20-F 1 a2082333z20-f.htm FORM 20-F

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Table of Contents
Item 7. Major Shareholders and Related Party Transactions

As filed with the Securities and Exchange Commission on June 14, 2002.

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, 2001
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. 8.750% Notes due 2004
	PDVSA Finance Ltd. 6.650% Notes due 2006		PDVSA Finance Ltd. 9.375% Notes due 2007
	PDVSA Finance Ltd. 6.800% Notes due 2008		PDVSA Finance Ltd. 9.750% Notes due 2010
	PDVSA Finance Ltd. 8.500% Notes due 2012		PDVSA Finance Ltd. 7.400% Notes due 2016
	PDVSA Finance Ltd. 9.950% Notes due 2020		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, 2001.

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 ý No o

Indicate by check mark which financial statement item the registrant has elected to follow.

Item 17 o Item 18 ý

PETROLEOS DE VENEZUELA, S.A.

Annual Report Pursuant to Section 13 or 15(d) of the
Securities Exchange Act of 1934
For the Fiscal Year Ended December 31, 2001

Table of Contents


INCORPORATION OF CERTAIN DOCUMENTS BY REFERENCE
FACTORS AFFECTING FORWARD-LOOKING STATEMENTS
PART I
Item 1.	Identity of Directors, Senior Management and Advisers
Item 2.	Offer Statistics and Expected Timetable
Item 3.	Key Information
Item 4.	Information on the Company
Item 5.	Operating and Financial Review and Prospects
Item 6.	Directors, Senior Management and Employees
Item 7.	Major Shareholders and Related Party Transactions
Item 8.	Financial Information
Item 9.	The Offer and Listing
Item 10.	Additional Information
Item 11.	Quantitative and Qualitative Disclosures about Market Risk
PART III
Item 17.	Financial Statements
Item 18.	Financial Statements
Item 19.	Exhibits
SIGNATURES
ANNEX A

INCORPORATION OF CERTAIN DOCUMENTS BY REFERENCE

With respect to our guarantee of PDV America, Inc.'s 7⁷/8% Senior Notes due 2003, PDV America, Inc.'s annual report on Form 10-K for the year ended December 31, 2001, as first filed with the U.S. Securities and Exchange Commission (Commission File No. 001-12138) on March 29, 2002 is incorporated herein 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, 2001, as first filed with the U.S. Securities and Exchange Commission (Commission file No. 333-9678) on June 14, 2002 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, exploitation 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, 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 10-K of PDV America, Inc., our wholly owned subsidiary, for the year ended December 31, 2001 incorporated by reference herein also contains forward-looking statements. For a discussion of these statements contained in PDV America's annual report, see "Factors Affecting Forward-looking Statements" on page 1 thereof.

The annual report on Form 20-F of PDVSA Finance Ltd., our wholly owned subsidiary, for the year ended December 31, 2001 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.

"BOPEC" — Bonaire Petroleum Corporation N. V.

"BORCO" — The Bahamas Oil Refining Company International Limited

"Carbozulia" — Carbones del Zulia, S. A.

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

"CIED" — Centro Internacional de Educación y Desarrollo

"CITGO" — CITGO Petroleum Corporation

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

"Conoco" — Conoco Inc.

"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 Petroluem Corporation

"Proesca" — Productos Especiales, C. A.

"Propernyn" — Propernyn B.V.

"Ruhr" — Ruhr Oel GmbH

"Statoil" — Statoil Sincor AS

"Texaco" — Texaco Corporation

"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 following table sets forth certain selected historical consolidated financial and operating data of PDVSA as of the end of and for each of the five-year period ended December 31, 2001. The following table should be read in conjunction with the consolidated financial statements of PDVSA as of December 31, 2001 and 2000, and for each of the years in the three-year period ended December 31, 2001, which have been prepared in accordance with accounting principles generally accepted in the United States. The consolidated financial statements as of and for the years ended December 31, 2001 and 2000 have been audited by KPMG Alcaraz Cabrera Vázquez (a member firm of KPMG International), independent accountants. The consolidated financial statements as of and for the year ended December 31, 1999 have been audited by Espiñera, Sheldon y Asociados (a member firm of PricewaterhouseCoopers, L.L.P.), independent accountants. The consolidated financial statements as of December 31, 2001 and 2000, and for each of the years in the three-year period ended December 31, 2001, and the reports of KPMG Alcaraz Cabrera Vázquez and Espiñera, Sheldon y

Asociados thereon, which are based partially upon the reports of other auditors, are included elsewhere herein. See "Item 18. Financial Statements."

		At or for the Year Ended December 31,
		2001		2000		1999		1998		1997
		($ in millions)
Income Statement Data:
Sales of crude oil and products
	Exports and international markets	42,682		49,780		30,369		23,289		32,502
	In Venezuela	1,701		2,230		1,450		1,315		1,305
Petrochemical and other sale		1,403		1,224		781		922		994

	Net sales	45,786		53,234		32,600		25,526		34,801
Bonuses(1)		—		—		—		—		2,193
Equity in earnings of nonconsolidated investees		464		446		48		133		146

Total revenues		46,250		53,680		32,648		25,659		37,140
Total costs and expenses		37,977		40,029		26,636		23,219		26,359
	Operating income	8,273		13,651		6,012		2,440		10,781
Financing expenses		509		672		662		365		315

	Income before income tax, minority interests and cumulative effect of accounting change	7,764		12,979		5,350		2,075		10,466
Provision for income tax		(3,766	)	(5,748	)	(2,521	)	(1,602	)	(5,932	)
Minority interests		(5	)	(15	)	(11	)	(1	)	(29	)
Income before cumulative effect of accounting changes		3,993		7,216		2,818		472		4,505
Cumulative effect of accounting change(2)		—		—		—		191		—

	Net income	3,993		7,216		2,818		663		4,505

Balance Sheet Data:
Cash and cash equivalents		925		3,257		1,079		685		1,827
Notes and accounts receivable		3,280		4,435		3,820		2,194		2,755
Total assets		57,542		57,600		49,990		48,816		47,250
Short-term debt (including current portion of long-term debt)(3)		1,000		596		910		1,410		942
Long-term debt and capital lease obligations (excluding current portion)		7,544		7,187		7,892		6,615		4,318
Stockholder's equity		37,098		37,932		32,894		31,763		34,411
Capital Stock		39,094		39,094		39,094		39,094		39,094
Other Financial Data:
Net cash provided by operating activities		6,954		9,585		4,633		2,606		7,185
Net cash used in investing activities		(5,125	)	(4,660	)	(3,326	)	(4,532	)	(5,093	)
Net cash (used in) provided by financing activities		(4,161	)	(2,747	)	(913	)	784		(3,010	)
Capital expenditures		3,524		2,485		3,041		3,726		5,442
Depreciation and depletion		2,624		3,001		2,821		2,849		2,650
Debt/Equity(4)		23	%	21	%	27	%	26	%	16	%
Total payments to shareholder		12,097		11,641		6,549		6,236		11,781

	Dividends(5)	4,862		1,732		1,719		1,996		2,015
	Production tax	3,792		4,954		2,654		2,253		3,265
	Income taxes(6)	3,443		4,955		2,176		1,987		6,501

(1): Represents bonuses received pursuant to operating service agreements entered into in 1997 and our profit sharing agreements with private sector oil companies. See "Item 4.B Business overview—Initiatives Involving Private Sector Participation."
(2): Effective January 1, 1998, we changed our method of accounting for the cost of major refinery repairs and maintenance (turnarounds).
(3): Excludes current portion of capital lease obligations, which amounted to $62 million, $122 million, $117 million, $90 million and $81 million in 2001, 2000, 1999, 1998 and 1997, respectively.
(4): Calculated as total debt (long-term debt, including current portion of long-term debt and capital leases) divided by stockholder's equity.
(5): During 1999, special tax recovery certificates, or CERTS, amounting to $1,291 million were used to pay dividends.
(6): During 2001, 2000, 1999 and 1998, we used CERTS amounting to $84 million, $255 million, $22 million and $622 million, respectively, to pay income tax.

				At or for the Year Ended December 31,
				2001			2000			1999			1998			1997
				(MBPD, unless otherwise indicated)
Operating Data:
Production
Condensate					48			50			43			43			42
Light crude oil (API gravity of 30° or more)					1,135			1,174			1,189			1,233			1,264
Medium crude oil (API gravity of between 21° and 30°)					1,018			1,047			1,095			1,137			1,002
Heavy crude oil (API gravity of less than 21°)					893			814			623			866			940

	Total crude oil				3,094			3,085			2,950			3,279			3,248
Liquid petroleum gas					173			167			177			170			176

		Total crude oil and liquid petroleum gas			3,267			3,252			3,127			3,449			3,424

Net natural gas (MMCFD)(1)					4,093			3,979			3,766			3,965			3,930

Total crude oil, liquid petroleum gas and net natural gas (BOE)(2)					3,973			3,938			3,776			4,133			4,101

Sales volumes exported
	Exports of crude oil with 30° or greater API				659			716			1,010			889			736
	Exports of crude oil with less than 30° API				1,406			1,282			913			1,372			1,475
	Exports of refined petroleum products				697			825			861			855			841

		Total			2,762			2,823			2,784			3,116			3,052

Average export prices per unit ($ per barrel)
	Exports of crude oil with 30° or greater API			$	22.47		$	28.20		$	17.08		$	11.38		$	17.32
	Exports of crude oil with less than 30° API			$	17.29		$	23.12		$	13.45		$	8.08		$	13.99
	Exports of refined petroleum products			$	23.94		$	28.40		$	17.80		$	13.88		$	19.76
	Weighted average export prices (3)			$	20.21		$	25.91		$	16.04		$	10.57		$	16.31
Average production costs ($ per BOE)
	Production cost per BOE of production, excluding operating service agreements(4)			$	2.17		$	2.22		$	2.00		$	2.33		$	1.94
	Production cost per BOE of production(4)			$	3.38		$	3.48		$	2.72		$	2.75		$	2.33
	Depreciation and depletion cost per BOE of production			$	0.38		$	0.46		$	0.37		$	0.45		$	0.45
Proved reserves(5)
	Crude oil (MMB)
		Condensate			1,723			1,772			1,847			1,922			2,255
		Light crude oil (API gravity of 30° or more)			10,345			10,244			10,258			9,292			9,447
		Medium crude oil (API gravity of between 21° and 30°)			12,891			12,804			12,195			12,505			10,777
		Heavy crude oil (API gravity of between 11° and 21°)			17,266			17,177			16,861			16,742			16,675
		Extra-heavy crude oil (API gravity of less than 11°)(6)			35,558			35,688			35,701			35,647			35,673

			Total crude oil		77,783			77,685			76,862			76,108			74,827

			Of which, relating to Operating Service Agreements(7)		5,600			5,479			5,450			4,895			5,457
		Natural gas (BCF)(8)			148,295			147,585			146,611			146,573			145,531

		Proved reserves of crude oil and natural gas (MMBOE)(6)			103,351			103,131			102,140			101,379			100,021

		Remaining reserve life of proved crude oil reserves (years)(9)			64	x		64	x		70	x		64	x		63	x
Net crude oil refining capacity(10)
		Venezuela (including Isla Refinery)			1,628			1,620			1,620			1,620			1,613
		United States			1,205			1,198			1,224			1,224			945
		Europe			252			252			252			252			263

			Total		3,085			3,070			3,096			3,096			2,821

(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, 2001, approximately 10,770 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 12,476 BCF, 12,505 BCF, 12,400 BCF, 12,437 BCF and 12,438 BCF in each of 2001, 2000, 1999, 1998 and 1997, 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. See note 1(d) and note 2 to our consolidated financial statements, included under "Item 18. Financial Statements."

	Year ended December 31,
	Period End	Average (1)	High	Low
1997	502.84	488.57
1998	563.17	545.62
1999	647.53	609.29
2000	698.23	679.80
2001	770.09	722.01
December, 2001			770.09	745.13
January, 2002			770.09	758.13
February, 2002(2)			1,087.09	765.59
March, 2002			1,002.09	866.86
April, 2002			919.97	834.64
May, 2002			1,148.96	847.56

(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.
(2): The Venezuelan government and the Central Bank of Venezuela adopted, as of February 13, 2002, a floating exchange rate system in place of the band system. See note 1(d) and note 17 to our consolidated financial statements, included under "Item 18. Financial Statements."

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,
•: 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 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. However, 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.

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. Although operations returned to normal, a prolonged labor action could have a material adverse effect on our operating activities. We have no control over the occurrence of such developments and cannot assure you that similar events will not occur in the future.

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 and exploitation 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. 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 be able to 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—Exploration and Production."

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 company of Venezuela, which controls PDVSA through the Ministry of Energy and Mines. 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"). 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. We are domiciled in Venezuela and are governed by the laws of Venezuela.

Petróleos de Venezuela's 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.

4.B Business overview

We engage 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 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.

Through our exploration, production and upgrading executive office, we manage our exploration and production activities, our Orinoco Belt projects and the activities of our subsidiaries, Bitor, Carbozulia and CVP. PDVSA enters into joint venture agreements to pursue projects in the Orinoco Belt with international oil companies to extract and upgrade extra-heavy crude oil and to develop

Orinoco Belt's extra-heavy crude oil reserves. Through Bitor and Carbozulia, PDVSA manages the production of Orimulsion®, a fuel for electric generation created by emulsifying bitumen in water, and the production of coal in the state of Zulia in Western Venezuela. CVP coordinates activities related to exploration and production in new areas under profit sharing agreements with private sector oil companies.

Our downstream operations are conducted through our refining, 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 Phillips Petroleum) 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 and refined petroleum product operations 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, heating oil, petrochemicals, lubricants, asphalt and other refined petroleum products in the United States, markets jet fuel directly to airlines and produces a variety of agricultural, automotive and industrial lubricants, waxes and private label lubricants for independent distributors, mass marketers and industrial customers as well as other clients. In addition, CITGO sells petrochemicals and industrial products directly to various manufacturers and industrial companies throughout the United States. In 2001, CITGO produced a total of 24.7 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 Phillips Petroleum 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 2001.

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.

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 2001, based on a combination of operating criteria and other data for 2000, including reserves, production, refining capacity and refined petroleum product sales, we were the world's second largest vertically integrated oil and gas company, ranked sixth in the world in production and proved reserves of crude oil and fourth in the world in refining capacity and product sales. Venezuela has been exporting crude oil without interruption since 1914. In 2001, we accounted for approximately 26% of Venezuelan gross domestic product, approximately 80% of its exports and approximately 48% of its fiscal 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 ensure our financial strength. PDVSA's business plan for the years 2002-2007 focuses on the exploration, production, refining and marketing of hydrocarbons. Additionally, it 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. PDVSA also seeks to maintain high safety and health standards in conducting its business, and aims to achieve effective and timely integration of business technologies in its operations.

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,
•: complete the development of our Orinoco Belt extra-heavy crude oil projects,

With respect to refining and marketing—

•: invest in product upgrades and environmental compliance in Venezuela and abroad,
•: expand our markets in Latin America and the Caribbean,

With respect to gas—

•: promote active national and international private sector participation in nonassociated gas reserves, processing, transmission and distribution.

With respect to petrochemicals—

•: develop new lines of business with natural gas and refining streams, and promote private investment.

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.

•: Refining. Our refining strategy focuses on upgrading our downstream operations in Venezuela, the United States and in Europe, our major worldwide markets, by upgrading our product mix 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 awareness for our products. We also intend to strengthen our position in the United States through the 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. 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 also intend to support these activities using the gas transmission and distribution systems currently controlled and managed by the Ministry of Energy and Mines.

The Ministry of Energy and Mines completed a nonassociated gas licensing bid round for exploration and production activities in 11 new onshore areas in 2001. Out of these 11 areas, the following six were allocated and assigned 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 that gas production will begin at the end of 2002 from the Yucal-Placer areas.

We anticipate that development of our gas business strategy will require approximately $10,000 million in capital, including an investment of approximately $2,400 million for transmission and distribution systems. We expect that such capital expenditures will be obtained primarily through investments from the private sector. See "Item 5.B Liquidity and Capital Resources—Cash Flow from Investing Activities."

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 believe that our gas business plan will also contribute to promoting an increased and more diverse use of natural gas as a fuel and as a raw material in Venezuela.

•: 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 levels based on anticipated market opportunities, mainly in the Far East. We intend to carry out our planned expansion 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, 2001 totaling approximately 54.6 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 40.1 billion and 14.5 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, 2001 production and the ratio of proved reserves to annual production in each of the principal basins at December 31, 2001:

PDVSA's Proved Reserves and Production by Basin

			Proved reserves(1)		Proved/ developed reserves	2001 Production		Ratio of proved reserves/annual production
			(MMB at Dec. 31, 2001, except as otherwise indicated)		(MMB at Dec. 31, 2001, except as otherwise indicated)	(MBPD, except as otherwise indicated)		(years)
Basin
Western Zulia:
	Crude Oil		21,546		6,720	1,567	(2)	38
	Natural Gas (BOE)		6,279		1,959	239	(3)	72
Western Barinas — Apure:
	Crude Oil		1,887		972	109	(2)	47
	Natural Gas (BOE)		38		19	1	(3)	104
Eastern:
	Total Crude Oil (4)		54,350		9,680	1,681	(2)	89
	Extra-Heavy Crude Oil		35,558		1,963	354		275
	Natural Gas (BOE)		19,251	(5)	3,429	466	(3)	113
		Total Crude Oil (4)	77,783		17,372	3,357	(2)	64
		Total Natural Gas (BOE)	25,568	(5)	17,898	706	(3)	99

(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 37 billion barrels at December 31, 2001. See "Item 4.B Business overview—Initiatives Involving Private Sector Participation."
(5): Includes proved reserves of natural gas in the Orinoco Belt, estimated to be 2.4 billion BOE at December 31,2001.

The following table shows the location, 2001 production volume, discovery year, proved reserves and the ratio of proved reserves to annual production for each of PDVSA's ten largest oil fields as of December 31, 2001:

PDVSA's Proved Reserves and Production by Field

Name of field	Location	2001 Production	Year of discovery	Proved reserves	Ratio of proved reserves/ annual production
	(State of)	(MBPD)		(MMB at Dec. 31, 2001)	(years)
Tía Juana	Zulia	302	1925	5,027	46
Bachaquero	Zulia	233	1930	2,400	28
Lagunillas	Zulia	198	1925	2,468	34
Urdaneta Oeste	Zulia	140	1955	1,597	31
Boscán	Zulia	105	1946	1,392	36
Bloque VII Ceuta	Zulia	134	1956	1,883	39
Jobo	Monagas	38	1956	1,079	78
Mulata	Monagas	246	1941	2,329	26
El Furrial	Monagas	383	1986	2,054	15
Sta. Barbara	Monagas	159	1941	1,489	26

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.

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, 2001.

Crude Oil. We had estimated proved crude oil reserves at December 31, 2001 totaling approximately 77.8 billion barrels (including an estimated 37 billion barrels of heavy and extra-heavy crude oil in the Orinoco Belt). We also had estimated proved reserves of natural gas totaling approximately 148,295 BCF (including an estimated 14,153 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 23.8° for our crude oil produced in 2001. Based on 2001 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 64 years.

From December 31, 1995 to December 31, 2001, our estimated proved reserves of crude oil increased by 11.5 billion barrels and our estimated proved reserves of natural gas increased by 0.82 billion barrels of oil equivalent ("BOE"). In 2001, 2000 and 1999, our proved crude oil reserve replacement ratio was 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 103,807 BCF (or 17,898 MMBOE) at December 31, 2001. Our natural gas reserves are composed 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 2001, approximately 32% 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 18 to our consolidated financial statements, included under "Item 18. Financial Statements"):

PDVSA's Proved Reserves

			Year Ended December 31,
			2001		2000		1999		1998		1997
Proved Reserves(1):
Crude oil (MMB)
	Condensate		1,723		1,772		1,847		1,922		2,255
	Light (API gravity of 30° or more)		10,345		10,244		10,258		9,292		9,447
	Medium (API gravity of between 21° and 30°)		12,891		12,804		12,195		12,505		10,777
	Heavy (API gravity of between 11° and 21°)		17,266		17,177		16,861		16,742		16,675
	Extra-heavy (API gravity of less than 11°)(2)		35,558		35,688		35,701		35,647		35,673

		Total crude oil	77,783		77,685		76,862		76,108		74,827

		Of which, assigned to Operating Service Agreements(3)	5,600		5,479		5,450		4,895		5,457
Natural gas (BCF)(4)			148,295		147,585		146,611		146,573		145,531

Proved reserves of crude oil and natural gas (MMBOE)(3)(5)			103,351		103,131		102,140		101,379		100,021

Remaining reserves life of crude oil (years)(6)			64	x	64	x	70	x	64	x	63	x
Proved Developed Reserves:
Crude oil (MMB)
	Condensate		747		814		1,009		1,007		1,230
	Light (API gravity of 30° or more)		3,590		3,803		3,827		3,522		3,553
	Medium (API gravity of between 21° and 30°)		5,568		5,928		6,480		6,609		5,681
	Heavy (API gravity of between 11° and 21°)		5,504		5,453		5,738		5,562		5,801
	Extra-heavy (API gravity of less than 11°)(2)(7)		1,963		1,375		1,070		751		751

		Total crude oil(7)	17,372		17,373		18,124		17,451		17,016

		Of which, assigned to Operating Service Agreements(3)	1,523		1,413		1,329		1,195		1,332

Percentage of proved crude oil reserves(8)			22	%	22	%	24	%	23	%	23	%
Natural gas (BCF)(4)			103,807		103,310		102,628		102,086		101,292

Percentage of proved natural gas reserves(9)			70	%	70	%	70	%	70	%	70	%
Proved developed reserves of crude oil and natural gas (MMBOE)(2)(3)			35,270		35,185		35,818		35,052		34,579

(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, 2001, approximately 1,170 MMB were being developed under four association agreements in which we have an equity interest of less than 50%. See "Item 4.B—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 12,476 BCF, 12,505 BCF, 12,400 BCF, 12,437 BCF and 12,438 BCF in each of 2001, 2000, 1999, 1998 and 1997, 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 2001, our exploration expenditures were used principally to fund the drilling of 11 exploratory wells and acquisition of 2,748 km2 of 3D seismic lines and 577 km of 2D seismic lines. Additionally, nine exploratory wells were drilled and 33 km2 of 3D seismic lines were acquired pursuant to our operating services agreements. In 2001, we added 357 MMB proved crude oil reserves (46 MMB from newly discovered reserves and 311 MMB from development wells), compared to 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 2001, we invested $2,100 million in 479 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,
			2001	2000	1999	1998	1997
Exploration:
	Wells spud		6	5	5	9	10
	Wells carry-over		5	9	7	6	11

		Total	11	14	12	15	21

	Wells completed		3	2	0	5	10
	Wells suspended		0	2	5	4	4
	Wells under evaluation		3	5	1	3	2
	Wells in progress		3	1	4	1	4
	Dry or abandoned wells		2	4	2	2	1

		Total	11	14	12	15	21

Development:
	Development wells drilled(1)		479	474	349	976	1,058

(1): Includes wells in progress, even if they were spud in previous years, and injector wells. It does not include 18 development wells from PDVSA Gas.

Pursuant to operating services agreements relating to the Orinoco Belt, 9 exploration wells and 349 development wells were drilled in 2001, and 15 exploration wells and 453 development wells were drilled in 2000.

In 2001, our crude oil production averaged 3,094 MBPD (includes 52 MBPD attributable to our participation in the Orinoco Belt projects) with an average API gravity of 23.8°. This production level represented approximately 78% of PDVSA's estimated year end crude oil production capacity of 3,990 MBPD (includes 488 MBPD of crude oil production capacity attributable to our Orinoco Belt projects). In 2001, our average production costs of crude oil during were approximately $3.38 per BOE, or $2.17 per BOE excluding the production and costs attributable to our operating service agreements, and the average of our depreciation and depletion costs was $0.38 per BOE. See "Item 3.A Selected financial data."

At December 31, 2001, we operated approximately 19,583 oil wells and three gas 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 2001, our natural gas production was 6,000 MMCFD (or 1,034 MBPD on an oil equivalent basis), of which 1,907 MMCFD, or 32%, was reinjected for purposes of maintaining reservoir pressure. The net natural gas production of 4,093 MMCFD was consumed in production of liquid natural gas (8%), as fuel in refinery and production operations (39%), in petrochemical operations (11%) and the remainder (42%) was sold to third parties for power generation, aluminum, iron and other manufacturing industries and domestic uses. Approximately 75% of the 2001 natural gas production and of total estimated proved net natural gas reserves are 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 average sales price and production cost for the periods specified:

PDVSA's Average Production, Sales Price and Production Cost

				Years Ended December 31,
				2001		2000		1999		1998		1997
				(MBPD, except as otherwise indicated)
Crude oil:
	Condensate				48		50		43		43		42
	Light (API gravity of 30° or greater)				1,135		1,174		1,189		1,233		1,264
	Medium (API gravity of between 21° and 30°)				1,018		1,047		1,095		1,137		1,002
	Heavy (API gravity of less than 21°)				893		814		623		866		940

			Total crude oil		3,094		3,085		2,950		3,279		3,248

			Of which, assigned to Operating Service Agreements(1)		502		466		404		359		284
	Liquid petroleum gas				173		167		177		170		176

			Total crude oil and liquid petroleum gas		3,267		3,252		3,127		3,449		3,424

Natural gas:
	Gross production (MMCFD)				6,000		5,946		5,685		5,875		5,707
	Less:
		Reinjected (MMCFD)			1,907		1,967		1,919		1,910		1,777

	Net natural gas (MMCFD)				4,093		3,979		3,766		3,965		3,930

			Total crude oil, liquid petroleum gas and net natural gas (BOE)		3,973		3,938		3,776		4,133		4,101
Crude oil production by basin:
	Western Zulia Basin				1,567		1,536		1,450		1,634		1,686
	Western Barinas — Apure Basin				109		115		131		134		138
	Eastern Basin				1,418		1,434		1,369		1,511		1,424

			Total crude oil production		3,094		3,085		2,950		3,279		3,248

Natural gas gross production by basin (MMCFD):
	Western Zulia Basin				1,408		1,665		1,801		2,022		2,072
	Western Barinas — Apure Basin				7		7		7		7		14
	Eastern Basin				4,585		4,274		3,877		3,846		3,621

			Total gross natural gas production		6,000		5,946		5,685		5,875		5,707

Average sales price(2):
	Crude oil ($ per barrel)			$	18.95	$	24.94	$	15.35	$	9.37	$	15.10
	Gas ($ per MCF)			$	0.88	$	0.90	$	0.73	$	1.37	$	0.73
Average production cost ($ per BOE)(3)				$	3.38	$	3.48	$	2.72	$	2.75	$	2.33
Average production cost ($ per BOE), excluding operating service agreements(3)				$	2.17	$	2.22	$	2.00	$	2.33	$	1.94

(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. See note 8(c) to our consolidated financial statements, included under "Item 18. Financial Statements."

Private Sector Participation

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 has no further obligations as to any remaining value of the assets existing in the fields. See note 8(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 exploit 15 oil fields. An average of 337 MBPD of crude oil was produced from these fields in 2001, and it is expected that such production will increase to approximately 460 MBPD when the fields are in substantially full operation by 2005. As of December 31, 2001, these fields had estimated proved reserves of approximately 3.84 billion barrels of crude oil. As of December 31, 2001, under this initiative, foreign companies had invested in excess of $4,000 million.
•: The Third Round. We auctioned the right to reactivate, rehabilitate, develop and additionally explore certain hydrocarbon reservoirs in 18 fields. An average of 165 MBPD of crude oil was produced from these fields in 2001. As of December 31, 2001, these fields had estimated proved reserves of 1.76 billion barrels of crude oil. Our business plan currently contemplates daily production of 424 MBPD by 2005 under our operating service agreements. As of December 31, 2001, under this initiative, the operator companies had invested in excess of $2,500 million.

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, 2001

Area		Consortium (Operator)	Proved Crude Oil Reserves (MMB) (1)
First and Second Rounds
Boscan		Chevron Global Technology Services Co.	1,444.6
Urdaneta / West		Shell Venezuela S.A.	845.2
DZO		B.P. Venezuela Holdings, Ltd.	381.4
Oritupano / Leona		Perez Companc S.A., Union Pacific Resources, Servicios Corod de Venezuela	281.3
Colon		Tecpetrol Venezuela, CMS Oil and Gas, Coparex	135.8
Quiamare / LA Ceiba		Repsol-YPF Venezuela, S.A., Ampolex Venezuela Inc., Tecpetrol Venezuela	89.1
Quiriquire		Repsol-YPF Venezuela, S.A.	73.4
Pedernales		Perenco	121.9
Uracoa/Bombal		Benton Oil & Gas, Vinccler	85.0
Sanvi / Güere		Teikoku Oil De Sanvi Güere, C.A.	100.8
Guarico East		Teikoku Oil De Venezuela C.A.	73.3
Jusepin		Total Oil and Gas de Venezuela, B.V., B.P. Venezuela Holding, Ltd.	151.3
Guarico West		Union Pacific Resources, Repsol-YPF Venezuela, S.A.	40.4
Falcon East		Vinccler	9.1
Falcon West		West Falcon Samson	3.0

	Sub Total		3,835.6

Third Round
Boquerón			B.P. Venezuela Holding, Ltd., Preussag Energie GmbH	100.2
LL-652			Chevron Global Technology, Statoil, B.P. Venezuela Holding, Ltd., Petróleo y Gas Inversiones, C.A.	363.4
Dación			Lasmo Dacion, B.V., Lasmo Caracas, B.V., Lasmo Oriente, B.V.	258.9
Intercampo norte			China National Petroleum Corp.	177.0
Caracoles			China National Petroleum Corp.	105.2
B2X 68/79			Nimir Petroleum Company Limited, Ehcopek Petróleo, S.A., Cartera de Inversiones Petroleras II, C.A.	108.5
Mene grande			Repsol-YPF Venezuela, S.A.	98.1
Mata			Inversora Mata, Perez Companc de Venezuela, S.A. Petrolera Mata	82.8
B2X 70/80			Pancanadian Petroleum Venezuela, S.A., Nimir Petroleum Company Limited	70.2
Kaki			Inemaka, Inversiones Polar, Petróleo y Gas Inversiones, C.A.	38.6
Ambrosio			Perenco, Petróleo y Gas Inversiones, C.A.	52.2
Onado			Compañía General Combustibles, Carmanah Resources, Korea Petroleum, Bco Popular Del Ecuador	53.9
La Concepción			Perez Compac de Venezuela, S.A. Williams Companies, Inc.	128.3
Cabimas			Preussag Energy GmbH, Suelopetrol	45.8
Casma Anaco			Cosa-Ingenieros Consultores, Cartera de Inversiones Venezolanas, Phoenix International, C.A., Rosewood North Sea, Open.	13.7
Maulpa			Inemaka, Inversiones Polar, Petróleo y Gas Inversiones, C.A.	31.4
Acema			Coroil, Perez Companc de Venezuela, S.A., Petrolera Coroil	35.8
La Vela			C.V.P., S.A.	—

	Sub Total			1,764.0

		Total		5,599.6

(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, 2001 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 the profit sharing arrangements pursuant to which private sector oil companies were offered the right to explore, exploit and develop light and medium crude oil, on an equity basis in ten designated blocks with a total area of 13,774 km2, 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. The activities conducted in 2001 were comprised principally of completing the minimum exploratory work, continuing exploration efforts, and approving plans for evaluation and delineation. The activities related to the minimum exploratory work are conducted solely by the private sector companies. In 2001, PDVSA invested an aggregate of $880 million in connection with these profit sharing agreements, including an investment of $103 million to drill three exploratory wells and to conduct geological and engineering studies and environmental audits. Significant discoveries have been made in four of the eight oil fields explored. During 2001 and 2000, the profit sharing agreements relating to the areas of Delta Centro, Guanare, Guarapiche and Punta Pescador were terminated in advance in accordance with their provisions. See note 8(b) to our consolidated financial statements, included under "Item 18. Financial Statements."

CVP owns shares representing 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	Maxus (Repsol) (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	Pérez Companc	Compañía Anónima Mixta San Carlos, S.A.

(1): Profit sharing agreement was terminated in 2001.
(2): Profit sharing agreement was terminated in 2000.

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 synthetic 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 Cerro Negro, S. A.) 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. These facilities have an anticipated production capacity of approximately 120 MBPD of crude oil with an average API gravity of 20° to 23°. During 2001, Petrozuata produced 109 MBPD of extra-heavy crude oil. Under the terms of the joint venture agreement, Conoco has agreed to undertake the refining process, which will take place at Conoco's Lake Charles refinery, in Houston, Texas.
•: The Sincor Joint venture. Sincrudos de Oriente is a company owned by us (through PDVSA Sincor, S.A.), Total Fina and Statoil. This joint venture anticipates production of 145 MBPD of crude oil by 2002, and further anticipates reaching a production level of 190 MBPD with an average API gravity of 30° to 32° by 2007.
•: The Hamaca Joint Venture. Petrolera Hamaca is a company owned by us (through Corpoguanipa, S. A.), Texaco and Phillips Petroleum. This joint venture anticipates its initial production phase to yield 190 MBPD of extra-heavy crude oil by 2004 and 230 MBPD by 2007, with an average API gravity of 25° to 27°.
•: The Cerro Negro Joint Venture. Petrolera Cerro Negro is a company owned by us (through PDVSA Cerro Negro, S. A.), ExxonMobil and Veba Oel. This joint venture anticipates a production of 117 MBPD of crude oil with an average API gravity of 16° by the end of 2002. 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 2001, this joint venture produced 80 MBPD of extra-heavy crude oil. See "Item 4.B Business overview—Refining and Marketing—Refining," and note 8(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 a synthetic 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 synthetic 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	49.9	2,647	102	20-23
Sincor	Total Fina, Statoil	38.0	3,596	170	30-32
Hamaca	Texaco, Phillips Petroleum	30.0	1,079	170	25-27
Cerro Negro	ExxonMobil, Veba Oel	41.7	3,448	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 km2. As of December 31, 2001, these fields have estimated proved reserves of approximately 246.5 MMB of crude oil, with an average API gravity of 8° to 22° API. We anticipate an average daily production from these fields of 46 MBPD by 2007 and our business plan anticipates a total investment of approximately $1.1 billion in these fields over the next 20 years.

Refining and Marketing

Refining

Our downstream strategy has 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 2001, 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, 2001. The following diagram presents a summary of PDVSA's refining operations in 2001:

PDVSA's Refining System

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, 2001:

PDVSA's Refining Capacity

			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 $3,035 million from 2002 through 2007 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 craker 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 hydro treatment facilities and diesel hydro sulphuration 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 $700 million and is anticipated to be capable of producing 45MBPD of gasoline and 30MBPD 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 subsidiaries, CITGO and PDVMR, 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, 2001, 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 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 degrees.

The refineries in Paulsboro, New Jersey and Savannah, Georgia are specialized asphalt refineries. The Paulsboro refinery, which is particularly suited to process asphalt, also has facilities to process 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 $1.5 billion of crude oil and feedstocks at market related prices from PDVSA in 2001. 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.

In April 1998, PDVSA, pursuant to its contractual rights, declared force majeure and reduced deliveries of crude oil to LYONDELL-CITGO. On October 1, 2000, the force majeure condition was terminated and PDVSA deliveries of crude oil returned to contract levels. On February 9, 2001, PDVSA notified LYONDELL-CITGO that, effective February 1, 2001, it had again declared force majeure under the long-term crude oil supply agreement described above. As of December 31, 2001, PDVSA deliveries of crude oil to LYONDELL-CITGO have not been reduced due to PDVSA's declaration of force majeure. On January 22, 2002, PDVSA notified LYONDELL-CITGO that, pursuant to the February 9, 2001 declaration of force majeure, effective March 1, 2002, PDVSA expects to deliver approximately 20% less crude oil than volume of crude oil contracted to be delivered, and that force majeure will be in effect until at least June 2002. LYONDELL-CITGO has commenced an action against Petróleos de Venezuela and PDVSA Petróleo in the Southern District of New York. LYONDELL-CITGO alleges that Petróleos de Venezuela wrongfully declared force majeure events and reduced shipments of extra-heavy crude oil to LYONDELL-CITGO. See "Item 8.A.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 through December 2000. 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. See "Item 4.B Business overview—Initiatives Involving Private Sector Participation—Orinoco Belt Extra-Heavy Crude Oil Projects".

In October 1998, we had entered into agreements with Phillips Petroleum 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 Phillips Petroleum own an integrated coker and vacuum crude distillation unit within an existing refinery owned by Phillips Petroleum 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. Phillips 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 Phillips Petroleum to the joint venture under the processing agreement and any revenues from the sale of coke to third parties. See note 6 to our consolidated financial statements, included under "Item 18. Financial Statements."

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 and will construct a coker facility to process heavy crude oils. It is anticipated that construction of this coker facility will be completed by July 2002.

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, 2001 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 Gothenberg 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, 2001 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, 2001 was 7 MBPD.

The Nynäs refineries in Nynäshamn produce asphalt and naphthenic specialty oils. The Dundee, Gothenbeug, 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 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, 2001.

PDVSA's Refinery Production

					Year Ended December 31,
					2001			2000			1999
					MBPD		% of Total	MBPD		% of Total	MBPD		% of Total
Total refining capacity					4,368			4,353			4,403

PDVSA's net interest in refining capacity					3,085			3,070			3,096

Refinery input(1):
	Crude oil
		PDVSA(2)			2,018		72	2,072		68	2,005		70

			Light (API gravity of 30^o or greater)		551		20	687		22	767		27
			Medium (API gravity of between 21^o and 30^o)		983		35	862		28	832		29
			Heavy (API gravity of less than 21^o)		484		17	523		18	406		14
		Other			483		17	555		18	546		19

			Light (API gravity of 30^o or greater)		356		13	378		12	291		10
			Medium (API gravity of between 21^o and 30^o)		120		4	49		2	237		8
			Heavy (API gravity of less than 21^o)		7		0	128		4	18		1

				Crude oil subtotal	2,501		89	2,627		86	2,551		89

	Other feedstocks
		PDVSA			168		6	303		10	173		6
		Other			139		5	138		4	129		5

				Other feedstocks subtotal	307		11	441		14	302		11

	Total refinery input(3)
		PDVSA			2,186		78	2,375		77	2,178		76
		Other			622		22	693		23	675		24

			Total		2,808		100	3,068		100	2,853		100

Product yield(4):
	Gasoline/Naphtha				1,006		35	1,092		38	1,035		36
	Distillate				947		33	874		30	912		32
	Low sulfur residual				34		1	55		2	52		2
	High sulfur residual				339		12	344		12	373		13
	Asphalt/Coke				211		8	187		6	189		7
	Naphthenic specialty oil				9		0	12		0	7		0
	Petrochemicals				92		3	106		4	134		5
	Other				225		8	225		8	171		5

		Total product yield			2,863		100	2,895		100	2,873		100

Utilization(5)					81	%		86	%		82	%

(1): Our refineries sourced 81%, 60% and 79% of our total crude oil requirements from crude oil produced by us in 2001, 2000 and 1999, 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 2001, we supplied substantially all of the crude oil requirements to our Venezuelan refineries (approximately 1,060 MBPD), 229 MBPD of crude oil to our leased refinery in Curaçao and an aggregate of 1,255 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, 202 MBPD were purchased by PDVSA in the global market and supplied to our European affiliates. Additionally, CITGO and PDVMR purchased a total of 290 MBPD of crude oil from PDVSA for processing in their refineries.

Marketing

In 2001, we exported 2,065 MBPD of crude oil or 67% of our total crude oil production and 697 MBPD of refined petroleum products produced in Venezuela. Of total exports of crude oil and refined petroleum products, 1,497 MBPD (54%) were sold to the United States and Canada. During the period from January through December 2001, according to the Petroleum Supply Monthly dated February 2002, we were the third largest aggregate supplier of crude oil and refined petroleum products in the United States.

Of our total crude oil exports in 2001, an aggregate of 1,190 MBPD (58%) were exported to the United States and Canada; 573 MBPD (28%) to the Caribbean and Central America; 151 MBPD (7%) to Europe and 151 MBPD (7%) to South America and other destinations.

Of our total refined petroleum products produced in Venezuela in 2001, approximately 458 MBPD were used in the domestic market and 697 MBPD were exported. Of the total exports of refined petroleum products in 2001, 307 MBPD (44%) were sold to the United States and Canada; 220 MBPD (32%) to the Caribbean and Central America and 170 MBPD (24%) 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, 2001:

PDVSA's Export Volumes

				Year Ended December 31,
				2001		2000		1999
				(MBPD)	(% of Total)	(MBPD)	(% of Total)	(MBPD)	(% of Total)
Crude oil(1):
	Light (API gravity of 30^o or more)			659	32	716	36	1,010	52
	Medium (API gravity of between 21^o and 30^o)			585	28	586	29	264	14
	Heavy and extra-heavy (API gravity of less than 21^o)			821	40	696	35	649	34

		Subtotal		2,065	100	1,998	100	1,923	100

Refined products:
	Gasoline/Naphtha			165	24	186	23	210	24
	Distillate(2)			241	35	294	36	332	39
	Low sulfur residual			3	—	29	3	34	4
	High sulfur residual			189	27	187	23	129	15
	Liquid petroleum gas			44	6	43	5	61	7
	Other			55	8	86	10	95	11

		Subtotal		697	100	825	100	861	100

			Total exports	2,762		2,823		2,784

(1): Includes sales of crude oil to subsidiaries and affiliated refineries (including to the Isla Refinery in Curaçao) of 1,143 MBPD, 973 MBPD and 969 MBPD in 2001, 2000 and 1999, 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, 2001:

PDVSA's Average Export Prices

	Year Ended December 31,
	2001	2000	1999
	($ per barrel)
Crude oil(1)	18.95	24.94	15.35
Refined products	23.94	28.40	17.80
Liquefied petroleum gas	19.55	25.42	14.71
Average for the year	20.21	25.91	16.04

(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, 2001:

PDVSA's Total Crude Oil and Refined Products Export Volumes

				Year Ended December 31,
				2001			2000			1999
				(MBPD)		(% of Total)	(MBPD)		(% of Total)	(MBPD)		(% of Total)
Crude oil:
	All types				2,065	100		1,998	100		1,923	100

		United States and Canada			1,190	58		1,185	59		1,208	63

			Affiliates		694	34		518	26		512	27
			Third parties		496	24		667	33		696	36
		Europe			151	7		138	7		138	7

			Affiliates		63	3		71	4		73	4
			Third parties		88	4		67	3		65	3
		Caribbean and Central America			573	28		571	29		490	25

			Affiliates		386	19		373	19		386	20
			Third parties		187	9		198	10		104	5
		South America and others			151	7		104	5		87	5

			Third parties		151	7		104	5		87	5
	Light (API gravity of 30^o or greater)(1)				659	32		716	36		1,010	53

		United States and Canada			273	13		417	21		553	29
		Others			386	19		299	15		457	24
	Medium/Heavy (API gravity of less than 30°)(2)				1,406	68		1,282	64		913	47

		United States and Canada			913	44		767	38		675	35
		Others			493	24		515	26		238	12
Refined petroleum products:					697	100		825	100		861	100

		United States and Canada			307	44		356	43		381	44
		Others			390	56		469	57		480	56
Total crude oil and refined petroleum products exports					2,762	n.a.		2,823	n.a.		2,784	n.a.

Average sales price per barrel (in $):
	Light (API gravity of 30^o or greater)			$	22.47		$	28.20		$	17.08
	Medium/Heavy (API gravity of less than 30^o)			$	17.29		$	23.12		$	13.45
	Refined petroleum products			$	23.94		$	28.40		$	17.80

(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, 2001:

PDVSA's Consolidated Sales Volume

	Year Ended December 31,
	2001		2000		1999
	(MBPD)	(% of Total)	(MBPD)	(% of Total)	(MBPD)	(% of Total)
Refined petroleum products	2,586	58	2,913	63	2,917	72
Crude oil	1,892	42	1,755	37	1,149	28

Total	4,478	100	4,668	100	4,066	100

Average Price/Barrel ($/barrel)	28.21		29.13		19.67

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 58% of CITGO's total sales in 2001. CITGO markets CITGO-branded gasoline through over 15,000 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 24 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 over 350 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, PDVMR, Chalmette Refining and Hovensa pursuant to long-term contracts. In 2001, CITGO purchased 424 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 2001, we supplied to the European refineries in which we held an interest 242 MBPD of crude oil, of which 40 MBPD were exported from Venezuela and 202 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 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 24%, respectively, of Nynäs' consolidated revenues for 2001. 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, CITGO's wholly owned subsidiary. Through CITGO Latin America, we are introducing the PDV and CITGO brands into various Latin American markets, including through wholesale and retail sales of lubricants, gasoline and distillates. In 2001, CITGO Latin America set up an office in Guayaquil, Ecuador, further advancing its presence in Latin American markets. CITGO-branded products were given a boost this year with the branding of service stations in Puerto Rico, the first CITGO-branded service stations located outside of the United States. The PDV brand was recently launched in Argentina 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,
			2001		2000		1999
			(MBPD, except as otherwise indicated)
Refined Products:
	Liquefied petroleum gas			67		67		62
	Motor gasolines			225		208		199
	Diesel			98		82		74
	Other			68		54		48

		Total		458		411		383

Natural gas (BOE)				307		288		287
Natural gas (MMCF)				1,780		1,670		1,665
Unit Sale Prices:
Refined products ($ per barrel)			$	8.74	$	9.20	$	8.00
Natural gas ($/BOE)			$	5.35	$	5.29	$	4.24
Natural gas ($/MCF)			$	0.88	$	0.90	$	0.73

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 of price for gasoline is set by the Venezuelan government and represents approximately 54% of the export price for gasoline in 2001.

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, Texaco, 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 2001, were estimated at 228 trillion cubic feet, of which 148 trillion cubic feet are proved reserves. Of these reserves, 91% are associated with crude oil deposits and 9% are in the form of free gas. At December 2001, our total production capacity and sales of methane gas were 2,325 MCFD and 2,107 MCFD, respectively. Substantially all of the sales (99%) were to the Venezuelan market.

According to BP AMOCO Statistical Review of World Energy dated June 2001, 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 1,917 MCFD.

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 composed 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. Construction is currently under way on our new terminal facilities at the Jose complex.

In addition to the storage and terminal facilities in Venezuela, we also maintain additional storage and terminal facilities in the Caribbean, located in Bonaire, the Bahamas, Trinidad, Curaçao and Statia, with an aggregate storage capacity of 50 MMB at December 31, 2001. The Curaçao oil terminal, which is leased from the Netherlands Antilles government, had a storage capacity of approximately 15 MMB at December 31, 2001.

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 five 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, 2001, 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, 2001 of approximately 12 years.

In 2001, our total average shipments of crude oil and refined petroleum products amounted to 1,081 MBPD, of which 839 MBPD were shipped by our tankers and the remaining quantities were transported by chartered tankers.

Petrochemicals

We engage in the Venezuelan petrochemical industry through Pequiven. Through Pequiven, our goals include increasing the capacity and flexibility of existing plants, both for local and international markets, and identifying new products or commercial opportunities, mainly in methanol, plastics and fertilizers. The raw materials currently used by Pequiven are natural gas and liquefied petroleum gas, reformed naphtha and sulfur which are provided by PDVSA Petróleo, and phosphate rock, which is supplied by a Pequiven's subsidiary, Fosfato de Venezuela S.A., located in the state of Falcón in northwestern Venezuela.

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,
	2001	2000	1999
	($ in millions, except as otherwise indicated)
Sales volume (thousands of metric tons)	4,167	3,564	3,215
Consolidated revenues (1)	1,070	1,010	718
Net property, plant and equipment at year end	2,221	2,245	2,316
Capital expenditures	46	66	122

(1): Includes $351 million, $329 million and $308 million of sales to affiliates for 2001, 2000, and 1999, respectively; and sales to PDVSA's subsidiaries, which are eliminated in our consolidated financial statements.

Pequiven and its joint ventures operate three petrochemical complexes, with a total combined production capacity of over eight million metric tons currently. The Morón complex, in the Carabobo state, primarily produces fertilizers and sulfuric acid. The El Tablazo complex, on the northeast shore of Lake Maracaibo in the Zulia state, produces mainly olefins, chlorine/caustic nitrogen-based fertilizers, industrial feedstocks and thermoplastic resins. The Eastern Jose complex, located on the north coast of the Anzoategui state, produces methanol, fertilizer, industrial products and methyl-ter-butyl-ether, or

MTBE. Pequiven also has facilities to produce aromatics in the PDVSA El Palito refinery, located in the Carabobo state. The gross production of Pequiven's wholly owned plants in 2001 and 2000 was approximately 3.6 million metric tons and 3.9 million metric tons, respectively.

At present, Pequiven has interests in 17 operational joint ventures, with most of their production facilities located in the three existing petrochemical complexes, and has interests in new joint ventures in various stages of development. The gross production of these joint ventures in 2001 was approximately 4.97 million metric tons, as compared to 3.1 million metric tons in 2000. Products of these joint ventures include methanol, MTBE, ethylene, propylene, dripolene, polyethylenes, polypropylene, ethylene oxide, glycols, caustic soda, chlorine, ethylene dichloride, fertilizers, caprolactam and other specialty products.

In January 1997, Pequiven and ExxonMobil entered into a preliminary development agreement to assess the possibility of building a polyolefins and glycol complex in Pequiven's Jose complex. It is expected that this project will require an aggregate investment of approximately $2.3 million and the joint venture would be owned in equal share by ExxonMobil and Pequiven. Basic engineering and class II cost estimates were concluded during 1999 and both partners are in the pre-development phase and are analyzing enhancements for the project in anticipation of entering into a definitive development agreement.

In April 1999, Pequiven signed a joint venture agreement with Koch Industries Inc., Snamprogetti S.P.A. and Polar Uno, C.A. to construct two ammonia and two urea plants in the Jose complex for a total investment of approximately $1,000 billion. The joint venture company is called FertiNitro and is owned 35% by Pequiven, 35% by Koch, 20% by Snamprogetti and 10% by Polar. According to the joint venture agreement, Koch and Pequiven will agree to purchase pursuant to long-term offtake contracts 50% of the output of the four plants at market prices. The plant was completed in April 2001 and began production shortly thereafter.

During 1998, the Venezuelan Congress formally enacted legislation which, among other things, permits us to sell shares of Pequiven or any of our subsidiaries to local or foreign investors, to cause Pequiven to dispose of Pequiven's interests in subsidiaries and joint ventures, and to sell Pequiven's assets to third parties. The net proceeds of such transactions, if any, would be used to develop further our petrochemical activities.

We invested $130 million in the construction of a petrochemical jetty at the Jose complex with capacity to handle refrigerated liquids, bulks solids and containers coming from the FertiNitro joint venture and the future polyolefins and glycol project. This facility began operating during the first quarter of 2001.

Our business plan contemplates increasing the aggregate capacity of Pequiven's own plants, and those operated by joint ventures, from 11.7 million metric tons in 2001 to 17.8 million metric tons in 2007. We anticipate that the aggregate investments for these plants will be $4.9 million. We anticipate that $1.0 million in investments will come from Pequiven's own resources (including bank loans), and our joint venture partners will contribute the remainder.

Through our subsidiary, Proesca, we are also involved in a number of projects with the private sector to process intermediate refinery streams into higher margin products that will substitute imports and increase non-traditional exports such as solvents, propylene, waxes and oil tars.

Natural Bitumen

The Orinoco Belt, located along the Orinoco River in Eastern Venezuela, has substantial reserves of natural bitumen, estimated to be in excess of 1 trillion barrels, an estimated 22% of which can be recovered by conventional petroleum exploitation methods. We are involved in several extra-heavy

crude oil projects in the Orinoco Belt to exploit these reserves. See "Item 4.B Business overview—Initiatives Involving Private Sector Participation—Orinoco Belt Extra-Heavy Crude Oil Projects."

Additionally, through our wholly owned subsidiary, Bitor, we have developed a process of emulsifying natural bitumen in water to create an alternative liquid fuel to generate electricity, named Orimulsion®, which offers advantages over coal and fuel oil in terms of combustion properties, environmental impact, ease of handling and costs. Field development and production of the resources needed to manufacture Orimulsion® are currently carried out through operating arrangements and contracts entered into by PDVSA Petróleo and other parties.

Our Orimulsion® production capacity is 6.5 million metric tons per year, and the net production in 2001 was approximately 6.2 million metric tons, as compared to 6.3 million metric tons in 2000. In accordance with our business plan, Bitor plans to increase Orimulsion® production to 20 million metric tons a year by 2007 and is currently analyzing various projects for the expansion of its development and production capacity that would involve the establishment of joint ventures with several foreign oil companies. An association agreement was entered into in December 2001, among Bitor, China National Oil and Gas Exploration and Development Corporation and Petrochina Fuel Oil Company Limited to build and operate additional production capacity up to 6.5 million metric tons by 2004.

Orimulsion® is marketed worldwide by Bitor through its wholly owned marketing subsidiaries. In Japan, Bitor markets Orimulsion® through its 50%-owned joint venture with Mitsubishi Corporation. Bitor's 2001 production was sold mainly to customers in Italy (36%), Denmark (18%), China (16%), Japan (14%) and Canada (13%).

The following table sets forth selected information of Bitor:

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

	Year Ended December 31,
	2001	2000	1999
	(Thousands of metric tons, except as otherwise indicated)
Raw material production	4,257	4,175	3,352
Production	6,226	6,255	4,805
Orimulsion® sales volume	6,173	6,235	4,885
Consolidated revenues ($ in millions)	200	215	148
Net property, plant and equipment ($ in millions)	561	556	545
Capital expenditures ($ in millions)	43	51	14

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 14% of resources in the basin are being exploited. It is estimated that up to 50% of such resources can be exploited 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,
	2001	2000	1999
	(Thousands of metric tons, except as otherwise indicated)
Coal production	7,571	7,748	6,392
Coal sales volume	7,627	8,097	6,291
Consolidated revenues ($ in millions)	164	112	61

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

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 costs, 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 2001, we continued to develop products and technologies such as MIS®, used in connection with heavy oil recovery and production; AQUADIESEL® (a low-emission diesel for public transportation vehicles, successfully tested in Houston); DISOL® (Gas-to-Liquid technology); and conducted early commercial tests of ISAL® (hydroconversion technology, successfully tested in a U.S. refinery, used to produce low sulfur, high octane gasolines). Further advances were obtained in the development of AQUACONVERSION®, which is a catalytic process used to produce high-quality diesels and medium distillates from heavy residues, successfully tested in downstream conversion in a Curaçao refinery; and HDH+ (technology to be used in Petrozuata for treatment and conversion of Orinoco Belt heavy and extra heavy crudes). With respect to environmental protection, we also developed two new products: INTEBIOS® (a biotreatment technology for the recovery of crude contaminated soils); and BIOLAGUNAS® (a system for phenol removal from water production streams). For long-term applications, Intevep is also conducting studies in biotechnology and nanotechnology (advanced materials), fuels for advanced vehicles and alternative sources of energy.

Petroleum Investment Promotion Corporation

In 1995, we established the Petroleum Investment Development Corporation, also known as Sociedad de Fomento de Inversiones Petroleras, or SOFIP, as the entity responsible for developing investment vehicles, funds and other instruments that will allow local and international investors, including individuals, to invest in projects within the Venezuelan oil industry where private participation is allowed.

From 1998 through 2001, SOFIP promoted funds whose portfolio consisted of investments in PDVSA's exploration and production projects that involved private sector participation, including Orinoco Belt extra-heavy crude oil projects and operating service agreements entered into in 1997. This initiative was cancelled during the fourth quarter of 2001 due to adverse financial and petroleum market conditions. SOFIP ceased activities on December 31, 2001.

Other Projects

In February 2002, with an investment of approximately $375 million, we began offshore drilling activities in a submarine platform in the Orinoco Delta, from a floating rig named Plataforma Deltana located in the Atlantic Ocean, close to the border with Trinidad and Tobago. This project aims to add new free natural gas reserves to meet internal and export market requirements. The Plataforma Deltana project will operate approximately 155 miles from the coast of Venezuela's Delta Amacuro territory, over a two-year period. The estimated production is 4.7 million metric tons per year. The total estimated investment in this project is $1,959 million for the period 2001-2007, of which 60% is expected to be financed by PDVSA and 40% is expected to be financed by private investors.

This floating rig drills exploration and outline wells, in search of potential hydrocarbon accumulations. The rig can operate at water depths of between 150 feet and 1,500 feet, and drill down to about 25,000 feet. Because of the nature of the operation, the drilling rig is of a size large enough to house a crew of about one hundred technicians and qualified workers.

This new venture into the gas business is seen as a potential contribution to meet the need for diversifying energy sources that help shape Venezuela's economic development. Similarly, the success of this project would further strengthen Venezuela's commercial competitiveness by improving its position in the global market, which has been progressively migrating towards the use of natural gas, as a clean non-polluting fuel.

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.

We have an investment plan to comply with the applicable environmental regulations in Venezuela. This investment plan contemplates approximately $1,998 million in capital expenditure from 2002 through 2007, including the following: $1,079 million for product quality; $583 million for risk control; $279 million for environmental adaptation; and $57 million for other environment-related investments.

For the purpose of compliance with future fuel specifications, both national and international, our production projects are aimed at the significant reduction of the sulfur content of fuels.

In addition to the activities outlined in our investment plan, expenditures of approximately $624 million are planned for remediation of 8,000 production pits as part of a global remediation plan that will culminate in 2010. The pits are excavations made in the soil and/or constructions of earth walls that were used in the past to temporarily store the waste generated by the exploration and production activities. These excavations were made when there was no appropriate technology available to avoid the use of pits. Currently, PDVSA does not excavate pits as part of its operations.

In addition, for the period 2002 - 2006, CITGO has planned expenditures of approximately $1,154 million to comply with environmental regulations in the United States.

In 1992, CITGO reached an agreement with a state agency to cease usage of certain surface impoundments at CITGO's Lake Charles refinery by 1994. A mutually acceptable closure plan was filed with the state in 1993. CITGO and its former owner are participating in the closure and sharing the related costs based on estimated contributions of waste and ownership periods. The remediation commenced in December 1993. In 1997, CITGO presented a proposal to a state agency revising the 1993 closure plan. In 1998 and 2000, CITGO amended its 1997 proposal as requested by the state agency. A ruling on the proposal, as amended, is expected in 2002, with final closure to begin later in 2002.

In January and July 2001, CITGO received notices of violation from the U.S. Environmental Protection Agency alleging violations of the Clean Air Act. The notices of violation are an outgrowth of an industry-wide and multi-industry U.S. Environmental Protection Agency enforcement initiative, alleging that many refineries and electric utilities modified air emission sources without obtaining permits under the New Source Review provision of the Clean Air Act. The notices of violation to CITGO followed inspections and formal information requests regarding CITGO's Lake Charles, Louisiana and Corpus Christi, Texas refineries and the Lemont, Illinois refinery operated by CITGO. At the request of the U.S. Environmental Protection Agency, CITGO is engaged in settlement discussions, but is prepared to contest the notices of violation if the settlement discussions fail. If CITGO settles or is found to have violated the provisions cited in the notices of violation, it would be subject to possible penalties and significant capital expenditures for installation or upgrading of pollution control equipment or technologies.

In June 1999, a notice of violation was issued by the U.S. Environmental Protection Agency alleging violations of the National Emission Standards for Hazardous Air Pollutants regulations covering benzene emissions from wastewater treatment operations at the Lemont, Illinois refinery operated by CITGO. CITGO is in settlement discussions with the U.S. Environmental Protection Agency. CITGO believes this matter will be consolidated with the matters described in the previous paragraph.

Conditions which 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. The amounts of such future expenditures, if any, are indeterminable. Management believes that these matters, in the normal course of operations, will not have a material effect on the financial position, liquidity or consolidated 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 optimize 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 an operating structure, increasing the involvement of our board of directors in our activities, and, at the same time, enhancing 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, 2001 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.

The average price of the OPEC basket decreased by $4.43 per barrel, or 16%, from $27.55 per barrel in 2000 to $23.12 per barrel in 2001, due to the decrease in oil demand and the drop in oil prices, primarily as a result of the global economic slowdown. The average prices of our exports, including refined products, decreased $5.70 per barrel, or 22%, from $25.91 per barrel in 2000 to $20.21 per barrel in 2001.

Throughout 2001, the OPEC agreed to oil production cuts for its members. Three production cuts were effected in February, April and September 2001, resulting in a total decrease in our production in 2001 of 407 MBD compared to our production level in 2000. In January 2002, pursuant to production agreements with OPEC members, we decreased our production by an additional 174 MBD.

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 been using exchange rates to moderate inflation, by devaluing the Bolivar within a pre-determined band. In 2001, 2000 and 1999, the annual rate of devaluation was 10%, 8% and 15%, respectively, which was lower than the annual rate of inflation of 12%, 13% and 20%, respectively.

	December 31,
	2001	2000	1999
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)	770.09	698.23	647.53
Average annual exchange rates (Bs/$1)	722.01	679.80	609.29
Interannual increments in the exchange rate (%)	10.29	7.82	14.98
Interannual increments in the CPI (%)	12.29	13.43	20.02

The Venezuelan government and the Central Bank of Venezuela adopted a floating exchange rate system, as opposed to the band system previously in effect, effective February 13, 2002. As a result of the adoption of a floating exchange rate system, the Bolivar has devalued against the dollar and inflation has accelerated in 2002. See note 1(d) and note 17 to our consolidated financial statements, included under "Item 18. Financial Statements."

Impact of Taxes on Net Income and Cash Flows

Our consolidated effective income tax rate increased 11%, from 44% in 2000 to 49% in 2001, due to an increase in the effect of the lower tax rate for our non-petroleum sector and foreign subsidiaries, partially offset by a decrease in the tax effects of the inflation adjustment and the remeasurement to dollars. See note 9 to our consolidated financial statements, included under "Item 18. Financial Statements."

Income tax expense is based on accounting denominated in Bolivars, in accordance with the Venezuelan income tax law. For fiscal purposes, Venezuelan companies are required to reflect the impact of inflation and the variations in the rate of the Bolivar vis-à-vis 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.

A production tax equal to 16²/3% of the market value at the well head of the crude oil and natural gas produced is charged for the right to extract crude oil and natural gas. This tax is fully deductible in determining net taxable income. This law was effective until December 2001.

The new Hydrocarbons Law that came into effect as of January 2002 affects PDVSA as follows:

•

Production tax increased from 16²/3% to 30% on the volume of extracted hydrocarbons. In the case of mature reservoirs or extra-heavy crude oil originating from the Orinoco Belt, a tax rate within a 20% to 30% band is established. For natural bitumen, a tax rate within a 16²/3% to 30% band is established, based on the profitability of 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 area conceded not under production; with an annual increase of 2% for five years and 5% in the following years.
–: General consumption tax applicable to each liter of hydrocarbon-derived product sold in the internal market, the rate for which shall be fixed annually in the Budget Law ranging between 30% and 50% of the price paid by the final consumer. In 2002, the tax is 30%.
–: Tax on PDVSA'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.

The net effect of the increase in the production tax rate and the decrease in the income tax rate is not expected to have a material impact on either our cash flows or financial results.

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 $245 million of CERTs, all of which were used against our income tax liability. In 2001, we recovered $347 million of CERTs.

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. See note 9 to our consolidated financial statements, included under "Item 18. Financial Statements."

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. This tax does not affect our oil producing subsidiaries, as the amounts payable in income tax are greater than the amounts that would be payable under this law.

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%.

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 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 its taxable income is not significant for 2001 and 2000.

Beginning January 2001, the amendment also included an universal tax system for Venezuela and introduced taxes on dividends and rules to promote international fiscal transparency.

In January 2002, another amendment of the Income Tax Law published in November 2001, came into effect. One of the most important aspects of this amendment is the change in the income tax rate applicable to the Venezuelan subsidiaries engaged in the production of hydrocarbon and related activities from 67.7% to 50%. See note 9 to our consolidated financial statements, included under "Item 18. Financial Statements."

Basis of Presentation

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

5.A Operating results

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 Consolidated Sales Volume" above.

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 synthetic crude 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 Average Production, Sales Price and Production Cost" above.

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.

Income Before Income Tax and Minority Interests

Income before income tax and minority interests was 40% lower in 2001 than in 2000 ($7,764 million in 2001 as compared to $12,979 million in 2000), primarily as a result of a decrease in net sales. We were subject to an effective consolidated income tax rate in 2001 of 49% compared to 44% in 2000. This difference is primarily due an increase in the effect of the lower tax rate for our non-petroleum sector and foreign subsidiaries, partially offset by a decrease in the tax effects of the inflation adjustment and the remeasurement to dollars.

Results of Operations—2000 Compared to 1999

Production

Our production of crude oil and liquid petroleum gas averaged 3,252 MBPD in 2000, a 4% increase from 3,127 MBPD produced in 1999. Of this total, 38% was light crude oil and condensates, 32% was medium crude oil, 25% 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) increased 6% (to 3,979 MMCFD in 2000 compared to 3,766 MMCFD in 1999). In 2000, our natural gas production capacity reached 6,594 MMCFD and natural gas liquid production capacity totaled 2,482 MBPD. Our crude oil production capacity was 3,582 MBPD in 2000 compared to 3,691 MBPD in 1999. All of our crude oil and natural gas production operations are located in Venezuela.

In 2000, our 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 2,895 MBPD, from 2,873 MBPD in 1999. Of this total, 1,364 MBPD (47%) was produced in our Venezuelan refineries (including the Isla Refinery in Curaçao), 1,253 MBPD (43%) was produced by our United States refineries and our interests in our European joint ventures accounted for the remaining 278 MBPD (10%).

Total Revenues

In 2000, our revenues (including total net sales and equity in earnings of non-consolidated investees) totaled $53,680 million, a 64% increase over our 1999 total revenues of $32,648 million.

Net Sales

Our 2000 net sales totaled $53,234 million, a 63% increase over 1999 net sales of $32,600 million. In terms of volume, our sales increased by 15% in 2000 compared to our sales in 1999. Our total sales volume of 4,668 MPBD in 2000 (compared to 4,066 MBPD in 1999) consists of Venezuelan domestic sales, exports of crude oil and refined petroleum products from Venezuela and sales of crude oil and refined petroleum products produced by and purchased from third parties by our international subsidiaries.

Export Revenues of Crude Oil and Refined Products. In terms of volume, exports represented 61% of our sales. Our exports increased in volume by 1% in 2000, to 2,823 MBPD from 2,784 MBPD in 1999. The average realized export price per barrel for Venezuelan crude oil, refined petroleum products and liquid petroleum gas was $25.91 in 2000, compared to $16.04 in 1999, a 62% increase.

The following table sets forth the primary markets for Venezuelan crude oil, refined petroleum products and liquid petroleum gas for the periods 2000 and 1999.

PDVSA's Export Sales—Geographical Breakdown

	2000	1999	Increase (Decrease)
	(MBPD, except as otherwise indicated)
United States and Canada	1,540	1,589	(3)%
Caribbean and Central America	870	748	16%
South America	183	349	(48)%
Europe	230	98	135%

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 2,823 MBPD in 2000, 1,998 MBPD were exported (including to the Isla Refinery in Curaçao) as crude oil and 825 MBPD were exported as refined petroleum products. For the purpose of calculating export volumes, we treat crude oil processed

Sales Revenues of International Subsidiaries. In 2000, the total volumes of crude oil and refined petroleum products that we sold exceeded our total production of crude oil and liquid petroleum gas (3,252 MBPD of crude oil and liquid petroleum gas production as compared to 4,668 MBPD of total sales in 2000). 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 2000 were approximately 1,636 MBPD, compared to 1,547 MBPD in 1999, and its purchases of crude oil from us totaled approximately 329 MBPD in 2000, compared to 314 MBPD in 1999. PDV America's revenues increased to $22,157 million in 2000 from $13,300 million in 1999, primarily as a result of higher prices for hydrocarbon products.

Domestic Sales. In 2000, in the Venezuelan domestic market, we sold 411 MBPD of refined petroleum products (including liquid petroleum gas), compared to 383 MBPD sold in 1999. We also sold 288 MBPD of oil equivalent of natural gas, compared to 287 MBPD sold in 1999. Unit sales prices of refined petroleum products increased 15% to $9.20 per barrel in 2000 (from $8.00 per barrel in 1999) and unit sales prices of natural gas increased to $0.90 per MCF or $5.22 per BOE in 2000 (from $0.73 per MCF or $4.24 per BOE in 1999).

Petrochemical and Other Sales. Our net sales for 2000 included $1,224 million from sales of petrochemicals, bitumen and coal, a 57% increase compared to $781 million of revenues from sales of these products in 1999. Such increase in net sales is due primarily to an increase in production and higher sales volumes for fertilizers, bitumen and coal. Such net sales also included $989 million (of which $321 million was derived from sales in the international markets) from sales of petrochemical products, including fertilizers, industrial products and olefins, natural bitumen ($215 million) and coal ($112 million).

Equity in Earnings of Nonconsolidated Investees

Equity in earnings of non-consolidated investees increased 829% to $446 million in 2000 from $48 million in 1999. In the United States, PDV America's equity in earnings of non-consolidated investees increased 168% to $59 million in 2000 from $22 million in 1999. This increase was primarily due to increased earnings at LYONDELL-CITGO. CITGO's equity in earnings increased $40 million, to $41 million in 2000 from $1 million in 1999. The increase in LYONDELL-CITGO's earnings was due primarily to increased deliveries and an improved mix of crude oil, higher spot margins due to a stronger gasoline market in 2000 and higher margins for reformulated gasoline due to industry supply shortages. These improvements were partly offset by higher fuel and utility costs and interest expense.

Purchase of Crude Oil and Products

Our purchase of crude oil and products increased by 80% to $19,759 million in 2000 from $10,959 million in 1999, primarily as a result of the increase in prices for hydrocarbons in the international markets. We also purchased an average of 51 MBPD and 67 MBPD of refined products and crude oil for our Venezuelan operations, during 2000 and 1999, respectively. Purchases of crude oil were also made to meet our supply commitments.

Operating Expenses

Our operating expenses increased by 17% to $10,010 million in 2000 from $8,532 million in 1999. Such increase is due primarily to our operating expenses under our operating service agreements. Our production costs per barrel increased to $3.48 in 2000, as compared to $2.72 in 1999, due primarily to an increase in the fees incurred pursuant to our operating service agreements. Our production costs per barrel, excluding operating service agreements, increased to $2.22 in 2000, as compared to $2.00 in 1999, due primarily to an increase in the cost of reconditioning and recovery of wells. Production from our fields that are operated under the operating service agreements (which have higher than average cost structures) increased from 403 MBPD in 1999 to 466 MBPD in 2000, and the average cost per barrel from such production was $12.90 in 2000.

Our total refining costs represented 37% and 34% of our total operating expenses for 2000 and 1999, respectively. Costs incurred at our Venezuelan refineries (including the Isla Refinery) represented 8% of our total operating expenses in 2000 and 11% of our total operating expenses in 1999.

Exploration Expenses

Our total exploration expenses was $169 million in 2000, compared to $118 million in 1999. Our exploration expenses also include expenses related to four dry wells which were abandoned during 2000, totaling $57 million (compared to $17 million in 1999).

Depreciation and Depletion

Depreciation and depletion increased by 6% to $3,001 million in 2000 from $2,821 million in 1999 due to the depreciation and depletion related to new production units.

Selling, Administrative and General Expenses

Selling, administrative and general expenses increased 5% to $1,256 million in 2000 from $1,192 million in 1999.

Financing Expenses

Financing expenses increased 2% to $672 million in 2000 from $662 million in 1999, in each case, net of capitalized interest of $59 million and $188 million, respectively, primarily as a result of a decrease in the amount of such expenses that was capitalized, partially offset by a decrease in the average balance of outstanding debt and a decrease in the weighted average interest rate from 7.06% in 1999 to 6.07% in 2000. See "—Liquidity and Capital Resources" below.

Income Before Income Tax and Minority Interests

Income before income tax and minority interests was 143% higher in 2000 than in 1999 ($12,979 million in 2000 as compared to $5,350 million in 1999), primarily as a result of the increase in net sales. We were subject to an effective consolidated income tax rate in 2000 of 44% compared to 47% in 1999.

5.B Liquidity and Capital Resources

Cash Flows from Operating Activities

For the year ended December 31, 2001, PDVSA's net cash provided by operating activities totaled $6,954 million, primarily reflecting $3,993 million of net income, $2,624 million of depreciation and depletion, $1,479 million of provision for employee termination and pension benefit and other post-retirement benefits, $603 million of deferred income tax and the net effect of other items of

$1,745 million. The more significant changes in other items included the decrease in accounts receivable of approximately $1,155 million and the decrease in accounts payable and other current liabilities of approximately $1,648 million. The decrease in accounts receivable was primarily due to lower prices in the international market for crude oil and refined products, as compared with the prices in 2000. See table captioned "PDVSA Average Export Prices" table above. The decrease in accounts payable is related to the decline in the purchase prices of crude oil and refined products in the international markets resulting in a decrease in accounts payable to suppliers of approximately $500 million. The balance comprised of payments of employee termination of approximately $760 million and other current liabilities of approximately $388 million.

Cash Flows from Investing Activities

Net cash used in investing activities totaled $5,125 million for 2001, of which $3,524 million was invested in property, plant and equipment and $1,666 million represented deposits to the FIEM.

For the three-year period ended December 31, 2001, our capital expenditures were as follows:

	2001		2000		1999
	($ in millions)
Exploration and Production	$	507	$	2,208	$	2,555
Refining		2,809		175		398
Petrochemicals and others		208		102		88

	$	3,524	$	2,485	$	3,041

The following table sets forth our planned capital expenditures for the period 2002-2004:

	2002		2003		2004
	($ in millions)
Venezuela(1)	$	4,033	$	4,478	$	4,527
United States		509		589		707
Europe and Caribbean		165		156		154

	$	4,707	$	5,223	$	5,388

(1): Includes $386 million, $1,298 million and $1,588 million for gas projects.

Our capital expenditures in Venezuela for 2002 are as follows: $2,197 for exploration and production, $566 million for refining and marketing, $386 million for natural gas projects, $173 million for petrochemicals and others, and $711 for equity investments in our Orinoco Belt associations. Our anticipated capital expenditures for our international subsidiaries and affiliates are aimed toward compliance with increasingly stringent environmental laws affecting their operations.

We expect to meet our capital expenditure requirements primarily through internally-generated cash flows, financing in the international markets and withdrawal of our deposits with the FIEM.

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 is 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 year 2002. Beginning 2003, 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 2007.

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 the FIEM board of directors, within the established period, of compliance with established conditions. See note 3 to our consolidated financial statements, included under "Item 18. Financial Statements."

In June 2002, the Venezuelan government and the National Assembly authorized PDVSA to withdraw up to $2,445 million of the funds deposited with the FIEM for capital investments.

Cash Flows from Financing Activities

Consolidated net cash from financing activities totaled approximately $4,161 million, resulting primarily from borrowings of $1,509 million, payments of dividends in the amount of $4,862 million, capital lease payments of $127 million and debt repayments of $681 million.

As of December 31, 2001, PDVSA had an aggregate of $8,427 million of indebtedness outstanding that mature on various dates through 2031.

As of December 31, 2001, PDV Finance had an aggregate of $3,297 million of unsecured notes outstanding that matures on various dates through 2028.

In May 1998 and April 1999, PDVSA Finance issued $1,800 million and $1,000 million and Euro 200 million of unsecured notes, respectively, with due dates ranging from 2000 to 2028, and with annual interest rates ranging from 6.25% to 9.95%. PDVSA Finance used the proceeds from these notes to purchase from PDVSA Petróleo certain current and future accounts receivables generated from export sales of crude oil and refined products by PDVSA Petróleo.

In 2001, PDVSA Finance and Petróleos de Venezuela filed a shelf registration statement with the U.S. Securities and Exchange Commission for the offering from time to time of up to $1,500 million in aggregate principal amount of notes. Pursuant to this shelf registration statement, PDVSA Finance issued $500 million aggregate principal amount of senior notes on November 16, 2001 with an interest rate of 8.50%, payable quarterly. The notes mature on November 16, 2012. PDVSA Finance used the proceeds from the issuance of these notes to purchase from PDVSA Petróleo certain current and future accounts receivables generated from export sales of crude oil and refined products by PDVSA Petróleo.

As of December 31, 2001, PDV America had an aggregate of $1,911 million of indebtedness outstanding that matures on various dates through 2031.

In August 1993, PDV America issued $1,000 million principal amount of senior notes with interest rates ranging from 7.25% to 7.875% and with due dates ranging from 1998 to 2003. Interest on these notes is payable semiannually. The senior notes are guaranteed by Petróleos de Venezuela and Propernyn. In August 1998, PDV America repaid the $250 million 7.25% senior notes due August 1, 1998 with the proceeds received from the maturity of $250 million of mirror notes due to PDV America from PDVSA on July 31, 1998. On August 1, 2000, PDV America repaid $250 million 7.75% senior notes due August 1, 2000 with proceeds from the maturity of $250 million of mirror notes due to PDV America from PDVSA on July 31, 2000.

As of December 31, 2001, CITGO's bank credit facilities consist of a $400 million five-year revolving bank loan, a $150 million 364-day revolving bank loan and a $25 million 364-day revolving bank loan, all of which are unsecured and have various borrowing maturities. At December 31, 2001, $360 million was outstanding under these credit agreements. CITGO's other principal indebtedness consists of (i) $200 million in senior notes issued in 1996, (ii) $260 million in senior notes issued pursuant to a master shelf agreement with an insurance company, (iii) $57 million in private placement senior notes issued in 1991, (iv) $338 million in obligations related to tax exempt bonds issued by various governmental units and (v) $146 million in obligations related to taxable bonds issued by various governmental units. See note 11 to our consolidated financial statements, included under "Item 18. Financial Statements."

PDVMR has available borrowings under a $75 million revolving credit facility, committed through April 2002, of which $32 million was outstanding at December 31, 2001. Inventories and accounts receivable of PDVMR were pledged as collateral. The weighted average interest rate for this facility at December 31, 2001 was 2.5%. PDVMR cancelled this facility effective January 23, 2002. PDVMR's other indebtedness consists of $20 million in pollution control bonds. See note 11 to our consolidated financial statements, included under "Item 18. Financial Statements."

As of December 31, 2001, PDVSA Petróleo had an aggregate of $1,842 million of indebtedness outstanding that matures on various dates through 2028.

In June 1998, Cerro Negro Finance, Ltd. (a company 50% owned by PDVSA Cerro Negro, an indirect wholly owned subsidiary of Petróleos de Venezuela, and 50% owned by Mobil Cerro Negro, Ltd., an indirect wholly owned subsidiary of ExxonMobil) issued $600 million principal amount of senior notes with annual interest rates ranging from 7.33% to 8.03% and due dates ranging from 2009 to 2028. The senior notes are guaranteed by Petróleos de Venezuela and are being used to finance the development and construction of part of the facilities for the exploitation, production, transportation and upgrading of extra-heavy crude oil from reserves located in the Cerro Negro area of the Orinoco Belt. See "Item 4.B Business overview—Orinoco Belt Extra-Heavy Crude Oil Projects" and note 11 to our consolidated financial statements, included under "Item 18. Financial Statements."

In June 1999, PDVSA Cerro Negro obtained loans from a financial institution for $150 million, with LIBOR interest rates plus an additional annual interest rate ranging from 5.76% to 6.79%, due in 2002. The proceeds from these loans have been used to finance the exploration and production of crude oil from reserves located in the Cerro Negro area of the Orinoco Belt.

In 1999 and 1998, PDVSA Sincor (an indirect subsidiary of Petróleos de Venezuela), Total Fina and a subsidiary of Statoil entered into two lines of credit totaling $1,200 million and $1,500 million, respectively, with syndicates of international banks to finance the Sincor extra-heavy crude oil project. See "Item 4.B Business overview—Orinoco Belt Extra-Heavy Crude Oil Projects" and note 11 to our consolidated financial statements, included under "Item 18. Financial Statements."

Petróleos de Venezuela, Total and Statoil have guaranteed, on an individual basis, the amounts withdrawn by each of their subsidiaries until the completion of the construction phase of the project.

PDVSA Sincor's participation interest under the $1,200 million line of credit, in an aggregate amount equal to $456 million, was fully drawn down as of December 31, 2001. The amount borrowed was used to pay financing expenses and to cover cash requirements and operating expenses for the Sincor joint venture. Interest on this line of credit accrues at a fixed base rate for the first six months and at LIBOR beginning the seventh month and, for both periods, an additional annual interest ranging from 4.44% to 7.695% is also payable.

Approximately $1,175 million of the $1,500 million line of credit has been drawn down; of this amount, PDVSA Sincor's participation interest as of December 31, 2001 was approximately $447 million. Interest on this line of credit accrues at LIBOR, and additional annual interest ranging from 5.44% to 8% is also payable. See "Item 4.B Business overview—Orinoco Belt Extra-Heavy Crude Oil Projects" and note 11 to our consolidated financial statements, included under "Item 18. Financial Statements."

In 2001, PDVSA and its joint venture partners in the Hamaca project obtained a $470 million line of credit from a group of international banks and a $627 million line of credit from certain United States banks. Amounts borrowed under these loans are used for the construction of project facilities for the improvement of synthetic crude and production. In 2001, approximately $633 million was drawn down from these lines of credit at LIBOR ranging from 2.75% to 4.69% on $300 million and LIBOR ranging from 1.90% to 3.84% on $333 million. Corpoguanipa, S.A., our indirect wholly owned subsidiary, has a 30% participation interest in these lines of credit. See "Item 4.B Business overview—Orinoco Belt Extra-Heavy Crude Oil Projects" and note 11 to our consolidated financial statements, included under "Item 18. Financial Statements."

In September 2000, PDVSA Petróleo entered into a loan agreement with a group of Japanese banks headed by the Japan Bank for International Cooperation for a credit facility in yen equivalent to $500 million for use in the VALCOR project in Puerto La Cruz.

The following table summarizes future payments for PDVSA's contractual obligations at December 31, 2001.

Future Payments for PDVSA's Contractual Obligations
At December 31, 2001

	Total (MM$)	Less than 1 year	Years 2-3	Years 4-5	After 5 years
Long-Term Debt	8,427	1,000	1,590	1,213	4,624
Capital Lease Obligations	179	62	61	40	16
Operating Leases	1,400	130	226	103	941

Total Contractual Cash Obligations	10,006	1,192	1,877	1,356	5,581

In 2001, we declared and paid $4,774 million in dividends. At December 31, 2001, $198 million, corresponding to dividends declared in 2000, remain payable by us. See note 12 to our consolidated financial statements, included under "Item 18. Financial Statements."

On June 6, 2002, a cash dividend amounting to $1,533 million was declared (based on the exchange rate of Bs.1,147 to $1).

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 flow, 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. If it is not expected that an asset will be recovered through future cash flows, then the asset is written down to fair value. Fair value is generally determined from estimated discounted future net cash flows. Statement of Financial Accounting Standards No. 121 ("SFAS No. 121") requires that assets to be disposed of be reported at the lower of carrying amount or fair value, less disposal costs.

Environmental Expenditures

The costs to comply with environmental regulations are significant. Environmental expenditures incurred currently that relate to present 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 reviews 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.

New Accounting Standards

In July 2001, the Financial Accounting Standards Board (the "FASB") issued Statement of Financial Accounting Standards No. 141, "Business Combinations" ("SFAS No. 141"). SFAS No. 141 addresses financial accounting and reporting for business combinations and requires that all business combinations initiated after June 30, 2001 be accounted for under the purchase method. Use of the pooling of interests method is no longer permitted. The adoption of SFAS No. 141 will not impact PDVSA's financial position nor results of operations.

In July 2001, the FASB issued Statement of Financial Accounting Standards No. 142, "Goodwill and Other Intangible Assets" ("SFAS No. 142"). SFAS No. 142 addresses financial accounting and reporting for acquired goodwill and other in intangible assets, and requires that goodwill and intangible assets with an indefinite life no longer be amortized but, instead, be periodically reviewed for impairment. The provisions of SFAS No. 142 are fully effective for fiscal years beginning after December 15, 2001. However, certain provisions of SFAS No. 142 are applicable to goodwill and other intangible assets acquired in transactions completed after June 30, 2001. We believe that the adoption of SFAS No. 142 will not materially impact our financial position nor results of operations.

In June 2001, the FASB issued Statement of Financial Accounting Standards 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.

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.

PDVSA is required to, and plans to, adopt SFAS No. 143 on January 31, 2003. In order to accomplish this, PDVSA must identify all its legal obligations for asset retirement obligations, if any, and determine the fair value of these obligations as of the date of adoption of SFAS No. 143. The determination of fair value is a complex exercise, and PDVSA will need to gather market information and develop cash flow models in order to make this determination. Additionally, PDVSA will need to develop processes to track and monitor these obligations. Because of the effort necessary to comply with the adoption of SFAS No. 143, it is presently not practicable for PDVSA's management to estimate the impact of adopting SFAS No. 143. We have not determined the impact of SFAS No. 143 on our financial statements.

In August 2001, the FASB issued SFAS No.144 "Accounting for the Impairment or Disposal of Long-Lived Assets" ("SFAS No. 144"). SFAS No. 144, fully effective beginning January 1, 2002, addresses financial accounting and reporting for the impairment or disposal of long-lived assets. SFAS No. 144 requires that long-lived assets be 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 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. SFAS No. 144 requires companies to separately report discontinued operations and extends that reporting to a component of an entity that either has been disposed of (by sale, abandonment, or in a distribution to owners) or is classified as held for sale. Assets to be disposed of are reported at the lower of the carrying amount or fair value less costs to sell. We believe that the adoption of SFAS No. 144 will not materially impact our financial position nor results of operations.

5.C Research and development, patents and licenses

As of December 31, 2001, 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(p) 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 eleven members: a president, two vice presidents, five 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.

The President of Venezuela appointed the current members of our board of directors in April 2002. Our current directors and executive officers are:

Name	Age	Position with PDVSA	Date of Appointment
Alí Rodríguez Araque	64	President	2002
Jorge Kamkoff Miller	57	Vice President	2001
José Rafael Paz	51	Vice President	2002
Nelson Nava	49	Director	2002
Ludovico Nicklas	57	Director	2002
Hugo Hernández Rafalli	53	External Director	2002
Clara Coro	44	External Director	2002
Arnoldo Rodríguez Ochoa	61	External Director	2002

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

Alí Rodríguez Araque
President

Mr. Rodríguez graduated from the Central University of Venezuela in 1961 with a degree in Law. He also undertook studies in economics, specializing in the petroleum industry, and has been a member of study and analysis teams on mining and oil economics.

He was a member of Venezuela's Congress from 1983 to 1999 and was also president of the Chamber of Deputies' Energy and Mines Commission from 1994 to 1997. He was vice president of Congress' Energy and Mines Commission for the analysis and approval of reports on the oil opening master contract. From 1993 to 1999, he was a member of the National Energy Council and the Latin American Parliament's Energy Commission. Mr. Rodríguez was a member of President Chavez's Presidential Liaison Commission for Energy and Mines and was again elected to Congress, as senator for the Bolivar state, for the 1999-2004 period. He has published several articles on energy policy. His most recent article is "The privatization process in the Venezuelan oil industry," published in 1997.

In February 1999, Mr. Rodríguez was appointed Venezuela's Minister of Energy and Mines and was named president of the OPEC in 2000. In January 2001, he was elected secretary-general of the OPEC, and in April 2002 he was appointed President of Petróleos de Venezuela.

Jorge Kamkoff Miller
Vice President

Mr. Kamkoff graduated from the Central University of Venezuela in 1969 with a degree in Chemical Engineering. He joined the petroleum industry in 1970 with the Venezuelan Gulf Refining Company. Mr.Kamkoff held various supervisory and managerial positions at the Puerto La Cruz refinery, mainly in process engineering and refining operations, including Management and Projects Manager in petrochemicals coordination, Operations Manager and Manager of the Puerto La Cruz District. He also served as Refining General Manager at Corpoven, Advisor to Petróleos de Venezuela on relations with the U.S. Congress and the Venezuelan government in energy affairs and President of

PDVSA's Formation and Training Center (CEPET, now known as CIED). In 1990, Mr. Kamkoff was President of the National Ports Institute's Governing Council assisting in the decentralizing and privatization process of the Institute and, later, he was the President of the Restructuring Commission of the Venezuelan Institute of Social Insurance (IVSS).

In 1992, he was appointed director of PDV Marina and, in January 1998, he was named president of the PDV Marina Business Unit at the PDVSA Manufacturing and Marketing Division. In October 1999, Mr. Kamkoff became Executive Vice-President of PDVSA's Gas Division and, later, Vice-President of the Manufacturing and Marketing Division, now Refining, Supply and Commerce Division, of PDVSA. On March 15, 2001, Mr. Kamkoff was appointed Vice-President of Petróleos de Venezuela.

He has taken part in, and contributed actively to, the social development of several of Venezuela's communities and in various joint activities with the armed forces, including the PDV Marina-Navy, PDV Marina-Airforce, PDV Marina-National Guard agreements, and in Safety and National Defense operations with the Armed Forces. Mr. Kamkoff belongs to several national and international associations related to the energy sector.

José Rafael Paz
Vice President

Mr. Paz graduated from Louisiana State University in 1974 with a degree in Chemical Engineering. He began his professional career with Diamond Shamrock Company's Specialized Chemical Products Division in the United States.

In 1975, he joined Compañía Shell de Venezuela, later known as Maraven, S.A., as processes engineer at the Cardón refinery, where he later held various technical, supervisory and managerial positions in the areas of processes, conversion, supply, operations and technology.

In 1991, he was appointed general manager of Maraven's Internal Market Division and, in 1994, was transferred to Pequiven, where he was business manager of the Olefins and Plastics Business Unit. Mr. Paz then served as director, Vice-President and, later, President of Pequiven from October 2001 until April 2002, when he was appointed Vice-President of Petróleos de Venezuela.

Mr. Paz has also held executive positions in other companies in the chemicals field, such as president of Productos Especiales C.A. (Proesca), president of Comercializadora de Químicos y Petroquímicos (COPEQUIM), president of the Grupo Zuliano, president of Metanol de Oriente (Metor) and principal director of International Petrochemical Holding Ltd. (IPHL).

Ludovico Nicklas
Director

Mr. Nicklas graduated from Innsbruck University, Austria, in 1970 with a degree in Geology. He joined the oil industry in 1970 with Creole Petroleum Corporation, where he held several technical and supervisory positions in the divisions of Development Geology, Well Repairs, and Exploration and Production Geology.

Mr. Nicklas has served as Petróleos de Venezuela's Offshore Operations Manager in the Eastern Division, coordinator of the Geology Planning Section, and Lagoven's Production manager. He was Intevep's manager of Earth Sciences Division in 1985, returning to Lagoven in 1987, where he served as assistant manager of Informatics, assistant manager of the Eastern Division (1990), manager in charge of Major Projects (1992) and Corporate Planning manager (1994).

He was subsequently appointed manager of the Petróleos de Venezuela's Exploration and Production Division in 1996, and managing director of Exploration Division in 1998. In 2001, he was

named executive director of Exploration, Production and Upgrading, a position which he held until his current appointment as director of Petróleos de Venezuela.

Nelson Nava Hernández
Director

Mr. Nava graduated from the University of Zulia in 1975 with a degree in Chemical Engineering. He obtained a Master's degree in Management from the Massachusetts Institute of Technology in 1993.

Upon graduation in 1975, he joined Creole Petroleum Corporation in the Gas Engineering Organization at Tía Juana, Zulia state. He has held several technical, supervisory and managerial positions in General Engineering and Major Gas Compression Projects, in the various areas of Lagoven's Western Division.

In 1986, he was transferred to the Production department in Caracas, where he held the position of Production Installations Planning manager until the end of 1987. In February 1988, he was appointed Technical Services manager in the Orinoco Project Organization, working on the commercial development of Orimulsion®.

In 1990, Mr. Nava was assigned to the Lagoven Eastern Division as Technical Manager. In 1993, he was appointed assistant manager of Corporate Finance, later becoming manager of this department.

In 1997, he was appointed manager of the PDVSA Information Services Division, being named corporate manager of Information Technology in January 1998. In July of that year, he was named Managing Director of Information Technology (Cybernetics) in the PDVSA Services Division. He was seconded in October 1999 to PDVSA Gas as Managing Director of Development and New Business.

In March 2001, he was named President of PDVSA Gas, a position which he held until his appointment as director of Petróleos de Venezuela in April 2002.

Arnoldo Rodríguez Ochoa
External Director

Mr. Rodríguez is a retired army General who graduated from the Military Academy of Venezuela in 1961 with a Bachelor of Science in Military Sciences and Arts.

Mr. Rodríguez specializes in Staff and National Security and Defense and has attended the following courses: Basic and Integral Armament, Basic Command and Staff and Higher Command and Staff in Argentina. He also completed the Higher National Security and Defense Course in the Institute of Higher Studies of National Defense of Venezuela.

Mr. Rodríguez has served as the Head of the Supply Department of the Armament Service of the Army; Head of the Payment Processing Department in the Army Finance Division; Army IT Director; Sub-director of the Military Academy of Venezuela; Army Acquisitions Director; Director of the Technical Army School; Chief of Staff and 2^nd Commanding Officer of the Fourth Division of Infantry and Garrison of Aragua State; Executive Vice President of Compañía Anónima Venezolana de Industrias Militares (CAVIM) (Venezuelan Company of Military Industries); Commanding Officer of the First Division of Cavalry and Garrison of Guárico State with jurisdiction in Apure State. He was the Executive Secretary of the Consejo Nacional de Seguridad y Defensa (SECONASEDE) (National Security and Defense Council) and was commissioned by the President of Venezuela as the President of the Fundación para el Programa Alimentario Materno Infantil (PAMI) (Foundation for the Child-Maternal Food Program).

In the private sector, he has been a principal director and President of the Cámara Nacional del Gas Natural Vehicular (National Chamber of Vehicle Natural Gas). He was also a principal director of the company Importaciones Gasmóvil 91, C.A., engaged in vehicle conversion to VNG. He has received

numerous awards during his professional career. On August 9, 1999, he was appointed as an external director of Petróleos de Venezuela, position which was ratified on March 15, 2001 and in February 2002.

Clara Coro Fernández
External Director

Ms. Coro graduated from the Central University of Venezuela in 1981 with a degree in Chemical Engineering. Ms. Coro also completed her postgraduate studies at the Simón Bolívar University, specializing in Hydrocarbons Economy Management.

She joined the Ministry of Energy and Mines in its Hydrocarbons Planning and Economy Division in September 1982. In 1990, she was appointed head of the International Markets Division and in 1994 was also placed in charge of the Ministry's Economy and Finance Division. In 2000, she became director of Hydrocarbons Planning and Economy. In November 2001, Ms. Coro was named Venezuela's national representative to the Economic Commission of the OPEC.

In February 2002, she was appointed external director of Petróleos de Venezuela.

Hugo Hernández Raffalli
External Director

Mr. Hernández graduated from the University of Zulia with a degree in Law. He has been president of the electrical contractor Construcciones Eléctricas e Industriales C.A. (CEICA), and of the managing boards of Siderúrgica Occidental, C.A. (SIDEROCA) and C.A. Venezolana Procesadora de Acero (PROACERO). He was also a principal director on the boards of C.A. Energía Eléctrica de Venezuela (Enelven), Las Américas Construction Company, Suramericana de Constructores, and Inversiones Turísticas, C.A.

Mr. Hernández was also president of the Venezuelan Petroleum Chamber's Zulia chapter from 1994 to 2000, board director of the Chamber between 1996 and 1998, when he was also elected first vice president. In 2000, he was elected president of the Venezuelan Petroleum Chamber for the 2000-2002 period.

Mr. Hernández is also a member of the Maracaibo Chamber of Commerce, of the State of Zulia's Industry Chamber and of the Fedecámaras Energy Commission. He was a member of the Presidential Commission charged with analyzing the Organic Law on Hydrocarbons bill and has represented the Venezuelan oil sector as a speaker at international events.

In April 2002, he was appointed external director of Petróleos de Venezuela.

6.B Compensation

For the year ended December 31, 2001, the aggregate amount paid by Petróleos de Venezuela as compensation to its directors and executive officers for services in all capacities was approximately $2.4 million (based on the 2001 average exchange rate of Bs/$ 722.01).

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 location of employment for 2001, 2000 and 1999 are as follows:

Year	Total Number of Employees	In Venezuela	Abroad
2001	46,425	40,945	5,480
2000	46,920	41,462	5,458
1999	47,750	42,267	5,483

Our productivity has increased during the last six years from 20.13 barrels of crude oil produced per year per employee in Venezuela in 1995 to 27.58 barrels of crude oil produced per year per employee in Venezuela in 2001. Our total number of employees in Venezuela during this six-year period declined by approximately 9%. 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%) or the recently created national union 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.

The term of our two-year collective bargaining agreement with our operating subsidiaries is scheduled to expire in October 2002. The collective bargaining agreement currently in effect provides that proposals for a new agreement may be submitted beginning May 21, 2002. We anticipate that this agreement will be extended after negotiations.

From May 28, 2001 through May 30, 2001, there was a nationwide labor strike. A satisfactory agreement was reached on May 31, 2001 with the objective of achieving the continuity of our operations.

For our non-unionized workers, we adopted a new social compensation program. This program introduced a variable factor in 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.

6.E Share ownership

Petróleos de Venezuela's common stock is not publicly traded and, as of December 31, 2001, 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 recommendation 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 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 policies and 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 recently adopted 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 its minority interests in various exploration and exploitation joint venture arrangements.

Our operations and activities are subject to the Nationalization Law and its regulations, our charter and by-laws, 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 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.

The Nationalization Law provides that every activity related to the exploration, exploitation, manufacture, refining, transportation by special means, storage and domestic and foreign sales of hydrocarbons and their derivatives is reserved to the State, acting directly or through State-owned entities. The Nationalization Law also provides that the State or entities created pursuant to the Nationalization Law may enter into operating agreements with third parties and, to the extent approved by the Venezuelan National Assembly (formerly, the Congress of Venezuela), enter into association agreements with private sector entities. Petróleos de Venezuela was created as the entity that coordinates monitors and controls all operations related to hydrocarbons.

The Nationalization Law contains a number of articles intended to promote commercial business practices. Article 3 specifies that our operating companies shall pursue the most efficient means to commercialize hydrocarbons, establishing the legal basis for our international business ventures. Article 6 permits our operating subsidiaries to exist as incorporated entities operating under the Commercial Code and requires that 10% of our operating subsidiaries' net revenues from exports of crude oil be paid to us to be applied for reinvestment in the development of the Venezuelan hydrocarbons industry. Article 7 establishes that the state-owned companies will continue to operate under the Hydrocarbons Law that previously regulated the activities of foreign concessionaires and established production tax levels and will not be subject to state and municipal taxes. Article 8 stipulates that officers and employees of Petróleos de Venezuela and its operating affiliates are not public employees, thereby permitting PDVSA to develop, train, and compensate human resources in accordance with industry standards.

In January 2002, the new Hydrocarbons Law came into effect, superseding the Hydrocarbons Law of 1943, the Law of Assets Subject to Reversion in Hydrocarbon Concessions of 1971, Law that Reserves for the State the Exploitation of the Internal 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 Internal 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 regulations dated June 2000. See note 1(a) to our consolidated financial statements, included under "Item 18. Financial Statements."

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 us. 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 14 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 accountants 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 15 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, where the matter is still pending. On September 19, 2000, the Court of International Trade (per Judge Aquilino) 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 within 60 days. 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 is awaiting review by the Court of International Trade (per Judge Pogue).

Petróleos de Venezuela and its Venezuelan subsidiaries and joint ventures are involved in various lawsuits and claims arising in the normal course of their businesses. Information regarding legal proceedings affecting PDV America and its subsidiaries is set forth under "Item 3. Legal proceedings" in PDV America's 2001 annual report on Form 10-K, incorporated herein by reference, and information regarding legal proceedings affecting Propernyn and its non-U.S. subsidiaries is set forth under "Item 8.A.7. Legal Proceedings" in Propernyn's 2001 annual report on Form 20-F, filed with the U.S. Securities and Exchange Commission.

LYONDELL-CITGO has commenced an action against Petróleos de Venezuela and PDVSA Petróleo in the Southern District of New York. LYONDELL-CITGO is seeking damages and specific performance for alleged breaches of the crude oil supply agreement, dated May 5, 1993, between LYONDELL-CITGO and Lagoven (subsequently merged into PDVSA Petróleo) and the supplemental supply agreement, dated May 5, 1993, between LYONDELL-CITGO and Petróleos de Venezuela. LYONDELL-CITGO alleges that Petróleos de Venezuela wrongfully declared force majeure events and reduced shipments of extra-heavy crude oil to LYONDELL-CITGO. See "Item 4.B Business overview—Refining and Marketing—United States."

The challenged reductions in the shipment of extra-heavy crude oil to LYONDELL-CITGO were made pursuant to instructions received from the Ministry of Energy and Mines. In accordance with the contract, PDVSA Petróleo and Petróleos de Venezuela declared a force majeure when the Ministry and Energy and Mines' instructions required them to reduce production.

Since the underlying cause of action is a challenge to the Venezuelan government's ability to limit crude oil production, Petróleos de Venezuela and PDVSA Petróleo filed a motion to dismiss based upon the Act of State doctrine on May 31, 2002. LYONDELL-CITGO's response papers are due on June 17, 2002.

We are not involved (whether as defendant or otherwise) in and, other than as described above, we have no knowledge of any threat of, any litigation, arbitration, or administrative or other proceeding

which management believes will have a material adverse effect on our consolidated financial position or results of operations.

Item 9. The Offer and Listing

9.A Offer and listing details

Our guarantee of the PDV America's notes are not traded separately from such senior notes. These notes are traded principally on the New York Stock Exchange, and are also listed on the Luxembourg Stock Exchange.

PDVSA Finance's senior notes are solely obligations of PDVSA Finance and are not obligations of, or guaranteed by, Petróleos de Venezuela. The 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.

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 2001, our foreign exchange inflows totaled $27,951 million, while outflows totaled $9,713 million.

10.E Taxation

Under current Venezuelan tax law, no tax is imposed by Venezuela, by reason of withholding or otherwise, on payments made by (1) PDV America pursuant to its senior notes, (2) Propernyn pursuant to its obligations under its guarantee of PDV America's notes, (3) PDVSA pursuant to its obligations under its guarantee of PDV America' notes or (4) PDVSA pursuant to the notes (the "Mirror Notes")

issued to PDV America at the time of the original issuance of the senior notes issued by PDV America, except for the application of a Venezuelan withholding tax on interest payments under the Mirror Notes.

The PDV America' notes, the related indenture and Mirror Notes contain gross-up provisions for certain Venezuelan and other taxes, including the withholding tax referred to in clause (4) of the preceding paragraph.

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 ratification instruments on December 30, 1999. As a result, the treaty was fully in force in 2000 and 2001.

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, 2001, 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, 2001, for commodity derivatives, and includes futures purchased and futures sold.

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	2002	1.647	37	33
	Futures Sold	2002	2.397	49	49
	OTC Swaps (Pay Float/Receive Fixed)(3)	2002	2	—	—
	OTC Swaps (Play Fixed/Receive Float)(3)	2002	1	—	—
	Forward Purchase Contracts	2002	6.651	128	132
	Forward Sale Contracts	2002	6.261	124	125
Refined Products	Futures Sold	2002	450	12	11
Unleaded	Futures Purchased	2002	994	25	25
	Futures Sold	2002	332	8	8
	Forward Purchase Contracts	2002	4.095	96	94
	Forward Sale Contracts	2002	3.148	71	73
Distillates	Futures Purchased	2002	1.483	43	35
	Futures Purchased	2003	94	2	2
	Futures Sold	2002	943	25	22
	OTS Options Purchased	2002	10	—	—
	OTS Options Sold	2002	10	—	—
	Forward Purchase Contracts	2002	30	—	—
	Forward Sale Contracts	2002	30	—	—
Natural Gas	Futures Sold	2002	55	2	1
	OTC Options Sold	2002	20	—	—

(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, 2000

Commodity	Derivative	Maturity	Volumes of Contracts(1)	Contract Value(2)	Market Value
				($ in millions)	($ in millions)
Crude Oil	Futures Purchased	2001	7.188	431	713
	Futures Sold	2001	7.640	216	179
Refined Products	Futures Sold	2001	92	3	3
Unleaded	Futures Purchased	2001	25	0.8	0.8
Heating Oil(1)	Futures Purchased	2001	1.533	53.9	55.9
	Futures Purchased	2002	16	0.5	0.5
	Futures Sold	2001	579	21.2	21.7
	OTS Swaps (Pay Fixed/Receive Float)	2001	9	—	0.1
	OTS Swaps (Pay Fixed/Receive Fixed)	2001	500	—	0.5

(1): Thousand barrels.
(2): Weighted average price.

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, 2001, 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, 2001 and 2000

Variable Rate Index	Expiration Date	Fixed Rate Paid	Notional Principal Amount
		%	($ in millions)
J. J- Kenny	February 2005	5.30	12
J. J- Kenny	February 2005	5.27	15
J. J- Kenny	February 2005	5.49	15

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 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, 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

Short-Term and Long-Term Debt
at December 31, 2000

Expected Maturities	Fixed Rate Debt	Average Fixed Interest Rate	Variable Rate Debt	Average Variable Interest Rate
	($ in millions)	%	($ in millions)	%
2001	389	7.93	207	7.96
2002	711	7.65	160	6.95
2003	1,073	7.58	172	5.76
2004	370	7.31	196	5.54
2005	413	7.93	147	5.12
Thereafter	2,594	7.97	1,167	6.11

Total	5,550	7.73	2,049	6.07

Fair Value	7,270

Foreign Exchange Risk

The dollar is our functional 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, 2001
Currency	At December 31, 2001
Currency	Assets	Liabilities	Net
	($ in millions)
Venezuelan Bolivars	5,294	6,640	(1,346	)
Euros	483	—	483
German marks	—	178	(178	)
Other currencies	12	196	(184	)

	At December 31, 2001
Currency	At December 31, 2001
Currency	Assets	Liabilities	Net
	($ in millions)
Venezuelan Bolivars	5,037	6,452	(1,415	)
Euros	618	—	618
German Marks	—	189	(189	)
Other currencies	13	178	(165	)

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
Yenes		84

At December 31, 2000, we had approximately $242 million of short-term and long-term debt, denominated in currencies other than dollars, as summarized below:

Currency		At December 31, 2000
		($ in millions)
Bolivars		30
Euros		212

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-54 incorporated herein by reference.

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

		Page
Independent Auditors' Report of KPMG Alcaraz Cabrera Vázquez (a member firm of KPMG International)		F-1
Independent Auditor's Report of Deloitte & Touche LLP		F-2
Report of the Independent Accountants, Espiñeira, Sheldon y Asociados (a member firm of PricewaterhouseCoopers L.L.P.)		F-3
Consolidated Balance Sheet at December 31, 2001 and 2000		F-4
Consolidated Statement of Income for the years ended December 31, 2001, 2000 and 1999		F-5
Consolidated Statement of Stockholder's Equity for the years ended December 31, 2001, 2000 and 1999		F-6
Consolidated Statement of Cash Flows for the years ended December 31, 2001, 2000 and 1999		F-7
Notes to the Consolidated Financial Statements		F-8

Item 19. Exhibits

Exhibit No:		Description
Exhibit 10.1		Consent of KPMG Alcaraz Cabrera Vázquez (a member firm of KPMG International).
Exhibit 10.2		Consent of Espiñeira, Sheldon y Asociados (a member firm of PricewaterhouseCoopers L.L.P.).
Exhibit 10.3		Consent of Deloitte & Touche LLP.
Exhibit 99.1		Annual Report on Form 20-F of PDVSA Finance Ltd. for the year ended December 31, 2001 as first filed with the U.S. Securities and Exchange Commission (Commission file No. 333-09678) on June 14, 2002 (incorporated herein by reference).
Exhibit 99.2		Annual Report on Form 10-K of PDV America, Inc. for the year ended December 31, 2001 as first filed with the U.S. Securities and Exchange Commission (Commission file No. 001-12138) on March 29, 2002 (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.

	PETROLEOS DE VENEZUELA, S.A.
	By:	/s/ JORGE KAMKOFF Name: Jorge Kamkoff Title: Vice President
Date: June 14, 2002

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 (Km2).
4D		Three dimensional seismic lines (Km2) 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.

A-2

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.
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.

A-3

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-4

Independent Auditors' Report

The Stockholder and Board of Directors
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, 2001 and 2000, and the related consolidated statements of income, stockholder's equity and cash flows for the years then ended. 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 12% as of December 31, 2001 and 2000 and total revenues constituting 43% and 42%, for the years ended on those dates, 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, 2001 and 2000, 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.

KPMG Alcaraz Cabrera Vázquez

/s/ Gustavo González Brache
Gustavo González Brache
Public Accountant
C.P.C. N^o 476

Caracas, Venezuela
March 8, 2002

F-1

INDEPENDENT AUDITORS' REPORT

To the Board of Directors and Shareholder of
PDV Holding, Inc.:

We have audited the accompanying consolidated balance sheets of PDV Holding, Inc. and subsidiaries (the "Company") as of December 31, 2001 and 2000, 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, 2001 and 2000, 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
March 8, 2002

F-2

REPORT OF INDEPENDENT ACCOUNTANTS

To the Shareholder and Board of Directors of
Petróleos de Venezuela S.A. (PDVSA)

In our opinion, based upon our audit and the reports of the other independent accountants, the accompanying consolidated statements of income, stockholder's equity and cash flows, present fairly, in all material respects, the results of operations of Petróleos de Venezuela S.A. (PDVSA) and its subsidiaries (PDVSA or the Company) and their cash flows for the year ended December 31, 1999, in conformity with accounting principles generally accepted in the United States of America. 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 audit. We did not audit the financial statements of certain subsidiaries and affiliates which in the aggregate reflect total revenues which represent approximately 44% of consolidated revenues for the year ended December 31, 1999. Those statements were audited by other independent accountants whose reports thereon have been furnished to us, and our opinion expressed herein, insofar as it relates to the amounts included for such subsidiaries and affiliates, is based solely on the reports of other independent accountants. We conducted our audit of these statements in accordance with generally accepted auditing standards in Venezuela, which are substantially similar to those in the United States of America. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatements. 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 audit and the reports of the other independent accountants provide a reasonable basis for our opinion expressed above. We have not audited the consolidated financial statements of Petróleos de Venezuela, S.A. (PDVSA) and its subsidiaries for any period subsequent to December 31, 1999.

ESPIÑEIRA, SHELDON Y ASOCIADOS

/s/ Carlos Hugo Odremán
Carlos Hugo Odremán

CPC 463

Caracas, Venezuela
March 10, 2000

F-3

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

Consolidated Balance Sheets

(Expressed in millions of U.S. dollars)

			December 31
			2001	2000
Assets
Current assets:
	Cash and cash equivalents		925	3,257
	Notes and accounts receivable		3,280	4,435
	Inventories		2,208	2,175
	Recoverable value added tax		2,150	1,475
	Prepaid expenses and other		1,087	788
	Deferred income tax		342	657

		Total current assets	9,992	12,787
Restricted cash			4,072	2,406
Investments in nonconsolidated investees			2,819	2,702
Property, plant and equipment, net			37,230	36,330
Deferred income tax			301	502
Other assets			3,128	2,873

			57,542	57,600

Liabilities and Stockholder's Equity
Current liabilities:
	Accounts payable to suppliers		2,584	3,084
	Short-term debt		1,000	596
	Taxes payable		1,185	1,598
	Employee termination, pension benefits and other postretirement benefits		679	320
	Other liabilities		2,484	2,614

		Total current liabilities	7,932	8,212
Long-term debt			7,427	7,003
Capital lease obligations			117	184
Employee termination, pension benefits and other postretirement benefits			3,167	2,807
Deferred income tax			834	637
Other liabilities			800	608

		Total liabilities	20,277	19,451
Minority interests			167	217
Stockholder's equity (see accompanying statement)			37,098	37,932

			57,542	57,600

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

F-4

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

Consolidated Statements of Income

(Expressed in millions of U.S. dollars)

			Years ended December 31
			2001		2000		1999
Sales of crude oil and products:
	Exports and international markets		42,682		49,780		30,369
	In Venezuela		1,701		2,230		1,450
Petrochemical and other sales			1,403		1,224		781
Equity in earnings of nonconsolidated investees			464		446		48

			46,250		53,680		32,648

Costs and expenses:
	Purchases of crude oil and products		18,228		19,759		10,959
	Operating expenses		10,882		10,010		8,532
	Exploration expenses		174		169		118
	Depreciation and depletion		2,624		3,001		2,821
	Selling, administrative and general expenses		1,853		1,256		1,192
	Production and other taxes		3,760		4,986		3,008
	Financing expenses		509		672		662
	Other expense, net		456		848		6

			38,486		40,701		27,298

		Income before income tax and minority interests	7,764		12,979		5,350
Provision for income tax			(3,766	)	(5,748	)	(2,521	)
Minority interests			(5	)	(15	)	(11	)

		Net income	3,993		7,216		2,818

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

F-5

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

Consolidated Statements of Stockholders' Equity
Years ended December 31, 2001, 2000 and 1999

(Expressed in millions of U.S. dollars)

				Deficit
			Capital stock	Legal reserves and other		Accumulated losses		Accumulated other comprehensive income		Total
Balances at December 31, 1998			39,094	7,567		(14,702	)	(196	)	31,763
Comprehensive income:
	Net income 1999		—	—		2,818		—		2,818
	Change in additional minimum pension liability		—	—		—		32		32

		Total comprehensive income								2,850

Transfer to reserves			—	(10	)	10		—		—
Dividends			—	—		(1,719	)	—		(1,719	)

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		—	—		—		(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		—	—		—		(53	)	(53	)

		Total comprehensive income								3,940

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

Balances at December 31, 2001			39,094	7,982		(9,601	)	(377	)	37,098

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

F-6

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

Consolidated Statements of Cash Flows

(Expressed in millions of U.S. dollars)

					Years ended December 31
					2001		2000		1999
Cash flows from operating activities:
	Net income				3,993		7,216		2,818
	Adjustment to reconcile net income to net cash provided by operating activities:
		Depreciation and depletion			2,624		3,001		2,821
		Deferred income tax			603		(155	)	(82	)
		Provision for employee termination, pension benefits and other postretirement benefits			1,479		2,125		823
		Equity in earnings of nonconsolidated investees			(464	)	(446	)	(48	)
		Dividends received from nonconsolidated investees			282		148		126
		Change in operating assets:
			Notes and accounts receivable		1,155		(615	)	(1,627	)
			Inventories		(33	)	(364	)	11
			Recoverable value added tax		(675	)	(554	)	(624	)
			Prepaid expenses and other assets		(554	)	(1,471	)	131
		Change in operating liabilities:
			Accounts payable to suppliers		(500	)	614		529
			Taxes payable and dividends payable, accruals and other short-term liabilities		(388	)	1,001		360
			Payments of employee termination, pension benefits and other postretirement benefits		(760	)	(1,106	)	(666	)
			Other liabilities		192		191		61

				Net cash provided by operating activities	6,954		9,585		4,633

Cash flows from investing activities:
	Capital expenditures, net				(3,524	)	(2,485	)	(3,041	)
	Increase in restricted cash				(1,666	)	(2,191	)	(215	)
	Net change in investments				65		16		(70	)

				Net cash used in investing activities	(5,125	)	(4,660	)	(3,326	)

Cash flows from financing activities:
	Proceeds from issuance of debt				1,509		438		2,388
	Debt repayments				(681	)	(1,349	)	(1,567	)
	Payments of capital lease obligations				(127	)	(104	)	(15	)
	Dividends paid				(4,862	)	(1,732	)	(1,719	)

				Net cash used in financing activities	(4,161	)	(2,747	)	(913	)

				Net (decrease) increase in cash and cash equivalents	(2,332	)	2,178		394
	Cash and cash equivalents at beginning of year				3,257		1,079		685

	Cash and cash equivalents at end of year				925		3,257		1,079

SUPPLEMENTAL DISCLOSURE:
	Cash paid during the year for:
		Interest, net of capitalized amounts			699		761		846
		Income tax			3,443		4,955		2,176

	Non cash activities:
		Tax certificates applied against:
			Income tax payable		84		255		22
			Dividends payable		—		—		1,291

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

F-7

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

Notes to Consolidated Financial Statements

December 31, 2001 and 2000

(1)

Operations and Summary of Significant Accounting Policies

(a): Operations

Petróleos de Venezuela, S. A. and subsidiaries (PDVSA or the Company) is 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 internal 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 is 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.

(b): Basis of Presentation

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 (U.S. GAAP). The main economic operating environment of PDVSA consists of the international markets for crude oil

F-8

and products. The U.S. dollar (dollar or $) is the functional currency for PDVSA, since a significant portion of the Company's revenues and long-term debt, as well as the majority of costs, expenses and investments are denominated in dollars.

The financial statements of the Venezuelan subsidiaries, whose accounting records are maintained in bolivars (Bs), have been remeasured into dollars for purposes of consolidation. Adjustments arising from the remeasurement of the financial statements to dollars are included in the consolidated statement of income in other expense, net, and are not significant.

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.

(c): Consolidation

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 purposes 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 wholly owned by PDV America. Significant balances and transactions between consolidated subsidiaries have been eliminated in consolidation.

Investments between 20% and 50% in nonconsolidated investees are accounted for using the equity method. Any excess of acquisition cost over the underlying net assets is amortized over a maximum of forty years, based upon the estimated useful lives of the investees' assets. Furthermore, an evaluation is made on whether the book value of the referred excess cost is recoverable (see note 1(i) to the consolidated financial statements). Investments of less than 20% are recorded at the lower of cost or market value, and dividends from these companies are included in income when declared.

PDVSA through its subsidiaries PDVSA Cerro Negro, S. A. (PDVSA Cerro Negro), PDVSA Sincor, S. A. (PDVSA Sincor) y 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.

(d): Transactions and Balances in Foreign Currency

Transactions in foreign currency are recorded at the exchange rate on the date of the transaction. See note 2 to the consolidated financial statements for the foreign exchange

F-9

agreement with the Central Bank of Venezuela (BCV). PDVSA has the following monetary assets and liabilities denominated in currencies other than the dollar which are converted to dollars at the prevailing exchange rate at the balance sheet date (expressed in millions of dollars):

		December 31
		2001		2000
Monetary assets:
	Bolivars	5,294		5,037
	Euros	483		618
	Other currencies	12		13

		5,789		5,668

Monetary liabilities:
	Bolivars	6,640		6,452
	Euros	178		189
	Other currencies	196		178

		7,014		6,819

	Net monetary liability position, see note 17 to the consolidated financial statements	(1,225	)	(1,151	)

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

	December 31
	2001	2000	1999
Exchange rates at year-end	770.09	698.23	647.53
Average annual exchange rates (Bs/$1)	722.01	679.80	609.29
Interannual increments in the exchange rate (%)	10.29	7.83	14.98
Interannual increments in the CPI (%)	12.29	13.43	20.02

(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.

F-10

(g): Property, Plant and Equipment

Property, plant and equipment is stated at cost, less losses due to impairment (see note 1(i) to the consolidated financial statements). 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 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.

(h): Depreciation and Depletion

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 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.

(i): Impairment of Long-Lived Assets and Long-Lived Assets to be Disposed of

PDVSA reviews 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. If it is not expected that an asset will be recovered through future cash flows, then the asset is written down to fair value. Fair value is generally determined from estimated discounted future net cash flows. Statement of Financial Accounting Standards No. 121 (SFAS No. 121) requires that assets to be disposed of be reported at the lower of carrying amount or fair value, less disposal costs.

(j): 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

F-11

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). The subsequent realization of this benefit does not affect income.

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 was 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 occur 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 will be recognized as realized.

(k): Accrual for Employee Termination and Pension 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.

In October 2000 PDVSA executed its current collective labor contract introducing improved salaries and benefits for its contractual workers. At that same date, 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.

In addition to pension benefits, PDVSA provides certain health care and life insurance benefits to eligible employees upon retirement; this liability is accrued using actuarial methods over the active service lives of the employees.

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(l): Other Postretirement Benefits

PDVSA provides other benefits to its eligible former employees, such as disability payments, payments in lieu of salaries and wages and other social benefits. This liability is accrued over the active service lives of employees.

(m): Commodity and Interest Rate Derivatives

Beginning January 1, 2001, the Company adopted Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities" ("SFAS No. 133"). 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 year ended December 31, 2001, were not significant.

Prior to the adoption of SFAS No. 133 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. See note 10 to the consolidated financial statements.

(n): Environmental Expenditures

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.

(o): Research and Development Costs

Research and development costs are expensed when incurred. In 2001, 2000 and 1999, amounts charged to expense for research and development activities amounted to $41 million, $28 million and $39 million, respectively.

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(p): Comprehensive Income

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

(q): 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.

(r): Reclassifications

Certain reclassifications in the financial statements from previous years have been made for comparative purposes with the 2001 classifications.

(s): 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 BCV, available on a current basis, which at December 31, 2001, 2000 and 1999 amounted to $87 million, $1,995 million and $57 million, respectively.

(t): New Accounting Standards

In July 2001, the FASB issued Statement of Financial Accounting Standards No. 142, "Goodwill and Other Intangible Assets" ("SFAS No. 142"). SFAS No. 142 addresses financial accounting and reporting for acquired goodwill and other in intangible assets, and requires that goodwill and intangible assets with an indefinite life no longer be amortized but, instead, be periodically reviewed for impairment. The provisions of SFAS No. 142 are fully effective for fiscal years beginning after December 15, 2001. However, certain provisions of SFAS No. 142 are applicable to goodwill and other intangible assets acquired in transactions completed after June 30, 2001. Management considers that the adoption of SFAS No. 142 will not materially impact PDVSA's financial position nor results of operations.

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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.

PDVSA is required to, and plans to, adopt SFAS No. 143 on January 1, 2003. In order to accomplish this, PDVSA must identify all its legal obligations for asset retirement obligations, if any, and determine the fair value of these obligations as of the date of adoption of SFAS No. 143. The determination of fair value is a complex exercise, and PDVSA will need to gather market information and develop cash flow models in order to make this determination. Additionally, PDVSA will need to develop processes to track and monitor these obligations. Because of the effort necessary to comply with the adoption of SFAS No. 143, it is presently not practicable for PDVSA's management to estimate the impact of adopting SFAS No. 143. The Company has not determined the impact on its financial statements that may result from the adoption of SFAS No.143.

In August 2001, the FASB issued SFAS No. 144 "Accounting for the Impairment or Disposal of Long-Lived Assets" (SFAS No. 144). SFAS No. 144 addresses financial accounting and reporting for the impairment or disposal of long-lived assets. This Statement requires that long-lived assets be 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 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. SFAS No. 144 requires companies to separately report discontinued operations and extends that reporting to a component of an entity that either has been disposed of (by sale, abandonment, or in a distribution to owners) or is classified as held for sale. Assets to be disposed of are reported at the lower of the carrying amount or fair value less costs to sell. The Company is required to adopt SFAS No. 144 on January 1, 2002. Management considers that the adoption of SFAS No. 144 will not materially impact PDVSA's financial position nor results of operations.

(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, which approximates the market 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, which approximates the market 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.

(3): Restricted Cash

Restricted cash includes (expressed in millions):

	December 31
	2001	2000
Macroeconomic Stabilization Investment Fund (FIEM)	4,072	2,406
Funds for extra-heavy crude oil project in the Orinoco Belt	109	58
Liquidity Accounts of PDVSA Finance	96	88

	4,277	2,552
Less current portion, included in prepaid expenses and other	205	146

	4,072	2,406

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 is 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 addition to deposits based on export sales, PDVSA is required to deposit income derived from bonuses paid by private companies selected to participate in the bidding processes related to the oil opening, initial bonuses and those related to the net profitability of the projects and the participation of the State in the results from risk exploration in new areas, net of the respective taxes.

In October 2001, the Venezuelan Government introduced reforms to the FIEM Law and, among other changes, suspended the contributions for the last quarter of 2001 and the year 2002. Beginning 2003, 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 2007.

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

A summary of the accumulated contributions due by PDVSA to the FIEM follows (expressed in millions):

	December 31
	2001	2000
Contribution to the FIEM	4,072	2,406
Unpaid contributions	420	624

Contributions generated	4,492	3,030

At December 31, 2001 and 2000, there are contributions pending payment to the FIEM for $420 million and $624 million, corresponding to the third quarter of 2001 and the last quarter of 2000, respectively.

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(4): Notes and Accounts Receivable

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

	December 31
	2001	2000
Trade	2,506	3,968
Related parties (see note 14 to the consolidated financial statements)	440	281
Other	383	215

	3,329	4,464
Less allowance for doubtful trade accounts receivable	49	29

	3,280	4,435

(5): Inventories

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

	December 31
	2001	2000
Crude oil and products	1,826	1,818
Fertilizers, industrial products, coal, Orimulsion® and other	85	79
Materials and supplies	395	358

	2,306	2,255
Less materials and supplies classified in non-current assets, net	98	80

	2,208	2,175

The current replacement cost of inventories of crude oil and products approximates LIFO costs. At December 31, 2001 and 2000, inventories stated using the LIFO method accounted for 79% and 81% of total inventories, respectively.

At December 31, 2001 and 2000, the replacement cost of inventories of crude oil and products exceeded LIFO cost by approximately $1,490 million and $1,845 million, respectively, and accordingly, no write-down was necessary.

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(6): Investments in Nonconsolidated Investees

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

				December 31
				Percentage of capital stock		Share of equity
				2001	2000	2001	2000
Foreign investees:
	United States of America:
		CITGO investees:
			LYONDELL-CITGO	41	41	509	518
			Needle Coker	25	25	22	24
			Other	—	—	170	170
		Chalmette Refining		50	50	316	286
		Merey Sweeny		50	50	34	36

						1,051	1,034

	Virgin Islands:
		PDVSA VI		50	50	805	746
	Germany:
		Ruhr Oel		50	50	132	130
	Sweden:
		Nynäs Petroleum		50	50	61	73
	Colombia:
		Monómeros Colombo:
			Venezolanos	47	47	30	30
	Other:
		Bitor investees		50	50	2	2

						2,081	2,015

Investees in Venezuela:
	PETROZUATA			49	49	230	176
	FERTINITRO			35	35	122	108
	METOR			38	38	98	90
	Carbones del Guasare			49	49	88	87
	Supermetanol			35	35	70	69
	Super Octanos			49	49	78	78
	CERAVEN			49	49	10	10
	PROFALCA			35	35	10	10
	INTESA			40	40	6	5
	Other			—	—	26	54

						738	687

			Total nonconsolidated investees			2,819	2,702

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

			December 31
			2001						2000						1999
Financial position:			2001						2000						1999
Financial position:			Venezuela		Abroad		Total		Venezuela		Abroad		Total		Venezuela		Abroad		Total
	Current assets		886		1,800		2,686		726		1,725		2,451		650		1,635		2,285
	Non-current assets		5,253		6,943		12,196		4,883		6,366		11,249		4,101		5,774		9,875
	Current liabilities		(576	)	(2,034	)	(2,610	)	(476	)	(2,218	)	(2,694	)	(508	)	(1,782	)	(2,290	)
	Long-term liabilities		(3,818	)	(3,355	)	(7,173	)	(3,570	)	(2,802	)	(6,372	)	(3,098	)	(2,678	)	(5,776	)

		Net equity	1,745		3,354		5,099		1,563		3,071		4,634		1,145		2,949		4,094

	Operating results for the year:
		Revenues	1,768		12,623		14,391		1,337		13,790		15,127		1,092		9,205		10,297
		Operating income	422		2,309		2,731		573		2,285		2,858		243		2,053		2,296
		Net income	303		1,133		1,436		396		663		1,059		102		174		276

In 1993 several subsidiaries of CITGO and LYONDELL Petrochemical Company (LYONDELL) executed definitive agreements with respect to LYONDELL-CITGO Refining LP (LYONDELL-CITGO), which owns and operates a refinery with a capacity of 265,000 barrels per day in Houston, Texas. LYONDELL contributed the refinery and CITGO has made cash contributions and other commitments for a participation of 41.3% of LYONDELL-CITGO. The total investment gave CITGO a 41.3% interest in this expansion project in LYONDELL-CITGO. The heavy crude oil, processed in the refinery, is supplied from PDVSA's Venezuelan operation under a long-term crude oil supply contract. CITGO purchases a substantial portion of the refined products produced at this refinery under a long-term contract that expires in 2017.

At December 31, 2001 and 2000, CITGO had notes receivable from LYONDELL-CITGO of $35 million. The notes are due July 1, 2003 and bear interest at market rates of approximately 2.2%, 6.9% and 6.7% at December 31, 2001, 2000 and 1999, respectively. On December 31, 1999, CITGO converted $33 million of these notes to investments in LYONDELL-CITGO.

Summarized financial information of LYONDELL-CITGO follows (expressed in millions of dollars):

			December 31
			2001		2000		1999
Financial position:
	Current assets		227		310		219
	Non-current assets		1,434		1,386		1,406
	Current liabilities		(377	)	(867	)	(697	)
	Long-term liabilities		(776	)	(321	)	(316	)

		Member's equity	508		508		612

		December 31
		2001	2000	1999
Operating results for the year:
	Revenues	3,284	4,075	2,571
	Gross profit	317	250	133
	Net income	203	128	24

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In July 2001, LYONDELL- CITGO completed a refinancing of its working capital revolver and its $450 million term bank loan for an eighteen month period, maturing in January 2003.

Other investments in the United States of America mainly comprise participations of between 6% and 50% in terminals and pipelines, including 15.8% in Colonial Pipeline Company; 49.5% in Nelson Industrial Steam Company (NISCO), a steam generating plant and 49% in Mount Vernon Phenol Plant. The carrying value of these investments exceeds the net value of the corresponding assets by approximately $134 million and $138 million at December 31, 2001 and 2000, respectively (see notes 1(c) and 1(i) to the consolidated financial statements). At those dates, NISCO presents a deficit in which the participation of CITGO is $40 million and $50 million, respectively.

In October 1997 an indirect subsidiary of PDVSA, entered into an association agreement with ExxonMobil to acquire a 50% participation in the Chalmette refinery, in Louisiana, with a processing capacity of 184,000 barrels per day for $319 million. PDVSA (through CITGO) exercised its option to purchase up to 50% of refined products produced at the refinery through December 31, 2000. ExxonMobil, which operates the refinery, purchased substantially all of the refined products produced by the Chalmette refinery at market prices during 2001.

In October 1998 the subsidiary PDVSA VI, Inc. (PDVSA VI) entered into an association agreement (Hovensa) with Amerada Hess Corporation for the processing of crude oil in St. Croix, U.S. Virgin Islands and marketing of such products in the international markets. Pursuant to the agreement, PDVSA VI purchased a 50% interest for approximately $625 million; this refinery has a capacity of approximately 495,000 barrels per day.

Summarized financial information of Hovensa follows (expressed in millions of dollars):

			December 31
			2001		2000
Financial position:
	Current assets		491		524
	Non-current assets		1,881		1,632
	Current liabilities		(294	)	(424	)
	Long-term liabilities		(388	)	(155	)

		Net equity	1,690		1,577

Operating results for the year:
	Revenues		4,209		5,242
	Operating income		131		606
	Net income		120		247

In October 1998, an indirect subsidiary of PDVSA entered into an association agreement (Merey Sweeny) with Phillips Petroleum Corporation (Phillips) for the processing of crude oil in the United States of America. Pursuant to the agreement, the parties constructed a delayed coking facility for an estimated cost of $530 million, within an existing refinery owned by Phillips in Sweeny, Texas, in which each party has a 50% interest. Phillips purchases the heavy crude processed in the Sweeny refinery from PDVSA. The joint venture's revenues consist of fees paid by Phillips to the joint venture and other income generated by the sale of coker to third parties, in accordance with the agreement.

In September 1993, the Venezuelan Congress authorized the venture with Conoco, Inc. (Conoco) and an agreement was signed in 1995 for the incorporation of the company Petrolera Zuata, C. A. (PETROZUATA) with a 49.9% participation for PDVSA Petróleo and 50.1% for Conoco. In 1998 development production operations commenced and the construction of the pipeline was completed.

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In the petrochemical sector, PDVSA is involved in the production and marketing of fertilizers, olefins, plastics and industrial products. In order to carry out these operations, Pequiven has entered into joint ventures with international companies such as METOR, Supermetanol, Super Octanos and FERTINITRO. Pequiven's interest in these associations varies between 20% and 50%. In September 1998 the Venezuelan Congress amended the law governing the ownership of petrochemical companies, allowing the sale of up to 49% of Pequiven's capital stock.

(7): Property, Plant and Equipment, net

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

	December 31
	2001	2000
Oil and gas production	43,485	43,548
Refining, marketing and transportation	19,281	16,393
Petrochemical	3,687	3,532
Other	1,639	1,413

	68,092	64,886
Less accumulated depreciation and depletion	36,784	34,612

	31,308	30,274
Land	222	288
Construction in progress	5,700	5,768

	37,230	36,330

In 2001 and 2000, PDVSA disposed of unproductive assets, charging the results of each year with approximately $600 million (see note 1(i) to the consolidated financial statements).

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

	December 31
	2001	2000	1999
Depreciation and depletion during the year	2,624	3,001	2,821
Capitalized interest during the year	51	59	188

At December 31, 2001 and 2000, there are certain gas compression plants and related equipment acquired under capital leases agreements recorded as property, plant and equipment for approximately $349 million and $394 million, net of accumulated depreciation of approximately $537 million and $492 million, respectively. Depreciation expense recorded in 2001, 2000 and 1999 for assets acquired under capital lease agreements, amounted to $45 million, $46 million and

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$46 million, respectively. At December 31, 2001 future lease payments for operating and capital leases are summarized as follows (expressed in millions of dollars):

		December 31
Years		December 31
Years		Operating	Capital
2002		130	81
2003		122	74
2004		104	42
2005		103	5
2006 and thereafter		941	26

Estimated future lease payments		1,400	228

Less interest			49

	Present value		179
Short-term portion, included in accruals and other			62

Long-term portion			117

Rent expense incurred from operating leases during 2001, 2000 and 1999 was $108 million, $52 million and $186 million, respectively.

(8): Joint Development Activities

As part of the process of opening the oil industry to private initiatives and investments, PDVSA has undertaken the following projects 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 synthetic crude, as follows:

Association	PDVSA's percentage of participation	Partners	Estimated gross project cost (unaudited)	Incurred as of December 31, 2001 (unaudited)
			(millions of dollars)	(millions of dollars)
PETROZUATA	49.90	Conoco	3,000	2,929
Cerro Negro	41.66	ExxonMobil-Veba Oel	2,000	1,737
Sincor	38.00	Total Fina-Statoil	4,200	4,272
Hamaca	30.00	Texaco-Phillips Petroleum	3,400	1,230

PDVSA participates in these joint ventures through its 49.9% owned subsidiary PETROZUATA (see note 6 to the consolidated financial statements) and the wholly-owned subsidiaries, PDVSA Cerro Negro, PDVSA Sincor and Corpoguanipa, (see note 1(c) to the consolidated financial statements).

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

Since 1998 development production commenced in PETROZUATA, and the production of synthetic crude oil commenced in February 2001. During 1999, 2000 and 2001 development

F-22

production commenced in Cerro Negro, Sincor and Hamaca, respectively. The commercial production of synthetic crude in Cerro Negro began in August 2001, while such production for Sincor and Hamaca is expected to commence in 2003 and 2004, respectively.

The disbursements required for these joint ventures during the construction phase 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.

These areas were assigned under a competitive bidding process to participate in profit sharing agreements with CVP. In these agreements it is established 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	Conoco—AGIP-OPIC	Compañía Agua Plana, S.A.
Guanare	ELF—Conoco (1)	Administradora Petrolera Guanare, S.A.
Guarapiche	Maxus (Repsol) (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	Pérez Companc	Compañía Anónima Mixta San Carlos, S.A.

(1): Until 2001
(2): Until 2000

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 in 2001 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 of 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, 2000, the amount of the guarantees is approximately $32 million. At December 31, 2001, 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

F-23

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.

In 2001 the investors Burlington-Union Pacific-Benton (Delta Centro area), ELF-Conoco (Guanare area) and Maxus-Repsol (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 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, for which 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 the results of each year are presented below (in millions of dollars):

	Years ended December 31
	2001	2000	1999
Operating fees	766	755	559
Capital fees and other	550	686	436
Stipends	794	716	277

	2,110	2,157	1,272

F-24

(9): Taxes

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

	Years ended December 31
	2001	2000	1999
Income tax	3,766	5,748	2,521
Production and other taxes	3,760	4,986	3,008

	7,526	10,734	5,529

(a): Income before Income Tax

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

	Years ended December 31
	2001	2000	1999
In Venezuela	6,730	12,408	5,020
Foreign	1,034	571	330

	7,764	12,979	5,350

The income tax provision for each year is summarized as follows (expressed in millions of dollars):

			Years ended December 31
			2001	2000		1999
Current income tax expense:
	In Venezuela		3,033	5,780		2,620
	Foreign		130	123		(17	)

			3,163	5,903		2,603

Deferred income tax expense (benefit):
	In Venezuela		454	(249	)	(163	)
	Foreign		149	94		81

			603	(155	)	(82	)

		Provision for income tax	3,766	5,748		2,521

F-25

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

			December 31
			2001		2000
Deferred tax assets:
	Accruals for employee benefits		1,005		1,087
	Property, plant and equipment		291		276
	Production tax payable		130		249
	Inventories		123		208
	Other reserves		—		89
	Investment tax credits and tax loss carryforwards		1,098		1,371
	Other		153		273

			2,800		3,553
	Less valuation allowance		1,036		850

			1,764		2,703

Deferred tax liabilities:
	Property, plant and equipment		869		991
	Operating agreements, net		397		365
	Capitalized interest		189		302
	Investments in nonconsolidated investees		221		207
	Inventories		94		122
	Deferred charges for plant turnaround costs		84		109
	Other		101		85

			1,955		2,181

		Net deferred tax (liabilities) assets	(191	)	522

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

	December 31
	2001		2000
Current assets	342		657
Long-term assets	301		502
Long-term liabilities	(834	)	(637	)

	(191	)	522

In assessing the realization of the deferred tax assets, management considers whether it is more likely than not that some portion of the 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 2001 and 2000, the valuation allowance increased by $186 million and decreased by $17 million respectively.

F-26

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

			Years ended December 31
			2001		2000		1999
			%		%		%
In Venezuela:
	Statutory income tax rate for the petroleum sector		67.7		67.7		67.7
	Inflation adjustment for tax purposes and effect of remeasurement to dollars		(8.4	)	(10.5	)	(8.9	)
	Legal contribution received from subsidiaries		(2.4	)	(5.3	)	(2.9	)
	Effect of lower income tax rate for non-petroleum sector subsidiaries		(7.4	)	(6.0	)	(3.8	)
	Other differences, net		2.3		(1.3	)	(2.8	)

		Effective income tax rate in Venezuela	51.8		44.6		49.3
Foreign:
	Other, primarily effect of lower income tax rate for foreign subsidiaries		(3.3	)	(0.3	)	(2.2	)

		Consolidated effective income tax rate	48.5		44.3		47.1

PDVSA and 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 $847 million and tax loss carryforwards were $559 million; these amounts expire as follows (expressed in millions of dollars):

	December 31
	2002	2003	2004
Tax credits	169	277	401
Tax losses	496	56	7

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 will be 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. Any resulting effects will be included as a taxable item in the determination of income tax.

PDVSA has significant operations subject to transfer pricing rules. Based on a study performed by the Company, the effect of these rules on taxable income is not significant for 2001 and 2000.

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

F-27

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.
•: Taxation on dividends: when a difference exists between the net income approved at the stockholders meeting and that determined for tax purposes based on the financial statements adjusted for inflation.
•: 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. This tax has a maximum rate of 16²/3% and is calculated according to certain parameters, pursuant to agreements with the Venezuelan Government. Production tax expenses recorded by the Company for 2001, 2000 and 1999 amounted to $3,733 million, $4,957 million and $2,986 million, respectively, which is included in production and other taxes. Commencing January 2002, the production tax was modified (see note 1 to the consolidated financial statements).

(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 2001, 2000 and 1999, this tax resulted in an expense of $27 million, $29 million and $22 million, respectively, which is included in production and other taxes.

(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%.

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. A summary of tax credits pending compensation or recovery follows (expressed in millions of dollars):

	Years ended December 31
	2001		2000		1999
Pending recovery or compensation at beginning of year	1,475		921		1,381
Generated during the year	1,022		799		874
Recovered during the year	(347	)	(245	)	(1,334	)

Pending recovery or compensation at end of year	2,150		1,475		921

F-28

At December 31, 2001, Special Tax Recovery Certificates (CERT) are comprised as follows (expressed in millions of dollars):

	Approved by the Integrated National Tax Administration Service (SENIAT), corresponding to the period June 1999 to December 2000, in process of obtaining the CERT		1,048
	Pending recovery from 2000 and 1999 under administrative proceedings		105
	Awaiting reply from SENIAT, corresponding to the period January to June 2001		446
	Under application, corresponding to the period July to December 2001		551

			2,150

The amounts recoverable do not generate interest.

(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 2001, 2000 and 1999, such taxes, paid to the corresponding governments, amounted to $4,133 million, $3,969 million and $3,801 million, respectively. These taxes are not included in sales.

(10)

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 hedge 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.

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 in 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 disclosure of the estimated fair value of financial instruments is made in accordance with the requirements of SFAS No. 107, "Disclosures about fair value of financial

F-29

instruments". The 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 (expressed in millions of dollars):

		December 31
		2001		2000
		Carrying amount	Fair value	Carrying amount	Fair Value
Assets:
	Cash and cash equivalents	925	925	3,257	3,257
	Notes and accounts receivable	3,280	3,280	4,435	4,435
	Other investments	187	187	148	148
	Long-term accounts receivable	774	674	538	451
	Derivative assets (included in other assets)	16	16	—	—

Liabilities:
	Accounts payable	2,584	2,584	3,084	3,084
	Short-term debt	1,000	1,000	596	596
	Long-term debt	7,427	7,376	7,003	6,674
	Derivative liabilities (included in other liabilities)	65	65	—	—

The carrying amounts of cash and cash equivalents, notes and accounts receivable, other investments, accounts payable and short-term debt approximate their fair value due to the short maturity of these instruments.

(d): Long-term Debt

The fair value of long-term debt is based on interest rates that are currently available to PDVSA for issuance of debt with similar terms and remaining maturities, except for (i) in 2000 fair values of PDV America's $500 million principal amount of senior notes due 2001 and $200 million principal amount of senior notes due 2006, which were based upon quoted market prices and (ii) in 2001 and 2000 fair values y PDVSA Finance's debt of $178 million and $189 million, respectively, which were based on brokers quotes, which in turn were based on secondary markets.

(e): Derivative Instruments

The fair value of these agreements 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.

F-30

(11): Debt

Debt is summarized as follows (expressed in millions of dollars):

(a): Short-term Debt

	December 31
	2001	2000
Short-term borrowing facilities with various banks with a weighted average interest rate of 8.62%	—	58
Current portion of long-term debt	1,000	538

	1,000	596

PDVSA has a corporate short-term line of credit of some $875 million, which at December 31, 2001 was unused and available for borrowing on an unsecured basis.

CITGO has $190 million of uncommitted, unsecured, short-term borrowing facilities with various banks which at December 31, 2001 were unused and available for borrowing on an unsecured basis. Interest rates on these facilities are determined daily based upon the Federal Funds' Rates in the United States of America.

F-31

(b): Long-term Debt

			December 31
			2001	2000
PDV America/CITGO:
	Senior notes		499	499
	Revolving bank loans		392	—
	Senior notes under shelf registration		200	200
	Private placement senior notes		57	97
	Master shelf agreement senior notes		260	260
	Tax-exempt bonds		357	329
	Taxable bonds		146	174
	Other		—	7

			1,911	1,566

PDVSA Finance:
	Unsecured notes		3,297	2,907

PDVSA VI:
	Guaranteed secured note		442	491

PDVSA Petróleo:
	Loans guaranteed by governmental export agencies and financial institutions		299	413
	PDVSA Cerro Negro bonds		300	300
	PDVSA Cerro Negro line of credit		150	150
	PDVSA Sincor line of credit		903	809
	Corpoguanipa line of credit		190	—

			1,842	1,672

Bariven, S. A. (Bariven):
	Loans guaranteed by governmental export agencies and financial institutions		365	401
	Commercial paper program		179	179

			544	580

PDV Marina, S. A. (PDV Marina):
	Credit facility		185	234

Other — Corporate and other subsidiaries			206	91

			8,427	7,541
Less current portion of long-term debt			1,000	538

		Total long-term portion	7,427	7,003

F-32

Future maturities of the long-term portion at December 31, 2001 are as follows (expressed in millions of dollars):

Years
2003		1,590
2004		604
2005		609
2006		581
2007 and thereafter		4,043

		7,427

PDV America/CITGO

(1): In August 1993 PDV America issued $1,000 million principal amount of senior notes, guaranteed by PDVSA, with interest rates ranging from 7.25% to 7.87% and due dates ranging from 1998 to 2003. Interest on notes is payable semi-annually, commencing February 1994. At December 31, 2001, the senior notes outstanding amount to $499 million.
(2): CITGO has loan agreements with various banks, comprising: (i) a $400 million, five-year, revolving bank loan maturing in May 2003; (ii) a $150 million, 364-day, revolving bank loan; and (iii) a $25 million 364-day revolving bank loan established in May 2001. These loans are unsecured and have various maturities and interest rates options. The annual interest rate on the loans at December 31, 2001 range from 2.5% to 2.9%. At December 31, 2001, $360 million was outstanding under these loan agreements.

PDV Midwest Refining, LLC (PDVMR), a wholly owned subsidiary of PDV America, has a revolving credit facility with a consortium of banks which is committed through April 2002, and currently allows for borrowings up to $75 million at various interest rates. Inventories and accounts receivable of PDVMR are pledged as collateral. At December 31, 2001 there is a balance of $32 million bearing interest of 2.5%. In January 2002, PDVMR settled this revolving credit facility.

(3): In April 1996, CITGO filed a registration statement with the U.S. Securities and Exchange Commission (SEC) relating to the shelf registration of $600 million, of debt securities that may be offered and sold from time to time. In May 1996, the registration became effective and CITGO sold a tranche of debt securities with an aggregate offering price of $200 million which were outstanding as of December 31, 2001 and 2000.
(4): At December 31, 2001, CITGO has outstanding approximately $57 million of privately placed, unsecured senior notes. Principal amounts are payable in annual installments in November and interest is payable semiannually in May and November.
(5): At December 31, 2001, CITGO has outstanding $260 million of privately placed senior notes under an unsecured Master Shelf Agreement with an insurance company. The notes have various fixed interest rates of between 7.17% and 8.94%, maturing between 2002 and 2009.
(6): At December 31, 2001, through state entities, CITGO has issued $75 million of industrial development tax-exempt bonds for certain Lake Charles, Louisiana, port facilities and pollution control equipment and $262 million of environmental revenue bonds to finance a portion of CITGO's environmental facilities at its Lake Charles, Louisiana and Corpus Christi, Texas, refineries and at the LYONDELL-CITGO refinery. Additional credit support for these bonds is provided through letters of credit. The bonds bear interest at various floating rates which ranged from 2.5% to 6.0% and from 4.7% to 6.0% at December 31, 2001 and 2000, respectively.

F-33

Additionally, PDVMR has issued variable rate pollution control bonds, with interest currently paid monthly. The bonds have one payment at maturity in the year 2008 to retire the principal, and the principal and interest payments are guaranteed by a $20 million letter of credit.

(7): At December 31, 2001, through state entities, CITGO has outstanding $146 million of taxable environmental revenue bonds to finance a portion of CITGO's environmental facilities at its Lake Charles, Louisiana, refinery and at the LYONDELL-CITGO refinery. Such bonds are secured by letters of credit and have floating interest rates of 3.1% and 6.6% at December 31, 2001 and 2000, respectively. At the option of CITGO and upon the occurrence of certain specified conditions, all or any portion of such taxable bonds may be converted to tax-exempt bonds. At December 31, 2001, $49 million of the originally issued taxable bonds had been converted to tax-exempt bonds.

PDVSA Finance

PDVSA Finance's main objective is to purchase from PDVSA Petróleo certain current and future accounts receivable generated from the export of crude oil and refined petroleum products. As a special purpose financing vehicle of PDVSA, PDVSA Finance owns its assets and has creditors with priority in respect of these assets, as set forth in the terms and conditions of the bonds issued as described below:

(1): Unsecured notes issued in November 2001, for $500 million, with annual interest rate of 8.50% due in 2012.
(2): Unsecured notes issued in April 1999 for approximately $1,000 million, with annual interest rates ranging from 8.75% to 9.95% and due dates from 2000 to 2020; PDVSA Finance also issued unsecured notes for approximately €200 million ($178 million) with an interest rate of 6.25% due 2002 through 2006.
(3): Unsecured notes issued in May 1998 for $1,800 million with annual interest rates ranging from 6.45% to 7.50%, with due dates from 2002 to 2028. Interest is payable quarterly for each series of such notes.

Current notes are indicated as follows (expressed in millions of dollar):

		2001		2000
6.45% due 2002 through 2004		400		400
8.75% due 2000 through 2004		226		325
6.25% due 2002 through 2006 (in Euros)		178		189
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		—
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		(7	)	(7	)

	Total	3,297		2,907

PDVSA VI

In October 1998, PDVSA VI, in connection with its investment in HOVENSA, issued a $563 million secured note to Hess Oil Virgin Islands Corp., guaranteed by PDVSA. The note is payable in semiannual installments from August 1999 to February 2009, bearing fixed annual

F-34

interest of 8.46%. PDVSA VI has the right, on any payment date, to prepay portions of this note, in whole or in part, without premium or penalty. At December 31, 2001, the balance of this note is $442 million.

PDVSA Petróleo

(1)

The net proceeds from loans guaranteed by governmental export agencies have been used for the investment plan of PDVSA Petróleo. Such loans are payable semiannually, have various fixed annual interest rates at December 31, 2001, ranging from 4.1% to 5% and are guaranteed by governmental export agencies in the United States of America, Europe and Japan. At December 31, 2001 and 2000, the balance of these loans is approximately $299 million and $413 million, respectively.

(2)

In June 1998, Cerro Negro Finance, Ltd., incorporated in the Cayman Islands, issued $600 million principal amount of senior notes (the senior notes) with annual interest rates ranging from 7.33% to 8.03% and due dates ranging from 2009 to 2028. Interest on the senior notes is payable semiannually. Proceeds from the issuance of the senior notes were used to purchase participations in the loans made by an offshore financial institution to PDVSA Cerro Negro, for approximately $300 million, and to the related company Mobil Cerro Negro for approximately $300 million. The funds are guaranteed by PDVSA and are being used to finance the development and construction of part of the facilities for the exploitation, production, transportation and upgrading of extra-heavy crude oil from reserves located in the Cerro Negro Area of the Orinoco Belt in the eastern region of Venezuela.

(3)

In June 1999, PDVSA Cerro Negro obtained loans from a financial institution for $150 million, bearing LIBOR interest rates plus an additional percentage, fluctuating between 5.76% and 6.79%, due in 2002. The proceeds from these loans have been used to finance the project. Interest is paid semiannually.

(4)

In August 1998, PDVSA Sincor, an indirect subsidiary of PDVSA, Total Venezuela, S. A. and Statoil Sincor AS agreed to finance the project "SINCOR", whose administrative agent is the Chase Manhattan Bank. The financing is as follows:

(a): A credit line of $1,200 million, of which PDVSA Sincor's 38% participation was fully utilized at December 31, 2000 and was used to pay financing expenses to cover cash requirements and operating expenses for the project. The interest rate is applicable in two periods: one at a base rate fixed by the bank for the first six months, and the other at LIBOR fixed by the capital market beginning from the seventh month. Additional interest is applicable for both periods.
(b): A credit line of $1,500 million in which PDVSA Sincor has a 38% participation; at December 31, 2001, some $1,175 million has been utilized. The annual interest rate is LIBOR plus an additional percentage ranging from 5.44% to 8%.

(5): In 2001, Corpoguanipa and the partners of the Hamaca Project entered into a $470 million financing program with a group of international banks, whereby BNP Paribas is the agent. Furthermore, another financing plan was organized with Barclays Bank PLC and the New York branch of Westdeutsche Landesbank Girozentarale for $627 million, which includes a guarantee with the Export-Import Bank of the United States of America (US EXIM). Both financing programs are used for the construction of project facilities for the improvement of synthetic crude and production. In 2001 some $633 million was obtained from these loans at LIBOR ranging from 2.75% to 4.69% on $300 million and LIBOR ranging from 1.90% to 3.84% on $333 million. Corpoguanipa has a 30% participation in these financing programs.

F-35

(6): In September 2000, PDVSA Petróleo entered into a loan agreement with a group of Japanese banks headed by Japan Bank for International Cooperation (JBIC) for a credit facility in yens equivalent to $500 million for the valuation project for the refining currents (VALCOR) at the refinery in Puerto La Cruz.

Bariven

(1): The net proceeds from loans guaranteed by governmental export agencies and financial institutions have been used for the Company's domestic investment plan. Such loans are repayable semiannually, have various annual interest rates at December 31, 2001 ranging from 2.68% to 7.5% and are guaranteed by governmental export agencies in the United States of America, Europe and Japan. The balance at December 31, 2001 amounted to $365 million with maturities up to 2008.
(2): In March 1992, Bariven launched a U.S. dollar denominated commercial paper program of $200 million principal amount with an annual interest rate of 10.625% at December 31, 2001, due in 2002. The balance at December 31, 2001 amounted to $179 million.

PDV Marina

To finance the acquisition of eight tankers, PDV Marina subscribed in 1991 to a credit facility agreement with Fairplay Shipfinance. This credit facility is payable in twenty-one semiannual installments. The annual interest rate ranges from LIBOR plus 1.5% for the first 18 installments to LIBOR plus 1.75% for the remaining installments. The tankers (with a net book value of $361 million at December 31, 2001) acquired under this credit facility are pledged as collateral. The interest rate applicable at December 31, 2001 was LIBOR plus 1.75% (6.625%).

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, 2001 and 2000.

(12): Capital Stock and Reserves

At December 31, 2001 and 2000, PDVSA's capital stock is represented by 51,204 registered shares of Bs25 million each, totalling $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, 2001, 2000 and 1999 amounted to $3,866 million, $3,845 million and $3,480 million, respectively. The legal reserve cannot be used to distribute dividends. Other reserves include the reserve for the realization of deferred tax assets and the reserve for new investments.

Dividends to the shareholder are declared and paid in bolivars based on the statutory financial statements, which reflect positive retained earnings. In 2001 and 2000, dividends were declared for Bs3,400,000 million and Bs1,400,000 million equivalent to $4,774 million and $2,018 million, respectively.

At December 31, 2001, $198 million, corresponding to dividends declared in 2000, are pending payment.

F-36

(13): 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, 2001, the guaranteed amount in the savings fund is $230 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. A U.S. subsidiary also maintains three non-contributory defined benefit pension plans. The subsidiary's policy is to fund the pension plans in accordance with current legislation, without exceeding tax deduction restrictions. In addition to pension plans, PDVSA provides social benefits and medical and life insurance for retired personnel. These benefits are funded on a cash basis.

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 2001 and 2000, and the funded status of such plans reconciled with amounts reported in the consolidated balance sheets (expressed in millions of dollars):

				December 31
				Pension benefits				Other postretirement benefits
				2001		2000		2001		2000
Venezuela:
	Change in benefit obligation—
		Benefit obligation, beginning of year		3,836		2,955		892		885
			Service cost	142		116		52		28
			Interest cost	386		307		135		80
			Participants contribution	16		19		—		—
			Plan amendments	81		971		465		—
			Actuarial (gain) loss	(65	)	(339	)	(54	)	95
			Benefits paid	(156	)	(193	)	(28	)	(196	)

		Benefit obligation, end of year		4,240		3,836		1,462		892

F-37

				December 31
				Pension benefits				Other postretirement benefits
				2001		2000		2001		2000
Change in plan assets—
	Fair value of plan assets, beginning of year			1,206		855		—		—
		Actual return on plan assets		(37	)	80		—		—
		Employer contribution		105		360		29		196
		Participant contributions		16		19		—		—
		Benefits paid		(91	)	(108	)	(29	)	(196	)

	Fair value of plan assets, end of year			1,199		1,206		—		—

Funded status				(3,041	)	(2,630	)	(1,462	)	(892	)
Employer contribution				22		—		—		—
Benefit payments made directly by employer				21		—		—		—
Unrecognized net actuarial loss				949		901		520		444
Unrecognized prior service cost				1,193		1,231		365		123
Unrecognized transition obligation				4		7		—		—

		Net amount recognized		(852	)	(491	)	(577	)	(325	)

Amounts recognized in the Company's consolidated balance sheets consist of—
		Accrued benefit liability		(2,847	)	(2,538	)	(577	)	(325	)
		Employer contributions		22		—		—		—
		Benefit payments made directly by employer		21		—		—		—
		Intangible asset		1,199		1,237		—		—
		Accumulated other comprehensive income		753		810		—		—

			Net amount recognized	(852	)	(491	)	(577	)	(325	)

Foreign:
	Change in benefit obligation—
		Benefit obligation, beginning of year		288		259		206		189
			Service cost	16		15		6		6
			Interest cost	22		20		16		14
			Plan vesting changes	—		6		—		—
			Actuarial gain (loss)	23		—		41		4
			Benefits paid	(12	)	(12	)	(8	)	(7	)

		Benefit obligation, end of year		337		288		261		206

	Change in plan assets—
		Fair value of plan assets, beginning of year		273		276		1		1
			Actual return on plan assets	(10	)	7		—		—
			Employer contribution	13		2		8		7
			Benefits paid	(12	)	(12	)	(8	)	(7	)

			Fair value of plan assets, end of year	264		273		1		1

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			December 31
			Pension benefits				Other postretirement benefits
			2001		2000		2001		2000
Funded status			(73	)	(15	)	(260	)	(205	)
Unrecognized net actuarial gain			(2	)	(62	)	31		(10	)
Unrecognized prior service cost			2		2		—		—
Net gain at date of adoption			—		(1	)	—		—

	Net amount recognized		(73	)	(76	)	(229	)	(215	)

Amounts recognized in the Company's consolidated balance sheets consist of—
	Accrued benefit liability		(80	)	(83	)	(229	)	(215	)
	Intangible asset		3		4		—		—
	Accumulated other comprehensive income		4		3		—		—

		Net amount recognized	(73	)	(76	)	(229	)	(215	)

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Actuarial assumptions are detailed below:

		December 31
		Pension benefits			Other postretirement benefits
		2001	2000	1999	2001	2000	1999
		%	%	%	%	%	%
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	12	—	—	—
Foreign:
	Discount rate	7	7.8	7.8	7	7.8	7.8
	Rate of compensation increase	5	5	5	—	—	—
	Expected return on plan assets	9	9	9	6	6	6

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, 2001 by $40 million and the net periodic cost for postretirement benefits by $4 million.

For the years ended at December 31 the net periodic benefit costs are as follows (expressed in millions of dollars):

				December 31
				Pension benefits						Other postretirement benefits
				2001		2000		1999		2001	2000		1999
Venezuela:
	Components of net periodic benefit cost—
		Service cost		142		116		105		52	28		28
		Interest cost		386		307		261		135	80		80
		Expected return on plan assets		(121	)	(95	)	(60	)	—	—		—
		Amortization of prior service cost		118		62		30		68	17		17
		Amortization of net gain at date of adoption		2		2		2		—	—		—
		Recognized net actuarial loss		45		62		88		26	17		24

			Net periodic benefit cost	572		454		426		281	142		149

Foreign:
	Components of net periodic benefit cost—
		Service cost		16		15		20		6	6		7
		Interest cost		22		20		18		16	14		13
		Expected return on plan assets		(24	)	(24	)	(23	)	—	—		—
		Recognized net actuarial gain		(4	)	(5	)	(2	)	—	(17	)	—

			Net periodic benefit cost	10		6		13		22	3		20

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(14): Related Party Transactions

A summary of transactions with nonconsolidated investees and other entities owned by the Bolivarian Republic of Venezuela for the years ended December 31, follows (expressed in millions of dollars):

		2001	2000
Transactions during the year:
	Sales	4,167	4,424
	Costs and expenses	4,991	7,043
Balances at year-end:
	Deposits with the BCV, including contributions to FIEM	4,159	4,401
	Accounts receivable	440	281
	Long-term accounts receivable included in other assets	668	538
	Investments in nonconsolidated investees	2,819	2,702
	Accounts payable	152	262

Long-term accounts receivable at December 31, 2001 and 2000 include a balance receivable from PETROZUATA of $544 million and $474 million, respectively. Furthermore, these include balances receivable from C. A. Administración y Fomento Eléctrico (CADAFE) of $118 million and $55 million, respectively. These accounts do not generate interest.

In 2001, 2000 and 1999, the affiliated company, Informática Telecomunicaciones, S. A. (INTESA) invoiced PDVSA in respect of information technology services of $309 million, $281 million and $315 million, respectively, which include costs and expenses.

PDVSA Petróleo has various agreements for supplies with affiliated companies, which are summarized as follows (thousands of barrels a day):

Affiliate	Delivery obligation	Year of termination
Ruhr Oel	220	2002
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

CITGO acquires refined products from various affiliated companies, including LYONDELL-CITGO, HOVENSA and Chalmette under long-term agreements. During the years ended December 31, 2001, 2000 and 1999, these purchases amounted to $3,400 million, $5,600 million and $3,300 million, respectively. At December 31, 2001 and 2000, accounts payable in connection with these operations include $72 million and $194 million, respectively.

During the years ended December 31, 2001, 2000 and 1999, CITGO sold to affiliated companies refined products and other refinery supplies of $292 million, $222 million and $190 million, respectively. Furthermore the sales of crude of CITGO to affiliated companies amounted to $5 million and $4 million in 2001 and 2000, respectively. The accounts receivable in connection with these operations at December 31, 2001 and 2000, amount to $134 million and $38 million, respectively.

(15): 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.

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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(q) to the consolidated financial statements).

Summarized financial information concerning the Company's reportable segments is shown in the following table (expressed in millions of dollars):

				Years ended December 31
				2001		2000		1999
Revenues:
	Net sales of crude oil and products:
		Segments in Venezuela:
			Upstream operations	20,480		26,785		15,883
			Downstream operations	25,903		31,547		19,097
			Petrochemical operations	1,070		990		702
		Segments in United States of America—
			Downstream operations	19,601		22,157		13,332
	Other			851		609		657

				67,905		82,088		49,671
	Eliminations (1)			(21,655	)	(28,408	)	(17,023	)

				46,250		53,680		32,648

Operating income: (2)
	Segments in Venezuela:
		Upstream operations		7,653		12,673		7,040
		Downstream operations		(1,348	)	(1,327	)	(1,010	)
		Petrochemical operations		(104	)	11		(99	)
	Segments in United States of America:
		Downstream operations		658		612		341
	Other			2,534		2,589		395

				9,393		14,558		6,667
	Eliminations (1)			(1,120	)	(907	)	(655	)

				8,273		13,651		6,012

(1): Represent the elimination of intersegment sales.
(2): Before financing expenses, income tax and minority interests.

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			Years ended December 31
			2001	2000	1999
Capital expenditures, net:
	Segments in Venezuela:
		Upstream operations	507	2,208	2,555
		Downstream operations	2,517	9	166
		Petrochemical operations	110	47	76
	Segments in United States of America:
		Downstream operations	292	166	232
	Other		98	55	12

			3,524	2,485	3,041

Property, plant and equipment, net:
	Segments in Venezuela:
		Upstream operations	22,015	22,880	22,540
		Downstream operations	8,899	7,165	7,615
		Petrochemical operations	2,241	2,245	2,316
	Segments in United States of America—
		Downstream operations	3,293	3,287	3,410
	Other		782	753	965

			37,230	36,330	36,846

Net sales and long-lived assets information by geographic area are summarized below (expressed in millions of dollars):

	December 31, 2001
	Venezuela	United States of America	Other countries (3)	Total
Net sales (1)	26,184	19,602	—	45,786
Long-lived assets (2)	42,229	4,432	2,351	49,013

	December 31, 2000
Net sales (1)	31,077	22,157	—	53,234
Long-lived assets (2)	39,639	5,150	1,928	46,717

	December 31, 1999
Net sales (1)	19,268	13,332	—	32,600
Long-lived assets (2)	34,676	4,620	1,837	41,133

(1): Based on the country in which the sales originate.
(2): Based on the location of the asset.
(3): Primarily investment in nonconsolidated investees.
(16): Commitments and Contingencies

Litigation and Other Claims

In August 1999, the 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, where the matter is still pending. On September 19, 2000, the Court of International Trade remanded the case to the Department of

F-43

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 within 60 days. 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 is awaiting review by the Court of International Trade.

LYONDELL-CITGO has commenced an action against Petróleos de Venezuela and PDVSA Petróleo in the Southern District of New York. LYONDELL-CITGO seeks damages and specific performance for alleged breaches of the Crude Oil Supply Agreement, dated May 5, 1993, between LYONDELL-CITGO and Lagoven (subsequently merged into PDVSA Petróleo) and the Supplemental Supply Agreement, dated May 5, 1993, between LYONDELL-CITGO and Petróleos de Venezuela. LYONDELL-CITGO alleges that PDVSA wrongfully declared force majeure events and reduced shipments of extra-heavy crude oil to LYONDELL-CITGO.

The challenged reductions in the shipment of extra-heavy crude oil to LYONDELL-CITGO were made pursuant to instructions received from the MEM. In accordance with the contract, PDVSA Petróleo and Petróleos de Venezuela declared a force majeure when the MEM's instructions required them to reduce production.

Additionally, a number of lawsuits and claims have arisen in the normal course of business, the possible final effect of which cannot be quantified. Management believes that these claims have no legal grounds and that the proceedings will be decided favorably. Based on analysis of the available information, provisions have been recorded and are included in accruals and other liabilities. Taking into account these provisions, in the opinion of management, based in part on advice of its legal counsel, the resolution of these matters will not have a material adverse effect on PDVSA's consolidated financial statements.

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 of America and Europe, PDVSA's 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 has an investment plan to comply with the applicable environmental regulations in Venezuela, for the period 2002 - 2007 of approximately $1,998 million which includes the following: product quality for $1,079 million; risk control for $583 million; environmental adaptation for $279 million and other environmental investments for $57 million.

For the purpose of compliance with future fuel specifications, both national and international, the projects for quality products are aimed at the significant reduction of the sulfur content of fuels.

In addition to the activities outlined in the programs, expenditures of $624 million are planned for remediation of 8,000 production pits as part of a global remediation plan that will culminate in 2010. The pits are excavations made in the soil and/or constructions of earth walls that were used in the past to temporarily store the effluents and waste generated by the exploration and production activities. These excavations were made when there was not the appropriate technology to avoid the need of their use in the drilling and production operations. Currently, PDVSA does not excavate pits as part of its operations.

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In addition, for the period 2002 - 2006, CITGO has planned expenditures of approximately $1,154 million to comply with environmental regulations in the United States of America.

In 1992, CITGO reached an agreement with a state agency to cease usage of certain surface impoundments at CITGO's Lake Charles refinery by 1994. A mutually acceptable closure plan was filed with the state in 1993. CITGO and its former owner are participating in the closure and sharing the related costs based on estimated contributions of waste and ownership periods. The remediation commenced in December 1993. In 1997 CITGO presented a proposal to a state agency revising the 1993 closure plan. In 1998 and 2000 Company amended its 1997 proposal as requested by the state agency. A ruling on the proposal, as amended, is expected in 2002, with final closure to begin later in 2002.

Conditions which require additional expenditures may exist at various sites including, but not limited to, PDVSA's operating complexes, closed refineries, service stations and crude oil and petroleum storage terminals. The amounts of such future expenditures, if any, are indeterminable. Management believes that these matters, in the normal course of operations, will not have a material effect on the financial position, liquidity or consolidated operations of PDVSA.

Other Commitments

Minority interests shown 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, 2001, preferred shares for approximately $180 million have been redeemed and $108 million are pending to be redeemed.

(17): New Foreign Exchange System

The National Government and the Central Bank of Venezuela decided to adopt, as of February 13, 2002, a floating rate of exchange system (US$/Bs) rather than the band system previously in effect. Consequently, at March 8, 2002, the rate of exchange was Bs945.25 to $1, which reduced the net liability position of the Company to $998 million at December 31, 2001 (see note 1(d) to the consolidated financial statements).

F-45

(18): 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.

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 expected 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.

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 (expressed in millions of barrels):

			2001		2000		1999
Proved developed and undeveloped reserves of light, medium and heavy crude oil at January 1			41,998		41,162		40,461
	Revisions		784		1,652		1,782
	Extensions and new discoveries		538		286		—
	Production		(1,095	)	(1,103	)	(1,082	)

Proved developed and undeveloped reserves of light, medium and heavy crude at December 31			42,225		41,997		41,161
Proved developed and undeveloped reserves of extra-heavy crude oil at December 31			35,558		35,688		35,701

		Total proved developed and undeveloped reserves at December 31	77,783		77,685		76,862

		Total proved developed reserves, submitted to production, including extra-heavy crude oil at December 31 (included above)	17,372		17,373		18,124

At 31 December 2001, 2000 and 1999, proved reserves of crude oil developed under operating agreements amounted to 5,600 million barrels, 5,479 million barrels and 5,450 millions barrels,

F-46

respectively, (see note 8(c) to the consolidated financial statements). During 2001, 2000 and 1999, the production of crude oil in the areas under operating agreements was approximately 502,000, 466,000 and 403,000 barrels per day, 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 27 million, 26 million and 21 million of extra-heavy crude oil for the production of Orimulsión® during the years 2001, 2000 and 1999, respectively. Furthermore, PDVSA is currently developing Venezuela's significant extra-heavy crude oil reserves with several foreign companies through joint ventures (see note 8(a) to the consolidated financial statements).

At December 31, 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 (expressed in millions of barrels):

	2001				2000
	Projects		Total including projects		Projects		Total including projects
Proved developed and undeveloped reserves of extra-heavy crude oil at January 1	9,776		35,687		5,652		35,689
Revisions (1)	1,079		—		4,181		101
Production	(87	)	(129	)	(57	)	(103	)

Proved developed and undeveloped reserves of extra-heavy crude oil at December 31	10,768		35,558		9,776		35,687

Proved developed extra-heavy crude oil reserves at December 31	1,170		1,963		646		1,375

Net proved extra-heavy crude oil reserves in unincorporated joint ventures at December 31	8,121				7,089
Net proved extra-heavy crude oil reserves in equity affiliate at December 31	2,647				2,687

	10,768				9,776

(1): Include transfers from unassigned areas.
(2): In 2000, excludes the Hamaca joint venture, which was in its initial development stage.

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(b): Natural gas reserves:

			2001		2000		1999
			(Billions of cubic feet)
Proved developed and undeveloped reserves of natural gas at January 1			135,080		134,174		134,136
	Revisions		997		1,957		1,413
	Extensions and new discoveries		1,209		446		—
	Production		(1,467	)	(1,497	)	(1,375	)

Proved developed and undeveloped reserves of natural gas at December 31			135,819		135,080		134,174
Proved reserves related to extra-heavy crude reserves at December 31			12,476		12,505		12,437

		Total proved developed and undeveloped reserves at December 31	148,295		147,585		146,611

		Total proved developed reserves, submitted to production, including quantities associated with extra-heavy crude oil in production at December 31 (included above)	103,807		103,310		102,625

Proved natural gas reserves include the portion of liquefiable natural hydrocarbons recoverable in PDVSA's processing plants. In 2001, 2000 and 1999, natural gas liquids recovered amounted to some 63 million, 63 million and 65 million barrels, respectively.

Production of natural gas is shown on the basis of actual volumes before the extraction of liquefiable hydrocarbons. During 2001, 2000 and 1999, natural gas utilized in reinjection operations amounted to 695 billion, 720 billion and 700 billion cubic feet, 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 below, include amounts both expensed and capitalized for PDVSA's conventional and extra-heavy crude oil reserves (expressed in millions of dollars):

		2001				2000				1999
		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		174	—		174	169	—		169	118	—		118
Development costs		1,364	792	(2)	2,156	1,207	851	(2)	2,058	1,339	785	(2)	2,124

	Total	1,538	792		2,330	1,376	851		2,227	1,457	785		2,242

Equity affiliate (1)		—	86		86	—	387		387	—	197		197

	Total	1,538	878		2,416	1,376	1,238		2,614	1,457	982		2,439

(1): Represents PDVSA's equity share of the PETROZUATA joint venture.
(2): Represents PDVSA's proportional share in unincorporated joint ventures.

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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 (expressed in millions of dollars):

		2001						2000						1999
		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)		31,255		1,038		32,293		30,949		312		31,261		29,426		176		29,602
Support facilities		12,657		5		12,662		11,748		6		11,754		11,404		4		11,408

	Total	43,912		1,043		44,955		42,697		318		43,015		40,830		180		41,010
Accumulated depreciation and depletion		(25,720	)	(43	)	(25,763	)	(24,680	)	(17	)	(24,697	)	(23,049	)	(2	)	(23,051	)
Construction in progress		3,092		1,674		4,766		2,943		1,607		4,550		3,603		894		4,497

Net capitalized costs		21,284		2,674		23,958		20,960		1,908		22,868		21,384		1,072		22,456
Equity affiliate (2)		—		1,394		1,394		—		1,308		1,308		—		921		921

	Total	21,284		4,068		25,352		20,960		3,216		24,176		21,384		1,993		23,377

(1): Includes land of $139 million, $121 million and $116 million at December 31, 2001, 2000 and 1999, 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):

				31 December
				2001						2000						1999
				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			14,091		254		14,345		21,310		227		21,537		11,508		7		11,515
		Transfers		8,931		—		8,931		9,594		—		9,594		6,478		—		6,478
		Production costs		(4,888	)	(76	)	(4,964	)	(5,037	)	(105	)	(5,142	)	(3,748	)	(10	)	(3,758	)
		Production and other taxes		(3,757	)	(32	)	(3,789	)	(4,953	)	(31	)	(4,984	)	(2,983	)	(1	)	(2,984	)
		Depreciation and depletion		(1,479	)	(25	)	(1,504	)	(1,814	)	(2	)	(1,816	)	(1,402	)	(1	)	(1,403	)
		Exploration costs		(174	)	—		(174	)	(169	)	—		(169	)	(118	)	—		(118	)

			Results before income tax	12,724		121		12,845		18,931		89		19,020		9,735		(5	)	9,730
Income tax				(8,218	)	—		(8,218	)	(12,035	)	—		(12,035	)	(6,268	)	—		(6,268	)

			Results from production operations	4,506		121		4,627		6,896		89		6,985		3,467		(5	)	3,462
Equity affiliate (1)				—		114		114		—		212		212		—		87		87

			Total	4,506		235		4,741		6,896		301		7,197		3,467		82		3,549

(1): Represents PDVSA's equity share of the PETROZUATA 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 tax referred to above and the operating income reported for the upstream segment in note 15 to the consolidated financial statements for the years ended 2001, 2000 and 1999, 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 $2,796 million, $4,119 million and $2,110 million, respectively; (2) the inclusion in the business segment of general expenses and other of some $1,670 million, $1,380 million and $260 million, respectively and; (3) certain intercompany charges of some $391 million, $759 million and $320 million, 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 $2,110 million, $2,157 million and $1,272 million, paid to independent contractors under service contracts during 2001, 2000 and 1999, respectively, which relate to the

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production of 183 million, 170 million and 147 million barrels of crude oil during 2001, 2000 and 1999, 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, two of the facilities for the production of synthetic crude oil are in the commercial production stage and two are 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.

The following table summarizes average per unit sales prices and production costs for the years ended December 31 (expressed in dollars):

		2001	2000	1999
Average sales price:
	Crude oil, per barrel	18.95	24.94	15.35
	Natural gas liquids, per barrel	19.55	25.42	14.71
	Natural gas, per barrel	5.35	5.29	4.24
	Average production costs, per barrel of oil equivalent	3.38	3.48	2.72
	Average production costs, per barrel of oil equivalent, excluding operating agreements	2.17	2.22	2.00

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 synthetic crude that will be produced in the upgrading facilities. Synthetic 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

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should not be relied upon as an indication of PDVSA's future cash flows or the value of its oil and gas reserves (expressed in millions of dollars):

		December 31
		2001						2000						1999
		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		893,878		27,364		921,242		1,220,395		33,158		1,253,553		1,167,935		35,676		1,203,611
Future production costs		(187,727	)	(7,108	)	(194,835	)	(142,434	)	(5,206	)	(147,640	)	(148,073	)	(8,961	)	(157,034	)
Future production taxes		(251,816	)	(3,418	)	(255,234	)	(203,440	)	(4,181	)	(207,621	)	(194,695	)	(4,528	)	(199,223	)
Future development costs		(60,136	)	(2,220	)	(62,356	)	(73,296	)	(1,502	)	(74,798	)	(62,150	)	(3,642	)	(65,792	)
Future income tax expense		(179,962	)	(3,918	)	(183,880	)	(499,905	)	(6,876	)	(506,781	)	(471,286	)	(5,711	)	(476,997	)

Future net cash flows		214,237		10,700		224,937		301,320		15,393		316,713		291,731		12,834		304,565
Effect of discounting net cash flows at 10%		(172,961	)	(7,881	)	(180,842	)	(225,369	)	(11,866	)	(237,235	)	(215,187	)	(9,859	)	(225,046	)

Discounted future net cash flows		41,276		2,819		44,095		75,951		3,527		79,478		76,544		2,975		79,519
Equity affiliate (1)		—		1,124		1,124		—		2,065		2,065		—		1,704		1,704

	Total	41,276		3,943		45,219		75,951		5,592		81,543		76,544		4,679		81,223

(1): Represents PDVSA's equity share of the PETROZUATA 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 for each year (expressed in millions of dollars):

			December 31
			2001						2000						1999
			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			(11,446	)	(60	)	(11,506	)	(21,342	)	(91	)	(21,433	)	(11,255	)	3		(11,252	)
Value of reserves added during the year due to extensions and discoveries			902		1,229		2,131		877		2,208		3,085		—		5,132		5,132

			(10,544	)	1,169		(9,375	)	(20,465	)	2,117		(18,348	)	(11,255	)	5,135		(6,120	)
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		1,339		777		2,116
	Change in future development costs		2,272		(317	)	1,955		(3,328	)	286		(3,042	)	(4,898	)	(1,022	)	(5,920	)
	Net changes in prices and production costs		(81,216	)	(3,887	)	(85,103	)	13,342		315		13,657		160,953		—		160,953
	Revisions of previous reserve estimates		1,161		—		1,161		6,415		—		6,415		6,122		—		6,122
	Net changes in income taxes		61,642		1,012		62,654		(7,214	)	(334	)	(7,548	)	(99,874	)	(1,319	)	(101,193	)
	Net changes in production rates and other		(9,354	)	498		(8,856	)	9,450		(2,586	)	6,864		9,781		(596	)	9,185

		Total change during the year	(34,674	)	(733	)	(35,407	)	(593	)	552		(41	)	62,168		2,975		65,143
Equity affiliate (1)			—		(915	)	(915	)	—		361		361		—		1,781		1,781

		Total	(34,674	)	(1,648	)	(36,322	)	(593	)	913		320		62,168		4,756		66,924

(1): Represents PDVSA's equity share of the PETROZUATA joint venture.
(19): Subsequent Events (Unaudited)

On June 6, 2002, a cash dividend amounting to $1,533 million was declared (based on the June 6, 2002 exchange rate of Bs.1,147 to $1).

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In June 2002, the Venezuelan government and the National Assembly authorized PDVSA to withdraw up to $2,445 million of the funds deposited with the FIEM.

At the end of February 2002, PDVSA personnel initiated labor actions against political decisions of the Venezuelan government related to PDVSA matters. These protests resulted in a period of disruption in production at some of PDVSA's Venezuelan refineries and shipping terminals. In April 2002, PDVSA's operations returned to normal.

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