------- --------
January 1.................... 234,170 1,560,344 494,228 227,227 1,464,324 471,281 232,531 1,507,826 483,836
======== ========== ======= ======== ========= ======= ======= ========= ========
United States.................. 209,349 1,202,264 409,727 209,948 1,067,701 387,899 196,893 1,027,750 368,184
Argentina...................... 21,149 352,660 79,926 22,180 402,640 89,287 28,248 341,967 85,243
Canada......................... 2,312 86,500 16,728 2,042 90,003 17,042 2,086 94,607 17,854
Africa......................... 6,817 - 6,817 - - - - - -
-------- ---------- ------- -------- --------- ------- ------- --------- --------
December 31.................. 239,627 1,641,424 513,198 234,170 1,560,344 494,228 227,227 1,464,324 471,281
======== ========== ======= ======== ========= ======= ======= ========= ========
- -------------
(a) The revisions of previous estimates above, include revisions attributable
to changes in commodity prices totaling a 3,429 MBOE increase, a 28,643
MBOE increase and a 24,970 MBOE decrease for the years ended December 31,
2003, 2002 and 2001, respectively.
90
PIONEER NATURAL RESOURCES COMPANY
UNAUDITED SUPPLEMENTARY INFORMATION
Years Ended December 31, 2003, 2002 and 2001
Standardized Measure of Discounted Future Net Cash Flows
The standardized measure of discounted future net cash flows is computed by
applying year-end prices of oil and gas (with consideration of price changes
only to the extent provided by contractual arrangements) to the estimated future
production of proved oil and gas reserves less estimated future expenditures
(based on year-end costs) to be incurred in developing and producing the proved
reserves, discounted using a rate of 10 percent per year to reflect the
estimated timing of the future cash flows. Future income taxes are calculated by
comparing undiscounted future cash flows to the tax basis of oil and gas
properties plus available carryforwards and credits and applying the current tax
rates to the difference. The discounted future cash flow estimates do not
include the effects of the Company's commodity hedging contracts. Utilizing
December 31, 2003 commodity prices held constant over each hedge contract's
term, the net present value of the Company's hedge contracts, less associated
estimated income taxes and discounted at 10 percent, was a liability of
approximately $191.0 million.
Discounted future cash flow estimates like those shown below are not
intended to represent estimates of the fair value of oil and gas properties.
Estimates of fair value should also consider probable reserves, anticipated
future oil and gas prices, interest rates, changes in development and production
costs and risks associated with future production. Because of these and other
considerations, any estimate of fair value is necessarily subjective and
imprecise.
The following tables provide the standardized measure of discounted future
cash flows by geographic area and in total for the years ended December 31,
2003, 2002 and 2001, as well as a rollforward in total for each respective year:
91
PIONEER NATURAL RESOURCES COMPANY
UNAUDITED SUPPLEMENTARY INFORMATION
Years Ended December 31, 2003, 2002 and 2001
Year Ended December 31,
-----------------------------------------
2003 2002 2001
----------- ----------- -----------
(in thousands)
UNITED STATES
Oil and gas producing activities:
Future cash inflows.................................. $18,239,318 $15,161,717 $ 8,222,573
Future production costs.............................. (5,918,790) (4,830,294) (3,231,730)
Future development costs............................. (1,188,394) (864,386) (735,984)
Future income tax expense............................ (3,057,968) (2,325,946) (598,612)
---------- ---------- ----------
8,074,166 7,141,091 3,656,247
10% annual discount factor.............................. (4,276,678) (3,684,400) (1,691,118)
---------- ---------- ----------
Standardized measure of discounted future cash flows.... $ 3,797,488 $ 3,456,691 $ 1,965,129
========== ========== ==========
ARGENTINA
Oil and gas producing activities:
Future cash inflows.................................. $ 1,257,068 $ 986,716 $ 1,070,664
Future production costs.............................. (233,399) (175,938) (227,435)
Future development costs............................. (136,663) (84,669) (144,604)
Future income tax expense............................ (161,683) (143,845) (45,140)
---------- ---------- ----------
725,323 582,264 653,485
10% annual discount factor.............................. (282,205) (242,158) (262,334)
---------- ---------- ----------
Standardized measure of discounted future cash flows.... $ 443,118 $ 340,106 $ 391,151
========== ========== ==========
CANADA
Oil and gas producing activities:
Future cash inflows.................................. $ 520,976 $ 502,260 $ 301,002
Future production costs.............................. (91,675) (89,246) (73,601)
Future development costs............................. (11,551) (22,294) (27,050)
Future income tax expense............................ (72,895) (87,363) (10,771)
---------- ---------- ----------
344,855 303,357 189,580
10% annual discount factor.............................. (126,436) (104,345) (59,995)
---------- ---------- ----------
Standardized measure of discounted future cash flows.... $ 218,419 $ 199,012 $ 129,585
========== ========== ==========
AFRICA
Oil and gas producing activities:
Future cash inflows.................................. $ 713,459 $ 279,896 $ 149,777
Future production costs.............................. (212,615) (95,216) (73,697)
Future development costs............................. (261,413) (26,770) (54,281)
Future income tax expense............................ (17,062) (10,912) -
---------- ---------- ----------
222,369 146,998 21,799
10% annual discount factor.............................. (98,141) (16,255) (7,338)
---------- ---------- ----------
Standardized measure of discounted future cash flows.... $ 124,228 $ 130,743 $ 14,461
========== ========== ==========
TOTAL
Oil and gas producing activities:
Future cash inflows.................................. $20,730,821 $16,930,589 $ 9,744,016
Future production costs.............................. (6,456,479) (5,190,694) (3,606,463)
Future development costs (a)......................... (1,598,021) (998,119) (961,919)
Future income tax expense............................ (3,309,608) (2,568,066) (654,523)
---------- ---------- ----------
9,366,713 8,173,710 4,521,111
10% annual discount factor.............................. (4,783,460) (4,047,158) (2,020,785)
---------- ---------- ----------
Standardized measure of discounted future cash flows.... $ 4,583,253 $ 4,126,552 $ 2,500,326
========== ========== ==========
- -------------
(a) Includes $208.1 million of undiscounted future asset retirement
expenditures estimated as of December 31, 2003 using current estimates of
future abandonment costs. See Notes B and L for corresponding information
regarding the Company's discounted asset retirement obligations.
92
PIONEER NATURAL RESOURCES COMPANY
UNAUDITED SUPPLEMENTARY INFORMATION
Years Ended December 31, 2003, 2002 and 2001
Year Ended December 31,
-----------------------------------------
Oil and Gas Producing Activities 2003 2002 2001
----------- ----------- -----------
(in thousands)
Oil and gas sales, net of production costs.............. $(1,136,520) $ (489,338) $ (631,365)
Net changes in prices and production costs.............. 670,165 2,042,575 (4,528,168)
Extensions and discoveries.............................. 413,777 152,253 184,454
Development costs incurred during the period............ 202,396 262,469 239,156
Sales of minerals-in-place.............................. - - (23,372)
Purchases of minerals-in-place.......................... 198,442 187,460 201,535
Revisions of estimated future development costs......... (444,726) (387,404) (429,365)
Revisions of previous quantity estimates................ 458,468 527,987 40,771
Accretion of discount................................... 514,608 250,033 701,943
Changes in production rates, timing and other........... (71,557) 99,722 (274,689)
---------- --------- ----------
Change in present value of future net revenues.......... 805,053 2,645,757 (4,519,100)
Net change in present value of future income taxes...... (348,352) (1,019,531) 1,373,924
---------- ----------- ----------
456,701 1,626,226 (3,145,176)
Balance, beginning of year.............................. 4,126,552 2,500,326 5,645,502
---------- ---------- ----------
Balance, end of year.................................... $ 4,583,253 $ 4,126,552 $ 2,500,326
========== =========== ==========
Selected Quarterly Financial Results
The following table provides selected quarterly financial results for
the years ended December 31, 2003 and 2002:
Quarter
-------------------------------------------------------
First Second Third (a) Fourth
--------- --------- --------- ---------
(in thousands, except per share data)
2003
Oil and gas revenues......................... $ 281,156 $ 339,954 $ 332,515 $ 345,022
Total revenues and other income.............. $ 285,295 $ 341,318 $ 332,909 $ 352,673
Total costs and expenses..................... $ 214,184 $ 261,503 $ 240,991 $ 264,741
Net income:
Income before cumulative effect of change
in accounting principle................. $ 68,807 $ 77,185 $ 191,813 $ 57,374
Cumulative effect of change in accounting
principle, net of tax................... 15,413 - - -
-------- -------- -------- --------
Net income................................ $ 84,220 $ 77,185 $ 191,813 $ 57,374
======== ======== ======== ========
Net income per share:
Basic:
Income before cumulative effect of change
in accounting principle............... $ .59 $ .66 $ 1.64 $ .49
Cumulative effect of change in accounting
principle, net of tax................. .13 - - -
-------- -------- -------- --------
Net income.............................. $ .72 $ .66 $ 1.64 $ .49
======== ======== ======== ========
Diluted:
Income before cumulative effect of change
in accounting principle............... $ .58 $ .65 $ 1.62 $ .48
Cumulative effect of change in accounting
principle, net of tax................. .13 - - -
-------- -------- -------- --------
Net income.............................. $ .71 $ .65 $ 1.62 $ .48
======== ======== ======== ========
2002
Oil and gas revenues......................... $ 165,539 $ 172,430 $ 168,317 $ 195,494
Total revenues and other income.............. $ 166,658 $ 174,338 $ 178,753 $ 197,685
Total costs and expenses..................... $ 169,027 $ 161,759 $ 177,454 $ 177,418
Net income (loss)............................ $ (1,959) $ 11,142 $ (890) $ 18,420
Net income (loss) per share:
Basic .................................... $ (.02) $ .10 $ (.01) $ .16
======== ======== ======== ========
Diluted................................... $ (.02) $ .10 $ (.01) $ .16
======== ======== ======== ========
- -------------
(a) The Company's third quarter results for 2003 include a $104.7 million
adjustment to reduce United States deferred tax asset valuation allowances.
See Note P for additional information regarding income taxes.
93
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None.
ITEM 9A. CONTROLS AND PROCEDURES
Evaluation of disclosure controls and procedures. The Company's principal
executive officer and principal financial officer have evaluated, as required by
Rule 13a-15(b) under the Securities Exchange Act of 1934 (the "Exchange Act"),
the Company's disclosure controls and procedures (as defined in Exchange Act
Rule 13a-15(e)) as of the end of the period covered by this annual report on
Form 10-K. Based on that evaluation, the principal executive officer and
principal financial officer concluded that the design and operation of the
Company's disclosure controls and procedures are effective in ensuring that
information required to be disclosed by the Company in the reports that it files
or submits under the Exchange Act is recorded, processed, summarized and
reported within the time periods specified in the Securities and Exchange
Commission's rules and forms.
Changes in internal control over financial reporting. There have been no changes
in the Company's internal control over financial reporting (as defined in Rule
13a-15(f) under the Exchange Act) that occurred during the Company's last fiscal
quarter that has materially affected or is reasonably likely to materially
affect the Company's internal control over financial reporting.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
The information required in response to this item is set forth in the
Company's definitive proxy statement for the annual meeting of stockholders to
be held on May 13, 2004 and is incorporated herein by reference.
ITEM 11. EXECUTIVE COMPENSATION
The information required in response to this item is set forth in the
Company's definitive proxy statement for the annual meeting of stockholders to
be held on May 13, 2004 and is incorporated herein by reference.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT AND RELATED STOCKHOLDER MATTERS
The information required in response to this item is set forth in the
Company's definitive proxy statement for the annual meeting of stockholders to
be held on May 13, 2004 and is incorporated herein by reference.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The information required by Item 201(d) of Regulation S-K in response to
this item is provided in "Item 5. Market for Registrant's Common Equity and
Related Stockholder Matters". The information required by Item 403 of Regulation
S-K in response to this item is set forth in the Company's definitive proxy
statement for the annual meeting of stockholders to be held on May 13, 2004 and
is incorporated herein by reference.
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
The information required in response to this item is set forth in the
Company's definitive proxy statement for the annual meeting of stockholders to
be held on May 13, 2004 and is incorporated herein by reference.
94
PART IV
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(a) Listing of Financial Statements and Exhibits
Financial Statements
The following consolidated financial statements of the Company are included
in "Item 8. Financial Statements and Supplementary Data":
Independent Auditors' Report
Consolidated Balance Sheets as of December 31, 2003 and 2002
Consolidated Statements of Operations for the Years Ended December 31,
2003, 2002 and 2001
Consolidated Statements of Stockholders' Equity for the Years Ended
December 31, 2003, 2002 and 2001
Consolidated Statements of Cash Flows for the Years Ended December 31,
2003, 2002 and 2001
Consolidated Statements of Comprehensive Income (Loss) for the Years
Ended December 31, 2003, 2002 and 2001
Notes to Consolidated Financial Statements
Unaudited Supplementary Information
(b) Reports on Form 8-K
During the three months ended December 31, 2003, the Company filed one
Current Report on Form 8-K dated October 30, 2003. The Company's October 30,
2003 Form 8-K provided, under Items 7 and 12, the Company's news release
including attached schedules dated October 30, 2003 that announced the Company's
financial and operating results for the three and nine month periods ended
September 30, 2003, an operational update and the Company's fourth quarter 2003
financial outlook.
(c) Exhibits
The exhibits to this Report required to be filed pursuant to Item 15(c) are
listed below and in the "Index to Exhibits" attached hereto.
(d) Financial Statement Schedules
No financial statement schedules are required to be filed as part of this
Report or they are inapplicable.
95
Exhibits
Exhibit
Number Description
3.1 - Amended and Restated Certificate of Incorporation of the Company
(incorporated by reference to Exhibit 3.1 to the Company's
Registration Statement on Form S-4, dated June 27, 1997, Registration
No. 333-26951).
3.2 - Restated Bylaws of the Company (incorporated by reference to Exhibit
3.2 to the Company's Registration Statement on Form S-4, dated June
27, 1997, Registration No. 333-26951).
4.1 - Form of Certificate of Common Stock, par value $.01 per share, of the
Company (incorporated by reference to Exhibit 4.1 to the Company's
Registration Statement on Form S-4, dated June 27, 1997, Registration
No. 333-26951).
4.2 - Rights Agreement dated July 24, 2001, between the Company and
Continental Stock Transfer & Trust Company, as Rights Agent
(incorporated by reference to Exhibit 4.1 to the Company's
Registration Statement on Form 8-A, File No. 1-13245, filed with the
SEC on July 24, 2001).
4.3 - Certificate of Designation of Series A Junior Participating Preferred
Stock (incorporated by reference to Exhibit A to Exhibit 4.1 to the
Company's Registration Statement on Form 8-A, File No. 1-13245, filed
with the SEC on July 24, 2001).
4.4 - Indenture, dated April 12, 1995, between Pioneer USA (successor to
Parker & Parsley Petroleum Company ("Parker & Parsley")), and The
Chase Manhattan Bank (National Association), as Trustee (incorporated
by reference to Exhibit 4.1 to Parker & Parsley's Current Report on
Form 8-K, dated April 12, 1995, File No. 1-10695).
4.5 - First Supplemental Indenture, dated as of August 7, 1997, among
Parker & Parsley, The Chase Manhattan Bank, as Trustee, and Pioneer
USA, with respect to the indenture identified above as Exhibit 4.4
(incorporated by reference to Exhibit 10.5 to the Company's Quarterly
Report on Form 10-Q for the period ended September 30, 1997, File No.
1-13245).
4.6 - Second Supplemental Indenture, dated as of December 30, 1997, among
Pioneer USA, a Delaware corporation, Pioneer NewSub1, Inc., a Texas
corporation, and The Chase Manhattan Bank, a New York banking
association, as Trustee, with respect to the indenture identified
above as Exhibit 4.4 (incorporated by reference to Exhibit 10.17 to
the Company's Current Report on Form 8-K, File No. 1-13245, filed
with the SEC on January 2, 1998).
4.7 - Third Supplemental Indenture, dated as of December 30, 1997, among
Pioneer NewSub1, Inc. (as successor to Pioneer USA), a Texas
corporation, Pioneer DebtCo, Inc., a Texas corporation, and The Chase
Manhattan Bank, a New York banking association, as Trustee, with
respect to the indenture identified above as Exhibit 4.4
(incorporated by reference to Exhibit 10.18 to the Company's Current
Report on Form 8-K, File No. 1-13245, filed with the SEC on January
2, 1998).
4.8 - Fourth Supplemental Indenture, dated as of December 30, 1997, among
Pioneer DebtCo, Inc. (as successor to Pioneer NewSub1, Inc., as
successor to Pioneer USA), a Texas corporation, the Company, a
Delaware corporation, Pioneer USA, a Delaware corporation, and The
Chase Manhattan Bank, a New York banking association, as Trustee,
with respect to the indenture identified above as Exhibit 4.4
(incorporated by reference to Exhibit 10.19 to the Company's Current
Report on Form 8-K, File No. 1-13245, filed with the SEC on January
2, 1998).
96
Exhibit
Number Description
4.9 - Guarantee, dated as of December 30, 1997, by Pioneer USA relating to
the $150,000,000 in aggregate principal amount of 8-7/8% Senior Notes
due 2005 and $150,000,000 vin aggregate vprincipalv amount of v8-1/4%
Senior Notes due 2007 issued under thev indenture identified above as
Exhibitv 4.4 v(incorporated by vreference to vExhibit v10.20 vto vthe
Company's Current Report on Form 8-K, vFilev No. 1-13245,v filed with
the SEC on January 2, 1998).
4.10 - Indenture, dated January 13, 1998, between the Company and The Bank
of New York, as Trustee (incorporated by reference to Exhibit 99.1 to
the Company's and Pioneer USA's Current Report on Form 8-K, File No.
1-13245, filed with the SEC on January 14, 1998).
4.11 - First Supplemental Indenture, dated as of January 13, 1998, among the
Company, Pioneer USA, as the Subsidiary Guarantor, and The Bank of
New York, as Trustee, with respect to the indenture identified above
as Exhibit 4.10 (incorporated by reference to Exhibit 99.2 to the
Company's and Pioneer USA's Current Report on Form 8-K, File No.
1-13245, filed with the SEC on January 14, 1998).
4.12 - Second Supplemental Indenture, dated as of April 11, 2000, among the
Company, Pioneer USA, as the subsidiary guarantor and the Bank of New
York, as Trustee, with respect to the Indenture, dated January 13,
1998, between the Company and The Bank of New York, as Trustee, with
respect to the indenture identified above as Exhibit 4.10
(incorporated by reference to Exhibit 10.1 to the Company's Quarterly
Report on Form 10-Q for the period ended March 31, 2000, File No.
1-13245).
4.13 - Third Supplemental Indenture dated as of April 30, 2002, among the
Company, Pioneer USA as the subsidiary guarantor and The Bank of New
York, as Trustee, with respect to the indenture identified above as
Exhibit 4.10 (incorporated by reference to Exhibit 10.4 to the
Company's Quarterly Report on Form 10-Q for the three months ended
March 31, 2002, File No. 1-13245).
4.14 - Guarantee dated as of January 13, 1998, by Pioneer USA relating to
the $350,000,000 in aggregate principal amount of 6.50% Senior Notes
Due 2008 issued under the indenture identified above as Exhibit 4.10
(incorporated by reference to Exhibit 99.5 to the Company's and
Pioneer USA's Current Report on Form 8-K, File No. 1-13245, filed
with the SEC on January 14, 1998).
4.15 - Guarantee dated as of January 13, 1998, by Pioneer USA relating to
the $250,000,000 in aggregate principal amount of 7.20% Senior Notes
Due 2028 issued under the indenture identified above as Exhibit 4.10
(incorporated by reference to Exhibit 99.6 to the Company's and
Pioneer USA's Current Report on Form 8-K, File No. 1-13245, filed
with the SEC on January 14, 1998).
4.16 - Guarantee, dated as of April 11, 2000, by Pioneer USA as the
subsidiary guarantor relating to the $425,000,000 aggregate principal
amount of 9-5/8% Senior Notes Due April 1, 2010 issued under the
Second Supplemental Indenture identified above as Exhibit 4.12
(incorporated by reference to Exhibit 10.3 to the Company's Quarterly
Report on Form 10-Q for the period ended March 31, 2000, File No.
1-13245).
4.17 - Guarantee dated as of April 30, 2002, by Pioneer USA relating to the
$150,000,000 in aggregate principal amount of 7.50% Senior Notes Due
2012 issued under the indenture identified above as Exhibit 4.13
(incorporated by reference to Exhibit 10.6 to the Company's Quarterly
Report on Form 10-Q for the period ended March 31, 2002, File No.
1-13245).
10.1H - 1991 Stock Option Plan of Mesa Inc. ("Mesa") (incorporated by
reference to Exhibit 10(v) to Mesa's Annual Report on Form 10-K for
the period ended December 31, 1991).
10.2H - 1996 Incentive Plan of Mesa (incorporated by reference to Exhibit
10.28 to the Company's Registration Statement on Form S-4, dated
June 27, 1997, Registration No. 333-26951).
97
Exhibit
Number Description
10.3H - Parker & Parsley Long-Term Incentive Plan, dated February 19, 1991
(incorporated by reference to Exhibit 4.1 to Parker & Parsley's
Registration Statement on Form S-8, Registration No. 33-38971).
10.4H - First Amendment to the Parker & Parsley Long-Term Incentive Plan,
dated August 23, 1991 (incorporated by reference to Exhibit 10.2 to
Parker & Parsley's Registration Statement on Form S-1, dated
February 28, 1992, Registration No. 33-46082).
10.5H - The Company's Long-Term Incentive Plan (incorporated by reference to
Exhibit 4.1 to the Company's Registration Statement on Form S-8,
Registration No. 333-35087).
10.6H - First Amendment to the Company's Long-Term Incentive Plan, effective
as of November 23, 1998 (incorporated by reference to Exhibit 10.72
to the Company's Annual Report on Form 10-K for the period ended
December 31, 1999, File No. 1-13245).
10.7H - Second Amendment to the Company's Long-Term Incentive Plan, effective
as of May 20, 1999 (incorporated by reference to Exhibit 10.73 to the
Company's Annual Report on Form 10-K for the period ended December
31, 1999, File No. 1-13245).
10.8H - Third Amendment to the Company's Long-Term Incentive Plan, effective
as of February 17, 2000 (incorporated by reference to Exhibit 10.76
to the Company's Annual Report on Form 10-K for the period ended
December 31, 1999, File No. 1-13245).
10.9H - The Company's Employee Stock Purchase Plan (incorporated by reference
to Exhibit 4.1 to the Company's Registration Statement on Form S-8,
Registration No. 333-35165).
10.10H - First Amendment to the Company's Employee Stock Purchase Plan, dated
December 9, 1998 (incorporated by reference to the Company's Annual
Report on Form 10-K for the year ended December 31, 1998, File No.
1-13245).
10.11H - Second Amendment to the Company's Employee Stock Purchase Plan, dated
December 14, 1999 (incorporated by reference to Exhibit 10.74 to the
Company's Annual Report on Form 10-K for the period ended December
31, 1999, File No. 1-13245).
10.12H - The Company's Deferred Compensation Retirement Plan (incorporated by
reference to Exhibit 4.1 to the Company's Registration Statement on
Form S-8, Registration No. 333-39153).
10.13H - Omnibus Amendment to Nonstatutory Stock Option Agreements, included
as part of the Parker & Parsley Long-Term Incentive Plan, dated as of
November 16, 1995, between Parker & Parsley and Named Executive
Officers identified on Schedule 1 setting forth additional details
relating to the Parker & Parsley Long-Term Incentive Plan
(incorporated by reference to Parker & Parsley's Annual Report on
Form 10-K for the year ended December 31, 1995, File No. 1-10695).
10.14H - Severance Agreement, dated as of August 8, 1997, between the Company
and Scott D. Sheffield, together with a schedule identifying
substantially identical agreements between the Company and each of
the other named executive officers identified on Schedule I for the
purpose of defining the payment of certain benefits upon the
termination of the officer's employment under certain circumstances
(incorporated by reference to Exhibit 10.7 to the Company's
Quarterly Report on Form 10-Q for the period ended September 30,
1997, File No. 1-13245).
10.15H - Indemnification Agreement, dated as of August 8, 1997, between the
Company and Scott D. Sheffield, together with a schedule identifying
substantially identical agreements between the Company and each of
the Company's other directors and named executive officers
identified on Schedule I (incorporated by reference to Exhibit 10.8
to the Company's Quarterly Report on Form 10-Q for the period ended
September 30, 1997, File No. 1-13245).
98
Exhibit
Number Description
10.16H - Pioneer USA 40l(k) and Matching Plan, Amended and Restated Effective
as of January 1, 2002 (incorporated by reference to Exhibit 10.30 to
the Company's Annual Report on Form 10-K for the year ended December
31, 2002, File No. 1-13245).
10.17 - Agreement and Plan of Merger dated as of September 20, 2001, among
the Company, Pioneer USA and the Parker & Parsley partnerships named
therein (incorporated by reference to Exhibit 2.1 to the Company's
Registration Statement on Form S-4, Registration No. 333-59094).
10.18* - $700,000,000 Credit Agreement, dated as of December 16, 2003, among
the Company, as the borrower, JP Morgan Chase Bank, as the
Administrative Agent, Bank of America, N.A., Bank One, N.A., Fleet
National Bank and Wells Fargo Bank, National Association, as the
Co-Documentation Agents, Wachovia Bank, National Association, as the
Syndication Agent and certain Lenders.
14.1 - Code of Business Conduct and Ethics (incorporated by reference to
Annex D of the Company's Schedule 14A Definitive Proxy Statement,
File No. 1-13245, filed with the SEC on April 7, 2003).
21.1* - Subsidiaries of the registrant.
23.1* - Consent of Ernst & Young LLP.
23.2* - Consent of Netherland, Sewell & Associates, Inc.
23.3* - Consent of Gaffney, Cline & Associates, Inc.
31.1* - Chief Executive Officer certification under Section 302 of the
Sarbanes-Oxley Act of 2002.
31.2* - Chief Financial Officer certification under Section 302 of the
Sarbanes-Oxley Act of 2002.
32.1* - Chief Executive Officer certification under Section 906 of the
Sarbanes-Oxley Act of 2002.
32.2* - Chief Financial Officer certification under Section 906 of the
Sarbanes-Oxley Act of 2002.
- ---------------
* Filed herewith
H Executive Compensation Plan or Arrangement previously filed pursuant to Item
14(c).
99
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused this Report to be signed on
its behalf by the undersigned, thereunto duly authorized.
PIONEER NATURAL RESOURCES COMPANY
Date: February 2, 2004 By: /s/ Scott D. Sheffield
-------------------------------------------
Scott D. Sheffield, Chairman of the Board,
Chief Executive Officer, President and
Assistant Secretary
Pursuant to the requirements of the Securities Exchange Act of 1934, this
Report has been signed below by the following persons on behalf of the
Registrant and in the capacities and on the dates indicated.
Signature Title Date
--------- ----- ----
/s/ Scott D. Sheffield Chairman of the Board, Chief February 2, 2004
- ---------------------------- Executive Officer, President
Scott D. Sheffield and Assistant Secretary
(principal executive officer)
/s/ Timothy L. Dove Executive Vice President, February 2, 2004
- ---------------------------- Chief Financial Officer and
Timothy L. Dove Assistant Secretary
/s/ Richard P. Dealy Vice President and Chief February 2, 2004
- ---------------------------- Accounting Officer
Richard P. Dealy
/s/ James R. Baroffio Director February 2, 2004
- ----------------------------
James R. Baroffio
/s/ Edison C. Buchanan Director February 2, 2004
- ----------------------------
Edison C. Buchanan
/s/ R. Hartwell Gardner Director February 2, 2004
- ----------------------------
R. Hartwell Gardner
/s/ James L. Houghton Director February 2, 2004
- ----------------------------
James L. Houghton
/s/ Jerry P. Jones Director February 2, 2004
- ----------------------------
Jerry P. Jones
/s/ Linda K. Lawson Director February 2, 2004
- ----------------------------
Linda K. Lawson
/s/ Charles E. Ramsey, Jr. Director February 2, 2004
- ----------------------------
Charles E. Ramsey, Jr.
/s/ Robert A. Solberg Director February 2, 2004
- ----------------------------
Robert A. Solberg
100
Exhibit Index Page
3.1 - Amended and Restated Certificate of Incorporation of the
Company (incorporated by reference to Exhibit 3.1 to the
Company's Registration Statement on Form S-4, dated June
27, 1997, Registration No. 333-26951).
3.2 - Restated Bylaws of the Company (incorporated by reference
to Exhibit 3.2 to the Company's Registration Statement on
Form S-4, dated June 27, 1997, Registration No. 333-26951).
4.1 - Form of Certificate of Common Stock, par value $.01 per
share, of the Company (incorporated by reference to Exhibit
4.1 to the Company's Registration Statement on Form S-4,
dated June 27, 1997, Registration No. 333-26951).
4.2 - Rights Agreement dated July 24, 2001, between the Company
and Continental Stock Transfer & Trust Company, as Rights
Agent (incorporated by reference to Exhibit 4.1 to the
Company's Registration Statement on Form 8-A, File No.
1-13245, filed with the SEC on July 24, 2001).
4.3 - Certificate of Designation of Series A Junior Participating
Preferred Stock (incorporated by reference to Exhibit A to
Exhibit 4.1 to the Company's Registration Statement on Form
8-A, File No. 1-13245, filed with the SEC on July 24, 2001).
4.4 - Indenture, dated April 12, 1995, between Pioneer USA
(successor to Parker & Parsley Petroleum Company ("Parker &
Parsley")), and The Chase Manhattan Bank (National
Association), as Trustee (incorporated by reference to
Exhibit 4.1 to Parker & Parsley's Current Report on Form
8-K, dated April 12, 1995, File No. 1-10695).
4.5 - First Supplemental Indenture, dated as of August 7, 1997,
among Parker & Parsley, The Chase Manhattan Bank, as
Trustee, and Pioneer USA, with respect to the indenture
identified above as Exhibit 4.4 (incorporated by reference
to Exhibit 10.5 to the Company's Quarterly Report on Form
10-Q for the period ended September 30, 1997, File No.
1-13245).
4.6 - Second Supplemental Indenture, dated as of December 30,
1997, among Pioneer USA, a Delaware corporation, Pioneer
NewSub1, Inc., a Texas corporation, and The Chase Manhattan
Bank, a New York banking association, as Trustee, with
respect to the indenture identified above as Exhibit 4.4
(incorporated by reference to Exhibit 10.17 to the
Company's Current Report on Form 8-K, File No. 1-13245,
filed with the SEC on January 2, 1998).
4.7 - Third Supplemental Indenture, dated as of December 30,
1997, among Pioneer NewSub1, Inc. (as successor to Pioneer
USA), a Texas corporation, Pioneer DebtCo, Inc., a Texas
corporation, and The Chase Manhattan Bank, a New York
banking association, as Trustee, with respect to the
indenture identified above as Exhibit 4.4 (incorporated by
reference to Exhibit 10.18 to the Company's Current Report
on Form 8-K, File No. 1-13245, filed with the SEC on
January 2, 1998).
4.8 - Fourth Supplemental Indenture, dated as of December 30,
1997, among Pioneer DebtCo, Inc. (as successor to Pioneer
NewSub1, Inc., as successor to Pioneer USA), a Texas
corporation, the Company, a Delaware corporation, Pioneer
USA, a Delaware corporation, and The Chase Manhattan Bank,
a New York banking association, as Trustee, with respect to
the indenture identified above as Exhibit 4.4 (incorporated
by reference to Exhibit 10.19 to the Company's Current
Report on Form 8-K, File No. 1-13245, filed with the SEC on
January 2, 1998).
101
Exhibit Index Page
4.9 - Guarantee, dated as of December 30, 1997, by Pioneer USA
relating to the $150,000,000 in aggregate principal amount
of 8-7/8% Senior Notes due 2005 and $150,000,000 in
aggregate principal amount of 8-1/4% Senior Notes due 2007
issued under the indenture identified above as Exhibit 4.4
(incorporated by reference to Exhibit 10.20 to the
Company's Current Report on Form 8-K, File No. 1-13245,
filed with the SEC on January 2, 1998).
4.10 - Indenture, dated January 13, 1998, between the Company and
The Bank of New York, as Trustee (incorporated by reference
to Exhibit 99.1 to the Company's and Pioneer USA's Current
Report on Form 8-K, File No. 1-13245, filed with the SEC on
January 14, 1998).
4.11 - First Supplemental Indenture, dated as of January 13, 1998,
among the Company, Pioneer USA, as the Subsidiary
Guarantor, and The Bank of New York, as Trustee, with
respect to the indenture identified above as Exhibit 4.10
(incorporated by reference to Exhibit 99.2 to the Company's
and Pioneer USA's Current Report on Form 8-K, File No.
1-13245, filed with the SEC on January 14, 1998).
4.12 - Second Supplemental Indenture, dated as of April 11, 2000,
among the Company, Pioneer USA, as the subsidiary guarantor
and the Bank of New York, as Trustee, with respect to the
Indenture, dated January 13, 1998, between the Company and
The Bank of New York, as Trustee, with respect to the
indenture identified above as Exhibit 4.10 (incorporated
by reference to Exhibit 10.1 to the Company's Quarterly
Report on Form 10-Q for the period ended March 31, 2000,
File No. 1-13245).
4.13 - Third Supplemental Indenture dated as of April 30, 2002,
among the Company, Pioneer USA as the subsidiary guarantor
and The Bank of New York, as Trustee, with respect to the
indenture identified above as Exhibit 4.10 (incorporated by
reference to Exhibit 10.4 to the Company's Quarterly Report
on Form 10-Q for the three months ended March 31, 2002,
File No. 1-13245).
4.14 - Guarantee dated as of January 13, 1998, by Pioneer USA
relating to the $350,000,000 in aggregate principal amount
of 6.50% Senior Notes Due 2008 issued under the indenture
identified above as Exhibit 4.10 (incorporated by reference
to Exhibit 99.5 to the Company's and Pioneer USA's Current
Report on Form 8-K, File No. 1-13245, filed with the SEC on
January 14, 1998).
4.15 - Guarantee dated as of January 13, 1998, by Pioneer USA
relating to the $250,000,000 in aggregate principal amount
of 7.20% Senior Notes Due 2028 issued under the indenture
identified above as Exhibit 4.10 (incorporated by reference
to Exhibit 99.6 to the Company's and Pioneer USA's Current
Report on Form 8-K, File No. 1-13245, filed with the SEC on
January 14, 1998).
4.16 - Guarantee, dated as of April 11, 2000, by Pioneer USA as
the subsidiary guarantor relating to the $425,000,000
aggregate principal amount of 9-5/8% Senior Notes Due April
1, 2010 issued under the Second Supplemental Indenture
identified above as Exhibit 4.12 (incorporated by reference
to Exhibit 10.3 to the Company's Quarterly Report on Form
10-Q for the period ended March 31, 2000, File No.1-13245).
4.17 - Guarantee dated as of April 30, 2002, by Pioneer USA
relating to the $150,000,000 in aggregate principal amount
of 7.50% Senior Notes Due 2012 issued under the indenture
identified above as Exhibit 4.13 (incorporated by reference
to Exhibit 10.6 to the Company's Quarterly Report on Form
10-Q for the period ended March 31, 2002, File No.
1-13245).
102
Exhibit Index Page
10.1H - 1991 Stock Option Plan of Mesa Inc. ("Mesa") (incorporated
by reference to Exhibit 10(v) to Mesa's Annual Report on
Form 10-K for the period ended December 31, 1991).
10.2H - 1996 Incentive Plan of Mesa (incorporated by reference to
Exhibit 10.28 to the Company's Registration Statement on
Form S-4, dated June 27, 1997, Registration No. 333-26951).
10.3H - Parker & Parsley Long-Term Incentive Plan, dated February
19, 1991 (incorporated by reference to Exhibit 4.1 to
Parker & Parsley's Registration Statement on Form S-8,
Registration No. 33-38971).
10.4H - First Amendment to the Parker & Parsley Long-Term Incentive
Plan, dated August 23, 1991 (incorporated by reference to
Exhibit 10.2 to Parker & Parsley's Registration Statement
on Form S-1, dated February 28, 1992, Registration No.
33-46082).
10.5H - The Company's Long-Term Incentive Plan (incorporated by
reference to Exhibit 4.1 to the Company's Registration
Statement on Form S-8, Registration No. 333-35087).
10.6H - First Amendment to the Company's Long-Term Incentive Plan,
effective as of November 23, 1998 (incorporated by
reference to Exhibit 10.72 to the Company's Annual Report
on Form 10-K for the period ended December 31, 1999, File
No. 1-13245).
10.7H - Second Amendment to the Company's Long-Term Incentive Plan,
effective as of May 20, 1999 (incorporated by reference to
Exhibit 10.73 to the Company's Annual Report on Form 10-K
for the period ended December 31, 1999, File No. 1-13245).
10.8H - Third Amendment to the Company's Long-Term Incentive Plan,
effective as of February 17, 2000 (incorporated by
reference to Exhibit 10.76 to the Company's Annual Report
on Form 10-K for the period ended December 31, 1999, File
No. 1-13245).
10.9H - The Company's Employee Stock Purchase Plan (incorporated by
reference to Exhibit 4.1 to the Company's Registration
Statement on Form S-8, Registration No. 333-35165).
10.10H - First Amendment to the Company's Employee Stock Purchase
Plan, dated December 9, 1998 (incorporated by reference to
the Company's Annual Report on Form 10-K for the year ended
December 31, 1998, File No. 1-13245).
10.11H - Second Amendment to the Company's Employee Stock Purchase
Plan, dated December 14, 1999 (incorporated by reference to
Exhibit 10.74 to the Company's Annual Report on Form 10-K
for the period ended December 31, 1999, File No. 1-13245).
10.12H - The Company's Deferred Compensation Retirement Plan
(incorporated by reference to Exhibit 4.1 to the Company's
Registration Statement on Form S-8, Registration No.
333-39153).
10.13H - Omnibus Amendment to Nonstatutory Stock Option Agreements,
included as part of the Parker & Parsley Long-Term
Incentive Plan, dated as of November 16, 1995, between
Parker & Parsley and Named Executive Officers identified on
Schedule 1 setting forth additional details relating to the
Parker & Parsley Long-Term Incentive Plan (incorporated by
reference to Parker & Parsley's Annual Report on Form 10-K
for the year ended December 31, 1995, File No. 1-10695).
103
Exhibit Index Page
10.14H - Severance Agreement, dated as of August 8, 1997, between
the Company and Scott D. Sheffield, together with a
schedule identifying substantially identical agreements
between the Company and each of the other named executive
officers identified on Schedule I for the purpose of
defining the payment of certain benefits upon the
termination of the officer's employment under certain
circumstances (incorporated by reference to Exhibit 10.7 to
the Company's Quarterly Report on Form 10-Q for the period
ended September 30, 1997, File No. 1-13245).
10.15H - Indemnification Agreement, dated as of August 8, 1997,
between the Company and Scott D. Sheffield, together with a
schedule identifying substantially identical agreements
between the Company and each of the Company's other
directors and named executive officers identified on
Schedule I (incorporated by reference to Exhibit 10.8 to
the Company's Quarterly Report on Form 10-Q for the period
ended September 30, 1997, File No. 1-13245).
10.16H - Pioneer USA 40l(k) and Matching Plan, Amended and Restated
Effective as of January 1, 2002 (incorporated by reference
to Exhibit 10.30 to the Company's Annual Report on Form
10-K for the year ended December 31, 2002, File No.
1-13245).
10.17 - Agreement and Plan of Merger dated as of September 20,
2001, among the Company, Pioneer USA and the Parker &
Parsley partnerships named therein (incorporated by
reference to Exhibit 2.1 to the Company's Registration
Statement on Form S-4, Registration No. 333-59094).
10.18* - $700,000,000 Credit Agreement, dated as of December 16,
2003, among the Company, as the borrower, JP Morgan Chase
Bank, as the Administrative Agent, Bank of America, N.A.,
Bank One, N.A., Fleet National Bank and Wells Fargo Bank,
National Association, as the Co-Documentation Agents,
Wachovia Bank, National Association, as the Syndication
Agent and certain Lenders.
14.1 - Code of Business Conduct and Ethics (incorporated by
reference to Annex D of the Company's Schedule 14A
Definitive Proxy Statement, File No. 1-13245, filed with
the SEC on April 7, 2003).
21.1* - Subsidiaries of the registrant.
23.1* - Consent of Ernst & Young LLP.
23.2* - Consent of Netherland, Sewell & Associates, Inc.
23.3* - Consent of Gaffney, Cline & Associates, Inc.
31.1* - Chief Executive Officer certification under Section 302 of
the Sarbanes-Oxley Act of 2002.
31.2* - Chief Financial Officer certification under Section 302 of
the Sarbanes-Oxley Act of 2002.
32.1* - Chief Executive Officer certification under Section 906 of
the Sarbanes-Oxley Act of 2002.
32.2* - Chief Financial Officer certification under Section 906 of
the Sarbanes-Oxley Act of 2002.
- ---------------
* Filed herewith
H Executive Compensation Plan or Arrangement previously filed pursuant to Item
14(c).
104