20FR12B 1 c54803_20fr12b.htm

As filed with the Securities and Exchange Commission on September 12, 2008


UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

 

Registration Statement on Form 20-F

 

x

REGISTRATION STATEMENT PURSUANT TO SECTION 12(b) OR (g) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2007

OR

o

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

OR

o

TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from ____________ to ___________

OR

o

SHELL COMPANY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Date of event requiring this shell company report __________________

Commission file number:

 

ECOPETROL S.A.

(Exact name of Registrant as specified in its charter)

 

N/A

(Translation of Registrant’s name into English)

REPUBLIC OF COLOMBIA

(Jurisdiction of incorporation or organization)

Carrera 7 No. 37 – 69

BOGOTA – COLOMBIA

(Address of principal executive offices)

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

 

Title of each class

Name of each exchange on which registered:

 

 

American Depository Shares (as evidenced by American
Depository Receipts), each representing the right to receive
20 Common Shares

New York Stock Exchange 

   

Ecopetrol Common Shares with par value Ps$250 per share*

New York Stock Exchange

 
* Not for trading but only in connection with the registration of the American Depository Shares pursuant to the requirements of the SEC.

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

(Title of Class)

(Title of Class)

Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act.      None

(Title of Class)

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.

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.

o Yes x No

If this report is an annual or transition report, indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934.

o Yes x No

Note - Checking the box above will not relieve any registrant required to file reports pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 from their obligations under those Sections.

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.

o Yes x No

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):

 Large accelerated filer o
Accelerated filer o
Non-accelerated filer x
 

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

oItem 17 xItem 18

If this is an annual report, indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

oYes xNo

(APPLICABLE ONLY TO ISSUERS INVOLVED IN BANKRUPTCY PROCEEDINGS DURING THE PAST FIVE YEARS)

Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Sections 12, 13 or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court.

o Yes o No

 

 

ii

 


Table of Contents

 

 

 

Page

Forward-Looking Statements

 

5

Enforcement of Civil Liabilities

 

5

Presentation of Financial Information

 

6

Presentation of Information Concerning Reserves

 

7

ITEM 1

 

Identity of Directors, Senior Management and Advisors

 

7

ITEM 2

 

Offer Statistics and Expected Timetable

 

8

ITEM 3

 

Key Information

 

8

ITEM 3A

 

Selected Financial Data

 

8

ITEM 3B

 

Capitalization and Indebtedness

 

11

ITEM 3C

 

Reasons for the Offer and Use of Proceeds

 

11

ITEM 3D

 

Risk Factors

 

12

ITEM 4

 

Information on the Company

 

23

ITEM 4A

 

History and Development of the Company

 

23

ITEM 4B

 

Business Overview

 

23

ITEM 5

 

Operating and Financial Review and Prospects

 

58

ITEM 5B

 

Liquidity and Capital Resources

 

72

ITEM 5C

 

Research and Development, Patents and Licenses, etc.

 

74

ITEM 5D

 

Trend Information

 

74

ITEM 5E

 

Off-Balance Sheet Arrangements

 

74

ITEM 5F

 

Tabular Disclosure of Contractual Obligations

 

74

ITEM 5G

 

Safe Harbor

 

77

ITEM 5H

 

Recent U.S. GAAP Pronouncements

 

77

ITEM 6

 

Directors, Senior Management and Employees

 

77

ITEM 6A

 

Directors and Senior Management

 

77

ITEM 6B

 

Compensation

 

81

ITEM 6C

 

Board Practices

 

81

ITEM 6D

 

Employees

 

82

ITEM 6E

 

Share Ownership

 

84

ITEM 7

 

Major Shareholders and Related Party Transactions

 

84

ITEM 7A

 

Major Shareholders

 

84

ITEM 7B

 

Related Party Transactions

 

84

ITEM 7C

 

Interests of Experts and Counsel

 

87

ITEM 8

 

Financial Information

 

87

ITEM 8A

 

Consolidated Statements and Other Financial Information – 2008

 

87

ITEM 9

 

The Offer and Listing

 

87

ITEM 10

 

Additional Information

 

89

ITEM 10A

 

Share Capital

 

89

ITEM 10B

 

Articles of Incorporation and By-laws

 

90

ITEM 10C

 

Material Contracts

 

93

ITEM 10D

 

Exchange Controls

 

94

ITEM 10E

 

Taxation

 

95

ITEM 10F

 

Dividends and Paying Agents

 

100

ITEM 10G

 

Statement by Experts

 

101

ITEM 10H

 

Documents on Display

 

102

ITEM 10I

 

Subsidiary Information

 

102

ITEM 11

 

Quantitative and Qualitative Disclosures About Market Risk

 

102

ITEM 12

 

Description of Securities Other than Equity Securities

 

104

ITEM 12A

 

Debt Securities

 

104

ITEM 12B

 

Warrants and Rights

 

104

ITEM 12C

 

Other Securities

 

104

ITEM 12D

 

American Depositary Shares

 

104

ITEM 13

 

Defaults, Dividend Arrearages and Delinquencies

 

113

 

 

iii

 


 

 

iv

 


FORWARD-LOOKING STATEMENTS

This registration statement on Form 20-F contains forward-looking statements of Ecopetrol S.A., (hereinafter “we”, “us”, “our”, “Ecopetrol” or the “Company”) within the meaning of the safe harbor provisions of the U.S. Private Securities Litigation Reform Act of 1995. These statements are not based on historical facts and reflect our expectations for future events and results. Most facts are uncertain because of their nature. Words such as “anticipate”, “believe”, “could”, “estimate”, “expect”, “should”, “plan”, “potential”, “predicts”, “prognosticate”, and “achieve”, among other similar expressions, are understood as forward-looking statements. These factors may include the following:

 

Drilling and exploration activities

 

Future production rates

 

Import and export activities

 

Liquidity, cash flow and uses of cash flow

 

Projected capital expenditures

 

Dates by which certain areas will be developed or will come on-stream

 

Allocation of capital expenditures to exploration and production activities

Actual results are subject to certain factors out of the control of the Company and may differ materially from the anticipated results. These factors may include the following:

 

Changes in international crude oil and natural gas prices

 

Competition

 

Limitations on our access to sources of financing

 

Significant political, economic and social developments in Colombia

 

Military operations, terrorist acts, wars or embargoes

 

Regulatory developments

 

Technical difficulties

 

Other factors discussed in this document as “Risk Factors”

Most of these statements are subject to risks and uncertainties that are difficult to predict. Therefore, our actual results could differ materially from projected results. Accordingly, readers should not place undue reliance on the forward-looking statements contained in this registration statement.

ENFORCEMENT OF CIVIL LIABILITIES

We are a Colombian company, all of our Directors and executive officers and certain of the experts named in this registration statement are residents of Colombia, and a substantial portion of their respective assets are located in Colombia. Colombian courts determine whether to enforce a U.S. judgment predicated on the U.S. securities laws through a procedural system known as exequatur. Colombian courts will enforce a foreign judgment, without reconsideration of the merits, only if the judgment satisfies the following requirements:

 

a treaty exists between Colombia and the country where the judgment was granted or there is reciprocity in the recognition of foreign judgments between the courts of the relevant jurisdiction and the courts of Colombia;

 

 

5

 


 

the foreign judgment does not relate to “in rem rights” vested in assets that were located in Colombia at the time the suit was filed and does not contravene or conflict with Colombian laws relating to public order other than those governing judicial procedures;

 

the foreign judgment, in accordance with the laws of the country where it was rendered, is final and is not subject to appeal and a duly certified and authenticated copy of the judgment has been presented to a competent court in Colombia;

 

the foreign judgment does not refer to any matter upon which Colombian courts have exclusive jurisdiction;

 

no proceeding is pending in Colombia with respect to the same cause of action, and no final judgment has been awarded in any proceeding in Colombia on the same subject matter and between the same parties; and

 

in the proceeding commenced in the foreign court that issued the judgment, the defendant was served in accordance with the law of such jurisdiction and in a manner reasonably designated to give the defendant an opportunity to defend against the action.

The United States and Colombia do not have a bilateral treaty providing for automatic reciprocal recognition and enforcement of judgments in civil and commercial matters. The Colombian Supreme Court has in the past accepted that reciprocity exists when it has been proven that either a U.S. court has enforced a Colombian judgment or that a U.S. court would enforce a foreign judgment, including a judgment issued by a Colombian court. However, such enforceability decisions are considered by Colombian courts on a case-by-case basis.

We reserve our right to plead sovereign immunity under the United States Foreign Sovereign Immunities Act of 1976 with respect to actions brought against us under United States federal securities laws or any state securities laws.

PRESENTATION OF FINANCIAL INFORMATION

In this registration statement, references to “US$” or “U.S. dollars” are to United States Dollars and references to “$”, “Ps$”, “Peso” or “Pesos”, are to Colombian Pesos, the functional currency under which we prepare our financial statements. Certain figures shown in this registration statement have been subject to rounding adjustments and accordingly, certain totals or tables may not be an exact calculation of the preceding figures. In this registration statement a billion is equal to one with nine zeros.

The accompanying audited consolidated financial statements of Ecopetrol and our consolidated subsidiaries for the years ended December 31, 2007 and 2006, and the unaudited unconsolidated financial statements for the six-month period ended June 30, 2008 and 2007 have been prepared from accounting records, which are maintained under the historical cost convention as modified in 1992, to comply with the legal provisions of the Colombian Contaduría General de la Nación or National Accounting Office or CGN, to recognize the effect of inflation on non-monetary balance sheet accounts until December 31, 2001, including shareholders’ equity. The CGN authorized us to discontinue adjusting for inflation starting on January 1, 2002.

Our consolidated financial statements are prepared in accordance with accounting principles for Colombian state-owned entities issued by the CGN and other applicable legal provisions or Colombian Government Entity GAAP. These accounting standards differ in certain significant respects from generally accepted accounting principles in the United States or U.S. GAAP. Note 33 to our audited consolidated financial statements included in this registration statement provides a description of the principal differences between Colombian Government Entity GAAP and U.S. GAAP as they relate to our audited consolidated financial statements and provides a reconciliation of net income and shareholders’ equity for the years and dates indicated therein.

Our consolidated financial statements include the financial results for Black Gold Re Ltd., Oleo é Gas Do Brasil Ltda., Ecopetrol Peru S.A. and Ecopetrol America Inc., of which we have a 100%, 99.9%, 99.9% and 100% interest, respectively. Black Gold Re Ltd. and Oleo é Gas Do Brasil Ltda are included in our consolidated financial statements for the years ended December 31, 2006 and 2007. Ecopetrol Peru S.A. and Ecopetrol America Inc. are

 

 

6

 


included in our consolidated financial statements for the year ended December 31, 2007. These financial statements were consolidated line by line and all transactions and significant balances between affiliates have been eliminated.

This registration statement translates certain Peso amounts into U.S. dollars at specified rates solely for the convenience of the reader. Unless otherwise indicated, such Peso amounts have been translated at the rate of Ps$2,014.76 per US$1.00, which corresponds to the Tasa Representativa del Mercado or Representative Market Rate calculated at December 31, 2007, the last business day of the year. The Representative Market Rate is computed and certified by the Superintendencia Financiera or Superintendency of Finance, the Colombian banking and securities regulator, on a daily basis and represents the weighted average of the buy and sell foreign exchange rates negotiated on the previous day by certain financial institutions authorized to engage in foreign exchange transactions. The Superintendency of Finance also calculates the Representative Market Rate for each month for purposes of preparing financial statements and converting amounts in foreign currency to Pesos. Such conversion should not be construed as a representation that the Peso amounts correspond to, or have been or could be converted into, U.S. dollars at that rate or any other rate. On September 9, 2008, the Representative Market Rate was Ps$2,031.12 per US$1.00.

PRESENTATION OF ABBREVIATIONS

The following is a list of crude oil and natural gas measurement abbreviations commonly used throughout this registration statement.

 

bpd

 

Barrels per day

boe

 

Barrels of oil equivalent

cf

 

Cubic feet

cfpd

 

Cubic feet per day

mcf

 

Million cubic feet

mcfpd

 

Million cubic feet per day

btu

 

Million British thermal units

gbtu

 

Giga British thermal units

gbtud

 

Giga British thermal units per day

PRESENTATION OF THE NATION AND GOVERNMENT OF COLOMBIA

References to the Nation in this registration statement relate to the Republic of Colombia, our controlling shareholder. References made to the Government of Colombia or the Government correspond to the executive branch including the President of Colombia, the ministries and other governmental agencies responsible for regulating our business.

PRESENTATION OF INFORMATION CONCERNING RESERVES

Information concerning the technical definitions used for the estimated proved reserves is included in this registration statement. The information given about our proved reserves for 2007 is based on the 2006 audited reserves reports prepared by experts under the U.S. Securities and Exchange Commission or SEC definitions and rules at December 31, 2006 and updated by us to December 31, 2007 by applying the same rules. The experts have completed their reports for the year ended December 31, 2007 and there is a total negative variation between our estimates and the expert estimates of 5.6%. See “Item 4B Business Overview-Reserves” for an explanation of the differences between the estimated proved reserves in the expert reserve reports and our internal estimates.

ITEM 1

Identity of Directors, Senior Management and Advisors

The address of our Directors and executive officers is Carrera 7 No. 37-69, Bogota, Colombia.

 

 

7

 


Directors

 

Name

 

Position

 

Age


 


 


Minister of Mines and Energy (Hernan Martínez)

 

Director

 

66

Minister of Finance (Oscar I. Zuluaga)

 

Director

 

49

Director of the National Planning Agency (Carolina Rentería)

 

Director

 

41

Fabio Echeverri

 

Independent Director

 

75

Joaquin Moreno

 

Independent Director

 

59

Ignacio Sanín

 

Independent Director

 

60

Maria E. Velásquez

 

Independent Director

 

51

Omar A. Baquero

 

Independent Director

 

56

Mauricio Cárdenas

 

Independent Director

 

45

Executive Officers

 

Name

 

Position

 

Age


 


 


Javier G. Gutierrez

 

President and Chief Executive Officer

 

57

Adriana M. Echeverri

 

Chief Financial Officer

 

37

Martha S. Serrano

 

Secretary of the Board of Directors

 

52

Nelson Navarrete

 

Exploration and Production Executive Vice-President

 

46

Pedro A. Rosales

 

Downstream Executive Vice-President

 

45

Diego A. Carvajal

 

Vice-President of Exploration

 

55

Alvaro E. Vargas

 

Vice-President of Strategy

 

47

Federico Maya

 

Vice-President of Refining and Petrochemicals

 

43

Camilo Marulanda

 

Vice-President of Supply and Marketing

 

29

Oscar Trujillo

 

Vice-President of Transportation

 

48

Gabriel Osorio

 

Vice-President of Production

 

46

Oscar A. Villadiego

 

Vice-President of Services and Technology

 

44

Mauricio Echeverry

 

General Counsel

 

52

Auditors

 

Name

 

Business Address

 

Professional Body Membership


 


 


Ernst & Young Audit Ltda

 

Calle 93B No. 16-47, Bogota Colombia

 

Registered in the Colombian Central Board of Accountants

 

ITEM 2

Offer Statistics and Expected Timetable

Not applicable.

 

ITEM 3

Key Information

 

ITEM 3A

Selected Financial Data

The following table sets forth our selected financial data for the years ended December 31, 2007, 2006, 2005, 2004 and 2003, which have been derived from our consolidated financial statements, presented in Pesos which

 

 

8

 


were audited by Ernst & Young Audit Ltda. The information included below and elsewhere in this registration statement is not necessarily indicative of our future performance. The selected consolidated financial information presented below should be read in conjunction with, and should be qualified in its entirety by reference to, our consolidated financial statements and accompanying notes, “Presentation of Financial Information” and “Operating and Financial Review and Prospects”, included elsewhere in this registration statement.

 

 

 

BALANCE SHEET

 

 


 

 

For the year ended December 31,

 

 

2007(1)

 

2007

 

2006

 

2005

 

2004

 

2003

 

 


 


 


 


 


 


 

 

(US$
in thousands
except for
common share
and dividends
per share
amounts)

 

(Pesos in millions except for
common share and dividends per
share amounts)

Total assets

 

23,879,808

 

48,112,080

 

42,137,722

 

32,664,817

 

27,964,390

 

26,186,525

 

 


 


 


 


 


 


Shareholders’ Equity

 

13,306,035

 

26,808,467

 

20,835,746

 

13,285,251

 

10,000,871

 

9,228,863

 

 


 


 


 


 


 


Number of common shares(3)

 

40,472,512,588

 

40,472,512,588

(2)

36,384,788,817

 

36,384,788,817

 

36,384,788,817

 

36,384,788,817

 

 


 


 


 


 


 


Dividends declared per share:

 

0.06

 

123.0

(4)

55.0

 

35.7

 

31.8

 

29.7

Amounts in accordance with U.S. GAAP

 

 

 

 

 

 

 

 

 

 

 

 

Total Assets

 

14,740,479

 

29,698,528

 

26,517,482

 

 

 

 

 

 

Shareholders’ Equity

 

10,418,626

 

20,991,031

 

18,015,386

 

 

 

 

 

 

Number of common shares(3)

 

40,472,512,588

 

40,472,512,588

 

36,384,788,817

 

 

 

 

 

 

Dividends declared per share:

 

0.06

 

123.0

 

55.0

 

 

 

 

 

 

______________

(1)

Amounts stated in U.S. dollars have been translated at the rate of Ps$2,014.76 to US$1.00, which is the Representative Market Rate calculated at December 31, 2007, the last business day of the year, as reported and certified by the Superintendency of Finance.

(2)

Includes 4,087,723,771 new shares issued to the Republic of Colombia or the Nation on November 13, 2007, as a result of the capitalization of developed reserves in accordance with Decree 2625 of 2000.

(3)

Number of common shares include (i) a 1 to 400 stock split occurred in July 2007 which for purposes of comparability and dividends per share has been applied as if it had occurred in 2003, (ii) 48,512,147 shares issued to the Nation on April 2007 representing in-kind contributions, and (iii) 4,087,723,771 shares issued to the public in connection with our initial offering of shares in Colombia.

(4)

Represents payments made in 2007 based on net income and retained earnings for the year ended December 31, 2006. Dividends were declared and paid on 36,384,788,817 shares. In 2007 dividend payments to the Nation amounted to Ps$4,475,399 million of which Ps$3,052,236 million corresponded to net income and Ps$1,423,163 million to retained earnings paid prior to our initial public offering in the fourth quarter of 2007. See Item 5 —”Operating and Financial Review and Prospects — Pre-IPO Distribution of Retained Earnings”.

Colombian Government Entity GAAP differs in certain material respects to U.S. GAAP. For differences in net income and shareholders’ equity, see Note 33 to our consolidated financial statements “Differences between Colombian Government Entity GAAP and U.S. GAAP” and Item 5— “Operating and Financial Review and Prospects — Principal Differences between Colombian Government Entity GAAP and U.S. GAAP.”

 

 

9

 


 

 

INCOME STATEMENT

 

 

For the year ended December 31,

 

 


 

 

2007(1)

 

2007

 

2006

 

2005

 

2004

 

2003

 

 


 


 


 


 


 


 

 

(US$
in thousands
except for net
income per share
and average
number of shares
amounts)

 

(Pesos in millions except for net
income per share and average
number of shares amounts)

Total revenue

 

11,084,357

 

22,332,320

 

18,389,965

 

15,512,903

 

13,050,607

 

11,525,955

 

 


 


 


 


 


 


Operating income

 

4,433,201

 

8,931,837

 

4,635,832

 

4,498,385

 

3,934,227

 

3,014,833

 

 


 


 


 


 


 


Net operating income per share

 

0.14

 

291

 

109,207

 

105,969

 

92,679

 

71,021

 

 


 


 


 


 


 


Income before income tax

 

3,506,772

 

7,065,304

 

4,891,142

 

4,288,330

 

2,916,390

 

2,488,269

 

 


 


 


 


 


 


Net income

 

2,570,923

 

5,179,792

 

3,391,373

 

3,253,756

 

2,110,506

 

1,589,124

 

 


 


 


 


 


 


Weighted average number of shares outstanding(2)

 

30,702,164,870

 

30,702,164,870

 

42,449,825

 

42,449,825

 

42,449,825

 

42,449,825

 

 


 


 


 


 


 


Net income per share(3)

 

0.08

 

169

 

79,891

 

76,648

 

49,717

 

37,435

 

 


 


 


 


 


 


Amounts in accordance with U.S. GAAP

 

 

 

 

 

 

 

 

 

 

 

 

Total revenue

 

11,308,887

 

22,784,694

 

19,461,739

 

 

 

 

 

 

Operating income

 

4,196,579

 

8,455,099

 

7,245,976

 

 

 

 

 

 

Net operating income per share

 

0.11

 

229

 

199

 

 

 

 

 

 

Income before income tax and minority interest

 

4,323,417

 

8,710,648

 

7,765,863

 

 

 

 

 

 

Net income

 

3,049,835

 

6,144,685

 

6,636,424

 

 

 

 

 

 

Net income per share

 

0.08

 

166.42

 

182.40

 

 

 

 

 

 

Average number of shares outstanding(4)

 

36,922,352,491

 

36,922,352,491

 

36,384,788,817

 

 

 

 

 

 

 

 

10

 


______________

(1)

Amounts stated in U.S. dollars have been translated at the rate of Ps$2,014.76 to US$1.00, which was the Representative Market Rate calculated at December 31, 2007, the last business day of the year, as reported and certified by the Superintendency of Finance.

(2)

The weighted average number of common shares outstanding during 2007 was 30,702,164,870 as a result of the application of the 1 to 400 stock split, capitalization of reserves by the Nation and initial public offering in Colombia, which represents a net income per share of Ps$169, compared to Ps$79,891 during 2006 when the average number of shares outstanding was 42,449,825.

(3)

Net Income per share is calculated using the weighted-average number of outstanding shares at December 31 of each year, adjusted for a 1 to 400 stock split and the contribution to equity from the Nation. See Note 33 to our consolidated financial statements.

(4)

Amounts calculated in accordance with U.S. GAAP which differs in certain respects with the calculation of weighted average number of shares for Colombian Government Entity GAAP.

Exchange Rates

On September 9, 2008, the Representative Market Rate was Ps$2,031.12 per US$1.00. The Federal Reserve Bank of New York does not report a noon-buying rate for Pesos. The Superintendency of Finance calculates the Representative Market Rate based on the weighted averages of the buy/sell foreign exchange rates quoted daily by foreign exchange rate market intermediaries including financial institutions for the purchase and sale of U.S. dollars.

The following table sets forth the high, low, average and period-end exchange rate for Pesos/U.S. dollar Representative Market Rate for each of the last five years and for the last six months.

 

 

 

Exchange Rates

 

 


 

 

High

 

Low

 

Average

 

Period-End

 

 


 


 


 


Year ended December 31,

 

 

 

 

 

 

 

 

2003

 

2,968.88

 

2,778.21

 

2,877.79

 

2,778.21

2004

 

2,778.92

 

2,316.12

 

2,626.22

 

2,389.75

2005

 

2,397.25

 

2,272.95

 

2,320.77

 

2,284.22

2006

 

2,634.06

 

2,225.44

 

2,357.98

 

2,238.79

2007

 

2,261.22

 

1,877.88

 

2,078.35

 

2,014.76

January 2008

 

2,014.76

 

1,939.60

 

1,980.60

 

1,939.60

February 2008

 

1,939.77

 

1,843.59

 

1,903.27

 

1,843.59

March 2008

 

1,902.17

 

1,810.68

 

1,846.90

 

1,821.60

April 2008

 

1,834.96

 

1,765.30

 

1,796.13

 

1,780.21

May 2008

 

1,793.13

 

1,755.95

 

1,778.01

 

1,755.95

June 2008

 

1,923.02

 

1,652.41

 

1,722.81

 

1,923.02

July 2008

 

1,923.02

 

1,719.48

 

1,784.67

 

1,792.24

August 2008

 

1,932.20

 

1,771.31

 

1,848.69

 

1,932.20

September 9, 2008

 

2,041.81

 

1,932.20

 

1,998.39

 

2,031.12

______________

Source:

Superintendency of Finance for historical data. Banco de la República or the Colombian Central Bank (www.banrep.gov.co) and internal calculation for averages.

ITEM 3B

Capitalization and Indebtedness

The following table sets forth our total capitalization at March 30, 2008, on an actual and unaudited basis.

 

 

 

At March 30, 2008
(Pesos in millions)

 

 


Cash and cash equivalents

 

5,114,615

Shareholders’ equity

 

24,742,368

 

 


Total capitalization

 

29,856,983

 

 


ITEM 3C

Reasons for the Offer and Use of Proceeds

Not applicable.

 

 

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ITEM 3D

Risk Factors

Below is a description of the risk factors that we face which may affect our future results and the overall performance of the Colombian oil industry. Prospective purchasers of our shares represented by American Depositary Receipts or ADRs should carefully consider the risks described below, as well as other information contained in this registration statement, before deciding to invest in our ADRs. The risk factors described below are not the only ones that we face. Additional risks and uncertainties that we are unaware of, or that we currently deem immaterial, may also become important factors that affect us.

Financial results and the operation of the business units could be affected by the occurrence of one or more of these factors resulting in a decline in the price of our shares, which may result in you losing some or all of your investment.

Risks relating to Colombia’s political and regional environment

Colombia has experienced internal security issues that have had or could have in the future a negative effect on the Colombian economy and on us.

Colombia has experienced internal security issues, primarily due to the activities of guerrillas, paramilitary groups and drug cartels. In the past, guerrillas have targeted the crude oil pipelines, including the Caño Limón-Coveñas and Ocensa pipelines, and other related infrastructure disrupting our activities and those of our business partners. On several occasions guerilla attacks have resulted in unscheduled shut-downs of the transportation systems in order to repair damaged sections and undertake clean-up activities. These activities, their possible escalation and the violence associated with them have had and may have in the future a negative impact on the Colombian economy or on us, which may affect our customers, employees or assets. In the context of the political instability, allegations have been made against members of the Congress of Colombia and on Government officials for possible ties with paramilitaries. This situation may have a negative impact on the credibility of the Colombian Government or the Government which could in turn have a negative impact on the Colombian economy or on us in the future.

Attacks or alleged attacks by the Colombian army of guerrilla positions in neighboring countries have resulted in political tension with neighboring countries

The Government’s recent attacks on Revolutionary Armed Forces of Colombia or FARC’s positions in Ecuador, as well as the Colombian Government’s allegations that neighboring countries are supporting the guerilla groups, have raised regional tensions. On March 1, 2008 the Colombian army and air force launched an air strike on a FARC camp in Ecuador, that resulted in the death of one of the members of FARC’s secretariat. On other occasions allegations have been made by Venezuela that the Colombian army has entered foreign soil while in pursuit of FARC members. The Colombian army and air force continue to combat FARC members throughout Colombian including in regions near Colombia’s borders. New attacks by the Colombia’s armed forces on FARC positions near Colombia’s borders could result in new and heightened tensions with its neighbors, which could have a negative impact on Colombia’s economy and general security situation.

Companies operating in Colombia, including us are subject to prevailing economic conditions and investment climate in Colombia, which may be less stable than prevailing economic conditions in developed countries.

The market price of securities issued by Colombian companies, including us are subject to the prevailing economic conditions in Colombia. Substantially all of our assets and operations are located in Colombia, and all of our sales are currently derived from our crude oil and natural gas production and production of our refineries located in Colombia. In the past economic growth in Colombia has been negatively affected by lower foreign direct investment and high inflation rates and the perception of political instability.

The Colombian government has exercised and continues to exercise substantial influence over many aspects of the Colombian economy, and has changed monetary, fiscal, taxation, labor and other policies over time to influence the performance of the Colombian economy. We have no control over the extent and timing of government intervention and policies

 

 

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If the perception of improved overall security in Colombia changes or if foreign direct investment declines, the Colombian economy may face a downturn which could negatively affect our financial condition and results of operation. Furthermore the market price of our shares and ADSs may be adversely affected by changes in governmental policy, particularly those affecting economic growth, interest rates, inflation, taxes and the value of the Colombian peso.

Developments and the perception of risk in other countries, especially emerging market countries, may adversely affect the market price of Colombian securities, including our American Depositary Shares (ADSs).

Securities issued by Colombian companies may be affected by economic and market conditions in other countries, including other Latin American and emerging market countries. Securities issued by Colombian issuers are also likely to be affected by economic and political conditions in Colombia’s neighbors: Venezuela, Ecuador, Peru, Brazil and Panama. Although economic conditions in such Latin American and other emerging market countries may differ significantly from economic conditions in Colombia, investors’ reactions to developments in these other countries may have an adverse effect on the market value of securities of Colombian issuers.

Due to recent crises in several emerging market countries (such as the Asian financial crisis of 1997, the Russian financial crisis of 1998 and the Argentine financial crisis of 2001), investors may view investments in emerging markets with heightened caution. As a result of the crisis in other Latin American countries, flows of investments into Colombia were reduced. Crises in other emerging market countries may hamper investor enthusiasm for securities of Colombian issuers. If Latin America experiences a new slow-down or if the price for securities of Latin American issuers falls, the price for our ADSs could follow this trend and could be adversely affected. A new financial crisis could also make it more difficult for us and our subsidiaries to access the international capital markets and finance our operations and capital expenditures in the future on acceptable terms.

Our controlling shareholder’s interests may be different from yours.

The Republic of Colombia, or the Nation, is our largest shareholder controlling 89.9% of our outstanding capital stock. Colombian law requires the Nation to maintain the majority of our outstanding capital stock, thus holding the right to elect the majority of the members of our Board of Directors. In the future the Nation as our controlling shareholder may undertake projects which may not be in our best interest or in the best interest of our minority shareholders, including holders of our ADSs.

Before we can issue any debt in the international and local capital markets, the Government, through the Ministry of Finance and Public Credit, must authorize the issuance of such debt and we must register external debt with the Colombian Central Bank. We cannot assure you that if we were to seek such an authorization, that the Nation would issue it in a timely fashion or at all.

In the future the Government could amend the rules currently requiring it to reimburse us for the motor fuel subsidy. We could also be forced to make equity investments or to incur additional costs and sell our products in terms and conditions that would not be necessarily in our best interest.

Additionally our controlling shareholder may require our Board of Directors to declare dividends in an amount that result in us having to reduce our capital expenditures thereby negatively affecting our prospects, results of operations and financial condition.

Our operations are subject to extensive regulation.

The Colombian hydrocarbons industry is subject to extensive regulation and supervision by the Government in matters including the award of exploration and production blocks by the National Hydrocarbon Agency, or Agencia Nacional de Hidrocarburos or ANH, the imposition of specific drilling and exploration obligations, restrictions on production, price controls, capital expenditures and required divestments. Existing regulation applies to virtually all aspects of our operations in Colombia and abroad. See Item 4B—”Business Overview — Regulation”.

 

 

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The terms and conditions of the agreements with the ANH under which we explore and produce crude oil and natural gas generally reflect negotiations with the ANH and other governmental authorities and may vary by fields, basins and hydrocarbons discovered.

We are required, as are all oil companies undertaking exploratory and production activities in Colombia, to pay a percentage of our production to the Government as royalties. The Government has modified the royalty program for crude oil and natural gas production several times in the last 20 years, as it has modified the regime regulating new contracts entered into with the Government. The royalty regime for contracts being entered into today for crude oil is tied to a scale starting at 8% for production of up to 5,000 barrels per day or bpd and increases up to 25% for production above 600,000 bpd. Royalties for natural gas production are also subject to a sliding scale depending on whether the field is on- or off-shore and range between 8% and 25%.

In the future, the Government may once again amend royalty payment levels for new contracts and such changes could have a material adverse effect on our financial condition or results of operation.

The Government may delay the reimbursement of the gasoline and diesel fuel subsidies.

The Government regulates the maximum prices at which we can sell certain kinds of fuels to wholesalers in the local market. We sell regular gasoline and diesel fuel to wholesalers at prices which are lower than the export parity price. According to Law 1110 of 2006, the Government is responsible for reimbursing us for the difference between the regulated price and the export and import parity price, which we call the fuel subsidy. The calculation and payment of the fuel subsidy has been significantly delayed in recent months due to a processing and payment backlog. Ultimate collection of subsidy due depends on the Government’s financial condition and payment schedule, the promptness of taxes collected and the total amount due. We are unable to determine when we will fully collect these amounts or any additional subsidies that become due in the future.

The Ministry of Mines and Energy put forward a proposal pursuant to which oil and gas companies working in Colombia would make a special contribution to a fund when the international price of oil exceeds US$60 per barrel. The contribution would increase by 5% every time the price of crude oil increased by US$30 dollars. The cash deposited in the fund would be used by the Government to pay the motor fuel subsidy. The oil and gas companies rejected the proposal and the Government has indicated that it will revise it before making a final decision.

Any material delay in payment of these subsidies by the Government or a significant amendment to Law 1110 imposing on us additional responsibilities with respect to the subsidies could have a negative impact on our financial condition and results of operations.

Risks related to our business

Our business depends substantially on international prices for crude oil and refined products, and prices for these products are volatile. A sharp decrease in such prices could materially and adversely affect our business prospects and results of operations.

Crude oil prices have traditionally fluctuated as a result of a variety of factors including, among others, the following:

 

Changes in international prices of natural gas and refined products;

 

Long-term changes in the demand for crude oil, natural gas and refined products;

 

Regulatory changes;

 

Inventory levels;

 

Increase in the cost of capital;

 

Adverse economic conditions;

 

 

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Development of new technologies;

 

Economic and political events, especially in the Middle East and elsewhere with high levels of crude oil production;

 

The willingness and ability of the Organization of the Petroleum Exporting Countries or OPEC and its members to set production levels and prices;

 

Local and global demand and supply;

 

Development of alternative fuels;

 

Weather conditions; and

 

Terrorism and global conflict.

As of December 2007, nearly 96% of our revenues came from sales of crude oil, natural gas and refined products. Most prices for products developed and sold by us are quoted in U.S. dollars and variances in the U.S. dollar/Peso exchange rate have a direct effect on our Peso-denominated financial statements.

A significant and sustained decrease in crude oil prices could have a negative impact on our results of operations and financial condition. In addition, a reduction of international crude oil prices could result in a delay in our capital expenditure plan, in particular delaying exploration and development activities, thereby delaying the incorporation of reserves.

Achieving our long-term growth prospects depends on our ability to execute our strategic plan, in particular discovering additional reserves and successfully developing them, and failure to do so could prevent us from achieving our long-term goals.

The ability to achieve our long-term growth objectives depends on discovering or acquiring new reserves as well as successfully developing them. Our exploration activities expose us to the inherent risks of drilling, including the risk that we will not discover commercially productive crude oil or natural gas reserves. The costs associated with drilling wells are often uncertain, and numerous factors beyond our control may cause drilling operations to be curtailed, delayed or cancelled.

If we are unable to conduct successful exploration and development of our exploration activities, or if we do not acquire properties having proved reserves, our level of proved reserves will decline. Failure to secure additional reserves may impede us from achieving our growth targets, production targets and may have a negative effect on our results of operations and financial condition.

In association with our business partners we have undertaken deep water drilling (between 300 and 1,500 meters depth) in two blocks in the Gulf Coast and are planning to undertake deep water drilling in nine blocks in Colombia and six blocks in Brazil. Currently, we are acting as operators in three exploration blocks in Colombia. Deep water drilling entails new and heightened risks as reserves are located at greater distances underneath the seabed and seismic information for these deposits is more expensive to produce. Our lack of expertise in deep water drilling and the heightened risks and costs associated with this type of drilling may have a negative effect on our results of operations and financial condition.

Our crude oil and natural gas reserve estimates involve some degree of uncertainty and may prove to be incorrect over time, which could adversely affect our ability to generate revenue.

Historical reserves correspond to quantities estimated by us in accordance with international standards issued by the Society of Petroleum Engineers, World Petroleum Congresses and the SEC. Estimates are based on geological, topographic and engineering facts. Actual reserves and production may vary materially from estimates shown in this registration statement, which could affect our results of operation.

 

 

15

 


Our drilling activities are capital intensive and may not be productive.

Drilling for crude oil and natural gas involves numerous risks, including the risk that we will not encounter commercially productive crude oil or natural gas reservoirs. The costs of drilling, completing and operating wells are high or uncertain, and drilling operations may be curtailed, delayed or canceled as a result of a variety of factors, including:

 

Unexpected drilling conditions;

 

Pressure or irregularities in formations;

 

Security problems;

 

Equipment failures or accidents;

 

Fires, explosions, blow-outs and surface cratering;

 

Title problems;

 

Other adverse weather conditions; and

 

Shortages or delays in the availability or in the delivery of equipment.

Certain of our future drilling activities may not be successful and, if unsuccessful, this failure could reduce the ratio at which we replace our reserves, which could have an adverse effect on our results of operations and financial condition. While all drilling, whether developmental or exploratory, involves risks, exploratory drilling involves greater risks of dry holes or failure to find commercial quantities of hydrocarbons. Because of the percentage of our capital budget devoted to higher-risk exploratory projects, it is likely that we may in the future experience significant exploration and dry hole expenses.

Increased competition from foreign crude oil companies may have a negative impact on our ability to gain access to additional crude oil and natural gas reserves in Colombia.

The ANH is the governmental entity responsible for promoting oil and gas investments in Colombia, establishing reference terms for exploration rounds and assigning exploration blocks to oil and gas companies. Prior to the enactment of Decree Law 1760 of 2003, we had an automatic right to explore any territory in Colombia and to enter into joint venture agreements with foreign and local oil companies. Under current regulations, we are obligated to bid on any exploration blocks deemed as reserved by the ANH and compete with local and foreign oil companies for the blocks offered for exploration by the agency. We may also request the ANH to assign us exploration blocks which have not been previously reserved by the agency. Our ability to obtain access to potential production fields also depends on our ability to evaluate and select potential hydrocarbon-producing fields and to adequately bid for these exploration fields.

Our strategies include international expansion where we do not have extensive experience and where we may face competition from local market players and international oil companies that have more experience exploring in these countries.

If we are unable to adequately compete with foreign and local oil companies, or if we cannot enter into joint ventures with market players with properties where we could potentially find additional reserves, we may be obligated to conduct exploration activities in less attractive blocks. If we fail to maintain our current market position in Colombia, our results of operations and financial conditions may be adversely affected.

We may be subject to substantial risks relating to our development of exploration activities outside Colombia.

We began exploration activities outside Colombia in 2006 through our Brazilian subsidiary, Oleo é Gas Do Brazil Ltda., in a joint venture with Petrobras. Our foreign subsidiaries have subsequently entered into a number of joint venture exploration agreements with regional and international oil companies to explore blocks in Peru, Brazil

 

 

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and the Gulf of Mexico. The results of operations and financial condition of our subsidiaries in these countries may be adversely affected by fluctuations in their local economies, political instability and government actions.

We have limited or no experience exploring outside Colombia, where we are the incumbent operator. We may face new and unexpected risks involving environmental requirements that exceed those faced by us locally. We may also experience the imposition of restrictions on hydrocarbon exploration and export, or increases in export tax or income tax rates for crude oil and natural gas. We may be exposed to legal disputes related to our operating or exploration activities such as the one we currently face in Brazil where the awarding of an exploration block is under dispute. See Note 4 to our consolidated financial statements that includes a description of this dispute.

If one or more of these risks described above were to materialize, we may not achieve the strategic objectives in our international operations, which may negatively affect our results of operations and financial condition.

We may incur losses and spend time and money defending pending law suits and arbitrations.

We are currently a party to several legal proceedings relating to civil, administrative, environmental, and labor claims filed against us. We are also subject to labor-related lawsuits filed by current and former employees in connection with pension plans and retirement benefits affecting the plaintiffs. These claims involve substantial sums of money as well as other remedies. See Notes 18 and 29 to our consolidated financial statements.

Our most relevant legal proceeding was brought by an association of former employees known by the acronym Foncoeco. The former employees brought an action against us in connection with a company profit-sharing plan offered in 1962 that expired in 1975. The plaintiffs claim that our Board of Directors had set aside a specific amount under the profit sharing plan, which was not entirely distributed to employees eligible under the plan. The court of first instance ruled in our favor and rejected the plaintiffs’ arguments. The plaintiffs appealed the ruling to the Tribunal Superior de Bogota or Bogota Higher Tribunal, which ordered us to present a rendición de cuentas (an accounting action) to the first instance judge based on the amounts allocated by our Board of Directors. Pursuant to our accounting and based on the expert testimony of a witness presented by the plaintiffs who included amounts never allocated by our Board of Directors to the profit sharing plan, the first instance judge ordered us to pay Ps$541,833 million, or approximately US$260 million. We have appealed the decision by the first instance judge to the Bogota Higher Tribunal. Additionally, we have initiated a separate Recurso de Revisión (review proceeding) of the Tribunal’s ruling before the Colombian Supreme Court. If we are not successful in our appeal, we may be obligated to pay the total amount of the ruling, which could have a negative impact on our results of operations. We have recorded a provision of Ps$64,000 million in respect of this claim.

Our operations may not be able to keep pace with the increasing demand for natural gas.

The demand for natural gas in Colombia has grown significantly in recent years. As a result of this growth, demand for natural gas could exceed production capacity, resulting in possible supply shortages. When production shortages occur we are required to compensate industrial clients with whom we have supply contracts by paying penalties and other compensatory expenses detailed in the supply contracts.

Internal demand for natural gas has experienced strong growth during the last decade as a result of national campaigns for cleaner energy and cheaper tariffs for retail customers. We may not be able to keep up with local demand or our industrial commitments if demand outpaces the rate of new discoveries.

We have long-term contracts to supply power utilities and other large customers. In 2007, we entered into an agreement with Petróleos de Venezuela, S.A. or PDVSA to supply natural gas to Venezuela until 2012, when it is expected that Venezuela will supply us with natural gas. It is uncertain whether Venezuela will begin supplying us with natural gas in 2012.

If we are unable to discover new natural gas reserves or if we cannot extract existing reserves to meet our commitments, contracts and support local demand, we may be required to compensate our customers for our failure to supply natural gas, which may have a negative effect on our financial condition and results of operation.

 

 

17

 


We are not permitted by law to own more than 25% of a natural gas transportation company or sell transportation capacity pipelines which may not allow us to transport new natural gas reserves to distribution points and to our customers.

We discovered natural gas reserves in the Cusiana and Cupiagua fields for which limited transportation capacity currently exists. New natural gas transportation infrastructure may not be available to transport natural gas from new or existing fields to regions where there is a demand for natural gas. Furthermore, we are prohibited by law from holding more than 25% of the equity of any natural gas transportation company or from selling transportation capacity to third parties and we cannot determine whether the necessary transportation capacity will be built by third parties to transport natural gas. We may be required to enter into agreements with natural gas transportation companies in terms that are not favorable to us.

Furthermore, we currently have long-term supply contracts with gas-fired power plants that require us to deliver natural gas in Barrancabermeja and not at the La Guajira fields. Our ability to deliver the natural gas to these clients at the delivery point is limited by the Ballena-Barranca transportation capacity. If we are unable to acquire the necessary transportation, we may be unable to meet our obligation with power generators, which could result in us having to pay fines.

If we are unable to transport natural gas discoveries to our customers or to regions where natural gas is needed, we may not be able to develop these reserves, which would not allow us to recover the capital expenditures invested to make new natural gas discoveries.

Results could be affected by conflicts with the labor unions.

In the past we have been affected by strikes and work stoppages promoted by our labor union. These strikes have been both politically and contract-related, especially during collective bargaining negotiations. In the event relations with our labor unions deteriorate, which could result in industry-general strikes, work stoppages or even sabotages, our results of operations and financial condition could be negatively affected.

Our collective bargaining agreement entered into with Unión Sindical Obrera de la Industria del Petróleo— USO and Sindicato Nacional de Trabajadores de Empresas Operadoras, Contratistas, Subcontratistas de Servicios y Actividades de la Industria del Petróleo y Similares— SINDISPETROL two of our most significant industry labor unions will expire on June 8, 2009. Failure to reach a new collective bargaining agreement through consensual negotiations could result in labor unrest, including a strike or work stoppages that could negatively affect our results of operations and financial condition.

We may experience difficulties in recruiting and retaining key personnel.

The increase in worldwide activity in the oil and gas sector has resulted in an increase in the demand for qualified industry personnel. Compensation for oil engineers and other experienced industry personnel has risen in recent years making it harder for oil companies with smaller budgets to recruit and retain top talent. Larger oil companies in need of qualified personnel have begun to recruit in non-traditional markets, including Colombia. Since the enactment of Decree Law 1760 of 2003, pursuant to which private oil companies signed exploration and production agreements directly with the ANH and not with us, Colombia has become a more attractive market for regional and international oil companies. New participants and other industry players have started searching for qualified personnel in Colombia by offering them more attractive compensation schemes, including our current employees.

As a result of our initial public offering, we are no longer subject to the Government’s salary caps. Nevertheless, for a short period of time and while we adjust our compensation structure to industry standards in Latin America, we could lose some of our current employees, thereby adversely affecting our productivity and the timing of our projects. We may need to spend additional resources in identifying and recruiting highly qualified personnel. If we are unable to recruit the necessary personnel or if we cannot retain existing personnel, we may not be able to operate adequately or meet our growth plans which could adversely affect our results of operations.

 

 

18

 


Interruption of activities caused by external factors.

We are exposed to several risks that may partially interrupt our activities. These risks include, among others, fire disasters, explosions, malfunction of pipelines and emission of toxic substances. As a result of the occurrence of any of the above, operational activities could be significantly affected or paralyzed. These risks could result in property damage, loss of revenue, cost of human lives, pollution and harm to the environment, among others. If any of these occur, we may be exposed to economic sanctions, fines or penalties.

At December 2007, we had a corporate insurance program with specific coverage against property damage, sabotage and terrorism, product liability, loss of cargo, crime and Directors and Officers’ liability. According to our credit requirements, all of the reinsurance companies comply with an A- risk rating by Duff & Phelps, or equivalent. Due to the nature of our business, we are a highly vulnerable company, and could face losses due to risks excluded or within deductibles of our corporate insurance program. Some other factors may affect our ability to continue our normal operations and our financial position, which may affect our results of operation.

We carry out and plan to carry out exploration and production activities in areas classified by the Government as indigenous reserves. We may not begin to explore for or produce hydrocarbons in these regions until we reach an agreement with the indigenous communities living on these lands. Generally these consultations last between four and six months, but may be significantly delayed if we cannot reach an agreement. For example, we conduct operations in areas of the Northeastern region which are inhabited by the U’wa community. Commencement of operations on two blocks in this region have been delayed for 16 years and seven years, respectively and as of June 2008 we have not received approval to undertake activities in these two blocks by the indigenous authorities. Similarly, some of our exploration operations in the Southern region have been delayed for over a year as a result of the presence of the Kofan community who oppose our presence and activities in the reservation. If our activities endanger the conservation and preservation of these cultural minorities or their identities or beliefs, we may not be able to explore regions with good prospects. We may face similar risks in other jurisdictions where we have initiated exploration which could have a negative effect on our operations.

Currency fluctuations and an appreciation of the Peso against the U.S. dollar could have a material adverse effect on our financial condition and results of operations because approximately 40% of our revenues are in U.S. dollars or are referenced to U.S. dollars.

Approximately 40% of our sales are denominated in U.S. dollars and are made in the international markets. The impact of fluctuations in exchange rates, especially the Peso/U.S. dollar rate on our operations has been and may continue to be material. In addition, a substantial share of our liquid assets are held in U.S. dollars or indexed to foreign currencies and have lost value as the Peso has appreciated against these currencies. We usually do not use forwards, swaps or futures contracts to mitigate the impact of currency fluctuations. The Peso has appreciated 11.6%, (1.6)% and 11.9% on average against the U.S. dollar in 2005, 2006 and 2007, respectively, as a result of an improving Colombian economy and the relative weakness of the U.S. dollar and this has had a material adverse effect on our results of operations.

When the Peso depreciates against the U.S. dollar, our revenues from exports, when translated into Pesos, increase. However, imported goods and oil services denominated in U.S. dollars become more expensive for us.

We may be exposed to increases in interest rates, thereby increasing our financial costs.

As a result of our initial public offering, we became a Sociedad de Económica Mixta or mixed economy company and can now issue debt locally and in the international capital markets. In the future we may issue floating rate debt or issue structured finance products and other debt-related instruments, the funding of which depend on prevailing interest rates. If market interest rates increase, our financing expenses may increase, which could have an adverse effect on our results of operations and financial condition.

We are subject to extensive environmental regulations in Colombia and in the other countries in which we operate.

Our operations are subject to extensive national, state and local environmental regulations in Colombia. Environmental rules and regulations cover our exploration, transportation, refining and production activities. These

 

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regulations establish, among others, quality standards for hydrocarbon products, air emissions, water discharges and waste disposal, environmental standards for abandoned crude oil wells, remedies for soil, water pollution and the general storage, handling, transportation and treatment of hydrocarbons in Colombia. Since the creation of the Ministry of the Environment in 1993 and the enactment of more rigorous laws, environmental regulations have substantially impacted our operations and business results. Currently, all exploratory project drilling in areas that do not yet have a license must have an environmental impact assessment and must receive an environmental license from the local authorities. The Ministry of the Environment routinely inspects our crude oil fields, refineries and other production sites and may decide to open investigations which may result in fines, restrictions on operations or other sanctions in connection with our non-compliance with environmental laws.

We are also subject to local environmental regulations issued by the corporaciones autonomas regionales or regional environmental authorities, which oversee compliance with each department’s environmental laws and regulations by oil and gas companies. If we fail to comply with any of these national or local environmental regulations we could be subject to administrative and criminal penalties, including warnings, fines and closure orders of our facilities. See Item 4– Business Overview – Environmental Matters.

Environmental compliance has become more stringent in Colombia in recent years and as a result we have allocated a greater percentage of our capital expenditures for compliance with these laws and regulations. If environmental laws continue to impose additional costs and expenses on us, we may need to reduce our investments on strategic projects in order to allocate funds to environmental compliance. These additional costs may have a negative impact on the profitability of the projects we intend to undertake or may make them economically unattractive, in turn having a negative impact on our results of operations and financial condition.

We are subject to foreign environmental regulations for the exploratory activities conducted by us outside Colombia. Foreign environmental regulations may be more severe than those established under Colombian law and therefore, we may be required to make additional investments to comply with those regulations. Failure to comply with foreign environmental regulations may result in investigations by foreign regulators, which could lead to fines, warnings or temporary suspensions of our operations, which could have a negative impact on our financial condition and results of operations.

Our activities face operational risks that may affect the health and safety of our workforce.

Some of our operations are developed in remote and dangerous locations which involve health and safety risks that could affect our workforce. Under Colombian law and industrial safety regulations we are required to have health and safety practices that minimize risks and healthy issues faced by our workforce. Failure to comply with health and safety regulations may derive investigations by health officials which could result in lawsuits or fines.

We may be obliged to incur in additional costs and expenses to allocate funds to industrial safety and health compliance. These additional costs may have a negative impact on the profitability of the projects we may decide to undertake.

In addition, we may be subject to foreign health and safety regulations for our exploratory activities conducted outside Colombia. Foreign health and safety regulations may be more severe than those established under Colombian law and therefore, we may be required to make additional investments to comply with those regulations.

Risks relating to our ADSs

There has been no prior market for our ADSs. An active and liquid public market for our ADSs may not develop.

There is no existing market for our ADSs. Accordingly, an active and liquid public market for our ADSs may not develop or be sustained after this listing. Illiquid or inactive trading markets generally result in higher price volatility and lower efficiency in the execution of sale and purchase orders in the securities markets. The market

 

 

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price of the ADSs may fluctuate significantly in response to a number of factors, some of which may be beyond our control. In the event that the trading price of our ADSs declines, you may lose all or part of your investment in our ADSs. In addition, holders of ADSs may choose to cancel them and receive instead common shares in an amount equivalent to that of the ADSs previously held. Cancellation of a considerable number of ADSs may significantly influence the development of an actively liquid market for our ADSs, which may have a material adverse effect on the price of our ADSs.

Holders of our ADSs may encounter difficulties in exercising their voting rights.

Holders of our common shares are entitled to vote on shareholder matters. However, holders of our ADSs may encounter difficulties in exercising some of the rights of shareholders if they hold our ADSs rather than the underlying common shares. For example, holders of our ADSs are not entitled to attend shareholders’ meetings, and can only vote by giving timely instructions to the depositary in advance of a shareholders’ meeting. Under Colombian law, we are not required to solicit proxies from our existing shareholders and, therefore, you may not receive notice in time to instruct the depositary to vote the shares. See Item 12D—”American Depositary Shares.”

We believe that the holders of the ADSs should be able to direct the depositary to vote the common shares separately in accordance with their individual instructions, particularly as this is the current interpretation of the Superintendencia de Sociedades or Superintendency of Corporations, this issue has been the subject of differing regulatory interpretations in the past and may be subject to differing interpretations in the future. Under prior regulatory interpretations, the depositary could be required to vote the underlying common shares in a single block (presumably reflecting the majority vote of the ADS holders). In the future the Colombian regulatory authorities may change their interpretation as to how voting rights should be exercised by ADSs holders, and if this were to occur any such limitation or loss could adversely affect the value of such common shares and your ADSs.

Our ADSs holders may be subject to restrictions on foreign investment in Colombia.

Colombia’s International Investment statute regulates the manner in which non-Colombian residents can invest in Colombia and participate in the Colombian securities market. Among other requirements, Colombian law requires foreign investors to register certain foreign exchange transactions with the Colombian Central Bank and outlines the necessary procedures to authorize certain types of foreign investments. Colombian law requires that certain foreign exchange transactions including international investment in foreign currency between Colombian residents and non-Colombian residents must be made through authorized foreign exchange market participants. Any income or expenses under our ADR program must be made through the foreign exchange market.

Investors acquiring our ADRs are not required to register with the Colombian Central Bank. Investors in ADRs who choose to surrender their ADRs and withdraw common shares would have to register their investment in the common shares as a foreign direct investment, in the event the investor does not own a portfolio of investments in Colombia; or as a portfolio investment, in the event the investor delivers such shares to a registered foreign capital investment fund. Non-Colombian residents cannot directly hold portfolio investments in Colombia, but are able to do so through a registered foreign capital investment fund. Investors would only be allowed to transfer dividends abroad after their foreign investment registration procedure with the Colombian Central Bank has been completed. Investors withdrawing the common shares may incur in expenses and/or suffer delays in the application process. The failure of a non-resident investor to report or register foreign exchange transactions with the Colombian Central Bank relating to investments in Colombia on a timely basis may prevent the investor from remitting dividends, or initiate an investigation that may result in a fine. In the future, the Government, the Congress of Colombia or the Colombian Central Bank may amend Colombia’s International Investment Statute or the foreign investment rules which could result in more restrictive rules and could negatively affect trading of our ADSs.

Additionally, Colombia currently has a free exchange rate system; however, other restrictive rules for the exchange rate system could be implemented in the future. In the event that a more restrictive exchange rate system is implemented, the depositary may experience difficulties converting Peso amounts into U.S. dollars to remit dividend payments.

 

 

21

 


Holders of our ADSs are not able to effect service of process on us, our directors or executive officers within the United States, which may limit your recovery in any foreign judgment you obtain against us.

We are a sociedad de economía mixta organized under the laws of Colombia. All of our directors and executive officers reside outside the United States. All or a substantial portion of our assets and the assets of these persons are located outside the United States. As a result, it may not be possible for you to effect service of process within the United States upon us or these persons or to enforce against us or them in U.S. courts judgments obtained in such courts predicated upon the civil liability provisions of the U.S. federal securities laws. Colombian courts determine whether to enforce a U.S. judgment predicated on the U.S. securities laws through a procedural system known as exequatur. For a description of these limitations, see “Enforcement of Civil Liabilities.”

We may claim some immunities under the Foreign Sovereign Immunities Act with respect to actions brought against us under the US securities laws and your ability to sue or recover may be limited.

We reserve the right to plead sovereign immunity under the United States Foreign Sovereign Immunities Act of 1976 with respect to actions brought against us under United States federal securities laws or any state securities laws. Accordingly, you may not be able to obtain a judgment in a U.S. court against us unless the U.S. court determines that we are not entitled to sovereign immunity with respect to that action. Moreover, you may not be able to enforce a judgment against us in the United States except under the limited circumstances specified in the Foreign Sovereign Immunities Act.

The protections afforded to minority shareholders in Colombia are different from those in the United States, and may be difficult to enforce.

Under Colombian law, the protections afforded to minority shareholders are different from those in the United States. In particular, the legal framework with respect to shareholder disputes is less developed under Colombian law than U.S. law and there are different procedural requirements for commencing shareholder lawsuits, such as shareholder derivative suits. As a result, it may be more difficult for our minority shareholders to enforce their rights against us or our Directors or controlling shareholder than it would be for shareholders of a U.S. company.

The relative volatility and illiquidity of the Colombian securities markets may substantially limit our investors’ ability to sell our ADSs at the price and time they desire.

Investing in securities that are traded in emerging markets, such as Colombia, often involves greater risk when compared to other world markets, and these investments are generally considered to be more speculative in nature. The Colombian securities market is substantially smaller, less liquid, more concentrated and can be more volatile than other securities markets. For example, the Bolsa de Valores de Colombia or BVC had a market capitalization of approximately Ps$205,671 billion (US$98.95 billion using the monthly average exchange rate for 2007) as of December 31, 2007, and an average daily trading volume of approximately Ps$88,287 million (US$42.5 million, using the average exchange rate for 2007) compared to a market capitalization of Ps$125,884 billion (US$55.7 billion) as of December 31, 2006, and an average daily trading volume of approximately Ps$109,951 million (US$46.6 million) in 2006. In contrast, the New York Stock Exchange had a market capitalization of US$17.9 trillion as of December 31, 2007, and a daily trading volume of approximately US$87.1 billion in 2007.

At December 31, 2007 our shares had the highest trading volume in the BVC averaging 20.8 million shares traded per day representing the highest market capitalization of the BVC and 39.8% of the BVC’s total market capitalization. Our shares represent 18.7% of the Índice General de la Bolsa de Valores de Colombia or IGBC stock market index, 9.0% of the COL20, a stock market index that includes the top 20 traded stocks in the BVC and 20% of the COLCAP, a stock price volatility index. In addition, our shares were placed with a large number of retail investors and concentration of our shares may be low. Consequently, it may be difficult for you to purchase large quantities of shares from a single shareholder. We cannot assure you that a liquid trading market for our ADSs will develop or, if developed, will be maintained following this offering, which could substantially limit the ability of investors in our ADSs to sell them at the price and time you desire.

 

 

22

 


We are not required to disclose as much information to investors as a U.S. issuer is required to disclose.

We are subject to the reporting requirements of the Superintendency of Finance and the BVC. The corporate disclosure requirements that apply to us may not be equivalent to the disclosure requirements that apply to a U.S. issuer and, as a result, you may receive less interim information about us than you would receive from a U.S. issuer.

ITEM 4

Information on the Company

ITEM 4A

History and Development of the Company

Ecopetrol is a mixed economy company, organized on August 25, 1951, and existing under the laws of Colombia. We have an unlimited duration. Our address is Carrera 7 No. 37-69 Bogota, Colombia and our telephone number is +571 234 4000.

We were incorporated as the Empresa Colombiana de Petróleos S.A. as a result of the reversion of the De Mares concession to the Government by the Tropical Oil Company in 1921. We began our operations as a governmental industrial and commercial company, responsible for administering Colombia’s hydrocarbon resources.

We began operating the crude oil fields at Cira-Infantas and the pipeline that connected that field with the Barrancabermeja refinery and the port of Cartagena. Three years later, the first national seismic study was performed under the De Mares concession which led to the discovery of the Llanito crude oil field in 1960.

In 1961, we assumed the direct operation of the Barrancabermeja refinery and continued its transformation into an industrial complex. International Petroleum Colombia Limited or Intercol began the construction of a new facility in Mamonal, Cartagena, where the pipeline terminal of the Andean National Corporation was already located and which also included a loading port. In December 1957, the Cartagena refinery began operations, and in 1974 it was acquired by us.

In 1970, we adopted our first by-laws that transformed us into a governmental industrial and commercial company, linked to the Ministry of Mines and Energy. Decree Law 1760 of June 26, 2003 transformed us from an industrial and commercial company into a state-owned corporation by shares linked to the Ministry of Mines and Energy and renamed us Ecopetrol S.A. in order to make us more competitive. Prior to our reorganization our capital expenditures program and access to the credit markets were limited by the Government which was making its decisions based on its budgetary needs and not on our growth prospects.

In 2006, the Congress of Colombia authorized us to issue up to 20% of our capital stock in Colombia, subject to the condition that the Nation control at least 80% of our capital stock. On November 13, 2007, we placed 4,087,723,771 shares in the BVC, which resulted in approximately 483,000 new shareholders and raised approximately Ps$5,723 billion for the sale of 10.1% of our capital stock.

Currently, we are the largest company in Colombia as measured by revenue, profit, assets and shareholders’ equity. We are Colombia’s only vertically-integrated crude oil and natural gas company with operations in Colombia and overseas. Our operation excludes natural gas transportation activities.

ITEM 4B

Business Overview

Strategy

Our 2008 – 2015 Strategic Plan focuses on transforming us into a global company with emphasis on crude oil and natural gas and the development of alternative fuels. We are committed to developing into a key player with high competitive standards, strong human resources and clear social responsibility policies. We intend to become one of Latin America’s leading oil and natural gas companies.

Our strategic plan provides detailed initiatives for each one of our business segments. Our main objective is to increase our reserves to 1,280 million barrels of oil equivalent or boe by 2015 and achieve a daily output of

 

 

23

 


approximately 1 million boe by such date. We are also planning on expanding our refining and conversion capacity and increasing our petrochemical production, while complying with local and international environmental standards.

We expect to fund our strategic initiatives through cash on hand and cash flow from operating activities. We also expect to access the local and international capital markets to fund part of our expansion. We currently have no long-term debt and almost no short-term debt and therefore we believe that we will be able to access local and international markets when the need arises. We are also authorized by law 1118 of 2006 to sell an additional 9.9% of our equity, which could be used to fund our Strategic Plan.

We expect to achieve our strategy together with our joint venture partners with whom we have built long-term relationships even if none of them is obliged to provide specific funding commitments under our current joint venture agreements. We are also working with foreign governmental authorities in countries where we already have operation or where we intend to develop operations.

Exploration and Production

We intend to continue to expand our exploration and production activities and enter into joint ventures to further develop our business. We intend to become one of Latin America’s leading crude oil and natural gas companies. In line with our development strategy we intend to increase our average daily production of hydrocarbons to one million boe per day by the year 2015. We estimate our total investment in future exploration activities at US$11 billion and in future production activities at US$27 billion for a total of US$38 billion.

Increase our average daily production of hydrocarbons

Our 2008-2015 Strategic Plan contemplates estimated capital expenditures of approximately US$38 billion in exploratory and development activities inc Colombia and abroad. Our goal is to increase our daily output of hydrocarbons to approximately one million boe per day by 2015. We currently estimate spending approximately US$11 billion in exploratory activities in Colombia and abroad during the next seven years and anticipate drilling directly and together with other oil companies approximately 300 gross wells during the next seven years. We estimate that we will need to incorporate approximately 435 million boe per year of new crude oil and natural gas reserves from a combination of exploratory drilling, acquisition of reserves in place and incorporation of new reserves from existing fields to achieve our one million boe per day production target.

We plan to invest approximately US$16 billion in production projects, including development of mature fields, increasing production of heavy crude oil and development of natural gas fields. In addition, we intend to invest approximately US$11 billion to execute our growth strategy by selectively entering into joint ventures with major international and regional crude oil companies to bid for new exploration and production blocks on-shore and off-shore within and outside Colombia.

Refining

Expand our refining capacity in the Cartagena and Barrancabermeja refineries

We intend to expand our refining capacity in the Cartagena and Barrancabermeja refineries in order to reach a 95% conversion rate which we define as the percentage of crude oil converted into refined products such as gasoline, diesel and middle distillates. Our goal is to process approximately 650 thousand bpd by 2015. The implementation of this initiative will allow us to increase production of refined products, increase the efficiency and upgrade existing facilities, especially in the Cartagena refinery, towards higher-margin refined products. Our strategic plan contemplates the investment of approximately US$11 billion in the upgrade and expansion of our refineries and the Cartagena refinery, and in the acquisition of refineries in markets where we have crude oil production. We expect to invest approximately US$4 billion to increase our production of petrochemicals and reach 2.7 million tons per year by 2015, including 700,000 tons per year of polypropylene produced by Polipropileno del Caribe S.A. or Propilco,

 

 

24

 


Transportation

Development of our transportation infrastructure

We plan to implement a transportation infrastructure program focused on the construction of crude oil pipelines and multipurpose transportation systems to assure our transportation capacity. We intend to invest approximately US$1.2 billion in the construction and upgrading of our transportation infrastructure to meet our future requirements and in the conversion of existing crude oil pipelines for the transportation of heavy crude oil.

Marketing

Selectively expand our activities into the retail segment

Our marketing strategy is focused on supplying the local market and exporting crude oil and refined products to end-users, including refineries and wholesalers in order to improve our margins. We are focused on increase our market participation in crude oil and refined products in the Far East . We are currently opening new markets for our products, such as China. We continue to selectively evaluate entering into retail markets in Colombia and abroad by seeking strategic partners or acquiring existing operations. Our 2008-2015 Strategic Plan contemplates investments of approximately US$3 billion in the retail sector.

Our principal export markets for the first six months of 2008 were: the US market, which accounted for 59%; Far East 12%; Aruba 8% and the Dominican Republic 7%. We sold 69% of our exports to end-users. Currently we maintain short-term crude oil supply contracts with Valero, ConocoPhillips and Tesoro Refining, as well as supply contracts for refined products with Refineria Dominicana de Petróleo S.A., Glencore and Berkshire, and a natural gas supply agreement with PDVSA.

Based on our natural gas production growth projections we expect to increase our sales by focusing on deliveries of compressed natural gas for motor vehicles and industrial users, which have high demand.

Others

Expand our operations in the renewable energy market

We intend to participate in the renewable energy market in Colombia with local investors with whom we have undertaken the development of a refinery to process palm oil for bio-fuels. Our plan calls for investment of US$570 million in these initiatives. See Item 4B— “Business Overview— Environmental Matters.”

Capital Expenditures

Our consolidated capital expenditures during 2007 amounted to Ps$3,036,962 million compared to Ps$1,862,934 million in 2006 and Ps$1,254,144 million in 2005. The most significant increase in our capital expenditures has been in our exploration and production segment which increased 105% in 2007 to Ps$2,678,684 million from Ps$1,309,361 million in 2006, and 93% in 2006 when compared to Ps$678,940 in 2005. We plan to meet our budgeted capital expenditures primarily through existing cash on hand and cash from operating activities. We may be required to access the local and international capital markets in the future to fund our capital expenditure program.

At May 31, 2008, our subsidiary in Peru had made capital expenditures of approximately US$21 million; our subsidiary in Brazil had made capital expenditures of approximately US$6 million and our subsidiary in the Gulf of Mexico had made capital expenditures of approximately US$44 million. These capital expenditures were funded by our own resources. All expenditures include project evaluation, payments to advisors, operation expenditures and costs associated to assignment of exploration blocks.

Business Overview

We are a vertically integrated oil company operating in Colombia and overseas. We are majority owned by the Nation and our shares trade on the BVC under the symbol ECOPETROL. We divide our operations into four

 

 

25

 


business segments that include exploration and production; transportation; refining; and marketing of crude oil, natural gas and refined-products. As part of our strategic plan, on December 24, 2007, we entered into an agreement for the purchase of Propilco which we completed during the second quarter of 2008. Propilco is the main polypropylene supplier in Colombia and the first resins producer in the Andean region, Central America and the Caribbean. We are the largest corporation in Colombia, as measured by assets, sales, net income and net worth, and we play a key role in the local energy supply market. Exports of crude oil and refined-products accounted for approximately 25% of Colombia’s total exports in 2007, of which our exports accounted for 44%.

Overview by Business Segment

Exploration and Production

Summary

Our exploration and production business segment includes exploration, development and production activities in Colombia and abroad. We began local exploration in 1955 and international exploration in 2006. We conduct exploration and production activities in Colombia directly and through joint ventures with third parties. We are the largest producer of crude oil and natural gas, the largest operator, and at December 31, 2007, we had the most acreage under exploration in Colombia.

 

 

26

 


Colombia has 18 sedimentary basins, and at December 31, 2007, we had exploratory activities in eight of them. The following map shows the eight basins where we conduct exploratory activities.


We have organized our production activities into five administrative regions. The administrative regions are:

Northeastern Region – The Northeastern region is comprised of two areas, one located in the north of Colombia along the Atlantic coast and the other located in the Piedemonte Llanero. The Northeastern region covers approximately 200,350 acres, and includes the natural gas fields located at La Guajira and the crude oil and natural gas fields located in Cusiana-Cupiagua. The Northeastern region has a total production of approximately 47.5 thousand bpd of crude oil and 375 million cubic feet per day or mcfpd of natural gas. At December 31, 2007, we had 468 million boe of net proved reserves of crude oil and natural gas.

Mid-Magdalena Valley Region – The Mid-Magdalena Valley region runs along the Magdalena river valley and covers approximately 1,282,339 acres. The Mid-Magdalena Valley region includes the crude oil fields located in Santander and Cesar departments near the Barrancabermeja refinery. The Mid-Magdalena Valley region has a total production of approximately 52.1 thousand bpd of heavy and light crude oil and 30 mcfpd of natural gas. At December 31, 2007, we had 229 million boe of net proved reserves of crude oil and natural gas.

Central Region – The Central region is located in Colombia’s central region and includes the Meta and Casanare departments. The Central region covers approximately 521,697 acres and has a total production of

27

 


approximately 98.1 thousand bpd of heavy and medium crude oil and 2 mcfpd of natural gas. At December 31, 2007, we had 218 million boe of net proved reserves of crude oil and natural gas.

Catatumbo-Orinoquía Region – The Catatumbo-Orinoquía region is located in the eastern part of Colombia and runs along the border with Venezuela covering approximately 669,616 acres. The Catatumbo-Orinoquía region includes the Caño Limón crude oil field and the Gibraltar natural gas field with a total production of approximately 70.9 thousand bpd of crude oil and 1 mcfpd. At December 31, 2007, we had 110 million boe of net proved reserves of crude oil and natural gas.

Southern Region – The Southern region is located on the southwestern region of Colombia and covers approximately 1,502,376 acres. The Southern region includes the Orito, Guando and Neiva fields located in the Cundinamarca and Putumayo departments. The Southern region has a total production of approximately 58.1 thousand bpd of crude oil and 4 mcfpd of natural gas. At December 31, 2007, we had 185 million boe of net proved reserves of crude oil and natural gas.

The map below indicates the location of our operations in Colombia.


 

 

28

 


Strategy

Our main strategies in exploration and production in Colombia and abroad are to increase our crude oil and natural gas reserves and reach a production of one million boe per day in 2015, by:

 

Investing in high potential hydrocarbon areas in Colombia and abroad;

 

Selectively acquiring reserves;

 

Implementing new strategies and deploying state-of-the art technologies to increase reserve recovery of new and mature fields;

 

Investing in the development of natural gas and heavy crude oil; and

 

Entering into new joint ventures with regional and international oil companies in Colombia and abroad.

Exploration

Our exploration plan in Colombia is focused in three areas, exploration near existing production sites; exploration in already producing basins; and exploration in frontier areas including off-shore areas with potential for large findings. Our exploration strategy outside Colombia is focused on larger prospects.

In 2007, surface exploration in Colombia by acquisition of seismic data covered approximately 9,971 of equivalent kilometers of which we participated in 3,081 equivalent kilometers corresponding to 1,010 kilometers of 2D seismic data and 1,218.4 square kilometers of 3D seismic data. Of this amount 1,670 equivalent kilometers were directly prospected by us and together with our business partners and 1,411 were prospected by third parties under sole risk contracts. (1 square kilometer (3D seismic data) corresponds to 1.7 kilometers (2D seismic data) of equivalent kilometers).

Exploration Activities in Colombia

We conduct exploration in Colombia on our own and through joint ventures with regional and international oil and gas companies. We also benefit from sole risk contracts when commercial reserves are found, for which we do not take any exploration risk.

 

 

29

 


The following table sets forth the number of gross and net exploratory wells drilled by us and our joint venture partners, and the exploratory wells drilled by third parties under a sole risk contract for the years ended December 31, 2007, 2006 and 2005.

 

 

 

For the year ended December 31, 

 

 

 


 

 

 

2007

 

2006

 

2005

 

 

 


 


 


 

Gross Exploratory Wells:

 

 

 

 

 

 

 

Owned and operated by Ecopetrol

 

 

 

 

 

 

 

Productive(1)

 

1

 

1

 

1

 

Dry(2)

 

3

 

2

 

5

 

 

 


 


 


 

Total

 

4

 

3

 

6

 

 

 


 


 


 

Operated by Ecopetrol in Joint Venture

 

 

 

 

 

 

 

Productive

 

1

 

 

1

 

Dry

 

2

 

1

 

1

 

 

 


 


 


 

Total

 

3

 

1

 

2

 

 

 


 


 


 

Operated by Partner in Joint Venture

 

 

 

 

 

 

 

Productive

 

 

 

1

 

Dry

 

5

 

 

 

 

 


 


 


 

Total

 

5

 

 

1

 

 

 


 


 


 

Net Exploratory Wells:

 

 

 

 

 

 

 

Productive

 

1.4

 

1

 

1.9

 

Dry

 

5.6

 

2.5

 

5.7

 

 

 


 


 


 

Total

 

7

 

3.5

 

7.6

 

 

 


 


 


 

Sole Risk(3):

 

 

 

 

 

 

 

Productive

 

8

 

14

 

9

 

Dry

 

13

 

16

 

14

 

 

 


 


 


 

Total

 

21

 

30

 

23

 

 

 


 


 


 

______________________

(1)

A productive well is an exploratory well that is not a dry well.

(2) 

A dry well or hole is an exploratory well found to be incapable of producing either crude oil or natural gas in sufficient quantities to justify completion as a crude oil or natural gas well.

(3)

We do not take any risk in sole risk contracts but we benefit from successful exploratory efforts . See Item 4 — “Overview of Exploration and Production Contractual Arrangements.”

The following table sets forth our current net and gross exploratory wells drilled at March 31, 2008.

 

 

 

For the three-month period ended March 31, 2008 

 

 

 


 

 

 

Gross

 

Net

 

 

 


 


 

Number of net and gross wells drilled:

 

 

 

 

 

Joint ventures(1)

 

2

 

0.75

 

Sole Risk

 

6

 

 

Directly Ecopetrol

 

1

 

1

 

 

 


 


 

Total

 

9

 

1.75

 

 

 


 


 

______________________

(1)

Includes one exploratory well in Colombia and one in the U.S. Gulf.

 

 

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International Exploration Activities

Our international exploration strategy is focused on securing blocks available for exploration and entering into joint ventures with international and regional oil companies. Exploring outside Colombia will allow us to diversify our risk and improve the possibilities for increasing our crude oil and natural gas reserves. In December 2006, the incorporation of Ecopetrol Oleo e Gas do Brasil Ltda., our first foreign affiliate, represented a milestone in our international expansion. With the incorporation of our first foreign affiliate, we initiated our international exploration and the consolidation as an international oil and gas company. In 2007, two new operating subsidiaries were incorporated, Ecopetrol del Peru and Ecopetrol America Inc.

During 2007, we signed 16 agreements to participate in exploratory blocks in Peru, Brazil and one in the Gulf of Mexico. Our partners include, among others, Talisman, Repsol-YPF, Petrobras, Petroperu, Petrogal, CVRD, Shell and New Field.

Production

Our average daily production of hydrocarbons in 2007, totaled 399 thousand boe, of which 327 thousand bpd corresponded to crude oil and 72.4 thousand boe corresponded to natural gas. Of our 327 thousand bpd, 151 thousand bpd came from fields we directly operate and 175.6 thousand bpd came from our participation in joint ventures, shared risk agreements and other contractual arrangements with our business partners. During 2006, our average daily production of hydrocarbons totaled 385 thousand boe, of which 316 thousand bpd corresponded to crude oil and 69 thousand boe corresponded to natural gas. Our average daily production of hydrocarbons in 2005 was 375 thousand bpd, of which 312 thousand bpd corresponded to crude oil and 63 thousand boe to natural gas. Our production during 2007 consisted of approximately 75% light and medium crudes (with a gravity between 16° and 35° American Petroleum Institute or API) and 25% of heavy crudes, with a gravity lower than 15° API.

Our crude oil and natural gas production includes 107 fields directly operated by us and 168 fields in joint venture with 35 oil companies. At December 31, 2007, we were the largest participant in the Colombian hydrocarbons industry with approximately 62% of crude oil production and approximately 56% of natural gas production.

We produce crude oil and natural gas in the five administrative regions. The Northeastern region has significant production of natural gas and light crude oil while the Central region and the southern part of the Mid-Magdalena Valley region have the most significant production and prospects of heavy crude oil, and currently produce light and medium crude oil. The Catatumbo-Orinoquía region has significant production of medium crude oil and the Southern region has production of medium and light crude oil.

We undertook development drilling in the five producing regions and applied new technologies, allowing us to drill 120 net development wells in 2007, 55 more than in 2006 and 67 more than in 2005. Of the total gross development wells drilled in 2007, five were dry wells, of which two were located in the Catatumbo-Orinoquia region and three were located in the Southern region. There were no dry development wells during 2006 and 2005.

 

 

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The following table sets forth the number of gross and net development wells drilled exclusively by us and in joint ventures for the years ended December 31, 2007, 2006 and 2005.

 

 

 

For the year ended December 31, 

 

 

 


 

 

 

2007

 

2006

 

2005

 

 

 


 


 


 

Northeastern region:

 

 

 

 

 

 

 

Gross wells owned and operated by Ecopetrol

 

 

 

 

Gross wells in Joint Ventures

 

2

 

6

 

5

 

Net Wells(1)

 

1

 

3

 

3

 

Mid- Magdalena Valley region:

 

 

 

 

 

 

 

Gross wells owned and operated by Ecopetrol

 

77

 

45

 

28

 

Gross wells in Joint Ventures

 

153

 

34

 

64

 

Net Wells

 

146

 

62

 

58

 

Central region:

 

 

 

 

 

 

 

Gross wells owned and operated by Ecopetrol

 

29

 

15

 

21

 

Gross wells in Joint Ventures

 

17

 

3

 

7

 

Net Wells

 

38

 

17

 

25

 

Catatumbo-Orinoquía region:

 

 

 

 

 

 

 

Gross wells owned and operated by Ecopetrol

 

8

 

 

 

Gross wells in Joint Ventures

 

53

 

52

 

26

 

Net Wells

 

36

 

25

 

14

 

Southern region:

 

 

 

 

 

 

 

Gross wells owned and operated by Ecopetrol

 

6

 

5

 

4

 

Gross wells in Joint Ventures

 

58

 

50

 

50

 

Net Wells

 

33

 

30

 

29

 

Total Gross wells owned and operated by Ecopetrol

 

120

 

65

 

53

 

 

 







Total Gross wells in Joint Ventures

 

283

 

145

 

152

 

 

 







Total Net Wells

 

254

 

137

 

129

 

 

 







___________________

(1)

Net wells correspond to the sum of wells entirely owned by us and our percentage ownership of wells owned in joint venture with our partners.

Production Activities in Colombia

As a result of our investments in production activities, our average daily production of crude oil reached 327 thousand bpd in 2007, a 3.3% increase compared to 2006 and a 4.6 % increase when compared to 2005. The increase in average daily production is due to a 1% increase in production from fields developed with our business partners, which totaled 175 thousand bpd in 2007 from 174 thousand bpd in 2006, and a 6% increase from fields operated by us, which totaled a 151 thousand bpd in 2007 compared to 142 thousand bpd in 2006.

 

 

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The following table sets forth our net average daily crude oil production, average sales price and average production costs (lifting costs) for the years ended December 31, 2007, 2006 and 2005.

 

 

 

For the Year ended December 31  

 

 

 


 

 

 

2007

 

2006

 

2005

 

 

 






 

 

 

(thousand bpd)  

 

Northeastern region:

 

 

 

 

 

 

 

Joint venture operation

 

47.5

 

58.3

 

67.4

 

Direct operation

 

 

 

 

 

 


 


 


 

Total Northeastern region

 

47.5

 

58.3

 

67.4

 

Mid-Magdalena Valley region:

 

 

 

 

 

 

 

Joint venture operation

 

12.7

 

12.4

 

12.1

 

Direct operation

 

39.4

 

34.9

 

32.3

 

 

 


 


 


 

Total Mid-Magdalena Valley region

 

52.1

 

47.3

 

44.5

 

Central region:

 

 

 

 

 

 

 

Joint venture operation

 

15.3

 

3.7

 

3.0

 

Direct operation

 

82.8

 

85.7

 

78.0

 

 

 


 


 


 

Total Central region

 

98.1

 

89.4

 

81.0

 

Catatumbo-Orinoquía region:

 

 

 

 

 

 

 

Joint venture operation

 

64.9

 

63.8

 

59.5

 

Direct operation

 

6.0

 

1.9

 

6.6

 

 

 


 


 


 

Total Catatumbo-Orinoquía region

 

70.9

 

65.7

 

66.1

 

Southern region:

 

 

 

 

 

 

 

Joint venture operation

 

35.2

 

35.7

 

32.9

 

Direct operation

 

22.9

 

20

 

20.4

 

 

 


 


 


 

Total Southern region

 

58.1

 

55.6

 

53.3

 

 

 


 


 


 

Total average daily crude oil production

 

326.6

 

316.2

 

312.3

 

 

 


 


 


 

Crude Oil Average Sales Price
(U.S. dollar per barrel)

 

64.76

 

53.39

 

46.14

 

Aggregate Average Lifting Costs of crude oil (U.S. dollars per barrel)

 

7.24

 

5.23

 

3.26

 

Aggregate Average Lifting Costs of crude oil (Ps$ per barrel)

 

15,057

 

12,343

 

7,573

 

The increase in our crude oil lifting costs for 2007 was mainly due to an increase in crude oil production activities and a 28% average increase in oil services costs, in part offset by the increase in volumes produced.

The table below sets forth the volumes of crude oil purchased from our business partners and volumes of crude oil purchased from the ANH corresponding to royalties which have been received by the ANH in-kind from producers for the years ended December 31, 2007, 2006 and 2005.

 

 

 

For the year ended December 31, 

 

 

 


 

 

 

2007

 

2006

 

2005

 

 

 


 

 

 

 

(million barrels) 

 

 

 

 

 

Crude oil purchased from the ANH

 

31.1

 

33.5

 

34.3

 

Crude oil purchased from our Business partners

 

12.9

 

10.3 

 

10.1 

 

 

 







Total

 

44.0

 

43.8

 

44.4

 

 

 







 

 

33

 


The following table sets forth our developed and undeveloped gross and net acreage of crude oil production by region for the year ended December 31, 2007.

 

 

 

Production Acreage at
December 31, 2007 

 

Average crude oil production for the year ended December 31, 2007

 

 

 


 


 

 

 

Developed and Undeveloped 

 

(thousand bpd)

 

 

 


 

 

 

 

 

Gross

 

Net

 

 

 

 

 


 


 

 

 

 

 

(in acres) 

 

 

 

Northeastern region

 

200,350

 

120,210

 

47.5

 

Mid-Magdalena Valley region

 

1,282,339

 

635,944

 

52.1

 

Central region

 

521,697

 

330,799

 

98.1

 

Catatumbo-Orinoquía region

 

669,616

 

399,920

 

70.9

 

Southern region

 

1,502,376

 

847,454

 

58.1

 

 

 


 


 


 

Total

 

4,176,378

 

2,334,327

 

327

 

 

 


 


 


 

The following table sets forth our total gross and net productive wells by region for the year ended December 31, 2007.

 

 

 

At December 31, 2007

 

 

 


 

 

 

Crude Oil 

 

Natural Gas 

 

Natural Gas and Crude Oil 

 

 

 


 


 


 

 

 

Gross

 

Net

 

Gross

 

Net

 

Gross

 

Net

 

 

 


 


 


 


 


 


 

Northeastern region

 

 

 

28

 

16

 

62

 

31

 

Mid-Magdalena Valley region

 

81

 

65

 

3

 

2

 

1,883

 

1,451

 

Central region

 

142

 

110

 

 

 

99

 

91

 

Catatumbo-Orinoquía region

 

393

 

242

 

 

 

197

 

140

 

Southern region

 

12

 

10

 

7

 

3

 

876

 

612

 

 

 













Total

 

628

 

427

 

38

 

21

 

3,117

 

2,325

 

 

 













Crude Oil

Light crude oil

Light crude oil has an API gravity 25° or higher and tends to have a higher sales price in the international market. We develop and produce light crude oil in the Cravo Norte joint venture with Occidental Petroleum and in the Cusiana and Cupiagua fields. During 2007, our production of light crude oil was 97.9 thousand bpd, a 8.1 % decrease compared to 106.5 thousand bpd produced in 2006. During 2006, our production of crude oil was 106.5 thousand bpd compared to 113.7 thousand bpd in 2005. The decrease in production is due to the decline of the fields as they are becoming mature and the recovery level continues to be lower.

Our most productive fields are located in the Catatumbo-Orinoquía and Northeastern regions. These fields are:

(i) Caño Limón. The Caño Limón field is located in the department of Arauca. The production of the Cravo Norte project during 2007 reached 50.4 thousand bpd, compared to 48.3 thousand bpd in 2006 and 46.3 thousand bpd in 2005. We estimate that the Cravo Norte project has approximately 74.7 million barrels of crude oil in proved reserves.

(ii) Cusiana and Cupiagua. The Cusiana and Cupiagua blocks are located in the Piedemonte Llanero and are developed in partnership with British Petroleum and Total. The project is composed by the Cusiana, Cupiagua, Pauto, Floreña and Volcanera fields. The production of these fields during 2007 was 47.5 thousand bpd, compared to 58.2 thousand bpd in 2006 and 67.4 thousand bpd in 2005. We estimate that the Cusiana and Cupiagua project has approximately 181.6 million barrels of crude oil in proved reserves and 824 mcf of natural gas reserves. The first joint venture agreement under which we produce crude oil and natural gas in this project will expire in 2010 and the production rights r evert to us at no additional cost. See Item 4 — “Overview of Exploration and Production Contractual Arrangements.”

Heavy crude oil

We consider heavy crudes those having an API gravity below 15°. We develop, upgrade and produce heavy crude in the Central and Mid-Magdalena Valley regions. We invested approximately US$850.0 million between 2000 and 2007 to expand our production of heavy crude oil, which increased from 24 thousand bpd in 2000 to 81 thousand bpd in 2007. Our production of heavy crudes in 2007 reached 81 thousand bpd, an 18% increased when compared to 2006 as a result of the Rubiales Field being developed. In 2006 our production of heavy crudes amounted to 68.5 thousand bpd compared to 60 thousand bpd in 2005 mainly as a result of the Castilla field being

 

 

34

 


developed. We are committed to developing our heavy crude reserves as they are an integral part of our growth strategy.

Our most important heavy crude oil projects are:

(i) Cubarral. The Cubarral block is located in the Central region and is composed of the Castilla and Apiay fields with approximately 203.8 million barrels of developed and undeveloped proved reserves. We decided to undertake the development of the project and selected a strategic partner for exploration in the Caño Sur Block.

(ii) Rubiales. The Rubiales field is located in the Central region and is developed in joint venture with Metapetroleum. Investments in this field during 2007 amounted to US$38.4 million as we and our business partner drilled 14 development wells and enlarged our fluid treatment facilities. The Rubiales field increased its production from 11.7 thousand bpd in 2006 to 18.7 thousand bpd in 2007. We expect production during 2008 to reach 31.2 thousand bpd.

(iii) Nare-Teca. Nare-Teca field is located in the Mid-Magdalena Valley region developed in joint venture with Mansarovar, a joint venture between Sinopec from China and Oil and Natural Gas Corporation Ltd. from India. During 2007, we invested approximately US$95 million in drilling 125 development wells and fluid treatment facilities. We expect to produce 21 thousand bpd in 2008 and to reach a maximum output of 30 thousand bpd by 2010.

Mature fields

Development of mature fields is an integral part of our strategy to increase average daily production and hydrocarbon reserves. Mature fields are those fields that have reached their maximum output and have entered their final decline in production. Approximately 72.7% of our fields are considered mature. However, these reservoirs, discovered over 20 years ago, still have significant reserves which can be recovered through aggressive drilling campaigns and by applying new technologies. We continue to focus our efforts on improving the productivity ratio of several directly operated mature fields and other fields currently held in joint venture with other oil companies, which will become mature in the near future.

During the last five years, we developed mature fields in all five regions. As a result of these activities, we were able to reduce the rate of decline in production from mature crude oil fields which totaled 227 thousand bpd in 2007 compared to 228 thousand bpd in 2006 and 242 thousand bpd in 2005.

The table below describes the location, number and daily production of our mature fields for the periods indicated below.

 

 

 

At December 31,
2007

 

For the year ended December 31,

 

 


 


 

 

Number of fields

 

2007

 

2006

 

2005

 

 


 


 


 


 

 

 

 

(thousand bpd)

Northeastern region:

 

 

 

 

 

 

 

 

Joint Venture

 

5

 

47.5

 

58.2

 

67.4

Direct Operation

 

 

 

 

 

 


 


 


 


Total Northeastern region

 

5

 

47.5

 

58.2

 

67.4

Mid-Magdalena Valley region:

 

 

 

 

 

 

 

 

Joint Venture

 

15

 

5.2

 

5.4

 

5.4

Direct Operation

 

32

 

39.0

 

34.9

 

32.3

 

 


 


 


 


Total Mid-Magdalena Valley region

 

47

 

44.2

 

40.3

 

37.7

Central region:

 

 

 

 

 

 

 

 

Joint Venture

 

5

 

1.5

 

1.8

 

1.7

Direct Operation

 

19

 

23.5

 

26.0

 

30.1

 

 


 


 


 


Total Central region

 

24

 

25

 

27.8

 

31.8

Catatumbo-Orinoquía region:

 

 

 

 

 

 

 

 

Joint Venture

 

56

 

64.1

 

57.5

 

59.5

Direct Operation

 

6

 

5.7

 

5.7

 

6.6

 

 


 


 


 


Total Catatumbo-Orinoquía region:

 

62

 

69.7

 

63.2

 

66.1

Southern region:

 

 

 

 

 

 

 

 

Joint Venture

 

37

 

17.6

 

18.0

 

18.2

Direct Operation

 

32

 

22.9

 

20.0

 

20.5

 

 


 


 


 


Total Southern region

 

69

 

40.5

 

38.0

 

38.7

Total

 

207

 

227

 

228

 

242

 

 


 


 


 


 

 

35

 


Purchase Commitments with our business partners

We have entered into a number of crude oil purchase contracts with certain of our business partners. Deliveries of crude oil are made on a continuous basis. At April 30, 2008 we had 50 of these contracts outstanding, of which 22 or 44% expire in 2008, 25 or 50% expire in 2010 and the remaining 3 or 6% thereafter.

Under the existing contracts we are obligated to purchase 100% of our partner’s production in the specific field. As of April 30, 2008 our accumulated purchases of crude oil under these commitments for 2008 amounted to 45.1 thousand bpd of crude oil.

The term of some of our purchase contracts is linked to the term of the joint venture agreements signed with our business partners. Other clauses of the contracts such as price and place of delivery may be subject to renegotiation during the term of the contract. Other purchase contracts not linked to joint venture agreements may be extended and renegotiated by the parties. We expect to renegotiate and extend our most significant purchase contracts not linked to the joint venture agreements.

Crude oil purchased from our business partners is processed in our refineries or is exported. The purchase price is calculated based on international market prices. Our total financial exposure depends on the international prices of oil and volumes produced. We believe that the risk of such exposure is hedged because we either export the crude oil at international market prices or sell refined products at prices which are correlated with international market prices. During 2007, the total volumes of crude oil we purchased from our business partners amounted to 23% of our total crude oil sales.

Natural Gas

Our production of natural gas is driven by the growth of local demand and exports to Venezuela. In 2007 we produced 411 mcfpd, a 4.6% increase when compared to 2006 and a 15.6% increase when compared to 2005.

 

 

36

 


The following table sets forth our average daily natural gas production, our average sales price and average production costs (lifting costs) for the years ended December 31, 2007, 2006 and 2005.

 

 

 

For the year ended December 31, 2007

 

 


 

 

2007

 

2006

 

2005

 

 


 


 


 

 

 

 

(mcfpd)

 

 

Northeastern region:

 

 

 

 

 

 

Joint Venture

 

375.4

 

348.0

 

324.1

Direct Operation

 

 

 

 

 


 


 


Total Northeastern region

 

375.4

 

348.0

 

324.1

Mid-Magdalena Valley region:

 

 

 

 

 

 

Joint Venture

 

8.1

 

10.2

 

6.2

Direct Operation

 

21.5

 

21.8

 

18.7

 

 


 


 


Total Mid-Magdalena Valley region

 

29.6

 

32.0

 

24.9

Central region:

 

 

 

 

 

 

Joint Venture

 

 

 

Direct Operation

 

1.6

 

7.7

 

 

 


 


 


Total Central region

 

1.6

 

7.7

 

Catatumbo-Orinoquía region:

 

 

 

 

 

 

Joint Venture

 

1.1

 

1.8

 

1.3

Direct Operation

 

 

 

 

 


 


 


Total Catatumbo-Orinoquía region

 

1.1

 

1.8

 

1.3

Southern region:

 

 

 

 

 

 

Joint Venture

 

3.3

 

4.2

 

5.8

Direct Operation

 

1.0

 

0.2

 

0.2

 

 


 


 


Total Southern region

 

4.2

 

4.5

 

6.0

Total natural gas production (thousand cfpd)

 

411,974

 

393,996

 

356,316

 

 


 


 


Natural gas average sales price (U.S. dollar per mbtu)(1)

 

1.98

 

2.04

 

1.59

 

 


 


 


Aggregate Average Lifting Costs of natural gas (U.S. dollars per thousand cf)(2)

 

0.21

 

0.20

 

0.18

Aggregate Average Lifting Costs of natural gas (Ps$ per thousand cf)(3)

 

427.2

 

479.3

 

405.6

______________

(1)

Corresponds to million British thermal units.

(2)

Corresponds to lifting costs from La Guajira fields.

(3)

Corresponds to Colombian Pesos

Natural gas lifting costs increased to US$0.21 per thousand cubic feet or thousand cf in 2007 from US$0.20 per thousand cf in 2006 due to an increase in production costs and the revaluation of the Colombian Peso against the Dollar, offset in part by the increase in the volumes produced from La Guajira fields. Our natural gas lifting costs decreased to Ps$427.2 per thousand cf in 2007 from Ps$479.3 per thousand cf in 2006 as a result of the increase in the volumes from La Guajira fields.

The following table sets forth our developed and undeveloped gross and net acreage of natural gas production by region:

 

 

 

Developed and Undeveloped
Production Acreage as of
December 31, 2007

 

Average natural gas production for
the year ended
December 31, 2007

 

 


 


 

 

(in acres)

 

(thousand cfpd)

 

 

Gross

 

Net

 

 

 

 


 


 

 

Northeastern region

 

238,801

 

142,127

 

375,446

Mid-Magdalena Valley region

 

769,582

 

455,228

 

29,660

Central region

 

201,415

 

129,384

 

1,607

Catatumbo-Orinoquía region

 

10,166

 

 

1,097

Southern region

 

241,933

 

121,802

 

4,164

 

 


 


 


Total

 

1,461,897

 

848,539

 

411,974

 

 


 


 


 

 

37

 


Northeastern region

The largest production of natural gas in Colombia is located in the Northeastern region which we develop under two joint venture contracts. We develop the Guajira natural gas reserves with our partner Chevron and the Cusiana and Cupiagua reserves in partnership with British Petroleum and Total. Natural gas production in the Northeastern region averaged 375.4 mcfpd in 2007. The natural gas produced from these fields is used to supply our local demand and the surplus is exported to Venezuela. Currently, we are re-injecting a significant percentage of the natural gas in the Cusiana and Cupiagua fields to increase recovery ratio.

As a result of the age and the decline rate of the Cusiana, Cupiagua and Floreña crude oil fields, we commenced production of natural gas for sale. As a result, natural gas treatment capacity in the Cusiana fields increased to 200 mcfpd. During 2007 the production of natural gas for sale from the Cusiana, Cupiagua and Floreña fields totaled to 210.7 mcfpd exceeding our initial estimates. We plan to build two new plants including a natural gas treatment plant to increase treatment capacity and production of natural gas for sale to 410 mcfpd by 2011.

Catatumbo-Orinoquía region

Natural gas production in the Catatumbo-Orinoquía region is located in the Gibraltar block in the department of Arauca. We are currently building the production infrastructure and are evaluating the transportation alternatives. We expect the Gibraltar block to produce approximately 30 mcfpd in 2009.

Reserves

Our net proved reserves of crude oil and natural gas at December 31, 2007, totaled 1,210 million boe which represents a 3.4% decrease from 1,253 million boe registered in 2006. In 2006, our proved reserves decreased 0.2% from 1,254 million boe registered in 2005. The reduction in our reserves is due to a 64% ratio at which we replaced reserves from 121 million boe produced in 2007 compared to 78.0 million boe of new reserves incorporated during the same year. Our crude oil reserves in 2007 decreased to 857 million barrels of crude oil from 921 million barrels of crude oil in 2006 offset by our natural gas proved reserves which increased to 1,980 million cubic feet or mcf from 1,860 mcf of reserves in 2006.

Hydrocarbon reserves were calculated based on the valuation method established by the SEC. Our reserves were audited in 2006 by Ryder Scott, DeGolyer and MacNaughton, and Gaffney, Cline & Associates (collectively, the “External Engineers”). We updated the reserve estimates at December 31, 2007 using the same valuation method. In July 2008, the External Engineers audited 85% of our reserves at December 31, 2007 but the reserve estimates shown in this registration statement are ours. The total negative difference between our estimates and those of the experts with respect to the 85% of reserves that were audited is 5.6%. Although the total difference was not material, there were significant differences, both positive and negative, with respect to particular fields. The most important differences, on a field by field basis arise from the following four areas: (1) Evaluation of the quality and quantity of information available to incorporate reserves as proved with reasonable certainty, reflecting changes for the Tibu (+100.6% or 12.77 million barrels), Casabe (-14.8% or 6.01 million barrels) and Gibraltar (-59.2% or 18.48 million boe) fields; (2) differences in quantifying depletion rates for purposes of estimating future production, affecting the estimates for the Cusiana (-33.4% or 29.65 million barrels), San Francisco (-70.2% or 20.58 million barrels), Guando (-8.9% or 6.4 million barrels), La Cira (-18.2% or 8.99 million barrels) and Orito (-25.8% or 4.57 million barrels) fields; (3) differences in the method used to estimate the reserves in the Cupiagua fields (+23.9% or 17.3 million barrels) which in 2006 was the gas/oil ratio against accumulated gas and in 2007 was oil rate against time; and (4) as a result of differences in the External Engineers’ interpretations, the economic limits differ with respect to the ones reported by us, therefore reflecting differences between operating expenses and capital expenditures applied by us and by the external Engineers. We do not deem these differences to be significant with respect to the impact on the Company’s estimates as a whole.

The reserve information presented in this section is based on the SEC’s valuation method used for U.S. GAAP purposes. See Item 5– “Operating and Financial Review and Prospects – Principal differences between Colombian Government Entity GAAP and U.S. GAAP” and note 33 to our consolidated financial statements.

 

 

38

 


The following table sets forth our estimated net proved reserves (developed and undeveloped) and net proved developed reserves of crude oil for the years ended December 31, 2007, 2006 and 2005.

   
At December 31,
   
2007
  2006  
2005
    Proved               Proved              
Proved
       
    Developed       Developed       Developed    
    and  
Proved
  and  
Proved
 
and
 
Proved
   
Undeveloped
 
Developed
 
Undeveloped
  Developed  
Undeveloped
 
Developed
            (million barrels)        
Northeastern region   133.2  
  87.5
  127.1  
   96.1
 
172.0
 
148.3
Mid-Magdalena Valley region   214.5  
154.5
  217.4  
140.3
 
189.7
 
163.7
Central region   218.2  
153.1
  282.4  
125.5
 
339.6
 
180.6
Catatumbo– Orinoquía region   109.9  
  97.2
 
  96.9
 
  88.0
 
  94.8
 
  81.7
Southern region   181.5  
159.0
  197.2  
160.8
 
134.9
 
118.0
Total   857.4  
651.3
  921.2  
610.7
 
930.9
 
692.3

The following table sets forth our estimated net proved reserves (developed and undeveloped) and net proved developed reserves of crude oil and natural gas by region for the years ended December 31, 2007, 2006 and 2005.

   
At December 31,
   
2007
  2006  
2005
    Proved               Proved               Proved        
    Developed       Developed       Developed    
    and   Proved   and   Proved   and   Proved
   
Undeveloped
 
Developed
 
Undeveloped
  Developed  
Undeveloped
 
Developed
            (million boe)        
Northeastern region   467.7   286.9   442.3   259.9   484.4   345.3
Mid-Magdalena Valley region   228.8   166.9   232.9   153.0   199.2   172.2
Central region   218.2   153.1   282.4   125.5   340.5   181.5
Catatumbo– Orinoquía region   109.9     97.2     97.0     88.1     94.8     81.7
Southern region   185.3   162.7   197.9   161.4   135.5   118.6
Total   1,209.9      866.9   1,252.5      788.0   1,254.4      899.3

The following table sets forth our estimated net proved developed and undeveloped reserves of crude oil and natural gas at December 31, 2007, 2006 and 2005.

   
Net proved developed and undeveloped
   
Reserves
    Oils   Gas   Total
   
(million barrels)
  (giga cf)   (million boe)
 
Reserves at December 31, 2005   930.9         1,816.6         1,254.4  
         Revisions   77.4     108.8     96.8  
         Extensions and discoveries   8.6     48.7     17.3  
         Production   (95.7 )   (113.6 )   (115.9 )
Reserves at December 31, 2006   921.2     1,860.4     1,252.5  
 
         Revisions   25.9     74.0     39.0  
         Extensions and discoveries   9.8     164.1     39.0  
         Production   (99.6 )   (118.8 )   (120.7 )
Reserves at December 31, 2007                   857.4                     1,979.6                     1,209.9  
                   
Net proved developed reserves
                 
         At December 31, 2005
 
692.3
    1,162.2     899.3  
         At December 31, 2006
 
610.7
    995.4     788.0  
         At December 31, 2007
 
651.3
    1,210.5     866.9  

 

39

 


Current Activities

We began drilling of multilateral wells in 2007, particularly in heavy crude oil fields. We drilled three multilateral wells in the Castilla field, located in the Central region, two of them during the first quarter of 2008. We also drilled two additional wells in the Nare-Teca field located in the Mid-Magdalena Valley region with our partner Mansarovar.

As of March 31, 2008, we undertook maintenance work of our waterfloods systems in the Casabe fields, located in the Mid-Magdalena Valley region, to improve crude oil production of these fields from approximately 7,000 bpd to 9,000 bpd. With our partner Occidental, we also evaluated the waterfloods and water injection systems in the Cira fields, located in the Mid-Magdalena Valley region, to increase the recovery factor.

During the first quarter of 2008 we undertook direct drilling activities in productive fields and drilled 22 wells in the Mid-Magdalena Valley region, eight wells in the Central region and two wells in the Southern region. All wells drilled correspond to productive wells.

Overview of Exploration and Production Contractual Arrangements

Contractual Arrangements for the exploration and production of crude oil and natural gas in Colombia

Introduction

Colombia has modified the contractual regime governing the exploration, development and production of hydrocarbons several times since its introduction in 1970 to address the country’s exploration and production needs. The exploration and production contracts entered into by us and our business partners provide for the production split, the length of the exploration and production terms and royalty payments.

Under Colombian law, an existing contract cannot be modified because of a change to the contractual regime, except in the cases of public order regulations. As a result, contracts that were executed prior to the issuance of a new contractual regime remain in force and are not affected by the new regime put in place subsequently. At December 31, 2007 we were party to 37 agreements executed under the contractual regime existing prior to 1994; to 39 agreements executed under the contractual regime existing between 1994 and 2004; and to 9 agreements executed under the contractual regime existing after 2004.

Under joint venture contracts entered into before March 1994, which include the Cusiana and Cupiagua crude oil fields, the private investor explored a previously agreed upon area at its own risk and expense. Thereafter, we had the option to become a joint venture partner by reimbursing the investor 50% of the exploration costs of oil wells within commercially viable fields and 50% interest of all future development costs related to those fields. Once we became a partner, we had a 50% interest in the production of the crude oil field.

If we decided not to become a joint venture partner within a certain period of time, the private investor had the right to enter into a sole risk contract for the field’s crude oil production until it had recovered 200% of its investment and a 100% of its total costs. Thereafter, we could participate in the development of the field and all future costs and expenses are automatically shared with our partner as if we had elected to become a joint venture partner in the field.

Beginning in 1994, modifications were made to standard joint venture contracts to maintain the private investor’s share of production at 50% until aggregate production exceeded 60 million barrels. Thereafter, our share increased gradually, up to a maximum of 70% of production. In 1995, further modifications to the standard joint

 

 

40

 


venture contracts required us to pay for half of the exploration costs, not only for wells which ultimately proved to be productive, but also for dry wells, stratigraphic wells and seismic exploration in fields that became commercially viable. The modifications also provided for competitive bidding for the right to explore and develop marginal fields (defined according to certain technical, financial and operational criteria). In the bidding process, private companies presented bids based on percentages of production they would pay us in exchange for the rights to develop these fields. Winning bidders were responsible for all future investment and operating costs related to the field.

The standard joint venture contracts were once again modified in 1997 to promote private sector activity in the development of inactive areas and small fields and in the exploration for natural gas. These modifications extended the exploration periods, increased the levels of reimbursement for private companies’ exploration costs and provided for the reimbursement of exploration costs in real terms and denominated in U.S. dollars.

In 1999, the Government adopted two additional modifications to the standard terms of the joint venture contracts, applicable to new joint venture contracts:

 

Reduction of Our Initial Participation. We reduced our initial participation under the joint venture contracts from 50% to 30%. At December 31, 2007, we had 31 joint venture contracts outstanding in which our 50% participation did not change, and 14 joint venture agreements are outstanding where our participation was 30%.

 

Modified R-Factor. We modified the formula used to determine the increase in our share of total production or the R-Factor. The R-Factor is calculated by dividing accumulated revenues in cash by investments and costs. If the R-Factor increases above a certain profitability threshold, then our share of production increases above the initial 30%. Pursuant to the 1999 modifications, we raised the profitability threshold at which the R-Factor triggers an increase in our share from 1.0 to 1.5. Private companies benefited from this modification because our share remained at 30% for a longer period of time. In addition, the R-Factor was calculated in constant dollars. This new calculation method was designed to prevent inflation from independently causing an increase in the R-Factor and a corresponding increase in our share.

We also entered into various types of arrangements in connection with our own crude oil and natural gas exploration and production projects. These arrangements included: risk participation contracts, shared-risk contracts, risk services contracts and discovered undeveloped fields contracts.

 

Risk Participation Contracts. Under these contracts, we assumed 15% of the exploration costs and risks at the beginning of the second year in exchange for a larger participation in the future production and equal representation on the executive committee of the joint venture. At December 31, 2007, we had three risk participation contracts in effect.

 

Incremental Production Agreements. We currently have two types of incremental production agreements, the standard incremental production agreements or SIPA, and the development of incremental production project agreements or DIPA. Under the SIPA, we calculate the total number of proved developed reserves available in a specific field or well and then establish a base production curve for the reserves. Any future production exceeding the curve, which we refer as incremental production, results from extracting proved undeveloped reserves or probable reserves which require additional investments funded by our partners under the SIPA. We have the right to a previously specified percentage of the incremental production. Our percentage participation varies depending on the total amount invested by our partners and on the R-Factor which cannot be lower 1.5. The volume produced under the production curve is not shared with our partners. At December 31, 2007, we had five SIPAs in effect.

Under the DIPA, we file a request with the Ministry of Mines and Energy to approve an incremental production project for a field that we directly operate. If the project is approved, we agreed with our partners to develop the field and we determine mandatory investment thresholds for our partners. We are not require to fund any investment. The production from the field is distributed to us and our partners receive a percentage of the total production from the field which varies depending on the invested amount. Once the mandatory investment stage expires, we agree with our partners on the

 

 

41

 


percentage of production, total costs and additional investments to be paid by each party. We pay 20% royalties to the Nation on the base production curve and variable royalties on any incremental production. Additionally, in the event of higher prices and large volumes, we have adjustment clauses to increase our share in the production. At December 31, 2007, we had two DIPAs in effect.

 

Shared-Risk Production Contracts. Under these contracts, we remain as operators of the field and assume responsibility for 50% of all investments and costs. Private oil companies submit bids to enter into agreements with us based upon the production percentage they will assign to us. The successful bidder has the right to enter into the shared-risk contract with us. At December 31, 2007, we had one shared-risk production contract outstanding.

 

Risk Service Production Contracts. We began using the risk production service contract in January 1998 to increase production through the use of new technologies in crude oil fields then operated by our partners. All investments in new technologies were made by our partners who received a tariff payment based on a formula that took into account the incremental production resulting from the technological and operative investments. At December 31, 2007, we had two risk service contracts outstanding for the development of the Valdivia-Almagro field and the Rancho Hermoso field located in the Mirador formation.

 

Discovered Undeveloped Fields Contracts. We have entered into discovered undeveloped fields contracts to promote exploration by private companies of both undeveloped and inactive fields. Under this agreement, the contracting party assumes all costs and expenses for the development and operation of a field in exchange for a previously specified fee per barrel, which varies depending on the production level. At December 31, 2007, we had 18 discovered undeveloped fields contracts outstanding.

 

Sole Risk Contacts. After 2000, the party deciding to enter in a sole risk contract has the right to recover 100% of its investment and costs. Thereafter, we can participate in the development of the field sharing all new investment and costs. At December 31, 2007, we had 14 sole risk contracts outstanding.

Current Contractual Regime

In 2004, the authority to enter into exploration and production contracts was assigned to the ANH under a different exploration and production contractual scheme. We became an operator like any other company, competing with all other regional and international oil companies in Colombia for exploration and production opportunities under the same conditions and without any special privileges. Decree Law 1760 gave us the ability to maintain in effect all contracts we had entered into prior to January 1, 2004, as well as to have absolute discretion as to whether or not such contracts would be extended after their stated termination date. If we decide not to extend the contracts, the production rights will revert to us and we would have the right, at no additional costs to us, to exploit the associated reserves indefinitely. Contracts entered into by us after January 1, 2004, that are not extended by the ANH, they will revert to the ANH and not to us.

The ANH introduced two new model contracts to replace the previously used joint venture contracts: the exploration and production contract and the technical evaluation agreement.

 

Exploration and Production Contract or E&P. Under the E&P contract the contractor, including us assumes all exploration and production activities. The contractor also assumes all risks and costs of exploration and is the sole owner of all production and assets involved in the exploration and production activities for the term of the contract. There is no partnership or joint venture between the contractor and the ANH.

 

Technical Evaluation Agreements or TEA. The scope of the technical evaluation agreement is limited to exploration activities. Under this agreement, the contractor can evaluate a specific area and decide whether or not it will enter into an exploration and production contract. The contractor assumes all risks and costs of the activities and operations. The agreement may be entered into for an 18-month period for on-shore areas and up to a 24-month period for off-shore areas.

 

 

42

 


We have entered into a number of exploration and production contracts with regional and international oil companies. Please see Annex I — “Description of Exploration and Production Contracts” for a list of our exploration and productions contracts still in force at December 31, 2007 which describes the main characteristics of these contracts including the region where they are developed, the identity of our partners and operators, our ownership percentage, the expiration date, the percentage of royalties we have to pay, and whether or not once expired and not extended by us, they will revert to us.

Management of crude oil and natural gas joint ventures

Every crude oil and natural gas joint venture development has an executive committee, which makes all technical, financial and operational decisions. All major decisions are made unanimously, including for those projects where we have less than a 50% economic interest. Although we do not operate a number of these joint ventures under development, we do have an active role in the decision making process and development of the projects. As a result, we have direct control over the development of joint ventures, even for those joint ventures where we have less than a majority economic interest.

Refining and Petrochemicals

Summary

There are two main refineries in Colombia: Barrancabermeja, which we own and operate, and Cartagena, which we operate. We also own two other minor refineries, Orito and Apiay. In April 2007, we transferred the Cartagena refinery’s assets to Glencore International AG or Glencore in exchange for 49.0% interest in Refinería de Cartagena S.A. The refineries produce a full range of refined products including gasoline, diesel, liquefied petroleum gas or LPG and heavy fuel oils among others.

The following table sets forth our daily average installed and actual refinery capacity for each of the last three years.

 

 

 

For the year ended December 31,

 

 

 

2007

 

2006

 

2005

 

 

 


 


 


 

 

 

Capacity

 

Through
-put

 

% Use

 

Capacity

 

Through
-put

 

% Use

 

Capacity

 

Through
-put

 

% Use

 

 

 


 


 


 


 


 


 


 


 


 

 

 

(bpd)

 

Barrancabermeja

 

250,000

 

229,650

 

92

%

250,000

 

232,000

 

93

%

240,000

 

223,900

 

93

%

Cartagena

 

80,000

 

80,270

 

100

%

80,000

 

80,284

 

100

%

80,000

 

72,430

 

91

%

Apiay

 

2,500

 

2,208

 

88

%

2,500

 

1,839

 

74

%

2,500

 

2,063

 

83

%

Orito

 

3,000

 

1,258

 

42

%

3,000

 

807

 

27

%

3,000

 

853

 

28

%

 

 


 


 


 


 


 


 


 


 


 

Total

 

335,500

 

313,386

 

93

%

335,500

 

314,930

 

94

%

325,500

 

299,246

 

92

%

 

 


 


 


 


 


 


 


 


 


 

The average conversion ratio for the Barrancabermeja and Cartagena refineries was 81% and 73% respectively. In 2007 these refineries supplied the local demand for fuels and produced a surplus of certain refined products for export. Over the last three years we have improved the conversion ratios of our refineries resulting in higher margins to 79.2% in 2007 from 77.6% in 2006 and 77.5% in 2005, based on a 28.4° average API.

The increase in the refining margin was due to higher international oil prices and refining margins and the yields obtained from mid-distillates from the Barrancabermeja refinery which increased 3% during 2007 resulting in a reduction in imports of diesel fuel. We have also benefited from higher availability and a reduction in unscheduled shutdowns as a result of our maintenance program. Additionally, we have increased the Barrancabermeja refinery’s capacity through upgrades and expansion programs.

Strategy

Our strategy in this business segment is oriented towards improving the configuration of the Barrancabermeja and Cartagena refineries and upgrading them to high conversion through the addition of coking capacity, hydrocracking and complimentary hydroprocessing units and, making the necessary modifications in order for the fuels produced by the refineries to comply with more stringent environmental regulations in Colombia and our export markets. Our strategy is also focused on refining heavy crude oil and increasing our production of petrochemicals. In addition, to our current upgrade projects we have a long-term plan to increase our refining capacity to 650 thousand bpd which may include further upgrades and expansions and selectively acquiring additional refining assets. We seek to improve our ranking in the Solomon Index, which classifies refineries by their performance and rank, to be one of the best refineries in Latin America.

 

 

43

 


Barrancabermeja Refinery

In the Barrancabermeja refinery we produce a variety of fuels such as regular and premium unleaded gasoline, diesel fuel, kerosene, Jet fuel, aviation fuel, LPG, fuel oil and sulfur. We also produce petrochemicals, including, paraffin waxes, lube base oils, low-density polyethylene, aromatics, asphalts, alkylates, cyclohexane and aliphatic solvents, and refinery grade propylene.

The fuel hydro-treatment facility in the Barrancabermeja refinery is another major refining project that we have undertaken, which will enable us to meet existing regulation requirements relating to fuel quality standards, including diesel fuel with maximum sulfur content of 50 parts per million by 2010.

The Barrancabermeja refinery is undergoing a modernization process aiming to convert the refinery into deep conversion, allowing it to process heavy and extra-heavy crudes produced in local fields and increase production of mid-distillates for the local market, as well as producing fuels meeting international sulphur content standards. This project should be in operation in 2013.

Cartagena Refinery

In order to develop the Cartagena refinery master plan, we selected Glencore as our strategic partner. Refinería de Cartagena S.A. began its operations on April 1, 2007. The refinery’s products are mainly exported to the Caribbean and the United States.

As part of this overhaul plan we expect to increase the competitiveness and profitability of the Cartagena refinery through the modernization of its facilities and processes and improve the reliability of the refinery’s units. We plan to increase the refinery’s production capacity to 150 thousand bpd and improve refining margins by processing cheaper heavy crude oils; raising the conversion ratio, and producing a higher quality product slate. We also expect to satisfy existing environmental regulations for fuels by reducing sulfur content in gasoline and diesel fuel, thus complying with national and international fuel standards.

The following table sets forth our production of refined products of the Barrancabermeja refinery for the years ended December 31, 2007, 2006 and 2005.

 

 

 

For the year ended December 31,

 

 

 


 

 

 

2007

 

2006

 

2005

 

 

 

 


 


 

 

 

(bpd)

 

LPG and Butane

 

18,081

 

17,830

 

17,367

 

Motor Fuels

 

79,098

 

78,777

 

82,953

 

Jet Fuel

 

15,117

 

15,045

 

14,370

 

Diesel

 

66,966

 

63,137

 

55,242

 

Fuel Oil

 

41,387

 

47,837

 

46,824

 

Lube Base Oils and Waxes

 

1,358

 

1,358

 

1,346

 

Aromatics

 

2,023

 

2,023

 

1,704

 

Asphalts and Aromatics

 

4,574

 

4,574

 

3,059

 

Other Products

 

4,407

 

4,407

 

3,068

 

 

 







Total

 

233,012

 

234,989

 

225,933

 

 

 







 

 

44

 


The following table sets forth our production of refined products of the Cartagena Refinery for the years ended December 31, 2007, 2006 and 2005.

 

 

 

For the year ended December 31, (1)

 

 

 


 

 

 

2007

 

2006

 

2005

 

 

 


 


 


 

 

 

(bpd)

 

LPG and Butane

 

3,117

 

3,390

 

3,270

 

Motor Fuels

 

27,198

 

29,122

 

26,813

 

Jet Fuel

 

6,911

 

7,704

 

7,250

 

Diesel

 

21,534

 

22,095

 

18,533

 

Fuel Oil

 

19,483

 

18,105

 

16,418

 

Asphalts and Aromatics

 

1,162

 

1,552

 

1,507

 

Other Products

 

1,350

 

1,358

 

1,826

 

 

 


 


 


 

Total

 

80,755

 

83,326

 

75,617

 

 

 


 


 


 

______________

(1)

The table shows the entire production of the Cartagena refinery, which we no longer consolidate since April 2007.

In addition to our product slate, we have started to purchase low-sulfur diesel and biodiesel to improve the quality of the diesel produced in the Barrancabermeja and Cartagena refineries. The Cartagena refinery is currently purchasing biodiesel fuel in the local market and mixing it with its production of diesel to reduce sulfur content. The Barrancabermeja refinery is also working on improving the quality of its diesel products and is currently importing low-sulfur diesel. The low-sulfur diesel is being mixed with the current diesel production of the Barrancabermeja refinery. We expect to begin mixing biodiesel fuel in the Barrancabermeja refinery in June of 2008.

Petrochemicals and other products

We own and operate four petrochemical plants located within the Barrancabermeja refinery producing a variety of products including aromatics, cyclohexane, paraffin waxes, lube base oils and solvents. We are currently revamping our petrochemical capacity in the Barrancabermeja refinery to increase our production of low-density polyethylene by 12,000 tons per year.

Propilco

On December 24, 2007, we entered into an agreement with the Sandford Group and Valorem to acquire 100% of the outstanding shares of Propilco, which we completed during the second quarter of 2008. Propilco is the main polypropylene supplier in Colombia and the first resins producer in the Andean region, Central America and the Caribbean. On April 7, 2008, we completed the acquisition of Propilco.

During 2007, Propilco’s production totaled 314 thousand tons of petrochemical products compared to 355 thousand tons in 2006 and 383 thousand tons in 2005. We intend to expand Propilco’s production facilities to increase its production capacity to 500 thousand tons by 2011.

Transportation

Summary

Our transportation segment includes the transportation of crude oil, motor fuels, fuel oil and other refined products, excluding natural gas.

We, directly or in joint venture with private sector participants, own, operate and maintain an extensive network of crude oil and refined products pipelines connecting our and third-party production centers and terminals to refineries, major distribution points and export facilities. We own outright 32.9% of the total crude oil pipeline shipping capacity and 99% of the total product pipeline shipping capacity in Colombia. When aggregated with the crude oil pipelines in which we own a minority interest, we have access to 68.5 % of the oil pipeline shipping capacity in Colombia.

 

 

45

 


Our transportation business has three key elements: transportation and shipping of our own crude oil and refined products; sales of excess transportation capacity to third parties; and optimization of our future transportation needs.

At December 31, 2007, our network of crude oil and multi-purpose pipelines extended approximately 8,433 kilometers in length. The transportation network we own directly and in partnership with our joint venture partners consists of approximately 5,025 kilometers of main crude oil pipeline networks connecting various fields to the Barrancabermeja and Cartagena refineries, as well as to export facilities. Of the 5,025 kilometers of crude oil pipelines, we directly own 2,270.5 kilometers and 2,752 kilometers with our business partners. We also own 3,400 kilometers of pipelines for transportation of refined products from the Barrancabermeja and Cartagena refineries to wholesale distribution points. Approximately 55% of our crude oil pipelines were constructed through joint ventures and other agreements with our business partners in order to transport crude oil from producing fields.

Strategy

Our main strategies in our transportation segment are to:

 

Improve efficiency in all stages of logistic processes by using a variety of transportation systems and focusing on operational excellence, safety standards and high quality services;

 

Construct the necessary crude oil pipelines to transport our crude oil, refined products and heavy crude oil to the refineries and ports; and

 

Selectively invest in the development of new and more efficient transportation systems.

All of our transportation processes have been certified under ISO 9001, ISO 14001 and OHSAS 18001, which provide standards for hydrocarbons reception, storage and dispatch by pipes and pipelines.

We believe we have sufficient transportation capacity to meet our existing needs as well as any additional needs from new discoveries. We have ample experience in providing transportation services through crude oil pipelines, trucks, tankers and barges.

The map below shows the main transportation networks owned by us and our business partners.

TRANSPORTATION INFRASTRUCTURE

 

 

 

46

 


Pipelines

In 2007, pipelines in which we own an interest transported a total of 516.6 thousand bpd of crude oil and 193.8 thousand bpd of refined products for a total of 710.4 thousand bpd in 2007, a 9% increase when compared to 2006. In 2006 pipelines transported a total of 651.8 thousand bpd of crude oil and refined products compared to 603.2 thousand bpd in 2005.

The following table sets forth our pipelines and the pipelines in which we own an interest by name, kilometers covered, type of product transported, origin, destination and our ownership percentage.

 

Pipeline

 

Kilometers

 

Product
Transported

 

Origin

 

Destination

 

Ownership Percentage

 


 


 


 


 


 


 

Caño Limón-Coveñas

 

770

 

Crude Oil

 

Caño Limón

 

Coveñas

 

50

%(1)

Oleoducto del Alto Magdalena

 

400

 

Crude Oil

 

Tenay

 

Vasconia

 

49

%

Oleoducto de Colombia

 

480

 

Crude Oil

 

Vasconia

 

Coveñas

 

43.85

%

Oleoducto Central S.A. (Ocensa)

 

835

 

Crude Oil

 

Cusiana

 

Coveñas

 

35.29

%

Oleoducto Transandino

 

306

 

Crude Oil

 

Southern fields

 

Tumaco Port

 

100

%

______________

(1)

On January 1, 2009, we will exclusively own the Caño Limón-Coveñas pipeline.

The operation of our pipelines is made under international standards and industry practices, such as remote operation, integrity management, automatic ticket transfer, health, safety and environment policies and high index of customer satisfaction. The reduction in operating costs, fulfillment of volumetric commitments, reduction in theft, have resulted in higher customer satisfaction and a lower number of complaints.

The table below sets forth the volumes of crude oil and refined products transported through the crude oil pipelines and multipurpose pipelines owned by us.

 

 

 

For the year ended December 31,

 

 


 

 

2007

 

2006

 

2005

 

 


 


 


 

 

(thousand bpd)

Crude oil transport

 

516.6

 

471.1

 

443.8

Refined products transport

 

193.8

 

180.7

 

159.4

 

 


 


 


Total

 

710.4

 

651.8

 

603.2

 

 


 


 


We currently own 14 stations with tank farms that have a nominal storage capacity of 3.1 million barrels of crude oil and 3.0 million barrels of refined product. We also sell storage capacity to third parties in our Pozos Colorados and Maniella facilities and in the Coveñas port. We do not own any tankers.

Theft of fuel

Fuel theft, which reached 7,270 bpd in 2002, was reduced to 561 bpd in 2007, as a result of the comprehensive strategy developed in coordination with different law-enforcement agencies and governmental authorities. Theft of fuel in 2007, when compared to 2006, was reduced by 37.6% and 92.3% when compared to 2002. We continue to evaluate alternatives to improve the efficiency of our transportation system, including improvements to the monitoring and control systems through new supervisory activities and data collection systems.

The table below sets forth the decrease in the level of hydrocarbon theft in our pipelines and multipurpose pipelines.

 

 

 

For the year ended December 31,

 

 


 

 

2007

 

2006

 

2005

 

 


 


 


 

 

(thousand bpd)

Hydrocarbon theft

 

0.6

 

0.9

 

1.6

 

 

47

 


Other transportation facilities

We also enter into transportation agreements with tanker trucks and barge companies to transport crude oil from production locations that currently do not have pipeline connection to the refineries and our export locations. Production of refined products for which we currently have no pipeline capacity and cannot be transported in the tanker trucks is transported by barges. During 2007, 13 million barrels of crude oil and refined products were transported by tanker trucks and 9.1 million barrels of crude oil and refined products were transported by barges.

Export and import facilities

We currently own five docks for export of crude oil and refined products. Our crude oil loading facilities can load tankers of up to 150 thousand tons and deliver up to 1.5 million bpd. Adjacent to these loading facilities we also have crude oil storage facilities which are capable of storing 7.5 million barrels. Our docks used for import and export of refined products can load tankers of up to 70 thousand tons and deliver up to 500 thousand barrels. Additionally, these facilities have storage capacity of up to 1 million barrels.

New transportation projects:

Oleoducto de los Llanos Orientales

We and Pacific Rubiales Energy Corp., or Pacific, are jointly expanding the production of the Rubiales field in the Central region from its current production of heavy crude oil of 25 thousand bpd to 126 thousand bpd. We have reached a preliminary understanding to incorporate Oleoducto de los Llanos Orientales, a project company, in which we expect to hold a 65% interest and Pacific would hold a 35% interest.

As part of this process we are evaluating different alternatives to build, operate and maintain a pipeline that will connect the Rubiales field to the Ocensa pipeline through our facility at Monterrey.

Heavy Crude Oil Castilla Pipeline Project

We expect to construct two new pipelines. The first pipeline will transport heavy crude oil from the Castilla fields located in the Central region to El Porvenir pumping station, which is part of the Ocensa pipeline system. The second project will transport dissolvents from the Tocancipá pumping station to the Castilla field.

Tocancipá – Castilla naphtha pipeline

We intend to construct a new 170 kilometers pipeline from Tocancipá pump station to the Castilla fields. The pipeline will transport naphtha to be used as dissolvent for heavy crude oils produced in the Castilla fields.

Apiay – Porvenir pipeline

We expect to construct a new 127 kilometers pipeline in the Central region which will connect the Apiay field with El Porvenir pump station. The pipeline will increase our transportation capacity from the Castilla fields.

Distribution and Marketing

Summary

We market a full range of refined and feed stock products locally including regular and high octane gasoline, diesel fuel, jet fuel, natural gas and petrochemical products. Local sales of regular gasoline, LPG, jet fuel, diesel fuel and natural gas from the Guajira field, are subject to government price regulation with reference to international benchmarks for fuel oil. We export crude oil, LPG, butane, high octane gasoline, naphtha, jet fuel natural gas and fuel oil. During the last five years we have sold jet fuel, naphtha and gasoline to the Dominican Republic. We sell fuel oil to traders who mix it with solvents to improve the quality of our products and subsequently delivered it to the U.S. East Coast market, Rotterdam market and the Far-East.

 

 

48

 


We are the sole producer and main supplier of fuel and refined products in Colombia. For regulated products, the Ministry of Mines and Energy establishes maximum prices producers can charge and retail prices for these products pursuant to resolutions. The Ministry also establishes maximum wholesale and retail margins.

Strategy

Our strategy in the marketing and distribution business segment is focused on supplying the local market and exporting crude oil not used in our refineries and in the Cartagena refinery, and refined products principally to end-users, including refineries and wholesalers. Our crude oil export sales are made in the spot market and through long-term contracts, primarily to Gulf Coast refineries, the West Coast market and China. We are focused on entering into new and developing markets and increasing the direct sales of our products to the Far-East and China.

Crude oil supply commitments

As part of our transfer of the Cartagena refinery assets, we extended a ten-month commercial offer to Refinería de Cartagena for the supply of crude oil. The commercial offer is renewable for an additional one-year period. Pursuant to the terms of the offer, the Cartagena refinery has the option to purchase from us up to 85 thousand bpd of crude oil from our Caño Limón, Vasconia Blend, Ayacucho Blend, Cusiana and Castilla production. As we continue to operate the Cartagena refinery, our operations committee evaluates and decides monthly the refinery’s crude oil mix needs including the need for foreign crudes which we import from West Africa, the North Sea and the Caribbean.

The purchase price for the delivered volumes is equal to an international benchmark index, subject to certain adjustments.

Import of Low Sulfur Diesel Fuels