20-F 1 a2120904z20-f.htm 20-F
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As filed with the Securities and Exchange Commission on October 24, 2003.

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, DC 20549

FORM 20-F

(Mark One)
o	Registration statement pursuant to Section 12(b) or 12(g) of the Securities Exchange Act of 1934
ý	Annual report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
For the fiscal year ended December 31, 2002
o	Transition report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
For the transition period from to

Commission File No. 001-12142

Petróleos de Venezuela, S.A.
(Exact Name of Registrant as Specified in Its Charter)

Venezuelan National Petroleum Company		Bolivarian Republic of Venezuela
(Translation of Registrant's Name into English)		(Jurisdiction of Incorporation or Organization)
Avenida Libertador, La Campiña, Apdo. 169, Caracas 1010-A, Venezuela (Address of Principal Executive Offices)

Securities registered or to be registered pursuant to Section 12(b) of the Act:

Title of each class		Name of each exchange on which registered
Guarantee of PDV America, Inc.'s 7⁷/8% Senior Notes due 2003		New York Stock Exchange, Inc.

Securities registered or to be registered pursuant to Section 12(g) of the Act: None.

Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act:

PDVSA Finance Ltd. 6.450% Notes due 2004
PDVSA Finance Ltd. 6.650% Notes due 2006
PDVSA Finance Ltd. 6.800% Notes due 2008
PDVSA Finance Ltd. 8.500% Notes due 2012
PDVSA Finance Ltd. 9.950% Notes due 2020

PDVSA Finance Ltd. 8.750% Notes due 2004
PDVSA Finance Ltd. 9.375% Notes due 2007
PDVSA Finance Ltd. 9.750% Notes due 2010
PDVSA Finance Ltd. 7.400% Notes due 2016
PDVSA Finance Ltd. 7.500% Notes due 2028

Indicate the number of outstanding shares of each of the issuer's classes of capital or common stock as of the close of the period covered by the annual report: 51,204 shares of the common stock of Petróleos de Venezuela, S.A. were outstanding as of December 31, 2002.

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		No X
	Indicate by check mark which financial statement item the registrant has elected to follow.
Item 17		Item 18 X

TABLE OF CONTENTS

		Page
INCORPORATION OF CERTAIN DOCUMENTS BY REFERENCE		ii
FACTORS AFFECTING FORWARD-LOOKING STATEMENTS		ii
PART I		3
	Item 1. Identity of Directors, Senior Management and Advisers	3
	Item 2. Offer Statistics and Expected Timetable	3
	Item 3. Key Information	3
	Item 4. Information on the Company	9
	Item 5. Operating and Financial Review and Prospects	50
	Item 6. Directors, Senior Management and Employees	66
	Item 7. Major Shareholders and Related Party Transactions	70
	Item 8. Financial Information	71
	Item 9. The Offer and Listing	73
	Item 10. Additional Information	73
	Item 11. Quantitative and Qualitative Disclosures about Market Risk	74
	Item 12. Description of Securities Other than Equity Securities	79
PART II		80
	Item 13. Defaults, Dividend Arreages and Delinquencies	80
	Item 14. Material Modifications to the Rights of Security Holders and Use of Proceeds	80
	Item 15. Controls and Procedures	80
	Item 16. [Reserved]	81
PART III		81
	Item 17. Financial Statements	81
	Item 18. Financial Statements	81
	Item 19. Exhibits	82
SIGNATURES		83
ANNEX A		A-1

INCORPORATION OF CERTAIN DOCUMENTS BY REFERENCE

With respect to our obligations as co-registrant of PDVSA Finance Ltd.'s 6.450% Notes due 2004, 6.650% Notes due 2006, 6.800% Notes due 2008, 7.400% Notes due 2016, 7.500% Notes due 2028, 8.750% Notes due 2004, 9.375% Notes due 2007, 9.750% Notes due 2010, 9.950% Notes due 2020 and 8.500% Notes due 2012 (collectively, the "PDVSA Finance Notes"), PDVSA Finance Ltd.'s annual report on Form 20-F for the year ended December 31, 2002, as first filed with the U.S. Securities and Exchange Commission (Commission file No. 333-09678) on October 24, 2003 is incorporated herein by reference.

FACTORS AFFECTING FORWARD-LOOKING STATEMENTS

This annual report on Form 20-F contains "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. Specifically, certain statements under the caption "Item 4.B. Business overview" and under the caption "Item 5. Operating and Financial Review and Prospects" relating to the expected results of exploration, drilling and production activities, refining processes, petrochemicals, gas, Orimulsion® and coal activities, and related capital expenditures and investments, the expected results of joint venture projects, the anticipated demand for new or improved products, environmental compliance and remediation and related capital expenditures, sales, taxes, dividends and contributions to Venezuela, and our recovery efforts, are forward-looking statements. Words such as "anticipate," "estimate," "prospect" and similar expressions are used to identify forward-looking statements. Forward-looking statements are subject to risks and uncertainties related to Venezuelan and international markets, inflation, the availability of continued access to capital markets and financing on favorable terms, regulatory compliance requirements, changes in import controls or import duties, levies or taxes and changes in prices or demand for our products as a result of actions of our competitors or economic factors. Those statements are also subject to the risks of costs and anticipated performance capabilities of technology, and performance by third parties of their contractual obligations. Exploration activities are subject to risks arising from the inherent difficulty of predicting the presence, yield and quality of hydrocarbon deposits, as well as unknown or unforeseen difficulties in extracting, transporting or processing any hydrocarbons found or doing so on an economic basis. Should one or more of these risks or uncertainties materialize, actual results may vary materially from those estimated, anticipated or projected. Specifically, but without limitation, capital costs could increase, projects could be delayed, and anticipated improvements in capacity or performance may not be fully realized. Although we believe that the expectations reflected by such forward-looking statements are reasonable based on information currently available, readers are cautioned not to place undue reliance on these forward-looking statements, which speak only as of the date of this annual report. We undertake no obligation to publicly release any revision to these forward-looking statements to reflect events or circumstances after the date of this annual report.

The annual report on Form 20-F of PDVSA Finance Ltd., our wholly-owned subsidiary, for the year ended December 31, 2002 incorporated by reference herein also contains forward-looking statements. For a discussion of the factors affecting these statements contained in PDVSA Finance's annual report, see "Factors Affecting Forward-looking Statements" on page ii thereof.

As used in this annual report, references to "dollars" or "$" are to the lawful currency of the United States and references to "bolivars" or "Bs" are to the lawful currency of Venezuela. A unit conversion table and a glossary of certain oil and gas terms, including abbreviations for certain units, used in this annual report are contained in Annex A. When used in this annual report, the term "Petróleos de Venezuela" refers to Petróleos de Venezuela, S.A. and the terms "we," "our," "us" and "PDVSA" refer to Petróleos de Venezuela, S.A. and its consolidated subsidiaries.

Other miscellaneous terms

Unless the context indicates otherwise, the following terms have the meanings shown below:

"Amerada Hess"—Amerada Hess Corporation

"Bitor"—Bitúmenes Orinoco, S.A.

"BORCO"—The Bahamas Oil Refining Company International Limited

"Carbozulia"—Carbones del Zulia, S.A.

"Chalmette Refining"—Chalmette Refining, L.L.C.

"ChevronTexaco"—ChevronTexaco Corporation

"CIED"—Centro Internacional de Educación y Desarrollo

"CITGO"—CITGO Petroleum Corporation

"CITGO Latin America"—CITGO International Latin America, Inc.

"Conoco"—ConocoPhillips

"CVP"—Corporación Venezolana del Petróleo, S.A.

"Deltaven"—Deltaven, S.A.

"ExxonMobil"—ExxonMobil Corporation.

"FIEM"—Fondo de Inversión para la Estabilización Macroeconómica (Macroeconomic Stabilization Investment Fund)

"Hovensa"—Hovensa, L.L.C.

"Intevep"—Intevep, S.A.

"Isla Refinery"—Refinería Isla (Curaçao), S.A.

"Lyondell"—Lyondell Petrochemical Corporation

"LYONDELL-CITGO"—LYONDELL-CITGO Refining Company, L.P.

"Merey Sweeny"—Merey Sweeny, L.L.C.

"Nynäs"—AB Nynäs Petroleum

"OPEC"—Organization of Petroleum Exporting Countries

"PDV America"—PDV America, Inc.

"PDV Chalmette"—PDV Chalmette, Inc.

"PDV Europa"—PDV Europa B.V.

"PDV Holding"—PDV Holding, Inc.

"PDV Marina"—PDV Marina, S.A.

"PDVMR"—PDV Midwest Refining, L.L.C.

"PDV VI"—PDVSA Virgin Island, Inc.

"PDVSA Cerro Negro"—PDVSA Cerro Negro, S.A.

"PDVSA Finance"—PDVSA Finance Ltd.

"PDVSA Gas"—PDVSA Gas, S.A.

"PDVSA Petróleo"—PDVSA Petróleo, S.A.

"PDVSA Sincor"—PDVSA Sincor, S.A.

"PDVSA-P&G"—PDVSA Petróleo y Gas, S.A.

"Pequiven"—Petroquímica de Venezuela, S.A.

"Petrozuata"—Petrolera Zuata, C.A.

"Phillips Petroleum"—Phillips Petroleum Corporation

"Ruhr"—Ruhr Oel GmbH

"Statoil"—Statoil Sincor AS

"Total Fina"—Total Fina Venezuela, S.A.

"Veba Oel"—Veba Oel AG

"Venezuela"—The Bolivarian Republic of Venezuela

PART I

Item 1. Identity of Directors, Senior Management and Advisers

Not Applicable.

Item 2. Offer Statistics and Expected Timetable

Not Applicable.

Item 3. Key Information

3.A Selected financial data

The selected data presented below for, and as of the end of, each of the years in the five-year period ended December 31, 2002, are derived from the consolidated financial statements of PDVSA. The consolidated financial statements as of and for the years ended December 31, 2002, 2001 and 2000 have been audited by Alcaraz Cabrera Vazquez (a member firm of KPMG International), independent auditors. The consolidated financial statements as of and for the years ended December 31, 1999 and 1998 have been audited by Espiñeira, Sheldon y Asociados (a member firm of PricewaterhouseCoopers, LLP), independent auditors. The consolidated financial statements as of December 31, 2002 and 2001, and for each of the years in the three-year period ended December 31, 2002, and the report thereon, which is based partially upon the report of other auditors, are included elsewhere herein. See "Item 18. Financial Statements."

		At or for the Year Ended December 31,
		2002		2001		2000		1999		1998
		($ in millions)
Income Statement Data:
Sales of crude oil and products
	Exports and international markets	39,875		42,682		49,780		30,369		23,289
	In Venezuela	1,236		1,701		2,230		1,450		1,315
Petrochemical and other sales		1,201		1,403		1,224		781		922

	Net sales	42,312		45,786		53,234		32,600		25,526
Equity in earnings of nonconsolidated investees		268		464		446		48		133

Total revenues		42,580		46,250		53,680		32,648		25,659
Total costs and expenses		39,073		37,977		40,029		26,636		23,219
	Operating income	3,507		8,273		13,651		6,012		2,440
Financing expenses		763		509		672		662		365

	Income before income taxes, minority interests and cumulative effect of accounting change	2,744		7,764		12,979		5,350		2,075
Provision for income taxes		(149	)	(3,766	)	(5,748	)	(2,521	)	(1,602	)
Minority interests		(5	)	(5	)	(15	)	(11	)	(1	)
Income before cumulative effect of accounting changes		2,590		3,993		7,216		2,818		472
Cumulative effect of accounting change(1)		—		—		—		—		191

	Net income	2,590		3,993		7,216		2,818		663

Balance Sheet Data:
Cash and cash equivalents		1,703		925		3,257		1,079		685
Notes and accounts receivable		3,515		3,280		4,435		3,820		2,194
Total assets		54,958		57,200		57,600		49,990		48,816
Current portion of long-term debt(2)		1,817		1,000		596		910		1,410
Long-term debt and capital lease obligations (excluding current portion)		6,494		7,544		7,187		7,892		6,615
Stockholder's equity		37,288		37,098		37,932		32,894		31,763
Capital stock		39,094		39,094		39,094		39,094		39,094
Other Financial Data:
Net cash provided by operating activities		5,185		7,092		10,285		4,633		2,606
Net cash used in investing activities		(1,490	)	(5,263	)	(5,360	)	(3,326	)	(4,532	)
Net cash (used in) provided by financing activities		(2,917	)	(4,161	)	(2,747	)	(913	)	784
Capital expenditures		2,962		3,781		3,185		3,041		3,726
Depreciation and depletion		3,059		2,624		3,001		2,821		2,849
Debt/Equity(3)		22	%	23	%	21	%	27	%	26	%
Total payments to shareholder		9,474		12,097		11,641		6,549		6,236

	Dividends(4)	2,652		4,862		1,732		1,719		1,996
	Production tax	5,911		3,792		4,954		2,654		2,253
	Income taxes(5)	911		3,443		4,955		2,176		1,987

(1): Effective January 1, 1998, we changed our method of accounting for the cost of major refinery repairs and maintenance (turnarounds).
(2): Excludes current portion of capital lease obligations, which amounted to $30 million, $62 million, $122 million, $117 million and $90 million in 2002, 2001, 2000, 1999 and 1998, respectively.
(3): Calculated as total debt (long-term debt, including current portion of long-term debt and capital leases) divided by stockholder's equity.
(4): During 1999, special tax recovery certificates, or CERTS, amounting to $1,291 million were used to pay dividends.
(5): During 2001, 2000, 1999 and 1998, we used CERTS amounting to $84 million, $255 million, $22 million and $622 million, respectively, to pay income taxes.

				At or for the Year Ended December 31,
				2002			2001			2000			1999			1998
							(MBPD, unless otherwise indicated)
Operating Data:
Production
Condensate					46			48			50			43			43
Light crude oil (API gravity of 30° or more)					774			1,135			1,174			1,189			1,233
Medium crude oil (API gravity of between 21° and 30°)					962			1,018			1,047			1,095			1,137
Heavy crude oil (API gravity of less than 21°)					877			893			814			623			866

	Total crude oil				2,659			3,094			3,085			2,950			3,279
Liquid petroleum gas					173			173			167			177			170

			Total crude oil and liquid petroleum gas		2,832			3,267			3,252			3,127			3,449

Net natural gas (MMCFD)(1)					3,672			4,093			3,979			3,766			3,965

Total crude oil, liquid petroleum gas and net natural gas (BOE)(2)					3,464			3,973			3,938			3,776			4,133

Sales volumes exported
	Exports of crude oil with 30° or greater API				672			659			716			1,010			889
	Exports of crude oil with less than 30° API				1,092			1,406			1,282			913			1,372
	Exports of refined petroleum products				647			697			825			861			855

		Total			2,411			2,762			2,823			2,784			3,116

Average export prices per unit ($ per barrel)
	Exports of crude oil with 30° or greater API			$	23.46		$	22.47		$	28.20		$	17.08		$	11.38
	Exports of crude oil with less than 30° API			$	20.24		$	17.29		$	23.12		$	13.45		$	8.08
	Exports of refined petroleum products			$	24.23		$	23.94		$	28.40		$	17.80		$	13.88
	Weighted average export prices (3)			$	21.94		$	20.21		$	25.91		$	16.04		$	10.57
Average production costs ($ per BOE)
	Production cost per BOE of production, excluding operating service agreements (4)			$	2.42		$	2.17		$	2.22		$	2.00		$	2.33
	Production cost per BOE of production (4)			$	3.92		$	3.38		$	3.48		$	2.72		$	2.75
	Depreciation and depletion cost per BOE of production			$	0.54		$	0.38		$	0.46		$	0.37		$	0.45
Proved reserves (5)
	Crude oil (MMB)
		Condensate			1,900			1,723			1,772			1,847			1,922
		Light crude oil (API gravity of 30° or more)			10,012			10,345			10,244			10,258			9,292
		Medium crude oil (API gravity of between 21° and 30°)			12,450			12,891			12,804			12,195			12,505
		Heavy crude oil (API gravity of between 11° and 21°)			17,414			17,266			17,177			16,861			16,742
		Extra-heavy crude oil (API gravity of less than 11°)(6)			35,381			35,558			35,688			35,701			35,647

			Total crude oil		77,157			77,783			77,685			76,862			76,108

			Of which, relating to Operating Service Agreements (7)		5,501			5,600			5,479			5,450			4,895
		Natural gas (BCF)(8)			147,109			148,295			147,585			146,611			146,573

		Proved reserves of crude oil and natural gas (MMBOE)(6)			102,521			103,351			103,131			102,140			101,379

		Remaining reserve life of proved crude oil reserves (years)(9)			70	x		64	x		64	x		70	x		64	x
Net crude oil refining capacity(10)
	Venezuela (including Isla Refinery)				1,628			1,628			1,620			1,620			1,620
	United States				1,205			1,205			1,198			1,224			1,224
	Europe				252			252			252			252			252
		Total			3,085			3,085			3,070			3,096			3,096

(1): Amounts indicated are net of natural gas used for reinjection purposes.
(2): Natural gas is converted to barrels of oil equivalent (BOE) at a ratio of 5.8 thousand cubic feet of natural gas per one barrel of crude oil.
(3): Weighted average sales price of crude oil, refined petroleum products and liquid petroleum gas exports.
(4): Calculated by dividing total costs (excluding depreciation and depletion) and expenses of crude oil, natural gas and liquid natural gas producing activities by total crude oil, liquid petroleum gas and net natural gas (BOE) produced.
(5): Proved reserves include both proved developed and undeveloped reserves.
(6): Proved reserves of extra-heavy oil located in the Orinoco Belt have a low development grade. Of the total gross proved reserves to be exploited under our Orinoco Belt project at December 31, 2002, approximately 10,639 MMB reserves were being developed under four association agreements in which PDVSA has an equity interest of less than 50%. See "Item 4.B Business overview—Initiatives Involving Private Sector Participation—Orinoco Belt Extra-Heavy Crude Oil Projects."
(7): Includes portion of proved crude oil reserves in fields relating to operating service agreements as of December 31 of the year in which each of such agreements went into effect. Such agreements may not necessarily result in the exploitation of

100% of these reserves during their term. See "Item 4.B Business overview—Initiatives Involving Private Sector Participation—Operating Service Agreements."

(8): Includes 12,454 BCF, 12,476 BCF, 12,505 BCF, 12,400 BCF and 12,437 BCF in each of 2002, 2001, 2000, 1999 and 1998, respectively, associated with extra-heavy crude oil reserves.
(9): Based on crude oil production from the top of wells for each period and total proved crude oil reserves at the end of each period. Proved reserves of extra-heavy crude oil are substantially undeveloped. Proved reserves of extra-heavy crude oil in the Orinoco Belt will be developed in association with third parties, although there is uncertainty as to when production will begin or what interest PDVSA will have in these projects. See "Item 4.B Business overview—Initiatives Involving Private Sector Participation—Orinoco Belt Extra-Heavy Crude Oil Projects."
(10): Amounts represent PDVSA's interest in the refining capacity of all refineries in which it holds an equity or leasehold interest. See "Item 4.B Business overview—Refining and Marketing."

Exchange rates

The following table sets forth certain information concerning the exchange rate of the bolivar to the dollar based on daily rates of exchange established by the Central Bank of Venezuela pursuant to a foreign exchange agreement between Venezuela's Ministry of Finance and the Central Bank of Venezuela. See notes 2, 3 and 21 to our consolidated financial statements, included under "Item 18. Financial Statements."

	Year ended December 31,
	Period End	Average (1)	High	Low
1998	563.17	545.62
1999	647.53	609.29
2000	698.23	679.80
2001	770.09	722.01
2002	1,403.00	1,163.91
December, 2002			1,403.00	1,263.50
January, 2003			1,853.00	1,403.00
February, 2003			1,853.00	1,600.00
March 2003—October 23, 2003(2)			1,600.00	1,600.00

(1): Represents the average exchange rate for each full month during the year, calculated based on the average daily exchange rate established by the Central Bank of Venezuela pursuant to the foreign exchange agreement referred to above.
(2): The exchange rate for the sale and purchase of the bolivar relative to the dollar was fixed by the Venezuelan government pursuant to a new foreign exchange regime at Bs. 1,600.00 to $1 and Bs. 1,596.00 to $1, respectively, commencing February 5, 2003.

On February 13, 2002, the Venezuelan government and the Central Bank of Venezuela adopted a floating exchange rate system in place of the band system. On January 21, 2003, the Venezuelan government and the Central Bank of Venezuela adopted temporary measures to restrict the convertibility of the Bolivar, and on February 5, 2003, the Venezuelan government established a foreign exchange regime, setting the exchange rates for the sale and purchase of foreign currency at Bs. 1,600.00 to $1 and Bs. 1,596.00 to $1, respectively. It also created the Commission for the Administration of Foreign Exchange (CADIVI) and established rules for the administration and control of foreign currency.

Notwithstanding the new regime, the foreign exchange agreement between Venezuela's Ministry of Finance and the Central Bank of Venezuela contains provisions that are specific to PDVSA, which have been in effect since 1982. Among other things, the foreign exchange agreement effectively exempts PDVSA and its affiliates from the exchange controls described above, up to a specified dollar limit. As a result, we believe that the new exchange controls will not have a significant impact on PDVSA's operations.

3.D Risk factors

Our business depends substantially on international prices for oil and oil products and such prices are volatile. A decrease in such prices could materially and adversely affect our business.

PDVSA's business, financial condition, results of operations and prospects depend largely on international prices for crude oil and refined petroleum products. Prices of oil and refined petroleum products are cyclical and highly volatile, and have, historically, fluctuated widely due to various factors that are beyond our control, including:

•: changes in global supply and demand for crude oil and refined petroleum products;
•: political events in major oil producing and consuming nations;
•: agreements among OPEC members;
•: the availability and price of competing products;
•: actions of commodity markets participants and competitors;
•: international economic trends;
•: technological advancements and developments in the industry;
•: currency exchange fluctuations; and
•: inflation.

Historically, OPEC members have entered into agreements to reduce their production of crude oil. Such agreements have sometimes increased global crude oil prices by decreasing the global supply of crude oil. Venezuela is a party to and has complied with such production agreement quotas, and we expect that Venezuela will continue to comply with such agreements in the future. Since 1998, OPEC's production quotas have resulted in a worldwide decline in crude oil production and substantial increases in international crude oil prices.

Risks Related to Venezuela's Ownership, Regulation and Supervision of PDVSA.

We are owned by the Bolivarian Republic of Venezuela. The Venezuelan government regulates and supervises our operations, and the President of Venezuela appoints the members of our board of directors by an executive decree. However, Venezuela is not legally liable for our obligations, including our guarantees of indebtedness of our subsidiaries, or the obligations of our subsidiaries.

We have been operated as an independent commercial entity since our formation. In December 2002 and January 2003. The opponents of the Venezuelan government initiated a nationwide work stoppage that disrupted most activities in Venezuela, including PDVSA's operations. Although PDVSA's operations began to normalize in February 2003, any prolonged disruption in PDVSA's activities could have a material adverse effect on the generation of eligible receivables by PDVSA Petróleo. A similar labor stoppage briefly occurred in February 2002. We have no control over the occurrence of such developments and cannot assure you that similar events will not occur in the future. Additionally, because we are controlled by the Venezuelan government, we cannot assure you that the Venezuelan government will not in the future intervene in our commercial affairs in a manner that could adversely affect our business.

We do not own any of the hydrocarbon reserves that we develop and operate.

Under Venezuelan law, the hydrocarbon reserves that we develop and operate belong to Venezuela and not to us. The exploration of these hydrocarbon reserves are reserved to Venezuela. Petróleos de Venezuela was formed to coordinate, monitor and control operations related to Venezuela's hydrocarbon reserves.

While Venezuelan law requires that Venezuela retain exclusive ownership of Petróleos de Venezuela, it does not require the country to continue to conduct its crude oil exploration and exploitation activities through us. If the government elects to conduct its hydrocarbon activities other than through us, our operations will be materially and adversely affected. We can offer no assurance that Venezuelan law or the implementation of policies by the Venezuelan government will not adversely affect our operations. See also "Item 7.A Major shareholders."

Our business requires substantial capital expenditures.

The exploration and development of hydrocarbon reserves, production, processing and refining and the maintenance of machinery and equipment require substantial capital investments. We must continue to invest capital to maintain or to increase the number of hydrocarbon reserves that we operate and the amount of crude oil that we produce and process. We cannot assure you that we will maintain our production levels or generate sufficient cash flows or that we will have access to sufficient investments, loans or other financing alternatives to continue our refining, exploration and development activities at or above our present levels.

We are subject to production, equipment, transportation and other risks that are common to oil and gas companies.

As an integrated oil and gas company, we are exposed to production, equipment and transportation risks that are common to oil and gas companies, including fluctuations in production volume due to changes in reserve levels, production accidents, mechanical difficulties, adverse natural conditions, unforeseen production costs, condition of pipelines and the vulnerability of other modes of transportation and the adequacy of our equipment and production facilities. See "Item 4.B Business overview—Operations."

These risks may lower our production levels, increase our production costs and expenses, or cause damage to our property or personal injury to our employees or others. We maintain insurance to cover certain losses and exposure to liability. However, consistent with industry practice, we are not fully insured against the risks described above. These risks may materially and adversely affect our operations and financial results. We cannot assure you that our insurance coverage is sufficient to cover all of our losses or our exposure to liability that may result from these risks.

Item 4. Information on the Company

4.A History and development of the company

Petróleos de Venezuela is the national oil and gas company of the Bolivarian Republic of Venezuela. Petróleos de Venezuela was formed by the Venezuelan government in 1975 pursuant to the Organic Law Reserving to the State, the Industry and Commerce of Hydrocarbons (the "Nationalization Law"), and its operations are supervised by Venezuela's Ministry of Energy and Mines. Through its subsidiaries, Petróleos de Venezuela supervises, controls and develops the petroleum, petrochemical, gas, coal and Orimulsion® industries in Venezuela. These activities are complemented by Petróleos de Venezuela's operating companies established abroad, which are responsible for refining and marketing activities in North America, Europe and the Caribbean. See also "Item 7.A Major shareholders."

PDVSA's oil-related activities are governed by the Hydrocarbons Law, which came into effect in January 2002. PDVSA's gas-related activities are regulated by the Organic Law of Gas Hydrocarbons of September 1999 and its regulations dated June 2000.

Since its formation, Petróleos de Venezuela has been operated as a commercial entity, vested with commercial and financial autonomy. Petróleos de Venezuela and its domestic subsidiaries are organized under the Commercial Code of Venezuela, which sets forth the basic corporate legal framework applicable to all Venezuelan companies.

Petróleos de Venezuela is domiciled in Venezuela and its registered office is located at Avenida Libertador, La Campiña, Apdo. 169, Caracas 1010-A, Venezuela, and our telephone number is 011-58-212-708-1111. Our website is: www.pdvsa.com. All references to our website in this annual report are inactive textual references only. Information contained on our website is not incorporated by reference into this annual report.

4.B Business overview

PDVSA is engaged in various aspects of the petroleum industry, including:

•: the exploration, production and upgrading of crude oil and natural gas, or upstream operations;
•: the refining, marketing and transportation of crude oil, natural gas and refined petroleum products, or downstream operations;
•: the production and marketing of petrochemicals; and
•: the development and marketing of Venezuela's derivative of natural bitumen, known as Orimulsion®, and coal resources.

Our crude oil and natural gas reserves and our upstream operations are located in Venezuela, while our downstream operations are located in Venezuela, North America, Europe and the Caribbean.

Our exploration, production and upgrading executive office, manages our upstream operations, our Orinoco Belt development projects and the activities of our subsidiaries, Bitor, Carbozulia and CVP. In addition to the management of the exploration and production activities under profit sharing agreements with private sector oil companies, since August 2003, CVP assumed from PDVSA Petróleo the management of the operating agreements and the Orinoco Belt through projects conducted pursuant to joint venture agreements with international oil companies.

Our downstream operations are conducted through our supply and marketing executive office, through which we:

•: operate refineries and market crude oil and refined petroleum products in Venezuela under the PDV brand name and in the Eastern and Midwestern regions of the United States under the CITGO brand name;
•: own equity interests in three refineries (one 50%-owned by ExxonMobil, one 50.75%-owned by Lyondell and one 50%-owned by Amerada Hess) and in a coker/vacuum crude distillation unit (50%-owned by Conoco) through joint ventures in the United States;
•: own equity interests in eight refineries and market petroleum products in Germany, the United Kingdom, Belgium and Sweden through two joint ventures (one 50%-owned by Veba Oil and one 50%-owned by Fortum Oil and Gas OY);
•: conduct most of our business in the Caribbean through the Isla Refinery (a refinery and storage terminal which we lease in Curaçao);
•: operate storage terminals in Bonaire and The Bahamas;
•: process, market and transport all natural gas in Venezuela; and
•: conduct shipping activities.

In the United States, we conduct our crude oil refining operations and refined petroleum product marketing through our wholly-owned subsidiary, PDV Holding, which, through PDV America, owns 100% of CITGO. CITGO refines, markets and transports gasoline, diesel fuel, jet fuel, petrochemicals, lubricants, asphalt and other refined petroleum products in the United States. CITGO's transportation fuel customers include primarily CITGO branded independent wholesale marketers, major convenience store chains and airlines located mainly east of the Rocky Mountains. Asphalt is generally marketed to independent paving contractors on the East and Gulf Coasts and in the Midwest of the United States. Lubricants are sold principally in the United States to independent marketers, mass marketers and industrial customers. CITGO sells lubricants, gasoline, and distillates in various Latin American markets. Petrochemical feedstocks and industrial products are sold to various manufacturers and industrial companies throughout the United States. Petroleum coke is sold primarily in international markets. In addition, CITGO sells petrochemicals and industrial products directly to various manufacturers and industrial companies throughout the United States. In 2002, CITGO sold a total of 25.4 billion gallons of petroleum products. PDV Holding also owns 100% of PDVMR (through CITGO) and 50% of Chalmette Refining (through PDV Chalmette), each of which is primarily engaged in the refining of crude oil. In October 1998, we entered into agreements with Conoco to form Merey Sweeny, a joint venture to process crude oil in the United States, and with Amerada Hess to form Hovensa, a joint venture to process crude oil in the U.S. Virgin Islands. We are, through our U.S. subsidiaries, one of the largest refiners of crude oil in the United States, based on our aggregate net ownership interest in crude oil refining capacity at December 2002.

In Europe, we conduct our crude oil refining and refined petroleum product activities through PDV Europa, which owns our 50% interest in Ruhr, a company operating in Germany and owned jointly with Veba Oel, and our 50% interest in Nynäs, a company operating in Belgium, Sweden and the United Kingdom and owned jointly with Fortum Oil and Gas OY. Through Ruhr, we refine crude oil and market and transport gasoline, diesel fuel, heating oil, petrochemicals, lubricants, asphalt and other refined petroleum products. Through Nynäs, we refine crude oil and market and transport asphalt, specialty products, lubricants and other refined petroleum products.

We conduct our petrochemical activities through Pequiven, which has three petrochemical complexes in Venezuela and is currently involved in 17 joint ventures with private sector partners.

Our gas business is conducted through PDVSA Gas, which oversees our production and distribution of natural gas and gas liquids.

We have, since 1997, marketed and distributed retail gasoline and other refined petroleum products under the PDV brand in the Venezuelan local market through our subsidiary, Deltaven. Deltaven also is promoting the development of the commercial infrastructure and services for retail clients with the participation of the private sector.

PDVSA Finance was established in 1998 to serve as our principal vehicle for corporate financing through the issuance of unsecured debt.

Our other important subsidiary is Intevep, through which we manage our research and development activities. Additionally, PDVSA manages an educational center, CIED, which is responsible for the training and development of our personnel.

See "Item 4.C Organizational structure" for a list of our significant subsidiaries.

According to a comparative study published by Petroleum Intelligence Weekly in 2002, based on a combination of operating criteria and other data for 2001, including reserves, production, refining capacity and refined petroleum product sales, we were the world's third largest vertically integrated oil and gas company, ranked seventh in the world in production, sixth in proved reserves of crude oil, fourth in refining capacity and fifth in product sales. Venezuela has been exporting crude oil, primarily to the United States, without interruption, since 1914. In 2002, PDVSA accounted for approximately 27% of Venezuelan gross domestic product, approximately 79% of its exports and approximately 30% of its revenues.

Business Strategy

Our business strategy is to pursue the development of Venezuela's hydrocarbon resources with the support of both national and foreign private capital, to maximize shareholder value and to ensure our financial strength and stability.

Our business plan in respect of our operations in Venezuela for 2003-2008 focuses on the exploration, production, refining and marketing of hydrocarbons. Additionally, the plan also promotes investment from the private sector in the overall development of the gas and petrochemical industry, in the industrialization of refining streams and in Orimulsion® and coal. We anticipate that our business

plan would require approximately $36 billion to achieve a sustainable production capacity of 4,400 MBPD by 2008. A summary of our 2003-2008 business plan is as follows:

Capital Investment Plan 2003 - 2008
($ in millions)

	2003	2004	2005	2006	2007	2008	Total
Exploration	277	397	522	654	758	1,012	3,620
Production	1,838	2,001	2,265	1,993	1,812	1,650	11,558
Production Agreements	925	728	602	515	383	325	3,477
Orinoco Belt	970	426	250	203	199	159	2,208
Gas	456	789	781	453	698	1,290	4,466
Refining	450	524	813	510	230	87	2,614
Petrochemical	296	397	890	1,277	1,159	493	4,512
Coal	50	40	67	72	71	77	378
Bitumen (Orimulsion®)	366	416	428	182	34	34	1,461
Profit Sharing Agreement	290	315	240	258	203	88	1,394

Total:	5,918	6,034	6,858	6,117	5,547	5,215	35,688

We also are committed to maintaining high safety and health standards in conducting our business, and we aim to achieve effective and timely integration of business technologies in our operations. We also endeavor to provide quality training for our personnel.

As part of our business strategy, we intend to:

With respect to exploration, production and upgrading activities—

•: increase reserves of light and medium gravity crude oil;
•: increase overall recovery factor;
•: continue the development of our Orinoco Belt extra-heavy crude oil projects; and
•: improve on our existing technology in order to maximize the return on our investments.

With respect to refining and marketing—

•: invest in product enhancement and environmental compliance in Venezuela and abroad;
•: expand our markets in Latin America and the Caribbean; and
•: improve the efficiency of our refining processes and marketing activities.

With respect to gas—

•: promote active national and international private sector participation in nonassociated gas reserves and processing;
•: enhance our distribution processes in order to increase the breadth of our domestic and international markets; and
•: increase our focus in the liquified natural gas (or LNG) markets.

With respect to petrochemicals—

•: develop new lines of business with natural gas and refining streams; and

•: promote active national and international private sector participation and investments in this sector.

The implementation of our business plan includes the following initiatives:

•: Exploration, production and upgrading. Our exploration and production strategy focuses on increasing our efforts to search for new light and medium gravity crude oil reserves and the continued replacement of such reserves, developing new production areas, adjusting our production activities to cater to market demands and agreements reached with OPEC members and with other oil producing countries, maintaining competitive production costs by using state-of-the-art technology and completing the development of our Orinoco Belt projects, including Petrozuata (a joint venture between PDVSA and Conoco), Cerro Negro (a PDVSA—ExxonMobil—Veba Oel joint venture), Sincor (a PDVSA—TotalFinaElf—Statoil joint venture), Hamaca (a PDVSA—Conoco—ChevronTexaco joint venture).
•: Refining. Our refining strategy focuses on improving the efficiency of our downstream operations in Venezuela, the United States, Europe and the Caribbean. We continue to aim to achieve a higher margin of refined petroleum products and to comply with all applicable environmental quality standards.
•: Marketing. We plan to continue the expansion of our international marketing operations to ensure market growth for our crude oil and refined petroleum products and to increase brand recognition for our products. We also aim to strengthen our market position in the United States through a more efficient distribution by CITGO of its refined petroleum products. Through CITGO Latin America, a wholly-owned subsidiary of CITGO, we plan to introduce the PDV and CITGO brands into various Latin American and Caribbean markets, including through wholesale and retail sales of refined petroleum products. In 2001, CITGO Latin America set up an office in Guayaquil, Ecuador. In 2002, CITGO-branded service stations were established in Puerto Rico, and the PDV brand was recently launched in Argentina and Brazil.

In Venezuela, we plan to continue to promote a reliable supply of our products and the use of unleaded gasoline (a process which we started during the fourth quarter of 1999) to improve the competitive position of our network of service stations, lubrication centers and macro-stores, to continue the development of our commercial network through business relationships and other associations and to increase our product supply to high-traffic airports.

•: Gas. The development of our gas business is one of our major goals. We plan to focus on creating investment opportunities for the private sector in nonassociated gas production, expanding our transmission and distribution systems and natural gas liquids extraction, processing and fractioning capacity, and developing new gas export ventures, including exports of LNG. We intend to operate most of the existing associated natural gas production fields, currently assigned to us by the Ministry of Energy and Mines. We will continue to explore and develop nonassociated gas reserves with the support of private investment. We expect to support the activities related to our gas business using our existing gas transmission and distribution systems.

The Ministry of Energy and Mines completed a round of nonassociated gas licensing bids for exploration and production activities in 11 new onshore areas in 2001. Six of those areas were awarded to foreign and domestic investors: Yucal-Placer Norte and Yucal-Placer Sur (both development areas), Barrancas, Tinaco, Tiznado and Barbacoas (each exploratory areas). We anticipate the Yucal-Placer areas to produce approximately 100 MMCFD of gas beginning January 2004, and approximately 300 MMCFD by 2006-2007. During the first quarter of 2003, the Venezuelan government assigned two blocks within the Plataforma Deltana area (on the border with Trinidad & Tobago) to Statoil and ChevronTexaco. Additionally, we are currently

exploring the development of a project for the production of LNG in an area located in the northeast of the country.

We anticipate that development of our gas business strategy will require approximately $4.5 billion in capital from 2003 to 2008. We expect that such capital expenditures will be obtained primarily from investments by the private sector.

We believe that our natural gas resources and Venezuela's geographical location at the center of the Atlantic Basin puts us in an advantageous position to achieve our goals with respect to our gas business. We intend to capitalize on our position by promoting an increased and more diverse use of natural gas within the country.

•: Petrochemicals. We plan to continue to promote the development of the petrochemical industry in Venezuela by maximizing the use of our existing petrochemical infrastructure and by integrating our refineries and petrochemical plants to ensure maximum economic benefit and to promote independence of our business performance from the volatility of the oil and petrochemical markets. We intend to focus on three specific areas: development of petrochemicals from gas, industrialization of refinery streams and the manufacturing of certain aromatic products.
•: Orimulsion®. We plan to expand our Orimulsion® business and increase our production based on anticipated market opportunities, mainly in the Far East. We will execute our expansion plan through joint ventures. The growing popularity of Orimulsion® as a fuel is due to a new formulation, which makes it more environmentally friendly and more economical. At this time, our entire Orimulsion® production is operated to meet the needs of our clients in Europe, Asia and the United States.

Exploration and Production

Venezuela's proved crude oil reserves have continued to increase over the years, with a cumulative production of crude oil from 1914 through December 31, 2002 totaling approximately 55.7 billion barrels. Venezuela's commercial production of crude oil is concentrated in the Western Zulia Basin and the Western Barinas—Apure Basin in Western Venezuela and in the Monagas and Anzoategui states in the Eastern Basin. The large number of fields in production in these three basins are broadly distributed geographically and, as a result, substantially diversifies our production risk. The impact of a loss of production in any one field would be relatively minor when compared to Venezuela's total production. The Western and Eastern basins have produced 40.6 billion and 15.1 billion barrels, respectively, of crude oil to date. Substantial portions of the sedimentary basins in Venezuela have not yet been explored.

Principal Oil-Producing Basins in Venezuela

The following table shows our proved reserves, proved and developed reserves, 2002 production and the ratio of proved reserves to annual production in each of the principal basins at December 31, 2002:

PDVSA's Proved Reserves and Production by Basin

			Proved reserves(1)		Proved/developed reserves	2002 production		Ratio of proved reserves/annual production
			(MMB at Dec. 31, 2002, except as otherwise indicated)		(MMB at Dec. 31, 2002, except as otherwise indicated)	(MBPD, except as otherwise indicated)		(years)
Basin
Western Zulia:
	Crude Oil		21,478		6,598	1,332	(2)	44
	Natural Gas (BOE)		6,244		1,924	254	(3)	67
Western Barinas — Apure:
	Crude Oil		1,849		948	93	(2)	54
	Natural Gas (BOE)		34		19	1	(3)	70
Eastern:
	Total Crude Oil(4)		53,830		8,153	1,594	(2)	92
	Extra-Heavy Crude Oil		35,381		2,154	485		200
	Natural Gas (BOE)		19,086	(5)	15,676	527	(3)	99
		Total Crude Oil(4)	77,157		15,699	3,019	(2)	70
		Total Natural Gas (BOE)	25,364	(5)	17,619	782		89

(1): Developed and undeveloped.
(2): Includes condensate. Production obtained from the top of wells.
(3): Net natural gas production (gross production less natural gas reinjected).
(4): Includes proved reserves of heavy and extra-heavy crude oil in the Orinoco Belt, estimated to be 35.4 billion barrels at December 31, 2002. See "Item 4.B Business overview—Initiatives Involving Private Sector Participation—Orinoco Belt Extra-Heavy Crude Oil Projects."
(5): Includes proved reserves of natural gas in the Orinoco Belt, estimated to be 2.147 billion BOE at December 31, 2002.

The following table shows the location, 2002 production volume, discovery year, proved reserves and the ratio of proved reserves to annual production for each of PDVSA's eleven largest oil fields as of December 31, 2002:

PDVSA's Proved Reserves and Production by Field

Name of field	Location	2002 production	Year of discovery	Proved reserves	Ratio of proved reserves/annual production
	(State of)	(MBPD)		(MMB at Dec. 31, 2002)	(years)
Tia Juana	Zulia	266	1925	5,216	54
Bachaquero	Zulia	181	1930	2,382	36
Lagunillas	Zulia	151	1925	2,414	44
Urdaneta Oeste	Zulia	109	1955	1,559	39
Boscán	Zulia	97	1946	1,356	38
Bloque VII Ceuta	Zulia	114	1956	1,851	44
Bare	Anzoátegui	45	1950	1,263	77
Jobo	Monagas	26	1956	1,084	114
Mulata	Monagas	204	1941	2,184	29
El Furrial	Monagas	323	1986	1,950	17
Sta. Barbara	Monagas	135	1941	1,583	32

Reserves

We use geological and engineering data to estimate our proved crude oil and natural gas reserves, including proved developed and undeveloped reserves. Such data is capable of demonstrating with reasonable certainty whether such reserves are recoverable in future years from known reservoirs under existing economic and operating conditions. We expect to recover proved developed crude oil and natural gas reserves principally from new wells and acreage that has not been drilled using currently available equipment and operating methods. Our estimates of reserves are not precise and are subject to revision. We review these crude oil and natural gas reserves annually to take into account, among other things, production levels, field reviews, the addition of new reserves from discoveries, year-end prices and economic and other factors. Proved reserve estimates may be materially different from the quantities of crude oil and natural gas that are ultimately recovered.

New Hydrocarbon Reserves Findings

During recent exploration and drilling activities, which are still in progress in the Eastern part of Venezuela, new hydrocarbon reserves were discovered near Maturín. We expect these reserves to yield approximately 460 million barrels of crude oil of 32° API and 1.6 BCF of associated gas. Additionally, we currently are in the process of drilling an exploratory well located north of Anaco. We expect this exploratory well to yield approximately 2,800 BCF of free gas and 50 million barrels of crude oil. Further, new reserves were discovered in the Furrial field, which has been in production since 1996. We expect these reserves to yield approximately 2,000 million barrels of crude oil.

In the Western part of the country, we continue our exploration activities at Franquera-1, Pauji and Misoa Formations of Eocene. We expect these reserves to yield from 218 MMB to 1,559 MMB of crude oil and from 0.1 to 1,300 BCF of associated gas.

Crude oil and natural gas represented 75% and 25%, respectively, of our total estimated proved crude oil and natural gas reserves on an oil equivalent basis at December 31, 2002.

Crude Oil. We had estimated proved crude oil reserves at December 31, 2002 totaling approximately 77.2 billion barrels (including an estimated 35.4 billion barrels of heavy and extra-heavy crude oil in the Orinoco Belt). We also had estimated proved reserves of natural gas totaling approximately 147,109 BCF (including an estimated 12,454 BCF in the Orinoco Belt). The average API gravity of our estimated proved crude oil reserves was 16.5° as compared to an average API gravity of 24.2° for our crude oil produced in 2002; the API gravity of the oil produced by the Orinoco Belt projects ranges from 9 to 23° API. Based on 2002 production levels, estimated proved reserves of crude oil, including heavy and extra-heavy crude oil reserves that will require significant future development costs to produce and refine, have a remaining life of approximately 70 years.

From December 31, 1995 to December 31, 2002, our estimated proved reserves of crude oil increased by 10.9 billion barrels and our estimated proved reserves of natural gas increased by 0.62 billion barrels of oil equivalent ("BOE"). In 2002, 2001, 2000 and 1999, our proved crude oil reserve replacement ratio was 104%, 108%, 169% and 165%, respectively. These variations resulted from revisions to the expected recovery rate of oil in place and the application of secondary recovery technology to existing crude oil deposits.

Natural Gas. We have substantial proved developed reserves of natural gas amounting to 102,191 BCF (or 17,619 MMBOE) at December 31, 2002. Our natural gas reserves are comprised of associated gas that are developed incidental to the development of our crude oil reserves. A large proportion of our proved natural gas reserves are developed. During 2002, approximately 39% of the natural gas that we produced was reinjected for well pressure maintenance purposes.

The following table shows our proved crude oil and natural gas reserves and proved developed crude oil and natural gas reserves, all located in Venezuela (see note 20 to our consolidated financial statements, included under "Item 18. Financial Statements"):

PDVSA's Proved Reserves

			Year Ended December 31,
			2002		2001		2000		1999		1998
Proved Reserves(1):
Crude oil (MMB)
	Condensate		1,900		1,723		1,772		1,847		1,922
	Light (API gravity of 30° or more)		10,012		10,345		10,244		10,258		9,292
	Medium (API gravity of between 21° and 30°)		12,450		12,891		12,804		12,195		12,505
	Heavy (API gravity of between 11° and 21°).		17,414		17,266		17,177		16,861		16,742
	Extra-heavy (API gravity of less than 11°)(2)		35,381		35,558		35,688		35,701		35,647

		Total crude oil	77,157		77,783		77,685		76,862		76,108

		Of which, assigned to Operating Service Agreements(3)	5,501		5,600		5,479		5,450		4,895
Natural gas (BCF)(4)			147,109		148,295		147,585		146,611		146,573

Proved reserves of crude oil and natural gas (MMBOE)(3)(5)			102,521		103,351		103,131		102,140		101,379

Remaining reserves life of crude oil (years)(6)			70	x	64	x	64	x	70	x	64	x
Proved Developed Reserves:
Crude oil (MMB)
	Condensate.		419		747		814		1,009		1,007
	Light (API gravity of 30° or more)		2,716		3,590		3,803		3,827		3,522
	Medium (API gravity of between 21° and 30°)		5,533		5,568		5,928		6,480		6,609
	Heavy (API gravity of between 11° and 21°).		4,877		5,504		5,453		5,738		5,562
	Extra-heavy (API gravity of less than 11°)(2)(7).		2,154		1,963		1,375		1,070		751

		Total crude oil(7)	15,699		17,372		17,373		18,124		17,451

		Of which, assigned to Operating Service Agreements(3)	1,935		1,523		1,413		1,329		1,195

Percentage of proved crude oil reserves(8)			22	%	22	%	22	%	24	%	23	%
Natural gas (BCF)(4)			102,191		103,807		103,310		102,628		102,080

Percentage of proved natural gas reserves(9).			69	%	70	%	70	%	70	%	70	%
Proved developed reserves of crude oil and natural gas (MMBOE)(2)(3).			33,318		35,270		35,185		35,818		35,052

(1): Proved reserves include both proved developed and undeveloped reserves.
(2): Proved reserves of extra-heavy oil located in the Orinoco Belt have a low development grade. Of the total proved reserves to be exploited under the Orinoco Belt Project, at December 31, 2002, approximately 1,273 MMB were developed under four association agreements in which we have an equity interest of less than 50%. See "Item 4.B Business overview—Initiatives Involving Private Sector Participation—Orinoco Belt Extra-Heavy Crude Oil Projects."
(3): Portion of reserves in fields assigned to operating service agreements as of December 31 of the year in which each such operating agreement went into effect. Such agreements will not necessarily result in the exploitation of 100% of those reserves during their term. See "Item 4.B Business overview—Initiatives Involving Private Sector Participation—Operating Service Agreements."

(4): Includes 12,454 BCF, 12,476 BCF, 12,505 BCF, 12,400 BCF and 12,437 BCF in each of 2002, 2001, 2000, 1999 and 1998, respectively, associated with extra-heavy crude oil reserves.
(5): Natural gas is converted to BOE at a ratio of 5.8 thousand cubic feet of natural gas per one barrel of crude oil.
(6): Based on crude oil production and total crude proved reserves. Proved reserves of extra-heavy crude oil in the Orinoco Belt are being developed in association with third parties. See note (2) above.
(7): Includes proved developed reserves of extra-heavy crude oil utilized in the production of Orimulsion®.
(8): Proved developed crude oil reserves divided by total proved crude oil reserves.
(9): Proved developed natural gas reserves divided by total proved natural gas reserves.

Operations

We maintain an active exploration and development program designed to increase our proved crude oil reserves and production capacity. We have been successful in our efforts to increase our proved crude oil and natural gas reserves in each of the last 20 years. Beginning in 1992, we commenced a program designed to attract and incorporate private sector participation into our exploration and production activities. We currently conduct our exploration and development activities in the Western Zulia Basin, the Western Barinas—Apure Basin and the Eastern Basin in the Monagas and Anzoategui states. We are currently conducting extensive exploration and development activities in the Orinoco Belt of the Eastern Basin and in the other basins, either independently or together with foreign partners through joint venture associations. See "Item 4.B Business overview—Initiatives Involving Private Sector Participation."

In 2002, our exploration expenditures were used principally to fund the drilling of 10 exploratory wells and the acquisition of 3,142 square kilometers of 3D seismic lines and 6,714 km of 2D seismic lines. Additionally, 27 exploratory wells were drilled and 219 square kilometers of 3D seismic lines and 204 km of 2D seismic lines were acquired pursuant to our operating services agreements. 238 MMB proved crude oil reserves were added in 2002 (135 MMB from newly discovered reserves and 103 MMB from development wells), compared to 357 MMB in 2001 (46 MMB from newly discovered reserves and 311 MMB from development wells), 209 MMB in 2000 (5 MMB from newly discovered reserves and 204 MMB from development wells) and 184 MMB in 1999 (84 MMB from newly discovered wells and 100 MMB from development wells). In 2002, we invested $649 million in 366 development wells and other facilities.

The following table summarizes our drilling activities for the periods indicated:

PDVSA's Exploration and Development

			Year Ended December 31,
			2002	2001	2000	1999	1998
Exploration:
	Wells spud		3	6	5	5	9
	Wells carry-over		7	5	9	7	6

		Total	10	11	14	12	15

	Wells completed		3	3	2	0	5
	Wells suspended		2	0	2	5	4
	Wells under evaluation		0	3	5	1	3
	Wells in progress		3	3	1	4	1
	Dry or abandoned wells		2	2	4	2	2

		Total	10	11	14	12	15

Development:
	Development wells drilled (1)		366	479	474	349	976

(1): Includes wells in progress, even if they were wells spud in previous years, and injector wells. Does not include 22 development wells from PDVSA Gas and 155 development wells (including 7 injector wells) attributable to our operating service agreements. See Item 4.B Business overview—Initiatives Involving Private Sector Participation—Operating Service Agreements."

Pursuant to operating services agreements relating to the Orinoco Belt, 17 exploration wells and 144 development wells were drilled in 2002, nine exploration wells and 349 development wells were drilled in 2001 and 15 exploration wells and 453 development wells were drilled in 2000.

In 2002, our crude oil production averaged 2,659 MBPD (including 92 MBPD attributable to our participation in the Orinoco Belt projects) with an average API gravity of 23.2°. This production level represented approximately 72% of PDVSA's estimated 2002 year end crude oil production capacity of 3,674 MBPD (including 443 MBPD of crude oil production capacity attributable to our Orinoco Belt projects). During 2002, our average production costs of crude oil was approximately $3.92 per BOE, or $2.42 per BOE excluding the production and costs attributable to our operating service agreements, and the average of our depreciation and depletion costs was $0.54 per BOE. See "Item 3.A Selected financial data."

At December 31, 2002, we operated approximately 16,970 oil wells. At such date, we had 37,659 gross kms2 of undeveloped acreage and 177,829 gross kms2 of acreage under development, including 49,194 kms2 developed pursuant to our operating service agreements.

On average, during 2002, our natural gas production was 6,023 MMCFD (or 1,038 MBPD on an oil equivalent basis), of which 2,351 MMCFD, or 39.0%, was reinjected for purposes of maintaining reservoir pressure. The net natural gas production of 3,672 MMCFD was consumed in production of liquid natural gas (8.0%), as fuel in refinery and production operations (37.9%), in petrochemical operations (4.0%) and the remainder (50.1%) is sold to third parties for power generation, aluminum, iron and other manufacturing industries and domestic uses. Approximately 75% of the 2002 natural gas production and the total estimated proved net natural gas reserves is located in the Eastern Basin. A significant portion of this production is transported through our pipeline systems for use by industries in the coastal and central regions of Venezuela.

The following table summarizes our historical average net daily crude oil and natural gas production by type and by basin and the average sales price and production cost for the periods specified:

PDVSA's Average Production, Sales Price and Production Cost

			Years Ended December 31,
			2002		2001		2000		1999		1998
					(MBPD, except as otherwise indicated)
Crude oil:
	Condensate			46		48		50		43		43
	Light (API gravity of 30° or greater)			774		1,135		1,174		1,189		1,233
	Medium (API gravity of between 21° and 30°)			962		1,018		1,047		1,095		1,137
	Heavy (API gravity of less than 21°)			877		893		814		623		866

		Total crude oil		2,659		3,094		3,085		2,950		3,279

		Of which, assigned to Operating Service Agreements(1)		481		502		466		404		359
	Liquid petroleum gas			173		173		167		177		170

		Total crude oil and liquid petroleum gas		2,832		3,267		3,252		3,127		3,449

Natural gas:
	Gross production (MMCFD)			6,023		6,000		5,946		5,685		5,875
	Less:
		Reinjected (MMCFD)		2,351		1,907		1,967		1,919		1,910

	Net natural gas (MMCFD)			3,672		4,093		3,979		3,766		3,965

		Total crude oil, liquid petroleum gas and net natural gas (BOE)		3,464		3,973		3,938		3,776		4,133
Crude oil production by basin:
	Western Zulia Basin			1,332		1,567		1,536		1,450		1,634
	Western Barinas — Apure Basin			93		109		115		131		134
	Eastern Basin			1,234		1,418		1,434		1,369		1,511

		Total crude oil production		2,659		3,094		3,085		2,950		3,279

Natural gas gross production by basin (MMCFD):
	Western Zulia Basin			1,261		1,408		1,665		1,801		2,022
	Western Barinas — Apure Basin			8		7		7		7		7
	Eastern Basin			4,754		4,585		4,274		3,877		3,846

		Total gross natural gas production		6,023		6,000		5,946		5,685		5,875

Average sales price(2):
	Crude oil ($ per barrel)		$	21.35	$	18.95	$	24.94	$	15.35	$	9.37
	Gas ($ per MCF)		$	0.71	$	0.88	$	0.90	$	0.73	$	1.37
Average production cost ($ per BOE)(3)			$	3.92	$	3.38	$	3.48	$	2.72	$	2.75
Average production cost ($ per BOE), excluding operating service agreements(3)			$	2.42	$	2.17	$	2.22	$	2.00	$	2.33

(1): See "Item 4.B Business overview—Initiatives Involving Private Sector Participation—Operating Service Agreements."
(2): Including sales to subsidiaries and affiliates.

(3): The combined average production cost per barrel (for crude oil, natural gas and liquid petroleum gas), is calculated by dividing the sum of all direct and indirect production costs (including our own consumption but not including depreciation and depletion); by the combined total production volumes of crude oil, natural gas and liquid petroleum gas.

Initiatives Involving Private Sector Participation

As part of the process encouraging private initiatives and investment in the oil industry, and pursuant to Article 5 of the Nationalization Law, with the approval of the National Congress, we are permitted to enter into operating and association agreements with private entities. Since 1992, we have undertaken projects with the private sector in connection with our exploration and development activities.

In August 2003, to streamline our business operations and reduce our administrative costs, the administration of our business ventures with private sector entities was assigned to our subsidiary, CVP. In this regard, CVP will assume all responsibility within PDVSA with respect to our operating service agreements, strategic associations and profit sharing agreements described below. In addition to its administrative responsibilities, CVP will continue to promote PDVSA's relations with third parties and private sector participation in the petroleum industry. However, any dividends and profits from production activities conducted pursuant to our operating service agreements and our other strategic associations continue to be paid to Petróleos de Venezuela, and not to CVP.

The members of CVP's board of directors and their positions within CVP are Luis Vierma (President and Director), Rafael Lander (Vice-President and Director), Ángel González (Director), Oscar Fanti (Director), Nehil Duque (Director) and José Felix Rivas (Director), each of whom has more than 20 years of experience within PDVSA. Additionally, as part of this restructuring, our personnel formerly in charge of such activities will be relocated to CVP from their various positions within PDVSA.

Operating Service Agreements

During 1992, 1993 and 1997, PDVSA auctioned the rights to and entered into agreements with several international companies. The purpose of these agreements was to reactivate the operation of thirty-three oil fields which no longer met our minimum rate of return on investment threshold, using

secondary and tertiary recovery techniques. The auctions conducted during 1992 and 1993 are referred to in this annual report as the "first and second rounds" and the auction conducted in 1997 is referred to in this annual report as the "third round."

The terms of the operating agreements entered into require the international oil company investors to make capital investments in the form of assets necessary to increase production in the relevant oil fields. These investors would then recover their investments by collecting operating fees and stipends from PDVSA, amounts to be determined based on pricing formulas derived from the amount of crude oil delivered to PDVSA during the term of the operating agreement. The operating agreements also provide that PDVSA would own the capital assets employed in the production, retain title on the hydrocarbons produced and have no further obligations as to any remaining value of the assets existing in the fields. See note 10(c) to our consolidated financial statements, included under "Item 18. Financial Statements."

•: The First and Second Rounds. A total of 27 oil companies were awarded rights to drill 15 oil fields. An average of 334 MBPD of crude oil was produced from these fields in 2002, and it is expected that such production will increase to approximately 405 MBPD when the fields are in substantially full operation by 2005. As of December 31, 2002, these fields had estimated proved reserves of approximately 3.8 billion barrels of crude oil. As of December 31, 2002, under this initiative, foreign companies had invested in excess of $4.3 million.
•: The Third Round. We auctioned the right to reactivate, rehabilitate, develop and additionally explore certain hydrocarbon reservoirs in 17 fields. An average of 147 MBPD of crude oil was produced from these fields in 2002. As of December 31, 2002, these fields had estimated proved reserves of approximately 1.6 billion barrels of crude oil. Our business plan currently contemplates daily production of this field of 225 MBPD by 2005 under our operating service agreements. As of December 31, 2002, under this initiative, the operator companies had invested in excess of $2.8 billion.

The following table sets forth information with respect to the contracts awarded to reactivate the fields under the operating service agreements:

PDVSA's Operating Service Agreements
As of December 31, 2002

Area			Consortium (Operator)	Proved Crude Oil Reserves (MMB)(1)
First and Second Rounds
Boscan			Chevron Global Technology Services Co.	1,409.2
Urdaneta/West			Shell Venezuela S.A.	829.0
DZO			B.P. Venezuela Holdings, Ltd.	374.0
Oritupano/Leona			Petrobras Energía Venezuela, Union Pacific Resources, Servicios Corod de Venezuela	301.9
Colon			Tecpetrol Venezuela, CMS Oil and Gas, Coparex	130.7
Quiamare/LA Ceiba			Repsol—YPF Venezuela, S.A., Ampolex Venezuela Inc., Tecpetrol Venezuela	100.6
Quiriquire			Repsol—YPF Venezuela, S.A.	69.9
Pedernales			Perenco	119.0
Uracoa/Bombal			Benton Oil & Gas, Vinccler	160.7
Sanvi/Güere			Teikoku Oil De Sanvi Güere, C.A.	82.8
Guarico East			Teikoku Oil De Venezuela C.A.	67.8
Jusepin			Total Oil and Gas de Venezuela, B.V., B.P. Venezuela Holding, Ltd.	142.8
Guarico West			Union Pacific Resources, Repsol — YPF Venezuela, S.A.	42.3
Falcon East			Vinccler	8.9
Falcon West			West Falcon Samson	2.8

	Subtotal			3,842.4

Third Round
Boquerón			B.P. Venezuela Holding, Ltd., Preussag Energie GmbH	89.4
LL-652			Chevron Global Technology, Statoil, B.P. Venezuela Holding, Ltd., Petróleo y Gas Inversiones, C.A.	358.1
Dación			Lasmo Dacion, B.V., Lasmo Caracas, B.V., Lasmo Oriente, B.V.	222.5
Intercampo norte			China National Petroleum Corp.	68.7
Caracoles			China National Petroleum Corp.	108.7
B2X ⁶⁸/79			Nimir Petroleum Company Limited, Ehcopek Petróleo, S.A., Cartera de Inversiones Petroleras II, C.A.	108.0
Mene grande			Repsol — YPF Venezuela, S.A.	127.2
Mata			Inversora Mata, Petrobras Energía de Venezuela, S.A., Petrolera Mata	91.6
B2X 70/80			Pancanadian Petroleum Venezuela, S.A., Nimir Petroleum Company Limited	78.3
Kaki			Inemaka, Inversiones Polar, Petróleo y Gas Inversiones, C.A.	38.3
Ambrosio			Perenco, Petróleo y Gas Inversiones, C.A.	48.0
Onado			Compañía General Combustibles, Carmanah Resources, Korea Petroleum, Bco Popular Del Ecuador	53.7
La Concepción			Petrobras Energía de Venezuela, S.A., Williams Companies, Inc.	124.0
Cabimas			Preussag Energy GmbH, Suelopetrol	62.3
Casma Anaco			Cosa-Ingenieros Consultores, Cartera de Inversiones Venezolanas, Phoenix International, C.A., Rosewood North Sea, Open.	11.9
Maulpa			Inemaka, Inversiones Polar, Petróleo y Gas Inversiones, C.A.	32.5
Acema			Coroil, Petrobras Energía de Venezuela, S.A., Petrolera Coroil	35.4
La Vela			CVP	—

	Subtotal			1,658.6

		Total		5,501,0

(1): These proved crude oil reserves correspond to the fields assigned to each of the operating service agreements and are included in our total proved crude oil reserves. Such operating service agreements will not necessarily result in the exploitation of 100% of those reserves during their term. See "Item 4.B Business overview—Exploration and Production—Reserves," the proved reserves disclosed at December 31, 2002 do not include any additional reserves which may ultimately be proved based on secondary and tertiary recovery projects to be implemented by the operators of the service agreements.

Exploration and Production in New Areas Under Profit Sharing Agreements

In July 1995, the Venezuelan Congress approved profit sharing arrangements pursuant to which private sector oil companies were offered the right to explore, drill and develop light and medium crude oil, on an equity basis in ten designated blocks with a total area of 13,774 square kilometers,

pursuant to the terms of the profit sharing agreements entered into by such companies and CVP, our subsidiary appointed to coordinate, control and supervise these agreements. Under the profit sharing agreements, CVP has the right to participate, at its option, with an ownership interest between 1% and 35% in the development of any recoverable reserves with commercial potential. Eight oil fields were awarded to 14 companies in 1996. The awards were based on the percentage of pretax earnings ranging up to 50% that the bidders were willing to share with the Venezuelan government. Our business plan currently contemplates an aggregate average daily production from the fields in these new areas of 460 MBPD by 2010. The profit sharing agreements provide for the creation of a Control Committee, as the ultimate authority for approval and control, and which shall make fundamental decisions of national interest for Venezuela in connection with the execution of these agreements.

To date, the private sector companies have not carried out significant commercial operations pursuant to the profit sharing agreements. In 2002, these companies invested approximately $51 million in activities related to the discovery, well evaluation, development and exploration efforts in Golfo Paria Este, Golfo de Paria Oeste and La Ceiba. See note 10 to our consolidated financial statements, included under "Item 18. Financial Statements."

CVP owns shares representing a maximum 35% participation interest in the joint ventures formed pursuant to profit sharing agreements in the following oil fields:

Field	CVP partners	Mixed companies
Delta Centro	Burlington, Union Pacific, Benton (1)	Administradora General Delta Centro, S.A.
Golfo de Paria Este	Ineparia	Administradora del Golfo de Paria Este, S.A.
Golfo de Paria Oeste	Conoco, AGIP, OPIC	Compañía Agua Plana, S.A.
Guanare	ELF, Conoco (1)	Administradora Petrolera Guanare, S.A.
Guarapiche	Repsol — YPF Venezuela, S.A. (1)	Administradora General Guarapiche, S.A.
La Ceiba	ExxonMobil, Veba, Nippon	Administradora Petrolera La Ceiba, C.A.
Punta Pescador	Amoco, Total Fina, Veba (2)	Administradora General Punta Pescador, S.A.
San Carlos	Petrobras Energía de Venezuela, S.A. (3)	Compañía Anónima Mixta San Carlos, S.A.

(1): Profit sharing agreement was terminated in 2001.
(2): Profit sharing agreement was terminated in 2000.
(3): Profit sharing agreement was converted into a gas license in 2002.

A recent evaluation plan confirmed large hydrocarbon and gas reserves in Golfo de Paria Oeste field. It is anticipated that the field contains over two billion barrels of crude oil. On April 3, 2003, we approved phase I of the development plan for this field, involving a capital investment of approximately $557 million by investors and an expected production level of 250 million barrels of crude oil over the next 20 years. Phase I of this development will be conducted using of a wellhead platform, a floating production unit with separate accommodations platform, pipeline to a floating storage offtake vessel (FSO), and a mooring buoy for loading arriving tankers. Phase I also will include water injection for pressure maintenance. The produced associated gas will be stored an aquifer zone wholly contained within the overall Corocoro gas column. The operator will manage the facilities design, construction installation and subsequent production operations. A total of 24 wells will be drilled comprising 11 producers, 10 water injectors and three utility wells.

It is currently projected that phase II (expected to commence in 2006) would involve a further $487 million of investments to recover additional reserves of up to 450 million barrels of crude oil from the field. We believe that we can make an efficient transition from phase I to phase II by using existing

production facilities in the second phase. The total project cost for phase I and phase II is estimated at $4.3 per barrel, comprising $2.3 per barrel for development and $2.0 per barrel for operations.

Orinoco Belt Extra-Heavy Crude Oil Projects.

The Venezuelan Congress approved the creation of four vertically integrated joint venture projects in the Orinoco Belt for the exploitation and upgrading of extra-heavy crude oil of average API gravity of 9° and marketing of the upgraded crude oil with API gravities ranging from 16° to 32°. These joint venture projects have been implemented through association agreements between us and the various participating entities. The term of each association agreement is approximately 35 years after commencement of commercial production, and, upon termination, the foreign participant's ownership is transferred to us. Each of the projects is assigned an area that is expected to contain sufficient recoverable extra-heavy oil to meet planned output during the life of the association. For the foreign partners, the projects represent a significant opportunity to increase production and proved crude oil reserves. For us, the projects represent an opportunity to develop the Orinoco Belt's extra-heavy crude oil reserves.

The approval by the Venezuelan Congress of each of these associations sets forth the conditions under which each of the projects may operate and requires that the associations pay the standard Venezuelan corporate tax rate of 34% (as compared to a tax rate of 67.7%, revised to 50% in January 2002, that is applicable to our Venezuelan subsidiaries engaged in the production of hydrocarbon and related activities). In addition, in May 1998, the Ministry of Energy and Mines and PDVSA Petróleo signed agreements to provide relief from the 16²/3% production tax, establishing instead a tax rate band ranging from 1% to 16²/3%, measured based on accumulated revenues and total investment.

The four joint venture projects in the Orinoco Belt are as follows:

•: The Petrozuata Joint Venture. Petrozuata is a company owned by us (through PDVSA Petróleo) and Conoco. The construction of facilities at Petrozuata began in 1997. Initial production of extra-heavy crude oil commenced in August 1998. Upgraded facilities were completed in 2001. During 2002, Petrozuata produced 115 MBPD of extra heavy crude oil and 97 MBPD of upgraded crude oil with an average API gravity ranging from 19° to 25°. Under the terms of the joint venture agreement, Conoco has agreed to undertake the refining process at its Lake Charles refinery, in Lake Charles, Louisiana.
•: The Sincor Joint Venture. Sincrudos de Oriente is a company owned by us (through PDVSA Sincor), Total Fina and Statoil. In 2002, this joint venture produced 112 MBPD of extra heavy crude oil, and 86 MBPD of upgraded crude oil with an average API gravity ranging from 30° to 32°. We anticipate this joint venture to reach a production level of 180 MBPD of upgraded crude oil by 2007.
•: The Hamaca Joint Venture. Petrolera Hamaca is a company owned by us (through Corpoguanipa, S.A.), ChevronTexaco and Conoco. This joint venture anticipates its initial production phase to yield 190 MBPD of upgraded crude oil by 2004-2007, with an average API gravity of 25° to 27°. In 2002, it had an average production of extra heavy crude oil of 26 MBPD and an average production of 51 MBPD of diluted crude oil with an average gravity of 16° API.
•: The Cerro Negro Joint Venture. Petrolera Cerro Negro is a company owned by us (through PDVSA Cerro Negro, S.A.), ExxonMobil and Veba Oel. Pursuant to the terms of this joint venture agreement, we have agreed to sell our share of upgraded crude oil produced by this joint venture (approximately 80% of total production) to the Chalmette Refining, a refinery in Chalmette, Louisiana, which is an equal share joint venture between PDVSA and ExxonMobil. During 2002, this joint venture produced 101 MBPD of extra-heavy crude oil and 90 MBPD of

upgraded crude oil with an average API gravity of 16°. See "Item 4.B Business overview—Refining and Marketing—Refining," and note 10(a) to our consolidated financial statements, included under "Item 18. Financial Statements."

The Orinoco Belt projects differ primarily by the quantity and quality of output. For our foreign joint ventures without a U.S. Gulf Coast refinery (i.e., the Hamaca and Sincor joint ventures), the projects are designed to produce upgraded crude oil that can be sold to third-party refiners who would otherwise process light sweet conventional crude oil. For our foreign joint ventures with refining capacity on the U.S. Gulf Coast (i.e., the Petrozuata and Cerro Negro joint ventures), the projects are designed to produce upgraded crude oil that is suitable for a dedicated refinery.

The following table sets forth for each association in the Orinoco Belt, the parties, estimated proved reserves in the areas associated with the projects and estimated production:

PDVSA's Orinoco Belt Proved Reserves

Project	Private Sector Participants	PDVSA's Interest	Gross Proved Reserves	Estimated Production of Upgraded Crude Oil	Expected Average API of Upgraded Crude Oil
		(%)	(MMB)	(MBPD)	(degrees)
Petrozuata	Conoco	49.90	2,605	104	19-25
Sincor	Total Fina, Statoil	38.00	3,555	180	30-32
Hamaca	ChevronTexaco, Conoco	30.00	1,069	190	25-27
Cerro Negro	ExxonMobil, Veba Oel	41.67	3,410	105	16

Operating Service Agreement with National Universities

In October 2000, we entered into operating service agreements with three National Universities: Universidad de Oriente (Eastern University), Universidad del Zulia (Zulia University), and Universidad Central de Venezuela (Central University of Venezuela). In these agreements, we auctioned the right to reactivate, rehabilitate and develop fields located in three geographical areas. The purpose of these agreements with the National Universities is to provide training and industry experience to Venezuelan university students, especially geophysics, petroleum engineering and geology students.

Each field will be developed by separate entities that are 51% owned by us and 49% owned by the respective universities. These fields are: Socororo, located in Anzoategui State (operated by Petroucv, S.A.); Mara Este, located in the Zulia State (operated by Oleoluz, S.A.); and Jobo, located in Monagas State (operated by Petroudo, S.A.). The total assigned area for all these fields is approximately 523 square kilometers. As of December 31, 2002, these fields have estimated proved reserves of approximately 236.5 MMB of crude oil (consisting of 50.8 MMB at Socororo, 70.5 MMB at Mara Este and 115.2 MMB at Jobo, respectively), with an average API gravity of 8° to 22° API. We expect these fields to produce approximately 35 MBPD by 2007. We also anticipate investing a total of approximately $202 million in these fields over the next 20 years.

Refining and Marketing

Refining

Our downstream strategy has been focused on the expansion and upgrading of our refining operations in Venezuela, the United States and Europe, allowing us to increase our production of refined petroleum products and upgrade our product slate toward higher-margin refined petroleum products. We have also increased the complexity of our refining capacity in Venezuela and made extensive investments to convert our worldwide refining assets from simple conversion to deep conversion capabilities. Deep conversion capabilities in our Venezuelan refineries have enabled us to

improve yields by allowing a greater percentage of higher value products to be produced. Such capabilities have resulted in an increase in our gasoline and distillate yield from 35% in 1976 to 70% in 2002, and has allowed us to reduce our fuel oil production from 60% to 23% during the same period, resulting in an improved export product portfolio.

We conduct refining activities in Venezuela, the Caribbean, the United States and Europe. Our net interest in refining capacity has grown from 2,362 MBPD in 1991 to 3,085 MBPD at December 31, 2002. The following diagram presents a summary of PDVSA's refining operations in 2002:

PDVSA's Refining System

PDVSA's Refining Capacity

The following table sets forth the refineries in which we hold an interest, the rated crude oil refining capacity and our net interest at December 31, 2002:

			Owner	PDVSA Interest	Total Rated Crude Oil Refining Capacity	PDVSA Net Interest in Refining Capacity
				(%)	(MBPD)	(MBPD)
Venezuela
	Paraguaná Refining Complex, Falcón		PDVSA	100	940	940
	Puerto La Cruz, Anzoategui		PDVSA	100	203	203
	El Palito, Carabobo		PDVSA	100	130	130
	Bajo Grande, Zulia		PDVSA	100	15	15
	San Roque, Anzoategui		PDVSA	100	5	5

		Total Venezuela			1,293	1,293

Netherlands Antilles (Curaçao)
	Isla (1)		PDVSA	100	335	335

United States
	Lake Charles, Louisiana		CITGO	100	320	320
	Corpus Christi, Texas		CITGO	100	157	157
	Paulsboro, New Jersey		CITGO	100	84	84
	Savannah, Georgia		CITGO	100	28	28
	Houston, Texas(2)		LYONDELL-CITGO	41	265	109
	Lemont, Illinois		PDVMR	100	167	167
	Chalmette, Louisiana(3)		Chalmette Refining	50	184	92
	Saint Croix, U.S. Virgin Islands(4)		Hovensa	50	495	248

		Total United States			1,700	1,205

Europe
	Gelsenkirchen, Germany(5)		Ruhr	50	226	113
	Schwedt, Germany(5)		Ruhr	19	210	39
	Neustadt, Germany(5)		Ruhr	13	246	31
	Karlsruhe, Germany(5)		Ruhr	12	275	33
	Nynäshamn, Sweden(6)		Nynäs	50	22	11
	Antwerp, Belgium(6)		Nynäs	50	14	7
	Gothenburg, Sweden(6)		Nynäs	50	11	6
	Dundee, Scotland(6)		Nynäs	50	10	5
	Eastham, England(6)		Nynäs	27	26	7

		Total Europe			1,040	252

		Total outside Venezuela			3,075	1,792

		Worldwide Total			4,368	3,085

(1): Leased in 1994. The lease expires in 2014.
(2): A joint venture with Lyondell Chemical Company.
(3): A joint venture with ExxonMobil
(4): A joint venture with Amerada Hess.
(5): A joint venture with Veba Oel.
(6): A joint venture with Fortum Oil and Gas OY.

In order to maintain our competitiveness within international markets, we expect to invest approximately $2,614 million from 2003 through 2008 in Venezuela to improve our refining systems and to adapt our systems to meet environmental regulations and domestic and international product quality requirements. We intend to implement AQUACONVERSION®, a PDVSA-owned technology for heavy crude oil processing, at the Isla Refinery in Curaçao. We are also expanding our delayed coking plants located at the refining complex in Paraguaná, Venezuela. Additionally, we are participating in projects aimed at the manufacture of gasoline. For example, the three fluid catalytic cracking units located at our Amuay, Cardón and El Palito refineries are being modified to manufacture gasoline. A low sulfur gasoline production unit (currently in the engineering phase) is expected to be operational in the first quarter of 2005, using oil products and technology developed by Intevep, a wholly-owned subsidiary of PDVSA. Finally, on March 13, 2001, we entered into a contract for approximately $300 million with a Venezuelan-Japanese Consortium led by the Japanese JGC Corporation (formed by the Japanese Chiyoda Corporation and the Venezuelan companies, Jantesa and Vepica) to construct naphtha hydrotreating facilities and diesel hydro-desulphurization and environmental units in a refinery located in Puerto La Cruz, referred to in this annual report as the VALCOR project. This project is budgeted at $500 million and is anticipated to be capable of producing 45MBPD of gasoline and 31MBPD of diesel blending components for the local market and for export.

Venezuela and the Caribbean

Our refineries in Venezuela are located at Amuay, Cardón, Puerto La Cruz, El Palito, Bajo Grande and San Roque, with rated crude oil refining capacities of 635 MBPD, 305 MBPD, 203 MBPD, 130 MBPD, 15 MBPD and 5 MBPD, respectively. We integrated our operations at the Amuay and Cardón refineries to form the Paraguaná Refining Complex, one of the world's largest refining complexes. We also operate the Isla Refinery in Curaçao, which we lease on a long-term basis from the Netherlands Antilles government. The lease expires in 2014. Through these refineries, we produce reformulated gasoline and distillates to meet the U.S. and other international market requirements.

United States

Through our wholly-owned subsidiary, CITGO, we produce light fuels and petrochemicals primarily through our refineries in Lake Charles, Louisiana; Corpus Christi, Texas; and Lemont, Illinois. Our asphalt refining operations are carried out through refineries in Paulsboro, New Jersey; and Savannah, Georgia. At December 31, 2002, the rated crude oil refining capacities at each of the above refineries were 320 MBPD, 157 MBPD, 167 MBPD, 84 MBPD and 28 MBPD, respectively.

CITGO's largest supplier of crude oil is PDVSA. CITGO has entered into long-term crude oil supply agreements with PDVSA with respect to the crude oil requirements for each of CITGO's Lake Charles, Corpus Christi, Paulsboro and Savannah refineries. These crude oil supply agreements require PDVSA to supply minimum quantities of crude oil and other feedstocks to CITGO for a fixed period, usually 20 to 25 years. These crude supply agreements contain force majeure provisions which entitle the supplier to reduce the quantity of crude oil and feedstocks delivered under the crude supply agreements under specified circumstances.

The Lake Charles refinery has a rated refining capacity of 320 MBPD and is capable of processing large volumes of heavy crude oil into a flexible slate of refined products, including significant quantities of high-octane unleaded gasoline and reformulated gasoline. Its main petrochemical products are propylene and benzene. Its industrial products include sulphur, residual fuels and petroleum coke. This refinery has one of the highest capacity levels for higher value-added products production in the United States, with a multiple stream capacity that allows it to continue operating with one or more units shut down. This refinery has a Solomon Process Complexity Rating of 17.7 (as compared to an average of 13.9 for U.S. refineries in Solomon Associates, Inc.'s most recently available survey). The Solomon Process Complexity Rating is an industry measure of a refinery's ability to produce higher value

products. A higher Solomon Process Complexity Rating indicates a greater capability to produce such products.

The Corpus Christi refinery has a refining capacity of 157 MBPD and a processing technology that enables it to produce premium grades of gasoline that exceed that of most of its U.S. competitors and to reduce sulfur levels in refined petroleum products. This refinery has a Solomon Process Complexity Rating of 16.3. The Corpus Christi refinery's main petrochemical products include cumene, cyclohexane, and aromatics (including benzene, toluene and xylene).

The Lemont refinery processes heavy crude oil into a flexible slate of refined products. The refinery has a rated refining capacity of 167 MBPD and has a Solomon Process Complexity Rating of 11.7. This refinery is one of the most recently designed and constructed refineries in the United States. It is a flexible deep conversion facility that produces primarily gasoline, diesel, jet fuel and petrochemicals. The average API gravity of the composite crude slate run at the Lemont refinery is approximately 26^o.

The refineries in Paulsboro, New Jersey and Savannah, Georgia are specialized asphalt refineries. The Paulsboro refinery, which is particularly suited to processing asphalt, also has facilities to processing low sulfur, light crude oil whenever favorable conditions exist.

Through LYONDELL-CITGO, a joint venture owned 41.25% by PDVSA and 58.75% by Lyondell, we have a net interest in refining capacity of 109 MBPD in a refinery located in Houston, Texas with a refining capacity of 265 MBPD. PDVSA supplies a substantial amount of the crude oil processed by this refinery under a long-term crude oil supply agreement that expires in the year 2017. Under this agreement, LYONDELL-CITGO purchased approximately $1.3 billion of crude oil and feedstocks at market related prices from PDVSA in 2002. CITGO purchases substantially all of the gasoline, diesel and jet fuel produced at this refinery under a long-term contract.

Various disputes exist between LYONDELL-CITGO and its partners and their respective affiliates concerning the interpretation of agreements between the parties relating to the operation of the refinery.

PDVSA Petróleo, pursuant to its contractual rights under the crude oil supply agreement with LYONDELL-CITGO, declared a force majeure situation in April 1998, and again in February 1999 through October 2000, as well as from February 2001 to March 2003. Petróleos de Venezuela, pursuant to its contractual rights under the supplemental supply agreement with LYONDELL-CITGO, which guarantees PDVSA Petróleo's obligations under the crude oil supply agreement, invoked its right to declare a force majeure situation during the same time periods. As a result of these declarations PDVSA Petróleo and Petróleos de Venezuela were relieved of their obligations to deliver crude oil under both agreements and LYONDELL-CITGO purchased crude oil from alternate sources. Recently, LYONDELL-CITGO received notice of force majeure from PDVSA Petróleo and/or Petróleos de Venezuela in December 2002. LYONDELL-CITGO purchased crude oil in the spot market to replace the volume not delivered under contract. The force majeure was lifted March 6, 2003. In February 2002, LYONDELL-CITGO commenced an action against PDVSA Petróleo and Petróleos de Venezuela in the Southern District of New York, alleging that PDVSA Petróleo and Petróleos de Venezuela wrongfully declared force majeure and further that PDVSA Petróleo and Petróleos de Venezuela breached the agreements by paying liquidated damages under the contract rather than delivering oil. See "Item 8A.7 Legal Proceedings."

Through Chalmette Refining, an equal-share joint venture between PDVSA and ExxonMobil, we have a net interest in refining capacity of 92 MBPD in a refinery located in Chalmette, Louisiana. The Chalmette refinery processes upgraded extra-heavy crude oil to be produced by our Cerro Negro joint venture. PDVSA (through PDV Chalmette) has an option to purchase up to 50% of the refined products produced at the Chalmette refinery. PDVSA (through CITGO) exercised its option during

2000, and acquired approximately 67 MBPD of refined products, approximately one-half of which was gasoline. PDVSA did not exercise or assign this option to CITGO for 2001 or 2002. ExxonMobil, which operates both the Cerro Negro joint venture and the Chalmette refinery, purchased substantially all of the refined products produced by the Chalmette refinery at market prices during 2001 and 2002. See "Item 4.B Business overview—Initiatives Involving Private Sector Participation—Orinoco Belt Extra-Heavy Crude Oil Projects."

In October 1998, we entered into agreements with Conoco to form Merey Sweeny, a joint venture to process crude oil in the United States, and with Amerada Hess to form Hovensa, a joint venture to process crude oil in the U.S. Virgin Islands.

Pursuant to the Sweeny joint venture, PDV Holding and Conoco own an integrated coker and vacuum crude distillation unit within an existing refinery owned by Conoco in Sweeny, Texas. Each party owns a 50% equity interest in this facility, which is composed of a 58 MBPD coker and a 110 MBPD vacuum crude distillation unit. Conoco will purchase heavy crude oil from us to be processed in the Sweeny refinery pursuant to a processing agreement. Revenues from the Sweeny joint venture will consist of fees paid by Conoco to the joint venture under the processing agreement and any revenues from the sale of coke to third parties.

Pursuant to the Hovensa joint venture, we purchased a 50% interest in a refinery in the U.S. Virgin Islands previously owned by Hess Oil Virgin Islands Corporation, with a current refining capacity of approximately 495 MBPD. The joint venture has entered into long-term supply contracts with PDVSA for up to 60% of its crude oil requirements. During 2002, Hovensa completed construction of a delayed coker unit and related facilities that it had been building in connection with the formation of the joint venture.

Europe

Through Ruhr, a joint venture owned 50% by PDVSA and Veba Oel, we have equity interests in refineries in four German refineries (Gelsenkirchen, Neustadt, Karlsruhe and Schwedt) in which our net interest in crude oil refining capacity at December 31, 2002 was 113 MBPD, 31 MBPD, 33 MBPD and 39 MBPD, respectively. Ruhr also owns two petrochemical complexes (Gelsenkirchen and Münchmünster). The Gelsenkirchen complex, which includes modern, large-scale units that are integrated with the crude oil refineries located in the same complex, primarily produces olefins, aromatic products, ammonia and methanol. The Münchmünster complex, integrated with the nearby Bayear Oil refinery, primarily produces olefins. Ruhr's petrochemical complexes have an average production capacity of approximately 3.8 million metric tons per year of olefins, aromatic products, methanol, ammonia and various other petrochemical products.

Through Nynäs, a joint venture owned 50.001% by PDV Europa and 49.999% by Fortum Oil and Gas OY, we own interests in four specialized refineries: Nynäshamn and Gothenburg in Sweden, Antwerp in Belgium and Dundee in Scotland. Our net interest in crude oil refining capacity in each of these refineries at December 31, 2002 was 11 MBPD, 6 MBPD, 7 MBPD and 5 MBPD, respectively. The Nynäs refineries are specially designed to process heavy sour crude oil. Nynäs also owns a 50% interest in a refinery in Eastham, England. The Eastham refinery is a specialized asphalt refinery in which our net interest crude oil refining capacity at December 31, 2002 was 7 MBPD.

The Nynäs refineries in Nynäshamn produce asphalt and naphthenic specialty oils. The Dundee, Gothenburg, Antwerp and Eastham refineries are specialized asphalt refineries. Nynäs purchases crude oil from us and produces asphalt and naphthenic specialty oils, two products for which Venezuelan heavy sour crude oil is particularly well suited to feedstock due to its proportions of naphthenic, paraffinic and aromatic compounds. Asphalt products are used for road construction and various industrial purposes, while naphthenic specialty oils are used principally in electrical transformers, as mechanical process oils and in the rubber and printing ink industries.

The following table sets forth our aggregate refinery capacity, input supplied by us (out of our own production or bought in the open market), product yield and utilization rate for the three-year period ended December 31, 2002.

PDVSA's Refinery Production

				Year Ended December 31,
				2002			2001			2000
				MBPD		% of Total	MBPD		% of Total	MBPD		% of Total
Total refining capacity				4,368			4,368			4,353

PDVSA's net interest in refining capacity				3,085			3,085			3,070

Refinery input(1):
	Crude oil
		PDVSA(2)		1,848		70	2,018		72	2,072		68

			Light (API gravity of 30^o or greater)	565		21	551		20	687		22
			Medium (API gravity of between 21^o and 30^o)	850		32	983		35	862		28
			Heavy (API gravity of less than 21^o)	433		17	484		17	523		18
		Other		440		16	483		17	555		18

			Light (API gravity of 30^o or greater)	330		12	356		13	378		12
			Medium (API gravity of between 21^o and 30^o)	84		3	120		4	49		2
			Heavy (API gravity of less than 21^o)	26		1	7		0	128		4

			Crude oil subtotal	2,288		86	2,501		89	2,627		86
	Other feedstocks
		PDVSA		250		9	168		6	303		10
		Other		120		5	139		5	138		4

			Other feedstocks subtotal	370		14	307		11	441		14
Total refinery input(3)
		PDVSA		2,098		79	2,186		78	2,375		77
		Other		560		21	622		22	693		23

			Total	2,658		100	2,808		100	3,068		100

Product yield(4):
	Gasoline/Naphtha			951		37	1,006		35	1,092		38
	Distillate			817		31	947		33	874		30
	Low sulfur residual			30		1	34		1	55		2
	High sulfur residual			273		11	339		12	344		12
	Asphalt/Coke			177		7	211		8	187		6
	Naphthenic specialty oil			12		1	9		0	12		0
	Petrochemicals			92		3	92		3	106		4
	Other			225		9	225		8	225		8

		Total product yield		2,577		100	2,863		100	2,895		100

Utilization(5)				74	%		81	%		86	%

(1): Our refineries sourced 81%, 81% and 60% of our total crude oil requirements from crude oil produced by us in 2002, 2001 and 2000, respectively.
(2): Sourced by us (including supplies from entities that are not subject to our control).
(3): Includes our interest in crude oil and other feedstocks.
(4): Our interest in product yield.
(5): Crude oil refinery input divided by the net interest in refining capacity.

In 2002, we supplied substantially all of the crude oil requirements to our Venezuelan refineries (approximately 879 MBPD), 186 MBPD of crude oil to our leased refinery in Curaçao and an aggregate of 1,223 MBPD of crude oil to refineries owned by our international subsidiaries or in which we otherwise have an interest. Of the total volumes supplied by us to our international affiliates, 213 MBPD were purchased by PDVSA in the global market and supplied to our European affiliates. Additionally, CITGO purchased a total of 320 MBPD of crude oil from PDVSA for processing in their refineries.

Marketing

In 2002, we exported 1,764 MBPD of crude oil or 66% of our total crude oil production and 647 MBPD of refined petroleum products produced in Venezuela. Of total exports of crude oil and refined petroleum products, 1,269 MBPD (53%) were sold to the United States and Canada. During the period from January through December 2002, according to the Petroleum Supply Monthly, we were the fourth largest aggregate supplier of crude oil and refined petroleum products in the United States.

Of our total crude oil exports in 2002, an aggregate of 1,053 MBPD (60%) were exported to the United States and Canada; 500 MBPD (28%) to the Caribbean and Central America; 134 MBPD (8%) to Europe and 77 MBPD (4%) to South America and other destinations.

Of our total refined petroleum products produced in Venezuela in 2002, approximately 420 MBPD were used in the domestic market and 647 MBPD were exported. Of the total exports of refined petroleum products in 2002, 216 MBPD (33%) were sold to the United States and Canada; 239 MBPD (37%) to the Caribbean and Central America and 192 MBPD (30%) to South America and other destinations.

The following tables set forth the composition and average prices of our exports of crude oil and refined petroleum products for the three-year period ended December 31, 2002:

PDVSA's Export Volumes

				Year Ended December 31,
				2002		2001		2000
				MBPD	% of Total	MBPD	% of Total	MBPD	% of Total
Crude oil(1):
	Light (API gravity of 30^o or more)			672	38	659	32	716	36
	Medium (API gravity of between 21^o and 30^o)			360	20	585	28	586	29
	Heavy and extra-heavy (API gravity of less than 21^o)			732	42	821	40	696	35

		Subtotal		1,764	100	2,065	100	1,998	100

Refined products:
	Gasoline/Naphtha			137	21	165	24	186	23
	Distillate(2)			231	36	241	35	294	36
	Low sulfur residual			—	—	3	—	29	3
	High sulfur residual			149	23	189	27	187	23
	Liquid petroleum gas			56	9	44	6	43	5
	Other			74	11	55	8	86	10

		Subtotal		647	100	697	100	825	100

			Total exports	2,411		2,762		2,823

(1): Includes sales of crude oil to subsidiaries and affiliated refineries (including to the Isla Refinery in Curaçao) of 1,028 MBPD, 1,143 MBPD and 973 MBPD in 2002, 2001 and 2000, respectively.
(2): Includes kerosene.

The following table sets forth the average prices of our exports of crude oil and refined petroleum products from Venezuela for the three-year period ended December 31, 2002:

PDVSA's Average Export Prices

	Year Ended December 31,
	2002	2001	2000
	($ per barrel)
Crude oil(1)	21.35	18.95	24.94
Refined products	24.23	23.94	28.40
Liquefied petroleum gas	17.65	19.55	25.42
Average for the year	21.94	20.21	25.91

(1): Includes sales of crude oil to affiliates.

The following table sets forth the geographic breakdown of our exports by types of crude oil, identifying sales to affiliates and third parties for the three-year period ended December 31, 2002:

PDVSA's Total Crude Oil and Refined Products Export Volumes

	Year Ended December 31,
	2002			2001			2000
	(MBPD)		(% of Total)	(MBPD)		(% of Total)	(MBPD)		(% of Total)
Crude oil:
All types		1,764	100		2,065	100		1,998	100

United States and Canada		1,053	60		1,190	58		1,185	59

Affiliates		678	38		694	34		518	26
Third parties		375	22		496	24		667	33
Europe		134	8		151	7		138	7

Affiliates		61	4		63	3		71	4
Third parties		73	4		88	4		67	3
Caribbean and Central America		500	28		573	28		571	29

Affiliates		360	20		386	19		373	19
Third parties		140	8		187	9		198	10
South America and others		77	4		151	7		104	5

Third parties		77	4		151	7		104	5
Light (API gravity of 30^o or greater)(1)		672	38		659	32		716	36

United States and Canada		256	14		273	13		417	21
Others		416	24		386	19		299	15
Medium/Heavy (API gravity of less than 30^o)(2)		1,092	62		1,406	68		1,282	64

United States and Canada		797	45		913	44		767	38
Others		295	17		493	24		515	26
Refined petroleum products:		647	100		697	100		825	100

United States and Canada		216	33		307	44		356	43
Others		431	67		390	56		469	57
Total crude oil and refined petroleum products exports		2,411	n.a.		2,762	n.a.		2,823	n.a.

Average sales price per barrel (in $):
Light (API gravity of 30^o or greater)	$	23.46		$	22.47		$	28.20
Medium/Heavy (API gravity of less than 30^o)	$	20.24		$	17.29		$	23.12
Refined petroleum products	$	24.23		$	23.94		$	28.40

(1): Includes condensate.
(2): Crude oils can also be classified by sulfur content (by weight). "Sour" crudes contain 0.5% or greater sulfur content (by weight) and "sweet" crudes contain less than 0.5% sulfur content (by weight). Substantially all of our exports are classified as sour crude.

The following table sets forth our consolidated sales volume of crude oil and refined petroleum products for the three-year period ended December 31, 2002:

PDVSA's Consolidated Sales Volume

	Year Ended December 31,
	2002		2001		2000
	(MBPD)	(% of Total)	(MBPD)	(% of Total)	(MBPD)	(% of Total)
Refined petroleum products	2,583	59	2,586	58	2,913	63
Crude oil	1,782	41	1,892	42	1,755	37

Total	4,365	100	4,478	100	4,668	100

Average Price/Barrel ($/barrel)	26.56		28.21		29.13

Marketing in the United States

Sales of Crude Oil to Affiliates. We supply our international refining affiliates with crude oil and feedstocks either produced by us or purchased in the open market. Some of our U.S. affiliates have entered into long-term supply contracts with us that require us to supply minimum quantities of crude oil and other feedstocks to such affiliates for a fixed period of typically 20 to 25 years. These contracts are scheduled to expire in or after 2006.

Such contracts incorporate price formulas based on the market value of a slate of refined petroleum products deemed to be produced from each particular grade of crude oil or feedstocks, less certain deemed refining costs, certain actual costs, including transportation charges, import duties and taxes, and a fixed margin, which varies according to the grade of crude oil or other feedstocks delivered. Fixed margins and deemed costs are adjusted periodically by a formula that is primarily based on the rate of inflation. Because deemed operating costs and the slate of refined petroleum products deemed to be produced for a given barrel of crude oil or other feedstocks do not necessarily reflect the actual costs and yields in any period, the actual refining margin earned by the purchaser under the various contracts will vary depending on, among other things, the efficiency with which such purchaser conducts its operations during such period. These contracts are designed to reduce the inherent earnings volatility of the refining and marketing operations of our international refining affiliates. Other supply contracts between us and our U.S. affiliates provide for the sale of crude oil at market prices.

Some of the above contracts provide that, under certain circumstances, if supplies are interrupted, we are required to compensate the affected affiliate for any additional costs incurred in securing crude oil or other feedstocks. These crude oil supply contracts may be terminated by mutual agreement, by either party in the event of a material default, bankruptcy or similar financial hardship on the part of the other party or, in certain cases, if we no longer hold, directly or indirectly, 50% or more of the ownership interests in the related affiliate.

Sales of Crude Oil to Third Parties. Most of our export sales of crude oil to third parties, including customers in the United States with which we maintain long-standing commercial relationships, are made at market prices pursuant to our general terms and conditions, and priced in dollars. Among our customers are major oil companies and other medium-sized companies. Although our general terms and conditions do not require specified volumes to be bought or sold, historically, a majority of our customers have taken shipments on a regular basis at a relatively constant volume throughout the year.

Sales of Refined Products. We conduct all our retail sales in the United States through CITGO. CITGO's major products are light fuels (including gasoline, jet fuel and diesel fuel), industrial products and petrochemicals, asphalt, and lubricants and waxes. Gasoline sales accounted for 61% of CITGO's total sales in 2002. CITGO markets CITGO-branded gasoline through approximately 13,000 independently owned and operated retail outlets, located throughout the United States, primarily east of the Rocky Mountains.

CITGO also markets jet fuel directly to airline customers at over 20 airports, diesel fuel in wholesale rack sales to distributors and in bulk through contract sales (primarily as heating oil in the Northeast region of the United States) or on a spot basis, petrochemicals in bulk to a variety of U.S. manufacturers as raw

materials for finished goods, including sulfur, cycle oils, liquid petroleum gas, petroleum coke and residual fuel oil, asphalt to independent contractors for use in the construction and resurfacing of roadways, and many different types, grades and container sizes of lubricant and wax products.

Crude Oil and Refined Product Purchases. CITGO owns no crude oil reserves or production facilities and must therefore rely on purchases of crude oil and feedstocks for its refinery operations. We are CITGO's largest supplier of crude oil, and CITGO has entered into long-term crude oil supply agreements with us with respect to the crude oil requirements for each of CITGO's refineries. CITGO also purchases crude oil in the market. In addition, because CITGO's refinery operations do not produce sufficient refined petroleum products to meet the demands of its branded distributors, CITGO purchases refined petroleum products, primarily gasoline, from third party refiners. CITGO also purchases refined petroleum products from various other affiliates, including LYONDELL-CITGO, Chalmette Refining and Hovensa, pursuant to long-term contracts. In 2002, CITGO purchased 321 MBPD of refined petroleum products under these contracts. In addition, CITGO occasionally purchases on a spot basis refined petroleum products from our Venezuelan refineries.

Marketing in Europe

We supply crude oil to our European affiliates pursuant to various supply agreements. The crude oil that we supply to our European affiliates exceeds, as a percentage of total supply, our aggregate net ownership interest in such entities' combined refining capacity. In 2002, we supplied to the European refineries in which we held an interest, 245 MBPD of crude oil, of which 32 MBPD were exported from Venezuela and 213 MBPD were purchased in world markets.

The crude oil processed at the Ruhr Oel refineries is supplied 50% by us and 50% by Veba Oel pursuant to a joint venture agreement and a long-term supply contract. Pursuant to these agreements, Ruhr does not acquire title to any crude oil or refined petroleum products. Instead, the crude oil supplied by us or Veba Oel remains owned by us or Veba Oel, as applicable, throughout the refining process. Our share of the refined petroleum products processed at the Ruhr Oel refineries is distributed through Veba Oel's marketing network. The operating costs of the Ruhr Oel refineries are shared equally by us and Veba Oel.

We receive 50% of the revenues from Veba Oel's sales of the refined petroleum products processed at the Ruhr Oel refineries, less attributable operating and marketing costs. This arrangement effectively provides Ruhr Oel with constant break-even results. We supply crude oil to the Ruhr Oel refineries and receive revenues from the sale of refined petroleum products attributable to such crude oil.

Nynäs purchases crude oil from PDVSA and produces asphalt and naphthenic specialty oils, two products for which Venezuelan heavy sour crude oil is particularly well suited to feedstock due to its proportions of naphthenic, paraffinic and aromatic compounds. Asphalt products are used for road construction and various industrial purposes, while naphthenic specialty oils are used principally in electrical transformers, as mechanical process oils and in the rubber and printing ink industries. Nynäs does not own crude oil reserves or production facilities and, therefore, must purchase crude oil for its refining operations. Nearly all crude oil purchased by Nynäs is supplied by us pursuant to long-term supply contracts. We supply Nynäs only with high sulfur, extra-heavy Venezuelan crude oil.

Nynäs markets asphalt products through an extensive marketing network in several European countries. Scandinavia, the United Kingdom and Continental Europe are the source of 24%, 22% and 22%, respectively, of Nynäs' consolidated revenues for 2002. Nynäs markets its naphthenic specialty oils throughout Europe, Africa, the Middle East and Australia, and the distillates that it produces are either sold as fuel or further processed into naphthenic specialty oils. Nynäs distributes its refined products primarily by specialized bitumen ships, rail tanks and trucks. Nynäs also maintains a terminal system network in Scandinavia.

Marketing in Latin America and Caribbean

We have begun implementing our market development strategy for Latin America and the Caribbean, through CITGO Latin America, or "CILA," CITGO's wholly-owned subsidiary. Through CILA, we are introducing the PDV and CITGO brands into various Latin American markets, including wholesale and retail sales of lubricants, gasoline and distillates. CILA's operations currently are in Puerto Rico, Mexico, Ecuador, Chile and Brazil.

Marketing in Venezuela

The following table shows our sales of refined petroleum products and natural gas of the Venezuelan domestic market:

PDVSA's Local Market Sales

				Year Ended December 31,
				2002		2001		2000
				(MBPD, except as otherwise indicated)
Refined Products:
	Liquefied petroleum gas				59		67		67
		Motor gasolines			207		225		208
		Diesel			91		98		82
		Other			63		68		54

			Total		420		458		411

Natural gas (BOE)					324		307		288
Natural gas (MMCF)					1,879		1,780		1,670
Unit Sale Prices:
Refined products ($ per barrel)				$	6.73	$	8.74	$	9.20
Natural gas ($/BOE)				$	4.34	$	5.35	$	5.29
Natural gas ($/MCF)				$	0.71	$	0.88	$	0.90

Since December 1993, the Venezuelan government has permitted private sector participants to market lubricants in Venezuela.

Since January 1997, through our subsidiary Deltaven, we have been marketing and distributing retail gasoline and other refined petroleum products under the PDV brand in the Venezuelan local market. Deltaven is also promoting the development of the commercial infrastructure and services for retail clients with the participation of the private sector.

The retail price for gasoline is set by the Venezuelan government and represents approximately 35% of the export price for gasoline in 2002.

Effective November 1997, the Venezuelan government has permitted private sector participants to market gasoline and other refined petroleum products in Venezuela through retail outlets owned or operated by such participants. At the end of 2001, three private domestic participants, Grupo Trebol, Llanopetrol and CCMonagas, and four private international participants, Shell, ChevronTexaco, ExxonMobil and British Petroleum, were marketing their products in Venezuela. These companies market their brands through 830 retail outlets owned or operated by them, and have a market share in the gasoline and diesel sector of 53% compared to Deltaven's 47%.

Gas

Venezuela has abundant natural gas deposits that, in 2002, were estimated at 226,000 BCF, of which 147,000 BCF are proved reserves. Of these reserves, 91% are associated with crude oil deposits and 9% are in the form of free gas. At December 2002, our total production capacity and sales of methane gas were 4,594 MMCFD and 2,158 MMCFD, respectively. Substantially all of the sales were to the Venezuelan market.

According to BP AMOCO Statistical Review of World Energy dated December 2002, Venezuela is the eighth largest owner of proved reserves in the world and the largest owner of proved reserves in Latin America. These reserves can easily supply a domestic market of 1,837 MMCFD

Petrochemicals

Pequiven is our subsidiary, established in 1977 to produce and commercialize petrochemical products in the domestic and international markets. Pequiven is organized into business units focused on three production lines:

•: olefins and derivative products;
•: fertilizers; and
•: industrial products.

Pequiven is party to 17 joint ventures with domestic and international business partners. Most of the production facilities of these joint ventures are located at Pequiven's complexes. We estimate that the combined production capacity of these complexes is approximately eight million tons.

Pequiven operates three petrochemical complexes in Venezuela:

•: the Zulia—El Tablazo complex, in western Venezuela, which produces mainly olefins, chlorine or caustic soda, fertilizers, industrial feedstocks and thermoplastic resins;
•: the Morón Complex, in central Venezuela, which produces fertilizers and sulfuric acid; and
•: the Jose Complex, in eastern Venezuela, which produces methanol, fertilizers, industrial products and methyl-terbutyl-ether (MTBE).

In addition to the three petrochemical complexes, Pequiven also has facilities to produce aromatics in the PDVSA El Palito refinery, located in the central north region of Venezuela. The gross production of Pequiven's wholly-owned plants and complexes in 2002 and 2001 was approximately 3.7 million metric tons and 4.1 million metric tons, respectively. The gross production of Pequiven's joint ventures in 2002 and 2001 was approximately 3.23 million metric tons and 4.97 million metric tons, respectively. Products of these joint ventures include methanol, MTBE, ethylene, propylene, polyethylenes, polypropylenes, ethylene oxide, ethylene glycols, ethylene dichloride, caustic soda, chlorine, fertilizers, caprolactam and other specialty products.

Through Pequiven, our goals are to increase the production of our petrochemical products and promote growth in this sector by increasing the sales of petrochemical products domestically. We hope to achieve an annual combined production capacity of 13.5 million metric tons by 2006 at Pequiven's plants and through Pequiven's joint ventures. Pequiven also will continue to focus on improving competitiveness (especially in the Latin-American market) and profitability of the natural chemical and petrochemical sector.

In this regard, Pequiven continuously explores new projects and joint ventures with third parties. We currently are in discussions with potential partners regarding the development of the Jose Complex. To date, Pequiven's joint ventures have allowed it to establish a significant and growing presence in regional and international markets. In 2003, North America remained Pequiven's largest export destination (49%), followed by South America (38%), Europe and Asia (10%), and Central America and the Caribbean (3%).

The following table sets forth Pequiven's sales, consolidated revenues, net property, plant and equipment and capital expenditures in its wholly-owned plants for each of the years indicated:

Pequiven's Sales, Consolidated Revenues, Net Property, Plant and Equipment and Capital Expenditures

	Year ended December 31,
	2002	2001	2000
	($ in millions, except as otherwise indicated)
Sales volume (thousands of metric tons)	4,127	4,167	3,564
Consolidated revenues(1)	919	1,070	1,010
Net property, plant and equipment at year end	1,925	2,221	2,245
Capital expenditures	53	46	66

(1): Includes $268 million, $351 million and $329 million of sales to affiliates for 2002, 2001 and 2000, respectively; and sales to PDVSA's subsidiaries, which are eliminated in our consolidated financial statements.

Natural Bitumen

We have developed a process of emulsifying natural bitumen in water to create an alternative liquid fuel to generate electricity, which we refer to as Orimulsion®. We believe that Orimulsion® offers competitive advantages over coal and fuel oil in terms of combustion properties, environmental impact, user-friendliness and production costs.

We market Orimulsion® worldwide through our wholly-owned marketing subsidiaries. In Japan, we market Orimulsion through a 50%-owned joint venture with Mitsubishi Corporation, and we market the product in Europe and North America through Bitor Energy PLC, located in London, and Bitor America Corporation, located in Florida, respectively.

We are in the process of developing reservoirs containing approximately 321.6 million of metric tons of bitumen (or approximately 2,010 million barrels). We generally manage all the resources needed to manufacture Orimulsion®. However, we also produce Orimulsion® together with our joint venture partners. Our business strategy for the near future in respect of expanding our Orimulsion® production business is as follows:

•: In December 2001, PDVSA, China National Oil and Gas Exploration and Development Corporation and Petrochina Fuel Oil Company Limited formed a joint venture called Orifuels Sinoven, S.A. with the view to building and operating a production facility capable of producing up to 6.5 million metric tons by 2005. As of today, Orifuels Sinoven, S.A. has already developed approximately 11% of the production facilities. We believe that the production levels at this facility, when completed, will meet the growing demand for alternative fuel of the Chinese market.
•: We have two new Orimulsion® manufacturing facilities currently under construction. We anticipate these facilities to commence operations by the third quarter of 2005.
•: We also propose to build a third Orimulsion® manufacturing complex, with a view to meeting the expanding demand of markets such as Italy, Korea and Canada. We expect to complete the construction of this manufacturing plant by 2007.

Our Orimulsion® production capacity is currently 6.5 million metric tons per year (or approximately 1 million barrels). Our net production in 2002 was approximately 5.8 million metric tons

(or 0.94 million barrels), as compared to 6.2 million metric tons (or 0.99 million barrels) in 2001. We believe that we will be able to achieve a production capacity of 19.5 million metric tons (or 3.1 million barrels) of Orimulsion® per year by 2006.

PDVSA's 2002 Orimulsion® production was sold as follows:

Geographic location	% of sales
Italy	44	%
China	15	%
Denmark	15	%
Canada	12	%
Japan	11	%
Others	3	%

The following table sets forth certain production, revenue and capital expenditure figures relating to our Orimulsion® business for the periods indicated:

	Year ended December 31,
	2002	2001	2000
Raw material production (thousands of metric tons)	4,041	4,257	4,175
Production (thousands of metric tons)	5,784	6,226	6,255
Orimulsion sales volume (thousands of metric tons)	5,575	6,173	6,235
Consolidated revenues ($ in millions)	186	200	215
Net property, plant and equipment ($ in millions)	544	551	556
Capital expenditure ($ in millions)	9	43	51

Coal

We are an active participant in the coal mining industry through our wholly-owned subsidiary, Carbozulia. Venezuela's most important coal deposits are in the Guasare Basin, which is located in the northwestern state of Zulia. There are approximately three thousand million metric tons of coal resources and four mines in the Guasare Basin. Currently, two mines in the Guasare Basin are operational and approximately 4% of resources in the basin are being exploited. It is estimated that up to 15% of such resources can be drilled using current operating methods. Carbozulia has entered into two joint venture agreements with foreign companies to operate the two currently operational mines.

The following table sets forth Carbozulia's share of coal production, sales and revenues for each of the periods indicated:

Carbozulia's Production, Sales and Consolidated Revenues

	Year Ended December 31,
	2002	2001	2000
	(thousands of metric tons, except as otherwise indicated)
Coal production	7,859	7,571	7,748
Coal sales volume	7,361	7,627	8,097
Consolidated revenues ($ in millions)	160	164	112

Carbozulia's total coal production is exported, primarily to the United States, Italy, Holland, Brasil, Canada, France, Sweden, Peru and Spain.

Carbozulia's business plan for 2003-2008 focuses on increasing its coal production to a targeted 21.0 million metric tons per year. It also intends to construct a transportation infrastructure that includes a 70 km railroad and port facilities. We believe that Carbozulia's business plan will be aided by the abundance of quality coal reserves in Venezuela (approximately 3,000 million metric tons) and our strong presence in the international market. We also believe that Carbozulia's business plan would enable it to attain an increase in its market share of between 5% and 10% from its market share today, generating revenues of up to $8 billion, over the next 10 years. This growth strategy is capital intensive and, we believe, will require approximately $1.1 billion in funding.

Our above projections are based on an expected sustained growth of the power generation industry, our main target market. We also base our assessments on projections of the International Energy Agency, predicting an increase in coal production of about 200 millions metric tons over the next 20 years. The International Energy Agency also projects that over the next 20 years, the thermoelectrical industry is expected to grow at the rate of approximately 0.6% in the United States, 5.5% in Europe and 14% in Latin America, with coal prices remaining at prices that are comparative to gas and fuel oil prices.

Overview of Main Projects

The VALCOR Project

On March 13, 2001, we entered into a contract for approximately $300 million with a Venezuelan-Japanese Consortium led by the Japanese JGC Corporation (formed by the Japanese Chiyoda Corporation and the Venezuelan companies, Jantesa and Vepica) to construct naphtha hydrotreating facilities and diesel hydro-desulphurization and environmental units in a refinery located in Puerto La Cruz, referred to in this annual report as the VALCOR project. The primary objective of this project is to produce unleaded gasoline to meet the demands of the local market and to distillates of low sulphur content for export to international markets. The new facilities and processing units are currently being constructed for purposes of this project. As of October 2003, the construction of these facilities was approximately 96% completed. We expect to complete the construction and commence production during the first quarter of 2004. This project is budgeted at $500 million and is anticipated to be capable of producing 45MBPD of gasoline and 31MBPD of diesel blending components.

The Plataforma Deltana Project

The exploratory drilling phase of our Plataforma Deltana project began in February 2002 in marine areas located east of the Orinoco Delta, and southeast of the border with Trinidad and Tobago, covering an area of 6,500 square kilometers. The Plataforma Deltana gas project includes the participation of third parties to complete exploration and future development of the area. PDVSA completed the initial phase of the project, including seismic studies and drilling of four exploratory wells, by December 31, 2002, and our total investment in this project has amounted to $180 million. During 2002, the first phase of the selection of partners was completed. Licenses for exploration and development for two of the five blocks comprising the project were granted by the Ministry of Energy and Mines to two multinational oil and gas companies in February 2003. These companies are committed to a minimum exploratory program, with an estimated investment of $150 million, and to subsequent investments for development if commerciality is confirmed. PDVSA's participation in the partnership, which could range from 1% to 35%, will be determined upon declaration of commercial viability of each block. The selection of partners for two other blocks, from 13 participating multinational companies, will be announced by the end of November 2003.

We have budgeted $375 million for this initial phase, which is expected to last between two to five years. At present, three exploratory wells have been drilled.

The semi-sub drilling rig used for this project can operate between 150 feet and 1,500 feet water depths and drill up to 25,000 feet wells. The rig has a capacity for housing more than 100 people. There are 440 workers assigned to this project, 83% of whom are Venezuelan (including workers of the Warao ethnic group, originally from the Deltana area).

The objective of this project is to add new non-associated natural gas reserves to meet our domestic market requirements, and for export purposes.

We expect that a successful first phase of this Plataforma Deltana exploration campaign, which is concentrated on an area of approximately 1,000 square kilometers, will lead to a gas development project with expected reserves of approximately 10,000 BCF and estimated investments totaling approximately $4 billion.

We believe that this project will contribute toward the expansion of our gas business, and will promote diversity of energy sources in Venezuela.

The Anaco Gas Project

We currently are in the process of drilling an exploratory well located north of Anaco. The objective of the Anaco Gas Project is to satisfy the internal demand for gas. This project includes designing and building the facilities anticipated to yield a daily production of 2,400 million cubic feet of gas and 35 thousand barrels of associated light crude oil when completed. The project is being developed in two phases, with start up operations capable of producing 2,016 million cubic feet of gas anticipated to commence in 2005. We expect the production capacity of this project to reach 2,400 million cubic feet of gas per day in 2007. Our total estimated investment for this project is $658 million, of which $475 has been obtained from Citibank of Japan.

The ICO Project

The objective of this project is to connect Venezuela's Central and Eastern (Anaco-Barquisimeto) and Western (Ule-Amuay) natural gas transmission systems with a view to:

•: facilitating the supply of gas to the western region of Venezuela;
•: expanding the delivery of gas to other regions and cities within the country; and
•: promoting industrial and commercial development in the areas along the gas transmission pipeline to be built in connection with this project.

In connection with this project, we expect to construct a 30-inch, 300 km gas pipeline running from Morón to Rio Seco (see table below) and three compression stations located at Altagracia, Los Morros and Morón. As of the end of the third quarter of 2003, phase 1 of this project has been completed. Construction of the pipeline and compression station will commence in 2004.

We expect to invest approximately $510 million in this project, and we anticipate that this project will be completed by the first quarter of 2006.

ICO Project Gas Pipeline and Compression Stations

Transportation and Infrastructure

Pipelines and Storage

Venezuela and the Caribbean. We have an extensive transportation network in Venezuela consisting of approximately 3,113 km in total of crude oil pipelines (over 28 pipelines), with a throughput capacity of approximately 6,340 MBD of crude oil. These pipelines connect production areas to terminal facilities and refineries. We have a network of gas pipelines in Venezuela totaling approximately 3,781 km, with a throughput capacity of 2,748 million MM3D. Our network is comprised of the Western and East Central systems, stretching from Lake Maracaibo, in the Zulia state to Punto Fijo, in the Falcón state and from Puerto Ordaz, in the Bolívar state to Barquisimeto, in the Lara state. We also have a network of 1,179 km of products pipelines with a total flow capacity of approximately 831 MBPD.

We maintain total crude oil and refined products storage capacity of approximately 30 MMB and 74 MMB in Venezuela, respectively, including tank farms, refineries and shipping terminals, of which approximately 16.3 MMB is available at our refineries. Our terminal facilities are comprised of nine maritime ports as well as two river ports. A new terminal facility was completed at the Jose Complex in 2002.

In addition to the storage and terminal facilities in Venezuela, we maintain storage and terminal facilities in the Caribbean, located in Bonaire, the Bahamas, Trinidad, Curaçao and St. Eustatius, with an aggregate storage capacity of 50 MMB at December 31, 2002. The Curaçao oil terminal, which is leased from the Netherlands Antilles government, had a storage capacity of approximately 15 MMB at December 31, 2002.

United States. CITGO owns and operates a crude oil pipeline and three products pipeline systems. CITGO also has equity interests in three crude oil pipeline companies and six refined product pipeline companies. CITGO's pipeline interests provide it with access to substantial refinery feedstocks and reliable transportation to the refined product markets, as well as cash flows from dividends. One of the refined product pipelines in which CITGO has an interest, Colonial Pipeline, is the largest refined product pipeline in the United States, transporting refined products form the Gulf Coast to mid-Atlantic and Eastern seaboard states.

Europe. Through equity interests in five European pipeline companies, we have interests in four crude oil terminals and four crude oil pipelines in northwestern Europe, including two pipelines from the Mediterranean coast to Germany. We also own three port facilities in the Rhine-Herne Canal providing barge access to Rhine and North Sea coastal ports.

Shipping

At December 31, 2002, PDV Marina, a wholly-owned subsidiary of Petróleos de Venezuela, owned and operated 21 tankers with a total capacity of approximately 1,347 MDWT and an average age at December 31, 2002 of approximately 13 years.

During 2002, average shipments of crude oil and refined petroleum products amounted to approximately 1,058 MBPD, of which 373 MBPD were shipped by our own tankers and the remainder by chartered tankers.

Research and Development

Intevep is our wholly-owned subsidiary responsible for research and technology support. Its overall mission is to create and sustain a competitive advantage for PDVSA through efficient and effective development, adaptation and application of technology. Intevep contributes substantially, through application of technology, toward the exploration for new oil and gas reserves, better utilization of existing reserves, increases in production, reduction in operational cost, greater productivity, upgraded processes for heavy and extra-heavy crude oil, improvements in product quality, improvements in health and safety standards and the development of new petroleum-derived products and innovative processes.

During 2002, we continued to develop products and technologies, including:

•: DISOL®, a gas-to-liquid technology;
•: AQUADIESEL®, a low emission diesel for public transportation; and
•: AQUACONVERSION®, a catalytic process used to produce upgraded crude oil.

During 2002, we completed construction of the basic structure of a new DISOL® plant and improved on the capabilities of the DISOL® catalyst. We also successfully tested AQUADIESEL® in Houston, Texas, in the United States, and made progress in reducing AQUADIESEL® production costs.

Environmental and Safety Matters

Environmental

The majority of Petróleos de Venezuela's subsidiaries, both in Venezuela and abroad, are subject to various environmental laws and regulations under which they may be required to make significant expenditures to modify their facilities and to prevent or remedy the environmental effects of waste disposal and spills of pollutants. In the United States and Europe, our operations are subject to various federal, state and local environmental laws and regulations, which may require them to take action to remedy or alleviate the effects on the environment of earlier plant decommissioning or leakage of pollutants.

and American Petroleum Institute (API)'s 750 for process safety. In addition, PDVSA has an investment plan to comply with the applicable environmental regulations in Venezuela. This investment plan contemplates approximately $2,227 million in capital expenditure from 2003 through 2008, including the following: $1,180 million for product quality; $690 million for risk control at operating sites; $312 million for environmental compliance projects; and $45 million for other environmental-related investments. CITGO estimates expenditures of approximately $1,300 million for environmental and regulatory capital projects from 2003 through 2007. During 2002, PDVSA spent approximately $9 million in Venezuela and CITGO spent approximately $148 million for environmental and regulatory capital improvements in its operations.

During the work stoppage in December 2002 and January 2003, there were oil spills which affected the environment in Venezuela. Two technical reports were prepared; one by INTEVEP (PDVSA's Research and Development Center) and ICLAM (Maracaibo Lake Conservation Institute) and the other by the Simón Bolívar University and IVIC (Venezuelan Scientific Investigations Institute). Both reports conclude that the impact of the oil spills are minor and are located principally in the Maracaibo Lake area. These conclusions were confirmed by the Ministry of Environment. The remediation costs for these minor oil spills are covered by the operating budget of the Western Operations Division of PDVSA.

CITGO has received various notices of violation from the Environmental Protection Agency (EPA)and other regulatory agencies, which include notices under the federal Clean Air Act, and could be designated as Potentially Responsible Parties ("PRPs") jointly with other industrial companies with respect to sites under the Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA). These notices are being reviewed and, in some cases, remedial action is being taken or CITGO is engaged in settlement negotiations.

Conditions that require additional expenditures may exist at various sites including, but not limited to, our operating complexes, closed refineries, service stations and crude oil and petroleum storage terminals. Based on currently available information we cannot determine the amounts of any such expenditures. Management believes that these matters, in the normal course of operations, will not have a material effect on the financial position, liquidity or operations of PDVSA.

Safety

Due to the nature of our business, our operating subsidiaries and joint ventures are subject to stringent occupational health and safety laws in the jurisdictions in which they operate. As such, each of our subsidiaries and joint ventures maintains comprehensive safety, training and maintenance programs with the help of international and recognized leading authorities in this area. Our management believes that our activities are conducted substantially in compliance with all applicable laws.

4.C Organizational structure

Petróleos de Venezuela was formed by the Venezuelan government in 1975, and conducts its operations through its Venezuelan and international subsidiaries.

Through December 31, 1997, we conducted our operations in Venezuela through three main operating subsidiaries, Corpoven, S.A., Lagoven, S.A. and Maraven, S.A. In 1997, we established a new operating structure based on business units. Since then, we have been involved in a process of transforming our operations with the aim of improving our productivity, modernizing our administrative processes and enhancing the return on capital. The transformation process involved the merger of Lagoven, S.A. and Maraven, S.A. into Corpoven S.A., effective January 1, 1998, and renaming the combined entity PDVSA-P&G. In May 2001, we renamed PDVSA-P&G "PDVSA Petróleo" and began the process of transferring certain of our nonassociated gas assets to PDVSA Gas during the second quarter of 2001.

Additionally, we have also made several adjustments within our organization in order to enhance internal control of our operations, to improve on our governance model and to align our operating structure with the long-term strategies of our shareholder. These adjustments consist primarily of the adoption of a new framework of operating structure that increases the involvement of our board of directors in our activities, and, at the same time, enhances PDVSA's operational independence. These adjustments are also a part of our effort to promote private investment in our subsidiaries, PDVSA Gas, Pequiven, Bitor and Carbozulia.

Our significant subsidiaries at December 31, 2002 and our percentage of equity capital (to the nearest whole number) are set out below. The principal country of operation is generally indicated by the subsidiary's country of incorporation:

Significant Subsidiary	% Ownership	Principal Activities	Country of Incorporation
AB Nynäs Petroleum	50	Refining and marketing	Sweden
Bitúmenes Orinoco, S.A.	100	Orimulsion	Venezuela
Bonaire Petroleum Corporation N. V.	100	Storage	The Netherlands Antilles
Carbones del Zulia, S.A.	100	Coal	Venezuela
Chalmette Refining, L.L.C.	50	Refining	United States
CITGO Petroleum Corporation	100	Refining, marketing and transportation	United States
Corporación Venezolana del Petróleo, S.A.	100	Exploration and production	Venezuela
Deltaven, S.A.	100	Marketing (in Venezuela)	Venezuela
Hovensa, L.L.C.	50	Refining	U.S. Virgin Islands
Intevep, S.A.	100	Research and development	Venezuela
LYONDELL-CITGO Refining Company, L.P.	41	Refining	United States
PDV America, Inc.	100	Refining, marketing and transportation	United States
PDV Europa B.V.	100	Refining and marketing	The Netherlands
PDV Holding, Inc.	100	Refining, marketing and transportation	United States
PDV Insurance Company Ltd.	100	Insurance	Bermuda
PDV Marina, S.A.	100	Shipping	Venezuela
PDV Midwest Refining, L.L.C.	100	Refining and marketing	United States
PDVSA Finance Ltd.	100	Financing	The Cayman Islands
PDVSA Gas, S.A.	100	Gas	Venezuela
PDVSA Petróleo, S.A.	100	Integrated oil operations	Venezuela
Petroquímica de Venezuela, S.A.	100	Chemicals and petrochemicals	Venezuela
Ruhr Oel GmbH	50	Refining and marketing	Germany
The Bahamas Oil Refining Company International Limited	100	Storage	The Bahamas

Item 5. Operating and Financial Review and Prospects

Overview and Trends

Our consolidated financial results depend primarily on the volume of crude oil produced and the price levels for hydrocarbons. The level of crude oil production and the capital expenditures needed to

achieve such level of production have been among the principal factors determining our financial condition and results of operations since 1990, and are expected to continue to be the principal factors in determining our financial condition and results of operations for the foreseeable future.

Historically, members of the OPEC have entered into agreements to reduce their production of crude oil. Such agreements have sometimes increased global crude oil prices by decreasing the global supply of crude oil. Venezuela is a party to and has complied with such agreements, and we expect that Venezuela will continue to comply with such production agreements with other OPEC members. Since 1998, OPEC's production quotas have resulted in a worldwide decline in crude oil production and substantial increases in international crude oil prices.

During 2002, the OPEC agreed to oil production cuts for its members, resulting in a decrease in our production quota in 2002 of 23 MBPD. Primarily due to these production cuts, the average price of the OPEC basket increased by $1.24 per barrel, or 5%, from $23.12 per barrel in 2001 to $24.36 per barrel in 2002. The average price of our exports, including refined products, increased by $1.74 per barrel, or 9%, from $20.21 per barrel in 2001 to 21.95 per barrel in 2002.

Venezuela's OPEC production quota increased by a total of 426 MBPD in 2003 - 150 MBPD in January 2003, 172 MBPD in April 2003 and 104 MBPD in June 2003. Our total OPEC production quota increased from 2,497 MBPD in December 2002 to 2,923 MBPD in June 2003. As of September 2003, the average price of the OPEC basket was $26.38 per barrel and the average price of the Venezuelan basket was $23.35 per barrel.

Recent Developments and Recovery Efforts

A similar disruption occurred in December 2002 and January 2003, when a nationwide work stoppage halted most of PDVSA's operations. The work stoppage resulted in a significant reduction in the number of PDVSA employees. Between December 2002 and the end of the first quarter of 2003, PDVSA terminated the employment of approximately 18,000 of its personnel—a reduction of approximately 45% of PDVSA's workforce in Venezuela.

The work stoppage in Venezuela during December 2002 and January 2003 resulted in significantly reduced operating levels in PDVSA. Crude oil production levels were reduced from around 3.3 MBPD in November 2002 to an average of about 1.2 MBPD in December 2002 and an average of about 0.8 MBPD in January 2003. By April 2003, production levels had returned to approximately 3.2 MBPD (including Orinoco Belt production), levels which have since been sustained. In December 2002, PDVSA gave notice of force majeure under its crude oil supply agreements. Since February 2003, PDVSA began to normalize its operations, including the delivery of crude oil and products to its customers under the conditions established in its supply agreements. The force majeure was lifted in March 2003. See notes 1(a) and 19 to our consolidated financial statements included under "Item 18. Financial Statements."

Additionally, because production activities at our refineries were temporarily affected as a result of the work stoppage, from December 2002 through March 2003, we had to import gasoline and diesel to meet our domestic distribution obligations during the affected period. We imported a total of approximately 521,600 barrels of gasoline at a weighted average price of $40.40 per barrel and approximately 480,299 barrels of diesel at a weighted average price of $36.05 per barrel in December 2002. During the first quarter of 2003, we imported a total of approximately 13.5 million barrels of gasoline at a weighted average price of $37.56 per barrel and approximately 975,196 barrels of diesel at a weighted average price of $41.23 per barrel.

The principal impact of the work stoppage on our 2002 financial results was the temporary disruption to our production and shipments during December 2002, and a resulting loss in revenue. The reduced sales volume, combined with the higher costs to import gasoline and diesel for the domestic market, considering that domestic prices are regulated, impacted the results of operations and liquidity in early 2003. The lower sales volumes were substantially offset by a decrease in our costs and expenses. Our crude oil sales and operations had fully recovered by the end of the third quarter of 2003. Also, our billing systems have been restored and our collections cycle has normalized, and management does not currently expect the abovementioned disruption to have a significant impact on our financial results in 2003.

The work stoppage and the extensive reduction in our workforce temporarily impacted the timely processing of our operational and financial data. During the affected period, we implemented alternative control systems and, among other things, focused our efforts on filling key management positions and on hiring and training new personnel to oversee and manage our operational, administrative, financial and information systems. Our pre-existing financial and computer systems began to be re-established in February 2003. These control systems were fully restored by the end of July 2003.

We also have implemented a human resources strategic plan to ensure that personnel are hired with qualifications to meet the challenges presented by PDVSA's business plan. Our recovery efforts included a special emphasis on information technology, including controls over the security and integrity of our data and programs. As part of the financial systems recovery process, the activities of the Department if Internal Control were re-established, both in the operational areas and at headquarters, to monitor adherence to our internal controls and procedures.

In March 2003, the Venezuelan government appointed a new board of directors for Petróleos de Venezuela comprised of the President, the Vice-President, three internal directors and three external directors.

Impact of Inflation and Devaluation

While more than 95% of our revenues and a significant portion of our expenses are in dollars, some of our operating costs (including income tax liabilities) are incurred in bolivars. As a result, our financial condition and results of operations are affected by the Venezuelan inflation rate and the timing and magnitude of any change in the $/Bs exchange rate during a given financial reporting period.

Since 1998, the Venezuelan government has used exchange rates to moderate inflation, by devaluing the bolivar within a pre-determined band. Effective February 13, 2002, however, the Venezuelan government and the Central Bank of Venezuela adopted a floating exchange rate system, as opposed to the band system previously in effect. As a result of the adoption of a floating exchange rate system, the bolivar devalued substantially against the dollar and inflation accelerated in 2002. In 2002, we experienced a devaluation of the bolivar at an annual rate of 82%. The annual inflation rate in 2002 was 31%. For 2001 and 2000, the annual rate of devaluation was 10% and 8%, respectively, and the annual rate of inflation was 12% and 13%, respectively. For 1999 and 1998, the inflation rate was 20% and 30%, respectively.

On February 5, 2003, the Venezuelan government established a foreign exchange management regime, setting the exchange rates for the sale and purchase of foreign currency at Bs1,600.00 to $1 and Bs1,596.00 to $1, respectively. The new exchange controls do not have a significant impact on PDVSA's operations. See note 3 and note 21 to our consolidated financial statements, included under "Item 18. Financial Statements."

Summary of Exchange Rates (Bs/$1)

	December 31,
	2002	2001	2000
Exchange rates at year-end derived from exchange agreement with the Central Bank of Venezuela (Bs/$1) (see note 2 to our consolidated financial statements)	1,403.00	770.09	698.23
Average annual exchange rates (Bs/$1)	1,163.91	722.01	679.80
Interannual increments in the exchange rate (%)	82.18	10.29	7.82
Interannual increments in the CPI* (%)	31.22	12.29	13.43

*: Consumer Price Index

Impact of Taxes on Net Income and Cash Flows

In accordance with Venezuelan income tax law, our income tax expense is based on accounting denominated in bolivars. For fiscal purposes, Venezuelan companies are required to reflect the impact of inflation and the variations in the rate of the bolivar relative to the dollar and other foreign currencies by adjusting non-monetary assets and stockholder's equity on their fiscal balance sheets. The Venezuelan income tax law considers any gain resulting from this adjustment as taxable income and any loss as a deductible expense. Such adjustments affect our taxable income and therefore the amount of our income tax liability in bolivars. When such tax liabilities are translated into dollars, the adjustments may create a material difference between the effective tax rate paid when expressed in dollars and the statutory rate in bolivars.

The following is a summary of new laws that affect taxes levied on PDVSA's operations in 2002:

•: Income taxes. In January 2002, an amendment to the Venezuelan income tax law came into effect, reducing the income tax rate applicable to our Venezuelan subsidiaries engaged in the production of hydrocarbons and related activities from 67.7% to 50%.
•: Production tax. Venezuela's new Hydrocarbons Law came into effect in January 2002. Among other things, the new Hydrocarbons Law increased the production tax rate from 16²/3% to 30% based on the volume of extracted hydrocarbons. For mature reservoirs or extra-heavy crude oil from the Orinoco Belt, a tax rate within a 20% to 30% band was established. For natural bitumen, a tax rate within a 16²/3% to 30% band was established, based on the profitability of reservoirs. Until December 2001, PDVSA was subject to a production tax equal to 16²/3% of the market value at the wellhead of the crude oil and natural gas produced, and is charged for the right to extract crude oil and natural gas. This tax is fully deductible in determining net taxable income.

The following taxes also were established in 2002:

•: Surface tax at the annual rate of 100 tax units for each square kilometer or fraction thereof. Surface tax is determined based on the concession area not under production, with an annual increase of 2% for five years and 5% in subsequent years.
•: General consumption tax, at a rate ranging between 30% and 50% of the price paid by the final customer, is applicable to each liter of hydrocarbon-derived product sold in the domestic market. The consumption tax rate is determined annually. In 2002, the consumption tax rate was 30%.

•: PDVSA also is taxed on its own consumption, equivalent to 10% of the value of each cubic meter of hydrocarbon-derived product consumed as fuel oil in its operations, calculated based on the final sale price.

Venezuela levied a 16.5% wholesale tax (a form of value added tax) on domestic sales transactions. Effective June 1999, the wholesale tax was substituted by a 15.5% value added tax and in August 2000, the value added tax was lowered to 14.5%. As an exporter, each of our Venezuelan operating subsidiaries is entitled to a refund for a significant portion of such taxes paid, which we classify on our balance sheet as recoverable luxury and wholesale tax. The Venezuelan government reimburses taxes through special tax recovery certificates, or CERTS. In January 1999, the Venezuelan government delivered to us $1,334 million of CERTs, of which $1,291 million were used to pay dividends declared by our shareholder in an extraordinary meeting held on September 30, 1998. At the beginning of 2000, the Venezuelan government delivered to us $178 million of CERTs, all of which were used against our income tax liability. In 2001, we recovered $209 million of CERTs, and none during 2002.

Petróleos de Venezuela and its Venezuelan subsidiaries are entitled to a tax credit for new investments of up to 12% of the amount invested. In the case of PDVSA Petróleo, however, such credits may not exceed 2% of its annual net taxable income and, in all cases, the carryforward period cannot exceed three years.

Venezuela also levies a tax on corporate assets at a rate of 1% of the average value of a company's assets, as adjusted for inflation at the beginning and at the end of each year. The tax is in effect a minimum income tax, as it is only paid if the amount that would be due thereunder is greater than the income tax otherwise payable. See note 11 to our consolidated financial statements, included under "Item 18. Financial Statements."

Effective March 2002, and for the term of one year, the Venezuelan government introduced a tax on certain banking transactions to be levied at a rate of 0.75%. On March 2003, the term was extended for one more year, and this tax was raised to a rate of 1.00% until June 2003, when the rate was reduced to 0.75%. The tax rate will reduce to 0.50% from December 2003 through March 2004.

An amendment of the income tax law of Venezuela was approved in October 1999. This amendment established the introduction of transfer pricing rules that came into effect in January 2000. Pursuant to the standard on transfer pricing, taxpayers subject to income tax who carry out import, export and loan operations with related parties domiciled abroad are obliged to determine their income, costs and deductions by applying the methodology set forth under this law. Any resulting effects will be included as a taxable item in the determination of income tax. PDVSA carries out significant operations regulated by transfer pricing rules. Our management believes that the effects of transfer pricing rules on taxable income are not significant for 2002 and 2001.

A summary of the tax effects on PDVSA's consolidated operations for the years ended 2002, 2001 and 2000, are as follows:

	Years ended December 31
	2002	2001	2000
	($ in millions)
Income taxes	149	3,766	5,748
Production and other taxes	5,748	3,760	4,986

	5,897	7,526	10,734

For the year ended 2002, PDVSA expensed $5,897 million in taxes, compared to $7,526 million in 2001, representing a 22% decrease in the amount of taxes. Also, the effective income tax rate was reduced from 49% in 2001 to 5% in 2002. These decreases were due principally to a significant tax loss in the principal Venezuelan operating subsidiary (PDVSA Petróleo) in 2002, resulting principally from

foreign currency and inflationary losses, which was partially offset by the increase in the production tax rate from 16²/3% in 2001 to 30% in 2002. Consequently, the effect of the production tax rate increase was to reduce net income by approximately $2,500 million in 2002. The increase in the production tax rate was not offset by the reduction in the income tax rate, due to the abovementioned tax loss. See note 11 to our consolidated financial statements, included under "Item 18. Financial Statements."

Basis of Presentation

The economic environment of our operations involves mainly the international market for crude oil and refined products. As such, the dollar is our reporting currency. See note 1(b) to our consolidated financial statements, included under "Item 18. Financial Statements."

5.A Operating results

Results of Operations 2002 Compared to 2001

Production

Our production of crude oil and liquid petroleum gas averaged 2,832 MBPD in 2002, a 13% decrease from 3,267 MBPD produced in 2001. Of this total, 29% was light crude oil and condensates, 34% was medium crude oil, 31% was heavy and extra-heavy crude oil and the remaining 6% was liquid petroleum gas. Our production of natural gas (net of amounts re-injected) was 3,672 MMCFD in 2002 compared to 4,093 MMCFD in 2001. In 2002, our natural gas production capacity reached 7,560 MMCFD and natural gas liquid production capacity totaled 288 MBPD. Our crude oil production capacity was 3,653 MBPD in 2002 compared to 3,990 MBPD in 2001. All of our crude oil and natural gas production operations are located in Venezuela.

In 2002, the net output of refined petroleum products (including output representing our equity interest in refineries held by our affiliates in the United States and in Europe) was 2,577 MBPD, compared to 2,863 MBPD in 2001. Of this total, 1,182 MBPD (46%) was produced in our Venezuelan refineries (including the Isla Refinery in Curaçao), 1,124 MBPD (43%) was produced by the refineries in the United States, and the remaining 271 MBPD (11%), was produced by our interests in the European joint ventures.

Total Revenues

Total revenues decreased $3,670 million, or 8%, from $46,250 million in 2001 to $42,580 million in 2002.

Net Sales

Net sales decreased $3,474 million, or approximately 8%, from $45,786 million in 2001 to $42,312 million in 2002. This was due mainly to a 3% decrease in sales volume, from a total of 4,478 MBPD in 2001 to a total of 4,365 MBPD in 2002, and a decrease in average sales price of approximately 6%, from an average price per barrel of $28.21 in 2001 to $26.56 in 2002. See "Item 3.A Selected Financial Data" and the table captioned "PDVSA's Consolidated Sales Volume" under "Item 4.B Business overview."

Export Revenues of Crude Oil and Refined Products. Exports represented 55% of our sales volumes. Our exports decreased in volume by approximately 13% from 2,762 MBPD in 2001 to 2,411 MBPD in 2002. The average export price per barrel for Venezuelan crude oil, refined petroleum products and liquid petroleum gas was $21.94 in 2002, compared to $20.21 in 2001, representing a 9% increase.

The following table sets forth the primary markets for Venezuelan crude oil, refined petroleum products and liquid petroleum gas for 2002 and 2001.

PDVSA's Export Sales—Geographical Breakdown

	2002	2001	Increase (Decrease)
	(MBPD, except as otherwise indicated)
United States and Canada	1,269	1,497	(15	)%
Caribbean and Central America	739	793	(7	)%
South America	269	321	(16	)%
Europe	134	151	(11	)%

We export all of the crude oil that we produce that is not processed in our Venezuelan refineries (including to the Isla Refinery in Curaçao). Of our total exports of 2,411 MBPD in 2002, 1,764 MBPD were exported (including to the Isla Refinery in Curaçao) as crude oil and 647 MBPD were exported as refined petroleum products. For the purpose of calculating export volumes, we treat crude oil processed in the Isla Refinery in Curaçao as an export of crude oil from Venezuela and do not treat the sale of refined petroleum products from the Isla Refinery as an export of refined petroleum products from Venezuela.

Sales Revenues of International Subsidiaries. In 2002, the total volumes of crude oil and refined petroleum products that we sold exceeded our total production of crude oil and liquid petroleum gas. In 2002, our total production of crude oil and liquid petroleum gas was 2,832 MBPD, compared to 4,365 MBPD of total sales of such products. PDV America, through its wholly-owned subsidiaries (primarily CITGO), generates most of the sales in excess of our crude oil and liquid petroleum gas production, because it purchases crude oil and refined petroleum products from third parties (including affiliates) for supply to refining and marketing network in the United States. Total sales of refined petroleum products by PDV America were approximately 1,658 MBPD in 2002, compared to 1,610 MBPD in 2001, and its purchases of crude oil from us totaled approximately 320 MBPD in 2002, compared to 348 MBPD in 2001. PDV America's revenues decreased to $19,358 million in 2002 from $19,601 million in 2001, due to a decrease in average sales price of 4%, offset by an increase in sales volume of 3%.

Domestic Sales. In 2002, we sold 420 MBPD of refined petroleum products (including liquid petroleum gas) domestically, compared to 458 MBPD sold domestically in 2001. We also sold 324 MBPD of oil equivalent of natural gas, compared to 307 MBPD sold in 2001. Unit sales prices of refined petroleum products decreased 23%, from $8.74 per barrel in 2001 to $6.73 per barrel in 2002, and unit sales prices of natural gas decreased from $0.88 per MCF, or $5.35 per BOE, in 2001 to $0.71 per MCF, or $4.10 per BOE, in 2002.

Petrochemical and Other Sales. Our net sales for 2002 included $1,201 million from sales of petrochemicals, bitumen and coal, a 14% decrease compared to $1,403 million of revenues from sales of these products in 2001. This decrease in net sales is due primarily to the effects of devaluation on petrochemical revenues denominated in bolivars.

Equity in Earnings of Nonconsolidated Investees

Equity in earnings of nonconsolidated investees decreased 42% to $268 in 2002 from $464 million in 2001. This resulted primarily from the 84% decrease in PDV Holding's equity in earnings from $225 million in 2001 to $36 million in 2002, which was due to the $113 million decrease in our share in the earnings of Chalmette Refining from a $50 million gain in 2001 to a $(63) million loss in 2002. Additionally, our share in the earnings of Merey Sweeny decreased $68 million, from a $66 million gain in 2001 to a $(2) million loss in 2002. Finally, in 2002, PDV Holding experienced a $12 million

reduction in its earnings from other investments. This decrease in earnings was partially offset by a $4 million increase of LYONDELL-CITGO's earnings from $74 million in 2001 to $78 million in 2002.

Purchase of Crude Oil and Products

Our purchases of crude oil and products decreased by 1% from $18,228 million in 2001 to $17,956 million in 2002, primarily due to a decrease in volumes. We also purchased an average of 61 MBPD and 55 MBPD of refined products and crude oil for our Venezuelan operations, during 2002 and 2001, respectively. Other purchases of crude oil were made to meet our supply commitments. Through CITGO, we purchase crude oil and refined petroleum products from third parties (including affiliates) to supply our refining and marketing networks in the United States.

Operating Expenses

Our operating expenses decreased by $1,604 million, or 15%, from $10,882 million in 2001 to $9,278 million in 2002, due to lower oil production in 2002.

Total refining costs represented 39% and 36% of our total operating expenses for 2002 and 2001, respectively. Costs incurred at our Venezuelan refineries (including the Isla Refinery) represented 9% of our total operating expenses in 2002 and 10% of our total operating expenses in 2001.

Exploration Expenses

Our total exploration expenses were $133 million in 2002, compared to $174 million in 2001. The decrease in exploration expenses is attributable to our abandonment of two dry wells in 2002 (thereby reducing our exploration expenses by $25 million in 2002, compared to $9 million in 2001) and a decrease in exploratory drilling costs. We conducted exploratory drilling of 10 wells in 2002, compared to 11 wells in 2001, principally attributable to our joint ventures and association agreements in connection with our Orinoco Belt projects.

Depreciation and Depletion

Depreciation and depletion increased 17% from $2,624 million in 2001 to $3,059 million in 2002, due to an increase in our properties, plant and equipment resulting from the capitalization of new assets at the end of 2001, principally attributable to our joint ventures and association agreements in connection with our Orinoco Belt projects.

Asset Impairment

Asset impairment increased by $649 from $257 in 2001 to $906 in 2002, principally due to an increase in oil and gas wells included under oil and gas production assets, which are planned to be retired.

Selling, Administrative and General Expenses

Selling, administrative and general expenses remained at a similar level of $1,854 million in 2002 and $1,853 million in 2001.

Financing Expenses

Financing expenses increased by 50% to $763 million in 2002 from $509 million in 2001, in each case, net of capitalized interest of $7 million and $51 million, respectively. The increase in financing expenses resulted primarily from the increase in the weighted average variable interest rate from 4.73% in 2001 to 5.40% in 2002 and an increase in average indebtedness outstanding from $8,013 million in 2001 to $8,335 million in 2002, offset by a decrease in the weighted average fixed interest rate from 8.13% in 2001 to 7.97% in 2002.

Results of Operations—2001 Compared to 2000

Production

Our production of crude oil and liquid petroleum gas averaged 3,267 MBPD in 2001, a 0.46% increase from 3,252 MBPD produced in 2000. Of this total, 35% was light crude oil and condensates, 31% was medium crude oil, 27% was heavy and extra-heavy crude oil and the remaining 5% was liquid petroleum gas. Our production of natural gas (net of amounts re-injected) was 4,093 MMCFD in 2001 compared to 3,979 MMCFD in 2000. In 2001, our natural gas production capacity reached 7,560 MMCFD and natural gas liquid production capacity totaled 288 MBPD. Our crude oil production capacity was 3,990 MBPD in 2001 compared to 3,582 MBPD in 2000. All of our crude oil and natural gas production operations are located in Venezuela.

In 2001, the net output of refined petroleum products (including output representing our equity interest in refineries held by our affiliates in the United States and in Europe) was 2,863 MBPD, slightly less than the 2,895 MBPD in 2000. Of this total, 1,408 MBPD (49%) was produced in our Venezuelan refineries (including the Isla Refinery in Curaçao), 1,187 MBPD (41%) was produced by the refineries in the United States, and the remaining 268 MBPD (10%), was produced by our interests in the European joint ventures.

Total Revenues

Total revenues decreased $7,430 million, or 14%, from $53,680 million in 2000 to $46,250 million in 2001.

Net Sales

Net sales decreased $7,448, or approximately 14%, from $53,234 million in 2000 to $45,786 million in 2001. This was due to a decrease in sales volume of 4% and a decrease in average sales price of 3%. See "Item 3.A Selected financial data" and the table captioned "PDVSA's Consolidated Sales Volume" under "Item 4.B Business overview."

Export Revenues of Crude Oil and Refined Products. Exports represented 67% of our sales. Our exports decreased in volume by 2% from 2,823 MBPD in 2000 to 2,762 MBPD in 2001. The average export price per barrel for Venezuelan crude oil, refined petroleum products and liquid petroleum gas was $20.21 in 2001, compared to $25.91 in 2000, representing a 22% decrease.

The following table sets forth the primary markets for Venezuelan crude oil, refined petroleum products and liquid petroleum gas for 2001 and 2000.

PDVSA's Export Sales—Geographical Breakdown

	2001	2000	Increase (Decrease)
	(MBPD, except as otherwise indicated)
United States and Canada	1,497	1,540	(3)%
Caribbean and Central America	793	870	(9)%
South America	321	183	75 %
Europe	151	230	(34)%

We export all of the crude oil that we produce that is not processed in our Venezuelan refineries (including to the Isla Refinery in Curaçao). Of our total exports of 2,762 MBPD in 2001, 2,065 MBPD were exported (including to the Isla Refinery in Curaçao) as crude oil and 697 MBPD were exported as refined petroleum products. For the purpose of calculating export volumes, we treat crude oil processed in the Isla Refinery in Curaçao as an export of crude oil from Venezuela and do not treat the sale of refined petroleum products from the Isla Refinery as an export of refined petroleum products from Venezuela.

Sales Revenues of International Subsidiaries. In 2001, the total volumes of crude oil and refined petroleum products that we sold exceeded our total production of crude oil and liquid petroleum gas. In 2001, our total production of crude oil and liquid petroleum gas was 3,267 MBPD of crude oil and liquid petroleum gas production, compared to 4,478 MBPD of total sales of such products. PDV America, through its wholly-owned subsidiaries (primarily CITGO), generates most of the sales in excess of our crude oil and liquid petroleum gas production, because it purchases crude oil and refined petroleum products from third parties (including affiliates) for supply to refining and marketing network in the United States. Total sales of refined petroleum products by PDV America in 2001 were approximately 1,610 MBPD, compared to 1,636 MBPD in 2000, and its purchases of crude oil from us totaled approximately 347 MBPD in 2001, compared

to 329 MBPD in 2000. PDV America's revenues decreased to $19,601 million in 2001 from $22,157 million in 2000, due to a decrease in average sales price of 11% and a decrease in sales volume of 2%.

Domestic Sales. In 2001, in the domestic market, we sold 458 MBPD of refined petroleum products (including liquid petroleum gas), compared to 411 MBPD sold in 2000. We also sold 307 MBPD of oil equivalent of natural gas, compared to 288 MBPD sold in 2000. Unit sales prices of refined petroleum products decreased 5%, from $9.20 per barrel in 2000 to $8.74 per barrel in 2001, and unit sales prices of natural gas decreased from $0.90 per MCF, or $5.29 per BOE, in 2000 to $0.88 per MCF, or $5.35 per BOE, in 2001.

Petrochemical and Other Sales. Our net sales for 2001 included $1,403 million from sales of petrochemicals, bitumen and coal, a 15% increase compared to $1,224 million of revenues from sales of these products in 2000. Such increase in net sales is due primarily to an increase in sales volumes and average sales prices for fertilizers, bitumen and coal.

Equity in Earnings of Nonconsolidated Investees

Equity in earnings of nonconsolidated investees increased 4% to $464 million in 2001 from $446 million in 2000. In the United States, PDV Holding's equity in earnings increased 85% from $59 million in 2000 to $109 million in 2001. The increase was primarily due to the increase in the earnings of LYONDELL-CITGO, CITGO's share of which increased $33 million, from $41 million in 2000 to $74 million in 2001. LYONDELL-CITGO's increased earnings in 2001 are primarily due to higher refining margins, offset by the impact of lower crude processing rates due to a major turnaround in the fourth quarter and an unplanned production unit outage in the first quarter and higher natural gas costs. The earnings for 2000 were impacted by a major planned turnaround which occurred during the second quarter of 2000. In Venezuela, PDVSA Petróleo's equity in earnings decreased 63%, from $145 million in 2000 to $53 million in 2001, mainly due to higher crude oil upgrading costs in 2001 to produce upgraded crude oil in Petrozuata.

Purchase of Crude Oil and Products

Through CITGO, we purchase crude oil and refined petroleum products from third parties (including affiliates) to supply our refining and marketing networks in the United States. Our purchase of crude oil and products decreased by 8% from $19,759 million in 2000 to $18,228 million in 2001, primarily due to a decrease in prices and supply for hydrocarbons in the international markets. We also purchased an average of 55 MBPD and 51 MBPD of refined products and crude oil for our Venezuelan operations, during 2001 and 2000, respectively. Other purchases of crude oil were also made to meet our supply commitments.

Operating Expenses

Our operating expenses increased by $872 million, or 9%, from $10,010 million in 2000 to $10,882 million in 2001, primarily due to higher labor costs and maintenance costs. All of these costs were offset by a decrease in production costs per barrel from $3.48 in 2000 to $3.38 in 2001. Our production costs per barrel, excluding costs associated with operating service agreements, decreased from $2.22 in 2000 to $2.17 in 2001. Production from our fields that are operated under the operating service agreements (which have higher than average cost structures) increased from 466 MBPD in 2000 to 502 MBPD in 2001, and the average cost per barrel from their production was $11.72 in 2001 as compared with $12.90 in 2000. See the table captioned "PDVSA's Average Production, Sales Price and Production Cost" under "Item 4.B Business overview."

Total refining costs represented 36% and 37% of our total operating expenses for 2001 and 2000, respectively. Costs incurred at our Venezuelan refineries (including the Isla Refinery) represented 10% of our total operating expenses in 2001 and 8% of our total operating expenses in 2000.

Exploration Expenses

Our total exploration expenses were $174 million in 2001, compared to $169 million in 2000. These also include expenses related to two dry wells which were abandoned during 2001, totaling $9 million (compared to $57 million in 2000), offset by an increase in administrative cost due to higher labor cost and more geophysics activities.

Depreciation and Depletion

Depreciation and depletion decreased 13% from $3,100 million in 2000 to $2,624 million in 2001, due to a lower depletion factor and the write-off of unproductive assets.

Selling, Administrative and General Expenses

Selling, administrative and general expenses increased 48% to $1,853 million in 2001 from $1,256 million in 2000, due principally to increased labor costs and pension plan and other postretirement benefits.

Financing Expenses

Financing expenses decreased 24% to $509 million in 2001 from $672 million in 2000, in each case, net of capitalized interest of $51 million and $59 million, respectively, primarily as a result of a decrease in the weighted average variable interest rate from 6.07% in 2000 to 4.73% in 2001, partially offset by an increase in the weighted average fixed interest rate from 7.73% in 2000 to 8.13% in 2001 and an increase in average indebtedness outstanding.

5.B Liquidity and Capital Resources

Our liquidity needs are attributable to our exploration and development of hydrocarbon reserves, our production, processing and refining activities and our maintenance of machinery and equipment, each of which require substantial capital investments. We must continue to invest capital to maintain or to increase the number of hydrocarbon reserves that we operate and the amount of crude oil that we produce and process. We generally rely on funds provided by our operations to meet these needs. We expect to meet our capital expenditure requirements primarily through cash flows generated from our operations. We have borrowings under our loan agreements and credit facilities and, from time to time, we also may pursue financing alternatives in the international capital markets. In our opinion, we have sufficient working capital for our present requirements.

Cash Flows from Operating Activities

For the year ended December 31, 2002, PDVSA's net cash provided by operating activities totaled $5,185 million, primarily reflecting $2,590 million of net income, $3,059 million of depreciation and depletion, $906 million of asset impairment, $1,340 million of provision, less $1,060 million of payments, for employee termination, pension and other postretirement benefits and changes in working capital of $(1,058) million.

The more significant changes in working capital were: an increase in accounts receivable of approximately $235 million, due to delays in the delivery of invoices to customers caused by the work stoppage in December 2002, a decrease in taxes and dividends payable, accrued and other liabilities of $1,166 million, of which $594 million relates to the reduction in income taxes payable, due to tax losses in Venezuela.

Cash Flows from Investing Activities

Net cash used in investing activities totaled $1,490 million for 2002, resulting from $2,962 million of capital expenditures, less net movements on restricted cash of $1,472 million, which include principally net withdrawals from the FIEM of $1,754 million.

For the three-year period ended December 31, 2002, our capital expenditures were as follows:

	2002		2001		2000
	($ in millions)
In Venezuela:
Exploration and Production	$	1,775	$	507	$	2,208
Refining		365		2,809		175
Petrochemicals and others		83		208		102

	$	2,223	$	3,524	$	2,485
Foreign-Refining		739		257		700

	$	2,962	$	3,781	$	3,185

The following table sets forth our planned capital expenditures by geographic locations for the period 2003-2005:

	2003		2004		2005
	($ in millions)
Venezuela(1)	$	2,424	$	6,033	$	6,858
United States		448		519		518
Europe and Caribbean		106		154		154

	$	2,978	$	6,706	$	7,530

(1): Includes $171 million, $789 million and $781 million for gas projects in 2003, 2004 and 2005, respectively.

Our planned capital expenditures in Venezuela for 2003 are as follows: $1,869 for exploration and production, $248 million for refining and marketing, $171 million for natural gas projects, $70 million for petrochemicals and others, and $66 million for equity investments in our Orinoco Belt associations. Our anticipated capital expenditures for our international subsidiaries and affiliates are principally to comply with increasingly stringent environmental laws affecting their operations. The original 2003 capital expenditure plan for Venezuela of $5,918 million has been revised to $2,424 million.

In June 1999, the Venezuelan government created the Macroeconomic Stabilization Investment Fund, or the FIEM, to minimize the adverse effects of volatile prices in the global energy markets on Venezuela's economy, national budget and monetary and foreign exchange markets. PDVSA was required to make deposits to the FIEM equivalent to 50% of its revenues from export sales in excess of $9 per barrel, net of taxes related to such sales.

In October 2001, the Venezuelan government introduced reforms to laws governing the FIEM and, among other changes, suspended contributions for the last quarter of 2001 and the years 2002 and 2003. For 2004 to 2008, 6% of income from exports, net of the respective taxes, will be transferred to the FIEM. This rate will be progressively increased on an annual basis at a constant rate of 1% up to 10% in 2008.

PDVSA's deposits with the FIEM can be used only by PDVSA with the prior approval of the board of directors of the FIEM, provided that the National Assembly and the Venezuelan government have informed them, within the established period, of compliance with conditions established for this purpose. As of December 31, 2002, the FIEM had approximately $2,382 million in outstanding funds, as compared to $4,072 million as of December 31, 2001. PDVSA has withdrawn $1,702 million in 2003 and as of October 2003, PDVSA has $697 million on deposit with the FIEM. See note 4 to our consolidated financial statements, included under "Item 18. Financial Statements."

Cash Flows from Financing Activities

Consolidated net cash used in financing activities totaled approximately $2,917 million, resulting primarily from borrowings of $1,175 million, payments of dividends in the amount of $2,652 million, capital lease payments of $81 million and debt repayments of $1,359 million.

As of December 31, 2002, PDVSA had an aggregate of $8,243 million of indebtedness outstanding that mature on various dates through 2032. PDVSA and its subsidiaries also have the following credit facilities available at December 31, 2002:

Source of Financing		($ in millions)
Shelf registration (CITGO)(1)		400
Loan credit agreements (CITGO)(1)		356
Loan credit agreement (VALCOR project)(2)		250
Lines of credits agreement (Anaco Gas Project)(2)		125
Lines of credits (Orinoco Belt Associations-Corpoguanipa)(2)		45

		1,176

(1): Unsecured
(2): Secured

The following table summarizes future payments for PDVSA's contractual obligations at December 31, 2002.

Future Payments for PDVSA's Contractual Obligations
At December 31, 2002

	Total (MM$)	Less than 1 year	Years 2-3	Years 4-5	After 5 years
Long-Term Debt	8,243	1,817	1,705	1,312	3,409
Capital Lease Obligations	98	42	30	10	16
Operating Leases	1,342	182	254	190	716

Total Contractual Cash Obligations	9,683	2,041	1,989	1,512	4,141

As of December 31, 2002, we were in compliance with our debt covenants. Petróleos de Venezuela and PDVSA Finance have been in breach of certain of their loan covenants due to the late filings of their respective annual reports on Form 20-F for the year ended December 31, 2002 (and, in respect of Petróleos de Venezuela, its 2002 audited financial statements). Upon delivery of the foregoing documents to the trustee and to the creditors, as the case may be, such covenant breaches will be remedied.

In 2002, we paid dividends of $2,652 million and we declared $2,752 million in dividends, of which $1,129 million were paid by September 2003. See notes 14 and 21 to our consolidated financial statements, included under "Item 18. Financial Statements."

On February 27, 2003, CITGO issued $550 million aggregate principal amount of 11³/8% unsecured senior notes due February 1, 2011. In connection with this debt issuance, CITGO repurchased $50 million principal amount of its 7¹/8% senior notes due 2006. On July 25, 2003, CITGO made a $500 million dividend payment for the purpose of enabling its parent, PDV America, to make the principal repayment of $500 million, 7⁷/8% senior notes due August 1, 2003.

In January 2003, CITGO's debt rating was lowered which caused a termination event under CITGO's accounts receivable sale facility existing at that time, which ultimately led to the repurchase of $125 million of accounts receivable and cancellation of the facility on January 31, 2003. That facility had a maximum size of $225 million, of which $125 million was used at the time of cancellation. On February 28, 2003 a new accounts receivable facility of $200 million was established. This facility allows for the non-recourse sale of certain accounts receivable to independent third parties. On August 1, 2003, $200 million was sold under this facility.

On February 27, 2003, CITGO closed on a three-year $200 million senior secured term loan with a variable interest rate.

We have long-term debt ratings assigned by certain internationally recognized credit rating agencies, currently as follows:

	CITGO		PDVSA Finance
	(unsecured)	(secured)	(unsecured)
Moody's Investors Service	Ba3	Ba2	Caa+
Standard & Poor's Ratings Services	BB	BB+	B+
Fitch Ratings	BB-	BB+	BB-

Contractual Obligations and Commercial Commitments

Most of our export sales of crude oil to third parties, including customers in the United States with which we maintain long-standing commercial relationships, are made at market prices pursuant to our general terms and conditions, and priced in dollars. Among our customers are major oil companies and other medium-sized companies. Although our general terms and conditions do not require specified volumes to be bought or sold, historically, a majority of our customers have taken shipments on a regular basis at a relatively constant volume throughout the year.

We also have various agreements for supplies with our affiliated companies, which are summarized as follows (thousands of barrels a day):

Affiliate	Delivery obligation	Year of termination
Ruhr Oel	220	After two years notice
Nynäs Petroleum	34	Not defined
LYONDELL-CITGO	230	2017
Chalmette Refining	90	Strategic association period
Hovensa	155	2008
CITGO	297	Between 2006 and 2013

	1,026

Critical Accounting Policies

The preparation of financial statements in conformity with Accounting Principles Generally Accepted in the United States of America requires that management apply accounting policies and make estimates and assumptions that affect results of operations and the reported amounts of assets and liabilities. Actual outcomes could differ from the estimates and assumptions used. The following areas are those that management believes are important to the financial statements and which require significant judgment and estimation because of inherent uncertainty.

Impairment of Long-Lived Assets and Long-Lived Assets to be Disposed

A reduction in our crude oil production or export activities or a decline in the prices of crude oil and refined petroleum products for a substantial period of time may materially and adversely affect our operations, cash flows, and financial results. We review for impairment long-lived assets and certain identifiable intangibles, to be held and used, whenever events indicate that the carrying amount of an asset may not be recoverable.

Our review of impairment of an asset is based on a comparison of the carrying amount of an asset to future net cash flows expected to be generated by the asset. If the carrying amount of an asset exceeds its estimated future cash flow an impairment charge is required for the amount by which the carrying of the asset exceeds the fair value of the asset.

Environmental Expenditures

The costs to comply with environmental regulations are significant. Environmental expenditures that relate to current or future revenues are expensed or capitalized as appropriate. Expenditures that relate to an existing condition caused by past operations and that do not contribute to current or future revenue generation are expensed. We constantly monitor our compliance with environmental regulations and respond promptly to issues raised by regulatory agencies. Liabilities are recorded when environmental assessments and/or cleanups are probable and the costs can be reasonably estimated. Environmental liabilities are not discounted to their present value. Subsequent adjustments to estimates, to the extent required, may be made as more refined information becomes available.

Litigation

Petróleos de Venezuela and its subsidiaries and joint ventures are involved in various lawsuits and claims arising in the normal course of their businesses. External and internal legal counsel continually review the status of these lawsuits and claims. These reviews provide the basis for which we determine whether or not to record accruals for potential losses. Accruals for losses are recorded when, in management's opinion, such losses are probable and reasonably estimable. If known lawsuits and claims were to be determined in a manner adverse to PDVSA, and in amounts greater than our accruals, then such determinations could have a material adverse effect on our results of operations in a given reporting period.

Oil and Gas Reserves

All the crude oil and natural gas reserves located in Venezuela are owned by Venezuela. Crude oil and natural gas reserves are estimated by PDVSA and reviewed by the Ministry of Energy and Mines, using reserve criteria which are consistent with those prescribed by the American Petroleum Institute (API) and the U.S. Securities and Exchange Commission. Proved oil and gas reserves are 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. Accordingly, these estimates do not include probable or possible reserves. Our estimates of reserves are not precise and are subject to revision. We review these crude oil and natural gas reserves annually to take into account, among other things, production levels, field reviews, the addition of new reserves from discoveries, year-end prices and economic and other factors. Proved reserve estimates may be materially different from the quantities of crude oil and natural gas that are ultimately recovered.

Recently Issued Accounting Standards

In June 2001, the Financial Accounting Standards Board (FASB) issued SFAS No. 143, "Accounting for Asset Retirement Obligations" ("SFAS No. 143"), which addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. SFAS No. 143 applies to legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or normal use of such assets. SFAS No. 143 requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it was incurred if a reasonable estimate of such fair value can be made. The fair value of the liability is added to the carrying amount of the associated asset and this additional carrying amount is depreciated over the life of such asset. The liability is adjusted at the end of each period to reflect the passage of time and changes in the estimated future cash flows underlying the initial fair value measurement, and such adjustments are reflected in operations. If PDVSA's obligation is settled for other than the carrying amount of the liability, PDVSA will recognize a gain or loss on settlement. The cumulative adjustment for the adoption of this accounting principle as of January 1, 2003 is an after tax charge to income of $436 million. The accounting change led to a $87 million increase in property, plant and equipment, net, a $919 million increase in accrued liabilities and a $396 million increase in deferred tax assets.

In April 2002, the FASB issued SFAS No. 145, "Rescission of FASB Statement No. 4, 44 and 64, Amendment of FASB Statement No. 13, and Technical Corrections." SFAS No. 145 amends existing guidance on reporting gains and losses on the extinguishment of debt to prohibit the classification of the gain or loss as extraordinary, as the use of such extinguishments have become part of the risk management strategy of many companies. SFAS No. 145 also amends SFAS No. 13 to require sale-leaseback accounting for certain lease modifications that have economic effects similar to sale-leaseback transactions. The provisions of the Statement related to the rescission of Statement No. 4 is applied in fiscal years beginning after May 15, 2002. The provisions of the Statement related to Statement No. 13 were effective for transactions occurring after May 15, 2002. The adoption of SFAS No. 145 is not expected to have a material effect on PDVSA's financial statements.

In June 2002, the FASB issued SFAS No. 146, "Accounting for Costs Associated with Exit or Disposal Activities." SFAS No. 146 addresses financial accounting and reporting for costs associated with exit or disposal activities and nullifies Emerging Issues Task Force (EITF) Issue 94-3, "Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity." The provisions of this Statement are effective for exit or disposal activities that are initiated after December 31, 2002. The adoption of SFAS No. 146 is not expected to have a material effect on PDVSA's financial statements.

In November 2002, the FASB issued Interpretation No. 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness to Others, an Interpretation of FASB Statements No. 5, 57 and 107 and rescission of FASB Interpretation No. 34." This Interpretation elaborates on the disclosures to be made by a guarantor in its interim and annual financial statements about its obligations under guarantees issued. The Interpretation also clarifies that a guarantor is required to recognize, at inception of a guarantee, a liability for the fair value of the obligation undertaken. The initial recognition and measurement provisions of the Interpretation are applicable to guarantees issued or modified after December 31, 2002, and are not expected to have a material effect on PDVSA's financial statements. The disclosure requirements are effective for financial statements of interim and annual periods ending after December 15, 2002.

In January 2003, the FASB issued Interpretation No. 46 (FIN 46), "Consolidation of Variable Interest Entities, an Interpretation of Accounting Research Bulletin No. 51," which provides a guide when certain entities should be consolidated or the interests in those entities should be disclosed by corporations that do not control them through majority voting interest. Under FIN 46, entities are required to be consolidated by corporations that lack majority voting interest when equity investors of those entities do not have significant capital at risk or they lack voting rights, the obligations to absorb expected losses, or the right to receive expected returns. Entities identified with these characteristics are called variable interest entities and the

interests that corporations have in these are called variable interests. These interests can derive from certain guarantees, leases, loans or other arrangements that result in risks and rewards that are disproportionate to voting interests in the entities. The Interpretation applies immediately to variable interest entities created after January 31, 2003, and to variable interest entities in which an enterprise obtains an interest after that date. For variable interest entities created before February 1, 2003, the Interpretation applies in the first fiscal year or interim period beginning after June 15, 2003. The FASB has delayed the effective date for implementing FIN 46, to interim and annual periods ending on or after December 15, 2003. PDVSA is currently in the process of analyzing the effects of this Interpretation.

Proposed Accounting Change

The American Institute of Certified Public Accountants (AICPA) has issued a "Statement of Position" exposure draft on cost capitalization that is expected to require companies to expense the non-capital portion of major maintenance costs as incurred. The statement is expected to require that any existing unamortized deferred non-capital major maintenance costs be expensed immediately. This statement also has provisions that will change the method of determining depreciable lives. The impact on future depreciation expense is not determinable at this time. The exposure draft indicates that this change will be required to be adopted for fiscal years beginning after June 15, 2003, and that the effect of expensing existing unamortized deferred non-capital major maintenance costs will be reported as a cumulative effect of an accounting change in the consolidated statement of income. Currently, the AICPA is discussing the future of this exposure draft with the FASB. The final accounting requirements and timing of required adoption are not known at this time. At December 31, 2002, the Companies had included turnaround costs of $505 million in other assets, net of $103 million in prepaid expenses and other. The Company's management has not determined the amount, if any, of these costs that could be capitalized under the provisions of the exposure draft.

5.C Research and development, patents and licenses

As of December 31, 2002, the amounts that we have spent on our research and development activities have not been material. See "Item 4.B Business overview—Research and Development" and note 1(l) to our consolidated financial statements, included under "Item 18. Financial Statements."

Item 6. Directors, Senior Management and Employees

6.A Directors and senior management

In accordance with our charter, we are managed by our board of directors and our president. Our board of directors is responsible for convening our shareholder's meetings, preparing our year-end accounts and presenting them at our shareholder's meetings and reviewing and monitoring our economic, financial and technical strategies.

Our board of directors comprises eight members: a President, one Vice President, three internal directors and three external directors. Our board of directors is directly appointed by the President of Venezuela for an initial term of two years, which may be extended indefinitely until a new board of directors is appointed.

Our board of directors meets weekly and, at other times, when summoned by the President of Petróleos de Venezuela.

Pursuant to our charter, the President of Petróleos de Venezuela has broad powers to act on behalf of Petróleos de Venezuela and to represent Petróleos de Venezuela in its dealings with third parties, subject only to those powers expressly reserved to the board of directors or reserved to be effected at our general shareholder's meeting. The President of Petróleos de Venezuela determines and is responsible for the implementation of the goals, strategies and budgets (which must be approved at the general shareholder's meeting) for our different businesses. Such goals, strategies and budgets are reviewed and monitored by our board of directors.

Name	Age	Position with PDVSA	Date of Appointment
Alí Rodríguez Araque	65	President	2002
Aires Barreto	58	Vice-President	2003
José Gregorio Morales	46	Chief Financial Officer	2003
Félix Rodríguez	54	Internal Director	2003
Nelson Martinez	52	Internal Director	2003
Déster Rodríguez	41	Internal Director	2003
Luis Vierma	50	External Director	2003
Rafael Rosales	44	External Director	2003
Nelson Núñez	48	External Director	2003

Certain information on our current directors and executive officers is set forth below:

Alí Rodríguez Araque is an attorney from Universidad Central de Venezuela (1961). He majored in Petroleum Economy and has been a member of several mining and oil economy study and analysis teams. He was a member of the Venezuelan Congress between 1983 and 1999, and was appointed President of the Energy and Mines Commission of the House of Representatives between 1994 and 1997. He was Vice-President of the Bicameral Commission of Energy and Mines of Congress for the analysis and approval of the reports on the oil opening agreement. Between 1993 and 1999, he was a member of the National Council of Energy and of the Commission of Energy and Mines of the Latin American Parliament. He was also a member of the Energy and Mines Liaison Presidential Commission of President Hugo Chávez Frías and was elected Senator to Congress for Bolívar state during 1999-2004. He has published several articles on energy policy. His most recent publication is titled "El proceso de privatización de la industria petrolera venezolana" (The privatization process of the Venezuelan oil industry) (1997). From February 1999 to December 2000, he was Minister of Energy and Mines. He was also President of the Conference of the Organization of the Petroleum Exporting Countries (OPEC) during 2000. In January 2001, he was elected Secretary General of OPEC. In April 2002, he was appointed CEO of Petróleos de Venezuela.

Aires Barreto has a bachelor's degree in Chemistry from the University of Bombay (India, 1963). He has a degree in Chemical Engineering from Instituto Químico Sarría (Spain,1966) and holds a master's degree in Hydrocarbon Economy and Administration from Loughborough University (England, 1968). In 1974, he joined Shell de Venezuela, where he held technical and supervisory positions, mostly in the Cardón refinery. In 1982 he was appointed Maraven's Refining Planning manager, PDVSA's Manufacturing Planning manager, and Manufacturing manager in the Cardón refinery. In 1987 he was transferred to Intevep, where he was appointed Planning functional manager, Refining and Petrochemicals General Manager, and Technology General Manager. In 1996, he was appointed Manufacturing Planning Functional Manager of PDVSA and in 1998, Functional Manager of Corporate Topics. In 2000, he was appointed Vice-President of Petróleos de Venezuela and in February 2003 he was appointed Chief Executive Officer of Pequiven.

José Gregorio Morales was appointed Chief Financial Officer of Petróleos de Venezuela in May 2003. He also serves on the board of directors of our subsidiary, Propernyn B.V. Mr. Morales graduated with a degree in Economics from the National Experimental University "Ezequiel Zamora" (Barinas 1982). He completed his postgraduate studies in Petroleum Administrative Sciences in Central University of Venezuela (Caracas). He began his career in the oil industry in 1983. From 1983 through 1993, Mr. Morales served in various divisions in the Western Production division of PDVSA: Land and Properties Department, Investment Budget, General Accounting, Budget and Negotiations. In the Eastern Division of PDVSA, he served as Contracts Manager in 1994, Finance Superintendent in 1996, Finance Manager in 1997 and Technical Services Director in 2002. He also was the Manager of the Oritupano Project and PDVSA's public relations manager.

Félix M. Rodríguez is a petroleum engineer from Universidad de Oriente (1975). He joined the oil industry in 1976 as a production engineer in Roqueven (Puerto La Cruz). From 1978 to 1987, he held several technical and supervisory positions in Lagoven in production, wells, and development. In 1987, he was transferred to Corpoven, as Supervisor in the operational area of Anaco. In 1994, he was appointed Evaluation and Technology Manager in Puerto La Cruz. In 1995, he was appointed Production technical manager in Anaco and in 1996, Production Planning Manager in Caracas. In 1997, he was Manager of Corpoven's Barinas District. When PDVSA was restructured in 1998, he was ratified as manager of the Southern District, Barinas. In 1999, he was appointed manager of the Lagunillas District (Producción Occidente—Western Production Division). In April 2001, he was appointed Production Planning Manager in Caracas. In February 2002, he was appointed Director of PDVSA, and then President of Petrozuata through December 2002, when he became the General Manager of the Western Production Division of PDVSA.

Nelson Martínez is a chemistry graduate from the Poitiers University (France, 1973). He completed a MSc in Physical Chemistry in Poitiers University in 1974. He has a Ph.D. in Chemistry from Reading University (England, 1978) and a MSc in Technology Management from The Massachusetts Institute of Technology. He is a specialist in refining processes and technology and began his career at INTEVEP (PDVSA's research and development branch). In 1987 he was appointed Head of the Catalysis Unit at INTEVEP and, in 1980, Head of the Process Development Department. In 1995, he was appointed Head of the Technology Management group of the Strategic Planning Direction of PDVSA. In 1995, he was the Planning Manager of INTEVEP. In the year 2000, he became Under Manager of the Refining and Petrochemical Division of PDVSA and, in 2002, Manager of PDVSA's Puerto la Cruz Refinery. In 2003, he was appointed as a Director of PDVSA.

Dester Rodríguez is an Army Colonel with a bachelor's degree in Military Science and Arts from the Military Academy of Venezuela. He completed Systems Engineering studies in Universidad Experimental de las Fuerzas Armadas (Experimental University of the Armed Forces). In 1997, he was appointed Head of Personnel of the Military Engineering School of the Army. In 1998, he was appointed Head of the Army Personnel Registry and Control Division. In 1999, he was assigned General Director of the Information Technology Ministerial Office of the Ministry of Education, Culture, and Physical Education, a position he simultaneously held with that of President of the Fundación Bolivariana de Informática y Telemática (Bolivarian IT and Telecommunications Foundation) since 2001. In December 2002, he was appointed as a member of PDVSA's Restructuring Committee.

Luis Vierma has a Bachelor's degree in Chemistry from Universidad Central de Venezuela (1978) and a Master's degree in Geology (Petroleum Geochemistry) from Indiana University (1984). Between 1975 and 1978, he was a professor in the Chemistry Department of Universidad Central de Venezuela. From 1978 to 1981, he was an Exploration Geochemist in PDVSA's Research Center in Caracas. Between 1981 and 1984, he was appointed Research Assistant in the Department of Geology at Indiana University. He was then appointed Head of the Geochemistry Laboratory in PDVSA's Exploration Center, Hydrocarbons Exploration Project Leader in PDVSA's Exploration Center, and Head of the Inorganic Geochemistry Unit. In 1993, he was manager of Exhibit XIII, Agreement between the Minister of Energy and Mines of Venezuela and the U.S. Department of Energy (DOE) in Microorganic Crude Enhanced Recovery. In 1995, he was Head of the Geochemistry Section of PDVSA's Exploration Center. In 1997, he was Head of the Geology Section and in 1998 he was appointed Exploration Business Manager. In 2000, he was appointed Director of the Office of Policies and Plans of the Viceministry of Hydrocarbons of the Ministry of Energy and Mines. Since 2002, he has been General Director of Hydrocarbons of the Ministry of Energy and Mines.

Rafael Rosales Nieves is a mechanical technician in Aeronautics from the Escuela Técnica de la Fuerza Aérea Venezolana (Technical School of the Venezuelan Air Forces), specialized in Reaction Engines. He studied Law at the Universidad Rafael Belloso Chacín in Zulia state. He has 22 years' experience in the oil industry and is currently a Programming Assistant at the SAP Room of the

Land-East Department of PDVSA's Exploration and Production Western Division. He has been Secretary General of SOEP, Mene Grande, President of the Disciplinary Board of Fedepetrol, First Spokesperson of Fedepetrol, Fedepetrol's Finance Secretary and President of Fedepetrol, a position he currently holds.

Nelson Alberto Núñez has an Associate's degree in Industrial Relations. He joined the Industrial Protection Department of Lagoven in June 1978 in Quiriquire, Monagas state. In 2003, Mr. Núñez was appointed Director of PDVSA.

6.B Compensation

For the year ended December 31, 2002, the aggregate amount paid by Petróleos de Venezuela as compensation to its directors and executive officers for services in all capacities was approximately $1.1 million (based on the 2002 average exchange rate of Bs. 1,163.00 to $1).

6.C Board practices

Our directors are appointed for an initial term of 2 years, which may be extended indefinitely until a new board of directors is appointed. We have not entered into any service or employment contracts with any of our directors and executive officers.

6.D Employees

The number of PDVSA employees and their locations of employment for 2002, 2001 and 2000 are as follows:

At December 31	Total Number of Employees	In Venezuela	Abroad
2002	45,683	40,133	5,550
2001	46,425	40,945	5,480
2000	46,920	41,462	5,458

Approximately 37% of our Venezuelan work force is unionized and belongs to one of three principal unions: the Federación de Trabajadores Petroleros, Químicos y Similares (79.4%), the Federación de Trabajadores de la Industria de los Hidrocarburos (11.4%) and the Sindicato de Trabajadores de la Industria Petrolera (9.2%). Our management, employees based in our headquarters and security personnel are generally not affiliated with any union.

For our non-unionized workers, we have a social compensation program. This program establishes a variable factor for a portion of the employees' compensation, which is tied to individual performance based on predetermined targets and goals, as well as on our financial results.

At the end of February 2002, PDVSA personnel initiated labor actions against political decisions of the Venezuelan government relating to PDVSA matters. These protests resulted in a brief period of disruption in production at certain PDVSA refineries and shipping terminals in Venezuela. A similar disruption occurred in December 2002 and January 2003, when a nationwide work stoppage halted most of PDVSA's operations. The work stoppage resulted in a significant reduction in the number of PDVSA employees in Venezuela. Between December 2002 and the end of the first quarter of 2003, PDVSA terminated the employment of approximately 18,000 of its personnel.

6.E Share ownership

Petróleos de Venezuela's common stock is not publicly traded and, as of October 24, 2003, we had 51,204 shares outstanding. All of our issued and outstanding shares of common stock are owned by Venezuela.

6.F Audit Committee Structure and Objectives

PDVSA's Audit Committee comprises three members and a secretary, and its main functions are as follows:

•: to maintain an understanding of the overall control environment of PDVSA's operations,
•: to recommend to PDVSA's board of directors any actions needed to improve PDVSA's internal control system,
•: to review and approve the corporate internal audit annual plan and to ensure that the plan attends to PDVSA's interests and main risks,
•: to consider and periodically review the Public Control Office's report on the operations of PDVSA and its affiliates,
•: to submit to the board of directors recommendations on the selection of the independent accountants to perform the external audit of PDVSA's financial statements, and
•: to review with the independent accountants the adequacy of internal accounting and financial reporting controls.

Item 7. Major Shareholders and Related Party Transactions

7.A Major shareholders

Control of Registrant

Petróleos de Venezuela is an entity wholly-owned by The Bolivarian Republic of Venezuela, which exercises its ownership through the Ministry of Energy and Mines. The Ministry of Energy and Mines establishes our general policies, approves our production levels, capital expenditures and operating budgets annually, while our board of directors is responsible for implementing the policies established by our shareholder.

Since its formation, Petróleos de Venezuela has been operated as a commercial entity, vested with commercial and financial autonomy. Under the Constitution of Venezuela (effective as of December 30, 1999), Venezuela must retain exclusive ownership of the shares of Petróleos de Venezuela. However, the Constitution does not require Venezuela to retain ownership of the shares of Petróleos de Venezuela's subsidiaries or of its interests in various exploration and joint venture arrangements.

PDVSA's oil-related activities are governed by the Hydrocarbons Law, which came into effect in January 2002. PDVSA is subject to regulations adopted by the executive branch of the Venezuelan government and other laws of general application, such as the Commercial Code of Venezuela. Petróleos de Venezuela and its Venezuelan subsidiaries are organized under the Commercial Code, which regulates the rights and obligations of Venezuelan commercial companies. Under the Commercial Code, Petróleos de Venezuela and Venezuelan subsidiaries are permitted to develop and execute their shareholder's objectives as corporate entities rather than governmental agencies.

PDVSA's gas-related activities are regulated by the Organic Law of Gas Hydrocarbons of September 1999 and its regulations dated June 2000.

None of Petróleos de Venezuela, its Venezuelan subsidiaries engaged in the conduct of activities reserved to the State pursuant to the Nationalization Law or its foreign subsidiaries is subject to the authorization process set forth in the Finance Administration for the Public Sector Law enacted on September 5, 2000 revoking the Organic Public Credit Law, which establishes the regulations applicable to borrowing and other forms of financing by Venezuelan public entities.

Venezuela is not legally liable for Petróleos de Venezuela's obligations, including Petróleos de Venezuela's guarantees of indebtedness or obligations of its subsidiaries, nor for the debt or obligations of Petróleos de Venezuela's subsidiaries.

Ownership of Reserves

All oil and hydrocarbon reserves within Venezuela are owned by Venezuela and not by Petróleos de Venezuela. Under the Nationalization Law, every activity related to the exploration, exploitation, manufacture, refining, transportation by special means and domestic and foreign sales of hydrocarbons and their derivatives is reserved to the State. Petróleos de Venezuela was created as the entity that coordinates monitors and controls all operations related to hydrocarbons.

7.B Related Party Transactions

See note 17 to our consolidated financial statements, included under "Item 18. Financial Statements."

Item 8. Financial Information

8.A Consolidated Statements and Other Financial Information

8.A.1 See Item 18.

8.A.2 See Item 18.

8.A.3 See reports of independent auditors beginning on page F-1.

8.A.6 Substantially all of our revenues are derived from export sales. See "Item 3.A Selected financial data," and note 18 to our consolidated financial statements.

8.A.7 Legal proceedings

In August 1999, the U.S. Department of Commerce rejected a petition filed by a group of independent oil producers to apply antidumping measures and countervailing duties against imports of

crude oil from Venezuela and some other countries. The petitioners appealed this decision before the U.S. Court of International Trade based in New York. On September 19, 2000, the Court of International Trade remanded the case to the Department of Commerce with instructions to reconsider its August 1999 decision. The Department of Commerce was required to make a revised decision as to whether or not to initiate an investigation. The Department of Commerce appealed to the U.S. Court of Appeals for the Federal Circuit, which dismissed the appeal as premature on July 31, 2001. The Department of Commerce issued its revised decision, which again rejected the petition, in August 2001. The revised decision was affirmed by the Court of International Trade on December 17, 2002. In February 2003, the independent oil producers appealed the Court of International Trade's decision to the Federal Circuit, where the matter is still pending.

In February 2002, LYONDELL-CITGO commenced an action against PDVSA and PDVSA Petróleo, S.A. in the United States District Court for the Southern District of New York. LYONDELL-CITGO alleges that PDVSA and PDVSA Petróleo, S.A. wrongfully declared force majeure events and reduced shipments of extra-heavy crude oil to LYONDELL-CITGO. LYONDELL-CITGO is seeking damages and specific performance for alleged breaches of the long-term crude oil supply agreement between LYONDELL-CITGO and Lagoven (subsequently merged into PDVSA Petróleo, S.A.) and the supplemental supply agreement, between LYONDELL-CITGO and PDVSA, both agreements dated May 5, 1993 and expiring in 2017. On May 31, 2002, PDVSA and PDVSA Petróleo, S.A. filed a motion to dismiss the case, which was briefed. On May 29, 2003, the case was reassigned to another judge. On August 6, 2003, the judge issued a ruling on the motion to dismiss. The judge dismissed one of the ten counts in LYONDELL-CITGO's complaint, allowing the remaining counts to proceed through early stages of litigation without precluding PDVSA and PDVSA Petróleo, S.A. from advancing the same defenses again at a later stage of the case. The defendant's answer to LYONDELL-CITGO's complaint was filed with the court on September 29, 2003. The parties were ordered to appear for a pre-trial conference on October 30, 2003. Management of the companies intend to vigorously contest the allegations. Management and their legal counsel believe that they have substantial defenses.

An action was filed against PDVSA and its subsidiaries PDVSA Petróleo, S.A., PDVSA Finance Ltd. and CITGO Petroleum Corporation on April 11, 2003, in the federal district court of Denver, Colorado. The plaintiff is a U.S. oil and gas exploration and production company that has allegedly entered into an exclusive offshore license agreement with the government of Grenada to explore, develop, produce and market oil and/or natural gas in 4.75 million offshore acres between Grenada and Venezuela. The plaintiff alleges that PDVSA has interrupted and otherwise interfered with its ability to develop and market Grenada's oil and natural gas resources in violation of the U.S. antitrust laws. The plaintiff seeks damages in an amount to be established at trial that it believes should exceed $100 million. The companies deny the allegations and complaint and intend to contest the case vigorously if it proceeds, and the management and their legal counsel believe that the companies have substantial defenses.

During December 2002 and January 2003, there was a work stoppage by a significant number of workers and employees of PDVSA and its subsidiaries in Venezuela. This resulted in the termination of employment effective January 1, 2003 for approximately 18,000 employees (of its then total labor force of 45,000). Based on the opinion of PDVSA's management and legal counsel the terminations were in accordance with the Venezuela labor law. All significant outstanding employee benefits in accordance with PDVSA's employment conditions and the Venezuelan labor law were accrued as of December 31, 2002. The above-mentioned former PDVSA employees have filed a petition for reinstatement with the labor courts. Based on their legal counsel's opinion, management believes that the resolution of this matter will not have a material effect to the Company's financial position or results of operations.

PDVSA previously outsourced its information technology services to Informática, Negocios y Tecnología, S.A. (INTESA) based on a joint venture and a services agreement. INTESA is a Venezuelan company owned 60% by SAIC Bermuda Ltd. and 40% by PDV-IFT, a subsidiary of

PDVSA. PDVSA gave notice of termination of the services agreement, in accordance with the contract on June 28, 2002. PDVSA has proposed a plan to jointly liquidate INTESA and to honor all valid obligations with the employees and providers. PDVSA has been assigned and has paid a significant portion of INTESA's obligations with providers, which will be offset against the debt that PDVSA has with INTESA. Management and their legal counsel believe that the liquidation of INTESA will not have a material effect on the Company's financial position or results of operations.

Additionally, a number of lawsuits and claims have arisen and are being defended and handled in the normal course of business, the possible final effect of which cannot be quantified. Based on analysis of the available information, a provision as of December 31, 2002 and 2001, amounting to $46 million and $30 million, respectively, has been recorded and is included in other liabilities. If known lawsuits and claims were to be determined in a manner adverse to the Company, and in amounts greater than the Company's accruals, then such determinations could have a material adverse effect on the Company's results of operations in a given reporting period. Although it is not possible to predict the outcome of these matters, management, based in part on advice of its legal counsel, does not believe that it is probable that losses associated with the proceedings discussed above, that exceed amounts already recognized, will be incurred in amounts that would be material to the Company's financial position or results of operations.

Item 9. The Offer and Listing

9.A Offer and listing details

PDVSA Finance's senior notes are solely obligations of PDVSA Finance and are not obligations of, or guaranteed by, Petróleos de Venezuela. PDVSA Finance's 6.450% Notes due 2004, 6.650% Notes due 2006, 6.800% Notes due 2008, 7.400% Notes due 2016, 7.500% Notes due 2028, 8.750% Notes due 2004, 9.375% Notes due 2007, 9.750% Notes due 2010 and 9.950% Notes due 2020 are listed on the Luxembourg Stock Exchange. PDVSA Finance's Finance's 8.500% Notes due 2012 are not listed on any securities exchange.

Item 10. Additional Information

10.D Exchange controls

Foreign Exchange Agreements

Article 89 of the regulations of the Central Bank of Venezuela stipulates that the Central Bank of Venezuela must sell non-Venezuelan currency to us on a priority basis to meet our foreign exchange requirements, subject to the annual foreign currency budget approved by the shareholders. We are the only entity accorded such priority under the regulations of the Central Bank of Venezuela, which was approved by the Venezuelan Congress in 1992, although the article establishing our priority to foreign exchange was originally incorporated into the regulations of the Central Bank of Venezuela in 1983 and effectively reaffirmed in 1992.

The priority access has been formalized through a foreign exchange agreement between the Ministry of Finance and the Central Bank of Venezuela. The agreement requires us to sell our foreign exchange receipts to the Central Bank of Venezuela within 48 hours of receipt, except that we may maintain a foreign currency working capital fund of up to the amount authorized by the board of directors of the Central Bank of Venezuela (currently $600 million). We may use amounts contained in this fund to cover our obligations and operating costs in foreign currency and external debt service.

Current revenues and the working capital fund have always proved sufficient to meet all foreign currency requirements as they became due, and we have never experienced payment delays as a result of foreign exchange controls.

Foreign Exchange Budget

We are required to submit a foreign exchange budget for approval by our shareholder each year. Foreign exchange inflows are based on projected export volumes and prices, as well as proceeds from any debt issuance, while outflows are based on projected purchases of imported goods and services, as well as payments of principal of and interest on foreign currency denominated debt. In 2002, our foreign exchange inflows totaled $23,086 million, while outflows totaled $8,699 million.

10.E Taxation

United States holders of PDVSA Finance Notes are not subject to Venezuelan taxes, by reason of withholding or otherwise, on payments made by PDVSA Finance pursuant to the PDVSA Finance Notes.

On January 25, 1999, representatives from the United States and Venezuela signed an income tax treaty for the avoidance of double taxation. Both countries exchanged instruments of ratification on December 30, 1999. The treaty has been fully in force since 2000.

Item 11. Quantitative and Qualitative Disclosures about Market Risk

Introduction

We are exposed to hydrocarbon price fluctuations, interest rate fluctuations and foreign currency exchange risks. To manage these exposures, we have defined certain benchmarks consistent with our preferred risk profile for the environment in which we operate and finance our assets. We do not attempt to manage the price risk related to all of our inventories of hydrocarbon products. As a result, at December 31, 2002, we were exposed to the risk of broad market price with respect to a substantial portion of our hydrocarbon inventories. The following disclosure does not attempt to quantify the price risk associated with such commodity inventories. All matters related to market risk are managed by our international subsidiaries.

Commodity Derivative Instruments

We balance our crude oil and refined products supply and demand and manage a portion of our price risk by entering into petroleum commodity derivatives through CITGO. Generally, CITGO's risk management strategies qualified as hedges through December 31, 2000. Effective January 1, 2001, we decided not to elect hedge accounting. Petroleum Marketing International, A.V.V., a direct trading subsidiary of Petróleos de Venezuela in Aruba, and PMI Panama, S.A., a direct trading subsidiary of Petróleos de Venezuela in Panama, have limited involvement with commodity derivatives. Both these entities manage commodity price risks associated with crude oil or refined products that arise out of their respective core business activities. These entities do not use derivative financial instruments for trading or speculative purposes.

In December 1999, PDVSA Trading, S.A. was incorporated as a direct subsidiary of Petróleos de Venezuela in Venezuela primarily to manage commodity price risk associated with derivatives. This subsidiary began its operations in March 2000.

The table below presents contractual amounts with open positions at December 31, 2002, for commodity derivatives, and includes futures purchased and futures sold.

Non-Trading Commodity Derivatives
Open positions at December 31, 2002

Commodity	Maturity date	Derivative	Number of Contracts (1)	Contract Value (2)	Market Value
				($ in millions)	($ in millions)
No Lead Gasoline	2003 2003 2003 2003 2003 2003	Futures Purchased Futures Sold Listed Options Purchased Listed Options Sold Forward Purchase Contracts Forward Sales Contracts	564 1,023 1,225 2,225 2,577 2,364	19.9 35.3 — — 89.2 81.3	20.6 37.6 4.2 (5.5 92.5 86.2	)
Distillates	2003 2004 2003 2003 2003 2003 2003 2003 2003 2003	Futures Purchased Futures Purchased Futures Sold OTC Options Purchased OTC Options Sold OTC Swaps (Pay Fixed/Receive Float) OTC Swaps (Pay Float/Receive Float) Forward Purchase Contracts Forward Sale Contracts Swap Futures Sold	2,227 31 2,953 66 66 12 75 3,134 2,944 200	73.4 0.8 93.2 — — — — 106.5 98.1 5.9	78.7 0.9 96.7 0.1 (0.1 — — 111.0 104.7 7.3	)
Crude Oil	2003 2003 2003 2003 2003 2003 2003 2003	Futures Purchased Futures Sold Listed Options Purchased Listed Options Sold OTC Swaps (Pay Float/Receive Fixed) Forward Purchase Contracts Forward Sale Contracts Swap Futures Sold	1,986 1,476 2,250 3,150 3,500 5,721 4,412 1,225	51.2 41.8 — — 160.8 129.8 34.6	54.5 45.3 2.3 (3.1 (3.0 174.4 137.2 38.2	) )
Natural Gas	2003 2003	Listed Options Purchased Listed Options Sold	85 40	— —	0.1 0.1
Propane	2003 2003	OTC Swaps (Pay Fixed/Receive Float) OTC Swaps (Pay Float/Receive Float)	75 300	— —	0.5 (1.5	)

(1): Thousand barrels.
(2): Weighted average price.
(3): Floating price based on market index designated in contract; fixed price agreed upon at date of contract.

Non-Trading Commodity Derivatives Open positions at December 31, 2001

Commodity	Derivative	Maturity Date	Volumes of Contracts(1)	Contract Value(2)	Market Value
				($ in millions)	($ in millions)
Crude Oil	Futures Purchased Futures Sold OTC Swaps(Pay Float/Receive Fixed)(3) OTC Swaps(Play Fixed/Receive Float)(3) Forward Purchase Contracts Forward Sale Contracts	2002 2002 2002 2002 2002 2002	1,647 2,397 2 1 6,651 6,261	37 49 — — 128 124	33 49 — — 132 125
Refined Products	Futures Sold	2002	450	12	11
Unleaded	Futures Purchased Futures Sold Forward Purchase Contracts Forward Sale Contracts	2002 2002 2002 2002	994 332 4,095 3,148	25 8 96 71	25 8 94 73
Distillates	Futures Purchased Futures Purchased Futures Sold OTS Options Purchased OTS Options Sold Forward Purchase Contracts Forward Sale Contracts	2002 2003 2002 2002 2002 2002 2002	1,483 94 943 10 10 30 30	43 2 25 — — — —	35 2 22 — — — —
Natural Gas	Futures Sold OTC Options Sold	2002 2002	55 20	2 —	1 —

(1): Thousand barrels.
(2): Weighted average price.
(3): Floating price based on market index designated in contract; fixed price agreed upon at date of contract.

Debt Related Instruments

Interest Rate Risk

We enter into various interest rate swap agreements to manage the risks related to interest rate fluctuations on our debt.

On January 28, 2000, PDVSA Finance entered into an interest rate swap agreement to manage the risks related to interest rate fluctuations in respect of its Euro 200 million 6.250% notes due 2002 through 2006 issued on April 8, 1999. The agreement provides protection to PDVSA Finance in respect of interest and principal payments from a possible appreciation of the Euro relative to the U.S. dollar during the terms of the notes. The agreement contains a knock-in provision that eliminates protection to PDVSA Finance, in respect of principal payments, above a 1.09 U.S. dollar/Euro exchange rate if during the term of the agreement the U.S. dollar/euro exchange rate reaches or exceeds 1.2.

CITGO has fixed and floating U.S. currency denominated debt. CITGO uses interest rate swaps to manage its debt portfolio toward a benchmark of 40% to 60% fixed rate debt to total fixed and floating rate debt. These instruments have the effect of changing the interest rate with the objective of

minimizing CITGO's long-term costs. At December 31, 2002, CITGO's primary exposures were to LIBOR and floating rates on tax exempt bonds.

For interest rate swaps, the table below presents notional amounts and interest rates by expected (contractual) maturity dates. Notional amounts are used to calculate the contractual payments to be exchanged under the contracts.

Non-Trading Interest Rate Derivatives
Open positions at December 31, 2002 and 2001

Variable Rate Index	Expiration Date	Fixed Rate Paid		Notional Principal Amount
				(000s omitted)
J.J. Kenny	February 2005	5.30	%	$	12,000
J.J. Kenny	February 2005	5.27	%		15,000
J.J. Kenny	February 2005	5.49	%		15,000

				$	42,000

Generally, we do not enter into interest rate swaps with respect to debt incurred by PDVSA, other than with respect to debt of CITGO or PDVSA Finance. The table below presents our principal cash flows and related weighted average interest rates by expected maturity date. Weighted average variable rates are based on implied forward rates in the yield curve at the reporting date.

Short-Term and Long-Term Debt
at December 31, 2002

Expected Maturities	Fixed Rate Debt	Average Fixed Interest Rate	Variable Rate Debt	Average Variable Interest Rate
	($ in millions)	%	($ in millions)	%
2003	1,064	7.87	753	4.48
2004	372	7.90	387	4.10
2005	411	8.48	535	5.01
2006	463	8.17	283	4.45
2007	296	8.37	263	4.55
Thereafter	2,369	7.86	1,047	7.22

Total	4,975	7.97	3,268	5.40

Fair Value	7,631

Short-Term and Long-Term Debt
at December 31, 2001

Expected Maturities	Fixed Rate Debt	Average Fixed Interest Rate	Variable Rate Debt	Average Variable Interest Rate
	($ in millions)	%	($ in millions)	%
2002	761	8.79	239	4.85
2003	1,069	8.03	521	5.02
2004	367	7.48	237	3.95
2005	410	8.05	198	3.69
2006	470	7.99	111	3.41
Thereafter	2,600	8.11	1,444	4.97

Total	5,677	8.13	2,750	4.73

Fair Value	7,295

Foreign Exchange Risk

The dollar is our reporting currency, since a significant portion of our revenues and debt, as well as the majority of our costs, expenses and investments are denominated in dollars. We generally do not enter into foreign currency derivative transactions to hedge against movements in exchange rates. We are, however, exposed to foreign currency exchange risk associated with our recoverable luxury and wholesale tax receivables, notes and accounts receivable, and long-term and short-term debt denominated in currencies other than the dollar, as summarized below:

	At December 31, 2002
Currency	Assets	Liabilities	Net
		($ in millions)
Venezuelan bolivars	6,495	5,272	1,223
Euros	195	172	23
Other currencies	5	414	(409	)

	At December 31, 2001
Currency	Assets	Liabilities	Net
	($ in millions)
Venezuelan bolivars	5,294	6,640	(1,346	)
Euros	483	178	305
Other currencies	12	196	(184	)

At December 31, 2002, we had approximately $464 million of short-term and long-term debt denominated in currencies other than dollars, as summarized below:

Currency		At December 31, 2002
		($ in millions)
Bolivars		42
Euros		172
Yens		250

At December 31, 2001, we had approximately $281 million of short-term and long-term debt, denominated in currencies other than dollars, as summarized below:

Currency		At December 31, 2001
		($ in millions)
Bolivars		19
Euros		178
Yens		84

Item 12. Description of Securities Other than Equity Securities

Not applicable.

PART II

Item 13. Defaults, Dividend Arreages and Delinquencies

Petróleos de Venezuela and PDVSA Finance have been in breach of certain of their loan covenants due to the late filings of their respective annual reports on Form 20-F for the year ended December 31, 2002 (and, in respect of Petróleos de Venezuela, its 2002 audited financial statements). Upon delivery of the foregoing documents to the trustee and to the creditors, as the case may be, such covenant breaches will be remedied.

Item 14. Material Modifications to the Rights of Security Holders and Use of Proceeds

Not applicable.

Item 15. Controls and Procedures

Our President and Principal Executive Officer and our Principal Financial Officer have evaluated the effectiveness of the design and operation of the our disclosure controls and procedures (as defined under Rules 13a-15(e) and 15d-15(e) of the Exchange Act) as of December 31, 2002.

Based upon that evaluation, our President and Principal Executive Officer and our Principal Financial Officer observed that there were certain weaknesses in our disclosure controls and procedures and our internal controls that temporarily impacted the timely processing of PDVSA's operational and financial data as a result of the work stoppage and the extensive reduction in our workforce during December 2002 through the first quarter of 2003. During the affected period, PDVSA implemented alternative control systems and, among other things, focused its efforts on filling key management positions and on hiring and training new personnel to oversee and manage its operational, administrative, financial and information systems. Our pre-existing financial and computer systems began to be re-established in February 2003. These control systems were fully restored by the end of July 2003.

Therefore, as of the date of this annual report, our management, including our President and Principal Executive Officer and our Principal Financial Officer, have evaluated our disclosure controls and procedures related to the recording, processing, summarizing and reporting of information in our periodic reports that we file with the Securities and Exchange Commission (SEC). These disclosure controls and procedures have been designed to ensure that (a) material information relating to Petróleos de Venezuela, including its consolidated subsidiaries, is made known to our management, including these officers, by other employees of Petróleos de Venezuela and its subsidiaries, and (b) this information is recorded, processed, summarized, evaluated and reported, as applicable, within the time periods specified in the SEC's rules and forms. Due to the inherent limitations of control systems, not all misstatements may be detected. These inherent limitations include the realities that judgments in decision-making can be faulty and that breakdowns can occur because of simple error or mistake. Additionally, controls can be circumvented by the individual acts of some persons, by collusion of two or more people, or by management override of the control. Our controls and procedures can only provide reasonable, not absolute, assurance that the above objectives have been met. Also, Petróleos de Venezuela does not control or manage certain of its unconsolidated entities and as such, the disclosure controls and procedures with respect to such entities are more limited than those it maintains with respect to its consolidated subsidiaries.

Item 16. [Reserved]

PART III

Item 17. Financial Statements

We have responded to Item 18 in lieu of this item.

Item 18. Financial Statements

See pages F-1 through F-50 incorporated herein by reference.

The following financial statements, together with the report of Alcaraz Cabrera Vázquez (a member firm of KPMG International) thereon, are filed as a part of this annual report:

		Page
Independent Auditors' Report of Alcaraz Cabrera Vázquez (a member firm of KPMG International)		F-1
Independent Auditor's Report of Deloitte & Touche LLP		F-2
Consolidated Balance Sheets at December 31, 2002 and 2001		F-3
Consolidated Statements of Income for the years ended December 31, 2002, 2001 and 2000		F-4
Consolidated Statements of Stockholder's Equity and Comprehensive Income for the years ended December 31, 2002, 2001 and 2000		F-5
Consolidated Statements of Cash Flows for the years ended December 31, 2002, 2001 and 2000		F-6
Notes to Consolidated Financial Statements		F-7

Item 19. Exhibits

Exhibit No:		Description
Exhibit 12.1		Certification of the Principal Executive Officer required by Rule 13a-14(a) or Rule 15d-14(a) of the Securities and Exchange Act of 1934.
Exhibit 12.2		Certification of the Principal Financial Officer required by Rule 13a-14(a) or Rule 15d-14(a) of the Securities and Exchange Act of 1934.
Exhibit 13.1		Certification of the Principal Executive Officer required by Rule 13a-14(b) or Rule 15d-14(b) of the Securities and Exchange Act of 1934 and Section 1350 of Chapter 63 of Title 18 of the United States Code (18 U.S.C. 1350).
Exhibit 13.2		Certification of the Principal Financial Officer required by Rule 13a-14(b) or Rule 15d-14(b) of the Securities and Exchange Act of 1934 and Section 1350 of Chapter 63 of Title 18 of the United States Code (18 U.S.C. 1350).
Exhibit 14.1		Annual Report on Form 20-F of PDVSA Finance Ltd. for the year ended December 31, 2002 as first filed with the U.S. Securities and Exchange Commission (Commission file No. 333-09678) on October 24, 2003 (incorporated herein by reference).

SIGNATURES

The registrant hereby certifies that it meets all of the requirements for filing on Form 20-F and that it has duly caused and authorized the undersigned to sign this annual report on its behalf.

		PETRÓLEOS DE VENEZUELA, S.A.
		By:	/s/ ALÍ RODRÍGUEZ ARAQUE Name: Alí Rodríguez Araque Title: President

Date: October 24, 2003

ANNEX A

Measurement Conversion Table

1 barrel	=	42 U.S. gallons
1 barrel of oil equivalent	=	1 barrel of crude oil	=	5,800 cubic feet of gas (based on the actual average equivalent energy content of PDVSA's proved natural gas reserves)
1 barrel of crude oil per day	=	Approximately 50 tons of crude oil per year
1 cubic meter	=	33.315 cubic feet
1 metric ton	=	1,000 kilograms	=	Approximately 2,205 pounds
1 metric ton of crude oil	=	Approximately 7.3 barrels of crude oil (assuming a specific gravity of 33°)
1 metric ton of oil equivalent	=	Approximately 1,125 cubic meters of natural gas

A-1

Glossary of Certain Oil and Gas Terms

Unless the context indicates otherwise, the following terms used in this report have the meanings set forth below:

2D		Two dimensional seismic lines (km).
3D		Three dimensional seismic lines (square kilometers).
4D		Three dimensional seismic lines (square kilometers) taken as different periods of time.
Alquilation		The process of producing alquilates (refined products used to enhance gasoline).
AQUACONVERSION®		A proprietary technology for the thermal/catalytic conversion of heavy crude oil and residuals by treatment with steam and additives, to reduce the viscosity of heavy crude oil fractions and residuals.
API gravity		An indication of density of crude oil or other liquid hydrocarbons as measured by a system recommended by the American Petroleum Institute (API), measured in degrees. The lower the API gravity, the heavier the compound. For example, asphalt has an API gravity of 8° and gasoline has an API gravity of 50°.
Barrels (or bbl)		Barrels of crude oil, including condensate and natural gas liquids.
BCF		Billions of cubic feet.
BOE		Barrels of oil equivalent.
BPD		Barrels per day.
Cetane index		An index used to measure diesel quality based on the efficiency with which the fuel ignites; the higher the number the higher the quality of the diesel.
Condensate		Light carbon substances produced from natural gas that condense into liquid at normal temperatures and pressures associated with surface production equipment.
crude oil		Crude oil containing condensate.
crude slate (or slate)		A listing of the various crudes that are processed in a refinery during a given period in a given configuration.
Distillate		Liquid hydrocarbons distilled from crude or condensate.
extra-heavy crude oil		Crude oil with an average API gravity of less than 11°.
FCC		The FCC unit is the basis of modern refineries. It "cracks" heavy molecules of crude oils into smaller, lighter ones that can then be used in the formulation of gasolines.
Feedstocks		Partially refined petroleum that is added to the crude slate and converted into refined petroleum products.
Fractionator		A processing unit that breaks down feedstocks into desired fractions (specific boiling ranges).
heavy crude oil		Crude oil with an average API gravity of less than 21°.
Hydrotreatment		The process of removing sulfur from a hydrocarbon stream in the presence of a catalyst.
km		Kilometer.

A-2

light crude oil		Crude oil with an average API gravity of 30° or more.
LNG		Liquefied natural gas.
Medium crude oil		Crude oil with an average API gravity of 21° or more and less than 30°.
MBPD		Thousands of barrels per day.
MCF		Thousands of cubic feet.
MCFD		Thousands of cubic feet per day.
MDWT		Thousand deadweight tons; a designation for the size or displacement of a ship.
M3D		Cubic meters per day.
MM3D		One thousand cubic meters per day.
MMB		Millions of barrels.
MMMB		Billions of barrels.
MMCFD		Millions of cubic feet per day.
Olefins		A class of unsaturated hydrocarbons.
Pitch		Black or dark viscose substance obtained as a residual in the distillation of oil (bituminous — resin).
Proved reserves		Proved oil and gas reserves are 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 reserves 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 escalations based upon future conditions.
Proved developed reserves		Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing natural forces and mechanisms of primary recovery are included as "proved developed reserves" only after testing by a pilot project or after the operating of an installed program has confirmed through production response that increased recovery will be achieved.
Proved undeveloped reserves		Proved undeveloped oil and gas reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively minor expenditure is required for recompletion, but does not include reserves attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proven to be effective by actual testing in the area and in the same reservoir. Reserves on undrilled acreage are limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive field.
Reformer		A processing unit that converts naphtha into higher octane components.
Spud		To begin to drill a well.

A-3

PETRÓLEOS DE VENEZUELA, S.A. AND
SUBSIDIARIES (PDVSA)
(Wholly-owned by the Bolivarian Republic of Venezuela)

Consolidated Financial Statements

December 31, 2002 and 2001

With Independent Auditors' Report Thereon

Independent Auditors' Report

To the Stockholder and Board of Directors of
Petróleos de Venezuela, S.A. (PDVSA):

We have audited the accompanying consolidated balance sheets of Petróleos de Venezuela, S.A. and subsidiaries (PDVSA) (wholly-owned by the Bolivarian Republic of Venezuela) as of December 31, 2002 and 2001, and the related consolidated statements of income, stockholder's equity and comprehensive income, and cash flows for each of the years in the three-year period ended December 31, 2002. These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We did not audit the consolidated financial statements of PDV Holding, Inc. and subsidiaries, a wholly-owned subsidiary, which statements reflect total assets constituting 13% and 12% as of December 31, 2002 and 2001 and total revenues constituting 46%, 43% and 42% for the years ended December 31, 2002, 2001 and 2000, respectively, of the related consolidated totals. Those statements were audited by other auditors whose report has been furnished to us, and our opinion, insofar as it relates to the amounts included for PDV Holding, Inc. and subsidiaries, is based solely on the report of the other auditors.

We conducted our audits in accordance with auditing standards generally accepted in the United States of America. 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 and the report of the other auditors provide a reasonable basis for our opinion.

In our opinion, based on our audits and the report of the other auditors, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Petróleos de Venezuela, S.A. and subsidiaries (PDVSA) as of December 31, 2002 and 2001, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2002, in conformity with accounting principles generally accepted in the United States of America.

ALCARAZ CABRERA VÁZQUEZ


/s/ DAVID ARISMENDI N. David Arismendi N. Public Accountant C.P.C. N^o 3424 Caracas, Venezuela

October 10, 2003

F-1

[Letterhead of Deloitte & Touche LLP]

INDEPENDENT AUDITORS' REPORT

To the Board of Directors and Shareholders of
PDV Holding, Inc.

We have audited the accompanying consolidated balance sheets of PDV Holding, Inc. and subsidiaries (the "Company") as of December 31, 2002 and 2001, and the related consolidated statements of income and comprehensive income, shareholder's equity and cash flows for the years then ended. 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.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of PDV Holding, Inc. and subsidiaries at December 31, 2002 and 2001, and the results of their operations and their cash flows for the years then ended, in conformity with accounting principles generally accepted in the United States of America.

/s/ DELOITTE & TOUCHE LLP

Tulsa, Oklahoma
April 11, 2003

F-2

PETRÓLEOS DE VENEZUELA, S.A. AND
SUBSIDIARIES (PDVSA)
(Wholly-owned by the Bolivarian Republic of Venezuela)

Consolidated Balance Sheets

(In millions of U.S. dollars)

			December 31
			2002	2001
Assets
Current assets:
	Cash and cash equivalents		1,703	925
	Restricted cash		1,772	2,378
	Notes and accounts receivable		3,515	3,280
	Inventories		2,263	2,208
	Prepaid expenses and other		930	882
	Deferred income taxes		476	342

		Total current assets	10,659	10,015
Restricted cash			1,033	1,899
Recoverable value added tax			1,933	2,150
Investments in nonconsolidated investees			2,859	2,819
Property, plant and equipment, net			35,885	36,888
Deferred income taxes			454	301
Other assets			2,135	3,128

			54,958	57,200

Liabilities and Stockholder's Equity
Current liabilities:
	Accounts payable to suppliers		2,850	3,043
	Current portion of long-term debt		1,817	1,000
	Income taxes payable		327	921
	Employee termination, pension and other postretirement benefits		431	679
	Accrued and other liabilities		1,771	1,947

		Total current liabilities	7,196	7,590
Long-term debt, net of current portion			6,426	7,427
Capital lease obligations, net of current portion			68	117
Employee termination, pension and other postretirement benefits			2,395	3,167
Deferred income taxes			946	834
Accrued and other liabilities			525	800

		Total liabilities	17,556	19,935
Minority interests			114	167
Stockholder's equity			37,288	37,098

			54,958	57,200

The accompanying notes form an integral part of the consolidated financial statements.

F-3

PETRÓLEOS DE VENEZUELA, S.A. AND SUBSIDIARIES (PDVSA)
(Wholly-owned by the Bolivarian Republic of Venezuela)

Consolidated Statements of Income

(In millions of U.S. dollars)

			Years ended December 31
			2002	2001	2000
Sales of crude oil and products:
	Exports and international markets		39,875	42,682	49,780
	In Venezuela		1,236	1,701	2,230
Petrochemical and other sales			1,201	1,403	1,224
Equity in earnings of nonconsolidated investees			268	464	446

			42,580	46,250	53,680

Costs and expenses:
	Purchases of crude oil and products		17,956	18,228	19,759
	Operating expenses		9,278	10,882	10,010
	Exploration expenses		133	174	169
	Depreciation and depletion		3,059	2,624	3,001
	Asset impairment		906	257	700
	Selling, administrative and general expenses		1,854	1,853	1,256
	Production and other taxes		5,748	3,760	4,986
	Financing expenses		763	509	672
	Other expenses, net		139	199	148

			39,836	38,486	40,701

		Income before income taxes and minority interests	2,744	7,764	12,979
Income taxes			149	3,766	5,748
Minority interests			5	5	15

		Net income	2,590	3,993	7,216

The accompanying notes form an integral part of the consolidated financial statements.

F-4

PETRÓLEOS DE VENEZUELA, S.A. AND SUBSIDIARIES (PDVSA)
(Wholly-owned by the Bolivarian Republic of Venezuela)

Consolidated Statements of Stockholder's Equity and Comprehensive Income
Years ended December 31, 2002, 2001 and 2000

(In millions of U.S. dollars)

				Capital stock	Legal reserves and other		Accumulated losses		Accumulated other comprehensive income		Total stockholder's equity
Balances at December 31, 1999				39,094	7,557		(13,593	)	(164	)	32,894
Comprehensive income:
	Net income 2000			—	—		7,216		—		7,216
	Change in additional minimum pension liability, net of tax			—	—		—		(160	)	(160	)

			Total comprehensive income								7,056

Transfer to reserves				—	576		(576	)	—		—
Dividends				—	—		(2,018	)	—		(2,018	)

Balances at December 31, 2000				39,094	8,133		(8,971	)	(324	)	37,932
Comprehensive income:
	Net income 2001			—	—		3,993		—		3,993
	Change in additional minimum pension liability, net of tax			—	—		—		(53	)	(53	)

			Total comprehensive income								3,940

Transfer from reserves				—	(151	)	151		—		—
Dividends				—	—		(4,774	)	—		(4,774	)

Balances at December 31, 2001				39,094	7,982		(9,601	)	(377	)	37,098
Comprehensive income:
	Net income 2002			—	—		2,590		—		2,590
	Change in additional minimum pension liability, net of tax			—	—		—		352		352

		Total comprehensive income									2,942

Transfer to reserves				—	66		(66	)	—		—
Dividends				—	—		(2,752	)	—		(2,752	)

Balances at December 31, 2002				39,094	8,048		(9,829	)	(25	)	37,288

The accompanying notes form an integral part of the consolidated financial statements.

F-5

PETRÓLEOS DE VENEZUELA, S.A. AND SUBSIDIARIES (PDVSA)
(Wholly-owned by the Bolivarian Republic of Venezuela)

Consolidated Statements of Cash Flows

(In millions of U.S. dollars)

					Years ended December 31
					2002		2001		2000
Cash flows from operating activities:
	Net income				2,590		3,993		7,216
	Adjustment to reconcile net income to net cash provided by operating activities:
		Depreciation and depletion			3,059		2,624		3,001
		Asset impairment			906		257		700
		Deferred income taxes			(552	)	603		(155	)
		Provision for employee termination, pension and other postretirement benefits			1,340		1,479		2,125
		Equity in earnings of nonconsolidated investees			(268	)	(464	)	(446	)
		Dividends received from nonconsolidated investees			228		163		148
		Change in operating assets:
			Notes and accounts receivable		(235	)	1,155		(615	)
			Inventories		(55	)	(33	)	(364	)
			Prepaid expenses and other assets		374		(554	)	(1,471	)
			Recoverable value added tax		217		(675	)	(554	)
		Change in operating liabilities:
			Accounts payable to suppliers		(193	)	(500	)	614
			Income taxes payable, accrued and other liabilities and minority interests		(1,166	)	(196	)	1,192
			Payments of employee termination, pension and other postretirement benefits		(1,060	)	(760	)	(1,106	)

				Net cash provided by operating activities	5,185		7,092		10,285

Cash flows from investing activities:
	Capital expenditures, net				(2,962	)	(3,781	)	(3,185	)
	Decrease (increase) in restricted cash				1,472		(1,666	)	(2,191	)
	Net change in investments				—		184		16

				Net cash used in investing activities	(1,490	)	(5,263	)	(5,360	)

Cash flows from financing activities:
	Proceeds from issuance of debt				1,175		1,509		438
	Debt repayments				(1,359	)	(681	)	(1,349	)
	Payments of capital lease obligations				(81	)	(127	)	(104	)
	Dividends paid				(2,652	)	(4,862	)	(1,732	)

				Net cash used in financing activities	(2,917	)	(4,161	)	(2,747	)

				Net increase (decrease) in cash and cash equivalents	778		(2,332	)	2,178
Cash and cash equivalents at beginning of year					925		3,257		1,079

Cash and cash equivalents at end of year					1,703		925		3,257

SUPPLEMENTAL DISCLOSURE:
	Cash paid during the year for:
		Interest, net of capitalized amounts			615		699		761
		Income taxes			911		3,443		4,955

	Non-cash activities:
		Tax certificates applied against income taxes payable			—		84		255

The accompanying notes form an integral part of the consolidated financial statements.

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PETRÓLEOS DE VENEZUELA, S.A. AND SUBSIDIARIES (PDVSA)
(Wholly-owned by the Bolivarian Republic of Venezuela)

Notes to Consolidated Financial Statements

December 31, 2002 and 2001

(1) Operations and Summary of Significant Accounting Policies

(a) Operations

Petróleos de Venezuela, S.A. and its subsidiaries (PDVSA or the Company) are wholly-owned by the Bolivarian Republic of Venezuela, which controls PDVSA through the Ministry of Energy and Mines. PDVSA is responsible for developing the national petroleum, petrochemical, coal and Orimulsion® industries and planning, coordinating, supervising and controlling the activities of its subsidiaries, both in Venezuela and abroad. Most of the foreign companies are responsible for refining and marketing activities in North America, Europe and the Caribbean.

The main activities of PDVSA are governed by the Organic Hydrocarbons Law, which came into effect in January 2002, repealing the Hydrocarbons Law of 1943, the Law of Assets Subject to Reversion in Hydrocarbon Concessions of 1971, the Law that Reserves for the State the Exploitation of the Domestic Market for the Byproducts of Hydrocarbons of 1973, the Organic Law that Reserves for the State the Industry and Trade of Hydrocarbons of 1975, the Organic Law of Domestic Market Opening for Gasoline and Other Hydrocarbon-derived Fuels for Use in Automobiles of 1998, and any other legal provision that may be in conflict with this law. Gas activities are regulated by the Organic Law of Gas Hydrocarbons of September 1999 and its Regulation dated June 2000.

The main changes in the new Organic Hydrocarbons Law which affect the Company are as follows:

•

Production tax or royalty increased from 16²/3% to 30% of the volume of extracted hydrocarbons. For mature reservoirs or extra-heavy crude oil from the Orinoco Belt, the percentage ranges from 20% to 30%, and from 16²/3% to 30% for Bitumen, based on the profitability of those reservoirs.

•

The following taxes are also established:

•: Surface tax equal to 100 tax units for each square kilometer or fraction thereof for each year, determined based on the concession area not under production; with an annual increase of 2% for five years and 5% in subsequent years.
•: General consumption tax applicable to each liter of hydrocarbon-derived product sold in the domestic market, the rate for which shall be fixed annually in the Budget Law at between 30% and 50% of the price paid by the final consumer. For 2002, the tax was 30%.
•: Tax on the Company's own consumption, equivalent to 10% of the value of each cubic meter of hydrocarbon-derived product consumed as fuel oil in the organization's operations, calculated based on the final sale price.

At the end of February 2002, some PDVSA personnel initiated labor actions against political decisions of the Venezuelan government relating to PDVSA matters. These protests resulted in a brief period of disruption in production at certain PDVSA refineries and shipping terminals in Venezuela.

During December 2002 and January 2003, a nationwide work stoppage disrupted most activity in Venezuela, including the operations of PDVSA and its Venezuelan subsidiaries. PDVSA's production of

F-7

crude oil and natural gas, as well as the export of crude oil and refined petroleum products were severely affected by these events. As a result of the work stoppage and the extensive reduction in our workforce there were certain weaknesses in our internal controls that temporarily impacted the processing of PDVSA's operational and financial data during December 2002 through the first quarter of 2003. During the affected period, PDVSA implemented alternative control systems and among other things, focused efforts on filling key management positions and on hiring and training new personnel to oversee and manage our operational, administrative, financial and information systems. Preexisting controls were progressively re-established and were restored by the end of July 2003. As part of the financial systems recovery process, the activities of the Department of Internal Control were re-established, both in the operational areas and at the headquarters (see notes 19 and 21).

(b) Basis of Presentation and Foreign Currency Translation

In preparing its consolidated financial statements, the Company, for international reporting purposes, has elected to present its financial statements in accordance with accounting principles generally accepted in the United States of America (US GAAP). The main economic operating environment of PDVSA consists of the international markets for crude oil and products. The U.S. dollar (dollar or $) is the reporting currency for PDVSA.

Assets and liabilities of subsidiaries outside of Venezuela and the United States of America are generally translated into U.S. dollars at the rates of exchange in effect at the balance sheet date. Income and expense items are translated at the weighted average exchange rates prevailing during each period presented. The financial statements of Venezuelan subsidiaries, whose accounting records are maintained in bolivars (Bs), have been remeasured into dollars for purposes of consolidation. Gains and losses resulting from foreign currency transactions are included in the results of operations. Foreign currency losses in 2002 amounted to $509 million, which is comprised of $26 million gain included in other expenses, net and $535 million loss included in deferred income tax (benefit) expense. For 2001 and 2000, foreign currency gains and losses were not significant.

(c) Estimates, Risks and Uncertainties

The preparation of financial statements requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

PDVSA's operations can be influenced by domestic and international political, legislative, regulatory and legal environments. In addition, significant changes in the prices or availability of crude oil and refined products could have a significant impact on the results of operations for any particular year.

(d) Consolidation and Investments

The consolidated financial statements include the accounts of PDVSA and its subsidiaries in which PDVSA's interest, direct or indirect, exceeds 50%. Significant wholly-owned subsidiaries are: PDVSA Petróleo, S.A. (PDVSA Petróleo; formerly PDVSA Petróleo y Gas, S.A.); Petroquímica de Venezuela, S.A. (PEQUIVEN); PDVSA Gas, S.A. (PDVSA Gas); Bitúmenes Orinoco, S.A. (BITOR); Deltaven, S.A. (DELTAVEN) and Carbones del Zulia, S.A. (CARBOZULIA) in Venezuela; PDV Holding, Inc. (PDV HOLDING) and its main subsidiary PDV America, Inc. (PDV AMERICA), which operate in the United States of America and PDVSA Finance Ltd. (PDVSA FINANCE), a special purpose company, incorporated in The Cayman Islands. The main activity of PDVSA in the United States of America is represented by CITGO Petroleum Corporation and its subsidiaries (CITGO), which is

F-8

wholly-owned by PDV AMERICA. Significant balances and transactions between consolidated entities have been eliminated in consolidation.

Investments between 20% and 50% in nonconsolidated investees are accounted for using the equity method. Prior to the adoption of Statement of Financial Accounting Standards No. 142, "Goodwill and Other Intangible Assets" (SFAS No. 142), the excess of cost of the stock of those investees over PDVSA's share of their net assets at the acquisition date was recognized as goodwill and was being amortized on a straight-line basis over a maximum of 40 years, based on the estimated useful lives of the investees' assets. Subsequent to adoption of SFAS No. 142 on January 1, 2002, the equity method goodwill is not amortized but is tested annually for impairment, by applying a fair-value based test at the reporting unit level. The effect of adopting this standard was not significant.

Investments of less than 20% are recorded at cost, and dividends from these companies are included in income when declared.

PDVSA, through its consolidated subsidiaries PDVSA Cerro Negro, S.A. (PDVSA Cerro Negro), PDVSA Sincor, S.A. (PDVSA Sincor) and Corpoguanipa, S.A. (Corpoguanipa), participates in various unincorporated joint ventures to develop extra-heavy crude oil reserves in the Orinoco Belt. The companies recognize their proportional share of the assets, liabilities, income and costs based on their ownership interest in these joint ventures.

(e) Revenue Recognition

Revenues from sales of crude oil, natural gas, refined and petrochemical products, coal, Orimulsion® and other products are recorded on an accrual basis when title is transferred.

(f) Inventories

Inventories are stated at the lower of cost or market value. Costs of inventories of crude oil and its products are determined by the last-in, first-out (LIFO) method. Fertilizers and industrial products are stated at average cost. Materials and supplies are stated mainly at average cost, less an allowance for possible losses and are classified into three groups: current assets, non-current assets and the portion to be capitalized as property, plant and equipment.

(g) Property, Plant and Equipment

Property, plant and equipment is stated at cost, less losses due to impairment. The successful efforts method of accounting is used for oil and gas exploration and production activities. All costs of development wells, related to plant and equipment and oil and gas properties are capitalized. Costs of exploratory wells are capitalized pending determination of whether the wells find proved reserves. Costs of wells for which no proved reserves are found are expensed, when they are determined unsuccessful. Other exploratory expenditures, including geophysical costs, are expensed as incurred. Major replacements and renewals are capitalized. Expenditures for major maintenance and plant repairs (plant turnaround costs) are recorded as deferred costs and amortized over the period between maintenance. Expenditures for minor maintenance, repairs and renewals carried out to maintain facilities in operating condition are expensed.

Financing costs of projects requiring major investments in long-term construction and those incurred from financing of specific projects are capitalized and amortized over the estimated useful lives of the related assets. Gains or losses from significant retirements or sales are included in net income.

Depreciation and depletion of capitalized costs of proved crude oil, natural gas and Orimulsion® production properties are determined pursuant to the unit-of-production method by field based on proved developed reserves. These rates are revised annually based on a reserve study and applied

F-9

retroactively to the beginning of the year. Depreciation and depletion for coal production are determined pursuant to the unit-of-production method as the proved reserves are produced. Depreciation for petrochemical plants is determined pursuant to the unit-of-production method. Capitalized costs of the remaining facilities and equipment are depreciated on a straight-line basis over their estimated useful lives, which for refining assets average seventeen years; service stations-ten years; administration buildings-twenty years and the remaining assets between three and ten years. Additionally, assets capitalized under capital leases are depreciated by the straight-line method over ten years, which approximates the estimated useful life of the assets, since ownership of such assets generally transfers at the end of the lease term.

Oil, gas and other properties held and used by PDVSA are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of an asset to future undiscounted net cash flows expected to be generated by the asset. If the carrying amount of an asset exceeds its estimated future cash flows, an impairment charge is recognized for the amount by which the carrying amount of the asset exceeds the fair value of the asset.

(h) Accounting for Income Taxes

PDVSA applies the provisions established in SFAS No. 109 "Accounting for Income Taxes". This statement requires an asset and liability approach for financial accounting and reporting for income tax under the following basic principles: a) A current tax liability or asset is recognized for the estimated taxes payable or refundable on tax returns for the current year, b) A deferred tax liability or asset is recognized for the estimated future tax effects attributable to temporary differences and tax loss and tax credit carryforwards, c) The measurement of current and deferred tax liabilities and assets is based on provisions of the enacted tax law and the effects of future changes in the tax law or rates are not anticipated, and d) The measurement of deferred tax assets is reduced, if necessary, by the amount of any tax benefits for which available evidence indicates that it is more likely than not that they will not be realized. Under this method, deferred tax is recognized with respect to all temporary differences, and the benefit from utilizing tax loss carryforwards and tax credits is recognized in the year in which the losses or credits arise (subject to a valuation allowance with respect to any tax benefits not expected to be realized).

PDVSA and its Venezuelan subsidiaries were required to adjust the tax bases of their non-monetary assets and liabilities in bolivars for the effects of inflation beginning in 1993. No deferred tax asset is recorded for the future benefit of the inflation revaluation in accordance with SFAS No. 109. SFAS No. 109 prohibits recognition of a deferred tax liability or asset for differences related to assets and liabilities that are remeasured from bolivars to U.S. dollars using historical exchange rates and that result from: (1) changes in exchange rates or (2) indexing for tax purposes. Revaluation for the effects of inflation on PDVSA and its Venezuelan subsidiaries non-monetary assets and liabilities is performed annually. These annual revaluations may generate additional taxable income or losses which may be offset against or increase the benefit from the amortization of the initial and annual revaluation. Under SFAS No. 109, the net benefit from the initial and future revaluations are recognized as realized.

(i) Accrual for Employee Termination, Pension and Other Postretirement Benefits

PDVSA accrues its liability for Venezuelan employee termination benefits, in accordance with Venezuelan labor legislation and the collective labor contracts. A significant portion of the termination benefits has been deposited in trust accounts on behalf of the employees. Labor contracts, both in Venezuela and abroad, provide for pension plans for all eligible workers based, among other things, on length of service, age and compensation levels. The pension liability is calculated using actuarial methods. The cost of this program is being funded currently.

F-10

In October 2002, PDVSA agreed to a new collective labor contract effective until 2004, introducing improved salaries and benefits for its contractual workers. In 2000, the Company approved a new pension system which established an individual capitalization plan for each worker, with monthly contributions of 9% by PDVSA and 3% by the worker of the base compensation thereby eliminating the worker's contribution of 25% of the termination benefits at the time of retirement.

PDVSA provides other benefits to its eligible former employees, such as health care, life insurance, disability payments, payments in lieu of salaries and wages and other social benefits. This liability is accrued using actuarial methods over the active service lives of employees. The net periodic costs are recognized as employees render the services necessary to earn the postretirement benefits.

(j) Commodity and Interest Rate Derivatives

Beginning January 1, 2001, the Company adopted SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities", as amended by SFAS No. 138. SFAS No. 133 requires that all derivatives be recognized at fair value as either assets or liabilities in the balance sheet with an offset either to stockholder's equity and other comprehensive income or income depending upon the classification of the derivative.

PDVSA elected not to designate any of its derivatives as hedges for accounting purposes. Beginning January 1, 2001, all derivatives were recognized in the balance sheet at fair value, and subsequent changes were recorded in the statement of income. The effects of adoption of the new accounting principle at January 1, 2001 and the effects of changes in the fair value of derivatives during the years ended December 31, 2002 and 2001 were not significant.

Prior to the adoption of SFAS No. 133, as amended, in January 2001, gains or losses on contracts, which qualified as hedges, were recognized when the related inventory was sold or the hedged transaction was completed. Changes in the market value of commodity derivatives, that were not hedges, were recorded as gains or losses in the period in which they occurred. Premiums paid for purchased interest rate swap and cap agreements were amortized to interest expense over the terms of the agreements. Unamortized premiums were included in other assets. The interest rate differentials received or paid by the Company related to these agreements were recognized as adjustments to interest expense over the term of the agreements. Gains or losses on terminated swap agreements were either amortized over the original term of the swap agreement if the hedged borrowings remained in place, or were recognized immediately if the hedged borrowings were no longer held.

(k) Dismantlement, Removal and Environmental Expenditures

The Company provides for estimated dismantlement and site removal costs of oil and gas exploration and production areas based on the plan of disincorporation of assets for the following year. Environmental expenditures that relate to current or future revenues are expensed or capitalized as appropriate. Expenditures that relate to an existing condition caused by past operations and do not contribute to current or future revenue generation are expensed. Provisions are recorded when the costs are probable and may be reasonably estimated. These provisions are generally set up to coincide with the formalization of an action plan by PDVSA. Environmental liabilities are not discounted to their present value. Subsequent adjustments to estimates, to the extent required, may be made as more refined information becomes available.

(l) Research and Development Costs

Research and development costs are expensed when incurred. In 2002, 2001 and 2000, amounts charged to expense for research and development activities amounted to $31 million, $41 million and $28 million, respectively.

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(m) Other Comprehensive Income

Other comprehensive income consists of net income and changes in the minimum pension liability, and is presented in the consolidated statement of stockholder's equity.

(n) Segment Information

PDVSA has determined that its reportable segments are those that are based on the Company's method of internal reporting. PDVSA identifies such segments based on its business units and geographically. PDVSA's reportable operating segments include exploration, production and improvement of crude oil and natural gas (upstream); refining, supply and marketing (downstream); and petrochemicals.

(o) Cash Flows

For purposes of the consolidated statement of cash flows, PDVSA considers as cash equivalents all deposits and other cash placements with original maturities of less than three months, including amounts deposited with the Central Bank of Venezuela (BCV), available on a current basis, which at December 31, 2002, 2001 and 2000 amounted to $273 million, $87 million and $1,995 million, respectively.

F-12

(p): Recently Issued Accounting Standards

In June 2001, the Financial Accounting Standards Board (FASB) issued SFAS No. 143, "Accounting for Asset Retirement Obligations" ("SFAS No. 143"), which addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. SFAS No. 143 applies to legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or normal use of such assets. SFAS No. 143 requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it was incurred if a reasonable estimate of such fair value can be made. The fair value of the liability is added to the carrying amount of the associated asset and this additional carrying amount is depreciated over the life of such asset. The liability is adjusted at the end of each period to reflect the passage of time and changes in the estimated future cash flows underlying the initial fair value measurement, and such adjustments are reflected in operations. If PDVSA's obligation is settled for other than the carrying amount of the liability, PDVSA will recognize a gain or loss on settlement. The estimated cumulative adjustment for the adoption of this accounting principle as of January 1, 2003 is an after-tax charge to income of $436 million. The accounting change led to a $87 million increase in property, plant and equipment, net, a $919 million increase in accrued liabilities and a $396 million increase in deferred tax assets.

In April 2002, the FASB issued SFAS No. 145, "Rescission of FASB Statements No. 4, 44 and 64, Amendment of FASB Statement No. 13, and Technical Corrections". SFAS No. 145 amends existing guidance on reporting gains and losses on the extinguishment of debt to prohibit the classification of the gain or loss as extraordinary, as the use of such extinguishments have become part of the risk management strategy of many companies. SFAS No. 145 also amends SFAS No. 13 to require sale-leaseback accounting for certain lease modifications that have economic effects similar to sale-leaseback transactions. The provisions of the Statement related to the rescission of Statement No. 4 is applied in fiscal years beginning after May 15, 2002. The provisions of the Statement related to Statement No. 13 were effective for transactions occurring after May 15, 2002. The adoption of SFAS No. 145 is not expected to have a material effect on PDVSA's financial statements.

In June 2002, the FASB issued SFAS No. 146, "Accounting for Costs Associated with Exit or Disposal Activities". SFAS No. 146 addresses financial accounting and reporting for costs associated with exit or disposal activities and nullifies Emerging Issues Task Force (EITF) Issue 94-3, "Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity". The provisions of this Statement are effective for exit or disposal activities that are initiated after December 31, 2002. The adoption of SFAS No. 146 is not expected to have a material effect on PDVSA's financial statements.

In November 2002, the FASB issued Interpretation No. 45 (FIN 45), "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness to Others, an Interpretation of FASB Statements No. 5, 57 and 107 and rescission of FASB Interpretation No. 34". This Interpretation elaborates on the disclosures to be made by a guarantor in its interim and annual financial statements about its obligations under guarantees issued. The Interpretation also clarifies that a guarantor is required to recognize, at inception of a guarantee, a liability for the fair value of the obligation undertaken. The initial recognition and measurement provisions of the Interpretation are applicable to guarantees issued or modified after December 31, 2002, and are not expected to have a material effect on PDVSA's financial statements. The disclosure requirements are effective for financial

F-13

statements of interim and annual periods ending after December 15, 2002, and such disclosures are provided in note 19.

In January 2003, the FASB issued Interpretation No. 46 (FIN 46), "Consolidation of Variable Interest Entities, an Interpretation of Accounting Research Bulletin No. 51", which provides a guide when certain entities should be consolidated or the interests in those entities should be disclosed by corporations that do not control them through majority voting interest. Under FIN 46, entities are required to be consolidated by corporations that lack majority voting interest when equity investors of those entities do not have significant capital at risk or they lack voting rights, the obligations to absorb expected losses, or the right to receive expected returns. Entities identified with these characteristics are called variable interest entities and the interests that corporations have in these are called variable interests. These interests can derive from certain guarantees, leases, loans or other arrangements that result in risks and rewards that are disproportionate to voting interests in the entities. The Interpretation applies immediately to variable interest entities created after January 31, 2003 and to variable interest entities in which an enterprise obtains an interest after that date. For variable interest entities created before February 1, 2003, the Interpretation applies in the first fiscal year or interim period beginning after June 15, 2003. The FASB has delayed the effective date for implementing FIN 46, to interim and annual periods ending on or after December 15, 2003. PDVSA is currently in the process of analyzing the effects of this Interpretation.

(q): Proposed Accounting Change

The American Institute of Certified Public Accountants (AICPA) has issued a "Statement of Position" exposure draft on cost capitalization that is expected to require companies to expense the non-capital portion of major maintenance costs as incurred. The statement is expected to require that any existing unamortized deferred non-capital major maintenance costs be expensed immediately. This statement also has provisions that will change the method of determining depreciable lives. The impact on future depreciation expense is not determinable at this time. The exposure draft indicates that this change will be required to be adopted for fiscal years beginning after June 15, 2003, and that the effect of expensing existing unamortized deferred non-capital major maintenance costs will be reported as a cumulative effect of an accounting change in the consolidated statement of income. Currently, the AICPA is discussing the future of this exposure draft with the FASB. The final accounting requirements and timing of required adoption are not known at this time. At December 31, 2002, the companies had included turnaround costs of $505 million in other assets, net of $103 million in prepaid expenses and other. Company management has not determined the amount, if any, of these costs that could be capitalized under the provisions of the exposure draft.

(r): Reclassifications

Certain reclassifications have been made to the 2001 and 2000 financial statements to conform with the classifications used in 2002.

(2) Foreign Exchange Agreement with The Central Bank of Venezuela (BCV)

Under Venezuelan law, the BCV is required to sell foreign currency to PDVSA at an agreed rate, and on a priority basis to meet its foreign exchange needs, as set out in PDVSA's annual foreign exchange budget. Pursuant to the agreement between the Venezuelan government and the BCV, all foreign currency from petroleum activities received by PDVSA or its Venezuelan subsidiaries must be sold to the BCV at the agreed rate. PDVSA may use such foreign currency to service its current debt,

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make capital investments and pay expenses and maintain a rotatory fund for working capital which shall not exceed $600 million (see note 21).

(3) Transactions and Balances in Foreign Currency

PDVSA has the following monetary assets and liabilities denominated in currencies other than the dollar which are converted to dollars at the exchange rate prevailing at the balance sheet date (in millions of dollars):

		December 31
		2002	2001
Monetary assets:
	Bolivars	6,495	5,294
	Euros	195	483
	Other currencies	5	12

		6,695	5,789

Monetary liabilities:
	Bolivars	5,272	6,640
	Euros	172	178
	Other currencies	414	196

		5,858	7,014

	Net monetary asset (liability) position (see note 21)	837	(1,225	)

The year-end exchange rate, the average exchange rate for the year and the interannual increases in the exchange rate and Consumer Price Index (CPI), published by the BCV, were as follows:

	December 31
	2002	2001	2000
Exchange rates at year-end (Bs/$1)	1,403.00	770.09	698.23
Average annual exchange rates (Bs/$1)	1,163.91	722.01	679.80
Interannual increase in the exchange rate (%)	82.19	10.29	7.83
Interannual increase in the CPI (%)	31.22	12.29	13.43

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(4) Restricted Cash

Restricted cash includes (in millions of dollars):

	December 31
	2002	2001
Macroeconomic Stabilization Investment Fund (FIEM)	2,382	4,072
Funds for extra-heavy crude oil project in the Orinoco Belt	239	109
Liquidity account of PDVSA Finance	161	96
Other	23	—

	2,805	4,277
Less current portion	1,772	2,378

	1,033	1,899

In June 1999, the Venezuelan government created the Macroeconomic Stabilization Investment Fund (FIEM) to minimize the adverse effects of volatile prices in the global energy markets on Venezuela's economy, national budget, and monetary and foreign exchange markets. PDVSA was required to make deposits to the FIEM equivalent to 50% of revenues from export sales in excess of $9 per barrel, net of taxes related to such sales.

In October 2001 and April 2003, the Venezuelan government introduced reforms to the FIEM Law and, among other changes, suspended the contributions for the last quarter of 2001 and the years 2002 and 2003. For 2004 to 2008 inclusive, 6% of income from exports, net of the respective taxes, will be transferred to the FIEM. This rate will be progressively increased on an annual basis at a constant rate of 1% up to 10% in 2008.

PDVSA's deposits with the FIEM can be used only by PDVSA with the prior approval of the board of directors of the FIEM, provided that the National Assembly of Venezuela and the Venezuelan government have informed them, within the established period, of compliance with the conditions established for this purpose.

At December 31, 2001, there were contributions pending payment to the FIEM of $420 million which were paid during 2002.

In June 2002, the board of directors of the FIEM and the National Assembly authorized PDVSA to withdraw up to $2,445 million. As of December 31, 2002, $2,173 million have been withdrawn.

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(5) Notes and Accounts Receivable

Notes and accounts receivable are summarized as follows (in millions of dollars):

	December 31
	2002	2001
Trade	3,066	2,506
Related parties (see note 17)	328	440
Other	179	383

	3,573	3,329
Less allowance for doubtful trade accounts receivable	58	49

	3,515	3,280

(6) Inventories

Inventories are summarized as follows (in millions of dollars):

	December 31
	2002	2001
Crude oil and products	1,883	1,826
Fertilizers, industrial products, coal, Orimulsion® and other	57	85
Materials and supplies	404	395

	2,344	2,306
Less materials and supplies classified in non-current assets, net (see note 9)	81	98

	2,263	2,208

At December 31, 2002 and 2001, crude oil and products inventories stated using the LIFO method accounted for 80% and 79% of total inventories, respectively.

At December 31, 2002 and 2001, the replacement cost of inventories of crude oil and products exceeded LIFO cost by approximately $1,759 million and $1,490 million, respectively, and accordingly, no write-down was necessary.

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(7) Investments in Nonconsolidated Investees

Investments in nonconsolidated investees accounted by the equity method are summarized as follows (in millions of dollars):

				December 31
				Percentage of capital stock		Share of equity
				2002	2001	2002		2001
Foreign investees:
	United States of America:
	CITGO investees:
		LYONDELL-CITGO		41	41	518		509
		Needle Coker		25	25	19		22
		Other		—	—	179		170
	Chalmette Refining			50	50	253		316
	Merey Sweeny			50	50	14		34

						983		1,051
	Virgin Islands:
		Hovensa L.L.C.		50	50	762		805
	Germany:
		Ruhr Oel		50	50	146		132
	Sweden:
		Nynäs Petroleum		50	50	83		61
	Colombia:
		Monómeros Colombo Venezolanos		47	47	26		30
	Other:
		Bitor investees		50	50	(3	)	2

						1,997		2,081

Investees in Venezuela:
	PETROZUATA			50	50	352		230
	FERTINITRO			35	35	121		122
	METOR			38	38	109		98
	Carbones del Guasare			49	49	53		88
	Supermetanol			35	35	58		70
	Super Octanos			49	49	97		78
	CERAVEN			49	49	10		10
	PROFALCA			35	35	13		10
	INTESA			40	40	5		6
	Tripoliven, C.A.			33	33	5		8
	Aguas Industriales de Jose, C.A.			25	25	10		9
	Other			—	—	29		9

						862		738

			Total nonconsolidated investees			2,859		2,819

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The carrying value of these investments exceeded PDVSA's equity in the underlying net assets by approximately $197.1 million and $205.9 million at December 31, 2002 and 2001, respectively.

Information on PDVSA's investments in nonconsolidated investees follows (in millions of dollars):

	2002	2001
PDVSA's investments in nonconsolidated investees	2,859	2,819
PDVSA's equity in net income of nonconsolidated investees	268	464
Dividends and distributions received from nonconsolidated investees	228	163

Summarized gross combined financial information of the above nonconsolidated investees abroad and in Venezuela follows (in millions of dollars):

			December 31
			2002						2001						2000
			Venezuela		Abroad		Total		Venezuela		Abroad		Total		Venezuela		Abroad		Total
Financial position:
	Current assets		851		2,092		2,943		886		1,800		2,686		726		1,725		2,451
	Non-current assets		5,027		7,247		12,274		5,253		6,943		12,196		4,883		6,366		11,249
	Current liabilities		(519	)	(1,886	)	(2,405	)	(576	)	(2,034	)	(2,610	)	(476	)	(2,218	)	(2,694	)
	Long-term liabilities		(3,516	)	(4,400	)	(7,916	)	(3,818	)	(3,355	)	(7,173	)	(3,570	)	(2,802	)	(6,372	)

		Net equity	1,843		3,053		4,896		1,745		3,354		5,099		1,563		3,071		4,634

Operating results for the year:
	Revenues		1,614		8,913		10,527		1,768		12,623		14,391		1,337		13,790		15,127
	Operating income		548		2,018		2,566		422		2,309		2,731		573		2,285		2,858
	Net income		508		246		754		303		1,133		1,436		396		663		1,059

(8) Property, Plant and Equipment, Net

Property, plant and equipment, net is summarized as follows (in millions of dollars):

	December 31
	2002	2001
Oil and gas production	44,483	43,485
Refining, marketing and transportation	21,724	19,281
Petrochemical	3,267	3,687
Other	1,358	1,639

	70,832	68,092
Less accumulated depreciation and depletion	40,432	37,126

	30,400	30,966
Land	347	222
Construction in progress	5,138	5,700

	35,885	36,888

Accumulated depreciation and depletion includes $1,103 million and $342 million as of December 31, 2002 and 2001, respectively, related to impairment charges.

F-19

Depreciation and depletion expenses, impairment charges and capitalized interest are summarized as follows (in millions of dollars):

	Years ended December 31
	2002	2001	2000
Depreciation and depletion	3,059	2,624	3,001
Impairment charges	906	257	700
Capitalized interest	7	51	59

Asset impairment charges relate to oil and gas wells included under oil and gas production assets which are planned to be retired. These charges represent the amount by which the carrying value of the related assets exceed their fair value, as determined based on cash flow analysis. For segment reporting purposes these assets are reflected in the Company's Venezuelan upstream operations.

At December 31, 2002 and 2001, there are certain gas compression plants and related equipment acquired under capital lease agreements recorded as property, plant and equipment for approximately $304 million and $349 million, net of accumulated depreciation of approximately $582 million and $537 million, respectively. Depreciation expense recorded in 2002, 2001 and 2000 for assets acquired under capital lease agreements, amounted to $45 million, $45 million and $46 million, respectively. At December 31, 2002, future lease payments for operating and capital leases are summarized as follows (in millions of dollars):

Years		Operating	Capital
2003		182	65
2004		139	25
2005		115	5
2006		99	5
2007		91	5
Remaining years		716	16

Estimated future lease payments		1,342	121

Less interest			23

	Present value		98
Short-term portion, included in accrued and other liabilities (see note 16)			30

Long-term portion			68

Rent expense incurred from operating leases during 2002, 2001 and 2000 was $182 million, $108 million and $52 million, respectively.

F-20

(9): Other Assets

Other assets are summarized as follows (in millions of dollars):

	December 31
	2002	2001
Long-term accounts receivable	669	858
Materials and supplies (see note 6)	81	98
Plant turnaround costs, net of amortization and short-term portion	402	312
Intangible pension plan asset (see note 15)	680	1,202
Other	303	658

	2,135	3,128

(10) Joint Development Activities

PDVSA has undertaken the following joint development activities in Venezuela:

(a): Development of the Orinoco Belt Extra-Heavy Crude Oil Reserves

The Venezuelan Congress approved several association agreements for the exploitation and upgrading of extra-heavy crude oil and marketing of the upgraded crude oil, as follows:

			Estimated gross project cost (unaudited)	Incurred as of December 31, 2002 (unaudited)
	PDVSA's percentage of participation		Estimated gross project cost (unaudited)	Incurred as of December 31, 2002 (unaudited)
Association	PDVSA's percentage of participation	Partners	(millions of dollars)	(millions of dollars)
Petrozuata	49.90	ConocoPhillips	3,000	3,478
Cerro Negro	41.67	ExxonMobil-Veba Oel	2,000	2,823
Sincor	38.00	Total Fina-Statoil	4,200	4,654
Hamaca	30.00	ChevronTexaco-ConocoPhillips	3,400	2,227

PDVSA participates in these joint ventures through its 49.9% owned subsidiary PETROZUATA (see note 7) and its wholly-owned subsidiaries, PDVSA Cerro Negro, PDVSA Sincor and Corpoguanipa (Hamaca Project) (see note 1(d)).

The objective of these joint ventures is to perform vertically integrated activities for the exploration, development, production, mixing and transport of extra-heavy crude oil, in the areas of Zuata, Cerro Negro, and Hamaca from the Orinoco Belt, for processing in the improvement plants, to produce upgraded crude oil of high gravity for commercialization on the international markets. During the construction phase of the plants, the joint ventures produce development products.

During 1998, 1999 and 2001, development production commenced in Petrozuata, Cerro Negro and Hamaca, respectively. The commercial production of upgraded crude oil in Petrozuata, Cerro Negro and Sincor began in February 2001, August 2001 and March 2002, respectively; and for Hamaca, it is expected to commence in the second quarter of 2004.

The disbursements required for these joint ventures are covered by capital contributions of PDVSA and the partners, from financing and income from development production.

(b): Risk Exploration and Production in New Areas Under Profit Sharing Agreements

Corporación Venezolana del Petróleo, S.A. (CVP) is the subsidiary appointed to coordinate, control and supervise risk exploration and production activities for hydrocarbon fields in new areas, assigned to CVP by the Ministry of Energy and Mines in January 1996, through limited liability joint ventures with foreign investors.

F-21

These areas were assigned under a competitive bidding process to participate in profit sharing agreements with CVP. These agreements establish that the investors are to perform exploration activities and, in the event of discovery and commercial production, the Venezuelan state will receive a participation in the net income before income tax generated by each development area.

The agreements provide for the creation of a Control Committee, as the ultimate authority for approval and control, which shall make fundamental decisions in the interest of Venezuela.

CVP owns shares representing 35% participation in the joint ventures formed for each area, as follows:

Areas	CVP partners	Mixed companies
Delta Centro	Burlington-Union Pacific-Benton(1)	Administradora General Delta Centro, S.A.
Golfo de Paria Este	Ineparia	Administradora del Golfo de Paria Este, S.A.
Golfo de Paria Oeste	ConocoPhillips—AGIP-OPIC	Compañía Agua Plana, S.A.
Guanare	ELF—Conoco(1)	Administradora Petrolera Guanare, S.A.
Guarapiche	Repsol—YPF Venezuela, S.A.(1)	Administradora General Guarapiche, S.A.
La Ceiba	Exxon Mobil—Veba-Nippon	Administradora Petrolera La Ceiba, C.A.
Punta Pescador	Amoco—Total Fina—Veba(2)	Administradora General Punta Pescador, S.A.
San Carlos	Petrobras Energía de Venezuela, S.A.(3)	Compañía Anónima Mixta San Carlos, S.A.

(1): Until 2001
(2): Until 2000
(3): Changed to a gas license in 2002

The object of the mixed companies is to manage, coordinate and supervise the activities of the agreement performed by the operator of the area. The mixed companies have not carried out significant commercial operations; the activities developed until 2002 comprised principally completing the minimum exploratory program and continuing exploration efforts, as well as approving and continuing with the plans for evaluation and delineation. The investors are fully responsible for the activities related to the minimum work schedule.

To guarantee compliance with the minimum work schedule under the agreements in July 1996, CVP received letters of credit or guarantees from the investors' parent companies. Pursuant to these agreements, the guarantees can be reduced every six months, at the request of the investors, based on the progress of the work schedule. At December 31, 2002, the amount of the guarantees was approximately $29 million. At December 31, 2002, the minimum work schedules were completed.

Under the agreements, in the event that a discovery is declared commercially viable and the respective development plan is approved by the Control Committee, CVP will notify the investors of its participation in such development, which shall be no less than 1% and no greater than 35%. Taking into consideration the exploration, development and production phases, in general, the agreements will have a maximum duration of thirty-nine years.

F-22

In April 2003, the Control Committee declared commercially viable a discovery in the Golfo de Paria Oeste Project, denominated Corocoro. In May 2003, the board of directors of PDVSA authorized CVP to participate in the development plan of this discovery. The participants in the consortium for Corocoro's development plan are: CVP (35.0%), ConocoPhillips (32.5%), AGIP (26.0%) and OPIC (6.5%). The plan contemplates total investment of $557 million for the period 2003-2005, and average production of 60 thousand barrels per day (BPD) of crude oil 24^o API, similar to Tía Juana crude oil.

During 2003, a major gas field was discovered in the San Carlos area, and exploration commenced the same year.

In 2001, the investors Burlington-Union Pacific-Benton (Delta Centro area), ELF-Conoco (Guanare area) and Repsol-YPF Venezuela, S.A. (Guarapiche area), with prior approval of the Control Committee and PDVSA, decided to terminate in advance the association agreements with CVP; therefore, pursuant to the agreements, the investors paid CVP $26 million, $15 million and $32 million, respectively. In 2000, the investors, Amoco-Total Fina-Veba (Punta Pescador area) decided to terminate in advance the association agreements and paid CVP $15 million. The mixed companies incorporated for the aforementioned agreements are currently in the process of liquidation, which will not have a significant impact on the financial position and consolidated results of PDVSA.

(c): Operating Agreements

During 1992 and 1993, PDVSA signed the first and second rounds of operating agreements with specialized international companies. The purpose of these agreements is the reactivation and operation of fifteen oil fields which in general cover a term of twenty years.

In June 1997, PDVSA held a third bidding round and awarded an additional eighteen fields to be operated under operating agreements with specialized national and international companies. These fields are located in the Venezuelan States of Anzoátegui, Falcón, Monagas and Zulia. Field operations are subject to the approval of development programs which include the execution of exploration activities at the operator's risk, and in areas where reserves are discovered, the agreement provides for the signing of new agreements for further development.

As established in the operating agreements, the investors will make capital investments in the assets necessary to increase production in the fields received, possibly recovering their investments by collecting operating fees and stipends, which are determined based on the amount of crude oil delivered to PDVSA during the term of the agreement. PDVSA has no liability to pay for the remaining value of the assets existing in the fields.

The operating fees, capital fees and other, and stipends included in operating expenses in the consolidated statements of income are presented below (in millions of dollars):

	Years ended December 31
	2002	2001	2000
Operating fees	852	766	755
Capital fees and other	629	550	686
Stipends	620	794	716

	2,101	2,110	2,157

F-23

(d): Other Development Activities

The Plataforma Deltana gas project includes the participation of third parties to complete exploration and future development of the area. PDVSA completed the initial phase of the project, including seismic studies and drilling of four exploratory wells, by December 31, 2002, and total investment amounted to $180 million. During 2002, the first phase of selecting partners was completed. Licenses for exploration and development for two of the five blocks comprising the project were granted by the Ministry of Energy and Mines to two multinational oil and gas companies in February 2003. These companies are committed to a minimum exploratory program, with an estimated investment of $150 million, and to subsequent investments for development if commerciality is confirmed. PDVSA's participation in the partnership, which could range from 1% to 35%, will be determined upon declaration of commerciality of each block. The selection of partners for two other blocks, from 13 participating multinational companies, will be announced by the end of November 2003.

(11) Taxes

A summary of the taxes, which affect the consolidated operations of PDVSA, follows (in millions of dollars):

	Years ended December 31
	2002	2001	2000
Income taxes	149	3,766	5,748
Production and other taxes	5,748	3,760	4,986

	5,897	7,526	10,734

(a): Income before Income Taxes

Income before income taxes and minority interests for each year consisted of the following (in millions of dollars):

	Years ended December 31
	2002	2001	2000
In Venezuela	2,283	6,730	12,408
Foreign	461	1,034	571

	2,744	7,764	12,979

F-24

The income tax expense is summarized as follows (in millions of dollars):

			Years ended December 31
			2002		2001	2000
Current income tax expense:
	In Venezuela		663		3,033	5,780
	Foreign		38		130	123

			701		3,163	5,903

Deferred income tax (benefit) expense:
	In Venezuela		(613	)	454	(249	)
	Foreign		61		149	94

			(552	)	603	(155	)

		Income tax expense	149		3,766	5,748

The tax effects of significant items comprising PDVSA's net deferred tax assets (liabilities) are as follows (in millions of dollars):

			December 31
			2002		2001
Deferred tax assets:
	Accruals for employee benefits		999		1,005
	Property, plant and equipment		391		291
	Production tax payable		141		130
	Inventories		101		123
	Investment tax credits and tax loss carryforwards		1,890		1,098
	Other		94		153

			3,616		2,800
	Less valuation allowance		1,961		1,036

			1,655		1,764

Deferred tax liabilities:
	Property, plant and equipment		836		869
	Operating agreements, net		104		397
	Capitalized interest		144		189
	Investments in nonconsolidated investees		238		221
	Inventories		82		94
	Deferred charges for plant turnaround costs		82		84
	Other		185		101

			1,671		1,955

		Net deferred tax liabilities	(16	)	(191	)

The movement on net deferred tax assets (liabilities) for the year ended December 31, 2002 includes the tax effects of the reversal of the minimum pension liability in Venezuela from other comprehensive income during 2002, amounting to $377 million.

F-25

The total deferred tax assets and liabilities were reclassified so as to present the net current and long-term position indicated as follows (in millions of dollars):

	December 31
	2002		2001
Current assets	476		342
Long-term assets	454		301
Long-term liabilities	(946	)	(834	)

	(16	)	(191	)

In assessing the realization of deferred tax assets, management considers whether it is more likely than not that some portion of deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. Management considers the scheduled reversal of deferred tax liabilities, projected future taxable income, and tax planning in making these assessments. During 2002 and 2001, the valuation allowance increased by $925 million and by $186 million, respectively.

The difference between the statutory income tax rate and the effective consolidated income tax rate for each year is analyzed as follows:

			Years ended December 31
			2002		2001		2000
			%		%		%
In Venezuela:
	Statutory income tax rate for the petroleum sector		50.0		67.7		67.7
	Inflation adjustment for tax purposes and effects of remeasurement to dollars		(79.8	)	(8.4	)	(10.5	)
	Valuation allowance		45.8		—		—
	Legal contribution received from subsidiaries		—		(6.1	)	(5.3	)
	Other differences, net		(16.0	)	(1.4	)	(7.3	)

		Effective income tax rate in Venezuela	—		51.8		44.6
Foreign:
	Effects of foreign taxation		5.4		(3.3	)	(0.3	)

		Consolidated effective income tax rate	5.4		48.5		44.3

PDVSA and some of its Venezuelan subsidiaries are entitled to tax credits for new investments up to 12% of the amounts invested. Such credits, however, may not exceed 2% of net taxable income, and the carryforward period may not exceed three years. The investment tax credit carryforwards aggregated approximately $660 million and tax loss carryforwards were $2,728 million, which expire as follows (in millions of dollars):

	December 31
	2003	2004	2005
Tax credits	210	231	219
Tax losses	967	103	1,658

F-26

The Venezuelan Income Tax Law introduced an initial adjustment for the effects of inflation for the calculation of income tax. The inflation adjusted value of fixed assets is depreciated or depleted over their remaining useful lives for tax purposes. The Tax Law also provides for the calculation of a regular inflation adjustment to be made every year, and included in the reconciliation to taxable income as a taxable or deductible item.

An amendment of the Venezuelan Income Tax Law was approved in October 1999. This amendment established the introduction of transfer pricing rules that came into effect in January 2000. Pursuant to the transfer pricing rules, taxpayers subject to income tax who carry out import, export and loan operations with related parties domiciled abroad must determine their income, costs and deductions applying the methodology in this law. PDVSA has obtained studies supporting its transfer pricing methodology. The resulting effects are included as a taxable item in the determination of income tax.

Beginning January 2001, the amendment also included a universal tax system for Venezuela and taxes on dividends, as well as the introduction of rules for international fiscal transparency.

In January 2002, the Partial Reform of the Income Tax Law published in November 2001, came into effect. The most important aspects of this Reform are presented below:

•: The income tax rate applicable to companies engaged in the production of hydrocarbons and related activities was reduced from 67.7% to 50%.
•: The determination of the taxable base for the calculation of income tax results from the sum of territorial income and extraterritorial income. The Reform prohibits offsetting losses from an extraterritorial source against income from a territorial source.
•: The methods for determining transfer prices were modified. Furthermore, rules relating to prior transfer pricing agreements were introduced.
(b): Production Tax

Production tax is payable based on crude oil produced and natural gas processed in Venezuela. Commencing January 2002, the maximum rate of this tax was increased from 16²/3% to 30% and is calculated according to certain parameters, pursuant to agreements with the Venezuelan government. Production tax expense recorded by the Company for 2002, 2001 and 2000 amounted to $5,659 million, $3,733 million and $4,957 million, respectively, which is included in production and other taxes in the consolidated statements of income.

(c): Business Assets Tax

This tax is calculated as 1% of the average value of the inflation-adjusted assets at the beginning and end of the year. PDVSA and its Venezuelan subsidiaries calculate this tax together with income tax and pay the higher of the two. In 2002, 2001 and 2000, this tax resulted in an expense of $47 million, $27 million and $29 million, respectively, which is included in production and other taxes in the consolidated statements of income.

(d): Value Added Tax

The Value Added Tax (VAT) Law established the tax rate applicable to the taxable base as 15.5%. In August 2000, the rate was changed from 15.5% to 14.5%. Effective September 2002, the applicable rate is 16%.

According to the VAT Law, the sales of certain hydrocarbon derivative products are exempt and tax credits (derived from export sales) may be recovered from the Venezuelan tax authorities. The

F-27

amounts receivable do not generate interest. A summary of tax credits pending compensation or recovery follows (in millions of dollars):

	Years ended December 31
	2002		2001		2000
Tax credits receivable at beginning of year	2,150		1,475		921
Generated during the year	753		1,022		799
Exchange loss	(970	)	(138	)	(67	)
Recovered during the year	—		(209	)	(178	)

Tax credits receivable at end of year	1,933		2,150		1,475

(e): Sales and Excise Taxes

In Venezuela and the United States of America, sales of gasoline and other motor fuels are subject to sales and excise taxes. In 2002, 2001 and 2000, such taxes, paid to the corresponding governments, amounted to $3,623 million, $4,133 million and $3,969 million, respectively. These taxes are not included in sales.

(f): Surface Tax

In 2002, PDVSA incurred surface tax in Venezuela of $42 million, included under production and other taxes in the consolidated statements of income.

(12) Financial and Derivative Instruments

(a): Commodity Derivative Activity and Interest Rate Swap and Cap Agreements

PDVSA uses commodity and financial instrument derivatives to manage defined commodity price and interest rate risks arising out of the Company's core business activities, and does not use them for trading or speculative purposes. The Company's commodity derivatives are generally entered into through major brokerage houses and are traded on national exchanges and can be settled in cash or through delivery of the commodity.

PDVSA enters into petroleum futures contracts, options and other over-the-counter commodity derivatives principally to manage a portion of the risk associated with market price movements of crude oil and refined products. The Company's derivative commodity activity is undertaken within limits established by management and contract duration is generally less than thirty days.

F-28

Furthermore, PDVSA enters into various interest rate swap agreements to manage the risk related to interest rate fluctuations on its debt.

(b): Concentration of Credit Risk

The Company's financial instruments that are exposed to concentrations of credit risk consist primarily of its cash equivalents, derivative financial instruments and notes and accounts receivable. The Company's cash equivalents are in high-quality securities placed with a wide array of institutions. Similar standards of creditworthiness and diversity are applied to the Company's counterparties to derivative instruments. Notes and accounts receivable balances are dispersed among a broad customer base worldwide and the Company routinely assesses the financial strength of its customers. The Company's credit risk is dependent on numerous additional factors including the price of crude oil and refined products, as well as the demand for and the production of crude oil and refined products.

(c): Fair Value of Financial Instruments

The following estimated fair value amounts have been determined by the Company using available market information and appropriate valuation methodologies. However, considerable judgment is required for interpreting market data to develop the estimates of fair value. Accordingly, the estimates presented herein are not necessarily indicative of the amounts that the Company could realize in a current market exchange. The use of different market assumptions and/or estimation methodologies could have a material effect on the estimated fair value amounts (in millions of dollars):

		December 31
		2002		2001
		Carrying amount	Fair value	Carrying amount	Fair value
Assets:
	Cash and cash equivalents	1,703	1,703	925	925
	Restricted cash	2,805	2,805	4,277	4,277
	Notes and accounts receivable	3,515	3,515	3,280	3,280
	Recoverable value added Tax	1,933	1,693	2,150	1,774
	Long-term accounts receivable	669	583	858	758
	Derivative assets (included in other assets)	3	3	16	16

Liabilities:
	Accounts payable to suppliers	2,850	2,850	3,043	3,043
	Current portion of long-term debt	1,817	1,770	1,000	1,000
	Long-term debt, net of current portion	6,426	5,851	7,427	7,376
	Derivative liabilities (included in other liabilities)	20	20	65	65

The carrying amounts of cash and cash equivalents, notes and accounts receivable and accounts payable to suppliers, approximate their fair value due to the short maturity of these instruments. Restricted cash bears interest at variable market rates, and the carrying amount approximates fair value.

The fair value of recoverable value added tax has been determined by discounting the non-interest bearing carrying value, based on future estimated recoveries, using interest rates applicable in the money market.

The fair value of long-term debt, including the current portion, at December 31, 2002 and 2001, is based on interest rates that are currently available to PDVSA for issuance of debt with similar terms and remaining maturities and broker quotes which contemplate credit risk.

F-29

The fair value of derivative instruments is based on the estimated amount that the Company would receive or pay to terminate the agreements at the reporting dates, considering current commodity prices and interest rates and the current creditworthiness of the counterparties.

(13) Credit Facilities and Long-Term Debt

PDVSA and its subsidiaries have the following unused credit facilities available at December 31, 2002 (in millions of dollars):

Shelf registration – unsecured		400
Loan credit agreements – unsecured		356
Loan credit agreements – secured		375
Lines of credits – secured		45

		1,176

F-30

Long-term debt at December 31, 2002 and 2001 consists of the following (in millions of dollars):

		December 31
		2002		2001
PDV America/CITGO:
	7.25% to 7.87% unsecured senior notes due 2003	499		499
	2.4% to 2.5% unsecured revolving bank loans due 2003 – 2005	279		392
	7.875% unsecured senior notes under $600 million shelf registration due 2006	200		200
	9.3% unsecured private placement senior notes due 2003 to 2006	46		57
	7.17% to 8.94% unsecured master shelf agreement senior notes due 2003 to 2009	235		260
	Variable and fixed rate 2.1% to 8.0% guaranteed tax-exempt bonds due 2004 to 2032	426		357
	Variable rate guaranteed taxable bonds due 2026 to 2028	115		146

		1,800		1,911

PDVSA Finance—unsecured notes:
	6.45% due 2002 through 2004	250		400
	8.75% due 2000 through 2004	127		226
	6.25% due 2002 through 2006 (in euros)	171		178
	6.65% due 2004 through 2006	300		300
	9.37% due 2004 through 2007	250		250
	6.80% due 2007 through 2008	300		300
	9.75% due 2008 through 2010	250		250
	8.50% due 2010 through 2012	500		500
	7.40% due 2014 through 2016	400		400
	9.95% due 2018 through 2020	100		100
	7.50% due 2027 through 2028	400		400
	Treasury notes	(4	)	(7	)

		3,044		3,297

PDVSA VI:
8.46% guaranteed notes due 2003 to 2009		395		442

F-31

			December 31
			2002	2001
PDVSA Petróleo:			5,239	5,650
	Variable and fixed rate 4.1% to 5.0% loans guaranteed by governmental export agencies and financial institutions due 2004 to 2005		185	299
	7.33% to 8.03% guaranteed PDVSA Cerro Negro bonds due 2003 to 2028		288	300
	Variable rate guaranteed PDVSA Cerro Negro line of credit due 2003 to 2012		136	150
	Variable rate guaranteed PDVSA Sincor loan due 2003 to 2012		456	903
	Variable rate guaranteed Corpoguanipa lines of credit due 2008 and 2018		284	190

			1,349	1,842

Bariven, S.A. (Bariven):
	Variable and fixed rate 6.13% to 7.69% loans guaranteed by governmental export agencies and financial institutions due 2003 to 2008		348	365
	Commercial paper program		—	179

			348	544

PDV Marina, S.A. (PDV Marina):
	Variable rate guaranteed credit facility due 2003 to 2006		136	185

PDVSA Corporate:
	Variable rate guaranteed loan credit agreements due 2008 and 2012		725	83
	Variable rate guaranteed loan credit facility due 2003		370	—

			1,095	83

Other subsidiaries			76	123

			8,243	8,427
Less current portion of long-term debt			1,817	1,000

		Total long-term portion	6,426	7,427

Future maturities of the long-term portion at December 31, 2002 are as follows (in millions of dollars):

Years
2004				758
2005				947
2006				746
2007				566
Remaining years				3,409

				6,426

F-32

Covenants

Various of PDVSA's borrowing facilities contain covenants that restrict, among other things, the ability of the Company and its subsidiaries to incur additional debt, to pay dividends, place liens on property, and sell certain assets. The Company was in compliance with these covenants at December 31, 2002 and 2001.

PDVSA and PDVSA Finance have been in breach of certain of their covenants due to the late filings of their respective annual reports on Form 20-F for the year ended December 31, 2002 (and, in respect of PDVSA, its 2002 audited financial statements). Upon delivery of the foregoing documents to the trustee and to the creditors, as the case may be, such covenant breaches will be remedied. Consequently, the corresponding long-term portions of these debts have not been reclassified to current.

(14) Capital Stock and Reserves

At December 31, 2002 and 2001, PDVSA's capital stock is represented by 51,204 registered shares of Bs 25 million each, totaling $39,094 million. By law the shares may not be transferred or encumbered in any way.

Venezuelan companies are required to maintain a legal reserve by setting aside 5% of net income until the reserve reaches a minimum of 10% of the capital stock. The legal reserve at December 31, 2002, 2001 and 2000 amounted to $3,876 million, $3,866 million and $3,845 million, respectively. In accordance with Venezuelan law, the legal reserve cannot be used to distribute dividends. Other reserves include a reserve for the realization of deferred tax assets and a reserve for new investments.

Dividends to the shareholder are declared and paid in bolivars based on the statutory financial statements, which reflect retained earnings. In 2002, 2001 and 2000, dividends were declared for Bs 3,400,000 million, Bs 3,400,000 million and Bs 1,400,000 million, equivalent to $2,752 million, $4,774 million and $2,018 million, respectively.

(15) Employee Benefit Plans

PDVSA and its subsidiaries have the following employee benefit plans:

(a): Defined Contribution Savings Plans

PDVSA and its Venezuelan subsidiaries maintain savings funds for their employees and guarantee contributions to the members' accounts. At December 31, 2002, the guaranteed amount in the savings fund is $160 million. In addition, a U.S. subsidiary maintains three retirement and savings plans with defined contributions, covering all eligible employees; the employees who are members of these plans make voluntary contributions and in turn the subsidiary matches the contributions.

(b): Pension Plans and Other Postretirement Benefits

Pursuant to the collective labor contract, PDVSA and its Venezuelan subsidiaries have a retirement plan that covers all eligible employees. There is a single pension fund and an organization which administers the assets of the pension plan. The pension plan is terminally funded for most of the retirees' liabilities. A U.S. subsidiary also sponsors three qualified noncontributory defined benefit pension plans and three nonqualified defined benefit plans. The qualified pension plans are funded in accordance with current legislation, without exceeding tax deduction restrictions. The nonqualified plans are funded as necessary to pay retiree benefits. In addition to pension plans, PDVSA provides social benefits and medical and life insurance for retired personnel. These benefits are funded on a pay-as-you-go basis.

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PDVSA and some of its Venezuelan subsidiaries have a foreign currency denominated pension obligation measured under the U.S. dollar method and remeasured into the reporting currency (dollar) before calculating actuarial gains and losses. Foreign currency gains and losses from remeasurement of the bolivar pension obligation are treated as actuarial gains and losses and therefore are subject to deferral and amortization of the corridor.

Based on independent actuarial studies, PDVSA has the intention to record during 2003, a $267 million curtailment gain for the pension plan, and a $26 million curtailment loss for the postretirement benefit plan, related to the termination of employment for approximately 18,000 employees, effective January 1, 2003.

In October 2000, PDVSA approved a change in the pension plan for the Venezuelan workers, based on a defined benefits plan, administered as an individual capitalization plan. Under the revised plan monthly contributions of 3% and 9% of the base compensation are made by the worker and employer, respectively.

The following sets forth the changes in benefit obligations, plan assets for the pension plans, and the funded status of such plans and postretirement benefits for 2002 and 2001, and the funded status of such plans reconciled with amounts reported in the consolidated balance sheets (in millions of dollars):

				December 31
				Pension benefits				Other postretirement benefits
				2002		2001		2002		2001
Venezuela:
	Change in benefit obligation
		Benefit obligation, beginning of year		4,240		3,836		1,462		892
			Service cost	152		142		52		52
			Interest cost	414		386		143		135
			Participant contributions	12		16		—		—
			Plan amendments	180		81		6		465
			Actuarial gain	(2,091	)	(65	)	(494	)	(54	)
			Benefits paid	(173	)	(156	)	(73	)	(28	)

		Benefit obligation, end of year		2,734		4,240		1,096		1,462

	Change in plan assets
		Fair value of plan assets, beginning of year		1,199		1,206		—		—
			Actual return on plan assets	(592	)	(37	)	—		—
			Employer contributions	501		105		73		29
			Participant contributions	12		16		—		—
			Benefits paid	(66	)	(91	)	(73	)	(29	)

		Fair value of plan assets, end of year		1,054		1,199		—		—

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				December 31
				Pension benefits				Other postretirement benefits
				2002		2001		2002		2001
	Funded status			(1,680	)	(3,041	)	(1,096	)	(1,462	)
		Employer contributions		11		22		—		—
		Benefit payments made directly by employer		5		21		—		—
		Unrecognized net actuarial (gain) loss		(475	)	949		(147	)	520
		Unrecognized prior service cost		1,256		1,193		457		365
		Unrecognized transition obligation		2		4		—		—

			Net amount recognized	(881	)	(852	)	(786	)	(577	)

Amounts recognized in the Company's consolidated balance sheets consist of:
		Accrued benefit liability		(1,574	)	(2,847	)	(786	)	(577	)
		Employer contributions		10		22		—		—
		Benefit payments made directly by employer		5		21		—		—
		Intangible asset		678		1,199		—		—
		Accumulated other comprehensive income		—		753		—		—

		Net amount recognized		(881	)	(852	)	(786	)	(577	)

Foreign:
	Change in benefit obligation
		Benefit obligation, beginning of year		337		288		261		206
			Service cost	17		16		7		6
			Interest cost	24		22		19		16
			Actuarial loss	28		23		56		41
			Benefits paid	(12	)	(12	)	(8	)	(8	)

		Benefit obligation, end of year		394		337		335		261

Change in plan assets
	Fair value of plan assets, beginning of year			264		273		1		1
		Actual return on plan assets		(20	)	(10	)	—		—
		Employer contributions		9		13		8		8
		Benefits paid		(12	)	(12	)	(8	)	(8	)

	Fair value of plan assets, end of year			241		264		1		1

Funded status				(153	)	(73	)	(333	)	(260	)
	Unrecognized net actuarial loss (gain)			69		(2	)	75		31
	Unrecognized prior service cost			2		2		—		—

			Net amount recognized	(82	)	(73	)	(258	)	(229	)

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		December 31
		Pension benefits				Other postretirement benefits
		2002		2001		2002		2001
Amounts recognized in the Company's consolidated balance sheets consist of
	Accrued benefit liability	(91	)	(80	)	(258	)	(229	)
	Intangible asset	2		3		—		—
	Accumulated other comprehensive income	7		4		—		—

	Net amount recognized	(82	)	(73	)	(258	)	(229	)

Actuarial assumptions are presented below:

		December 31
		Pension benefits			Other postretirement benefits
		2002	2001	2000	2002	2001	2000
		%	%	%	%	%	%
Venezuela:
	Discount rate	10	10	10	10	10	10
	Rate of compensation increase	7	7	7	7	7	7
	Expected return on plan assets	10	10	10	—	—	—
Foreign:
	Discount rate	6.75	7.25	7.8	6.75	7.25	7.8
	Rate of compensation increase	5	5	5	—	—	—
	Expected return on plan assets	8.50	9	9	6	6	6

In Venezuela an annual increase of 1% in the inflation assumption for social benefits and medical and life insurance in future years would increase the accumulated postretirement benefit obligation at December 31, 2002 by $161 million and the net periodic cost for postretirement benefits by $25 million.

For foreign operations an annual increase of 1% in the inflation assumption for service and interest costs would increase the accumulated pension benefits at December 31, 2002 by $5 million and the postretirement benefit obligation by $53 million.

For the years ended at December 31, the net periodic benefit costs are as follows (in millions of dollars):

				December 31
				Pension benefits						Other postretirement Benefits
				2002		2001		2000		2002	2001	2000
Venezuela:
	Components of net periodic benefit cost
		Service cost		152		142		116		52	52	28
		Interest cost		414		386		307		143	135	80
		Expected return on plan assets		(120	)	(121	)	(95	)	—	—	—
		Amortization of prior service cost		118		118		62		68	68	17
		Amortization of net gain at date of adoption		2		2		2		—	—	—
		Recognized net actuarial loss		44		45		62		18	26	17

			Net periodic benefit cost	610		572		454		281	281	142

Foreign:
	Components of net periodic benefit cost
		Service cost		17		16		15		7	6	6
		Interest cost		24		22		20		19	16	14
		Expected return on plan assets		(24	)	(24	)	(24	)	—	—	—
		Recognized net actuarial loss (gain)		1		(4	)	(5	)	11	—	(17	)

			Net periodic benefit cost	18		10		6		37	22	3

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(16) Accrued and Other Liabilities

Accrued and other liabilities are summarized as follows (in millions of dollars):

	December 31
	2002	2001
Withholding taxes	109	143
Valued added tax (VAT)	230	224
Production tax payable	288	264
Capital leases	30	62
Long-term accounts payable	334	304
Provision for lawsuits and claims (see note 19)	46	30
Employees' accounts payable	421	225
Environmental reserve	58	36
Interest payable	117	99
Dividends payable	109	198
Accrued expenses	204	482
Other	350	680

	2,296	2,747
Less current portion of accrued and other liabilities	1,771	1,947

Long-term portion	525	800

(17) Related Party Transactions

A summary of transactions with nonconsolidated investees and other entities owned by the Bolivarian Republic of Venezuela follows (expressed in millions of dollars):

		Years ended December 31
		2002	2001	2000
Transactions during the year:
	Sales	6,602	4,167	4,424
	Costs and expenses	2,641	4,991	7,043

Balances at year-end:
	Deposits with the BCV-contributions to FIEM (see note 4)	2,382	4,072
	Funds for extra-heavy crude oil project	239	87
	Accounts receivable (see note 5)	328	440
	Long-term accounts receivable, included in other assets	594	668
	Investments in nonconsolidated investees (see note 7)	2,859	2,819
	Accounts payable to suppliers	684	152

Accounts receivable at December 31, 2002 and 2001 include balances receivable from C.A. Administración y Fomento Eléctrico (CADAFE) of $132 million and $118 million, respectively. Furthermore long-term accounts receivable include a balance receivable from PETROZUATA of $490 million and $544 million, respectively, representing cash call loans. These accounts do not generate interest.

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During the years ended December 31, 2002, 2001 and 2000, PDVSA purchased products from PETROZUATA amounting to $261 million, $301 million and $425 million, respectively. Additionally, PETROZUATA reimbursed PDVSA for project and operating expenditures amounting to $11 million, $68 million and $38 million in 2002, 2001 and 2000, respectively (see notes 7 and 10).

In 2002, 2001 and 2000, the affiliated company, INTESA Informática Telecomunicaciones, S.A. (INTESA) invoiced PDVSA in respect of information technology services of $253 million, $309 million and $281 million, respectively, which include costs and expenses. On June 28, 2002, PDVSA gave notice of termination of the Services (IFT) agreement to INTESA (see note 19).

PDVSA Petróleo has various agreements for supplies with affiliated companies, which are summarized as follows (thousands of barrels per day):

Affiliate	Delivery obligation	Year of termination
Ruhr Oel	220	After two years notice
Nynäs Petroleum	34	Not defined
LYONDELL-CITGO (see note 19)	230	2017
Chalmette Refining	90	Strategic association period
Hovensa	155	2008
CITGO	297	Between 2006 and 2013

	1,026

CITGO acquires refined products from various affiliated companies, including LYONDELL-CITGO, HOVENSA and Chalmette under long-term agreements. During the years ended December 31, 2002, 2001 and 2000, these purchases amounted to $3,500 million, $3,400 million and $5,300 million, respectively. At December 31, 2002 and 2001, accounts payable in connection with these operations include $110 million and $73 million, respectively.

During the years ended December 31, 2002, 2001 and 2000, CITGO sold to affiliated companies refined products and other refinery supplies of $277 million, $248 million and $205 million, respectively. The accounts receivable in connection with these operations at December 31, 2002 and 2001 amount to $94 million and $64 million, respectively.

(18) Operating Segments and Geographic Data

Intersegment sales, which primarily consist of sales of crude oil, are generally made at approximate market prices. PDVSA evaluates the performance of its segments and allocates resources to them based on net revenues, operating income (calculated as income before financing expenses and income taxes), capital expenditures and property, plant and equipment. The "Other" line item includes corporate related items and results of non-significant operations in Venezuela, Europe and the Caribbean.

Refining, supply and marketing activities in Venezuela include the administration of refineries, marketing and transportation of crude oil, natural gas and refined petroleum products under the brand name PDV. Petrochemical activities in Venezuela cover the production and marketing of various compound mixes, olefins, plastic resins and chemical additives. Refining, supply and marketing activities in the United States of America cover the administration of refineries, the marketing of gasoline and refined petroleum products in the eastern and midwestern regions under the brand name CITGO (see note 1(n)).

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Summarized financial information for Company's reportable segments is presented in the following table (in millions of dollars):

				Years ended December 31
				2002		2001		2000
Revenues:
	Net sales of crude oil and products:
		Segments in Venezuela:
			Upstream operations	18,931		20,480		26,785
			Downstream operations	23,342		25,903		31,547
			Petrochemical operations	919		1,070		990
		Segments in the United States of America:
			Downstream operations	19,358		19,601		22,157
		Other		645		851		609

				63,195		67,905		82,088
	Eliminations(1)			(20,615	)	(21,655	)	(28,408	)

				42,580		46,250		53,680

Operating income:(2)
	Segments in Venezuela:
		Upstream operations		4,032		7,653		12,673
		Downstream operations		(583	)	(1,348	)	(1,327	)
		Petrochemical operations		265		(104	)	11
	Segments in the United States of America:
		Downstream operations		314		658		612
	Other			464		2,534		2,589

				4,492		9,393		14,558
Eliminations(1)				(985	)	(1,120	)	(907	)

				3,507		8,273		13,651

(1): Represents the elimination of intersegment sales.

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(2): Before financing expenses, income tax expense and minority interests.

			Years ended December 31
			2002		2001	2000
Capital expenditures, net:
	Segments in Venezuela:
		Upstream operations	1,335		764	2,908
		Downstream operations	976		2,517	9
		Petrochemical operations	(163	)	110	47
	Segments in the United States of America:
		Downstream operations	757		292	166
	Other		57		98	55

			2,962		3,781	3,185

Property, plant and equipment, net:
	Segments in Venezuela:
		Upstream operations	20,415		21,673	22,880
		Downstream operations	9,024		8,899	7,165
		Petrochemical operations	1,925		2,241	2,245

	Segments in the United States of America:
		Downstream operations	3,750		3,293	3,287
	Other		771		782	753

			35,885		36,888	36,330

Net sales and long-lived assets information by geographic area are summarized below (in millions of dollars):

		Venezuela	United States of America	Other Countries(3)	Total
December 31, 2002
	Net sales(1)	22,309	19,358	645	42,312
	Long-lived assets(2)	37,888	5,086	1,325	44,299

December 31, 2001
	Net sales(1)	26,184	19,602	—	45,786
	Long-lived assets(2)	40,402	4,432	2,351	47,185

December 31, 2000
	Net sales(1)	31,077	22,157	—	53,234
	Long-lived assets(2)	40,472	5,150	1,928	47,550

(1): Based on the country in which the sales originate.
(2): Based on the location of the asset.
(3): Primarily investment in nonconsolidated investees.

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(19) Commitments and Contingencies

Litigation and Other Claims

In August 1999, the U.S. Department of Commerce rejected a petition filed by a group of independent oil producers to apply antidumping measures and countervailing duties against imports of crude oil from Venezuela and some other countries. The petitioners appealed this decision before the U.S. Court of International Trade based in New York. On September 19, 2000, the Court of International Trade remanded the case to the Department of Commerce with instructions to reconsider its August 1999 decision. The Department of Commerce was required to make a revised decision as to whether or not to initiate an investigation. The Department of Commerce appealed to the U.S. Court of Appeals for the Federal Circuit, which dismissed the appeal as premature on July 31, 2001. The Department of Commerce issued its revised decision, which again rejected the petition, in August 2001. The revised decision was affirmed by the Court of International Trade on December 17, 2002. In February 2003, the independent oil producers appealed the Court of International Trade's decision to the Federal Circuit, where the matter is still pending.

In February 2002, LYONDELL-CITGO commenced an action against PDVSA and PDVSA Petróleo, S.A. in the United States District Court for the Southern District of New York. LYONDELL-CITGO alleges that PDVSA and PDVSA Petróleo, S.A. wrongfully declared force majeure events and reduced shipments of extra-heavy crude oil to LYONDELL-CITGO. LYONDELL-CITGO is seeking damages and specific performance for alleged breaches of the long-term crude oil supply agreement between LYONDELL-CITGO and Lagoven (subsequently merged into PDVSA Petróleo, S.A.) and the supplemental supply agreement, between LYONDELL-CITGO and PDVSA, both agreements dated May 5, 1993 and expiring in 2017. On May 31, 2002, PDVSA and PDVSA Petróleo, S.A. filed a motion to dismiss the case, which was briefed. On May 29, 2003, the case was reassigned to another judge. On August 6, 2003, the judge issued a ruling on the motion to dismiss. The judge dismissed one of the ten counts in LYONDELL-CITGO's complaint, allowing the remaining counts to proceed through early stages of litigation without precluding PDVSA and PDVSA Petróleo, S.A. from advancing the same defenses again at a later stage of the case. The defendant's answer to LYONDELL-CITGO's complaint was filed with the Court on September 29, 2003. The parties were ordered to appear for a pre-trial conference on October 30, 2003. Management of the companies intend to vigorously contest the allegations. Management and their legal counsel believe that they have substantial defenses.

An action was filed against PDVSA and its subsidiaries PDVSA Petróleo, S.A., PDVSA Finance Ltd. and Citgo Petroleum Corporation on April 11, 2003, in the federal district court of Denver, Colorado. The plaintiff is a U.S. oil and gas exploration and production company that has allegedly entered into an exclusive offshore license agreement with the government of Grenada to explore, develop, produce and market oil and/or natural gas in 4.75 million offshore acres between Grenada and Venezuela. The plaintiff alleges that PDVSA has interrupted and otherwise interfered with its ability to develop and market Grenada's oil and natural gas resources in violation of the U.S. antitrust laws. The plaintiff seeks damages in an amount to be established at trial that it believes should exceed $100 million. The companies deny the allegations and complaint and intend to contest the case vigorously if it proceeds, and the management and their legal counsel believe that the companies have substantial defenses.

During December 2002 and January 2003, there was a work stoppage by a significant number of workers and employees of PDVSA and its subsidiaries in Venezuela. This resulted in the termination of employment effective January 1, 2003 for approximately 18,000 employees (of its then total labor force of 45,000). Based on the opinion of PDVSA's management and legal counsel the terminations were in accordance with the Venezuelan labor law. All significant outstanding employee benefits in accordance with PDVSA's employment conditions and the Venezuelan labor law were accrued as of December 31, 2002. The abovementioned former PDVSA employees have filed a petition for reinstatement with the labor courts. Management, based on their legal counsel's opinion, believes that the resolution of this matter will not have a material effect to the Company's financial position or results of operations.

PDVSA previously outsourced its information technology services to INTESA, based on a joint venture and a services agreement. INTESA is a Venezuelan company owned 60% by SAIC Bermuda Ltd. and 40% by PDV-IFT, a subsidiary of PDVSA. PDVSA gave notice of termination of the services agreement, in accordance with the contract, on June 28, 2002. PDVSA has proposed a plan to

F-41

jointly liquidate INTESA and to honor all valid obligations with the employees and providers. PDVSA has been assigned and has paid a significant portion of INTESA's obligations with providers, which will be offset against the debt that PDVSA has with INTESA. Management and their legal counsel believe that the liquidation of INTESA will not have a material effect on the Company's financial position or results of operations.

Additionally, a number of lawsuits and claims have arisen and are being defended and handled in the normal course of business, the possible final effect of which cannot be quantified. Based on analysis of the available information, a provision as of December 31, 2002 and 2001, amounting to $46 million and $30 million, respectively, and is included in accrued and other liabilities (see note 16). If known lawsuits and claims were to be determined in a manner adverse to the Company, and in amounts greater than the Company's accruals, then such determinations could have a material adverse effect on the Company's results of operations in a given reporting period. Although it is not possible to predict the outcome of these matters, management, based in part on advice of its legal counsel, does not believe that it is probable that losses associated with the proceedings discussed above, that exceed amounts already recognized, will be incurred in amounts that would be material to the Company's financial position or results of operations.

Environmental Compliance and Remediation

The majority of PDVSA's subsidiaries, both in Venezuela and abroad, are subject to various environmental laws and regulations under which they may be required to make significant expenditures to modify their facilities and to prevent or remedy the environmental effects of waste disposal and spills of pollutants. In the United States and Europe, the operations are subject to various federal, state and local environmental laws and regulations, which may require them to take action to remedy or alleviate the effects on the environment of earlier plant decommissioning or leakage of pollutants.

PDVSA is taking steps to prevent risks to the environment, people's health, and the integrity of its installations. In 2002, PDVSA developed an Integral Risk Management System (SIR-PDVSA®) that is being implemented throughout the Company. This management system is based on international practices and standards, such as ISO 14001 for Environmental Management, ISO 18000 & British Standard BS8800 for health and the Occupational Safety and Health Administration (OSHA)'s and American Petroleum Institute (API)'s 750 for process safety. In addition, PDVSA has an investment plan to comply with the applicable environmental regulations in Venezuela. This investment plan contemplates approximately $2,227 million in capital expenditure from 2003 through 2008, including the following: $1,180 million for product quality; $690 million for risk control at operating sites; $312 million for environmental compliance projects; and $45 million for other environmental-related investments. CITGO estimates expenditures of approximately $1,300 million for environmental and regulatory capital projects from 2003 through 2007. During 2002, PDVSA spent approximately $9 million in Venezuela and CITGO spent approximately $148 million for environmental and regulatory capital improvements in its operations.

During the work stoppage in December 2002 and January 2003, there were oil spills which affected the environment in Venezuela. Two technical reports were prepared, one by INTEVEP (PDVSA's Research and Development Center) and ICLAM (Maracaibo Lake Conservation Institute) and the other by the Simón Bolívar University and IVIC (Venezuelan Scientific Investigations Institute). Both reports conclude that the impact of the oil spills are minor and are located principally in the Maracaibo Lake area. These conclusions were confirmed by the Ministry of Environment. The remediation costs for these minor oil spills are covered by the operating budget of the Western Operations Division of PDVSA.

CITGO has received various notices of violation from the Environmental Protection Agency (EPA) and other regulatory agencies, which include notices under the federal Clean Air Act, and could be designated as Potentially Responsible Parties (PRPs) jointly with other industrial companies with respect to sites under the Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA).

These notices are being reviewed and, in some cases, remedial action is being taken or CITGO is engaged in settlement negotiations.

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Conditions that require additional expenditures may exist at various sites including, but not limited to, operating complexes, closed refineries, service stations and crude oil and petroleum storage terminals. Based on currently available information we cannot determine the amounts of any such expenditures. Management believes that these matters, in the normal course of operations, will not have a material effect on the consolidated financial position, liquidity or operations of PDVSA.

Guarantees

As of December 31, 2002, some of PDVSA's subsidiaries have construction completion guarantees related to debt and financing arrangements secured by joint venture projects. The subsidiaries, projects, guarantee obligations and year of termination are presented below (in millions of dollars):

Subsidiary/Project	Guarantee obligations	Year of termination
PDV Holding Inc./Merey Sweeny, L.P. (MSLP)	175	2003
PDVSA Petróleo/Hamaca Project	284	2005
PDVSA Petróleo/Sincor Project	456	2003

On September 30, 2003, a certificate of completion was received for the SINCOR project, which was sent to the trustee to reduce the $456 million debt guarantee to $50 million.

PDVSA and its affiliates have guaranteed the debt of others in a variety of circumstances including letters of credit, bank debt and customer debt amounting to $163 million. No liabilities have been recorded for these amounts.

Others Commitments

Minority interests presented in the consolidated balance sheet include the preferred stock of a Venezuelan subsidiary with the right to annual cumulative dividends. The subsidiary is committed to redeem these preferred shares in equal amounts of 12.5% from 1997 to 2004. As of December 31, 2002, preferred shares for approximately $365 million have been redeemed and $52 million are pending redemption.

(20): Supplementary Information on Oil and Gas Exploration and Production Activities (Unaudited)

The following tables provide supplementary information on the oil and gas exploration, development and production activities in compliance with SFAS No. 69 "Disclosures about Oil and Gas Producing Activities", published by the U.S. Financial Accounting Standards Board. All exploration and production activities are located in Venezuela principally represented by PDVSA Petróleo and PDVSA Gas.

Table I—Crude oil and natural gas reserves

All the crude oil and natural gas reserves located in Venezuela are owned by the Bolivarian Republic of Venezuela. Crude oil and natural gas reserves are estimated by PDVSA and reviewed by the Ministry of Energy and Mines, using reserve criteria which are consistent with those prescribed by the American Petroleum Institute (API) and the U.S. Securities and Exchange Commission (SEC).

Proved reserves are the quantities of oil and gas which, with reasonable certainty, are recoverable in future years from known deposits under existing economic and operating conditions. Due to the inherent uncertainties and limited nature of the data relating to deposits, estimates of underground reserves are subject to change over time, as additional information becomes available. Proved reserves do not include additional quantities which may result from the extension of currently explored areas, or from the application of secondary recovery processes not yet tested and determined to be economically feasible.

Proved developed reserves are the quantities to be recovered from existing wells with existing equipment and operating methods. Proved undeveloped reserves are those volumes which are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

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Proved crude oil reserves have been separated between conventional crude oils, consisting of light, medium and heavy grade crude oils, and extra-heavy crude oil.

A summary of the annual changes in the proved reserves of crude oil and natural gas follows:

(a): Conventional and extra-heavy crude oil reserves (in millions of barrels):

		2002		2001		2000
Proved developed and undeveloped reserves of light, medium and heavy crude oil at January 1		42,225		41,998		41,162
	Revisions	238		784		1,652
	Extensions and new discoveries	238		538		286
	Production	(925	)	(1,095	)	(1,103	)

Proved developed and undeveloped reserves of light, medium and heavy crude at December 31		41,776		42,225		41,997
Proved developed and undeveloped reserves of extra heavy crude oil at December 31		35,381		35,558		35,688

	Total proved developed and undeveloped reserves at December 31	77,157		77,783		77,685

	Total proved developed reserves, submitted to production, including extra-heavy crude oil at December 31 (included above)	15,699		17,372		17,373

At December 31 2002, 2001 and 2000, proved reserves of crude oil under operating agreements amounted to 5,501 million barrels, 5,600 million barrels and 5,479 million barrels, respectively (see note 10 (c)). During 2002, 2001 and 2000, the daily production of crude oil in the areas under operating agreements was approximately 481,000 barrels, 502,000 barrels and 466,000 barrels, respectively.

Venezuela has significant reserves of extra-heavy crude (less than 8 API degrees), which are being developed in conjunction with the production of Orimulsión® by the subsidiary BITOR, through operating agreements which apply new technologies for refining and improvement of the crude oil aimed at the economic viability of production. PDVSA used 25 million, 27 million and 26 million barrels of extra-heavy crude oil for the production of Orimulsión® during the years 2002, 2001 and 2000, respectively. Furthermore, PDVSA is currently developing Venezuela's significant extra-heavy crude oil reserves with several foreign companies through joint ventures (see note 10 (a)).

At December 31, 2002, 2001 and 2000, the proved developed and undeveloped extra-heavy crude oil reserves related to these projects and total proved developed and undeveloped extra-heavy crude oil reserves at those dates, reflecting the full amount of the reserves, are summarized below (in millions of barrels):

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	2002				2001				2000
	Projects		Total including projects		Projects		Total including projects		Projects (2)		Total including projects
Proved developed and undeveloped reserves of extra-heavy crude oil at January 1	10,768		35,558		9,776		35,688		5,652		35,689
Revisions(1)	—		—		1,079		—		4,181		102
Production	(129	)	(177	)	(87	)	(130	)	(57	)	(103	)

Proved developed and undeveloped reserves of extra-heavy crude oil at December 31	10,639		35,381		10,768		35,558		9,776		35,688

Proved developed extra-heavy crude oil reserves at December 31	1,273		2,154		1,170		1,963		646		1,375

Net proved extra-heavy crude oil reserves in unincorporated joint ventures at December 31	8,224				8,121				7,089
Net proved extra-heavy crude oil reserves in equity affiliate at December 31	2,415				2,647				2,687

	10,639				10,768				9,776

(1)

Includes transfers from unassigned areas.

(2)

In 2000, excludes the Hamaca joint venture which was in its initial development stage.

(b): Natural gas reserves:

		2002		2001		2000
		Billions of cubic feet (BCF)
Proved developed and undeveloped reserves of natural gas at January 1		135,819		135,080		134,174
Revisions		468		997		1,957
Extensions and new discoveries		—		1,209		446
Production		(1,632	)	(1,467	)	(1,497	)

Proved developed and undeveloped reserves of natural gas at December 31		134,655		135,819		135,080
Proved reserves related to extra-heavy crude reserves at December 31		12,454		12,476		12,505

	Total proved developed and undeveloped reserves at December 31	147,109		148,295		147,585

	Total proved developed reserves, submitted to production, including quantities associated with extra-heavy crude oil in production at December 31 (included above)	102,191		103,807		103,310

Proved natural gas reserves include the portion of liquefiable natural hydrocarbons recoverable in PDVSA's processing plants. In 2002, 2001 and 2000, natural gas liquids recovered amounted to some 63 million barrels, 63 million barrels and 63 million barrels, respectively.

Production of natural gas is shown on the basis of actual volumes before the extraction of liquefiable hydrocarbons. During 2002, 2001 and 2000, natural gas utilized in reinjection operations amounted to 638 BCF, 695 BCF and 720 BCF, respectively.

Table II—Costs Incurred in Exploration and Development Activities

Exploration costs include the costs of geological and geophysical activities and drilling and equipping exploratory wells. Development costs include those of drilling and equipping development wells, enhanced recovery projects and facilities to extract, treat and store crude oil and natural gas. Annual costs, summarized

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below, include amounts both expensed and capitalized for PDVSA's conventional and extra-heavy crude oil reserves (in millions of dollars):

		2002					2001				2000
		Conventional reserves	Extra- heavy crude oil reserves		Total		Conventional reserves	Extra- heavy crude oil reserves		Total	Conventional reserves	Extra- heavy crude oil reserves		Total
Exploration costs		133	—		133		174	—		174	169	—		169
Development costs		1,434	510	(2)	1,944		1,364	792	(2)	2,156	1,207	851	(2)	2,058

	Total	1,567	510		2,077		1,538	792		2,330	1,376	851		2,227

Equity affiliate(1)		—	(19	)	(19	)	—	86		86	—	387		387

Total		1,567	491		2,058		1,538	878		2,416	1,376	1,238		2,614

(1): Represents PDVSA's equity share of the PETROZUATA extra-heavy oil joint venture.
(2): Represents PDVSA's proportional share in unincorporated extra-heavy oil joint ventures.

Table III—Capitalized Costs Relating to Oil and Gas Producing Activities

The following table summarizes capitalized costs of oil and gas exploration and production activities and the related accumulated depreciation and depletion at December 31 for PDVSA's conventional and extra-heavy crude oil reserves (in millions of dollars):

		2002						2001						2000
		Conventional reserves		Extra- heavy crude oil reserves		Total		Conventional reserves		Extra- heavy crude oil reserves		Total		Conventional reserves		Extra- heavy crude oil reserves		Total
Producing assets(1)		33,211		2,638		35,849		31,255		1,038		32,293		30,949		312		31,261
Support facilities		12,681		16		12,697		12,657		5		12,662		11,748		6		11,754

	Total	45,892		2,654		48,546		43,912		1,043		44,955		42,697		318		43,015
Accumulated depreciation and depletion		(27,350	)	(239	)	(27,589	)	(25,720	)	(43	)	(25,763	)	(24,680	)	(17	)	(24,697	)
Construction in progress		2,546		573		3,119		3,092		1,674		4,766		2,943		1,607		4,550

Net capitalized costs		21,088		2,988		24,076		21,284		2,674		23,958		20,960		1,908		22,868
Equity affiliate(2)		—		1,375		1,375		—		1,394		1,394		—		1,308		1,308

Total		21,088		4,363		25,451		21,284		4,068		25,352		20,960		3,216		24,176

(1): Includes land of $139 million, $139 million and $121 million at December 31, 2002, 2001 and 2000, respectively.
(2): Represents PDVSA's share of the PETROZUATA extra-heavy oil joint venture.

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Table IV—Results of Operations for Oil and Gas Producing Activities for Each Year (expressed in millions of dollars):

			2002						2001						2000
			Conventional reserves		Extra- heavy crude oil reserves		Total		Conventional reserves		Extra- heavy crude oil reserves		Total		Conventional reserves		Extra- heavy crude oil reserves		Total
Revenues from Production:
	Sales		13,479		633		14,112		14,091		254		14,345		21,310		227		21,537
	Transfers		8,322		—		8,322		8,931		—		8,931		9,594		—		9,594
	Production costs		(4,824	)	(135	)	(4,959	)	(4,888	)	(76	)	(4,964	)	(5,037	)	(105	)	(5,142	)
	Production tax		(5,642	)	(17	)	(5,659	)	(3,701	)	(32	)	(3,733	)	(4,926	)	(31	)	(4,957	)
	Depreciation and depletion		(1,882	)	(165	)	(2,047	)	(1,479	)	(25	)	(1,504	)	(1,814	)	(2	)	(1,816	)
	Exploration costs		(133	)	—		(133	)	(174	)	—		(174	)	(169	)	—		(169	)

	Results before income tax		9,320		316		9,636		12,780		121		12,901		18,958		89		19,047
Income tax			(4,494	)	(17	)	(4,511	)	(8,218	)	—		(8,218	)	(12,035	)	—		(12,035	)

	Results from production operations		4,826		299		5,125		4,562		121		4,683		6,923		89		7,012
Equity affiliate(1)			—		213		213		—		114		114		—		212		212

		Total	4,826		512		5,338		4,562		235		4,797		6,923		301		7,224

(1): Represents PDVSA's equity share of the PETROZUATA extra-heavy oil joint venture.

Revenues from crude oil production are calculated using market prices as if all production were sold.

The difference between the results before income taxes referred to above and the operating income reported for the upstream segment in note 18 for the years ended 2002, 2001 and 2000, is mainly due to: (1) the use of transfer prices for segment reporting purposes and market prices in the results of operations, and the reclassification of sales of gas to the downstream operations segment of some $2,870 million, $2,796 million and $4,119 million, respectively; (2) the inclusion in the business segment of general expenses and other of some $2,943 million, $2,102 million and $1,947 million, respectively and; (3) certain intercompany charges of some $391 million and $759 million during the years 2001 and 2000, respectively, recognized only for segment reporting purposes.

Production costs are lifting costs incurred to operate and maintain productive wells and related equipment and facilities, including such costs as operating labor, materials, supplies, fuel consumed in operations and the costs of operating natural liquid gas plants. Production costs also include administrative expenses and depreciation and depletion of equipment associated with production activities. In addition, they include operating fees for certain fields operated by specialized companies under operating agreements.

Production costs include $2,174 million, $2,110 million and $2,157 million, paid to independent contractors under service contracts during 2002, 2001 and 2000, respectively, which relate to the production of 176 million, 183 million and 170 million barrels of crude oil during 2002, 2001 and 2000, respectively.

The costs of extra-heavy crude production include the expenses incurred to operate and maintain the productive wells, as well as transportation and handling expenses. As of December 31, 2001, three of the facilities for the production of upgraded crude oil are in the commercial production stage and one is in the construction stage.

Exploration costs include those related to the geological and geophysical activities and non-productive exploratory wells. Depreciation and depletion expenses relate to assets employed in exploration and development activities. Income tax expense is calculated using the statutory rate for the year. For these purposes, results of operations do not include financing expenses and corporate overhead nor their associated tax effects.

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The following table summarizes average per unit sales prices and production costs for the years ended December 31 (in dollars):

		2002	2001	2000
Average sales price:
	Crude oil, per barrel	21.19	18.95	24.94
	Natural gas liquids, per barrel	17.65	19.55	25.42
	Natural gas, per barrel	4.34	5.35	5.29
Average production costs, per barrel of oil equivalent		3.92	3.38	3.48
Average production costs, per barrel of oil equivalent, excluding operating agreements		2.42	2.17	2.22

Table V—Standardized Measure of Discounted Future Net Cash Flows Related to Proved Oil and Gas Reserves

Due to uncertainties surrounding the timing of the ultimate development of the country's extra-heavy crude oil reserves, only the conventional proved reserves and those reserves related to PDVSA's participation in the extra-heavy crude oil projects have been used in the calculation of discounted future net cash flows.

Estimated future cash inflows from production are computed by applying year-end prices for oil and gas to year-end quantities of estimated proved reserves. Future income from extra-heavy crude oil production is determined using prices and quantities of the upgraded crude that will be produced in the upgrading facilities. Upgraded crude oil prices approximate those of conventional crude oil with similar characteristics at year-end. Future development and production costs are those estimated future expenditures necessary to develop and produce year-end estimated proved reserves, assuming continuation of year-end economic conditions. Estimated future income tax expense is calculated by applying the appropriate year-end statutory tax rates. These rates reflect allowable deductions and tax credits and are applied to estimated future pre-tax net cash flows. This calculation requires a year-by-year estimate of when future expenditures will be incurred and when the reserves will be produced.

The information provided below does not represent certified estimates of PDVSA's expected future cash flows or a precise value of its proved measured crude oil and gas reserves. Estimates of proved reserves are imprecise and may change over time as new information becomes available. Furthermore, probable and possible reserves, which may become proved in the future, are excluded from the calculation. The valuation to comply with SFAS No. 69 requires assumptions as to the timing of future production from proved reserves and the timing and amount of future development and production costs. The calculations are made as of December 31 of each year and should not be relied upon as an indication of PDVSA's future cash flows or the value of the oil and gas reserves (in millions of dollars):

		2002						2001						2000
		Conventional reserves		Extra- heavy crude oil reserves		Total		Conventional reserves		Extra- heavy crude oil reserves		Total		Conventional reserves		Extra- heavy crude oil reserves		Total
Future cash inflows		1,091,423		64,524		1,155,947		893,878		27,364		921,242		1,220,395		33,158		1,253,553
Future production costs		(212,869	)	(10.018	)	(222,887	)	(187,727	)	(7,108	)	(194,835	)	(142,434	)	(5,206	)	(147,640	)
Future production taxes		(308,413	)	(9,156	)	(317,569	)	(251,816	)	(3,418	)	(255,234	)	(203,440	)	(4,181	)	(207,621	)
Future development costs		(74,130	)	(4,952	)	(79,082	)	(60,136	)	(2,220	)	(62,356	)	(73,296	)	(1,502	)	(74,798	)
Future income tax expense		(220,483	)	(11,322	)	(231,805	)	(179,962	)	(3,918	)	(183,880	)	(499,905	)	(6,876	)	(506,781	)

Future net cash flows		275,528		29,076		304,604		214,237		10,700		224,937		301,320		15,393		316,713
Effect of discounting net cash flows at 10%		(223,588	)	(23,643	)	(247,231	)	(172,961	)	(7,881	)	(180,842	)	(225,369	)	(11,866	)	(237,235	)

Discounted future net cash flows		51,940		5,433		57,373		41,276		2,819		44,095		75,951		3,527		79,478
Equity affiliate(1)		—		2,064		2,064		—		1,124		1,124		—		2,065		2,065

	Total	51,940		7,497		59,437		41,276		3,943		45,219		75,951		5,592		81,543

(1): Represents PDVSA's equity share of the PETROZUATA extra-heavy oil joint venture.

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Table VI—Analysis of Changes in the Standardized Measure of Discounted Future Net Cash Flows Related to Proved Crude Oil and Natural Gas Reserves

The following table analyzes the changes as of December 31 of each year (in millions of dollars):

			2002						2001						2000
			Conventional reserves		Extra- heavy crude oil reserves		Total		Conventional reserves		Extra- heavy crude oil reserves		Total		Conventional reserves		Extra- heavy crude oil reserves		Total
Present value at January 1,
	Sales, net of production costs and taxes		(12,762	)	(63	)	(12,825	)	(11,446	)	(60	)	(11,506	)	(21,342	)	(91	)	(21,433	)
Value of reserves added during the year due to extensions and discoveries			—		—		—		902		1,229		2,131		877		2,208		3,085

			(12,762	)	(63	)	(12,825	)	(10,544	)	1,169		(9,375	)	(20,465	)	2,117		(18,348	)
Change in value of previous year reserves due to:
	Development costs incurred during the year		—		—		—		1,365		792		2,157		1,207		754		1,961
Change in future development costs			13,994		—		13,994		2,272		(317	)	1,955		(3,328	)	286		(3,042	)
Net changes in prices and production costs			23,943		(4	)	23,939		(81,216	)	(3,887	)	(85,103	)	13,342		315		13,657
Revisions of previous reserve estimates			(3,215	)	(1	)	(3,216	)	1,161		—		1,161		6,415		—		6,415
Net changes in income taxes			(8,301	)	—		(8,301	)	61,642		1,012		62,654		(7,214	)	(334	)	(7,548	)
Net changes in production rates and other			(2,994	)	70		(2,924	)	(9,354	)	498		(8,856	)	9,450		(2,586	)	6,864

Total change during the year			10,665		2		10,667		(34,674	)	(733	)	(35,407	)	(593	)	552		(41	)
Equity affiliate(1)			—		(915	)	(915	)	—		(915	)	(915	)	—		361		361
		Total	10,665		(913	)	9,752		(34,674	)	(1,648	)	(36,322	)	(593	)	913		320

(1): Represents PDVSA's equity share of the PETROZUATA extra-heavy oil joint venture.

(21) Subsequent Events (Unaudited)

The PDVSA work stoppage in Venezuela during December 2002 and January 2003 resulted in significantly reduced operating levels in PDVSA. Crude oil production levels were reduced from around 3.3 million BPD in November 2002 to an average of about 1.2 million BPD in December 2002 and an average of about 0.8 million BPD in January 2003. By April 2003, production levels had returned to approximately 3.2 million BPD (including Orinoco Belt production), levels which have since been sustained. In December 2002 PDVSA gave notice of force majeure under its crude oil supply agreements. Since February 2003, PDVSA began to normalize its operations, including the delivery of crude oil and products to its customers under the conditions established in its supply agreements. The force majeure was lifted in March 2003 (see notes 1(a) and 19).

On February 5, 2003, the Venezuelan government established a foreign exchange regime, setting the exchange rates for the sale and purchase of foreign currency at Bs. 1,600.00 to $1 and Bs. 1,596.00 to $1, respectively. It also created the Commission for the Administration of Foreign Exchange (CADIVI) and established rules for the administration and control of foreign currency.

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note 2). As a result, the new exchange controls will not have a significant impact on PDVSA's operations.

During 2003, the Venezuelan government and the National Assembly authorized PDVSA to withdraw $1,702 million of the funds deposited with the FIEM, which has been fully drawn down. During 2003, dividends amounting to $1,129 million were paid by PDVSA.

During 2003, PDVSA's board of directors decided to transfer from PDVSA Petróleos to CVP the coordination and control activities related to the first, second and third rounds of operating agreements and association agreements for the exploitation corresponding to PETROZUATA, Cerro Negro, Sincor and Hamaca.

On February 27, 2003, CITGO closed on a three-year $200 million senior secured term loan with a variable interest rate.

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QuickLinks

TABLE OF CONTENTS
INCORPORATION OF CERTAIN DOCUMENTS BY REFERENCE
FACTORS AFFECTING FORWARD-LOOKING STATEMENTS
PART I
Capital Investment Plan 2003 - 2008 ($ in millions)
Principal Oil-Producing Basins in Venezuela
PDVSA's Proved Reserves and Production by Basin
PDVSA's Proved Reserves and Production by Field
PDVSA's Proved Reserves
PDVSA's Exploration and Development
PDVSA's Average Production, Sales Price and Production Cost
PDVSA's Operating Service Agreements As of December 31, 2002
PDVSA's Orinoco Belt Proved Reserves
PDVSA's Refining System
PDVSA's Refining Capacity
PDVSA's Refinery Production
PDVSA's Export Volumes
PDVSA's Average Export Prices
PDVSA's Total Crude Oil and Refined Products Export Volumes
PDVSA's Consolidated Sales Volume
PDVSA's Local Market Sales
Pequiven's Sales, Consolidated Revenues, Net Property, Plant and Equipment and Capital Expenditures
Carbozulia's Production, Sales and Consolidated Revenues
ICO Project Gas Pipeline and Compression Stations
Summary of Exchange Rates (Bs/$1)
PDVSA's Export Sales—Geographical Breakdown
Non-Trading Commodity Derivatives Open positions at December 31, 2002
Non-Trading Commodity Derivatives Open positions at December 31, 2001
Non-Trading Interest Rate Derivatives Open positions at December 31, 2002 and 2001
Short-Term and Long-Term Debt at December 31, 2002
Short-Term and Long-Term Debt at December 31, 2001
PART II
PART III
SIGNATURES
ANNEX A Measurement Conversion Table
Glossary of Certain Oil and Gas Terms
PETRÓLEOS DE VENEZUELA, S.A. AND SUBSIDIARIES (PDVSA) (Wholly-owned by the Bolivarian Republic of Venezuela) Consolidated Financial Statements December 31, 2002 and 2001 With Independent Auditors' Report Thereon
Independent Auditors' Report
[Letterhead of Deloitte & Touche LLP]
PETRÓLEOS DE VENEZUELA, S.A. AND SUBSIDIARIES (PDVSA) (Wholly-owned by the Bolivarian Republic of Venezuela) Consolidated Balance Sheets (In millions of U.S. dollars)
PETRÓLEOS DE VENEZUELA, S.A. AND SUBSIDIARIES (PDVSA) (Wholly-owned by the Bolivarian Republic of Venezuela) Consolidated Statements of Income (In millions of U.S. dollars)
PETRÓLEOS DE VENEZUELA, S.A. AND SUBSIDIARIES (PDVSA) (Wholly-owned by the Bolivarian Republic of Venezuela) Consolidated Statements of Stockholder's Equity and Comprehensive Income Years ended December 31, 2002, 2001 and 2000 (In millions of U.S. dollars)
PETRÓLEOS DE VENEZUELA, S.A. AND SUBSIDIARIES (PDVSA) (Wholly-owned by the Bolivarian Republic of Venezuela) Consolidated Statements of Cash Flows (In millions of U.S. dollars)
PETRÓLEOS DE VENEZUELA, S.A. AND SUBSIDIARIES (PDVSA) (Wholly-owned by the Bolivarian Republic of Venezuela)
Notes to Consolidated Financial Statements December 31, 2002 and 2001