20-F 1 a05-17375_120f.htm 20-F

 

As filed with the Securities and Exchange Commission on October 7, 2005.

 

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, 2003

 

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:  None.

 

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. 6.650% 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, 2003.

 

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

o

No

ý

 

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

 

Item 17

o

Item 18

ý

 

If this is an annual report, indicate check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).  which financial statement item the registrant has elected to follow.

 

Yes

o

No

ý

 

 



 

TABLE OF CONTENTS

 

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

 

Item 12.

Description of Securities Other than Equity Securities

 

 

 

 

PART II

 

 

 

 

 

Item 13.

Defaults, Dividend Arrearages and Delinquencies

 

Item 14.

Material Modifications to the Rights of Security Holders and Use of Proceeds

 

Item 15.

Controls and Procedures

 

Item 16.

[Reserved]

 

Item 16A.

Audit Committee Financial Expert

 

Item 16B.

Code of Ethics

 

Item 16C.

Principal Accountant Fees and Services

 

Item 17.

Financial Statements

 

Item 18.

Financial Statements

 

Item 19.

Exhibits

 

 

 

 

ANNEX A

 

 

 

i



 

INCORPORATION OF CERTAIN DOCUMENTS BY REFERENCE

 

With respect to our obligations as co-registrant of PDVSA Finance Ltd.’s 6.650% Notes due 2006, 9.375% Notes due 2007, 6.800% Notes due 2008, 9.750% Notes due 2010, 8.500% Notes due 2012, 7.400% Notes due 2016, 9.950% Notes due 2020 and 7.500% Notes due 2028 (collectively, the “PDVSA Finance Notes”), PDVSA Finance Ltd.’s annual report on Form 20-F for the year ended December 31, 2003, as first filed with the U.S. Securities and Exchange Commission (Commission file No. 333-09678) on October 7, 2005 is incorporated herein by reference.

 

FACTORS AFFECTING FORWARD-LOOKING STATEMENTS

 

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

 

The annual report on Form 20-F of PDVSA Finance Ltd., our wholly-owned subsidiary, for the year ended December 31, 2003 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 1 thereof.

 

ii



 

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,”  “the Company” 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

 

“BCV” – Banco Central de Venezuela

 

“Bitor” – Bitúmenes Orinoco, S.A.

 

“BOPEC” – Bonaire Petroleum Corporation N.V.

 

“BORCO” – The Bahamas Oil Refining Company International Limited

 

“BP” – British Petroleum

 

“BP RP” – British Petroleum Refining & Petrochemical GmbH

 

“Carbozulia” – Carbones del Zulia, S.A.

 

“Chalmette Refining” – Chalmette Refining, L.L.C.

 

“ChevronTexaco” – ChevronTexaco Corporation

 

“CIED” – Centro Internacional de Educación y Desarrollo

 

“CITGO” – CITGO Petroleum Corporation

 

“CITGO Latin America” – CITGO International Latin America, Inc.

 

“ConocoPhillips” – ConocoPhillips

 

“CVP” – Corporación Venezolana del Petróleo, S.A.

 

“Deltaven” – Deltaven, S.A.

 

“ExxonMobil” – ExxonMobil Corporation

 

“FEM” – Fondo para la Estabilización Macroeconómica (Macroeconomic Stabilization Fund)

 

“FONDESPA” – Fondo para el Desarrollo Económico y Social del País

 

“Fortum Oil and Gas” – Fortum Oil and Gas OY

 

“Hovensa” – Hovensa, L.L.C.

 

“ENI” – Eni B.V.

 

1



 

“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.P.

 

“Neste Oil Corporation” – Neste Oil

 

“Nynäs” – AB Nynäs Petroleum

 

“OPEC” – Organization of Petroleum Exporting Countries

 

“PDV America” – PDV America, Inc.

 

“PDV Chalmette” – PDV Chalmette, Inc.

 

“PDV Europa” – PDV Europa B.V.

 

“PDV Holding” – PDV Holding, Inc.

 

“PDV Marina” – PDV Marina, S.A.

 

“PDVMR” – PDV Midwest Refining, L.L.C.

 

“PDV VI” – PDVSA Virgin Island, Inc.

 

“PDVSA Cerro Negro” – PDVSA Cerro Negro, S.A.

 

“PDVSA Finance” – PDVSA Finance Ltd.

 

“PDVSA Gas” – PDVSA Gas, S.A.

 

“PDVSA Petróleo” – PDVSA Petróleo, S.A.

 

“PDVSA Sincor” – PDVSA Sincor, S.A.

 

“PDVSA-P&G” – PDVSA Petróleo y Gas, S.A.

 

“Pequiven” – Petroquímica de Venezuela, S.A.

 

“Petrozuata” – Petrolera Zuata, C.A.

 

“Phillips Petroleum” – Phillips Petroleum Corporation

 

“Ruhr” – Ruhr Oel GmbH

 

“SEC” –  Securities and Exchange Commission

 

“Statoil” – Statoil Sincor AS

 

“Total Fina” – Total Fina Venezuela, S.A.

 

2



 

“Veba Oel” – Veba Oel AG

 

“Venezuela” – The Bolivarian Republic of Venezuela

 

3



 

PART I

 

Item 1.            Identity of Directors, Senior Management and Advisers

 

Not Applicable.

 

Item 2.            Offer Statistics and Expected Timetable

 

Not Applicable.

 

Item 3.            Key Information

 

3.A          Selected financial data

 

The selected data presented below for, and as of the end of, each of the years in the five-year period ended December 31, 2003, are derived from the audited consolidated financial statements of PDVSA.  See “Item 18.  Financial Statements.”

 

 

 

At or for the Year Ended December 31,

 

 

 

2003

 

2002

 

2001

 

2000

 

1999

 

 

 

($ in millions)

 

Income Statement Data:

 

 

 

 

 

 

 

 

 

 

 

Sales of crude oil and products

 

 

 

 

 

 

 

 

 

 

 

Exports and international markets

 

44,178

 

39,875

 

42,682

 

49,780

 

30,369

 

In Venezuela

 

961

 

1,236

 

1,701

 

2,230

 

1,450

 

Petrochemical and other sales

 

1,071

 

1,201

 

1,403

 

1,224

 

781

 

Net sales

 

46,210

 

42,312

 

45,786

 

53,234

 

32,600

 

Equity in earnings of non-consolidated investees

 

379

 

268

 

464

 

446

 

48

 

Total revenues

 

46,589

 

42,580

 

46,250

 

53,680

 

32,648

 

Total costs and expenses

 

41,400

 

39,073

 

37,977

 

40,029

 

26,636

 

Operating income

 

5,189

 

3,507

 

8,273

 

13,651

 

6,012

 

Financing expenses

 

627

 

763

 

509

 

672

 

662

 

Income before income taxes and minority interests and cumulative effect of accounting change

 

4,562

 

2,744

 

7,764

 

12,979

 

5,350

 

Provision for income taxes

 

(1,602

)

(149

)

(3,766

)

(5,748

)

(2,521

)

Minority interests

 

(6

)

(5

)

(5

)

(15

)

(11

)

Income before cumulative effect of accounting change

 

2,954

 

2,590

 

3,993

 

7,216

 

2,818

 

Cumulative effect of accounting change for the cost of asset retirement obligations

 

(234

)

 

 

 

 

Net income

 

2,720

 

2,590

 

3,993

 

7,216

 

2,818

 

Balance Sheet Data:

 

 

 

 

 

 

 

 

 

 

 

Cash and cash equivalents

 

2,938

 

1,703

 

925

 

3,257

 

1,079

 

Notes and accounts receivable

 

4,955

 

3,515

 

3,280

 

4,435

 

3,820

 

Total assets

 

55,355

 

54,939

 

57,200

 

57,600

 

49,990

 

Current portion of long-term debt(1)

 

750

 

1,817

 

1,000

 

596

 

910

 

Long-term debt and capital lease obligations (excluding current portion).

 

6,265

 

6,426

 

7,544

 

7,187

 

7,892

 

Stockholder’s equity

 

37,418

 

37,288

 

37,098

 

37,932

 

32,894

 

Capital stock

 

39,094

 

39,094

 

39,094

 

39,094

 

39,094

 

Other Financial Data:

 

 

 

 

 

 

 

 

 

 

 

Net cash provided by operating activities

 

5,746

 

4,880

 

6,965

 

10,285

 

4,633

 

Net cash used in investing activities

 

(902

)

(1,226

)

(5,263

)

(5,360

)

(3,326

)

Net cash used in financing activities

 

(3,609

)

(2,836

)

(4,034

)

(2,747

)

(913

)

Capital expenditures

 

1,969

 

2,743

 

3,781

 

3,185

 

3,041

 

Depreciation and depletion

 

2,824

 

3,038

 

2,624

 

3,001

 

2,821

 

Debt/Equity(2)

 

19

%

22

%

23

%

21

%

27

%

Total payments to shareholder

 

9,585

 

9,474

 

12,097

 

11,641

 

6,549

 

Dividends(3) (5)

 

2,326

 

2,652

 

4,862

 

1,732

 

1,719

 

Production tax

 

5,944

 

5,911

 

3,792

 

4,954

 

2,654

 

Income taxes(4)

 

1,315

 

911

 

3,443

 

4,955

 

2,176

 

 

4



 


(1)           Excludes current portion of capital lease obligations, which amounted to $20 million, $30 million, $62 million, $122 million and $117 million in 2003, 2002, 2001, 2000 and 1999, respectively.

(2)           Calculated as total debt (long-term debt, including current portion of long-term debt and capital leases) divided by stockholder’s equity.

(3)           During 1999, special tax recovery certificates, or CERTs, amounting to $1,291 million were used to pay dividends.

(4)           During 2001, 2000 and 1999, we used CERTs amounting to $84 million, $255 million and $22 million, respectively, to pay income taxes.

(5)           During 2003, $251million of trade notes receivable were distributed as a dividend.

 

 

 

At or for the Year Ended December 31,

 

 

 

2003

 

2002

 

2001

 

2000

 

1999

 

 

 

(MBPD, unless otherwise indicated)

 

Operating Data:

 

 

 

 

 

 

 

 

 

 

 

Production

 

 

 

 

 

 

 

 

 

 

 

Condensate

 

22

 

46

 

48

 

50

 

43

 

Light crude oil (API gravity of 30° or more)

 

727

 

774

 

1,135

 

1,174

 

1,189

 

Medium crude oil (API gravity of between 21° and 30°)

 

914

 

962

 

1,018

 

1,047

 

1,095

 

Heavy crude oil (API gravity of less than 21°)

 

788

 

877

 

893

 

814

 

623

 

Total crude oil

 

2,451

 

2,659

 

3,094

 

3,085

 

2,950

 

Liquid petroleum gas

 

144

 

173

 

173

 

167

 

177

 

Total crude oil and liquid petroleum gas

 

2,595

 

2,832

 

3,267

 

3,252

 

3,127

 

Net natural gas (MMCFD)(1)

 

3,432

 

3,672

 

4,093

 

3,979

 

3,766

 

Total crude oil, liquid petroleum gas and net natural gas (BOE)(2)

 

3,187

 

3,464

 

3,973

 

3,938

 

3,776

 

Sales volumes exported

 

 

 

 

 

 

 

 

 

 

 

Exports of crude oil with 30° or greater API

 

657

 

672

 

659

 

716

 

1,010

 

Exports of crude oil with less than 30° API

 

991

 

1,092

 

1,406

 

1,282

 

913

 

Exports of refined petroleum products

 

502

 

647

 

697

 

825

 

861

 

Total

 

2,150

 

2,411

 

2,762

 

2,823

 

2,784

 

Average export prices per unit ($ per barrel)

 

 

 

 

 

 

 

 

 

 

 

Exports of crude oil with 30° or greater API

 

$

27.16

 

$

23.46

 

$

22.47

 

$

28.20

 

$

17.08

 

Exports of crude oil with less than 30° API

 

$

22.56

 

$

20.24

 

$

17.29

 

$

23.12

 

$

13.45

 

Exports of refined petroleum products

 

$

26.53

 

$

24.23

 

$

23.94

 

$

28.40

 

$

17.80

 

Weighted average export prices(3)

 

$

24.89

 

$

21.94

 

$

20.21

 

$

25.91

 

$

16.04

 

Average production costs ($ per BOE)

 

 

 

 

 

 

 

 

 

 

 

Production cost per BOE of production, excluding operating service agreements(4)

 

$

2.06

 

$

2.42

 

$

2.17

 

$

2.22

 

$

2.00

 

Production cost per BOE of production (4)

 

$

3.85

 

$

3.92

 

$

3.38

 

$

3.48

 

$

2.72

 

Depreciation and depletion cost per BOE of production

 

$

0.53

 

$

0.54

 

$

0.38

 

$

0.46

 

$

0.37

 

 

 

 

 

 

 

 

 

 

 

 

 

Proved reserves(5)

 

 

 

 

 

 

 

 

 

 

 

Crude oil (MMB)

 

 

 

 

 

 

 

 

 

 

 

Condensate

 

1,919

 

1,900

 

1,723

 

1,772

 

1,847

 

Light crude oil (API gravity of 30° or more)

 

10,078

 

10,012

 

10,345

 

10,244

 

10,258

 

Medium crude oil (API gravity of between 21° and 30°)

 

12,340

 

12,450

 

12,891

 

12,804

 

12,195

 

Heavy crude oil (API gravity of between 11° and 21°)

 

17,617

 

17,414

 

17,266

 

17,177

 

16,861

 

Extra-heavy crude oil (API gravity of less than 11°)(6)

 

35,186

 

35,381

 

35,558

 

35,688

 

35,701

 

Total crude oil

 

77,140

 

77,157

 

77,783

 

77,685

 

76,862

 

Of which, relating to Operating Service Agreements(7)

 

5,446

 

5,501

 

5,600

 

5,479

 

5,450

 

Natural gas (BCF)(8)

 

150,043

 

147,109

 

148,295

 

147,585

 

146,611

 

Proved reserves of crude oil and natural gas (MMBOE) (6)

 

103,009

 

102,521

 

103,351

 

103,131

 

102,140

 

Remaining reserve life of proved crude oil reserves (years)(9)

 

74

x

70

x

64

x

64

x

70

x

Net crude oil refining capacity (MBPD) (10)

 

 

 

 

 

 

 

 

 

 

 

Venezuela (including Isla Refinery)

 

1,628

 

1,628

 

1,628

 

1,620

 

1,620

 

United States

 

1,205

 

1,205

 

1,205

 

1,198

 

1,224

 

Europe

 

259

 

252

 

252

 

252

 

252

 

Total

 

3,092

 

3,085

 

3,085

 

3,070

 

3,096

 

 

5



 


(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, 2003, approximately 10,483 MMB reserves are 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 12,427 BCF, 12,454 BCF, 12,476 BCF, 12,505 BCF and 12,400 BCF in each of 2003, 2002, 2001, 2000 and 1999, 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 are being developed in association with third parties.  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 BCV pursuant to a foreign exchange agreement between Venezuela’s Ministry of Finance and the BCV.  See notes 2, 3 and 22(b) to our consolidated financial statements, included under “Item 18.  Financial Statements.”

 

 

 

Year ended December 31,

 

 

 

Period End

 

Average (1)

 

High

 

Low

 

1999

 

647.53

 

609.29

 

 

 

 

 

2000

 

698.23

 

679.80

 

 

 

 

 

2001

 

770.09

 

722.01

 

 

 

 

 

2002

 

1,403.00

 

1,163.91

 

 

 

 

 

2003

 

1,600.00

 

1,611.32

 

 

 

 

 

2004(2)

 

1,920.00

 

1,893.00

 

 

 

 

 

February, 2005

 

 

 

 

 

1,920.00

 

1,915.20

 

March 2005—August, 2005(3)

 

 

 

 

 

2,150.00

 

2,144.60

 

 


(1)           Represents the average exchange rate for each full month during the year, calculated based on the average daily exchange rate established by the BCV pursuant to the foreign exchange agreement referred to above.

 

(2)           The exchange rate for the sale and purchase of the bolivar relative to the dollar was fixed by the Venezuelan government pursuant to a new foreign exchange regime of Bs. 1,920.00 to $1 and Bs. 1,915.20 to $1, respectively, commencing February 7, 2004.

 

(3)           The exchange rate for the sale and purchase of the bolivar relative to the dollar was fixed by the Venezuelan government pursuant to a new foreign exchange regime at Bs. 2,150.00 to $1 and Bs. 2,144.60 to $1, respectively, commencing March 2, 2005.

 

On February 13, 2002, the Venezuelan government and the BCV adopted a floating exchange rate system in place of the band system.  On January 21, 2003, the Venezuelan government and the BCV adopted temporary measures to restrict the convertibility of the Bolivar, and on February 5, 2003, the Venezuelan government

 

6



 

established a foreign exchange regime, setting the exchange rates for the sale and purchase of foreign currency at Bs. 1,600.00 to $1 and Bs. 1,596.00 to $1, respectively.  It also created the Commission for the Administration of Foreign Exchange (CADIVI) and established rules for the administration and control of foreign currency.  On February 7, 2004 a new foreign exchange rate for the sale and purchase of foreign currency was established at Bs. 1,920.00 to $1 and Bs. 1,915.20 to $1, respectively.  On March 2, 2005 a new foreign exchange rate for the sale and purchase of foreign currency was established at Bs. 2,150.00 to $1 and Bs. 2,144.60 to $1, respectively.

 

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

 

3.D          Risk factors

 

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

 

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

 

      changes in global supply and demand for crude oil and refined petroleum products;

 

      political events in major oil producing and consuming nations;

 

      agreements among OPEC members;

 

      the availability and price of competing products;

 

      actions of commodity markets participants and competitors;

 

      international economic trends;

 

      technological advancements and developments in the industry;

 

      currency exchange fluctuations; and

 

      inflation.

 

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

 

Any reduction in our crude oil production or export activities that could occur as a result of changes in OPEC’s production quotoas 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 results of operations, cash flows and financial results.

 

Risks related to the ownership, regulation and supervision of PDVSA.

 

The Bolivarian Republic of Venezuela is the sole owner of Petróleos de Venezuela.  The Venezuelan government, through the Ministry of Energy and Petroleum, establishes national petroleum policies and also

 

7



 

regulates and supervises PDVSA’s operations.  The President of Venezuela appoints the president of Petróleos de Venezuela and the members of its board of directors by executive decree.  Since November 2004, the Minister of Energy and Petroleum has also served as our President.  However, the Bolivarian Republic of Venezuela is not legally liable for the obligations of Petróleos de Venezuela, including our guarantees of indebtedness of our subsidiaries, or the obligations of our subsidiaries.

 

Petróleos de Venezuela has been operated as an independent commercial entity since our formation; however, recent changes to the Venezuelan law regarding the oil sector impose significant social commitments upon PDVSA, which will affect our saving capacity, and, indirectly, our commercial affairs.  Given that PDVSA is controlled by the Venezuelan government, we cannot assure you that the Venezuelan government will not in the future impose further material commitments upon PDVSA or intervene in our commercial affairs in a manner that will adversely affect our business.  For instance, through Petróleos de Venezuela, the government could cause PDVSA Petróleo to reduce production or limit future capital expenditure to levels that would limit PDVSA Petróleo’s ability to generate the necessary flow of receivables to support payments on our indebtedness.  In addition, despite recent precautions taken by the Company, we cannot assure you that opponents of the Venezuelan government will not seek to disrupt our activities through actions such as the work stoppages that occurred in late 2002 and early 2003, which in PDVSA’s opinion constituted sabotage.

 

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.  The exploration of these hydrocarbon reserves are reserved to Venezuela.  PDVSA was formed to coordinate, monitor and control operations related to Venezuela’s hydrocarbon reserves.

 

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

 

Our business requires substantial capital expenditures.

 

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

 

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

 

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

 

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

 

8



 

Item 4.            Information on the Company

 

4.A          History and development of the company

 

PDVSA is the national oil and gas company of Venezuela.  PDVSA was formed by the Venezuelan government in 1975 pursuant to the Organic Law Reserving to the State, the Industry and Commerce of Hydrocarbons (the “Nationalization Law”), and its operations are supervised by Venezuela’s Ministry of Energy and Petroleum (formerly the Ministry of Energy and Mines).  Through its subsidiaries, PDVSA supervises, controls and develops the petroleum, petrochemical, gas, coal and Orimulsion® industries in Venezuela.  These activities are complemented by PDVSA’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 and Related Party Transactions.”

 

PDVSA’s oil-related activities are governed by the Organic 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, PDVSA has been operated as a commercial entity, vested with commercial and financial autonomy.  PDVSA 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.

 

Furthermore, the National Constitution of the Bolivarian Republic of Venezuela and the Organic Hydrocarbons Law mandates that PDVSA contribute to social programs developed and administered by the Venezuelan government.  For example, PDVSA and its subsidiaries Palmeven and CVP contribute management as well as financial resources in support of social programs related to education, healthcare, job creation, and subsidized food distribution.

 

PDVSA is domiciled in Venezuela and its registered office is located at Avenida Libertador, La Campiña, Apdo. 169, Caracas 1010-A, Venezuela, and our telephone number is 011-58-212-708-4111.  Our website is: www.pdvsa.com.  Information contained on our website is not incorporated by reference into this annual report.

 

4.B          Business overview

 

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

 

 

the exploration, production and upgrading of crude oil and natural gas or upstream operations;

 

 

 

 

the exploration, production of natural gas from offshore sources, including the possibility for LNG export;

 

 

 

 

the refining, marketing and transportation of crude oil and refined petroleum products and the processing, marketing and transporation of natural gas, or downstream operations;

 

 

 

 

the production and marketing of petrochemicals. For our main petrochemical business unit “Pequiven,” the Venezuelan government decided in June 2005 to transfer the activities, assets and shares held by PDVSA in Pequiven (the company’s shareholder) to the Ministry of Energy and Petroleum and to submit this transfer for approval by the Shareholder of PDVSA. The transfer is subject to the reform of the Petrochemical Act and the resolution of other legal and administrative issues;

 

 

 

 

the development and marketing of Orimulsion®, Venezuela’s derivative of heavy and extra-heavy crude, which will be produced until expiration of the current supply agreement.

 

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

 

9



 

PDVSA has been structured in three vertically integrated geographic divisions to manage its upstream operations, including:  exploration, production, and upgrading.  These divisions are:  Eastern, Southern and the Western Division.  Since August 2003, CVP, a subsidiary, assumed from PDVSA Petróleo the management of the third party contracts (operating and profit sharing agreements), the Orinoco Belt joint ventures and ultimately offshore natural gas licenses.

 

Our downstream operations include:

 

      operation of refineries, marketing of crude oil and refined petroleum products in Venezuela under the PDV brand name and under the CITGO brand name for the eastern and midwestern regions of the United States;

 

      conduct of most of our business in the Caribbean through the Isla Refinery (a refinery and storage terminal which we lease in Curaçao);

 

      operation of the storage terminals in Bonaire and the Bahamas in the Caribbean;

 

      ownership of equity interests in three refineries (one 50%-owned by ExxonMobil, one 58.75%-owned by Lyondell and one 50%-owned by Amerada Hess) and in a coker/vacuum crude distillation unit (50%-owned by ConocoPhillips) through joint ventures in the United States;

 

      ownership of equity interests in eight refineries and market petroleum products in Germany, United Kingdom, Belgium and Sweden through two joint ventures (one 50%-owned by BP RP and one 50%-owned by Neste Oil, which currently owns Fortum Oil and Gas);

 

      processing, marketing and transport of all natural gas in Venezuela; and

 

      conduct of shipping activities.

 

In the United States, we conduct our crude oil refining operations and refined petroleum product marketing through our wholly owned subsidiary, PDV Holding, which owns through PDV America, 100% of CITGO.  CITGO also owns 41.25% of Lyondell-Citgo Refining LP.  CITGO refines, markets and transports gasoline, diesel fuel, jet fuel, petrochemicals, lubricants, asphalt and other refined petroleum products in the United States.  CITGO’s transportation fuel customers include primarily CITGO branded independent wholesale marketers, major convenience store chains and airlines located mainly along the east of the Rocky Mountains.  Asphalt is generally marketed to independent paving contractors on the East Gulf and the Midwest Coasts of the United States.  Lubricants are sold primarily in the United States to independent marketers, mass marketers and industrial customers.  During 2003 CITGO sold lubricants, gasoline, and distillates in various Latin American markets, including Puerto Rico, Brazil, Ecuador, Chile, Argentina, Dominican Republic, Mexico, Panama and Guatemala, however, these activities were recently transferred to another PDVSA affiliate.  Petrochemical feedstocks and industrial products are sold to various manufacturers and industrial companies across the United States.  Petroleum coke is sold essentially in international markets.  In 2004, CITGO sold a total of 26,811 millions gallons of petroleum products compared to 27,704 millions in the year 2003.

 

PDV Holding owns 50% of Chalmette Refining LLC (through PDV Chalmette) and 50% of Merey Sweeny L.P. (through PDV Sweeny).  These joint ventures with Exxon Mobil and ConocoPhillips, respectively, process crude oil in the United States.  PDVSA also owns 50% of Hovensa, a joint venture with Amerada Hess that processes 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 2004, equivalent to 1,205 MBPD.

 

Within Europe, we conduct our crude oil refining and refined petroleum product activities through PDV Europa, which owns our 50% interest in Ruhr, a company based in Germany and jointly owned with BP.  PDVSA also owns a 50% interest in Nynäs, a company with operations in Belgium, Sweden and the United Kingdom and jointly owned with Neste Oil, which currently owns Fortum Oil and Gas.  Through Ruhr, we refine crude oil and

 

10



 

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.

 

In Venezuela we have been conducting our petrochemical activities mainly through Pequiven, which has three petrochemical complexes in Venezuela and 17 joint ventures with private sector partners.  However, as previously discussed, the Venezuelan Government decided in June 2005 to transfer Pequiven to the Ministry of Energy and Petroleum and Pequiven is currently evaluating the sale and transfer of its 17 joint ventures.  Nevertheless, PDVSA will supply the feedstocks required by Pequiven. See also “Item 4.B Business overview – Marketing – Marketing in Venezuela – Petrochemicals.”

 

The gas business is conducted by the previously mentioned divisions (east and west exploration and production divisions), while the gas downstream operations and LNG segments are conducted by PDVSA Gas.  CVP manages offshore gas natural projects.

 

Since 1997, Deltaven, a local retailing subsidiary, has marketed and distributed retail gasoline and other refined petroleum products in Venezuela, under the PDV brand.  Deltaven also is promoting the development of the commercial infrastructure and services for retail clients together with the private sector.

 

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

 

Another important subsidiary is Intevep, through which we manage our research and development activities.  PDVSA also has an educational center, CIED, which is responsible for the training and development of our personnel.  CIED is currently under a restructuring process to better suit current PDVSA’s needs.

 

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

 

According to a comparative study published by Petroleum Intelligence Weekly on December 13, 2004, based on a combination of operating criteria and other data for 2003, such as: reserves, production, refining capacity and refined petroleum product sales, PDVSA is the world’s fourth largest vertically integrated oil and gas company, ranked fifth in the world in production, fifth in proved reserves of crude oil, fourth in refining capacity and eighth in product sales.  Venezuela has been exporting crude oil, primarily to the United States, continously since 1914.  At the end of 2003, we exported to the US market approximately 1,183 MBPD of crude oil and petroleum products and by December 2004, we were exporting to the US market approximately 1,367 MBPD of crude oil and petroleum products.

 

The oil sector has a great impact on the Venezuelan economy.  In 2003, PDVSA accounted for approximately 18% of Venezuelan gross domestic product, 67% of its exports and 57% of government revenues.  In 2004, PDVSA accounted for approximately 27% of Venezuelan gross domestic product, 83% of its exports and 48% of government revenues.

 

Business Strategy

 

Our business strategy is focused on the development of Venezuela’s hydrocarbon resources on behalf of the country with the support of both national and foreign private capital.  This strategy aims to maximize the value of oil and gas resources and also to ensure our financial strength and stability, within the context of the dynamics of the energy market.  Since oil is a nonrenewable resource with an expected imbalance between oil demand and supply for the mid-term, we continue to participate actively in the world oil market in order to receive a fair and stable oil price.  Investments have to be made to avoid this expected imbalance, especially considering that it is predicted that an imbalance between the installed refining capacity and the market for refined products also exists.

 

This core strategy has been ratified in the 2005-2010 Corporate Business Plan.

 

11



 

PDVSA plans to intensively invest in both upstream and downstream projects in order to satisfy the current and expected increasing energy demand.

 

According to this plan for 2005-2010, operations in Venezuela will focus on:

 

      The exploration of condensate, light and medium crude oil.  PDVSA financial resources will be mainly concentrated on the backyard areas.  All other exploration regions either onshore or offshore are opened for third party participation, under the umbrella of the Venezuelan Organic Hydrocarbon Law, Gaseous Hydrocarbon Organic Law and, of course, the National Constitution.

 

      The production and marketing of the heavy and extra-heavy crude oil, including the huge reserves in the Orinoco Belt.  According to the laws mentioned above, PDVSA is willing to develop new business opportunities with third parties in order to manufacture high quality products.

 

      The gas sector development.  PDVSA is planning thefast track development of this business segment with third party participation in either onshore or offshore and under the framework of Venezuela’s Gaseous Hydrocarbon Law.

 

      In the downstream business we are looking for the right balance between our overseas and local assets in order to assure the domestic supply and quality for customers, in line with the strategy of maximizing the value of Venezuelan oil and gas resources.

 

      A new strategic objective consists of developing a sustainable social plan of large dimensions, aligned with the Social Plan of the Venezuelan Government.  PDVSA’s social plan includes education, agricultural, infrastructure and local/regional development projects, which will generate about 1.7 million direct and indirect jobs and benefit 8.4 million people in Venezuela.

 

      We estimate that our business plan will require about $49 billion (excluding Pequiven) to achieve a sustainable production capacity of 5,109 MBPD by 2010.  We expect to provide about 70% of the funds required for this Plan from our own resources and 30% by means of different financing sources.  The following chart shows a summary of actual and estimated capital expenditures:

 

Capital Investment Plan 2005 – 2010 for Venezuela
($ in millions)

 

 

 

Actual
2004

 

2005

 

2006

 

2007

 

2008

 

2009

 

2010

 

Total
2005-
2010

 

Exploration

 

134

 

314

 

443

 

459

 

426

 

413

 

247

 

2,302

 

Production (1)

 

1,438

 

2,381

 

2,658

 

2,783

 

2,326

 

2,174

 

2,100

 

14,422

 

Production Agreements

 

478

 

628

 

688

 

492

 

355

 

302

 

228

 

2,693

 

Orinoco Belt

 

64

 

809

 

647

 

587

 

338

 

450

 

336

 

3,167

 

Profit Sharing Agreement

 

46

 

340

 

291

 

177

 

348

 

352

 

183

 

1,691

 

Gas

 

443

 

973

 

2,248

 

2,213

 

1,753

 

1,168

 

581

 

8,936

 

Refining

 

177

 

328

 

576

 

3,217

 

3,476

 

3,475

 

3,061

 

14,133

 

Proesca (2)

 

89

 

12

 

27

 

66

 

67

 

248

 

721

 

1,141

 

Supply & trading

 

121

 

84

 

91

 

201

 

55

 

33

 

21

 

485

 

Total:

 

2,990

 

5,869

 

7,669

 

10,195

 

9,144

 

8,615

 

7,478

 

48,970

 

 


(1) 2005 includes $96 million for completion of the Orifuels Sinoven Joint Venture plant.

(2) The 2004 expenditure corresponds to Pequiven.

 

We also are committed to maintaining high safety and health standards across all operations and we aim to achieve effective and timely integration of business technologies in our operational activities to develop a sustainable competitive advantage.  We also endeavor to provide quality training for our personnel; finally, the

 

12



 

business plan seeks to help to strengthen the national economy and to contribute to social programs such as education, healthcare and job creation.

 

We invested $2,990 million in operating assets in 2004.  This expenditure was 42% lower than we had anticipated in our previous business plan.  This was due to technical difficulties resulting from sabotage against the Venezuelan oil industry in December 2002 and the first quarter of 2003.  Additionally, in 2004 PDVSA expensed $4,355 million as a contribution to social programs in Venezuela.

 

Furthermore, we will support the process of Latin America and Caribbean energy and economic integration promoted by the Venezuelan Government.  We will also contribute effectively to put into practice the governmental initiative of building a new worldwide multipolar system of international relations based on justice, mutual respect and social equity.  This initiative will allow Venezuelan people to achieve a better standard of living with less poverty and sustainable development.

 

These new social commitments have not, to date, materially or adversely impacted PDVSA Petróleos’s ability to generate the necessary flow of eligible receivables to support payments on our indebtedness.

 

As part of our business strategy, we intend to:

 

With respect to exploration, production and upgrading activities –

 

      incorporate reserves of light and medium gravity crude oil;

 

      increase our overall recovery factor;

 

      continue the development of our Orinoco Belt extra-heavy crude oil projects; and

 

      leverage existing technology in order to maximize the return on our investments.

 

With respect to refining and marketing –

 

      assure product enhancement and environmental compliance in Venezuela and abroad;

 

      expand and diversify our markets into Latin America, Caribbean and Asia, including China and India; and

 

      improve the efficiency of our refining processes and marketing activities.

 

With respect to natural gas

 

      actively promote the national and international private sector participation in onshore and offshore non-associated gas reserves exploitation and processing;

 

      enhance our distribution processes in order to increase the breadth of our domestic and international markets; and

 

      assure participation in the liquified natural gas (LNG) markets.

 

With respect to petrochemicals –

 

      provide feedstocks and other raw material to Pequiven in a timely manner and continue to evaluate opportunities for petrochemical product development in our refineries abroad.

 

The execution of PDVSA’s Corporate Plan includes the following initiatives or business:

 

13



 

      Exploration, production and upgrading.  The exploration and production strategy focuses on increasing our efforts to search for new light and medium gravity crude oil reserves and the systematic replacement of such reserves in back yard areas, developing new production areas, adjusting our production activities to cater market demands and agreements reached among OPEC members and other oil producing countries.  For this purpose we will acquire 4,150 Km of 2D seismic lines, 20,593 Km2 of 3D seismic lines and drill about 91 exploratory wells.  PDVSA will drill some 3,751 production wells and perform maintenance (Ra/Rc) on 7,663 wells, among other activities, in order to reach a production capacity of 5,109 MBPD by 2010.  PDVSA is also making efforts to maintain competitive production costs by using state-of-the-art technology.  The first four Orinoco Belt projects have been completed and are in full operation: Hamaca (a PDVSA – ConocoPhillips & Chevron Texaco Joint Venture), Petrozuata (a joint venture between PDVSA and ConocoPhillips), Cerro Negro (a PDVSA – ExxonMobil – BP joint venture), Sincor (a PDVSA – TotalFina – Statoil joint venture).  These strategic alliances are currently producing more than 600 MBPD of heavy and extra-heavy crudes.  PDVSA will start a project to quantify and to certify proved hydrocarbons reserves in the Orinoco Belt, in order to determine the economic prospects and thus, properly direct future business in that area.

 

      Refining.  Our refining strategy focuses on improving the efficiency of our downstream operations.  In Venezuela, we will construct three new refineries: Cabruta (400 MBPD), Barinas (50 MBPD) and Caripito (50 MBPD).  Also, we will add deep conversion capacity to the Puerto La Cruz, CRP (Amuay and Cardón) and El Palito refineries in order to increase the efficiency of heavy crude oil processing.  In our refineries in the United States, Europe and the Caribbean we will invest in order to comply with quality standards demanded by those markets.  Additionally, we will invest in the refineries of Kingston-Jamaica and Cienfuegos-Cuba, and develop a new refinery with Petrobras in the north of Brazil and in a deep conversion project in La Teja refinery in Uruguay.  We continue to aim to achieve a higher margin on refined petroleum products and to comply with all applicable environmental quality standards. (See “Item 4.B. Business overview — Refining and Marketing”).

 

      Marketing.  The plan considers continuing the expansion of our international marketing operations to ensure market share growth for our crude oil and refined petroleum products and to increase brand recognition for the products.  Also, we seek to diversify our customer portfolio by entering new markets such as China and India.  PDVSA will expand its operations in the Caribbean and South America through the Petroamerica initiative, which includes the Petrosur, Petrocaribe and Petroandina initiatives, in order to promote regional integration and a fair energy distribution among the Latin American nations.  We aim to maintain our market position in the U.S. through a more efficient distribution system of CITGO and its refined petroleum products.  CITGO International Latin America, Inc. “CILA”, which sells lubricants, gasoline and distillates in various Latin American countries, was recently transferred to Interven Venezuela and is currently evaluating the operation of its various subsidiaries. (See “Item 4.B. Business overview — Refining and Marketing”).  Additionally, in order to improve our logistic and marine transportation capabilities, PDVSA will construct 42 tankers through strategic agreements with Argentina, Brazil, China and Spain, to increase from 21 to 58 the number of ships owned and operated by our subsidiary PDV Marina.

 

      In Venezuela, we plan to continue to promote a reliable supply of our products and the use of unleaded gasoline (a process 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.  Also, we are developing an ethanol production project in order to substitute octane enhancement additives such as TEL and MTBE in the production of gasoline.  With the use of ethanol, we will have environmentally friendlier products and at the same time, we will be promoting agricultural and social development in rural areas, due to the fact that ethanol is produced from agricultural feedstocks such as sugarcane.

 

      Gas.  The development of the gas business is one of our major goals.  We plan to focus on creating attractive investment opportunities for the private sector in non-associated gas production, expanding

 

14



 

our transmission and distribution systems and natural gas liquids extraction, processing and fractioning capacity, and developing new gas export ventures, including exports of LNG.  We intend to operate most of the existing associated natural gas production fields, currently assigned to us by the Ministry of Energy and Petroleum.  We will continue to explore and develop non-associated gas reserves with the support of private investment.  We expect to support the activities related to our gas business using our existing gas transmission and distribution systems.

 

      The Ministry of Energy and Mines, currently known as the Ministry of Energy and Petroleum, completed a round of onshore non-associated gas licensing bids for exploration and production activities in 11 new onshore areas in 2001.  Six of those areas were awarded to foreign and domestic investors:  Yucal-Placer Norte and Yucal-Placer Sur (both development areas), Barrancas, Tinaco, Tiznado and Barbacoas (each exploratory areas).  The Yucal-Placer areas produced 44 MMCFD in 2004, and approximately 300 MMCFD are expected to be in production by 2010.  During the first quarter of 2003, the Venezuelan Government assigned two blocks within the Deltana Platform area (eastern Venezuela and on the maritime border with Trinidad & Tobago) to Statoil and ChevronTexaco and ConocoPhillips.  More recently it has assigned another block to ChevronTexaco.  Additionally, we have under way a new bidding round to explore and develop offshore resources in the west and northeast of Venezuela; such developments will principally include projects for the production of LNG, once the local demand in Venezuela has been satisfied.  We have defined an offshore natural gas project called Rafael Urdaneta located in the Venezuelan Gulf and northeast of Falcon State, with an area of 30,000 Km2, split into 29 blocks to be offered in two phases.  Phase one was initiated beginning the second quarter of 2005, when the Venezuelan Government offered the first six blocks to 37 national and foreign oil companies.  Of this offer, blocks Urumaco I and II were awarded to the Russian company Gazprom, while block Cardon III was awarded to ChevronTexaco.

 

      We anticipate that development of our gas business segment will require approximately $9 billion in capital from 2005 to 2010.  We expect that such capital expenditures will be obtained primarily from the private sector, including partners.

 

      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 by 2010.  We intend to capitalize on our advantages by promoting an increased and more diverse use of natural gas within the country.

 

      At this time, the Orimulsion® production is operated just to meet the needs of our clients in Europe, Asia and the United States.  During 2003 we conducted a full review of this business.  The outcome of such analysis showed that a reevaluation of our strategy was necessary within the framework of the new Corporate Strategy in order to maximize the value of Venezuelan natural resources.  Since that reassessment, we produce only enough Orimulsion® to comply with our existing contracts.  A new production module (Sinovensa) will be in place by the end of 2005 in order to supply the existing agreements.

 

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, 2003 totaling approximately 56.7 billion barrels.  Venezuela’s commercial production of crude oil is concentrated in the Western Zulia Basin and the Western Barinas – Apure Basin in Western Venezuela and in the Monagas and Anzoategui states in the Eastern Basin.  The large number of fields in production in these three basins are broadly distributed geographically and, as a result, substantially diversifies our production risk.  The impact of a loss of production in any one field would be relatively minor when compared to Venezuela’s total production.  The Western and Eastern basins have produced 41.0 billion and 15.7 billion barrels, respectively, of crude oil to date.  Substantial portions of the sedimentary basins in Venezuela have not yet been explored.

 

15



 

Principal Oil-Producing Basins in Venezuela

 

 

16



 

The following table shows our proved reserves, proved and developed reserves, 2003 production and the ratio of proved reserves to annual production in each of the principal basins at December 31, 2003:

 

PDVSA’s Proved Reserves and Production by Basin

 

 

 

Proved
reserves(1)

 

Proved/
developed
reserves

 

2003 Production

 

Ratio of proved

 

 

 

(MMB at Dec.
31, 2003, except
as otherwise
indicated)

 

(MMB at Dec.
31, 2003, except
as otherwise
indicated)

 

(MBPD, except
as otherwise
indicated)

 

reserves/annual production
(years)

 

Basin

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Western Zulia:

 

 

 

 

 

 

 

 

 

Crude Oil

 

21,509

 

6,477

 

1,144

(2)

52

 

Natural Gas (BOE)

 

6,238

 

4,367

 

177

(3)

97

 

Western Barinas – Apure:

 

 

 

 

 

 

 

 

 

Crude Oil

 

1,842

 

927

 

86

(2)

59

 

Natural Gas (BOE)

 

40

 

28

 

1

(3)

110

 

Eastern:

 

 

 

 

 

 

 

 

 

Crude Oil (4)

 

53,789

 

8,884

 

1,616

(2)

91

 

Extra–Heavy Crude Oil included in previous quantity

 

35,186

 

3,010

 

455

 

212

 

Natural Gas (BOE)

 

19,591

(5)

13,714

 

414

(3)

130

 

Total Crude Oil (4)

 

77,140

(1)

16,288

 

2,846

(2)

74

 

Total Natural Gas (BOE)

 

25,869

(5)

18,109

 

592

 

120

 

 


(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, extra-heavy crude oil and bitumen in the Orinoco Belt, estimated to be 35.2 billion barrels at December 31, 2003.  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 2.45 billion BOE at December 31,2003.

 

The following table shows the location, 2003 production volume, discovery year, proved reserves and the ratio of proved reserves to annual production for each of PDVSA’s eleven largest oil fields as of December 31, 2003:

 

PDVSA’s Proved Reserves and Production by Field

 

Name of field

 

Location

 

2003 production

 

Year of
discovery

 

Proved
reserves

 

Ratio of proved
reserves/annual
production

 

 

 

(State of)

 

(MBPD)

 

 

 

(MMB at
Dec. 31, 2003)

 

(years)

 

Tía Juana

 

Zulia

 

201

 

1925

 

5,113

 

70

 

Lagunillas

 

Zulia

 

139

 

1925

 

2,464

 

49

 

Bachaquero

 

Zulia

 

141

 

1930

 

2,264

 

44

 

Bloque VII Ceuta

 

Zulia

 

104

 

1956

 

1,747

 

46

 

Urdaneta Oeste

 

Zulia

 

121

 

1955

 

1,501

 

34

 

Boscán

 

Zulia

 

99

 

1946

 

1,257

 

35

 

Mulata

 

Monagas

 

214

 

1941

 

2,106

 

27

 

El Furrial

 

Monagas

 

343

 

1986

 

1,999

 

16

 

Santa Barbara

 

Monagas

 

131

 

1941

 

1,570

 

33

 

Bare

 

Anzoátegui

 

40

 

1950

 

1,249

 

86

 

Jobo

 

Monagas

 

22

 

1956

 

1,077

 

134

 

 

17



 

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 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, 2003.

 

Crude Oil.  We had estimated proved crude oil reserves at December 31, 2003 totaling approximately 77.1 billion barrels (including an estimated 35.2 billion barrels of heavy, extra-heavy crude oil and bitumen in the Orinoco Belt).  We also had estimated proved reserves of natural gas totaling approximately 150,043 BCF (including an estimated 12,427 BCF in the Orinoco Belt).  The average API gravity of our estimated proved crude oil reserves was 17.3° as compared to an average API gravity of 23° for our crude oil produced in 2002; the API gravity of the up-graded oil produced by the Orinoco Belt projects ranges from 16° to 32°.  Based on 2003 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 74 years.

 

From December 31, 1995 to December 31, 2003, our estimated proved reserves of crude oil increased by 10.8 billion barrels and our estimated proved reserves of natural gas increased by 1.12 billion barrels of oil equivalent (“BOE”).  In 2003, 2002, 2001 and 2000, our proved crude oil reserve replacement ratio was 100%, 104%, 108% and 169%, 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 150,043 BCF (or 25,869 MMBOE) at December 31, 2003.  Our natural gas reserves are comprised of associated gas that is developed incidental to the development of our crude oil reserves.  A large proportion of our proved natural gas reserves are developed.  During 2003, approximately 42% 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 23 to our consolidated financial statements, included under “Item 18.  Financial Statements”):

 

18



 

PDVSA’s Proved Reserves

 

 

 

Year Ended December 31,

 

 

 

2003

 

2002

 

2001

 

2000

 

1999

 

Proved Reserves(1):

 

 

 

 

 

 

 

 

 

 

 

Crude oil (MMB)

 

 

 

 

 

 

 

 

 

 

 

Condensate

 

1,919

 

1,900

 

1,723

 

1,772

 

1,847

 

Light (API gravity of 30° or more)

 

10,078

 

10,012

 

10,345

 

10,244

 

10,258

 

Medium (API gravity of between 21° and 30°)

 

12,340

 

12,450

 

12,891

 

12,804

 

12,195

 

Heavy (API gravity of between 11° and 21°)

 

17,617

 

17,414

 

17,266

 

17,177

 

16,861

 

Extra-heavy (API gravity of less than 11°)(2)

 

35,186

 

35,381

 

35,558

 

35,688

 

35,701

 

Total crude oil

 

77,140

 

77,157

 

77,783

 

77,685

 

76,862

 

Of which, assigned to Operating Service Agreements(3)

 

5,446

 

5,501

 

5,600

 

5,479

 

5,450

 

Natural gas (BCF)(4)

 

150,043

 

147,109

 

148,295

 

147,585

 

146,611

 

Proved reserves of crude oil and natural gas (MMBOE)(3)(5)

 

103,009

 

102,521

 

103,351

 

103,131

 

102,140

 

Remaining reserves life of crude oil (years)(6)

 

74

x

70

x

64

x

64

x

70

x

Proved Developed Reserves:

 

 

 

 

 

 

 

 

 

 

 

Crude oil (MMB)

 

 

 

 

 

 

 

 

 

 

 

Condensate.

 

416

 

419

 

747

 

814

 

1,009

 

Light (API gravity of 30° or more)

 

2,760

 

2,716

 

3,590

 

3,803

 

3,827

 

Medium (API gravity of between 21° and 30°)

 

5,419

 

5,533

 

5,568

 

5,928

 

6,480

 

Heavy (API gravity of between 11° and 21°)

 

4,683

 

4,877

 

5,504

 

5,453

 

5,738

 

Extra-heavy (API gravity of less than 11°)(2)(7)

 

3,010

 

2,154

 

1,963

 

1,375

 

1,070

 

Total crude oil(7)

 

16,288

 

15,699

 

17,372

 

17,373

 

18,124

 

Of which, assigned to Operating Service Agreements(3)

 

1,267

 

1,935

 

1,523

 

1,413

 

1,329

 

Percentage of proved crude oil reserves(8)

 

21

%

20

%

22

%

22

%

24

%

Natural gas (BCF)

 

105,030

 

102,191

 

103,807

 

103,310

 

102,628

 

Percentage of proved natural gas reserves(9)

 

70

%

69

%

70

%

70

%

70

%

Proved developed reserves of crude oil and natural gas (MMBOE)(2)(3)

 

34,396

 

33,318

 

35,270

 

35,185

 

35,818

 

 


(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, 2003, approximately 1,751 MMB were developed under four association agreements in which we have an equity interest of less than 50%.
See “Item 4.B Business overview—Initiatives Involving Private Sector Participation—Orinoco Belt Extra-Heavy Crude Oil Projects.”

(3)           Portion of reserves in fields assigned to operating service agreements as of December 31 of the year in which each such operating agreement went into effect.  Such agreements will not necessarily result in the exploitation of 100% of those reserves during their term.  See “Item 4.B Business overview—Initiatives Involving Private Sector Participation—Operating Service Agreements.”

(4)           Includes 12,427 BCF, 12,454 BCF, 12,476 BCF, 12,505 BCF and 12,400 BCF in each of 2003, 2002, 2001, 2000 and 1999, 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.

 

New Hydrocarbon Reserves Findings

 

In 2003, the Eastern PDVSA Division discovered new hydrocarbon reserves of approximately 159 million barrels of crude oil and 1,675 BCF of associated gas.  Specifically in the North-East of Monagas State, near to Maturín well CHL-6X was discovered with 47 million barrels of crude oil and 350 BCF of associated gas. Currently, we are in the process of drilling the exploratory well CHL-7X, located near to well CHL-6X, with estimated hydrocarbon reserves of 255 million barrels of crude oil and 1,300 BCF of associated gas.  In the North West of Monagas State, at the Tacata Field, the well TAC-2X with 118 million barrels of crude oil and 2,457 BCF

 

19



 

of associated gas was discovered.  Further exploration activities include wells TAG-19 and TRAVI ESTE 1X in progress, with estimated reserves of 191 million barrels of crude oil and 629 BCF of associated gas.

 

In the Western part of the country, we continue our exploration activities at Franquera, Pauji and Misoa Formations of Eocene.  Currently, we are drilling the Franquera 1-X exploratory well and we expect this reservoir to yield new reserves of 789 million barrels of crude oil and 378 BCF of associated gas.

 

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 Anzoátegui 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 ventures.  See “Item 4.B Business overview—Initiatives Involving Private Sector Participation.”

 

In 2003, our exploration expenditures were used mainly to fund the drilling of 7 exploratory wells and the acquisition of 280 square kilometers of 3D seismic lines.  No additional exploratory wells were drilled and no seismic lines were acquired pursuant to our operating service agreements.  250 MMB proved crude oil reserves were added in 2003 (162 MMB from newly discovered reserves and 88 MMB from development wells) compared to 238 MMB in 2002 (135 MMB from newly discovered reserves and 103 MMB from development wells), 357 MMB in 2001 (46 MMB from newly discovered reserves and 311 MMB from development wells) 209 MMB in 2000 (5 MMB from newly discovered reserves and 204 MMB from development wells) and 184 MMB in 1999 (84 MMB from newly discovered reserves and 100 MMB from developed wells) (These proved crude oil reserves do not include extensions of existing reserves, secondary extractions, or other factors.  See note 23(a) to the financial statements, included under “Item 18. Financial Statements”).  In 2003, we invested $526 million in 206 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,

 

 

 

2003

 

2002

 

2001

 

2000

 

1999

 

Exploration:

 

 

 

 

 

 

 

 

 

 

 

Wells spud

 

2

 

3

 

6

 

5

 

5

 

Wells carry-over

 

5

 

7

 

5

 

9

 

7

 

Total

 

7

 

10

 

11

 

14

 

12

 

Wells completed

 

3

 

3

 

3

 

2

 

0

 

Wells suspended

 

1

 

2

 

0

 

2

 

5

 

Wells under evaluation

 

0

 

0

 

3

 

5

 

1

 

Wells in progress

 

3

 

3

 

3

 

1

 

4

 

Dry or abandoned wells

 

0

 

2

 

2

 

4

 

2

 

Total

 

7

 

10

 

11

 

14

 

12

 

Development:

 

 

 

 

 

 

 

 

 

 

 

Development wells drilled (1)

 

206

 

366

 

479

 

474

 

349

 

 


(1)           Includes wells in progress, even if they were wells spud in previous years, and injector wells.  Does not include 26 development wells from PDVSA Gas and 62 development wells (including 2 injector wells) attributable to our operating service agreements located in the Eastern Division.  See “Item 4.B Business overview—Initiatives Involving Private Sector Participation—Operating Service Agreements.”

 

20



 

Pursuant to the Orinoco Belt Extra-heavy Crude Oil Projects, no exploration wells and 64 development wells were drilled in 2003, 17 exploration wells and 144 development wells were drilled in 2002, 9 exploration wells and 349 development wells were drilled in 2001 and 15 exploration wells and 453 development wells were drilled in 2000.

 

In 2003, our crude oil production averaged 2,451 MBPD (including 122 MBPD attributable to our participation in the Orinoco Belt projects) with API gravity between 16° and 32°.  This production level represented approximately 69% of PDVSA’s estimated 2003 year end crude oil production capacity of 3,529 MBPD (including 525 MBPD of crude oil production capacity attributable to our Orinoco Belt projects).  During 2003, our average production costs of crude oil was approximately $3.85 per BOE, or $2.06 per BOE excluding the production and costs attributable to our operating service agreements, and the average of our depreciation and depletion costs was $0.53 per BOE.  See “Item 3.A Selected financial data.”

 

At December 31, 2003, we operated approximately 15,782 oil wells.  At such date, we had 37,659 gross kms2 of undeveloped acreage and 177,829 gross kms2 of acreage under development, including 49,194 kms2 developed pursuant to our operating service agreements.

 

On average, during 2003, our natural gas production was 5,938 MMCFD (or 1,024 MBPD on an oil equivalent basis), of which 2,506 MMCFD, or 42%, was reinjected for purposes of maintaining reservoir pressure.  The net natural gas production of 3,432 MMCFD was consumed in production of LNG (9%), as fuel in refinery and production operations (24%), in petrochemical operations (14%) and the remainder (53%) is sold to third parties for power generation, aluminum, iron and other manufacturing industries and domestic uses.  Approximately 70% of the 2003 natural gas production and 76% of the 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 the average sales price and production cost for the periods specified:

 

PDVSA’s Average Production, Sales Price and Production Cost

 

 

 

Year Ended December 31,

 

 

 

2003

 

2002

 

2001

 

2000

 

1999

 

 

 

(MBPD, except as otherwise indicated)

 

 

 

 

 

 

 

 

 

 

 

 

 

Crude oil:

 

 

 

 

 

 

 

 

 

 

 

Condensate

 

22

 

46

 

48

 

50

 

43

 

Light (API gravity of 30° or greater)

 

727

 

774

 

1,135

 

1,174

 

1,189

 

Medium (API gravity of between 21° and 30°)

 

914

 

962

 

1,018

 

1,047

 

1,095

 

Heavy (API gravity of less than 21°)

 

788

 

877

 

893

 

814

 

623

 

Total crude oil

 

2,451

 

2,659

 

3,094

 

3,085

 

2,950

 

Of which, assigned to Operating Service Agreements(1)

 

465

 

481

 

502

 

466

 

404

 

Liquid petroleum gas

 

144

 

173

 

173

 

167

 

177

 

Total crude oil and liquid petroleum gas

 

2,595

 

2,832

 

3,267

 

3,252

 

3,127

 

Natural gas:

 

 

 

 

 

 

 

 

 

 

 

Gross production (MMCFD)

 

5,938

 

6,023

 

6,000

 

5,946

 

5,685

 

Less:

 

 

 

 

 

 

 

 

 

 

 

Reinjected (MMCFD)

 

2,506

 

2,351

 

1,907

 

1,967

 

1,919

 

Net natural gas (MMCFD)

 

3,432

 

3,672

 

4,093

 

3,979

 

3,766

 

Total crude oil, liquid petroleum gas and net natural gas (BOE)

 

3,187

 

3,464

 

3,973

 

3,938

 

3,776

 

Crude oil production by basin:

 

 

 

 

 

 

 

 

 

 

 

Western Zulia Basin

 

1,121

 

1,332

 

1,567

 

1,536

 

1,450

 

Western Barinas – Apure Basin

 

86

 

93

 

109

 

115

 

131

 

Eastern Basin

 

1,244

 

1,234

 

1,418

 

1,434

 

1,369

 

Total crude oil production

 

2,451

 

2,659

 

3,094

 

3,085

 

2,950

 

 

21



 

 

 

Year Ended December 31,

 

 

 

2003

 

2002

 

2001

 

2000

 

1999

 

 

 

(MBPD, except as otherwise indicated)

 

 

 

 

 

 

 

 

 

 

 

 

 

Natural gas gross production by basin (MMCFD):

 

 

 

 

 

 

 

 

 

 

 

Western Zulia Basin

 

1,031

 

1,261

 

1,408

 

1,665

 

1,801

 

Western Barinas – Apure Basin

 

6

 

8

 

7

 

7

 

7

 

Eastern Basin

 

4,901

 

4,754

 

4,585

 

4,274

 

3,877

 

Total gross natural gas production

 

5,938

 

6,023

 

6,000

 

5,946

 

5,685

 

Average sales price(2):

 

 

 

 

 

 

 

 

 

 

 

Crude oil ($ per barrel)

 

24.39

 

$

21.35

 

$

18.95

 

$

24.94

 

$

15.35

 

Gas ($ per MCF)

 

0.61

 

$

0.71

 

$

0.88

 

$

0.90

 

$

0.73

 

Average production cost ($ per BOE)(3)

 

3.85

 

$

3.92

 

$

3.38

 

$

3.48

 

$

2.72

 

Average production cost ($ per BOE), excluding operating service agreements(3)

 

2.06

 

$

2.42

 

$

2.17

 

$

2.22

 

$

2.00

 

 


(1)           See “Item 4.B Business overview—Initiatives Involving Private Sector Participation—Operating Service Agreements.”

(2)           Including sales to subsidiaries and affiliates.

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

 

Initiatives Involving Private Sector Participation

 

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

 

In August 2003, to streamline our business operations and reduce our administrative costs, the administration of our business ventures with private sector entities was assigned to our subsidiary, CVP.  In this regard, CVP assumed administrative responsibility within PDVSA with respect to our operating service agreements, strategic associations and profit sharing agreements described below.  In addition to its administrative responsibilities, CVP will continue to promote PDVSA’s relations with third parties and private sector participation in the petroleum industry.  However, any dividends and profits from production activities conducted pursuant to our operating service agreements and our other strategic associations continue to be paid to PDVSA, except for dividends from our profit sharing agreements, which are paid to CVP.

 

22



 

 

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 to the hydrocarbons produced and have no further obligations as to any remaining value of the assets existing in the fields.  See note 10(c) to our consolidated financial statements, included under “Item 18.  Financial Statements.”

 

      The First and Second Rounds.  A total of 27 oil companies (grouped in different consortiums) were awarded rights to drill 15 oil fields.  Since then, some companies have changed their participation in the different consortiums.  In 2003, Anadarko bought the participation of Union Pacific in the Oritupano-Leona field; ExxonMobil bought the participation of Ampolex in Quiamare-La Ceiba field and Repsol-YPF bought the participation of Union Pacific in the West Falcon field.  An average of 313 MBPD of crude oil was produced from these fields in 2003, and it is expected that such production will be approximately 405 MBPD when the fields are in substantially full operation by 2005.  As of December 31, 2003, these fields had estimated proved reserves of approximately 3.83 billion barrels of crude oil.  Under this initiative, foreign companies have invested $5,535 million since 1992.

 

23



 

      The Third Round.  We auctioned the right to reactivate, rehabilitate, develop and additionally explore certain hydrocarbon reservoirs in 18 fields, one of which is currently inactive.  In 2003, ENI bought the participation of Lasmo in the Dación field.  An average of 150 MBPD of crude oil was produced from these fields in 2003.  As of December 31, 2003, these fields had estimated proved reserves of approximately 1.62 billion barrels of crude oil.  Our business plan currently contemplates daily production from these fields of 225 MBPD by 2005 under our operating service agreements.  Under this initiative, the operator companies have invested $3,548 million since 1997.

 

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, 2003

 

Area

 

Consortium (Operator)

 

Proved Crude
Oil Reserves
(MMB) (1)

 

First and Second Rounds

 

 

 

 

 

Boscán

 

Chevron Global Technology Services Co.

 

1,372.3

 

Urdaneta/West

 

Shell Venezuela S.A.

 

872.3

 

DZO

 

B.P. Venezuela Holdings, Ltd.

 

368.8

 

Oritupano/Leona

 

Petrobras Energía Venezuela, Servicios Corod de Venezuela, Anadarko

 

296.1

 

Colón

 

Tecpetrol Venezuela, CMS Oil and Gas, Coparex

 

157.2

 

Quiamare/LA Ceiba

 

Repsol–YPF Venezuela, S.A., Tecpetrol Venezuela, ExxonMobil

 

95.5

 

Quiriquire

 

Repsol–YPF Venezuela, S.A.

 

63.8

 

Pedernales

 

Perenco

 

116.2

 

Monagas Sur

 

Benton Oil & Gas, Vinccler

 

153.3

 

Sanvi/Güere

 

Teikoku Oil De Sanvi Güere, C.A.

 

81.9

 

Guárico East

 

Teikoku Oil De Venezuela C.A.

 

66.8

 

Jusepín

 

Total Oil and Gas de Venezuela, B.V., B.P. Venezuela Holding, Ltd.

 

132.4

 

Guárico West

 

Repsol–YPF Venezuela, S.A.

 

42.3

 

Falcón East

 

Vinccler

 

8.8

 

Falcón West

 

West Falcon Samson

 

2.7

 

Subtotal

 

 

 

3,830.4

 

Third Round

 

 

 

 

 

Boquerón

 

B.P. Venezuela Holding, Ltd., Preussag Energie GmbH

 

86.1

 

LL-652

 

Chevron Global Technology, Statoil, B.P. Venezuela Holding, Ltd., Petróleo y Gas Inversiones, C.A.

 

354.3

 

Dación

 

ENI

 

206.1

 

Intercampo norte

 

China National Petroleum Corp.

 

67.2

 

Caracoles

 

China National Petroleum Corp.

 

106.9

 

B2X 68/79

 

Nimir Petroleum Company Limited, Ehcopek Petróleo, S.A., Cartera de Inversiones Petroleras II, C.A.

 

107.4

 

Mene grande

 

Repsol–YPF Venezuela, S.A.

 

122.5

 

Mata

 

Inversora Mata, Petrobras Energía de Venezuela, S.A., Petrolera Mata

 

89.8

 

B2X 70/80

 

Pancanadian Petroleum Venezuela, S.A., Nimir Petroleum Company Limited

 

77.2

 

Kaki

 

Inemaka, Inversiones Polar, Petróleo y Gas Inversiones, C.A.

 

37.8

 

Ambrosio

 

Perenco, Petróleo y Gas Inversiones, C.A.

 

52.5

 

Onado

 

Compañía General Combustibles, Carmanah Resources, Korea Petroleum, Bco Popular Del Ecuador

 

52.6

 

La Concepción

 

Petrobras Energía de Venezuela, S.A., Williams Companies, Inc.

 

119.6

 

 

24



 

Area

 

Consortium (Operator)

 

Proved Crude
Oil Reserves
(MMB) (1)

 

Cabimas

 

Preussag Energy GmbH, Suelopetrol

 

56.9

 

Casma Anaco

 

Cosa-Ingenieros Consultores, Cartera de Inversiones Venezolanas, Phoenix International, C.A., Rosewood North Sea, Open

 

11.4

 

Maulpa

 

Inemaka, Inversiones Polar, Petróleo y Gas Inversiones, C.A.

 

32.4

 

Acema

 

Coroil, Petrobras Energía de Venezuela, S.A.

 

35.1

 

Subtotal

 

 

 

1,615.8

 

 

 

 

 

 

 

Total

 

 

 

5,446.2

 

 


(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, 2003 do not include any additional reserves which may ultimately be proved based on recovery projects to be implemented by the operators of the service agreements.

 

During 2005, the Ministry of Energy and Petroleum has instructed PDVSA to convert the Operating Service Agreements to a scheme of jointly owned enterprises, where PDVSA will hold a minimum of 51% stock ownership, according to the Organic Hydrocarbons Law of Venezuela.  CVP is analyzing each Operating Service Agreement and by the end of 2005, CVP is expecting to complete the conversion process.

 

Exploration and Production in New Areas under Profit Sharing Agreements

 

In July 1995, the Venezuelan Congress approved profit sharing arrangements pursuant to which private sector oil companies were offered the right to explore, drill and develop light and medium crude oil, on an equity basis in ten designated blocks with a total area of 13,774 square kilometers, pursuant to the terms of the profit sharing agreements entered into by such companies and CVP, our subsidiary appointed to coordinate, control and supervise these agreements.  Under the profit sharing agreements, CVP has the right to participate, at its option, with an ownership interest of 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.

 

In 2003, these companies invested approximately $55 million in activities related to the discovery, well evaluation, development and exploration efforts in Eastern Paria Gulf, La Ceiba and particularly in Western Paria Gulf, where the commercial stage of production has been reached.  See note 10(b) to our consolidated financial statements, included under “Item 18.  Financial Statements.”

 

CVP is entitled to hold shares representing a maximum of 35% participation in the joint ventures that could be formed pursuant to profit sharing agreements in the following oil fields:

 

Field

 

CVP Partners

 

Mixed companies

 

Western Paria Gulf

 

ConocoPhillips - ENI B.V. - OPIC (1)

 

Compañía Agua Plana, S.A.

 

Eastern Paria Gulf

 

Ineparia - ConocoPhillips - ENI B.V. - OPIC

 

Administradora del Golfo de Paria Este, S.A.

 

La Ceiba

 

ExxonMobil - PetroCanada

 

Administradora Petrolera La Ceiba, C.A.

 

San Carlos (2)

 

Petrobras Energía de Venezuela S.A.

 

Compañía Anónima Mixta San Carlos S.A.

 

 


(1)           Profit sharing agreement under phase I (development).

(2)           Changed to a gas license in 2002.

 

25



 

The profit sharing agreement with Punta Pescador was terminated in 2000, and agreements with Guanare, Guarapiche and Delta Centro were terminated in 2001.  The San Carlos agreement was converted into a gas license in 2002.

 

A recent evaluation plan confirmed large hydrocarbon and gas reserves in the Western Paria Gulf field.  It is anticipated that the field contains over two billion barrels of crude oil.  On April 3, 2003, we approved phase I of the development plan for this field, involving a capital investment of approximately $557 million by investors and an expected production level of 250 million barrels of crude oil over the next 20 years.  Phase I of this development will be conducted using a wellhead platform, a floating production unit with a separate accommodations platform, pipeline to a floating storage offtake vessel (FSO), and a mooring buoy for loading arriving tankers.  Phase I also will include water injection for pressure maintenance.  The produced associated gas will be stored in an aquifer zone wholly contained within the overall Corocoro gas column.  The operator will manage the facilities design, construction installation and subsequent production operations.  A total of 24 wells will be drilled comprising 11 producers, 10 water injectors, 2 gas injectors and one utility well.  We estimate an average production of 55 MBPD in 2005, increasing to 120 MBPD in or after 2008.

 

It is currently projected that phase II (expected to commence in 2008) would involve a further $487 million of investments to recover additional reserves of up to 450 million barrels of crude oil from the field.  We believe that we can make an efficient transition from phase I to phase II by using existing production facilities in the second phase.  The total project cost for phase I and phase II is estimated at $4.3 per barrel, comprising $2.3 per barrel for development and $2.0 per barrel for operations.

 

In 2002 we invested $2.8 million for exploratory activities related to the Western Paria Gulf field.  Additionally, in 2003 we drilled four development wells in that field, which required a total investment of $7.8 million.  In the La Ceiba field we began drilling wells La Ceiba 3X and La Ceiba 6X and, depending on the evaluation of the results of those wells, a declaration of commercial operation will be issued to then begin the construction of production facilities to handle the early crude oil production, with an estimated investment of approximately $11 million.

 

Orinoco Belt Extra-Heavy Crude Oil Projects

 

The Venezuelan Congress approved the creation of four vertically integrated joint venture projects in the Orinoco Belt for the exploitation and upgrading of extra-heavy crude oil of average API gravity of 9° and marketing of the upgraded crude oil with API gravities ranging from 16° to 32°.  These joint venture projects have been implemented through association agreements between the various participating entities and PDVSA.  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 PDVSA.  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.

 

Each of these associations are required to pay the standard Venezuelan corporate tax rate of 34% (as compared to a tax rate of 50% that is applicable to our Venezuelan subsidiaries engaged in the production of hydrocarbons).  In addition, they pay a production tax ranging between 1% to 16 2/3%, measured depending on accumulated revenues and total investment.  These tax conditions were modified in October 2004.  See note 23(a) to our consolidated financial statements, included under “Item 18.  Financial Statements.”  Also, these strategic associations benefit from a 10% investment tax credit on capital investments made after December 31, 2001, plus an additional 10% on capital investments that contribute to the environmental preservation of their operational areas.

 

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

 

      The Petrozuata Joint Venture.  Petrozuata is a company owned by PDVSA Petróleo (a subsidiary of PDVSA) and ConocoPhillips.  The construction of facilities at Petrozuata began in 1997.  Initial production of extra-heavy crude oil commenced in August 1998.  Upgraded facilities were completed

 

26



 

in 2001.  During 2003, Petrozuata produced 104 MBPD of extra-heavy crude oil and 86 MBPD of upgraded crude oil with an average API gravity ranging from 16° to 24°.  Under the terms of the joint venture agreement, ConocoPhillips has agreed to undertake the refining process at its Lake Charles refinery, in Lake Charles, Louisiana.  By December 2003, total investments in this project amounted to $3,478 million.

 

      The Sincor Joint Venture.  Sincrudos de Oriente is a joint venture owned by PDVSA Sincor (a subsidiary of PDVSA), TotalFina and Statoil.  In 2003, this joint venture produced 158 MBPD of extra-heavy crude oil and 137 MBPD of upgraded crude oil with an average API gravity ranging from 24° to 32°.  We anticipate that this joint venture will reach a production level of 180 MBPD of upgraded crude oil by 2007.  By December 2003, total investments in this project amounted to $4,654 million.

 

      The Hamaca Joint Venture.  Petrolera Hamaca is a company owned by Corpoguanipa (a subsidiary of PDVSA), ChevronTexaco and ConocoPhillips.  Hamaca started producing upgraded crude oil in October 2004, achieving by the end of that year a production of 101 MBPD, with an average API gravity of 25° to 27°.  In 2003, average production of extra-heavy crude oil was 67 MBPD and average production of diluted crude oil was 125 MBPD with an average gravity of 16° API.  By December 2003, total investments in this project amounted to $2,544 million, of which, $472 million was invested in 2003.

 

      The Cerro Negro Joint Venture.  Petrolera Cerro Negro is a company owned by PDVSA Cerro Negro, S.A. (a subsidiary of PDVSA), ExxonMobil and BP (formerly Veba Oel).  Pursuant to the terms of this joint venture agreement, we have agreed to sell our share of upgraded crude oil produced by this joint venture (approximately 80% of total production) to Chalmette Refining, a refinery in Chalmette, Louisiana, which is an equal share joint venture between PDVSA and ExxonMobil.  During 2003, this joint venture produced 101 MBPD of extra-heavy crude oil and 92 MBPD of upgraded crude oil with an average API gravity of 16°.  By December 2003, total investments in this project amounted to $2,823 million.  See “Item 4.B Business overview—Refining and Marketing—Refining” and note 10(a) to our consolidated financial statements, included under “Item 18.  Financial Statements.”

 

The Orinoco Belt projects differ primarily by the quantity and quality of output.  For the Hamaca and Sincor joint ventures, the projects are designed to produce upgraded crude oil that can be sold to third-party refiners who would otherwise process light sweet conventional crude oil.  For the Petrozuata and Cerro Negro joint ventures, the projects are designed to produce upgraded crude oil that is suitable for a dedicated refinery.

 

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

 

PDVSA’s Orinoco Belt Proved Reserves

 

Project

 

Private Sector Participants

 

PDVSA’s
Interest

 

Gross
Proved
Reserves

 

Estimated
Production of
Upgraded
Crude Oil

 

Expected
Average API
of Upgraded
Crude Oil

 

 

 

 

 

(%)

 

(MMB)

 

(MBPD)

 

(degrees)

 

 

 

 

 

 

 

 

 

 

 

 

 

Petrozuata

 

ConocoPhillips

 

49.90

 

2,567

 

120

 

 

16-19

 

Sincor

 

TotalFina, Statoil

 

38.00

 

3,497

 

210

 

 

30-32

 

Hamaca

 

ChevronTexaco, ConocoPhillips

 

30.00

 

1,046

 

190

(1)

 

25-27

 

Cerro Negro

 

ExxonMobil, BP (2)

 

41.67

 

3,373

 

120

 

 

16

 

 


(1) The upgrading facilities were not operating in 2003

(2) Formerly Veba Oel

 

27



 

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 engineers 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 Anzoátegui State, operated by Petroucv, S.A., with an assigned surface of 257 square Km; Mara Este, located in the Zulia State, operated by Oleoluz, S.A., with an assigned surface of 246 square Km; and Jobo, located in Monagas State, operated by Petroudo, S.A. with an assigned surface of 19.57 square Km.  The total assigned area for all these fields is approximately 523 square kilometers.  As of December 31, 2003, these fields have estimated proved reserves of approximately 234 MMB of crude oil (consisting of 50.5 MMB at Socororo, 69.3 MMB at Mara Este and 114.2 MMB at Jobo, respectively), with an average API gravity of 8° to 22° API.  During 2003, the total oil production under these operating service agreements was 2.5 MBPD.  We expect these fields to produce approximately 35 MBPD by 2007.  We also anticipate investing a total of approximately $202 million in these fields over the next 20 years.  By December 2004, total expenditures amounted to $25.8 million.

 

Overview of Main Projects with Private Sector Participation

 

The Plataforma Deltana Project

 

The Plataforma Deltana area is located 250 km offshore East of the Orinoco River Delta and Southeast of the territorial border with the Republic of Trinidad and Tobago (Trinidad and Tobago).  For bidding and business purposes, the zone has been divided into five blocks mainly prospective for non-associated gas.  The main objective of the project is to confirm and develop new non-associated natural gas reserves to meet domestic market requirements as well as for export, mainly to the Atlantic Basin.

 

The first exploration phase, with disbursement amounting to $180 million, was completed by PDVSA on July 9, 2003 in an area of 1,000 square kilometers next to the territorial border with Trinidad & Tobago.  Such exploration activity resulted in an increase of the non-associated natural gas reserves estimates to 5.6 Trillion cubic feet as audited by the specialized firm Ryder Scott.  A 10 TCF short term proven reserves objective is being considered as part of the second exploratory phase being executed in the period 2004-2005 by the companies working in the area under the granted licenses, to assure the commercial development of the Plataforma Deltana area.  Total investment in this project has been estimated at approximately $4 billion.

 

Licenses for exploration and development for blocks 2 and 4 were granted by the Ministry of Energy and Petroleum to three international oil and gas companies in February 2003 (ChevronTexaco and ConocoPhillips in Block 2 and Statoil in Block 4).  The international companies are committed to a minimum exploratory program, with an estimated investment of $150 million (drilling activities started in August 2004), and to subsequent investments for development if commercial viability is confirmed.  PDVSA’s participation in the partnership, which could range from 1% to 35%, will be determined upon declaration of commercial viability.

 

The selection process of partners for block 3 was completed in 2003.  In February 2004 the Ministry of Energy and Petroleum granted the license for exploration and development to ChevronTexaco.  Block 1 is reserved for business opportunities, subject to an unitization agreement with Trinidad and Tobago.  On August 2003 a memorandum of understanding was signed between the two countries to manage all common reservoirs along the territorial border.  The exploratory program for this block will cost approximately $27 million. Block 5 remains for future growth opportunities.

 

The natural gas produced offshore will be processed onshore in a new industrial complex to be located near the city of Guiria, in Sucre State in the North East of Venezuela.  It is planned that this industrial complex will also

 

28



 

serve the LNG Mariscal Sucre and other gas projects in the region.  The application of international health, safety and environment standards and sustainable development practices are key strategies for the development of this area.  This project will contribute to Venezuela’s natural gas business expansion, and will further diversify the country’s energy sources.

 

Mariscal Sucre Project

 

The main purpose of this project is the development of North Paria fields, at the North East of Venezuela to produce non-associated natural gas to supply both local and international markets. The project involves production of 1,070 million cubic feet of natural gas per day (MMCFD); the construction of a gas liquefaction train with a design capacity of 4.7 million metric tons per year (MMTY).  As a reference, one of the development scenarios for the four Mariscal Sucre Project’s fields consist of a total of 45 reservoirs that are going to be drained with 36 wells and drilled in 4 development phases over a period of about 20 years.

 

The first drilling phase comprises 14 platform wells – average of 31 days to drill and 14 days to complete if no downhole chemical injection is needed – and will all be completed with the use of a deepwater cantilever jack-up rig.  The initial wells will be at Río Caribe (6 wells) and Mejillones (8 wells) from four platforms.  The Central Production Facility (CPF) for the entire development will be located at Mejillones and initially, it will gather all production.  The export pipeline will initiate from this platform, and the offshore central control room will be located on this structure.  There are no processing facilities on the CPF.  The gas, condensate, and produced water will be routed to the LNG plant at Güiria by a multi-phase export pipeline.  All platforms will contain power generation and associated utilities.

 

Estimated initial production will be 17,000 BPD of stabilized condensate from Rio Caribe and 1,070 MMCFD of gas from all fields.  During this phase, the bulk of condensate will come from Rio Caribe.

 

The total estimated investment is $2,700 million.  First stage activities include basic services, dock services, port services, general services, corridors services, roads and security, residential area and relocation of city airport.

 

Refining and Marketing

 

Refining

 

Our downstream strategy has been focused on the expansion and upgrading of our refining operations in Venezuela, the United States and Europe, allowing us to increase our production of refined petroleum products and upgrade our product slate toward higher-margin refined petroleum products.  We have also increased the complexity of our refining capacity in Venezuela and made extensive investments to convert our worldwide refining assets from simple conversion to deep conversion capabilities.  Deep conversion capabilities in our Venezuelan refineries have enabled us to improve yields by allowing a greater percentage of higher value products to be produced.  Such capabilities have resulted in an increase in our gasoline and distillate yield from 35% in 1976 to 70% in 2003, 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 3,092 MBPD at December 31, 2003.  The following diagram presents a summary of PDVSA’s refining operations in 2003:

 

29



 

PDVSA’s Refining System

 

 

PDVSA’s Refining Capacity

 

The following table sets forth the refineries in which we hold an interest, the rated crude oil refining capacity and our net interest at December 31, 2003:

 

 

 

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, Anzoátegui

 

PDVSA

 

100

 

203

 

203

 

El Palito, Carabobo

 

PDVSA

 

100

 

130

 

130

 

Bajo Grande, Zulia

 

PDVSA

 

100

 

15

 

15

 

San Roque, Anzoátegui

 

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