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

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ITEM 14	Material Modifications to the Rights of Security Holders and Use of Proceeds	113
ITEM 15	Controls and Procedures	113
ITEM 16	[Reserved]	113
ITEM 16A	Audit Committee Financial Expert	113
ITEM 16B	Code of Ethics	114
ITEM 16D	Exemptions From the Listing Standards for Audit Committee	114
ITEM 16E	Purchases of Equity Securities by the Issuer and Affiliated Purchasers	114
ITEM 17	Financial Statements	114
ITEM 18	Financial Statements	114
ITEM 19	Exhibits	114
Annex I	Description of Production Contracts	115

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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;

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• 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

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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.

ITEM1 Identity of Directors, Senior Management and Advisors

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

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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

 

ITEM2 Offer Statistics and Expected Timetable

Not applicable.

 

ITEM3 Key Information

 

ITEM3A 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

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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 December31,
	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.”

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	INCOMESTATEMENT
	FortheyearendedDecember31,
	2007(1)	2007	2006	2005	2004	2003
	(US$ inthousands exceptfornet incomepershare andaverage numberofshares amounts)	(Pesosinmillionsexceptfornet incomepershareandaverage numberofsharesamounts)
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

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______________

(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 December31,
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.

ITEM3B Capitalization and Indebtedness

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

	AtMarch30,2008 (Pesosinmillions)
Cash and cash equivalents	5,114,615
Shareholders’ equity	24,742,368
Total capitalization	29,856,983

ITEM3C Reasons for the Offer and Use of Proceeds

Not applicable.

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ITEM3D 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.

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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.

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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.

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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 autonomasregionales 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.

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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.

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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

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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,

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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

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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.

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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

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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.

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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.

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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 December31,
	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 March31, 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 December31,
	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 December31,
	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

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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 December31, 2007		Average crude oil production for the year ended December31, 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 December31, 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

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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 operatedmature 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.

	AtDecember31, 2007	FortheyearendedDecember31,
	Numberoffields	2007	2006	2005
		(thousandbpd)
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

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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.

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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.

	FortheyearendedDecember31,2007
	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:

	DevelopedandUndeveloped ProductionAcreageasof December31,2007		Averagenaturalgasproductionfor theyearended December31,2007
	(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

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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.

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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

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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

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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.

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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 December31,
	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.

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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 December31,
	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

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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 December31, (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.

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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

 

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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	%

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(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.

	FortheyearendedDecember31,
	2007	2006	2005
	(thousandbpd)
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.

	FortheyearendedDecember31,
	2007	2006	2005
	(thousandbpd)
Hydrocarbon theft	0.6	0.9	1.6

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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 stockproducts 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.

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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

We intend to reduce sulfur emissions from fuels produced by us through the import of low sulfur diesel to be mixed with our local production in order to protect the environment.

Natural Gas

Summary

Development of natural gas reserves began in the 1970s with the discovery of the Guajira fields in the Northeastern region. Additional natural gas reserves were discovered in the Piedemonte Llanero. We sell natural gas in Colombia to local distribution companies, power generators and large customers. In 1986, we introduced a program known as “Natural Gas for Change”, which sought to increase local consumption. In 1993, the Government developed a regulatory framework for the distribution and marketing of natural gas. Between 1995 and 1997, we connected our natural gas production fields with distribution points and major cities. In 1997, we transferred all of our natural gas transportation assets to a newly created company, Empresa Colombiana de Gas or Ecogás. Ecogás was spun-off from us in 1998 and sold to Empresa de Energía Eléctrica de Bogotá in 2007.

We anticipate that the local demand for natural gas will grow as the Government continues to eliminate subsidies on regular gasoline and diesel fuels. As a result of the elimination of the motor fuel subsidies, prices for these fuels have begun to rise, making natural gas an attractive alternative for consumers.

Marketing of Natural Gas

Currently, there are approximately 20 natural gas distribution companies with operations in Colombia. As a result of the growth of the Colombian economy in recent years, demand for natural gas has increased by 5.4% in 2007 to 760.4 giga British thermal units per day or gbtud from 721.2 gbtud in 2006 and 658.8 gbtud in 2005. At December 31, 2007, natural gas distribution companies had approximately 4.58 million customers. We sell natural gas to distribution companies through take-or-pay contracts and in the spot market.

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Compressed Natural Gas

Demand for compressed natural gas for motor vehicles continues to grow as the Government has launched a plan to convert public transportation and taxis from regular fuel to compressed natural gas. Market participants including natural gas distribution companies, natural gas transportation companies and producers including us, contribute funds to incentivate the conversion to compressed natural gas. We do not compress the natural gas but instead sell it to third-parties for its compression. The compressed natural gas program was initiated in 2003. In 2006, 72,247 vehicles were converted and 66,489 were converted in 2007 for a total of 234,805. As a result, demand for compressed natural gas increased by 25.3% in 2007 compared to 2006.

Natural gas sales to the power and industrial sector

We market and sell natural gas to the industrial sector and to gas-fired and combined cycle power plants. We have a number of long-term supply contracts with power generators under which such companies have entered into take-or-pay contracts and purchase and supply obligations for the supply of natural gas. Pursuant to the terms of these agreements if we do not ship the contracted natural gas amounts we must pay a fine to our customers. Long-term supply contracts establish a pricing formula that depends on international reference prices.

The following table sets forth our local deliveries of natural gas including deliveries to our refineries, during 2007, 2006 and 2005.

	FortheyearendedDecember31,
	2007	2006	2005
	(million btud)
Gas-fired power plants	123,263	137,733	161,808
Refineries	93,508	96,664	87,597
Petrochemical	4,032	12,076	12,238
Industrial	40,576	28,971	157,603
Distributors(1)	152,938	143,171	—
Compressed Natural Gas	40,898	25,802	15,301
Producers	60,014	42,770	20,264
Total Deliveries	515,229	487,187	454,811

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(1) Deliveries to distributors include deliveries to industrial clients who are required to purchase natural gas from distributors.

Natural Gas Exports

In 2007, we entered into a long-term natural gas supply contract with PDVSA. Pursuant to the terms of the agreement, we have agreed to deliver the following quantities of natural gas to Venezuela:

	For the year ended December31,
	2008	2009	2010	2011
	(gbtud)
Volume Commitments	50	150	150	100

Natural gas delivery commitments

The table below sets forth the commitments including volumes in firm contracts, contracts in renegotiation and new firm-flexible contracts under negotiation with local natural gas distribution companies and by gas-fired power generators for the purchase of volumes of natural gas from us beginning in 2007.

	For the year ended December31,
	2008	2009	2010	2011	2012	2013
	(gbtud)
Volume Commitments	623	636	559	512	253	135

We have natural gas delivery commitments with gas-fired power generators, distributors and other purchasers, including PDVSA. Pursuant to long-term supply contracts and other agreements, we must supply natural gas to

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these parties and failure to deliver the agreed amounts would result in fines. In order to meet our natural gas delivery commitments we have two main natural gas production fields, the La Guajira fields and the Cusiana and Cupiagua natural gas reserves. Of our total natural gas production at December 31, 2007, 62% was supplied by the La Guajira production, 25% from the Cusiana and Cupiagua fields and the remaining 13% from fields located in the Central region.

The following table sets forth our estimated reserves available to meet our firm delivery commitments of natural gas for the years ended December 31, 2008 to 2012.

	For the year ended December 31,
	2008	2009	2010	2011	2012
	(gbtud)
Guajira Fields	422	490.3	489.7	453.2	402.2
Cusiana and Cupiagua fields	139.6	139.6	191.3	282.4	394.2
Other fields	100.7	115.7	130.4	186.0	182.3
Imports	—	—	—	—	38.9
Total	662.3	745.5	811.5	921.5	1,017.6

Price controls on the La Guajira natural gas production

The Ministry of Mines and Energy through the Colombian Commission for the Regulation of Energy and Gas or CREG, establishes the maximum price we are allowed to charge customers who consume less than 100 thousand cfpd, under take-or-pay contracts, which we refer to as regulated customers. Maximum prices we can charge are determined with reference to the average export price for fuel oil for the prior six months.

Priorities for delivery of natural gas

The Ministry of Mines and Energy established distribution priorities in the event of a shortfall of reserves or production of natural gas. Residential consumers with existing supply contracts, small businesses and distributors of compressed natural gas have the first priority for delivery. Contracts for export of natural gas have last priority under the firm commitments. The agreements that are not firm commitments and contemplate delivery of natural gas “as available” have priority over customers on the spot market. We may enter into natural gas export contracts if the ratio of reserves to production exceeds seven years.

Property, Plant and Equipment

Under Colombian law, the Nation owns all crude oil and natural gas reserves within Colombia, and we have certain rights to explore and produce those reserves in areas awarded by the ANH after public bidding. Most of our property, consisting of refineries and storage, production and transportation facilities, is located in Colombia. Our main assets consist of our wells, refining facilities and our pipelines. See Item 4 — “Information on the Company — Reserves” for a description of our reserves, sources of crude oil and natural gas, main tangible assets and material plans for expansion and improvements in our facilities.

Legal Proceedings

We are currently a party to 2,504 legal proceedings relating to civil, administrative, environmental, tax and labor claims filed against us in the Colombian courts and arbitration tribunals. Historically, we have been successful in defending law suits filed against us. Based on the advice of our legal advisors it is reasonable to assume that the litigation procedures brought against us will not materially affect our financial position or solvency regardless of the outcome. We highlight an unresolved material lawsuit:

Foncoeco

An association of former employees known by the acronym Foncoeco 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 on June 25, 2002, ruled in our favor and rejected the

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plaintiffs’ arguments. The plaintiffs appealed the ruling to the 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 on December 16, 2005, 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. Based on the opinions from our legal counsel regarding the likelihood of a favorable ruling we expect the Bogota Higher Tribunal to revise and reduce the amount of the first instance. Additionally, we have created a provision for Ps$64,000 million considering the probability of a ruling in favor of the plaintiffs.

Regulation

The principal governmental entities regulating us are the Ministry of Mines and Energy and the CREG.

Ministry of Mines and Energy

The Ministry of Mines and Energy is responsible for managing and regulating Colombia’s nonrenewable natural resources assuring their optimal utilization by defining and adopting national policies regarding exploration, production, transportation, refining and distribution of minerals and hydrocarbons.

CREG

Laws 142 and 143 of 1994 created the CREG, a special administrative unit of the Ministry of Mines and Energy, responsible for regulating and establishing the standards for the exploitation and use of energy and natural gas, fostering the development of the energy services industry, promoting competition and responding to consumer and industry needs.

Control Entities

Superintendency of Domiciliary Public Services

Under Colombian regulations, the distribution and marketing of natural gas is considered a public service. As such, this activity is regulated by Law 142 of 1994 and supervised by the Superintendency of Domiciliary Public Services.

Superintendency of Corporations

We are subject to the supervision of the Superintendency of Corporations, the governmental body responsible for supervising corporations domiciled in Colombia.

Superintendency of Finance

The Superintendency of Finance is responsible for monitoring, promoting and regulating the publicly traded securities market, registered issuers, broker-dealers, mutual funds and any other participants in the public market including the BVC.

We are a registered issuer and our debt (pension bonds) and equity securities are publicly traded. The Superintendency of Finance is responsible for the supervision of any activity we undertake that may affect the market for our securities. We are required to inform the Superintendency of Finance of any material event and provide periodic reports of our financial condition.

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Hydrocarbon Resources Administrator

National Hydrocarbons Agency – ANH

The ANH was created in 2003 and is responsible for the administration of Colombia’s hydrocarbon reserves. The ANH’s objective is to manage the hydrocarbon reserves owned by the Nation through the design, promotion and negotiation of the exploration and production agreements in areas where hydrocarbons are found. The ANH is also responsible for creating and maintaining attractive conditions for private investments in the hydrocarbon sector and for designing, bidding rounds for exploration blocks. Any oil company selected by the ANH to explore a specific block must execute an exploration and production contract with the ANH. All royalty payments in connection with the production of hydrocarbons are made to the ANH in-kind unless the ANH grants a specific waiver to make royalty payments in cash.

We, and other oil companies working in Colombia send to the ANH information on the evolution of our exploratory activities and those of our partners.

Regulatory Framework

Regulation of Exploration and Production Activities

Pursuant to Colombian law, the Nation is the exclusive owner of all hydrocarbon resources located in Colombia and has full authority to determine the rights, royalties or compensation to be paid by private investors for the exploration or production of any hydrocarbon reserves. The Ministry of Mines and Energy is the authority responsible for regulating all activities related to the exploration and production of hydrocarbons in Colombia.

Decree Law 1056 of 1953 or the Petroleum Code, establishes the general procedures and requirements that must be completed by a private investor prior to commencing hydrocarbon exploration or production activities. The Petroleum Code sets forth general guidelines, obligations and disclosure procedures that need to be followed during the performance of these activities.

Prior to 2003, all activities regarding the exploration and production of hydrocarbons were governed by Decree 231 of 1974. Consequently, during such period all of our activities were outlined and regulated by this decree. Decree 231 was replaced by Decree Law 1760 of 2003, but all agreements entered into by us prior to 2003 with other oil companies are still regulated by Decree 231.

Decree Law 1760 of 2003 introduced Colombia’s new contractual regime for hydrocarbons and granted the ANH full and exclusive authority to regulate and oversee the exploration and production of hydrocarbon reserves. Decree Law 1760 was complemented by Decree 2288 of 2004, which regulates all aspects related to the reversion of reserves and infrastructure under the joint venture agreements executed by us before 2004. Accord 008 of 2004 issued by the Directive Council of the ANH, sets forth the necessary steps for entering into exploration and production contracts with the ANH.

Pursuant to Colombian law we are obligated by law to pay a percentage of our production to the ANH as royalties. Each production contract has its own royalty arrangement. In 1999, a modification to the royalty system established a sliding scale for royalty payments linked to the production level of crude oil and natural gas fields discovered after July 29, 1999 whether the production is crude oil or natural gas, and the quality of the crude oil produced. Since 2002 the royalties system has ranged from 8% for fields producing up to 5,000 bpd to 25% for fields producing in excess of 600,000 bpd. Changes in royalty programs only apply to new discoveries and do not alter fields already in their production stage. Producing fields pay royalties in accordance with the applicable royalty program at the time of the discovery. Our contracts specify that royalties are to be paid in physical product (oil and gas) to the ANH.

We currently purchase all physical product delivered by producers of crude oil and natural gas as royalty payments to the ANH at prices set forth in Law 756 of 2002 and Resolution 18-1709 of 2003. The purchase price is calculated on a reference price for crude oil and natural gas at the wellhead and varies depending on prevailing international prices. We have an interagency agreement or Convenio with the ANH, whereby we collect all in kind and cash royalties owed to the ANH by the oil and gas companies in Colombia. The ANH may extend offers to sell such physical product and we, at our option, may accept such offers to purchase the royalty volume. We sell the physical product purchased from the ANH as part of our ordinary business.

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Regulation of Refining and Petrochemical Activities

Refining and petrochemical activities are considered a public service and are subject to Governmental regulation. Article 58 of the Petroleum Code establishes that oil refining activities can be developed throughout Colombia. Oil refineries must comply with the technical characteristics and requirements established by the existing regulations.

The Ministry of Mines and Energy is responsible for regulating, supervising and overseeing all activities related to the refining of crude oil, import of refined products, storage, transport and distribution.

Decree 2657 of 1964 regulated the oil refining activities and created the Oil Refining Planning Committee which is responsible for studying industry problems and implementing short and long-term refining planning policies. The Committee is also responsible for evaluating and reviewing new refining projects or expansion of existing infrastructure. Prior to deciding on a new project, the Committee must take into account the significance of the project and the economic impact, the sources of financing, profitability, social contribution, the effects on Colombia’s balance of payments and the price structure of the refined products.

Pursuant to Resolution 18 0966 of 2006 issued by the Ministry of Mines and Energy and Article 58 of the Petroleum Code, any refining company operating in Colombia must provide a portion or, if needed, the total of its production to supply local demand prior to exporting any production. If the regulated production income, the principal item in the price formula, becomes lower than the export parity price, the price paid for the refined products will be equivalent to the price for those products in the U.S. Gulf Coast market. If there is a need of local demand for imported crudes, the refining company may charge additional transportation costs in proportion to the crudes delivered to the refinery.

The Ministry of Mines and Energy establishes the safety standards for LPG, storage equipment, maintenance and distribution. Regulations issued in 1992 established that every local, commercial and industrial facility with a storage capacity of LPG greater than 420 pounds must receive an authorization for operations from the General Directorate of Hydrocarbons of the Ministry of Mines and Energy.

Regulation of Transportation Activities

Hydrocarbon transportation activity is considered a public service in Colombia and therefore is under governmental supervision and control. Transportation and distribution of crude oil, natural gas and refined products must comply with the Petroleum Code.

Transport systems, classified as crude oil pipelines and multipurpose pipelines, can be owned by private parties. The building, operation and maintenance of the pipelines must comply with environmental, social, technical and economic requirements under national and international standards. Transportation networks must follow specific conditions regarding design and specifications, while complying with the quality standards demanded by the oil and gas industry.

According to Law 681 of 2001, multipurpose pipelines owned by us must be open to third-party use and we must offer their capacity on the basis of equal access for all.

The hydrocarbon transport activity can be developed by third parties and must meet all requirements established by law.

The Ministry of Mines and Energy is responsible for:

• Studying and approving the design and blueprints for private pipelines and approving the construction of all pipelines;

• Establishing the hydrocarbon transport tariffs based on the information furnished by the service provider;

• Verifying the calculation and payment of transport related taxes; and

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• Managing the information system for the oil product distribution chain.

The construction of transportation systems requires Government licenses and local permits awarded by the Ministry of the Environment as well as licenses from the regional environmental authorities.

Regulation on selling, distributing, transporting and marketing of natural gas

The sale of natural gas and its by-products is subject to certain controls and limitations under Colombian law such as maximum prices to be charged to wholesalers, retailers and distributors.

The distribution of natural gas and its by-products is considered a domiciliary public service and is therefore subject to Government regulation. The transportation and marketing of natural gas, although not classified as a domiciliary public service, is considered a complementary activity to the distribution service and therefore, also governed by Law 142 of 1994. In addition, each of these activities is governed by specific regulations established by the CREG.

CREG’s Resolution 057 of 1996 defines transportation activity as an independent activity. As such, companies that produce, distribute or commercialize natural gas are not allowed to transport natural gas nor participate in companies that perform such activity. Regulation 057 also prohibits producers of natural gas to freely consume the natural gas they produce in excess of a specified limit. However, producers are allowed to re-inject natural gas in the crude of the oil fields operated by them.

CREG’s Resolution 093 of 2006 defines the marketing activity as an independent activity. This Regulation establishes that partners to a natural gas field are not allowed to jointly commercialize their product without the prior authorization of the CREG.

The CREG also regulates the type of agreements that can be used for the marketing, production, distribution and transport of natural gas. CREG’s Regulation 119 of 2006 provides three types of contracts that can be used:

• Take-or-Pay Agreements. The buyer agrees to purchase a specific amount or percentage of production of natural gas and the producer guarantees the making available 100% of the agreed amount.

• Optional Purchase Agreements. The buyer agrees to pay a premium for its right to take a fixed amount of natural gas and agrees to pay an exercise price for the amount of natural gas made available. The producer guarantees to have available 100% of the agreed-on amount.

• Spot Agreements. The buyer purchases natural gas according to its needs. The producer does not have to make any amount available.

The export of natural gas is not considered a public service under Colombian law and therefore is not subject to Law 142 of 1994. The export of natural gas is governed by Decree 3428 of 2003 which provides, among other things, that an importer of natural gas who acquires such natural gas through the national pipeline system is subject to CREG’s regulatory framework. Export prices and transportation of natural gas for export are not subject to price controls. Natural gas producers must first supply the local consumers.

Decree 3428 of 2003 provides that producers of natural gas may freely dispose of their proved reserves of natural gas when the R-Factor of the proved reserves is higher than seven years. If the R-Factor is lower than seven years, producers of natural gas are not allowed to enter into new agreements or increase the amounts of previous agreements for the production of natural gas.

Regulation for sales of liquid fuels

The sale and transport of liquid fuels (excluding natural gas liquids) is considered a public service under Colombian law and is therefore subject to the supervision and control by the Ministry of Mines and Energy.

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Decrees 293 and 1521 of 1990 and 1998, respectively, establish minimum technical requirements for the construction of storage plants and service stations and regulate the distribution of liquid fuels establishing the minimum requirements for distributors and the activities and types of agreements permitted for these agents. The Ministry also regulates the types of liquid fuels that can be sold and purchased and the penalties for noncompliance with governmental regulations.

The Ministry of Mines and Energy fixes the price that we can charge for the sale of gasoline and fuel oil to wholesalers. The Ministry of Mines and Energy issues periodic price adjustments and each municipality imposes additional surcharges applicable to the price.

The price of gasoline and fuel oil is composed by a set of items such as freights, volume conversion ratios, import and export tariffs, transportation tariffs and income tax. Such items are adjusted periodically depending on the fuel oil and gasoline market. Each municipality may impose additional surcharges depending on their economic needs.

Wholesalers sell the product based on the price set by the Ministry and the local municipalities to retailers, earning a distribution margin set by the Ministry of Mines and Energy. Retailers are free to set a sale price for the fuel oil and gasoline to be charged to the public.

The distribution of fuels in areas near Colombian borders is subject to specific regulations that impose stringent control procedures and requirements.

Regulation of biofuel and related activities

The sale and distribution of biofuels is regulated by the Ministry of Mines and Energy. Regulations establish the quality and pricing standards for biofuels and impose minimum requirements for mixing ethanol with gasoline.

Environmental Matters

Regulation

Law 99 of 1993 imposes on any company, including crude oil and natural gas companies, the obligation to obtain an environmental license prior to undertaking any activity that could negatively impact the environment. Crude oil companies must file an environmental plan with the Ministry of Environment which includes, among others, an environmental impact assessment, and mechanisms established to prevent, mitigate, correct and compensate any activity that may harm the environment. The number of licenses required for a crude oil or natural gas field may vary depending on the background of the field and the number of wells. In certain cases, the Ministry of Environment will require a license for each well, and in other cases will require only one license per field. Obtaining a license may take between 90 and 145 business days depending on whether or not the Ministry of Environment requires the applicant to file additional information.

The Ministry of Environment is the highest environmental authority in Colombia and is in charge of issuing Nation-wide environmental regulations, policies, and programs. At the regional level, regional environmental authorities such as the Corporaciones Autónomas Regionales, are the highest environmental authorities of the region and are in charge of executing and overseeing all regulations, policies and programs issued by the Ministry of Environment.

The use of natural resources is also regulated. Companies that use large amounts of water for consumption; that discharge industrial wastes into the coastlines or rivers; that exploit forests reserves or that produce atmospheric emissions of gases, must obtain a permit from the regional environmental authorities. Decree 1900 of 2006 provides that any company that uses water resources and that requires an environmental license to the use of such resources must assign 1% of its investment to the recovery, conservation, preservation and supervision of the water resources used.

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A company that does not comply with the environmental regulations, or does not follow the environmental plan filed before the Ministry of Environment, or that ignores the requirements imposed by an environmental license, may be subject to an administrative procedure initiated by the Ministry of Environment or the regional environmental authorities, as it may be the case, which may result in oral or written warnings, penalties, license revocation or even temporal or permanent suspension of the activity being undertaken.

We have been subject to 25 administrative procedures between January 2005 and February 2008. Thirteen of these processes were closed, we were exempted from seven processes, and we were subject to monetary fines in six of them. The other 11 processes are still at a preliminary evidentiary stage and therefore, it is not possible for us to determine the material effect of these processes. The highest fine we have received for an administrative action commenced against us has been Ps$58 million. Most of our fines have been between Ps$6 and Ps$25 million.

Environmental Practices

We have implemented aggressive environmental practices and standards throughout all the activities performed by us and our workforce. During 2007, we invested Ps$303,670 million in environmental programs to increase our environmental compliance levels. Such programs include:

• Compliance. The purpose of this program is to guarantee the compliance with all laws and regulations imposed by the Ministry of Environment and other regulatory bodies. We undertake environmental impact assessments and constantly review our environmental plan. During 2007, we optimized our compliance levels and had 100% of our permits and licenses in force or in the process of being renewed. Our transportation vice-presidency was certified with ISO 14001, and we renewed the certification of our operation center in Apiay.

• Contingency Planning. This program implements the contingency plans in our operative areas to promote preventive activities and establish the steps that need to be followed in case of an emergency. Our contingency planning program has had a positive impact in the number of environmental-related accidents. We reduced the number of accidents in 2007 to 59 incidents, a 33% reduction when compared with a total of 88 incidents that took place in 2006.

• Eco-Efficiency. This program is designed to minimize and mitigate the environmental impact resulting from deploying industrial residues into rivers and coastlines and from atmospheric emissions of gases.

• Biodiversity. This program implements initiatives to preserve endangered species in areas where our activities have strong influence in the community. During 2007, we invested approximately Ps$1,200 million in investigation and rehabilitation projects for the recovery of ecosystems and environmental education in the areas where we operate.

• Environmental Culture. This program seeks to promote an environmental culture in our organization, in our activities, and in our and daily life. We initiated several environmental campaigns to educate our working force in areas such as occupational health and environmental practices.

• Alternative Energy Sources. This program is designed to implement projects and activities for the development of alternative energy sources, such as biodiesel and ethanol. During 2007, we invested approximately US$35 million in alternative energy source projects. We incorporated Ecodiesel Colombia S.A. or Ecodiesel to undertake biodiesel activities in the Mid-Magdalena Valley region and initiated the construction of a biodiesel plant in Barrancabermeja. The project is being developed in partnership with seven palm-oil production companies which together own a 50% interest in the company and supply palm oil to the plant. We own the remaining 50% of Ecodiesel and will purchase the plant’s production of biodiesel. We plan to mix the biodiesel with other refined products and sell it into the market. The total cost of this project is approximately Ps$72,500 million and the plant is expected to be located in a free trade zone. We expect Ecodiesel to begin commercial production during the first quarter of 2009 with an estimated production of approximately 100,000 tons of biodiesel per year.

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Health, Safety and the Environment or HSE

We are devoted to improve our HSE practices. We have several programs in place to increase our industrial safety and minimize the number of accidents of our workforce or our contractors. The frequency of accidents taking place within our premises has declined significantly during since 2002, to 1.82 accidents per million of hours worked in 2007 from 19 accidents per million of hour worked in 2002, representing a 90% reduction. These programs include, among others, the standardization of HSE protocols and procedures, drafting safety manuals, compliance with existing regulations on industrial safety and the study of HSE benchmarks among oil companies.

During 2007, we improved the safety standards of our processes through the use of rigorous methods and new technologies, the performance of risk assessments to each stage of our process, the implementation of new technologies in our projects, including emergency shut down systems and conducted safety integrity level studies and alarm systems.

Human Rights Initiatives

We have a strong commitment for the protection of human rights in the areas where we operate. We have developed a set of security and human rights principles or Principios Voluntarios en Seguridad y Derechos Humanos that we use as basis for a risk analysis of our company and the communities where we operate. We use this set of principles to influence local communities and strengthen their relationship with local authorities, our third party contractors and us.

Insurance

We carry the necessary insurance to cover our local and international activities. As of December 2007, we had a corporate insurance program with specific coverage against property damage, sabotage & terrorism, product liability, loss of cargo, crime and Directors and Officers liability. Colombian law requires that our policies be issued in Colombia, but all our policies are reinsured abroad in the European and London reinsurance markets. Our reinsurance policies are negotiated and subscribed by Black Gold Re. Ltd., a captive insurance company 100% owned by us, that brings us important economic benefits and facilitates our access to the reinsurance markets. According to our credit requirements, all of the reinsurance companies comply with an A- risk rating by Duff & Phelps, or equivalent.

Under our policies, we have insurable assets for property damages for US$8.5 billion.

We have a liability insurance policy covering three main areas: general liability; product liability and environmental liability with an insurance limit of US$300 million. Our directors and officers are covered by Directors and Officers’ insurance policies covering their actions for up to US$40 million.

All our projects and installations under construction are insured against loss in compliance with the terms of the relevant agreements, usually through a performance bond in connection with completion of the contract and/or other damage and liability insurance.

 

ITEM 5 Operating and Financial Review and Prospects

The following discussion presents our financial results and prospects as well as factors that affect our results of operation under Colombian Government Entity GAAP, unless otherwise indicated.

Overview

We are a vertically integrated crude oil and natural gas company engaged in exploration, development and production of crude oil and natural gas. We are also engaged in refining, wholesaling and distribution of crude oil, natural gas and refined products. We are in the process of building a refinery to process palm oil for biofuels. We own and have interest in companies which own 8,433 kilometers of crude oil pipelines and multi-purpose transportation pipelines. For the year ended December 31, 2007, our average daily production of crude oil was 327 thousand bpd and 412 mcfpd of natural gas. All of our crude oil and natural gas production and refining capacity is

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located in Colombia, although we recently began hydrocarbon exploration outside Colombia in partnership with regional and international oil companies. We export crude oil and refined products mainly to North America and the Caribbean.

We refine crude oil and other hydrocarbons in our refineries and in the Cartagena refinery in Colombia into a variety of products, including gasoline, diesel, jet fuel, petrochemicals and industrial products. Crude oil, natural gas and refined products are transported mainly through pipelines to our customers and the refineries. In December 2007, we entered into an agreement to purchase Propilco, which we completed during the second quarter of 2008. As a result we will be entering into the petrochemicals business and further integrating our business.

In November 2007, we placed 4,087,723,771 common shares or 10.1% of our capital stock in Colombia. As a result of our initial public offering, we are now subject to the mixed economy regime, which among others, excludes us from the Government budgetary rules, the national procurement regime and salary caps for state-owned companies.

Transformation from a wholly state-owned entity

We have been undergoing a two-step transformation process since 2003, first from a wholly state-owned entity to a state-owned entity characterized by shares, and then with our initial public offering in November 2007, to a mixed economy company, which incorporates private capital. This two-step process has resulted in a substantial change in the legal framework to which we are subject and in the nature of our relationship to the Nation, including a number of changes that have had a significant effect on our results of operations. The most important changes are described below.

Role of Ecopetrol in managing Colombia’s hydrocarbon reserves

Prior to 2003, we were an Empresa Industrial y Comercial del Estado or state-owned commercial and industrial national entity responsible for the administration and exploitation of Colombia’s hydrocarbon reserves, including managing relationships with regional and international oil companies doing business in Colombia. As a result, we are the counterparty to a large number of contracts to exploit Colombia’s hydrocarbon reserves that predate the beginning of our transformation process.

In 2003, the Congress of Colombia created the ANH, which became the governmental agency responsible for managing Colombia’s hydrocarbon reserves and awarding exploration and production blocks to oil and gas companies. Since the creation of the ANH, any company, including us, wishing to explore, develop and produce hydrocarbon reserves in Colombia must sign contracts with the ANH and not with us. As a result, 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. Nevertheless, we have remained as counterparty to the contracts which we signed prior to the creation of the ANH.

The contracts on which we are the counterparty all have clauses which provide, at our sole option, for extensions. If we do not extend the contracts, the right to exploit the hydrocarbon reserves which are the subject of the contract revert to us, and we have the right to exploit them for an indefinite period at no additional cost to us. If we decide to extend a specific contract and have come to an agreement with the other parties on the terms of such extension, a copy of the final agreement is submitted to the ANH for its review. The ANH’s review focuses on assuring that the terms of the extension benefits the Nation more than if the contract were not extended, the production rights reverted to us and we undertook their development.

During 2008, one exploration and production contract will expire, and in 2010 the “Santiago de las Atalayas contract”, one of the most important exploration and production contracts due to its current production level and to the amount of crude oil and natural gas reserves.

All exploration and production contracts entered into after January 1, 2004, in the event they are not extended by the ANH, revert to the ANH and not to us.

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Accounting for reserves and production

Under Colombian law, the Nation owns all hydrocarbon reserves within Colombia, and we have the right to explore and produce those reserves as detailed in Item 4 — “Information on the Company — Overview of Exploration and Production Contractual Arrangements”. In connection with our transformation process we changed our accounting for all reserves other than reserves that arose in connection with the reversion of concessions.

Prior to March 2007 and in accordance with decree 2625 of 2000, we recorded a cost of sales in the line– cost of sales of contributions in kind, for every barrel produced (other than from reverted concessions) pursuant to a pricing formula specified in the decree and we recorded a contribution to capital from the Nation for the amount expensed. Since March 2007 and in accordance with Decree 727 of 2007, we no longer record a cost of sales or a capital contribution from the Nation in respect of our production (other than from reverted concessions). We account for production from reverted concessions by recording a depletion charge on our income statement and a reduction in the related asset. At the time we received the reverted concession, we placed the asset in our books at the book value carried by the party holding the concession.

FAEP

In 1995, the Government established a macroeconomic stabilization fund to manage excess export earnings from the sale of crude oil from three major oil fields in which we were a partner. As a result, some of our export earnings from these fields were required to be deposited into a fund, the FAEP, which we owned and recorded on our balance sheet as an asset, but which was held at the Colombian Central Bank, which acted as the FAEP’s portfolio manager. The amount we recognized as current revenues was determined by a specific formula contained in the law based on the amount of production and sales prices of specified fields. The remaining amount was retained in the FAEP account at the Colombian Central Bank and was recorded in our balance sheet as deferred income with the related liability and the FAEP account as a long-term asset. We recognized the deferred income as revenue when such funds were distributed to us from time to time. In August 2007, in connection with our corporate transformation prior to our initial public offering, we distributed to the Government all of the deferred income in the FAEP account and we removed from our balance sheet the asset and the liability attributable to the FAEP, and our FAEP account ceased to exist. As a result, since that date, we recognize all of our export earnings as current revenues.

Gasoline and diesel subsidies

The Government maintains a motor fuel subsidy program by regulating the maximum prices at which motor fuels are sold in the local market. Prior to 2007, we were not compensated for the difference between the regulated prices and the export prices. As part of our transformation process, the Government assumed direct responsibility for reimbursing producers of motor fuels for the difference between the two sets of prices, which we call the fuel subsidy. As of the beginning of 2007, we continue to charge the prices established by the Government to wholesalers, and at the same time, we accrue as revenues the amount of the fuel subsidy and record an account receivable from the Government. Each month the Government issued a resolution setting forth the fuel subsidy payment to be made in cash. Pursuant to a regulation issued by the Ministry of Mines and Energy and the Petroleum Code, producers of motor fuels must first supply the local market before exporting any refined products. Please refer to Item 4B — “Business Overview — Regulatory Framework” for a description of the local market priorities.

Transfer of the Cartagena refinery assets to Refinería de Cartagena S.A.

In April 2007, we initiated a process to upgrade and expand our Cartagena refinery. As part of the process we selected Glencore as our strategic partner to undertake the expansion of the refinery and contributed the refinery’s assets in exchange for a 49.0% of the equity in Refinería de Cartagena S.A. Glencore holds the remaining 51.0% interest in the company. As of April 1, 2007, we started recording as revenues the delivery of crude oil to the Cartagena refinery and stopped recording as revenues sales of the refined products from the Cartagena refinery.

Under Colombian Government Entity GAAP we treat our 49.0% interest in Refinería de Cartagena S.A. as an investment at cost. Any future dividends paid to us would be recognized as other income, while any decrease below the original book value of our investment is recorded as an expense in other expenses. An increase above the

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original book value and subsequent decreases back to original book value are recorded to the valuation account for the investment.

Under U.S. GAAP, we recorded a Ps$579,241 million gain equal to 51% of the difference between the book value of the transferred assets and the fair value of the assets received, which we determined to be a more reliable indicator of the value of the exchange. The gain also includes Ps$27,812 million corresponding to the amortization of the deferred gain. The remaining 49% or Ps$556,236 million is to be amortized over 20 years. Prior to the transfer the results of the Cartagena refinery were included in our consolidated results. After the transfer, the results are accounted for under U.S. GAAP using the equity method.

Payments of tariffs of the build, operate, maintain and transfer contracts or BOMTs transferred to Ecogás as part of its spin-off from us

As a result of Law 401 of 1997, in 1998, we were required to spin-off all of our natural gas transportation assets to Ecogás, a newly created natural gas transportation company. Prior to the spin-off of the natural gas transportation assets, we had entered into a number of BOMT contracts for the construction, operation, maintenance and transfer of the gas pipelines. As part of the spin-off we were required to transfer all rights under the BOMT contracts to Ecogás, while remaining obligated for 100% of the tariffs. Nevertheless, pursuant to Decree 958 of 1998 Ecogás was responsible for reimbursing us for 70% of the tariffs.

During 2007, in connection with the sale by the Government of Ecogás to Empresa de Energía de Bogota, Ecogás’ obligation was cancelled. We made a calculation of the present value of the future tariff payments corresponding to Ecogás’ 70% reimbursement obligation, and the Government delivered to us the future tariff payments in cash to cover these future BOMT obligations which totaled Ps$729,588 million at December 31, 2007. We recorded this payment as a deferred income and as we make payments under the BOMTs, we record an expense and a reduction in the related deferred income liability. We will make all future tariff payments under the BOMT contracts until their expiration. This arrangement should not have a negative effect on our operating expenses, as the 70% expense which was previously compensated by Ecogás’ reimbursement, is offset by our recording the deferred income arising from the lump-sum payment.

Pre-IPO distribution of retained earnings

On April 27, 2007, we distributed as dividends retained earnings and other reserves amounting to Ps$4,475,399 million to our shareholder in cash.

Development of a Strategic Plan

We have developed the 2008–2015 Strategic Plan aimed at producing one million boe by 2015, placing special emphasis on the production of heavy crude oil. We intend to invest heavily in our exploration and production activities, and in acquisition of reserves in Colombia and abroad to reach our goal. As part of our strategic plan, we are upgrading and expanding the Barrancabermeja and the Cartagena refinery, increasing their capacity and conversion rate. Finally, we entered into an agreement for the purchase of Propilco which we completed during the second quarter of 2008 to further enhance integration of our product lines.

Factors Affecting our Operating Results

Our operating results are affected by international prices for crude oil and natural gas, production volumes and product mix. Higher crude oil and natural gas prices have a positive impact on our results of operations in both our exploration and production segments due to our export revenues increasing. Results from our refining activities are also affected by conversion ratios, utilization rates, refining capacity and operating costs, all of which affect our refining margins. Currently, we have relatively low although improving, conversion ratios in our refineries which result in us producing and selling refined products, particularly fuel oil below costs. Finally, changes in the value of foreign currencies, particularly the U.S. dollar against the Peso, have a significant effect on our financial statements.

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Sales volumes and prices

Our exploration and production segments depend on production levels and average local and international prices for crude oil and natural gas that we market and sell to our customers locally and abroad. Additionally, sales volumes depend on our purchases of crude oil and natural gas from our business partners and the ANH.

We sell crude oil in the international market and since April 2007 to the Cartagena refinery. In addition, we process crude oil in our Barrancabermeja refinery and sell refined products in the local and international markets. Although sales of refined products have increased in recent years, production and sale of crude oil continues to be the driver of our financial performance.

Local sales and prices

We have a number of crude oil and natural gas long-term supply contracts with local customers, including the Cartagena refinery and gas-fired power plants. Local sale prices are determined in accordance with existing regulations, contractual arrangements and the spot market linked to international benchmarks. Starting in April 2007, we started recording sales of crude oil to the Cartagena refinery as third-party sales and not as internal sales.

International sales and prices

We export crude oil, natural gas and refined products at prices which are set by reference to international benchmarks and negotiation with our buyers. We export any crude oil and refined products surplus after we have fulfilled our supply commitments with the refineries and local buyers.

Exploration costs

We plan to spend approximately US$11billion in drilling directly and with our business partners, approximately 300 gross wells in the next seven years. We account for exploratory drilling using the successful efforts method whereby all costs associated with the exploration and drilling of productive wells are capitalized, while costs incurred in exploring and drilling of dry wells are expensed in the period. The number of exploratory wells we declared as dry negatively affects our results. Therefore, the significant expansion of our drilling can be expected to result in higher dry well expenses.

Labor costs

We expect our future labor costs to increase as we adjust the salaries of our employees to industry standards in the region and hire new personnel required to expand our exploration and production segments.

Royalties

We are obligated by law to pay a percentage of our production to the ANH as royalties. Each production contract has its own royalty arrangement. In 1999, a modification to the royalty system established a sliding scale for royalty payments linked to the production level of crude oil and natural gas fields discovered after July 29, 1999 whether the production is crude oil or natural gas, and the quality of the crude oil produced. Since 2002 the royalties system has ranged from 8% for fields producing up to 5,000 bpd to 25% for fields producing in excess of 600 thousand bpd. Changes in royalty programs only apply to new discoveries and do not alter fields already in their production stage. Producing fields pay royalties in accordance with the applicable royalty program at the time of the discovery. Our contracts specify that royalties are to be paid in physical product (crude oil or natural gas).

Purchases of hydrocarbons from the ANH

We currently purchase all physical product delivered by producers of crude oil and natural gas as royalty payments to the ANH at prices set forth in Law 756 of 2002 and Resolution 18-1709 of 2003. The purchase price is calculated on a reference price for crude oil and natural gas at the wellhead and varies depending on prevailing international prices. We have an interagency agreement or Convenio with the ANH, whereby we collect all in kind and cash royalties owed to the ANH by the oil and gas companies in Colombia. The ANH may extend offers to sell such physical product and we, at our option, may accept such offers to purchase the royalty volume. We sell the physical product purchased from the ANH as part of our ordinary business.

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Effect of taxes and exchange rate variation on our income

Income tax

We are subject to tax on our income at statutory rate of 33%, the standard corporate rate in Colombia since 2008. The statutory income tax rate during 2007, 2006 and 2005 was 34%, 38.5% and 38.5%, respectively. The income tax rate in 2005 and 2006 includes a 10% surcharge over the 35% statutory rate.

Exchange rate variation

Since 1999, the Government has allowed the Peso to float freely against all major currencies, including the U.S. dollar. A strong depreciation or revaluation of the Peso, particularly against the U.S. dollar, has multiple effects on our financial results. Our results are reported in Pesos, and we maintain our financial records in Pesos. During 2007, 2006 and 2005, the Peso has appreciated on average 11.9%, (1.6)% and 11.6% respectively against the U.S. dollar.

Almost all of our exports of crude oil, natural gas and refined products are made in U.S. dollars at prices determined by reference to international benchmarks. If the Peso depreciates against the U.S. dollar, our revenues from exports expressed in Pesos increase. Imported goods, however, including imported services denominated in U.S. dollars, will by the same token increase.

The opposite effect occurs when the Peso appreciates against the U.S. dollar as has been the case in 2005 and 2007 based on average exchange rates. Our revenues from exports of crude oil and natural gas have been reduced in Pesos as a result of the appreciation of the Peso. The appreciation of the Peso also results in lower cost of products, services supplied and contracted abroad as these are denominated in U.S. dollars.

Furthermore, most of our financial investments are denominated in U.S. dollars and the appreciation of the Peso during 2005 and 2007 resulted in substantial exchange losses.

Results of operations for the year ended December31, 2007, compared to the year ended December31, 2006, and compared to the year ended December31, 2005.

The following table sets forth components of our income statement for the years ended December 31, 2007, 2006 and 2005.

	At December31,
	2007			2006		2007/2006 % change		At December31, 2005			2006/2005 % change
	(Pesos inmillions)							(Pesos inmillions)
Revenues:
Total Revenue		22,332,320			18,389,965	21	%		15,512,903		19	%
Cost of Sales		12,058,527			12,756,563	(5	%)		10,095,542		26	%
Gross Profit		10,273,793			5,633,402	82	%		5,417,361		4	%
Operating Expenses:		1,341,956			997,570	35	%		918,976		9	%
Operating Income		8,931,837			4,635,832	93	%		4,498,385		3	%
Non-operating income (expenses):		(1,866,533	)		255,310	n.	m.		(210,055	)	n.	m.
Income before income tax		7,065,304			4,891,142	44	%		4,288,330		14	%
Income tax:		1,885,512			1,499,769	26	%		1,034,574		45	%
Net Income	$	5,179,792		$	3,391,373	53	%	$	3,253,756		4	%

______________

n.m.= Not meaningful

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The following discussion is based on information contained in our audited consolidated financial statements and should be read in conjunction therewith. Our consolidated financial statements have been prepared in accordance with Colombian Government Entity GAAP, which differs in certain material respects from U.S. GAAP. See Note 33 to our consolidated financial statements for a description of the principal differences.

The following table sets forth our principal sources of revenue for the years ended December 31, 2007, 2006 and 2005.

	For the year ended December31,						For the year ended December 31, 2005
	2007		2006		2007/2006 % change				2006/2005 % change
Production Segment:(1)	(Pesos inmillions)						(Pesos inmillions)
Crude oil:
Local sales(2)	3,004,629		29,825		n.	m.	7,286		n.	m.
Other Income from local sales of crude oil (3)	116,020		133,815		(13	)%	83,914		59	%
Export sales	4,476,137		3,670,080		22	%	3,057,929		20	%
Total sales of crude oil	7,596,786		3,833,720		n.	m	3,149,129		22	%
Natural Gas:
Local sales	660,171		717,879		(8	)%	509,693		41	%
Other income from local sales of natural gas(4)	67,085		65,701		2	%	72,022		(9	)%
Export sales	37		—		—		—		—
Total sales of natural gas	727,293		783,580		(7	)%	581,715		35	%
Total production segment sales	8,324,079		4,617,300		n.	m.	3,730,844		24	%
Refining segment:
Refined Products:
Local sales(5)	11,517,000		9,757,734		18	%	8,292,457		18	%
Sales of refined products allocated to our production segment(6)	(94,734	)	(101,310	)	(6	)%	(74,420	)	36	%
Other income from local sales of refined products(7)	49,646		26,804		85	%	2,088		n.	m.
Export sales	2,156,388		4,194,044		(49	)%	3,472,774		21	%
Total refining segment sales:	13,628,300		13,877,272		(2	)%	11,692,899		19	%
Transportation segment:
Transportation sales	695,268		685,871		1	%	684,403		—
Sales of transportation services allocated to our production and refining segment	(17,330	)	(19,376	)	(11	)%	(29,076	)	(33	)%
Total transportation sales	677,938		666,495		2	%	655,327		2	%
Other sales(8)	139,187		108,693		28	%	57,765		88	%
Adjustment to other sales(9)	(120,687	)	(105,635	)	14	%	(54,528	)	n.	m.
FAEP	(316,497	)	(774,160	)	(59	)%	(569,405	)	36	%
Total sales	22,332,320		18,389,965		21	%	15,512,903		19	%

______________

n.m.=Not meaningful.

(1) Corresponds to sales of crude oil, natural gas and refined products to third parties excluding intergroup sales.

(2) Includes Ps$2,917,378 million sales of crude oil to the Cartagena refinery since April 2007.

(3) Corresponds to sales of refined products, transportation services and industrial services allocated to our production segment.

(4) Corresponds to sales of refined products, transportation services and industrial services allocated to our production segment.

(5) Prior to 2007 we were not reimbursed by the Government for motor fuel subsidies. Includes motor fuel subsidy reimbursements amounting to Ps$1,778,050 million by the Government in 2007.

(6) Corresponds to sales of refined products from our Apiay and Orito refineries allocated to our production segment.

(7) Corresponds to sales of transportation services and industrial services allocated to our refining segment.

(8) Includes insurance premiums and sales of industrial services in Colombia.

(9) Corresponds to sales of industrial services allocated to our production segment.

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Total Revenues

Total revenues increased by 21% in 2007 compared to 2006 mainly due to higher exported volumes of crude oil, sales of crude oil to the Cartagena refinery that began in April 2007, and the increase in average sales prices for crude oil of approximately 21%, partially offset by lower sales of refined products as we no longer record the sales of refined products by the Cartagena refinery as we do not consolidate Refinería de Cartagena S.A. The 19% increase in total revenues in 2006 compared to 2005 was due to an increase in sales volumes of crude oil, natural gas and refined products, and a 16% increase in average sales price for crude oil, a 14% increase in average sales price of refined products and a 28% increase in average sales price of natural gas in 2006 compared to 2005.

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The following table sets forth our export and local sales of crude oil, natural gas and refined products for the years ended December 31, 2007, 2006 and 2005.

	For the year ended December31,		2007/2006 % change		For the year ended December31,	2006/2005 % change
	2007	2006			2005
Crude oil:
Local sales (barrels)(1)	20,859,714	333,003	n.m.		131,174	n.m.
Export sales (barrels)	34,724,093	29,056,837	20	%	28,493,379	2	%
Average price per local barrel (in U.S. dollars)	69.30	37.98	82	%	23.93	59	%
Average price per export barrel (in U.S. dollars)(2)	62.02	53.57	16	%	46.24	16	%
Weighted average price per local and export barrel (in U.S. dollars)	64.76	53.39	21	%	46.14	16	%
Natural gas:
Export sales (mbtu)(3)	6,555	—	n.m.		—	—
Local sales (mbtu)	160,056,709	148,977,334	7	%	138,248,249	8	%
Average local price (mbtu) (in U.S. dollars)	1.98	2.04	(3	)%	1.59	28	%
Refined products:
Export sales (barrels)	19,335,063	34,401,773	(44	)%	33,228,754	4	%
Product local sales (barrels)	71,191,548	79,635,684	(11	)%	78,383,037	2	%
Average export price per barrel (U.S. dollars)	53.66	51.7	4	%	45.03	15	%
Average local price per barrel (U.S. dollars)	65.82	51.96	27	%	45.59	14	%

______________

n.m. = Not meaningful.

(1) Starting in April 2007, we started recording crude oil sales to the Cartagena refinery, an affiliated entity.

(2) Amounts stated in U.S. dollars have been translated at 2,078.35 for 2007, 2,357.98 for 2006 and 2,320.77 for 2005.

(3) We initiated exports of natural gas to Venezuela in the third quarter of 2007.

Production segment sales

Crude oil

Local sales

Our local sales in 2007 reflect the recognition of sales of crude oil to the Cartagena refinery. Prior to April 2007 we did not have meaningful local sales of crude oil.

Export Sales

The increase in revenues in 2007 compared to 2006 from exports of crude oil including revenues deposited in the FAEP was due to a 20% increase in export volumes and a 16% increase in export prices, which in turn was partially offset by a 12% average appreciation of the Peso against the U.S. dollar. The increase in revenues from the export of crude oil in 2006 compared to 2005, was attributable to a 2% increase in exported volume and a 16% increase in average prices.

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Natural gas

Export Sales

Our export sales of natural gas reflect the beginning of sales of natural gas to Venezuela in 2007. Prior to 2007, we did not export any natural gas.

Local sales

The decrease in revenues in 2007 from local sales of natural gas was attributable to a 3% decrease in local prices for natural gas as a result of prices for natural gas from the La Guajira field being regulated and tied to the average fuel oil export price for the prior six months, (which for the last six months of 2006 was relatively depressed), offset by a 7% increase in local sales volumes. The increase in revenues from local sales of natural gas in 2006 compared to 2005 was due to an increase in volume resulting from the growth of local demand as well as an increase in average prices of natural gas due to higher average fuel oil export prices.

Refining segment sales

Export Sales

The decrease in revenues from export of refined products in 2007 as compared to 2006 was due to our transfer of the Cartagena refinery as a result of which we no longer record the sales of products from the refinery, which was offset in part by a 4% increase in average export prices. The increase in revenues from the export of refined products in 2006 compared to 2005 was attributable to the increase in average sales prices and increase in exported volumes. Both periods reflect the increase in international average prices and the improvement in the product slate from the Barrancabermeja refinery.

Local sales

Revenue from local sales of refined products in 2007 as compared to 2006 increased as a result of higher average sales prices resulting from an increase in international oil prices, reimbursement of the motor fuel subsidy by the Government and an improvement of our product slate from the Barrancabermeja refinery, partially offset by lower volumes resulting from us no longer recognizing as of April, sales of the Cartagena refinery. The increase in revenue in 2006 compared to 2005 was attributable to a14% increase in average local prices resulting from higher international oil prices and an improvement in our product slate, and to a 2% increase in volume sold.

Transportation segment sales

Revenues from transportation activities increased as a result of higher volumes transported and an increase in average tariffs for crude oil and natural gas pipelines. Revenues from the transportation segment for 2006 compared to 2005 remained stable as transported volumes did not vary significantly.

Cost and Expenses

The following table sets forth elements of our cost of sales, operating expenses and operating income for the years ended December 31, 2007, 2006 and 2005.

	At December31,		2007/2006 % change		At December 31, 2005	2006/2005 % change
	2007	2006
	(Pesos inmillions)				(Pesos inmillions)
Cost of sales	12,058,527	12,756,563	(5	%)	10,095,542	26	%
Operating expenses	1,341,956	997,570	35	%	918,976	9	%
Operating Income	8,931,837	4,635,832	93	%	4,498,385	3	%

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Cost of sales—consolidated

As a result of our two-step transformation process and the increase in international prices for crude oil, our costs of sales have been affected by a number of factors. The most important factors are described below:

• Cost of sales of contributions in kind decreased as a result of no longer being required to record as a cost of sales our production of reserves (other than from reverted concessions). Cost of sales of contributions in kind in 2006 compared to 2005 increased as a result of higher production of reserves resulting in a higher cost of sales recorded and higher contributions to capital from the Nation.

• Purchases of hydrocarbons from the ANH in 2007 as compared to 2006 increased to Ps$3,912,315 million as a result of higher average prices on a similar number of barrels purchased. Purchases of hydrocarbons from the ANH in 2006 compared to 2005 increased to Ps$3,676,374 million for the same reason.

• Purchases of crude oil from our business partners increased during 2007 to Ps$1,513,683 million as a result of higher volume purchased to meet existing supply obligations, which amounted to 12.9 million barrels in 2007 compared to 10.3 million barrels in 2006 and increases in average prices for crude oil. The decrease in costs from purchases of crude oil from our business partners in 2006 compared to 2005, were due to lower purchase volumes which amounted to Ps$922,825 million in 2006 offset in part by higher average crude oil prices.

• Purchases of natural gas and other products increased during 2007 to Ps$203,697 million as a result of our obligation to supply natural gas to our long-term purchasers, including gas-fired power generators and distributors, and to purchases of refined products from the Cartagena refinery, which we accounted for as intersegment sales prior to April 2007. Increases in costs related to purchases of natural gas and other products in 2006 compared to 2005 were due to purchases of natural gas to meet supply commitments with our customers and to an increase in the price of purchases of refined products to load and feed the refineries.

• Services contracted with associations, which are pro rata expenses for our joint ventures, increased to Ps$1,019,043 million in 2007 as a result of an increase in exploration activities, work-over activities, and maintenance programs for production fields and increases in the price of oil services as a result of a worldwide increase in demand for oil services. In 2006 compared to 2005, joint venture expenses increased to Ps$718,881 million as a result of higher prices for oil services.

• Labor costs in 2007 as compared to 2006 increased as a result of increases in wages, labor benefits and bonuses paid as part of our personnel retention policies. Labor costs in 2006 compared to 2005 increased as a result of inflation adjustments.

Principal elements of our cost of sales by business segments are as follows:

Production segment’s cost of sales

Cost of sales affecting our production segment are mainly cost of sales of contributions in kind which correspond to the cost recorded by us for every barrel produced prior to March 2007, purchases of crude oil and natural gas volumes from the ANH, purchases of crude oil and natural gas from other oil companies to meet our supply commitments and services contracted with joint venture partners. Our production segment’s cost of sales are also affected by the depreciation and amortization of production assets and the depletion of hydrocarbon reserves that have reverted to us from concessions.

Refining segment’s cost of sales

Cost of sales affecting our refining segment are primarily for the purchase of crude oil and natural gas to upload and feed the refineries, services contracted for the maintenance of the refineries, and amortization and depreciation of refining assets.

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Transportation segment’s cost of sales

Cost of sales affecting our transportation segment are: depreciation and amortization of our transportation assets and project costs, which relate to costs associated with the maintenance of transportation networks and conversion of existing pipelines to the transportation of heavy crude oil.

Operating expenses

Our operating expenses increased in 2007 compared to 2006, while they increased in 2006 compared to 2005, as a result of the following factors:

• Studies and projects in 2007 compared to 2006 and compared to 2005 increased as a result of higher maintenance expenses for production projects and accounting for dry wells and exploration costs.

• Oil pipeline transportation tariff payments increased in 2007 compared to 2006 as a result of higher volume transported and maintenance of back-up product pipelines, offset in part by a decrease in tariffs.

Our operating expenses by business segments increased in 2007 compared to 2006, and in 2006 compared to 2005. Such expenses by business segment are described below.

Exploration segment’s operating expenses

Operating expenses affecting our exploration segment are primarily for studies and projects, which correspond to expensing dry wells and labor expenses in connection with salaries and benefits paid to personnel assigned to our exploration segment.

Production segment’s operating expenses

Operating expenses affecting our production segment are related to depreciation and amortization of assets dedicated to production activities, studies and projects relating to production of crude oil and natural gas and labor expenses relating to salaries and benefits paid to personnel assigned to our production segment.

Refining segment’s operating expenses

Operating expenses affecting our refining segment are primarily for labor expenses relating to salaries and benefits paid to personnel assigned to our refining segment.

Transportation segment’s operating expenses

Operating expenses affecting our transportation segment are primarily for transportation tariffs paid in connection with crude oil and natural gas transportation and labor expenses relating to salaries and benefits paid to personnel assigned to our transportation segment.

Non-operating income (expenses)

	For the year ended December31,
	2007		2006		2005
	(Pesos in millions)
Non-operating income(expenses):
Financial income, net	93,628		683,436		1,532,212
Pension expenses	(1,090,343	)	(829,191	)	(765,504	)
Inflation gain	41,132		56,166		58,961
Other income (expenses), net	(910,950	)	344,899		(1,035,724	)

Financial income, net. Financial income, net, includes foreign exchange gains, valuation of investments, dividends received and profit from sale of investments, decreased during the last three years as a result of our holding a large portion of our investments in U.S. dollar denominated securities. The yield on these securities decreased as a result of the reduction of interest rates in the United States. Financial income was negatively impacted by appreciation of the Peso against the U.S. dollar during the last three years.

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decreased as a result of the reduction of interest rates in the United States. Financial income was negatively impacted by appreciation of the Peso against the U.S. dollar during the last three years.

Pension expenses. Pension expenses increased by 31% in 2007 compared to 2006, principally due to an increase of 5.69% in monthly pension payments; salary increases of 6.53% (pension benefits are affected by salary levels) and increases in health services per beneficiary of 22% as this service was contracted with a third-party in 2007while it was provided internally in 2006. Pension expenses increased by 8% in 2006 compared to 2005 principally due to increases in salaries of 5.04% and increases in education services per beneficiary of 18.9% as we started to contract third parties to provide education services that were formerly provided directly by us.

Other income (expenses), net. Other income (expenses), includes of BOMT expenses, recovery of provisions, other revenues and other recoveries. Other expenses include legal and other provisions and taxes unrelated to income.

Other income (expenses) decreased in 2007 to reflect expenses incurred during the year compared to income in 2006 mainly due to higher provisions for legal proceedings as a result of a new accounting rule issued by CGN which provided that a provision was to be recorded for a contingent event if the outcome was considered to be probable. The term probable, as used in the rule, has been interpreted in practice under Colombian Government Entiy GAAP to mean more-likely-than-not. As a result, the provision for legal processes included in Estimated Liabilities and Provisions was increased by Ps$951,158 million during 2007 to reflect the implementation of the new rule. Prior to September 5, 2007, under Colombian Government Entity GAAP, a provision was recorded for a contingent event at the time a judgment was issued against us, without reference to the evaluation of the outcome. The principal portion of the increase related to contingencies that were in existence at the date of the rule change. See Note 28 to our consolidates financial statements.

Other income (expenses) increased in 2006 compared to 2005 as a result of higher recoveries of deferred tax provisions related to fiscal inflation adjustments which are no longer required since 2006. In addition, the provision for pension liabilities calculated in 2005 in accordance with Decree 941 of 2002 and Decree 2210 of 2004, for a total amount of Ps$878,336 million was 83% accounted for during 2005 and the remaining 17% during 2006.

Income before income tax

Income before income taxes increased by 44.5% in 2007, compared to 2006, and by 14.1% in 2006 compared to 2005, as a result of higher revenue without a comparable increase in cost of sales and operating expenses due to the ceasing of accounting for cost of sales of contributions in kind in 2007.

Income tax

The effective income tax rate for 2007 was 26.7%, compared to 30.7% in 2006 and 24.1% in 2005. Our effective tax rates were lower than the statutory rate as a result of tax benefits related to an income tax deduction equal to 30% of all capital expenditures in 2005 and 2006 that was increased to 40% in 2007.

Net Income

As a result of the foregoing, net income increased by 52.7% in 2007, compared to 2006, and by 4.2% in 2006 when compared to 2005.

Principal differences between Colombian Government Entity GAAP and U.S. GAAP

We prepare our financial statements in accordance with Colombian Government Entity GAAP. These principles and regulations differ in certain significant respects from U.S. GAAP. The following is a description of the most relevant differences between Colombian Government Entity GAAP and U.S. GAAP. Note 33 to our consolidated financial statements presents reconciliations of net income and shareholders’ equity determined under Colombian Government Entity GAAP to those same amounts as determined according to U.S. GAAP, as well as a complete description of the differences between the two accounting standards. The principal differences between Colombian Government Entity GAAP and U.S. GAAP are as follows:

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FAEP

Under Colombian Governmental Entity GAAP, contributions to FAEP were recorded as increases to deferred income and an asset account for the same amount. No revenue was recognized for contributions to FAEP. Distributions from the FAEP to us were recorded as ordinary revenue with corresponding decreases in the deferred income and the FAEP asset accounts.

Under U.S. GAAP, the FAEP amount is recognized as current income and not as deferred income. U.S. GAAP requires us to recognize the FAEP as revenue even though it was a Government savings program with the purpose of maintaining macro-economic stability in the country. Therefore, the amounts recognized as current income under U.S. GAAP had the effect of increasing retained earnings and when the distribution of the amounts deposited in the FAEP was made by us to the Government in August 2007, for U.S. GAAP purposes, the distribution was treated as a dividend payment to the sole shareholder.

Advances received from Ecogás for BOMT Contracts (Build, Operate, Maintain and Transfer)

Under Colombian Government Entity GAAP, payment obligations under the BOMT contracts were treated as equivalent to an operating lease. Under U.S. GAAP the obligations are treated as capital leases, and an asset and liability were recognized and payments under the BOMT contracts serve to reduce the liability and the asset is depreciated. Subsequently, we subleased the same asset to Ecogás, with the corresponding treatment of the payments receivable from Ecogás as direct financing lease for U.S. GAAP purposes.

Contributions in kind

Under Colombian Government Entity GAAP, contributions of the Nation in kind (the produced reserves) pursuant to Decree 2625 of 2000 were recognized as a cost of production during the years Decree 2625 was in force and a contribution to equity. Under U.S. GAAP, costs associated with these contributions were reversed to reflect retained earnings that were later distributed to the Nation as a stock dividend.

Reversal of concessions

Under Colombian Government Entity GAAP, we recorded an asset for the contributions of the Nation of crude oil and natural gas reserves deriving from the reversal of concessions of oilfield areas in favor of the Nation, given before the effectiveness of Decree 1760 of 2003. Reserves were valued by means of the technical-economic model where the value per barrel resulted from the relation of the net present value obtained at a discount rate and the total proved reserves on the contribution date. For U.S. GAAP purposes, these reversions were considered a transfer of assets between entities under common control. Ecopetrol as the entity that received the net assets, should have initially recognized the assets transferred at their carrying amounts in the accounts of the transferring entity at the date of transfer, which in this case is zero as the transferring entity did not recognize a carrying value.

Reserves

The estimate for reserves at December 31, 2007 was prepared under our existing policy, using average prices for 2007, which is acceptable in Colombia but not under U.S. GAAP, which requires the calculation of reserves using year-end prices. As a result, the quantity of estimated proved reserves under our existing policy differs from the estimated quantities of proved reserves in accordance with U.S. GAAP and SEC Rule 4-10 of Regulation S-X. The main differences between our existing policy and U.S. GAAP are presented in Note 33 to our consolidated financial statements.

Effects of inflation on financial Information

The accompanying consolidated financial statements have been prepared from the accounting records, which are maintained under the historical cost convention, modified since 1992 to comply with the legal provisions of the CGN to recognize the effect of inflation on non-monetary balance sheet accounts until December 31, 2001, including equity. The CGN authorized us not to apply the inflation adjustment system from January 1, 2002 onwards. The accumulated inflation adjustments were eliminated in the process of reconciling our financial statements to U.S. GAAP.

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Valuation surplus

Under Colombian Government Entity GAAP, property, plant and equipment are revalued every three years in accordance with market value and the investments in unconsolidated investees are revalued by using the equity intrinsic value (percentage of ownership of the company in the equity of the investee). The excess of these amounts over the carrying amount is treated as valuation surplus with a corresponding amount in equity (valuation surplus). Revaluation of these assets is not done for purposes of U.S. GAAP.

Variable interest entity

Under Colombian Government Entity GAAP consolidation with significant subsidiaries is required when there is control by having more than 50% ownership or majority of the voting rights in the subsidiary. Under U.S. GAAP (FIN 46(R)) if an entity has variable interests whereby one party absorbs losses or benefits from net profits in excess of its ownership interest then those variable interests must be evaluated. Under this analysis Ocensa represents a variable interest entity of which we are the primary beneficiary and therefore we are required to consolidate it in our financial statements for U.S. GAAP purposes. See Note 33 to our consolidated financial statements for a description of our analysis.

Equity method accounting

Under Colombian Government Entity GAAP, equity method is only applied when control exists. Under U.S. GAAP, equity method is required for investments where significant influence exists (generally ownership higher than 20%) but the investment is not controlled.

Employee benefit plans

There are significant differences in measurement of expense and balance sheet amounts for employee benefit plans between Colombian Government Entity GAAP and U.S. GAAP. See Note 33 to our consolidated financial statements.

 

ITEM5B Liquidity and Capital Resources

History

Prior to our corporate transformation and initial public offering, the Government limited our capital expenditure program and access to the credit markets as it was making decisions for us based on its own budgetary needs and concerns and not on the growth prospects of the Company. Furthermore, we were required to make macroeconomic stabilization payments to the FAEP, which negatively affected our cash flow from the export of crude oil. As a result of our sale of shares to private investors, we became a mixed economy company, which provides us budgetary autonomy and access to credit markets.

Liquidity

Our principal sources of liquidity in 2007 were cash flow from operations amounting to Ps$9,404,810 million. In addition, we sold shares for Ps$5,722,813 million in our initial public offering in Colombia conducted during the third quarter of 2007 of which Ps$4,867,951 million was paid to us in November and December. The remaining Ps$854,862 million will be paid during the first eleven months of 2008 as these correspond to shares bought by investors pursuant to the installment option offered by us. Our principal uses of liquidity in 2007 were Ps$3,036,962 million in capital expenditures, which include investments in natural and environmental resources and reserves, and additions to property, plant and equipment, and dividend payments for the fiscal year 2006 of Ps$4,475,399 million. The proceeds from our initial public offering and available cash amounting to Ps$5,028,945 million are held in portfolio investments.

In 2008, major cash needs include planned capital expenditures amounting to approximately Ps$8,698,536 million, of which Ps$1,511,433 million correspond to exploration activities and acquisition of reserves, Ps$3,943,863 million correspond to production activities, Ps$1,927,233 million correspond to refining activities, Ps$1,101,870 million for transportation activities, Ps$214,137 million for other capital expenditures and Ps$4,654,339 million for dividend distributions. In addition, we use cash to finance the Government’s motor fuel

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subsidy program for which the Government reimburses us in cash. We believe our cash flow from operations, and the proceeds from our initial public offering, will allow us to meet our existing and anticipated working capital and capital expenditure requirement for the next two to three years.

Use of Funds

Capital Expenditures

The following table sets forth our consolidated capital expenditures for each of our business segments for 2007, 2006 and 2005.

	For the year ended December31,
	2007	2006	2005
	(Pesos inmillions)
Exploration & production	2,678,684	1,309,361	678,940
Refining and Petrochemicals	234,462	435,498	268,623
Transportation	92,344	72,765	274,352
Corporate	31,472	45,310	32,229
Total	3,036,962	1,862,934	1,254,144

Our 2008-2015 budget capital expenditure is approximately US$57.7 billion distributed by business segment. See Item 4B—”Business Overview — Strategy”.

We plan to meet our budgeted capital expenditures for the next two to three years primarily through existing cash at hand and cash from operating activities and from the proceeds of our equity offering made in November 2007. For the remaining years, we expect to access local and international financial markets to fund part of our capital expenditures and we may decide to access equity markets through the issue of an additional 9.9% of our equity as authorized by law 1118 of 2006.

Cash from operating activities

Net cash provided by operating activities increased by 54.8% in 2007 compared to 2006 and by 63.9% in 2006 compared to 2005 as a result of an 80.3% and a 23.8% increase in sales of crude oil and natural gas in 2007 and 2006, respectively as a result of an 82% and 59% increase in the export price of crude oil in 2007 and 2006, offset in part by a decrease in yields from financial investments resulting from interest rate cuts by the US Federal Reserve Bank.

Cash used in investing activities

Net cash used in investing activities increased in 2007 compared to 2006 and to 2005 as a result of the need to finance our exploration and production activities necessary to maintain our current crude oil production levels. We invested heavily in 2007 in the development of mature fields and drilling campaigns.

Cash used in financing activities

Net cash provided in financing activities increased in 2007 compared to 2006 as a result of our initial public offering in Colombia, offset by the dividend payment to our shareholder. Net cash used in financing activities in 2006 compared to 2005 increased by 40.3% due to a 54% increase in dividend payments.

Dividends

In 2007, we paid dividends of Ps$4,475,399 million to the Nation. On March 27, 2008, our ordinary general shareholders’ meeting approved dividends for the fiscal year ended December 31, 2007, amounting to Ps$4,654,339 million, or Ps$115.00 per share, based on the number of outstanding shares at such date December 31, 2007. Dividends declared will be paid in four installments. The first payment will be made between April 25 and

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the April 30, the second dividend payment will be made between July 25 and July 30, the third dividend payment will be made between October 25 and October 30, and the last dividend payment will be made between December 19 and December 24.

 

ITEM5C Research and Development, Patents and Licenses, etc.

Our research and development activities are conducted by the Instituto Colombiano de Petróleos or the Institute, our research and development unit. Our activities are focused on developing technology solutions for us and the Colombian oil industry, and development of technical tests and analyses to evaluate our business. Our research and development increased during the last three years to approximately Ps$65 billion in 2007, from approximately Ps$54 billion in 2006 and approximately Ps$46 billion in 2005.

The Institute has 29 locations and 21 research and development laboratories. During 2007 our research and development laboratories rendered services to other companies including Shell, British Petroleum, Exxon Mobil as well as the ANH.

We currently own 17 patents in Colombia, United States, Venezuela, Ecuador and Brazil. One of our most significant patents is an anti-theft patent which allowed us to reduce fuel oil and crude oil theft by 46% in 2007 when compared to 2006. Most of our patents will expire between 2015 and 2017.

 

ITEM 5D Trend Information

See Item 5 — “Operating and Financial Review and Prospects — Overview”

 

ITEM5E Off-Balance Sheet Arrangements

Under Colombian Government Entity GAAP we do not have any off-balance sheet arrangements. Under U.S. GAAP Oleoducto Central S.A. is a variable interest entity pursuant to FIN 46 and has been included in our consolidated results. See Note 33 to our consolidated financial statements for a description of our treatment of Oleoducto Central S.A. under U.S. GAAP.

 

ITEM5F Tabular Disclosure of Contractual Obligations

Contractual Obligations

We enter into various commitments and contractual obligations that may require future cash payments. The following table summarizes our commitments and contractual obligations at December 31, 2007.

	Payments due by period
	Total	Less than 1 year	1-3 years	3 to 5 years	More than 5 years
Contractual Obligations:	(Pesos in millions)
Pension Plan Obligations(1)	13,697,951	508,813	1,136,871	1,227,560	10,824,707
Contract Service Obligations	2,136,980	1,316,071	593,057	74,153	153,699
Operating Lease Obligations	39,091	19,115	11,133	2,527	6,316
Natural Gas Supply Agreements	665,586	163,731	323,804	169,561	8,489
Oil Transport Agreements	19,483	8,599	10,884	—	—
Energy Supply Agreements	205,527	135,291	26,333	16,609	27,293
Capital expenditures	2,825,704	1,505,406	735,005	168,048	417,245
Build, Operate, Maintain and Transfer contracts (BOMT)	1,184,482	197,997	354,782	222,812	408,891
Capital (Finance) Lease obligations	7,684	5,985	1,698	—	—
Total	20,782,487	3,861,009	3,193,566	1,881,270	11,846,641

______________

(1) Schedule payments for the next 20 years.

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Critical accounting policies and estimates

The following discussion sets forth our critical accounting policies. Critical accounting policies are those policies that require us to exercise the most judgment or involve a higher degree of complexity in the application of the accounting policies that currently affect our financial condition and results of operations. The accounting estimates we make in these contexts require us to calculate variables and make assumptions about matters that are highly uncertain. In each case, if we had made other estimates, or if changes in the estimates occur from period to period, our financial condition and results of operations could be materially affected. This information should be read together with Note 1 to our consolidated financial statements for a summary of the economic entity and principal accounting policies and practices. There are many other areas in which we use estimates about uncertain matters, but the reasonably likely effect of changed or different estimates is not material to our financial presentation.

Oil and gas reserves

When accounting for our reserves we use a similar method to the internationally recognized “successful efforts” method of accounting for investments in exploration and production areas. These investments are amortized using the technical units-of-production method on the basis of proved developed reserves by field. The reserves are based on technical studies prepared internally by our Department of Reservoirs and approved by our reserves committee, which follow estimation methodologies recommended by international organizations of specialists in hydrocarbon reserves and that in accordance with their certification meet the guidelines followed by the SEC.

Oil and gas reserves are divided between proved and unproved reserves. Proved reserves are estimated quantities of crude oil, natural gas and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved reserves can also be divided in two categories: developed and undeveloped. Developed proved reserves are expected to be recovered from existing wells including line pack, or when the costs necessary to put them in production are relatively low. For undeveloped proved reserves, significant investments are necessary, including drilling new wells and installing production or transportation facilities.

The estimation of hydrocarbon reserves is subject to several uncertainties inherent to the determination of proved reserves, production recovery rates, the timeliness with which investments are made to develop the reservoirs and the degree of maturity of the fields.

Under Colombian Government Entity GAAP we use the average WTI reference price for the year to estimate our total reserves. Required investments are based on technical and financial conditions for the field at the time reserves are estimated. For U.S. GAAP purposes, we used the WTI year end price.

Crude oil prices have traditionally fluctuated as a result of a variety of factors such as 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, economic conditions, development of new technologies, economic and political events, and local and global demand and supply. For example, during 2007, the price of crude oil rose by approximately 55%.

Revisions to proved reserves estimates of crude oil and gas and the effect of such price variations are presented in note 33. xxvii to our consolidated financial statements. Changes in the crude oil price may affect our estimates in the future.

The calculation of units-of-production depreciation and depletion is a critical accounting estimate that measures the depreciation and depletion of upstream assets. The units of production are equal to the ratio of actual volumes produced to total proved developed reserves (those proved reserves recoverable through existing wells with existing equipment and operating methods) and applied to our asset cost.

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Financial derivative instruments

Occasionally we enter into hedging agreements to protect our exposure from the fluctuations of international crude prices. The difference between amounts paid and income received under hedging operations is recognized as financial income/expense. We do not enter into hedging contracts for speculative purposes.

Under Colombian Government Entity GAAP, our estimates are based on current spot prices subject to market variations. The difference between our estimates and current payments have been immaterial. We do not foresee material variations in the near future that may significantly impact our financial condition or results of operations. Our transactions with financial derivatives have not been significant during the last three years.

Under U.S. GAAP, we used fair values to measure our financial derivative instruments. Fair values were based on market quotes. There have not been material variations between fair values that have impacted significantly our financial condition or operating performance in the past.

Pension plans and other retirement benefits

The determination of the expense and liability relating to our pension and other retirement benefits require us to use judgment in the determination of actuarial assumptions. These include active employees with indefinite term contracts, retirees and their heirs, pension benefits, healthcare and education expenses; number of temporary employees who will remain with us until retirement, voluntary retirement plans and pension bonuses. The calculation of retirement bonds posted by us to meet our pension obligations is regulated by Decrees 1748 of 1995, 1474 of 1997 and 876 of 1998, as well as Law 100 of 1993 and its regulatory decree.

These actuarial assumptions include estimates of future mortality, withdrawal, changes in compensation and discount rate to reflect the time value of money as well as the rate of return on pension bonds and other plan assets. These assumptions are reviewed at least annually and may differ materially from actual results due to changing market and economic conditions, regulatory events, judicial rulings, higher or lower withdrawal rates or longer or shorter life spans of participants.

Most of our assumptions have been based on historical trends. Actuarial gains and losses a result of differences between estimates and actual calculations and differences between U.S. GAAP and Colombian Government Entity GAAP are disclosed in note 33. vii to our consolidated financial statements. Changes in interest rates and amendments to plan conditions have affected prior estimates. We believe that the assumptions used in recording our obligations under the plans are reasonable based on our experience and market conditions.

Litigation and tax assessments

We are subject to claims for substantial amounts, regulatory and arbitration proceedings, tax assessment and other claims arising in the normal course of business. Management and legal counsel evaluate these situations based on their nature, the likelihood that they materialize, and the amounts involved, to decide on any changes to the amounts accrued and/or disclosed. This analysis includes current legal processes against the company and claims not yet initiated. In accordance with management’s evaluation and guidance provided by Colombian Government Entity GAAP, we created reserves to meet these costs when it is probable that a liability has been incurred and reasonable estimates of the liability can be made. At December 31, 2007, we had created a provision of 1,329,118 million for litigation contingencies. We also maintain insurance policies to cover specific operational risks and asset protection.

Estimates are based on legal counsel’s evaluation of the cases and management’s judgment. In the past our estimates have been accurate and have not varied substantially compared to final judgments. We believe that payments required to settle the amounts related to the claims, in case of loss, will not vary significantly from the estimated costs, and thus will not have a material adverse effect on our results of operations or cash flows. Litigation and tax assessment differences between U.S GAAP and Colombian Government Entity GAAP are disclosed in note 33 to our consolidated financial statements.

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Income taxes are accounted for under the assets and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the carrying amounts of existing assets and liabilities in the financial statements and their respective tax base. Deferred taxes on assets and liabilities are calculated based on statutory tax rates that we believe will be applied to our taxable income during the years in which temporary differences between the carrying amounts are expected to be recovered.

Abandonment of fields

We are required by law to remove equipment and restore the land or seabed at the end of operations at production sites. To estimate this obligation, we use estimation to include plugging costs and abandonment of wells, dismantling of facilities and environmental recovery of areas and wells. Changes resulting from new estimates of the liability for abandonment can occur as a result of changes in economic conditions. We accrue the estimated discounted costs of dismantling and removing these facilities at the time of installation of the assets. The related liability is estimated in foreign currency and is adjusted for exchange difference at the end of each year.

We use economic factors from different sources and develop our own internal estimates of future inflation rates and discount rates. There have not been significant disparities between estimates and asset retirement costs paid. We believe that the assumptions used in recording our asset retirement costs and obligations are reasonable based on our experience and market conditions.

Differences between U.S GAAP and Colombian Government Entity GAAP are disclosed in note 33. xvii.

 

ITEM5G Safe Harbor

See — “Forward Looking Statements.”

 

ITEM5H Recent U.S. GAAP Pronouncements

For a discussion see Note 33 to our consolidated financial statements on recent U.S. GAAP pronouncements.

 

ITEM6 Directors, Senior Management and Employees

 

ITEM 6A Directors and Senior Management

The information below sets forth the names and business experience of each of our Directors, officers and senior management, as of the date hereof.

Directors of Ecopetrol

The following are our current Directors as elected at the shareholders’ meeting held on March 27, 2008:

Hernan Martínez (66) has been a member of our Board of Directors since September 25, 2006. Mr. Martinez has served as Minister of Mines and Energy of Colombia since 2006. Prior to holding this position, Mr. Martinez worked as Manager of Corporate Planning for Esso Colombiana S.A.; President of International Colombia Resources Corporation; President of Exxon Mobil Colombia S.A., and as representative of the President of Colombia before the ANH. He has been a member of various Boards of Directors, including Carton Colombia S.A., Empresa de Interconexión Eléctrica S.A. ESP, Transmisión Eléctrica S.A. and Inversura S.A. Mr. Martinez earned a degree in chemical engineering from Universidad Pontificia Bolivariana and obtained a specialization degree in petroleum management from Northwestern University. Mr. Martinez was appointed as a director by the Nation.

Oscar I. Zuluaga (49) has been a member of our Board of Directors since March 26, 2007. Mr. Zuluaga has served as Minister of Finance of Colombia since 2007. From 1988 to 1990, Mr. Zuluaga was a member of the Council of Pensilvania (Caldas-Colombia), and in 1990 became the Mayor of this municipality. He served in the Senate of Colombia from 2002 to 2004. He is a founding member of the “U” Political Party, and served as the Advisor Minister for the Office of the President of Colombia in 2006. Mr. Zuluaga was also a Vice-President and President of Acerías de Colombia S.A. from 1992 to 2001. Mr. Zuluaga has been a member of the Board of

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Directors of Fenalco or Federación Nacional de Comerciantes, Fedemetal, and the Colombo-Venezuelan Chamber of Commerce. Mr. Zuluaga earned a degree in economics from Pontificia Universidad Javeriana and a master’s degree in public finance from Exeter University, England. Mr. Zuluaga was appointed as a director by the Nation.

Carolina Rentería (41) has been a member of our Board of Directors since October 20, 2006. Mrs. Rentería has served as Director of the National Planning Agency of Colombia since 2006. Mrs. Rentería is currently an alternate governor before the World Bank and before the Inter-American Development Bank. She has worked for the Ministry of Finance and Public Credit and the Council for Tax Policies of Colombia. She has also held positions at Fedesarrollo or Fundación para la Educación Superior y el Desarrollo, the Inter-American Development Bank and the Colombian Central Bank. Mrs. Rentería has served as a member of the Board of Directors of the Andean Investment Association and the National Coffee Growers Committee and as chairman of the National Science and Technology Council. Mrs. Renteria earned a degree in economics and a master’s degree in development from Universidad de los Andes. She also obtained a master’s degree in public administration from New York University and is currently a Ph.D. candidate from said university. Mrs. Renteria was appointed as a director by the Nation.

Fabio Echeverri (75) has been a member of our Board of Directors since September 16, 2002. From 1957 to 1962, Mr. Echeverri worked as the President of Banco de Colombia and Banco Comercial Antioqueño. Since then, he has held various positions in the private and public sectors, serving as President of Siderurgica de Medellin, Director of ANDI (National Association of Industries), AILA (Latin American Association of Industries) and CONANDI (Andean Confederation of Industries), and as a member of the Inter-American Council of Commerce and Production, a position that he held for over 18 years. Mr. Echeverri is currently a member of the Board of Directors of the Shaio Clinic, Telecom-Colombia and Firogríficos Ganaderos de Colombia S.A. During his career, Mr. Echeverri has been a chairman of the Board of Directors of Fondo Ganadero de Antioquia; and chairman of the board of Siemens S.A., among others. Mr. Echeverri earned degrees in economics from Gimnasio Moderno and Universidad Jorge Tadeo Lozano. Mr. Echeverri was appointed as an independent director by the Nation.

Joaquin Moreno (59) has been a member of our Board of Directors since March 27, 2008. Mr. Moreno worked for 33 years for the Royal Dutch/Shell Group. He held various positions such as Project Manager in Colombia; Project and Operations Manager and Marketing and Operations Manager of Shell Química de Venezuela; Director of Marketing for agrochemical products and Global Marketing Manager for petrochemical products at Shell Centre–Shell International Chemicals Company in London; Director of Shell Venezuela S.A.; Director of Shell Colombia S.A. and Director of Cerromatoso S.A., and Strategic Planning Director for Exploration and Production in Europe and the Middle East at the Shell offices in the Netherlands. Mr. Moreno has also served as Country Chairman and President for Shell in Mexico, Colombia and Venezuela. Mr. Moreno has been a member of various Boards of Directors of local and international companies. Mr. Moreno earned a degree in civil engineering from Universidad Industrial de Santander and completed a program in advanced management at Harvard University. He was appointed as an independent director by the Nation.

Ignacio Sanín (60) has been a member of our Board of Directors since September 16, 2002. Mr. Sanín is currently the managing partner of the law firm Ignacio Sanín Bernal & Cia, Asociados. Mr. Sanín is a recognized professor of law having taught in various universities in Colombia at the undergraduate and postgraduate levels. Mr. Sanín earned a law degree and a degree in political science from Universidad Pontificia Bolivariana. He has completed postgraduate studies in commercial and tax law at the Polytechnic School, London School of Economics and King’s College in London. He obtained a master’s degree in private law and a master’s degree in commercial law from Universidad Pontificia Bolivariana. Mr. Sanín was appointed as an independent director by the Nation.

Maria E. Velásquez (51) has been a member of our Board of Directors since December 16, 2004. Mrs. Velásquez has served as Vice- President of Tecnocquimicas S.A. since February 2008. Prior to her current position, Mrs. Velásquez held the positions of Vice-President and President of Imusa S.A. from 2002 to 2007. She has also held positions in marketing at Andeco Ltda. and Diriventas Ltda. Mrs. Velásquez has been a member of various Boards of Directors including those of the Colombian-American Chamber of Commerce and the Chamber of Commerce of Medellin. Mrs. Velásquez earned a business degree from Universidad de Medellin and specialization degrees in marketing from Universidad EAFIT and management from Universidad de la Sabana. Mrs. Velásquez was appointed as an independent director by the Nation.

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Omar A. Baquero (56) has been a member of our Board of Directors since March 26, 2007. Mr. Baquero worked as a specialized engineer for the Ministry of Transportation of Colombia from 1980 to 1993 and served as Mayor of the city of Villavicencio from 1983 to 1985 and from 1988 to 1990. Mr. Baquero was also elected Governor of the State of Meta, a position that he held from 1992 to 1994. In 1998, Mr. Baquero was elected as Regional Representative to the Congress of Colombia where he worked until 2006. Mr. Baqueroearned a degree in civil engineering and a specialization degree in geopolitics from Universidad La Gran Colombia. In accordance with Law 1118 of 2006, Mr. Baquero was appointed by the Nation as an independent director representing the hydrocarbon producing departments of Colombia.

Mauricio Cárdenas (45) has been a member of our Board of Directors since March 27, 2008. Mr. Cárdenas has served as the executive director of Fedesarrollo (Fundación para la Educación Superior y el Desarrollo) since 2003. Mr. Cardenas served as President of Empresa de Energía de Bogota in 1993. He left this position to become the Minister of Economic Development of Colombia. He then worked as an investigator and executive director of Fedesarrollo. In 1998, Mr. Cárdenas was appointed the Minister of Transportation and later became the Director of the National Planning Agency of Colombia. Mr. Cárdenas was also a visiting professor for the Center of International Development at Harvard University from March to June 2001 and has held several positions as a researcher and professor at various universities. Mr. Cárdenas has served as a member of the Board of Directors of various organizations, including the Latin American and Caribbean Economic Association, LACEA, Universidad de los Andes and the BVC. Mr. Cárdenas has published various economic treatises, articles and research papers. Mr. Cárdenas earned a degree and a master’s degree in economics from Universidad de los Andes and later obtained a Ph.D. in economics from the University of California, Berkeley. In accordance with the Declaration of the Nation dated July 26, 2007, Mr. Cárdenas was appointed by the Nation as an independent director representing the ten largest minority shareholders.

None of our Directors, or executive officers has any family relationship with any other director or executive officer.

Officers and Senior Management of Ecopetrol

The following presents information concerning our executive officers and senior management.

Javier G. Gutiérrez (57) has served as our President and Chief Executive Officer since January 22, 2007. Prior to becoming our CEO, Mr. Gutiérrez served as CEO of Empresa de Interconexión Eléctrica S.A. ESP or ISA since 1992 where he started in the planning department in 1975. Mr. Gutiérrez also worked as Vice-President of the Colombian Commission for Regional Electric Integration from 1995 to 1997. In 2002, Mr. Gutiérrez received an award from the Portafolio economic journalas the “Best Enterprise Leader in Colombia”. In 2005 the América EconomíaJournal granted Mr. Gutiérrez an award of excellence, and in the same year La República, a renowned financial journal in Colombia, ranked Mr. Gutiérrez among Colombia’s top 10 executives. Mr. Gutiérrez earned a degree in civil engineering, a master’s degree in industrial engineering from Universidad de los Andes and a specialization degree in finance from Universidad EAFIT. Mr. Gutierrez has worked as a part-time professor of statistics and research at Universidad de los Andes and as a professor of operational research at Universidad EAFIT.

Adriana M. Echeverri (37)joined us in 1994, and has served as our Chief Financial Officer since September 2006. Prior to being appointed as our CFO, Mrs. Echeverri worked as Chief of the Finance and Treasury Unit from September 2003 to September 2006. She earned a degree in finance and foreign affairs and an MBA from Universidad Externado de Colombia.

Martha S. Serrano (52)joined Ecopetrol in 1988 and has served as the Secretary of the Board of Directors and as Chief to the Support Office of the Chief Executive Officer since 1990. Prior to joining us, Ms. Serrano worked in the legal department of the Superintendencia Bancaria, or Colombia’s former Banking Commission where she was Second Delegate Commissionaire. Ms. Serrano also served as the head of the legal department of the Superintendencia de Valores,or Colombia’s former Securities Commission. Mrs. Serrano earned a law degree from Colegio Mayor de Nuestra Señora del Rosario and a masters degree in financial law.

Nelson Navarrete (46) has served as our Exploration and Production Executive Vice-President since February 2008. Mr. Navarrete joined us in 1986. Prior to becoming our Exploration and Production Executive Vice-President, he held several positions within the operations department, such as Management Coordinator of the

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Cusiana oil field, Director of Reserves & Production, Regional Manager of fields located in the Piedemonte, and Chief of Production. Mr. Navarrete earned a degree in petroleum engineering from Universidad America and a master’s degree in petroleum engineering from Tulsa University.

Pedro A. Rosales (45) joined us in 1989, and has served as our Downstream Executive Vice-President since February 2008. Mr. Rosales has held several positions in the transportation unit. Prior to becoming our Downstream Executive Vice-President, Mr. Rosales served as our Chief Operation Officer and Chief of Transportation. Mr. Rosales earned a degree in mechanical engineering and an MBA from Universidad de los Andes.

Diego A. Carvajal (55)has served as our Vice-President of Exploration since 2005. Mr. Carvajal has extensive technical and managerial experience in projects of exploration and production of hydrocarbons, both in Colombia and overseas. Former President of the Colombian Association of Petroleum Geologists and Geophysicists, affiliated to AAPG. From 1984 to 1993, Mr. Carvajal worked as an Exploration Geologist for the Texas Petroleum Company – TEXACO, and from 1993 to 2005 he worked as Exploration Team Leader for the BP Exploration Co. Colombia Ltd. He joined Ecopetrol in 2005 as our Vice-President of Exploration. Mr. Carvajal earned a degree in geology from Universidad Nacional de Colombia.

Alvaro E. Vargas (47)joined us in 1995 and has served as our Vice-President of Strategy since 2006. Prior to becoming our Vice-President of Strategy, Mr. Vargas served as Ecopetrol’s Chief of the Budgetary Unit; Chief of the Finance and Treasury Unit; Financial Manager; and Director of the Planning and Risk unit. Mr. Vargas earned a degree in economics from Universidad de la Salle and has completed postgraduate studies in management and economics from Universidad de los Andes and economics from the University of London.

Federico Maya (43) has served as our Vice-President of Refining and Petrochemicals since December 2005. Mr. Maya has held various positions at Ecopetrol over the last 20 years, including Marketing and Contract Coordinator for Ecopetrol’s Gas Department, member of the Corporate Planning Directory, and Chief of Supply and Marketing. Mr. Maya earned a degree in chemical engineering from Pontificia Universidad Bolivariana and a specialization degree in marketing from Universidad EAFIT.

Camilo Marulanda (29)joined us in 2003, and has served as our Vice-President of Supply and Marketing since December 2005. He worked for Procter & Gamble Colombia from August 2001 to February 2003 as Category Manager. Mr. Marulanda was Chief of the Supply and Marketing department since September 2003 and Director of the National Commercialization unit since December 2004 and until December 2005. Mr. Marulanda earned a degree in economics and a specialization degree in marketing from Universidad de los Andes.

Oscar Trujillo (48)has served as our Vice-President of Transportation since February 2008. He has been in the transportation unit at Ecopetrol for 23 years. Within this unit, Mr. Trujillo has served as Chief of the Mid-Magdalena Technical Department, Chief of the Mid-Magdalena Maintenance Department, and the Chief of the Northern Area Operations Department of Pipelines. Prior to becoming our Vice-President of Transportation, Mr. Trujillo served as the Refined Products Pipelines National Manager. Mr. Trujillo earned a degree in civil engineering from Universidad de Medellin, and obtained a master’s degree in management from Instituto Tecnológico de Monterrey (TEC), Mexico.

Gabriel Osorio (46) joined us in 1986 and has served as Vice-President of Production since February, 2008. Mr. Osorio has held several positions in Ecopetrol working as Manager of heavy crude oils in the Central region; Regional Manager of the Cusiana and Cupiagua fields; Manager of the Mid-Magdalena Valley Region and Chief of the joint venture division, among others. Mr. Osorio earned a degree in petroleum engineering from Universidad Nacional de Colombia and a degree in Earth Resources Management from the University of South Carolina.

Oscar A. Villadiego (44) joined us in 1986, and has served as Vice-President of Services and Technology since February 2008. He has held several positions in the Production Vice-Presidency in such areas as the crude oil reserves, development and human resources unit. He served as manager for the Central region for a period of 2.5 years, and as Technical Manager for the production Vice-Presidency for four years. Mr. Villadiego earned a degree in Petroleum Engineering from Universidad America in 1987.

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Mauricio Echeverry (52) joined us in November 1999, and has served as our General Counsel since then. Mr. Echeverry held the positions of Dean, Associate Dean and Professor at Universidad de los Andes Law School. He was also Colombia’s Deputy General Prosecutor and Plenipotentiary Minister for Colombia’s Embassy in the U.S. Mr. Echeverry earned a law degree and a specialization degree in commercial law from Universidad de los Andes.

ITEM 6B Compensation

The total compensation paid to our Directors for their attendance to ordinary and extraordinary Board of Directors meetings and committee sessions during 2007 amounted to Ps$135,072,000.

The compensation paid to our Directors for each ordinary and extraordinary Board meeting for in-person sessions was Ps$900,000 and for on-the-phone sessions was Ps$450,000. This amount was paid following the requirements of Resolutions 2128 of 2004 and 928 of 2006 from the Ministry of Finance.

One of our executive officers is eligible to receive pension and retirement benefits from us. Our remaining executive officers and all of our Directors are not eligible to receive pension and retirement benefits from us. The total amount set aside to provide pension and retirement benefits to our eligible executive officer totals Ps$2,252,510,460.

ITEM6C Board Practices

Our Board of Directors is composed of nine members and is responsible for, among other things, establishing our general business policies. The members of the Board of Directors are elected at the annual shareholders’ meeting for one-year terms and may be reelected indefinitely. Our Directors were elected on March 27, 2008. Our executive officers are appointed by our Board of Directors.

None of the service contracts of any of our Directors contain provisions for benefits upon termination of such director’s services.

Pursuant to our by-laws our Board of Directors is divided in three committees of three members each, an audit committee, an appointment and compensation committee, and a corporate governance committee. The following table sets forth the current members of our audit, appointment and compensation, and corporate governance committees:

Audit Committee(1)	Nominating and Compensation Committee	Corporate Governance Committee
Joaquin Moreno	Hernan Martínez	Ignacio Sanín
Mauricio Cárdenas	Fabio Echeverri	Omar Baquero
Maria E. Velásquez	Omar Baquero	Oscar Ivan Zuluaga
Ignacio Sanín

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(1) All members of our audit committee must be independent.

Audit Committee

Our audit committee, comprised of three independent Directors, is the highest internal control body of our company and provides support to our Board of Directors in accounting and financial matters.

Compensation Committee

Our compensation and nominating committee, comprised of at least one independent director, provides general guidelines for selection and compensation of our executive officers.

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Corporate Governance Committee

Our corporate governance committee, comprised of at least one independent director, makes good corporate governance proposals to our Board of Directors.

ITEM6D Employees

At December 31, 2007 we had 5,863 employees. Our employees may elect to be regulated under a collective bargaining agreement or under Agreement 01 of 1997. The collective bargaining agreement governs the labor relations of our unionized employees. Agreement 01 of 1997 governs the labor relations of our employees devoted to technical and trustworthy activities. The collective bargaining agreement and Agreement 01 of 1997 do not vary significantly in benefits or economic benefits. Employees hired before January 29, 2003 have a special retirement plan and those hired after January 29, 2003, are subject to Law 100 with respect to their retirement scheme.

We undertook a personnel restructuring process in 2004, and as a result, our headcount was reduced by 3.3%, to 5,801 in 2006 from 5,997 in 2005. The restructuring process included replacing certain employees who retired, a voluntary withdrawal plan and the outsourcing of certain jobs. We hired 108 new employees in the last three years.

The table below presents the number of employees and the average number of employees by business segments for the years ended December 31, 2007, 2006 and 2005.

December2007	Exploration	Production	Refining	Transport	Marketing	Corporate	TOTAL(1)
Direct employees (full time)	100	1,278	1,979	762	113	1,631	5,863
Direct employees average(2)	97	1,298	1,936	768	113	1,638	5,850
Temporary Employees	8	85	81	23	9	114	320

December2006	Exploration	Production	Refining	Transport	Marketing	Corporate	TOTAL
Direct employees (full time)	95	1,269	1,928	753	113	1,643	5,801
Direct employees average	92	1,397	1,972	726	113	1,677	5,977
Temporary Employees	8	94	53	20	11	117	303

December2005	Exploration	Production	Refining	Transport	Marketing	Corporate	TOTAL
Direct employees (full time)	94	1,404	2,008	716	112	1,663	5,997
Direct employees average	98	1,414	2,044	716	103	1,849	6,224
Temporary Employees	0	56	10	1	8	66	141

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(1) At the last day of each month.

(2) Averages are calculated on a monthly basis from January to December of each year.

Labor Unions

We currently have three industry-wide labor unions and one company labor union:

1. Unión Sindical Obrera de la Industria del Petróleo — USO (Industry labor union)

2. Asociación de Directivos Profesionales, Técnicos y Trabajadores de las Empresas de la Rama de Actividad Económica del Recurso Natural del Petróleo y sus Derivados de Colombia — ADECO (Industry labor union)

3. Sindicato Nacional de Trabajadores de Empresas Operadoras, Contratistas, Subcontratistas de Servicios y Actividades de la Industria del Petróleo y Similares — SINDISPETROL (Industry labor union)

4. Sindicato Nacional de Trabajadores de Ecopetrol — Sincopetrol (Company labor union)

Our employees and any employee working for a company in the oil and gas industry may join the USO, ADECO or Sindispetrol. Sincopetrol may only be joined by our employees.

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In 2006, we negotiated a new collective bargaining agreement with the USO. As a result of these negotiations we entered into a three-year collective bargaining agreement with USO and Sindispetrol. The collective bargaining agreement expires on June 2009 and we expect to begin negotiations with the USO on February of next year. The following are the most representative benefits of the agreement:

• Transportation Subsidy. Monthly transportation subsidy depends on the employee’s location and ranges between Ps$60 for approximately 2,000 employees located in Barrancabermeja and Ps$76,000 for our ten employees located in Dagua;

• Food Subsidy. Daily food subsidy ranges between Ps$4,884 and Ps$8,233 depending on the employee’s location;

• Lodging Subsidy. Monthly lodging subsidy to employees that do not own their own homes for Ps$174,557;

• Subsidy for Education. Subsidy that covers 90% of tuition expenses;

• Stability Clause. Employees that as of December 1, 2004 had worked over 16 months cannot be fired without just cause;

• Retirement Benefit. A retirement benefit is paid to our employees who meet the following requirements: have worked for us for at least 20 years and have reached the specific retirement age. In order for employees to be eligible to receive the benefit, the number of years working for us (in excess of 20), plus their age must be equal to or exceed 68 years in the case of women and 70 years in the case of men. The retirement benefit paid is equal to 75% of the average compensation received by the employee during the last 12 months. This benefit expires on July 31, 2010 and approximately 1,700 of our current employees will be eligible to receive the above mentioned payments. After July 31, 2010, we will transfer to pension funds the amounts accrued under this benefit for each employee who did not meet the requirements established by law.

• Retirement plan for new employees. Employees hired after July 1, 2004 are not covered by our retirement scheme and are covered by the general social security system;

• Five-year bonus. A cash benefit bonus accrued on a yearly basis and paid for every 5-year period worked in the Company according to the following scale:

5 years worked	Bonus equivalent to 9 days of basic payment plus Ps$154,966
10 years worked	Bonus equivalent to 14 days of basic payment plus Ps$154,966
15 years worked	Bonus equivalent to 19 days of basic payment plus Ps$154,966
20 years worked	Bonus equivalent to 24 days of basic payment plus Ps$154,966
25 years worked	Bonus equivalent to 29 days of basic payment plus Ps$154,966
30 years worked	Bonus equivalent to 34 days of basic payment plus Ps$154,966

Labor Relations

As part of our challenge to improve workplace morale we implemented a number of initiatives to strengthen on-site training and improve the general welfare of our employees. Our initiatives also sought to strengthen communication processes, and start performance-based compensation.

Our corporate plan seeks to generate an organizational culture aiming to recruit employees with the highest talent. The Department of Labor Relations and Development defined our new human resources model, which was implemented through the human resources and payroll project.

As part of the actions to improve quality of life, 584 home loans were extended to our employees for a total of Ps$1,979 million and 1,168 loans for computers were extended averaging Ps$5.2 million per beneficiary.

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We provided on-site and external training and development courses to our employees. At December 31, 2007, our employees had received 394 thousand hours of training, or 69.4 hours on average per employee. We offered 14,700 training activities or 2.5 activities on average per employee.

We undertook a number of initiatives to retain our current employees and decrease attrition rate, which amounted to approximately 6% in 2006, due to significant changes in the labor market, particularly demand for qualified personnel in the oil and gas sector.

Labor Regulation

Until November 13, 2007, all of our employees were official employees, as defined by Colombian labor laws except for the President and the Internal Control Officer, who were public employees. When we became a mixed economy company all of our employees changed their legal status to private employees, under the provisions of the Colombian Labor Code.

ITEM6E Share Ownership

The disclosure of the beneficial ownership of shares by any of our Directors or executive officers is not provided as no Director or executive officer beneficially owns more than 1% of our outstanding shares.

ITEM7 Major Shareholders and Related Party Transactions

ITEM7A Major Shareholders

The following table sets forth the name of our major shareholders, and the number of shares and the percentage of outstanding shares owned by them for the years ended December 31, 2007, 2006 and 2005.

	At December31,
	2007			2006			2005
Shareholders	Number ofshares	% Ownership		Number ofshares	% Ownership		Number ofshares	% Ownership
Nation	36,384,788,817	89.9	%	42,449,825	100	%	42,449.825	100	%
Public float	4,087,723,771	10.1	%	—	—		—	—
Total	40,472,512,588	100	%	42,449,825	100	%	42,449,825	100	%

All our common shares have identical voting rights.

ITEM7B Related Party Transactions

Agreements

We engage in a variety of transactions with related parties in the ordinary course of business. Set forth below is a description of material related party transactions. For additional information about transactions with related parties see Note 15 to our consolidated financial statements.

Ocensa

We entered into the following agreements with Ocensa, a company in which we have a 35.3% equity interest:

In March 1995, we entered into an agreement for the transportation of crude oil through the Ocensa pipeline. Pursuant to the terms of the agreement, we are required to make monthly payments that vary depending on the volumes of crude oil we transport through the pipeline and a tariff calculated by Ocensa on the basis of Ocensa’s financial projections and their expected volumes of crude oil. In 2007, payments made by us under this agreement amounted to US$245.7 million. This agreement expires in December 2093 or upon liquidation of Ocensa.

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In December 1995, we leased the Porvenir and Miralflores terminals to Ocensa. Pursuant to the terms of the agreement we receive monthly payments of approximately US$590,000 plus applicable taxes. The duration of the agreement is indefinite.

In November 1996, we leased the Cravo Norte port to Ocensa. Pursuant to the terms of the agreement we receive monthly payments of US$25,000, plus applicable taxes. The duration of this agreement is indefinite.

In September 1999, we entered into a joint operation agreement for the TLU-3 Coveñas buoy with Ocensa, ODC and the Cravo Norte joint venture. Pursuant to the terms of the agreement we are required to make monthly payments of a fixed amount of US$75,000 plus a variable amount depending of the volumes exported through the buoy. There has not been variable payments in the last three years. The duration of this agreement is indefinite.

In December 1999, we entered into an operation and maintenance agreement for the Porvenir, Miralflores and Vasconia terminals. Pursuant to the terms of the agreement we receive monthly payments of approximately US$370,000 plus applicable taxes. This agreement expires on December 1, 2010.

In December 2004 we entered into a natural gas supply agreement. Pursuant to the terms of the agreement we receive variable monthly payments based on the volumes of natural gas delivered and a fixed tariff. During 2007, we receive payments for approximately US$600,000. This agreement expires in May 2008 but may be extended for six months.

Oleoducto de Colombia S.A. or ODC

We entered into the following agreements with ODC, a company where we have a 43.85% equity interest:

In July 1992, we entered into a take-and-pay agreement for the transportation of hydrocarbons. Pursuant to the agreement we must pay a previously agreed tariff over the volume of hydrocarbons transported. The duration of this agreement is indefinite.

In August 1992, we entered into an operation and maintenance agreement for the Vasconia and Coveñas terminals. Pursuant to the terms of the agreement, ODC is required to make monthly payments amounting of approximately US$1.1 million per year plus any other expenses incurred by us in the performance of the agreement, including a variable surcharge between 5% and 12% on such expenses, plus any applicable taxes. The duration of this agreement is indefinite.

In March 2007, we entered into a services agreement to guarantee the protection and safety of the Cusiana-Coveñas and Vasconia-Coveñas pipeline systems. Under the terms of the agreement, ODC must pay us Ps$51 million per year. This agreement expires in March 2011.

In July 2006, we entered into an operation and maintenance agreement for the Caucasia Station and the Vasconia-Coveñas pipeline system. Pursuant to the terms of the agreement, ODC is required to make monthly payments of US$508,500 per year, plus any other expenses incurred by us in the performance of the agreement, including a variable surcharge of between 5% and 12% on such expenses, plus any applicable taxes. The duration of this agreement is indefinite.

Refinería de Cartagena S.A.

In April 2007, we entered into a maintenance and administration agreement for the Cartagena refinery with Refinería de Cartagena S.A., a company in which we have a 49.0% equity interest. Pursuant to the terms of the agreement we provide them with maintenance and administration services and Refinería de Cartagena S.A. pays us a monthly fee equal to Ps$2.9 billion and a variable annual fee that may not exceed Ps$6.96 billion. This agreement expires in April 2011 and may be extended for additional one-year periods until the upgrade and modernization of the Cartagena refinery’s facilities is completed.

On February 1, 2008 we extended a ten-month commercial offer to Refinería de Cartagena for the supply of crude oil. Pursuant to the terms of the offer, Cartagena refinery has the option to purchase from us up to 85

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thousand bpd of crude oil from our Caño Limón, Vasconia Blend, Ayacucho Blend, Cusiana and Castilla production. The purchase price for the delivered volumes is equal to an international benchmark index, subject to certain adjustments. 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. At March 30, 2008, we had received aggregate payments of approximately Ps$1,161 billion for the supplied amounts. This offer expires in November, 2008 but is renewable for an additional one-year period.

Other Agreements

We entered into a supply agreement with Ecodiesel, a company in which we have a 50.0% equity interest. This agreement is not yet operative and will begin once the Ecodiesel plant starts its activities. Pursuant to the terms of the agreement, Ecodisesel must deliver and we must purchase specific amounts of biodiesel each month. Payments vary depending on the purchased volumes of biodiesel. This agreement expires on December 31, 2017.

In April 2002, we entered into a service agreement with Sociedad Colombiana de Servicios Portuarios S.A. or Serviport, a company in which we have a 49% equity interest. Pursuant to the terms of the agreement, Serviport assists us in our maritime operations in the Coveñas port in exchange for which we pay it approximately US$155,000 per month. This agreement expires on November 30, 2008 but is renewable annually.

Transactions with other state-controlled entities

We are a state-owned oil and gas company and operate in an industry regulated by the Governmental authorities, agencies and other organizations.

In the ordinary course of business we enter into transactions with other state-owned entities which include but are not limited to the following:

• sales and purchase of goods, properties and other assets;

• rendering and receiving services;

• lease of assets;

• depositing and borrowing money; and

• use of public utilities.

These transactions are conducted in the ordinary course of business on terms comparable to the terms of transactions with private parties. We have also established procurement policies and approval processes for purchases of products and services, which do not depend on whether the counterparties are state-owned entities or not.

Loans to our Directors and Executive Officers

We only extend loans to our executive officers as part of our compensation scheme. We do not extend loans to our Directors. We grant loans for housing and computers. Housing loans to our executive officers are approved by a housing loans committee composed by the Human Resources and Strategy vice-presidents, and the Compensation manager. Executive officers may apply for housing loans after their third year in tenure. The principal amount of the loan depends on the applicant’s tenure and cannot exceed 59 times the applicant’s monthly salary. We do not guarantee any loans made by third parties to our executive officers or employees. At December 31, 2007 the total amount of outstanding loans granted to our executive officers was Ps$295.3 million.

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The following table sets forth a description of the loans outstanding to our executive officers at December 31, 2007.

Executive Officer	Nature of the LoanandDate of Disbursement	Principal Amountofthe Loan	Amount Outstandingat December31, 2007	LargestAmount Outstanding duringperiod	Termination Date	Applicable InterestRate
(Pesos inmillions)
Javier G. Gurierrez	Housing, July 2008	729	n/a	729	June 2028	UVR
Adriana M. Echeverri	Housing, June 2002	37.5	53.5	56.6	October, 2018	UVR + 1%
	Computer, November 2005	5.2	1.6	5.2	October, 2008	0%
Nelson Navarrete	Housing, December 1997	100.2	11.7	17.4	December, 2013	8%
	Computer, November 2005	5.2	1.7	5.2	October, 2008	0%
Pedro A. Rosales	Housing, April 1997 and September 2003	279.2	225	247.5	September 2018	UVR + 1%
	Computer, November 2005	5.2	1.7	5.2	October, 2008	0%

ITEM7C Interests of Experts and Counsel

Not applicable.

ITEM8 Financial Information

ITEM8A Consolidated Statements and Other Financial Information – 2008

Please see our Consolidated Financial Statements starting on page F-1.

ITEM9 The Offer and Listing

American Depositary Receipts

We expect to enter into a deposit agreement with JPMorgan Chase Bank, N.A., as depositary, for the issuance of ADRs evidencing ADSs. Each of the ADSs will represent 20 of our common shares or evidence of the right to receive 20 of our common shares. For further information see Item 12D — “American Depositary Shares”.

We intend to submit an application to list our ADSs evidenced by ADRs on the New York Stock Exchange or NYSE. Our ADSs are expected to begin trading on the NYSE under the symbol “EC” on or about September 18, 2008.

Trading Markets

In November 2007, we conducted an initial public offering of 10.1% of our common shares in Colombia. As a result of such offering, our common shares trade on the BVC under the symbol ECOPETROL.

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Price Information

The following table sets forth reported high and low closing prices in Pesos for our shares and the reported average daily trading volume of our shares on the BVC for the periods indicated. The table also sets forth information on the trading price of our shares in Pesos and U.S. dollars, as well as the average trading volume.

	Shares Traded on BVC
	Pesos per share		U.S. dollars per share(1)		Average number of shares traded per day
	High	Low	High	Low
2007	2,080	1,690	1.01	0.82	20,795,397
First quarter 2008	2,095	1,575	1.13	0.80	19,519,876
Most recent six months
January 2008	2,030	1,575	1.01	0.80	19,241,298
February 2008	1,805	1,720	0.94	0.89	19,574,944
March 2008	2,095	1,910	1.13	1.03	19,780,637
April 2008	2,600	2,095	1.46	1.14	23,873,541
May 2008	2,895	2,650	1.65	1.50	34,907,022
June 2008	2,845	2,555	1.66	1.43	17,303,794
July 2008	2,720	2,440	1.56	1.38	15,732,847
August 2008	2,615	2,390	1.37	1.31	17,549,002
September 8, 2008	2,730	2,600	1.41	1.29	23,666,778

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(1) U.S. dollars per common share translated at the Representative Market Rate for each period.

The price of our common shares rose substantially during the first two days of trading. During these two days, November 27 and 28, 2007, the trading of our common shares was suspended as it exceeded the price movement limits established by BVC.

Markets

The BVC was created in 2001 as a result of the merger of the Bogotá, Medellín and Occidental Stock Exchanges, the largest exchanges in Colombia. The BVC is the largest stock exchange in Colombia for trading securities and derivatives. The BVC has over 500 shareholders and is a member of the World Federation of Exchanges and the Federación Iberoamericana de Bolsas.

The BVC is the only exchange where our common shares trade in Colombia. The BVC is highly volatile compared to other major world stock exchanges. The table below sets forth the reported aggregate market capitalization of the BVC, as of December 31, 2007.

	Aggregate Market Capitalization on BVC
	Market Capitalization (Ps$ in billions)	Market Capitalization (US$ in billions)(1)
December 31, 2007	205,671	98.95

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(1) Representative Market Rate at December 31, 2007.

There are three basic indexes that measure the BVC’s performance. The principal and most important is the IGBC. The BVC is calculated on the price variation of the stock of the companies with the highest capitalization and highest trading volumes.

Another index used to measure the performance of the BVC, is the COLCAP. The COLCAP includes the price variations of the 20 companies having the highest trading volumes in the BVC, where the adjusted market capitalization of each company determines its weighted value.

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The COL20, an index measuring the performance of the BVC was introduced in 2008. The COL20 measures the liquidity of the 20 stocks having the highest trading volumes in the BVC, which in turn determines their weight on the index.

Transfer and Registration of Shares

In general, the following transfers do not need to be effected through the BVC: transfers between shareholders having the same beneficial owner; transfers of shares owned by financial institutions that are in process of liquidation under the control and supervision of the Superintendency of Finance; repurchase of shares; transfers of shares made by the Nation; transfers of shares issued abroad by Colombian companies, provided they take place outside Colombia; transfers of shares issued abroad by foreign companies, provided they take place outside Colombia; and any other transaction authorized to be effected outside the BVC by the Superintendence of Finance.

Pursuant to Colombian law, purchases of 25% or more of the outstanding shares with voting rights (including ADSs) of a listed company, or the purchase of 5% or more of the outstanding shares with voting rights (including ADSs) by a shareholder or group shareholders beneficially owning 25% or more of the outstanding capital stock of a listed company, should be made pursuant to public tender offer rules.

Certain exemptions apply to tender offer rules including, transfers made through an auction on the BVC as a result of privatization procedures; transfers authorized in writing by 100% of the shareholders; repurchase of shares by the issuer in open market transactions; transfers by virtue of law including donations, liquidation processes, judicial decisions, among others. In any case, the Superintendency of Finance must be notified of any transfer that is deemed to be an hecho relevante or a significant event, under Colombian law.

Under Colombian law, shares may be traded either in physical form or electronic form. Transfers of shares are subject to a registry system which differs depending on whether the shares are evidenced by electronic form or physical form. Transfers of shares evidenced by electronic certificates must first be registered with Depósito Centralizado de Valores or DECEVAL through the relevant stockbroker. DECEVAL’s main purpose is to receive, safekeep and manage share certificates issued by corporations in order to keep a record of the transactions undertaken over such securities, including but not limited to transfers, pledges and withdrawals. Accordingly, DECEVAL is not allowed to hold, invest or otherwise use the securities held under its custody.

Transfer of shares evidenced by electronic and physical certificates must be registered on the Issuer’s stock ledger. Only those holders registered on the stock ledger are recognized by us and third parties as shareholders. Registration requires endorsement of the certificates or a written instruction from the holder. In the case of electronic certificates, DECEVAL notifies us regarding the transfer of shares after registering it in its system.

Transfer of shares do not give rise to any fee for us but they may be subject to certain taxes, stamp duties or other governmental charges which the shareholder may be required to pay.

 

ITEM 10 Additional Information

 

ITEM 10A Share Capital

At December 31, 2007, our authorized capital was Ps$15,000,000,000,000 divided into 60,000,000,000 shares of common stock each with a par value Ps$250. On that date we had 40,472,512,588.19 shares outstanding out representing a capital of Ps$10,118,128,147,049¹. At December 31, 2007 we had 19,527,487,411,804 shares in reserve. Under Colombian law, a company may keep authorized amounts of shares in reserve to facilitate future issuances and avoid an additional authorization of the general shareholders’ meeting.

______________

¹ Of our total subscribed capital at December 31, 2007, Ps$10,113,334 million corresponds to subscribed and paid-in capital and Ps$4,794 million corresponds to shares bought by investors pursuant to the installment option offered by us in our initial public offering, which had not been paid at December 31, 2007.

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ITEM 10B Articles of Incorporation and By-laws

Corporate Purpose

Pursuant to article 4 of our by-laws, we may engage in the exploration, production, refining, transportation, storage, distribution and commercialization of crude oil and its by-products in Colombia and abroad. Our by-laws also authorizes us to perform activities for the exploration and production of crude oil in areas that prior to January 1, 2004 were operated by us directly or were subject to agreements subscribed by us; to directly or indirectly explore and produce crude oil in areas assigned to us by the ANH; to directly or indirectly explore and produce crude oil in areas assigned to us by a foreign regulatory entity; to buy, sell, import, export, store, mix, or distribute hydrocarbons and its by-products in Colombia or abroad; to undertake research for developing and commercializing alternative energy sources; and in general, to undertake any other activity instrumental or required to develop our corporate purpose. Our corporate purpose includes administering and managing all properties that were formerly part of the De Mares concession.

Directors

Pursuant to our by-laws, our Board of Directors is comprised of nine members with no alternates. Directors are elected for one-year terms by the general shareholders’ meeting and may be reelected indefinitely. Our by-laws require our Board of Directors to have at least three independent members.

Our by-laws provide for three committees of our Board of Directors, comprised of three members each. An audit committee, comprised of three independent Directors, is the highest internal control body of our company and provides support to our Board of Directors in accounting and financial matters; a compensation and nominating committee, comprised of at least one independent director, provides general guidelines for selection and compensation of our executive officers; and a corporate governance committee, comprised of at least one independent director, makes good corporate governance proposals to our Board of Directors.

According to Colombian law, Directors must be elected in accordance with a proportional representation system similar to cumulative voting. Directors may be removed without cause at any moment by a majority of the shareholders present at a general shareholders’ meeting.

Under Colombian law, a director or executive officer must disclose any transaction involving a conflict of interest to the general shareholders’ meeting. The general shareholders’ meeting may approve or reject the transaction giving rise to the conflict with the vote of the majority of the shares present at the shareholders’ meeting. If the director or executive officer with a conflict is a shareholder, his or her vote will be excluded.

The compensation of our Directors is set annually and exclusively by the general shareholders’ meeting. Directors are compensated for attending board meetings and committee meetings. A Board meeting requires a quorum of at least five members and decisions are approved with a majority of the members present.

Neither our by-laws nor our code of corporate governance provide a minimum retirement age for our Directors. Under our by-laws there is no requirement for a person to have a minimum number of shares to be considered as a director. Colombian law provides that Directors willing to sell or purchase shares in our company require a prior authorization of the Board of Directors. Colombian law does not impose any limitation as to the number of shares that may be acquired by a director.

Colombian law prohibits Directors from receiving corporate loans.

Preference Rights and Restrictions Attaching to Our Shares

We have only one class of stock without special rights or restrictions. Our shareholders do not have any type of preemptive rights.

Under Colombian law, our shareholders have the following economic privileges and voting rights:

• To participate and vote in the decisions of the general shareholders meeting;

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• To receive dividends based on the financial performance of company in proportion to their share ownership;

• To transfer and sell shares according to our by-laws and Colombian law;

• To inspect corporate books and records 15 business days prior to the ordinary meeting of shareholders where the year-end financial statements are to be approved;

• Upon liquidation, to receive a proportional amount of the corporate assets after the payment of external liabilities; and

• To sell the shares, known as derecho de retiro, if a corporate restructuring affects the economic or voting rights of the shareholders in the terms and conditions established under Colombian law;

Our by-laws and corporate governance code provide additional rights to our minority shareholders. These rights include:

• Sale of Assets. For a ten-year period counted from the date of adoption of our by-laws or until the Nation loses its status as majority shareholder, the Nation guarantees that any sale of 15% or more of our assets requires the approval of the general shareholders’ meeting and that the Nation would only be allowed to vote its shares in favor of the proposal if 2% or more of our minority shareholders accept the proposal.

• Candidate List. Pursuant to our by-laws and law 1118 of 2006, the Nation will include in its candidate list for election of members of the Board of Directors one member selected by the departments that produce hydrocarbons. In addition, pursuant to the declaration of the Nation dated July 26, 2007, the Nation will include in its candidate list for election of members of the Board of Directors one member selected by the ten largest minority shareholders. The right of minority shareholders to select a candidate to be included in the Nation’s list would only be available for ten years counted from the date of the adoption of our by-laws.

• Extraordinary Meetings. Our by-laws provide that shareholders holding at least 5% of the total number of shares outstanding may call an extraordinary shareholders’ meeting.

• Office for the Protection of Investors. We created an office for the protection of investors, our specialized unit responsible for receiving complaints from our shareholders. Pursuant to our by-laws, shareholders holding at least 5% of the total number of shares outstanding may request the office for the protection of investors a special audit of the following documents: the income statement; the proposal for the distribution of profits; the report of the Board of Directors as to the economic and financial status of our company; the report from our general counsel as to the legal status of our company; and the report from the independent auditors. Special audits cannot be made of documents that contain scientific, technological or statistical information of our company, or agreement that gives us competitive and economic advantages over our competitors, or in respect of any document related to intellectual property. Shareholders also have the right to propose good corporate governance recommendations to the office for the protection of investors.

• Others. Pursuant to our by-laws, shareholders holding at least 5% of the total number of shares outstanding may propose recommendations to our Board of Directors pertaining to the management of our company. Any shareholder may file a written petition to our Board of Directors to investigate corporate governance violations that the shareholder believes to have been committed.

Amendments to Rights and Restrictions to Shares

The rights and restrictions given to our shareholders may only be modified through an amendment to our by-laws. The general shareholders’ meeting has full and exclusive authority to modify or amend our by-laws.

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General Shareholders’ Meeting

Shareholders’ meetings may be ordinary or extraordinary. Ordinary meetings will take place in our legal domicile located in Bogota, Colombia, within the first three months following the end of each fiscal year, on the day and at the time set forth in the notice for the general shareholders’ meeting. The call for the general shareholders’ meeting may be made electronically or by written communication sent to each shareholder. In both cases the call must be published in a newspaper of wide circulation 20 business days prior to the date in which the meeting will take place.

In the ordinary general shareholders’ meeting, our Board of Directors and the external auditor are appointed and our annual financial statements, profit distribution, audit and management reports and any other matter provided under applicable law or our corporate by-laws are approved.

Extraordinary meetings of shareholders may be called by our Board of Directors, by our president or chief executive officer, by our external auditor, or by shareholders holding at least 5% of the shares outstanding. Calls to extraordinary meetings should be made at least eight days prior to the date of the meeting, and may be made electronically or by written communication to each shareholder or be published in a newspaper of wide circulation. The meeting notice must specify the agenda for the meeting.

The required quorum for both ordinary and extraordinary meetings is 50% plus one share entitled to vote and decisions are approved with a majority of the members present. This quorum is exempted in the case of “second-call meetings,” which may take place when a meeting fails to obtain the required quorum and is called within a period between 10 business days and 30 business days from the first date, in which case decisions may be adopted by a majority of the shares present regardless of the number represented.

Unless Colombian law requires a super majority, decisions made at the shareholders’ meeting must be approved by a majority of the shares present. Colombian law requires super majorities in the following cases:

• the vote of at least 70% of the shares present and entitled to vote at the ordinary shareholders’ meeting is required to approve the issuance of stock not subject to preemptive rights;

• the vote of at least 78% of the shares represented entitled to vote is required to approve the distribution of less than 50% of the annual net profits. If the sum of all legal reserves (statutory, legal and optional) exceed the amount of the outstanding capital, the company must distribute at least 70% of the annual net profits;

• the vote of at least 80% of the shares represented is required to approve the payment of dividends in shares; and

• the vote of 100% of the outstanding and issued shares is required to replace a vacancy on the Board of Directors without applying the electoral quotient system.

Shareholders may be represented by proxies provided that the proxy: (i) is in writing (faxes and electronic documents are valid), (ii) specifies the name of the representative, (iii) specifies the date or time of the meeting for which the proxy is given and (iv) is not issued to a legal representative of the company. Proxies granted abroad do not require legalization or an apostille.

Limitations to the Rights to Hold Securities

There are no limitations in our by-laws or Colombian law on the rights of Colombian residents or foreign investors to own the shares of our company, or on the right to hold or exercise voting rights with respect to those shares.

Restrictions on Change of Control Mergers, Acquisitions or Corporate Restructuring of the Company

Under Colombian law and our by-laws, the general shareholders’ meeting has full and exclusive authority to approve any corporate restructuring including, any mergers, acquisitions or spin-offs. Corporate restructurings are also subject to the requirement that the Nation must hold a minimum of 80% of our common stock at all times. While Law 1118 of 2006 is in effect, there cannot be any restructuring that results in a change of control of our company.

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Ownership Threshold Requiring Public Disclosure

Our corporate governance code provides that we must disclose periodically in our web page the name of all shareholders of our company, indicating at least, the twenty shareholders with the highest number of shares. We must also disclose this information to the Superintendency of Finance at the end of each fiscal year.

Colombian securities regulations set forth the obligation to disclose any material event or hecho relevante. Any transfer of shares equal or greater than 5% of our capital stock or any person acquiring a percentage of shares that would make him the beneficial owner of 5% or more of our capital stock, is a material event, and therefore, must be disclosed to the Superintendency of Finance.

Changes in the Capital of the Company

There are no conditions in our by-laws governing changes in our capital stock that are more stringent than those required under Colombian law, with the exception that the Nation must hold a minimum of 80% of our capital stock at all times.

ITEM10C Material Contracts

Transportation Agreement between Ecopetrol and ECOGAS/TGI

In October 6, 2006, we entered into a natural gas transportation agreement with Ecogás for the transportation of natural gas from the Ballena terminal located in the La Guajira fields to the Barrancabermeja terminal. The agreement is set to expire in November 30, 2012. Pursuant to the terms of the agreement, Ecogás will transport up to 90,086 thousand cfpd of natural gas produced by us upon our request. According to the agreement, Ecogás should undertake two overhauling stages to expand the pipeline’s capacity. After its first capacity expansion completed in June 2007 the pipeline’s capacity was increased to 190,000 thousand cfpd expanding its transportation capacity to 134,066 thousand cfpd. Once Ecogás executes the second expansion to 262,000 thousand cfpd we will have transportation availability of up to 175,000 thousand cfpd.

In February 27, 2007, Ecogás transferred, the rights and obligations under this agreement to Transportadora de Gas del Interior S.A. ESP or TGI.

Pursuant to the terms of agreement we pay TGI a regulated transportation tariff composed of a fixed fee, a variable fee depending on transported volumes and an administration, operation and maintenance fee. Payments for transported volume are made in Pesos. During 2007 we paid Ps$93,393,810,368 for the transportation services provided to us by TGI and at April 30, 2008, we had paid TGI Ps$35,524,892,460.

Please see Exhibit 4.2. to this registration statement for a full description of this agreement.

Transportation Agreement between Ecopetrol and Ocensa

On March 31, 1995 we entered into a crude oil transportation agreement with Ocensa. Pursuant to the terms of the agreement Ocensa agreed to transport trough its pipeline our production of crude oil from the Cusiana and Cupiagua fields.

We are required to make monthly payments that vary depending on the volumes shipped through the Ocensa pipeline and a tariff calculated by Ocensa based on its financial projections and its expected transportation volume. Payments to Ocensa are made in cash in accordance with the agreement. In 2006, payments made by us to Ocensa under this agreement amounted to US$219.9 million and to US$245.7 million in 2007.

This agreement expires in December 2093 or upon liquidation of Ocensa. Please refer to Exhibit 4.1. to this registration statement for a full description of this agreement.

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ITEM10D Exchange Controls

Payments in foreign currency with respect to certain foreign exchange transactions including international investments between Colombian residents and non-Colombian residents must by law be conducted through the commercial exchange market. Therefore, any foreign currency income or expenses under the ADRs must be channeled through that market. Transactions conducted through the commercial exchange market are made at market rates freely negotiated with authorized intermediaries (banks, financial corporations and others). Previously, the exchange rate traded within a band set by the Colombian Central Bank. Presently there is no such ceiling or floor.

Colombian law provides that the Colombian Central Bank may intervene in the foreign exchange market if the value of the Colombian Peso experiences significant volatility. Likewise the Colombian government introduces from time to time amendments to the International Investment Statute. For example, on May 23, 2007, the Colombian government introduced a new deposit requirement related to portfolio investments made by foreign investors. Decrees 1801 of 2007 and 1888 and 3264 of 2008 require foreign investors making portfolio investments in securities other than shares or mandatory convertible bonds to make a non-interest bearing deposit with the Colombian Central Bank for a term of six months from the date of such investment, for an amount equivalent to 40% of the value of investment converted at the representative market rate then in effect. See Item 3D “Risk Factors — Risks relating to the ADRs”. However, on June 29, 2007 the Colombian government issued Decree 2466 of 2007, setting forth that portfolio investments made pursuant to ADR programs are exempt from the deposit requirement of Decree 1801 of 2007. As a result, neither Ecopetrol nor the purchasers of ADRs will be required to comply with deposit requirements.

The Colombian Central Bank may also limit the remittance of dividends and/or investments of foreign currency received by Colombian residents whenever the international reserves fall below an amount equal to three months of imports. Since the creation of the current foreign exchange regime in 1991, the Colombian Central Bank has never taken such action. However, we cannot assure you that the Colombian Central Bank will not intervene in the future. See Item 3D — “Risk Factors — Risks Relating to Colombia.”

Registration of foreign investment represented in underlying shares

Colombia’s International Investment Statute, which has been amended from time to time through related decrees and regulations, regulates the manner in which non-Colombian resident entities and individuals can invest in Colombia and participate in the Colombian securities markets. Among other requirements, the statute mandates registration of certain foreign exchange transactions with the Colombian Central Bank and specifies procedures to authorize and administer certain types of foreign investments.

Foreign investors who acquire ADRs are not required to register before Colombian authorities. Holders of ADRs who wish to withdraw the underlying shares will have to comply with certain registration and reporting procedures, among other requirements. Under these foreign investment regulations, the failure of a foreign investor to report or register with the Colombian Central Bank foreign exchange transactions relating to investments in Colombia on a timely basis may prevent the investor from obtaining remittance rights, constitute an exchange control infraction and result in a fine.

Holders of ADRs will benefit from the registration to be obtained by the custodian for our common shares underlying the ADRs in Colombia, which permits the custodian to convert dividends and other distributions with respect to the common shares into foreign currency and remit the proceeds abroad. If investors in ADRs choose to surrender their ADRs and withdraw common shares, they would have to register their investment in the common shares as a foreign direct investment, provided that 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. Holders of ADRs that surrender their ADRs may also deliver the underlying common shares to a foreign investment capital fund authorized to operate in Colombia.

In obtaining its own foreign investment registration, an investor who surrendered its ADRs and withdrew common shares may incur expenses and/or suffer delays in the application process. Investors would only be allowed to transfer dividends abroad or transfer funds received as distributions relating to our common shares after their foreign investment registration procedure with the Colombian Central Bank has been completed. In addition, the depositary’s foreign investment registration may also be adversely affected by future legislative changes, but its rights to transfer abroad dividends or profits arising from distributions relating to our common shares must be

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maintained, according to Colombian law and foreign investment treaties entered into by Colombia, except when the Colombian international reserves fall below an amount equivalent to three months worth of imports.

 

ITEM 10E Taxation

Colombian Tax Considerations

The following is a description of the Colombian tax considerations for investments in common shares in Colombia or for the purchase of ADSs in a foreign securities market. This description is based on the applicable law in effect as of the date of this registration statement. Prospective purchasers of common shares or ADSs should consult their own tax advisors for a detailed analysis of the tax consequences resulting from the acquisition, ownership and disposition of common shares or ADSs.

General Considerations

Income tax and complementary taxes are considered a single tax with two components: income and sporadic earnings. Taxes are accrued on a calendar basis.

Pursuant to the Colombian Tax Code, Colombian corporations and public entities are subject to Colombian taxes on income earned in Colombia and worldwide; while foreign entities are liable only for income earned in Colombia.

Tax Treatment of a Non-Resident of Colombia who Purchases an ADR in a Foreign Securities Market

Dividends

In general, dividends paid to foreign companies or other foreign entities, non-Colombian residents or successors of non-Colombian residents are subject to Colombian income tax.

To avoid double taxation, corporate and branch profits are taxed at the corporate or branch level. If the accounting earnings and profits of a Colombian corporation exceed the tax profits subject to income tax, the excess is subject to income tax at the shareholder level. If the shareholder is a non-resident, the applicable tax rate is 33%.

Therefore, provided all distributions, including the payment of dividends, are made by Ecopetrol to non-resident holders of ADRs through the Depositary, such payments will be exempted from income, withholding and remittance tax in Colombia. This exception would not apply in the case of distributions paid out of non-taxed earnings made by Ecopetrol which would be subject to income tax at the 33% rate.

Taxation on Capital Gains for the sale of ADRs

Under Colombian law, capital from the sale of ADRs are not subject to income tax in Colombia as they are considered sourced foreign income.

Similarly, capital gains earned by foreign capital investment funds arising from the purchase or sale of securities are not subject to income taxes in Colombia. The remittance of capital gains to the Depositary is not subject to income tax in Colombia.

Dividends paid to foreign investment capital funds are subject to a 33% withholding income tax.

Tax Treatment in Colombia of Non-Residents who Purchase Ecopetrol’s shares in Colombia’s securities market

Dividends

Dividends paid to foreign companies, other foreign entities, non-Colombian residents or successors of non-Colombian residents are subject to Colombian income tax.

To avoid double taxation, corporate and branch profits are taxed at the corporate or branch level. If the accounting earnings and profits of a Colombian corporation exceed the tax profits subject to income tax, the excess is subject to income tax at the shareholder level. If the shareholder is a non-Colombian resident, the applicable tax rate is 33%.

Therefore, all distributions, including the payment of dividends, made by Ecopetrol to shareholders not resident in Colombia, will be exempted from income, withholding and remittance taxes. This exception would not

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apply in the case of distributions paid out of non-taxed earnings made by Ecopetrol which would be subject to the 33% income tax rate.

Taxation on Capital Gains for the sale of shares

Capital gains obtained in the sale of shares listed on the BVC and owned by the same beneficial owner, are not subject to income tax in Colombia, provided that the shares sold during the taxable year do not represent more than 10% of the outstanding shares of the listed company. However, a seller of shares must file an income tax return for each transaction involving a sale of shares within the month following the sale, even when such sale is not subject to any tax.

Tax treatment by Non- Residents who purchase Ecopetrol’s shares in BVC market and exchange them for ADRs

Dividends

Dividends paid to ADRs are not subject to income, withholding or remittance taxes. In the event Ecopetrol distributes dividends from such taxes are paid is the Depositary of ADRs. In any case, the Depositary of ADRs is only subject to income tax or complementary taxes non-taxed earnings the dividend payments would be taxed at the 33% rate.

Material U.S. Federal Income Tax Consequences

The following discussion is a summary of the material U.S. federal income tax consequences of purchasing, holding and disposing of our common shares or ADSs. This discussion applies only to beneficial owners of common shares or ADSs that are “U.S. Holders,” as defined below, that hold the common shares or ADSs as “capital assets” (generally, property held for investment). This discussion is based on the U.S. Internal Revenue Code of 1986, as amended, or the Code, its legislative history, existing final, temporary and proposed Treasury Regulations, administrative pronouncements by the U.S. Internal Revenue Service, or IRS, and judicial decisions, all as currently in effect and all of which are subject to change (possibly on a retroactive basis) and to different interpretations.

This discussion is also based in part on the representations of the depositary and the assumption that each obligation in the deposit agreement and any related agreement will be performed in accordance with its terms.

This discussion does not purport to address all U.S. federal income tax consequences that may be relevant to a particular U.S. holder and you are urged to consult your own independent tax advisor regarding your specific tax situation. The discussion does not address the tax consequences that may be relevant to U.S. Holders in special tax situations, including, for example:

• insurance companies;

• tax-exempt organizations;

• broker-dealers;

• traders in securities that elect to mark to market;

• banks or other financial institutions;

• partnerships or other pass-through entities;

• persons whose functional currency for U.S federal income tax purposes is not the U.S. dollar;

• real estate investment trusts, regulated investment companies or grantor trusts;

• persons that received our common stock or ADSs as compensation for the performance of services;

• U.S. expatriates;

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• persons that hold our common shares or ADSs as part of a hedge, straddle, conversion or other integrated transaction; or

• persons that own, directly, indirectly or constructively, 10% or more of the total combined voting power of our shares.

Except where specifically described below, this discussion assumes that we are not a passive foreign investment company, or PFIC, for U.S. federal income tax purposes. See “—Passive Foreign Investment Companies.” Further, this discussion does not address U.S. federal estate and gift tax or the alternative minimum tax consequences of holding common shares or ADSs or the indirect consequences to holders of equity interests in partnerships (or any other entity treated as a partnership for U.S. federal income tax purposes) that own our common shares or ADSs. In addition, this discussion does not address the state, local and non-U.S. tax consequences of holding our common shares or ADSs.

You should consult your own tax advisor regarding the U.S. federal, state and local, as well as non-U.S., income and other tax consequences of purchasing, owning and disposing of our common shares or ADSs in your particular circumstances.

You are a “U.S. Holder” if you are a beneficial owner of common shares or ADSs and you are for U.S. federal income tax purposes:

• an individual who is a citizen or resident of the United States;

• a corporation, or any other entity taxable as a corporation, created or organized in or under the laws of the United States, any state thereof or the District of Colombia;

• an estate the income of which is subject to U.S. federal income tax regardless of its source; or

• a trust if (i) a court within the United States is able to exercise primary supervision over its administration and one or more U.S. persons have the authority to control all substantial decisions of the trust or (ii) otherwise if the trust has a valid election in effect under current U.S. Treasury regulations to be treated as a U.S. person.

If a partnership holds common shares or ADSs the tax treatment of a partner will generally depend upon the status of the partner and upon the activities of the partnership. A partner of a partnership considering the purchase of our common shares or ADSs should consult its own independent tax advisor regarding the U.S. federal income tax consequences of investing in our common shares or ADSs through a partnership.

For U.S. federal income tax purposes, if you are a holder of ADSs, you generally will be treated as the owner of our common stock represented by such ADSs.

Distributions on Common shares or ADSs

If you are a U.S. Holder, for U.S. federal income tax purposes, distributions made by us of cash or property with respect to common shares or ADSs generally will be treated as a dividend for U.S. federal income tax purposes to the extent paid out of our current or accumulated earnings and profits (as determined under U.S. federal income tax principles). A U.S. Holder of common shares or ADSs generally will be taxed on such dividend as ordinary income. Distributions in excess of our current or accumulated earnings and profits will be treated first as a tax-free return of capital reducing such U.S. Holder’s adjusted tax basis in the common shares or ADSs. Any distribution in excess of such adjusted tax basis will be treated as capital gain and will be either long-term or short-term capital gain depending upon whether the U.S. Holder held the common shares or ADSs for more than one year. Distributions of additional common shares or ADSs to U.S. Holders that are part of a pro rata distribution to all of our shareholders generally will not be subject to U.S. federal income tax. We do not maintain calculations of our earnings and profits under U.S. federal income tax principles, and, therefore, U.S. Holders should expect that any distributions generally will be reported as dividends for U.S. federal income tax purposes. As used below, the term “dividend” means a distribution that constitutes a dividend for U.S. federal income tax purposes.

A U.S. Holder will be entitled, subject to a number of complex limitations and conditions, to claim a U.S. foreign tax credit in respect of any Colombian income taxes withheld on dividends received on common shares or

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ADSs. U.S. Holders who do not elect to claim a credit for any foreign income taxes paid during the taxable year may instead claim a deduction in respect of such Colombian income taxes. Dividends received with respect to the common shares or ADSs will be treated as foreign source income, subject to various classifications and other limitations. For purposes of the U.S. foreign tax credit limitation, foreign source income is separated into different “baskets,” and the credit for foreign taxes on income in any basket is limited to the U.S. federal income tax allocable to such income. Dividends paid with respect to our common shares or ADSs generally will constitute “passive category income” in most cases. The U.S. Treasury Department has expressed concerns that parties to whom depositary shares such as the ADSs are released may be taking actions that are inconsistent with the claiming of foreign tax credits by U.S. Holders of such ADSs. Accordingly, the analysis of the creditability of Colombian income taxes described above could be affected by future actions that may be taken by the U.S. Treasury Department. The rules relating to computing foreign tax credits or deducting foreign income taxes are extremely complex, and U.S. Holders are urged to consult their own independent tax advisors regarding the availability of foreign tax credits with respect to any Colombian income taxes withheld from payment.

Dividends paid by us generally will not be eligible for the dividends received deduction available under the Code to certain U.S. corporate shareholders. Also, dividends paid by us generally will not be eligible for the preferential tax rates available to U.S. non-corporate shareholders for certain qualified dividend income.

The amount of any cash distribution paid in Pesos will be included in your gross income in an amount equal to the U.S. dollar value of the distribution, calculated by reference to the exchange rate in effect at the time the distribution is received by the U.S. Holder, in the case of our common shares, or by the depositary, in the case of ADSs, regardless of whether the payment is in fact converted to U.S. dollars at that time. A U.S. Holder should not recognize any foreign currency gain or loss in respect of such distribution if such Pesos are converted into U.S. dollars on the date they are received by the U.S. Holder, in the case of our common shares, or by the depositary, in the case of ADSs. If the Pesos are not converted into U.S. dollars on the date of receipt, however, gain or loss may be recognized upon a subsequent sale or other disposition of the Pesos. Such foreign currency gain or loss, if any, will be U.S. source ordinary income or loss. U.S. Holders should consult with their independent tax advisors regarding the treatment of any foreign currency gain or loss if any Pesos received as a dividend are not converted into U.S. dollars on the date of receipt.

Sale, Exchange or Other Taxable Dispositions of Common shares or ADSs

A U.S. Holder generally will recognize capital gain or loss upon the sale, exchange or other taxable disposition of common shares or ADSs in an amount equal to the difference between the amount realized on the sale, exchange or other taxable disposition of the common shares or ADSs and the U.S. Holder’s adjusted tax basis in the common shares or ADSs. Any gain or loss will be long-term capital gain or loss if the common shares or ADSs have been held for more than one year. Certain non-corporate U.S. Holders (including individuals) may be eligible for preferential rates of U.S. federal income tax in respect of long-term capital gains. The deductibility of capital losses is subject to limitations under the Code.

If you are a U.S. Holder of common shares or ADSs, the initial tax basis of your common shares or ADSs will be the U.S. dollar value of the Peso-denominated purchase price determined on the date of purchase. If the common shares or ADSs are treated as traded on an “established securities market,” a cash basis U.S. Holder, or, if it elects, an accrual basis U.S. Holder, will determine the dollar value of the cost of such common shares or ADSs by translating the amount paid at the spot rate of exchange on the settlement date of the purchase. If you convert U.S. dollars to Pesos and immediately use that currency to purchase common shares or ADSs, such conversion generally will not result in taxable gain or loss to you.

With respect to the sale or exchange of common shares or ADSs, the amount realized generally will be the U.S. dollar value of the payment received determined on (i) the date of receipt of payment in the case of a cash basis U.S. Holder and (ii) the date of disposition in the case of an accrual basis U.S. Holder. If the common shares or ADSs are treated as traded on an “established securities market,” a cash basis taxpayer, or, if it elects, an accrual basis taxpayer, will determine the U.S. dollar value of the amount realized by translating the amount received at the spot rate of exchange on the settlement date of the sale.

If a Colombian income tax is withheld on the sale, exchange or other taxable disposition of common shares or ADSs, the amount realized by a U.S. Holder will include the gross amount of the proceeds of that sale or other disposition before deduction of the Colombian income tax. Capital gain or loss, if any, realized by a U.S. Holder on the sale, exchange or other taxable disposition of common shares or ADSs generally will be treated as U.S. source

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income or loss for U.S. foreign tax credit purposes. Consequently, in the case of a disposition of a common share or ADS that is subject to Colombian income tax imposed on the gain, the U.S. Holder may not be able to benefit from the foreign tax credit for the Colombian income tax (because the income or loss on the disposition would be U.S. sourced), unless the U.S. Holder can apply the credit against U.S. federal income tax payable on other income from foreign sources. Alternatively, the U.S. Holder may take a deduction for the Colombian income tax if it does not elect to claim a foreign tax credit for any foreign taxes paid or accrued during the taxable year.

Deposits and withdrawals of common shares in exchange for ADSs will not result in the realization of gain or loss for U.S. federal income tax purposes.

Passive Foreign Investment Companies

Special U.S. federal income tax rules apply to U.S. Holders owning shares in a PFIC. A non-U.S. corporation generally will be classified as a PFIC for U.S. federal income tax purposes in any taxable year in which, after applying certain look-through rules with respect to the income and assets of subsidiaries, either:

• at least 75% of its gross income is passive income; or

• at least 50% of the average value of its gross assets is attributable to assets that produce passive income or are held for the production of passive income.

Passive income for this purpose generally includes, among other things, dividends, interest, royalties, rent, gains from the disposition of passive assets and gains from commodities transactions (other than gains from commodities transactions derived in the active conduct of a trade or business and not derived from a related person).

Based on current estimates of our income and assets, we do not believe that we were classified for our most recently ended taxable year, or will be classified for our current taxable year, as a PFIC for U.S. federal income tax purposes, and we intend to continue our operations in such a manner that we do not expect that we would become a PFIC in the future. However, there can be no assurance in this regard, because the PFIC determination is made annually and is based on the portion of our assets (including goodwill) and income that is characterized as passive under the PFIC rules, and further because our business plans may be subject to change. If we are or become a PFIC, unless a U.S. Holder elects to be taxed annually on a mark-to-market basis with respect to its common shares or ADSs, as described below, any gain realized on a sale or other taxable disposition of our common shares or ADSs and certain “excess distributions” (generally distributions in excess of 125% of the average distribution over a three-year period or, if shorter, the holding period for our common shares or ADSs) will be treated as ordinary income and will be subject to tax as if (i) the excess distribution or gain had been realized ratably over the U.S. Holder’s holding period for our common shares or ADSs, (ii) the amount deemed realized in each year had been subject to tax in each such year at the highest marginal rate for such year, and (iii) the interest charge generally applicable to underpayments of tax had been imposed on the taxes deemed to have been payable in those years. Income allocated to the current period or any taxable period before we became a PFIC, would be subject to tax at the U.S. Holder’s regular ordinary income rate for the current year and would not be subject to the interest charge discussed above.

If we are treated as a PFIC, the rules above can be avoided by a U.S. Holder that makes a mark-to-market election. A U.S. Holder may make a mark-to-market election for our common shares or ADSs if our common shares or ADSs constitute “marketable stock” as defined in the Treasury Regulations. Our common shares and ADSs will be “marketable stock” if they are “regularly traded” on a “qualified exchange or other market.” We cannot provide any assurance that our common shares or ADSs are or will be considered “marketable stock” for this purpose. In particular, it is unclear whether the BVC would meet the requirements for a “qualified exchange or other market.” If a mark-to-market election were made, a U.S. Holder would take into account each year the appreciation or depreciation in value of its common shares or ADSs as if the common shares or ADSs were sold at fair market value at the end of the year. Such appreciation or depreciation generally would be treated as ordinary income or ordinary loss, as would gains or losses on actual dispositions of common shares or ADSs. A U.S. Holder will be entitled to deduct as an ordinary loss each year the excess of such holder’s adjusted tax basis in the common shares over their fair market value at the end of the year, but only to the extent of the net amount previously included in income as a result of the mark-to-market election. A mark-to-market election under the PFIC rules with respect to shares would not apply to a subsidiary PFIC, and a U.S. Holder would not be able to make such a mark-to-market election in respect of its indirect ownership interest in that subsidiary PFIC. Consequently, U.S. Holders of shares

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could be subject to the PFIC rules with respect to income of the subsidiary PFIC, the value of which already had been taken into account indirectly via mark-to-market adjustments.

Any U.S. Holder who owns common shares or ADSs during any year that we are a PFIC would be required to file IRS Form 8621. U.S. Holders should consult their own independent tax advisors regarding the application of the PFIC rules to the common shares or ADSs and the availability and advisability of making a mark-to-market election should we be considered a PFIC for any taxable year.

Backup Withholding and Information Reporting

In general, dividends on common shares or ADSs, and payments of the proceeds of a sale, exchange or other taxable disposition of common shares or ADSs, paid within the United States, by a U.S. payor or through certain U.S.-related financial intermediaries to a U.S. Holder are subject to information reporting and may be subject to backup withholding at a current rate of 28% unless the holder (i) establishes that it is a corporation or other exempt recipient or (ii) with respect to backup withholding, provides an accurate taxpayer identification number and certifies that it is a U.S. person and that no loss of exemption from backup withholding has occurred.

Backup withholding is not an additional tax. The amount of any backup withholding tax from a payment to a U.S. Holder will be allowed as a credit against the U.S. Holder’s U.S. federal income tax liability, provided that the required information is timely furnished to the IRS. A U.S. Holder generally may obtain a refund of any amounts withheld under the backup withholding rules that exceed its U.S. federal income tax liability by filing a timely refund claim with the IRS.

Non-U.S. Holders

The above discussion does not address the U.S. federal income tax consequences of purchasing, holding and disposing of our common shares or ADSs for holders of the common shares or ADSs that are not U.S. Holders. If you are such a non-U.S. holder, you should consult your own independent tax advisor regarding the U.S. federal income tax consequences, if any, of purchasing, owning and disposing of our common shares or ADSs in your particular circumstances.

ITEM10F Dividends and Paying Agents

All our common shares rank pari passu in right of payment of dividends and distributions upon liquidation. According to Colombian law and our by-laws, the ordinary shareholders’ meeting determines the allocation of distributable profits as dividends for the preceding fiscal year. The ordinary shareholders’ meeting must be held within three months following the end of the fiscal year.

Once profits are declared, we are obliged under Colombian law to subtract the following amounts from our net profits:

• first, an appropriation is made for the payment of income tax for the corresponding fiscal year;

• second, an amount equivalent to 10% of net profits is set aside to build up the legal reserve until that reserve is equal to at least 50% of the outstanding capital;

• third, in case there were losses in prior years, the balance is used to offset such losses; and

• fourth, the remaining amount will serve as the base for the dividends that are to be distributed and paid.

Pursuant to Colombian law, the vote of at least 78% of the shares represented entitled to vote is required to approve the distribution of less than 50% of the annual net profits. If the sum of all legal reserves (statutory, legal and optional) exceed the amount of the outstanding capital, the company must distribute at least 70% of the annual net profits.

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Colombian law provides that any dividend payable in stock requires the approval of at least 80% of the shares present at a shareholders’ meeting. If such majority is not obtained, shares may be distributed as dividends to the shareholders accepting stock dividends payment.

To the extent that we declare and pay dividends, owners of ADSs on the relevant record date will be entitled to receive dividends payable in respect of shares underlying the ADSs, subject to the terms of the relevant deposit agreement. Cash dividends may be paid to the depositary in Pesos and, except as otherwise described under Item 12D — “American Depositary Shares”, are converted into U.S. dollars by the depositary.

Pursuant to Colombian law, our ex-dividend date is ten business days prior to the payment date. Our dividend paying agent is DECEVAL (the registrar for the BVC).

The following table sets forth the dividends per share declared by our Board of Directors and paid in Pesos for the years ended December 31, 2007, 2006, 2005, 2004 and 2003. As additional information for the reader, we present these values in U.S. dollars.

Fiscal Year	Month and Year of Payment	Total Dividend per Share (in Ps$)		Total Dividend per Share (in US$)(1)
2007	April 2008		28.75	n.m.
	July 2008		28.75	n.m.
	October 2008		28.75	Not yet available
	December 2008		28.75	Not yet available
2006	May 2007		54.97	0.03
	June 2007		13.74	0.01
	August 2007		22.92	0.01
	September 2007		15.18	0.01
	October 2007		13.76	0.01
	December 2007		2.43	n.m.
2005	July 2006		27.48	0.01
	August 2006		13.74	0.01
	September 2006		13.74	0.01
2004	August 2005		11.89	0.01
	September 2005		11.89	0.01
	October 2005		11.89	0.01
2003	September 2004		21.22	0.01
	October 2004		10.61	n.m.

______________

n.m.= Not meaningful.

(1) Amounts in U.S. dollars have been translated at the Representative Market Rate for the last business day of the month in which dividends were paid as calculated and certified by the Superintendency of Finance. These amounts are only presented for information. Dividends are paid in Pesos.

 

ITEM10G Statement by Experts

Our consolidated financial statements at December 31, 2007 and 2006 and for each of the three years in the period ended December 31, 2007 appearing in this registration statement have been audited by Ernst & Young Audit Ltda, independent registered public accounting firm, as set forth in their report thereon appearing elsewhere herein, and are included in reliance upon such report given on the authority of such firm as experts in accounting and auditing.

Ryder Scott, DeGolyer and MacNaughton, and Gaffney, Cline & Associates have consented to the inclusion in this registration statement of reference to their engineering reports for the years ended December 31, 2006.

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ITEM10H Documents on Display

We have filed this registration statement on Form 20-F with the SEC under the Securities and Exchange Act of 1934, as amended, with respect to our common stock. You may read and copy all or any portion of this registration statement or other information in the SEC’s public reference room at 100 F. Street, NE, Washington, D.C. 20549. You can also request copies of these documents upon payment of a duplicating fee, by writing the SEC. Please call the SEC at 1-800-SEC-0330 for further information on the operation of the public reference rooms. The SEC maintains a web site (http://www.sec.gov) that contains all of our filings with the SEC.

 

ITEM10I Subsidiary Information

See Note 1— “Principles of Consolidation” in our consolidated accounting statements.

 

ITEM11 Quantitative and Qualitative Disclosures About Market Risk

Risk Management and Financial Instruments

We are subject to a number of risks. The most important risk we face is crude oil price volatility. Other exposures include currency and interest rate risk as we hold in our investment portfolio a number of foreign currency-denominated instruments.

Oil price risk results from our day-to-day operations as we export and import crude oil and refined products.

Currency risk is mainly an accounting risk as we have to report our financial statements in Pesos whereas 30% of our operations are denominated in U.S. dollars. We manage our currency risk by maintaining funds in U.S. dollars and in Pesos. We use our U.S. dollar funds to meet our U.S. dollar denominated expenses and liabilities and our Peso funds to meet our Peso denominated expenses.

Interest rate risk results from our exposure value of our floating-rate investments held in our investment portfolio. As interest rates vary, the value of our floating-rate investments held in our investment portfolio can experience fluctuations as a result of market movements.

Currently we manage our exposure to oil price variation risk using the cash flow at risk methodology. Our exposure tool prices fluctuations which are measured based on the impact such price variations have on our cash flow. Specifically, we implemented CF@R or cash flow at risk methodology to determine the impact of oil price variations on our cash flow.

From time to time we enter into derivative contracts as we deem necessary to hedge our exposure to oil price, exchange rate and interest rate risks.

With respect to interest rate risk, the effective duration of our fixed income portfolio in U.S. dollars vary between +/- 25% versus the portfolio’s benchmark.

Since 2007 we have been using a financial model based on key rate durations to measure our portfolio’s sensibility to interest rate changes from each segment of the curve.

Throughout this model, risk managers try to recognize the fact that yield curve movements are caused by multiple market factors and do not depend on a curve equilibrium model. Also, the model allows us to calculate value at risk versus a previously defined benchmark.

Finally, at December 2007 we did not have any off-balance sheet debt. As a result of this, our exposure to passive interest rate is only marginal.

Investment guidelines

Following Decree 648 of 2001, our management established investment guidelines for our investment portfolios. Our guidelines determine that we should invest our excess cash in fixed-income securities of issuers

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rated A+ or higher according to the rating issued by a recognized rating agency. We have no limitation to invest in securities issued or guaranteed by the U.S. government and we may invest in securities issued by OECD member countries so long as they are rated A+ or higher.

Our investment portfolio in U.S. dollars is segmented in four tranches, each one matching our liquidity needs. Working capital is calculated taking into account our cash flow needs for the next 60 days. The liquidity tranche is calculated as the contingent cash flow needs over the working capital taking into account the development of capital expenditure projects. The asset liability tranche is built to match our off-balance debt. Finally, the investment tranche is composed of the remaining resources from the total portfolio after deducting the above mentioned tranches.

Sensitivity Analysis

	Income Statement 2007		Income Statement Case WTI(1) + US$1		Differs Between Real 2007 and Case WTI	Income Statement Case TRM - 1%		Differs Between Real 2007 and Case TRM
	(Pesos in billions)
Local Revenue	16,003.00		16,151.07		148.07	15,935.38		(67.61	)
Export Revenue	6,329.32		6,420.64		91.32	6,262.62		(66.70	)
Total Revenue	22,332.32		22,571.71		239.39	22,198.01		(134.31	)
Cost of Sales	12,058.53		12,092.79		34.26	12,004.96		(53.57	)
Selling Operating Expenses	1,079.35		1,079.35		0.00	1,079.35		0.00
Administrative Operating Expenses	408.11		408.11		0.00	408.11		0.00
Operating Profit	8,786.34		8,991.47		205.13	8,705.60		(80.74	)
Non-Operating Income (expenses)	(1,721.04	)	(1,721.04	)	0.00	(1,741.04	)	(20.00	)
Profit before income Tax	7,065.30		7,270.43		205.13	6,964.56		(100.74	)
Income Tax	1,885.51		1,940.30		54.79	1,858.60		(26.91	)
Net Income	5,179.79		5,330.13		150.34	5,105.96		(73.83	)

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WTI= West Texas Intermediate.

(1) Average WTI for 2007 was US$72.31 for barrel. Average Market Representative Rate for 2007 was $2,077.30 per US$1.

Assumptions for the sensitivity analysis of Financial Statements

• The base scenario on which our sensitivity analysis is made corresponds to the Consolidated Statements of Financial, Economic and Social Activity or Income Statement for 2007 as presented elsewhere in this registration statement.

• The sensitivity of the WTI price index is the increase/decrease of one dollar per barrel of crude oil in the average WTI reference price based on a 365-day year, for 2007. Prices assumed correspond to real prices for crude oil, natural gas and refined products for 2007.

• The WTI sensitivity analysis maintains the price differentials for products against WTI prices, with the exception of price-regulated products for which real prices are taken.

• The sensitivity of our results to changes in the exchange rates, is the decrease by 1% on the average exchange rate for 2007 on a calendar day basis.

• Local sales are only affected by the variation in the exchange rates when their reference price is determined in U.S. Dollars.

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The table below sets forth the line items that are being affected by the variation on the reference prices or the average exchange rate.

VARIATION ON WTI REFERENCE PRICE	VARIATION ON AVERAGE EXCHANGE RATE
OPERATING INCOME
Local Sales	Local Sales
Crude Oil	Crude Oil
Subsidies on regular gasoline and diesel	Jet fuel
Local non-regulated product (Indirect effect)	Natural gas
	Subsidies on regular gasoline and diesel
Exports	Exports
Crude Oil	Crude Oil
Refined products	Refined products
Natural gas	Natural gas
COST OF SALES
Local purchases	Local purchases
Purchases from business partners	Purchases from business partners
Purchases of hydrocarbons from the ANH	Purchases of hydrocarbons from the ANH
Imports	Imports
Crude Oil	Crude Oil
Products	Products
NON-OPERATING INCOME
	Exchange income
	Exchange loss

 

ITEM12 Description of Securities Other than Equity Securities

Not applicable.

 

ITEM12A Debt Securities

Not applicable.

 

ITEM12B Warrants and Rights

Not applicable.

 

ITEM12C Other Securities

Not applicable.

 

ITEM12D American Depositary Shares

American Depositary Receipts

JPMorgan Chase Bank, N.A., as depositary or the Depositary will issue the ADSs. Each ADS will represent an ownership interest in 20 shares which will be deposited with the custodian, as agent of the Depositary, under the deposit agreement among ourselves, the Depositary and yourself as an ADR holder. In the future, each ADS will also represent any securities, cash or other property deposited with the Depositary but which they have not distributed directly to you. Unless specifically requested by persons depositing shares, all ADSs will be issued on the books of our Depositary in book-entry form and periodic statements will be mailed to you which reflect your ownership interest in such ADSs. In our description, references to American Depositary receipts or ADRs shall include the statements you will receive which reflects your ownership of ADSs.

The Depositary’s office is located at 4 New York Plaza, New York, NY 10004.

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You may hold ADSs either directly or indirectly through your broker or other financial institution. If you hold ADSs directly, by having an ADS registered in your name on the books of the Depositary, you are an ADR holder. This description assumes you hold your ADSs directly. If you hold the ADSs through your broker or financial institution nominee, you must rely on the procedures of such broker or financial institution to assert the rights of an ADR holder described in this section. You should consult with your broker or financial institution to find out what those procedures are.

As an ADR holder, we will not treat you as a shareholder of ours and you will not have any shareholder rights. Colombian law governs shareholder rights. Because the Depositary or its nominee will be the shareholder of record for the shares represented by all outstanding ADSs, shareholder rights rest with such record holder. Your rights are those of an ADR holder. Such rights derive from the terms of the deposit agreement to be entered into among us, the Depositary and all registered holders from time to time of ADSs issued under the deposit agreement. The obligations of the Depositary and its agents are also set out in the deposit agreement. Because the Depositary or its nominee will actually be the registered owner of the shares, you must rely on it to exercise the rights of a shareholder on your behalf. The deposit agreement and the ADSs are governed by New York law.

The following is a summary of the material terms of the deposit agreement. Because it is a summary, it does not contain all the information that may be important to you. For more complete information, you should read the entire deposit agreement and the form of ADR which contains the terms of your ADSs. You can read a copy of the deposit agreement which is filed as an exhibit to the registration statement of which this prospectus forms a part. You may also obtain a copy of the deposit agreement at the SEC’s Public Reference Room which is located at 100 F Street, NE, Washington, DC 20549. You may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-732-0330. You may also find the registration statement and the attached deposit agreement from the SEC’s website at http://www.sec.gov.

Share Dividends and Other Distributions

How will I receive dividends and other distributions on the shares underlying my ADSs?

We may make various types of distributions with respect to our securities. The Depositary has agreed to pay to you the cash dividends or other distributions it or the custodian receives on shares or other deposited securities, after converting any cash received into U.S. dollars and, in all cases, making any necessary deductions provided for in the deposit agreement. You will receive these distributions in proportion to the number of underlying securities that your ADSs represent.

Except as stated below, to the extent the Depositary is legally permitted, it will deliver such distributions to ADR holders in proportion to their interests in the following manner:

• Cash. Subject to and any restrictions imposed by the laws of Colombia, regulations or applicable permits issued by any governmental body, the Depositary will distribute any U.S. dollars available to it resulting from a cash dividend or other cash distribution or the net proceeds of sales of any other distribution or portion thereof (to the extent applicable), on an averaged or other practicable basis, subject to (i) appropriate adjustments for taxes withheld, (ii) such distribution being impermissible or impracticable with respect to certain registered ADR holders, and (iii) deduction of the Depositary’s expenses in (1) converting any foreign currency to U.S. dollars to the extent that it determines that such conversion may be made on a reasonable basis, (2) transferring foreign currency or U.S. dollars to the United States by such means as the Depositary may determine to the extent that it determines that such transfer may be made on a reasonable basis, (3) obtaining any approval or license of any governmental authority required for such conversion or transfer, which is obtainable at a reasonable cost and within a reasonable time and (4) making any sale by public or private means in any commercially reasonable manner. If exchange rates fluctuate during a time when the Depositary cannot convert a foreign currency, you may lose some or all of the value of the distribution.

• Shares. In the case of a distribution in shares, the Depositary will issue additional ADRs to evidence the number of ADSs representing such shares. Only whole ADSs will be issued. Any shares which would result in fractional ADSs will be sold and the net proceeds will be distributed in the same manner as cash to the ADR holders entitled thereto.

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• Rights to receive additional shares. In the case of a distribution of rights to subscribe for additional shares or other rights, if we provide satisfactory evidence that the Depositary may lawfully distribute such rights, the Depositary will distribute warrants or other instruments representing such rights. However, if we do not furnish such evidence, the Depositary may:

- sell such rights if practicable and distribute the net proceeds as cash; or

- if it is not practicable to sell such rights, do nothing and allow such rights to lapse, in which case ADR holders will receive nothing.

We have no obligation to file a registration statement under the Securities Act of 1933 in order to make any rights available to ADR holders.

• Other Distributions. In the case of a distribution of securities or property other than those described above, the Depositary may either (i) distribute such securities or property in any manner it deems equitable and practicable or (ii) to the extent the Depositary deems distribution of such securities or property not to be equitable and practicable, sell such securities or property and distribute any net proceeds in the same way it distributes cash.

If the Depositary determines that any distribution described above is not practicable with respect to any specific ADR holder, the Depositary may choose any practicable method of distribution for such ADR holder, including the distribution of foreign currency, securities or property, or it may retain such items, without paying interest on or investing them, on behalf of the ADR holder as deposited securities, in which case the ADSs will also represent the retained items.

Any U.S. dollar will be distributed by checks drawn on a bank in the United States for whole dollars and cents. Fractional cents will be withheld without liability and dealt with by the Depositary in accordance with its then current practices.

The Depositary is not responsible if it decides that it is unlawful or impractical to make a distribution available to any ADR holders.

There can be no assurance that the Depositary will be able to convert any currency at a specified exchange rate or sell any property, rights, shares or other securities at a specified price, nor that any of such transactions can be completed within a specified time period.

Deposit, Withdrawal and Cancellation

How does the Depositary issue ADSs?

The Depositary will issue ADSs if you or your broker deposits shares or evidence of rights to receive shares with the custodian and pay the fees and expenses owing to the Depositary in connection with such issuance.

Shares deposited with the custodian must be accompanied by certain delivery documentation, including instruments showing that such shares have been properly transferred or endorsed to the person on whose behalf the deposit is being made.

The custodian will hold all deposited shares for the account of the Depositary. ADR holders thus have no direct ownership interest in the shares and only have such rights as are contained in the deposit agreement. The custodian will also hold any additional securities, property and cash received on or in substitution for the deposited shares. The deposited shares and any such additional items are referred to as “deposited securities.”

Upon each deposit of shares, receipt of related delivery documentation and compliance with the other provisions of the deposit agreement, including the payment of the fees and charges of the Depositary and any taxes or other fees or charges owing, the Depositary will issue an ADR or ADRs in the name or upon the order of the person entitled thereto evidencing the number of ADSs to which such person is entitled. All of the ADSs issued will, unless specifically requested to the contrary, be part of the Depositary’s direct registration system, and a

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registered holder will receive periodic statements from the Depositary which will show the number of ADSs registered in such holder’s name. An ADR holder can request that the ADSs not be held through the Depositary’s direct registration system and that a certificated ADR be issued.

How do ADR holders cancel an ADS and obtain deposited securities?

When you turn in your ADSs at the Depositary’s office, or when you provide proper instructions and documentation in the case of direct registration ADSs, the Depositary will, upon payment of certain applicable fees, charges and taxes, deliver the underlying shares at the custodian’s office or effect delivery by such other means as the Depositary deems practicable, including transfer to an account of an accredited financial institution on your behalf. At your risk, expense and request, the Depositary may deliver deposited securities at such other place as you may request.

The Depositary may only restrict the withdrawal of deposited securities in connection with:

• temporary delays caused by closing our transfer books or those of the Depositary or the deposit of shares in connection with voting at a shareholders’ meeting, or the payment of dividends;

• the payment of fees, taxes and similar charges; or

• compliance with any U.S. or foreign laws or governmental regulations relating to the ADRs or to the withdrawal of deposited securities.

This right of withdrawal may not be limited by any other provision of the deposit agreement.

Notwithstanding anything to the contrary in the deposit agreement, holders of ADSs who are non-residents of Colombia, who withdraw deposited securities to or for their own account or the account of a non-resident third party whether or not with the purpose of selling or causing to be sold such deposited securities in Colombia simultaneously with such withdrawal, will be subject to applicable Colombian rules and regulations, including without limitation Colombia’s International Investment Statute as well as any taxes applicable thereby, as in effect from time to time. Neither we nor the Depositary or the custodian shall have any liability or responsibility whatsoever under the deposit agreement or otherwise for any action or failure to act by any Holder relating to its obligations under Colombian tax law or Colombian Foreign Investment Law or any other Colombian law or regulation relating to foreign investment in Colombia in respect of a withdrawal or sale of deposited securities, including, without limitation, any failure by any holder to comply with a requirement to register such investment prior to such withdrawal, or any failure by any holder to report foreign exchange transactions to the Colombian Central Bank, as the case may be.

Record Dates

The Depositary may fix record dates for the determination of the ADR holders who will be entitled (or obligated, as the case may be):

• to receive any distribution on or in respect of shares;

• to give instructions for the exercise of voting rights at a meeting of holders of shares;

• for the determination of the registered holders who shall be responsible for the fee assessed by the Depositary for administration of the ADR program and for any expenses as provided for in the ADR; or

• to receive any notice or to act in respect of other matters.

All the above are subject to the provisions of the deposit agreement.

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Voting Rights

How do I vote?

If you are an ADR holder and the Depositary asks you to provide it with voting instructions, you may instruct the Depositary how to exercise the voting rights for the shares which underlie your ADSs. After receiving voting materials from us, the Depositary will notify the ADR holders of any shareholders’ meeting or solicitation of consents or proxies. This notice will state such information as is contained in the voting materials and describe how you may instruct the Depositary to exercise the voting rights for the shares which underlie your ADSs and will include instructions for giving a discretionary proxy to a person designated by us. For instructions to be valid, the Depositary must receive them in the manner and on or before the date specified. The Depositary will try, as far as is practical, subject to the provisions of and governing the underlying shares or other deposited securities, to vote or to have its agents vote the shares or other deposited securities as you instruct. The Depositary will only vote or attempt to vote as you instruct. The Depositary will not itself exercise any voting discretion. Furthermore, neither the Depositary nor its agents are responsible for any failure to carry out any voting instructions, for the manner in which any vote is cast or for the effect of any vote.

There is no guarantee that you will receive voting materials in time to instruct the Depositary to vote and it is possible that you, or persons who hold their ADSs through brokers, dealers or other third parties, will not have the opportunity to exercise a right to vote. The holders will be solely responsible for any exercise of the voting rights of the deposited shares represented by the deposited securities by the ADSs, if such vote is made pursuant to the procedure described in the deposit agreement.

Reports and Other Communications

Will I be able to view our reports?

The Depositary will make available for inspection by ADR holders any written communications from us which are both received by the custodian or its nominee as a holder of deposited securities and made generally available to the holders of deposited securities. We will furnish these communications in English when so required by any rules or regulations of the SEC.

Additionally, if we make any written communications generally available to holders of our shares, including the Depositary or the custodian, and we request the Depositary to provide them to ADR holders, the Depositary will mail copies of them, or, at its option, English translations or summaries of them to ADR holders.

Fees and Expenses

What fees and expenses will I be responsible for paying?

The Depositary may charge each person to whom ADSs are issued, including, without limitation, issuances against deposits of shares, issuances in respect of share distributions, rights and other distributions, issuances pursuant to a stock dividend or stock split declared by us or issuances pursuant to a merger, exchange of securities or any other transaction or event affecting the ADSs or deposited securities, and each person surrendering ADSs for withdrawal of deposited securities in any manner permitted by the deposit agreement or whose ADRs are cancelled or reduced for any other reason, US$5.00 for each 100 ADSs (or any portion thereof) issued, delivered, reduced, cancelled or surrendered, the case may be. The Depositary may sell (by public or private sale) sufficient securities and property received in respect of a share distribution, rights and/or other distribution prior to such deposit to pay such charge.

The following additional charges shall be incurred by the ADR holders, by any party depositing or withdrawing shares or by any party surrendering ADSs or to whom ADSs are issued (including, without limitation, issuance pursuant to a stock dividend or stock split declared by the Company or an exchange of stock regarding the ADRs or the deposited securities or a distribution of ADSs), whichever is applicable:

• a fee of US$1.50 per ADR or ADRs for transfers of certificated or direct registration ADRs;

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• a fee of up to US$0.05 per ADS for any cash distribution made pursuant to the deposit agreement;

• a fee of US$0.05 per ADS per calendar year (or portion thereof) for services performed by the Depositary in administering our ADR program (which fee may be charged on a periodic basis during each calendar year and shall be assessed against holders of ADRs as of the record date or record dates set by the Depositary during each calendar year and shall be payable in the manner described in the next succeeding provision);

• any other charge payable by any of the Depositary, any of the Depositary’s agents, including, without limitation, the custodian, or the agents of the Depositary’s agents in connection with the servicing of our shares or other deposited securities (which charge shall be assessed against registered holders of our ADRs as of the record date or dates set by the Depositary and shall be payable at the sole discretion of the Depositary by billing such registered holders or by deducting such charge from one or more cash dividends or other cash distributions);

• a fee for the distribution of securities (or the sale of securities in connection with a distribution), such fee being in an amount equal to the fee for the execution and delivery of ADSs which would have been charged as a result of the deposit of such securities (treating all such securities as if they were shares) but which securities or the net cash proceeds from the sale thereof are instead distributed by the Depositary to those holders entitled thereto;

• stock transfer or other taxes and other governmental charges;

• cable, telex and facsimile transmission and delivery charges incurred at your request;

• transfer or registration fees for the registration of transfer of deposited securities on any applicable register in connection with the deposit or withdrawal of deposited securities;

• expenses of the Depositary in connection with the conversion of foreign currency into U.S. dollars; and

• such fees and expenses as are incurred by the Depositary (including, without limitation, expenses incurred in connection with compliance with foreign exchange control regulations or any law or regulation relating to foreign investment) in delivery of deposited securities or otherwise in connection with the Depositary’s or its custodian’s compliance with applicable laws, rules or regulations.

We will pay all other charges and expenses of the Depositary and any agent of the Depositary (except the custodian) pursuant to agreements from time to time between us and the Depositary. The fees described above may be amended from time to time.

Our Depositary has agreed to reimburse us for certain expenses we incur that are related to establishment and maintenance of the ADR program, including investor relations expenses and exchange application and listing fees. Neither the Depositary nor we can determine the exact amount to be made available to us because (i) the number of ADSs that will be issued and outstanding, (ii) the level of fees to be charged to holders of ADSs and (iii) our reimbursable expenses related to the ADR program are not known at this time. The Depositary collects its fees for issuance and cancellation of ADSs directly from investors depositing shares or surrendering ADSs for the purpose of withdrawal or from intermediaries acting for them. The Depositary collects fees for making distributions to investors by deducting those fees from the amounts distributed or by selling a portion of distributable property to pay the fees. The Depositary may collect its annual fee for Depositary services by deduction from cash distributions, or by directly billing investors, or by charging the book-entry system accounts of participants acting for them. The Depositary may generally refuse to provide services to any holder until the fees and expenses owing by such holder for those services or otherwise are paid.

Payment of Taxes

ADR holders must pay any tax or other governmental charge payable by the custodian or the Depositary on any ADS or ADR, deposited security or distribution. If an ADR holder owes any tax or other governmental charge, the Depositary may (i) deduct the amount thereof from any cash distributions, or (ii) sell deposited securities and

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deduct the amount owing from the net proceeds of such sale. In either case, the ADR holder remains liable for any shortfall. Additionally, if any tax or governmental charge is unpaid, the Depositary may also refuse to effect any registration, registration of transfer, split-up or combination of deposited securities or withdrawal of deposited securities (except under limited circumstances mandated by securities regulations). If any tax or governmental charge is required to be withheld on any non-cash distribution, the Depositary may sell the distributed property or securities to pay such taxes and distribute any remaining net proceeds to the ADR holders entitled thereto.

By holding an ADR or an interest therein, you will be agreeing to indemnify us, the Depositary, its custodian and any of our or their respective Directors, employees, agents and affiliates against, and hold each of them harmless from, any claims by any governmental authority with respect to taxes, additions to tax, penalties or interest arising out of any refund of taxes, reduced rate of withholding at source or other tax benefit obtained in respect of, or arising out of, your ADSs.

Reclassifications, Recapitalizations and Mergers

If we take certain actions that affect the deposited securities, including (i) any change in par value, split-up, consolidation, cancellation or other reclassification of deposited securities or (ii) any recapitalization, reorganization, merger, consolidation, liquidation, receivership, bankruptcy or sale of all or substantially all of our assets, then the Depositary may choose to:

• amend the form of ADR;

• distribute additional or amended ADRs;

• distribute cash, securities or other property it has received in connection with such actions;

• sell any securities or property received and distribute the proceeds as cash; or

• not perform any of the above.

If the Depositary does not choose any of the above options, any of the cash, securities or other property it receives will constitute part of the deposited securities and each ADS will then represent a proportionate interest in such property.

Amendment and Termination

How may the deposit agreement be amended?

We may agree with the Depositary to amend the deposit agreement and the ADSs without your consent for any reason. ADR holders must be given at least 30 days notice of any amendment that imposes or increases any fees or charges (other than stock transfer or other taxes and other governmental charges, transfer or registration fees, cable, telex or facsimile transmission costs, delivery costs or other such expenses), or otherwise prejudices any substantial existing right of ADR holders. If an ADR holder continues to hold an ADR or ADRs after being so notified, such ADR holder is deemed to agree to such amendment. Notwithstanding the foregoing, if any governmental body or regulatory body should adopt new laws, rules or regulations which would require amendment or supplement of the deposit agreement or the form of ADR to ensure compliance therewith, we and the Depositary may amend or supplement the deposit agreement and the ADR at any time in accordance with such changed laws, rules or regulations, which amendment or supplement may take effect before a notice is given or you otherwise receive notice. No amendment, however, will impair your right to surrender your ADSs and receive the underlying securities, except in order to comply with mandatory provisions of applicable law.

How may the deposit agreement be terminated?

The Depositary may, and shall at our written direction, terminate the deposit agreement and the ADR by mailing notice of such termination to the registered holders of ADRs at least 30 days prior to the date fixed in such notice for such termination; provided, however, if the Depositary shall have (i) resigned as Depositary under the deposit agreement, notice of such termination by the Depositary shall not be provided to registered holders unless a

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successor Depositary shall not be operating under the deposit agreement within 45 days of the date of such resignation, and (ii) been removed as Depositary under the deposit agreement, notice of such termination by the Depositary shall not be provided to registered holders of ADRs unless a successor Depositary shall not be operating under the deposit agreement on the 90^th day after our notice of removal was first provided to the Depositary. After termination, the Depositary’s only responsibility will be (i) to deliver deposited securities to ADR holders who surrender their ADRs, and (ii) to hold or sell distributions received on deposited securities. As soon as practicable after the expiration of six months from the termination date, the Depositary will sell the deposited securities which remain and hold the net proceeds of such sales, without liability for interest, in trust for the ADR holders who have not yet surrendered their ADRs. After making such sale, the Depositary shall have no obligations except to account for such proceeds and other cash. The Depositary will not be required to invest such proceeds or pay interest on them.

Limitations on Obligations and Liability to ADR holders

Limits on our obligations and the obligations of the Depositary; limits on liability to ADR holders and holders of ADSs

Prior to the issue, registration, registration of transfer, split-up, combination, or cancellation of any ADRs, or the delivery of any distribution in respect thereof, the Depositary and its custodian may require you to pay, provide or deliver:

• payment with respect thereto of (i) any stock transfer or other tax or other governmental charge, (ii) any stock transfer or registration fees in effect for the registration of transfers of shares or other deposited securities upon any applicable register and (iii) any applicable fees and expenses described in the deposit agreement;

• the production of proof satisfactory to the Depositary and/or its custodian of (i) the identity of any signatory and genuineness of any signature and (ii) such other information, including, without limitation, information as to citizenship, residence, exchange control approval, beneficial ownership of any securities, compliance with applicable law, regulations, provisions of or governing shares and terms of the deposit agreement and the ADRs, as it may deem necessary or proper;

• compliance with such regulations as the Depositary may establish consistent with the deposit agreement or any Colombian law or regulation relating to Colombian taxes, foreign investment in Colombia and laws, rules and regulations relating to the regulation of foreign exchange in Colombia.

The issuance of ADRs, the acceptance of deposits of shares, the registration, registration of transfer, split-up or combination of ADRs or the withdrawal of shares, generally or in particular instances, when the ADR register or any register for shares is closed or when any such action is deemed advisable by the Depositary; provided that the ability to withdraw shares may only be limited under the following circumstances: (i) temporary delays caused by closing transfer books of the Depositary or our transfer books or the deposit of shares in connection with voting at a shareholders’ meeting, or the payment of dividends, (ii) the payment of fees, taxes, and similar charges, and (iii) compliance with any laws or governmental regulations relating to ADRs or to the withdrawal of shares.

The deposit agreement expressly limits the obligations and liability of the Depositary, ourselves and our respective agents. Neither we nor the Depositary nor any such agent will be liable if:

• present or future law, rule or regulation of the United States, Colombia or any other country, or of any governmental or regulatory authority or securities exchange or market or automated quotation system, the provisions of or governing any deposited securities, any present or future provision of our charter, any act of God, war, terrorism or other circumstance beyond our, the Depositary’s or our respective agents’ control shall prevent, delay or subject to any civil or criminal penalty any act which the deposit agreement or the ADRs provide shall be done or performed by us, the Depositary or our respective agents (including, without limitation, voting);

• it exercises or fails to exercise discretion under the deposit agreement or the ADR;

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• it performs its obligations without gross negligence or bad faith;

• it takes any action or refrains from taking any action in reliance upon the advice of or information from legal counsel, accountants, any person presenting shares for deposit, any registered holder of ADRs, or any other person believed by it to be competent to give such advice or information; or

• it relies upon any written notice, request, direction or other document believed by it to be genuine and to have been signed or presented by the proper party or parties.

Neither the Depositary nor its agents have any obligation to appear in, prosecute or defend any action, suit or other proceeding in respect of any deposited securities or the ADRs. We and our agents shall only be obligated to appear in, prosecute or defend any action, suit or other proceeding in respect of any deposited securities or the ADRs, which in our opinion may involve us in expense or liability, if indemnity satisfactory to us against all expense (including fees and disbursements of counsel) and liability is furnished as often as may be required. The Depositary and its agents may fully respond to any and all demands or requests for information maintained by or on its behalf in connection with the deposit agreement, any registered holder or holders of ADRs, any ADSs or otherwise to the extent such information is requested or required by or pursuant to any lawful authority, including without limitation laws, rules, regulations, administrative or judicial process, banking, securities or other regulators.

Additionally, none of us, the Depositary or the custodian shall be liable for the failure by any registered holder of ADRs or beneficial owner therein to obtain the benefits of credits on the basis of non-U.S. tax paid against such holder’s or beneficial owner’s income tax liability. Neither we nor the Depositary shall incur any liability for any tax consequences that may be incurred by holders or beneficial owners on account of their ownership of ADRs or ADSs.

The Depositary will not be responsible for failing to carry out instructions to vote the deposited securities or for the manner in which the deposited securities are voted or the effect of the vote. In no event shall we, the Depositary or any of our respective agents be liable to holders of ADSs or interests therein for any indirect, special, punitive or consequential damages.

The Depositary may own and deal in deposited securities and in ADSs.

Disclosure of Interest in ADSs

To the extent that the provisions of or governing any deposited securities may require disclosure of or impose limits on beneficial or other ownership of deposited securities, other shares and other securities and may provide for blocking transfer, voting or other rights to enforce such disclosure or limits, you agree to comply with all such disclosure requirements and ownership limitations and to comply with any reasonable instructions we may provide in respect thereof. We reserve the right to request you to deliver your ADSs for cancellation and withdrawal of the deposited securities so as to permit us to deal with you directly as a holder of deposited securities and, by holding an ADS or an interest therein, you will be agreeing to comply with such instructions.

Books of Depositary

The Depositary or its agent will maintain a register for the registration, registration of transfer, combination and split-up of ADRs, which register shall include the Depositary’s direct registration system. You may inspect such records at such office during regular business hours, but solely for the purpose of communicating with other holders in the interest of business matters relating to the deposit agreement. Such register may be closed from time to time, when deemed expedient by the Depositary or when requested by us.

The Depositary will maintain facilities to record and process the issuance, cancellation, combination, split-up and transfer of ADRs. These facilities may be closed from time to time, to the extent not prohibited by law.

Pre-release of ADSs

The Depositary may issue ADSs prior to the deposit with the custodian of shares (or rights to receive shares). This is called a pre-release of the ADS. A pre-release is closed out as soon as the underlying shares (or

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rights to receive shares from us or from any registrar, transfer agent or other entity recording share ownership or transactions) are delivered to the Depositary. The Depositary may pre-release ADSs only if:

• the Depositary has received collateral for the full market value of the pre-released ADSs (marked to market daily); and

• each recipient of pre-released ADSs agrees in writing that he or she

- owns the underlying shares;

- assigns all rights in such shares to the Depositary;

- holds such shares for the account of the Depositary;

- will deliver such shares to the custodian as soon as practicable, and promptly if the Depositary so demands, and

- will not act inconsistently with treating the Depositary, acting in its capacity as such on behalf of holders, as the owner of such Shares.

In general, the number of pre-released ADSs will not evidence more than 30% of all ADSs outstanding at any given time (excluding those evidenced by pre-released ADSs). However, the Depositary may change or disregard such limit from time to time as it deems appropriate. The Depositary may retain for its own account any earnings on collateral for pre-released ADSs and its charges for issuance thereof.

Appointment

In the deposit agreement, each holder and each person holding an interest in ADSs, upon acceptance of any ADSs (or any interest therein) issued in accordance with the terms and conditions of the deposit agreement will be deemed for all purposes to:

• be a party to and bound by the terms of the deposit agreement and the applicable ADR or ADRs, and

• appoint the Depositary its attorney-in-fact, with full power to delegate, to act on its behalf and to take any and all actions contemplated in the deposit agreement and the applicable ADR or ADRs, to adopt any and all procedures necessary to comply with applicable laws and to take such action as the Depositary in its sole discretion may deem necessary or appropriate to carry out the purposes of the deposit agreement and the applicable ADR and ADRs, the taking of such actions to be the conclusive determinant of the necessity and appropriateness thereof.

ITEM13 Defaults, Dividend Arrearages and Delinquencies

Not applicable.

ITEM14 Material Modifications to the Rights of Security Holders and Use of Proceeds

Not applicable.

ITEM15 Controls and Procedures

Not applicable.

ITEM16 [Reserved]

ITEM16A Audit Committee Financial Expert

Not applicable.

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ITEM16B Code of Ethics

Not applicable.

ITEM16D Exemptions From the Listing Standards for Audit Committee

Not applicable.

ITEM16E Purchases of Equity Securities by the Issuer and Affiliated Purchasers

Not applicable.

ITEM17 Financial Statements

Not applicable.

ITEM18 Financial Statements

See page F-1.

ITEM19 Exhibits

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ANNEX I

DESCRIPTION OF PRODUCTION CONTRACTS

Region	Contract Name	Type of Agreement	Purpose	Operator	Partners	Ownership Percentage	Term of Contract	Expiration Date	Right of Reversion upon Termination	Royalty
Catatumbo-Orinoquía	Cravo Norte	Joint Venture	E&P	Occidental de Colombia Inc.	Occidental de Colombia Inc.	54.48%	Until economic limit	Until economic limit	No	5% to 25%
Catatumbo-Orinoquía	Rondon	Joint Venture	E&P	Occidental de Colombia Inc.	Occidental de Colombia Inc.	50%	28 years	January 8, 2023	Yes	8% to 25%
Catatumbo-Orinoquía	Chipiron	Joint Venture	E&P	Occidental de Colombia Inc.	Occidental de Colombia Inc. and Occidental Andina	30%	25 years	February 13, 2028	Yes	8% to 25%
Catatumbo-Orinoquía	Cosecha	Joint Venture	E&P	Occidental de Colombia Inc.	Occidental de Colombia Inc.	30%	28 years	October 31, 2030	Yes	8% to 25%
Catatumbo-Orinoquía	Capachos	Joint Venture	E&P	Repsol YPF	Repsol YPF	50%	28 years	September 15, 2025	Yes	5% to 25%
Catatumbo-Orinoquía	Bolivar	Joint Venture- Sole Risk	E&P	Harken de Colombia Ltda.	Harken de Colombia Ltda. and Harken Energy Corporation	0%	28 years	June 12, 2024	Yes	20%
Catatumbo-Orinoquía	Rio de Oro	Discovered Undeveloped Field	E&P- Discovered and Undeveloped Fields	Petrotesting Colombia S.A.	Petrotesting Colombia S.A.	12%	10 years	December 29, 2013	Yes	20%
Catatumbo-Orinoquía	Puerto Barco	Discovered Undeveloped Field	E&P- Discovered and Undeveloped Fields	Petrotesting Colombia S.A.	Petrotesting Colombia S.A.	6%	10 years	December 29, 2013	Yes	20%
Catatumbo-Orinoquía	Carbonera la Silla	Discovered Undeveloped Field	E&P- Discovered and Undeveloped Fields	Mompos Oil Company Inc.	Mompos Construction	6%	10 years	October 25, 2014	Yes	20%

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Region	Contract Name	Type of Agreement	Purpose	Operator	Partners	Ownership Percentage	Term of Contract	Expiration Date	Right of Reversion upon Termination	Royalty
Mid– Magdalena Valley	Magangué	Joint Venture	E&P	Solana Petroleum Exploration (Colombia Limited)	Solana Petroleum Exploration	58%	28 years	January 1, 2018	Yes	20%
Northeastern	Guajira	Joint Venture	E&P	Chevron Petroleum Company	Chevron Petroleum Company	57%	Until economic limit	Until economic limit	No	20%
Catatumbo-Orinoquía	Cerrito	Joint Venture	E&P	Kappa Resources Colombia Ltda.	Kappa Resources Colombia Ltda.	0%	27.5 years	August 17, 2029	Yes	20%
Mid – Magdalena Valley	Maracas	Joint Venture- Sole Risk	E&P	Texican Oil Ltd.	Texican Oil Ltd.	0%	28 years	March 5, 2024	Yes	20%
Mid – Magdalena Valley	Arjona	Discovered Undeveloped Field	E&P- Discovered and Undeveloped Field	Vetra- NCT	Vetra- NCT Consortium	35%	10 years	March 9, 2017	Yes	8% to 25%
Catatumbo-Orinoquía	Tibú	Development Incremental Production	E&P	Ecopetrol S.A.	Tibú Consortium formed by Petrobras Colombia Limited and Petrobras Energía de Colombia	60%	Undetermined	Undetermined	No	8% to 25%
Catatumbo-Orinoquía	Alcaravan	Joint Venture	E&P	Harken de Colombia Ltd.	Harken de Colombia Ltd.	50%	28 years	February 13, 2021	No	20%
Central	Caracara	Joint Venture	E&P	Hupecol LLC	Hupecol LLC	30%	28 years	April 9, 2029	Yes	8% to 25%
Central	Camoa	Discovered Undeveloped Field	E&P-Discovered and Undeveloped Field	Drilling and Workeover Services Ltda	Drilling and Workeover Services Ltda.	20%	10 years	December 28, 2013	Yes	8% to 25%

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Region	Contract Name	Type of Agreement	Purpose	Operator	Partners	Ownership Percentage	Term of Contract	Expiration Date	Right of Reversion upon Termination	Royalty
Catatumbo-Orinoquía	Entrerrios	Discovered Undeveloped Field	E&P Discovered and Undeveloped Field	Union Temporal Andina composed by Rancho Hermoso S.A., Celsa S.A., Inversiones Valin Ltda & CIA S.C.A. and Saturde S.A.	Union Temporal Andina composed by Rancho Hermoso S.A., Celsa S.A., Inversiones Valin Ltda & CIA S.C.A. and Saturde S.A.	61%	10 years	December 28, 2013	Yes	8% to 25%
Catatumbo-Orinoquía	Guarimea	Discovered Undeveloped Field	E&P Discovered and Undeveloped Field	Petrotesting Colombia S.A.	Petrotesting Colombia S.A.	81%	10 years	January 17, 2018	Yes	8% to 25%
Catatumbo-Orinoquía	La Punta	Discovered Undeveloped Field	E&P Discovered and Undeveloped Field	Petrotesting Colombia S.A.	Petrotesting Colombia S.A.	70%	10 years	December 28, 2013	Yes	8% to 25%
Central	Tambaqui	Joint Venture- Sole Risk	E&P	Hupecol	Hupecol	30%	28 years	February 28, 2026	Yes	8% to 25%
Central	Upia B	Joint Venture	E&P	Petrobras	Holifield International Colombia Inc.	50%	28 years	March 1, 2012	Yes	20%
Catatumbo-Orinoquía	Campo Rico	Joint Venture	E&P	Emerald Energy PLC Sucursal Colombia	Emerald Energy PLC Sucursal Colombia	50%	25 years	May 24, 2027	Yes	8% to 25%
Catatumbo-Orinoquía	Casanare	Joint Venture	E&P	Perenco	Perenco Hocol and Homcol	64%	28 years	Until economic limit	No	20%
Catatumbo-Orinoquía	Corocora	Joint Venture	E&P	Perenco	Hocol and Perenco	50%	28 years	Until economic limit	No	8% to 25%
Catatumbo-Orinoquía	Estero	Joint Venture	E&P	Perenco	Perenco Hocol and Homcol.	50%	28 years	Until economic limit	No	20%
Catatumbo-Orinoquía	Garcero	Joint Venture	E&P	Perenco	Perenco Hocol and Homcol	50%	28 years	Until economic limit	No	5% to 25%

117

Region	Contract Name	Type of Agreement	Purpose	Operator	Partners	Ownership Percentage	Term of Contract	Expiration Date	Right of Reversion upon Termination	Royalty
Catatumbo-Orinoquía	Guachiria	Joint Venture	E&P	Solana	Solana Petroleum Exploration Colombia Limited	13%	28 years	September 30, 2031	Yes	8% to 25%
Catatumbo-Orinoquía	Orocue	Joint Venture	E&P	Perenco	Perenco and Hocol	50%	28 years	Until economic limit	No	20%
Catatumbo-Orinoquía	Tapir	Joint Venture- Sole Risk	E&P	Petrolco	Petrolco and Doreal Energy	0%	28 years	February 24, 2023	Yes	20%
Central	Rubiales	Risk Participation Contract	E&P	Metapetroleum	Tethys Petroleum Company Limited, and Metapetroleum	60%	28 years	June 30, 2016	Yes	20%
Central	Piriri	Joint Venture	E&P	Metapetroleum	Tethys Petroleum Company Limited, and Metapetroleum	50%	28 years	June 30, 2016	Yes	20%
Northeastern	Piedemonte	Joint Venture	E&P	BP	BP	50%	28 years	February 29, 2020	Yes	20%
Northeastern	Recetor	Joint Venture	E&P	BP	BP	50%	28 years	May 29, 2017	Yes	20%
Northeastern	Rio Chitamea	Joint Venture	E&P	BP	BP	50%	28 years	January 31, 2019	Yes	20%
Northeastern	Santiago de las Atalayas	Joint Venture	E&P	BP	BP , Total, TEPMA	50%	28 years	June 30, 2010	Yes	20%
Northeastern	Tauramena	Joint Venture	E&P	BP	BP	50%	28 years	July 3, 2016	Yes	20%
Southern	Boqueron	Joint Venture	E&P	Petrobras	Petrobras	50%	28 years	October 2, 2023	Yes	5% to 25%
Southern	Espinal	Risk Participation Contract	E&P	Petrobras	Petrobras	55%	28 years	October, 2015	Yes	20%
Southern	Hobo	Joint Venture	E&P	Petrobras	Petrobras	50%	28 years	December 31, 2011	Yes	20%
Southern	Caguan	Joint Venture	E&P	Petrobras	Petrobras	50%	28 years	December 31, 2011	Yes	20%

118

Region	Contract Name	Type of Agreement	Purpose	Operator	Partners	Ownership Percentage	Term of Contract	Expiration Date	Right of Reversion upon Termination	Royalty
Southern	Palermo	Joint Venture	E&P	Hocol S.A.	Hocol S.A.	50%	28 years	April 30, 2012	Yes	20%
Southern	San Jacinto	Joint Venture- Sole Risk	E&P	Hocol S.A.	Hocol S.A.	0%	28 years	December 22, 2024	Yes	5%
Southern	Río Paez	Joint Venture- Sole Risk	E&P	Hocol S.A.	Hocol S.A.	0%	28 years	April 26, 2029	Yes	5%
Southern	Ortega	Standard Incremental Production	E&P	Ecopetrol	Hocol S.A.	31%	22 years	March 18, 2023	Yes	8%
Southern	Puli	Joint Venture	E&P	Interoil	Interoil.	50%	28 years	February 29, 2012	Yes	20%
Southern	Armero	Joint Venture	E&P	Interoil	Interoil	50%	28 years	December 31, 2010	Yes	20%
Southern	Ambrosia	Joint Venture	E&P	Interoil	Interoil	30%	28 years	December 27, 2027	Yes	8% to 25%
Southern	Rio Opia	Joint Venture	E&P	Interoil	Interoil	30%	28 years	June 23, 2030	Yes	8% to 25%
Southern	Mana	Joint Venture	E&P	Interoil	Interoil	30%	28 years	November 11, 2028	Yes	8% to 25%
Southern	Abanico	Joint Venture	E&P	Kappa Resources Colombia Limited	Kappa Resources Colombia Limited	50%	28 years	October 10, 2024	Yes	5% to 25%
Southern	Chipalo	Joint Venture Sole Risk	E&P	Kappa Resources Colombia Limited	Kappa Resources Colombia Limited	0%	28 years	February 27, 2026	Yes	8% to 25%
Southern	Matambo	Joint Venture	E&P	Emerald Energy PLC	Emerald Energy PLC	25%	28 years	November 29, 2024	Yes	20%
Southern	Dindal	Joint Venture Sole Risk	E&P	SIPETROL	SIPETROL	0%	28 years	March 22, 2021	Yes	20%
Southern	Río Seco	Joint Venture Sole Risk	E&P	SIPETROL	SIPETROL	0%	28 years	August 21, 2023	Yes	20%
Southern	Tolima B	Joint Venture- Sole Risk	E&P	Petrotesting	Petrotesting.	0%	28 years	June 12, 2014	Yes	20%
Southern	Chaparral	Joint Venture	E&P	Petrotesting	Petrotesting	50%	28 years	October 4, 2012	Yes	8% to 25%

119

Region	Contract Name	Type of Agreement	Purpose	Operator	Partners	Ownership Percentage	Term of Contract	Expiration Date	Right of Reversion upon Termination	Royalty
Southern	Chenche	Discovered Undeveloped Field	E&P	Petrotesting	Petrotesting	70%	10 years	December 28, 2013	Yes	8% to 25%
Southern	San Luis	Joint Venture	E&P	Petrotesting	Petrotesting	50%	28 years	May 8, 2014	Yes	20%
Southern	Suroriente	Standard Incremental Production	E&P	Colombia Energy	Colombia Energy	48%	22 years	June 11, 2024	Yes	8% to 25%
Southern	CPR Santana	Risk Participation Contract	E&P	Gran Tierra Colombia	Gran Tierra Colombia	65%	28 years	July 27, 2015	Yes	20%
Southern	Guayuyaco	Joint Venture	E&P	Gran Tierra Colombia	Gran Tierra Colombia	30%	28 years	May 30, 2030	Yes	8% to 25%
Southern	Orito	Standard Incremental Production	E&P	Ecopetrol	Petrominerales	21%	22 years	June 5, 2023	Yes	8% to 25%
Southern	Neiva	Standard Incremental Production	E&P	Ecopetrol	Petrominerales	31%	22 years	June 5, 2023	Yes	8% to 25%
Southern	Nancy-Burdine- Maxime	Discovered Undeveloped Field	E&P	Union Temporal II&B	Union Temporal II&B	41%	10 years	December 28, 2013	Yes	20%
Southern	Hato Nuevo	Discovered Undeveloped Field	E&P	NCT Consortium	NCT Consortium	41%	10 years	July 3, 2016	Yes	32%
Mid – Magdalena Valley	Nare	Joint Venture	Production	Mansarovar Energy Colombia Ltd.	Mansarovar Energy Colombia Ltd.	50%	28 years	November 4, 2021	Yes	20%
Mid – Magdalena Valley	Cocorna	Joint Venture	Production	Mansarovar Energy Colombia Ltd.	Mansarovar Energy Colombia Ltd.	50%	28 years	September 1, 2008	Yes	20%
Mid – Magdalena Valley	Carare las Monas	Joint Venture	Production	Petrosantander	Petrosantander	30%	Until economic limit	Until economic limit	Yes	20%

120

Region	Contract Name	Type of Agreement	Purpose	Operator	Partners	Ownership Percentage	Term of Contract	Expiration Date	Right of Reversion upon Termination	Royalty
Mid – Magdalena Valley	Palagua	Standard Incremental Production	Production	Union Temporal IJP	Union Temporal Isomocol, Joshi- Petcar- Parko	50%	22 years	July 14, 2023	Yes	20%
Mid – Magdalena Valley	Tisquirama	Joint Venture	Production	Petroleos del Norte S.A.	Petroleos del Norte S.A – Petrosantander	50%	28 years	March 1, 2009	Yes	20%
Mid – Magdalena Valley	Opon	Joint Venture	Production	Compañía Operadora Petrocolombiana	Compañía Operadora Petrocolombiana	0%	28 years	July 14, 2015	Yes	20%
Mid – Magdalena Valley	Lebrija	Joint Venture- Sole Risk	E&P	Petroleos del Norte S.A.	Petroleos del Norte S.A.	0%	28 years	August 26, 2013	Yes	20%
Mid – Magdalena Valley	Opon-6	Joint Venture- Sole Risk	E&P	Compañía Operadora Petrocolombiana	Compañía Operadora Petrocolombiana	0%	N/A	July 14, 2015	Yes	20%
Mid – Magdalena Valley	Bocachico	Joint Venture- Sole Risk	E&P	Harken de Colombia S.A.	Harken de Colombia S.A.	0%	28 years	March 7, 2022	Yes	20%
Mid – Magdalena Valley	Mugrosa	Discovered Undeveloped Field	Develop Field	Cosacol S.A.	Cosacol S.A.	53%	10 years	July 12, 2015	Yes	20%
Mid – Magdalena Valley	Playon	Discovered Undeveloped Field	Develop Field	Serinpet	Representaciones y Servicios de Petroleos Serinpet	54%	10 years	July 12, 2015	Yes	20%
Mid – Magdalena Valley	Quebrada Roja	Discovered Undeveloped Field	Develop Field	Campos de Producción Consortium	Campos de Producción Consortium	58%	10 years	July 12, 2015	Yes	20%
Mid – Magdalena Valley	Toca	Discovered Undeveloped Field	Develop Field	Campos de Producción Consortium	Campos de Producción Consortium	12%	10 years	July 12, 2015	Yes	20%
Mid – Magdalena Valley	Rompida	Discovered Undeveloped Field	Develop Field	Petrtotesting	Petrotesting Colombia S.A. - Vetra	19%	10 years	December 30, 2013	Yes	20%
Mid – Magdalena Valley	Barranca lebrija	Discovered Undeveloped Field	Develop Field	Union Temporal Mocam	Union Temporal Mocam	8%	10 years	December 31, 2013	Yes	20%

121

Region	Contract Name	Type of Agreement	Purpose	Operator	Partners	Ownership Percentage	Term of Contract	Expiration Date	Right of Reversion upon Termination	Royalty
Mid – Magdalena Valley	Las Quinchas	Joint Venture- Sole Risk	E&P	Kappa Resources Colombia Limited	Kappa Resources Colombia Limited	7%	Until economic limit	Until economic limit	Yes	20%
Mid – Magdalena Valley	Pavas- Cachira	Discovered Undeveloped Field	Develop Field	Ismocol de Colombia S.A.	Union Temporal Isomocol, Joshi- Petcar- Parko	5%	10 years	December 29, 2013	Yes	20%
Mid – Magdalena Valley	La Cira	Development Incremental Production	E&P	Ecopetrol S.A	Occidental de Colombia	52%	Undetermined	Undetermined	No	8% to 25%

122

Ecopetrol S.A. and Subsidiaries

Consolidated Financial Statements

Years ended December 31, 2007, 2006 and 2005

Contents

Report of Independent Registered Public Accounting Firm	F-3
Consolidated Financial Statements
Consolidated Balance Sheets	F-4
Consolidated Statements of Financial, Economic and Social Activities	F-5
Consolidated Statements of Changes in Equity	F-6
Consolidated Statements of Cash Flows	F-7
Notes to Consolidated Financial Statements	F-8

F-2

Report of Independent Registered Public Accounting Firm

To the Shareholders of Ecopetrol S.A. and subsidiaries

We have audited the accompanying consolidated balance sheets of Ecopetrol S.A. and subsidiaries (“the Company”) as of December 31, 2007 and 2006, and the related consolidated statements of financial, economic and social activities, changes in equity, and cash flows for each of the three years in the period ended December 31, 2007. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Company’s internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Ecopetrol S.A. and subsidiaries at December 31, 2007 and 2006, and the consolidated results of their financial, economic and social activities and their cash flows for each of the three years in the period ended December 31, 2007, in conformity with generally accepted accounting principles for Colombian Governmental Entities issued by the Contaduría General de la Nación, which differ in certain respects from accounting principles generally accepted in the United States of America (see Note 33 to the consolidated financial statements).

ERNST & YOUNG AUDIT LTDA. Francisco J. González R.
Statutory Auditor
Professional Card 13442-T
Designated by Ernst & Young Audit Ltda. – TR 530

Bogotá, D.C., Colombia, February 15, 2008

(except for Notes 32 and 33 to which the date is May 30, 2008)

F-3

Ecopetrol S.A. and Subsidiaries

Consolidated Balance Sheets

	December 31,
	2007		2006
	(In millions of Colombian pesos)
Assets
Current assets:
Cash and cash equivalents (Notes 2 and 3)	$	3,749,899	$	1,627,876
Investments (Notes 2 and 4)		5,954,502		1,961,687
Accounts and notes receivable, net (Notes 2 and 5)		2,269,904		1,336,319
Inventories (Note 6)		1,298,792		996,361
Advances and deposits (Notes 2 and 7)		1,979,614		1,351,750
Pension plan assets (Note 10)		508,813		—
Prepaid expenses		12,598		9,740
Total current assets		15,774,122		7,283,733
Investments (Notes 2 and 4)		3,844,819		2,808,690
Accounts and notes receivable, net (Note 5)		202,565		148,903
Advances and deposits (Note 7)		—		302,600
Property, plant and equipment, net (Note 8)		6,151,951		5,833,934
Natural and environmental properties, net (Note 9)		5,128,917		3,780,390
Pension plan assets (Note 10)		8,986,861		8,960,897
Petroleum Stabilization Savings Fund - FAEP (Notes 2 and 11)		—		3,844,167
Deferred charges (Notes 2 and 12)		1,976,062		3,008,371
Other assets (Note 13)		399,401		429,286
Valuations (Note 20)		5,647,382		5,736,751
Total assets	$	48,112,080	$	42,137,722
Liabilities and equity
Current liabilities:
Financial obligations (Notes 2 and 14)	$	3,569	$	42,874
Accounts payable and related parties (Notes 2 and 15)		1,146,296		761,720
Taxes payable (Note 16)		2,893,012		2,037,748
Labor and pension plan obligations (Note 17)		586,964		534,750
Estimated liabilities and provisions (Note 18)		1,435,943		605,337
Total current liabilities		6,065,784		3,982,429
Accounts payable, long-term (Notes 2 and 15)		—		50,018
Labor and pension plan obligations (Note 17)		10,316,041		9,647,256
Estimated liabilities and provisions (Notes 2, 9 and 18)		2,742,052		2,839,170
Deferred income – Petroleum Stabilization Savings Fund – FAEP (Note 11)		—		3,844,167
Other long-term liabilities (Note 19)		2,179,735		938,935
Minority interest		1		1
Equity (Note 20 and see accompanying statement)		26,808,467		20,835,746
Total liabilities and shareholders’ equity	$	48,112,080	$	42,137,722
Memorandum accounts (Note 21)
Rights	$	36,393,191	$	42,474,274
Obligations	$	27,787,054	$	22,654,380

See accompanying notes.

F-4

Ecopetrol S.A. and Subsidiaries

Consolidated Statements of Financial, Economic and Social Activities

	Year ended December 31,
	2007			2006			2005
	(In millions of Colombian pesos, except net income per share)
Revenue (Note 22):
Local sales	$	16,002,997		$	11,300,001		$	9,551,605
Foreign sales:
Total		6,645,820			7,864,124			6,530,703
FAEP		(316,497	)		(774,160	)		(569,405	)
Foreign sales, net		6,329,323			7,089,964			5,961,298
Total revenue		22,332,320			18,389,965			15,512,903
Cost of sales (Note 23)		12,058,527			12,756,563			10,095,542
		10,273,793			5,633,402			5,417,361
Operating expenses (Note 24):
Administration		408,105			353,019			337,261
Selling		933,851			644,551			581,715
Operating income		8,931,837			4,635,832			4,498,385
Non-operating income (expenses):
Financial income, net (Note 25)		93,628			683,436			1,532,212
Pension expenses (Notes 17 and 26)		(1,090,343	)		(829,191	)		(765,504	)
Inflation gain (Note 27)		41,132			56,166			58,961
Other income (expenses), net (Note 28)		(910,950	)		344,899			(1,035,724	)
Income before income tax		7,065,304			4,891,142			4,288,330
Income tax (Note 16):
Current		2,006,484			1,456,268			1,246,325
Adjustments of prior periods		—			38,526			—
Deferred tax		(120,972	)		4,975			(211,751	)
		1,885,512			1,499,769			1,034,574
Net income (Note 1)	$	5,179,792		$	3,391,373		$	3,253,756
Net income per share (Note 1)	$	169		$	79,891		$	76,648

See accompanying notes.

F-5

Ecopetrol S.A. and Subsidiaries

Consolidated Statements of Changes in Equity

	Subscribed and Paid-in Capital			Additional Paid-in Capital			Contribution of Nation in Kind			Legal and Other Reserves			Incorporated Institutional Equity		Adjustment in Conversion of Subsidiaries			Valuation Surplus			Retained Earnings			Total Equity
	(In millions of Colombian pesos, except the dividend per share)
Balance at December 31, 2004	$	4,244,943		$	—		$	699,219		$	1,249,122		$	17,682	$	—		$	1,679,399		$	2,110,506		$	10,000,871
Hydrocarbon reserves contributed by the Colombian Nation		—			—			1,345,379			—			—		—			—			—			1,345,379
Appropriation to reserves		—			—			—			598,506			—		—			—			(598,506	)		—
Distribution of contributions to ANH		—			—			—			—			—		—			—			(214,000	)		(214,000	)
Appropriation to incorporated institutional equity		—			—			—			—			1,452		—			—			—			1,452
Distribution of dividends ($30,577 per share)		—			—			—			—			—		—			—			(1,298,000	)		(1,298,000	)
Valuation surplus		—			—			—			—			—		—			195,793			—			195,793
Net income		—			—			—			—			—		—			—			3,253,756			3,253,756
Balance at December 31, 2005		4,244,943			—			2,044,598			1,847,628			19,134		—			1,875,192			3,253,756			13,285,251
Hydrocarbon reserves contributed by the Colombian Nation		—			—			2,374,512			—			—		—			—			—			2,374,512
Appropriation to legal reserve		—			—			—			325,376			—		—			—			(325,376	)		—
Appropriation for investment programs		—			—			—			821,708			—		—			—			(821,708	)		—
Distribution of contributions to ANH		—			—			—			—			—		—			—			(106,672	)		(106,672	)
Addition to incorporated institutional equity		—			—			—			—			29,723		—			—			—			29,723
Distribution of dividends ($47,114 per share)		—			—			—			—			—		—			—			(2,000,000	)		(2,000,000	)
Valuation surplus		—			—			—			—			—		—			3,861,559			—			3,861,559
Net income		—			—			—			—			—		—			—			3,391,373			3,391,373
Balance at December 31, 2006		4,244,943			—			4,419,110			2,994,712			48,857		—			5,736,751			3,391,373			20,835,746
Distribution of dividends ($97,863 per share)		—			—			—			(1,423,163	)		—		—			—			(3,052,236	)		(4,475,399	)
Capitalization of the Nation contributions in hydrocarbon reserves and other		4,851,254			—			(4,851,254	)		—			—		—			—			—			—
Capitalization (4,087,723,771 shares)		1,021,931			4,700,882			—			—			—		—			—			—			5,722,813
Subscribed capital receivable and additional paid-in capital		(4,794	)		(850,068	)		—			—			—		—			—			—			(854,862	)
Appropriation to reserves		—			—			—			339,137			—		—			—			(339,137	)		—
Contribution of the Nation with hydrocarbon reserves		—			—			432,144			—			—		—			—			—			432,144
Addition to incorporated institutional equity		—			—			—			—			59,873		—			—			—			59,873
Adjustment in conversion of subsidiaries		—			—			—			—			—		(2,271	)		—			—			(2,271	)
Valuation surplus		—			—			—			—			—		—			(89,369	)		—			(89,369	)
Net income		—			—			—			—			—		—			—			5,179,792			5,179,792
Balance at December 31, 2007	$	10,113,334		$	3,850,814		$	—		$	1,910,686		$	108,730	$	(2,271	)	$	5,647,382		$	5,179,792		$	26,808,467

See accompanying notes.

F-6

Ecopetrol S.A. and Subsidiaries

Consolidated Statements of Cash Flows

	Year ended December 31
	2007			2006			2005
	(In millions of Colombian pesos)
Operating activities:
Cash received from clients	$	21,683,589		$	18,410,244		$	15,597,896
Cash from financial interests		968,899			519,309			1,522,230
Cash received from restricted FAEP fund and others		1,167,534			80,611			67,830
Payment of other contributions and purchases of hydrocarbons to ANH		(4,153,060	)		(4,101,696	)		(3,699,912	)
Cash paid to suppliers and contractors		(4,630,295	)		(5,154,051	)		(4,253,944	)
Payment of income and other taxes		(1,409,720	)		(2,040,025	)		(849,128	)
Payment of salaries, fringe benefits and social security		(703,003	)		(735,537	)		(613,193	)
Payment of retirement pensions and transfers to funds		(1,122,170	)		(885,695	)		(2,793,208	)
Other payments, net		(1,089,550	)		259,106			(1,038,396	)
Payments of financial interest and other income		(875,270	)		1,424			(64,411	)
Net cash provided by operating activities		9,836,954			6,353,690			3,875,764
Investing activities:
Net increase in investments		(5,031,216	)		(1,358,094	)		(494,094	)
Investment in natural and environmental properties		(2,013,948	)		(1,162,165	)		(190,826	)
Additions to property, plant and equipment		(1,023,014	)		(700,769	)		(1,063,318	)
Net cash used in investing activities		(8,068,178	)		(3,221,028	)		(1,748,238	)
Financing activities:
Dividends paid		(4,475,399	)		(2,000,000	)		(1,298,000	)
Payment of financial obligations		(39,305	)		(120,013	)		(74,783	)
Capitalization in cash and additional paid-in capital		4,867,951			––			––
Disbursements of contributions to ANH		––			(106,672	)		(214,000	)
Net cash provided (used) by financing activities		353,247			(2,226,685	)		(1,586,783	)
Net increase in cash and cash equivalents		2,122,023			905,977			540,743
Cash and cash equivalents at beginning of year		1,627,876			721,899			181,156
Cash and cash equivalents at end of year	$	3,749,899		$	1,627,876		$	721,899

See accompanying notes.

F-7

Ecopetrol S.A.

Notes to the Consolidated Accounting Statements (Continued)

Ecopetrol S.A. and Subsidiaries

Notes to Consolidated Financial Statements

(Amounts expressed in millions of Colombian pesos, unless otherwise stated, except amounts in

other currencies, exchange rates and income per share, which are expressed in unit pesos – though out these financial

statement pesos or Ps refer to Colombian pesos and US Dollar refer to United States Dollar)

1. Economic Entity and Principal Accounting Policies and Practices

Reporting Entity

Ecopetrol S.A., (hereinafter Ecopetrol or the Company) was organized by Law 165 of 1948 and transformed through Extraordinary Decree 1760 of 2003 (added by Decree 409 of 2006) and Law 1118 of 2006 into a state-owned company by shares and then into a mixed economy entity of a commercial character, at national level, related to the Ministry of Mines and Energy, for an indefinite period. Ecopetrol’s corporate purpose is the development, in Colombia or abroad, of commercial or industrial activities corresponding to or related with exploration, production, refining, transportation, storage, distribution, and selling of hydrocarbons, their by-products and associated products, and of subsidiary operations, connected or complementary to these activities in accordance with applicable regulations. Ecopetrol’s principal domicile is Bogotá, D.C. and it may establish subsidiaries, branches and agencies in Colombia or abroad.

By means of the transformation Decree 1760 of June 27, 2003, the integral administration of the hydrocarbon reserves owned by the Colombian Nation (the Nation), and the administration of non-strategic assets, represented by shares and the participation in companies were separated from Ecopetrol. In addition, Ecopetrol’s basic structure was changed and two entities were created: a) the Agencia Nacional de Hidrocarburos (ANH) was created to hereinafter issue and develop the Colombian petroleum policy (formerly the responsibility of Ecopetrol), and b) Sociedad Promotora de Energía de Colombia S.A., which received the non-strategic assets owned by Ecopetrol.

Law 1118 of December 27, 2006 changed the legal nature of Ecopetrol S.A., and authorized the Company to issue shares to be placed in the equity market and acquired by Colombian individuals or legal entities. Once the shares were issued and placed, fully or partially, the Company became a Mixed Economy Entity of a commercial nature, at a national level, controlled by the Ministry of Mines and Energy.

At December 31, 2007, the Company maintains current obligations related to 136 exploration and production contracts, of which it is the operator in 29 and 107 are operated by third parties, of the following types:

Type	Number
Exploration	50
Joint Venture	43
Discovered undeveloped fields	18
Sole risk	14
Standard incremental production	5
Risk participation contracts	3
Development incremental production	2
Services and technical cooperation	1
	136

F-8

Ecopetrol S.A.

Notes to the Consolidated Accounting Statements (Continued)

1. Economic Entity and Principal Accounting Policies and Practices (continued)

Reporting Entity (continued)

Contracts operated by the Company, the following types of activities are undertaken:

Type	Number
Exploration	23
Standard incremental production	3
Development incremental production	2
Services and technical cooperation	1
	29

The 107 production contracts operated by third parties include 199 fields, in agreements established in the current contracts, of which 115 have the standard production terms, 35 the incremental production terms, 16 are sole risk, 12 are undeveloped discovered fields, 3 are in low risk operations and 18 in extended tests for which commerciality has not yet been determined. As part of its strengthening and economic development strategy the Company directly operates 59 production fields.

Ecopetrol is a shareholder in Oleoducto de Colombia S.A. with a 44% and Oleoducto Central S.A. with 35%. In addition, the company is a joint venture partner in two association contracts with pipelines as part of production facilities: 49% on the Alto Magdalena pipeline (operated by the Colombian branch of Hocol S.A.) and 50% on the Caño Limón-Coveñas pipeline (operated by Ecopetrol).

Association contracts, entrusted to private partners, have an exploration phase of three years, which may be extended to six years, with various obligations in accordance with each contract. If exploration is successful and the field commerciality declared, Ecopetrol reimburses, from the field’s production, direct drilling and development costs of producing wells, in proportion to its working interest in the contract.

The development and production phase of association contracts lasts 22 years from completion date of the exploration period, not to exceed a total contract period of 28 years, unless a bilateral contract extension is agreed. Production after deducting royalties of 20% is in most cases allocated as follows: 50% among the private partners and the remaining 50% to Ecopetrol. Production costs are allocated in the same proportions.

Costs and expenses incurred, and investments and obligations acquired in complying with the operation of commercial fields and other income received, are accrued by the operator of the joint account and billed or distributed monthly, in accordance with the percentages established under each association contract.

At the end of the association contracts subscribed before January 1, 2004, private companies shall pass without cost to Ecopetrol all producing wells, facilities and other real estate and assets acquired in executing the contracts. For contracts signed after January 1, 2004, assets are transferred to ANH.

Under the sole-risk system, Ecopetrol may not initially accept the existence of a commercial field and, therefore, the partners are entitled, at their own expense and risk, to execute the work deemed necessary for field production and to recover up to 200% of the total cost incurred in this work on their own account and risk. Reimbursement is made from hydrocarbons produced less the respective royalties. The other conditions are the same as those applied to the regular association contracts with declared commerciality, once the stated reimbursement is achieved.

F-9

Ecopetrol S.A.

Notes to the Consolidated Accounting Statements (Continued)

1. Economic Entity and Principal Accounting Policies and Practices (continued)

Effects of Inflation on Financial Information

The accompanying consolidated accounting statements have been prepared from the accounting records, which are maintained under the historical cost convention, modified since 1992 to comply with the legal provisions of the Contaduría General de la Nación (CGN) to recognize the effect of inflation on non-monetary balance sheet accounts until December 31, 2001, including equity. The CGN authorized Ecopetrol not to apply the inflation adjustment system from January 1, 2002.

Principles of Consolidation

The consolidated financial statements include those of Ecopetrol S.A. (as Home Office), Black Gold Re Ltd. and Oleo é Gas Do Brasil Ltda., Ecopetrol del Perú and Ecopetrol América Inc. (collectively, “the Subsidiaries”), where Ecopetrol’s direct participation is 100%, 99.99%, 99.99% and 100%, respectively. The subsidiaries are included in the consolidated financial statements. These financial statements were consolidated line by line and all transactions and significant intercompany balances between companies have been eliminated. Accounting policies and methods of the Home Office and the Subsidiaries are homogeneous and do not require adjustments at December 31, 2007.

The preparation of the consolidated financial statements was carried out under accounting standards and principles issued by the CGN and other legal provisions. These principles, provided for in the General Governmental Accounting Plan (PGCP or Colombian Governmental Entity GAAP) may differ in certain aspects from those established by other standards and other control authorities and the opinions on specific matters issued by CGN prevail over general governmental accounting principles (PGCP). The accrual method was applied for the accounting recognition of financial, economic and social facts.

Segments

The Company operates in five primary segments of activity: exploration and production, refining, transportation, corporate and all others. The PGCP does not require disclosure of information by segment.

Materiality Concept

An economic fact is material when due to its nature and amount, and taking into account the surrounding circumstances, knowing or not knowing it could significantly alter the economic decisions of informed users.

The consolidated financial statements include specific headings in accordance with legal requirements, or those representing 5% or more of total assets, current assets, total liabilities, current liabilities, working capital, equity and results of operations, as appropriate. In addition, lower amounts are shown when they are deemed to contribute to a better interpretation of financial information.

Use of Estimates

The preparation of the consolidated financial statements in accordance with PGCP requires that the Company’s Management make estimates and assumptions that could affect the recorded amounts of assets, liabilities, results of activities and the attached notes. Current or market values could differ from such estimates.

F-10

Ecopetrol S.A.

Notes to the Consolidated Accounting Statements (Continued)

1. Economic Entity and Principal Accounting Policies and Practices (continued)

Transactions in Foreign Currency

Transactions in foreign currency are entered into in accordance with applicable regulations and they are recorded at appropriate exchange rates on the transaction date. Balances denominated in foreign currency are reflected in Colombian pesos at the representative market exchange rates of $2,014.76 and $2,238.79 per US$1 at December 31, 2007 and 2006, respectively.

The adjustment for exchange differences generated by foreign currency liabilities is recorded against results of operations, except when such adjustment is charged to acquisition cost of assets in construction and up to the time these assets are placed in service.

The Company in developing its crude oil exploration and production activities can freely retain foreign currency received. In addition, it can acquire the foreign currency it requires in the local market to pay its foreign obligations.

Joint Operation Contracts

Joint venture or common-interest operation contracts are entered into between Ecopetrol and third parties in a property whereby one party is designated as the operator to carry out the activities in order to share the risk, secure capital, maximize operating efficiency and optimize the recovery of reserves. In these joint ventures, each party retains an undivided ownership in the property under operation. Ecopetrol records these investments, revenues, costs and expenses on a timely basis based on information reported by the operators. When Ecopetrol directly operates the facilities, it records assets, revenues, costs and expenses, recognizing at the same time the accounts receivable of the third party for joint interest billings.

Cash and Cash Equivalents

Cash and cash equivalents are represented by cash in banks and highly liquid investments maturing within three months following their acquisition.

Financial Derivative Instruments

The Company enters into hedging agreements to protect itself from the fluctuations of international crude oil prices. The difference between amounts paid and income received under hedging operations is recognized as financial expense in the statements of financial, economic and social activities. Ecopetrol does not use these financial instruments for speculative purposes.

Hedging operations are carried out with banks and other counterparties with a credit risk rating higher than or equal to AA+.

The Company makes periodic evaluations based on the market risk of hedging operations and together with the Board of Directors and management, determines the need for extension or early termination of the subscribed contracts, when the result is ineffective vis-á-vis the hedged items. In the event of settlement, the financial and contractual effects are recognized in the results of operations.

F-11

Ecopetrol S.A.

Notes to the Consolidated Accounting Statements (Continued)

1. Economic Entity and Principal Accounting Policies and Practices (continued)

Investments

Fixed yield investments are initially recorded at cost adjusted monthly to their market value with a charge or credit to the results of operations. For valuation purposes, fixed yield investments are classified as negotiable or non-negotiable. The market value of non negotiable fixed yield investments is determined by calculating the present value of their future flows of capital and interest, discounted at a market interest rate that includes the determination of the basic rate and the credit risk of the issuer.

The market value of variable yield investments is determined based on their stock exchange quotation, negotiability, the intrinsic value for those not negotiated on the stock exchange, and the Company´s participation in the investee. At the year-end the market value is compared with cost in order to determine the respective valuation and/or provision.

Provision for Doubtful Accounts

The provision for doubtful accounts is reviewed and updated periodically in accordance with the aged analysis of balances, and the evaluation of the recoverability evaluations of individual accounts. The Company carries out the necessary administrative and legal procedures to recover delinquent accounts receivable as well as the payment and collection of interest from customers that do not comply with payment policies.

Inventories

Inventories include assets extracted, transformed and acquired for any reason, to be sold, intended for transformation and consumed in the production process, or as a part of the rendering of services. Ecopetrol uses the perpetual inventory system to account for raw material.

Inventories are recorded at historical costs or at purchase cost, which includes direct and indirect charges incurred to prepare the inventory for sale or production conditions.

This valuation is measured under the weighted average method, considering the following parameters:

• Crude oil inventories for the Company´s own production at production costs at year end

• Crude oil purchases at acquisition costs, including transportation and delivery costs incurred.

• Finished goods inventory, at total production costs (at each refinery).

• Work in process inventory, at production costs.

• Raw material inventory, at weighted average cost.

Raw materials and supplies in joint ventures are controlled by the operator and reported in a joint account at acquisition costs (recorded in the original currency at average costs). Work in process inventories are recorded as an expense or are capitalized, depending of their nature. Inventory consumptions are charged to the joint venture as expense or property, plant and equipment or natural environment properties, as appropriate.

F-12

Ecopetrol S.A.

Notes to the Consolidated Accounting Statements (Continued)

1. Economic Entity and Principal Accounting Policies and Practices (continued)

Inventories (continued)

Additionally, inventories are valued at the lower of market value and the average cost; and the actual cost incurred for in-transit inventories. At the end of the year, provisions are calculated to recognize impairment, obsolescence, excess or slow-moving or for the loss of market value.

Property, Plant and Equipment and Depreciation

Property, plant and equipment is recorded at cost, adjusted for inflation until 2001, which includes financial expenses and exchange differences from foreign currency financing incurred until the asset is placed in service. When an asset is sold or retired, the adjusted cost and accumulated depreciation are written off and any gain or loss is recognized in results of operations.

Depreciation is calculated on the total acquisition cost using the straight-line method, based on the useful life of the assets. Annual depreciation rates used are:

	%
Buildings and pipelines	5
Plant and equipment	10
Transportation equipment	20
Computers	33.3

Any gain or loss on the sale or retirement of property, plant and equipment is recognized in results of operations in the transaction year. Normal disbursements for maintenance and repairs are charged to expense and those significant costs that improve efficiency or extend the useful life are capitalized.

Following the guidelines set forth by CGN within the PGCP, the methodology used for the appraisal of property, plant and equipment was the actual value in use for going concern entities (VAU), for the economic valuation of assets, considering the current installation conditions and their useful life in production conditions and generation of revenues.

The net appraisal of property, plant and equipment includes the effect of devaluations against equity, originated by the excess between the net book value and the respective appraisal for plants and equipment of associated operations, refinery buildings and plants and transportation equipment and of the Colombian Oil Institute (a research department of Ecopetrol).

Natural and Environmental Properties

The Company applies a method similar to the internationally recognized successful efforts method of accounting for investments in exploration and production areas. The acquisition of geological and geophysical seismic information is expensed as incurred, before the discovery of proved reserves. Property acquisition costs are initially capitalized until such time as either exploratory drilling is determined to be successful or unsuccessful and all costs are written off. Once a project is sanctioned for development, the carrying value of the property acquisition cost and exploration costs are transferred to Amortizable Oil Investments. Costs capitalized also include asset retirement cost. Asset and liability balances related to asset retirement costs are updated annually. Production and support equipment are accounted for on a cost basis and are part of the Property, Plant and Equipment subject to depreciation.

F-13

Ecopetrol S.A.

Notes to the Consolidated Accounting Statements (Continued)

1. Economic Entity and Principal Accounting Policies and Practices (continued)

Natural and Environmental Properties (continued)

These investments are amortized using the technical units-of-production method on the basis of proved developed reserves by field. The reserves are based on technical studies prepared internally by the Company’s Department of Reservoirs and approved by the Company´s Reserves Committee, which follow estimation methodologies recommended by international organizations of specialists in hydrocarbon reserves. Proved reserves consist of estimated quantities of crude oil and natural gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, that is, prices and costs as of the date the estimate is made.

When a well is declared productive, in compliance with the information provided by the Exploration Vice-Presidency of Ecopetrol, tangible property (property, plant and equipment) is capitalized and intangible assets are recognized as an investment in natural and environmental properties.

When it is determined that a well located in an exploration zone has no proved reserves, it is considered a dry or not commercial well and accumulated costs are expensed in the same year this is known. Costs incurred in geology, seismic and similar activities are recorded in the income statement when incurred.

The estimation of hydrocarbon reserves is subject to several uncertainties inherent to the determination of proved reserves, production recovery rates, the timeliness with which investments are made to develop the reservoirs and the degree of maturity of the fields.

Support equipment and other property and equipment are depreciated over their estimated useful lives.

On the retirement of a complete unit of a proved fields the cost and related accumulated depreciation, depletion, and amortization are eliminated from the property accounts, and the resultant gain or loss is recognized. On the retirement of a partial unit of proved field, the cost is charged to accumulated depreciation, depletion, and amortization with a resulting gain or loss recognized as income. The Company does not sell any interest in properties.

The Company recorded as reservoirs within the account of nature and environment properties the contributions of the Nation represented by crude oil and natural gas reserves deriving from the reversals of concessions of oilfield areas in favor of the Nation, given before the effectiveness of Decree 1760 of 2003. Reserves were valued by means of the technical-economic model where the value per barrel resulted from the relation of the net present value obtained at a discount rate and the total proved reserves on the contribution date. Depletion is calculated using the units of production basis.

Impairment of Long-Lived Assets

At the end of each year, the net value of long-lived assets held and in use is reviewed, including those to be dismantled, when circumstances or changes occur indicating that the book value may not be recoverable. The recording of provisions usually coincides with the formalization of an action plan by Ecopetrol, including, among others, the offer of such assets to third parties.

Pension Plan Assets and Other Funds

Commercial trusts consist of funds with a specific purpose given to pension fund trusts, for the payment of pension obligations. Other funds also include trust to cover unexpected losses of oil equipment. Yields are estimated based on the valuation of market prices and the method established by the Financial Superintendence of Colombia.

F-14

Ecopetrol S.A.

Notes to the Consolidated Accounting Statements (Continued)

1. Economic Entity and Principal Accounting Policies and Practices (continued)

Petroleum Stabilization Savings Fund FAEP

Law 1151 of 2007 implemented by means of Decree 3238 of August 27, 2007, determined that the accounts owned by Ecopetrol in the FAEP belonged to the Nation, represented by the Ministry of Finance and Public Credit. These amounts were recognized as restricted funds in the financial statements of Ecopetrol until August 2007.

Prior to August 2007, the FAEP was a restricted fund that was only recorded as revenue for Ecopetrol when the Central Bank reimbursed to Ecopetrol actual cash as revenue of decreases in the production levels of the Cusiana, Cupiagua and Caño Limón fields. In addition, amounts in the FAEP could not be used as a guarantee for loans before its actual release by the Central Bank.

Deferred Charges

Deferred charges include major repairs of plant and equipment and cost incurred in an incremental production contract, which are amortized using the straight-line method over estimated useful lives ranging from two to five years, when such costs will generate benefits and by the unit of production basis, respectively.

Monetary correction attributable to non-monetary accounts (including equity) related to exploration and development activities, was recorded as a deferred asset or liability through December 31, 2001 and was transferred to results of operations during the amortization and/or depreciation period of the assets originating it.

Advances received from Ecogas for BOMT Contracts (Build, Operate, Maintain and Transfer)

As a result of the recognition of an account receivable from Ecogas and following specific instructions from CGN, the Company recognized as deferred income the net present value of the future payments scheme, in connection with Ecopetrol´s liability related to BOMT contractors. These liabilities are due in 2017, the year when the contractual obligations end. Due to the payment of this amount in 2007, the deferred income was recognized as a component of other income.

Valuations

a. Investments

Valuations and valuation surplus correspond to the difference between the historical cost and the investment’s intrinsic value or its price quoted on a stock exchange.

b. Property, Plant and Equipment

Valuations and valuation surplus of property, plant and equipment included as part of equity correspond to the difference between net book value and the market value for real estate or the current value in use for plant and equipment, determined by specialists registered with the Colombian Real Estate Control entity or by suitable technical personnel, respectively. If the technical study is lower than the carrying value, the difference is recorded in equity as a reduction in the property, plant and equipment appraisal until it is depleted, and any excess as devaluation, (notwithstanding that the account balance results in a debit position), without affecting the Company’s statement of financial, economic and social activities.

F-15

Ecopetrol S.A.

Notes to the Consolidated Accounting Statements (Continued)

1. Economic Entity and Principal Accounting Policies and Practices (continued)

Income Tax

The provision for income tax is calculated at the official rate of 34% in 2007 (38.5% in 2006 and 2005) by the accrual method, on the higher of presumptive and net taxable income. Accounting balances reflect independently the income tax liability and the advances and withholdings generated in favor of the year. For 2008 and following years, the official rate will be 33%.

The effect of timing differences involving the payment of a lower or higher income tax in the current year is recorded as a deferred tax credit or debit, respectively, provided that a reasonable expectation exists such differences will reverse and in the case of the deferred tax asset, that sufficient taxable income will be generated to recover the tax. The deferred tax balance was calculated at the rate of 33%.

Labor and Pension Obligations

The system for salaries and fringe benefits for Ecopetrol personnel is governed by the Collective Labor Agreement, Agreement 01 of 1977, and in the absence thereof, by the Labor Code. In addition to fringe benefits, Ecopetrol employees are entitled to receive additional benefits covered by previous regulations that depend both on the place, type of work, length of service, and basic salary. Annual interest of 12% is paid on accumulated severance amounts in favor of each employee and the payment of indemnities is provided for when special circumstances arise that result in the non voluntary termination of the contract, and in periods other than the qualifying period.

The actuarial calculation includes active employees with indefinite contract term, pensioners and heirs, for the pension, health care and education plan; temporary, active employees, and voluntary retirees, for pension bonuses.

All social benefits of employees who joined the Company before 1990 are the direct responsibility of Ecopetrol, without the involvement of the Colombian social security entity or institution. The cost of health services of the employee and his/her relatives registered with the Company is determined by means of the morbidity table, prepared on the basis of facts occurring during 2007. Likewise, the experience of Ecopetrol is considered for the calculation of educational allowances, based on the annual average cost of each business segment, subdivided in accordance with the class of studies: pre-school, primary, high school and university.

For employees who joined the Company as of the effectiveness of Law 50 of 1990, the Company makes periodic contributions for severance, pensions and labor related injuries to the respective funds that assume all these obligations. Likewise, Law 797 of 2003 determined that Ecopetrol employees who joined the Company as of January 29, 2003 will be subject to the provisions of the General Pension Regime.

Purchases of Hydrocarbons from ANH

The Company purchases the physical product that the ANH receives from all producers in Colombia at prices set forth in the Law 756 of 2002 and Resolution 18-1709 of 2003, which reference international prices.

F-16

Ecopetrol S.A.

Notes to the Consolidated Accounting Statements (Continued)

1. Economic Entity and Principal Accounting Policies and Practices (continued)

Recognition of Income, Costs and Expenses

Income from crude oil and natural gas sales is recognized when product has been physically delivered to the buyer at the specific delivery or shipping point and when all risks and benefits have been transferred to the purchaser. Title is transferred to the buyer when products are delivered to the customer. Invoices are issued at this point and revenue is recognized. In the case of refined and petrochemical products, income is recognized when products are shipped by the refinery; subsequently, they are adjusted in accordance with the volumes actually delivered. Income from transportation services are recognized when products are transported and delivered to the buyer in accordance with the sale terms. In all other cases, income is recognized at the time it is earned and a true, probable and quantifiable right to demand its payment arises.

Before the effectiveness of Law 1151 of 2007, transfers made to the FAEP only constituted income for Ecopetrol insofar as the actual reimbursement by the Central Bank are realized as a result of reduction on the average production levels of the Cusiana, Cupiagua and Caño Limón fields, while the respective production costs are part of results when incurred. After such date of law 1151 there were no further transfers to the FAEP.

Late payment interest income on the collection of accounts receivable is recognized following prudence and realization principles.

Starting March 2007, subsidies for motor gasoline and Diesel are granted by the Nation to refiners such as Ecopetrol, as provided in Law 1111 of 2006 (Budgets Law). Revenues from said subsidies correspond to the difference between the regulated price and the international parity price, which are recorded by the Company as operating revenue, in accordance with Resolution No. 180414 of the Ministry of Mines and Energy of March 2007.

Cost of Sales and Expenses

Costs and expenses are recognized upon receipt of the goods or services or when there is certainty of the occurrence of an economic obligation. Fuel shortages and losses due to thefts and explosions are recorded as non operating expenses.

Abandonment of Fields

The Company recognizes the liability for future assets retirement obligations and its contra entry is a higher amount of the natural and environmental properties. The estimation includes plugging costs and abandonment of wells, dismantling of facilities and environmental recovery of areas and wells. Amortization is imputed to production costs, using the technical units-of-production method based on proved developed reserves. Changes resulting from new estimates of the liability for abandonment and environmental restoration are charged to the respective asset. The related liability is estimated in foreign currency as applicable and is adjusted for exchange difference at the end of each year.

When certain association contracts are extended, abandonment costs are assumed by the partners in the participation percentages established in each contract, which in turn are funded up to their total amount, after the agreement with the contract partners. In accordance with the current regulations, Ecopetrol has not assigned assets or specific funds to cover its direct obligations.

F-17

Ecopetrol S.A.

Notes to the Consolidated Accounting Statements (Continued)

1. Economic Entity and Principal Accounting Policies and Practices (continued)

Accounting for Contingencies

As of the date the consolidated financial statements are issued, conditions might exist that result in losses for the Company, which will only be known if future specific circumstances arise. Management and legal counsel evaluate these situations based on their nature, the likelihood that they will materialize, and the amounts involved, to decide on any changes to the amounts accrued and/or disclosed. This analysis includes current legal processes against the Company and claims not yet initiated. On the other hand, the Company maintains insurance policies to cover specific operational risks and asset protection.

Ecopetrol has recognized the provisions corresponding to rational estimations intended to cover the forecast of future facts deriving from probable loss contingencies or occurrence of events that may impact Company’s equity.

Risks and Uncertainties

The Company is subject to certain operational risks such as terrorism, products’ thefts, crude oil international price changes and environmental damages in variations in the estimations of hydrocarbon reserves.

Net Weighted Income per Share

Net income per share is calculated on the weighted average of outstanding shares of the Company during the year.

Memorandum Accounts

These accounts represent facts or circumstances from which rights or obligations could derive and affect the Company.

2. Assets and Liabilities Denominated in Foreign Currency

At December 31, 2007 and 2006, the consolidated financial statements of Ecopetrol included the following assets and liabilities denominated in foreign currencies (which are translated into Colombian pesos at the closing exchange rates):

F-18

Ecopetrol S.A.

Notes to the Consolidated Accounting Statements (Continued)

2. Assets and Liabilities Denominated in Foreign Currency (Continued)

	2007		2006
	(Thousands of US$)	(Millions of Equivalent Pesos)	(Thousands of US$)	(Millions of Equivalent Pesos)
Assets:
Investments	3,445,552	6,941,960	894,917	2,003,532
Cash and cash equivalents	565,783	1,139,916	405,473	907,768
Receivables from foreign products clients	219,707	442,657	142,459	318,936
Advances for joint operations investments	184,453	371,629	111,994	250,731
Other advances	73,416	147,915	128,800	288,356
Sundry debtors	57,171	115,185	74,329	166,404
Petroleum Stabilization Savings Fund – FAEP	––	––	1,717,073	3,844,167
Accounts receivables Ecogas (BOMT´s)	––	––	482,212	1,079,571
	4,546,082	9,159,962	3,957,257	8,859,465
Liabilities:
Abandonment costs	758,589	1,528,374	605,680	1,355,991
Advances received/obligations related with BOMT	626,927	1,263,107	164,697	368,723
Partners’ financing	123,143	248,104	104,381	233,686
Suppliers	14,368	28,948	1,498	3,354
Deposits and guarantees	682	1,375	40,968	91,679
Petroleum Stabilization Savings Fund – FAEP	––	––	1,717,073	3,844,167
Financial obligations	––	––	19,050	42,649
Estimated liabilities and provisions	4,921	9,913	11,926	26,706
	1,528,630	3,079,821	2,665,273	5,966,955

3. Cash and Cash Equivalents

	2007		2006
Banks and savings entities	$	1,160,069	$	596,018
Sight investments (1)		2,466,180		995,174
Special and revolving funds (2)		110,728		36,148
In-transit funds		12,523		—
Cash		399		536
	$	3,749,899	$	1,627,876

(1) Sight investments correspond to deposits with financial institutions that generate a yield and can be withdrawn at any time without prior notice or penalty.

(2) Includes $66 to settle potential future claims pending the decision of the extraordinary recourse filed by Comuneros de Santiago de las Atalayas and Pueblo Viejo and $6 with which the Company expects to settle the sentence against it by the First Cúcuta Civil Circuit Court, originated by the lawsuit filed by Ana Cecilia Rodríguez for easements and legal fees.

F-19

Ecopetrol S.A.

Notes to the Consolidated Accounting Statements (Continued)

4. Investments

	2007			2006
Current:
Fixed yield:
Dollar investments:
Treasury Securities – TES	$	3,695,211		$	60,805
Bonds and securities of private or foreign entities		1,168,723			22,345
Latin American Reserves Fund – FLAR (1)		447,249			464,863
Santiago de las Atalayas Fund (Note 18)		331,900			224,174
Time deposits		195,699			1,178,999
Bonds issued by the Government		115,714			10,107
Other investments		6			—
Tax refund securities		—			394
	$	5,954,502		$	1,961,687
Long term:
Variable yield – shares	$	1,125,945		$	962,064
Fixed yield:
Bonds and securities of foreign entities:		2,264,230			1,186,783
Bonds issued by the Government		521,997			440,535
Treasury securities – TES		60,878			64,282
Santiago de las Atalayas Fund (Note 18)		2,287			128,242
Own Insurance Fund		25			152,377
		3,975,362			2,934,283
Less provision for protection of investments (shares of Oleoducto de Colombia S.A.)		(130,543	)		(125,593	)
	$	3,844,819		$	2,808,690

(1) On April 17, 2006, the Company entered into an agreement for the custody, investment and administration of resources delivered to the FLAR to set up an investment portfolio. The contract duration was extended through December 31, 2009 and the fund amount may be increased or decreased during the contract execution period, or its extensions, without falling below US$100 million. During the contract term, the average annual profitability of the portfolio has been of 6.29% effective annually.

F-20

Ecopetrol S.A.

Notes to the Consolidated Accounting Statements (Continued)

4. Investments (continued)

Investments are identified and recorded at their historical cost or acquisition price and are revaluated upon considering the intention of realization, the availability of information in the market and, dealing with equity investments, the degree of control over the issuer, by applying methodologies that approach their economic value, such as the quotation in the stock exchange, the net present value for the determination of the market price or the security internal profitability.

A summary of variable yield long term investments at December 31, 2007, valued at market value and their provision, is as follows:

	Number of Shares and/or Quotas	Participation Percentage	Valuation Date		Intrinsic Market Value		Historical Cost		Valuation		Provision
Not Strategic Investments:
Interconexión Eléctrica ISA (1)	58,925,480	6	Dec-07	$	418,371	$	69,549	$	348,822	$	—
Empresa Energía de Bogotá (1)	6,310,980	7	Dec-07		448,106		169,421		278,685		—
Colombia Telecomunicaciones	100	0.1	Dec-07		1		1		—		—
Strategic Investments:											—
Refinería de Cartagena S.A. (2)	979,999	49	Dec-07		1,375,037		239,271		1,135,766		—
Ocensa S.A.	1,820,824	35	Dec-07		643,848		396,020		247,828		—
Invercolsa (1) and (4)	889,410,047	32	Dec-07		127,696		60,282		67,414		—
Oleoducto de Colombia S.A.	15,925	44	Nov-07		51,026		181,569		—		130,543
Ecodisel (3)	7,750,000,000	50	Dec-07		7,751		7,750		1		—
Serviport	53,714,116	49	Oct-07		4,082		2,082		2,000		—
				$	3,075,918	$	1,125,945	$	2,080,516	$	130,543

(1) During 2007, Interconexión Eléctrica ISA, Empresa de Energía de Bogotá and Invercolsa declared dividends to its shareholder Ecopetrol of $7,542, $8,626 and $9,219, respectively.

(2) Ecopetrol initially contributed to Refinería de Cartagena S.A. certain assets with an historical cost of $239,271 and a valuation of $1,146,824 in exchange for a 49% shareholding participation. Ecopetrol recorded its investment initially at $1,386,095, which was the fair value of the 49% interest received. This transaction was authorized by CGN by means of communication SGI 200612-81970 of December 1, 2006. The subsequent devaluations in the intrinsic value of the shares, originated by losses incurred in the valuation of investments in foreign currency, are accounted for as a redemption of the original appraised value.

(3) Ecodisel Colombia S.A. was organized on April 19, 2007 to construct and operate a plant in Barrancabermeja that will produce 100,000 tons of bio-diesel fuel per year, equivalent to 2,000 barrels per day. Ecopetrol’s initial contribution amount was $2,600.

Restrictions over Investments:

(4) In accordance with the sentence of February 8, 2007, issued by the 28th Bogotá Civil Court, Mr. Fernando Londoño was required to return to Ecopetrol the package of shares of Inversiones de Gases de Colombia S.A. (Invercolsa), as well as the amount paid in 1997. This sentence was appealed and its second instance decision is pending. On June 8, 2007, the 28^th the Court declared the seizure and deposit into an escrow account of the 145 million Invercolsa shares and any dividends or distribution in connections therewith and appointed a custodian.

F-21

Ecopetrol S.A.

Notes to the Consolidated Accounting Statements (Continued)

4. Investments (continued)

In developing a constitutional action filed by two citizens, the Council of State ruled in favor of Ecopetrol granting it the control of the shares under litigation, a decision that was confirmed by a tutela action and which, in turn, was reviewed by the Constitutional Court in August 2007.

The Company will only recognize dividends income once the final sentence in its favor is delivered and the recoverability of the resulting amounts can be assured.

A summary of the balances as of December 31, 2007 of consolidated subsidiaries:

	Assets		Liabilities		Equity		Year result
Black Gold Re (1)	$	199,499	$	10,172	$	189,327	$	8,646
Ecopetrol del Perú S.A. (2)		53,234		5,846		47,388		—
Ecopetrol America Inc. (3)		40,295		—		40,295		—
Ecopetrol Oleo e Gas Do Brasil Ltda. (4) and (5)		4,875		22		4,853		—
	$	297,903	$	16,040	$	281,863	$	8,646

(1) On August 24, 2006, a captive reinsurance company was organized abroad, which serves to process the Company’s risks, permitting the optimization of insurance retention levels and the transfer thereof. The initial investment for its organization was of US$12 million and a capitalization of US$77.7 million was made in December 2007. Black Gold Re was registered as the foreign reinsurance company with the Financial Superintendency, which authorizes it to render direct reinsurance services through insurance companies organized in Colombia.

(2) In July 12, 2007, Ecopetrol and Talisman obtained in Perú Lot 134 in the bidding of exploratory blocks, designated as 2007 Round, carried out by Perupetro, a regulatory entity of the hydrocarbons sector in that country.

Lot 134 of 827,000 hectares (8,270 square kilometers) is located in the northeast of Perú in the Marañon Basin.

Geological and geophysical studies will be carried out during the first phase of the project, which includes a waiver option at the end of the first 12 months. The option also exists of continuing in a second phase of 18 months with the minimum commitment of acquiring 200 kilometers of 2D seismic.

Additionally, in November 2007, the Peruvian government issued a decree whereby it approved the assignment of interests for the participation in Lots 101 and 90 to Ecopetrol, Talisman and Repsol, respectively. Ecopetrol has a 30% and 49% participation in these lots, respectively.

For the development of these activities in August 2007, Ecopetrol organized the company Ecopetrol del Perú S.A., with a 99.99% ownership interest. The initial contribution amount of Ecopetrol was US$5,000 and a capitalization of US$23.5 million was made in November 2007.

(3) In December 2007, the Company entered into a participation agreement with Shell Offshore Inc. for the exploration of exploratory blocks 777 and 778 (Clearwater prospect), located in deep waters of the Mexican Gulf; Ecopetrol owns a 25% participation in these blocks.

For the development of these activities, the Company organized the company Ecopetrol America Inc., with an initial contribution of US$20 million and a participation of 100% ownership interest.

F-22

Ecopetrol S.A.

Notes to the Consolidated Accounting Statements (Continued)

4. Investments (continued)

(4) Ecopetrol was awarded by the National Oil Agency of Brazil the Block TUC-T-156, an exploratory block off the coast of Brazil. Ecopetrol will have a participation of 30% and will serve as the operator. Petrobrás will have a participation of 70%.

Pre-contractual commitments acquired by Ecopetrol correspond to the execution of an exploratory program equivalent to 250 kilometers of seismic 2D to be developed during the first three years, of an estimated net amount of US$1,125,000 for the Company.

In developing the round, two legal actions were filed that generated a temporary suspension that has not yet permitted the confirmation of the block award and entering into the respective concession contract. Accordingly, no activities have been carried out in the stated block.

As part of the previous requirements for entering into the contract, the company Ecopetrol Oleo e Gas do Brasil Ltda. was organized in December 2006, which was capitalized with an initial contribution by Ecopetrol of US$2 million and an ownership interest of 99.99977%. These resources have had as their principal purpose the commitments acquired in Block TUC-T-156, and the development of new exploration and production businesses in Brazil.

(5) In November 2007, Ecopetrol S.A. submitted winning offers in six exploratory blocks within the 9th Bidding Round held in Brazil as follows:

The Consortium was formed by Petrobrás, Petrogal and Ecopetrol for Block CM593 located in the Campos Basin, where the Company has a participation of 37.5%.

The consortium that includes Petrobrás, Compañía Vale do Rio Doce and Ecopetrol in PAMA-M 187, 188, 222 and 223 blocks, is located in the Para-Maranhao basin, where Ecopetrol has a 30% participation.

The Petrobrás and Ecopetrol Consortium in the offshore block S-M-1476 in the Santos basin, where Ecopetrol has a 30% participation.

The subscription of contracts will be made through Ecopetrol Oleo e Gas do Brasil Ltda., which was capitalized in December 2007 with an additional contribution of US$6.3 million.

The economic activity and the gross results of the 2007 year of the investments issuers in participations are:

Company	Economic Activity	Company’s Net Income
Interconexión Eléctrica S.A.	Operation, maintenance, transmission and commercialization of electric power.	$226,021
Empresa de Energía de Bogotá S.A.	Electric power transmission	625,602
Colombia Telecomunicaciones S.A. E.S.P.	Rendering of long-distance services, local telephony, data transmission, dedicated and commuted internet.	233,838
Refinería de Cartagena S.A.	Construction and operation of refineries, refining of hydrocarbons, production, commercialization and distribution of crude oil, natural gas and by-products.	1,357
Ocensa S.A.	Construction and operation of a pipeline system, which terminal is located at the Coveñas port, Municipality of Tolú, Colombia.	25,555
Invercolsa	Investments in energy sector companies including activities inherent to the hydrocarbons and mining industries.	7,772

F-23

Ecopetrol S.A.

Notes to the Consolidated Accounting Statements (Continued)

4. Investments (continued)

Company	Economic Activity	Gross Result of Year
Oleoducto de Colombia S.A	Construction and operation of a pipeline system, which terminal is also at Coveñas port,	(6,553)
Serviport S.A.	Rendering to the public in general of the necessary services for the loading and unloading support of oil ships, supply of equipment for the same purpose, load inspections and measurements	(207)
Ecodiesel Colombia S.A.	Construction and operation of plants for the production of bio-fuels and oleo-chemicals and their mixes with hydrocarbon derivative fuels, in addition to the production and distribution thereof.	2

Investments with maturities of less than one year and those which will be utilized within the next business cycle are classified as current assets.

Summary of main long term investments at December 31, 2007 to be redeemed during the next five years:

		1 - 3 Years		3 - 5 Years		> 5 Years		Total
Private bonds	$	1,731,704	$	457,753	$	74,773	$	2,264,230
Bonds and other Government securities		224,837		50,016		247,144		521,997
Treasury Securities - TES		17,721		32,583		10,574		60,878
Santiago de las Atalayas Fund		2,287		—		—		2,287
	$	1,976,549	$	540,352	$	332,491	$	2,849,392

5. Accounts and Notes Receivable

	2007			2006
Current portion:
Clients:
Local	$	482,059		$	500,264
Foreign		442,657			318,936
		924,716			819,200
Other debtors (1)		778,712			183,052
Related parties (Note 15)		341,054			40,506
Reimbursements and investment yields		111,935			164,170
Association contracts – joint operations		79,559			120,054
Doubtful accounts		28,665			8,173
Notes receivable		19,642			4,966
Accounts receivable from employees		7,541			15,086
Industrial service clients		6,745			4,959
		2,298,569			1,360,166
Less provision for doubtful accounts		(28,665	)		(23,847	)
	$	2,269,904		$	1,336,319
Long-term portion:
Cavipetrol – loans to employees for housing (2)	$	137,629		$	129,741
Credit portfolio		60,040			13,092
Other		4,896			6,070
	$	202,565		$	148,903

F-24

Ecopetrol S.A.

Notes to the Consolidated Accounting Statements (Continued)

5. Accounts and Notes Receivable (continued)

(1) Includes $636,551 of the balance receivable from the Ministry of Mines and Energy, corresponding to subsidies for diesel and regular gasoline and $22,695 receivable from intermediaries in the placement of Company’s new shares, for the collection corresponding to the initial installment paid by the subscriber during 2007.

(2) By means of Leg contracts 058-80 of 1980 and 4008928 of 2006, the administration, management and control of loans granted to employees by the Company were given to Cavipetrol. In its capacity as administrator, Cavipetrol acts as custodian in its database and financial system of the detail by employee of said loans and their respective conditions. Within the policies established by the Company, the applicable interest rate as of April 7, 2006, for new credits corresponds to UVR (Real Value Unit) with a ceiling of 12%.

Aging determination and classification of accounts receivable at December 31, 2007, pursuant to maturity:

	Expiration Days
	0 – 180		181 – 360	More than 361
Current accounts receivable	$	920,211	—	$	—
Past due accounts receivable		4,505	—		1,507
	$	924,716	—	$	1,507
Local customers	$	482,059	—	$	1,507
Foreign customers		442,657	—		—
	$	924,716	—	$	1,507

Classification by expiration of long-term credit portfolio at December 31, 2007:

		Days Rank
Debtor Name	Applicable Interest Rate	365 – 720		721 – 1095		1096 – 1460		1461 – 1825		1826 – 2190		>2190		Total
Asfalto y Transporte	DTF+ 6 pts.	$	10	$	—	$	—	$	—	$	—	$	—	$	10
Ultragás	IPC		14		19		19		19		19		2		92
Perenco			23		—		—		—		—		—		23
Almansilla	IPC		37		19		19		19		16		81		191
Departamento de Nariño	0%		45		—		—		—		—		—		45
Almagás	IPC		66		61		61		61		61		59		369
Cotempetrol	DTF		76		42		45		11		—		—		174
Chevron Texaco			87		—		—		—		—		—		87
USO	6%		120				—		—		—		—		120
Víctor Manuel Gutiérrez	9%		127		—		—		—		—		—		127
Petrosantander			302		—		—		—		—		—		302
Gecelca S.A. E.S.P.	IPC		19,500		13,000		13,000		13,000		—		—		58,500
		$	20,407	$	13,141	$	13,144	$	13,110	$	96	$	142	$	60,040

DTF: Average of interest rates for fixed term deposits, promulgated by the Superintendency of Finance.

IPC: Consumer index prices, as indicated by Colombian Government.

The classification of accounts and notes receivable between current and non-current is based upon Management’s estimation of the recoverability of accounts receivable. When it is estimated that their realization will occur within twelve months following the balance sheet date, it is classified as current; otherwise, it will be classified as non-current. Also, certain accounts receivable have the nature of non-current, when there are contractual or legal provisions that require such presentation.

F-25

Ecopetrol S.A.

Notes to the Consolidated Accounting Statements (Continued)

5. Accounts and Notes Receivable (continued)

Future collections of accounts receivable at December 31, 2007 from Cavipetrol, are as follows:

Year	Amount
2008	$	21,670
2009		22,564
2010		23,107
2011		23,411
2012 and thereafter		46,877
	$	137,629

Below are the initial and ending balances of provisions for accounts receivable, together with period adjustments:

	2007			2006
Initial balance	$	23,847		$	28,760
Additions (new provisions)		15,591			41,835
Adjustments of existing provisions		3,064			(33,999	)
Recoveries		(13,837	)		(12,749	)
Ending balance	$	28,665		$	23,847

No other significant restrictions exist for the recovery of accounts and notes receivable.

6. Inventories

	2007			2006
Processed products:
Crude oil and natural gas	$	522,157		$	317,789
Fuels		313,798			191,032
Petrochemicals		70,217			52,832
Raw materials – crude oil and natural gas		129,506			146,628
Purchased products:
Crude oil and natural gas		14,780			96,501
Fuels		152,898			23,782
Petrochemicals		2,543			4,678
Natural gas		110			1
In-process products – fuels and petrochemicals		162,377			144,728
Materials for production of assets		10,483			17,333
In transit materials		894			1,809
		1,379,763			997,113
Less provision for price difference		(80,971	)		(752	)
	$	1,298,792		$	996,361

F-26

Ecopetrol S.A.

Notes to the Consolidated Accounting Statements (Continued)

6. Inventories (continued)

Below are the adjustments made to the provisions for price difference for the years ended December 31, 2007 and 2006:

	2007		2006
Initial balance	$	752	$	243
Adjustment of existing provisions		80,219		509
Ending balance	$	80,971	$	752

7. Advances and Deposits

Official entities (1)	$	1,184,023	$	804,601
Partners in joint operations (2)		577,792		495,626
Related parties (3) (Note 15)		161,422		302,600
Contractors		23,274		23,511
Agreements		17,163		16,614
Customs agents		15,049		5,942
Advances to suppliers		664		5,190
Employees		227		266
		1,979,614		1,654,350
Long-term portion (tariffs advanced to Ocensa) (3)		—		(302,600	)
	$	1,979,614	$	1,351,750

(1) Includes transactions with the National Tax and Customs Administration (“DIAN”) for income tax withholdings and with the Municipal Tax Administrations of Cartagena and Barrancabermeja for industry and commerce tax advances.

(2) Associated operations:

Operator	2007		2006
Partners:
BP Exploration Company (Colombia) Ltd.	$	278,827	$	140,798
Mansarovar Energy Colombia Ltd.		54,370		9,606
Petrobrás Colombia Ltd.		31,267		145,118
Meta Petroleum Ltd.		31,051		16,742
Other operations		25,324		21,160
Occidental de Colombia Inc.		21,301		14,423
BHP Billintin Petroleum Colombia		10,330		—
Nexem Petroleum Ltd.		8,781		9,506
Perenco Colombia Ltd.		7,320		9,570
Kappa Resources Colombia Ltd.		5,788		713
Petrobras International Braspetro B.V.		5,420		26,161
Operator - Ecopetrol S.A.:
Oleoducto Caño Limón		95,525		81,110
Other operations		2,323		12,691
Catleya shared risk		88		1,947
Gasoducto Opon		77		182
Master agreement TLU1		—		1,120
Oleoducto de Colombia – Mandate		—		4,779
	$	577,792	$	495,626

F-27

Ecopetrol S.A.

Notes to the Consolidated Accounting Statements (Continued)

7. Advances and Deposits (continued)

(3) From 2004 to 2006 it was necessary to apply the mechanisms provided for in the Ocensa transportation agreement, for the tariff advance, and complement the payment of Ocensa cash needs payable by its shareholders. The balance of the advance of $159,202 at December 31, 2007 (equivalent to US$72 million, plus a portion in pesos of $14,065) will be recovered during the next few months given the end of the payment of financial obligations of said company. During 2007, there were recoveries of advances by US$53 million, plus a portion in pesos of $5,460.

8. Property, Plant and Equipment, net

	2007			2006
Plant and equipment	$	10,116,645		$	10,340,395
Pipelines, networks and lines		3,700,446			3,653,204
Construction in progress		1,526,127			906,896
Buildings		1,007,769			1,002,362
Equipment on deposit and in transit		638,784			532,038
Computers		268,598			267,762
Other fixed assets		166,355			201,543
Transportation equipment and communication networks		132,004			137,848
Land		64,789			65,136
		17,621,517			17,107,184
Less accumulated depreciation		(11,364,448	)		(11,176,023	)
Less provision for obsolete oil and gas materials and supplies		(105,118	)		(97,227	)
	$	6,151,951		$	5,833,934

Construction in progress corresponds to development projects, which are transferred to the respective headings once the assets start their production stage and are in a condition to be used.

The estimated residual values are only considered in the valuation process of property, plant and equipment and only in the event that assets are fully depreciated and are not under operation conditions. A general average of 5% of cost is applied, considering its exclusive usefulness for the oil industry. This criterion is not applicable to assets classified as pipelines and buildings upon considering that recoverable costs are equivalent to removal and transportation costs for their retirement. Assets are depreciated at 100% of their book cost adjusted for inflation.

During 2005 and 2006, the Company carried out a physical inspection of property, plant and equipment for its standardization of procedures, and its reconciliation to the Company´s accounting records. The appraisal study was supported by methodologies of recognized technical value corresponding to international standards, incorporating a technical depreciation methodology widely used by the industrial public sector and by companies in the worldwide oil sector.

The result of said study generated an excess realization amount for accounting purposes of $4,940,169 and was recorded in accordance with the policy contained in the PGCP, which indicates that when the realization value is higher than the carrying amount, a valuation is recognized and, on the contrary, the valuation is decreased until it is zero, and beyond that amount, devaluations are recorded even if the new appraisal value is bellow original cost.

F-28

Ecopetrol S.A.

Notes to the Consolidated Accounting Statements (Continued)

8. Property, Plant and Equipment (continued)

Summary of property, plant and equipment at December 31, 2007:

Class of Asset	Adjusted Cost		Accumulated Depreciation		Provisions		Valuations		Realization Value
Plant and equipment	$	10,116,645	$	7,903,317	$	44,120	$	3,027,351	$	10,324,281
Pipelines and networks lines		3,700,446		2,511,837		60,990		192,738		242,013
Construction in progress		1,526,127		—		—		—		—
Buildings		1,007,769		480,961				263,157		736,633
Equipment on deposit and in ransit		638,784		—				—		—
Other assets		298,359		248,077		8		67,592		97,848
Computers		268,598		220,256		—		4,360		14,660
Land		64,789		—		—		11,668		11,668
	$	17,621,517	$	11,364,448	$	105,118	$	3,566,866	$	11,427,103

Summary of property, plant and equipment at December 31, 2006:

Class of Asset	Adjusted Cost		Accumulated Depreciation		Provisions		Valuations			Realization Value
Plant and equipment	$	10,340,395	$	7,749,795	$	3,185	$	4,568,628		$	11,149,221
Pipelines and networks lines		3,653,204		2,476,824		60,990		115,871			202,663
Construction in progress		1,002,362		423,917		—		150,703			800,021
Buildings		906,896		—		—		—			—
Equipment on deposit and in transit		532,038		—		33,044		—			—
Other assets		267,762		226,801		8		(1,904	)		8,227
Computers		339,391		298,686		—		37,230			84,902
Land		65,136		—		—		69,641			69,641
	$	17,107,184	$	11,176,023	$	97,227	$	4,940,169		$	12,314,675

Summary of non-operating assets:

Asset Class	No. of Units	Net Accounting Value
Plant and equipment	144	$	8
Other fixed assets	89		—
Computer	9		—
Other equipment	12		—
	254	$	8

In accordance with the Company’s policy, assets not required for the operation are removed from the books and recorded in accordance with the means of disposition defined, i.e., sale, assignment without cost, payment in kind or scrapping.

F-29

Ecopetrol S.A.

Notes to the Consolidated Accounting Statements (Continued)

9. Natural and Environmental Properties

	2007			2006
Amortizable oil investments	$	10,289,578		$	8,509,583
Less – accumulated amortization		(6,082,884	)		(5,527,975	)
		4,206,694			2,981,608
Plugging and abandonment, dismantling of facilities and environmental recovery costs		1,528,132			1,355,991
Less – accumulated amortization		(951,690	)		(861,947	)
		576,442			494,044
Reservoirs and appraisals (1)		701,590			701,590
Less – accumulated depletion		(556,014	)		(538,452	)
		145,576			163,138
Exploration in progress		200,205			112,979
Development of exploration areas		—			28,621
	$	5,128,917		$	3,780,390

(1) The appraisal of reserves represents reservoirs received from the reversion of concession contracts of $520,218 and $181,372, administrated by the Central and Middle Magdalena managements, respectively.

10. Pension Plan Assets

At December 31, the Company has set up the following trusts:

	2007			2006
Consorcio Fidubogotá y Fiducolpatria	$	2,077,168		$	2,003,564
Consorcio Fiducafé, Fiduprevisora y Fidupetrol		1,982,653			1,895,769
Consorcio Fidupopular y Fiduoccidente		1,767,901			1,680,822
Consorcio Fiducolombia y Santander Investment		1,391,593			1,216,310
Consorcio Fiducomercio, Fiduvalle y BBVA		1,140,656			1,082,690
Consorcio Fiduagraria, Fiducoldex y Helm Trust		1,135,703			1,081,742
		9,495,674			8,960,897
Less portion redeemable within short term		(508,813	)		—
	$	8,986,861		$	8,960,897

Funds are settled under irrevocable five-year contracts conditioned to the level and type of investment and subject to the control of the Company’s Investments Committees. Interest accumulated as of December 31, 2007 at the annual rate of 4.81%, is capitalized in the investment accounts.

Decree 2153 of 1999 required the Company to fund up to 70% of its pension liability existing as of December 31, 1998, by means of annual contributions to the fund from 2000 to 2007. However, pursuant to Extraordinary Decree 1760 of 2003, the Company may issue shares to be placed, in the name of its pension trusts as contributions intended to cover pension obligations. The Board of Directors and the Superior Council of Tax Policy (CONFIS) authorized the funding of this liability to the Company’s with prior years’ treasury surpluses.

F-30

Ecopetrol S.A.

Notes to the Consolidated Accounting Statements (Continued)

10. Pension Plan Assets (continued)

	2007		2006
Initial balance	$	8,960,897	$	8,618,698
Capital contributions		102,032		—
Yields		432,745		342,199
Ending balance	$	9,495,674	$	8,960,897

Trend of the coverage of pension trusts with reference to the pension liability:

	December 31
	2001			2002			2003			2004			2005			2006			2007
	(In billions)
Pension liability (Note 17)	$	7,020		$	7,837		$	8,626		$	9,080		$	9,583		$	10,122		$	10,819
Pension trusts		3,239			3,769			4,590			6,322			8,618			8,961			9,496
Coverage		46	%		48	%		53	%		70	%		90	%		89	%		88	%

	2007	2006
Cusiana and Cupiagua field	—	$	2,529,439
Caño Limón field	—		1,314,728
	—	$	3,844,167

11. Petroleum Stabilization Savings Fund – FAEP

The FAEP was organized in accordance with Law 209 of 1995, as a system to handle overseas accounts with restricted availability to be managed by the Central Bank. The transfer of Ecopetrol´s operating cash to this restricted Fund which it owns had a strictly temporary nature and its single purpose was tax savings and macroeconomic stabilization, and did not mean its appropriation by the Nation. The Cusiana, Cupiagua and Caño Limón fields were the generators of savings for the Fund. Until August, 2007 the FAEP had an average annual return of approximately 4.53%.

Decree 3238 of August 27, 2007, in agreement with Law 1151 of 2007, determined that the ownership of the accounts at the name of Ecopetrol in the FAEP belongs to the Nation, represented through the Ministry of Finance and Public Credit. For this reason the FAEP operations were only recognized in the financial statements until August 2007.

12. Deferred Charges

	2007		2006
Deferred income tax (Note 16)	$	1,779,874	$	1,624,756
Other deferred charges, net		111,556		239,531
Charge for deferred monetary correction, net		79,242		94,980
Deferred reinsurance expenses		5,390		—
BOMT – ECOGAS contracts (1)		—		983,350
Preoperative expenses		—		38,214
Maintenance and major repairs of plant, tanks and equipment		—		27,540
	$	1,976,062	$	3,008,371

F-31

Ecopetrol S.A.

Notes to the Consolidated Accounting Statements (Continued)

12. Deferred Charges (continued)

(1) In February 2007, in agreement with section 1.1.6 of communication 199911-1505 of the CGN, the Company amortized 100% of the deferred charge accrued for the billing of the BOMT contracts and created an account receivable together with the balances pending billing to Ecogas, which was fully collected in June 2007. (See Note 19).

13. Other Assets

	2007		2006
Retirement pension fund of personnel related with joint operations	$	211,238	$	174,791
Hydrocarbons investments fund of Colombia		72,845		68,079
Trademarks, licenses and patents		53,775		58,550
Deposits in administration		29,092		11,015
Fund for abandonment of facilities (1)		21,651		13,229
National Royalties Fund		6,206		90,349
Other assets		4,594		12,401
Assets retired		—		872
	$	399,401	$	429,286

(1) The movement of trusts funds administrated by Fiducolombia for activities related with the abandonment of wells in the joint operation of Cravo Norte, ACN and Casanare are shown below:

	2007		2006
Initial balance	$	13,229	$	—
Capital contribution		7,196		13,229
Yields		1,226		—
Ending balance	$	21,651	$	13,229

14. Financial Obligations

	Interest Rate 2007/2006	2007	2006	2007			2006
	(Thousands)
Foreign currency debt
Japan Eximbank	Libor + 0.34%	—	US$ 18,750	$	—		$	41,977
Overdrafts and interest			—		3,569			897
		—	18,750		3,569			42,874
Less: Current portion		—	(18,750)		(3,569	)		(42,874	)
		—	US$ –	$	—		$	—

Foreign currency obligations were guaranteed directly by the Colombian Nation and paid during 2007.

F-32

Ecopetrol S.A.

Notes to the Consolidated Accounting Statements (Continued)

15. Accounts Payable and Transactions with Related Parties

	2007		2006
Advances from partners	$	660,538	$	345,525
Deposits received from third parties		249,148		250,826
Reimbursements of exploratory costs		128,998		121,315
Suppliers		66,135		72,515
Sundry creditors		26,170		19,882
Related parties		15,108		1,675
Reinsurance payable		199		—
		1,146,296		811,738
Less long-term portion		—		(50,018	)
	$	1,146,296	$	761,720

Summary of the most representative balances with related parties where Ecopetrol holds direct investments or interest, and are included in debtors, suppliers and accounts payable:

	Accounts Receivable		Advances Receivable		Accounts Payable
Ocensa S.A.	$	2,780	$	159,202	$	—
Oleoducto de Colombia S.A.		150		2,220		1,097
Refinería de Cartagena S.A.		325,829		—		13,494
Cavipetrol		11,726		—		—
Short term	$	340,485	$	161,422	$	14,591
Long term	$	569		—	$	517
Balance at December 31, 2007	$	341,054	$	161,422		15,108
Balance at December 31, 2006	$	40,506	$	302,600	$	1,675

Principal transactions with related parties during the years ended December 31, 2007 and 2006:

	Sales and Services		Leases		Other
Revenue:
Refinería de Cartagena S.A.	$	2,995,346	$	—	$	12,428
Ocensa S.A.		11,562		13,209		533
Ferticol S.A.		5,361		—		14,033
Oleoducto de Colombia S.A.		5,050		—		—
Cavipetrol		—		—		1
Serviport		—		—		16
Total 2007	$	3,017,319	$	13,209	$	27,011
Total 2006	$	29,273	$	18,539	$	34,719

F-33

Ecopetrol S.A.

Notes to the Consolidated Accounting Statements (Continued)

15. Accounts Payable and Transactions with Related Parties (continued)

	Transportation Cost		Assignment of Accounts Receivable		Other
Expense:
Ocensa S.A.	$	521,828	$	—	$	23,121
Oleoducto de Colombia S.A.		13,121		—		—
Cavipetrol		—		—		7,352
Ferticol S.A.		—		13,836		220
Serviport		—		—		70
Refinería de Cartagena S.A.		—		—		550
Total 2007	$	534,949	$	13,836	$	31,313
Total 2006	$	487,081	$	—	$	28,483

For Ocensa S.A. and Oleoducto de Colombia S.A. there is a maximum tariff determined by the Ministry of Mines and Energy that can be collected by both companies for the use of its system. Their operation is based on the collection of total operating and administrative expenses and in the determination of the transportation unit cost. The cost per barrel is transferred to each shareholder that uses the system based on the barrels transported.

16. Taxes Payable

	2007		2006
Income tax	$	2,006,484	$	1,456,268
Payable to ANH for purchases of hydrocarbons		418,273		268,036
Sales tax payable		120,664		128,462
Equity tax		103,556		—
Special tax on gasoline (1)		100,866		99,714
Taxes withheld from third parties		127,121		75,481
Industry and commerce and other minor taxes		16,048		9,787
	$	2,893,012	$	2,037,748

(1) This tax is levied on sales and/or consumption of regular and premium gasoline and Diesel. The funds collected for this tax are paid to the National Treasury Office of the Ministry of Finance. The special tax is paid on the basis of the percentage participation of each beneficiary in the national monthly consumption of regular and extra gasoline.

Income tax returns may be reviewed by the tax authorities within two years of their filing date. Currently, differences exist with the National Tax and Customs (DIAN) regarding the calculation and payment method of the first installment of the 2003 and 2004 income tax returns because in the opinion of the DIAN the surtax of such years should have been included in the base. Additionally, for the 1996 income tax return, the Council of State is evaluating the applicability of exempt income of asphalts and the disallowance by the DIAN of losses on the sales of accounts receivable. The Company’s claims were recognized in the first court decision as far as exempt income from asphalts, and the interpretation of the DIAN was backed in connection with losses on sales of accounts receivable, a decision that was appealed by Ecopetrol. However, Management does not expect significant differences in the resolution of these actions.

F-34

Ecopetrol S.A.

Notes to the Consolidated Accounting Statements (Continued)

16. Taxes Payable (continued)

The provision for income tax was determined on net taxable income, as follows:

	2007			2006
Current income tax	$	2,006,484		$	1,456,268
Prior years’ income tax		—			38,526
Deferred tax:
Credit		34,146			(65,396	)
Debit		(155,118	)		70,371
		(120,972	)		4,975
	$	1,885,512		$	1,499,769

The deferred tax liability arises mainly from differences in capitalization, amortization and depreciation policies and inflation adjustments of assets, while the deferred tax assets arises mainly, from the higher accounting provisions. The balance of deferred income tax is as follows:

	2007			2006
Deferred tax asset:
Initial balance	$	1,624,756		$	921,833
Movement of the year		155,118			(70,371	)
Prior periods’ movement – Inflation adjustments		—			770,474
Other		—			2,820
Ending balance (Note 12)		1,779,874			1,624,756
Deferred tax liability:
Initial balance		610,711			668,426
Movement of the year		41,239			(65,396	)
Prior periods’ movement		(7,093	)		7,681
Ending balance (Note 19)	$	644,857		$	610,711

As established in Decree 941 of 2002 and article 135 of Law 100 of 1993, trusts funds formed for the payment of the Company’s pension liabilities, are exempt from all taxes, rates and contributions of any national origin.

Subsidiaries in a preoperative stage are not subject to the payment of income tax. Black Gold Re is located in a country not requiring payment of income tax.

F-35

Ecopetrol S.A.

Notes to the Consolidated Accounting Statements (Continued)

16. Taxes Payable (continued)

Reconciliation of net taxable income:

	2007			2006
Accounting net income before income taxes	$	7,065,304		$	4,891,142
Income from monetary correction		23,711			(89,940	)
Effect of tax inflation adjustments		(391,391	)		23,598
Non deductible costs and expenses		432,278			227,812
Special deductions and deductible tax expenses		(1,176,608	)		(589,051	)
Income from recovery of deductions		27,022			—
Other taxable income		28,950			—
Income not constituting income or capital gains		(22,772	)		(30,324	)
Non-taxed income		(594,954	)		(995,505	)
Non-deductible provisions		1,184,895			647,949
Lower value of income from autonomous equities		238,327			482,255
Net taxable income		6,814,762			4,567,936
Net exempt income		(863,946	)		(764,633	)
Net taxable income		5,950,816			3,803,303
Basic income tax		2,023,277			1,331,156
Surtax 10%		—			133,115
Tax discounts		(16,793	)		(8,003	)
Current tax payable	$	2,006,484		$	1,456,268

17. Labor and Pension Plan Obligations

	2007			2006
Retirement pensions (1)	$	10,819,078		$	10,121,809
Bonuses and allowances		32,520			13,892
Vacations		24,184			21,312
Severance		17,620			17,913
Pension bonuses issued and interest		6,152			4,450
Salaries payable		1,710			1,629
Interest on severance		1,008			1,001
Others		733			—
		10,903,005			10,182,006
Less current portion		(586,964	)		(534,750	)
	$	10,316,041		$	9,647,256

(1) Actuarial liability at December 31, 2007:

	Actuarial Calculation
Retirement pensions	$	7,949,074
Health care		1,392,584
Pension bonuses		1,010,417
Education		391,084
Retirement pensions – joint operations		75,919
	$	10,819,078

F-36

Ecopetrol S.A.

Notes to the Consolidated Accounting Statements (Continued)

17. Labor and Pension Plan Obligations (continued)

The actuarial method used at December 31, 2007 is based on the projected future liability for retirement pensions and the health care and education costs, at the actual technical rate of 4.8% and based on the actual personnel information at the same date.

Detail of personnel covered by the actuarial calculation of 2007:

	Headcount
Bonuses reserve – retired personnel	10,194
Bonuses reserve – employees retiring after 2010	2,699
Pensions reserve (active employees and pensioners)	16,222
Health care and education services reserve (active and pensioners)	16,782

The accumulated and amortized percentage for the liabilities used in the actuarial calculation at December 31, 2007 is 100%.

18. Estimated Liabilities and Provisions

	2007			2006
Provision for abandonment, dismantling of facilities and environmental recovery costs (1)	$	1,528,374		$	1,355,989
Provision for legal processes (Note 29)		1,329,118			305,579
Provision for pension obligations (2)		871,146			871,029
Provision Comuneros and other (3)		334,253			668,863
Provision for contingencies		80,679			83,203
Other provisions		24,927			137,745
Technical reserve		9,498			—
FAEP estimated liability		—			22,099
		4,177,995			3,444,507
Less current portion		(1,435,943	)		(605,337	)
	$	2,742,052		$	2,839,170

(1) During 2007, the Company updated the study and analysis of the estimated liability for future abandonment disbursements, environmental restoration and termination of contracts and oilfield operations. The effect of that study was an increase of liability by $173,679, as compared to the liability at December 31, 2006, due mainly to the inclusion of new fields operated by Petrobrás, Perenco and Hupecol,

Below are the movements of the provision for abandonment costs, dismantling of facilities and environmental recovery for the years ended December 31, 2007 and 2006:

	2007			2006
Balance at beginning of year	$	1,355,989		$	958,324
Retirements and uses		(1,296	)		(218,942	)
Additions		94,887			244,916
Changes in estimations, including programming		78,794			371,691
Balance at end of year	$	1,528,374		$	1,355,989

F-37

Ecopetrol S.A.

Notes to the Consolidated Accounting Statements (Continued)

18. Estimated Liabilities and Provisions (continued)

(2) Includes mainly the provision for contingencies established in 2006, equivalent to $869 billions as a result of the effect of the discount exchange rate used in the partial transfer of actuarial obligations, which passed from 4.8% to 4%, as established by Decree 941 of 2002.

(3) The 2007 balance includes a provision related to claims of Comuneros de Santiago de las Atalayas and Pueblo Viejo de Cusiana, originated in Royalties Contracts Nos. 15, 15ª, 16 and 16ª entered into with Ecopetrol. These claims were declared null by the Colombian Council of State. Of this amount, $90,752 corresponds to the initial claimed amounts, $243,501, represents the interest accrued until 2007. The extraordinary right of petition filed by these Comuneros is pending judgment. An escrow account in the amount of $331,900 was set-up to settle this liability. (See Note 4).

19. Other Long Term Liabilities

	2007		2006
Advances received from Ecogas for BOMT obligations (Note 12)	$	1,263,108	$	—
Deferred income tax liability (Note 16)		644,857		610,711
Credit for deferred monetary correction		271,355		328,224
Deferred commissions		415		—
	$	2,179,735	$	938,935

20. Equity

Transformation of the Company

The authorized capital of Ecopetrol is $15,000,000 ($5,500,000 at 2006), divided into 60,000,000,000 (55,000,000 at 2006) of ordinary registered shares, par value of $250 ($100,000 at 2006) each, of which 40,472,512,588 (42,449,825 at 2006) shares have been subscribed, represented by 10.1% in private shareholders and 89.9% in public shareholders.

Subscribed capital and the additional paid-in capital receivable at December 31, 2007 amount to $4,794 and $850,068, respectively, represented in the shares pending payment by the shareholders that financed their acquisition.

Regulatory Decree 727 of March 7, 2007 replaced the use of Decree 2625 of 2000 and authorized the transfer to subscribed and paid-in capital of contributions in kind (hydrocarbons) of the Colombian Nation that were separately recognized until March 9, 2007. By means of Minute No. 012 of March 26, 2007 of the General Shareholders’ Meeting, formalized on April 27, 2007, the balance was reclassified to subscribed and paid-in capital in the name of the shareholder Ministry of Finance.

Legal Reserve

Legal reserve is set up with 10% of net income and it may be used to absorb losses or distributed at the liquidation of the Company. At December 31, 2007, other reserves and retained earnings will be freely available for distribution in accordance with the instructions of the General Shareholders’ Meeting.

Incorporated Institutional Equity

During 2007, the Company adjusted the incorporated institutional equity, in accordance with the PGCP, based on the commerciality of the Nare, Matambo, Garcero, Corocora, Estero and Caracara association contracts, for the Sardinas 6, Remache Norte 3, Abejas 3 and Jaguar T5 and T6 wells, respectively.

F-38

Ecopetrol S.A.

Notes to the Consolidated Accounting Statements (Continued)

20. Equity (continued)

Summary of Valuation Surplus

	2007		2006
Property, plant and equipment:
Plant and equipment	$	3,027,351	$	4,568,628
Buildings		263,157		150,703
Pipelines and networks		192,738		115,871
Other assets		67,592		37,230
Land		11,668		69,641
Computers		4,360		(1,904	)
		3,566,866		4,940,169
Variable yield investment:
Refinería de Cartagena S.A		1,135,766		—
Interconexión Eléctrica S.A.		348,822		278,701
Empresa de Energía de Bogotá S.A. ESP		278,685		193,333
Ocensa		247,828		269,882
Invercolsa S.A.		67,414		52,153
Serviport		2,000		2,513
Ecodisel		1		—
		2,080,516		796,582
	$	5,647,382	$	5,736,751

21. Memorandum Accounts

Under PGCP Ecopetrol is required to maintain records in memorandum accounts of certain transactions and financial information not required to be recognized in the financial statements. PGCP further requires the memorandum account balances be disclosed in the notes to the financial statements. Such accounts are principally used to maintain accounting control of rights, commitments, guarantees and certain differences between the book and tax bases of accounts:

As of December 31, 2007 and 2006 memorandum account balances were as follows:

	2007		2006
Rights:
Exploitation rights in fields (1)	$	21,235,570	$	18,233,490
Costs and expenses (deductible and non-deductible) (2)		10,297,898		10,327,841
Other contingent rights and debtor accounts (3)		3,931,976		10,275,092
Legal processes (4)		481,726		571,622
Execution of investment projects (5)		359,474		129,434
Securities given in custody (6)		86,547		363,700
BOMT´s reimbursement – Ecogás (7)		—		2,573,095
		36,393,191		42,474,274

F-39

Ecopetrol S.A.

Notes to the Consolidated Accounting Statements (Continued)

21. Memorandum Accounts (continued)

		2007		2006
Obligations:
Contractual agreements (8)		6,452,576		1,318,070
Non-taxable income (9)		6,124,282		4,540,550
Accumulated depletion (10)		5,893,626		5,633,813
Non-taxable liabilities (11)		4,486,070		6,321,198
Mandate contracts (12)		1,682,664		—
Administration funds and advances received (13)		971,728		957,958
Legal processes (14)		946,527		2,159,287
Payments of BOMTs (15)		729,588		1,040,742
Agreements to Ocensa (16)		343,075		493,855
Inventory received in custody (17)		78,563		108,254
Securities received in custody and other contingent obligations (18)		70,663		73,233
Other contingent obligations (19)		7,692		7,420
		27,787,054		22,654,380
	$	64,180,245	$	65,128,654

(1) This account represents the control of estimated value of Ecopetrol´s total proved reserves at each year end, valued at the international market prices (less transporting, taxes, lifting costs and exploration and development costs at each year end).

(2) Control of tax costs and expenses reported in the prior year income tax return and other non deductible expenses.

(3) Control of tax balances of investments, inventories, property, plant and equipment, accounts receivable. Additionally, this caption includes the capital commitments on sole risk contracts.

(4) Control of legal processes includes contingencies in favor of Ecopetrol against third parties.

(5) Execution of investment projects correspond to the control of accumulated capital expenditures incurred in the following extended association contracts: Guajira, Tibu and La Cira Infantas

(6) Securities given in custody represent the control account for security titles given in custody to Deceval for their custody, as well as transportation tools in third party custody.

(7) Control of the 2006 net present value of future payments to be received from Ecogas on BOMT contracts, as well as the accumulated amount of payments already received from the same entity.

(8) Contractual agreements include the control of outstanding amount of unperformed contract obligations at year end.

(9) Control of non-taxable income reflected in the prior year income tax return.

(10) Control of differences between the accumulated depletion and amortization computed under the unit-of-production method for book purposes and the straight-line method for tax purposes. The related deferred income tax was provided in the balance sheet.

(11) Control of non-taxable liabilities for 2006 and 2005, respectively.

(12) Control of amount of assets received in custody by Refinería de Cartagena S.A. to comply with the obligations entered into for the operation of the refinery.

(13) Administration funds and advances received under administration agreements.

(14) Control of legal processes represents the control of eventual and remote contingencies against Ecopetrol.

(15) Control of net present value of future disbursements to BOMT contractors.

(16) Control of Ecopetrol´s commitment to provide the necessary funds to Ocensa to repay capital contributions and the preferred dividend to an Ocensa´s shareholder.

F-40

Ecopetrol S.A.

Notes to the Consolidated Accounting Statements (Continued)

21. Memorandum Accounts (continued)

(17) Control of inventory received in custody from third parties to be transported by Ecopetrol.

(18) This account controls the amount of notes received from Cavipetrol securing loans made to Ecopetrol employees.

(19) This account controls the pension obligations related to the following association contracts: Nare, Hobo, Cocorna, Upia, Espinal, Caguan.

22. Revenue

	2007			2006			2005
Local sales :
Medium distillates	$	4,889,373		$	4,867,350		$	3,788,626
Gasoline		3,346,360			3,468,095			3,371,336
Crude oil (1)		3,004,629			29,825			7,286
Other products		898,465			876,328			658,769
Services		821,197			794,564			742,168
Natural gas		660,171			717,879			509,692
L.P.G.		604,752			545,960			473,728
		14,224,947			11,300,001			9,551,605
Diesel and gasoline subsidies (2)		1,778,050			—			—
		16,002,997			11,300,001			9,551,605
Foreign sales:
Crude oil		4,476,137			3,670,080			3,057,929
FAEP		(316,497	)		(774,160	)		(569,405	)
Net crude oil		4,159,640			2,895,920			2,488,524
Fuel oil		1,560,399			2,256,064			1,714,000
Gasoline		269,248			625,027			913,194
Naphtha		244,393			807,437			481,604
Jet fuel		71,378			372,012			326,638
Other products		11,007			133,504			37,338
		6,316,065			7,089,964			5,961,298
Income from premiums, net		13,258			—			—
		6,329,323			7,089,964			5,961,298
	$	22,332,320		$	18,389,965		$	15,512,903

(1) Effective April 2007, Ecopetrol began selling crude oil to Refinería de Cartagena S.A., as a separate entity.

(2) Until 2006, no subsidies were granted by the Nation for the difference between the regulated price and the price at international parity being assumed by refiners and importers as they were not an express part in the price determination resolutions. Accordingly, subsidies were not recognized for accounting or tax purposes. Pursuant Law 1110 of 2006 (Budgets Laws), the Nation granted diesel and gasoline subsidies. In March 2007, the Ministry of Mines and Energy issued Resolution No. 180414 whereby the procedure for the recognition of the current subsidies for gasoline and diesel was established.

F-41

Ecopetrol S.A.

Notes to the Consolidated Accounting Statements (Continued)

23. Cost of Sales

	2007			2006			2005
Variable cost:
Purchases of hydrocarbons from ANH (1)	$	3,912,315		$	3,676,374		$	2,894,612
Purchase of crude oil from business partner		1,513,683			922,825			986,221
Cost of sale of contributions in kind (2)		432,144			2,374,512			1,345,379
Imported products		681,485			888,993			878,002
Amortization and depletion		665,459			517,500			532,583
Absorption of the cost in final inventory balances		(390,416	)		(234,955	)		(170,353	)
Purchase of natural gas and others products		203,697			67,302			43,111
Process materials		93,017			105,256			93,859
Insurance premium costs, net		6,237			—			—
Fixed cost:
Services contracted with associations		1,019,043			718,881			589,779
Depreciation		719,811			758,187			761,157
Transportation services to refineries		699,987			700,447			543,157
Labor cost		531,120			436,632			419,926
Ecopetrol contracted services		502,647			414,188			268,060
Maintenance		441,500			336,071			259,073
Amortization of actuarial liability		161,825			156,454			144,030
Project expense		540,864			642,923			285,003
Amortization of deferred charges, intangibles and insurances		173,883			111,416			99,235
Materials and operations supplies		196,137			159,207			165,626
Taxes		64,228			61,241			45,876
General costs		10,057			7,482			5,495
Reclassification to selling and non-operating expenses		(120,196	)		(64,373	)		(94,289	)
	$	12,058,527		$	12,756,563		$	10,095,542

(1) These are the costs incurred related to the purchase of oil and natural gas volumes from the ANH at prices set forth in the Law 756 of 2002 and Resolution 18-1709 of 2003, which reference international prices. A detail of the average price, provided by the Ministry of Mines, and the production volume, in accordance with each contract, used for its settlement, is as follows:

	2007		2006		2005
Crude oil and natural production (thousands of barrels) production of crude oil and natural gas	$	191,844		192,793		191,917
Purchase of crude oil production liquidation base (thousands of barrels)		31,101		33,451		34,290
Average liquidation price (U.S.$ per barrel)		U$56.48		US$43.20		US$34.28
Average exchange rate		2,073		2,360		2,321
	$	3,641,101	$	3,410,198	$	2,728,612
Purchase of natural gas		271,214		266,176		166,000
	$	3,912,315	$	3,676,374	$	2,894,612

(2) This cost of sales represents the amount determined under the methodology of Decrees 2625 of 2000 an 1760 of 2003 for the crude and gas production contributed to Ecopetrol as capital by the Nation until March 2007.

F-42

Ecopetrol S.A.

Notes to the Consolidated Accounting Statements (Continued)

24. Operating, Administrative and Selling Expenses

Administration:	2007		2006		2005
Labor	$	156,959	$	144,063	$	123,903
Amortization of actuarial calculation		32,494		96,379		90,216
Depreciation and amortization		45,059		39,497		49,553
General expenses		33,623		13,698		10,399
Fees and commissions		16,523		10,866		8,779
Maintenance		11,730		7,598		7,778
Leases		24,255		16,746		28,498
Taxes		87,462		24,172		18,135
		408,105		353,019		337,261
Selling:
Studies and projects		425,355		271,155		109,621
Crude oil pipeline transportation tariff		146,721		66,822		54,710
Tariff and BOMT gas pipelines capacity payment		27,301		42,605		44,907
Gas pipeline transportation tariff		75,474		70,851		83,459
Industry and commerce tax and transportation		132,619		127,418		117,295
Commissions, fees and services		33,332		52,643		34,979
Amortization of actuarial calculation		4,002		3,504		3,729
Labor expenses		11,622		9,553		8,703
Freight		2,026		—		—
Maintenance and other		75,399		—		124,312
		933,851		644,551		581,715
	$	1,341,956	$	997,570	$	918,976

25. Financial Income, Net

	2007		2006		2005
Income:
Exchange gain	$	3,772,753	$	2,675,248	$	399,008
Valuation of investments		808,922		591,539		1,416,110
Interest and monetary correction		161,125		107,197		107,038
Dividends in cash		25,387		36,093		29,525
FAEP earnings		—		162,703		74,393
Income on sale of investments and equity method		—		29,529		6,248
		4,768,187		3,602,309		2,032,322
Expenses:
Exchange loss		4,385,021		2,901,910		369,817
Discount on cash purchases of shares		166,789		—		—
Administration and issue of securities		76,770		—		—
Hedging operations		43,696		—		78,051
Interest, commissions and premiums		1,142		13,052		19,606
Other		1,141		3,911		32,636
		4,674,559		2,918,873		500,110
	$	93,628	$	683,436	$	1,532,212

26. Pension Expenses

Amortization of actuarial calculation	$	496,736	$	278,686	$	258,132
Retirement pensions		458,645		429,760		401,679
Health care services		86,520		73,288		65,962
Education services		48,442		47,457		39,731
	$	1,090,343	$	829,191	$	765,504

F-43

Ecopetrol S.A.

Notes to the Consolidated Accounting Statements (Continued)

27. Inflation Gain

This gain corresponds to net amortization of deferred monetary correction.

28. Other Income (Expenses), Net

		2007			2006		2005
Income:
Recovery of BOMT expenses (Note 12)	$	31,309		$	8,483	$	11,647
Recovery of provisions (1)		555,438			922,986		117,229
Other revenues		60,366			15,038		13,637
Other recoveries		70,133			18,451		71,618
Discovered and undeveloped fields		13,622			—		—
Income on sale of property, plant and equipment		8,724			7,944		29
Recovery of other expenses		39,575			43,093		29,974
Income for services		6,685			6,093		11,851
Prior year income (3)		3,696			25,908		132,964
Liquidation of variable yield investments		—			96,604		—
Indemnities received		1,703			1,099		17,308
		791,251			1,145,699		406,257
Expenses:
Taxes	$	328,871		$	138,421	$	119,240
Provisions (2)		1,240,400			441,633		1,015,047
Loss on sale and retirement of assets		3,148			1,440		3,024
Fuel loss		56,648			56,336		94,587
Other expenses		21,317			4,982		24,018
Inspection quota		25,934			22,265		20,263
Surveillance and guards		14,457			8,004		42,652
Contributions and donations		9,535			28,422		44,388
Prior year expenses (4)		1,891			99,297		78,762
		1,702,201			800,800		1,441,981
	$	(910,950	)	$	344,899	$	(1,035,724	)

(1) A detail of the recovery of provisions follows:

Taxes	$	117,680	$	772,184	$	972
BOMT provisions		221,055		—		—
Projects’ expenses		120,082		—		—
Other recoveries		34,229		102,272		51,293
Legal processes		46,934		3,026		62,012
Accounts receivable		15,458		45,504		2,952
	$	555,438	$	922,986	$	117,229

(2) A detail of provision expenses is as follows:

Partial transfer of pension obligations	$	—	$	151,848	$	726,488
Legal processes		1,096,117		119,998		131,263
Receivables		20,276		40,591		2,229
Ecogas’ BOMTs		—		35,317		37,018
Investments		6,273		18,075		27,753
Inventories		115,944		14,745		9,576
Other		1,790		61,059		80,720
	$	1,240,400	$	441,633	$	1,015,047

F-44

Ecopetrol S.A.

Notes to the Consolidated Accounting Statements (Continued)

28. Other Income (Expenses), Net (continued)

(3) A detail of other prior years’ income is as follows:

Expense recovery	$	1,933	$	24,437	$	6,615
Sale of property, plant and equipment		—		1,471		—
Health services		1,763		—		—
Recovery of provisions		—		—		65,648
Amortization of oil field investments		—		—		60,701
	$	3,696	$	25,908	$	132,964

(4) A detail of other prior years’ expenses is as follows:

Amortization and depletion	$	—	$	93,629	$	—
General expenses		1,891		5,668		35,130
Unsuccessful oilfield investments		—		—		43,632
	$	1,891	$	99,297	$	78,762

29. Contingencies

Ecopetrol has recognized provisions corresponding to reasonable estimates intended to cover future situations deriving from loss contingencies or the occurrence of future events that could affect the public equity. Prior to September 5, 2007, under PGCP, a provision was recorded for a contingent event at the time a judgment was issued against the Company, without reference to the evaluation of the outcome. On September 5, 2007, the CGN issued Resolution 356 which provided that a provision was to be recorded for a contingent event if the evaluation of the outcome was evaluated to be probable. As a result, the provision for legal processes included in Estimated Liabilities and Provisions was increased by $951,158 during 2007 to reflect the implementation of the new rule.

A summary of the most significant estimates (claim amount in excess of $40 billions) for which provisions have been recognized, in accordance with the evaluations of the Company’s internal and external legal advisors at December 31, 2007:

Process	Action	Amount of Claims
Gobernación del Tolima/ Municipio de Melgar	Popular action for the re-liquidation of royalties with the 20% stipulated in Law 141 of 1994.	$162,989
Universidad de Cartagena Junta Especial de la Estampilla	Compliance action for the payment of the stamp on exports made by Ecopetrol between 1997 and 2004.	100,738
Latinamerican Hydrocarbon Corporation S.A.	Ordinary Administrative Process to obtain the declaration that the condensate supply contract clauses were not complied with by Ecopetrol.	162,052
Junta de Acción Comunal El Llanito y Asoc. de Pescadores del Llanito	Constitutional action to declare the responsibility of Ecopetrol in the environmental damage in Ciénaga de San Silvestre	115,000
Freddy Antonio Otálvaro Gómez and Others	Constitutional action to declare the responsibility of Ecopetrol in the ecological and environmental impairment in the mangrove swamps and asturiana of Bahía de Tumaco due to crude oil spills.	78,790
Asociación Municipal de Pescadores Artesanales de Tumaco –and Others	Ordinary Civil Process for the payment of consequential damage and loss of profit, caused by the spill in the loading operation of the Daedalus ship.	65,147

F-45

Ecopetrol S.A.

Notes to the Consolidated Accounting Statements (Continued)

29. Contingencies (continued)

Process	Action	Amount of Claims
Foncoeco	Ordinary civil process for the payment of capital and financial yields authorized by the Board of Directors to set-up the profit participation fund of the Company’s employees. In the opinion of Management and its legal counsel, there are sufficient arguments to demonstrate that the Board of Directors never appropriated the resources to set-up any fund. Furthermore, Foncoeco is not the holder of that amount and, accordingly, no accounts should be given to the employees, and the lawsuit claims are not valid.	64,000
Cocodril Oil Ltda..	Ordinary Administrative Process to declare non-compliance by Ecopetrol and the Ministry of Mines and Energy.	40,000
Consorcio Riogrande S.A.	Ordinary Administrative Process for the payment of damages arising from non-compliance with the execution of Contract DIJ-818	42,000
Álvaro Rueda Urquijo	Constitutional Action for the payment of the deduction made for exports in the ICA returns of 2004, filed in the Municipality of Barrancabermeja, which applicability is not provided or demonstrated.	44,000

30. Commitments

Natural Gas Supply Contracts

The Company has entered into contracts with third parties, for the supply of natural gas in developing its commercialization, whereby it commits to deliver the minimum quantities established in each contract as follows.

		Minimum Quantity
Company Name	Contract Terms	CDGF (MBTU) *	CDMIN*
Gecelca	March 30, 2005 - October 31, 2009	175,000	70% CDGF
Gas Natural S.A. ESP	December 30 , 2005 - December 31, 2008	7,200	60% CDGF
	April 28, 2004 - December 31, 2011	54,000	26,000 MBTU
Empresas Públicas de Medellín	May 19, 1996 - December 1, 2012	55,000	25% CDGF
	December 29, 2005 - December 31, 2008	6,600	75% CDGF
Termoflores	December 04, 1997 - January 1, 2013	21,420	70% CDGF
	December 04, 1997 - January 10, 2013	30,600	70% CDGF

* CDGF: Minimal quantity of gas that the seller is obliged to surrender

* CDMIN: Minimal quantity of gas that the buyer is obliged to accept

* MBTU: Million British Thermal Units

During 2007, Ecopetrol commercialized 160.847 GBTUD for $660,171.

F-46

Ecopetrol S.A.

Notes to the Consolidated Accounting Statements (Continued)

30. Commitments (continued)

TLU 1 and TLU 3 Master Agreement

In March 1998 and September 1999, the Company entered into agreements: TLU-1 – joint operation of the assets at the Coveñas terminal for the receipt, storage and loading of tankers with crude oil between the Cravo Norte Association and Oleoducto de Colombia S.A.; and TLU-3 – joint operation for the use of the loading unit of vessel tanks TLU-3 at the Coveñas terminal between the Cravo Norte Association, Oleoducto de Colombia S.A. and Oleoducto Central S.A., respectively, agreements where the parties designated Ecopetrol as the Operator.

Cartagena Refinery

The commitment to deliver assets and working capital to Refinería de Cartagena S.A., where Ecopetrol owns 49%, was entered into initially for December 31, 2006. Due to logistical reasons, the Company’s management and the partner re-scheduled the compliance with such commitment, which it assumed on March 31, 2007. The Company offered the sale and delivery of a maximum volume of 85 thousand barrels per day corresponding to the sum of crude oils: Caño Limón, Mezcla Coveñas South Blend, in accordance with certain quality parameters agreed to between the parties. The contract term is one year and can be renewed on an annual basis.

Propilco

In December 2007, the Company signed an agreement to acquire Propilco, the petrochemical company, which is the principal manufacturer of resins in the Andean region, Central America and the Caribbean, subject to the approval of business integration by the Superintendency of Industry and Commerce, the receipt of which receipt is expected for 2008.

Petro Rubiales S.A.

In December 2007, the Company signed a memorandum of understanding with Petro Rubiales S.A. for the construction of a 230 kilometer pipeline, which will permit transporting the crude oil extracted from the Rubiales and Pirirí fields in the Department of Meta, to be connected with the Ocensa pipeline. Ecopetrol´s participation is 65% with its start-up operation expected to begin during 2009. The estimated cost of the project is US$ 300 million.

31. Reclassifications

Certain prior figures in the statements of financial, economic and social activities of 2006 were reclassified for comparative purposes with those of 2007, as a result of the establishment of new parameters of accounts in the accounting application because of the operating reorganization of certain areas, such as those related with resources given for administration purposes, the pension liability, operating expenses, the cost of sales, mainly, and the adjustment of the official accounting plan of CGN for governmental companies.

32. Subsequent Events

Extensions of Contracts

The extension of the Estero, Garcero, Orocue, and Corocora association contracts located in the Department of Casanare, which include 21 commercial fields were signed during January 2008. The Company has the following participation therein: 89%, 76%, 63%, 56%, respectively.

F-47

Ecopetrol S.A.

Notes to the Consolidated Accounting Statements (Continued)

32. Subsequent Events (continued)

Propilco

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

Discoveries in Tempranillo-1

In April, 2008, Ecopetrol discovered a crude oil and natural gas reserves at the Basin “Valle Superior del Magdalena”, in Huila Department, regards to the Tempranillo-1 well. Crude oil is light (37 degrees API) and runs at rates within 1,600 and 2,400 barrels per day. Natural gas productions were between within 2.0 y 2.75 million cubic feet per day.

Dry Holes

The following are holes declared dry during 2008:

• Clear Water-1: Declared dry hole in February 17, 2008 with an approximately cost incurred in 2008 of US$50,000,000 Ecopetrol share.

• Hadas-1: Declared dry hole in April 13, 2008. Ecopetrol S.A. operates the field but the approximately expense of US$8,200,000 were assumed by Shell according to contractual obligation.

33. Differences between Colombian Governmental Entity accounting principles and U.S. GAAP

The Company’s financial statements are prepared in accordance with Colombian Governmental Entity GAAP or PGCP. These principles and regulations differ in certain significant respects from accounting principles generally accepted in the United States of America (U.S. GAAP), and therefore this note presents reconciliations of net income and shareholders’ equity determined under PGCP to those same amounts as determined according to U.S. GAAP. Also presented in this note are those disclosures required under U.S. GAAP but not required under PGCP.

F-48

Ecopetrol S.A.

Notes to the Consolidated Accounting Statements (Continued)

A) Reconciliation of net income:

The following table presents the reconciliation of net income per PGCP to net income under U.S. GAAP for the years ended December 31, 2007 and 2006:

			2007			2006
	Consolidated net income under PGCP		$	5,179,792		$	3,391,373
i.	Investment securities
	a.	Unrealized gain		69,657			11,080
	b.	Impairment		(78,123	)		(60,742	)
ii.	Investments in non-marketable securities:
	a.	Equity method		(36,960	)		(43,241	)
	b.	Variable Interest Entity (VIE)		11,658			(3,972	)
iii.	Investments in unconsolidated subsidiaries			—			(136,372	)
iv.	Derivatives			6			157
v.	Exchange of non-monetary assets			606,751			—
vi.	Deferred charges			240,293			(30,624	)
vii.	Employee benefit plans			(1,045,374	)		325,316
viii.	Provisions – allowances and contingencies			925,380			88,671
ix.	Deferred income taxes			(624,185	)		(362,271	)
x.	Revenue recognition
	a.	Revenue - FAEP		329,355			916,941
	b.	Cost of sales – Over and Under		16,607			(152,375	)
	c.	Other income – exchange losses - FAEP		(97,127	)		(117,880	)
xi.	Inflation adjustment			230,822			144,248
xii.	Inventories			(67,089	)		(9,731	)
xiii.	Lease accounting			(393,131	)		(1,030	)
xiv.	Prior year adjustments			574			73,857
xv.	Property, plant and equipment:
	a.    Interest			1,228			1,635
	b.    Impairment			(65,137	)		(12,241	)
xvi.	Property, plant and equipment – DD&A			227,754			237,972
xvii.	Asset retirement obligations			10,039			(22,777	)
xviii.	Equity contributions:
	a.	Incorporated equity		9,304			351
	b.	Contributions in kind		432,144			2,374,512
	c.	Reversion of concession rights contributed as capital		17,562			23,567
xix.	Public offering cost and discount on issuance of shares			242,885			—
	Consolidated net income under U.S. GAAP		$	6,144,685		$	6,636,424

F-49

Ecopetrol S.A. and Subsidiaries

Notes to the Consolidated Financial Statements (continued)

33. Differences between Colombian Governmental Entity accounting principles and U.S. GAAP (Continued)

B) Reconciliation of Shareholders’ equity:

The following table presents a reconciliation of shareholders’ equity under PGCP to shareholders’ equity under U.S. GAAP as of December 31, 2007 and 2006:

			2007			2006
	Consolidated shareholders’ equity under PGCP		$	26,808,467		$	20,835,746
i.	Investment securities
	a.	Unrealized gain		(889	)		(11,705	)
	b.	Impairment		—			—
ii.	Investments in non-marketable securities:
	a.	Equity method		42,726			138,489
	b.	Variable Interest Entity (VIE)		47,143			43,609
	c.	Valuation surplus		(2,080,516	)		(796,582	)
iii.	Investment in unconsolidated subsidiaries			—			—
iv.	Derivatives			—			(6	)
v.	Exchange of non-monetary assets			606,751			—
vi.	Deferred charges			(6,905	)		(247,198	)
vii.	Employee benefit plans			(719,267	)		(759,585	)
viii.	Provisions – allowance and contingencies			1,637,881			712,501
ix.	Deferred income taxes			(623,847	)		364,980
x.	Revenue recognition:
	a.	Revenue - FAEP		97,127			3,962,047
	b.	Cost of sales – Over and Under		19,871			(9,594	)
	c.	Other income – exchange losses - FAEP		(97,127	)		(117,880	)
xi.	Inflation adjustment			(992,333	)		(1,223,155	)
xii.	Inventories			(76,844	)		(9,755	)
xiii.	Lease accounting			404,373			722,957
xiv.	Prior year adjustments			—			(575	)
xv.	Property, plant and equipment:
	a.	Interest		39,768			38,540
	b.	Valuation surplus		(3,566,866	)		(4,940,169	)
	c.	Impairment		(176,023	)		(110,886	)
	d.	Capitalized expenses		(631,851	)		(631,851	)
	e.	Exchange difference		(217,535	)		(217,535	)
xvi.	Property, plant and equipment – DD&A			658,667			430,913
xvii.	Asset retirement obligations			45,960			35,921
xviii.	Equity contributions:
	a.	Incorporated equity		(82,124	)		(30,703	)
	b.	Contributions in kind		—			—
	c.	Reversion of concession rights contributed as capital		(145,576	)		(163,138	)
xix.	Public offering cost and discount on issuance of shares			—			—
	Consolidated shareholders’ equity under US GAAP		$	20,991,031		$	18,015,386

F-50

Ecopetrol S.A. and Subsidiaries

Notes to the Consolidated Financial Statements (continued)

33. Differences between Colombian Governmental Entity accounting principles and U.S. GAAP (Continued)

C) Supplemental consolidated condensed financial statements under U.S.GAAP

C) 1. Supplemental consolidated condensed balance sheets

The condensed balance sheets of the Company as of December 31, 2007 and 2006 under U.S. GAAP are presented below:

	2007		2006
Assets
Current assets:
Cash and cash equivalents	$	8,007,282	$	2,338,663
Investments		1,820,270		2,203,890
Accounts and notes receivable, net		2,310,864		1,568,207
Inventories		1,246,538		1,009,506
Advances and deposits		689,826		274,185
Prepaid expenses		15,077		10,330
Deferred income taxes		332,057		214,797
Direct finance lease		—		30,096
Total current assets		14,421,914		7,649,674
Investments		3,929,943		1,511,860
Accounts and notes receivable, net		202,565		1,273,488
Advances and deposits		—		302,600
Property, plant and equipment, net		4,989,533		4,941,153
Natural and environmental properties, net		3,966,780		2,950,993
Petroleum Stabilization Savings Fund FAEP		—		3,844,167
Deferred charges and other assets		495,740		466,766
Deferred income taxes		1,692,053		2,209,873
Direct finance lease long-term		—		1,366,908
Total Assets	$	29,698,528	$	26,517,482
Liabilities and equity
Current liabilities:
Financial obligations	$	72,491	$	260,767
Accounts payable and related parties		1,361,720		1,203,555
Capital lease liability		88,101		179,264
Taxes payable		1,777,132		1,267,522
Labor and pension plan obligations		78,674		56,515
Estimated liabilities and provisions		669,864		704,699
Unearned income		156,364		28,212
Total current liabilities		4,204,346		3,700,534
Financial obligations, long-term		—		86,769
Accounts payable, long-term		123,930		426,691
Capital lease liability		434,928		494,604
Pension plan obligation and other labor obligations, long-term		2,048,447		1,924,677
Deferred income, long-term		—		37,859
Estimated liabilities and provisions		1,323,834		1,265,843
Other long-term liabilities		415		—
Total non-current liabilities		3,931,554		4,236,443
Total liabilities		8,135,900		7,936,977
Minority interest		571,597		565,119
Equity		20,991,031		18,015,386
Total liabilities and equity	$	29,698,528	$	26,517,482

F-51

Ecopetrol S.A. and Subsidiaries

Notes to the Consolidated Financial Statements (continued)

33. Differences between Colombian Governmental Entity accounting principles and U.S. GAAP (Continued)

C) 2. Supplemental consolidated condensed statements of income

In accordance with the Financial Accounting Standards Board (FASB) Interpretation No. 46(R), Consolidation of Variable Interest Entities (FIN 46R), the Company also consolidated Oleoducto Central S.A., a Variable Interest Entity (VIE) in which it is the primary beneficiary. All significant intercompany balances and transactions have been eliminated in consolidation. See Note 33 ii – Variable Interest Entity (VIE), for additional information.

The condensed statements of income of the Company for the years ended December 31, 2007 and 2006 under U.S. GAAP are presented below:

	2007			2006
Revenue:
Local sales	$	16,138,874		$	11,597,615
Foreign sales		6,645,820			7,864,124
Total Revenue		22,784,694			19,461,739
Cost of sales		10,942,526			10,296,434
		11,842,168			9,165,305
Operating expenses:
Administration		2,431,443			1,297,301
Selling		955,626			622,028
Operating income		8,455,099			7,245,976
Financial income, net		255,549			519,887
Income before income tax and minority interest		8,710,648			7,765,863
Income tax
Current income tax		2,045,997			1,535,088
Deferred tax expense – (benefit)		498,593			(398,366	)
		2,544,590			1,136,722
Income before minority interest		6,166,058			6,629,141
Minority interest		(21,373	)		7,283
Net Income	$	6,144,685		$	6,636,424
Earnings per equivalent share	$	166.42		$	182.40

F-52

Ecopetrol S.A. and Subsidiaries

Notes to the Consolidated Financial Statements (continued)

33. Differences between Colombian Governmental Entity accounting principles and U.S. GAAP (Continued)

C) 3. Supplemental consolidated condensed statements of cash flows

The condensed statements of cash flows of the Company for the years ended December 31, 2007 and 2006 under U.S. GAAP are presented below:

	2007			2006
Cash flows provided by operating activities:
Net income	$	6,144,685		$	6,636,424
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		1,467,372			1,386,459
Equity method		36,960			43,241
Impairment		65,137			12,072
Provisions for inventory losses and other		86,746			1,131
Deferred income taxes		498,593			(398,366	)
Net exchange loss on monetary operating assets and liabilities		524,739			226,957
Minority interest		21,373			(7,283	)
Write-off of property, plant and equipment		—			21,064
Loss on liquidation of investments in unconsolidated subsidiaries		—			8,162
Net changes in operating assets and liabilities:
Accounts and notes receivable		1,534,251			167,200
Inventories		(316,950	)		(229,382	)
Other assets		(33,721	)		(18,305	)
Accounts payable and related parties		(171,444	)		242,482
Taxes payable		509,612			(508,827	)
Labor obligations		1,231,621			(70,126	)
Estimated liabilities and others		130,729			(269,421	)
Cash provided by operating activities		11,729,703			7,243,482
Cash flows from investing activities:
Purchase of investment securities		(33,328,213	)		(32,577,124	)
Redemption of investment securities		34,664,457			31,078,640
Investment in natural and environmental properties		(1,866,544	)		(801,470	)
Additions to property, plant and equipment		(1,176,142	)		(883,008	)
Proceeds from the liquidation of investments in unconsolidated subsidiaries		—			128,210
Net cash used in investing activities		(1,706,442	)		(3,054,752	)
Cash flows from financing activities:
Minority interest		(14,893	)		(19,248	)
Payment of financial obligations		(425,879	)		(604,550	)
Proceeds from issuance of shares		4,625,066			—
Disbursements of contributions to ANH		—			(106,672	)
Dividends paid		(8,538,936	)		(2,000,000	)
Proceeds from financial obligations		—			81,163
Net cash used in financing activities		(4,354,642	)		(2,649,307	)
Net increase in cash and cash equivalents		5,668,619			1,539,423
Cash and cash equivalents at beginning of year		2,338,663			799,240
Cash and cash equivalents at end of year	$	8,007,282		$	2,338,663

U.S. GAAP requires the presentation of a reconciliation of net income to net cash provided by operating activities.

F-53

Ecopetrol S.A. and Subsidiaries

Notes to the Consolidated Financial Statements (continued)

33. Differences between Colombian Governmental Entity accounting principles and U.S. GAAP (Continued)

C) Reconciliation of net income to net cash provided by operating activities

This reconciliation, prepared under PGCP, for the years ended December 31, 2007 and 2006, is presented below:

	2007			2006
Net income	$	5,179,792		$	3,391,373
Adjustments to reconcile net income to cash provided by operating activities:
Amortization and depletion		1,589,416			1,402,526
Amortization of actuarial calculation		695,057			535,022
Deferred income tax		(189,265	)		(760,638	)
Valuation of investments		(808,922	)		(591,539	)
Contribution in kind		432,144			2,374,512
Exchange loss		612,268			226,662
Discount on cash purchases of shares		166,789			—
Inflation gain		(41,132	)		(56,166	)
Inventory losses		56,648			56,336
Changes in operating assets and liabilities, net of acquisition:
Accounts and notes receivable		(987,247	)		(376,509	)
Inventories		(302,431	)		(236,697	)
Advances and deposits		(325,264	)		(314,839	)
Other assets		980,492			(97,268	)
Accounts payable		334,558			60,390
Taxes payable		855,264			302,637
Labor obligations		52,214			45,128
Estimated liabilities and provisions		1,536,573			392,760
Cash provided by operating activities	$	9,836,954		$	6,353,690

F-54

Ecopetrol S.A. and Subsidiaries

Notes to the Consolidated Financial Statements (continued)

33. Differences between Colombian Governmental Entity accounting principles and U.S. GAAP (Continued)

During 2007, the Company exchanged property, plant and equipment for a share in Refinería de Cartagena S.A. The Company exchanged assets with a cost of approximately $234,371 for an investment in Refinería de Cartagena S.A at $1,369,546, which represented the fair value of the 49% interest the Company received. This non-cash transaction had the effect of reducing property, plant and equipment by $234,371, increasing investments. For U.S. GAAP purposes, a partial gain equivalent to 51% was recognized as explained in v Exchange of non – monetary assets.

During 2007 and 2006, the Company capitalized property, plant and equipment and investment in natural and environmental properties amounting to $83,088 and $340,457, respectively, which corresponds to asset retirement costs which are reflected as asset retirement obligation for U.S. GAAP purposes.

In 2007, the Company signed leasing contracts that increased property, plant and equipment and capital lease obligations by $1,632 under U.S. GAAP. See note 33. xiii.

Under PGCP, some deposits with banks were considered as short – term investments because they produce yields and the Company has defined them to be used for specific purposes. Under US GAAP, these deposits are considered cash. The amounts reclassified as of December 31, 2007 and 2006 were $4,133,705 and $617,240. These deposits are valued at fair value.

C) 4. Supplemental consolidated statement of comprehensive income

The statements of Comprehensive Income of the Company as of December 31, 2007 and 2006 under U.S. GAAP are as follows:

	2007			2006
U.S. GAAP consolidated net income	$	6,144,685		$	6,636,424
Other comprehensive income (loss), net of tax:
Pension liability		(982,048	)		(1,709,463	)
Unrealized losses on securities		49,699			36,781
Cumulative translation adjustment		(66,983	)		(56	)
Comprehensive income	$	5,145,353		$	4,963,686

The statements of Other Comprehensive Income during the years ended December 31, 2007 and 2006 are presented below:

	Pension Liability			Unrealized Losses on Securities		Cumulative Translation Adjustment			Accumulated Other Comprehensive Income
Balance at December 31, 2005	$	(902,518	)	$	10,334	$	—		$	(892,184	)
Net unrealized change in:
Investment securities, net of tax effect of $11,646		—			26,447		—			26,447
Actuarial loss, net of tax effect of $356,002		(806,945	)		—		—			(806,945	)
Translation adjustment		—			—		(56	)		(56	)
Balance at December 31, 2006	$	(1,709,463	)	$	36,781	$	(56	)	$	(1,672,738	)
Net unrealized change in:
Investment securities, net of tax effect of $6,364		—			12,918		—			12,918
Amortization of actuarial loss, net of tax effect of $358,277		727,415			—		—			727,415
Translation adjustment		—			—		(66,927	)		(66,927	)
Balance at December 31, 2007	$	(982,048	)	$	49,699	$	(66,983	)	$	(999,332	)

F-55

Ecopetrol S.A. and Subsidiaries

Notes to the Consolidated Financial Statements (continued)

33. Differences between Colombian Governmental Entity accounting principles and U.S. GAAP (Continued)

C) 4. Supplemental consolidated statement of comprehensive income (Continued)

A detail of Other Comprehensive Income, including the related income tax effects, is presented below:

	2007
	Before-Income Tax Amount			(Income Tax Expense) Or Benefit			Net Of Income Tax Amount
Unrealized loss on securities available for sale	$	74,179		$	(24,480	)	$	49,699
Pension liability - net unamortized actuarial loss		(1,465,744	)		483,696			(982,048	)
Cumulative translation adjustment		(66,983	)		—			(66,983	)
Other comprehensive income (loss)	$	(1,458,548	)	$	459,216		$	(999,332	)

	2006
Unrealized gain (loss) on securities available for sale	$	54,897		$	(18,116	)	$	36,781
Pension liability - net unamortized actuarial loss		(2,551,436	)		841,973			(1,709,463	)
Cumulative translation adjustment		(56	)		—			(56	)
Other comprehensive income (loss)	$	(2,496,595	)	$	823,857		$	(1,672,738	)

D) Summary of significant differences and required U.S. GAAP disclosures

i. INVESTMENT SECURITIES

The Company’s investments include both marketable securities and non-marketable securities. Under PGCP, the Company classifies investment securities based on the form of their investment return, either as fixed-yield investment or as variable-yield investments. Fixed-yield investments generally represent debt securities and are initially recorded at cost with subsequent adjustments to fair market value recorded in the income statement. Variable-yield investments generally represent equity securities or interests in other entities and are initially recorded at cost. Subsequent adjustments to fair value are made with increases in fair value resulting in an increase to equity, while decreases in fair value are charged to the income statement. Fair values are determined using quoted market prices, if and when available. Absent quoted market prices, these investments are recorded at Management’s estimate of fair value using discounted cash flow techniques.

Under U.S. GAAP, the Company has classified its investment securities as held to maturity or available for sale, as defined by Statement of Financial Accounting Standard No. 115, Accounting for Certain Investments in Debt and Equity Securities (“SFAS No. 115”). Debt security investments for which the Company has demonstrated its positive ability and intent to hold until maturity are classified as held-to-maturity. Such investments are reported at amortized cost. Investments classified as available-for-sale are reported at fair value, with unrealized gains and losses reported, net of taxes, as a component of other comprehensive income.

In the event an other than temporary impairment of the values of the investments occurs, the impairment loss is recorded in income.

F-56

Ecopetrol S.A. and Subsidiaries

Notes to the Consolidated Financial Statements (continued)

33. Differences between Colombian Governmental Entity accounting principles and U.S. GAAP (Continued)

The Company’s short-term and long-term investments at December 31, 2007 and 2006 consist of the following:

	Aggregated Fair Value		Gross Unrealized Holding Gains		Gross Unrealized Holding Losses			Gross Recognized Losses			Cost Basis
As of December 31, 2007 (in millions of Colombian pesos)
Short-term Investments - Available for Sale Securities:
Securities issued or secured by Colombian government	$	60,382	$	2,084	$	(1,380	)	$	—		$	59,678
Securities issued or secured by government entities		1,226,125		16,436		(11,757	)		(76,343	)		1,297,789
Securities issued or secured by financial entities		397,306		8,080		(3,642	)		(15,968	)		408,836
Other debt securities		136,457		4,255		(496	)		(8,462	)		141,160
Total Short-term Investments Classified as Available for Sale	$	1,820,270	$	30,855	$	(17,275	)		(100,773	)	$	1,907,463
Long-term Investments - Available for Sale Securities:
Securities issued or secured by Colombian government	$	63,165	$	1,251	$	(187	)	$	—		$	62,101
Securities issued or secured by government entities		2,287,235		71,024		(27,247	)		(104,033	)		2,347,491
Securities issued or secured by financial entities		249,275		11,019		(1,165	)		(1,179	)		240,600
Other debt securities		113,553		7,751		(1,847	)		(2,002	)		109,651
Total Long-term Investments Classified as Available for Sale	$	2,713,228	$	91,045	$	(30,446	)	$	(107,214	)	$	2,759,843
Total Available for Sale	$	4,533,498	$	121,900	$	(47,721	)	$	(207,987	)	$	4,667,306

	Aggregated Fair Value		Gross Unrecognized Holding Gains		Gross Unrecognized Holding Losses			Net Carrying Amount
Long-term Investments- Held to Maturity Securities
Securities issued or secured by government entities	$	82,210	$	2,766	$	—		$	79,444
Other debt securities		59,014		2,737		(102	)		56,379
Total Long-term Investments Classified as Held to Maturity	$	141,224	$	5,503	$	(102	)	$	135,823

F-57

Ecopetrol S.A. and Subsidiaries

Notes to the Consolidated Financial Statements (continued)

33. Differences between Colombian Governmental Entity accounting principles and U.S. GAAP (Continued)

	Aggregated Fair Value		Gross Unrealized Holding Gains		Gross Unrealized Holding Losses			Gross Recognized Losses			Cost Basis
As of December 31, 2006 (in millions of Colombian pesos)
Short-term Investments - Available for Sale Securities:
Securities issued or secured by Colombian government	$	286,062	$	1,463	$	(4,975	)	$	(4,286	)	$	293,860
Securities issued or secured by government entities		473,172		7,495		(5	)		(17,690	)		483,372
Securities issued or secured by financial entities		1,061,510		12,290		(353	)		(49,056	)		1,098,629
Other debt securities		383,146		6,215		(321	)		(16,104	)		393,356
Total Short-term Investments Classified as Available for Sale	$	2,203,890	$	27,463	$	(5,654	)	$	(87,136	)	$	2,269,217
Long-term Investments - Available for Sale Securities:
Securities issued or secured by Colombian government	$	312,137	$	25,624	$	(1,995	)	$	(7,848	)	$	296,356
Securities issued or secured by government entities		610,841		9,355		(37	)		(33,450	)		634,973
Securities issued or secured by financial entities		40,954		321		(22	)		(1,283	)		41,938
Other debt securities		4,350		72		(230	)		(149	)		4,657
Total Long-term Investments Classified as Available for Sale	$	968,282	$	35,372	$	(2,284	)	$	(42,730	)	$	977,924
Total Available for Sale	$	3,172,172	$	62,835	$	(7,938	)	$	(129,866	)	$	3,247,141

	Fair Aggregated Value		Gross Unrecognized Holding Gains		Gross Unrecognized Holding Losses			Net Carrying Amount
Long-term Investments- Held to Maturity Securities
Securities issued or secured by Colombian government	$	51,987	$	1,220	$	—		$	50,767
Other debt securities		87,284		5,275		(12	)		82,021
Total Long-term Investments Classified as Held to Maturity	$	139,271	$	6,495	$	(12	)	$	132,788

F-58

Ecopetrol S.A. and Subsidiaries

Notes to the Consolidated Financial Statements (continued)

33. Differences between Colombian Governmental Entity accounting principles and U.S. GAAP (Continued)

The maturities of fixed-income investments at December 31, 2007 and 2006 are as follows (in millions of Colombian pesos):

As of December 31, 2007
	Available for Sale				Held to Maturity
	Cost Basis		Fair Value		Cost Basis		Fair Value
Due in one year or less	$	1,907,463	$	1,820,270	$	—	$	—
Due in one year to five years		2,534,878		2,501,469		66,522		69,636
Due in five years to ten years		224,965		211,759		69,301		71,588
Total	$	4,667,306	$	4,533,498	$	135,823	$	141,224
As of December 31, 2006
Due in one year or less	$	2,269,217	$	2,203,890	$	—	$	—
Due in one year to five years		909,550		901,272		93,246		98,508
Due in five years to ten years		68,374		67,010		39,542		40,763
Total	$	3,247,141	$	3,172,172	$	132,788	$	139,271

Proceeds from the sale of investment securities, gains and losses resulting from such sales are as follow:

	2007		2006
Proceeds from sales	$	805,550	$	184,954
Gains		747		358
Losses		933		429

There were no sales of held to maturity investments.

Realized gains and losses on securities available for sale at December 31, 2006 and 2005 in 2007 and 2006 were:

	2007		2006
Losses	$	27,730	$	99
Gains		5,219		5,563

Foreign Exchange Gains and Losses on Securities Available for Sale

Under PGCP, changes in account balances resulting from changes in foreign currency exchange rates are reflected in a company’s net income. Under U.S. GAAP, any change in value of available-for-sale debt securities as a result of changes in foreign currency exchange rates is reflected in equity as required under the guidance in Emerging Issues Task Force 96-15, Accounting for the Effects of Changes in Foreign Currency Exchange Rates on Foreign-Currency-Denominated Available-for-Sale Debt Securities (“EITF 96-15”). The amount reclassified from earnings under PGCP purposes to other comprehensive income for U.S. GAAP purposes includes $37,817 and $(11,590) in 2007 and 2006, respectively that correspond to exchange rate differences.

F - 59

Ecopetrol S.A. and Subsidiaries

Notes to the Consolidated Financial Statements (continued)

33. Differences between Colombian Governmental Entity accounting principles and U.S. GAAP (Continued)

Unrealized losses disclosure

Available-for-sale securities in an unrealized loss position as of December 31, 2007 and 2006 are as follows (in millions of Colombian pesos):

	Less than 12 months					More than 12 months
	Gross Unrealized Loss			Market Value		Gross Unrealized Loss			Market Value
2007	$	(36,424	)	$	883,748	$	(11,294	)	$	187,604
2006		(3,104	)		50,244		(4,830	)		472,838

Impairment

Impairment of security investments is reported differently under PGCP and U.S. GAAP. Under PGCP, impairment is also charged to earnings in the current period, but recoveries in value can be recorded up to the amount that was originally impaired. Under U.S. GAAP, other-than-temporary impairment should be charged to earnings in the current period and a new cost basis for the security is established. Subsequent increases in the cost basis of an impaired investment as a result of a recovery in fair value is prohibited.

The Company has a policy under which they conduct periodic reviews of marketable securities to assess whether other-than-temporary impairment exists. A number of factors are considered in performing an impairment analysis of securities. Those factors include:

a) the length of time and the extent to which the market value of the security has been less than cost;

b) the financial condition and near-term prospects of the issuer, including any specific events which influence the operations of the issuer (such as changes in technology that may impair the earnings potential of the investment, or the discontinuance of a segment of a business that may affect the future earnings potential); and

c) the intent and ability of the Company to retain its investment in the issuer for a period of time that allows for any anticipated recovery in market value.

The Company also takes into account changes in global and regional economic conditions and changes related to specific issuers or industries that could adversely affect these values.

Ecopetrol’s marketable security portfolio consists only of debt securities, such as treasuries, bonds, and commercial paper. For this reason, the Company has an internal policy to limit the ratings of their investments and issuers to the following ratings:

Credit Rating Agency	Short-term Credit Rating	Long-Term Credit Rating
Standard & Poor’s	A-1	A
Moody’s Investors Services	P-1	A2
Fitch Ratings	F-1	A

If the credit rating of an issuer or an investment drops below the aforementioned limits, the Company must sell the investment within 10 days. Investment securities were assessed for other than temporary impairment. For U.S. GAAP purposes, the Company recognized impairment on its investment securities amounting to $78,123 and $60,742 in 2007 and

F - 60

Ecopetrol S.A. and Subsidiaries

Notes to the Consolidated Financial Statements (continued)

33. Differences between Colombian Governmental Entity accounting principles and U.S. GAAP (Continued)

2006, respectively. A major contributing factor to these losses has been that Ecopetrol has a large portion of their investments in securities denominated in U.S. dollars. The weakening of the U.S. dollar as compared to the Colombian peso has thus forced a lot of these securities into a loss position.

ii. INVESTMENTS IN NON-MARKETABLE SECURITIES

a. Equity Method

Under PGCP, equity securities for which prices are unquoted, or for which trading volume is minimal, and the Company does not control the investee, are accounted for under the cost method and subsequently are valued by the shareholders’ equity comparison method. Under the equity comparison method, the Company accounts for the difference between its proportionate share of shareholders’ equity of the investee and its acquisition cost, adjusted for inflation through 2001, in a separate valuation account in the assets and equity (valuation surplus), if the proportionate share of shareholders’s equity of the investee is higher than its cost or as an allowance for losses, affecting net income, if the cost is higher than the proportionate share of shareholders’s equity of the investee. The proportionate share of shareholder’s equity is considered as the market value for this purpose and is known as intrinsic value. Under this method, the Company only records dividends as income when received.

Under U.S. GAAP, an investment in a non-marketable equity security is recorded using the equity method when the investor can exercise significant influence over the investee, or the cost method when significant influence cannot be exercised. Investments accounted for using the equity comparison method under PGCP are accounted for using the equity method for U.S. GAAP. Under the equity method of accounting for U.S. GAAP the carrying value of such an investment is adjusted to reflect (1) the Company’s proportionate share of earnings or losses from the investee and (2) additional investments and distributions of dividends. The Company’s proportionate share of income or loss is reported in earnings but any dividends or additional investments are reported only as an adjustment of the carrying amount of the investment. The income tax consequences that the Company would incur as a result of equity earnings have been reported by the Company as additional deferred income tax expenses and deferred tax liabilities.

The differences between the application of the cost and equity comparison methods under PGCP and the equity method under U.S. GAAP were:

• Reversion of valuations and allowances for losses recorded under PGCP

• Reversion of inflation adjustments recorded under PGCP

• Inclusion of share of earnings or losses under U.S. GAAP, net of intercompany eliminations.

• Inclusion of share in other comprehensive income under U.S. GAAP.

The summary of the investments valued by the equity method for U.S. GAAP purposes is shown in the following table:

F - 61

Ecopetrol S.A. and Subsidiaries

Notes to the Consolidated Financial Statements (continued)

33. Differences between Colombian Governmental Entity accounting principles and U.S. GAAP (Continued)

For the Year Ended December 31, 2007

Company	Percentage Of Voting Interest		Equity Calculated under US GAAP			Equity Under Colombian GAAP		Assets Under Colombian GAAP		Liabilities Under Colombian GAAP		Net Income (Loss) Under Colombian GAAP			Investment Under US GAAP Equity Method
Oleoducto de Colombia S.A.	44	%	$	(419,253	)	$	121,101	$	134,271	$	13,170	$	(10,714	)	$	—
Invercolsa S.A.	32	%		178,228			528,202		586,049		57,847		58,081			56,605
Serviport	49	%		3,240			13,374		16,336		2,962		(207	)		1,587
Refinería de Cartagena S.A.	49	%		1,508,744			1,833,758		2,273,797		440,039		(20,790	)		739,285
Ecodiesel S.A.	50	%		14,738			15,502		16,016		514		2			7,369
															$	804,846

For the Year Ended December 31, 2006

Company	Percentage of Voting Interest		Equity Calculated under US GAAP			Equity Under Colombian GAAP		Assets Under Colombian GAAP		Liabilities Under Colombian GAAP		Net Income (Loss) Under Colombian GAAP			Investment Under US GAAP Equity Method
Oleoducto de Colombia S.A.	44	%	$	(418,335	)	$	127,311	$	143,130	$	15,819	$	(26,763	)	$	—
Invercolsa S.A.	32	%		157,788			364,994		373,111		8,117		54,511			50,113
Serviport	49	%		3,564			8,124		12,059		3,935		421			1,746
Refinería de Cartagena S.A.	49	%		9,853			9,853		9,923		70		(170	)		4,828
															$	56,687

F - 62

Ecopetrol S.A. and Subsidiaries

Notes to the Consolidated Financial Statements (continued)

33. Differences between Colombian Governmental Entity accounting principles and U.S. GAAP (Continued)

The number of shares which the Company owns with respect to its investment in Invercolsa S. A. has been subject to a legal dispute with another Invercolsa shareholder. Numerous court decisions have ruled in favor of both the Company and the other shareholder, with the final outcome still unknown. As a result of these court decisions, the number of shares owned by the Company has fluctuated, from the current 31.76% to more than 50%. Consequently, applying appropriate GAAP in both Colombia and the U.S., which is based on the Company’s percentage ownership of the investee, would result in different accounting treatment each time a court decision was handed down. Therefore, until the final legal outcome is known, the Company has decided to record the investment under the equity method for US GAAP purposes, applying the lower percentage owned (31.76%) during all of the years that the Company has had an ownership interest in Invercolsa S.A. As such, the amount of the Company’s investment is adjusted only for its proportionate share of Invercolsa’s net income or loss and any dividends received or additional investments made, and no adjustment is made for changes in Invercolsa’s estimated fair value.

In regards to the Company’s investment in Oleoducto de Colombia S.A., after removing the valuation adjustments and inflation adjustments that are permitted under Colombian GAAP, Oleoducto de Colombia S.A. would have negative equity for U.S. GAAP. Therefore, the Company ceased applying the equity method and the amount of the investment has been reduced to zero in accordance with U.S. GAAP.

b. Variable Interest Entity (VIE)

Under U.S. GAAP, Financial Accounting Standards Board Interpretation (FIN) No. 46(R), Consolidation of Variable Interest Entities, clarifies the application of ARB No. 51 to certain entities in which equity investors do not have the characteristics of a controlling financial interest or do not have sufficient equity at risk for the entity to finance its activities without additional subordinated financial support. ARB No. 51 requires that consolidated financial statements include subsidiaries in which the company has a controlling financial interest, i.e., a majority voting interest. Application of the majority voting interest requirement to certain types of entities may not identify the party with a controlling financial interest because that interest may be achieved through other arrangements. Under FIN No. 46(R), a company shall consolidate a variable interest entity if that company has a variable interest that will absorb a majority of the entity’s expected losses, receive a majority of the entity’s expected residual returns, or both. In determining whether it is a primary beneficiary of a variable interest entity, a company shall treat variable interests in that same entity held by the company’s related parties as its own interest. Under PGCP, consolidated financial statements only include subsidiaries in which the company has the majority voting interest. Based on the FIN 46(R) definition, Ecopetrol identified that its investment in Oleoducto Central S.A. (hereinafter Ocensa), valued at cost under PGCP, should be consolidated as a VIE for U.S. GAAP purposes.

Ocensa is a mixed economy company organized in accordance with Colombian laws in December 1994, with a duration expiring in December 2093 and dedicated to designing, constructing, operating, managing, commercially exploiting and owning an oil transportation system for public use, without any limitation, including maritime ports and oil terminals, whose starting point is located in the Cusiana and Cupiagua oil fields, Department of Casanare, and whose final point is located in the Coveñas shipment port, in the municipalities of San Antero, Department of Córdoba and Coveñas, Department of Sucre. Ocensa is defined as a Port Company, per Resolution 0155 of March 29, 2000 of the Ports Superintendency.

Ecopetrol S.A. owns 35.29% of Ocensa. Ocensa is a VIE because Ecopetrol contractually absorbs 60% of the operating expenses of Ocensa through tariffs. A minority interest owner is entitled to a cumulative annual preferred return on its investment amounting to US$16.968892 per share on 1,274,576 shares for a total of US$21,628,142 annually. The interest of the preferred owner is 24.71% at December 31, 2007 and 2006 and will revert to Ecopetrol upon retirement of its investment.

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Ecopetrol S.A. and Subsidiaries

Notes to the Consolidated Financial Statements (continued)

33. Differences between Colombian Governmental Entity accounting principles and U.S. GAAP (Continued)

The summary of Ocensa financial information as of and for the years ended December 31, 2007 and 2006 follows:

		2007		2006
Assets	$	1,255,285	$	1,674,734
Liabilities		371,907		801,369
Equity		883,378		873,365
Net income (loss)	$	33,901	$	(11,255	)

c. Cost Method Investments

For investments in non-marketable securities that the Company has determined should be accounted for under the cost method in accordance with U.S. GAAP, the inflation adjustment and the valuation recorded under PGCP were reversed. The effect is all recorded in shareholders’ equity.

The following table lists those non-marketable equity investments held by the Company at December 31, 2007 and 2006 which are accounted for using the cost method:

December 31, 2007:
(all amounts except share and percentage information are in millions of Colombian pesos)
Investment	Number of Shares	Participation Percentage		Cost
Interconexión Eléctrica S.A.	58,925,480	6	$	124,113
Empresa de Energía de Bogotá S.A. E.S.P	6,310,980	7		151,932
Colombia Telecomunicaciones	100	—		1
Total			$	276,046
December 31, 2006:
Electrocosta S.A.	180,000,000	3	$	18,000
Electrificadora del Caribe S.A.	600,000,000	5		60,000
Interconexión Eléctrica S.A.	58,925,480	6		124,113
Empresa de Energía de Bogotá S.A. E.S.P	6,310,980	7		151,932
Fertilizantes de Colombia S.A.	2,062,841	—		48
Postal Services S.A.	3	3		10
Total			$	354,103

Under U.S. GAAP (EITF 03-1), assets held at cost, including non-marketable equity investments, should be evaluated for impairment if the Company is aware of any events or changes in circumstances that may have significant adverse effects on the fair value of the investment. If the Company believes such circumstances exist, the Company would estimate the asset’s fair value and compare that to cost to determine if any impairment is necessary. The Company believes no such events or changes in circumstances existed at the balance sheets dates. However, the Company used market values established under PGCP to assess impairment of these investments and determined that they were not impaired.

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Ecopetrol S.A. and Subsidiaries

Notes to the Consolidated Financial Statements (continued)

33. Differences between Colombian Governmental Entity accounting principles and U.S. GAAP (Continued)

iii. INVESTMENT IN UNCONSOLIDATED SUBSIDIARIES

Certain of the Company’s wholly-owned subsidiaries (including a company in which Ecopetrol had a 99.93% voting participation) were discontinued and completely liquidated during 2006. The decision to liquidate these subsidiaries was made in 1998 and, at the same time, operations ceased. Pursuant to PGCP, when a controlled company is liquidated, consolidation is suspended. Also, the assets and liabilities of the companies in liquidation are adjusted to net realizable value. The financial statements for 2006, prepared under PGCP, reflect the gains and losses from these liquidations.

Under U.S. GAAP, these entities were still subject to consolidation until they were completely liquidated. Consequently, an estimate was made of the amount for which the investment in these companies should have been valued at the beginning of 2006 to determine the amount of the liquidation that should be reclassified to retained earnings. An amount of $136,372 was reclassified to retained earnings because, under PGCP, gains from the liquidation of these companies were recorded in 2006 whereas, under U.S. GAAP, gains were recognized in previous years. Cash received from liquidations was $128,210. Accounting for discontinued operations in 2006 for U.S. GAAP was not necessary as the Company ceased operations of the affected subsidiaries at the time Management made the decision to liquidate in 1998.

iv. DERIVATIVES

Ecopetrol is exposed to market risk from changes in foreign currency exchange rates, interest rate risk of its financial obligations and to commodity price risk, resulting from the fluctuations of international crude oil prices which affect its earnings, cash flows and financial condition. Ecopetrol manages its exposure to these market risks through its regular operating and financial activities and, when appropriate, through the use of derivative financial instruments. Ecopetrol has established a control to assess, approve and monitor derivative financial instrument activities. Ecopetrol does not buy, hold or sell derivative financial instruments for trading purposes. Ecopetrol’s primary foreign currency exposures relate to the US dollar; however, Ecopetrol manages its US dollar position internally, according to its asset-liability position in US Dollars. To mitigate the effect of changes in interest rates, Ecopetrol utilizes interest rate swap contracts to convert its variable rate financial obligations to fixed rates. Ecopetrol also utilizes other derivative agreements to mitigate changes in the fair value of commodities. None of the derivatives qualify for hedge accounting.

At December 31, 2006, all of Ecopetrol’s financial debt was at variable rate. To cover changes in interest rates, Ecopetrol held two interest rate swap of contracts. Accordingly, a change in market interest rates would not have a material effect on Ecopetrol’s interest expense but would affect the fair value of Ecopetrol’s debt. These swap contracts expired in March 2007 with no material effect on the financial position.

At December 31, 2007 and 2006, there were no commodity forward contracts open. Total losses incurred in 2007 were $43,696. The Company did not enter into any commodity forward contracts in 2006.

Under PGCP, the difference between the amounts paid and received under these arrangements is recognized as financial income or expense. In a swap arrangement, if the net payment will result in a payment to the counterparty, this is recorded as interest payable and thus is accrued as a liability. If the net payment will result in a payment to be received from the counterparty this is recorded as interest receivable. Both the interest payable and interest receivable resulting from net swap payments are recorded using current rates for the period. Commodity forward contracts are not recorded in the financial statements until exercised. Thus, their fair value gains and losses are not separately recorded in the financial statements.

U.S. GAAP requires that all derivative instruments are recorded on the balance sheet at fair value. Changes in the fair value of derivatives are recorded each period in current earnings or other comprehensive income, depending on whether a derivative is designated to be part of an effective cash-flow hedging transaction or an effective fair-value hedging transaction. Derivative instruments that do not meet the requirements of either a cash-flow or fair value hedge would be

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Notes to the Consolidated Financial Statements (continued)

33. Differences between Colombian Governmental Entity accounting principles and U.S. GAAP (Continued)

recorded at fair value on the balance sheet with the fair value gains and losses of the instrument recorded in the income statement.

Under U.S. GAAP, embedded derivative instruments shall be separated from the host contract, and accounted for using different measurement attributes, if certain conditions are met. In the case of the Company, some contracts to which the Company is counterparty include embedded foreign exchange derivatives. According to FASB DIG Issue B21, these contracts do not require separate accounting for the embedded derivative and the host contract because contract payments are made in the functional currency of a party to the contract or contract payments are made in a currency in which the price of the good or service delivered is routinely denominated in international commerce.

Gas imbalance agreements were evaluated to identify if they were derivatives. Management concluded these agreements are not derivatives because they do not contain notional amounts.

v. EXCHANGE OF NON-MONETARY ASSETS

During 2007, the Company exchanged fixed assets with a cost of $234,371 for a 49% interest in Refinería de Cartagena S.A. The Company estimated the fair value of the investment at $1,369,546. Under PGCP, this difference between the cost of assets given and the fair value of assets received was recorded as an increase to asset revaluation and equity. However, under U.S. GAAP (EITF 01-2), 51% of the difference between the cost of assets given and the fair value of assets received, which the Company determined to be a more reliable indicator of the value of the exchange, was recorded in the results of operations as a gain amounting to $579,241. Additionally, the reconciliation includes $27,812 corresponding to the amortization of the deferred gain. The remaining 49% of the difference, equivalent to $556,236 is to be amortized in 20 years, period of depreciation of the equipment.

vi. DEFERRED CHARGES

Under PGCP, the Company deferred certain pre-operating expenses and other deferred charges, which are expensed as incurred under U.S. GAAP. These charges include research studies and projects in the research and development phase. Normal recurring maintenance is also included in this category.

vii. EMPLOYEE BENEFIT PLANS

Pension, health care and education plans

Under PGCP, the Company estimates the net present value of its actuarial liability for all pension obligations. Initially, the liability was established and an expense was recorded. Annually, the Company estimates the net present value of the actuarial liability and adjusts the recorded liability accordingly. The amount of the adjustment is reflected in the Company’s net income. Funds are set aside to settle this liability and are reflected as Pension Plan Assets in the Company’s consolidated balance sheets.

U.S. GAAP requires the recognition of pension costs based on actuarial computations under a prescribed methodology which differs from that used under PGCP. For purposes of U.S. GAAP reconciliation, the transition obligation calculated at the date the Company adopted Statement on Financial Accounting Standard No. 87, Employers Accounting for Pensions (SFAS 87) is being amortized from January 1, 1989, for a period of 16.64 years for the pension plan. The transition obligation for the education and medical plan is being amortized from January 1, 1995, for a period of 10.64 years.

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Ecopetrol S.A. and Subsidiaries

Notes to the Consolidated Financial Statements (continued)

33. Differences between Colombian Governmental Entity accounting principles and U.S. GAAP (Continued)

Disclosure and calculation of differences under U.S. GAAP

The economic assumptions used in the determination of pension obligations under U.S. GAAP differ from those used under PGCP because the latter are established annually by the Colombian regulations.

The combined costs for the above mentioned benefit plans, determined using U.S. GAAP, for the years ended December 31, 2007 and 2006, are summarized below: (all obligations were measured at the year end).

		As of December 31,
		2007									2006
Components of net periodic benefit cost	Pension			Health		Education		Total		Pension			Health		Education		Total
Service cost	$	58,608		13,490		6,862		78,960		$	54,245		11,511		6,039		71,795
Interest cost		757,536		116,511		41,659		915,706			711,394		107,465		41,808		860,667
Expected Return on plan assets		(292,564	)	(45,244	)	(17,940	)	(355,748	)		(724,117	)	(114,070	)	(45,230	)	(883,417	)
Amortization of net (gain) or loss		904,528		149,121		83,755		1,137,404			214,388		—		48,845		263,233
Adjustment to be recognized:
Net periodic pension cost under U.S. GAAP - (gain) or loss	$	1,428,108		233,878		114,336		1,776,322		$	255,910		4,906		51,462		312,278
Net periodic pension cost under PGCP - (gain) or loss		526,277		239,432		(34,761	)	730,948			474,303		114,351		48,940		637,594
Difference to be recognized under U.S. GAAP	$	901,831		(5,554	)	149,097		1,045,374		$	(218,393	)	(109,445	)	2,522		(325,316	)

The net periodic pension cost increased in 2007 as a result of the change in the expected rate of return on plan assets from 15.2% in 2006 to 3.97% in 2007, which is reflected in the amortization of the net loss.

The changes in the benefit obligations for the above mentioned benefit plans, determined using U.S. GAAP, for the years ended December 31, 2007 and 2006, are summarized below:

		As of December 31,
		2007									2006
Change in benefit obligation	Pension			Health		Education		Total		Pension			Health		Education		Total
Benefit obligation at beginning of year	$	8,199,691		1,266,834		465,388		9,931,913		$	7,151,312		1,086,539		434,542		8,672,393
Service cost		58,608		13,490		6,862		78,960			54,245		11,511		6,039		71,795
Interest cost		757,536		116,511		41,659		915,706			711,394		107,465		41,808		860,667
Actuarial (gain) or loss		45,298		149,606		(66,195	)	128,709			712,500		138,278		34,184		884,962
Benefits paid		(458,644	)	(92,563	)	(52,071	)	(603,278	)		(429,760	)	(76,959	)	(51,185	)	(557,904	)
Benefit obligation at end of year	$	8,602,489		1,453,878		395,643		10,452,010		$	8,199,691		1,266,834		465,388		9,931,913
Accrued benefit cost under PGCP		7,949,074		1,392,585		391,084		9,732,743			7,522,262		1,193,787		456,279		9,172,328
Difference to be recognized under US GAAP shareholders’ equity	$	653,415		61,293		4,559		719,267		$	677,429		73,047		9,109		759,585

F-67

Ecopetrol S.A. and Subsidiaries

Notes to the Consolidated Financial Statements (continued)

33. Differences between Colombian Governmental Entity accounting principles and U.S. GAAP (Continued)

The changes in plan assets for the above mentioned benefit plans, determined using U.S. GAAP, for the years ended December 31, 2007 and 2006, are summarized below:

		As of December 31,
		2007						2006
Change in plan assets:	Pension		Health	Education		Total	Pension			Health		Education		Total
Fair value of plan assets at beginning of year	$	7,369,376	1,139,640	451,881		8,960,897	$	7,064,556		1,112,874		441,268		8,618,698
Actual return on plan assets		292,564	45,244	17,940		355,748		724,117		114,070		45,230		883,417
Company’s contributions		83,977	14,193	3,862		102,032		—		—		—		—
Actuarial gain (loss)		69,463	121,774	(114,240	)	76,997		(419,297	)	(87,304	)	(34,617	)	(541,218	)
Fair value of plan assets at end of year	$	7,815,380	1,320,851	359,443		9,495,674	$	7,369,376		1,139,640		451,881		8,960,897

For U.S. GAAP purposes, plan assets are shown net of the pension obligations. There are no differences between the fair value of plan assets under PGCP and U.S. GAAP.

Under U.S. GAAP, the Company applies the provisions of Statement on Financial Accounting Standard No. 87, as amended by Statement on Financial Accounting Standard No. 132(R), Employers Disclosure about Pension and Other Post-retirement Benefits, an amendment to FASB Statements No. 87, 88 and 106”. The Company adopted Statement on Financial Accounting Standard No. 158, Employers Accounting for Defined Benefit Pension and Other Postretirement Plans (SFAS 158) effective January 1, 2006, in respect of its defined benefits pension, health and education plans. This standard requires the Company to recognize the overfunded or underfunded status of each of its defined benefit pension and other postretirement benefit plans as an asset or liability and to reflect changes in the funded status through Accumulated Other Comprehensive Income, as a separate component of shareholders’ equity. The actuarial calculations are estimated at year end dates.

As of December 31, 2007 and 2006, the amounts recognized in the balance sheet related to pension, health and education obligation consists of:

	2007		2006
Long-term liability
Pension	$	787,109	$	830,315
Health		133,027		127,194
Education		36,200		13,507
Total long-term liability	$	956,336	$	971,016

As of December 31, 2007 and 2006, the amounts recognized in accumulative other comprehensive loss, related to pension, health and education obligations consist of:

Equity	2007			2006
Other comprehensive income Actuarial loss (debit)
Pension	$	(1,130,480	)	$	(2,059,173	)
Health		(209,690	)		(330,979	)
Education		(125,574	)		(161,284	)
Total other comprehensive income		(1,465,744	)		(2,551,436	)
Deferred income tax		483,696			841,973
Total equity	$	(982,048	)	$	(1,709,463	)

F-68

Ecopetrol S.A. and Subsidiaries

Notes to the Consolidated Financial Statements (continued)

33. Differences between Colombian Governmental Entity accounting principles and U.S. GAAP (Continued)

The Company expects the following amounts in other comprehensive income to be recognized as components of net periodic pension cost during 2008:

Pension	$	270,231
Health		64,302
Education		79,035

The economic assumptions adopted are shown below in nominal terms. Those assumptions used in determining the actuarial present value of pension obligation and the projected pension obligations for the plan years were as follows:

	2007						2006
	Pension		Health		Education		Pension		Health		Education
Discount rate	10.29	%	10.29	%	10.29	%	9.50	%	9.50	%	9.50	%
Rate of compensation increases and pensions	6.71	%	7.20	%	5.69	%	5.82	%	5.90	%	4.48	%
Expected rate of return	3.97	%	3.97	%	3.97	%	15.2	%	15.2	%	15.2	%
Mortality table	*		*		*		*		*		*

* Colombian mortality table ISS, male and female, 1981-1989.

The discount rate used in the assumptions above corresponds to the rate of long-term bonds of the Colombian treasuries as of December 31, 2007 and 2006 respectively. The discount rate, excluding cost of living, increases were 4.35% in 2007 and 4.8% in 2006. The rate of return on pension funds was 4.81% in 2007 and 3.97% in 2006.

Estimated future benefit payments

The benefit payments, which reflect expected future service, as appropriate, are expected to be paid as follows:

Period	PensionBenefits		HealthCare Benefits		Education Benefits
2008	$	469,461	$	109,571	$	48,696
2009		503,302		104,540		38,691
2010		505,860		101,193		37,128
2011		497,459		97,819		35,930
2012		486,311		94,650		34,669
Years 2013 – 2017	$	1,611,632	$	304,522	$	101,646

All of the benefits estimated in the table above are to be paid from plan assets. The Company does not have any insurance policies that are intended to cover benefits that plan participants are to receive.

Furthermore, at the current time the company does not intend to contribute to the fund in the upcoming fiscal year. Management believes that the plan assets will provide for a return sufficient to cover any payments that are necessary to be made in the upcoming year.

Assumed health care cost trend rates have an effect on the amounts reported for the health care plans. A one percentage point change in assumed health care cost trend rates would have the following effects:

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Notes to the Consolidated Financial Statements (continued)

33. Differences between Colombian Governmental Entity accounting principles and U.S. GAAP (Continued)

	1-Percentage Point
(In millons of Colombian pesos)	Increase		Decrease
Effect on total of service and interest cost	$	20,085	$	16,718
Effect on postretirement benefit obligation	$	168,342	$	141,428

Plan assets

Although the liabilities are separated for accounting purpose, the pension, health care and education benefits, are covered by assets in a single fund with the following investment allocation:

	2007			2006
Government securities		66	%		79	%
Private bonds		9	%		6	%
Foreign currency		5	%		4	%
Other		20	%		11	%
		100	%		100	%

The plan assets do not contain any shares of stock of Ecopetrol or any of its related parties.

viii. PROVISIONS, ALLOWANCES AND CONTINGENCES

The Company is in the process of outsourcing administration of its pension plan to a third party (known as a partial transfer.) As a result of this process, under PGCP, the discount rate was reduced from 4.8% to 4.0%, the effect of which was an additional pension liability of $869,927. For US GAAP purposes, the provision was reversed, because the partial transfer is not a settlement, as defined by SFAS 88. For U.S, GAAP purposes, the Company used the discount rate in accordance with SFAS 87 to prepare its actuarial calculation. The amount reversed at December 31, 2007 and 2006 was $869,927.

Prior to September 5, 2007, under PGCP, a provision was recorded for a contingent event at the time a judgment was issued against the Company, without reference to the evaluation of the outcome. On September 5, 2007, the CGN issued Resolution 356 which provided that a provision was to be recorded for a contingent event if the evaluation of the outcome was evaluated to be probable. The term probable as used here has been interpreted in practice under PCGP to mean more-likely-than-not. As a result, the provision for legal processes included in Estimated Liabilities and Provisions was increased by $951,158 during 2007 to reflect the implementation of the new rule. Additionally, the amount at which the provision is valued under PCGP is the amount of the initial claim made against the Company.

For U.S. GAAP, Statement of Financial Accounting Standards No. 5, Accounting for Contingencies (“SFAS 5”), provides the guidance for recording contingencies. Under SFAS 5, there are three levels of assessment of contingent events – probable, reasonably possible and remote. The term probable in SFAS 5 is defined as “the future event or events are likely to occur”. The term reasonably possible is defined as “the chance of the future event or events occurring is more than remote but less than likely”. And the term remote is defined as “the chance of the future event or events occurring is slight”.

Under SFAS 5, an estimated loss related to a contingent event is to be accrued by a charge to income if both of the following conditions are met:

• Information available prior to issuance of the financial statements indicates that it is probable that an asset had been impaired or a liability had been incurred at the date of the financial statements.

• The amount of loss can be reasonably estimated.

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Ecopetrol S.A. and Subsidiaries

Notes to the Consolidated Financial Statements (continued)

33. Differences between Colombian Governmental Entity accounting principles and U.S. GAAP (Continued)

The amount recorded is an estimate of the amount of loss at the date of the financial statements. If the contingent event is evaluated to be reasonably possible, no provision for the contingent event may be made, but disclosure of the event is required.

As a result of the difference in the definition of “probable” between PGCP and U.S. GAAP, and the general interpretation of the definition in practice in Colombia, there is a difference in the amount of the provision for legal processes. This difference increased significantly during 2007 as a result of the rule change issued by the CGN. Additionally, there is a difference in the amount at which the provision for loss is recorded, as described above. The total effect on income as a result of these differences was an increase of $930,119 in 2007 and a decrease of $63,081 in 2006.

In 2007, the Company received a claim from a provider of natural gas transportation services for tariffs due in accordance with the terms of their contract. The contract called for Ecopetrol to reimburse this provider for any increase in related tariffs that arose due to changes in tax law in Colombia. The tariffs were increased several years ago and Ecopetrol had not reimbursed this provider for this expense. Under PGCP, the Company recorded the charge for this expense, and a related liability, in 2007, the year the Company became aware of the claim. For U.S. GAAP purposes, the Company restated its prior years’ financial statements to record this expense in those periods when the tariff expense should have been recognized. Thus, the 2006 and 2007 U.S. GAAP financial statements reflect the liability and the effect of the prior period adjustment in retained earnings. The difference in the timing of when this expense was recognized under PGCP as compared to U.S. GAAP results in a reconciling item in net income in 2007 and 2006. This adjustment increased (reduced) net income by $2,537 and ($303) in 2007 and 2006, respectively.

ix. DEFERRED INCOME TAXES

Under PGCP, deferred income taxes are generally recognized only for temporary differences arising from the income statement. Under U.S. GAAP, deferred tax assets or liabilities must be recorded for all temporary differences between the financial and tax bases of assets and liabilities. A valuation allowance is provided for deferred tax assets to the extent that it is more likely than not that they will not be realized.

The Company and its subsidiaries file separate income tax returns because the tax regulation does not allow consolidated income tax returns. There are no requirements to file tax returns by segments. Tax returns are required by each legal entity. Subsidiaries in foreign countries have not generated taxable income and, consequently, they have not incurred in income tax expense.

The following information regarding income taxes has been prepared under U.S. GAAP:

Income Taxes

Total income taxes for the years ended December 31, 2007 and 2006 were comprised as follows:

	2007			2006
Income taxes based on net income	$	2,544,590		$	1,136,722
Income tax effects based on items of Other Comprehensive Income:
Pension Plan Liability		358,277			356,002
Available-for-sale securities		(6,364	)		(11,646	)
	$	2,896,503		$	1,481,078

Income tax expense attributable to income from continuing operations consists of:

	2007		2006
Current	$	2,045,997	$	1,535,088
Deferred		498,593		(398,366	)
	$	2,544,590	$	1,136,722

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Notes to the Consolidated Financial Statements (continued)

33. Differences between Colombian Governmental Entity accounting principles and U.S. GAAP (Continued)

Tax Rate Reconciliation

Income tax expense attributable to income from continuing operations was $2,544,590 and $1,136,722 for the years ended December 31, 2007 and 2006, respectively, and differed from the amounts computed by applying the income tax rate of 34% in 2007 and 38.5% in 2006 to pretax income from continuing operations as a result of the following:

	2007		2006
Nominal income tax	34.00	%	38.5	%
Non – taxable income	(0.89	%)	(7.75	%)
Non – deductible expenses	1.14	%	1.52	%
Effect of contribution in kind	(1.69	%)	(11.77	%)
Others	0.08	%	(3.67	%)
Exempt revenue	(3.37	%)	(3.80	%)
Changes in tax rate	0.10	%	1.6	%
Effective income tax under U.S. GAAP	29.21	%	14.63	%

Non – taxable income in 2006 includes FAEP and a prior year adjustment related to deferred income taxes under PGCP.

Deferred Taxes

The significant components of deferred income tax expense attributable to income from continuing operations for the years ended December 31, 2007 and 2006 are as follows:

	2007			2006
Deferred income tax expense (exclusive of the effects of other components below):
Accounts payable	$	111,514		$	(36,028	)
Inventories, principally due to inflation adjustments		(54,565	)		14,480
Property, plant and equipment, principally due to DD&A and inflation adjustments		190,536			(520,863	)
Deferred charges		379,099			230,904
Capital lease		50,776			53,681
Other liabilities		377,656			(23,066	)
Direct finance lease		(461,312	)		(32,288	)
Estimated liabilities and provisions		75,919			(178,861	)
Accounts and notes receivable principally due to BOMT		(431,134	)		48,744
Natural and environmental properties due to inflation adjustments and capitalized expenses		192,990			38,990
Other		441,565			(8,003	)
		873,044			(412,310	)
Amortization of actuarial loss recorded in OCI		(375,343	)		(114,637	)
Unrealized loss in available for sale securities		(7,428	)		2,728
Adjustment to deferred tax assets and liabilities for enacted changes in tax laws and rates		8,399			123,635
Increase (decrease) in beginning-of-the-year balance of the valuation allowance for deferred income tax assets		(79	)		2,218
	$	498,593		$	(398,366	)

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Notes to the Consolidated Financial Statements (continued)

33. Differences between Colombian Governmental Entity accounting principles and U.S. GAAP (Continued)

The adjustment to deferred tax assets and liabilities for enacted changes in tax laws and rates includes amounts of $7,812 and $116,696 relating to the December 31, 2006 and December 31, 2005, respectively enactment of the tax reform legislation. This legislation reduced the corporate income tax rate. The Company recognized the impact of the future rate changes in 2006, the year of enactment of the legislation.

The tax effects of temporary differences that give rise to significant portions of the deferred tax assets and deferred tax liabilities at December 31, 2007 and 2006 are presented below:

	2007		2006
Deferred income tax assets and liabilities
Deferred income tax assets:
Inventories, principally due to inflation adjustments	$	65,096	$	10,531
Investments, principally due to inflation adjustments		33,147		437,479
Property, plant and equipment, principally due to DD&A and inflation adjustments		1,454,677		1,645,213
Deferred charges		107,391		486,490
Financial obligation, principally due to capitalized leasing		172,600		223,376
Pension obligations		237,358		250,663
Accounts payable		121,784		233,297
Estimated liabilities and provisions		573,327		649,290
Total gross deferred income tax assets		2,765,380		3,936,339
Less valuation allowance		8,083		8,162
Net deferred income tax assets	$	2,757,297	$	3,928,177

	2007		2006
Deferred income tax liabilities
Accounts and notes receivable principally due to BOMT	$	6,430	$	437,565
Natural and environmental properties due to inflation adjustments and capitalized expenses		192,990		219,408
Others, principally due to deferred monetary correction		529,783		152,127
Investments		3,984		233,095
Direct finance lease		—		461,312
Total deferred income tax liabilities		733,187		1,503,507
Net deferred income tax assets (liability)	$	2,024,110	$	2,424,670

The valuation allowance for deferred income tax assets as of December 31, 2007 and 2006 was $8,083 and $8,162, respectively. The valuation allowance at December 31, 2007 and 2006 was primarily related to the effect on income tax related to inflation adjustments of lands that, in the judgment of management, are not more likely than not to be realized because lands are not depreciated and there are no plans to sell these lands. In assessing the realizability of deferred income tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. Management considers the scheduled reversal of deferred tax liabilities, projected future taxable income, and tax planning strategies in making this assessment. Taxable income for the years ended December 31, 2007 and 2006was $5,545,624 and $3,895,503,

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Notes to the Consolidated Financial Statements (continued)

33. Differences between Colombian Governmental Entity accounting principles and U.S. GAAP (Continued)

respectively. Based upon the level of historical taxable income and projections for future taxable income over the periods in which the deferred tax assets are deductible, management believes it is more likely than not that the Company will realize the benefits of these deductible differences, net of the existing valuation allowances, at December 31, 2007.

x. REVENUE RECOGNITION

a.1 FAEP

The Colombian government created and regulated in Law 209 of 1995 the savings and stabilization fund for the oil sector (Fondo de Ahorro y Estabilización Petrolera, or FAEP) with the exclusive dual purpose of fiscal savings and macroeconomic stabilization, and government management of overseas accounts. The law required the Company to defer a certain portion of cash received in U.S. dollars from sales to third parties into FAEP. Banco de la República (Colombian Central Bank) acted as the portfolio manager of the funds and monies were withdrawn in accordance with the formula specified in the law.

Under PGCP, contributions to FAEP were recorded as increases to deferred income and an asset account for the same amount. No revenue was recognized for contributions to FAEP despite the completion of a sale. Distributions out of the fund were recorded as revenue, with corresponding decreases in the deferred income and the FAEP asset accounts. The amount of income that was deferred under PGCP and the cash deposited into the Fund through December 31, 2005 amounted to $3,187,887. In 2006, an additional $774,160 was deferred and an equivalent amount was deposited into the fund; and an exchange loss of $117,880 was recorded in the fund. In 2007, an additional $316,497 was deferred and an equivalent amount was deposited into the fund; and an exchange loss of $97,127 was recorded in the fund. During 2007, the Colombian government issued Law 1151 of 2007 by means of Decree 3238 of August 27, 2007, which rescinded Law 209 of 1995 and declared that Ecopetrol’s contributions to the fund and not previously distributed to the Company pursuant to Law 209 belonged to the Colombian government. The total amount remitted to the Government was $4,063,537.

The amount of the deferred income was recognized currently for U.S. GAAP purposes, considering that this deferral responded to a Government saving program with the purpose of maintaining macro-economic stability in the country and that the transaction with the third party was complete. Further, the effective receipt by the Government of the fund balance in August 2007 was treated as a distribution to its sole shareholder under U.S. GAAP.

a.2 Natural Gas Imbalance

For US GAAP purposes, the Company utilizes the entitlement method of accounting for natural gas balancing arrangements by which the amount of natural gas sold is based on its shared interests in the properties. The Company’s natural gas imbalance positions at December 31, 2007 and 2006 were $5,838 and $15,525 in favor, equivalent to 1,052,182 MBTU and 2,232,799 MBTU, respectively. Under PGCP, natural gas imbalances are settled with a purchase or sale to the partner that are accounted for at the end of each period.

a.3 Over and Under

For U.S. GAAP purposes, the company utilizes the entitlement method of accounting for over and under positions by which the amount of crude oil sold is based on its shared interest in the properties. The company’s crude oil imbalance positions at December 31, 2007 and 2006 were $155,638 and $142,781 in favor of Ecopetrol, equivalent to 923,134 and 746,689 barrels, respectively. Under PGCP, the Company recognizes receivables from or payables to partners based on the cost of the inventory. Under U.S. GAAP, revenue was recognized based on market prices.

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Notes to the Consolidated Financial Statements (continued)

33. Differences between Colombian Governmental Entity accounting principles and U.S. GAAP (Continued)

b. Cost of Sales

The related cost of sale for Over and Under transactions described on a.3 above amounted to 152,375 for 2006 while during 2007 the effect represented a recognition of $16,607 in comparison with the amount recognized under PGCP.

c. Exchange Losses

For U.S. GAAP purposes, the Company recognized exchange losses originated from FAEP funds. Under PGCP, exchange losses on FAEP funds were offset with deferred income. Exchange losses were $97,127 in 2007 and $117,880 in 2006.

xi. INFLATION ADJUSTMENT

The PGCP consolidated financial statements were adjusted for inflation based on the variation in the IPC (Colombia’s equivalent to the consumer price index in the United States) for middle income-earners, from January 1, 1992, to December 31, 2001. The adjustment was applied monthly to non-monetary assets, equity (except for the valuation surplus) and memorandum accounts.

Financial statements are only adjusted for inflation under U.S. GAAP when an entity operates in a hyperinflationary environment. The environment in which the Company has operated has not been hyperinflationary since the early 1990’s. For this reason, inflation adjustments recorded from 1992 until 2001 that remained as part of the cost of assets have been excluded for U.S. GAAP purposes.

xii. INVENTORIES

Under PGCP, inventories are valued at the lower of average cost or sale price. Under U.S. GAAP, inventories are valued at the lower of average cost or market value, the determination of which can be made using several different methods acceptable under U.S. GAAP. An adjustment has been recorded to reflect the difference in the method used to determine the valuation of inventories that arises from using sale price instead of market value, as defined by U.S. GAAP. The effects of this adjustment in the reconciliation of income were $301 and ($346) in 2007 and 2006, respectively.

Inventories are also affected by the effect of adjustments to cost of sales included in this reconciliation note. These adjustments relate to depreciation, expenses capitalized in property, plant and equipment, asset retirement cost and impairment of long lived assets. The effects of these adjustments in the reconciliation of income and equity and the corresponding effect in inventory were as follows:

	2007		2006
Net income	($67,390	)	($9,385	)
Equity	($76,775	)	($9,385	)

xiii. LEASE ACCOUNTING

Under both PGCP and U.S. GAAP, lessees’ accounting for capital leases and operating leases are identical. However, the tests used to determine if a lease is a capital or an operating lease differs between PGCP and U.S. GAAP. In applying the tests in accordance with PGCP, the Company has determined that all leases are operating leases. Under U.S. GAAP some of these leases should be accounted for as capital leases in accordance with Statement on Financial Accounting Standard No.13, Accounting for Leases (SFAS 13). As a result, adjustments were recorded to reflect the related assets and liabilities, and to recognize interest expense and de-recognize operating expenses associated with the lease payments.

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Notes to the Consolidated Financial Statements (continued)

33. Differences between Colombian Governmental Entity accounting principles and U.S. GAAP (Continued)

Build, Operate, Maintain and Transfer (BOMT)

Three original leases that were accounted for as capital leases under U.S. GAAP are BOMT contracts, the use of which are specifically required under Colombian law for projects that involve the building, operating, maintaining and transferring of natural gas pipelines for the transportation of natural gas. These contracts had original terms of 20 years, no renewal provisions, and a purchase option. The rights to the leased assets were subsequently transferred to a related company (ECOGAS) that was sold, but Ecopetrol was not relieved of the primary obligation under the original lease. This transfer was considered a sublease accounted for as a direct finance lease.

As of December 31, 2006, the amounts outstanding under the sublease were:

Gross investment	$	2,435,804
Unearned income		1,038,799
Net investment in the lease	$	1,397,005

In 2007, Ecopetrol received a prepayment of all amounts to be received during the term of the sublease contract.

The outstanding amount of rentals, excluding operation and maintenance, payable under the BOMT obligations that were not relieved during the next years follows for these three leases:

Year	USD		Colombian Pesos
2008	US$	35	$	70,954
2009		34		68,066
2010		31		62,575
2011		20		40,443
2012		18		36,946
Payments after 2012	US$	78	$	156,891
	US$	216	$	435,875

Embedded Leasing

Under PGCP, there is no requirement to identify whether the arrangements or contracts contain leases.

Under US GAAP, an arrangement contains a lease if both of the following two criteria are met:

1. The arrangement depends on a specific fixed asset, either identified contractually or implicitly identified as no alternative item could feasibly be used.

2. The purchaser has the right to control the use of the underlying fixed asset, such control demonstrated by the existance of any of the following qualitative conditions:

a) The purchaser can operate the asset or direct others to operate the asset while obtaining or controlling more than a minor amount of the asset’s output;

b) The purchaser can control physical access to asset while obtaining or controlling more than a minor amount of the asset’s output; or

c) Probability is remote that another party will get more than minor amount of the asset’s output and the price is not fixed per unit.

Under U.S. GAAP, if the arrangement contains a lease, SFAS 13 is applied by both purchaser and supplier for recognition,

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Notes to the Consolidated Financial Statements (continued)

33. Differences between Colombian Governmental Entity accounting principles and U.S. GAAP (Continued)

measurement, classification and disclosure purposes.

In the case of the Company, it was determined that there were leases included in various contracts. The most significant embedded lease was determined to exist in Contract DIJ 970 (Transmetano), Natural gas transportation - Sebastapol – Medellín pipeline.

The contractor is entitled to receive natural gas at the designated point, and it is also obligated along with the Company to transport the product throughout the pipeline and bring it to the delivery point (conducting up to 67 million cubic feet per day). The contract has a duration of 15 years, and could be extended for periods of 1 year, not longer than 10 years. Leasing payments include the costs of transportation, administration, operation and pipeline maintenance.

This contract meets the criteria of Emerging Issues Task Force 01-08, Determining Whether an Arrangement Contains a Lease (EITF 01-08) in order to be considered a lease agreement. Similarly, according to SFAS 13, the contract meets the criteria to be recognized as a capital lease. At December 31, 2007 and 2006, the capitalized amount and the related liability are as follows:

	2007		2006
Assets
Property, plant and equipment	$	83,245	$	83,245
Accumulated depreciation		55,497		49,947
Net value		27,748		33,298
Liabilities:
Financial obligations	$	80,991	$	100,531

The following table shows the net present value (in thousands of dollars) of the lease payments for the next 5 years:

Year	USD		Colombian Pesos
2008	$	6	$	11,385
2009		7		13,524
2010		8		15,929
2011		9		18,577
2012		11		21,576
	$	41	$	80,991

Other minor contracts contained capital leases that were adjusted under U.S. GAAP.

xiv. PRIOR YEAR ADJUSTMENTS

In accordance with PGCP, adjustments of previously issued financial statements shall be included in the net income of the period in which they are discovered. These adjustments do not have any impact on the income tax because they cannot be considered a deduction in the period in which they are discovered. Under U.S. GAAP, when comparative statements are presented, corresponding adjustments shall be made of the amounts of net income, its components, retained earnings balances, and other affected balances for all of the periods presented to reflect the retroactive application of the prior period adjustments. Prior year adjustments were classified in the year they were incurred as defined by U.S. GAAP.

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Notes to the Consolidated Financial Statements (continued)

33. Differences between Colombian Governmental Entity accounting principles and U.S. GAAP (Continued)

xv. PROPERTY, PLANT AND EQUIPMENT

Under PGCP, property, plant and equipment is recorded at cost, adjusted for inflation until 2001. Cost includes administrative expenses until 2004, financial expenses and exchange differences from foreign currency financing until the asset is placed in service. Normal disbursements for maintenance and repairs are charged to expense and those significant costs that improve efficiency or extend the useful life are capitalized. Under U.S. GAAP, cost includes expenditures until the asset is placed in service such as installation cost, freight, interest, retirement cost; construction cost and other direct expenses are capitalized, with exception of adjustment for inflation and foreign currency loss. For U.S. GAAP purposes, administrative expenses capitalized were eliminated from property, plant and equipment. In addition, a deferred income tax asset resulted from the application of the provisions of EITF 98–11, Accoun ting for Acquired Temporary Differences in Certain Purchase Transactions That Are Not Accounted for as Business Combinations, because this investment creates an additional tax deduction of 40% in 2007 and 30% in previous years.

Revaluation of property, plant and equipment

Valuation surplus of property, plant and equipment corresponds to the difference between net book value and the market value for real estate or the current value in use for plant and equipment, determined by specialists. These accounts are reflected as Valuations and as Valuation Surplus from reappraisals of assets (a component of equity) in the Company’s consolidated balances sheets. The last valuation was in December 2006. Technical appraisals are valid for three years.

Under U.S. GAAP valuation and valuation surplus of assets are not permitted.

Impairment

Under PGCP, technical appraisals for property, plant and equipment are performed at least every three years. If the technical study is lower than the carrying value, the difference is recorded in equity as a reduction of the property, plant and equipment carrying value even if it reduces the valuation surplus below zero. Under U.S. GAAP, in accordance with FASB Statement No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets (SFAS 144), property, plant, and equipment are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If circumstances require a long-lived asset to be tested for possible impairment, the Company first compares undiscounted cash flows expected to be generated by the asset to the carrying value of the asset. If the carrying value of the long-lived asset is not recoverable on an undiscounted cash flow basis, an impairment is recognized to the extent that the carrying value exceeds its fair value. Fair value is determined through various valuation techniques including discounted cash flow models, quoted market values and third-party independent appraisals, as considered necessary. For U.S. GAAP purposes, the Company reviewed property, plant and equipment for impairment as of December 31, 2005, 2006 and 2007 and recorded impairment losses when required. For US GAAP purposes, the Company recorded in 2007 and 2006 $65,137 and $12,241 as impairment additional impairment charges to reduce the net book value of certain wells and pipelines to their estimated values.

Differences among the successful efforts method

For PGCP purposes, the Company applies a similar method to the internationally known “successful efforts method”, but prior to 2006, activities such as geology and geophysics, exploration expenses and maintenance were capitalized. This was the main difference with requirements of SFAS 19. Production facilities are depreciated using the straight line method under PGCP. For US GAAP purposes, Ecopetrol made all the necessary adjustments to reverse these capitalized expenses not allowed under US GAAP. Ecopetrol also used the US GAAP oil and natural gas reserves to compute the units of production method to depreciate its production facilities for U.S. GAAP purposes.

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Notes to the Consolidated Financial Statements (continued)

33. Differences between Colombian Governmental Entity accounting principles and U.S. GAAP (Continued)

Disclosure of amounts capitalized in exploratory wells

The following table reflects the net changes in capitalized exploratory wells during 2007 and 2006 and does not include amounts that were capitalized and subsequently expensed during the same period.

	2007			2006
Beginning balance at January 1	$	113,200		$	107,400
Additions to capitalized exploratory well cost		288,910			85,254
Reclassifications to wells, facilities and equipment based on the determination of proved reserves		(113,900	)		(42,500	)
Capitalized exploratory well cost charged to expense		(81,910	)		(36,954	)
Ending balance at December 31	$	206,300		$	113,200

The balance at December 31, 2007 and 2006 corresponds to well costs capitalized during the years ended at those dates.

xvi. DEPRECIATION, DEPLETION AND AMORTIZATION

Under PGCP, all tangible equipment, including those used in the production of crude oil and natural gas, is depreciated on a straight-line basis over the related estimated useful lives. Intangible crude oil and natural gas assets reflected on the Company’s consolidated balance sheets as Natural and environmental properties are depleted on a units-of-production basis. Under U.S. GAAP, all assets, including tangible equipment, used in crude oil and natural gas producing activities are required to be depreciated or depleted using a units-of-production method, using proved reserves calculated in accordance with U.S. GAAP requirements. Therefore, an adjustment to net income per U.S. GAAP has been recorded to account for the difference in depreciation, depletion and amortization expense based on the above-described differences in the methods used.

xvii. ASSET RETIREMENT OBLIGATIONS

Under PGCP, the Company annually updates an analysis of the estimated liability for future asset retirement obligations as of each balance sheet date. The liability is adjusted to the current value and an offsetting amount is recorded as an adjustment to the asset cost. To the extent that elements of the liability originate in U.S. dollars, changes in the foreign currency rates are included in the adjustment to the liability and the related asset. The component of the asset cost resulting from this liability is included in the depreciable base of the related asset.

For purposes of U.S. GAAP reporting, the Company follows the provisions of Statement of Financial Accounting Standards No. 143 Accounting for Asset Retirement Obligations (SFAS 143), as amended. SFAS 143 requires the Company to recognize a liability for the present value of all legal obligations associated with the retirement of tangible, long-lived assets as of the date the related asset was placed into service, and capitalize an equal amount as an additional cost of the asset. Each period the liability is accreted using an effective interest rate method. The accretion is included as an operating expense. The cost associated with the abandonment obligation, along with any estimated salvage value, is included in the computation of depreciation, depletion and amortization.

An adjustment has been recorded in the consolidated financial statements to reflect accretion expense, and the related obligation and assets in accordance with SFAS 143. This adjustment was based on an estimate of the obligation as of December 31, 2007 because it provided the most reliable fair value.

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Notes to the Consolidated Financial Statements (continued)

33. Differences between Colombian Governmental Entity accounting principles and U.S. GAAP (Continued)

The following table presents the changes in abandonment obligations for 2007 and 2006 as is required by SFAS 143.

	2007			2006
Beginning of year	$	900,826		$	829,118
Accretion expense:
Under PGCP		89,295			48,931
Adjustment to U.S. GAAP		(10,039	)		22,777
		79,256			71,708
End of year	$	980,082		$	900,826

xviii. EQUITY CONTRIBUTIONS

i. INCORPORATED INSTITUTIONAL EQUITY

At the end of association contracts that were signed prior to January 1, 2004, private companies are required to transfer, without cost, to Ecopetrol, all producing wells, facilities and other real estate and assets acquired in executing the contracts. Under PGCP, the Company accounts for the receipt, using the relinquishing company’s reported historical cost, by recording an increase to assets and equity. The assets are then depreciated in accordance with the Company’s previously disclosed accounting policies. For U.S. GAAP reporting purposes, these balances and their related impacts on accumulated depreciation, depletion and amortization, and cost of production have been removed from the financial statements, based on the fact that the cost of these assets is zero. The adjustment to conform to U.S. GAAP in 2006 was a reduction in equity of $30,703 (original value of $31,054 net of $351 of accumulated depreciation of the assets received.) The adjustment in 2007 was a reduction in equity of $82,124 (original value of $91,779 net of $9,655 of accumulated depreciation of the assets received.).

ii. CONTRIBUTIONS IN KIND

Under PGCP, contributions of Nation in Kind established by Decree 2625 of 2000 were recognized as a cost of production during the years that the Decree was in force, by increasing equity. Contributions in kind established by Decree 2625 of 2000 were estimated based on the number of oil barrels extracted at market price in situ. Under U.S. GAAP, costs associated with these contributions were reverted as they were transactions between entities under common control in which the transferor had no basis in the investment.

iii. REVERSION OF CONCESSION RIGHTS CONTRIBUTED AS CAPITAL

Under PGCP, the Company recorded as reservoirs the contributions of the Nation represented by crude oil and natural gas reserves deriving from the reversion of concessions of oilfield areas in favor of the Nation, given before the effectiveness of Decree 1760 of 2003. Reserves were valued by means of the technical-economic model where the value per barrel resulted from the relation of the net present value obtained at a discount rate and the total proved reserves on the contribution date.

For U.S. GAAP purposes, these reversions were considered a transfer of assets between entities under common control. Ecopetrol, the entity that received the net assets, recognized the assets transferred at their carrying amounts in the accounts of the transferring entity at the date of transfer which was zero value. The unamortized amount reverted at December 31, 2007 and 2006 was $145,576 and $163,138 respectively.

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Notes to the Consolidated Financial Statements (continued)

33. Differences between Colombian Governmental Entity accounting principles and U.S. GAAP (Continued)

xix. PUBLIC OFFERING COSTS

In August 2007, the Company issued shares in an initial public offering in Colombia. Under PGCP, all related costs of this issuance were expensed as well as a discount granted to shares fully paid in cash. For U.S. GAAP purposes, direct costs incurred in public offerings and cash discounts are recorded as a reduction of the proceeds received and, consequently, a reduction in equity. An adjustment in the amount of $242,886 was recorded to recognize the effect of these amounts.

xx. EARNINGS PER SHARE

Under PGCP, earnings per share (“EPS”) are calculated by dividing net income by the weighted average of both common and preferred shares outstanding for each period presented. The Company does not have any issued or outstanding preferred shares.

U.S. GAAP requires dual presentation of basic and diluted EPS for entities with complex capital structures, as well as a reconciliation of the basic EPS calculation with the diluted EPS calculation. Basic EPS is calculated by dividing net income available to common shareholders by the weighted average of common shares outstanding for the corresponding period.

Diluted EPS assumes the issuance of common shares for all dilutive potential common shares outstanding during the reporting period. For the years ended December 31, 2007 and 2006, the Company had a simple capital structure. Therefore, the Company is not required to present diluted EPS for these years.

On April 27, 2007, the Colombian government, in its capacity as sole owner of the Company, issued 48,512,147 additional shares to capitalize contributions in kind from prior years, which was considered a stock dividend. On July 19, 2007, the Government declared a 1-to-400 stock split. For purposes of U.S. GAAP reporting and only in this footnote, all prior shares and per share data have been retroactively restated to include the effects of these two transactions. PGCP does not require restatement of earning per share information.

The following table summarizes information related to the computation of basic EPS for the years ended December 31, 2007 and 2006 (In millions of Colombian pesos, except per share data):

	2007		2006
U.S. GAAP consolidated net income (in millions)	$	6,144,685	$	6,636,424
Weighted average number of common shares outstanding		36,922,352,491		36,384,788,800
Basic and Diluted earnings per share U.S. GAAP (in pesos)	$	166.42	$	182.40

xxi. CONCENTRATIONS

At December 31, 2007 and 2006, 26.6% and 28.5%, respectively, of the Company’s employees belong to unions. Management believes the Company’s relationships with those unions are good. The current labor agreement with the union is up for renewal on June 8, 2009.

In 2006, two customers of the refinery segment accounted for 16.4% and 16.3% of total sales, respectively. No other customers accounted for more than 10% of total sales in 2006. In 2007, two customers of the refinery segment accounted for 14.2% and 12.9%, and one customer of the production segment accounted for 13.4% of total sales, respectively. No other customers accounted for more than 10% of total sales in 2007.

The significant majority of the Company’s assets and activities are located in Colombia. The financial position and results of operations of those subsidiaries located outside of Colombia are not material to the Company.

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Notes to the Consolidated Financial Statements (continued)

33. Differences between Colombian Governmental Entity accounting principles and U.S. GAAP (Continued)

xxii. RECENT U.S. GAAP PRONOUNCEMENTS

In February 2007, the FASB issued Statement of Financial Accounting Standards No. 159, The Fair Value Option for Financial Assets and Financial Liabilities – including an amendment of FASB Statement No. 115 (SFAS 159). Statement 159 gives the Company the irrevocable option to carry most financial assets and liabilities at fair value that are not currently required to be measured at fair value. If the fair value option is elected, changes in fair value would be recorded in earnings at each subsequent reporting date. SFAS 159 is effective for the Company’s 2008 fiscal year. The Company is currently evaluating the impact the adoption of this statement could have on its financial condition and results of operations.

In September 2006, the FASB issued FASB Statement No. 157, Fair Value Measurement (SFAS 157). Statement 157 defines fair value, establishes a framework for the measurement of fair value, and enhances disclosures about fair value measurements. The Statement does not require any new fair value measures. The Statement (as amended by FSP FAS 157-2) is effective for fair value measures already required or permitted by other standards for fiscal years beginning after November 15, 2007. Statement 157 is required to be applied prospectively, except for certain financial instruments. Any transition adjustment will be recognized as an adjustment to opening retained earnings in the year of adoption. FSP FAS 157 – 2, “Effective Date of FASB Statement No. 157”, delays the effective date of Statement 157 for nonfinancial assets and liabilities that are not measured at fair value on a recurring basis (at least annually) until fiscal years beginning after November 15, 2008, and interim periods within those fiscal years. The Company is currently evaluating the impact of adopting Statement 157 on its results of operations and financial position.

In December 2007, the FASB issued FASB Statement No. 141R, Business Combinations (SFAS 141R) and FASB Statement No. 160, Noncontrolling Interests in Consolidated Financial Statements – an amendment to ARB No. 51 (SFAS 160). Statements 141R and 160 require most identifiable assets, liabilities, noncontrolling interests, and goodwill acquired in a business combination to be recorded at full fair value and require noncontrolling interests (previously referred to as minority interests) to be reported as a component of equity, which changes the accounting for transactions with noncontrolling interest holders. Both Statements are effective for periods beginning on or after December 15, 2008, and early adoption is prohibited. Statement 141R will be applied to business combinations occurring after the effective date. Statement 160 will be applied prospectively to all noncontrolling interests, including any that arose before the effective date. The Company is currently evaluating the impact of adopting Statement 141R and Statement 160 on its results of operations and financial position.

In March 2008, the FASB issued FASB Statement No. 161, Disclosures about Derivative Instruments and Hedging Activities, which amends FASB Statement No. 133, Accounting for Derivative Instruments and Hedging Activities. The Statement requires companies with derivative instruments to disclose information that should enable financial statement users to understand how and why a company uses derivative instruments, how derivative instruments and related hedged items are accounted for under Statement 133, and how derivative instruments and related hedged items affect a company’s financial position, financial performance, and cash flows. The required disclosures include the fair value of derivative instruments and their gains or losses in tabular format, information about credit risk related contingent features in derivative agreements, counterparty credit risk, and a company’s strategies and objectives for using derivative instruments. The Statement expands the current disclosure framework in Statement 133. Statement 161 is effective prospectively for periods beginning on or after November 15, 2008. Early adoption is encouraged. The Company is currently evaluating the impact of adopting Statement 161.

xxiii. RECENTLY ADOPTED ACCOUNTING STANDARDS

In June 2006, the FASB issued interpretation No. 48 Accounting for Uncertainty in Income Taxes - an interpretation of FASB Statement No.109 (FIN 48). FIN 48 prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. FIN 48 also provides guidance on derecognizing, classification, interest and penalties, accounting in interim periods, disclosure, and transition.

F-82

Ecopetrol S.A. and Subsidiaries

Notes to the Consolidated Financial Statements (continued)

33. Differences between Colombian Governmental Entity accounting principles and U.S. GAAP (Continued)

The evaluation of a tax position in accordance with this interpretation is a two-step process. The first step is recognition: the enterprise determines whether it is more likely than not that a tax position will be sustained upon examination, including resolution of any related appeals or litigation processes, based on the technical merits of the position. In evaluating whether a tax position has met the more-likely-than-not recognition threshold, the enterprise should presume that the position will be examined by the appropriate taxing authority that has full knowledge of all relevant information. The second step is measurement: a tax position that meets the more-likely-than-not recognition threshold is measured to determine the amount of benefit to recognize in the financial statements. The tax position is measured at the largest amount of benefit that is greater than 50 percent likely of being realized upon ultimate settlement. Differences between tax positions taken in a tax return and amounts recognized in the financial statements will generally result in one of the following: (a) an increase in a liability for income taxes payable or a reduction of an income tax refund receivable; (b) a reduction in a deferred tax asset or an increase in a deferred tax liability; or both (a) and (b).

Tax positions that previously failed to meet the more-likely-than-not recognition threshold should be recognized in the first subsequent financial reporting period in which that threshold is met. Previously recognized tax positions that no longer meet the more-likely-than-not recognition threshold should be derecognized in the first subsequent financial reporting period in which that threshold is no longer met. This interpretation is effective from January 1, 2007 for the Company.

In applying the provisions of FIN 48, the Company considered those tax returns that were open at the end of 2007 together with criteria used to declare revenues and claim deductions. The Company evaluated that it is more likely than not that tax positions taken will be sustained upon examination, including resolution of any related appeals or litigation processes, based on the technical merits of the position. The Company determined it was not required to record any additional taxes payable.

The Company has not incurred any significant interests or penalties as a result of tax uncertainties.

xxiv. SEGMENT INFORMATION

The following segment information has been prepared in accordance with Statement on Financial Accounting Standard No. 131, Disclosure about Segments of an Enterprise and Related Information (SFAS 131). Financial information by business segment is reported in accordance with the internal reporting system and shows internal segment information that is used by the chief operating decision maker to manage and measure the performance of Ecopetrol. The Company operates under the following segments, which are described as follows:

Exploration and Production —this segment includes the Company’s exploration and production activities of oil & gas. Revenue is derived from the sale of crude oil and natural gas to inter-company segments, at cost, and to third parties. Revenue is derived from local sales of crude oil, regulated fuels, non-regulated fuels and natural gas. Sales are made to local and foreign distributors. Costs include those costs incurred in production. Expenses include all exploration costs that are not capitalizable.

Refining Activities — this segment includes the Company’s refining activities. Goods sold, both internally and to third parties, include refined products such as motor fuels, fuel oils and petrochemicals. This segment also includes sales of industrial services to third parties.

Transportation — this segment includes the Company’s sales and costs associated with the Company’s pipelines and other transport activities.

All Other – Includes only market supply operations.

F-83

Ecopetrol S.A. and Subsidiaries

Notes to the Consolidated Financial Statements (continued)

33. Differences between Colombian Governmental Entity accounting principles and U.S. GAAP (Continued)

Corporate — Includes the financial results and other activities not included in the previous segments, and all corporate financial management and overhead related with the Company’s central administration. It also includes actuarial expenses related with the pension and health-care plans for non-active participants.

These functions have been defined as the operating segments of the Company because they are the segments (a) that engage in business activities from which revenues are earned and expenses are incurred; (b) whose operating results are regularly reviewed by the Company’s chief operating decision maker to allocate resources to the segments and assess their performance; and (c) for which discrete financial information is available. Internal transfers represent sales to intercompany segments and are recorded and presented at cost.

As described in Note 32, on April 7, 2008, Ecopetrol completed the acquisition of Propilco, a company that operates in the petrochemical industry. This acquisition resulted in a new business segment of Ecopetrol.

F-84

Ecopetrol S.A. and Subsidiaries

Notes to the Consolidated Financial Statements (continued)

33. Differences between Colombian Governmental Entity accounting principles and U.S. GAAP (Continued)

xxiv. Segment information (Continued)

The following presents the Company’s assets by segment in accordance with PGCP:

	As of December 31, 2007
	Exploration & Production			Refining Activities			Transportation			All Other			Corporate			Total
Current assets
Cash and cash equivalents	$	117,231		$	503		$	20,008		$	1		$	3,612,156		$	3,749,899
Accounts and notes receivable		892,734			1,213,755			24,147			55			139,213			2,269,904
Inventories		514,294			782,594			1,417			—			487			1,298,792
Investments		—			—			—			—			5,954,502			5,954,502
Other current assets		1,387,466			426,403			107,142			698			579,316			2,501,025
	$	2,911,725		$	2,423,255		$	152,714		$	754		$	10,285,674		$	15,774,122
Investments in unconsolidated companies		396,021			239,271			50,745			7,751			432,157			1,125,945
Property, plant and equipment, net		7,887,869			1,941,755			1,203,771			14,105			233,368			11,280,868
Pension plan assets		—			—			—			—			8,986,861			8,986,861
Other non current assets		3,805,094			2,603,033			737,494			46,619			3,752,044			10,944,284
Non current assets		12,088,984			4,784,059			1,992,010			68,475			13,404,430			32,337,958
Total assets	$	15,000,709		$	7,207,314		$	2,144,724		$	69,229		$	23,690,104		$	48,112,080
Accounts payable		(803,715	)		(111,758	)		(112,723	)		(15	)		(118,085	)		(1,146,296	)
Other current liabilities		(2,546,871	)		(1,182,238	)		(355,851	)		(43,398	)		(791,130	)		(4,919,488	)
Current liabilities	$	(3,350,586	)	$	(1,293,996	)	$	(468,574	)	$	(43,413	)	$	(909,215	)	$	(6,065,784	)
Non current liabilities		(2,592,625	)		(383,366	)		(430,798	)		(33,565	)		(11,797,475	)		(15,237,829	)
Total liabilities	$	(5,943,211	)	$	(1,677,362	)	$	(899,372	)	$	(76,978	)	$	(12,706,690	)	$	(21,303,613	)
Equity	$	(9,057,498	)	$	(5,529,952	)	$	(1,245,352	)	$	7,749		$	(10,983,414	)	$	(26,808,467	)
Total liabilities and equity	$	(15,000,709	)	$	(7,207,314	)	$	(2,144,724	)	$	(69,229	)	$	(23,690,104	)	$	(48,112,080	)
Capital expenditures	$	2,678,684		$	234,462		$	92,344		$	—		$	31,472		$	3,036,962

F-85

Ecopetrol S.A. and Subsidiaries

Notes to the Consolidated Financial Statements (continued)

33. Differences between Colombian Governmental Entity accounting principles and U.S. GAAP (Continued)

xxiv. Segment information (Continued)

							As of December 31, 2006
	Exploration & Production			Refining Activities			Transportation			All Other			Corporate			Total
Current assets
Cash and cash equivalents	$	17,908		$	2,228		$	18,810		$	1		$	1,588,929		$	1,627,876
Accounts and notes receivable		556,902			565,689			24,009			561			189,158			1,336,319
Inventories		387,880			607,101			1,380			—			—			996,361
Investments		—			—			—			—			1,961,687			1,961,687
Other current assets		575,898			582,455			120,777			682			81,678			1,361,490
	$	1,538,588		$	1,757,473		$	164,976		$	1,244		$	3,821,452		$	7,283,733
Investments		396,021			4,900			55,976			—			505,167			962,064
Property, plant and equipment, net		6,268,567			1,898,455			1,223,077			13,517			210,708			9,614,324
FAEP		—			—			—			—			3,844,167			3,844,167
Pension plan assets		—			—			—			—			8,960,897			8,960,897
Other non current assets		4,127,119			2,756,652			650,417			39,796			3,898,553			11,472,537
Non Current assets		10,791,707			4,660,007			1,929,470			53,313			17,419,492			34,853,989
Total assets	$	12,330,295		$	6,417,480		$	2,094,446		$	54,557		$	21,240,944		$	42,137,722
Accounts payable		(412,053	)		(102,791	)		(113,601	)		(2,599	)		(130,676	)		(761,720	)
Other Current Liabilities		(918,437	)		(1,392,780	)		(119,808	)		(71,054	)		(718,630	)		(3,220,709	)
Current Liabilities	$	(1,330,490	)	$	(1,495,571	)	$	(233,409	)	$	(73,653	)	$	(849,306	)	$	(3,982,429	)
Non current liabilities		(2,744,162	)		(871,157	)		(611,964	)		(40,952	)		(13,051,312	)		(17,319,547	)
Total Liabilities	$	(4,074,652	)	$	(2,366,728	)	$	(845,373	)	$	(114,605	)	$	(13,900,618	)	$	(21,301,976	)
Equity	$	(8,255,643	)	$	(4,050,752	)	$	(1,249,073	)	$	60,048		$	(7,340,326	)	$	(20,835,746	)
Total liabilities and equity	$	(12,330,295	)	$	(6,417,480	)	$	(2,094,446	)	$	(54,557	)	$	(21,240,944	)	$	(42,137,722	)
Capital expenditures	$	1,309,361		$	435,498		$	72,765		$	—		$	45,310		$	1,862,934

F-86

Ecopetrol S.A. and Subsidiaries

Notes to the Consolidated Financial Statements (continued)

33. Differences between Colombian Governmental Entity accounting principles and U.S. GAAP (Continued)

xxiv. Segment information (Continued)

Revenues and net income by segment are as follows in accordance with PGCP:

							Year ended December 31, 2007
	Exploration & Production			Refining Activities			Transportation			All Other			Corporate			Eliminations			Total
Revenues:
Local sales	$	3,847,905		$	11,471,912		$	677,938		$	—		$	5,242		$	—		$	16,002,997
Foreign sales:
Total Foreign sales		4,476,173			2,156,388			—			—			13,259			—			6,645,820
FAEP		—			—			—			—			(316,497	)		—			(316,497	)
Foreign sales, net		4,476,173			2,156,388			—			—			(303,238	)		—			6,329,323
Inter-segment net operating revenues		2,396,824			36,574			229,888			—			—			(2,663,286	)		—
Total revenue	$	10,720,902		$	13,664,874		$	907,826		$	—		$	(297,996	)	$	(2,663,286	)	$	22,332,320
Cost of sales		4,417,138			7,714,722			577,461			—			21,309			(2,663,286	)		10,067,344
Depreciation, depletion and amortization		1,523,251			286,700			161,473			—			19,759			—			1,991,183
Selling		635,567			128,577			82,502			27,954			59,251			—			933,851
Administration expenses		7,325			29,575			24,105			2,618			344,482			—			408,105
Costs and expenses		6,583,281			8,159,574			845,541			30,572			444,801			(2,663,286	)		13,400,483
Operating income		4,137,621			5,505,300			62,285			(30,572	)		(742,797	)		—			8,931,837
Financial income (expenses), net		(89,435	)		(25,260	)		(16,284	)		(3,992	)		69,088			—			(65,883	)
Interest income		—			—			—			—			160,532			—			160,532
Interest expenses		—			—			—			—			(1,021	)		—			(1,021	)
Pension expenses		—			—			(5,660	)		—			(1,084,683	)		—			(1,090,343	)
Other non-operating income (expenses)		(240,541	)		(516,904	)		(165,540	)		1,797			51,370			—			(869,818	)
Other expenses, net		(329,976	)		(542,164	)		(187,484	)		(2,195	)		(804,714	)		—			(1,866,533	)
Income before income taxes		3,807,645			4,963,136			(125,199	)		(32,767	)		(1,547,511	)		—			7,065,304
Income tax benefits (expense)		(1,016,632	)		(1,325,146	)		33,428			8,749			414,089			—			(1,885,512	)
Net income for the year	$	2,791,013		$	3,637,990		$	(91,771	)	$	(24,018	)	$	(1,133,422	)	$	—		$	5,179,792

F-87

Ecopetrol S.A. and Subsidiaries

Notes to the Consolidated Financial Statements (continued)

33. Differences between Colombian Governmental Entity accounting principles and U.S. GAAP (Continued)

xxiv. Segment information (Continued)

							Year ended December 31, 2006
	Exploration & Production			Refining Activities			Transportation			All Other			Corporate			Eliminations			Total
Revenues:
Local sales	$	947,220		$	9,683,228		$	666,495		$	—		$	3,058		$	—		$	11,300,001
Foreign sales:
Total Foreign sales		3,670,080			4,194,044			—			—			—			—			7,864,124
FAEP		—			—			—			—			(774,160	)		—			(774,160	)
Foreign sales, net		3,670,080			4,194,044			—			—			(774,160	)		—			7,089,964
Inter-segment net operating revenues		2,282,949			2,841			220,210			—			—			(2,506,000	)		—
Total revenue	$	6,900,249		$	13,880,113		$	886,705		$	—		$	(771,102	)	$	(2,506,000	)	$	18,389,965
Cost of sales		2,131,714			8,931,753			412,150			—			66,311			(2,506,000	)		9,035,928
Depreciation, depletion and amortization		3,296,487			280,195			142,972			—			981			—			3,720,635
Selling		322,897			202,883			7,881			24,888			86,002			—			644,551
Administration expenses		19,048			17,109			9,704			903			306,255			—			353,019
Costs and expenses		5,770,146			9,431,940			572,707			25,791			459,549			(2,506,000	)		13,754,133
Operating income		1,130,103			4,448,173			313,998			(25,791	)		(1,230,651	)		—			4,635,832
Financial income, net		(14,081	)		(14,091	)		18,342			(1,412	)		599,998			—			588,756
Interest income		—			—			—			—			103,107			—			103,107
Interest expenses		—			—			—			—			(8,427	)		—			(8,427	)
Pension expenses		—			—			(3,168	)		—			(826,023	)		—			(829,191	)
Other non-operating income (expenses)		30,176			(33,913	)		(162,350	)		(1,785	)		568,937			—			401,065
Other expenses, net		16,095			(48,004	)		(147,176	)		(3,197	)		437,592			—			255,310
Income before income taxes		1,146,198			4,400,169			166,822			(28,988	)		(793,059	)		—			4,891,142
Income tax benefits (expense)		(351,459	)		(1,349,222	)		(50,838	)		8,574			243,176			—			(1,499,769	)
Net income for the year	$	794,739		$	3,050,947		$	115,984		$	(20,414	)	$	(549,883	)	$	—		$	3,391,373

F-88

Ecopetrol S.A. and Subsidiaries

Notes to the Consolidated Financial Statements (continued)

33. Differences between Colombian Governmental Entity accounting principles and U.S. GAAP (Continued)

xxiv. Segment information (Continued)

The following table illustrates sales by geographic zones:

Sales by Geographic Zones 2007

Zone	Products		Value	Participation
Colombia	Refined and Petrochemicals	$	16,002,997	71.7	%
United States of America	Crude oil and Refined		4,531,885	20.3	%
Central America and Caribbean	Crude oil and Refined		1,109,504	4.9	%
Europe	Crude oil and Refined		673,948	3.0	%
Rest of world	Crude oil and Refined		13,986	0.1	%
		$	22,332,320	100.0	%

Sales by Geographic Zones 2006

Zone	Products		Value	Participation
Colombia	Refined and Petrochemicals	$	11,300,001	61.4	%
USA (Export)	Crude oil and Refined		4,936,720	26.8	%
Central America and Caribbean (Export)	Crude oil and Refined		1,428,949	7.8	%
Europe (Export)	Crude oil and Refined		710,847	3.9	%
Other (Export)	Crude oil and Refined		13,448	0.1	%
		$	18,389,965	100.0	%

Sales of products by Segment 2007

Local Sales	Production		Refining Activities		Transportation		Corporate		Total
Medium distillates	$	18,997	$	4,870,376	$	—	$	—	$	4,889,373
Gasolines		748		3,345,612		—		—		3,346,360
Crude Oil		3,004,629		—		—		—		3,004,629
Other products		53,382		845,083		—		—		898,465
Services		88,371		49,646		677,938		5,242		821,197
Natural Gas		660,171		—		—		—		660,171
L.P.G.		18,649		586,103		—		—		604,752
Diesel and gasoline subsidies		2,958		1,775,092		—		—		1,778,050
Total local sales	$	3,847,905	$	11,471,912	$	677,938	$	5,242	$	16,002,997

F-89

Ecopetrol S.A. and Subsidiaries

Notes to the Consolidated Financial Statements (continued)

33. Differences between Colombian Governmental Entity accounting principles and U.S. GAAP (Continued)

Sales of products by Segment 2007

Foreign Sales	Production		Refining Activities		Transportation		Corporate			Total
Crude oil	$	4,476,137	$	—	$	—	$	—		$	4,476,137
FAEP		—		—		—		(316,497	)		(316,497	)
Fuel oil		—		1,560,399		—		—			1,560,399
Gasolines		—		269,248		—		—			269,248
Naftas		—		244,393		—		—			244,393
Jet fuel		—		71,378		—		—			71,378
Other products		37		10,970		—		13,258			24,265
Total foreign sales	$	4,476,174	$	2,156,388	$	—	$	(303,239	)	$	6,329,323

Sales of products by Segment 2006

Local Sales	Production		Refining Activities		Transportation		Corporate		Total
Medium distillates	$	23,222	$	4,844,128	$	—	$	—	$	4,867,350
Gasolines		439		3,467,656		—		—		3,468,095
Crude Oil		29,825		—		—		—		29,825
Other products		55,576		820,752		—		—		876,328
Services		98,206		26,805		666,495		3,058		794,564
Natural Gas		717,879		—		—		—		717,879
L.P.G.		22,073		523,887		—		—		545,960
Diesel and gasoline subsidies		—		—		—		—		—
Total local sales	$	947,220	$	9,683,228	$	666,495	$	3,058	$	11,300,001

Sales of products by Segment 2006

Foreign Sales	Production		Refining Activities		Transportation		Corporate			Total
Crude oil	$	3,670,080	$	—	$	—	$	—		$	3,670,080
FAEP		—		—		—		(774,160	)		(774,160	)
Fuel oil		—		2,256,064		—		—			2,256,064
Gasolines		—		625,027		—		—			625,027
Naftas		—		807,437		—		—			807,437
Jet fuel		—		372,012		—		—			372,012
Other products		—		133,504		—		—			133,504
Total foreign sales	$	3,670,080	$	4,194,044	$	—	$	(774,160	)	$	7,089,964

F-90

Ecopetrol S.A. and Subsidiaries

Notes to the Consolidated Financial Statements (continued)

33. Differences between Colombian Governmental Entity accounting principles and U.S. GAAP (Continued)

The net income of investees accounted for by the equity method was $8,695 in 2007, and in 2006 the net losses was $51 in the Black Gold Re Ltd Company.

The research and development costs and expenses charged to each income statement were $96,420 in 2007 and $70,197 in 2006 respectively.

xxv. RELATED PARTIES

In addition to the transactions disclosed in Note 15, Ecopetrol is controlled by the Colombian Government which owns a majority stake in the Company. Thus, Ecopetrol has numerous transactions with other government entities as well as state-owned companies in the ordinary course of its business. The most significant of these transactions are disclosed below:

FAEP – Ecopetrol was required to defer revenue into a stabilization fund by the Colombian government. However, this process ended in 2007, at which time Ecopetrol was required to remit all deferred revenue to the government. For more information about this transaction, please see Notes 11 and 33.

Subsidies - The Colombian government regulates the price at which refiners sell refined products to distributors located in Colombia. For each unit sold, the price received, for which revenue was recorded, was the regulated price which was less than what the Company could have received had it sold those products to customers located outside Colombia at market prices. In 2006, that difference amounted to $3,350,000. Effective, January 1, 2007, the Colombian government began reimbursing refiners for that difference in the form of a subsidy. The Company records that subsidy as revenue when earned. The amount of subsidy included in revenue in 2007 was $1,778,050.

Contribution of Nation in Kind – Decree 2625 of 2000 imposed contributions in kind (hydrocarbons) of the Colombian Nation that were recognized as cost of production until March 9, 2007. For more information on this transaction please see Notes 20 and 23.

Taxes – Ecopetrol recognizes taxes to the Government and municipalities where it has facilities. Taxes paid in 2007 and 2006 are disclosed in the cash flow statement.

Purchases of hydrocarbons from ANH – The Company purchases the physical product that the ANH receives from all producers in Colombia at prices set forth in the Law 756 of 2002 and Resolution 18-1709 of 2003, which reference international prices. For more information on this transaction please see Notes 1 and 23.

Sublease of BOMT contracts - Ecopetrol entered into a sublease agreement with a related party (ECOGAS) as described in note 33 xiii. During 2007 and 2006, under U.S. GAAP, Ecopetrol recognized losses amounting to $407,452 and $6,123, respectively as a result of this contract. In 2007, ECOGAS prepaid all installments associated with this contract. As a result of this prepayment, Ecopetrol recognized a contribution received in equity amounting to $74,546.

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Ecopetrol S.A. and Subsidiaries

Notes to the Consolidated Financial Statements (continued)

33. Differences between Colombian Governmental Entity accounting principles and U.S. GAAP (Continued)

The following table presents accounts receivable and payable with related parties as of December 31, 2007 and 2006:

	2007				2006
	Assets		Liabilities		Assets		Liabilities
Municipio de Barrancabermeja	$	30,919	$	21	$	19,367	$	—
E.S.P. Generadora y Comercializadora de Energía del Caribe S.A. - Gecelca		91,369		24,696		—		—
Empresa de Energía de Bogotá		169,611		—		9,838		—
Ministerio de Minas y Energía		636,551		—		—		—
Ministerio de Defensa		385		—		538		8
Ministerio de Hacienda y Crédito Público		4,385,079		101,554		747,010		—
Banco de la República		—		—		3,844,167		—
Instituto de Seguros Sociales ISS		812		494		713		1,111
E.S.P. Central Hidroeléctrica de Caldas S.A. - Chec		1,059		1,492		541		1,461
E.S.P. Termoemcali S.A.		1,501		1,915		970		2,343
Corporación Eléctrica de la Costa Atlántica S.A. - Corelca		—		9		19,143		21,856
Dirección de Impuestos y Aduanas Nacionales - DIAN		—		107,554		—		4,496
Ministerio de Transporte		24		—		24		—
Municipio de Cartagena		—		8		—		—
Agencia Nacional de Hidrocarburos		23		875		153,419		17
Municipio de Bogotá		707		—		707		—
	$	5,318,040	$	238,618	$	4,796,437	$	31,292

Other transactions with related parties during 2007 and 2006 are:

	2007				2006
	Income		Expenses		Income		Expenses
Municipio de Barrancabermeja	$	—	$	80,949	$	—	$	71,745
Ministerio de Minas y Energía		1,778,050		—		—		—
Ministerio de Defensa		—		10,928		—		12,196
Dirección de Impuestos y Aduanas Nacionales - DIAN		—		2,267,929		—		1,636,185
Ministerio de Transporte		—		22,572		—		—
Municipio de Cartagena		—		5,325		—		11,944
Agencia Nacional de Hidrocarburos		—		44,973		—		40,870
Municipio de Bogotá		—		12,179		—		10,190
Transelca		—		—		11,742		3,680
Invercolsa		9,219		—		—		—
Unidad de Planeación Minero Energética		—		2,885		—		—
Contraloría General de la República		—		25,934		—		—
	$	1,787,269	$	2,473,674	$	11,742	$	1,786,810

Agreements

Set forth below is a description of material related party agreements.

F-92

Ecopetrol S.A. and Subsidiaries

Notes to the Consolidated Financial Statements (continued)

33. Differences between Colombian Governmental Entity accounting principles and U.S. GAAP (Continued)

Ocensa

We entered into the following agreements with Ocensa, a company in which we have a 35.3% equity interest:

In March 1995, we entered into an agreement for the transportation of crude oil through the Ocensa pipeline. Pursuant to the terms of the agreement, we are required to make monthly payments that vary depending on the volumes of crude oil we transport through the pipeline and a tariff calculated by Ocensa on the basis of Ocensa’s financial projections and their expected volumes of crude oil. In 2007, payments made by us under this agreement amounted to US$245.7 million. This agreement expires in December 2093 or upon liquidation of Ocensa.

In December 1995, we leased the Porvenir and Miralflores terminals to Ocensa. Pursuant to the terms of the agreement we receive monthly payments of approximately US$590,000 plus applicable taxes. The duration of the agreement is indefinite.

In November 1996, we leased the Cravo Norte port to Ocensa. Pursuant to the terms of the agreement we receive monthly payments of US$25,000, plus applicable taxes. The duration of this agreement is indefinite.

In September 1999, we entered into a joint operation agreement for the TLU-3 Coveñas buoy with Ocensa, ODC and the Cravo Norte joint venture. Pursuant to the terms of the agreement we are required to make monthly payments of a fixed amount of US$75,000 plus a variable amount depending of the volumes exported through the buoy. There have been no variable payments in the last three years. The duration of this agreement is indefinite.

In December 1999, we entered into an operation and maintenance agreement for the Porvenir, Miralflores and Vasconia terminals. Pursuant to the terms of the agreement we receive monthly payments of approximately US$370,000 plus applicable taxes. This agreement expires on December 1, 2010.

In December 2004 we entered into a natural gas supply agreement. Pursuant to the terms of the agreement we receive variable monthly payments based on the volumes of natural gas delivered and a fixed tariff. During 2007, we receive payments for approximately US$600,000. This agreement expires in May 2008 but may be extended for six months.

Oleoducto de Colombia S.A. or ODC

We entered into the following agreements with ODC, a company where we have a 43.85% equity interest:

In July 1992, we entered into a take-or-pay agreement for the transportation of hydrocarbons. Pursuant to the agreement we must pay a previously agreed tariff over the volume of hydrocarbons transported. The duration of this agreement is indefinite.

In August 1992, we entered into an operation and maintenance agreement for the Vasconia and Coveñas terminals. Pursuant to the terms of the agreement, ODC is required to make monthly payments amounting to approximately US$1.1 million per year plus any other expenses incurred by us in the performance of the agreement, including a variable surcharge between 5% and 12% on such expenses, plus any applicable taxes. The duration of this agreement is indefinite.

In March 2007, we entered into a services agreement to guarantee the protection and safety of the Cusiana-Coveñas and Vasconia-Coveñas pipeline systems. Under the terms of the agreement, ODC must pay us Ps$51 million per year. This agreement expires in March 2011.

In July 2006, we entered into an operation and maintenance agreement for the Caucasia Station and the Vasconia-Coveñas pipeline system. Pursuant to the terms of the agreement, ODC is required to make monthly payments of US$508,500 per year, plus any other expenses incurred by us in the performance of the agreement, including a variable surcharge of between 5% and 12% on such expenses, plus any applicable taxes. The duration of this agreement is indefinite.

F-93

Ecopetrol S.A. and Subsidiaries

Notes to the Consolidated Financial Statements (continued)

33. Differences between Colombian Governmental Entity accounting principles and U.S. GAAP (Continued)

Refinería de Cartagena S.A.

In April 2007, we entered into a maintenance and administration agreement for the Cartagena refinery with Refinería de Cartagena S.A., a company in which we have a 49.0% equity interest. Pursuant to the terms of the agreement we provide them with maintenance and administration services and Refinería de Cartagena S.A. pays us a monthly fee equal to Ps$2.9 billion and a variable annual fee that may not exceed Ps$6.96 billion. This agreement expires in April 2011 and may be extended for additional one-year periods until the upgrade and modernization of the Cartagena refinery’s facilities is completed.

On February 1, 2008 we extended a ten-month commercial offer to Refinería de Cartagena for the supply of crude oil. Pursuant to the terms of the offer, 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. The purchase price for the delivered volumes is equal to an international benchmark index, subject to certain adjustments. 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. At March 30, 2008, we had received aggregate payments of approximately Ps$1,161 billion for the supplied amounts. This offer expires in November, 2008 but is renewable for an additional one-year period.

Other Agreements

We entered into a supply agreement with Ecodiesel S.A., a company in which we have a 50.0% equity interest. This agreement is not yet operative and will begin once the Ecodiesel plant starts its activities. Pursuant to the terms of the agreement, Ecodisesel must deliver and we must purchase specific amounts of biodiesel each month. Payments vary depending on the purchased volumes of biodiesel. This agreement expires on December 31, 2017.

In April 2002, we entered into a service agreement with Sociedad Colombiana de Servicios Portuarios S.A. or Serviport, a company in which we have a 49% equity interest. Pursuant to the terms of the agreement, Serviport assists us in our maritime operations in the Coveñas port in exchange for which we pay it approximately US$155,000 per month. This agreement expires on November 30, 2008 but is renewable annually.

F-94

Ecopetrol S.A. and Subsidiaries

Notes to the Consolidated Financial Statements (continued)

33. Differences between Colombian Governmental Entity accounting principles and U.S. GAAP (Continued)

xxvi. FAIR VALUE OF FINANCIAL INSTRUMENTS

The following table presents the carrying amounts and estimated fair values under U.S. GAAP of the Company’s financial instruments at December 31, 2006 and 2007. The fair value of a financial instrument is the amount at which the instrument could be exchanged in a current transaction between willing parties.

	2007				2006
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Financial assets:
Cash and cash equivalents	$	8,007,282	$	8,007,282	$	2,338,663	$	2,338,663
Investments		4,945,367		5,245,034		3,659,063		3,889,634
Accounts/notes receivable		2,513,429		2,475,429		2,841,695		2,048,050
Direct finance lease receivable		—		—		1,397,004		1,383,128
Petroleum Stabilization Fund (FAEP)		—		—		3,844,167		3,844,167
Financial liabilities:
Financial obligations		72,491		72,491		347,536		347,536
Accounts payable		1,485,650		1,485,650		1,630,246		1,630,246
Capital lease	$	523,029	$	398,183	$	673,868	$	555,136

The carrying amounts shown in the table are included in the condensed U.S. GAAP balance sheets found in Note 33.

The following methods and assumptions were used to estimate the fair value of each class of financial instruments:

Cash and cash equivalents; Petroleum Stabilization Fund “FAEP”, Financial Obligations, Accounts Payable: The carrying amounts approximate fair value because of the short maturity of these instruments.

Investment securities: The fair values of debt securities (both available-for-sale and held-to-maturity investments) and equity securities are based on quoted market prices at the reporting date for those or similar investments.

Accounts/Notes Receivable and Direct Finance Lease: The fair value is determined as the present value of expected future cash flows discounted at the rate offered by financial institutions in a current or savings account in Colombia.

Capital Lease: The fair value is determined as the present value of expected future payments discounted at Ecopetrol’s borrowing rate.

xxvii. SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)

In accordance with the requirements of the United States Securities and Exchange Commission (SEC) and Statement of Financial Accounting Standards No. 69, “Disclosures about Oil and Gas Producing Activities” (“SFAS 69”), this section provides supplemental information on oil and gas exploration and producing activities of the Company. The information included in items (i) through (iii) provides historical cost information pertaining to costs incurred in exploration, property acquisitions and development, capitalized costs and results of operations. The information included in items (iv) and (v) present information on Ecopetrol’s estimated net proved reserve quantities, standardized measure of estimated discounted future net cash flows related to proved reserves, and changes in estimated discounted future net cash flows.

The following information corresponds to Ecopetrol’s oil and gas producing activities at December 31 of 2007 and 2006 in

F-95

Ecopetrol S.A. and Subsidiaries

Notes to the Consolidated Financial Statements (continued)

33. Differences between Colombian Governmental Entity accounting principles and U.S. GAAP (Continued)

direct and joint operations. The financial and reserve information has been prepared in accordance with U.S. GAAP.

Table i – Capitalized costs relating to oil and gas producing activities

	2007			2006
Natural and environmental properties – proved properties	$	7,026,558		$	5,718,373
Wells, equipment and facilities – property, plant and equipment		3,899,238			3,599,959
Construction in progress		1,108,023			982,613
Accumulated depreciation, depletion and amortization		(6,460,233	)		(5,747,565	)
Net capitalized costs	$	5,573,586		$	4,553,380

In accordance with SFAS 143, Accounting for Asset Retirement Obligations (“SFAS No. 143”) during 2007 and 2006 an additional $175,114 and $389,388 was added to the cost basis of oil and gas wells for wells drilled.

The company does not capitalize general and administrative expenses within exploration and production activities.

Table ii – Costs incurred in oil and gas exploration and development activities

Costs incurred are summarized below and include both amounts expensed and capitalized in the corresponding period, and has not acquired reserves either in-situ.

	2007		2006
Exploration costs	$	497,737	$	184,838
Development costs		2,163,444		1,058,837
Total costs incurred	$	2,661,181	$	1,243,675

The exploration costs include the expenses related to obtain the exploration rights given by ANH.

Table iii - Results of operations for oil and gas producing activities

	2007			2006
Net revenues from production
Sales	$	8,324,078		$	4,617,300
Inter-company transfers		2,396,825			2,282,949
Total net revenues		10,720,903			6,900,249
Operating expenses
Cost of production		5,200,507			4,395,714
Depreciation, depletion and amortization		819,138			625,089
Exploration costs		383,884			142,350
Other operating costs		256,645			554,693
Total operating expenses		6,660,174			5,717,846
Results of operations before income taxes		4,060,729			1,182,403
Income taxes		(1,380,648	)		(413,841	)
Results of operations net of income taxes	$	2,680,081		$	768,562

In accordance with SFAS No. 143, the combined depletion and accretion expense related to asset retirement obligations that were recognized during 2007 and 2006 in depreciation, depletion and amortization expense was approximately $79,256 and

F-96

Ecopetrol S.A. and Subsidiaries

Notes to the Consolidated Financial Statements (continued)

33. Differences between Colombian Governmental Entity accounting principles and U.S. GAAP (Continued)

$71,708, respectively.

The Company’s results of operations from oil and gas producing activities for the years ending December 31, 2007 and 2006 are shown above. The Company transferred approximately 43% and 56% of its crude oil and gas production; percentages are based on the sales value in Colombian pesos, to inter-company business units in 2007 and 2006, respectively. Using volumes, those transfers were 48% and 60%, respectively, in 2007 and 2006. The inter-company transfers were recorded at values equal to the Company’s cost of production.

Production costs are lifting costs incurred to operate and maintain productive wells and related equipment and facilities, including such costs as operating labor, materials, supplies, and fuel consumed in operations and the costs of operating natural gas liquids plants. Production costs also include administrative expenses and depreciation and amortization of equipment associated with production activities.

Exploration expenses include the costs of geological and geophysical activities and non-productive exploratory wells. Depreciation and amortization expenses relate to assets employed in development activities. In accordance with SFAS 69, income taxes are based on statutory tax rates, reflecting allowable deductions. Interest income and expense are excluded from the results reported in this table.

Table iv – Reserve quantities information

The estimates for proved oil and gas reserves used in the preparation of the consolidated financial statements were prepared by Ecopetrol’s engineers and approved by the reserves internal committee. Such estimates are in accordance with guidelines established by the SEC and the Financial Accounting Standards Board, which require that reserve reports be prepared under economic and operating conditions existing at the registrant’s year end with no provision for price and cost escalations except by contractual arrangements. Future cash inflows were computed by applying year-end prices to the year-end quantities of proved reserves. Future development, abandonment and production costs were computed by estimating the expenditures to be incurred in developing, producing, and abandoning proved oil and gas reserves at the end of the year, based on year-end costs. Future income taxes were computed by applying statutory tax rates to the estimated net pre-tax cash flows after consideration of tax basis and tax credits and carry forwards. Discounted future net cash flows are calculated using 10% mid period discount factors. This discounting requires a year-by-year estimate of when the future expenditures will be incurred and when the reserves will be produced. All of the Company’s activities and reserves are located in Colombia.

The information provided does not represent management’s estimate of the Company’s expected future cash flows or value of proved oil and gas reserves. Estimates of proved reserve quantities involve uncertainty and change over time as new information becomes available.

The arbitrary valuation methodology prescribed under SFAS 69 requires assumptions as to the timing and amount of future development and production costs. The calculations are made as of December 31 each year and should not be relied upon as an indication of the Company’s future cash flows or the value of its oil and gas reserves.

Proved oil and gas reserves are the estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved reserves do not include additional quantities recoverable beyond the term of the concession or contract, or that may result from extensions of currently proved areas, or from application of secondary or tertiary recovery processes not yet tested and determined to be economic.

Proved developed reserves are the quantities expected to be recovered from existing wells with existing equipment and operating methods. Proved undeveloped reserves are those volumes which are expected to be recovered as a result of future investments in drilling, re-equipping existing wells and installing facilities necessary to deliver the production from these

F-97

Ecopetrol S.A. and Subsidiaries

Notes to the Consolidated Financial Statements (continued)

33. Differences between Colombian Governmental Entity accounting principles and U.S. GAAP (Continued)

reserves.

In some cases, substantial new investments in additional wells and related facilities will be required to recover these proved reserves. Due to the inherent uncertainties and the limited nature of reservoir data, estimates of reserves are subject to change as additional information becomes available.

The Colombian Nation is the owner of all mineral interests located in Colombia. The Company and, by extension of joint association contracts, its partners, are given the right to explore, develop, produce and sell those reserves, but do not own them. The reserve quantities and their standardized measure, presented in the following tables, represent those reserves and their estimated value that the Company has the right to extract and sell.

The following table sets forth proved oil and gas reserves together with their changes as of and for the years ended December 31, 2007 and 2006 (oil in million barrels, gas in billion cf, gas converted to million barrels at 5.615 billion cf per million barrels):

	2007						2006
	Oil		Gas		Total		Oil		Gas		Total
	million		billion		million		million		billion		million
	barrels		cf		boe		barrels		cf		boe
Proved reserves:
Beginning of period	921.2		1,860.4		1,252.5		930.9		1,816.6		1,254.4
Revisions	25.9		74.0		39.0		77.4		108.8		96.8
Extensions and discoveries	9.8		164.1		39.0		8.6		48.7		17.3
Production	(99.6	)	(118.8	)	(120.7	)	(95.7	)	(113.6	)	(115.9	)
End of period	857.4		1,979.6		1,209.9		921.2		1,860.4		1,252.5
Proved developed reserves:
Beginning of period	610.7		995.4		788.0		692.3		1,162.2		899.3
End of period	651.3		1,210.5		866.9		610.7		995.4		788.0

This note to the Ecopetrol’s consolidated financial statements presents the Company’s total proved oil and gas reserves together with the changes therein as of and for the years ended December 31, 2007 and 2006. The estimate of reserves at December 31, 2007 was prepared under Ecopetrol’s policy, using average prices for 2007, which is acceptable in Colombia but differ under US GAAP, which requires the calculation of reserves using year-end prices. The estimate of reserve at December 31, 2006 was prepared used a non commercialized natural gas reserves and different technical parameters used to calculate the heavy crude oil proved reserves. As a result, the quantity of estimated proved reserves under Ecopetrol’s Policy differs from the estimated quantities of proved reserves in accordance with US GAAP and SEC Rule 4-10 of Regulation S-X. The following table presents the difference in total proved reserves at December 31, 2007 and 2006:

F-98

Ecopetrol S.A. and Subsidiaries

Notes to the Consolidated Financial Statements (continued)

33. Differences between Colombian Governmental Entity accounting principles and U.S. GAAP (Continued)

2007
	Quantities under	Quantities under
	Ecopetrol’s Policy	US GAAP	Difference
Oil, million of barrels	833.2	857.4	(24.2	)
Gas, billion cf	1,919.6	1,979.6	(60.0	)
Total, million boe	1,175.1	1,209.9	(34.8	)
2006
	Quantities under	Quantities under
	Ecopetrol’s Policy	US GAAP	Difference
Oil, million of barrels	972.7	921.2	51.5
Gas, billion cf	2,466.7	1,860.4	606.3
Total, million boe	1,412.0	1252.5	159.5

Table v – Standardized measure of discounted future net cash flows relating to proved oil and gas quantities and changes therein

The standardized measure of discounted future net cash flows, related to the above proved crude oil and natural gas reserves, is calculated in accordance with the requirements of SFAS 69. Estimated future cash inflows from production are computed by applying year-end prices for oil and gas to year-end quantities of estimated net proved reserves.

	2007			2006
	(In millions of Colombian pesos)
Future cash inflows	$	160,896,123		$	106,443,313
Future costs
Production		(51,432,611	)		(35,801,923	)
Development		(4,619,633	)		(9,131,531	)
Income Taxes		(27,196,665	)		(21,636,373	)
Abandonment costs		(14,411,180	)		(1,495,580	)
Future net cash flow		63,236,034			38,377,906
10% discount factor		(20,220,499	)		(14,149,038	)
Standardized measure of discounted net cash flows	$	43,015,535		$	24,228,868

The following are the principal sources of change in the standardized measure of discounted net cash flows:

F-99

Ecopetrol S.A. and Subsidiaries

Notes to the Consolidated Financial Statements (continued)

33. Differences between Colombian Governmental Entity accounting principles and U.S. GAAP (Continued)

	2007			2006
	(In millions of Colombian pesos)
Standardized measure of discounted future net cash flows: beginning of year	$	24,228,868		$	27,765,077
Increases (decreases)
Sales net of production costs		(5,520,395	)		(2,504,535	)
Development costs incurred during the period		2,163,444			1,058,837
Increases (decreases) due to passage of time		2,422,887			2,776,508
Net change in sales prices net of production costs		16,408,023			(10,457,035	)
Revision of quantity estimates		1,923,511			2,899,211
Extensions and discoveries		1,181,380			318,459
Net change in income taxes		(4,840,649	)		5,186,403
Changes in estimated future development costs		1,683,660			(4,922,605	)
Changes of production rates (timing) and other		3,364,806			2,108,548
Net increase (decrease)		18,786,667			(3,536,209	)
Standardized measure of discounted future net cash flows: end of year	$	43,015,535		$	24,228,868

F-100

Ecopetrol S.A.

Finance Vice-presidency

Unit of Accounting and Tax Information

UNCONSOLIDATED FINANCIAL STATEMENTS

At June 30, 2008 and December 31, 2007

And for the six-month period ended on June 30, 2008 and 2007

F-101

Ecopetrol S.A.

Unconsolidated Financial Statements

At June 30, 2008 and December 31, 2007

And for the six-month period ended on June 30, 2008 and 2007

Contents

Unconsolidated Financial Statements

Unconsolidated Balance Sheets	F-103
Unconsolidated Statements of Financial, Economic, and Social Activities	F-104
Unconsolidated Statements of Changes in Equity	F-105
Notes to the Unconsolidated Financial Statements	F-106

F-102

Ecopetrol S.A.

Unconsolidated Balance Sheets

	At June 30, 2008 (unaudited)		At December 31, 2007
	(In millions of Colombian pesos)
Assets
Current assets::
Cash and cash equivalents (Notes 2 and 3)	$	3,175,542	$	3,466,184
Investments (Notes 2 and 4)		6,365,244		5,954,502
Accounts and documents receivable, net (Notes 2 and 5)		5,044,689		2,269,645
Inventories (Note 6)		1,557,878		1,298,792
Advances and deposits (Notes 2 and 7)		1,926,046		1,978,599
Pension plan assets (Note 11)		493,933		508,813
Prepaid expenses (Note 8)		24,701		12,590
Total current assets		18,588,033		15,489,125
Non-current assets:
Investments (Notes 2 and 4)		6,983,319		4,125,858
Accounts and notes receivable, net (Note 5)		195,539		202,565
Property, plant and equipment, net (Note 9)		6,586,070		6,151,951
Natural and environmental properties, net (Note 10)		5,290,891		5,128,917
Pension plan assets (Note 11)		9,025,814		8,986,861
Deferred charges (Notes 12)		1,888,435		1,963,156
Other assets (Note 13)		1,227,665		399,401
Valuations (Note 19)		5,575,963		5,647,382
Total assets	$	55,361,729	$	48,095,216
Liabilities and equity
Current liabilities:
Financial obligations		—	$	3,569
Accounts payable and related parties (Notes 2 and 14)		6,198,466		1,141,161
Taxes payable (Note 15)		3,780,049		2,892,020
Labor and pension plan obligations (Note 16)		569,804		586,964
Estimated liabilities and provisions (Note 17)		1,136,726		1,435,943
Total current liabilities		11,685,045		6,059,657
Non-current liabilities
Labor and pension plan obligations (Note 17)		10,375,970		10,316,041
Estimated liabilities and provisions (Notes 2 and 17)		2,991,083		2,732,554
Other long-term liabilities (Note 18)		2,042,158		2,179,321
Equity (Note 19 and see accompanying statement)		28,267,473		26,807,643
Total liabilities and shareholders’ equity	$	55,361,729	$	48,095,216
Memorandum accounts (Note 20)	$	78,759,096	$	64,180,245

See accompanying notes.

F-103

Ecopetrol S.A.

Unconsolidated Statements of Financial, Economic, and Social Activities (unaudited)

	For the six-month period ended June 30
	2008			2007
	(In millions of Colombian pesos)
Revenue (Note 21):
Local sales	$	10,793,748		$	7,185,312
Foreign sales:		5,821,592			2,525,228
Total revenue		16,615,340			9,710,540
Cost of sales (Note 22)		7,849,216			5,333,411
		8,766,124			4,377,129
Operating expenses (Note 23):
Administration		167,708			141,592
Selling		592,120			435,523
Operating income		8,006,296			3,800,014
Non-operating income (expenses):
Financial income, net (Note 24)		467,457			(437,674	)
Pension expenses (Notes 16 and 25)		(583,137	)		(429,995	)
Inflation gain (Note 26)		20,221			26,119
Other income (expenses), net (Note 27)		(3,214	)		(127,334	)
Income before income tax		7,907,623			2,831,130
Income tax (Note 15):		2,257,626			786,771
Net income	$	5,649,997		$	2,044,359
Net Income per share	$	139.60		$	85.75

See accompanying notes.

F-104

Ecopetrol S.A.

Unconsolidated Statements of Changes in Equity (unaudited)

(Amounts expressed in millions of Colombian pesos, except for dividends per share which are expressed in unit pesos)

For the six-month period ended on June 30, 2008 and 2007

	Subscribed and Paid-in Capital		Additional Paid-in Capital		Contribution of Nation in Kind			Legal and Other Reserves			Incorporated Institutional Equity		Adjustment in Conversion of Subsidiaries		Valuation Surplus			Retained Earnings			Total Equity
Balance at December 31, 2006	$	4,244,943	$	—	$	4,419,110		$	2,994,712		$	48,857	$	—	$	5,736,751		$	3,391,373		$	20,835,746
Distribution of dividends ($85.75 per share)		—		—		—			(1,423,163	)		—		—		—			(3,052,236	)		(4,475,399	)
Appropriation to reserves		—		—		—			339,137			—		—		—			(339,137	)		—
Hydrocarbon reserves contributed by the Colombian Nation		4,851,215		—		(4,851,215	)		—			—		—		—			—			—
Distribution of contributions to ANH						432,105																432,105
Appropriation for investment programs		39		—		—			—			37,217		—		—			—			37,256
Valuation surplus		—		—		—			—			—		—		(177,300	)		—			(177,300	)
Net income		—		—		—			—			—		—		—			2,044,359			2,044,359
Balance at June 30, 2007		9,096,197		—		—			1,910,686			86,074		—		5,559,451			2,044,359			18,696,767
Balance at December 31, 2007		10,113,334		3,850,814		—			1,910,686			108,730		303		5,647,382			5,176,394			26,807,643
Distribution of dividends ($115 per share)		—		—		—			4,415			—		—		—			(4,658,755	)		(4,654,340	)
Subscribed capital receivable and additional paid-in capital		3,372		492,949		—			—			—		—		—			—			496,321
Appropriation to reserves		—		—		—			517,639			—		—		—			(517,639	)		—
Adjustment in conversion of subsidiaries		—		—		—			—			—		36,603		—			—			36,603
Addition to incorporated institutional equity		—		—		—			—			2,668		—		—			—			2,668
Valuation surplus		—		—		—			—			—		—		(71,419	)		—			(71,419	)
Net income		—		—		—			—			—		—		—			5,649,997			5,649,997
Balance at June 30, 2008	$	10,116,706	$	4,343,763	$	—		$	2,432,740		$	111,398	$	36,906	$	5,575,963		$	5,649,997		$	28,267,473

See accompanying notes.

F-105

Ecopetrol S.A.

Notes to the Non Consolidated Financial Statements (unaudited)

(Amounts expressed in millions of Colombian pesos, unless otherwise stated, except amounts in

other currencies, exchange rates and income per share, which are expressed in unit pesos – though out these

financial statement pesos or Ps refer to Colombian pesos and US Dollar refer to United States Dollar)

1. Economic Entity and Principal Financial Policies and Practices

Reporting Entity

Ecopetrol S.A., (hereinafter Ecopetrol or the Company) was organized by Law 165 of 1948 and transformed through Extraordinary Decree 1760 of 2003 (added by Decree 409 of 2006) and Law 1118 of 2006 into a state-owned company by shares and then into a mixed economy entity of a commercial character, at national level, related to the Ministry of Mines and Energy, for an indefinite period. Ecopetrol’s corporate purpose is the development, in Colombia or abroad, of commercial or industrial activities corresponding to or related with exploration, production, refining, transportation, storage, distribution, and selling of hydrocarbons, their by-products and associated products, and of subsidiary operations, connected or complementary to these activities in accordance with applicable regulations. Ecopetrol’s principal domicile is Bogotá, D.C. and it may establish subsidiaries, branches and agencies in Colombia or abroad.

By means of the transformation Decree 1760 of June 27, 2003, the integral administration of the hydrocarbon reserves owned by the Colombian Nation (the Nation), and the administration of non-strategic assets, represented by shares and the participation in companies were separated from Ecopetrol. In addition, Ecopetrol’s basic structure was changed and two entities were created: a) the Agencia Nacional de Hidrocarburos (ANH) was created to hereinafter issue and develop the Colombian petroleum policy (formerly the responsibility of Ecopetrol), and b) Sociedad Promotora de Energía de Colombia S.A. which received the non-strategic assets owned by Ecopetrol.

Law 1118 of December 27, 2006 changed the legal nature of Ecopetrol S.A., and authorized the Company to issue shares to be placed in the equity market and acquired by Colombian individuals or legal entities. Once the shares were issued and placed, fully or partially, the Company became a Mixed Economy Entity of a commercial nature, at a national level, controlled by the Ministry of Mines and Energy.

Ecopetrol is a shareholder in Oleoducto de Colombia S.A. with a 44% interest and 35% interest in Oleoducto Central S.A. (Ocensa S.A.)

The company is a joint venture partner in two association contracts (joint operating agreements) with pipelines as part of production facilities: 49% on the Alto Magdalena pipeline (operated by the Colombian branch of Hocol S.A.) and 50% on the Caño Limón-Coveñas pipeline (operated by Ecopetrol).

Association contracts with private partners have an exploration phase of three years which may be extended to six years, with various obligations in accordance with each contract. If exploration is successful and the field commerciality declared, Ecopetrol reimburses, from the field’s production, direct drilling and development costs of producing wells, in proportion to its working interest in the contract.

The development and production phase of association contracts lasts 22 years from completion date of the exploration period, not to exceed a total contract period of 28 years, unless a bilateral contract extension is agreed. Production after deducting royalties of 20% is in most cases allocated as follows: 50% among the private partners and the remaining 50% to Ecopetrol. Production costs are allocated in the same proportions.

F-106

Ecopetrol S.A.

Notes to the Non Consolidated Financial Statements (unaudited)

Costs and expenses incurred, and investments and obligations acquired in complying with the operation of commercial fields and other income received, are accrued by the operator of the joint account and billed or distributed monthly, in accordance with the percentages established under each association contract.

At the end of the association contracts subscribed before January 1, 2004, private companies shall pass without cost to Ecopetrol all producing wells, facilities and other real estate and assets acquired in executing the contracts.

Under the sole-risk system, Ecopetrol may not initially accept the existence of a commercial field and, therefore, the partners are entitled, at their own expense and risk, to execute the work deemed necessary for field production and to recover up to 200% of the total cost incurred in this work on their own account and risk. Reimbursement is made from hydrocarbons produced less the respective royalties. The other conditions are the same as those applied to the regular association contracts with declared commerciality, once the stated reimbursement is achieved.

Effects of inflation on financial Information

The accompanying unconsolidated financial statements have been prepared from the accounting records, which are maintained under the historical cost convention, modified since 1992 to comply with the legal provisions of the Contaduría General de la Nación (CGN) to recognize the effect of inflation on non-monetary balance sheet accounts until December 31, 2001, including equity. The CGN authorized Ecopetrol not to apply the inflation adjustment system from January 1, 2002.

Principles of Consolidation

The preparation of the unconsolidated financial statements was carried out under accounting standards and principles contained in the Régimen de Contabilidad Pública (RCP) issued by the CGN and other legal dispositions. These principles may differ in certain aspects from those established by other standards and other control authorities and the opinions on specific matters issued by CGN are considered mandatory. The accrual method was applied for the accounting recognition of financial, economic and social facts.

The unconsolidated financial statements were prepared by disposition of management to support the accounting information presented to the CGN, and does not require the preparation of the statement of cash flows.

Segments

The Company operates in five primary segments of activity: exploration and production, refining, transportation, corporate, and all other. RCP does not require disclosure of information by business segment.

Materiality Concept

An economic fact is material when due to its nature and amount, and taking into account the surrounding circumstances, knowing or not knowing it could significantly alter the economic decisions of informed users.

The unconsolidated financial statements include specific headings in accordance with legal requirements, or those representing 5% or more of total assets, current assets, total liabilities, current liabilities, working capital, equity and revenue, as appropriate. In addition, lower amounts are shown when they are deemed to contribute to a better interpretation of financial information.

F-107

Ecopetrol S.A.

Notes to the Non Consolidated Financial Statements (unaudited)

Use of Estimates

The preparation of the unconsolidated financial statements in accordance with RCP requires the Company’s management to make estimates and assumptions that could affect the recorded amounts of assets, liabilities, results of activities and the attached notes. These estimates are carried out following technical standards in compliance with current norms and legal dispositions. Current or market values could differ from such estimates.

Transactions in Foreign Currency

Transactions in foreign currency are entered into in accordance with applicable regulations and they are recorded at appropriate exchange rates on the transaction date. Balances denominated in foreign currency are reflected in Colombian pesos at the representative market exchange rates of $1,923.02 and $1,960.61 per US Dollar at June 30, 2008 and 2007, respectively.

The adjustment for exchange differences generated by foreign currency liabilities is recorded against results of operations, except when such adjustment is attributed to subsidiaries or investments recognized under the equity method, in which case affects equity, and to acquisition cost of assets in construction and up to the time these assets are placed in service, in which case affects the project itself.

The Company in developing its crude oil exploration and production activities can freely retain foreign currency received. In addition, it can acquire the foreign currency it requires in the local market to pay its foreign obligations.

Joint Operation Contracts

Joint venture or common-interest operation contracts are entered into between Ecopetrol and third parties in a property whereby one party is designated as the operator to carry out the activities in order to share the risk, secure capital, maximize operating efficiency and optimize the recovery of reserves. In these joint ventures, each party retains an undivided ownership in the property under operation. Ecopetrol records these investments, revenues, costs and expenses on a timely basis based on information reported by operators. When Ecopetrol directly operates the facilities, it records assets, revenues, costs and expenses, recognizing at the same time the accounts receivable of the third party for joint interest billings.

Cash and Cash Equivalents

Cash and cash equivalents are represented by cash in banks and highly liquid investments maturing within three months following their acquisition.

Financial Derivative Instruments

The Company enters into hedging agreements to protect itself from the fluctuations of international crude oil prices. The difference between amounts paid and income received under hedging operations is recognized as financial income (expense) in the Statements of Financial, Economic, Social and Environmental Activities. Ecopetrol does not use these financial instruments for speculative purposes.

Hedging operations are carried out with banks and other counterparties with a credit risk rating higher than or equal to A+.

The Company makes periodic evaluations based on the market risk of hedging operations and determines the need for extension or early termination of the subscribed contracts, when the result is ineffective vis-á-vis the hedging items. In the event of settlement, the financial and contractual effects are recognized in the results of operations.

F-108

Ecopetrol S.A.

Notes to the Non Consolidated Financial Statements (unaudited)

Investments

Investments are classified in: i) fixed yield investments; ii) special purpose investments (political); and iii) variable yield investments.

Fixed yield investments are initially recorded at cost and adjusted based on methodologies issued by the Superintendency of Finance, current at that moment.

Special purpose investments are debt securities issued by national and foreign entities, which are purchased in compliance with macroeconomic or internal policy. These investments include held to maturity and available for sale.

Held to maturity investments are adjusted based on the internal rate of return foreseen in the methodologies adopted by the Superintendency of Finance. Special purpose investments and available for sale may also be adjusted based on the methodologies adopted by the Superintendency of Finance for negotiable investments.

Variable yield investments are classified in controlled and none controlled entities. Investments in controlled entities are recognized at historical cost, whenever the cost is less than the intrinsic value. If the intrinsic value is less than the historical cost, the difference is adjusted under the equity method.

None controlled variable yield investments that are not negotiated on the stock exchange are recognized at historical cost, any adjustment resulting from differences in historical cost and intrinsic value is done periodically when necessary.

In compliance with “Noma Técnica Relativa a los Activos” of the RCP (Technical Norm Relative to Assets), foreign currency investments may be recognized applying the “Tasa representativa de mercado – TRM” (exchange rate) at the date of the transaction. The valuation may be reevaluated periodically on the same basis whenever the methodology for its computation does not consider it. For investments in foreign subsidiaries, the equity method may be applied in Colombian pesos before the actual conversion of the financial statements.

Provision for Doubtful Accounts

The provision for doubtful accounts is reviewed and updated periodically in accordance with the aged analysis of balances, and the evaluation of the recoverability evaluations of individual accounts. The Company carries out the necessary administrative and legal procedures to recover delinquent accounts receivable as well as the payment and collection of interest from customers that do not comply with payment policies.

Inventories

Inventories include assets extracted, transformed and acquired for any reason, to be sold, intended for transformation and consumed in the production process, or as a part of the rendering of services. Ecopetrol uses the perpetual inventory system to account for raw material.

Inventories are recorded at historical costs or at purchase cost, which includes direct and indirect charges incurred to prepare the inventory for sale or production conditions.

F-109

Ecopetrol S.A.

Notes to the Non Consolidated Financial Statements (unaudited)

This valuation is measured under the weighted average method, considering the following parameters:

• Crude oil inventories for the Company´s own production at production costs corresponding to the latest valuation available (May 2008).

• Crude oil purchases at acquisition costs, including transportation and delivery costs incurred.

• Finished goods inventory, at total production costs (at each refinery).

• Work in process inventory, at production costs.

• Raw material inventory, at weighted average cost.

The materials and supplies in joint ventures are controlled by the operator and reported in a joint account at acquisition costs (recorded in the original currency at average costs). Work in process inventories are recorded as an expense or are capitalized, depending of their nature.

Additionally, inventories of materials and supplies are valued at the lower of market value and the average cost; and the actual cost incurred for in-transit inventories. At the end of the year, provisions are calculated to recognize impairment, obsolescence, excess or slow-moving or for the loss of market value.

Property, Plant and Equipment and Depreciation

Property, plant and equipment is recorded at cost, adjusted for inflation until 2001, which includes financial expenses and exchange differences from foreign currency financing incurred until the asset is placed in service. When an asset is sold or retired, the adjusted cost and accumulated depreciation are written off and any gain or loss is recognized in results of operations.

Depreciation is calculated on the total acquisition cost using the straight-line method, based on the useful life of the assets. Annual depreciation rates used are:

	%
Buildings and pipelines	5
Plant and equipment	10
Transportation equipment	20
Computers	33.3

Any gain or loss on the sale or retirement of property, plant and equipment is recognized in results of operations in the transaction year. Normal disbursements for maintenance and repairs are charged to expense and those significant costs that improve efficiency or extend the useful life are capitalized.

Following the guidelines set forth by CGN within the RCP, the methodology used for the appraisal of property, plant and equipment was the actual value in use for going concern entities (VAU), for the economic valuation of assets, considering the current installation conditions and their useful life in production conditions and generation of revenues.

The net appraisal of property, plant and equipment includes the effect of devaluations against equity, originated by the excess between the net book value and the respective appraisal for plants and equipment of associated operations, refinery buildings and plants and transportation equipment and of the Colombian Oil Institute (a research department of Ecopetrol), as well as the provision when necessary.

F-110

Ecopetrol S.A.

Notes to the Non Consolidated Financial Statements (unaudited)

Natural and Environmental Properties

The Company applies a method similar to the internationally recognized successful efforts method of accounting for investments in exploration and production areas. These investments are amortized using the technical units-of-production method on the basis of proved developed reserves by field. The reserves are based on technical studies prepared internally by the Company’s Department of Reservoirs and approved by the Company´s reserves committee, which follow estimation methodologies recommended by international organizations of specialists in hydrocarbon reserves and SEC.

When a well is declared productive, in compliance with the information provided by the Exploration Vice-Presidency of Ecopetrol, tangible property (property, plant and equipment) is capitalized and intangible assets are recognized as an investment in natural and environmental properties.

When it is determined that a well located in an exploration zone has no proved reserves, it is considered a dry or not commercial well; thus, accumulated costs are expensed in the same year this is known. Costs incurred in geology, seismic and similar activities are recorded in the income statement when incurred.

The estimation of hydrocarbon reserves is subject to several uncertainties inherent to the determination of proved reserves, production recovery rates, the timeliness with which investments are made to develop the reservoirs and the degree of maturity of the fields.

The Company recorded as reservoirs within the account of nature and environment properties the contributions of the Nation represented by crude oil and natural gas reserves deriving from the reversals of concessions of oilfield areas in favor of the Nation, given before the effectiveness of Decree 1760 of 2003. Depletion is calculated using the units of production basis.

Decree 727, issued on March 7^th, 2007 replaces Decree 2625 of 2000, and issued norms for valuation and accountability of hydrocarbon reserves belonging to the Nation. Additionally, it mandates Ecopetrol to recognize the rights of exploration and production of hydrocarbons which the Company is entitled.

Impairment of Long-Lived Assets

At the end of each year, the net value of long-lived assets held and in use is reviewed, including those to be dismantled, when circumstances or changes occur indicating that the book value may not be recoverable. The recording of provisions usually coincides with the formalization of an action plan by Ecopetrol, including, among others, the offer of such assets to third parties.

Pension Plan Assets and Other Funds

Commercial trusts consist of funds with a specific purpose given to pension fund trusts for the payment of pension obligations. Other funds also include trust to cover unexpected losses of oil equipment. Yields are estimated based on the valuation of market prices and the method established by the Financial Superintendence of Colombia.

Petroleum Stabilization Savings Fund FAEP

Law 1151 of 2007 implemented by means of Decree 3238 of August 27, 2007, determined that the accounts owned by Ecopetrol in the FAEP belonged to the Nation, represented by the Ministry of Finance and Public Credit. These amounts were recognized as restricted funds in the financial statements of Ecopetrol until August 2007.

F-111

Ecopetrol S.A.

Notes to the Non Consolidated Financial Statements (unaudited)

Prior to August 2007, the FAEP was a restricted fund that was only recorded as revenue for Ecopetrol when the Central Bank reimbursed to Ecopetrol actual cash as revenue of decreases in the production levels of the Cusiana, Cupiagua and Caño Limón fields. In addition, amounts in the FAEP could not be used as a guarantee for loans before its actual release by the Central Bank.

Deferred Charges

Deferred charges include major repairs of plant and equipment and cost incurred in an incremental production contract, which are amortized using the straight-line method over estimated useful lives ranging from two to five years, when such costs will generate benefits and by the unit of production basis, respectively.

Monetary correction attributable to non-monetary accounts (including equity) related to exploration and development activities, was recorded as a deferred asset or liability through December 31, 2001 and was transferred to results of operations during the amortization and/or depreciation period of the assets originating it.

Other Assets

Other assets include intangibles including goodwill, which corresponds to the difference between the acquisition price and the intrinsic value of equity investments. Goodwill reflects the economic benefit from the investment, attributed to its name reputation, specialized labor, credit risk assessment, location, and new business development expectancies, etc.

Goodwill is amortized based on methodologies using the technical value during the life of the investment.

Advances received from Ecogas for BOMT Contracts (Build, Operate, Maintain and Transfer)

As a result of the recognition of an account receivable from Ecogas and following specific instructions from CGN, the Company recognized as deferred income the net present value of all future payments scheme, in connection with Ecopetrol´s liability related to BOMT contractors. These liabilities are due in 2017, the year when the contractual obligations end. Due to the payment of this amount in 2007, the deferred income was recognized as part of other income.

Valuations

a. Investments

Valuations and valuation surplus correspond to the difference between the historical cost and the investment’s intrinsic value or its price quoted on a stock exchange.

b. Property, Plant and Equipment

Valuations and valuation surplus of property, plant and equipment included as part of equity correspond to the difference between net book value and the market value for real estate or the current value in use for plant and equipment, determined by specialists registered with the Colombian Real Estate Control entity or by suitable technical personnel, respectively. If the technical study is lower than the carrying value, the difference is recorded as a lesser value of the valuation surplus until it is fully depleted, and if needed a provision is made.

F-112

Ecopetrol S.A.

Notes to the Non Consolidated Financial Statements (unaudited)

Income Tax

The provision for income tax was applied to income before income taxes applying the effective rate established on May 2008, equivalent to 28.55% for the six-month period ended on June 30, 2008.

The effect of timing differences involving the payment of a lower or higher income tax in the current year is recorded as a deferred tax credit or debit, respectively, provided that a reasonable expectation exists such differences will reverse and in the case of the deferred tax asset, that sufficient taxable income will be generated to recover the tax. The deferred tax balance was calculated at the rate of 33%.

Ecopetrol uses a special deduction benefit for investments in fixed - productive assets, equivalent to 40% of the effective capital expenditures made during the fiscal year. If assets are disposed or not used for revenue generating activities prior to the end of their useful lives, the Company may reimburse the proportional deduction previously requested in the income tax declaration for the period in which the event occurs.

Labor and Pension Obligations

The system for salaries and fringe benefits for Ecopetrol personnel is governed by the Collective Labor Agreement, Agreement 01 of 1977, and in the absence thereof, by the Labor Code. In addition to fringe benefits, Ecopetrol employees are entitled to receive additional benefits covered by previous regulations that depend both on the place, type of work, length of service, and basic salary. Annual interest of 12% is paid on accumulated severance amounts in favor of each employee and the payment of indemnities is provided for when special circumstances arise that result in the non voluntary termination of the contract, and in periods other than the qualifying period.

The actuarial calculation includes active employees with indefinite contract term, pensioners and heirs, for the pension, health care and education plan; temporary, active employees, and voluntary retirees, for pension bonuses. The calculation for pension bonuses is established and regulated in Decrees 1748 of 1995, 1474 of 1997 and 876 of 1998, and Law 100 of 1993.

All social benefits of employees who joined the Company before 1990 are the direct responsibility of Ecopetrol, without the involvement of the Colombian social security entity or institution. The cost of health services of the employee and his/her relatives registered with the Company is determined by means of the morbidity table, prepared on the basis of facts occurring during 2007. Likewise, the experience of Ecopetrol is considered for the calculation of educational allowances, based on the annual average cost of each business segment, subdivided in accordance with the class of studies: pre-school, primary, high school and university.

For employees who joined the Company as of the effectiveness of Law 50 of 1990, the Company makes periodic contributions for severance, pensions and labor related injuries to the respective funds that assume all these obligations. Likewise, Law 797 of 2003 determined that Ecopetrol employees who joined the Company as of January 29, 2003 will be subject to the provisions of the General Pension Regime.

Purchases of Hydrocarbons from ANH

The Company purchases the physical product that the ANH receives from all producers in Colombia at prices set forth in the Law 756 of 2002 and Resolution 18-1709 of 2003, which reference international prices.

Recognition of Income, Costs and Expenses

Income from crude oil and natural gas sales is recognized when product has been physically delivered to the buyer at the specific delivery or shipping point and when all risks and benefits have been transferred to the

F-113

Ecopetrol S.A.

Notes to the Non Consolidated Financial Statements (unaudited)

purchaser. Title is transferred to the buyer when products are delivered to the customer. Invoices are issued at this point and revenue is recognized. In the case of refined and petrochemical products, income is recognized when products are shipped by the refinery; subsequently, they are adjusted in accordance with the volumes actually delivered. Income from transportation services are recognized when products are transported and delivered to the buyer in accordance with the sale terms. In all other cases, income is recognized at the time it is earned and a true, probable and quantifiable right to demand its payment arises.

Before the effectiveness of Law 1151 of 2007, transfers made to the FAEP only constituted income for Ecopetrol insofar as the actual reimbursement by the Central Bank are realized as a result of reduction on the average production levels of the Cusiana, Cupiagua and Caño Limón fields, while the respective production costs are part of results when incurred. After such date of law 1151 there were no further transfers to the FAEP.

Late payment interest income on the collection of accounts receivable is recognized following prudence and realization principles.

Starting March 2007, subsidies for motor gasoline and Diesel are granted by the Nation to refiners such as Ecopetrol, as provided in Law 1111 of 2006 (Budgets Law). Revenues from said subsidies correspond to the difference between the regulated price and the international parity price, which are recorded by the Company as operating revenue, in accordance with Resolution No. 180414 of the Ministry of Mines and Energy of March 2007.

Costs of Sales and Expenses

Costs are recognized at historical costs for goods purchased for sale, accumulated production costs of goods and services.

Costs and expenses are recognized upon receipt of the goods or services or when there is certainty of the occurrence of an economic obligation. Fuel shortages and losses due to thefts and explosions are recorded as non operating expenses.

Abandonment of Fields

The Company recognizes the liability for future assets retirement obligations and its contra entry is a higher amount of the natural and environmental properties. The estimation includes plugging costs and abandonment of wells, dismantling of facilities and environmental recovery of areas and wells. Amortization is imputed to production costs, using the technical units-of-production method based on proved developed reserves. Changes resulting from new estimates of the liability for abandonment and environmental restoration are charged to the respective asset. The related liability is estimated in foreign currency as applicable and is adjusted for exchange difference at the end of each year.

When certain association contracts are extended, abandonment costs are assumed by the partners in the participation percentages established in each contract, which in turn are funded up to their total amount, after the agreement with the contract partners. In accordance with the current regulations, Ecopetrol has not assigned assets or specific funds to cover its direct obligations.

Accounting for Contingencies

As of the date the consolidated financial statements are issued, conditions might exist that result in losses for the Company, which will only be known if future specific circumstances arise. Management and legal counsel evaluate these situations based on their nature, the likelihood that they will materialize, and the

F-114

Ecopetrol S.A.

Notes to the Non Consolidated Financial Statements (unaudited)

amounts involved, to decide on any changes to the amounts accrued and/or disclosed. This analysis includes current legal processes against the Company and claims not yet initiated. On the other hand, the Company maintains insurance policies to cover specific operational risks and asset protection.

Ecopetrol has recognized the provisions corresponding to rational estimations intended to cover the forecast of future facts deriving from probable loss contingencies or occurrence of events that may impact Company’s equity.

Risks and Uncertainties

The Company is subject to certain operational risks such as terrorism, products’ thefts, crude oil international price changes and environmental damages in variations in the estimations of hydrocarbon reserves.

Net Weighted Income per Share

Net income per share is calculated on the weighted average of outstanding shares of the Company during the year.

Memorandum Accounts

These accounts represent facts or circumstances from which rights or obligations could derive and affect the Company.

Memorandum accounts are adjusted periodically based on reasonable values.

2. Assets and Liabilities Denominated in Foreign Currency

At June 30, 2008 and December 31, 2007, the unconsolidated financial statements of Ecopetrol included the following assets and liabilities denominated in foreign currencies (which are converted into Colombian pesos at closing exchange rates):

	Jun - 08		Dec - 07
	(Thousand of US$)	(Millions of equivalent Pesos)	(Thousand of US$)	(Millions of equivalent Pesos)
Assets
Cash and cash equivalents	188,046	361,616	1,198,495	2,349,782
Investments	3,963,874	7,622,609	1,970,715	3,835,123
Pension plan assets	977,868	1,880,460	359,206	704,264
Receivables from foreign clients	500,271	962,031	103,345	202,619
Advances for joint operations investments	244,816	470,786	125,995	247,028
Other advances	—	—	128,397	251,737
Other receivables	61,182	117,654	137,430	269,447
Petroleum Stabilization Savings Fund – FAEP	—	—	1,781,966	3,493,741
	5,936,057	11,415,156	5,805,549	11,353,741
Liabilities:
Advances received/obligations related with BOMT	592,097	1,138,615	659,488	1,292,999
Abandonment costs	766,944	1,474,849	635,957	1,246,864
Suppliers	189,843	365,072	68,829	134,947
Partners’ financing	146,785	282,270	110,060	215,784
Deposits and guarantees	698	1,342	38,367	75,187
Other payables	—	—	16,568	32,484
Petroleum Stabilization Savings Fund – FAEP	—	—	1,781,966	3,493,741
Abandonment costs – potential obligations	25,610	49,249	148,309	290,776
	1,721,977	3,311,397	3,459,544	6,782,782

F-115

Ecopetrol S.A.

Notes to the Non Consolidated Financial Statements (unaudited)

3. Cash and Cash Equivalents

	Jun - 08		Dec - 07
Banks and savings entities	$	1,881,834	$	876,354
Sight investments (1)		911,757		2,466,180
Special and revolving funds		381,683		110,728
In-transit funds		—		12,523
Cash		268		399
	$	3,175,542	$	3,466,184

(1) Investments with maturities of 90 days or less.

4. Investments

	Jun - 08			Dec - 07
Current:
Cash and cash equivalents ( held by Central Bank)	$	2,826,241		$	3,686,431
Price differential on hydrocarbons		536,793			—
Treasury Securities – TES		8,695			8,780
Bonds and securities of private or foreign entities		559,861			1,168,723
Latin American Reserves Fund – FLAR (1)		782,732			447,249
FFTW Funds and Deutsche Bank Trust (2)		765,494			—
Santiago de las Atalayas Fund		50,570			331,900
Time deposits		650,574			195,699
Bonds issued by the Government		184,279			115,714
Other investments		5			6
Total Current	$	6,365,244		$	5,954,502
Long term:
Variable yield – shares	$	2,048,020			$1,406,984
Bonds and securities of foreign entities		4,245,886			2,264,230
Bonds issued by the Government		476,356			521,997
Treasury securities – TES		60,810			60,878
Santiago de las Atalayas Fund		281,319			2,287
Own Insurance Fund		—			25
Provision for investments		(129,072	)		(130,543	)
TOTAL	$	6,983,319		$	4,125,858

(1) On April 17, 2006, the Company entered into an agreement for the custody, investment and administration of resources delivered to the FLAR to set up an investment portfolio. The contract duration was extended through December 31, 2009 and the fund amount may be increased or decreased during the contract execution period, or its extensions, without falling below US$100 million. On February, 2008, US$180 million were added to the fund. On June

F-116

Ecopetrol S.A.

Notes to the Non Consolidated Financial Statements (unaudited)

2008, the portfolio obtained a profitability of 2.14% (not annualized).

(2) On March 31, 2008, US$200 million were given in administration under new specialized firms (Deutsche Investment Management and Fischer Francis Trees & Watts), acting as custodian of the funds JP Morgan Chase.

A summary of variable yield long term investments, valued at market value and their provision, is as follows:

	Number of Shares and/or Quotas	Participation Percentage	Adjusted Cost		Intrinsic Market Value		Valuation / Provision
Strategic Investments
Sociedad Refinería de Cartagena (1)	979,999	49.00	$	239,271	$	1,230,656	$	991,385
Oleoducto Central S.A.	1,820,824	35.29		396,021		649,714		253,693
Invercolsa (3)	889,410,047	31.76		60,282		146,800		86,518
Oleoducto de Colombia S.A.	15,925	43.85		181,569		52,497		(129,072	)
Serviport	53,714,116	49.00		2,081		6,495		4,414
Ecodiesel Colombia S.A. (2)	7,750,000,000	50.00		7,750		7,663		(87	)
			$	886,974	$	2,093,825	$	1,206,851
Not Strategic Investments
Empresa de Energía de Bogotá	6,310,980	7.35	$	169,422	$	465,191	$	295,769
Interconexión Eléctrica S. A.	58,925,480	5.48		69,549		453,137		383,588
Colombia Telecomunicaciones	100	0.00000011		0.100000		—		—
			$	238,971	$	918,328	$	679,357
			$	1,125,945	$	3,012,153	$	1,886,208

(1) Ecopetrol initially contributed to Refinería de Cartagena S.A. certain assets with an historical cost of $239,271 and a valuation of $1,146,824 in exchange for a 49% shareholding participation. Ecopetrol recorded its investment initially at $1,386,095, which was the fair value of the 49% interest received. This transaction was authorized by CGN by means of communication SGI 200612-81970 of December 1, 2006. The subsequent devaluations in the intrinsic value of the shares, originated by losses incurred in the valuation of investments in foreign currency, are accounted for as a redemption of the original appraised value.

(2) Ecodisel Colombia S.A. was organized on April 19, 2007 to construct and operate a plant in Barrancabermeja that will produce 100,000 tons of bio-diesel fuel per year, equivalent to 2,000 barrels per day. Ecopetrol’s initial contribution amount was $2,600.

Restrictions over Investments:

(3) In accordance with the sentence of February 8, 2007, issued by the 28th Bogotá Civil Court, Mr. Fernando Londoño was required to return the package of shares of Inversiones de Gases de Colombia S.A. (Invercolsa), as well as the amount paid in 1997. This sentence was appealed and its second instance decision is pending. On June 8, 2007, the 28^th the Court declared the seizure and

F-117

Ecopetrol S.A.

Notes to the Non Consolidated Financial Statements (unaudited)

deposit into an escrow account of the 145 million Invercolsa shares and any dividends or distribution in connections therewith and appointed a custodian.

The Council of State ruled in favor of Ecopetrol a constitutional action filed by two citizens granting the Company control over the shares under litigation; decision which was reviewed by the Constitutional Court in August 2007.

A summary of Ecopetrol’s consolidated subsidiaries:

	Number of Shares	Participation Percentage	Adjusted Cost		Historical Cost
Black Gold Re Ltd. (1)	120,000	100.00	$	191,372	$	184,079
Ecopetrol Oleo & Gás do Brasil Ltda.	20,370,700	99.99		21,730		22,499
Ecopetrol del Perú S. A. (2)	23,519,999	99.99		51,366		48,390
Ecopetrol América INC (3)	1	100.00		98,448		98,916
Polipropileno del Caribe S. A. (4)	206,910,325	49.90		265,463		263,660
Andean Chemicals Limited (4)	29,494	100.00		293,696		277,393
			$	922,075	$	894,937

(1) On August 24, 2006, a captive reinsurance company was organized offshore, which serves to process the Company’s risks, permitting the optimization of insurance retention levels and the transfer thereof. The initial investment for its organization was of US$12 million and a capitalization of US$77.7 million was made in December 2007. Black Gold Re was registered as the foreign reinsurance company with the Financial Superintendency, which authorizes it to render direct reinsurance services through insurance companies organized in Colombia.

(2) In July 12, 2007, the Company and Talisman obtained in Perú Lot 134 in the bidding of exploratory blocks, designated as 2007 Round, carried out by Perupetro, a regulatory entity of the hydrocarbons sector in that country.

Additionally, in November 2007, the Peruvian government issued a decree whereby it approved the assignment of interests for the participation in Lots 101 and 90 to the Company, Talisman and Repsol, respectively. The Company has a 30% and 49% participation in these lots, respectively.

For the development of these activities in August 2007, the Company organized the company Ecopetrol del Perú S.A., with a 99.99% ownership interest. The initial contribution amount of the Company was US$5,000 and a capitalization of US$23.5 million was made in November 2007.

(3) In December 2007, the Company entered into a participation agreement with Shell Offshore Inc. for the exploration of exploratory blocks 777 and 778 (Clearwater prospect), located in deep waters of the Mexican Gulf; the Company owns a 25% participation in these blocks. For the development of these activities, the Company organized Ecopetrol America Inc., with an initial contribution of US$20 million and a participation of 100% ownership interest. On February 2008, the Company capitalized US$ 31.2 million in its subsidiary.

(4) In December 2007, the Company agreed to purchase Andean Chemical Limited and its subsidiary (Polipropileno del Caribe S.A. (Propilco S.A.) for US$690 million. Propilco is the principal producer of oil-derivative products in the Andean region, Central America and the Caribbean. The

F-118

Ecopetrol S.A.

Notes to the Non Consolidated Financial Statements (unaudited)

acquisition was settled on April 7, 2008 when all legal procedures with the Superintendency of Industry and Commerce were completed.

After the acquisition, the new shareholders have the following interests: 1) Andean Chemicals Limited, 50.1%; 2) Ecopetrol S. A., 49.90%; 3) Oleo é Gas Do Brasil Ltda., one share; 4) Ecopetrol del Perú S. A., one share; and 5) Ecopetrol América Inc., one share. Hence, Ecopetrol owns 100% of Propilco S. A., indirectly.

The transaction was made on the following terms:

Acquisition cost: US$ 690 million; $1.254.647 million Colombian pesos.

	Andean Chemicals Limited		Polipropileno del Caribe S. A.
	(Thousand of US$)	(Millions of equivalent Pesos)	(Thousand of US$)	(Millions of equivalent Pesos)
Equity	152,726	277,393	167,526	304,274
Goodwill (Note 13)	193,354	351,185	177,172	321,795
Purchased price	346,080	628,578	344,698	626,069

On April 7, 2008, the seller made a guarantee deposit of US$50 million, entitled to Ecopetrol. This deposit guarantees indemnity to Ecopetrol in the event of occurring something extraordinary that could affect the negotiation, not foreseen in the initial agreement. The duration of this guarantee is one year beginning after the closing date of the transaction.

Ecopetrol’s subsidiaries present the following balances at May 31, 2008:

	Assets		Liabilities		Equity		Net Income
Black Gold Re	$	218,763	$	27,391	$	191,372	$	10,183
Ecopetrol del Perú S. A.		63,445		12,080		51,365		355
Ecopetrol América Inc.		98,454		6		98,448		(10	)
Ecopetrol Oleo e Gas Do Brasil Ltda		21,745		15		21,730		—
Andean Chemicals Limited		293,695		—		293,695		—

Ecopetrol’s subsidiaries present the following balances at December 31, 2007:

	Assets		Liabilities		Equity		Net Income
Black Gold Re	$	199,499	$	10,172	$	189,327	$	8,646
Ecopetrol del Perú S. A.		53,234		5,846		47,388		—
Ecopetrol América Inc.		40,295		—		40,295		—
Ecopetrol Oleo e Gas Do Brasil Ltda		4,875		22		4,853		—

F-119

Ecopetrol S.A.

Notes to the Non Consolidated Financial Statements (unaudited)

Both the economic activity and net income at June 2008 are provided for the companies where Ecopetrol is a shareholder:

Company	Economic Activity	Net Income at June-08 (In millions of Colombian pesos)
Interconexión Eléctrica S.A.	Operation, maintenance, transmission and selling of electric energy.	$	164,474
Empresa de Energía de Bogotá S.A.	Electric power transmission		472,883
Colombia Telecomunicaciones S.A.	Rendering of long-distance services, local telephony, data transmission, dedicated and commuted internet.		58,829
Refinería de Cartagena S.A.	Construction and operation of refineries, refining of hydrocarbons, production, selling and distribution of crude oil, natural gas and by-products.		(90,142	)
Ocensa S.A.	Construction and operation of a pipeline system, which terminal is located at the Coveñas port, Municipality of Tolú, Colombia.		15,484	*
Invercolsa S.A.	Investments in energy sector companies including activities inherent to the hydrocarbons and mining industries.		40,309	*
Oleoducto de Colombia S.A.	Construction and operation of a pipeline system, which terminal is also at the Coveñas port.		(3,189	)
Serviport S.A	Rendering to the public in general of the necessary services for the loading and unloading support of oil ships, supply of equipment for the same purpose, load inspections and measurements.		(315	)
Ecodiesel Colombia S.A.	Construction and operation of plants for the production of bio-fuels and oleo-chemicals and their mixes with hydrocarbon derivative fuels, in addition to the production and distribution thereof.		(138	)
Black Gold & Re Ltd.	Control and negotiation of subscriptions, total or partial, directly or indirectly of insurance policies to Ecopetrol, its affiliates or subsidiaries.		18,052	**
Ecopetrol Oleo & Gas Do Brasil Ltda.	Exploration, exploitation, refining, transport, storage, distribution and selling of hydrocarbons, derivatives and other products, and research and development.		—
Ecopetrol America Inc.	Exploration, exploitation, refining, transport, storage, distribution and selling of hydrocarbons, derivatives and other products, and research and development		—
Ecopetrol del Perú S.A.	Exploration, exploitation, refining, transport, storage, distribution and selling of hydrocarbons, derivatives and other products, and research and development.		—

(*) Net income at May 2008

(**) Net income of US$9.389 converted at an exchange rate of 1,923.02 Colombian pesos per US Dollar.

F-120

Ecopetrol S.A.

Notes to the Non Consolidated Financial Statements (unaudited)

Investments are classified depending on their class and maturities. Investments with maturities of less than one year and those which will be utilized within the next business cycle are classified as current assets.

Summary of main long-term investments at June 30, 2007 to be redeemed during the next five years:

	1 - 3 Years		3 - 5 Years		> 5 Years		Total
CDT’s	$	1,475,651	$	—	$	—	$	1,475,651
Private bonds		50,124		1,547		—		51,671
Bonds and other foreign securities		4,633,695		168,444		—		4,802,139
Bonds and other Government securities		349,056		262,721		87,474		699,251
Treasury Securities - TES		34,764		24,503		10,238		69,505
Santiago de las Atalayas Fund		324,657		—		4,494		329,151
	$	6,867,947	$	457,215	$	102,206	$	7,427,368

5. Accounts and Notes Receivable

	Jun - 08			Dec - 07
Current
Local customers	$	506,439		$	481,639
Foreign customers		878,397			442,657
		1,384,836			924,296
Price differential receivable (1)		2,116,274			636,550
Other debtors (2)		264,750			144,907
Related parties (Note 14)		1,003,905			341,054
Reimbursements and investment yields (3)		159,025			111,676
Association contracts – joint operations		77,471			79,559
Doubtful accounts		28,144			28,665
Notes receivable		11,018			19,642
Accounts receivable from employees		24,804			7,541
Industrial service clients		2,606			4,420
		5,072,833			2,298,310
Provision for doubtful accounts		(28,144	)		(28,665	)
	$	5,044,689		$	2,269,645
Long-term
Cavipetrol – loans to employees for housing (4)	$	130,575		$	137,629
Credit portfolio		60,213			60,040
Other		4,751			4,896
	$	195,539		$	202,565

(1) Includes the balance receivable from the Ministry of Mines and Energy, corresponding to the price differential for diesel and regular gasoline, which also includes at June 2008, $13,939 of past due interests.

(2) Includes $7.211 receivables from commission brokers in the Initial Public Offering of the company, corresponding to the initial payment received from the shareholders. Its composition is the following: Cavipetrol, $4,249; Fenalco, $2,950; Coopetrol $2.

(3) The balance at June 30, 2008 includes $50,627 of dividends receivables from: 1) Polipropileno del Caribe, $27,076; 2) Interconexión Eléctrica S. A., $5,964; 3) Empresa de Energía Eléctrica de Bogotá, $17,587.

F-121

Ecopetrol S.A.

Notes to the Non Consolidated Financial Statements (unaudited)

(4) By means of Leg contracts 058-80 of 1980 and 4008928 of 2006, the administration, management and control of loans granted to employees by the Company were given to Cavipetrol. In its capacity as administrator, Cavipetrol acts as custodian in its database and financial system of the detail by employee of said loans and their respective conditions. Within the policies established by the Company, the applicable interest rate as of April 7, 2006, for new credits corresponds to UVR (Real Value Unit) with a ceiling of 12%.

Aging determination and classification of accounts receivable at June 30, 2008, pursuant to maturity:

	Expiration Days
	0 – 180		181 – 360		More than 361*
Current accounts receivable	$	1,383,101	$	—	$	—
Past due accounts receivable		1,735		—		1,507
	$	1,384,836	$	—	$	1,507
Local customers	$	506,439	$	—	$	1,507
Foreign customers		878,397		—		—
	$	1,384,836	$	—	$	1,507

* Clients receivables included within doubtful accounts.

* Clients receivables included within doubtful accounts.

The classification of accounts and notes receivable between current and non-current is based upon Management´s estimation of the recoverability of accounts receivable. When it is estimated that their realization will occur within twelve months following the balance sheet date, it is classified as current; otherwise, it will be classified as non-current. Also, certain accounts receivable have the nature of non-current, when there are contractual or legal provisions that require such presentation.

The collection schedule of accounts and notes receivables of Cavipetrol at June 30, 2008 is as follows:

Year	Amount
2008	$	23,111
2009		25,488
2010		28,109
2011		31,001
2012 and over		22,866
	$	130,575

No other significant restrictions exist for the recovery of accounts and documents receivable.

F-122

Ecopetrol S.A.

Notes to the Non Consolidated Financial Statements (unaudited)

6. Inventories

	Jun - 08			Dec - 07
Processed products	$	1,193,180		$	906,172
Purchased products		155,222			170,331
Raw materials		144,250			129,506
In-process products		233,144			162,377
Materials for production of assets		10,483			10,483
Materials in transit		2,888			894
Less provision for price difference		(181,289	)		(80,971	)
	$	1,557,878		$	1,298,792

Below are the adjustments made to the provisions for price difference at June 30, 2008 and December 31, 2007:

	Jun - 08		Dec - 07
Initial balance	$	80,971	$	752
Adjustment of existing provisions		100,318		80,219
Ending balance	$	181,289	$	80,971

7. Advances and Deposits

	Jun - 08		Dec - 07
Official entities (1)	$	904,020	$	1,183,008
Partners in joint operations (2)		868,555		577,792
Related parties		92,432		161,422
Contractors		21,089		23,274
Agreements		15,269		17,163
Customs agents		17,703		15,049
Advances to suppliers		4,488		664
Advances to Employees		2,490		227
	$	1,926,046	$	1,978,599

(1) Includes transactions with the National Tax and Customs Administration - DIAN for income tax withholdings.

F-123

Ecopetrol S.A.

Notes to the Non Consolidated Financial Statements (unaudited)

(2) Associated operations:

	Jun - 08		Dec - 07
Partners:
BP Exploration Company Colombia	$	330,224	$	278,827
Mansarovar Energy Colombia Ltd.		53,576		54,370
Occidental de Colombia Inc.		41,371		21,301
Petrobras Colombia Ltd.		39,428		31,267
Occidental Andina LLC		25,727		4,209
Meta Petroleum Ltd.		17,931		31,051
Petrobras Internacional Braspetro B.V.		10,540		5,420
BHP Billiton Petroleum Colombia		9,059		10,330
Nexen Petroleum Colombia Limited		8,390		8,781
Chevron Texaco Petroleum Company		7,677		486
Hocol S. A.		7,135		9,430
Kappa Resources Colombia Ltd.		5,534		5,788
Perenco Colombia Limited		4,276		7,320
Otras Operaciones		19,400		9,203
Operator - Ecopetrol S.A.:
Oleoducto Caño Limón		241,001		95,525
Joa Caño Sur		20,374		—
Contrato La Cira		14,656		542
Otras operaciones		6,054		966
Operación y mantenimiento TLU-3		4,644		274
Joa Platanillo		1,039		2,614
Riesgo compartido Catleya		519		88
	$	868,555	$	577,792

8. Prepaid Expensed

	Jun - 08		Dec - 07
Insurance	$	23,258	$	10,388
Others		1,443		2,202
	$	24,701	$	12,590

F-124

Ecopetrol S.A.

Notes to the Non Consolidated Financial Statements (unaudited)

9. Property, Plant and Equipment, net

	Jun - 08			Dec - 07
Plant and equipment	$	10,204,914		$	10,116,645
Pipelines, networks and lines		3,675,340			3,700,446
Construction in progress		2,126,826			1,526,127
Buildings		1,028,964			1,007,769
Equipment on deposit and in transit		702,333			638,784
Computers		267,694			268,598
Other fixed assets		141,974			166,355
Transportation equipment and communication networks		132,294			132,004
Land		67,422			64,789
		18,347,761			17,621,517
Less accumulated depreciation		(11,658,338	)		(11,364,448	)
Less provision for property, plant and equipment		(103,353	)		(105,118	)
	$	6,586,070		$	6,151,951

Construction in progress corresponds to development projects, which are transferred to the respective headings once the assets start their production stage and are ready to be used.

The estimated residual value is only considered in the valuation process of property, plant and equipment, and only in the event that assets are fully depreciated and are not under operation conditions. A general average of 5% of cost is applied, considering its exclusive usefulness for the oil industry. This criterion is not applicable to assets classified as pipelines and buildings upon considering that recoverable costs are equivalent to removal and transportation costs for their retirement. Assets are depreciated at 100% of their book cost adjusted for inflation.

Summary of property, plant and equipment at June 30, 2008:

Class of Asset	Adjusted Cost		Accumulated Depreciation		Valuations, net		Realization Value
Plant and equipment	$	10,204,914	$	8,136,931	$	3,021,577	$	10,389,981
Pipelines and networks lines		3,675,340		2,572,111		192,735		308,175
Construction in progress		2,126,826		—		—		—
Buildings		1,028,964		504,719		262,913		843,766
Equipment on deposit and in transit		702,333		—		—		—
Computers		267,694		222,213		4,299		13,982
Other assets		274,268		222,364		67,491		67,124
Land		67,422		—		11,668		14,730
	$	18,347,761	$	11,658,338	$	3,560,683	$	11,637,758

F-125

Ecopetrol S.A.

Notes to the Non Consolidated Financial Statements (unaudited)

Summary of property, plant and equipment at December 31, 2007:

Class of Asset	Adjusted Cost		Accumulated Depreciation		Valuations, net		Realization Value
Plant and equipment	$	10,116,645	$	7,903,317	$	3,027,351	$	10,324,281
Pipelines and networks lines		3,700,446		2,511,837		192,738		242,013
Construction in progress		1,526,127		—		—		—
Buildings		1,007,769		480,961		263,157		736,633
Equipment on deposit and in transit		638,784		—		—		—
Computers		268,598		220,256		4,360		14,660
Other assets		298,359		248,077		67,592		97,848
Land		64,789		—		11,668		11,668
	$	17,621,517	$	11,364,448	$	3,566,866	$	11,427,103

In accordance with the Company’s policy, assets not required for the operation are removed from the books and recorded in accordance with the means of disposition defined, i.e., sale, assignment without cost, payment in kind or scrapping.

10. Natural and Environmental Resources

	Jun-08			Dec-07
Amortizable oil investments	$	10,912,997		$	10,289,578
Less – accumulated amortization		(6,515,870	)		(6,082,883	)
		4,397,127			4,206,695
Plugging and abandonment, dismantling of facilities and environmental recovery costs		1,487,501			1,528,132
Less – accumulated amortization		(1,028,065	)		(951,690	)
		459,436			576,442
Reservoirs and appraisals (1)		701,590			701,590
Less – accumulated depletion		(564,923	)		(556,014	)
		136,667			145,576
Exploration in progress		297,661			200,204
	$	5,290,891		$	5,128,917

(1) The appraisal of reserves represents reservoirs received from the reversion of concession contracts of $520,218 and $181,372, administrated by the Central and Middle Magdalena managements, respectively.

F-126

Ecopetrol S.A.

Notes to the Non Consolidated Financial Statements (unaudited)

11. Pension Plan Assets

At June 30, 2008, the Company has set up the following trusts:

	Jun-08			Dec-07
Consorcio Bogotá - Colpatria	$	2,068,945		$	2,077,168
Consorcio Popular - Occidente		1,773,877			1,767,901
Consorcio Agraria - Coldex - Helm		1,143,183			1,135,703
Consorcio BBVA - Corficolombiana - Bogotá		1,144,503			1,140,656
Cons. Café-Previsora-Petrol		1,986,710			1,982,653
Cons. Colombia-Santander		1,402,529			1,391,593
		9,519,747			9,495,674
Less redeemable portion, short-term		(493,933	)		(508,813	)
	$	9,025,814		$	8,986,861

Funds are settled under irrevocable five-year contracts conditioned to the level and type of investment and subject to the control of the Company’s Investments Committees. On June 2008, the trust funds had an appraisal of $25,000 million. Accumulated yield generated at June 30, 2008 is $268,000 million, which were capitalized.

Decree 2153 of 1999 required the Company to fund up to 70% of its pension liability existing as of December 31, 1998, by means of annual contributions to the fund from 2000 to 2007. However, pursuant to Extraordinary Decree 1760 of 2003, the Company may issue shares to be placed, in the name of its pension trusts as contributions intended to cover pension obligations. The Board of Directors and the Superior Council of Tax Policy (CONFIS) authorized the funding of this liability to the Company’s with prior years’ treasury surpluses.

From January 1, 2008, the pension payments are made with the funds at the pension plan trusts of the Company, which are transferred to an account of Ecopetrol, based on a request by the Company.

The trend of the coverage of pension trusts with reference to the pension liability is as follows:

	Dec - 04			Dec - 05			Dec - 06			Dec - 07			Jun - 08
Pension liability	$	9,080,156		$	9,583,281		$	10,121,809		$	10,819,077		$	10,866,698
Pension trusts		6,322,115			8,618,698			8,960,897			9,495,674			9,519,747
Coverage		70	%		90	%		89	%		88	%		88	%

F-127

Ecopetrol S.A.

Notes to the Non Consolidated Financial Statements (unaudited)

12. Deferred Charges

	Jun-08		Dec-07
Deferred income tax	$	1,680,014	$	1,779,874
Other deferred charges, net		137,391		104,038
Maintenance and major repairs of plant, tanks and equipment		71,030		79,244
	$	1,888,435	$	1,963,156

13. Other Assets

	Jun-08			Dec-07
Goodwill (1)	$	672,980		$	—
Less amortization		(6,381	)		—
		666,599			—
Trademarks, licenses and patents		48,590			53,774
Retirement Pension Fund of personnel related with joint operations		308,548			211,238
Trust funds, long-term		69,910			72,845
Deposits in administration		24,706			29,092
Fund for abandonment of facilities with joint operations		32,512			21,651
National Royalties Fund (2)		70,711			6,206
Other		6,089			4,592
	$	1,227,665		$	399,398

(1) Goodwill is generated from the acquisition of Andean Chemicals Limited and Polipropileno del Caribe S. A. (See note 4). The estimated amortization period for the investment is 17 years and eight months, determined as the net present value of future cash flows. Amortization is calculated on a straight-line basis, which would be revised and adjusted annually.

(2) Corresponds to deposits made by the Company into the FAEP. The Fund has the sole purpose to repay debts valid through December 29, 2000 corresponding to financing of programs and projects for the development of hydrocarbon producing municipalities and departments. The Company grants cash resources when the Ministry of Finance (Ministerio de Hacienda) grants credit approvals.

14. Accounts Payable and Transactions with Related Parties

	Jun-08		Dec-07
Advances from partners	$	889,417	$	660,538
Deposits received from third parties		312,562		249,148
Dividends payable		3,491,235		—
Reimbursements of exploratory costs		114,581		128,998
Suppliers		1,314,033		61,198
Other payables		58,620		26,171
Related parties		18,018		15,108
	$	6,198,466	$	1,141,161

F-128

Ecopetrol S.A.

Notes to the Non Consolidated Financial Statements (unaudited)

Summary of the most representative balances with related parties where Ecopetrol holds direct investments or interest, and are included in debtors, suppliers and accounts payable:

	Accounts Receivable		Advances Receivable		Accounts Payable
Ocensa S.A.	$	2,695	$	91,925	$	(191	)
Oleoducto de Colombia S.A.		286		507		3,156
Refinería de Cartagena S.A.		968,876		—		2,040
Ferticol S.A.		700		—		413
Ecodiesel Colombia S.A.		11		—		—
Serviport		—		—		—
Cavipetrol		4,251		—		12,600
Compounding and Masterbatching (COMAI)		10		—		—
Polipropileno del Caribe S. A.		27,076		—		—
Balance at June 30, 2008	$	1,003,905	$	92,432	$	18,018
Balance at December 31, 2007	$	341,054	$	161,422	$	15,108

Principal transactions with related parties at June 30, 2008:

	Sales and Services		Leases		Other
Revenue:
Refinería de Cartagena S.A.	$	2,591,132	$	—	$	29,784
Ocensa S.A.		4,419		6,597		4
Ferticol S.A.		2,682		—		—
Ecodiesel Colombia S.A.		10		—		—
Oleoducto de Colombia S.A.		1,647		—		—
Compounding and Masterbatching		17,920		—		—
Cavipetrol		—		—		77
Total at June 30, 2008	$	2,617,810	$	6,597	$	29,865
Total at December 31, 2007	$	3,017,319	$	13,209	$	27,011

	Transportation Cost		Assignment of Accounts Receivable		Other
Egresos:
Ocensa S.A.	$	274,344	$	—	$	7,907
Oleoducto de Colombia S.A.		8,340		—		—
Cavipetrol		—		—		3,535
Ferticol S.A.		—		—		7
Serviport		—		—		30
Refinería de Cartagena S.A.		—		—		1,532
Total at June 30, 2008		282,684		—		13,011
Total at December 31, 2007	$	534,949	$	13,836	$	31,313

F-129

Ecopetrol S.A.

Notes to the Non Consolidated Financial Statements (unaudited)

There are no special price conditions or in deviation from market prices in transactions entered with related parties. However, for Ocensa S.A. and Oleoducto de Colombia S.A. there is a maximum tariff payable determined by the Ministry of Mines and Energy that can be collected by both companies for the use of its system. Their operation is based on the collection of total operating and administrative expenses and in the determination of the transportation unit cost. The cost per barrel is transferred to each shareholder that uses the system based on the barrels transported.

15. Taxes Payable

	Jun-08		Dec-07
Income tax	$	2,352,803	$	2,006,484
Payable to ANH for purchases of hydrocarbons		1,035,319		418,273
Sales tax payable		86,740		120,664
Equity tax		103,556		103,556
Special tax on gasoline (1)		89,228		100,865
Taxes withheld from third parties		86,109		127,121
Industry and commerce and other minor taxes		26,294		15,058
	$	3,780,049	$	2,892,021

(1) This tax is levied on sales and/or retirement of current, extra gasoline and Diesel. The funds collected for this tax are paid to the National Treasury Office of the Ministry of Finance. The special tax is paid on the basis of the percentage participation of each beneficiary in the national monthly consumption of regular and extra gasoline.

Income tax returns may be reviewed by the tax authorities within two years of their filing date. Currently, differences exist with DIAN regarding the calculation and payment method of the first installment of the 2003 and 2004 income tax returns because in the opinion of the DIAN the surtax of such years should have been included in the base. Additionally, for the 1996 income tax return, the Council of State is evaluating the applicability of exempt income of asphalts and the disallowance by the DIAN of losses on the sales of accounts receivable. The Company’s claims were recognized in the first court decision as far as exempt income from asphalts, and the interpretation of the DIAN was backed in connection with losses on sales of accounts receivable, a decision that was appealed by Ecopetrol. However, Management does not expect significant differences in the resolution of these actions.

The effective tax rate applicable during the first semester of 2008 was 28.55%.

F-130

Ecopetrol S.A.

Notes to the Non Consolidated Financial Statements (unaudited)

16. Labor and Pension Plan Obligations

Current	Jun-08		Dec-07
Retirement pensions (1)	$	497,456	$	508,813
Vacations		30,329		24,712
Severance		19,698		17,620
Bonuses and allowances		17,341		30,120
Pension bonuses issued and interest		486		376
Salaries payable		2,741		3,582
Interest on severance		310		1,008
Others		1,443		733
		569,804		586,964
Long-term
Retirement pensions (1)		10,292,099		10,234,345
Retirement pensions – joint operations (1)		77,143		75,919
Pension bonuses issued and interest		6,728		5,777
		10,375,970		10,316,041
	$	10,945,774	$	10,903,005
Total Actuarial Liability	$	10,866,698	$	10,819,077

(1) Actuarial liability at June 30, 2008 and December 31, 2007:

	Jun-08		Dec-07
Retirement pensions	$	7,856,657	$	7,949,074
Health care		1,444,389		1,392,584
Education		409,287		391,084
Pension bonuses		1,079,222		1,010,417
Retirement pensions – joint operations		77,143		75,918
	$	10,866,698	$	10,819,077

The actuarial method used at June 30, 2008 is based on the projected future liability for retirement pensions and the health care and education costs, at the actual technical rate of 4.8% and based on the actual personnel information at the same date.

Detail of personnel covered by the actuarial estimate at June 2008:

	Headcount
Bonuses reserve - retired personnel	10,169
Bonuses reserve – employees retiring after 2010	2,699
Pensions reserve (active employees and pensioners)	16,241
Health care and education services reserve (active and pensioners)	16,782

F-131

Ecopetrol S.A.

Notes to the Non Consolidated Financial Statements (unaudited)

The accumulated and amortized percentage of the actuarial calculation at June 30, 2008 is:

Concept	Percentage
Pending amortization at June 30, 2008	50
Accumulated amortization at June 30, 2008	50
Amortization at December 31, 2008	100

At year ended, the actuarial calculation is completely amortized. Every January, a new amortization is initiated with the new actuarial calculation, which difference is amortized with a 1/12 factor.

The amortization plan of the actuarial calculation, until a 100% of accumulated amortization is reached, is as follows:

	% of Amortization	% of Accumulated Amortization	% of Pending Amortization
July 31, 2008	8.33	58.33	41.67
August 31, 2008	8.33	66.67	33.33
September 30, 2008	8.33	75.00	25.00
October 31, 2008	8.33	83.33	16.67
November 30, 2008	8.33	91.67	8.33
December 31, 2008	8.33	100.00	0.00

The actuarial calculation is fully amortized at the end of the year. In January of the following year, a new amortization starts with updated actuarial figures, which difference is amortized on a straight-line basis.

17. Estimated Liabilities and Provisions

	Jun-08		Dec-07
Current
Provision for legal processes (Note 28)	$	1,043,662	$	1,329,118
Provision for pension obligations		1,219		1,220
Provisions for contingencies		73,962		80,679
Other provisions		17,883		24,926
		1,136,726		1,435,943
Long-term
Abandonment costs provision (1)		1,487,743		1,528,374
Provision - Comuneros and other (2)		333,219		334,253
Provision for pension obligations (3)		1,170,121		869,927
		2,991,083		2,732,554
	$	4,127,809	$	4,168,497

(1) On June 2008, the Vice-presidency of Production reevaluated abandonment costs, dismantling of facilities and environmental recovery.

F-132

Ecopetrol S.A.

Notes to the Non Consolidated Financial Statements (unaudited)

Below are the movements of the provision for abandonment costs, dismantling of facilities and environmental recovery at June 30, 2008 and December 31, 2007:

	Jun-08			Dec-07
Balance at beginning of year	$	1,528,374		$	1,355,989
Retirements and uses		—			(1.296	)
Additions		28.375			94.887
Changes in estimations, including programming		—			78.794
Exchange rate difference		(69.006	)		—
Balance at end of year	$	1,487,743		$	1,528,374

(2) These balances include a provision related to claims of Comuneros de Santiago de las Atalayas and Pueblo Viejo de Cusiana, originated in Royalties Contracts Nos. 15, 15ª, 16 and 16ª entered into with Ecopetrol. These claims were declared null by the Colombian Council of State. The extraordinary right of petition filed by the stated Comuneros is pending sentencing. A trust was set-up to settle an eventual liability.

(3) Includes provision for contingencies established in 2006, equivalent to $869 billion mainly as a result of the effect of the discount exchange rate used in the partial transfer of actuarial calculation, which passed from 4.8% to 4%, as established by Decree 941 of 2002.

18. Other Long Term Liabilities

Other long term liabilities at June 30, 2008 and December 31, 2007 correspond:

	Jun-08		Dec-07
Advances received from Ecogas for BOMT obligations	$	1,138,615	$	1,263,108
Deferred income tax liability		659,245		644,857
Credit for deferred monetary correction		242,922		271,356
Other		1,376		—
	$	2,042,158	$	2,179,321

F-133

Ecopetrol S.A.

Notes to the Non Consolidated Financial Statements (unaudited)

19. Equity

The following is a detail of Equity:

	Jun-08			Dec-07
Authorized Capital	$	15,000,000		$	15,000,000
Capital not yet subscribed		(4,881,872	)		(4,881,872	)
Subscribed Capital		10,118,128			10,118,128
Subscribed Capital - Receivable		(1,422	)		(4,794	)
Subscribed and Paid-in Capital		10,116,706			10,113,334
Additional Paid-in Capital		4,700,882			4,700,882
Additional Paid-in Capital - Receivable		(357,119	)		(850,068	)
Additional Paid-in Capital		4,343,763			3,850,814
Valuation surplus		5,575,963			5,647,383
Net income		5,649,997			5,176,394
Legal Reserves		2,428,325			1,910,686
Appropriation for investment programs		4,415			—
Prior year adjustments		17,804			17,804
Valuation surplus of foreign subsidiaries		36,906			302
incorporated institutional equity		93,594			90,926
Total Equity	$	28,267,473		$	26,807,643

Transformation of the Company

The authorized capital of Ecopetrol is $15,000,000 divided into 60,000,000,000 (55,000,000 shares at December 31, 2006) common shares each with a par value $250, of which 40,472,512,588 shares have been subscribed, represented by 10.1% in private shareholders and 89.9% held by the Nation.

Regulatory Decree 727 of March 7, 2007 replaced the use of Decree 2625 of 2000 and authorized the transfer to subscribed and paid-in capital of contributions in kind (hydrocarbons) of the Colombian Nation that were separately recognized until March 9, 2007. By means of Minute No. 012 of March 26, 2007 of the General Shareholders’ Meeting, formalized on April 27, 2007, the balance of $4,851,215 was reclassified to subscribed and paid-in capital in the name of the shareholder Ministry of Finance. From this date on, field production makes part of the operational revenues of the Company.

Legal Reserve

Legal reserve is set up with 10% of net income and it may be used to absorb losses or distributed at the liquidation of the Company. At March 31, 2008, retained earnings will be freely available for distribution in accordance with the instructions of the General Shareholders’ Meeting, held on March 27, on which it was declared to increase the legal reserve in $ 517,639 for a total of $ 2,428,325 in contrast with the $1,910,686 at December 31, 2007.

In addition, $4.415 was declared also reserves for new exploration.

Incorporated Institutional Equity

During 2007, the Company adjusted the incorporated institutional equity, in accordance with the PGCP, based on the commerciality y of the Nare, Matambo, Garcero, Corocora, Estero and Caracara association contracts, for the Sardinas 6, Remache Norte 3, Abejas 3 and Jaguar T5 and T6 wells, respectively.

F-134

Ecopetrol S.A.

Notes to the Non Consolidated Financial Statements (unaudited)

For the second quarter of 2008, the incorporated institutional equity account was adjusted due to the commerciality of the joint operating contract “Orocue, pozo Guarilaque 7”. The commerciality value was estimated to be US$ 1.4 million, equivalent to $2,635 million.

Summary of Valuation Surplus

	Jun-08		Dec-07
Fixed yield investments (1)	$	2,015,280	$	2,080,515
Plant and equipment		3,021,577		3,027,351
Buildings		262,913		263,158
Pipelines and networks		192,735		192,738
Land		11,668		11,668
Computers		4,299		4,360
Others assets		67,491		67,592
	$	5,575,963	$	5,647,382

(1) A detail of fixed yield investments is as follows:

	Jun-08			Dec-07
Refinería de Cartagena S.A.	$	991,385		$	1,135,766
Interconexión Eléctrica S. A. E.S.P.		383,588			348,822
Empresa de Energía de Bogotá S.A. E.S.P.		295,769			278,685
Ocensa S.A.		253,693			247,827
Invercolsa S.A.		86,518			67,414
Serviport S.A.		4,414			2,000
Ecodiesel Colombia S.A.		(87	)		1
	$	2,015,280		$	2,080,515

F-135

Ecopetrol S.A.

Notes to the Non Consolidated Financial Statements (unaudited)

20. Memorandum Accounts

	Jun-08		Dec-07
Rights:
Exploitation rights in fields (1)	$	34,952,812	$	21,235,570
Costs and expenses (deductible and non-deductible)		9,731,161		10,297,898
Other contingent rights and debtor accounts		5,152,111		3,931,976
Legal processes		476,667		481,726
Execution of investment projects		355,804		359,474
Securities given in custody		852,192		86,547
	$	51,520,747	$	36,393,191
Obligations:
Contractual agreements	$	6,452,576	$	6,452,576
Non-taxable income		4,197,768		6,124,282
Accumulated depletion		5,893,626		5,893,626
Non-taxable liabilities		5,603,395		4,486,070
Mandate contracts (2)		1,745,071		1,682,664
Administration funds– Decree 1939 of 2001 and 2652 of 2002		971,907		971,728
Legal processes		1,207,353		946,527
Payments of BOMTs		658,519		729,588
Agreements to Ocensa (3)		346,763		343,075
Inventory received in custody		84,780		78,563
Securities received in custody and other contingent obligations		—		70,663
Other contingent obligations		76,591		7,692
		27,238,349		27,787,054
	$	78,759,096	$	64,180,245

(1) During the first half of 2007, together with hydrocarbon reserves experts hired, Ecopetrol performed an audit of its hydrocarbon reserves, the results of which were updated at December 31, 2007, without generating significant differences. At June 30, 2008, Ecopetrol updated its estimated reserves based on international methodologies. Decree 2625 is no longer in effect.

(2) Includes the amount of assets received in custody by Refinería de Cartagena S.A. to comply with the obligations entered into under the mandate contract entered into between the Company and said entity for the operation of the refinery.

(3) Control of Ecopetrol´s commitment to provide the necessary funds to Ocensa to repay capital contributions and the preferred dividend to Ocensa´s shareholder. Obligations contained in Tranche A are the following:

Term	Entity	Interest Rate	Original Value		Balance
			(Thousands of dollars)
1997 – June 2008	Chemical Chase	Libor + 1.375%	US$	335,000	US$	–
1997 – June 2008	Chemical Chase	Libor + 1.375%		335,000		–
				–		–
				670,000		–
Capital of Canadian’s interestholders				230,700		160,240
Interestholders’ preferential dividend				–		20,082
			US$	900,700	US$	180,322

F-136

Ecopetrol S.A.

Notes to the Non Consolidated Financial Statements (unaudited)

21. Revenue

	Jun-08		Jun-07
Local sales:
Medium distillates	$	2,766,027	$	2,424,008
Crude oil (1)		2,597,998		968,503
Gasoline		1,732,020		1,706,328
Services		440,054		397,566
L.P.G.		313,727		293,004
Natural Gas		346,096		303,303
Asphalt		177,979		105,486
Other products		417,280		303,599
		8,791,181		6,501,797
Price differential recognition – fuel products (2)		2,002,567		683,515
		10,793,748		7,185,312
Foreign sales:
Crude oil (1)		4,468,273		1,583,731
FAEP		—		(136,014	)
Net crude oil		4,468,273		1,447,717
Fuel oil		1,091,446		695,035
Gasoline		124,185		197,124
Natural Gas		97,181		—
Naptha		—		106,704
Jet fuel		—		68,627
Other products		40,507		10,021
		5,821,592		2,525,228
	$	16,615,340	$	9,710,540

(1) Effective April 2007, Ecopetrol began selling crude oil to Refinería de Cartagena S.A.

(2) Until 2006, price differential recognition generated by the difference between the regulated price and the price at international parity being assumed by refiners and importers were not an express part in the price determination resolutions and, accordingly, were not recognized for Financial or for tax purposes. Pursuant Law 1110 of 2006 (Budgets Laws), the Nation assumes the price differential. On March 2007, the Ministry of Mines and Energy issued Resolution No. 180414 whereby the procedure for the recognition of the price differential of gasoline and diesel is established.

F-137

Ecopetrol S.A.

Notes to the Non Consolidated Financial Statements (unaudited)

22. Cost of Sales

	Jun-08			Jun-07
Variable cost:
Purchases of hydrocarbons from ANH (1)	$	2,794,058		$	1,529,826
Purchase of crude oil from business partner		1,457,491			539,195
Amortization and depletion		518,271			280,000
Cost of sale of contributions in kind		—			432,105
Imported products		1,269,744			345,115
Process materials		45,708			40,441
Electric energy		43,812			34,803
Purchase of natural gas and others products		178,218			44,950
Initial less final inventory balances		(357,410	)		49,647
Fixed costs:
Depreciation		325,754			365,774
Services contracted with associations		451,534			395,234
Labor cost		308,515			224,079
Transportation services to refineries		273,886			313,210
Amortization of actuarial calculation		73,649			118,252
Maintenance		168,405			119,536
Amortization of deferred charges, intangibles and insurances		28,260			67,242
Ecopetrol contracted services		228,304			129,765
Materials and operations supplies		102,435			64,354
Taxes		43,756			32,516
General costs		3,733			817
Project expenses		150,724			107,196
Reclassification to non-operating expenses and others		(259,631	)		99,354
	$	7,849,216		$	5,333,411

(1) These are the costs incurred related to the purchase of oil and natural gas volumes from the ANH at prices set forth in the Law 756 of 2002 and Resolution 18-1709 of 2003, which reference international prices. A detail of the average price, provided by the Ministry of Mines, and the production volume, in accordance with each contract, used for its settlement, is as follows:

	Jun-08		Jun-07
Volume of crude oil production (thousands of barrels)	$	100,737	$	93,812
Volume of crude oil production liquidation base (thousands of barrels)		16,219		15,365
Average liquidation price (US$ per barrel)		88.42		42.50
Average exchange rate		1,836		2,115
		2,632,970		1,380,605
Purchase of natural gas		161,088		149,221
	$	2,794,058	$	1,529,826

F-138

Ecopetrol S.A.

Notes to the Non Consolidated Financial Statements (unaudited)

23. Operating, Administrative and Selling Expenses

	Jun-08		Jun-07
Administration:
Labor	$	82,924	$	68,108
Depreciation and amortization		23,848		19,989
Taxes		23,499		8,436
General expenses		17,297		14,524
Amortization of actuarial calculation		15,558		21,240
Leases		4,582		9,295
		167,708		141,592
Selling:
Crude oil pipeline transportation tariff		198,722		92,585
Studies and projects		139,754		160,122
Tariff and BOMT gas pipelines capacity payment		112,363		60,691
Taxes		66,598		59,875
Gas pipeline transportation tariff		46,844		42,470
Commissions, fees and services		18,396		11,755
Labor expenses		7,484		5,008
Amortization of actuarial calculation		1,959		3,017
		592,120		435,523
	$	759,828	$	577,115

24. Financial Income, Net

	Jun-08		Jun-07
Income:
Exchange gain	$	2,882,883	$	998,041
Valuation of investments		389,061		212,734
Interest and monetary correction		302,431		60,262
Dividends in cash		39,465		7,542
Profit of investments and equity method		12,349		1,443
Profit valuation of derivatives		4,782		—
FAEP earnings		—		77,763
		3,630,971		1,357,785
Expenses:
Exchange loss		3,125,944		1,749,772
Loss valuation of derivatives		28,299		—
Administration and issue of securities		7,606		236
Other		806		1.021
Hedging operations		496		43,448
Interest, commissions and premiums		353		864
Loss of investments and equity method		10		118
		3,163,514		1,795,459
	$	467,457		($437,674	)

F-139

Ecopetrol S.A.

Notes to the Non Consolidated Financial Statements (unaudited)

25. Pension Expenses

	Jun-08		Jun-07
Amortization of actuarial calculation	$	504,157	$	365,158
Health care services		51,184		38,557
Education services		27,796		26,280
	$	583,137	$	429,995

26. Inflation Gain

This gain corresponds to net amortization of deferred monetary correction.

27. Other Income (Expenses), Net

	Jun-08			Jun-07
Income:
Recovery of provisions (1)	$	387,636		$	207,951
Differed income BOMT		67,008			1,118,661
Adjustment of natural gas prices		31,845			3,062
Prior year income (2)		13,396			3,112
Other revenues		12,252			64,235
Recovery of other expenses		4,483			8,036
Income on sale of property, plant and equipment		2,699			26,814
Income for services		1,752			4,144
		521,071			1,436,015
Expenses:
Taxes		247,136			267,617
Provisions (3)		190,872			211,342
Fuel loss		39,323			23,915
Prior year expenses (4)		20,620			1,300
Other tax expenses		13,716			13,896
Surveillance and guards		5,704			7,758
Contributions and donations		4,872			4,703
Other expenses		2,042			14,396
Amortization of BOMT expenses		—			1,018,422
		524,285			1,563,349
		($ 3,214	)		($ 127,334	)

(1) A detail of the recovery of provisions follows:

	Jun-08		Jun-07
Legal processes	$	376,499	$	22,652
Taxes		9,011		98,327
Inventories		2,126		6,529
Projects’ expenses		—		66,387
Receivables		—		13,836
Investments		—		220
	$	387,636	$	207,951

(2) A detail of prior years’ income is as follows:

F-140

Ecopetrol S.A.

Notes to the Non Consolidated Financial Statements (unaudited)

	Jun-08		Jun-07
Natural gas sales 2007	$	7,886	$	—
Financial income		3,782		—
Technology fund		1,445		—
Health services		—		1,763
Expense recovery		283		1,349
	$	13,396	$	3,112

(3) A detail of provision expenses is as follows:

	Jun-08		Jun-07
Legal processes	$	89,206	$	186,322
Inventories		100,363		18,176
Investments		693		3,066
Receivables		610		3,778
	$	190,872	$	211,342

(4) A detail of prior years’ expenses is as follows:

	Jun-08		Jun-07
Natural gas sales 2007	$	19,294	$	—
Right of use – usufruct		—		1,180
General expenses		1,326		120
	$	20,620	$	1,300

28. Contingencies

1. An expert’s opinion in 2005 determined a fixed amount claim of $542,000 million against Ecopetrol corresponding to the ordinary civil action filed by Foncoeco, which alleged that Ecopetrol should have paid capital and financial income authorized by the Board of Directors to set-up the profit participation fund of the Company’s employees. In the opinion of Management and its legal counsel, there are enough arguments to demonstrate that the Board of Directors never appropriated funds to set-up a trust. Furthermore, Foncoeco is not the entitled to that amount and accordingly the claims under the lawsuit are not reasonable.

2. Ecopetrol has recognized provisions corresponding to reasonable estimates intended to cover future situations deriving from loss contingencies on the occurrence of future events that could affect equity. In 2007, the Company reevaluated its policy related to the valuation of such estimates and claims and included the results due to their value, which could result in a material contingency regardless that the probability of loss was remote.

F-141

Ecopetrol S.A.

Notes to the Non Consolidated Financial Statements (unaudited)

A summary of the most significant estimates (claim amount in excess of $40 billions) for which provisions have been recognized, in accordance with the evaluations of the Company’s internal and external legal advisors at June 30, 2008:

Process	Action	Amount of Claims
Gobernación del Tolima/ Municipio de Melgar	Popular action for the re-liquidation of royalties with the 20% stipulated in Law 141 of 1994.	$162,989
Universidad de Cartagena y Junta Especial de la Estampilla	Compliance action for the payment of the stamp on exports made by Ecopetrol between 1997 and 2004.	96,151
Latinamerican Hydrocarbon Corporation S.A.	Ordinary Administrative Process to obtain the declaration that the condensate supply contract clauses were not complied with by Ecopetrol.	162,052
Freddy Antonio Otálvaro Gómez and Others	Constitutional Action to declare the responsibility of Ecopetrol in the ecological and environmental impairment in the mangrove swamps and asturiana of Bahía de Tumaco due to crude oil spills.	78,790
Asociación Integración Costeña Costa Pesquera, Agrícola Y Conchera Y Asopesmar	Contractual Civil Responsibility Process caused by the spill of crude oil in the Transandino pipeline, which is property of Ecopetrol.	20,000
Metalización S.A	Contractual Process for insufficiency and errors in the information provided at the bid for the contract.	28,000
Jose Luis Romero Barreto	Direct Reparation Process for the spilling of crude oil, property of Ecopetrol causing a car accident.	22,693
Germán Mogollón Hernandez	Ordinary Civil Process for the payment of contributions in compliance with Law 99 of 1993 and Law 143 of 1994, and Decree 1933 of 1994.	20,000
Petróleos Del Norte	Ordinary Administrative Process to declare nullity of the resolution that ordered a reversion of the Zuila concession contract.	20,000
Antonio Jose Stambulie Saer	Ordinary Civil Process that requires Ecopetrol to transfer 4% of its equivalent electrical energy production.	20,000
Bolívar Amaya López Y Otros 320 Aprox.	Ordinary Civil Process claiming existence of the contract Ecopetrol - GAPS.	13,440
Javier Armando Rincón Gama Y Héctor Alfredo Suarez Mejía	Ordinary Civil Process – VIF. Thru auction, stocks of Gases de Colombia S.A. were purchased, which were property of Ecopetrol.	12,000

29. Commitments

Acquisition of Andean Chemical Limited and Propilco S.A.

Additionally to Note 4, an adjustment to the purchase price was contemplated, corresponding to the difference between working capital at November 30, 2007 and March 31, 2008.

F-142

Ecopetrol S.A.

Notes to the Non Consolidated Financial Statements (unaudited)

Natural Gas Supply Contracts

The Company has entered into contracts with third parties, such as Gecelca, Gas Natural S.A. E.S.P, Empresas Públicas de Medellín, Termoflores and Gases de Norte del Valle, for the supply of natural gas in developing its commercialization, whereby it commits to deliver the minimum quantities established in each contract. During 2007, Ecopetrol commercialized 160.847 GBTUD for $660,171.

TLU 1 and TLU 3 Master Agreement

In March 1998 and September 1999, the Company entered into agreements, : TLU-1 – joint operation of the assets at the Coveñas terminal for the receipt, storage and loading of tankers with crude oil between the Cravo Norte Association and Oleoducto de Colombia S.A.; and TLU-3 – joint operation for the use of the loading unit of vessel tanks TLU-3 at the Coveñas terminal between the Cravo Norte Association, Oleoducto de Colombia S.A. and Oleoducto Central S.A., respectively, agreements where the parties designated Ecopetrol as the Operator.

Petro Rubiales S.A.

In December 2007, the Company signed a memorandum of understanding with Petro Rubiales S.A. for the construction of a 230 kilometer pipeline, which will permit transporting the crude oil extracted from the Rubiales and Pirirí fields in the Department of Meta, to be connected with the Oleoducto Central (Ocensa) system. Ecopetrol´s participation is 65% with its start-up operation expected to begin during 2009.

Exploration

Ecopetrol and Turkish Petroleum International Company Limited (TPIC) subscribed an agreement to carry out exploratory activities in “Bloque González”, located in the “Departamento de Norte de Santander”, approximately 50 kilometers north of Cucuta City.

The subscribed agreement, subject to the ANH approval, contemplates the acquisition of 20 kilometers worth of seismic and the perforation of one exploratory well. TPIC will assume the initial costs of the project.

Ecopetrol participates with 50%; meanwhile, TPIC has the 50% remainder of the project. “Bloque González” has an extension of 21.809 hectares. TPIC will be the operator.

TPIC is a subsidiary of Turkish Petroleum Corporation (TPAO), which ranks among the top 100 largest petroleum companies in the world according to “Petroleum Intelligence Weekly” (PIW).

TPAO produces near 75% of the crude oil consumed in Turkey. The company concentrates its operations in the Caspio region, North of Africa and the Middle East.

Empresa Colombiana de Gas –Ecogas

In compliance with Law 401, during 1998, Ecopetrol subscribed an agreement with “Transportadora de Gas de la Región, Centragás y Transgás de Occidente S.A.” granting Ecogas the rights and obligations derived from the BOMT contract.

F-143

Ecopetrol S.A.

Notes to the Non Consolidated Financial Statements (unaudited)

On December 2006, the selling process of Ecogas was settled and “Empresa de Energía de Bogotá” acquired the rights.

On February 22, 2007, Ecopetrol subscribed along with Ecogas, and the Colombian Nation through the Ministry of Finance an agreement that allowed the Nation to handle and manage the funds that Ecogas had set up to pay the obligation. During 2007, the Company collected the total receivables from Ecogas.

30. Subsequent events

On June 2008, a shareholders agreement was signed between the Company and Petrorubiales to set up ODL Finance, where Ecopetrol has a 65% interest whereas Petrorubiales has 35%.

ODL Finance will be established in Panama; its main purpose will be to serve as an investment vehicle of Oleoducto de los Llanos Orientales S.A. – ODL.

31. Reclassifications

Certain prior figures in the statements of financial, economic and social activity of 2007 were reclassified for comparative purposes with those of 2008, as a result of the establishment of new parameters of accounts in the accounting application because of the operating reorganization of certain areas, such as those related with resources given for administration purposes, the pension liability, operating expenses, the cost of sales, mainly, and the adjustment of the official accounting plan of CGN for governmental companies.

F-144

Exhibit Numbers	Description
1.1	By-laws of Ecopetrol S.A. dated November 6, 2007 as recorded under Public Deed No. 5314 of November 14, 2007.
4.1	Transportation Agreement between Ecopetrol S.A. and Ocensa S.A., dated March 31, 1995.
4.2	Natural Gas Transportation Agreement between Ecopetrol S.A. and Empresa Colombiana de Gas- Ecogás, dated October 6, 2006.
15.1	Consent of Ernst & Young Audit Ltda. dated September 12, 2008.
15.2	Consent of Ryder Scott dated September 12, 2008.
15.3	Consent of DeGolyer and MacNaughton dated September 12, 2008.
15.4	Consent of Gaffney, Cline & Associates dated September 11, 2008.

F-145

SIGNATURE

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

	ECOPETROL S.A. (Registrant)
Date: September 12, 2008	/s/ Javier G. Gutierrez
	Name: Javier G. Gutierrez Title:   Chief Executive Officer