As filed with the Securities and Exchange Commission on april 30, 2012

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 20-F

ANNUAL REPORT PURSUANT TO SECTION 13 OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2011

Commission file number: 001-34175

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 13 No. 36 – 24

BOGOTA – COLOMBIA

(Address of principal executive offices)

Alejandro Giraldo

Investor Relations Officer

investors@ecopetrol.com.co

Tel. (571) 234 5190

Fax. (571) 234 5628

Carrera 13 N.36-24 Piso 8

Bogota, Colombia

(Name, Telephone, E-Mail and/or Facsimile number and Address of Company Contact Person)

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 20 common shares par value Ps$250 per share	New York Stock Exchange
Ecopetrol common shares par value Ps$250 per share	New York Stock Exchange (for listing purposes only)
7.625% Notes due 2019	New York Stock Exchange

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

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

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.

41,116,698,456 Ecopetrol common shares, par value Ps$250 per share

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

xYes ¨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.

¨Yes xNo

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.

xYes ¨No

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

N/A

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 x     Accelerated filer ¨   Non-accelerated filer ¨

Indicate by check mark which basis of accounting the registrant has used to prepare the financial statements included in this filing:

¨ U.S. GAAP ¨ International Financial Reporting Standards as issued by the International Accounting Standards Board x Other

If “Other” has been checked in response to the previous question, indicate by check mark which financial statement item the registrant has elected to follow:

¨ Item 17 x Item 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).

¨Yes xNo

TABLE OF CONTENTS

		Page
	Forward-Looking Statements	1
	Enforcement of Civil Liabilities	1
	Presentation of Financial Information	2
	Presentation of Abbreviations	4
	Presentation of The Nation and Government of Colombia	4
	Presentation of Information Concerning Reserves	4
ITEM 1.	Identity of Directors, Senior Management and Advisors	5
ITEM 2.	Offer Statistics and Expected Timetable	5
ITEM 3.	Key Information	5
	Selected Financial Data	5
	Exchange Rate Information	7
	Risk Factors	8
ITEM 4.	Information on the Company	21
	The Company	21
	Overview By Business Segment	25
	Transportation Infrastructure	47
	Property, Plant and Equipment	64
ITEM 4A.	Unresolved Staff Comments	64
ITEM 5.	Operating and Financial Review and Prospects	64
	Operating Results	71
	Liquidity and Capital Resources	81
	Research and Development, Patents and Licenses, etc.	84
	Off-Balance Sheet Arrangements	85
	Tabular Disclosure of Contractual Obligations	85
ITEM 6.	Directors, Senior Management and Employees	85
	Directors and Senior Management	85
	Compensation	89
	Share Ownership	89
	Board Practices	89
	Employees	91
ITEM 7.	Major Shareholders and Related Party Transactions	93
	Major Shareholders	93
	Related Party Transactions	93
ITEM 8.	Financial Information	97
	Consolidated Statements And Other Financial Information	97
	Legal Proceedings	98
	Dividends	98
	Significant Changes	99
ITEM 9.	The Offer and Listing	99
	Trading Markets	99
	Trading On The Bolsa De Valores De Colombia	100
ITEM 10.	Additional Information	101
	Bylaws	101
	Material Contracts	104
	Exchange Controls	105
	Taxation	106
	Documents On Display	110
ITEM 11.	Quantitative and Qualitative Disclosures About Market Risk	110
ITEM 12.	Description of Securities Other than Equity Securities	112
ITEM 12A.	Debt Securities	112
ITEM 12B.	Warrants and Rights	112
ITEM 12C.	Other Securities	112

i

		Page
ITEM 12D.	American Depositary Shares	112
ITEM 13.	Defaults, Dividend Arrearages and Delinquencies	113
ITEM 14.	Material Modifications to the Rights of Security Holders and Use of Proceeds	113
ITEM 15.	Controls and Procedures	114
ITEM 16.	[Reserved]	115
ITEM 16A.	Audit Committee Financial Expert	115
ITEM 16B.	Code of Ethics	115
ITEM 16C.	Principal Accountant Fees and Services	115
	Audit and Non-Audit Fees	115
ITEM 16D.	Exemptions from the Listing Standards for Audit Committees	116
ITEM 16E.	Purchases of Equity Securities by the Issuer and Affiliated Purchasers	116
ITEM 16F.	Change in Registrant’s Certifying Accountant	116
ITEM 16G.	Corporate Governance	116
ITEM 16H.	Mine Safety Disclosure	118
ITEM 17.	Financial Statements	118
ITEM 18.	Financial Statements	118
ITEM 19.	Exhibits	119

ii

Forward-Looking Statements

This annual report on Form 20-F contains forward-looking statements 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,” “achieve,” and “intend,” 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; and

· 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 and other countries where we do business;

· military operations, terrorist acts, wars or embargoes;

· regulatory developments, including regulations related to climate change;

· natural disasters;

· technical difficulties; and

· 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 annual report.

Enforcement of Civil Liabilities

We are a Colombian company, all of our Directors and executive officers and certain of the experts named in this annual report reside outside the United States.  All or a substantial portion of our assets and the assets of these persons are located outside of 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 judgments in U.S. courts obtained in such courts predicated upon the civil liability provisions of the U.S. federal securities laws.  Colombian courts will determine whether to enforce a U.S. judgment predicated on the U.S. securities laws through a proceeding 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;

1

· 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 laws 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.

Presentation of Financial Information

Unless the context otherwise requires, the terms “Ecopetrol,” “we,” “us,” “our,” the “Company” or the “Corporate Group” are used in this annual report to refer to Ecopetrol S.A. and its subsidiaries on a consolidated basis.

In this annual report, 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 annual report have been subject to rounding adjustments and, accordingly, certain totals may therefore not precisely equal the sum of the numbers presented. In this annual report a billion is equal to one with nine zeros.

Our consolidated financial statements are prepared in accordance with accounting principles for Colombian state-owned entities issued by the Colombian National Accounting Office (Contaduría General de la Nación), or CGN and other applicable legal provisions. The CGN adopted new accounting principles for Colombian state-owned entities in September 2007. These accounting principles are known as the Regime of Public Accounting (Régimen de Contabilidad Pública), or RCP. Pursuant to CGN Communication No. 0079 101345 of September 28, 2007, RCP became effective for Ecopetrol beginning with the fiscal year ended December 31, 2008. Our consolidated financial statements at and for the years ended December 31, 2011, 2010 and 2009 have been prepared under RCP. See Note 1 to our consolidated financial statements “Economic Entity and Principal Accounting Policies and Practices.” Our consolidated financial statements for all prior years were prepared under the General Governmental Accounting Plan (Plan General de Contabilidad Pública), or PGCP, the former accounting principles issued by CGN for Colombian state-owned entities. RCP differs in certain respects from PGCP. See Note 1 to our consolidated financial statements “Economic Entity and Principal Accounting Policies and Practices.” We refer to both RCP and PGCP as Colombian Government Entity GAAP. Colombian Government Entity GAAP differs in certain significant respects from generally accepted accounting principles in the United States, or U.S. GAAP. Note 34 to our consolidated financial statements included in this annual report 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. As a state-owned company, our consolidated financial statements are periodically reviewed by the CGN. However, the review of our accounts by the CGN does not constitute an audit.

The accompanying audited consolidated financial statements of Ecopetrol and our consolidated subsidiaries for the years ended December 31, 2011, 2010 and 2009 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 CGN.

2

Our consolidated financial statements were consolidated line by line and all transactions and significant balances between affiliates have been eliminated. These financial statements include the financial results of the following companies:

COMPANY	OWNERSHIP %		Included in consolidated Financial Statements for the year ended
			2011		2010		2009
Black Gold Re Ltd.		100.00		X		X		X
Ecopetrol Oleo é Gas Do Brasil Ltda.		100.00		X		X		X
Ecopetrol del Perú S.A.		100.00		X		X		X
Ecopetrol America Inc.		100.00		X		X		X
Andean Chemicals Ltd.		100.00		X		X		X
Polipropileno del Caribe S.A. (Propilco)		100.00		X		X		X
Ecopetrol Global Energy SLU		100.00		X		X		X
Ecopetrol Transportation Company Ltd.		100.00		X		X		X
Refinería de Cartagena S.A. (Reficar)		100.00		X		X		X
COMAI Compounding and Masterbatching Industry Ltda.		100.00		X		X		X
Hocol Petroleum Ltd.		100.00		X		X		X
Ecopetrol Transportation Investment Ltd.		100.00		X		X
Ecopetrol Capital AG		100.00		X		X
Bioenergy S.A.		88.60		X		X		X
ODL Finance S.A.		65.00		X		X		X
Oleoducto Central S.A. (Ocensa)		72.65		X		X		X
Oleoducto de Colombia (ODC)		73.00		X		X		X
Equion Energía Ltd. (Equion)		51.00		X
Oleoducto Bicentenario de Colombia S.A.S		55.97		X		X

This annual report 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$1,942.70 per US$1.00, which corresponds to the Tasa Representativa del Mercado or Representative Market Rate for December 31, 2011. 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 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 April 30, 2012, the Representative Market Rate was Ps$1,761.20 per US$1.00.

3

Presentation Of Abbreviations

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

bpd	Barrels per day
boe	Barrels of oil equivalent
boepd	Barrels of oil equivalent per day
btu	British thermal units
cf	Cubic feet
cfpd	Cubic feet per day
mcf	Million cubic feet
mcfpd	Million cubic feet per day
mbtu	Million British thermal units
gbtu	Giga British thermal units
gbtud	Giga British thermal units per day
bcf	Billion Cubic feet

Presentation Of The Nation And Government Of Colombia

References to the Nation in this annual report 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 annual report.  Our hydrocarbon net proved reserves have been audited in 2011 by Ryder Scott Company L.P., DeGolyer and MacNaughton and Gaffney, Cline & Associates Inc., which we refer to collectively as the External Engineers, and their reserves reports are included as exhibits herein. See “Item 4.  Information on the Company—Overview by Business Segment—Exploration and Production—Reserves” for additional information on our reserves estimates.

The following table sets forth the percentage of our estimated net proved reserves audited by External Engineers and the percentage calculated internally for the years ended December 31, 2011, 2010 and 2009. The estimates of our proved reserves of crude oil and natural gas included in this annual report have been calculated according to the technical definitions required by the U.S. Securities and Exchange Commission, or SEC.

	Estimated proved reserves for the year ended December 31,
	2011			2010			2009
Net proved reserves audited by External Engineers		99	%		99	%		97	%
Net proved reserves estimates on our own calculations		1	%		1	%		3	%

On December 31, 2008, the SEC issued a final rule revising disclosure requirements relating to oil and gas reserves. Our proved reserves as of December 31, 2011, 2010, and 2009 are based on the SEC average price methodology for purposes of both Colombian Government Entity GAAP and U.S. GAAP. All reserve estimates involve some degree of uncertainty. See “Item 3. Key Information—Risk Factors—Risks related to our business” for a description of the risks in relation to our reserves and our reserve estimates.

We are required, as are all oil companies undertaking exploratory and production activities in Colombia, to pay in kind a percentage of our production to the Government as royalties. The oil and gas reserve figures included in this annual report are net of such royalties.

4

ITEM 1. Identity of Directors, Senior Management and Advisors

Not applicable.

ITEM 2. Offer Statistics and Expected Timetable

Not applicable.

ITEM 3. Key Information

Selected Financial Data

The following table sets forth, for the periods and at the dates indicated, our summary historical financial data, which have been derived from our consolidated financial statements, presented in Pesos. KPMG Ltda. audited our consolidated financial statements for the year ended December 31, 2011. Our consolidated financial statements for the years ended December 31, 2010, 2009, and 2008 were audited by PricewaterhouseCoopers Ltda. and our consolidated financial statements for the year ended December 31, 2007 were audited by Ernst & Young Audit Ltda. The information included below and elsewhere in this annual report is not necessarily indicative of our future performance. The tables set forth below are derived from, and should be read in conjunction with, our consolidated financial statements and accompanying Notes included in this annual report. See also “Item 5. Operating and Financial Review and Prospects” in this annual report.

Colombian Government Entity GAAP differs in certain significant respects from U.S. GAAP. For a description of the principal differences between Colombian Government Entity GAAP and U.S. GAAP as they relate to us, a reconciliation to U.S. GAAP of net income and shareholders’ equity, and financial statements under U.S. GAAP, see Note 34 to our consolidated financial statements and “Item 5. Operating and Financial Review and Prospects— Principal Differences between Colombian Government Entity GAAP and U.S. GAAP.

	BALANCE SHEET
	For the year ended December 31,
	2011(1)		2011			2010			2009			2008			2007
	(Pesos in millions and US$ in thousands except for common share and dividends per share amounts)
Total assets		47,499,555		92,277,386			68,769,356			55,559,517			48,702,412			48,112,080
Shareholders’Equity		28,150,952		54,688,855			41,328,181			32,569,957			34,619,717			26,808,467
Subscribed capital		5,291,180		10,279,175			10,118,128			10,118,128			10,118,128			10,118,128
Number of common shares(2)		41,116,698,456		41,116,698,456			40,472,512,588			40,472,512,588			40,472,512,588			40,472,512,588
Dividends declared per share:		0.07		145	(3)		91.0	(3)		220.0	(3)		115.0	(3)		123.0	(4)
Amounts in accordance with U.S. GAAP
Total Assets		36,500,272		70,909,079			52,332,148			42,624,352			40,244,452			29,698,528
Ecopetrol Shareholders’ Equity		18,559,311		36,055,173			27,175,285			22,383,712			27,425,735			20,991,031
Number of common shares(2)		41,116,698,456		41,116,698,456			40,472,512,588			40,472,512,588			40,472,512,588			40,472,512,588
Dividends declared per share:		0.07		145			91.0			220.0			115.0			123.0

(1) Amounts stated in U.S. dollars have been translated for the convenience of the reader at the rate of Ps$1,942.70 to US$1.00, which is the Representative Market Rate at December 31, 2011, as reported and certified by the Superintendency of Finance.

(2) Number of common shares includes (i) 48,512,147 shares issued to the nation on April 2007, representing in-kind contributions, (ii) a 1 to 400 stock split in July 2007, which for purposes of comparability and dividends per share has been applied as if it had occurred in 2006, (iii) 4,087,723,771 shares issued to the public in connection with our initial offering of shares in Colombia in November 2007, and (iv) 644,185,868 shares issued to the public in connection with our subsequent offering of shares in Colombia in September 2011.

(3) Represents payments made in 2011, 2010, 2009 and 2008, based on net income and retained earnings for the years ended December 31, 2010, 2009, 2008 and 2007, respectively.

(4) In 2007 dividends were declared and paid on 36,384,788,817 shares. In the same year, 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.

5

	INCOME STATEMENT
	For the year ended December 31,
	2011(1)		2011		2010		2009		2008		2007
	(US$ in thousands except for net income per share and average number of shares amounts)		(Pesos in millions except for net income per share and average number of shares amounts)
Total revenue		33,845,817		65,752,268		41,968,311		30,404,390		33,896,669		22,332,320
Operating income		13,224,359		25,690,963		12,878,842		7,873,339		12,657,358		8,959,138
Net operating income per share		0.33		632		318		195		313		292
Income before income tax		12,169,368		23,641,432		11,492,617		7,250,844		16,011,204		7,065,304
Net income		7,954,051		15,452,334		8,146,471		5,132,054		11,629,677		5,179,792
Weighted average number of shares outstanding(2)		40,634,882,725		40,634,882,725		40,472,512,588		40,472,512,588		40,472,512,588		30,702,164,870
Net income per share(3)		0.20		380		201		127		287		169
Amounts in accordance with U.S. GAAP
Total revenue		32,282,810		62,715,815		40,879,324		29,551,574		33,849,213		22,784,694
Operating income		12,186,023		23,673,787		13,878,514		8,055,213		9,840,311		8,455,099
Net operating income per share		0.30		583		343		199		243		229
Income before income tax		12,074,064		23,456,285		12,840,721		8,768,383		13,427,443		8,710,648
Net income attributable to Ecopetrol		7,627,121		14,817,207		8,211,035		5,718,304		8,841,883		6,144,685
Net income per share		0.19		365		203		141		218		166
Average number of shares outstanding(4)		40,634,882,726		40,634,882,726		40,472,512,588		40,472,512,588		40,472,512,588		36,922,352,491

(1) Amounts stated in U.S. dollars have been translated for the convenience of the reader at the rate of Ps$1,942.70 to US$1.00, which was the Representative Market Rate at December 31, 2011, 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. The weighted average number of common shares outstanding during 2011 was 40,634,882,725 as a result of the second public offering in Colombia.

(3) Net income per share is calculated using the weighted-average number of outstanding shares at December 31 of each year.

(4) Calculated in accordance with U.S. GAAP, which differs in certain respects with the calculation of weighted average number of shares pursuant to Colombian Government Entity GAAP.

6

Exchange Rate Information

On April 30, 2012, the Representative Market Rate was Ps$1,761.20 per US$1.00. The Federal Reserve Bank of New York does not report a noon-buying rate for Colombian Pesos. The Superintendency of Finance calculates the Representative Market Rate based on the weighted averages of the buy/sell foreign exchange rates quoted daily by foreign exchange rate market intermediaries including financial institutions for the purchase and sale of U.S. dollars.

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

	Exchange Rates
	High		Low		Average		Period-End
Year ended December 31,
2007		2,261.22		1,877.88		2,078.35		2,014.76
2008		2,392.28		1,652.41		1,966.26		2,243.59
2009		2,596.37		1,825.68		2,156.29		2,044.23
2010		2,044.23		1,786.20		1,897.89		1,913.98
2011		1,972.76		1,748.41		1,848.17		1,942.70
October		1,972.76		1,862.84		1,910.38		1,863.06
November		1,967.18		1,871.49		1,918.21		1,967.18
December		1,949.56		1,920.16		1,934.08		1,942.70
2012:
January		1,942.70		1,801.88		1,852.12		1,815.08
February		1,805.98		1,767.83		1,738.56		1,767.83
March		1,784.66		1,758.03		1,766.34		1,792.07
April		1,793.30		1,761.20		1,775.06		1,761.20

Source: Superintendency of Finance for historical data. Banco de la República, or the Colombian Central Bank, for averages.

7

Risk Factors

Risks relating to Colombia’s political and regional environment

Colombia has experienced internal security issues that have had or could have 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, drug cartels and criminal bands known as Bacrim. From time to time, guerrillas target crude oil pipelines, including the Oleoducto Transandino, Caño Limón-Coveñas and Ocensa pipelines, and other related infrastructure disrupting our activities and those of our business partners. Over the last year, these attacks have intensified. On several occasions, guerilla attacks have resulted in unscheduled shut-downs of transportation systems in order to repair sections of pipelines that have been damaged and to undertake clean-up activities, as well as in deferral of production in certain fields. Guerrilla groups and other illegal armed groups also attacked natural gas transportation infrastructure. Although we do not have any interest in natural gas transportation assets, these attacks have affected our natural gas production. These activities, their possible escalation and the effects 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, assets or the environment, with resulting containment, clean-up and repair expenses. In the context of this situation, allegations and court judgments have been levied against members of the Colombian Congress and on Government officials for possible ties with illegal groups. This situation may have a negative impact on the credibility of the Colombian Government, which could in turn have a negative impact on the Colombian economy or on us in the future.

There have been certain events in Colombia and abroad, which have resulted in political tensions between Colombia and some of its neighboring countries.

Events such as the Colombian Government-sponsored attacks on a Revolutionary Armed Forces of Colombia, or FARC, camp in Ecuador in 2008, which resulted in the death of one of the members of the FARC’s Secretariat, or the signing in 2009 of a military treaty between Colombia and the United States (which was not ratified by the Colombian Constitutional Court in an August 2010 decision) have made the diplomatic relations between Colombia and some of its neighboring countries, in particular Ecuador and Venezuela, very tense. These political tensions were heightened by the Colombian Government’s allegations that neighboring countries are supporting the guerilla groups. 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 Colombia, including Colombia’s borders. Although relations with neighboring countries have stabilized recently, there can be no assurance that similar events could not occur again resulting in new and heightened tensions with Colombia’s neighbors, which have had in the past, and could have in the future, a negative impact on Colombia’s economy and general security situation.

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

Market prices of securities issued by Colombian companies, including us, are subject to the prevailing economic conditions in Colombia. A large portion of our assets and operations are located in Colombia, and most 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 changed monetary, fiscal, taxation, labor and other policies over time and has thus influenced the performance of the Colombian economy. We have no control over the extent and timing of government intervention and policies.

Juan Manuel Santos was elected President of Colombia on June 20, 2010. The investment and security climate in the country will continue to be tied to how the results and performance of his administration and the application of its economic, security and social policies are perceived by foreign investors. During his first year as President, Juan Manuel Santos has continued policies to increase foreign investment in Colombia as well as to improve relations with neighboring countries, which have resulted in economic stability for Colombia. In 2011, Colombia’s annual gross domestic product increased by 5.9% due principally to an increase of 14.3% in crude oil and mining production.

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

Developments and the perception of risk in other countries, especially emerging market countries, may adversely affect the market price of Colombian securities, including our 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, Perú, Brazil and Panama. Although economic conditions in these Latin American countries 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 past financial 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), the world financial crisis of 2009 and the current sovereign debt crises in certain European countries, investors may view investments in emerging markets with heightened caution. In the past, as a result of crises in other countries, flows of investments into Colombia have been reduced. Crises in other countries, especially in 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.

Our controlling shareholder’s interests may be different from those of our minority shareholders.

The Nation is our largest shareholder controlling 88.47% 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, make decisions or announcements about its intentions related to its holding of our capital stock, which may not be in our best interest or in the best interest of our minority shareholders, including holders of our ADSs, and could impact the price of our shares or ADSs.

Additionally, the Nation through its majority voting right, may approve dividends at the ordinary general shareholders’ meeting, notwithstanding the interests of minority shareholders, in an amount that results in us having to reduce our capital expenditures, thereby negatively affecting our prospects, results of operations and financial condition. See “Item 8. Financial Information—Dividends.”

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 (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. The commercialization activities of some of our products also have extensive regulation. Such regulation is subject to change by the applicable regulator affecting our ability to commercialize our products. See “Item 4. Information on the Company—Overview by Business Segment—Regulation.”

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 in kind a percentage of our production to the Government as royalties. The oil and gas reserve figures included in this annual report are net of such 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. Since2002, the royalty regime for contracts being entered into for crude oil is tied to a scale that begins at 8% for production of up to 5,000 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 an adverse effect on our future exploration and production contracts in Colombia.

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

The Government regulates domestic prices of liquid fuels according to international market conditions in order to align domestic prices with trends in international prices, with a one-month lag. When domestic prices of liquid fuels are lower than international parity prices, the Government is responsible for reimbursing importers or refiners for the difference, which is called the fuel price differential, pursuant to Law 1151 of 2007. The fuel price differential is calculated on a monthly basis and reported on a quarterly basis, with the corresponding cash payment to be made during the subsequent quarter. In cases of payment delays, refiners are entitled to receive interest on past due amounts.

Historically, when domestic prices of liquid fuels were higher than international parity prices, the Government lowered domestic prices. However, towards the end of 2008 as international prices decreased, the Government decided not to lower domestic prices. Instead, the Government kept domestic prices high and allocated the positive difference between domestic fuel prices and the international parity prices to a Fuels Stabilization Fund (Fondo de Estabilización de Precios de los Combustibles), or FEPC. Similar to the approach followed by other countries, the FEPC is funded with these excess payments when international prices are low and depleted when international prices are high in order to mitigate domestic price volatility.

During 2010, oil refiners, including us, were entitled to fuel price differential payments based on trends in international prices. The payments made by the Ministry of Mines and Energy to us corresponded to the first three quarters of the year. However, the amount due to us by the Ministry, which includes the fuel price differential payment and the opportunity cost recognized to compensate the delay on the payments, as of December 31, 2010, amounting to Ps$163.4 billion, was not made until the fourth quarter of 2011. During 2011, the fuel price differential payments corresponding to the first three quarters of the year were not paid until December 2011. The fuel price differential payment due to us as of December 31, 2011, equal to Ps$571.7 billion, had not been made by the end of the first quarter of 2012.

Past delays in price differential payments make it difficult to determine when we will collect the amount of any fuel price differentials that become due in the future. Any material delay in the payment of these fuel price differentials by the Government or a significant amendment to Law 1151 of 2007 imposing additional responsibilities on us with respect to fuel price differentials could have a negative impact on our financial condition and results of operations. On September 30, 2011, the Ministry of Mines and Energy established a new methodology to calculate domestic prices of gasoline and diesel fuel, which sets the maximum monthly variation in refiners’ revenues at 1.5%. Currently, the Colombian Congress is discussing a bill to introduce a new methodology to calculate fuel price differentials, and determine the maximum retail price of gasoline and diesel, including the revenues for the Colombian refineries. There can be no assurance that this bill, if enacted into law, will not negatively affect the amount and timeliness of the fuel price differential payments, which in turn could affect our financial condition and results of operations.

New or higher taxes resulting from changes in tax regulations or the interpretation thereof in Colombia could adversely affect our results of operations and financial condition.

New tax laws and regulations, and uncertainties with respect to future tax policies, pose risks to us. In recent years, Colombian tax authorities have imposed additional taxes in a variety of areas, such as taxes on financial transactions and other taxes on net worth. Changes in tax-related laws and regulations, and interpretations thereof, can affect tax burdens by increasing tax rates and fees, creating new taxes, limiting tax deductions, and eliminating tax-based incentives and non-taxed income. In addition, tax authorities or courts may interpret tax regulations differently than we do, which could result in tax litigation and associated costs and penalties. In order to avoid double taxation, our subsidiaries usually distribute dividends from profits that have already been subject to income tax. These dividends are usually not taxable for us in Colombia, and dividends paid by us to our shareholders in Colombia from these sources of income also are usually not taxable, in each case provided that such profits have been taxed at the subsidiary level. This tax treatment may not be maintained in the future, and any change could have an adverse effect on our results of operations and financial condition.

Risks related to our business

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.

Reserves estimates are prepared using generally accepted geological and engineering evaluation methods and procedures. Estimates are based on geological, topographic and engineering facts. Actual reserves and production may vary materially from estimates shown in this annual report, which could affect our results of operation.

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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 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;

· 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;

· natural events or disasters; and

· terrorism and global conflict.

As of December 2011, nearly 97% 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 consequently, fluctuations 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 or a change in our capital expenditure plan, in particular delaying exploration and development activities, thereby delaying the development of reserves and affecting future cash flows.

We are exposed to the credit risks of our customers and any material nonpayment or nonperformance by our key customers could adversely affect our cash flow and results of operations.

Some of our customers may experience financial problems that could have a significant negative effect on their creditworthiness. Severe financial problems encountered by our customers could limit our ability to collect amounts owed to us, or to enforce the performance of obligations owed to us under contractual arrangements. In addition, many of our customers finance their activities through their cash flows from operations, the incurrence of debt or the issuance of equity.

The combination of declining cash flows as a result of declines in commodity prices, a reduction in borrowing bases under reserve-based credit facilities and the lack of availability of debt or equity financing may result in a significant reduction of our customers’ liquidity and limit their ability to make payments or perform on their obligations to us.

Furthermore, some of our customers may be highly leveraged and subject to their own operating expenses. Therefore, the risk we face in doing business with these customers may increase. Other customers may also be subject to regulatory changes, which could increase the risk of defaulting on their obligations to us. For example, constraints on foreign currency transactions by the Venezuelan Government have resulted in delays by PDVSA Gas to make payments to its providers, including us. Financial problems experienced by our customers could result in the impairment of our assets, a decrease in our operating cash flows and may also reduce or curtail our customers’ future use of our products and services, which may have an adverse effect on our revenues.

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Achieving our long-term growth prospects depends on our ability to execute our Strategic Plan, in particular discovering additional reserves and successfully developing them.

We describe our Strategic Plan under “Item 4.  Information on the Company—The Company—Strategic Plan.” 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 and production targets, and may have a negative effect on our results of operation and financial condition.

Our participation in deep water drilling in conjunction with our business partners involves certain risks and costs, which may be outside of our control.

In association with our business partners, we have undertaken deep water exploratory drilling in the U.S. Gulf Coast and in Brazil. Additionally, we are involved in 15 off-shore exploratory and production projects in Colombia that involve deep-water drilling, of which we act as operators in seven, while Equion acts as operator in two. Our deep water drilling activities present several risks such as the risk of spills, explosions in platforms and drilling operations and natural disasters. The occurrence of any of these events or other incidents could result in personal injuries, loss of life, severe environmental damage with the resulting containment, clean-up and repair expenses, equipment damage and liability in civil and administrative proceedings. Heightened risks and costs associated with deep water drilling may have a negative effect on our results of operations, financial condition and reputation.

As a result of the oil spill in the Macondo field in the U.S. Gulf Coast in April 2010, significant concerns regarding the safety of deep water drilling had been raised and regulation in different countries has changed. In association with our business partners, which act as operators, we are currently drilling and have plans to drill exploratory wells in the U.S. Gulf Coast and Brazil. Since we have no control over these types of foreign government regulations, they may negatively impact the timing of our deep water drilling operations and consequently our results of operations and financial condition.

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 may be 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;

· theft;

· sabotage;

· terrorist attacks;

· equipment failures or accidents;

· fires, explosions, blow-outs and surface cratering;

· title problems;

· delays or cancellation of environmental licenses;

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· other adverse weather conditions and natural disasters; 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 local and 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 terms of reference 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 entitled to bid for any exploration blocks offered for exploration by the ANH and we compete under the same conditions as other domestic and foreign oil and gas companies, receiving no special treatment. We may also request the ANH to assign us exploration blocks which have not been previously reserved by that 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 face competition from local market players and international oil companies that have experience exploring in other countries.

If we are unable to adequately compete with local and foreign 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 conducting exploration activities in less attractive blocks, and we could reduce our market share participation. If we fail to maintain our current market position in Colombia, our results of operations and financial conditions may be adversely affected.

Our future performance depends on the successful development and deployment of new technologies and the knowledge to apply and improve them.

Technology, knowledge and innovation are essential to our business, especially for improvements in the production of heavy crude oil and the exploitation of mature fields. If we do not develop the right technology or do not obtain the expertise to operate new technology or to improve our processes, do not have access to, or deploy the knowledge necessary to apply and improve such technology effectively, the execution of our Strategic Plan, our profitability and our earnings 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, Ecopetrol Oleo é Gas Do Brasil Ltda. Our foreign subsidiaries have subsequently entered into a number of joint venture exploration agreements with regional and international oil companies to explore blocks in Perú, Brazil and the U.S. Gulf Coast. 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 experience exploring outside Colombia, where we are the incumbent operator. We may face new and unexpected risks involving environmental requirements that exceed those currently faced by us. Additionally, we may be exposed to legal disputes with foreign regulators. For example, we were awarded block Tucano-156 in Brazil in the 8th round of 2006. However, in August 2011, the Ministry of Mines and Energy of Brazil (Ministério de Minas e Energía) confirmed that the government would not sign any contract awarded in the 8th round of 2006, after the National Energy Policy Council (Conselho Nacional de Política Energética) decided to annul the bidding process. 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.

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.

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

We are currently a party to several legal proceedings 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. As of December 31, 2011, we were a party to 2,697 legal proceedings relating to civil, administrative, environmental, tax, and labor claims filed against us of which 784 met the accounting threshold for an accrual provision. We allocate substantial amounts of money and time to defend these claims. These claims involve substantial sums of money as well as other remedies. See Notes 19 and 31 to our consolidated financial statements and Item 8. “Financial Information—Legal Proceedings.”

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

The demand for natural gas has grown significantly in recent years. As a result of this growth, future demand for natural gas could exceed delivery capacity, resulting in possible supply shortages. When delivery shortages occur, we are required to compensate some 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 more competitive tariffs for retail customers. During 2009 and 2010, growth in demand was mainly driven by the natural weather phenomenon known as “El Niño,” which led to an increase in the demand for natural gas during certain months. This resulted in supply shortages and led the Ministry of Mines and Energy to ration natural gas, giving priority to natural gas delivery to certain areas of consumption regardless of supply contracts we had with our clients, forcing us to pay penalties and other compensatory expenses to certain of our clients whose demand was cut. During 2011, the natural weather phenomenon known as “La Niña”, which led to a more severe rain season, resulted in shortages in natural gas delivery caused by landslides which affected the transport infrastructure. During 2009, 2010 and 2011, the penalties paid in compensation for non-delivery of natural gas were Ps$27.8 billion (approximately US$14.5 million), Ps$85.2 billion (approximately US$44.5 million) and Ps$2.5 billion (approximately US$1.3 million), respectively.

We have long-term contracts to supply natural gas to power utilities and other large customers. In 2007, we signed an agreement with PDVSA Gas to supply natural gas to Venezuela and in December 2011 we extended this contract until June 2014. As a consequence of such extension, the gas supply from Venezuela that was expected to start in 2011 was rescheduled until July 2014, one month after the end of the exports from Colombia to Venezuela.

In the long term, we may not be able to keep up with local demand and industrial commitments if demand outpaces the rate of new gas developments and discoveries. Additionally, if we do not deliver natural gas to supply our contract clients due to specific situations, such as cuts in operations or delays in the current expansion of transportation and other new projects, we may be required to compensate our contract customers for our failure to supply natural gas. Both situations may negatively impact our financial condition and results of operations.

We are not permitted by law to own more than 25% of a natural gas transportation company, 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 transportation capacity is limited. New natural gas transportation infrastructure may not be available to transport natural gas from new or existing fields to consumption areas. Furthermore, we are prohibited by law from holding more than 25% of the equity of any natural gas transportation company and consequently there can be no assurance that the transportation capacity necessary to transport natural gas is built by third parties. We may be required to enter into agreements with natural gas transportation companies on terms that are not favorable to us.

We currently have long-term supply contracts with gas-fired power plants that require us to deliver natural gas in Barrancabermeja and at the La Guajira fields. Our ability to provide natural gas to these clients at the delivery point is limited by the transportation capacity of the Ballena-Barranca pipeline. Thus, 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 obtain transportation services to ship natural gas from new discoveries to our customers or to regions where natural gas is needed, we may not be able to develop these reserves, which may result in impairment of the related assets and would not allow us to recover the capital expenditures invested to make these natural gas discoveries.

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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 own and our industry’s labor unions. These strikes have been both politically and contract-related, especially during collective bargaining negotiations. In April, 2009, we entered into an agreement with the Unión Sindical Obrera de la Industria del Petróleo, or USO, one of our industry labor unions, to restore trust between USO and us with open communication and transparency as the main principles. Additionally, on August 22, 2009, as a result of consensual negotiations, we entered into a new five-year collective bargaining agreement with three of the most significant industry labor unions: USO, 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, or ADECO, and Sindicato Nacional de Trabajadores de Empresas Operadoras, Contratistas, Subcontratistas de Servicios y Actividades de la Industria del Petróleo y Similares, or SINDISPETROL. The new collective bargaining agreement was effective as of July 1, 2009 and covers salaries, healthcare, education, housing, transport, meals, cultural activities, union rights and guarantees, among other aspects. We consider reaching this agreement during consensual negotiations as a significant step towards the development of improved relations with our labor unions. Sindicato Nacional de Trabajadores de Empresas Operadoras, or SINCOPETROL, the Company’s labor union, neither presented any list of claims to us nor objected to the bargaining agreement, and as a result, we do not have a labor conflict with SINCOPETROL. During 2011, there were two work stoppages promoted by USO in Barrancabermeja in support of the protests by employees at Pacific Rubiales, an unaffiliated oil and gas company in Colombia. See “Item 6. Directors, Senior Management and Employees—Employees.”

However, we cannot assure you that we will not experience labor unrest in the future. In the event relations with our labor unions deteriorate, which could result in industry wide strikes, work stoppages or even sabotage, our results of operations and financial condition could be negatively affected.

Our operations are subject to social risks

Our exploration and production activities are subject to social risks, including protests by communities surrounding our operations. While we are committed to operating in a socially responsible manner, we may face opposition from local communities with respect to our current and future development and exploration projects which could adversely affect our business, results of operations and financial condition.

We may not be able to achieve our corporate goals if we face difficulty in finding competent successors to our current management and employees.

Our growth strategy and the successful achievement of our corporate goals depend on the competence of our management and employees. Due to the expiration of retirement benefits, some of our managers and employees left the Company in 2010 to avoid losing those benefits. As a result, we faced difficulty in finding successors to our managers and employees with the required competence and leadership. In addition, we may face difficulty in keeping our key managers and employees because of the high levels of competition for human talent with experience and knowledge in the oil and gas market. Furthermore, we may not be able to acquire or develop the right set of human talent competencies required to reach and sustain our performance under international standards. These difficulties, in turn, may negatively affect our results. See “Item 6. Directors, Senior Management and Employees—Employees.”

Our activities may be interrupted or affected by external factors, such as abnormal weather conditions, natural disasters and third-party acts.

We are exposed to several risks that may partially interrupt our activities. These risks include, among others, fire disasters, explosions, natural disasters such as earthquakes, landslides, volcanic eruptions, tropical storms, hurricanes and floods, criminal acts and acts of terror, malfunction of pipelines and emission of toxic substances.

For instance, last year we were affected by weather conditions that intensified the strength of the average rain season in Colombia, causing landslides due to the abnormal concentration of water in the soil. These abnormal landslides affected transportation of crude oil by trucks, transportation of crude oil, natural gas and products by pipelines and the normal operation of our production fields and Reficar, which experienced floods at its facilities also as a result of torrential rains.

As a result of the occurrence of any of the above, our activities could be significantly affected or paralyzed. These risks could result in property damage, loss of revenue, loss of life, pollution and harm to the environment, among others. If any of these occur, we may be exposed to economic sanctions, fines or penalties, which may adversely affect our financial condition and results of operations. On December 23, 2011, our Salgar-Cartago pipeline ruptured. We believe this incident occurred as a result of a creep movement as a consequence of severe weather conditions in the area, causing the surrounding soil to exercise strong pressure on the pipeline, causing it to rupture. The spilled gasoline from the pipeline subsequently came into contact with a heat source which ignited it causing several explosions, resulted in 33 fatalities, 77 injuries, and damaged and destroyed property. On December 11, 2011, our Caño Limón – Coveñas oil pipeline ruptured as a result of a soil motion caused by the heavy rainy season. While the accident did not result in any fatalities, it resulted in crude oil spilling into the Iscala creek. See “Item 4. Information on the Company—Transportation Infrastructure—Incidents at Transportation Facilities.”

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We conduct exploration and production activities in areas classified as indigenous reserves and Afro-Colombian lands.

We carry out and plan to carry out exploration and production activities in areas classified by the Government as indigenous reserves (resguardos) and Afro-Colombian lands (territorios colectivos). We may not begin to explore for or produce hydrocarbons in these regions until we reach an agreement with the indigenous or Afro-Colombian 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 19 years and nine years, respectively, and as of December 2011, 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 seven years as a result of the presence of the Kofan community who oppose our presence and activities in the reservation. We may be exposed to similar delays due to opposition from local communities in other countries where we carry out exploration activities in indigenous reserves, such as Peru. 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 activities, which could have a negative effect on our operations.

Currency fluctuations and an appreciation of the Peso against the U.S. dollar could have an adverse effect on our financial condition and results of operations given that approximately 65% of our revenues are derived from foreign sales.

Approximately 65% of our sales 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 gain value when the Peso depreciates against the U.S. dollar and lose value when the Peso appreciates against the U.S. dollar. Also, our U.S. dollar denominated assets (U.S.$ 7.3 billion as of December 31, 2011) only provide a partial hedge for our U.S. dollar-denominated indebtedness (U.S.$ 3.7 billion as of December 31, 2011). We use financial instruments such as forwards, swaps, or futures contracts to partially mitigate the impact of currency fluctuations.

The Peso appreciated 2.6% on average against the U.S. dollar in 2011, and a further 7.8% in the first three months of 2012. When the Peso appreciates against the U.S. dollar, our revenues from exports, when translated into Pesos, decrease. However, imported goods, oil services and interest on external debt denominated in U.S. dollars become less expensive for us. Conversely, when the Peso depreciates against the U.S. dollar, our revenues from exports, when translated into Pesos, increase, and our imports become more expensive.

Our ability to access the credit and capital markets on favorable terms to obtain funding for our capital projects may be limited due to the deterioration of these markets and the authorizations we need before incurring any financial indebtedness.

We expect to make significant expenditures in capital and operations to reach the corporate goals established by our 2012 – 2020 Strategic Plan. See “Item 4. Information on the Company—The Company—Strategic Plan.” Our ability to fund these expenditures is dependent on our ability to access the capital necessary to finance the construction of these facilities on terms acceptable to us. In recent years, domestic and global financial markets and economic conditions have been weak and volatile and have contributed significantly to a substantial deterioration in the credit and capital markets. A new financial crisis or an expansion of the current European sovereign debt crisis could also make it more difficult for us and our subsidiaries to access international capital markets and finance our operations and capital expenditures in the future on terms acceptable to us. These conditions, along with significant write-offs in the financial services sector and the re-pricing of credit risk, can make it difficult for us to obtain funding for our capital needs on favorable terms. As a result, we may be forced to revise the timing and scope of these projects as necessary to adapt to existing markets and economic conditions.

In addition, as the Nation is our controlling shareholder, the Government, through the Ministry of Finance and Public Credit, must authorize all of Ecopetrol’s and its subsidiaries’ indebtedness, except for those subsidiaries in which we hold minority interest as well as foreign subsidiaries. As such, we cannot assure you that such authorizations would be granted in a timely fashion or at all.

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

We can incur debt locally and in the international capital markets and, consequently, may be affected by changes in 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.

During recent periods, the cost of raising funds in debt and equity capital markets has increased while the availability of funds from those markets has diminished. Financial markets have not recovered from the recent global economic crisis and remain vulnerable to the European sovereign debt crisis that affects the liquidity of commercial banks and investment funds. If recovery falters or takes a few years longer than expected, the costs of raising funds in debt and equity capital markets may increase and impair our ability to obtain capital on terms acceptable to us.

We are subject to extensive environmental regulations in Colombia and in the other countries in which we operate and under certain of our credit agreements, we are under an obligation to comply with international environmental standards

Our operations are subject to extensive national, state and local environmental regulations in Colombia. Environmental rules and regulations are applicable to our exploration, production, refining, transportation, supply and marketing activities, as well as the biofuels we produce. These regulations establish, among others things, quality standards for hydrocarbon products, air emissions and greenhouse gases, 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. Currently, all exploratory projects drilling in areas that do not yet have a license must have an environmental impact assessment and must receive an environmental license from the Ministry of the Environment. 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 potential non-compliance with environmental laws.

We are also subject to regional environmental regulations issued by the corporaciones autónomas regionales, or regional environmental authorities, which oversee compliance with each region’s environmental regulations. If we fail to comply with any of these national or regional environmental regulations, we could be subject to administrative and criminal penalties, including warnings, fines and closure orders of our facilities. See “Item 4. Information on the Company—Overview by Business Segment—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 expenditures for compliance with these laws and regulations. If environmental laws continue to impose additional costs and expenses on us, and as new laws and regulations relating to climate change become applicable to us, we may need to reduce our investments on strategic projects in order to allocate funds to environmental compliance. We are exposed to delays in obtaining environmental licenses caused by the Ministry of the Environment, which can lead to cost overruns or to changes in the investment plans of the company. 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. 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.

Under certain of our credit agreements, we are under an obligation to comply with international environmental standards established by our lenders or by multilateral institutions. Failure to comply with such environmental standards could result in an event of default under the relevant credit agreements that we, or our subsidiaries, have entered into, which would affect our financial condition. For instance, the credit agreements executed by Reficar for the financing of its expansion and modernization project, includes an obligation to comply with the U.S.-Exim Environmental Procedures and Guidelines, and the Organization for Economic Co-operation and Development (OECD) Common Approaches on Environment and Officially Supported Export Credits.

Our investments outside Colombia are exposed to political risk.

We own investments in different countries, including Peru, Brazil, Panama, the United States, the United Kingdom, Spain, Switzerland and Bermuda, through our subsidiaries and accordingly, our business, financial condition or results of operations could be affected by changes in their governments’ economic or other policies, or by other political, regulatory or economic developments in these countries.

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As a result of the changes in the governments of these countries, it is uncertain whether the new governments will continue to pursue business-friendly and open - market economic policies or policies that promote private investment, stimulate economic growth and social stability. In addition, we cannot predict future governments positions on the oil and gas industry, land tenure, protection of private property, environmental regulation or taxation; nor can we assure you that future governments will maintain a generally favorable business climate and economic policies. Any changes in the economic policies or regulations by the governments of the countries where we own investments may adversely affect our business, financial condition and results of operations.

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

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 health issues faced by our workforce. Failure to comply with health and safety regulations may lead to investigations by health officials that could result in lawsuits or fines.

We may be required to incur additional costs and expenses to allocate funds to industrial safety and health compliance under Colombian law and industrial safety regulations. Additionally, if any operational incident occurs that affects local communities in nearby areas, we will need to incur additional costs and expenses in order to return affected areas to normality. 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.

We have made significant investments in acquisitions and we may not realize the expected value.

We have acquired interests in several companies in Colombia and abroad. See “Item 4. Information on the Company.” Obtaining the expected benefits of the acquisitions will depend, in part, on our ability to (i) obtain the expected operational and financial results from these acquisitions, (ii) manage disparate operations and integrate distinct corporate cultures and (iii) manage our objectives as a corporate group. These efforts may not succeed or may distract our management from operating our existing business. Our failure to successfully obtain the expected results from our acquisitions could adversely affect our financial condition and results of operations.

Our Strategic Plan contemplates the expansion of operations outside of Colombia where we will be subject to risks associated with investments in new countries.

As part of our Strategic Plan, we have begun to operate through business partners, subsidiaries or affiliates outside of Colombia. As of the date hereof, we have investments and subsidiaries incorporated in Peru, Brazil, Bermuda, Panama, the United Kingdom, Switzerland, Spain and the United States, and we are analyzing investments in other countries. In connection with making investments, we are and will be subject to risks relating to unstable economic and political conditions, governmental economic actions, such as exchange or price controls or limits on the activities to be performed by us, increases in tax rates, contractual changes, and social and environmental challenges. Such factors that our international activities may encounter, including tax regulations in foreign countries, could adversely affect our results of operations in those countries and decrease the value of our investments.

Our subsidiaries Reficar and Oleoducto Bicentenario are currently engaged in their own construction projects. If they or any other material investment project is delayed or if its costs exceed our initial estimate, it could affect our operating results and financial condition.

Reficar has raised US$3.5 billion through a limited-recourse project financing. We have acted as sponsor and have provided both a construction guarantee and a debt service guarantee to the project lenders. If the functioning of the upgraded refinery is delayed because of operational problems in the development of the project, or if the upgraded refinery does not reach the expected performance level in terms of the quality of products and/or volumes produced, the project lenders could request that we act on the guarantees and assume the payment obligations of Reficar, which would affect our operating results and financial condition. Delays in the implementation of the project may result in cost overruns, which could increase the overall cost of the project and impact our financial position.

Oleoducto Bicentenario is in the first phase of construction of the Araguaney -Coveñas pipeline, which connects the Araguaney and Banadía loading facilities. Its estimated investment of US$1,350 million is intended to be financed 30% by the equity participation of the project partners and 70% from loans from local banks. The first phase of the construction is expected to permit the evacuation of 120 thousand bpd, with 230 kilometers in length and a diameter of 42 inches. Delays in the completion of the first phase of this project could affect our production in certain fields that would be left without the necessary infrastructure for crude oil transportation, therefore impacting our financial position.

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Investment projects that are part of our Strategic Plan could face similar planning and implementation problems, which could impact the competitiveness of our programs and projects, affecting our results and expected financial condition.

Our results may be affected by the performance of our business partners, as many of our operations are executed under association and joint venture agreements with business partners.

Many of our operations are executed through associations, joint ventures and other agreements with our business partners, and consequently, we depend on the performance of our business partners. The poor performance of any of our business partners, especially in those projects in which we do not act as operators, could negatively impact our results of operations and financial condition. In addition, we are exposed to the risk of not finding business partners with the appropriate skills and performance that we require for our projects.

Our insurance policies do not cover all liabilities and may not be available for all risks.

Our insurance policies do not cover all liabilities, and insurance may not be available for all risks. There can be no assurance that incidents will not occur in the future, that insurance will adequately cover the entire scope or extent of our losses or that we will not be found liable in connection with claims arising from these and other events, which could adversely affect our financial condition and results of operations.

A failure in our information technology systems or cyber security attacks may affect adversely our financial results.

We depend on the reliability and security of our information technology systems to conduct certain exploration, development and production activities, process and record financial and operating data, communicate with our employees and business partners, and for many other activities related to our business. Our information technology systems may fail or have other significant shortcomings due to operational system flaws or employee misuse, tampering or manipulation. In addition, we may become the target of cyber attacks or information security breaches that could result in the unauthorized release, gathering, monitoring, misuse, loss or destruction of proprietary and other information. Any of these occurrences could disrupt our business, result in potential liability or reputational damage or otherwise have an adverse affect on our financial results. Although we have not experienced any material losses relating to failure of our information technology systems or cyber incidents, there can be no assurance that we will not suffer such losses in the future.

Risks relating to 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.

We believe that the holders of our 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 Superintendency of Corporations (Superintendencia de Sociedades). 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, it could adversely affect the value of such common shares and 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 American Depositary Receipt, or ADR, program must be made through the foreign exchange market.

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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 be required to register their investment in the common shares as a foreign direct investment, if the investor does not own a portfolio of investments in Colombia, or as a portfolio investment, if 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 will only be allowed to transfer dividends abroad after their foreign investment registration procedure with the Colombian Central Bank has been completed. Investors withdrawing common shares could incur 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. See “Item 10. Additional Information-Exchange Controls.”

Holders of our ADSs may not be 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 mixed economy company organized under the laws of Colombia. In addition, most 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 of 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 judgments against us or them in U.S. courts 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.”

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.

ADRs do not have the same tax benefits as other equity investments in Colombia.

Although ADRs represent Ecopetrol’s common shares, they are held through a fund of foreign capital in Colombia that is subject to a specific tax regulation regime. Accordingly, the tax benefits applicable in Colombia to equity investments, particularly, those relating to dividends and profits from sale, are not applicable to ADRs, including our ADRs. For more information see “Item 10. Additional Information—Taxation—Colombian Tax Considerations.”

Judgments of Colombian courts with respect to our ADSs will be payable only in Pesos.

If proceedings are brought in the courts of Colombia seeking to enforce the rights of ADS holders of common shares, we will be required to discharge our obligations amounts in Pesos. Under Colombian laws, an obligation in Colombia to pay amounts denominated in foreign currency may only be satisfied in Colombian currency at the Representative Market Rate of the date the judgment is obtained, and such amounts are then adjusted to reflect exchange rate variations through the effective payment date.

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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 Colombian Stock Exchange (Bolsa de Valores de Colombia), or BVC, had a market capitalization of approximately Ps$404,040 billion (US$207,979 million using the closing rate for 2011) as of December 31, 2011, a 3.37% decrease when compared with the amount at the end of 2010, a daily average trading volume of approximately Ps$162,571 million (US$83.7 million, using the average exchange rate for 2011), a 7% increase when compared to the volume in 2010. In contrast, the New York Stock Exchange, or NYSE, had a market capitalization of US$11.8 trillion as of December 31, 2011, and a daily trading volume of approximately US$72 billion in 2011.

As of December 31, 2011, our shares represented the highest market capitalization of the BVC with 43% of the total. In addition, they had the second highest trading volume in the BVC averaging Ps$26,146 million traded per day. In the last quarter of 2011, our shares represented 19.6% of the Índice General de la Bolsa de Valores de Colombia, or IGBC, stock market index, 9.8% of the COL20, a stock market index that includes the top 20 traded stocks in the BVC, and 19.8% of the COLCAP, a stock price volatility index, in the last quarter of 2011.

Given the current ownership structure of our shares, 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, it will be maintained. Without a liquid trading market, the ability of investors in our ADSs to sell them at the desired price and time could be substantially limited.

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

The Company

We are a vertically integrated oil company with presence in Colombia, Peru, Brazil and the U.S. Gulf Coast. We divide our operations into four business segments: exploration and production; transportation and logistics; refining and petrochemicals; and marketing and supply. We are the largest corporation in Colombia, as measured by revenues, profits, assets, shareholders’ equity, sales, net income and net worth, and we play a key role in the local hydrocarbon market. Our operation does not include natural gas transportation activities due to legal restrictions.

Corporate History

Ecopetrol is a mixed economy company, organized on August 25, 1951, and existing under the laws of Colombia. We have an unlimited duration. Our legal name is Ecopetrol S.A. Our principal executive offices are located at Carrera 13 No. 36-24 Bogota, Colombia and our telephone number is +571 234 4000.

In 1951, we were incorporated as the Empresa Colombiana de Petróleos as a result of the reversion of the De Mares concession to the Government by the Tropical Oil Company. We began our operations as a governmental industrial and commercial company, responsible for administering Colombia’s hydrocarbon resources. In the same year, 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.

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In 1970, we adopted our first bylaws that transformed us into a governmental industrial and commercial company, linked to the Ministry of Mines and Energy. Decree Law 1760 of 2003 renamed us Ecopetrol S.A. and transformed us from an industrial and commercial company into a state-owned corporation by shares linked to the Ministry of Mines and Energy, 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.

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.

In 2006, the Congress of Colombia authorized us to issue up to 20% of our voting capital stock in Colombia, subject to the condition that the Nation control at least 80% of our voting capital stock. On November 13, 2007, we placed 4,087,723,771 shares in the Colombian Stock Exchange (Bolsa de Valores de Colombia), or BVC, trading under the symbol “ECOPETROL,” which resulted in 482,941 new shareholders and raised approximately Ps$5,723 billion for the sale of 10.1% of our capital stock. On September 30, 2011, we issued a total of 644,185,868 shares in an offering directed exclusively to investors in Colombia. Of the 219,054 investors participating in this offering, 73% were new stockholders. The aggregate proceeds of this offering were Ps$2.38 trillion. As a result of the two offerings made by us, the Nation currently controls 88.49% of our voting capital stock. Since September 18, 2008, our American Depositary Shares, or ADSs, have been trading on the NYSE under the symbol “EC.” On December 4, 2009, our ADSs began trading on the Lima Stock Exchange under the symbol “EC.” Since March 16, 2011 our ADS´s were delisted from the Lima Stock Exchange. In addition, on August 13, 2010, our ADSs began trading on the Toronto Stock Exchange under the symbol “ECP.” Each ADS represents 20 common shares of the Company.

The following table sets forth our recent material acquisitions and the effective date as of which each has been reflected in our operating results.

Company	Date		Participation acquired in transaction			Sector	Price (US$)(1)
Polipropileno del Caribe S.A. (Propilco)		April 2008		100	%	Petrochemicals		691 million
Offshore International Group Inc. (OIG)		February 2009		50	%(2)	Exploration and Production		639 million
Oleoducto Central S.A. (Ocensa)		March 2009		24.7	%(3)	Transportation		418 million
Hocol Petroleum Limited		March 2009		100	%(4)	Exploration and Production		807 million
Refinería de Cartagena S.A. (Reficar)		May 2009		51	%(5)	Refining		549 million
Equion Energia Limited		January 2011		51	%(6)	Exploration and Production		814 million

(1) Includes amounts of adjustment on transaction prices.

(2) U.S. parent of Savía Perú (formerly Petrotech Peruana S.A.).

(3) As a result of this transaction, our ownership of Ocensa increased to 60%.

(4) We acquired 100% of Maurel et Prom’s interest in Hocol Petroleum Limited, whose most important assets are Hocol and Homcol. As a result of the acquisition, our ownership in Oleoducto de Colombia, increased from 43.85% to 65.57%.

(5) As a result of this transaction, we became the sole owner of Reficar.

(6) As a result of this acquisition, our ownership increased to 72.65% in Ocensa, 73.00% in ODC, and to 85.12% in Oleoducto del Alto Magdalena or OAM. We also obtained a 10.2% interest in Transgas de Occidente.

In August 2010, we incorporated Oleoducto Bicentenario de Colombia S.A.S., a new company to build and operate a private pipeline that will run from the Casanare Department to the port of Coveñas. The new pipeline will facilitate oil exports from the Llanos region. We have, directly and indirectly, a 55.97% ownership of the company and five other shareholders own the remaining 44.03%.

The transactions described above were funded mainly through cash on hand and cash flow from our operations.

In January 2011, we increased our participation in Invercolsa S.A., a holding company with investments in natural gas transportation and distribution companies in Colombia, to 43.35% based on a final judgment of a court, which ordered Fernando Londoño, who had been the legal representative of Invercolsa, to return to us approximately 145 million shares of Invercolsa he had illegally bought in 1997 as part of the restructuring of natural gas investments belonging to us.

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Significant Subsidiaries

We are a mixed economy company and have a number of subsidiaries both in Colombia and abroad. Our subsidiaries are either directly owned by us or indirectly owned by us through one or more of our other subsidiaries. At March 31, 2012, there were 21 subsidiaries directly owned by us, of which 10 were incorporated in Colombia and 11 were incorporated abroad, and 17 subsidiaries were indirectly owned by us. Some of our subsidiaries have subsidiaries of their own.

The Company does not have any significant subsidiaries as such term is defined under SEC Regulation S-X. The following table sets forth some of our subsidiaries, their respective countries of incorporation, our percentage ownership in each (both directly and indirectly through other subsidiaries) and our voting percentage in each as of March 31, 2012:

COMPANY	COUNTRY OF INCORPORATION	OWNERSHIP AND VOTING %
Exploration and Production
Ecopetrol Oleo e Gas do Brasil Ltda*	Brazil	100.00
Ecopetrol del Perú S.A.*	Peru	100.00
Ecopetrol America Inc.*	United States	100.00
Hocol Petroleum Limited	Bermuda	100.00
Equion Energía Limited	United Kingdom	51.00
Transportation
Oleoducto de los Llanos Orientales S.A. (ODL)**	Panama	65.00
Oleoducto de Colombia S.A.*	Colombia	73.00
Oleoducto Central S.A.*	Colombia	72.65
Oleoducto Bicentenario de Colombia S.A.S.*	Colombia	55.97
Refining and Petrochemicals
Refinería de Cartagena S.A.*	Colombia	100.00
Propilco S.A.*	Colombia	100.00
Compounding and Masterbatching Industry Ltda. (COMAI)**	Colombia	100.00
Biofuels
Bioenergy S.A.**	Colombia	91.43
Other
Black Gold Re Ltd.	Bermuda	100.00

* Direct and indirect participation.

** Solely indirect participation through other Subsidiaries or Affiliates.

See Exhibit 8.1 to this annual report for a complete list of our subsidiaries, their respective countries of incorporation, our percentage ownership in each (both directly and indirectly through our other subsidiaries) and our voting ownership in each.

Strategic Plan

In 2010, we extended our strategic plan to 2020, which was updated in 2011, which we refer to as our Strategic Plan. Our Strategic Plan considers Ecopetrol to be an integrated Corporate Group, composed of Ecopetrol S.A. and its subsidiaries and affiliates located in Colombia and abroad, focused on the exploration and development of crude oil, natural gas, petrochemicals and alternative fuels. We intend to develop as a key player and become one of the 30 main companies in the global oil industry, recognized for international positioning, innovation and commitment to sustainable development.

Our Strategic Plan provides detailed goals for each one of our business segments. Our main objective is to achieve a daily output of 1 million gross “Clean Barrels” of oil equivalent per day by 2015 and 1.3 million gross Clean Barrels of oil equivalent per day by 2020, working in three areas: economic, environmental and social, and we intend to obtain a profitability measured by return on capital employed (ROCE) of 17% as a Corporate Group. We use the term “Clean Barrels” to refer to the production of crude oil barrels without accidents or environmental incidents and in harmony with our stakeholders. Our Strategic Plan also includes the goal of continuing to develop the skills of our employees. The investments our Strategic Plan envisions are subject to market analysis, conceptual engineering and financial feasibility.

We are also planning to consolidate our strategy for our downstream operations by adding value to products and services from the Corporate Group and/or third parties, with a clear orientation toward the market and clients. In addition, we intend to be leaders in refining in Latin America by producing cleaner and more valuable products, taking advantage of synergies and ensuring profitability, developing and consolidating the Corporate Group’s basket of products through alternative energy and by strengthening the domestic market for natural gas and developing the business in the region.

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Transportation and logistics in the Strategic Plan is a key factor that leverages the entire value chain for the Corporate Group, with an expected ROCE above 11%.

We expect to fund our strategic initiatives mainly 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 believe that we will be able to access local and international debt markets when the need arises. See “Item 5. Operating and Financial Review and Prospects—Liquidity and Capital Resources.” We are also authorized by Law 1118 of 2006 to sell 20% of our equity, of which we have issued 11.51% and we may issue an 8.49%, which could be used as an additional source of funding for our Strategic Plan.

We expect to achieve our strategy together with our joint venture partners with whom we have built long-term relationships. We are also working with foreign governmental authorities in countries where we already have operations or where we intend to develop operations.

We also maintain strategic initiatives with respect to each of our different segments:

Exploration and Production

Become an international player with the capacity to incorporate reserves and increase production of crude oil and natural gas in a sustainable way

In line with our 2012-2020 development strategy, we intend to increase our average daily production of hydrocarbons to 1.0 million gross boepd by the year 2015 and 1.3 gross million boepd by 2020, of which around 50% are expected to be heavy crude oil. We estimate our total investment in exploration activities at US$20 billion and in production activities (exploiting new reserves, maximizing production in conventional fields, increasing production and development of heavy crude oil, and developing unconventional hydrocarbons and natural gas fields) at US$49 billion for a total of US$69 billion in Colombia and abroad.

In total, we expect to add 6,200 million gross barrels of new reserves in the years 2011-2020. In order to reach our production goal by year 2020, we expect production of our existing fields to reach 840 thousand gross boepd; while expecting a further 300 thousand gross boepd produced by our Colombian exploration activities and that of our domestic subsidiaries, 110 thousand gross boepd produced by our international exploration and that of our international subsidiaries; and an additional production of 50 thousand gross boepd of unconventional hydrocarbons.

In 2011, our capital expenditures in our Exploration and Production segment were Ps$8.1 trillion (approximately US$4.14 billion). During the same period, we added 364 million boe (net) to our proved reserves and we produced a daily average of 724 thousand gross boepd, representing an increase of 17.5% compared to 2010. Ecopetrol S.A. produced 670 thousand gross boepd, representing an increase of 15.5% compared to 2010.

Our Exploration and Production strategy has four main focuses: (i) increasing our recovery oil factor, (ii) hydrocarbons’ exploration on known basins, (iii) development of non-conventional hydrocarbons, and (iv) growth of the natural gas business along with downstream operations.

Refining and Petrochemicals

Produce cleaner and more valuable products, ensuring profitability through synergies, and take advantage of market opportunities by adding greater value to the refining streams and increasing production of petrochemicals

We intend to be one of the leaders in refining in Latin America, by continuing with the modernization of our refineries in Barrancabermeja and Cartagena (Reficar) in order to reach a 95% conversion rate, increasing the load of heavy crude oil, and producing more middle distillates and gasoline. In the refining area, we have established a goal under our Strategic Plan to achieve profitability between 9% and 11% ROCE by 2025 and in petrochemicals, of 13% ROCE. We also expect that the implementation of these initiatives will enable us to increase production of refined products and improve efficiency, while upgrading existing facilities in order to reach higher margins. Our Strategic Plan contemplates the investment of approximately US $5.9 billion, focusing also on operational excellence and profitable growth, and to increase our production of petrochemicals reaching 668 thousand tons per year by 2020, including the production of polypropylene produced by Polipropileno del Caribe S.A. (Propilco).

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In 2011, our capital expenditures in our refining and petrochemical segment were Ps$ 3.0 trillion (approximately US$1.5 billion ), mainly for modernization projects of our refineries in Barrancabermeja and Cartagena (Reficar) as part of our commitment to provide cleaner fuels.

Transportation and Logistics

Grow in a profitable way and make development viable across the entire value chain.

We plan to implement a transportation infrastructure program along with the participation of other companies in the sector, focused on the construction of crude oil pipelines and multipurpose transportation systems to assure our transportation capacity. We intend to invest approximately US$4 billion between 2012 and 2020 in the construction and upgrading of our transportation infrastructure to meet our future requirements and in the conversion of existing crude oil pipelines for the transportation of heavy crude oil and other hydrocarbon products. For 2011, capital expenditures in our transportation and logistics segment were Ps$ 3.4 trillion (approximately US$1.7 billion), including what we consider our most representative achievement, the development, with five business partners, of Oleoducto Bicentenario de Colombia S.A.S., which is currently in its first phase of construction.

Marketing and Supply

Focus on the importance of the market and clients, and define key products and markets for the Corporate Group

Our Strategic Plan sets out guidelines for sales and marketing that cut across our operational areas and emphasizes on the importance of our markets and clients and the need to define key products and markets for the Group. Our strategy is focused on supplying the local market and exporting crude oil, refined products, biofuels, petrochemical products and natural gas to end-users, including refineries and wholesalers, in order to improve our margins. We also intend to increase our market participation in crude oil and refined products in the Far East, Latin America and Europe.

Our principal export market in 2011 was the U.S. market. During 2011, our exported volumes of natural gas increased by 179.2% when compared to 2010. We signed an extension of two and a half years to our agreement to supply natural gas to 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.

Develop and consolidate the Corporate Group’s basket of products through alternative energy

We intend to participate with local investors in the Colombian renewable energy market, with whom we have undertaken the development of a refinery to process sugar cane for biofuels. We plan to consolidate in the local market in a profitable way, with the goal of producing 450 thousand tons of biofuels in 2020 (including biodiesel from Ecodiesel and ethanol from Bioenergy S.A.).

In mid-2010, we initiated the production of biodiesel with Ecodiesel, in which we have a 50% share. Our Strategic Plan contemplates the investment of US$516 million. These investments will allow having cleaner and more valuable fuel production.

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 directly and through joint ventures with third parties. As of December 31, 2011, we were the largest producer of crude oil and natural gas, the largest operator, and we maintained the most acreage under exploration in Colombia.

We have exploratory activities in all the sedimentary basins that currently have activity in Colombia. The following map shows the basins where we conduct exploratory activities.

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We have organized Ecopetrol S.A.’s production activities in Colombia into five administrative regions. The administrative regions, and their respective 2011 production results, prior to deducting royalties, are as follows:

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 541,404 acres and includes the natural gas fields located at La Guajira and the crude oil and natural gas fields located in Cusiana-Cupiagua. In 2011, the Northeastern region had a total production of approximately 46.8 thousand bpd of crude oil and 540.2 million cubic feet per day or mcfpd of natural gas.

Mid-Magdalena Valley Region – The Mid-Magdalena Valley region runs along the Magdalena river valley and covers approximately 961,362 acres. It includes the crude oil fields located in the Santander department and part of the Antioquia, Cesar and Boyacá departments near the Barrancabermeja refinery. In 2011, the Mid-Magdalena Valley region had a total production of approximately 94.4 thousand bpd of heavy and light crude oil and 20.7 mcfpd of natural gas.

Central Region – The Central region is located in Colombia’s central area and includes the Meta department and part of the Casanare department. It covers approximately 719,357 acres and in 2011, had a total production of approximately 284.7 thousand bpd of heavy and medium crude oil and 0.2 mcfpd of 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 1,197,310 acres. It includes the Caño Limón crude oil field and the Gibraltar natural gas field, with a total production in 2011 of approximately 80.7 thousand bpd of crude oil and 2.3 mcfpd.

Southern Region – The Southern region is located on the southwestern region of Colombia and covers approximately 906,773 acres. It includes the Orito, Guando and Neiva fields located mainly in the Cundinamarca, Huila and Putumayo departments. In 2011, the Southern region had a total production of approximately 57.1 thousand bpd of crude oil and 6.4 mcfpd of natural gas.

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In addition to the administrative regions mentioned above, we have established a minor fields area that covers some of our smaller fields throughout the country. The main purpose of this minor fields area is to establish strategies adequate enough to improve efficiency in the production of reserves from these fields. The total production of the minor fields area during 2011 was 5.6 thousand bpd of crude oil and 2.4 mcfpd of natural gas. This production corresponds to fields located in Mid-Magdalena Valley, Central, Catatumbo-Orinoquía and the Southern regions.

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

Exploration

Our exploration plan in Colombia is focused on exploration of existing production sites in close proximity, exploration of currently producing basins and exploration of frontier areas, including off-shore areas primarily operated by our business partners, which we believe have the potential for large findings. Our exploration strategy outside of Colombia is focused on locating prospects and establishing joint ventures with experienced operators.

During 2011, we drilled 39 A3-A2 gross exploratory wells, 28 in Colombia and 11 overseas.  A2 exploratory wells are drilled adjacent to, at deeper or at shallower depths than proven oil deposits in a productive oil field. We drill A3 exploratory wells to find oil deposits in fields were no wells have yet proven productive. We discovered 17 productive wells, of which 11 are located in Colombia, five in Peru, and one in the U.S. Gulf Coast. 18 wells were dry, of which 14 were located in Colombia and four overseas. As of December 31, 2011, four wells were under evaluation, of which three are located in Colombia and one in Peru.

Exploration Activities in Colombia

We conduct exploration in Colombia on our own and through joint ventures with regional and global oil and gas companies. We also benefit from sole risk contracts when commercial reserves are found. In the case of sole risk contracts, we do not take any exploration risk. See “Contractual Arrangements for the Exploration and Production of Crude Oil and Natural Gas in Colombia.”

In 2011, we acquired 7,145 equivalent kilometers of seismic in Colombia, including 1,702 equivalent kilometers acquired by Hocol. Ecopetrol S.A. acquired 5,443 equivalent kilometers, corresponding to 2,383 kilometers of 2D seismic and 3,060 equivalent kilometers of 3D seismic.  We directly acquired 3,978 of those kilometers of seismic and 1,465 kilometers were acquired by our business partners.

Ecopetrol S.A. drilled a total of 21 A3-A2 gross exploratory wells. Evidence of hydrocarbons was discovered in nine of the wells (Mito-1, Nunda-1, CSE-8 ST1, Rumbero-1, Pinocho-1, Fauno-1, Trasgo-1, Azabache-1 and Opalo-1). The remaining 12 wells were dry. Hocol drilled seven A3 wells. Evidence of hydrocarbons was found in two of the Hocol wells (Bonga-1 and Guarrojo Este -1), while other three are under evaluation (Granate-1, Merlín-1 and Merlín-2) and two were dry.

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In January 2011, Ecopetrol S.A. and Petrobras Colombia Limited (“Petrobras Colombia”) entered into an agreement for the exploration of the Tayrona block in the Colombian Carribbean Ocean with Repsol Exploración Colombia. Ecopetrol S.A. has a 30% interest in the block.

In February 2011, we acquired from Shell its interest in the Caño Sur block, increasing our participation to 100% from 50%.

In March 2011, Ecopetrol S.A. signed eight exploration and production contracts with the Agencia Nacional de Hidrocarburos, or ANH corresponding to blocks awarded to the Company in the Colombia Open Round 2010. The eight blocks cover a total area of more than 840 thousand hectares and are located in the Llanos (provinces of Arauca, Casanare and Meta), Valle Medio del Magdalena (Cundinamarca and Caldas provinces), Sinu-San Jacinto (Antioquia and Cordoba provinces) basins, and offshore of the Pacific coast. Ecopetrol owns a 100% stake in six of the contracts. In the SSJS 1 contract, Ecopetrol S.A.’s stake is 70%, and in the VMM 32 contract, Ecopetrol S.A. holds a 51% stake.

In June 2011, Ecopetrol S.A. signed three exploration and production contracts with the ANH corresponding to the Samichay A, Samichay B and Upar blocks. These blocks cover a total area of more than 543 thousand hectares and Ecopetrol controls a 100% in each of these contracts.

Exploration Activities Outside of Colombia

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 2011, we drilled 11 international gross exploratory wells through our subsidiaries and partners as follows:

(i) two were drilled in Brazil by Ecopetrol Oleo é Gas do Brasil with our business partners Petrobras and ONGC, in which each of our business partners has a 43.5% ownership interest, while we have the remaining 13%. These two wells were declared dry;

(ii) two wells were drilled in the US. Gulf Coast by Ecopetrol America Inc., the second of which, the Logan well, was declared a discovery. The first well was drilled with our business partners Statoil ASA and the China National Offshore Oil Corporation (“CNOOC”), which have 60% and 10% ownership interests respectively, while we have the remaining 30%. The Logan well was drilled with our business partners Statoil ASA, Petrobras, and CNOOC, which have 35%, 35%, and 10% ownership interests respectively, while we have the remaining 20%;

(iii) seven wells were drilled off of the Peruvian coast by Savía Perú S.A. (“Savía Perú”), in which we have a 50% ownership interest. As of December 31, 2011, five wells were declared as showing evidence of hydrocarbons, one of which was dry and the remaining well was under evaluation. See “Item 3. Key Information—Risk Factors—Risks related to our business—Our participation in deep water drilling in conjunction with our business partners involves certain risks and costs, which may be outside our control.”

As of December 31, 2011, we acquired 20,150 kilometers of additional seismic equivalent: 20,079 kilometers in the U.S. Gulf Coast and 71 kilometers in Peru, an increase of 81% compared with seismic data as of December 31, 2010. These figures do not include 3,535 kilometers of net seismic equivalent acquired by Savía Perú.

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In January 2011, Ecopetrol also obtained a 13% interest in the BM-S-73 and BM-S-74 blocks in Brazil.

Exploratory Wells

The following table sets forth the number of gross and net productive and dry 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, 2011, 2010 and 2009. This table does not include the wells that were under evaluation as of the date of disclosure.

	For the year ended December 31,
	2011		2010		2009
COLOMBIA
Ecopetrol
Gross Exploratory Wells
Owned and operated by Ecopetrol
Productive(1)		7		2		2
Dry(2)		10		4		7
Total(3)		17		6		9
Operated by Partner in Joint Venture
Productive(1)		-		1		-
Dry(2)		-		2		-
Total		-		3		-
Operated by Ecopetrol in Joint Venture
Productive(1)		2		3		3
Dry(2)		2		1		3
Total		4		4		6
Net Exploratory Wells(4)
Productive(1)		7.8		3.2		3.2
Dry(2)		10.9		5.6		8.2
Total		18.7		8.8		11.4
Sole Risk(5)
Productive(1)		2		7		4
Dry(2)		6		11		5
Total		8		18		9
Hocol
Gross Exploratory Wells
Productive (1)		2		-		1
Dry(2)		2		9		2
Total		4		9		3
Net Exploratory Wells(4)
Productive(1)		2		0		0.2
Dry(2)		1.5		5		2
Total		3.5		5		2.2
Equion
Gross Exploratory Wells
Productive (1)		-		N/A		N/A
Dry(2)		-		N/A		N/A
Total		-		N/A		N/A
Net Exploratory Wells(4)
Productive(1)		-		N/A		N/A
Dry(2)		-		N/A		N/A
Total		-		N/A		N/A
INTERNATIONAL
Ecopetrol America Inc.
Gross Exploratory Wells
Productive(1)`		1		-		-
Dry(2)		1		3		2
Total		2		3		2
Net Exploratory Wells(4)
Productive(1)		0.2		-		-
Dry(2)		0.3		0.9		0.4
Total		0.5		0.9		0.4
Ecopetrol Oleo e Gas do Brasil
Gross Exploratory Wells
Productive(1)		-		1		0
Dry(2)		2		1		1
Total		2		2		1
Net Exploratory Wells(4)
Productive(1)		-		0.5		-
Dry(2)		0.2		0.3		0.3
Total		0.2		0.8		0.3
Ecopetrol del Perú
Gross Exploratory Wells
Productive(1)		-		-		-
Dry(2)		-		1		-
Total		-		1		-
Net Exploratory Wells(4)
Productive(1)		-		-		-
Dry(2)		-		0.3		-
Total		-		0.3		-
Savía Perú
Gross Exploratory Wells
Productive(1)		5		1		1
Dry(2)		1		0		1
Total		6		1		2
Net Exploratory Wells(4)
Productive(1)		3		0.5		0.5
Dry(2)		0.5		0		0.5
Total		3.5		0.5		1

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(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) This total does not include four wells in evaluation at December 31, 2011.

(4) Net exploratory wells are calculated according to our percentage of ownership in these wells.

(5) We do not take any risk in sole risk contracts but we benefit from successful exploratory efforts.

Production

As part of our Strategic Plan, we consider the increase of the recovery factor in the current fields in Ecopetrol S.A., including those that were discovered more than 20 years ago, to increase our average daily production of hydrocarbons and reserves. 88% of the fields of Ecopetrol S.A. are in primary recovery. Secondary recovery (waterflooding) is or has been implemented in 8% of the fields. Finally, Enhanced Oil Recovery has been applied in 4% of the fields. We continue to focus our efforts on improving the productivity ratio of several such directly operated fields and other fields currently held through joint ventures with other oil companies. All figures for crude oil and natural gas production are shown prior to deducting royalties, except when specifically stated.

Our total average consolidated daily production of hydrocarbons in 2011, prior to deducting royalties, totaled 724 thousand boepd, of which 616 thousand bpd corresponded to crude oil and 108 thousand boepd corresponded to natural gas. This production includes the production contribution from our subsidiaries and affiliates, Hocol S.A., Equion, Ecopetrol America Inc. and Savía Perú S.A. on the basis of our participation. Ecopetrol S.A. production amounted to 92.5% total consolidated production, Hocol 4.2%, Equion 2.0%, Savia 1.0% and Ecopetrol America 0.3%.

During 2011, we produced 715 thousand boepd in Colombia through Ecopetrol S.A., Hocol and Equion out of which 608 thousand boepd corresponded to crude oil and 107 thousand boepd corresponded to natural gas.

During 2010, our consolidated average daily production of hydrocarbons totaled 616 thousand boepd, out of which 516 thousand bpd corresponded to crude oil and 100 thousand boepd corresponded to natural gas. In 2009, our consolidated average daily production of hydrocarbons totaled 521 thousand boepd, out of which 426 thousand bpd corresponded to crude oil and 95 thousand boepd corresponded to natural gas.

Ecopetrol S.A.’s crude oil production during 2011 consisted of approximately 51% light and medium crudes (above 15º American Petroleum Institute, or API gravity) and 49% of heavy crudes, with a gravity equal or lower than 15° API. In 2010, approximately 56% of the crude oil production corresponded to light and medium crudes while the remaining 44% to heavy crudes. During 2009, production distribution was approximately 63.8% of light and medium crudes and 36.2% of heavy crudes.

At December 31, 2011, we were the largest participant in the Colombian hydrocarbons industry, with approximately 67% of crude oil production and approximately 59% of natural gas production. Our production volume in 2011 in Colombia includes Ecopetrol S.A. and Hocol’s production along with our share of Equion’s production.

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We undertook development drilling in the producing regions, allowing us to drill 345 gross development wells operated by us in Colombia in 2011, 111 more than in 2010 and 180 more than in 2009. Of the total gross development wells drilled by Ecopetrol S.A. and through joint ventures in 2011, one well was dry in the Catatumbo-Orinoquía Region, two in the Minor Fields, and four more were dry in the Central Region. In 2009 and 2010, Ecopetrol S.A. had two dry development wells in each of the Southern Region and the Catatumbo-Orinoquía Region and three in the Southern Region, respectively.

Relevant operational activities

The following table sets forth the number of gross and net productive and dry development wells drilled exclusively by us and in joint ventures for the years ended December 31, 2011, 2010 and 2009.

	For the year ended December 31,
	2011		2010		2009
COLOMBIA
Ecopetrol
Northeastern Region:
Gross wells owned and operated by Ecopetrol		4		-		-
Gross wells in Joint Ventures		7		5		6
Net Wells(1)		8		3		3
Mid-Magdalena Valley Region:
Gross wells owned and operated by Ecopetrol		120		58		100
Gross wells in Joint Ventures		366		322		249
Net Wells(1)		309		217		227
Central Region:
Gross wells owned and operated by Ecopetrol		171		121		46
Gross wells in Joint Ventures		202		200		115
Net Wells(1)		258		213		113
Catatumbo-Orinoquía Region:
Gross wells owned and operated by Ecopetrol		14		-		4
Gross wells in Joint Ventures		44		23		12
Net Wells(1)		34		9		10
Southern Region:
Gross wells owned and operated by Ecopetrol		4		12		7
Gross wells in Joint Ventures		22		40		48
Net Wells(1)		12		17		23
Minor Fields:
Gross wells owned and operated by Ecopetrol		-
Gross wells in Joint Ventures		3
Net Wells(1)		-
Hocol
Gross wells owned and operated by Hocol		20		36		8
Gross wells in Joint Ventures		10		7		1
Net Wells(1)		23		34		8
Equion
Gross wells owned and operated by Equion		2		N/A		N/A
Gross wells in Joint Ventures		0		N/A		N/A
Net Wells(1)		1		N/A		N/A
Total Gross wells owned and operated in Colombia		335		227		165
Total Gross wells in Joint Ventures in Colombia		651		597		431
Total Net Wells (Colombia)		645		493		384
INTERNATIONAL
Savía Perú
Gross wells		20		14		5
Net Wells(1)		10		7		2.5
Ecopetrol America Inc.
Gross wells		-		-		1
Net Wells(1)		-		-		0.1
Total Gross Wells (International)		20		14		6
Total Net Wells (International)		10		7		2.6

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

Production Activities in Colombia

Our average daily production of crude oil in Colombia reached 608 thousand bpd in 2011, a 19.8% increase compared to 2010. The increase in our average daily production is due to (i) a 19.8% increase in production from fields developed with our business partners, which totaled 284 thousand bpd in 2011 from 237 thousand bpd in 2010, and (ii) a 19.8% increase from fields operated by us, which totaled 324 thousand bpd in 2011 compared to 270 thousand bpd in 2010.

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During 2010 we had an average daily production of crude oil of 508 thousand bpd of crude oil, which represents a 21% increase compared to 2009. This increase was due to (i) an 11.1% increase from fields developed with our business partners, which totaled 237 thousand bpd in 2010 from 214 thousand bpd in 2009, and (ii) a 31.3% increase from fields operated by us, for a total of 270 thousand bpd in 2010 compared to 206 thousand bpd in 2009.

The figures above do not include production test which amounted to 0.4 thousand bpd in 2011, 0.2 thousand bpd in 2010 and 0.3 thousand bpd in 2009.

The following table sets forth our average daily crude oil production, prior to deducting royalties, for the years ended December 31, 2011, 2010 and 2009.

	For the Year ended December 31
	2011		2010		2009
	(thousand bpd)
COLOMBIA
Ecopetrol
Northeastern region:
Joint venture operation		24		29		37
Direct operation		23		12		—
Total Northeastern region		47		41		37
Mid-Magdalena Valley region:
Joint venture operation		21		19		17
Direct operation		74		65		57
Total Mid-Magdalena Valley region		95		84		73
Central region:
Joint venture operation		120		78		45
Direct operation		165		140		112
Total Central region		285		219		156
Catatumbo-Orinoquía region:
Joint venture operation		77		60		67
Direct operation		4		3		3
Total Catatumbo-Orinoquia region		81		63		70
Southern region:
Joint venture operation		33		36		35
Direct operation		24		27		27
Total Southern region		57		62		62
Minor Fields:
Joint venture operation		6		12		7
Direct operation		0		1		1
Total Minor Fields		6		13		7
Hocol S.A.(1)
Joint venture operation		4		4		6
Direct operation		26		22		8
Total Hocol		30		26		14
Equion Energia Limited(1)
Joint venture operation		-		N/A		N/A
Direct operation		8		N/A		N/A
Total Equion		8		N/A		N/A
Production Tests		0.4		0.2		0.3
Total Average Daily Crude Oil Production (Colombia)		608		508		420
INTERNATIONAL
Savía Perú		6		6		5
Ecopetrol America Inc.		2		2		1
Total Average Daily Crude Oil Production (International)		8		8		6
TOTAL AVERAGE DAILY CRUDE OIL PRODUCTION		616		516		426

(1) Hocol and Savía Perú production figures correspond to their equivalent daily productions since their respective months of acquisition.

The following table sets forth our developed and undeveloped gross and net acreage of crude oil and natural gas production by region for the year ended December 31, 2011.

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	Production Acreage at December 31, 2011								Average crude oil and natural gas production for the year ended December 31, 2011(1)
	Developed				Undeveloped				(thousands
	Gross		Net		Gross		Net		boepd)
	(in acres)
COLOMBIA
Ecopetrol
Northeastern region		80,681		44,152		460,723		310,760		142
Mid-Magdalena Valley region		46,434		31,787		914,928		758,866		98
Central region		56,717		36,152		662,640		305,137		285
Catatumbo-Orinoquía region		52,523		41,484		1,144,787		641,780		81
Southern region		29,201		24,111		877,572		601,576		58
Minor Fields		5,919		3,844		414,208		169,909		6
Hocol		17,222		4,696		692		342		31
Equion		17,880		6,652		892,271		365,571		14
Total (Colombia)		306,577		192,878		5,367,821		3,153,941		715
INTERNATIONAL
Savía Perú		79,575		79,575		5,090		5,090		7
Ecopetrol America Inc.(2)		20,880		1,925		5,760		531		2
Total (International)		100,455		81,500		10,850		5,621		9
Total		407,032		274,378		5,378,671		3,159,562		724

(1) Does not include 0.4 thousand bpd of production from exploratory activities.

(2) Production and acreage from Ecopetrol America Inc. is related to K2 field lease contracts. There are five lease contracts, four of which are in the production stage and do not have expiration dates, while one is an exploratory lease that expires on June 30, 2016.

The following table sets forth our total gross and net productive wells by region for the year ended December 31, 2011.

	At December 31, 2011
	Crude Oil				Natural Gas
	Gross		Net		Gross		Net
COLOMBIA
Ecopetrol
Northeastern region		73		57		29		17
Mid-Magdalena Valley region		3,011		2,014		9		9
Central region		931		678		-		-
Catatumbo-Orinoquía region		688		544		-		-
Southern region		908		547		5		2
Minor fields		99		49		2		1
Hocol		283		154		2		1
Equion		30		10		-		-
Total (Colombia)		6,023		4,053		47		30
INTERNATIONAL
Savía Perú		660		330		-		-
Ecopetrol America Inc.		7		1		-		-
Total (International)		667		331		-		-
Total		6,690		4,384		47		30

We consider as crude oil wells those whose main operation is directed towards oil production, although many of these wells produce gas associated with oil production that, in some cases, have a commercial purpose. Natural gas wells are those whose operations are directed only towards production of commercial gas. The above table reflects the productive wells that directly contribute with hydrocarbons production, and therefore excludes wells used for injection, disposal, captation, or other similar activities.

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Crude Oil

Volume of crude oil purchased

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 that have been received by the ANH in-kind from producers for the years ended December 31, 2011, 2010 and 2009.

	For the year ended December 31,
	2011		2010		2009
	(million barrels)
Ecopetrol
Crude oil purchased from the ANH		46.7		40.5		35.1
Crude oil purchased from our business partners		22.8		23.1		26.4
Hocol
Crude oil purchased from our business partners		10.3		9.1		4.8
Equion
Crude oil purchased from our business partners		4.4		N/A		N/A
Total (1)		84.2		72.7		66.3

(1) Purchases of crude oil from the ANH and our business partners are allocated to our Marketing and Supply segment.

Light crude oil

Light crude oil has API gravity 35^° or higher and tends to have a higher sales price in the international market. We develop and produce light crude oil in Cusiana, Cupiagua, Pauto and Rancho Hermoso fields. During 2011, 2010 and 2009 our production of light crude oil (on a stand-alone basis) was 61 thousand, 48 thousand, and 44 thousand bpd, respectively.

Heavy crude oil

We consider heavy crudes as those with API gravity below 15^°. We (on a stand-alone basis) develop, upgrade and produce heavy crude in the Central and Mid-Magdalena Valley regions. Our production of heavy crude oil increased from 24 thousand bpd in 2000 to 278 thousand bpd in 2011, a 32.3% increase when compared to 2010 as a result of the development of the Rubiales, Castilla and Chichimene fields. In 2010, our production of heavy crudes amounted to 210 thousand bpd, compared to 146 thousand bpd produced in 2009, mainly as a result of the development of the same fields. We are committed to developing our heavy crude reserves as they are a key element of our growth strategy.

Our most important heavy crude oil projects are:

· Cubarral. The Cubarral block is located in the Central region and is composed of the Castilla and Chichimene fields. Together, these fields in 2011 produced approximately 142 thousand bpd, a 20.8% increase compared with 2010 production.

· Rubiales - Quifa. The Rubiales and Quifa fields are located in the Central region and are developed in joint venture with Metapetroleum. The Rubiales and Quifa fields increased our production from 71.8 thousand bpd in 2010 to 113.2 thousand bpd in 2011. In 2011, we, along with Pacific Rubiales Energy Corp., started the Synchronized Thermal Additional Recovery (STAR) technology pilot project in the Quifa field to begin to test the use of in situ combustion-based technology which is expected to increase the recovery factor in Colombia’s heavy oil fields.

· Nare. The Nare joint venture fields are located in the Mid-Magdalena Valley region. These fields are developed with Mansarovar, which is a joint venture between Sinopec from China and Oil and Natural Gas Corporation Ltd. from India. Our production reached 16.1 thousand bpd in 2011, representing a 21.6% increase from 2010.

Natural Gas

In 2011, our average daily production of natural gas in Colombia reached 609.3 mcfpd, an 8.4% increase when compared to 2010 production. When compared to 2009, natural gas production increased by 5.4% in 2010.

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The following table sets forth our average daily natural gas production, prior to deducting royalties, for the years ended December 31, 2011, 2010 and 2009.

	For the year ended December 31,
	2011		2010		2009
	(mcfpd)
COLOMBIA
Ecopetrol
Northeastern region:
Joint Venture		538		523		494
Direct Operation		2		0		—
Total Northeastern region		540		523		494
Mid-Magdalena Valley region:
Joint Venture		4		3		4
Direct Operation		16		18		19
Total Mid-Magdalena
Total Valley region		21		21		23
Central region:
Joint Venture		-		-		-
Direct Operation		0		1		4
Total Central region		0		1		4
Catatumbo-Orinoquía region:
Joint Venture		2		-		0
Direct Operation		-		1		1
Total Catatumbo-Orinoquía region		2		1		1
Southern region:
Joint Venture		3		4		3
Direct Operation		4		3		2
Total Southern region		6		6		5
Minor Fields:
Joint venture operation		2		3		2
Direct operation		-		-		-
Total Minor Fields		2		3		2
Hocol(1)
Joint venture operation		-		2		4
Direct operation		3		4		-
Total Hocol		3		6		4
Equion(1)
Joint venture operation		-		N/A		N/A
Direct operation		36		N/A		N/A
Total Equion		36		N/A		N/A
Production Tests		-		-		0.2
Total Natural Gas Production (Colombia)		611		562		533
INTERNATIONAL
Savía Perú(1)		5		6		5
Ecopetrol America		1		1		0
Total Natural Gas Production (International)		6		7		6
Total Natural Gas Production		617		569		539

(1) Equion, Hocol and Savía Perú production figures correspond to their equivalent daily productions since their respective months of acquisition.

Northeastern region

The largest production of natural gas in Colombia is located in the Northeastern region, which we develop primarily under joint venture contracts. We developed the Guajira natural gas reserves with our partner Chevron. The Cusiana and Cupiagua reserves are developed in partnership with Equion and Total.

Natural gas production in the Northeastern region averaged 540.2 mcfpd in 2011. The natural gas produced from these fields is used to supply local demand and to meet our commitments to supply natural gas to Venezuela. We are continuing to re-inject natural gas in the Cusiana field. This production outcome was leveraged by Chuchupa and Ballena assets operated by Chevron, which represented a production of 363.3 mcfpd in 2011 and 387.3 mcfpd in 2010.

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Lifting and production costs

Our consolidated average production costs on a Peso basis increased to Ps$20,739 during 2011 from Ps$18,940 during 2010 and Ps$ 19,523 during 2009, mainly due to increased costs from joint ventures, related to higher volumes of water production and related disposal costs, as well as to the triggering of high-price clauses in our joint venture agreements, which assign us additional production when oil prices are higher than a reference price (the “High-Price Clauses”). This increase was partially offset by (i) a 17.6% increase in production volumes, and (ii) a decrease in direct operation costs. Our consolidated average lifting costs on a dollar basis increased to US$10.43 in 2011 from US$9.83 in 2010 and US$9.05 in 2009, as a result of the above-mentioned factors and a 2.6% appreciation of the average exchange rate of the Peso against the U.S. dollar.

Our consolidated average lifting costs differ from our consolidated average production costs because our lifting costs do not include costs related to self-consumption of hydrocarbons included in the production process, such as by our small refineries and natural gas liquid plants.

The following table sets forth our crude oil and natural gas average sales price, average lifting costs and average production costs for the years ended December 31, 2011, 2010 and 2009.

	For the year ended December 31,
	2011		2010		2009
Crude Oil Average Sales Price
(U.S. dollars per barrel)(1)		99.30		72.42		60.86
Crude Oil Average Sales Price
(Ps$ per barrel)(1)		183,514		137,493		130,986
Natural Gas Average Sales Price
(U.S. dollars per thousand cf)(1)		4.62		3.42		2.94
Natural Gas Average Sales Price
(Ps$ per thousand cf)(1)		8,534		6,487		6,321
Aggregate Average Unit Production Costs
(U.S. dollars per boe)(2)(3)		11.70		9.98		9.05
Aggregate Average Unit Production Cost
(Ps$ per boe)(2)(3)		21,605		18,940		19,523
Aggregate Average Lifting Costs
(U.S. dollars per boe)(2)		10.43		9.83		9.04
Aggregate Average Lifting Costs
(Ps$ per boe)(2)		19,266		18,652		19,499

(1) Corresponds to our average sales price on a consolidated basis.

(2) Lifting costs per barrel are calculated based on total production, which are net of royalties, and correspond to our lifting costs on a consolidated basis.

(3) Unit production costs correspond to consolidate average costs on total production volumes net of royalties. Production costs do not include costs related to transport, commercialization and administrative expenses.

(4) During 2010, we modified our methodology for calculating our aggregate average lifting cost as follows: we now calculate this cost by taking our production cost and dividing it by our produced volumes net of royalties as the denominator. Our 2009 aggregate average lifting costs have been restated under the new methodology.

Reserves

Our proved reserves of crude oil and natural gas, net of royalties to the Nation, at December 31, 2011, totaled 1,856.7 million boe, which represents an 8.3% increase from the 1,714 million boe registered in 2010.  Our crude oil proved reserves in 2011 increased to 1,371 million barrels of crude oil from 1,236.4 million barrels of crude oil in 2010 and our natural gas proved reserves increased to 2,768.4 billion cubic feet, or bcf, from 2,722.6 bcf of reserves in 2010.  Our proved reserves in 2010 increased by 11% from the 1,538.2 million boe registered in 2009.  The increase in our reserves during 2011 is mainly due to (i) a 61.8 million boe increase corresponding to revisions of previous estimates, (ii) a 15.4 million boe increase corresponding to improved recovery, (iii) a 34.6 million boe increase corresponding to purchases of minerals in place, (iv) a 252.3 million boe increase corresponding to extensions and discoveries and (v) a 221.5 million boe decrease corresponding to production.

36

Hydrocarbon reserves were calculated in accordance with SEC regulations and the requirements of the Financial Accounting Standards Board, or FASB. Ecopetrol’s complete reserves process is supervised and coordinated by the Director of the Reserves Control Group, a petroleum engineer, with a graduate degree in finance and a master’s degree in petroleum engineering and who has 19 years of experience in several companies in reservoir engineering, field development, reservoir management and estimation and reporting of reserves. The Director of the Reserves Control Group reports to the Chief Financial Officer. The Reserves Control Group is comprised of reserves coordinators, petroleum engineers and geologists with experience of more than 15 years in reservoir characterization, field development, estimation and reporting of reserves and having supervision and supporting responsibilities with the professionals involved in the estimation and reporting process.

Reserves are initially estimated internally. These initial estimates are supervised and coordinated by the corporate manager of reservoirs, a geologist who holds a master’s degree in geology and has more than 20 years of experience in projects associated with reservoir characterization and development, estimation and reporting of reserves. The employees involved in the reserves process meet the Society of Petroleum Engineers-SPE qualifications for reserves estimators. Internally estimated reserves are submitted to an external audit process, which has been carried out by our External Engineers Ryder Scott, DeGolyer and MacNaughton and Gaffney, Cline & Associates. These firms have audited 99% of our total net proved reserves for 2011 and 2010.  According to our corporate policy, we report the reserves values obtained from the External Engineers.  The reserves process continues with the consolidation of the results by the Reserves Control Group and their presentation for approval to the Reserves Committee, consisting of the Chief Financial Officer, the Exploration and Production Executive Vice-President and the Vice-President of Strategy. Decisions of the Reserves Committee have to be unanimous. Finally, results are ratified by the Audit Committee of the Board of Directors and presented to the Board of Directors.

The audit process was conducted in accordance with SEC definitions and rules set forth in Rule 4-10(a) of Regulation S-X and the disclosure guidelines contained in the SEC’s Modernization of Oil and Gas Reporting final rule dated December 31, 2008 and effective as of January 1, 2010. The information presented below and elsewhere in this annual report referring to our 2010 and 2011 net proved reserves estimates is based on those reports and on our own calculations for the remaining 1% of our hydrocarbon net proved reserves. Our crude oil and natural gas net proved reserves include reserves from our subsidiaries located in the United States (Gulf of Mexico), Peru, and Colombia, which includes Hocol and, as of January 24, 2011, our participation in Equion.

The information regarding 2010 net proved reserves is based on the external audit of 99% of our total reserves, prepared by the External Engineers under SEC definitions and rules. The remaining 1% corresponds to estimations made by us internally using SEC definitions and rules. The information regarding 2009 net proved reserves is based on the 2009 audited reserve reports for 97% of our total reserves prepared by the External Engineers under SEC definitions and rules. The remaining 3% corresponds to estimations made by us internally using SEC definitions and rules.

The reserve information presented in this section is based on the SEC’s definitions and rules used for U.S. GAAP purposes. See “Item 5. Operating and Financial Review and Prospects—Critical Accounting Policies and Estimates” and Note 34 to our consolidated financial statements.

The following table sets forth our estimated net proved reserves (developed and undeveloped) of crude oil and gas by region and for the years ended December 31, 2011, 2010 and 2009.

	At December 31,
	2011				2010				2009
	Crude Oil (million barrels)		Gas (bcf)		Crude Oil (million barrels)		Gas (bcf)		Crude Oil (million barrels)		Gas (bcf)
PROVED DEVELOPED RESERVES
Colombia
Ecopetrol S.A.
Northeastern region		81.4		2,096.7		88.6		2,187.8		65.2		1,674.9
Mid-Magdalena Valley region		214.0		33.1		194.8		32.6		148.0		24.4
Central region		328.0		0.0		258.4		0.0		196.2		0.0
Catatumbo – Orinoquía region		74.3		1.0		75.1		7.2		68.6		0.0
Southern region		97.9		2.1		109.1		3.0		97.5		3.8
Minor Fields		4.7		2.7		13.3		2.6		6.6		0.8
Hocol		30.8		1.0		41.5		1.5		29.7		3.1
Equion		9.3		69.6
Total (Colombia)		840.4		2,206.1		780.7		2,234.6		611.6		1,707.0
International
Savía Perú		11.7		21.1		15.9		24.8		14.2		23.0
Ecopetrol America Inc.		3.7		2.3		4.1		2.3		4.7		2.6

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	At December 31,
	2011				2010				2009
	Crude Oil (million barrels)		Gas (bcf)		Crude Oil (million barrels)		Gas (bcf)		Crude Oil (million barrels)		Gas (bcf)
Total (International)		15.4		23.4		20.0		27.0		18.8		25.6
Total Proved Developed RESERVES		855.8		2,229.5		800.7		2,261.7		630.5		1,732.6
PROVED UNDEVELOPED RESERVES
Colombia
Ecopetrol S.A.
Northeastern region		31.0		500.2		38.2		431.8		75.8		584.7
Mid-Magdalena Valley region		53.0		4.1		78.8		15.7		99.1		7.5
Central region		379.3		0.0		270.3		0.0		242.5		0.0
Catatumbo – Orinoquía region		15.0		19.5		17.8		13.4		25.7		0.0
Southern region		8.1		0.0		4.6		0.0		14.6		0.4
Minor Fields		0.4		0.0		3.3		0.0		1.0		0.0
Hocol		14.3		0.0		8.5		0.0		19.3		0.4
Equion		6.6		13.2
Total (Colombia)		507.5		537.0		421.3		460.9		478.0		593.0
International
Savía Perú		7.7		1.9		14.3		0.0		14.9		3.8
Ecopetrol America Inc.		0.0		0.0		0.0		0.0		0.0		0.0
Total (International)		7.7		1.9		14.3		0.0		14.9		3.8
TOTAL PROVED UNDEVELOPED RESERVES		515.2		538.9		435.7		460.9		492.8		596.9
TOTAL PROVED RESERVES (DEVELOPED AND UNDEVELOPED)		1,371.0		2,768.4		1,236.4		2,722.6		1,123.3		2,329.4

The following table sets forth our estimated consolidated net proved developed and undeveloped reserves of crude oil and natural gas at December 31, 2011, 2010 and 2009.

	Net proved developed and undeveloped Reserves
	Crude Oil (million barrels)			Gas (bcf)			Total  (million boe)
Reserves at December 31, 2009		1,123.3			2,329.4			1,538.2
Revisions of previous estimates		99.1			558.7			190.9
Improved recovery		47.4			0.0			47.4
Purchases of minerals in place		0.0			0.0			0.0
Extensions and discoveries		126.3			0.3			126.5
Production		(159.8	)		(165.9	)		(188.9	)
Reserves at December 31, 2010		1,236.4			2,722.6			1,714.0
Revisions of previous estimate		107.6			(260.8	)		61.8
Improved recovery		14.8			3.6			15.4
Purchases of minerals in place		18.3			93.3			34.6
Extensions and discoveries		184.5			386.2			252.3
Production		(190.5	)		(176.5	)		(221.5	)
Reserves at December 31, 2011		1,371.0			2,768.4			1,856.7
Net proved developed reserves
At December 31, 2009		630.5			1,732.6			939.0
At December 31, 2010		800.7			2,261.7			1,197.5
At December 31, 2011		855.8			2,229.5			1,246.9

38

The above-referenced reserve amounts, net of royalty payments to the Nation, are the same amounts used to reconcile Note 34 to our consolidated financial statements under FASB ASC 932.

The Company’s revisions, on a consolidated basis, during 2011 amounted to 61.8 million boe, corresponding primarily to the following:

· Castilla Field: New development project in K1 unit and better production performance (lower decline rates), representing a 70 million boe increase.

· Chuchupa Field: Reevaluation of the original gas in place, derived from new pressure data, representing a decrease in gas sales forecast of 26 million boe.

· Gibraltar Field: Reevaluation of the original gas in the reservoir, representing a decrease in gas sales forecast of 20 million boe.

· Rubiales and Cusiana Fields: Better production performance representing a 16 million boe increase.

The revisions described above represented 64% of the additions to reserves revisions in 2011, while the revisions with respect to the remaining 22 million boe resulted from increases and decreases from a variety of fields such as Tibú, Moriche and Cusiana, among others.

The Company’s improved recovery during 2011 amounted to 15.4 million boe, which corresponded mainly to new proved areas under waterflooding in the La Cira-Infantas and Yarigui- Cantagallo fields.

The Company's purchases of minerals in place in 2011 relates to the acquisition of Equion Energía Limited.

The Company’s extensions and discoveries during 2011 amounted to 253.3 million boe, which corresponded to 4.8 million boe of newly discovered fields and 247.5 million boe to proved acreage extensions. 81% of the proved acreage extensions were associated with activities in the followings fields: 123 million boe were associated with the Castilla Field where the Company plans additional drilling activities in order to cover new proved areas, 41 million boe corresponded to new gas sales agreements in the Cupiagua Field and the availability of a new gas processing plant, and 40 million boe associated with new proved areas in the Quifa and Chichimene Fields. The remaining 19% is distributed among smaller variations in several other fields.

In terms of proved undeveloped reserves, during 2011, the Company added approximately 274 million boe and converted 181 million boe. Total proved undeveloped reserves increased by 93.3 million boe to 610 million boe at December 31, 2011 from 517 million boe at December 31, 2010. As of December 31, 2011, 84% of our total proved undeveloped reserves corresponded to crude oil. The additions in the Company’s proved undeveloped reserves in 2011 are primarily due to extensions and discoveries, revisions of previous estimates, improved recovery, and purchases of minerals in place.

Changes associated with revisions of previous estimates of proved undeveloped reserves corresponds primarily to variations in economic factors, adjustments based on production behavior and updated development plans in several fields, mainly in Castilla, Tibu, Cusiana and Rubiales. The increases by improved recovery are associated mainly with the waterflood projects of La Cira Infantas and Yarigui- Cantagallo fields described above. The Company’s extensions and discoveries relates mainly to extensions of proved acreage, corresponding to projects previously described in the Castilla, Quifa, Chichimene and Cupiagua fields.

Of the total amount of proved undeveloped reserves that we had at the end of 2010 (517 million boe), we converted approximately 181 million boe, or 35%, to proved developed reserves during 2011, mainly the result of (i) crude oil projects, primarily associated with the development of heavy crude oil in Rubiales, Castilla and Chichimene located in the Central region, which represented 58% of the total conversion and (ii) new gas sales agreements in the Cupiagua Field and the availability of a new gas processing plant, which accounted for 11% of the total conversion. The remaining 31% is associated with development execution in other fields, such as Tibú and Cira Infantas, among others. The amount invested during 2011 to convert the proved undeveloped reserves to proved developed reserves was US$2,328 million.

Present Activities

During the first quarter of 2012, Ecopetrol S.A. drilled its first stratigraphic well to explore for non-conventional reservoirs. The results of this stratigraphic well are currently under evaluation. Ecopetrol S.A. also drilled one A3/A2 well (Tisquirama Este-1) in the Mid-Magdalena Basin, where evidence of hydrocarbons was found in April.

39

During the first quarter of 2012 Hocol drilled four A3/A2 wells. Evidence of hydrocarbons was found in two of the wells (Guarrojo and CPO 17), while one is currently under evaluation (Mamey) and one was dry (Margay).

Regarding our offshore activity, during the first quarter of 2012 the exploration platform Offshore Mischief arrived to Cartagena. By using this specialized unit, Equion, who owns 30% of the block interest and acts as operator in a joint venture in which Ecopetrol S.A. owns 30% and Petrobras owns the remaining 40%, expects to drill two exploratory offshore wells in the Caribbean Sea.

In March, the Bureau of Ocean Energy Management (BOEM) of the US Department of the Interior officially awarded Ecopetrol America Inc., blocks EB–284, 285, 328 and 329, located in deep waters of the East Breaks sector of the US Gulf Coast. Additionally, the awarding of the KC-623 block at the Keathley Canyon sector was confirmed in February.

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

To address the country’s exploration and production needs, Colombia has modified the contractual regime governing the exploration, development and production of hydrocarbons on a number of occasions since its introduction in 1970. The exploration and production contracts entered into with 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 case of public order regulations. As a result, contracts that were executed prior to the issuance of a new contractual regime remain in full force and are not affected by the new regime put in place subsequently. At December 31, 2011, we were party to 109 agreements with partners and 23 exploration and production agreements with the ANH in which we do not have any partners.

Under joint venture contracts entered into before March 1994, which include the Cusiana and Cupiagua crude oil fields, among others, 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 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 were 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 venture contracts required us to pay for half of the exploration costs, not only for wells that 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 contract was once again modified in 1997 in order 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. Our initial participation under the joint venture contracts signed after this reform, was reduced from 50% to 30%. At December 31, 2011, we had 42 joint venture contracts outstanding in which our participation was greater than or equal to 50%, and 17 joint venture agreements where our participation was less than 50%.

· Modified R Factor. The Government 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. Additionally, the R Factor was calculated in constant U.S. dollars. The new calculation method was designed to prevent inflation from causing an increase in the R Factor and a corresponding increase in our share.

40

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

· Risk-participation contracts. Under these contracts, we assume 20% 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, 2011, we had four 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 to 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 than 1.5. The volume produced under the production curve is not shared with our partners. At December 31, 2011, we had five SIPAs in effect.

Under the DIPA, we must 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 agree with our partners to develop the field and we determine mandatory investment thresholds for our partners. We are not required 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 that varies depending on the invested amount. Once the mandatory investment stage expires, we agree with our partners on the 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, 2011, we had one DIPA 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, 2011, we had two shared risk production contracts outstanding.

· Risk Service Production Contracts. We began using the risk service production 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 previously specified fee per barrel. At December 31, 2011, 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 these contracts, the contracting party assumes all costs and expenses for the development and operation of a field in exchange for a certain amount of production. At December 31, 2011, we had sixteen discovered undeveloped fields contracts outstanding, of which at least two are nearing termination because the fields have not been in production for some time.

At December 31, 2011 we also had the following agreements:

· One Service and Technical Cooperation Contract with Universidad Industrial de Santander. Pursuant to this agreement, research and development can be undertaken as part of the development of the Colorado field.

· One Technical Alliance Agreement with a service company to support the operation of Casabe field in which we maintain operation and ownership of 100% reserves.

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Current Joint Venture 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 rights. Decree Law 1760 of 2003 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 cost, to exploit the associated reserves indefinitely. Contracts entered into by us after January 1, 2004 that are not extended by the ANH will revert to the ANH and not to us.

In 2004, 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. Under exploration and production contracts 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. The scope of the technical evaluation agreements 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.

In June 2010, the Santiago de las Atalayas Contract, one of the most significant exploration and production contracts based on crude oil and natural gas output and reserves expired. Pursuant to the terms of the agreement, the right to develop and commercialize the existing crude oil and natural gas reserves in the Cupiagua and Cupiagua Sur fields reverted back to us.

We entered into several agreements or “Convenios” with the ANH in areas directly operated by Ecopetrol S.A., where Ecopetrol S.A. holds total exploration and production rights up to the point when revenue from the well falls below the costs of operations set by the company (the “economic limit”). Article 2 of Decree 2288 of 2004 (a regulatory decree pursuant to Decree Law 1760 of 2003), establishes that the ANH shall determine the general criteria according to which the agreements pertaining to the areas directly operated by Ecopetrol shall be subscribed.

Agreements must also be entered into between Ecopetrol and the ANH according to Article 2 of Decree 2288 of 2004, when joint venture contracts subscribed before December 31, 2003, expire during their production phase. The purpose of the agreements is to grant Ecopetrol S.A. the exclusive right of exploration and production of hydrocarbons in the agreement area until the economic limit. Annex II presents a list of those “Convenios.”

We have entered into a number of exploration and production contracts with regional and international oil companies. Annex I present a list of our contracts still in force at December 31, 2011 with a complete description of their main characteristics.

Management of crude oil and natural gas joint ventures

Every crude oil and natural gas joint venture development has an executive committee, that makes all technical, financial and operational decisions. All major decisions are made unanimously, including for those projects in which 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 in which we have less than a majority economic interest. 

Refining and Petrochemicals

Summary

There are two main refineries in Colombia: the Barrancabermeja refinery, which we directly own and operate, and Reficar, a wholly-owned subsidiary. We also own and operate two other minor refineries, Orito and Apiay. Our refineries produce a full range of refined products, including gasoline, diesel, jet fuel, liquefied petroleum gas, or LPG, and heavy fuel oils among others.

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In 2011, we invested Ps$3.0 trillion (approximately US$1.5 billion) in refining and petrochemicals, an increase compared to the Ps$2.1 trillion (approximately US$1.1 billion) invested in 2010, mainly because of the investments related to the expansion and modernization of Reficar’s refinery. Investments in 2011 included 44 different projects, such as re-conversion, upgrading, equipment replacement and environmental projects.

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

	For the year ended December 31,
	2011							2010							2009
	Capacity		Through- put		% Use			Capacity		Through- put		% Use			Capacity		Through- put		% Use
								(bpd)
Barrancabermeja		250,000		225,990		90	%		250,000		225,259		90	%		250,000		216,970		87	%
Reficar		80,000		76,770		96	%		80,000		67,674		84	%		80,000		78,920		99	%
Apiay		2,500		1,768		71	%		2,500		1,631		65	%		2,500		1,525		61	%
Orito		2,500		1,103		44	%		2,500		1,480		59	%		2,500		1,495		60	%
Total		335,000		305,631		91	%		335,000		296,044		88	%		335,000		298,910		89	%

Barrancabermeja

At Barrancabermeja, 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 and industrial products, including, paraffin waxes, lube base oils, low-density polyethylene, aromatics, asphalts, alkylates, cyclohexane and aliphatic solvents, as well as refinery grade propylene. The Barrancabermeja refinery supplies approximately 80% of the fuels consumed in Colombia.

The average conversion ratio for Barrancabermeja during 2011 was 77.0%. The gross refining margin increased from US$8.01 per barrel in 2010, to US$11.22 in 2011 mainly due to better margins because of the higher price of refined products like gasoline, diesel and jet fuel, compared to 2010.

Barrancabermeja is currently undergoing a modernization process to convert it into a deep-conversion refinery, allowing it to process heavy and extra-heavy crudes produced at local fields and increase production of mid-distillates for the local market. This project is expected to improve the refinery’s profitability and supply the entire Colombian market without the need for any imports of refined products. The modernized refinery is expected to produce fuels of higher quality, which will help reduce pollution and lead to better air quality in Colombia. This project is expected to be in operation by 2016.

The following table sets forth the production of refined products of Barrancabermeja for the years ended December 31, 2011, 2010 and 2009.

	For the year ended December 31,
	2011		2010			2009
	(bpd)
LPG, Propylene and Butane		13,116		15,140			17,122
Gasoline Fuels and Naphtha		74,196		76,542			75,174
Diesel		53,319		52,801			52,413
Jet Fuel and Kerosene		18,562		18,324			15,375
Fuel Oil		52,179		49,570			44,390
Lube Base Oils and Waxes		2,001		2,216			2,288
Aromatics and Solvents		3,293		2,739			3,301
Asphalts and Aromatic Tar		7,495		6,759			7,547
Polyethylene, Sulfur and Sulfuric Acid		957		1,038	(1)		881
Total		225,118		225,129	(1)		218,491
Difference between Inventory of Intermediate Products		386		725	(1)		236
Total Production		225,504		225,854	(1)		218,727

(1) Amounts adjusted upwards based on updated measurements.

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During 2011, we delivered 64.50 thousand bpd of hydrotreated gasoline (less than 300 parts per million sulfur content) and 77.57 thousand bpd of hydrotreated diesel (less than 500 parts per million sulfur content) to meet existing fuel quality standards and to improve the refining margin.

Reficar

As part of our Strategic Plan, we expect to increase the competitiveness and profitability of Reficar through the modernization of its facilities and processes, and the improvement of its unit’s reliability. We plan to increase the refinery’s production capacity to 165 thousand bpd by 2013 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.

On December 30, 2011, with approval from the Ministry of Finance, Reficar executed the project financing agreements for the expansion and modernization of Reficar’s refinery in the amount of US$3.5 billion with a repayment term of 14 years. See “Item 5. Operating and Financial Review and Prospects—Liquidity and Capital Resources.”

The following table sets forth the production of refined products of Reficar for the years ended December 31, 2011, 2010 and 2009.

	For the year ended December 31,(1)
	2011		2010		2009
	(bpd)
LPG, Propylene and Butane		5,526		4,056		5,255
Motor Fuels		25,515		23,826		26,847
Diesel		20,533		16,516		20,742
Jet Fuel and Kerosene		6,730		6,252		8,098
Fuel Oil		17,469		14,907		16,710
Aromatic Tar		1,225		1,252		945
Other Products		44		42		40
Total		77,042		66,852		78,636
Difference between Inventory of Intermediate Products		1,130		1,722		1,619
Total Production		78,172		68,573		80,255

(1) The table shows the entire production of Reficar.

In 2011, production by Reficar was 78.2 thousand bpd, an increase compared with 68.6 thousand bpd in 2010. Nevertheless, during 2011 Reficar’s operation suffered some unplanned production stoppages during the months of September and October, which impacted the planned production. These stoppages were principally due to the overheating of the refinery’s cracking unit, the need to clean its sulfur unit and a failure in its power generation.

The average conversion ratio for Reficar during 2011 was 75.98%. The gross refining margin increased from US$6.11 per barrel in 2010, to US$6.68 in 2011, mainly due to better margins as a result of higher price of refined products like gasoline, diesel and jet fuel, compared to 2010.

In addition to our product slate, in 2011 we started to purchase low-sulfur gasoline and continue purchasing low-sulfur diesel and biodiesel to improve the quality of the diesel and gasoline produced at Reficar. Reficar is currently purchasing biodiesel fuel in the local market and mixing it with its production of diesel to reduce sulfur content to meet local specifications.

Petrochemicals and other products

We own and operate four petrochemical plants and one paraffin and lube plant located within Barrancabermeja, producing a variety of products including aromatics, cyclohexane, paraffin waxes, lube base oils, polyethylene and solvents. In 2011, we produced 28,992 tons per year of low-density polyethylene and 926 thousand barrels of aromatics (benzene, tolueneo, xylene, orthoxylene, heavy aromatics and cyclohexane), a 13.2% decrease and 25.7% increase compared to a production of 33,419 tons per year of low-density polyethylene and 736 thousand barrels aromatics in 2010, respectively.

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Propilco

During 2011, Propilco’s production totaled 381 thousand tons of petrochemical products, a 6.4% and 1.0% decrease when compared to the 407 thousand tons produced in 2010 and 385 tons in 2009, respectively. The gross margin in 2011 was 7.44% higher than in 2010, an increase from US$242 per ton in 2010 to US$260 per ton in 2011.

The following table sets forth Propilco’s average capacity and throughput for each of the last three years.

	For the year ended December 31,
	2011			2010			2009
	(Metric Tons)
Average capacity		475,000			475,278			455,000
Throughput		380,878			407,411			384,858
% Use		80	%		86	%		85	%

Transportation and Logistics

Summary

Our transportation and logistics segment includes the transportation of crude oil, motor fuels, fuel oil and other refined products, excluding natural gas due to legal restrictions. Since 2009, our transportation and logistics segment has been transporting diesel and palm oil mixture.

As of December 31, 2011, we, directly or indirectly with private sector participants, owned, operated and maintained an extensive network of crude oil and refined products pipelines connecting our own and third-party production centers and terminals to refineries, major distribution points and export facilities. We directly own 40% of the total crude oil pipeline shipping capacity, a 5% less than in 2010 due to the conversion of Apiay-Monterrey crude oil pipeline into a multipurpose pipeline, and 99% of the total product pipeline shipping capacity in Colombia. When aggregated with the crude oil pipelines in which we own an interest, we have 76% of the oil pipeline shipping capacity in Colombia.

At December 31, 2011, our network of crude oil and multi-purpose pipelines extended approximately 8,768 kilometers in length. The transportation network we own directly, in partnership with other companies, and in joint venture partnerships consists of approximately 5,089 kilometers of main crude oil pipeline networks connecting various fields to the Barrancabermeja refinery and Reficar, as well as to export facilities. We directly own 2,886 kilometers of crude oil pipeline and an additional 2,203 kilometers of crude oil pipeline with our business partners. We also own 3,679 kilometers of multi-purpose pipelines for transportation of refined products from the Barrancabermeja refinery and from Reficar to wholesale distribution points. Total length of multipurpose pipelines increased with respect to 2010 mainly due to the conversion of the Apiay-Monterrey segment from a crude oil to a multipurpose pipeline as a consequence of the start of operations of the Poliducto Andino.

During 2011, we met our customer satisfaction index goal, and we maintained our ISO 9001:2008, ISO 14001 and OHSAS 18001 certifications for all of our transportation processes. We also attained the certification by the Oil Companies International Marine Forum – OCIMF, which provide standards for hydrocarbons reception, storage, dispatch by pipes and pipelines and the import and export facilities of our docks.

We are currently developing our transportation infrastructure in order to meet our increased transportation needs in Colombia and any additional needs, which may result from new discoveries.

In 2011, as a result of an internal reorganization, the Transportation Vice-Presidency reports directly to our CEO and the areas of Ports Management and Commercial and Transportation Services Department were created. The goals and challenges of this reorganization are: (i) to provide transportation and logistics solutions in a comprehensive, effective and profitable way for all stakeholders, (ii) to promote businesses through capital diversification by incorporating third-party users and nonusers, (iii) to provide a service with clear rules and high levels of efficiency, and (iv) to provide solutions designed for the whole country’s oil production evacuation.

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In spite of all the programs and activities designed and developed according to our integrity assurance model, during the last quarter of 2011 our transportation infrastructure was severely affected by a heavy rain season. Due to unforeseeable circumstances, in December 11, 2011 and December 23, 2011, the Caño Limón – Coveñas crude oil pipeline and the Salgar-Cartago product pipeline, respectively, were ruptured due to the landslides caused by heavy rains that saturated the ground.

As a result of these incidents, we have sought to take precautions against similar events in the future, which might affect the transportation infrastructure and have an impact in the regions in which we have a presence. In January 2012 three large-scale programs were structured: the Dosquebradas Project, the Integrity Program and the Contingency Program:

· Dosquebradas Program: Intended to restore physical and social conditions of the people affected by the incident at Dosquebradas. We have designated a program manager and five coordinators for this program who are in charge of performing activities regarding the following topics: health, housing, business and government, social, legal and environmental. Additionally, the structure is strengthened by a group of employees that assist cross-related activities such as finance, control and communications.

· Integrity Program: Intended to strengthen the current transportation integrity scheme with technical, technological and management world class excellence. To fund this program, we approved a budget of US$489 million. The transportation integrity scheme aims at securing the reliability in our transportation system.

· Contingency Program: Intended to strengthen our contingency system to contain the effects that any future incident at our facilities, including those incidents derived from acts of god which are irresistible, unpredictable, and unforeseeable, may have on the local communities or the environment. The approved budget to carry out the planned activities is US$39 million. The main goals of the program are: (i) reinforce the implementation of the Contingency Plans within the communities and local and regional committees, (ii) update the Environmental Management Plans and the Contingency Plans associated to the expansion projects and new infrastructure, (iii) enhancement of the relations with institutions and organizations that participate in the activities established to attend emergencies and (iv) improve and implement the emergency response model.

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

TRANSPORTATION INFRASTRUCTURE

Pipelines

In 2011, pipelines in which we own an interest transported a total of 915.6 thousand bpd of crude oil and 288.9 thousand bpd of refined products for a total of 1.20 million bpd in 2011, a 16% increase when compared to 2010. In 2010 pipelines transported a total of 1.03 million bpd of crude oil and refined products compared to 799.5 thousand bpd in 2009.

The following table sets forth our main pipelines and the main pipelines in which we own an interest by name, kilometers covered, type of product transported, origin, destination and our ownership percentage as of December 31, 2011.

Pipeline	Kilometers	Capacity Thousand bpd	Product Transported	Origin	Destination	Ownership Percentage
Caño Limón-Coveñas	770.6	220.0	Crude Oil	Caño Limón	Coveñas	100.00	%
Oleoducto del Alto Magdalena (OAM)	396.5		Crude Oil	Tenay	Vasconia	85.12	%
Oleoducto de Colombia (ODC)	480.8	205.0	Crude Oil	Vasconia	Coveñas	73.00	%
Oleoducto Central (Ocensa)	834.5	551.6	Crude Oil	Cupiagua	Coveñas	72.50	%
Oleoducto Transandino	306.9	48.0	Crude Oil	Southern fields	Tumaco Port	100.00	%
Oleoducto de los Llanos (ODL)	262.0	340.0	Crude Oil	East fields	Monterrey Cusiana	65.00	%
Oleoducto Bicentenario de Colombia S.A.S.(1)	–	-	Crude Oil	Araguaney	Banadia	55.97	%

(1) Oleoducto Bicentenario de Colombia S.A.S. was incorporated by us in late 2010.

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Oleoducto Bicentenario de Colombia S.A.S. is constructing a crude oil pipeline, which will be the largest of its kind in Colombia. The construction of the pipeline will be developed in phases, which we expect to complete by 2014. The total investment is estimated at US$4.2 billion. Phase 1 will connect Araguaney to Banadía and is expected to permit the evacuation of 120 thousand bpd, with an investment estimated at US$1,350 million, of which, up to 70% is expected to be financed through a credit facility in the local market, and the remaining through shareholders’ contributions. During 2011, we completed the construction of 43% of phase 1 and expect to complete phase 1 in 2012. The next phases are awaiting internal approvals from shareholders and environmental licenses from governmental authorities.

The operation of our pipelines follows international standards and industry practices, such as remote operation, integral management, automatic ticket transfer, health, safety and environmental policies and a high customer satisfaction index.

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

	For the year ended December 31,
	2011		2010		2009
	(thousand bpd)
Crude oil transport		915.6		770.9		576.2
Refined products transport		288.9		264.9		223.3
Total		1,204.5		1,035.8		799.5

At December 31, 2011, we owned 52 stations, 20 of them located in crude oil pipelines, 23 of them in refined products pipelines and nine in the ports and riversides (not including those associated to the transportation network that belong to third parties and are operated by us). In addition, we have a nominal storage capacity associated to the transportation network of 19 million barrels of crude oil and 6 million barrels of refined products, an increase of 570 thousand barrels compared to 2010, represented by an increase of 270 thousand barrels in crude oil storage capacity and 300 thousand barrels in refined products storage capacity. We also sell storage capacity to third parties in our Pozos Colorados and Mansilla facilities and in the Coveñas port. We do not own any tankers.

Theft of hydrocarbons

Hydrocarbon theft, which reached a peak of 7,270 bpd in 2002, was reduced to 81 bpd in 2011, as a result of the comprehensive strategy developed in coordination with different law-enforcement agencies and governmental authorities. Theft of fuel in 2011, when compared to 2010, was reduced by 38.6%. 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.

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 facilities. 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 2011, 33.8 million barrels of crude oil and refined products were transported by tanker trucks and 8.9 million barrels of crude oil and refined products were transported by barges.

Export and import facilities

We currently have concessions from the Government for four docks for export of crude oil and refined products. Our crude oil loading facilities can load tankers of up to 150 thousand deadweight tonnage (DWT). Adjacent to these loading facilities we also have crude oil storage facilities that are capable of storing 7.5 million barrels. Our docks used for import and export of refined products can load tankers of up to 85 thousand DWT. Additionally, these facilities have storage capacity of up to 1 million barrels. In 2011, we also increased our export capacity from 470 to 770 kbpd in the Coveñas Port, and were able to load three crude oil tankers of up to 2 million barrels in capacity.

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New transportation projects

Oil Evacuation Program

In 2011, we enhanced the strategy to evacuate the oil production through the 2010-2016 Oil Evacuation Program in which short, medium and long-term projects were structured to develop the required infrastructure to increase oil transportation capacity up to 2.2 million bpd. The Program’s scope has been expanded this year, taking into account production forecasts calculated from yearly updated data provided by the Colombian oil producers.  Some of the projects from this program that were completed during 2011 include:

· increasing the capacity of the following crude oil pipelines: Caño Limón - Coveñas and Ayacucho – Coveñas; Araguaney - Monterrey – Porvenir; Castilla – Apiay; Vasconia – GRB – Galán; Rubiales – Monterrey – Cusiana (ODL); Vasconia – Coveñas (ODC);

· increasing the capacity of the Pozos Colorados – Galán product pipeline up to 90 thousand bpd;

· beginning operations of the Poliducto Andino product pipeline of 53 thousand bpd to assure the dilution of heavy crude oils;

· increasing the export capacity in the Coveñas Port to 770 thousand barrels;

· increasing our loading capacity by 65 thousand bpd with respect to 2010 as a consequence of the beginning of operations of the Banadía loading facility and the expansion of the Araguaney and Ayacucho loading facilities; and

· increasing our crude oil storage capacity by 270 thousand barrels in Banadía and Altos del Porvenir, and 300 thousand barrels in Ayacucho.

New Business Development

We completed two significant deals in 2011, including (i) an agreement with Occidental de Colombia Inc. to take control of the Caño Limón – Coveñas crude pipeline, (ii) the increase of Ocensa’s line up capacity to 560 kbpd and (iii) the development of plans to offer logistic solutions to third-party users through transport-capacity bidding rounds, in which contracts with Mansarovar, Gran Tierra and Petrominerales were signed.

Incidents at Transportation Facilities

Salgar-Cartago multipurpose pipeline spill

On December 23, 2011 our Salgar-Cartago pipeline ruptured. We believe this incident occurred as a result of creep movement caused by severe weather conditions in the area, causing the surrounding soil to exercise strong pressure on the pipeline and rupturing it. Due to the rupture, approximately 1,428 gallons of gasoline spilled into the surrounding area in La Divisa y Villa Carola in the Municipality of Dosquebradas, Risaralda. The spilled gasoline from the pipeline subsequently came into contact with a heat source which ignited it, causing several explosions that tragically resulted in 33 fatalities and 77 injuries, as well as damages to the neighboring houses and buildings.

In connection with this incident, the Corporacion Autónoma Regional de Risaralda or CARDER, the Regional Environmental Authority for the Department of Risaralda, has launched an investigation into the causes of the incident. As of the date of this Annual Report, CARDER has not filed any legal action against us. We launched our own internal investigation and hired a local engineering firm as well as a highly renowned international consultant to investigate the causes of this incident. Our internal investigation and the investigation conducted by the Colombian engineering firm confirmed that the pipeline had ruptured as a result of creep movement and the pressure exercised by the soil on the pipeline. The investigation conducted by the international engineering firm is still in progress.

As of March 21, 2012, we have made contributions of approximately Ps$4.2 billion to assist those affected by the incident. These contributions include transfers to “Gente Ecopetrol” foundation , the local red cross, and other organizations.

As of January 4, 2012, we have cleaned the totality of affected water bodies and the majority of our remediation activities in connection with the product spill have been completed. In addition, we are currently carrying out activities to restore the site according to the guidelines provided by the CARDER.

Together with the victims, we filed a joint request before the District Attorney of Pereira to promote an extrajudicial settlement of the damages caused by this incident. We recently reached to an extrajudicial settlement agreement with the 180 victims of this incident pursuant to which we agreed to indemnify them for an aggregate amount of approximately Ps$ 8,000 million. This settlement agreement was promoted by us under our principles of solidarity and social responsibility and does not imply an admission of our culpability for the damages caused by this incident. This settlement agreement still has to be approved by court of Risaralda.

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Caño Limon – Coveñas crude oil pipeline spill

In December 11, 2011, our Caño Limon - Coveñas oil pipeline ruptured. We believe this incident occurred as a result of an unusual movement of soil and the tensioning of the pipeline, resulting from severe weather conditions. The incident caused the spill of approximately 3,267 barrels of crude oil into the Iscala creek, which connects with the Pamplonita River, located in the Municipality of Chinácota in the Department of Norte de Santander, which capital city is Cúcuta. The incident did not cause any fatalities or injuries.

At the time of the incident, the pipeline was not in operation. We activated the corresponding contingency plan and called for the support of the CREPAD, which is the regional committee for attention and prevention of disasters. Five hundred workers were assigned to the decontamination of the Iscala creek and the Pamplonita River. In addition, the authorities decided to close Cúcuta’s aqueduct gates as a preventive measure, while certified laboratories performed tests to determine its water quality.

Notwithstanding a technical commission’s determination that the incident was caused by an unforeseeable events unrelated to our operation, as a result of negotiations with national, regional, and local authorities alongside representatives of the local community, we agreed to construct, at our own expense, an aqueduct intake in the upstream of the Caño Limon – Coveñas pipeline in order to prevent the water supply to Cúcuta and its surrounding area from being affected by any unexpected, irresistible, or unforeseen events caused by soil movements or terrorist attacks. In order to meet this commitment, as of December 2011, we allocated a provision of Ps$67 billion.

In connection with this incident, the Regional Environmental Authority of Norte de Santander, or Corporación Autónoma Regional de la Frontera Nororiental - CORPONOR, has launched an investigation into the causes of the incident and has initiated enforcement actions against us for the alleged wrong implementation of the contingency plan. Our response to the charge is aimed at demonstrating that CORPONOR does not have juridisction to launch an investigation for the alleged breach.

We launched our own internal investigation and hired a highly renowned international consultant to investigate the causes of this incident. We believe investigations will continue for the foreseeable future, and we cannot provide any indication as to their outcome, including whether we will be found liable or subject to enforcement actions.

In addition, we have paid Ps$17.2 billion in the decontamination of the Iscala creek and Pamplonita river and additional remediation activities.

As of January 4, 2012, we have cleaned the totality of affected water bodies and the majority of our remediation activities in connection with the product spill have been completed.

We have third-party general liability insurance coverage that applies to damages resulting from incidents such as the ones that occurred in Dosquebradas and Cucuta.

Given the uncertainty of the outcome of current investigations and of potential future claims regarding these two incidents, we recorded in our financial statements a provision for future payments and disbursements as if we had been found liable for all damages caused by the incidents. Nevertheless, the provision is only a reasonable estimate of the costs associated with the incident and not a definitive amount. We will continue to review the amount of any necessary accruals, potential asset impairments, or other related expenses and record the charges in the period in which the determination is made and an adjustment is required.

Marketing and Supply

Summary

We market a full range of refined and feed stock products locally including regular and high octane gasoline, diesel fuel, jet fuel, natural gas and petrochemical products, among others. Local sales of regular gasoline, LPG, jet fuel and diesel fuel as well as natural gas from the Guajira field are subject to government price regulation with reference to international benchmarks.

We are the main producer and supplier of 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. In terms of LPG, the Energy and Gas Regulatory Commission establishes maximum prices as well as wholesale and retail margins.

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Our crude oil export sales are made in the spot market and through long-term contracts, primarily to U.S. Gulf Coast refineries, the U.S. West Coast, Caribbean and Chinese refineries.

Purchase Commitments with our business partners

We have entered into a number of crude oil purchase contracts with certain of our business partners. Crude oil purchased from our business partners is either processed in our refineries or exported. The purchase price is calculated based on international market prices. Consequently, part of our financial exposure depends on the international prices of oil. We believe that the risk of such exposure is naturally hedged since we either export the crude oil at international market prices or sell refined products at prices which are correlated with international market prices. Under most of our existing contracts, we are obligated to purchase 100% of our partner’s production in the specific field. During 2011, total volumes of crude oil we purchased on from our business partners amounted to 20.4% of our total crude oil volume sales.

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.

Crude oil supply commitments

As part of our transfer of assets to Reficar in April 2007, we extended a commercial offer to Reficar for the supply of crude oil. The commercial offer has been periodically renewed and it is still in effect. Pursuant to the terms of the offer, Reficar has the option to purchase from us up to 85 thousand bpd of crude oil from our Caño Limón, Vasconia Blend, Cusiana and Castilla production. As we continue to operate Reficar, our operations committee evaluates and decides on a monthly basis the refinery’s crude oil mix needs, including the need for foreign crudes which we may import to meet our commitments. The purchase price for the delivered volumes is equal to an international benchmark index, subject to certain adjustments.

Import of Ultra Low Sulfur Diesel Fuels and Diluents

We are reducing sulfur emissions from fuels produced by us through the import of ultra low sulfur diesel to be mixed with our local production. Since January 2010, we supply diesel with sulfur levels under 50 ppm (parts per million) to Bogota, Medellin and other cities around the country that also have bus-based mass-transportation systems. In the rest of the country, we deliver diesel with sulfur levels under 500 ppm (parts per million). We expect that the quality of our diesel produced and sold (sulfur levels) will continue to improve in 2013 according to international standards. In 2011, to assure the required quality in the country we increased imports of ultra-low sulfur diesel in 9.8% as compared to 2010.

Until 2011, we managed gasoline sulfur levels under 1,000ppm (parts per million) nationwide. Since 2011, we reduced these levels to under 300 ppm (parts per million), an improvement that placed this type of gasoline as the one with the lowest sulfur levels in Latin America.

We have also increased imports of natural gasoline, used as a diluent to allow our heavy crudes to be pumped through the pipelines. In 2011, we imported 44.1 thousand bpd of natural gasoline against 17.5 thousand bpd in 2010.

Natural Gas Distribution

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. In Colombia we have been selling natural gas to local distribution companies, power generators and large customers, and have also been exporting natural gas to Venezuela. 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 Ecogas. Ecogas had spun off from us in 1998. Thereafter, Ecogas transferred all of its assets to a new company, incorporated for such purpose, named Transportadora de Gas Internacional S.A. E.S.P., or TGI, formerly, Transportadora de Gas del Interior S.A.E.S.P., which is owned by Empresa de Energía Eléctrica de Bogotá.

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Marketing of Natural Gas

As a result of the growth of the natural gas demand from Venezuela and the increase in the domestic consumption of the gas-powered plants in recent years, the total demand for natural gas, including natural gas exports in 2011 was 1,062 gbtu, representing a slight increase with respect to 1,061 gbtu, demanded in 2010. In 2009, demand was 1,035.1 gbtu; having grown 2.7% compared to 2008.

Natural Gas Distribution

Currently, there are more than 20 natural gas distribution companies with operations in Colombia.  We sell natural gas to distribution companies through take-or-pay or swing contracts.

Compressed Natural Gas

Demand for compressed natural gas decreased to 73 gbtud in 2011, a 2.7% decrease as compared to the 75 gbtud demanded in 2010. This decrease is explained mainly because during 2011 some compressed natural gas vehicles were taken off the market and not replaced, and new kits used to convert vehicles to compressed natural gas had higher energy efficiency, which was partially offset by an increase in the amount of vehicles converted to natural gas. According to the Ministry of Energy and Mines, a total of 365,182 vehicles had been converted to natural gas as of December 31, 2011, an increase of 40,667 vehicles over the total of 324,515 that had been converted in 2010, when 22,150 vehicles were added to the 2009 total of 302,365. The total amount of vehicles converted in 2010 was updated by the Ministry of Mines and Energy.

During 2011, we amended three of the agreements for the supply of compressed natural gas in the Colombian Atlantic Coast, Medellín and Bogota in order to maintain the current incentives program that fosters conversions of motor vehicles to natural gas in these regions from gasoline to natural gas. In addition, we began an early stage of planning and implementation of new incentives programs in Santander, in the south of the country and in the Llanos region. The objective is to sign these new agreements during 2012.

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. Currently, we have long-term take-or-pay contracts subscribed with 9 of 14 gas-fired and combined cycle power plants. Most of these contracts were signed between 1996 and1997, and the last one was subscribed in 2011. Some of these contracts expire in 2012. 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.

During 2011, Ecopetrol sold 252.4 gbtud of natural gas from Guajira and Cusiana fields to clients from different sectors such as distributors, industries and power plants. In 2011, the lower consumption by power generators allowed the recovery of sales to the industrial sector. This was the opposite of what had occurred in 2010, when sales to the industrial sector dropped, due both to the weather phenomenon known as “El Niño” and to the corresponding higher demand by power plants.

The following table sets forth our local deliveries of natural gas including deliveries to our refineries, during 2011, 2010 and 2009.

	For the year ended December 31,
	2011		2010			2009
		(gbtud)
Gas-fired power plants		95.1		158.8			153.7
Refineries		112.5		98.5			87.2
Petrochemical		3.8		3.7			3.1
Industrial(3)		156.5		67.8			65.7
Distributors (3)		101.7		167.6	(1)		172.2	(1)
Compressed Natural Gas		39.5		41.9			36.2
Producers(2)		36.2		106.5			30.3
Total Deliveries		545.3		644.8			548.4

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

(2) Between January and September 2010, an increase resulted from higher gas delivery contemplated by our agreement with Chevron.

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(3) The difference between 2010 and 2011 figures is explained by our implementation of “Sinergy,” a new nomination software we use to disaggregate sales to distributors by market sector supply. The previous nomination system did not allow this disaggregation.

Natural Gas Exports

In 2007, we and Chevron entered into a long-term natural gas supply contract with PDVSA through the end of 2011. In 2011, we extended the natural gas export contract until June 2014. Pursuant to the terms of the agreement, we have agreed to deliver the following quantities of natural gas to Venezuela:

	For the year ended December 31,
	2012		2013		2014(2)
	(gbtud)
Volume commitments(1)		93.4		87.3		100

(1) The quantities for each month are different, due to the fact that the volume per year is a weighted average.

(2) The quantity for 2014 is a weighted average from January to June 2014.

In 2011, we and our partner Chevron delivered 204.5 gbtud, exceeding the quantity of natural gas we agreed to supply in our gas export contract with PDVSA. In 2010 and 2009, we and Chevron delivered 154.9 gbtud and 179.1 gbtud respectively. Of the total volume of gas delivered in 2011, 73% came from us and 27% came from Chevron.

Natural gas delivery commitments

In 2011, we participated along with the Commission for Regulation of Energy and Gas in the definition and implementation of new rules for marketing gas in the mid-term. In accordance with the new regulatory framework, we updated our committed natural gas volumes for the years 2012 and 2013.

The table below sets forth the commitments we have in firm contracts with local natural gas distribution companies, local industries, gas fired power generators, international companies, including PDVSA in Venezuela, and internal agreements with our refineries and fields:

	For the year ended December 31,
	2012		2013		2014		2015		2016		2017
	(gbtud)
Volume Commitments		636.6		613		352.5		271		256		257

Pursuant to long-term supply contracts and other agreements, we must supply natural gas to these parties, and failure to deliver the agreed amounts could result in penalties under the contracts.

In 2011, we paid Ps$2.5 billion mainly in compensation for non-delivery of natural gas resulting from weather disruptions. In 2010, we paid Ps$85.2 billion for non-delivery of natural gas as a consequence of the weather phenomenon known as “El Niño”.

In order to meet our natural gas delivery commitments, we have four main natural gas production fields, the Guajira fields, the Cusiana and Cupiagua fields, the Piedemonte fields and the Gibraltar fields. The Guajira, Cusiana and Cupiagua and Piedemonte fields are productive fields. The Gibraltar field began production in 2011. Of our total natural gas production at December 31, 2011, 59.5% was supplied by the Guajira production, 26.3% from the Cusiana and Cupiagua fields and the remaining 7.41% from fields located in other regions. Our participation in the Colombian natural gas market in 2011, including export volumes, was 62%, a decrease compared to 2010 and 2009 when the participations stood at 64.5 % and 64.4% respectively.

Since 2011, Decree 2100 of 2011 issued by the Ministry of Energy and Mines established that, all the producers have to make a production statement including the volumes available for sales, because this production statement is official information for the market. The following table sets forth the total production statement for 2012-2016 published by the Ministry of Energy and Mines in the fields in which we hold a stake:

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	For the year ended December 31,
	2012		2013		2014		2015		2016
	(gbtud)
Guajira Fields		684.0		656.0		576.0		475.0		415.0
Cusiana and Cupiagua Fields		466.1		466.1		466.1		466.1		466.1
Other Fields		114.5		108.0		101.7		99.7		99.1
Imports(1)		0.0		0.0		39.0		85.0		127.0
Total		1,264.6		1,230.1		1,182.8		1,125.8		1,107.2

(1) Imports were moved from 2012 to 2014 due to the extension of the export contract with PDVSA.

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 that consume less than 100 thousand cfpd from La Guajira field under take-or-pay contracts. Maximum prices we can charge to these “regulated customers” are determined with reference to the average export price for fuel oil for the previous 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 the same priority under the firm commitments as other users such as industrial consumers and power generators. 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.

The Ministry of Mines and Energy also establishes distribution priorities in the event of a natural gas shortfall derived from supply or infrastructure issues. This order of priority is based on the type of contract, with firm supply contracts having priority over swing supply contracts.

Regulation

The principal authorities that regulate our activities in Colombia are the Ministry of Mines and Energy, the National Hydrocarbons Agency, or ANH, and the Regulatory Commission of Energy and Gas, or 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, distribution and export of minerals and hydrocarbons.

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 may be 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. Decree 4137 of 2011 changed ANH’s legal nature and defined new functions for it.

CREG

Laws 142 and 143 of 1994 created the CREG, a special administrative unit of the Ministry of Mines and Energy, responsible of establishing the standards for the exploitation and use of energy, regulating the domestic utilities of electricity and fuel gas (liquefied petroleum gas and natural gas). The CREG is also responsible of fostering the development of the energy services industry, promoting competition and responding to consumer and industry needs. Decree 4130 of 2011 assigns CREG new functions previously fulfilled by the Ministry of Mines and Energy.

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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 (Superintendencia de Servicios Públicos Domiciliarios).

Superintendency of Corporations

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

Superintendency of Finance

The Superintendency of Finance (Superintendencia Financiera) 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 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.

Superintendency of Ports and Transport

The Superintendency of Ports and Transport (Superintendencia de Puertos y Transporte) has exclusive control and regulates us in matters related to ports concession contracts, in which we act as contractor.

National Superintendency of Health

Because we provide health benefits to our employees and their families, the National Superintendency of Health (Superintendencia de Salud) has exclusive control and regulates us in matters related to the inspection, supervision and control of the Social Security Health System.

Hydrocarbon Resources Administrator

National Hydrocarbons Agency – ANH

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. Any oil company working in Colombia, must present to the ANH periodical reports on the evolution of their exploratory and production activities. 

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 (Código de Petróleos), 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 2310 of 1974. Consequently, during such period all of our activities were outlined and regulated by this decree. Decree 2310 of 1974 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 2310 of 1974.

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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 of 2003 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. Resolution 18-1495 of 2009 establishes a series of regulations regarding hydrocarbon exploration and production.

Pursuant to Colombian law we are obligated 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, linking them to the production level of crude oil and natural gas fields discovered after July 29, 1999 and to 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 products delivered by producers of crude oil 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 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 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.

Decree 2100 of 2011 modified the commercialization scheme of natural gas royalties. Beginning in June 2012, producers must directly commercialize the royalties of their own production on behalf of the ANH. In return, the ANH will pay a commercialization fee to producers.

Regulation of Refining and Petrochemical Activities

Refining and petrochemical activities are considered a public utility activity 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.

In 2008, Law 1205 was issued with the main purpose of contributing to a healthier environment, and established the minimum quality that fuels should have in the country and the time frame for such a purpose. Since August 2010, Ecopetrol has been selling diesel and gasoline that complies with the requirements of the aforementioned law, at its refinery in Barrancabermeja.

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 Ministry of Mines and Energy.

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As of May, 2012, under the powers granted by Decree 4130 of 2011 for currency and tax matters, the ANH will determine the crude oil price reference.

Regulation of Transportation Activities

Hydrocarbon transportation activity is considered a public utility activity 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, the Commerce Code (Código de Comercio) and with all governmental decrees and resolutions.

Notwithstanding the general rules for hydrocarbon transportation in Colombia, natural gas transportation has specific regulations, due to the categorization of natural gas distribution as a public utility activity under Colombian laws. Therefore, natural gas distribution transportation is governed by specific regulation, issued by the CREG that seeks primarily to satisfy the needs of the population.

Transport systems, classified as crude oil pipelines and multipurpose pipelines, can be owned by private parties. The building, operation and maintenance of 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 to all.

Hydrocarbon transport activity may 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 of all pipelines;

· Mediation of rates between parties or, in case of disagreement, establishing the hydrocarbon transport rates based on information furnished by the service provider;

· Issuing hydrocarbon transport regulations;

· Liquidation, distribution and verification of payment of transport-related taxes; and

· 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 other requirements from the regional environmental authorities.

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

The Colombian natural gas market is divided into two types of markets: (i) the regulated price market and (ii) the free price market. Decree 2100 of 2011, issued by the Ministry of Mines and Energy, introduced a new regime for the selling and marketing of natural gas in Colombia, including specific procedures that regulate the Colombian market in order to administer the remaining natural gas reserves that the Nation owns, and protect the national consumers, especially the residential consumers of natural gas.

Decree 2100 of 2011 divided markets in order to regulate marketing procedures as they relate to the production capacity of each production field in Colombia. The producers that operate fields with production capacity of more than 30 million cfpd (“Large Fields”) of natural gas must follow a specific procedure for selling natural gas. The producers that operate fields that produce under 30 million cfpd are free to sell natural gas in terms agreed upon with interested buyers in the Colombian market.

Regarding Large Fields selling procedure, Decree 2100 of 2011distinguished between regulated price fields (Guajira field), and non-regulated price fields. For the Guajira field, Decree 2100 of 2011 establishes a specific order to allocate natural gas, privileging the buyers that would supply to residential consumers and small businesses and industry, as well as natural gas transporters. Buyers included in the privileged list have the first option to buy natural gas under the conditions offered by the producer. If such buyers choose not to use this option, then the next buyer in the privileged list will be awarded that first option to acquire natural gas, until the gas is totally allocated.

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For non-regulated price fields, Decree 2100 of 2011 and Resolutions 118 of 2011, 140 of 2011 and 167 of 2011, issued by the CREG provide a specific procedure to sell natural gas in the Colombian market. First, the natural gas producer must publish the available natural gas volumes available for sale. Then, all potential consumers present a supply agreement request. Afterwards, the producer compares the natural gas volume offer with the volumes requested by the potential buyers. If the natural gas demand volumes are higher than the natural gas offer published by the producer, then the producer must perform an auction in order to sell the natural gas that is available. If the natural gas demand volumes are lower than the natural gas offer published by the producer, then the producer is able to directly negotiate the terms of the agreement with each one of the potential buyers that presented the supply agreement request.

The procedure to perform the auction process is completely regulated by the CREG in the aforementioned Resolutions, so that the conditions of the auction are clear to the whole market, establishing equal rules and opportunities for the buyers.

CREG’s Resolution 057 of 1996 establishes the rules for the different activities related to the natural gas market. It defines transportation as an independent activity. Therefore, transporters of natural gas are not allowed to (i) perform production, commercialization or distribution activities or (ii) participate in companies, the main purpose of which is to perform one of these activities. Transporters also cannot have an economic interest in electricity generating companies.

CREG Resolution 093 of 2006, as modified by CREG Resolution 095 of 2008, establishes that partners to a natural gas field are not allowed to jointly commercialize their product without the prior authorization of the CREG, except for commercialization in the form of auctions by the seller.

The CREG also regulates certain aspects of the agreements that can be used for the marketing, production, distribution and transportation of natural gas. CREG’s Resolutions 118 of 2011, 140 of 2011 and 167 of 2011, as amended, provide four 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 availability of 100% of the agreed amount. If the buyer does not consume the agreed natural gas volume, the buyer still must pay the producer the agreed price.

· Optional Purchase Agreements. The buyer agrees to pay a premium for its right to take a fixed amount of natural gas if certain previously agreed conditions are met, and then the buyer agrees to pay an exercise price for the amount of natural gas effectively delivered. The producer guarantees to maintain available 100% of the natural gas agreed volume.

· Interruptible Supply Agreements. The parties determine on a daily basis if the quantity of natural gas specified in the agreement is requested and will be supplied.

· Conditional Firm Supply Agreements. The seller must supply every day unless the agreed natural gas volumes certain previous agreed conditions take place. Then, the producer is able to interrupt the natural gas supply. While the producer supplies natural gas, the buyer must pay a fixed price.

The exportation of natural gas is not considered a public utility activity under Colombian law and therefore is not subject to Law 142 of 1994. Nevertheless, the internal supply of natural gas is a priority for the Colombian government. This policy is included in Decree 2100 of 2011, providing that in the event the supply of natural gas is reduced or halted as a result of a shortage of this hydrocarbon, the Colombian government has the right to suspend the supply of natural gas to foreign customers. Notwithstanding the foregoing, the Decree 2100 of 2011, establishes freedom to export natural gas, under normal conditions for gas reserves.

Regulation of selling, distributing, transporting and marketing of liquefied petroleum gas (LPG)

Wholesale marketing, transport, distribution and retail marketing of LPG are mainly regulated by Resolution CREG 74 of 1996, and subsequent resolutions.  LPG in Colombia is primarily obtained from our refineries, field production, and our own imports.  The LPG must meet minimum quality standards to be marketed.  Our wholesale marketing and transport activities are regulated by Resolutions 53 of 2011 and 92 of 2009. LPG price is regulated by Resolutions CREG 66 of 2007 and CREG 59 of 2008.

Regulation of sales of liquid fuels

According to section 212 of the Petroleum Code and Law 39 of 1987, distribution of liquid fuels and their derivatives is considered a public utility activity. Consequently, individuals or entities that engage in these activities are subject to regulations issued by the government in the interest of Colombian citizens. The government has the power to determine quality standards, measurement and control of liquid fuels, and establish penalties that may apply to dealers who do not observe such rules.

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The Ministry of Mines and Energy is the entity that controls and exercises technical supervision over the distribution of liquid fuels derived from petroleum, including the refining, importing, storage, transport and distribution in the country. Law 812 of 2003 identified the agents of the supply chain of petroleum-derived liquid fuels.

The distribution of liquid fuels, except LPG, is regulated by Decree 4299 of 2005, as modified by Decrees 1333 and 1717 of 2007 and 2008, respectively, which establish the requirements, obligations and penalties applicable to supply agents in the distribution, refining, import, storage, wholesale, transport, retail sale and consumption of liquid fuels.

Decrees 283 and 1521 of 1990 and 1998, respectively, each with its respective modifications, establish minimum technical requirements for the construction of storage plants and service stations. The Decrees also 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 of Mines and Energy also regulates the types of liquid fuels that can be sold and purchased and the penalties for noncompliance with governmental regulations.

As of May 2012, the CREG will determine the prices for regulated crude oil by-products, except for gasoline, diesel and biofuels, which will be determined by the Ministry of Mines and Energy. The ANH will determine the price for crude oil corresponding to royalty payments. Jet fuel price will be determined according to Law 1450 of 2011

The price of gasoline and diesel fuel is determined by (i) producer´s income, (ii) tariffs for pipeline transport, for fuel marking and for the continuity plan, (iii) wholesale and retail distribution margins, and (iv) taxes. The gasoline producer income is calculated according to the methodology established in Resolution number 181602 of September 2011 of the Mines and Energy Ministry. For diesel, the producer income is calculated by the methodology presented in Resolution 82439 of December 2008 of the Ministry of Mines and Energy. The methodology establishes that producer income corresponds to the opportunity cost or export parity price of products that for our case corresponds to the market of the U.S. Gulf Coast.

The distribution of fuels in areas near Colombian borders is subject to specific regulations that impose stringent control procedures and requirements. Currently, Ecopetrol is no longer responsible for fuel distribution in these areas. That responsibility was transferred to the Ministry of Mines and Energy, pursuant to Law 1430 of 2010.

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 and biodiesel with diesel.

Environmental Matters

Regulation

The Ministry of Environment and Sustainable Development is the highest environmental authority in Colombia and is in charge of issuing nationwide environmental regulations, policies, and programs. At the regional local 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 within their area of jurisdiction, the environment and renewable natural resources, as well as of overseeing all work for sustainable development.

Law 99 of 1993 and other environmental regulations impose on companies in general, including oil and gas companies, the obligation to obtain an environmental license prior to undertaking any activity that could negatively impact the environment, or produce serious damage to the environment and natural renewable resources. The Ministry of Environment is responsible for overseeing all hydrocarbons projects and monitoring compliance.

The licensing process begins when the crude oil company filing an environmental plan study with the Ministry of Environment, which includes, among others, an environmental impact assessment, and mechanisms that establish a plan to prevent, mitigate, correct and compensate for any activity that may harm the environment. According to the recently issued regulations, obtaining a license may take between 165 and 265 business days depending on whether the Ministry of Environment requires the applicant to file additional information or if it is necessary to establish a government committee to decide on the viability of the project.

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In order to comply with citizen participation mechanisms established by the Constitution and law, the communities are allowed to obtain information regarding the activities of the project and the impacts it will have. Also the Company must have prior consultation with indigenous and afrocolombian people and environmental public hearings.

The use of natural renewable resources is also regulated. Companies that use large amounts of water for consumption, that discharge industrial wastewater into the coastlines or rivers, that exploit forests reserves resources or that produce atmospheric emissions of gases, must obtain a permit that is either included within the environmental licenses or that is granted by the regional environmental authorities. Similarly, it is required by law that in specific conditions a user of natural resources make environmental investments, such as those provided by Decree 1900 of 2006, which requires any company that plans to use natural water resources and that requires an environmental license for the use of such resources, must assign 1% of its investment to the recovery, conservation, preservation and supervision of the water resources used.

The Ministry of Environment and Sustainable Development is also responsible for establishing guidelines regarding climate change policies for the hydrocarbon sector in Colombia. We are in compliance with those guidelines. To date, the Ministry of Environment has not proposed any specific steps for the implementation of the Kyoto Accords as regards our operations. We are continuously monitoring climate change requirements that could be applicable to us.

A company that does not comply with applicable environmental law and regulations, does not follow the environmental plan filed with the Ministry of Environment or that ignores the requirements imposed by an environmental license may be subject to an administrative proceeding initiated by the Ministry of Environment or the regional environmental authorities established by Law 1333 of 2009, which may result in oral or written warnings, monetary penalties fines, license revocation or even temporary or permanent suspension of the activity being undertaken.

As of April 2012, we were party to 114 environmental administrative proceedings, of which 30 were initiated during 2011 and 7 on 2012. During 2011, 3 proceedings were concluded, for which we were subject to monetary fines. The largest fine imposed in 2011 and as of the first quarter 2012 amounting to Ps$5,125 million (approximately US$2.6 million), against which the company filed an appeal that is pending resolution by the relevant authority. As of March 31, 2012, we were subject to four monetary fines that are not yet finally decided, amounting to Ps$85 million. It is not possible for us to determine the material effect of the pending proceedings.

Environmental Practices

We have implemented exhaustive environmental practices and standards for all of the activities performed by us and our workforce. During 2011, we invested Ps$1,311 million in environmental programs to increase our environmental compliance levels. These investments include investments made through our business partners in the sum of Ps$86,743 million. Such programs include:

· Compliance. The purpose of this program is to guarantee knowledge, assessment, disclosure and compliance with all laws, regulations and requirements imposed by the Ministry of Environment and other regulatory bodies. We undertake environmental impact assessments and constantly review our environmental plan.

· Contingency Planning. This program focuses on implementing preventative actions in our operative areas in order to diminish the impact of oil spills and establish the steps that need to be followed in case of an emergency.

· Eco-Efficiency. This program is designed to minimize the environmental impacts resulting from our (i) use of natural resources through activities such as water uptake and forest exploitation and (ii) waste generation through liquid emissions and the creation of hazardous waste.

· Biodiversity. This program implements initiatives to preserve endangered species in areas where our activities have strong influence. In 2011, we invested Ps$3.9 billion of a total estimate of Ps$8.9 billion to develop 13 projects related to biodiversity.

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

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· Climate Change. We have designed a climate change strategy to orient, plan, define and execute our actions towards mitigating the effects of climate change and our participation in the elaboration of local and international climate change policies. In this context, we have entered into technical cooperation agreements with different parties, such as the U.S. Environmental Protection Agency (EPA) under the Global Methane Initiative, and the Petroleum Technology Alliance of Canada (PTAC) under the energy efficiency program.

· Alternative Energy Sources. This program is designed to develop alternative energy sources, such as biodiesel and ethanol projects. We currently own 91.43% of Bioenergy S.A., a company organized in Colombia, which is expected to produce 115 million liters per year of ethanol. In 2011, Bioenergy S.A. began the construction of its plant, while its sugarcane plantation has been developed and covers 2,400 hectares. The plant is expected to begin operations during the first half of 2013.

We have also been undertaking important efforts to make an efficient and rational use of the energy resources we use in our production processes, reducing consumption, costs and CO₂ emissions. In line with the update of our Strategic Plan, energy issues have taken special relevance. These include energy use, which encompasses the concept of integral energy solutions focused on efficiency, reliability and optimization, and the concept of energy diversification. In 2011, we implemented internal procedures to ensure efficient energy management in the Company, through the Corporate Guideline for Electrical Safety Practices, monitoring of energy indicators and the inclusion of ISO 50001 as main references.

In line with our initiatives to diversify the energy resources we use, we began two studies during 2011 on the use of water, solar and eolic resources. We expect to have the results of such studies in 2012 and to implement them in 2013. The first one, regarding Small Hydraulic Plants (PCH – Pequeñas Centrales Hidráulicas) attempts to identify water resources with enough generation potential to supply the demand of our operations in the South Region. The second aims to measure 13 operation areas, to determine which of them have adequate conditions to implement applications of solar and eolic resources that could (i) have a positive impact in emissions reduction, (ii) provide energy solutions to reduce consumption and (iii) have economic feasibility.

As part of our continued effort to diversify the sources for our energy, in 2010, we built our first vertical axis wind generator to supply the Coveñas seaport energy demands (8 kilo Watts) and initiated solar energy generation for our telecommunications equipment in 21 oil fields and 17 regulating valves in various pipelines. Additionally, two self-generation projects began operations in Tibú and Tello Oil Fields, which led to a decrease of 77 boe daily and US$1.6 million in cost savings. Total energy consumption in 2010 was decreased by 715 boepd. In 2011, seven energy optimization projects are expected to be established to reduce consumption of an additional 2,349 boepd.

Finally, two studies were concluded, one of Pipeline Potential Energy in the plants located in Vasconia and Tocancipa, with a generation capacity of 1.5 Megawatts (MW), and the second of Low Enthalpy Geothermal Energy in the Apiay oil field with a projected generation capacity of 250 kW, both in an effort to determine energy usage and minimize energy requirements.

In the case of an oil spill or leak from our operations, we must follow contingency plans in accordance with internal guidelines, and procedures designed in line with our HSE programs in compliance with best practices to prevent oil spill events from happening and to mitigate the environmental impact. In addition, we must comply with Colombian Regulation Decree 321 of 1999 and the National Contingency Plan, which are a set of guidelines that must be followed by oil and gas companies in Colombia to prevent, and react in case of, operational events that could impact the environment. For offshore joint ventures, the operator partner has the responsibility of designing and implementing remediation plans and procedures to deal with operational emergencies in accordance with best practices and local environmental regulations. Despite the fact that in the case of an emergency the operator partner is the one responsible for the remediation plan, Ecopetrol will also activate its own contingency plan and act along with the operator. We acted according to our contingency plans with respect to the oil spills occurring in the Salgar-Cartago and the Caño Limón-Coveñas pipelines. See “Item 4. Information on the Company—Transportation Infrastructure—Incidents at Transportation Facilities.”

Health, Safety and the Environment

We are devoted to improving our health, safety and the environment, or HSE, practices. We have several programs in place to increase our industrial and process safety, minimize the number of accidents of our workforce or our contractors and minimize catastrophic incidents. The frequency of accidents taking place within our premises has declined significantly since 2005, to 1.03 accidents per million of hours worked in 2011 from 5.77 accidents per million of hours worked in 2005. Additionally, since 2009 we are working on “Process Safety Management,” a system aimed at the continuous improvement and minimization of operational incidents, such as fire, explosion, loss of primary containment and multiple fatalities. We also employ Technological Risk Analysis and a System of Command Incidents (SCI) and continue the process of standardization of HSE protocols and procedures, drafting safety manuals, compliance with existing regulations and the study of HSE benchmarks among oil companies. Our HSE programs are comprised of the following six pillars: (i) culture and leadership, (ii) HSE competences in our employees and contractors, (iii) safe design, (iv) safe operation, (v) prevention and response to emergencies and (vi) performance and audits.

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In the area of occupational health, our goal is to ensure a healthy workplace for all of our employees. We have defined four main programs in our organization: epidemiology surveillance, ergonomic risk management, industrial hygiene program and medical emergency response. These programs help to control the risks of our daily operations, identified through a health risk assessment. Our goal is to have healthy workers, in a safe work environment, potentiating the achievements of the Company.

In 2011, we recorded 41 environmental incidents, the same number as in 2010, and 116 were recorded in 2009. Oil spills declined from 5,107 barrels in 2010 to 2,599 barrels in 2011.

Human Rights Initiatives

We have a strong commitment for the protection of human rights in the areas where we operate and use a set of security and human rights principles, or Principios Voluntarios en Seguridad y Derechos Humanos, as basis for a risk analysis of our company and the communities where we operate. We use this set of principles to interact with local communities and strengthen their relationship with local authorities, our third party contractors and us. In particular, under the Colombian Constitution and legal framework, we are required to enter into formal consultations with indigenous communities whenever we are making plans to commence projects or operations in lands under their control.

In addition, as part of our commitment to human rights, in 2009, we approved our Human Rights Policy and joined the United Nations Global Compact. To manage and ensure compliance with the policy and principles of the Global Compact, in 2010, we created the following forums and tools:

· Human Rights Committee;

· Tactical Plan on Human Rights; and

· Compliance Indicator for Corporate Human Rights Program.

In 2011, we implemented a set of initiatives contained in our tactical plan on human rights, around six strategic themes:

· Right of association and collective bargaining;

· Right to equality at work;

· Human rights complaint, reporting and claims system;

· Rights of ethnic groups;

· Children’s rights; and

· Human rights and security.

This tactical plan also includes some cross-cutting issues and activities, which include:

· Ensuring due diligence in human rights in the operation with partners and company mergers.

· Continuing to work to strengthen the issue within our corporate group companies.

· Designing and implementing a plan of human rights communications and awareness for Ecopetrol stakeholders, placing priority on contractors, employees and the community.

In addition, to complement the strategic themes and ensure respect for human rights in the communities close to our operations, our Social Management Unit developed a plan for 2011, which included training of community leaders in human rights, programs for environmental education and the fight against corruption.

Finally, during 2011, we implemented practices to enable us to apply to the World Plenary for Voluntary Principles on Security and Human Rights, in order to be accepted as a participating member.

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Dow Jones Sustainabilty Index (DJSI)

In 2011, Ecopetrol S.A. entered the Dow Jones Sustainability Index-World. This index tracks the financial performance of the leading sustainability-driven companies worldwide and is a reference used by analysts, institutional investors, specialized entities, and asset managers to assess corporate sustainability in order to make investment decisions. The companies included in this index serve as world reference in terms of excellent corporate sustainability.

Insurance

We have a clear and defined corporate policy based on risk financing guidelines that summarizes the company risk transference and retention alternatives and also provides support and guidance for all the insurance-related issues of all of our affiliated and subsidiary companies. All of our reinsurers must have a credit risk rating of at least A- by Standard & Poor´s, or equivalent. We carefully monitor this credit risk rating.

During the second half of 2010, a new insurance program strategy was developed to improve our corporate insurance policies and coverages (onshore and offshore), organizing them into two programs according to our core business operations, insured values, limits and other aspects.

In the text and tables below, we set forth our insurance programs and the companies covered, along with limits and coverage details.

World-Wide Umbrella Program. This insurance program has been developed to provide coverage for downstream (assets and operations) of Ecopetrol S.A. and all of its affiliates and subsidiaries in excess of their local insurance programs and Global Energy Package, when applicable. Coverage includes all physical damage, sabotage and terrorism, general liability, directors and officers, crime and marine cargo.

Limit (eel/agg(1))

Deductible

Policies

Onshore

Offshore

Onshore

Offshore

ECP

ECP

(in million US$)

Downstream

Reficar

Propilco

Upstream

Equion

Hocol

America

Brazil

Peru

Property all risk

2,000

5 - 10

X

X

X

Sabotage and terrorism

600

5

X

X

X

Third Party Liability

500

500

1 - 5

X

X

X

X

X

X

X

X

X

Sabotage and terrorism Bgre

5

0.4

X

X

X

Crime

50

Underlying limit

X

X

X

X

X

X

X

X

X

Directors and Officers

200

X

X

X

Cargo

100

X

X

X

(1) Eel: each and every loss. Agg: Aggregate

Global Energy Package. This program has been developed to provide coverage for upstream and midstream (assets and operations) of Ecopetrol’s interests and all of its upstream affiliate and subsidiary companies, including: all physical damage, sabotage and terrorism, general liability and control of wells.

Limit (eel/agg(1))

Deductible

Policies

Onshore

Offshore

Onshore

Offshore

ECP

ECP

(in million US$)

Downstream

Reficar

Propilco

Upstream

Equion

Hocol

America

Brazil

Third Party Liability

100

0.15

X

X

X

Sabotage and terrorism

30

X

X

X

Control of wells

25

400

0.25 - 0.50

5

X

X

X

X

X

Property All Risk

400

0.25

X

X

X

X

(1) Eel: each and every loss. Agg: Aggregate

Our third-party liability insurance policies cover Ecopetrol S.A. and our subsidiaries and affiliates in excess of local underlying policy limits for claims made against them by third parties.  Our commercial general liability, umbrella liability, and excess liability coverages will pay on behalf of or indemnify amounts for which an insured becomes legally obligated to pay, including damages in respect of bodily injury, property, pollution and product liability.  Coverage of bodily injury and property damage is subject to a coverage territory during the policy period.

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We are not currently acting as operators of any offshore production operation, although we are involved in certain offshore joint ventures in Colombia, the U.S. Gulf Coast and Brazil, and have exploration operations offshore of the Guajira coast, which are operated by Equion. In Colombia, current production operations are carried out by Chevron. There are two platforms that produce liquified petroleum gas. All of our interests are covered by the World Wide Umbrella and Global Energy Package programs.

With respect to offshore operations in the U.S. Gulf Coast, Ecopetrol America Inc. is party to Operating Agreements (“OA”) that include customary conditions and which contain similar terms and provisions to those in the Model Form of Offshore Deepwater Operating Agreement of the American Association of Professional Landmen (AAPL). In general, pursuant to these OAs, the obligations, duties, and liabilities of the contract parties are several, and not joint or collective, for all operations covered by the OAs. Liability for losses, damages, costs, expenses, or claims involving activities or operations under the OA which are not covered by or in excess of the insurance carried for the joint account are borne by each contract party in proportion to its participating interest in the activity or operation out of which that liability arises, except when any damages result from a party’s s gross negligence or willful misconduct, in which case, such party is solely liable for such damages. The operators supervise the handling, conduct, and prosecution of all claims involving activities or operations under the respective OA or affecting the leases or the contract area covered thereunder. Finally, operators must obtain insurance as required by the OA which costs are charged to the joint account and must have HSE practices in place and comply with locally applicable HSE related statutory requirements.

Ecopetrol Oleo e Gas do Brasil Ltd. and Ecopetrol del Perú are parties to Joint Operating Agreements (JOA) based on the Association of International Petroleum Negotiators (AIPN) model.  Liability is generally the same as described for the OA above, with the following variations:  If claims arise from third parties as part of a case not involving an operator’s gross negligence or willful misconduct, and the operator pays such claims, all parties must concur and reimburse such claim amounts. In certain contracts, all environmental damages are distributed according the parties’ participation interest, regardless of whether the damages were caused by an operator’s gross negligence or willful misconduct. In certain cases, non-operators may intervene and directly verify compliance of the operator’s HSE programs. Ecopetrol S.A. use the same liability clauses in the JOA’s for offshore operations in Colombia, when such agreements are not governed by Colombian laws.

Salgar-Cartago and Caño Limon - Coveñas pipeline spill incidents

We have a liability policy covering damages to thirds arising from third party liability for every loss. The events of Dosquebradas (Salgar-Cartago pipeline) and Cucuta (Caño Limón-Coveñas pipeline) were appropriately notified to our insurance company, who appointed the corresponding loss adjusters. As of April 25, 2012, the adjusters are analysing the information provided, in order to determine whether the event is covered or not.

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 “—Overview by Business Segment—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. See “Item 5. Operating and Financial Review and Prospects—Liquidity and Capital Resources—Use of Funds—Capital expenditures” and “Item 4 – Transportation and Logistics.”

ITEM 4A.     Unresolved Staff Comments

None.

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.

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Development of Our Strategic Plan

In 2011, the Board of Directors of Ecopetrol approved the update of the strategic plan of the companies comprising the Ecopetrol Corporate Group for the period 2012-2020. The plan was prepared from the perspective of new business targets, with a focus on sustainable development and a clear market orientation, resulting in profit-linked value goals. According to our 2012-2020 Strategic Plan, the Corporate Group will operate in accordance with long-term profitable growth strategic guidelines. Our main objective under our Strategic Plan is to achieve a daily output of approximately 1 million gross Clean Barrels of oil equivalent per day by 2015 and 1.3 million gross Clean Barrels of oil equivalent per day by 2020. Also, we expect to achieve a ROCE of 17%. During 2011, we increased our net proved developed and undeveloped reserves of crude oil and natural gas by 8.3% compared to 2010 and achieved a reserve replacement ratio of 164%. See “Item 4. Information on the Company—The Company—Strategic Plan.”

Effects of Acquisitions

Our most significant recent acquisitions are listed below, together with the effective date as of which each has been reflected in our financial statements. These acquisitions were funded mainly through cash on hand and cash flow from our operations.

· Offshore International Group Inc. (OIG) (February 2009) – 50% ownership. OIG is incorporated in the United States and its main asset is Savía Perú, which carries out offshore exploration and production activities in Peru and has 8.6 million hectares of exploration and production areas. Savía Perú contributed with a gross production of approximately 6.9 thousand boepd in 2011 and net proved developed reserves of 11.7 million barrels of crude oil and 21.1 billion cubic feet of natural gas.

· Ocensa (March 2009) – 72.65% ownership. In January 2011, as a result of our acquisition of BP Exploration Company Limited, we indirectly acquired 51% of its interest in Ocensa, increasing our share in the company to 72.65%. With this acquisition we increased our participation in a key crude oil transport system in Colombia, which transports approximately 57.5% of total crude oil production that reaches the Coveñas export facilities. Prior to the acquisition of BP Exploration, in March 2009, we entered into an agreement with Enbridge Inc., a Canadian company, pursuant to which we acquired 100% of its stake in Ocensa, thereby increasing our interest in Ocensa from 35.3% to 60%. Ocensa has developed a project to increase its volume capacity from 460 thousand to 560 thousand bpd. During 2011, we used, on average, approximately 76% of the total capacity of this system.

· Reficar (May 2009) – 100% ownership. After increasing our participation in Reficar, we continue developing the expansion and modernization of the Cartagena refinery. We believe this project will allow us to transform heavy crude oil into more valuable products to improve our profitability.

· Hocol and Homcol (May 2009) – 100% ownership. The principal asset is Hocol S.A., which has exploration and production activities in Colombia. This operation contributed to increase our hydrocarbon reserves and production in Colombia. In 2011, Hocol’s proved developed reserves reached 30.8 million barrels of crude oil and a gross production of 30.8 thousand boepd.

· Equion Energía Limited (January 2011) – 51% ownership. BP Exploration Company Limited sold its interests in Colombia, which were acquired by us and Talisman Colombia Holdco Limited in January 2011. The company was later renamed Equion Energía Limited. We hold a 51% interest in Equion, which is reflected in our financial statements from January 2011. During 2011, Equion contributed a production of 8.1 thousand barrels per day of crude oil and 35.8 million cubic feet per day of natural gas and proved developed reserves of 9.3 million barrels of crude oil and 69.6 billion cubic feet of natural gas.

For more information related to our acquisitions, see “Item 4. Information on the Company.”

Factors Affecting our Operating Results

Our operating results are affected mainly by international prices of crude oil and natural gas, sales volumes and product mix. Higher crude oil and natural gas prices have a positive impact on our results of operations in our Exploration and Production segment due to the increase in our revenues from exported volumes. 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 conversion ratios in our refineries which result in producing and selling some 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 segment results 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 are affected by the purchase of crude oil and natural gas that we make from our business partners and the ANH.

We sell crude oil in the international market. In addition, we process crude oil at the Barrancabermeja Refinery and Reficar, and sell refined products in the local and international markets. Currently, production volumes and sale prices of crude oil and refined products are the main drivers of our financial performance, together with marketing, cost reduction and operative performance strategies.

Local sales and prices

We have a number of crude oil and natural gas long-term supply contracts with local customers, including Reficar, gas-fired power plants, local natural gas distribution companies, and PDVSA Gas in Venezuela. Local sale prices are determined in accordance with existing regulations, contractual arrangements and the spot market linked to international benchmarks. In May 2009, we started recording as revenues the refined products sales of Reficar and stopped recording as revenues our sales of crude oil to Reficar.

International sales and prices

We export crude oil and refined products at prices which are set by reference to international benchmarks. However, we export any crude oil and refined products surplus only after we have fulfilled our supply commitments with our refineries and local customers.

Our commercial strategy, which includes market diversification, has led us to the Far East, and countries such as China, India, Singapore, Spain, Italy, Nigeria and Angola. Additionally, we have started to trade some volume out of the Colombian supply chain by purchasing refined products from an international third party and selling such products to another international third party.

During the past three years we have significantly increased our international sales on a “delivered” basis to the Caribbean, Central America and United States markets, giving us more chartering experience and thus affording us more operational flexibility and the ability to increase prices.

Gasoline and diesel price differentials

We charge the domestic prices established by the Government to wholesalers and, at the same time, we accrue the amount of any fuel price differential due pursuant to Law 1151 of 2007 as revenues and record an account receivable from the Government.

During the first and second quarters of 2009, refiners, including us, were not entitled to fuel price differential payments. Instead, refiners, including us, were required to allocate the difference between high domestic prices and low international prices into the Fuels Stabilization Fund (Fondo de Estabilización de Precios de los Combustibles), or FEPC. During the third and fourth quarters of 2009, refiners, including us, were entitled to fuel price differential payments due to high international prices. Thus, the government depleted the FEPC in order to pay refiners, including us, the corresponding fuel price differential payments. The aggregate amount due to us, which includes the opportunity cost recognized to compensate the delay on the payments, as of December 31, 2009 totaled Ps$263.5 billion and was effectively paid in February 2010.

During 2010, refiners were entitled to fuel price differential payments. The payments made by the Ministry of Mines and Energy in 2010 corresponded to the first three quarters of the year. The amount due to us by the Ministry, which includes the opportunity cost recognized to compensate the delay on the payments, as of December 31, 2010, amounting to Ps$163.4 billion, was delayed and paid in the fourth quarter of 2011.

The fuel price differential payment from the Ministry of Mines and Energy corresponding to the first three quarters of 2011 was paid in December 2011. The fuel price differential for the fourth quarter of 2011, equal to Ps$571.7 billion, had not been paid to us by the end of the first quarter of 2012.

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Exploration costs

We account for exploratory drilling using the successful effort 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 and accounted for under operating expenses—studies and projects. Consequently, the number of exploratory wells we declared as dry negatively affects our results. As such, the significant expansion of our drilling program, which we are currently undertaking, will likely result in higher dry well expenses and may lead to material changes or volatility in our operating expenses.

Royalties

We are required by law to pay in kind a percentage of our production (crude oil and natural gas) 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 depending on whether the production is crude oil or natural gas, and on 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 therefore specify that royalties are to be paid in kind.

Commercialization of natural gas from the ANH

Pursuant to Decree 2100 of 2011, we entered into an agreement with the ANH under which we will no longer purchase the natural gas received in kind by the ANH as royalties and instead will commercialize the natural gas of those fields in which the producer does not decide to directly commercialize the royalties. The agreement establishes that we shall sell to third parties on behalf of the ANH the natural gas that belongs to the government between 2012 and 2013. This agreement will start to operate in July 2012 and will reduce the natural gas we purchase from the ANH and sale to third parties by approximately 110 gbtud during 2012.

Purchases of hydrocarbons from the ANH

We continue purchasing all crude oil delivered to the ANH by us and from third parties as well as the natural gas from certain fields not covered by the abovementioned agreement and delivered as royalty payments to the ANH at prices set forth in a crude oil offer letter from the ANH dated May 16, 2011, and a natural gas offer letter from ANH dated June 17, 2009. For crude oil, the purchase price is calculated according to a formula that includes a reference price for crude oil (WTI), a quality adjustment for API gravity and sulfur content, the transportation rates from the wellhead to Coveñas port and a marketing fee. We have an interagency agreement or Convenio with the ANH, whereby we collect 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.

Import of products for transportation and blending

During 2011, we increased the volume of naphtha imported to 12.7 million barrels from 6.4 million barrels in 2010 for blending in order to transport heavy crude oil. In addition, in order to meet local environmental regulations regarding sulfur content in diesel, we imported 13.5 million barrels of ultra low sulfur diesel for blending with our local production. Even though imported diesel volumes were lower because Barrancabermeja’s hydrotreating units began operation, average import prices were higher, in line with international trends. Consequently, our variable costs are affected by available volumes of these products and their prices, affecting our operating results.

Effect of taxes and exchange rate variation on our income

Income tax

We are subject to tax on our income at a statutory rate of 33%, the standard corporate rate in Colombia since 2008.

Exchange rate variation

The appreciation or revaluation of the Peso, particularly against the U.S. dollar, has multiple effects on our financial results. In compliance with Colombian regulations, our results are reported in Pesos, and we maintain our financial records in Pesos. During 2011, 2010 and 2009, the Peso has appreciated (depreciated) on average 2.6%, 12.0%, and (9.7%) respectively against the U.S. dollar.

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Almost all of our exports of crude oil, natural gas and refined products are paid for 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 increase when expressed in Pesos. 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 was the case in 2010 and 2011 based on average exchange rates. Our revenues from exports of crude oil and natural gas were reduced in Pesos as a result of that currency’s appreciation. 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.

In 2009, we incurred U.S. dollar-denominated long-term debt while at the same time began reducing our financial investments denominated in U.S. dollars. By doing so, we were able to balance the exposure between our U.S. dollar assets and liabilities. As a result, the net exchange gain/loss of our investments and liabilities denominated in U.S. dollars was essentially balanced at year-end.

During 2010 and 2011, we did not incur any additional U.S. dollar-denominated debt.

New Accounting Policies

Colombian Government Entity GAAP

There were no significant new accounting standards effective in year 2012 impacting the Company pursuant to Colombian Government Entity GAAP.

U.S. GAAP

In December 2010, the FASB issued ASU No. 2010-29 Business Combination (Topic 805) - Disclosure of Supplementary pro-forma information for Business Combination, to address diversity in practice about the interpretation of the pro-forma revenue and earnings disclosure requirements for business combinations. This accounting standard update was applied in Ecopetrol as of January 1, 2011. The adoption of this guidance did not have a significant impact on our consolidated financial statements and related disclosures.

In September 2011, the FASB issued ASU No. 2011-08 Intangibles - Good will and other (Topic 350) - Testing Goodwill for impairment. The objective of this update is to simplify how entities, both public and nonpublic, test goodwill for impairment. The amendments in the update permit an entity to first assess qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount as a basis for determining whether it is necessary to perform the two-step goodwill impairment test described in Topic 350. The amendment is effective for annual and interim goodwill impairment tests performed for fiscal years beginning after December 15, 2011. Anticipated adoption is permitted. This accounting standard update was applied since January 1, 2011. The adoption of this guidance did not have a significant impact on our consolidated financial statements and related disclosures.

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 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. Internally estimated reserves are then submitted to an external audit process, which is carried out by our External Engineers. Its results are then consolidated and presented for approval to the Reserves Committee. Finally, results are ratified by the Audit Committee of the Board of Directors and presented to the Board of Directors.

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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.

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. Revisions to proved reserves estimates of crude oil and gas and the effect of such price variations are presented in Note 34 to our consolidated financial statements. Changes in the crude oil price may affect our estimates in the future. A decrease in our estimated proved reserves due to pricing may result in the impairment of oil and gas properties.

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.

Financial derivative instruments

We enter into hedging agreements to reduce our exposure to the fluctuations of international crude oil and products prices. Under Colombian Government Entity GAAP, amounts paid and income received under hedging operations is recognized as financial income/expense. We are not permitted to enter into hedging contracts for speculative purposes.

Under Colombian Government Entity GAAP, our estimates are based on current spot prices subject to market variations according to the regulation and methodology established by the Superintendency of Finance.

Pension plans and other benefits

By virtue of Legislative Act 01 of 2005, enacted by Congress, the pension regimes excluded from the General Social Security System in Colombia expired on July 31, 2010. In accordance with provisions therein, it was concluded that those workers that consolidated their right to pension were those workers who complied with the age and continuous or discontinuous service time requirements of the law, the Collective Bargaining Agreement in force and/or Agreement 01 of 1977, prior to August 1, 2010. For other workers who were not covered by the previously described conditions, they must mandatorily be affiliated with the General Pension System. The agency responsible for paying the respective pension will be the pension administrator chosen by the worker (either the Social Security Institute or a private pension fund).

The determination of the expense, liability and adjustments in memorandum accounts relating to our pension and other retirement benefits requires 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. See Note 1 to our consolidated financial statements “Economic Entity and Principal Accounting Policies and Practices”.

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.

In accordance with Resolution 1555 of 2010 and Decree 4565 of the same year applicable in Colombian Government Entity GAAP, due to the change in the mortality rates in 2010, the Company started to amortize the increase in the pension obligation calculated as of December 31, 2011 using a five-year term. See Note 1 to our consolidated financial statements “Economic Entity and Principal Accounting Policies and Practices”.

Actuarial gains and losses, a result of differences between estimates and actual calculations and differences between Colombian Government Entity GAAP and U.S. GAAP are disclosed in Note 34 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. See Note 34 of our consolidated financial statements for an analysis of the sensitivity in assumed health care cost trend rates of a one percentage point change in interest rates.

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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 provisions to meet these costs when it is probable that a liability has been incurred and reasonable estimates of the liability can be made. As of December 31, 2011, we had a provision of Ps$699,270 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 financial statements taken as a whole. Litigation and tax assessment differences between Colombian Government Entity GAAP and U.S. GAAP are disclosed in Note 34 to our consolidated financial statements.

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 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.

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. The related liability is estimated in local currency and does not require adjustment for exchange difference at the end of each year as a greater or lesser value of assets.

Differences between Colombian Government Entity GAAP and U.S. GAAP are disclosed in Note 34 to our consolidated financial statements.

Recognition and measurement of assets recognized and liabilities assumed upon business combinations

Under U.S. GAAP, we account for businesses acquired using the purchase method of accounting which requires that the assets acquired and liabilities assumed be recorded at the date of acquisition at their respective fair values. The application of the purchase method requires certain estimates and assumptions especially concerning the determination of the fair values of the acquired intangible assets, property, plant and equipment as well as the liabilities assumed at the date of the acquisition. In addition, the useful lives of the acquired intangible assets, property, plant and equipment have to be determined. The judgments made in the context of the purchase price allocation can materially impact our future results of operations. Accordingly, for significant acquisitions, we obtain assistance from third-party valuation specialists. The valuations are based on information available at the acquisition date and different methodologies are used for each intangible identified above.

Goodwill

Under U.S. GAAP, we test goodwill for impairment at least annually using a two-step process that begins with an estimation of the fair value of a reporting unit. The first step is a screen for potential impairment and the second step measures the amount of impairment, if any. However, if certain criteria are met, the requirement to test goodwill for impairment annually can be satisfied without a re-measurement of the fair value of a reporting unit. Fair value is determined by reference to market value, if available, or by a qualified evaluator or pricing model. Determination of a fair value by a qualified evaluator or pricing model requires management to make assumptions and use estimates. Management believes that the assumptions and estimates used are reasonable and supportable in the existing market environment and commensurate with the risk profile of the assets valued. However, different assumptions and estimates could be used which would lead to different results. The valuation models used to determine the fair value of these companies are sensitive to changes in the underlying assumptions. For example, the prices and volumes of product sales to be achieved and the prices which will be paid for the purchase of raw materials are assumptions which may vary in the future. Adverse changes in any of these assumptions could lead us to record a goodwill impairment charge. See Notes 13 and 34 to our consolidated financial statements.

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Under Colombian Government Entity GAAP, goodwill corresponds to the difference between the acquisition price and the book value of the acquired company. This amount is amortized during the period in which the Company expects to receive future benefits. Additionally, under Colombian Government Entity GAAP, goodwill is not subject to impairment tests.

Operating Results

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 significant respects from U.S. GAAP. See Note 34 to our consolidated financial statements for a description of the principal differences.

Results of operations for the year ended December 31, 2011, compared to the year ended December 31, 2010, and compared to the year ended December 31, 2009.

The following table sets forth components of our income statement for the years ended December 31, 2011, 2010, and 2009.

	For the Year ended December 31,						2011/2010			For the Year ended			2010/2009
	2011			2010			%change			December 31, 2009			% change
	(Pesos in millions)									(Pesos in millions)
Revenues:
Total Revenue		65,752,268			41,968,311			57	%		30,404,390			38	%
Cost of Sales		36,665,056			25,959,001			41	%		19,906,073			30	%
Gross Profit		29,087,212			16,009,310			82	%		10,498,317			52	%
Operating Expenses:		3,396,249			3,130,468			8	%		2,624,978			19	%
Operating Income		25,690,963			12,878,842			99	%		7,873,339			64	%
Non-operating income
(expenses):		(2,049,531	)		(1,386,225	)		48	%		(622,495	)		123	%
Income before income tax		23,641,432			11,492,617			106	%		7,250,844			59	%
Income tax:		7,955,721			3,238,650			146	%		2,114,029			53	%
Non-controlling interest:		(233,377	)		(107,496	)		117	%		(4,761	)		n.m.
Net Income		15,452,334			8,146,471			90	%		5,132,054			59	%

n.m.= Not meaningful

Total Revenues

Methodology

We use the following criteria to analyze our financial information by business segment: (i) third party sales are made at market prices by each segment according to their ownership of the products or services sold; (ii) each segment bears costs and expenses incurred for production and marketing of its products, the corresponding administrative expenses and those expenses related to non-operational transactions related to its activity; (iii) transactions between segments are accounted for as if each segment was a separate entity and prices between segments are determined by reference to those that could be obtained in transactions with third parties.

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All of our financial information is distributed among these four business segments:

· Exploration and Production – includes our crude oil and natural gas exploration and production activities.  Revenue is derived from inter-company and inter-segment sales, exports and third party sales. Revenues, costs and expenses for this segment include those costs incurred by us from the production field to the end customer.  Expenses include all exploration costs that are not capitalized.

· Refining and Petrochemicals – includes our refining activities.  Revenue is derived from inter-company and inter-segment sales, exports and third party sales and corresponds to products processed in our refineries and our downstream subsidiaries such as motor fuels, fuel oils and petrochemicals at market prices. This segment also includes other services sold to third parties.

· Transportation – includes our sales and costs associated with our pipelines and other transport activities.

· Marketing and Supply – includes our revenues, costs and expenses associated with marketing and sale of products purchased from third parties and the ANH.

Results

The following table sets forth our principal sources of revenue by business segment for the years ended December 31, 2011, 2010 and 2009.

	For the Year ended December 31,						2011/2010			For the Year ended December 31,			2010/2009
	2011			2010			% change			2009			% change
	(Pesos in millions)									(Pesos in millions)
Exploration and Production segment:
Crude oil:
Local sales		245,345			123,797			98.2	%		1,943,410			(93.6	)%
Export sales		24,039,881			13,515,877			77.9	%		6,613,961			104.4	%
Total sales of crude oil		24,285,226			13,639,674			78.0	%		8,557,371			59.4	%
Natural gas:
Local sales		882,847			854,427			3.3	%		691,930			23.5	%
Other income from local sales of natural gas		210,232			142,018			48.0	%		155,469			(8.7	)%
Export sales		381,000			101,363			275.9	%		214,091			(52.7	)%
Total sales of natural gas		1,474,079			1,097,808			34.3	%		1,061,490			3.4	%
Other income from Exploration and Production segment(1)		197,717			193,991			1.9	%		85,401			127.2	%
Total Exploration and production segment sales		25,957,022			14,931,473			73.8	%		9,704,262			53.9	%
Exploration and Production segment eliminations in consolidation		(4,068,104	)		(2,859,175	)		42.3	%		(1,957,156	)		46	%
Total Exploration and Production segment sales to third parties		21,888,918			12,072,298			81.3	%		7,747,106			55.8	%
Refining and Petrochemicals segment:
Refined products:
Local sales(2)		19,177,714			14,360,357			33.5	%		11,910,770			20.6	%
Sales of refined products allocated to our Exploration and Production segment(3)		(121,249	)		(226,701	)		(46.5	)%		(154,816	)		46.4	%
Other income from local sales of refined products(4)		6,332			32,546			(80.5	)%		82,616			(60.6	)%
Export sales		8,403,561			5,641,545			49.0	%		4,196,143			34.4	%
Total Refining and Petrochemicals segment sales:		27,466,358			19,807,747			38.7	%		16,034,713			23.5	%
Refining and Petrochemicals segment eliminations in consolidation		(119,393	)		(22,337	)		434.5	%		-			n.m.

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	For the Year ended December 31,						2011/2010			For the Year ended December 31,			2010/2009
	2011			2010			% change			2009			% change
	(Pesos in millions)									(Pesos in millions)
Total Refining and Petrochemicals segments sales to third parties		27,346,965			19,785,410			38.2	%		16,034,713			23.4	%
Marketing and Supply segment:
Crude oil sales:
Local sales		-			-			-			1,692,832			(100	)%
Export sales		14,790,487			8,108,425			82.4	%		5,201,551			55.9	%
Total crude oil sales		14,790,487			8,108,425			82.4	%		6,894,383			17.6	%
Natural gas sales:
Local sales		332,851			378,939			(12.2	)%		336,366			12.6	%
Other income from local sales of natural gas		1,590			2,536			(37.3	)%		24,473			(89.6	)%
Export sales		173,540			44,700			288.2	%		97,643			(54.2	)%
Total natural gas sales		507,981			426,175			19.2	%		458,482			(7.1	)%
Refined products sales:
Local sales		714,874			522,145			36.9	%		15,978			n.m.
Export sales		179,389			10,246			n.m.			10,900			(6.0	)%.
Other income from local sales		67,284			51,956			29.5	%		13,811			n.m.
Total Marketing and Supply segment sales		16,260,015			9,118,947			78.3	%		7,393,554			23.3	%
Marketing and Supply segment eliminations in consolidation		(1,413,845	)		(772,502	)		83.0	%		(1,688,671	)		(54.3	)%
Total Marketing and Supply segment sales to third parties		14,846,170			8,346,445			77.9	%		5,704,883			46.3	%
Transportation and logistics segment:
Transportation sales		1,313,066			1,465,973			(10.4	)%		888,783			64.9	%
Other income transportation services		412,010			353,869			16.4	%		76,247			364.1	%
Total transportation sales		1,725,076			1,819,842			(5.2	)%		965,030			88.6	%
Transportation segment eliminations in consolidation		(54,861	)		(55,684	)		(1.5	)%		(47,341	)		17.6	%
Total Transportation segment sales to third parties		1,670,215			1,764,158			(5.3	)%		917,689			92.2	%
Total sales		65,752,268			41,968,311			56.7	%		30,404,390			38.0	%

n.m.=Not meaningful.

(1) Corresponds to sales of refined products, transportation services and other services allocated to our Exploration and Production segment.

(2) Includes motor fuel price differential reimbursements by the Government amounting to, Ps$196,533 million in 2009, Ps$740,682 million in 2010 and Ps$2,251,322 million in 2011.

(3) Corresponds to sales of refined products from our Apiay and Orito refineries allocated to our Exploration and Production segment.

(4) Corresponds to sales of transportation services and other services allocated to our refining and petrochemicals segment.

In 2011, total revenues increased by 56.7% as compared to 2010, mainly due to higher average prices of crude oil and refined products and an increase in total volumes produced and sold. The 38% increase in total revenues in 2010 compared to 2009 was mainly due to a higher average price of crude oil and an increase in total volumes produced and sold.

The following table sets forth our total export and local sales of crude oil, natural gas and refined products for the years ended December 31, 2011, 2010 and 2009.

								For the Year
								ended
	For the Year ended December 31,				2011/2010			December 31,		2010/2009
	2011		2010		% change			2009		% change
Crude oil:
Local sales (barrels)(1)		1,783,807		1,086,090		64.2	%		455,895		138.2	%
Export sales (barrels) (2)		181,504,337		131,316,387		38.2	%		92,921,245		41.3	%
Average price per local barrel (in U.S. dollars) (3)		69.90		56.85		23.0	%		67.77		(16.1	)%
Average price per export barrel (in U.S. dollars) (4)		99.58		72.55		37.3	%		60.83		19.3	%
Weighted average price per local and export barrel (in U.S. dollars)		99.30		72.42		37.1	%		60.86		19.0	%
Natural gas:
Local sales (mbtu)		153,293,739		188,681,680		(18.8	)%		167,095,380		12.9	%
Export sales (mbtu)(5)		55,013,647		19,701,959		179.2	%		43,568,928		(54.8	)%
Average local price (mbtu) (in U.S. dollars) (3)		4.28		3.24		32.1	%		2.72		18.9	%
Average export price (mbtu) (in U.S. dollars) (4)		4.97		3.93		26.5	%		3.27		19.9	%

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								For the Year
								ended
	For the Year ended December 31,				2011/2010			December 31,		2010/2009
	2011		2010		% change			2009		% change
Refined products:
Product local sales (barrels)		90,900,442		87,271,761		4.2	%		86,211,706		1.2	%
Export sales (barrels)		40,775,850		37,746,666		8.0	%		34,368,558		9.8	%
Average local price per barrel (U.S. dollars) (3)		105.21		84.42		24.6	%		67.18		25.7	%
Average export price per barrel (U.S. dollars) (4)		112.37		78.90		42.4	%		69.25		13.9	%

(1) Starting in May 2009, no longer includes sales to Reficar.

(2) Since 2010, the free trade zone sales are considering exports for local purposes. Includes sales of Hocol and Equion since May 2009 and January 2011 respectively.

(3) Corresponds to average price per local barrel translated at an average exchange rate of 1,848.17 for 2011, 1,897.89 for 2010 and 2,156.29 for 2009.

(4) Corresponds to the average of the actual prices at which we sold our products in the international markets.

(5) We initiated exports of natural gas to Venezuela in the third quarter of 2007. However, during the period of February to September 2010, we suspended the exports because Venezuela failed the payments due to politic conflicts between Colombia and Venezuela.

Exploration and Production segment sales

Crude oil

Local sales

Our revenues from local sales of crude oil increased by 98.2% in 2011 as compared to 2010, mainly due to an increase in the average price per barrel and a 64.2% increase in the volume sold primarily due to higher demand from shipping companies and local industries for energy generation purposes. Revenues from local sales of crude oil decreased by 93.6% in 2010 as compared to 2009 because in January 2010 Reficar was declared a special free trade zone, and since then crude oil sold to Reficar is accounted for in export sales.

Export sales

Our revenues from exports of crude oil increased by 77.9% in 2011 as compared to 2010, mainly due to a 37.3% increase in the average export price per barrel, and a 38.2% increase in the volume of export sales. Increased export sales resulted from improvements in our transportation capacity and higher production of Castilla and Magdalena blends, which started being exported during the third quarter 2011. These developments were partially offset by a 2.6% appreciation of the Peso against the U.S. dollar.

In 2010, our revenues from exports of crude oil increased by 104.4% as compared to 2009, mainly due to a 41.3% increase in the volume of crude oil exported, primarily Castilla and South blends, to new markets, such as China and India, and a 19.3% increase in our average crude oil export prices, partially offset by an appreciation of approximately 12% in the average exchange rate of the Peso against the U.S. dollar.  

Natural gas

Local sales

Our local sales of natural gas increased by 3.3% in 2011 as compared to 2010, mainly due to a 32.2% increase in the average local price per mbtu, almost entirely offset by an 18.8% decrease in volumes sold. The decrease in volumes sold was explained by a higher allocation of natural gas for export sales due to the elimination of local regulatory restrictions during 2010 that forced us to guarantee availability of natural gas to supply local gas-fired power plants.

In 2010, our local sales of natural gas increased by 23.5% as compared to 2009, mainly due to a 12.9% increase in volumes of natural gas sold and an 18.9% increase in the average sale price, both of which resulted from increased electricity demand during the occurrence of the El Niño phenomenon in the first half of 2010.  

Export sales

In 2011, export sales of natural gas increased by 275.9% as compared to 2010, principally due to a 179.2% increase in the volume of export sales as a result of higher volumes of natural gas available for export sales, an increase in the natural gas demand from Venezuela, and a 26.5% increase in our average export prices, partially offset by the appreciation in the average exchange rate of the Peso against the U.S. dollar.

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Export sales of natural gas decreased by 52.7% in 2010 as compared to 2009, mainly due to a 54.8% decrease in the exported volumes resulting from the restrictions on exports imposed by the Government to meet increasing national demand during the occurrence of the El Niño phenomenon in the first half of 2010, partially offset by higher average export price, which increased by 19.9%. 

Total Exploration and Production segment sales to third parties

In 2011, our total Exploration and Production segment sales to third parties increased by 81.3% as compared to 2010, as a result of an increase in volumes produced, higher prices for our export crude oil basket and higher selling spreads for our crude oil due to the indexation to the Brent benchmark price, which increased more than the WTI benchmark price.

Total Exploration and Production segment sales to third parties increased by 55.8% in 2010 as compared to 2009, as a result of an increase in volumes produced and the implementation of best practices and methods by our international trading desk to increase our export sales to new markets.  

Refining and Petrochemicals segment sales

Local sales

In 2011, local sales of refined products and petrochemicals increased by 33.5% as compared to 2010, as a result of a 24.6% increase in average local prices and a 4.2% increase in volumes sold due to higher demand for gasoline and mid distillates from automotive, aviation and mining sectors resulting from the country´s ecomomic growth.

Local sales of petrochemicals and refined products increased 20.6% in 2010 as compared to 2009 as a result of higher average sales prices, which increased 25.7% as a result of the higher import volumes of products for blending to meet local environmental regulations for sulfur content, an increase of vehicles using diesel, and the severe rain season in the second half of 2010 that restricted ethanol supply, which consequently increased local gasoline sales.  

Export sales

In 2011, export sales of refined products and petrochemicals increased by 49.0% as compared to 2010 due to a 42.4% increase in average export prices, and an 8.0% increase in the volume caused by an increase in fuel oil production at our Barrancabermeja refinery and an increase in the river transportation availability from Barrancabermeja to the Cartagena port.

Export sales of petrochemicals and refined products increased 34.4% in 2010 as compared to 2009 mainly as a result of an increase of 13.9% in the average export price and an increase of 9.8% in our exported volumes mainly due to an increase in our high sulfur diesel export sales from Reficar. 

Total refining and petrochemicals segment sales to third parties

In 2011, total refining and petrochemicals segment sales to third parties increased by 38.2% as compared to 2010 mainly as a result of an increase in selling prices and in the volumes sold.

Total refining and petrochemicals segment sales to third parties increased 23.4% in 2010 as compared to 2009 as a result of an increase in the average sales prices of refined products and a 9.8% increase in our volumes exported.

Marketing and Supply segment sales

Crude Oil

Local sales

Since January 2010, crude oil sold to Reficar is accounted for as export sales since it corresponds to special free trade zone sales.  For this reason, revenues from crude oil local sales decreased 100% in local sales allocated to our Marketing and Supply segment during 2010 compared to 2009 and we had no other local sales of crude oil in 2011 allocated to the Marketing and Supply segment.

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Export Sales

In 2011, export sales of crude oil from our Marketing and Supply segment increased by 82.4% due to higher volume available coming from purchases to third parties and the ANH as a result of an increase in other producers´ production and in our average export prices, partially offset by the appreciation in the average exchange rate of the Peso against the U.S. dollar.

Exports of crude oil allocated to our Marketing and Supply segment increased by 55.9% in 2010 as compared to 2009 as a result of a 19.3% increase in the average export price of crude oil and an increase in our exported volumes to Reficar performed by this segment. 

Natural Gas

Local Sales

In 2011, local sales of natural gas from our Marketing and Supply segment decreased by 12.2% as compared to 2010, mainly as a result of lower local demand and an increase in the volume of export sales, partially offset by a 32.2% increase in the average local prices.

Revenues from local sales of natural gas from our Marketing and Supply segment increased by 12.6% in 2010 as compared to 2009, mainly as a result of an increase in the volumes sold and the higher average sales price of natural gas.

Marketing and Supply segment sales to third parties

During 2011, our Marketing and Supply segment sales to third parties increased by 77.9% as compared to 2010, mainly due to an increase in the volume of export sales of crude oil and natural gas and higher average selling prices.

Our total Marketing and Supply segment sales to third parties increased by 46.3% in 2010 compared to 2009, mainly as a result of higher volumes of refined products allocated to this segment, partially offset by a decrease in sales of crude oil by elimination in consolidation of sales to Reficar.

Transportation and logistics segment sales

In 2011, our transportation and logistics segment sales decreased by 5.2% as compared to 2010 mainly because Ocensa received in 2010 an additional premium from Pacific Rubiales Energy Corp. to increase its transportation capacity during that year, which was a one-time transaction that no longer had effect in 2011. This decrease was partially offset by an increase in total transported volumes.

Total transportation sales increased by 88.6% in 2010 as compared to 2009, mainly due to higher volumes of crude oil and refined products transported resulting from (i) the consolidation of the results of operations of Ocensa and ODC, (ii) the commencement of operations of the second phase of ODL, and (iii) the expansion of our transportation infrastructure.

Transportation and logistics segment sales to third parties

As a result of the above mentioned increase in volumes and after giving effect to eliminations in consolidation of the transportation services provided by us to our subsidiaries, our transportation and logistics segment sales to third parties decreased by 5.3% in 2011 compared to 2010, and increased by 92.2% in 2010 compared to 2009.

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, 2011, 2010 and 2009.

	For the Year ended December 31,				2011/2010			For the Year ended December 31,		2010/2009
	2011		2010		%change			2009		%change
	(Pesos in millions)							(Pesos in millions)
Cost of sales		36,665,056		25,959,001		41	%		19,906,073		30	%
Operating expenses		3,396,249		3,130,468		8	%		2,624,978		19	%
Operating Income		25,690,963		12,878,842		99	%		7,873,339		64	%

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Cost of sales—consolidated

Our costs of sales have been affected by a number of factors, including the increase in international prices for crude oil. The most important factors are described below:

· Purchases of hydrocarbons from the ANH in 2011 increased 51% to Ps$8,048,981 million compared to 2010, mainly as a result of higher average prices and an increase in the volumes purchased.  These reasons also explain the 22% increase to Ps$5,335,946 million in 2010 as compared to 2009.

· Purchases of imported products in 2011 increased 56% to Ps$8,840,450 million compared to 2010 as a result of higher volumes of naphta purchased for blending with increasing heavy crude oil production in order to transport it, as well as of products (mainly low sulfur diesel) for blending to meet local environmental regulations regarding sulfur content, and higher average prices.  Purchases of imported products in 2010 increased to Ps$5,680,601 million compared to 2009 mainly as a result of higher volumes and average prices.

· Purchases of crude oil from our business partners in 2011 increased 47% to Ps$6,701,500 million compared to 2010 mainly due to higher average crude oil prices of purchased crude oil production from our business partners.  Purchases of crude oil from our business partners in 2010 increased 10% to Ps$4,548,193 million as compared to 2009 mainly due to higher prices and volumes purchased as crude oil production from our business partners increased.

· Services contracted with associations, which are pro rata expenses for our joint ventures, increased 22% in 2011 to Ps$1,791,681 million compared to 2010, mainly as a result of an increase in production activities and High-Price Clauses. Services contracted with associations in 2010 increased 14% to Ps$1,469,586 million compared to 2009 due to an increase in production activities.

· Maintenance costs increased 26% to Ps$1,593,327 million compared to 2010, mainly due to an increase in our operating activities and maintenance plan. Maintenance costs did not have a significant variation in 2010 as compared to 2009.

· Labor costs in 2011 increased 12% to Ps$1,219,219 million compared to 2010 as a result of an 8% increase in our total number of employees due to an increase in our operations and projects.  Labor costs increased 18% in 2010 as compared to 2009 as a result of an adjustment in wages which was implemented among all of our employees and of a 1% increase in our total number of employees in response to the increase in the exploration and production activities.

· Depreciation costs increased 21% to Ps$1,935,028 million in 2011 compared to 2010, mainly due to the new investments and transport systems.  Depreciation costs increased by 24% to Ps$1,604,270 million in 2010 as compared to 2009, as a result of the capitalization of investments in the Barrancabermeja hydrotreatment plant during 2010.

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

Exploration and Production segment’s cost of sales

Cost of sales affecting our Exploration and Production segment are mainly related to the amortization and depletion of our production assets, services contracted with outside vendors, maintenance costs, project expenses and labor costs related to this segment.

In 2011, cost of sales for this segment increased by 44.6%, mainly due to a 32.3% increase in our heavy crude oil production which required increased purchases of imported naphtha to dilute and transport crude oil, and an increase in costs for services contracted (subject to High-Price Clauses) with certain business associations, such as Cravo Norte and La Cira, due to higher production and participation levels.

In 2010, cost of sales for this segment increased by 27.3%, mainly due to the increase of 43.2% in heavy crude oil production, which required increased purchases of imported naphtha to dilute and transport heavy crude oil and costs for services contracted in business associations with respect to an increase in our participation in some of our association contracts, such as the Teca-Nare contract.

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Refined products and petrochemicals segment’s cost of sales

Cost of sales affecting our refined products and petrochemicals segment results primarily from the purchase of crude oil and natural gas to upload and feed our refineries, imported products for the refining process, feed stock transportation services, services contracted for refinery maintenance, and amortization and depreciation of refining assets.

In 2011, cost of sales for this segment increased by 23.7% as compared to 2010, principally due to higher prices for the crude oil purchased from our Exploration and Production segment, third parties and the ANH.

Cost of sales for this segment increased by 35.1% during 2010, mainly due to (i) an increase in the prices of crude oil purchased from third parties, the ANH and from our Exploration and Production segment and (ii) an increase in the volumes imported of diesel extra (low sulfur diesel) used to comply with sulfur content requirements for fuels, until we completed the Fuels Hydrotreatment Plant at Barrancabermeja.

Marketing and Supply segment’s cost of sales

Cost of sales affecting our Marketing and Supply segment are mainly related to the costs associated with purchases of crude oil and natural gas volumes from the ANH and from our business partners. Cost of sales for our Marketing and Supply segment increased by 80.4% in 2011 and 10.6% in 2010, on a yearly basis, due to the increase in volumes and prices of the crude oil and natural gas purchased from the ANH and third parties.

Transportation and logistics segment’s cost of sales

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

Cost of sales for this segment increased by 45.1% in 2011 as compared to 2010 due to an increase in volumes transported through pipelines and tanker trucks and an increase in maintenance costs as a result of the heavy rain season which forced us to increase pipeline maintenance activities.

In 2010, cost of sales of transportation activities increased by 14.8% mainly due to greater volumes of crude oil and refined products transported, as a result of increased production of crude oil in the country.

Operating expenses

In 2011, our operating expenses increased by 8% when compared to 2010 and by 19% in 2010 when compared to 2009, mainly as a result of the following factors:

Amortizations increased 56% in 2011 when compared to 2010 mainly as a result of goodwill amortizations.

Labor expenses which increased 104% as a result of the increased activities and projects.

Each segment bears the costs and expenses incurred for product use or marketing and each segment assumes administrative expenses and all non-operational transactions related to their activity. Operating expenses by business segment are described below.

Exploration and Production segment’s operating expenses

Operating expenses affecting our Exploration and Production segment are primarily for studies and projects, which correspond to expensing dry wells, the amortization of the goodwill from our acquisitions assigned to this segment and administrative expenses assigned to this segment. These expenses decreased by 5% in 2011 and increased 19% in 2010, in each case as compared to the prior year.

Refining and petrochemicals segment’s operating expenses

Operating expenses affecting our refining and petrochemicals segment result primarily from the amortization of goodwill from acquisitions, projects and administrative expenses assigned to this segment. In 2011 and 2010, expenses related to this segment increased by 26% and 8%, respectively, mainly due to non-capitalized projects expenses.

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Marketing and Supply segment’s operating expenses

Operating expenses affecting our Marketing and Supply segment result primarily from relatively low administrative expenses related to the commercialization of crude oil and natural gas assigned to this segment.

Transportation and logistics segment’s operating expenses

Operating expenses affecting our transportation and logistics segment result primarily from the amortization of the goodwill from acquisitions assigned to this segment and tariffs paid in connection with crude oil transportation. In 2011 and 2010, operating expenses assigned to this segment increased by 95% and 10%, respectively, mainly due to projects expenses related to our transportation and logistics increased activity.

Non-operating income (expenses)

The following table sets forth our non-operating income (expenses) for the years ended December 31, 2011, 2010 and 2009.

	At December 31,						2011/2010			At December 31,			2010/2009
	2011			2010			%change			2009			%change
	(Pesos in millions)									(Pesos in millions)
Non-operating income (expenses):
Financial income, net		(904,302	)		37,789			n.m.			495,833			(92.4	)%
Pension expenses		(706,298	)		(377,626	)		87.0	%		(595,157	)		(36.6	)%
Inflation gain		21,836			22,030			(0.9	)%		22,355			(1.5	)%
Other income (expenses), net		(460,767	)		(1,068,418	)		(56.9	)%		(545,526	)		95.9	%

n.m.=Not meaningful.

Financial income, net. Financial income, net mainly includes exchange difference gains or losses, results from our hedging operations, interest expenses, yields and interests from our investments. During 2011 our results reflected a net financial expense due to the results in our commodity hedging financial side (put options on WTI Nymex and swaps calculated using the Maya-WTI spread), affected by the situations of the spreads between Maya heavy crude oil and WTI light crude oil benchmark prices, which resulted in higher prices for the heavy crude oil compared to those of the light crude oil.  In addition, financial income net decreased by 92.4% in 2010 compared to 2009 due to a decrease in the interests on price differential of fuels amounts not timely paid by the government in 2009, the reduction in the net results of our hedging operations, a reduction in the valuation of our investment portfolio and the decrease in the net exchange difference as a result of the appreciation of the Colombian peso against the U.S. dollar.

Pension expenses. Pension expenses grew by 87% in 2011 when compared to 2010 principally as a result of (i) the actuarial calculation updating the health reserve which increased mainly due to a rise of approximately 21% in the average health services cost per beneficiary and an increase of approximately 15% in the population covered (retirees and their beneficiaries), and (ii) an increase in health care services resulting from an increase of approximately 20% in medicine supplies and services due to the increase in the average age of the retirees and their beneficiaries. Pension expenses decreased by 36.5% in 2010 from 2009 largely as a result of a change in the actuarial calculation under new mortality tables and our adoption of a 5-year term as of 2010 to amortize the increases resulting from the new calculations. See Note 1 to our consolidated financial statements “Principal Accounting Policies and Practices”.

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

Other income (expenses) decreased by 56.9% in 2011 compared to 2010, mainly due to a recovery of past provisions for legal proceedings and other recoveries, such as the recovery of our allowance for pension liabilities, partially offset by an increase in taxes not related to income and new legal, pension liability and other provisions. Other income (expenses) increased 95.9% in 2010 compared to 2009, principally due to an increase in losses of OIG’s goodwill.

Income before income tax

Income before income tax grew by 105.7% in 2011 when compared to 2010. This growth was largely due to higher revenues from greater average price of crude oil and an increase in the exported volumes of crude oil. Income before income tax increased by 58.5% in 2010, compared to 2009, as a result of the higher average price of crude oil and the increase in our produced volumes.

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Income tax

The effective income tax rate for 2011 was 33.7% compared to 28.2% in 2010 and 29.2% in 2009. The variation in the effective income tax rate was mostly determined by the elimination as of January 1, 2011 of the income tax deductions on investments in real productive fixed assets. In 2010 and 2009 our effective tax rates were lower than the statutory rate as a result of (i) tax benefits mainly due to an income tax deduction applicable to productive fixed assets investments, equal to 40% of these investments for 2009 and 30% for 2010, and (ii) exempt net income on asphalt sales.

Net Income

As a result of the foregoing, in 2011 our net income increased by 90% when compared to 2010 and by 59% in 2010 when compared to 2009.

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

We prepare our financial statements in accordance with Colombian Government Entity GAAP. The accounting principles and regulations under Colombian Government Entity GAAP 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 34 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:

Advances received from Ecogas 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 were treated as capital leases, and an asset and a 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 Ecogas, with the corresponding treatment of the payments receivable from Ecogas as direct financing lease for U.S. GAAP purposes.

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.

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 eliminated the use of inflation adjustments for accounting purposes for state-owned companies starting on January 1, 2002. However, our consolidated financial statements recognize the effect of inflation on non-monetary balance sheet accounts for an extended period from January 1, 1992 until December 31, 2006 for Propilco S.A., COMAI – Compounding and Masterbatching Industry Ltda, Hocol, Oleoducto de Colombia S.A. and Ocensa because, prior to our acquisition of these companies, they were subject to the accounting rules applicable to Colombian privately-owned entities. Under such rules, the effect of inflation on non-monetary balance sheet accounts was required to be recognized until December 31, 2006. 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. Ocensa was not consolidated under Colombian Government Entity GAAP until March 2009 since Ocensa was a variable interest entity under the rules of ASC 810 and included in our consolidated results pursuant thereto until March 2009. Thereafter, Ocensa was consolidated under both Colombian Government Entity GAAP and U.S. GAAP, when we acquired voting control. See Note 34 to our consolidated financial statements for a description of our analysis.

Equity method accounting

Under Colombian Government Entity GAAP as in effect for fiscal years 2011, 2010 and 2009, the equity method is applied for investments where significant influence exists but the investment is not controlled. However, unlike U.S. GAAP, there is no ownership requirement between 20% to 50%.

Employee benefit plans

There are significant differences in the measurement of expense and balance sheet amounts for employee benefit plans between Colombian Government Entity GAAP and U.S. GAAP. See “—Critical accounting policies and estimates— Pension payments and bonds” and Note 34 to our consolidated financial statements.

Investment securities

There are significant differences in the measurement of expense and balance sheet amounts for investments between Colombian Government Entity GAAP and U.S. GAAP. See Note 34 to our consolidated financial statements.

Provisions — allowances and contingences

There are significant differences in the measurement of expense and balance sheet amounts for provisions - allowances and contingences between Colombian Government Entity GAAP and U.S. GAAP. See Note 34 to our consolidated financial statements.

Cumulative Translation Adjustment

Under Colombian Government Entity GAAP, foreign currency investments held in a currency other than U.S. dollars must be remeasured to U.S. dollars prior to translating such financial information to Colombian pesos as the reporting currency. Any impact as a result of the translation process is recognized in equity as cumulative translation adjustments.

Under U.S. GAAP, investments in foreign currency must be remeasured to the functional currency with the effects recorded in the income statement and then translate them to the reporting currency with the effects recognized in equity as cumulative translation adjustments.

Liquidity and Capital Resources

Our principal sources of liquidity in 2011 were cash flows from our operations amounting to Ps$22,996,311 million and cash flows from financing activities, mainly from the proceeds of our second offering of our shares authorized by Law 1118 of 2006, which totaled Ps$2,383,488 million. Our principal uses of liquidity in 2011 were (i) Ps$14,500,671 million in capital expenditures, which included investments in natural and environmental resources and reserves, additions to our property, plant and equipment, (ii) dividend payments for the fiscal year 2011 amounting to Ps$5,896,886 million, and (iii) tax charged to Ecopetrol S.A. amounting to Ps$4,370,725 million. We believe that our financial performance driven by high production and favorable prices has resulted in cash generation sufficient to fund our operational activities and our investment plan without incurring additional indebtedness.

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At December 31, 2011, we had consolidated indebtedness of Ps$8,801,572 million, which corresponded mainly to:

· A balance of Ps$2,044 billion (approximately US$1.05 billion) out of a Ps$2,220 billion (approximately US$1.14 billion) syndicated loan facility entered into with a syndicate of 11 local banks in May 2009. This loan facility has a term of seven years with a two-year grace period. The interest rate under the facility equals the fixed term deposit rate (DTF) plus an additional 4%. Amortization is bi-annual under the loan. In addition, in November 2011, we modified the guarantee we initially granted by replacing the original pledge over direct stock in Reficar (which was 49% of the total shares at the time of the loan), Ocensa and Polipropileno del Caribe (Propilco) with a new pledge over our direct stock in Hocol Petroleum Limited, Offshore International Group (which corresponds to 50% of the total share) and Polipropileno del Caribe (Propilco). We used the proceeds from this loan to finance our Strategic Plan.

· An issuance of US$1,500 million aggregate principal amounts of 7.625% Notes Due 2019 (the “Original Notes”) on July 23, 2009. The Original Notes were issued pursuant to Rule 144A/ Regulation S with registration rights with the SEC. The Original Notes were subsequently registered with the SEC on September 3, 2009 (the “Registered Notes”). Concurrently with this registration, we commenced an exchange offer to exchange up to US$1.5 billion aggregate principal amount of the Registered Notes for an equal principal amount of our outstanding Original Notes under the terms and subject to the conditions set forth in a prospectus dated September 3, 2009. The exchange offer was carried out in compliance with the obligations acquired by us under the Registration Rights Agreement referred to in the prospectus. The exchange offer expired on October 2, 2009. Bonds exchange requests were received in an aggregate amount of US$1,492,541,000. On October 7, 2009, we issued an aggregate amount of US$1,492,541,000 in Registered Notes and cancelled an aggregate amount of US$1,492,541,000 in Original Notes. The Registered Notes were listed on the NYSE.

· A local issuance of Ps$1,000 billion (approximately US$515 million) notes on December 1, 2010. The notes were issued in four tranches with maturities of five, seven, 10 and 30 years and with variable interest rates based on the Consumer Price Index (IPC) plus spreads of 2.80%, 3.30%, 3.94%, and 4.90%, respectively. The notes have bi-annual payments of interest and bullet amortization. We used the proceeds from the offering of these notes to finance our capital expenditures in 2010.

In May 2010 ODL, our indirect Panamanian subsidiary, through its Colombian branch office, Oleoducto de los Llanos Orientales Sucursal Colombia, entered into an Ps$800,000 million (approximately US$406 million) loan facility with local banks. This loan facility has a term of seven years with a two-year grace period and the principal amount will be amortized in 20 equal quarterly payments. The interest rate under the facility equals the DTF plus an additional 4% margin. As guarantee for the loan, Oleoducto de los Llanos Orientales Sucursal Colombia pledged its economic rights to certain finance tariffs it is entitled to receive under its ship-or-pay contracts.  The proceeds from the credit facility were used to fully pay a Ps$520,000 million (approximately US$200 million) credit facility and the remaining amount was allocated to finance part of the Rubiales pipeline. In addition, in October 2009, Oleoducto de los Llanos Orientales Sucursal Colombia also issued a series of notes in an aggregate principal amount equal to Ps$500,000 million (approximately US$260 million); the notes have a maturity of seven years, will be amortized in five equal payments from 2012 to 2016 and have a variable interest rate based on the consumer price index plus an additional spread of 4.88%. See “Item 4. Information on the Company—Overview by Business Segment—Transportation—Pipelines— Oleoducto de los Llanos Orientales.”

Ocensa entered into a Ps$1,200,000 million (approximately US$631 million) loan facility with a syndicate of local banks in March 2010. This loan facility has a term of seven years and its proceeds were used to (i) increase Ocensa’s transportation capacity and (ii) return equity to Ocensa’s shareholders. The interest rate under the facility equals the DTF plus an additional 4%.

In December 2010, we incorporated a wholly-owned subsidiary to serve as our investment vehicle, Ecopetrol Capital AG. Its principal domicile is in Schaffhausen, Switzerland.

On December 30, 2011, with the approval from the Ministry of Finance dated December 29, 2011, Reficar executed the project financing agreements for the expansion and modernization of Reficar’s refinery. The lenders under this agreement are (i) the export credit agencies US EXIM - Export-Import Bank of the United States, SACE S.p.A- Servizi Assicurativi del Commercio Estero, EKN (Exportkreditnamndem), and (ii) the commercial banks The Bank of Tokyo-Mitsubishi UFJ Ltd., Banco Bilbao Vizcaya Argentaria S.A., HSBC Bank USA National Association and Sumitomo Mitsui Banking Corporation. The total amount of financing provided to Reficar is US$3.5 billion with a repayment term of 14 years, except for the commercial credit facility, which has a repayment term of 12 years, beginning six months after the date of completion of the project.

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As part of this project financing, we entered into a construction support agreement pursuant to which we agreed to support Reficar’s costs and expenses related to overcost and delays in construction. In addition, we executed a debt service guarantee agreement pursuant to which: (i) we agreed to provide Reficar with financial resources to pay its debt service shortfalls; (ii) we agreed to assume all or part of Reficar’s debt under certain circumstances described in the financing agreements, including a deterioration of its creditworthiness or our creditworthiness, (iii) we agreed to repay Reficar’s debt under certain circumstances, such as delays in the functioning of the upgraded refinery due to operational problems or if the upgraded refinery does not reach the expected performance level in terms of the quality of products and/or volumes produced; and (iv) reserved the right to assume Reficar’s debt voluntarily at any time. We provided the debt service guarantee agreement to the project lenders. See Item 4—Overview by Business Segment—Refining and Petrochemicals—Reficar.

Use of Funds

Capital expenditures

The following table sets forth our consolidated capital expenditures for each of our business segments for 2011, 2010 and 2009.

	For the Year ended December 31,
	2011		2010		2009
	(Pesos in millions)
Exploration & production		8,067,968		5,878,246		5,564,438
Refining and Petrochemicals		3,044,252		2,084,554		2,710,526	(1)
Transportation		3,382,463		2,351,662		2,269,540	(1)
Corporate		-		-		197,237
Marketing and Supply		5,988		5,513		8,455
Total		14,500,671		10,319,975		10,750,197

(1) Does not include our initial share ownership in acquired companies.

The budget for our 2012-2020 capital expenditures is approximately US$80 billion distributed by business segment. See “Item 4. Information on the Company—The Company—Strategic Plan.”

The investment plan approved for 2012, for Ecopetrol amounts to US$8,477 million of which US$7,452 is expected to be invested directly in Ecopetrol S.A. and US$1,025 million in other companies of the Corporate Group. According to the plan, 94% of investments will be made in Colombia and the remaining 6% for exploration and production projects along the U.S. Gulf Coast, Brazil and Peru.  As in prior years, the majority of investments (65%) are intended for exploration and production. An additional US$2,487 million is expected to be invested by our subsidiaries through their own cash generation, commercial financing and third party or partner contributions, and distributed by segments as follows: 55% downstream, 18% midstream and 27% in upstream branches. Consequently, on a consolidated basis as a Corporate Group, we will invest US$10,964 million in 2012. 

Based on the current price of crude oil, we expect our existing and anticipated working capital, capital expenditure requirements and declared dividend payments to be met from our cash flows from operations and cash in hand. We may also access local and international financial markets to fund part of our capital expenditures. We believe such funding will be available and that we will be able to fund our investment plan. See “Item 3—Key Information—Risk Factors—Risks related to our business.” Furthermore, we may decide to access the equity markets through the issuance of an additional 8.49% of our common stock as authorized by Law 1118 of 2006, or through credit facilities with commercial banks, export development credits, and sale of shares in non-strategic assets. The schedule for carrying out the 2012 investment plan will depend on our cash generating activities, capital market conditions, execution of the investment budget in the various business areas and possible acquisitions. Our investment plan for 2012 and anticipated capital expenditures in future years may change based on market and other conditions and our results of operations and financial resources.

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Cash from operating activities

Net cash provided by operating activities increased by 59% in 2011 compared to 2010 as a result of an increase in the average price of crude oil and natural gas and in volumes produced, which resulted in a 57% increase in our total revenues. Net cash provided by operating activities increased by 54% in 2010 compared to 2009 as a result of an increase in the average price of crude oil and natural gas.

Cash used in investing activities

In 2011, net cash used in investing activities increased by 37% when compared to 2010 mainly due to an increase in our property, plant and equipment investments resulting from our increasing activities. These investments were partially funded by cash provided by our portfolio investments, which totaled Ps$ 9,667,021 million.

Net cash used in investing activities increased in 2010 compared to 2009 mainly as a result of (i) increases in our investments as contemplated in our Strategic Plan, (ii) decreases in our redemption and sale of investments and (iii) payments made for the acquisition of BP Exploration Company Limited (now Equion Energia Limited). These investments were partially funded by cash provided by our portfolio investments, which totaled Ps$11,809 billion.

Cash used in financing activities

Net cash used in financing activities increased in 2011 compared to 2010 mainly due to an increase in dividend payments, partially offset by the proceeds from the second round of our shares offering and from our minority interest in other companies. Net cash used in financing activities decreased in 2010 compared to 2009 mainly due to the decrease in payments of our dividends, partially offset by the decrease in our financial obligations as a result of less incurrence of indebtedness. See “—Liquidity and Capital Resources.”

Dividends

In 2011, we paid dividends of Ps$5,896,886 million to our shareholders, including the Nation. On March 22, 2012, our shareholders at the ordinary general shareholders’ meeting approved dividends for the fiscal year ended December 31, 2011, amounting to Ps$12,335,010 million, or Ps$300 per share, based on the number of outstanding shares at December 31, 2011. The dividend per share was comprised of an ordinary dividend of Ps$263 per share and an extraordinary dividend of Ps$37 per share. Ordinary dividends corresponding to the Nation will be paid in three equal installments. The first payment was made in April 25, the second will be made in July 27, and the last payment will be made between November 15, 2012 and January 15, 2013. The extraordinary dividend to be paid to the Nation will be paid within the 12 month period following March 22, 2012. The payment of the ordinary and extraordinary dividend to the minority shareholders was made in one lump sum on April 25, 2012.

Research and Development, Patents and Licenses, etc.

Our research and development activities are conducted by the Instituto Colombiano del Petróleo (ICP) or the Institute, our research and development unit. Our activities are focused on developing technology solutions for us and the Colombian oil industry. Each year, we present to the Instituto Colombiano para el Desarrollo de la Ciencia y la Tecnología (COLCIENCIAS) our research and development projects in order to get a certification for our investment in science and technology. In 2011, 2010 and 2009, COLCIENCIAS recognized investments of US$50.83 million, US$46.5 million and US$50.8 million respectively in science and technology projects. Our total investment in science and technology during 2011 was approximately US$67.8, of which approximately US$27.58 million corresponded to 14 projects in research and development related to air and chemicals injection in oil fields, exploration processes in offshore exploration, multicomponent seismic, non-conventional hydrocarbons, biofuels, petrochemicals and new refining processes. In 2010, we invested approximately US$69 million, and in 2009 we invested approximately US$63 million.

We currently own 26 patents in Colombia, the United States, Mexico, Venezuela, Ecuador, Brazil and Nigeria. Of the three patents granted in 2011, two were technologies we developed to reduce fuel theft. In the first quarter of 2012, we obtained two additional patents in Mexico, related to the development of additives to reduce the formation and precipitation of coke on Visbreaking processes. In 2011, we filed for 28 new patents in various countries, including Colombia, the United States, Brazil, Mexico, Indonesia and Malaysia. One of our most significant patents for which we filed in 2009, when we filed 39 applications, is an anti-theft patent that allowed us to reduce fuel oil and crude oil theft by 50% in 2009 compared to 2008. Most of our patents will expire between 2015 and 2017.

During 2011 and 2010, two and nine new commercial brands were granted to us, respectively. In 2009, we were also granted 12 new commercial brands, adding to the eight brands we had been granted previously (the existing brands of which have been renewed for an additional ten-year period). By the end of 2011, we had 33 brands in total.

In 2010, the ICP’s Technical Information Center became one of the first specialized information units in the oil and gas sector in Latin America to receive the certification in the System of Information Security Management under the NTC/ISO 27001:2005, standard granted by the Instituto Colombiano de Normas Técnicas, or ICONTEC, a Colombian National Standards organization.

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Off-Balance Sheet Arrangements

As of December 31, 2011, we did not have off-balance sheet arrangements of the type that we are required to disclose under Item 5.E of Form 20-F.

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 contractual obligations at December 31, 2011.

Payments due by period

	Payments due by period
			Less than 1		1 to 3		3 to 5		More than 5
	Total		Year		years		years		years
	(Pesos in millions)
Contractual Obligations:
Pension Plan Obligations		17,890,963		691,272		1,443,091		1,532,315		14,224,285
Contract Service Obligations		3,253,791		1,616,600		1,412,580		108,258		116,354
Operating Lease Obligations		393,795		102,791		114,506		51,330		125,167
Natural Gas Supply Agreements		902,469		102,012		301,082		199,698		299,676
Purchase Obligations		231,258		94,505		136,753		-		-
Energy Supply Agreements		384,217		249,843		106,806		27,567		-
Capital Expenditures		2,269,628		1,887,591		359,274		9,108		13,655
Build, Operate, Maintain and  Transfer Contracts (BOMT)		479,221		61,837		115,408		118,386		183,590
Capital (Finance) Lease Obligations		71,191		35,964		28,842		6,235		150
Financial Sector Debt		5,610,320		1,178,110		3,402,953		993,709		35,548
Bonds		6,818,922		299,835		995,955		725,458		4,797,673
Total		38,305,773		6,320,360		8,417,250		3,772,064		19,796,099

ITEM 6.         Directors, Senior Management and Employees

Directors and Senior Management

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

Directors of Ecopetrol

In view of their experience and knowledge on the Energy and Mining Sectors, some members of the Board of Directors have been appointed as government officials, losing their status as independent directors. Mauricio Cárdenas Santamaría is currently the Minister of Mines and Energy and Federico Rengifo Vélez, previously the Secretary of the Presidency of Colombia has been recently appointed as Ministry of the Interior. The following are our current Directors as elected at the shareholders’ meeting held on March 22, 2012.

Minister of Mines and Energy, Mauricio Cárdenas Santamaría (49) has been a member of our Board of Directors since March 27, 2008. From March 27, 2008 until his nomination as Minister of Mines and Energy on September 26, 2011, Mr. Cárdenas served as independent director representing our minority shareholders. Mr. Cárdenas has served as Senior Fellow and Director of the Latin America Brooking Institution in Washington D.C. Previously, Mr. Cárdenas served as President of Empresa de Energía de Bogota, Minister of Economic Development of Colombia, Minister of Transportation and Director of the National Planning Agency of Colombia. He has also been the Executive Director of Fedesarrollo, a think-tank in Colombia. Mr. Cárdenas earned his undergraduate and master’s degrees in economics from Universidad de los Andes and later obtained a Ph.D. in economics from the University of California, Berkeley. In 2001, Mr. Cárdenas was a visiting scholar at Harvard University´s Center for International Development. In 1999 he was elected by Time Magazine and CNN as one of Latin America´s Leaders for the New Millennium. Mr. Cárdenas was appointed as a director by the Nation.

Minister of Finance and Public Credit of Colombia, Juan C. Echeverry (49) has been a member of our Board of Directors since August 24, 2010.  Mr. Echeverry is a macroeconomist and university professor experienced in economic and political analysis of Colombia and Latin America. He has worked as an advisor of international banks and financial institutions while working for Latin Source, a New York based consultancy, and Econcept, a Bogotá based consultancy.  Mr. Echeverry is an expert witness in international and Colombian litigations in topics of infrastructure concessions and finance. He has published papers in different fields of economics, in specialized journals, and a book about the Colombian economy.  He has been a member of the Board of Directors of Mazda Colombia, Holcim and Interbolsa. He was Minister of Economic Planning of Colombia and Dean of Economics at Universidad de los Andes.  Mr. Echeverry earned a degree in economics from los Andes University, Bogotá – Colombia, a master’s degree in International Economic Policy from Economic World Institute, Kiel - Germany, and later obtained a Ph. D. in economics from New York University. He also earned a degree in Philosophy from Universidad Complutense, Madrid – España. Mr. Echeverry was appointed as a director by the Nation.

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Director of the National Planning Agency of Colombia, Mauricio Santamaría Salamanca (45) has been a member of our Board of Directors since January 24, 2012. Mr. Santamaría was Minister of Health and Social Protection between 2011 and 2012. He has been Deputy Director and Deputy Executive Director of Fedesarrollo. He also has been Deputy Director, Director of Infraestructure and Energy, Social Development Director, and Head of the Foreign Business Division of the National Planning Agency of Colombia. Mr. Santamaría was Senior Economist and Advisor at the World Bank. He was a member of the Board of Directors of Ecopetrol in 2006. He earned Ph.D. degree and a master’s degree in Economics from Georgetown University, Washington, D.C. He also earned a degree Economics from Los Andes University. Mr. Santamaría was appointed as a director by the Nation.

Fabio Echeverri Correa (79) has been a member of our Board of Directors since September 16, 2002. He is currently the President of the Board of Directors. 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 the National Association of Industries (ANDI), the Latin American Association of Industries (AILA), and the Andean Confederation of Industries (CONANDI), 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 Frigoríficos 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 Directors of Siemens S.A., among others.  Mr. Echeverri earned degrees in economics from Universidad Jorge Tadeo Lozano.  Mr. Echeverri was appointed as an independent director by the Nation

Joaquín Moreno Uribe (63) 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 Exploration and Production Business Economics and Strategic Planning Director for Europe and the Middle East at the Shell International Central offices in The Hague, the Netherlands.  Mr. Moreno has also served as Country Chairman and President for Shell in Mexico, Colombia and Venezuela, as well as Regional CEO for Downstream Oil Business in Northern Latin American Region.  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 Business School in Cambridge (Massachussets). He was appointed as an independent director by the Nation.

Federico Rengifo Velez (58) has been a member of our Board of Directors since March 24, 2011.  Mr. Rengifo has served as the Secretary of the Presidency of Colombia and he has recently been appointed as Minitry of the Interior. He has been Vice-minister and Minister of Finance, Economic Development, Mines and Energy of Colombia and as Executive President of Banco de Colombia, President of Compañia Financiera Internacional S.A., and member of the Council of Cali (Valle del Cauca – Colombia), among others. He has participated in several boards of directors of the financial and public sectors. He earned a law degree and a degree in Social-Economic Sciences from Javeriana University. Mr. Rengifo was appointed as a director by the Nation.

Luis Carlos Villegas Echeverri (54) has been a member of our Board of Directors since March 22, 2012.  Mr. Villegas has been President of the National Business Association of Colombia or ANDI since 1996. Prior to his position as President of ANDI, he served as the Economic Advisor to the Colombian Embassy in France, Vice-Minister of Foreign Affairs of Colombia, Governor of the Department of Risaralda, General Secretary of the Federación Nacional de Cafeteros, and as Colombian Senator. Mr. Villegas has served as a member of several boards of directors of financial and industrial companies throughout Colombia. Mr. Villegas is also President of the National Council of Private Sector Associations and a board member of the International Organisation of Employers. In 1999, Mr. Villegas was designated Chairman of the Board of the Fund for Reconstruction and Social Development of the “Eje Cafetero,” overseeing all reconstruction efforts after an earthquake hit that region. Mr. Villegas received a degree in law and social economics from the Universidad Javeriana and attended a master’s program on Public Administration at the University of Paris II. Mr. Villegas was appointed as an independent director by the Nation.

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Roberto Steiner Sampedro (52) has been a member of our Board of Directors since October 12, 2011. Mr. Steiner is the Executive Director of Fedesarrollo (Fundación para la Educación Superior y el Desarrollo) since 2008. He served as Alternate Executive Director of International Monetary Fund from 2002 to 2007, Director of the Economics Research Department of Banco de la República from October 1989 to April 1993, Director at the Economic Development Research Centre of Los Andes University, Consultant at the World Bank from 1995 to 1996, Deputy Director of Fedesarrollo from 1993 to 1994, Deputy Director of the Economics Research Department of Banco de la República from 1988 to 1989, and Senior Economist at Banco de la República from 1986 to 1988. He was professor and researcher at various Colombian universities, such as Los Andes, Javeriana and Nacional. In 1995 he was summer professor at Columbia University in New York. He has published many economic books, treatises, articles and research papers. Mr. Steiner earned a degree in economics from Universidad de los Andes and a master’s degree and a Ph.D. in economics from Columbia University in New York. Mr. Steiner was appointed by the shareholders’ meeting as an independent director representing our minority shareholders. Mr. Steiner was nominated to our Board of Directors in connection with the 2012 appointment pursuant to a shareholder agreement among representatives of eight pension and retirement funds.

Amilcar Acosta Medina (61) has been a member of our Board of Directors since his appointment at the extraordinary shareholders’ meeting held on August 3, 2011. From 2002 to 2004 he served as Advisor to the Office of the Comptroller General of the Republic. Mr. Acosta served in the Senate of Colombia from 1991 until 2002 and was the President of the Congress of Colombia from July 1997 to July 1998. From 1991 to 1992 he served as Deputy Minister of Mines and Energy. He has held positions as a researcher and professor at several universities and published many treatises on economics, and research articles on the mines and energy sector, and ex columnist of the leading newspapers of the country. Mr. Acosta earned a BA in Economics from the University of Antioquia. He was appointed by the shareholders’ meeting as an independent director representing our hydrocarbon producing departments.

Officers and Senior Management of Ecopetrol

In March 2012, our Board of Directors approved changes to our senior management’s structure adding four new positions: Vice-President of HSE and Operational Sustainability, Director of Strategic Procurement, Vice-President of Innovation and Technology and Director of Shared Services.

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

Javier Gutiérrez (60) 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 (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 journal   as the “Best Enterprise Leader in Colombia.”  In 2005 the América Economía Journal 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.  In 2008, Mr. Gutiérrez was recognized as the enterprise leader with the best reputation in Colombia by the Spanish Monitor of Corporate Reputation (MERCO).  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. Gutiérrez 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 (41) 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 Head of the Finance and Treasury Unit and Head of the Corporate Finance Unit.  She earned a degree in finance and foreign affairs and an MBA from Universidad Externado de Colombia.

Margarita Obregon (54) joined Ecopetrol in 2000 and has served as the Secretary of the Board of Directors and as Chief to the Support Office of the Chief Executive Officer since 2008.  Prior to joining us, Mrs. Obregon worked in the supply department of Previsora S.A: Compañía de Seguros and as legal advisor of lands for British Petroleum Company – BP in Alvaro Rengifo y Cia. Mrs. Obregon also served as the head of the Business and Administration department of the Fiduciaria del Estado. Mrs. Obregon earned a law degree from Colegio Mayor de Nuestra Señora del Rosario with specialization degrees in financial law and administration law.

Hector Manosalva (50) is a petroleum engineer, graduated from the Fundacion Universidad de America, and completed post-graduate studies in Finance at the Universidad EAFIT and in Executive Management at the Universidad de los Andes. Mr. Manosalva joined Ecopetrol in 1986. Over the course of his career at Ecopetrol, Mr. Manosalva has served as Chief of Production, Head of the Division of Planning, Production Manager of the South Region, Director of Corporate Social Responsibility, Advisor to the Office of the President of the Republic for the Protection of Energy Infrastructure, Production Manager of the Central Region and, most recently, as Vice-President of Production. He was appointed second alternate president of the Company in 2010.

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Pedro A. Rosales (48) joined us in 1989, and has served as our Downstream Executive Vice-President since February 2008.  Mr. Rosales is responsible for the following businesses:  refining, petrochemicals, marketing and distribution, biofuels and gas.  Mr. Rosales has held several positions in the Company within the areas of maintenance, operations, projects, planning and administration.  Prior to becoming our Downstream Executive Vice-President, Mr. Rosales served as our Vice-President of Transportation since January 2003 and as our Chief Operation Officer since 2006.    Mr. Rosales earned a degree in mechanical engineering and an MBA from Universidad de los Andes.

Hector Castaño (50) joined us in 1988 and has served as our Production Vice-President since 2011.  Mr. Castaño earned a degree in petroleum engineering from Universidad Nacional and a specialization degree in management from Universidad Sur Colombiana de Neiva.  He has held a number of positions in Ecopetrol, including Director of Production in the Central region, in the Southern region and in the Mid-Magdalena Valley region.

Enrique Velasquez (59) joined us in June 2008 and has served as our Exploration Vice-President since September 2010.  Mr. Velasquez earned a degree in geology from Universidad Nacional, a specialization degree in financial management from Universidad EAN and a specialization degree in high management from Universidad de los Andes.  In his 32 years of labor experience, he has held a number of positions in oil and gas companies, such as Oxy, Hocol, Sipetrol, Texaco, Exxon and Halliburton.  He has served as our International Exploration Manager and National Exploration Manager.

Camilo Marulanda (33) joined us in 2003 and has served as our Vice-President of Strategy since 2009.  Mr. Marulanda earned a degree in economics, a specialization degree in marketing and an MBA from Universidad de los Andes.  He worked for Procter & Gamble Colombia from August 2001 to February 2003 as Category Manager.  Prior to becoming our Vice-President of Strategy, Mr. Marulanda served as Chief of the Marketing Department since September 2003, Director of the National Commercialization unit since December 2004 and Vice-President of Supply and Marketing since December 2005.

Federico Maya (47) 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 Vice-President 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.

Claudia Castellanos (48) has served as our Vice-President of Supply and Marketing since 2009.  Mrs. Castellanos earned a degree in chemical engineering from Universidad Industrial de Santander and a specialization degree in energy resources management from Universidad Autónoma de Bucaramanga.  She has worked in Ecopetrol for over 22 years including positions as a process engineer at Refineria de Cartagena, where she also worked in the Finance Department.  Prior to becoming our Vice-President of Supply and Marketing, Mrs. Castellanos was chief of our Gas Department for six years, where her focus was in the domestic and international commercialization of natural gas.

Alvaro Castañeda (49) has served as our Vice-President of Transportation since 2009.  Mr. Castañeda earned a degree in metallurgical engineering, a specialization degree in international management of oil and gas and a master’s degree in administration from Universidad Autonoma de Bucaramanga and Instituto Tecnologico de Monterrey.  He has worked for Ecopetrol for the last 20 years, and has held various positions within the Company, including Plant Coordinator, Director of the Operations Department, Chief of the Centralized Operations Department and Director of Multipurpose Pipelines.

Martha Cecilia Castaño (43) joined us in 2004 and has served as our Vice-President of Human Resources since 2008.  Prior to becoming our Human Resources Vice-President, Mrs. Castaño worked as Coordinator of Organizational Culture, Chief of the Leadership, Internal Communications and Cultural Unit and was also in charge of the Labor Relations Department.  Mrs. Castaño earned a degree in social communications and a specialization degree in economics from Universidad de la Sabana.  She has also worked in Acopi, El Tiempo, Uniandinos and Empresa de Telecomunicaciones de Bogotá (ETB), in several areas such as human resources management, corporate communications and labor relations.

Oscar Villadiego (47) joined us in 1986, he is currently the Vice-President of HSE and Operational Sustainability. He served as Vice-President of Services and Technology since February 2008, until 2012. He has held several positions in the Production Vice-Presidency in areas such 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 (55) 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.

Jaime Pineda (49) joined us in November 1989, he started working for the Legal Advisory Office in Barrancabermeja, ,and has served as our Head of Procurement Legal Advice Office from 2003 until 2012. Mr. Pineda is temporarily in charge of our Strategic Procurement Unit since March 2012 until the new director is appointed. He also serves as professor at Santo Tomas and Externado de Colombia universities. Mr. Pineda has a Law Degree from Universidad Autónoma de Bucaramanga, and a specialization degree in public procurement from Universidad Santo Tomas and a contracting law degree from Universidad Externado de Colombia.

Nestor Saavedra (49) is temporarily the head of our Vice-Presidency of Innovation and Technology since March 2012, and will continue to serve in that position until a new Vice-President is appointed. Mr. Saavedra earned a degree in petroleum engineering from Universidad Industrial de Santander and a master’s degree in petroleum engineering from Texas A&M. His work within the Company, has included serving as Director of the Colombian Petroleum Institute of Ecopetrol, coordinating horizontal well technology and rock mechanics projects, as well as assessing and predicting the behavior of Colombian oil fields. Mr. Saavedra serves as Director of the Society of Petroleum Engineers (SPE) in the South American and Caribbean Region.

Jorge Enrique Gómez Rodríguez (44) joined us in 1991. He has been the Director of Shared Services since March 2012. Over the course of his career in Ecopetrol, Mr. Gómez has served as Head of the Information and Technology Unit, Head of the Optimization Unit, and Head of the Enterprise Management Unit, among others. He is an Information and Computer Science Professional, with a specialization in Geographic Information Systems from Universidad Industrial de Santander. He earned his MBA from Universidad de los Andes.

Adriana M. Echeverri is the first cousin of Luis Carlos Villegas Echeverri, a member of the Board of Directors. None of our other Directors or executive officers has any familial relationship with any other director or executive officer.

Compensation

The total compensation paid to our Directors, executive officers and senior management during 2011 amounted to Ps$10.212 million.

Based on a resolution adopted at our 2012 annual shareholders’ meeting, Directors’ compensation for Board and/or committee meetings in person increased from the equivalent of four, to six minimum monthly wage salaries, which totals approximately Ps$2,142,400 for 2011 and Ps$3,400,200 for 2012.  Fees for attendance at virtual meetings are set at 50% of the in-person meeting fee.

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 officers totals Ps$6,163 million.

Share Ownership

No individual Director or executive officer beneficially owns more than 1% of our outstanding shares.

Board Practices

Our Board of Directors is composed of nine members and is responsible for, among other things, establishing our general business policies.  According to Colombian law, the members of the Board of Directors must be elected at the annual shareholders’ meeting in accordance with a proportional representation system similar to cumulative voting (through an electoral quota voting system – number of votes required to fill each position is calculated by dividing the number of possible votes by the number of open board positions) and may be reelected indefinitely.  The members of the Board of Directors may be elected without an electoral quota voting system when there is unanimity.   Pursuant to our bylaws, Directors are elected for a one-year term, and the positions are filled either by person or by position.  Currently, we have three members appointed by their position:  the Minister of Finance and Public Credit, the Minister of Mines and Energy and the Director of the National Planning Agency.  Our current Directors were elected on March 22, 2012.  Directors may be removed without cause at any moment by a majority of the shareholders present at a general shareholders’ meeting.  Our executive officers are appointed by our Board of Directors.

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The compensation of our Directors is set exclusively by the general shareholders’ meeting.  Colombian law prohibits Directors from receiving corporate loans.  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.  None of the service contracts of any of our Directors contains provisions for benefits upon termination of such director’s services.

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.  We disclose conflicts of interest of our employees, executive officers and directors in our Corporate Governance and Board of Directors Report.

Neither our bylaws nor our corporate governance code provide a minimum retirement age for our Directors.  Under our bylaws 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.

Pursuant to our bylaws, our Board of Directors has four committees (Audit Committee, Corporate Governance and Sustainability Committee, Nomination and Compensation Committee and Business Committee), which establish guidelines, set specific actions and evaluate and submit proposals designed to improve performances in the areas under their supervision and control.  These committees are comprised by members of the Board of Directors who are appointed by the Board of Directors.  In addition to applicable regulations, the committees also have their own specific regulations that establish their purposes, duties and responsibilities.

The following table sets forth the current members of our committees:

Audit Committee(1)	Compensation and Nomination Committee	Corporate Governance and Sustainability Committee
Joaquín Moreno Uribe	Fabio Echeverri Correa	Joaquín Moreno Uribe
Amilcar Acosta Medina	Minister of Mines and Energy	Minister of Finance and Public Credit
Roberto Steiner Sampedro	Joaquín Moreno Uribe	Amilcar Acosta Medina
Luis Carlos Villegas Echeverri	Amilcar Acosta Medina	Roberto Steiner Sampedro
		Minister of Mines and Energy
Business Committee
Joaquín Moreno Uribe
Minister of Mines and Energy
Federico Rengifo Velez
Director of the National Planning Agency
Luis Carlos Villegas Echeverri
Roberto Steiner Sampedro

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

Audit Committee

Our audit committee, which must be comprised of at least three members, all of them independent Directors, is our highest internal control body and provides support to our Board of Directors in accounting and financial matters.  It is in charge of guaranteeing the design, implementation and supervision of our internal control over financial reporting.  It also supervises the reserves certification process, ratifies the Hydrocarbons Reserves Report and provides support for our Board in analyzing topics related to financial matters, risks, control environment and assessment of the Company’s internal and external auditors.

All committee members are required to be knowledgeable in accounting matters and at least one of them is required to be an expert in financial and accounting matters. Roberto Steiner Sampedro currently serves as the audit committee financial expert.

Compensation and Nomination Committee

Our compensation and nomination committee, which must be comprised of at least three members, including at least one independent director, provides general guidelines for selection and compensation of our executive officers and employees.  

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Corporate Governance and Sustainability Committee

Our corporate governance and sustainability committee, which must be comprised of at least three members, including at least one independent director, makes proposals to our Board of Directors to ensure and supervise the fulfillment of our good corporate governance and sustainability practices of the Company according to our corporate governance code.

Business Committee

Our business committee, which must be comprised of at least five members, including at least one independent director, was created to assist our Board in analyzing potential business ventures.  Based on its delegation of power, the committee studies and analyzes capital expenditure policies, major investment projects, strategy, new business and other matters that would help us move forward in our efforts toward the consolidation of our strategy. The primary criteria used in the committee’s decision-making are the optimization of our portfolio and the proper allocation of our resources.

Employees

At December 31, 2011, we had 8,729 employees.  The collective bargaining agreement that was entered into between us and our three main labor unions governs the labor relations of our unionized employees, which amounted in Ecopetrol S.A. to 3,221 employees on December 31, 2011.  Agreement 01 of 1977 governs the labor relations of our employees devoted to technical and trustworthy activities, which numbered 4,082 employees in Ecopetrol S.A. on December 31, 2011.  The collective bargaining agreement and Agreement 01 of 1977 do not vary significantly in benefits.  Employees hired before January 29, 2003 have a special retirement plan, and those hired after January 29, 2003 are subject to Law 100 of 1993 with respect to their retirement scheme.

Most of our employees are located in Colombia. In order to support our corporate growth strategy, we increased the total number of Ecopetrol S.A. employees by 8.3% from 6,744 in 2010 to 7,303 in 2011.  The table below presents the number of Ecopetrol S.A.’s employees unconsolidated by business segments and those of our subsidiaries for the years ended December 31, 2011, 2010 and 2009. As of December 31, 2011 we had 10 direct employees working abroad.

	As December 31,
	2011(1)		2010		2009
Ecopetrol S.A.
Exploration and Production
Exploration		130		133		130
Production		1,565		1,460		1,369
Others		309		283		240
Total Exploration and Production		2,004		1,876		1,739
Downstream
Refining		2,134		2,000		2,080
Marketing		175		159		150
Others		18		17		18
Total Downstream		2,327		2,176		2,248
Transport		964		856		869
Corporate		2,008		1,836		1,839
TOTAL ECOPETROL S.A.		7,303		6,744		6,695
Ecopetrol America Inc.		14		10		0
Bioenergy S.A.		102		83		62
Bioenergy Zona Franca S.A.S		23		19		-
Hocol S.A.		202		192		152
Equion Energia Limited		465		-		-
Oleoducto Central S.A.		133		133		130
Oleoducto de Colombia S.A.		1		1		2
Oleoducto de los Llanos S.A.		19		17		9
Oleoducto Bicentenario de Colombia S.A.S		19		-		-
Ecopetrol del Perú S.A.		12		6		4
Refinería de Cartagena S.A.		142		122		106
Ecopetrol Oleo e Gas do Brasil Ltda.		10		3		4
Propilco S.A.		284		245		231
TOTAL(2)		8,729		7,575		7,395

(1) 483 persons employed by us during 2011 were not included in our 2011 employee statistics as they were involved in intermittent, non-regular activities and do not classify as temporary employees.

(2) Totals are as of the last day of each year.

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During 2011, Ecopetrol S.A. had 574 temporary employees, an increase of 51% compared to 2010. In 2010 and 2009, Ecopetrol S.A. had 379 and 467 temporary employees, respectively.

Labor Unions

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

· Unión Sindical Obrera de la Industria del Petróleo — USO (Industry labor union);

· 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);

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

· Sindicato Nacional de Trabajadores de Ecopetrol — SINCOPETROL (Company labor union).

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

On August 2, 2011 and November 8, 2011 we experienced two work stoppages promoted by the USO in Barrancabermeja to support workers protesting at an unaffiliated oil and gas exploration and production company, Pacific Rubiales Energy. These protests did not affect our operations.

On August 22, 2009, as a result of consensual negotiations, we entered into a five-year collective bargaining agreement with USO, ADECO and Sindispetrol.

The following are the key terms of the agreement currently in effect since 2009 until 2014:

· Transportation Subsidy.  Monthly transportation subsidy depends on the employee’s location and ranges between Ps$1,292 and Ps$138,557;

· Food Subsidy.  Monthly food subsidy ranges between Ps$258,390 and Ps$299,010 depending on the employee’s location;

· Lodging Subsidy.  Monthly lodging subsidy to employees is Ps$205,564;

· Subsidy for Education.  Subsidy that covers 90% of tuition and board expenses and fixed amounts of transportation and textbooks for our employees and their children;

· Health Benefits.  Ecopetrol pays 100% of medical expenses for workers and their families. The health benefits include integral basic attention, programs in prevention of diseases, the supply of medicines and others.

· Six months Bonus. Ecopetrol pays 48 days of regular wage to its workers; 24 days in June and 24 in December.

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

· Retirement plan for employees.  Employees hired after January 29, 2003 are not covered by our retirement scheme and are instead covered by the national social security system;

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· Five-year bonus.  A cash benefit bonus accrues on a yearly basis and is paid for every 5-year period an employee works in the Company according to the following scale:

5 years worked:	Bonus equivalent to 9 days of basic payment plus Ps$193,990
10 years worked:	Bonus equivalent to 14 days of basic payment plus Ps$193,990
15 years worked:	Bonus equivalent to 19 days of basic payment plus Ps$193,990
20 years worked:	Bonus equivalent to 24 days of basic payment plus Ps$193,990
25 years worked:	Bonus equivalent to 29 days of basic payment plus Ps$193,990
30 years worked:	Bonus equivalent to 34 days of basic payment plus Ps$193,990

Recently, as is our customary practice, we held meetings with different unions to discuss potential revisions to our collective bargaining agreements.

Labor Relations

As part of our goal to improve workplace morale, in 2010 we implemented a number of initiatives to maintain high-trust relations with our employees, guarantee competitive wages, strengthen our corporate principles and culture, provide opportunities for personal development and improve the general welfare of our employees.  Our initiatives also sought to strengthen communication processes, and to start performance-based compensation.

To improve the quality of life of our employees, we extended various types of loans to our employees, including home loans and general-purpose loans.  In 2011, we extended 1,020 home loans to our employees for a total of Ps$92,090 million and 790 general-purpose loans for a total of Ps$5,270 million.  We also provided on-site and external training and development courses to our employees.  At December 31, 2011, our investments in employees’ development amounted to Ps$24 billion and we extended a total of Ps$57.8 billion in subsidies for education.

Labor Regulation

As of November 13, 2007, all of our employees are official employees as a result of our transformation into a mixed economy company.  Therefore, our employees have been governed by the provisions of the Colombian Labor Code since that time.

ITEM 7.         Major Shareholders and Related Party Transactions

MAJOR SHAREHOLDERS

The following table sets forth the names of our major shareholders, and the number of shares and the percentage of outstanding shares owned by them at March 31, 2012.

	At March 31, 2012
Shareholders	Number of shares		% Ownership
Nation		36,384,788,817		88.49	%
Public float		4,731,909,639		11.51	%
Total		41,116,698,456		100.0	%

All our common shares have identical voting rights.

As of March 31, 2012, 1.498% of our common shares were held of record in the form of American Depository Shares.  As of March 22, 2012, we had nine registered holders and 11,241 beneficiaries of common shares, or ADSs representing common shares, in the United States.

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 16 to our consolidated financial statements.

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Ocensa

We have entered into the following agreements with Ocensa:

· In March 1995, we entered into an agreement for the transportation of crude oil through the Ocensa pipeline. Pursuant to the terms of this 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 2011, payments made by us under this agreement amounted to US$297.83 million. This agreement expires in December 2093 or upon liquidation of Ocensa.

· In December 1995, we leased the Porvenir and Miraflores terminals to Ocensa. Pursuant to the terms of the lease agreement we received monthly payments during 2011 of approximately US$7,532,701 plus applicable taxes. The duration of this agreement is indefinite.

· In November 1996, we leased the Cravo Norte dock to Ocensa. Pursuant to the terms of the agreement, we received monthly payments during 2011 of US$23,000, 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 and ODC. Pursuant to the terms of this 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 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, Miraflores and Vasconia pumping stations. In 2011, pursuant to the terms of this agreement, we received monthly payments of approximately US$379,000 plus applicable taxes and variable costs in 2011. This agreement was renewed for a five-year term on April 1, 2011.

· In December 2004, we entered into a natural gas supply contract pursuant to which we receive variable monthly payments based on the volumes of natural gas delivered and a fixed tariff. During 2011, we received monthly payments of approximately US$2,465,008 under this contract.

Ocensa has entered into the following agreements with some of our subsidiaries:

· Equion Energia Limited and Santiago Oil Company have entered with Ocensa into transportation agreements similar to the one we executed in March 1995 and described above. Pursuant to the agreement between Ocensa and Ecopetrol S.A., our subsidiaries Hocol S. A. and Homcol Inc. have been able to get their oil transported through the Ocensa Pipeline. In 2011, the transportation fees billed by Ocensa were: to Equion Energia Limited US$1.25 million, to Santiago Oil Company US$3.1 million, and to Hocol and Homcol US$17.1 million.

Oleoducto de Colombia S.A.

We entered into the following agreements with ODC:

· In July 1992, we entered into a take-and-pay agreement for the transportation of hydrocarbons. Pursuant to this 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 this agreement, ODC is required to make monthly payments of approximately US$1.5 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 July 2006, we entered into an operation and maintenance agreement for the Caucasia Station and the Vasconia-Coveñas pipeline system. Since 2010, this agreement is only in effect for the operation of the Caucasia Station. Pursuant to the terms of this agreement, we received monthly payments of approximately US$704,065 per year, plus any other expenses incurred by us for 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.

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· 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 this agreement, ODC paid us Ps$51 million per year. This agreement expired on December 31, 2011.

Refinería de Cartagena S.A.

In conjunction with our transfer of Reficar’s assets in April 2007, we entered into a maintenance and administration agreement with Reficar, which we wholly own as of May 2009. Pursuant to the terms of this agreement, we provided Reficar with maintenance and administration services in exchange of a monthly fee. This agreement expired in April 2011, but was extended through the term of our negotiations. In December 2011, we executed an agreement that governs the composition of the crude slate that the refinery processes, its purchase of crude and other products, and its sale of refining products. In January 2012, we executed a new operations and maintenance contract. These contracts replaced the old maintenance and administration services contract. The fees billed to Reficar during 2011 under these contracts were approximately Ps$45.2 billion.

On February 1, 2012, we entered into a crude oil supply contract with Reficar for a period of five years. Pursuant to the terms of this contract, Reficar has the option to purchase up to 200 thousand bpd of crude oil from our Caño Limón, Vasconia Blend and Castilla blends. This contract includes an option for Reficar to receive from Ecopetrol crude oil we have bought from other national producers or imported from foreign producers on behalf of Reficar.

On November 29, 2010, Ecopetrol S.A. entered into a Colombian Peso-denominated loan facility with Reficar for an amount in Pesos equivalent to US$1 billion to finance capital expenditures and construction costs in connection with a project to modernize Reficar’s refinery. Ecopetrol S.A. disbursed US$591 million peso equivalent and amended the agreement to reduce the commitment amount to US$600 million. The interest rate for the US$591 million peso equivalent loan is equal to the DTF as of December 31 of the year before each annual period. On September 26, 2011, Reficar and Ecopetrol Capital A.G. executed a new long term U.S. dollar-denominated subordinated loan agreement for up to US$400 million also to finance capital expenditures and construction costs in connection with the project to modernize Reficar’s refinery. Ecopetrol Capital A.G. disbursed the US$400 million under this new subordinated loan agreement in 2011. The interest rate for this subordinated loan is LIBOR 6 months plus 4.775% per annum.

In June 2011, Ecopetrol Capital A.G. granted a US$240 million treasury loan to Reficar to finance delayed subsidy payments from the Nation. The interest rate for this loan is 2.10% per annum. In December 2011, the Nation paid US$198 million to Reficar for accrued subsidies, and Reficar used the entire amount to repay principal and interest on the treasury loan. As of December 31, 2011, the amount outstanding under this loan was US$45 million.

In December 2011, Ecopetrol S.A. entered into a construction support agreement and a debt service guarantee agreement to guarantee certain obligations of Reficar under the US$3.5 billion project finance for the expansion and modernization of its facilities. Pursuant to the terms of the construction support agreement, Ecopetrol S.A. agreed to support Reficar’s costs and expenses related to overcost and delays in construction. Pursuant to the terms of the debt service guarantee agreement, Ecopetrol S.A. provided Reficar with a liquidity mechanism to pay its debt service shortfalls and a mechanism to exit the project financing by transferring its debt to us. See “Item 5. Operating and Financial Review and Prospects—Liquidity and Capital Resources.”

Oleoducto de los Llanos Orientales S.A.

We have entered into two ship-or-pay agreements with ODL:

In March 2009, we entered into a ship-or-pay agreement with ODL that establishes a financing tariff used to pay ODL’s indebtedness to Grupo Aval for five years. This agreement was superseded by a new contract executed in May 2010, with a seven-year term, to reflect new conditions agreed with Grupo Aval. This financing tariff is collected through a trust fund, which in turn is responsible for making the debt service payments to Grupo Aval. Under this agreement, ODL has committed to transport 75 thousand bpd during the two-year grace period of the facility and 90 thousand bpd during the remaining five years.

In September 2009, we entered into a second ship-or-pay agreement with ODL that establishes a financing tariff collected through a trust fund that in turn is responsible for making debt service payments to security holders. Under this agreement, ODL committed to transport 19.5 thousand bpd during the first phase of the ODL project (which began in September 2009 and ended in the first quarter of 2010) and 39 thousand bpd upon commencement of the second phase of the ODL project which occurred in the first quarter of 2010.

In December 2009, we entered into a service agreement with ODL to transport crude oil. This agreement expires in June 2016 and can be renewed. Pursuant to the terms of this agreement, in 2011 we made monthly payments of Ps$189 billion.

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In March 2010, we entered into a pipeline O&M agreement with ODL. This agreement has a five year term and the amount payable to us for the entire term of the agreement is Ps$ 56.4 billion, plus any applicable taxes.

In March 2010, we entered into an undiluted crude oil supply agreement, which was renewed in March and May 2012 until November 2012. Pursuant to the terms of this agreement, in 2011 ODL paid us Ps$17.8 billion.

Oleoducto Bicentenario de Colombia S.A.S.

In November 2011, we signed a five-year technical assistance services contract for the construction of the Araguaney-Covenas pipeline. This contract is part of the project construction and the amount payable to us for the entire term of the agreement is approximately Ps$8.8 billion.

In November 2011, we entered into an operation and maintenance agreement for the Banadia unloading facility. Pursuant to the terms of the agreement, we receive monthly payments of approximately Ps$128.9 million plus applicable taxes. The duration of this agreement is 15 years.

Andean Chemicals Ltd.

In May 2009 we granted a loan to our subsidiary, Andean Chemicals Ltd., for the acquisition from Glencore International A.G. of its 51% interest in Reficar, in the amount of US$541 million for a five year term. The interest rate for each year is the fixed term deposit rate (DTF) applicable at December 31 of the previous year. In December 2011, we decided to capitalize this loan, for a total amount of US$615.7 million (capital and interest).

Compounding and Masterbatching Industry Ltda. - COMAI

In 2008 we entered into a contract with COMAI for the delivery of refinery grade propylene until January 2018. COMAI operates a splitter to separate refinery-grade propylene into polymer-grade propylene and propane. Refinery grade propylene is sold by COMAI to Propilco who uses it as raw material in the production of polypropylene, while propane is delivered back to us.

Other Agreements

We entered into a supply agreement with Ecodiesel Colombia S.A., or Ecodiesel, a company in which we have a 50% equity interest. This agreement has been operative since August 1, 2010. Pursuant to the terms of this agreement, Ecodiesel must deliver to us and we must purchase from Ecodiesel at least 80% of Ecodiesel’s biodiesel production each month. Payments vary depending on the purchased volumes of biodiesel. This agreement expires on December 31, 2017.

In 2010, we renewed the service agreement with Sociedad Colombiana de Servicios Portuarios S.A., or Serviport, a company in which we have a 44.76% equity interest. Pursuant to the terms of this agreement, Serviport assists us in our maritime operations in Coveñas port. This agreement expires on May 27, 2019.

Transactions with other state-controlled entities

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

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

· selling and purchasing goods,

· properties and other assets;

· rendering and receiving services;

· leasing assets;

· depositing and borrowing money; and

· using public utilities.

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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 Employees

We extend loans to all of our employees as part of our compensation scheme. We grant loans for housing and general purposes.  The Human Resources and Strategy vice-presidents along with the Compensation manager are part of the housing loans committee which is in charge of approving housing loans to employees.  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.

Other than maintaining housing loans to some executive officers, which were in place prior to the registration of our ADSs, since registering our ADSs, neither us nor any of our subsidiaries have provided loans (including housing loans), extended or maintained credit, arranged for the extension of credit, or renewed an extension of credit, in the form of a personal loan to or for any of our executive officers.  We have not materially modified any term of any such extension of credit or renewed any such extension of credit, in each case including the aforementioned housing loans, since our ADSs were registered.

In addition, other than the housing loans referred to below, neither us, nor any of our subsidiaries will provide loans (including housing loans), extend or maintain credit, arrange for the extension of credit, or renew an extension of credit, in the form of a personal loan to or for any of our executive officers in the future.  In addition, we will not materially modify any term of any such extension of credit or renew any such extension of credit, in each case including the aforementioned housing loans, in the future.

We do not extend loans to Directors.

The following table sets forth a description of the loans outstanding to our executive officers as of March 31, 2012.

	Nature of the	Principal	Amount	Largest Amount
	Loan and Date	Amount of	Outstanding at	Outstanding		Termination		Applicable
Executive Officer	of Disbursement	the Loan	March 31, 2012	during period		Date		Interest Rate
		(Pesos	(Pesos	(Pesos
		in millions)	in millions)	in millions)
Javier G. Gutiérrez	Housing, June 2008	729.0	593.1		729.0		June 2028		UVR(1)
Adriana M. Echeverri	Housing, June 2002	37.5	34.2		45.1		October 2018		UVR(1)
Pedro A. Rosales	Housing, April 1997 and September 2003	279.2	152.8		247.5		September 2018		UVR(1)
Oscar Villadiego (2)	Housing, January 2001	78.0	8.1		78.0		January 2016		UVR(1)

(1) As the regulatory entity for these purposes, the Central Bank of Colombia (Banco de la República) defines the term “UVR” as Unidad de Valor Real (Real Value Unit), an accounting unit which reflects purchasing power based exclusively on the consumer price index variation certified by the National Statistics Department of Colombia (DANE). The UVR is used to calculate the cost of housing credits in Colombia. This accounting unit allows financial entities to adjust credit values to the cost of living increase in Colombia.

(2) Oscar Villadiego became an executive officer in March 2012 as a consequence of the reorganization of our senior management’s structure approved by our Board of Directors. See “Item 6. Directors, Senior Management and Employees–Officers and Senior Management of Ecopetrol.”

ITEM 8. Financial Information

CONSOLIDATED STATEMENTS AND OTHER FINANCIAL INFORMATION

Our Annual Consolidated Financial Statements are filed as part of this annual report starting on page F-1.

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LEGAL PROCEEDINGS

We are party to various legal proceedings in the ordinary course of business.  Other than as disclosed in this annual report, we are not currently involved in any litigation or arbitration proceeding, including any proceeding that is pending or threatened of which we are aware, which we believe will have a material adverse effect on our Company.  Other legal proceedings that are pending against or involve us and our subsidiaries are incidental to the conduct of our and their business.  We believe that the ultimate disposition of such other proceedings individually or in an aggregate basis will not have a material adverse effect on our consolidated financial condition or results of operations.

As of December 31, 2011, we were a party to 2,697 legal proceedings relating to civil, administrative, environmental, tax and labor claims filed against us in the Colombian courts and arbitration tribunals of which 784 had an accrual provision.  We allocate substantial amounts of money and time to defend these claims.  Historically, we have been successful in defending lawsuits 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.  See Note 31 to our annual consolidated financial statements included in this annual report for a discussion of our legal proceedings.

In December 2010, Llanos Oil Exploration Ltd., or Llanos Oil, filed a lawsuit against us in a district court of the Netherlands, which if decided against us, could materially affect our financial condition. The written summons of Ecopetrol and Llanos Oil have been presented and the Court is studying them in order to render judgment. In principle the Court should render judgment on April but it can defer its decision. This claim is being heard by the Court of Hague. The complaint alleges early termination by us of the following exploration activity contracts:  the 1997 Las Nieves Association Contract and the 2002 Guatapuri Association Contract.  These contracts were terminated because of the default by Llanos Oil on July 28, 2000, and July 23, 2003, respectively, in accordance with the provisions of the contracts.  We have not created a provision for this claim because our legal counsel in The Hague considers there to be a remote probability of success for Llanos Oil.

On April 16, 2012, we were served with a class action suit against us seeking monetary damages of approximately Ps$85,936 billion related to the Caño Limon – Coveñas crude oil pipeline spill. Based on a preliminary analysis, we believe that the amount of money damages claimed is reckless. The Attorney General´s Office filed a motion requesting the judge to require the claimant to justify the amount. However, we are still in the process of evaluating the merits of this claim and whether the ultimate outcome is likely to have a material adverse effect on our financial position or results of operations.  See “Item 4.  Information on the Company—Transportation Infrastructure—Incidents at Transportation Facilities.”

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 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.  Based on the judge’s conclusion with respect to our accounting and the expert testimony of a witness presented by the plaintiffs who we maintain 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 appealed the decision by the first instance judge to the Bogota Higher Tribunal and on June 22, 2011, the court ruled in our favor and reduced the amount we must pay to Ps$6.6 million, or approximately US$3,707.

As of the date of this annual report, we have not received notice but are aware that the plaintiffs have filed an extraordinary appeal with the Colombian Supreme Court of Justice requesting the review of the judgment issued by the Bogota Higher Tribunal. Our legal counsel is of the view that the appeal has a remote possibility of success based on the judgment issued by the Bogota Higher Tribunal.

DIVIDENDS

We do not have a dividend policy. Pursuant to Colombian law, we may distribute dividends to our shareholders. Our Board of Directors may propose a dividend, which declaration, amount and payment per share is subject to approval by a simple majority of the shareholders. In 2009, 2010 and 2011 the shareholders approved the distribution of 76.6%, 71.8%, and 70.3% of 2008, 2009 and 2010 of net income, respectively. On March 22, 2012, our shareholders at the ordinary general shareholders’ meeting approved an ordinary dividend of 70% plus an extraordinary dividend of 9.85% of net income for the fiscal year ended December 31, 2011. See “Item 5. Operating and Financial Review and Prospects —Liquidity and Capital Resources—Use of Funds— Dividends.”

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SIGNIFICANT CHANGES

There have not been any significant changes since the date of our Annual Consolidated Financial Statements for the year ended December 31, 2011.

ITEM 9. The Offer and Listing

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 Colombian Stock Exchange (Bolsa de Valores de Colombia), or BVC, under the symbol, “ECOPETROL.” Our American Depositary Shares, or ADSs, representing 20 common shares, have been traded on the NYSE under the symbol “EC” since September 2008. JPMorgan Chase Bank, N.A. serves as depositary for our ADSs.

In December 2009, our ADSs were listed on the Lima Stock Exchange under the symbol “EC.” Since March 16, 2011, our ADSs were delisted from the Lima Stock Exchange.

Since August 2010, our ADSs have been traded on the Toronto Stock Exchange under the symbol “ECP.”

The second round of the equity offering program took place between July 27 and August 17, 2011. The offer was directed exclusively to investors in Colombia. A total of 644,185,868 shares were allotted, equivalent to approximately Ps$2.38 trillion. Out of the 219,054 investors participating in this round, 73% were new stockholders. In addition, 87% of the offering was allocated to retail investors and the remaining 13% to institutional investors. Funds obtained by us through this offering were allocated to the company’s investment plan.

In the future, the Nation, as our controlling shareholder, may undertake projects, make decisions or announcements about its intentions related to its holding of our capital stock. We intend to coordinate with the Nation the process by which it may sell part of its interest in us.

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 the BVC
	Pesos per share				U.S. dollars per share(1)				Average number of
									shares traded
	High		Low		High		Low		per day
2007		2,080		1,400		1.0187		0.6701		19,706,337
2008		2,895		1,575		1.6638		0.7647		21,063,806
2009		2,815		1,990		1.4707		0.7833		10,245,002
2010		4,660		2,370		2.5582		1.1958		8,764,023
2011		4,300		3,575		2.2823		1.9466		6,750,979
Most recent quarters
First quarter 2010		2,710		2,370		1.4313		1.1958		7,013,937
Second quarter 2010		2,790		2,630		1.4634		1.3035		6,314,608
Third quarter 2010		3,370		2,725		2.0910		1.4296		9,924,828
Fourth quarter 2010		4,660		3,725		2.5582		1.9904		11,953,966
First quarter 2011		4,060		3,750		2.1774		1.9805		5,983,470
Second quarter 2011		4,045		3,605		2.2823		1.9964		5,769,997
Third quarter 2011		4,135		3,575		2.2689		1.9967		8,029,866
Fourth quarter 2011		4,300		3,755		2.2342		1.9466		7,105,117
First quarter 2012		5,480		4,200		3.0963		2.1619		11,929,722
Most recent six months
October 2011		4,065		3,755		2.1768		1.9466		7,859,383
November 2011		4,100		3,860		2.1406		2.0048		6,546,500
December 2011		4,300		4,085		2.2342		2.1097		6,943,754
January 2012		4,605		4,200		2.5343		2.1619		11,342,508
February 2012		5,210		4,625		2.9471		2.5609		13,773,470
March 2012		5,480		5,120		3.0963		2.9057		10,756,995
April 2012 through April 26		5,680		5,260		3.2044		2.9616		10,538,122

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

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

	ADSs Traded on NYSE
	U.S. dollars per ADS(1)				Average number of ADSs
	High		Low		traded per day
2008		27.25		15.04		42,074
2009		29.99		15.31		48,289
2010		51.92		23.60		163,749
2011		46.00		38.47		357,289
Most recent quarters
First quarter 2010		28.73		23.60		64,272
Second quarter 2010		29.58		26.00		65,182
Third quarter 2010		42.36		28.84		216,042
Fourth quarter 2010		51.92		40.17		315,881
First quarter 2011		43.81		39.54		289,293
Second quarter 2011		46.00		39.66		337,737
Third quarter 2011		45.53		39.31		469,033
Fourth quarter 2011		44.70		38.47		327,033
First quarter 2012		61.86		44.52		522,679

	ADSs Traded on NYSE
	U.S. dollars per ADS(1)				Average number of shares
	High		Low		traded per day
Most recent six months
October 2011		44.02		38.47		393,851
November 2011		42.92		39.93		267,933
December 2011		44.70		42.37		322,353
January 2012		51.07		44.52		382,924
February 2012		58.19		51.28		599,059
March 2012		61.86		58.05		589,526
April 2012 (through April 26)		64.40		59.35		664,578

(1) Each ADS represents the right to receive 20 of our common shares.

TRADING ON THE BOLSA DE VALORES DE COLOMBIA

The BVC is the largest stock exchange in Colombia for trading securities and derivatives. The BVC is a member of the World Federation of Exchanges and the Federaci6n Iberoamericana de Bolsas.

The BVC is the only exchange where our common shares trade in Colombia. The table below sets forth the reported aggregate market capitalization of the BVC, as of December 31, 2011.

	Aggregate Market Capitalization of the BVC
	Market Capitalization		Market Capitalization
	(Ps$ in billions)		(US$ in billions)(1)
December 31, 2011		404,040		207,979

(1) Representative Market Rate at December 31, 2011.

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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 Superintendency 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 an existing shareholder or group of shareholders beneficially owning 25% or more of the outstanding capital stock of a listed company, must be made pursuant to a public tender offer.

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 and 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 material 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 that 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, safeguard 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

BYLAWS

The following is a summary of the material provisions of our bylaws.  The last amendment of our bylaws was approved on March 24, 2011, by the shareholders.  This description does not purport to be complete and is qualified by reference to our bylaws, which are filed as an exhibit to this annual report.  For a description of the provisions of our bylaws relating to our Board of Directors and its committees, see “Item 6. Directors, Senior Management and Employees.”

Organization and Register

Ecopetrol was organized on August 25, 1951, existing under the laws of Colombia.  Since November 13, 2007, Ecopetrol has been a mixed economy company.  We are registered in the Chamber of Commerce of Bogota (Cámara de Comercio de Bogota) under registry number 899.999.068-1.

Corporate Purpose

Pursuant to Article 4 of our bylaws, we may engage in the exploration, production, refining, transportation, storage, distribution and commercialization of crude oil and its by-products in Colombia and abroad, and to support, promote and manage democratization programs and sales of its equity in accordance with applicable norms.  Our bylaws also authorize 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 National Hydrocarbon Agency (Agencia Nacional de Hidrocarburos), or 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, blend, 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.

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Additionally, pursuant to Article 5 of our bylaws, we may enter into all acts, contracts and legal business and activities that may be required for us to adequately fulfill our corporate purpose.

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 on the decisions of the general shareholders meeting;

· to receive dividends based on the financial performance of the Company in proportion to their share ownership;

· to transfer and sell shares according to our bylaws and Colombian law;

· to inspect corporate books and records 15 business days prior to the ordinary shareholders’ meeting 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 bylaws 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 subscription of the declaration of the Nation dated July 26, 2007 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 bylaws 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 minority shareholders’ right to select a candidate loses its effect when minority shareholders, according to their share participation, name a member to our Board of Directors.

· Extraordinary Meetings.  Our bylaws and corporate governance code provide that the entity exercising permanent control over Ecopetrol must instruct the Company’s CEO or External Auditor to call an extraordinary meeting of the Company’s shareholders when so requested by a or plurality of shareholders holding at least 5% of the total number of shares outstanding.  Such requests shall be made in writing and must clearly indicate the purpose of the meeting.

· Office for the Attention of Shareholders.  Ecopetrol has an office for the attention of shareholders, our specialized unit responsible for receiving complaints from our shareholders.  Pursuant to our bylaws, shareholders holding at least 5% of the total number of shares outstanding may request that the office for the attention of shareholders conduct 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.

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· Others.  Pursuant to our bylaws, 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 bylaws. The general shareholders’ meeting has full and exclusive authority to modify or amend our bylaws.

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 on 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 bylaws 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 ordinary and extraordinary 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) exceeds 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) includes other information specified by the applicable law.  Proxies granted abroad do not require legalization or an apostille.

During our ordinary annual shareholders’ meeting, our employees and Directors are only allowed to represent their own shares, unless they act as legal representatives.

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Limitations to the Rights to Hold Securities

There are no limitations in our bylaws 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, except in cases of legal representation.

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

Under Colombian law and our bylaws, the general shareholders’ meeting has full 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.

Ownership Threshold Requiring Public Disclosure

Our corporate governance code provides that we must disclose periodically on our web page, the names of the shareholders of our Company, indicating at least, the 20 shareholders with the greatest 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 bylaws 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. The Government has noted its intention to make a proposal to the Colombian Congress that would allow the Nation to hold 70% of the capital stock of the Company. We do not know whether the Government will make such a proposal or if Congress will approve any such law.

External Auditor

Pursuant to our bylaws as amended on March 24, 2011, our external auditor shall not be appointed for more than five consecutive terms by Ecopetrol S.A. or its subsidiaries. However, an external auditor may be hired again after two terms have passed since the conclusion of its last term of appointment.  At the ordinary general shareholders’ meeting on March 24, 2011, the shareholders appointed KPMG Ltda. as external auditor of Ecopetrol and its subsidiaries and reappointed it at the ordinary general shareholders’ meeting on March 22, 2012.

MATERIAL CONTRACTS

Transportation Agreement between Ecopetrol and Empresa Colombiana de Gas ESP/Transportadora de Gas del Interior S.A. ESP

On October 6, 2006, we entered into a natural gas transportation agreement with Empresa Colombiana de Gas ESP, or Ecogas, for the transportation of natural gas from the Ballena terminal located in the La Guajira fields to the Barrancabermeja terminal. The agreement was amended as of October 2008 in order to increase contracted capacity and is set to expire in November 30, 2012. Pursuant to the terms of the agreement, Ecogas will transport natural gas produced by us upon our request, up to the available capacity set forth in the agreement. According to the agreement, Ecogas 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 our transportation capacity to 134,066 thousand cfpd. Once Ecogas executes the second expansion to 262,000 thousand cfpd we will have transportation availability of up to 175,000 thousand cfpd. On the other hand, on October 1, 2008 we entered into another agreement to supply the demand for natural gas of the Barancabermeja Refinery. This  agreement will be in force  from December 1, 2012 to December 31, 2020.

In February 27, 2007, Ecogas transferred the rights and obligations under this agreement to Transportadora de Gas del Interior S.A. ESP, currently operating as Transportadora de Gas Internacional S.A. ESP, or TGI. On October 1, 2008, Ecopetrol and TGI signed a new natural gas transportation agreement for the transportation of 116,500 thousand cfpd from December 2012 to 2020 of natural gas from the Ballena terminal located in the La Guajira fields to Barrancabermeja.

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Pursuant to the terms of the 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 2011, we paid Ps$143,345 million for the transportation services provided to us by TGI.

Transportation Agreement between Ecopetrol and Ocensa

On March 31, 1995, we entered into a crude oil transportation agreement with Ocensa. See “Item 7. Major Shareholders and Related Party Transactions—Related Party Transactions—Agreements—Ocensa.”

Reficar

On December 30, 2011, we entered into a construction support agreement pursuant to which we agreed to support Reficar’s costs and expenses related to overcost and delays in construction. The project financing contract and the related guarantee are described in “Item 5. Operating and Financial Review and Prospects—Liquidity and Capital Resources.”

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 American Depositary Receipts, or 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, administrators and others).

Foreign capital investments must be made through an authorized foreign exchange asset manager. Only brokerage firms, trusts and asset managers subject to the inspection and supervision of the Superintendency of Finance will be allowed to make investments in the local Colombian market on behalf of foreign capital investors.

Colombian law provides that the Colombian Central Bank may intervene in the foreign exchange market at its own discretion at any time. Likewise, from time to time, the Colombian government introduces 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 required 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. Nevertheless, from June 29, 2007, to October 8, 2008, when the Colombian government issued Decree 2466 of 2007 and Decree 3913 respectively, setting forth that portfolio investments made pursuant to ADR programs were exempt from the deposit requirement, ADRs were not affected by the requirement of Decree 1801 of 2007. As a result, neither Ecopetrol nor the purchasers of ADRs had to comply with the 40% deposit requirement. See “Item 3. Key Information—Risk Factors—Risks relating to our ADSs.”

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. We cannot assure you that the Colombian Central Bank will not intervene in the future. However, since the creation of the current foreign exchange regime in 1991, the Colombian Central Bank has never taken such action. See “Item 3. Key Information—Risk Factors—Risks Relating to Colombia’s political and regional environment.”

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. Additionally, pertinent information must be updated yearly.

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.

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Foreign investors who acquire ADRs are not required to register to Colombian authorities. 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 must register their investment in the common shares as a foreign direct investment, provided that the investor wishes to maintain ownership of the shares on a permanent basis. If the investor wishes to maintain ownership of the shares only for speculative purpose, that is, as a portfolio investment, no further registration is required. Non-Colombian residents cannot directly hold portfolio investments in Colombia, but are able to do so through an “administrator,” such as a stock broker, trust company or an investment management company, duly authorized by Colombian Superintendency of Finance.

In obtaining its own foreign investment registration, an investor who surrenders its ADRs and withdraws 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 dividends abroad or profits arising from distributions relating to our common shares must be 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.

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 American Depositary Shares, or ADSs, in a foreign securities market. This description is based on the applicable law in effect as of the date of this annual report. 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 us 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 us which would be subject to income tax at the 33% rate.

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

Taxation on Capital Gains for the sale of ADRs

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

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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 us to shareholders not resident in Colombia, will be exempted from income, withholding and remittance taxes. This exception would not apply in the case of distributions paid out of non-taxed earnings made by us 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 Colombian Stock Exchange (Bolsa de Valores de Colombia), or 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 the BVC market and exchange them for ADRs

Dividends

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

U.S. Federal Income Tax Consequences

This summary describes the principal U.S. federal income tax consequences of the ownership and disposition of common shares or ADSs, but it does not purport to be a comprehensive description of all of the U.S. tax consequences that may be relevant to a decision to hold or dispose of common shares or ADSs. This summary applies only to purchasers of common shares or ADSs who will hold the common shares or ADSs as capital assets and does not apply to special classes of holders such as dealers in securities or currencies, holders whose functional currency is not the U.S. dollar, holders of ten percent or more of our shares (taking into account shares held directly or through depositary arrangements), tax-exempt organizations, financial institutions, holders liable for the alternative minimum tax, securities traders who elect to account for their investment in common shares or ADSs on a mark-to-market basis, partnerships or other pass-through entities, insurance companies, U.S. expatriates, and persons holding common shares or ADSs in a hedging transaction or as part of a straddle, conversion or other integrated transaction for U.S. federal income tax purposes. The statements regarding U.S. tax law set forth in this summary are based on U.S. law as in force on the date of this annual report, and changes to such law subsequent to the date of this annual report may affect the tax consequences described herein (possibly with retroactive effect). This summary 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.

Each holder is encouraged to consult such holder’s tax advisor concerning the overall tax consequences to it, including the consequences under laws other than U.S. federal income tax laws, of an investment in common shares or ADSs.

In this discussion, references to a “U.S. Holder” are to a beneficial holder of a common share or an ADS (i) that is a citizen or resident of the United States of America, (ii) that is a corporation, or any other entity taxable as a corporation, organized under the laws of the United States of America, any state thereof or the District of Columbia, or (iii) that is otherwise subject to U.S. federal income taxation on a net basis with respect to the common shares or ADS.

For purposes of the U.S. Internal Revenue Code of 1986, as amended, which we call the “Code,” holders of ADSs will generally be treated as owners of the common shares represented by such ADSs.

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This discussion does not address U.S. federal estate and gift tax or the alternative minimum tax consequences of holding 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.

Distributions on Common Shares or ADSs

A distribution to U.S. Holders 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.

The amount of any distribution will include the amount of Colombian tax withheld on the amount distributed, and the amount of a distribution paid in Pesos will be measured by reference to the exchange rate for converting Pesos into U.S. dollars in effect on the date the distribution is received by the Depositary (or by a U.S. Holder in the case of a holder of common shares). If the Depositary (or U.S. Holder in the case of a holder of common shares) does not convert such Pesos into U.S. dollars on the date it receives them, it is possible that the U.S. Holder will recognize foreign currency loss or gain, which would be ordinary loss or gain, when the Pesos are converted into U.S. dollars. Dividends paid by us will not be eligible for the dividends received deduction allowed to corporations under the Code.

Subject to certain exceptions for short-term and hedged positions, the dividends received by an individual prior to January 1, 2013 with respect to the ADSs will be subject to taxation at a maximum rate of 15.0% if the dividends are “qualified dividends.” Dividends paid on the ADSs will be treated as qualified dividends if (i) the ADSs are readily tradable on an established securities market in the United States and (ii) we were not, in the year prior to the year in which the dividend was paid, and are not, in the year in which the dividend is paid, a passive foreign investment company (“PFIC”). The ADSs are listed on the New York Stock Exchange, and will qualify as readily tradable on an established securities market in the United States so long as they are so listed. Based on our audited financial statements and relevant market and shareholder data, we believe that we were not treated as a PFIC for U.S. federal income tax purposes with respect to our 2011 taxable year. In addition, based on our audited financial statements and our current expectations regarding the value and nature of our assets, the sources and nature of our income, and relevant market and shareholder data, we do not anticipate becoming a PFIC for the 2012 taxable year. Based on existing guidance, it is not clear whether dividends received with respect to the common shares will be treated as qualified dividends. In addition, the U.S. Treasury has announced its intention to promulgate rules pursuant to which holders of ADSs or common shares and intermediaries through whom such securities are held will be permitted to rely on certifications from issuers to treat dividends as qualified for tax reporting purposes. Because such procedures have not yet been issued, it is not clear whether we will be able to comply with them. Holders of ADSs and common shares should consult their own tax advisers regarding the availability of the reduced dividend tax rate in the light of the considerations discussed above and their own particular circumstances.

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 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 provided the U.S. Holder elects to deduct (rather than credit) all foreign income taxes for that year. 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 the purposes of the U.S. foreign tax credit limitations, the dividends paid with respect our common shares or ADSs should generally constitute “passive category income”. 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.

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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 or otherwise imposed 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 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 income 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.

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 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 timely filing a refund claim with the IRS.

U.S. Tax Considerations for Non-U.S. Holders

A holder or beneficial owner of common shares or ADSs that is not a U.S. Holder for U.S. federal income tax purposes (a “non-U.S. Holder”) generally will not be subject to U.S. federal income or withholding tax on dividends received on common shares or ADSs.

A non-U.S. Holder of common shares or ADSs will not be subject to U.S. federal income or withholding tax on gain realized on the sale of common shares or ADSs, unless, in the case of gain realized by an individual non-U.S. Holder, the non-U.S. Holder is present in the United States for 183 days or more in the taxable year of the sale and certain other conditions are met.

Although non-U.S. Holders generally are exempt from backup withholding, a non-U.S. Holder may be required to comply with certification and identification procedures in order to establish its exemption from information reporting and backup withholding.

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DOCUMENTS ON DISPLAY

We file reports, including annual reports on Form 20-F, and other information with the SEC pursuant to the rules and regulations of the SEC that apply to foreign private issuers. You may read and copy any materials filed with the SEC in the SEC’s public reference room at 100 F. Street, NE, Washington, D.C. 20549. Please call the SEC at 1-800-SEC-0330 for further information on the operation of the public reference room. Any filings we make are also available to the public over the Internet at the SEC’s website at www.sec.gov and at our website at www.ecopetrol.com.co. (This URL is intended to be an inactive textual reference only. It is not intended to be an active hyperlink to our website. The information on our website, which might be accessible through a hyperlink resulting from this URL, is not and shall not be deemed to be incorporated into this annual report.)

ITEM 11. Quantitative and Qualitative Disclosures About Market Risk

Risk Management and Financial Instruments

We are exposed to certain risks associated with the nature of our operations and the financial instruments we use. Among those risks affecting our financial assets, liabilities and expected future cash flows are the changes in commodity prices, currency exchange rates and interest rates.

Commodity price risk is associated with our day-to-day operations as we export and import crude oil, natural gas, and refined products. We control our exposure to commodity price volatility using the “cash flow at risk” methodology, which provides an estimation of the impact that price fluctuations have over the liquidity of the company. When necessary, we use derivative financial instruments such as options and swaps to hedge our exposure to volatility in commodity prices. We do not use derivative financial instruments for speculative or profit-generating purposes.

Currency risk is associated with the fact that 60% of our income is denominated in U.S. dollars and only 35% of our expenses are denominated in U.S. dollars, whereas our income and expenses denominated in Colombian pesos are 35% and 60%, respectively. We control our currency risk using natural hedging when possible, by maintaining funds in U.S. dollars and Pesos to meet our expenses in its respective currency. However, the company has to sell U.S. dollars regularly in order to cover the currency mismatches that may arise. Derivative financial instruments such as forwards, futures and swaps are usually used when weaker or stronger Peso /U.S. dollar denominated obligations may affect the cash flow of the Company. In addition, the obligations derived from our U.S. dollar denominated debt are naturally hedged by our funds in the same currency. This situation partially mitigates any adverse effect that currency risk may have over the financial statements of the Company.

Interest rate risk arises from our exposure to changes in interest rates as we have floating-rate instruments in our investment portfolio and issuances of floating rate debt linked to DTF and IPC rates. Thus, volatility in interest rates may affect the fair value and cash flows related to our investments and floating rate debt. In 2011, credit risk events emerged constantly, with financial entities being downgraded or declaring restricted default. As a result, our analysis of the situation in the global financial markets resulted in the decision to not hedge the interest rate risk. Nevertheless, the treasury office continuously monitors the performance of interest rates and its impact on the financial statements of the Company. On the other hand, the exposure to interest rate risk of our fixed income portfolio is controlled through its effective duration. The limits allowed for the effective duration are between +/- 25% of the portfolio’s benchmark duration.

Investment Guidelines

Following Decree 2550 of 2008, our management established guidelines for our investment portfolios. In general terms, our guidelines determine that we must invest our excess cash in fixed-income securities issued by entities rated A+ or higher by a recognized rating agency.  We have no limitation to invest in securities issued or guaranteed by the U.S. government or the Colombian government. In our Peso-portfolio, we must invest in fixed-income securities of issuers rated AAA by a recognized rating agency, except securities issued or guaranteed by the Colombian government.

Our investment portfolio in U.S. dollars is segmented in four tranches, each one matching our liquidity needs.  The working capital tranch 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 expenditures related to projects. The asset liability tranche is built to match our off-balance sheet debt. The investment tranche includes the remaining amount of the total portfolio after deducting the amounts pertaining to the above mentioned tranches.

Our investment portfolio in Pesos is segmented in two tranches, each one matching our liquidity needs.  The first tranche is calculated taking into account our cash flow needs for the next 30 days, and the second tranche is built for investment purposes.

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Sensitivity Analysis

The following table provides information about our financial statements as of December 31, 2011that may be sensitive to changes in West Texas Intermediate, or WTI, prices and exchange rates:

							Difference						Difference
				Income			Between Real			Income			Between Real
	Income			Statement Case			2011 and Case			Statement Case			2011 and Case
	Statement 2011			WTI(1) + US$1			WTI			TRM(2) - 1%			TRM
	(Pesos in billions)
Local Revenue		23,339.38			23,572.02			232.63			23,162.29			(177.10	)
Export Revenue		42,412.89			42,474.54			61.66			42,047.09			(365.80	)
Total Revenue		65,752.27			65,965.47			294.29			65,209.37			(542.90	)
Cost of Sales		36,665.06			36,765.40			100.35			36,478.60			(186.45	)
Selling Operating Expenses		2,377.33			2,377.33			0.00			2,377.33			0.00
Administrative Operating Expenses		1,018.92			1,018.92			0.00			1,018.92			0.00
Operating Profit		25,690.96			25,884.90			193.94			25,334.52			(356.44	)
Non-Operating Income (Expenses)		(2,049.53	)		(2,049.53	)		0.00			(2,049.53	)		0.00
Profit before Income Tax		23,641.43			23,835.37			193.94			23,284.99			(356.44	)
Income Tax		(7,955.72	)		(8,022.36	)		(66.63	)		(7,837.79	)		117.93
Minority Interest		(233.38	)		(233.38	)		0.00			(233.38	)
Net Income		15,452.33			15,579.64			117.98			15,210.98			(238.51	)

 WTI= West Texas Intermediate.

(1) Average WTI for 2011 was US$95.14 for barrel.

(2) Average Market Representative Rate for 2011 was Ps$1,847 per US$1.00 on a calendar day basis.

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, Social and Environmental Activity or Income Statement, for 2011 as presented elsewhere in this annual report.

· The sensitivity of the WTI price index is the increase of one U.S. dollar per barrel of crude oil in the average WTI reference price based on a 365-day year for 2011. Prices assumed correspond to real prices for crude oil, natural gas and refined products for 2011, adjusted to account for the differences between such real prices and the WTI reference price.

· The sensitivity of our results to changes in the exchange rates is the 2.6% average appreciation of the Peso against dollar during 2011. Prices assumed correspond to real prices of crude oil, natural gas and refined products in 2011, proportionally adjusted to account for differences between such real prices and the monthly average exchange rate.

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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
Refined products	Refined products
Natural gas	Natural gas
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
Purchases of Natural gas	Purchases of Natural gas
Imports	Imports
Crude Oil	Crude Oil
Products	Products
NON-OPERATING INCOME
	Exchange income
	Exchange loss

ITEM 12. Description of Securities Other than Equity Securities

ITEM 12A. Debt Securities

Not applicable.

ITEM 12B. Warrants and Rights

Not applicable.

ITEM 12C. Other Securities

Not applicable.

ITEM 12D. American Depositary Shares

Fees and charges that a holder of our ADSs may have to pay, either directly or indirectly

JPMorgan Chase Bank, N.A., our Depositary, may charge each person to whom, American Depositary Shares, or 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 American Depositary Receipts, or 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, as 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 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.

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The following additional charges shall be incurred by ADS 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 us 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;

· a fee of up to US$0.02 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 the ADS holder’s 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.

Fees and other direct and indirect payments made by the Depositary to us

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.  In 2011, the Depositary made direct payments and reimbursements to us in the amount of approximately US$226,093.98 for expenses related to investor relations expenses.

ITEM 13. Defaults, Dividend Arrearages and Delinquencies

None.

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

None.

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ITEM 15. Controls and Procedures

Disclosure Controls and Procedures

As required by Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as of December 31, 2011, we evaluated the design and effectiveness of our financial disclosure controls and procedures under the supervision and participation of our management, including our Chief Executive Officer and Chief Financial Officer. There are inherent limitations to the effectiveness of any system of disclosure controls and procedures, including the possibility of human error and the circumvention or overriding of the controls and procedures. Accordingly, even if effective, disclosure controls and procedures can only provide reasonable assurance of achieving their control objectives.

Based upon this evaluation, our Chief Executive Officer and Chief Financial Officer concluded that as of the end of the period covered by this annual report, our disclosure controls and procedures were effective to provide reasonable assurance that the information required to be disclosed in the reports that we file and submit under the Securities Exchange Act of 1934 is recorded, summarized and reported as and when required and is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.

Management’s Annual Report on Internal Control over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15(d)-15(f) under the Securities Exchange Act of 1934. Our internal control over financial reporting is a process designed under the supervision of our Chief Executive Officer and Chief Financial Officer, and affected by our board of directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of our financial statements for external reporting purposes in accordance with generally accepted accounting principles, and it includes those policies and procedures that:

· pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect transactions and dispositions of our assets;

· provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures are being made only in accordance with authorization of our management and directors; and

· provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on our financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Therefore, effective control over financial reporting cannot, and does not, provide absolute assurance of achieving our control objectives. Also, projection of any evaluation of the effectiveness of the internal controls to future periods is subject to the risk that controls may become inadequate because of changes in conditions or that the degree of compliance with the policies or procedures may deteriorate.

As of the year ended December 31, 2011, our management conducted an assessment of the effectiveness of our internal control over financial reporting in accordance with the criteria established in the publication “Internal Control – Integrated Framework”, issued by the Treadway Commission’s Committee of Sponsoring Organizations (COSO), as well as the rules prescribed by the SEC in its Final Rule “Management’s Report on Internal Control Over Financial Reporting and Certification of Disclosure in Exchange Act Periodic Reports.”

Based on the assessment performed, management concluded that our internal control over financial reporting was effective as of the end of the period covered by this annual report.

As discussed in Item 5 — “Effect of Acquisitions”, we acquired 51% ownership of Equion Energía Limited  (the “Acquired Company”). For purposes of evaluating internal controls over financial reporting, our management determined that the internal controls of the Acquired Company would be excluded from their internal control assessment as of December 31, 2011, because Equion Energía Limited was acquired in purchase business combinations during 2011. For the year ended December 31, 2011, Equion Energía Limited total assets represent 3.4% and total revenues represent 3.2% of the related consolidated financial statement amounts as of and for the year ended December 31, 2011, prepared in accordance with accounting principles generally accepted for Colombian Government Entities.

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The effectiveness of our internal control over financial reporting has been audited by KPMG Ltda., an independent registered public accounting firm, as stated in their audit report accompanying our consolidated financial statements.

Changes in Internal Control over Financial Reporting

There were no changes made in our internal control over financial reporting during the year ended December 31, 2011 that have materially affected or are reasonably likely to materially affect the Company’s internal controls over financial reporting.

Attestation Report of the Registered Public Accounting Firm

KPMG Ltda.’s attestation report on our internal control over financial reporting is included in their audit report accompanying our consolidated financial statements. See our consolidated financial statements.

ITEM 16. [Reserved]

ITEM 16A. Audit Committee Financial Expert

Our Board of Directors has determined that Roberto Steiner Sampedro qualifies as an “audit committee financial expert,” and he is independent under the definition of “independent” applicable to us under the rules of the NYSE (17 CFR 240.10A-3). See “Item 6. Directors, Senior Management and Employees—Audit Committee.”

ITEM 16B. Code of Ethics

We have adopted a code of ethics within the meaning of this Item 16B of Form 20-F, which complies with applicable U.S. and Colombian law.  Our code of ethics applies to our chief executive officer, chief financial officer, principal accounting officer, persons performing similar functions and other personnel.  Our code of ethics is available on our website at http://www.ecopetrol.com.co/english/especiales/Ethics_Code2010_English/index_eng.html.  If we amend the provisions of our code of ethics that apply to our chief executive officer, our chief financial officer, our principal accounting officer and persons performing similar functions, or if we grant any waiver of such provisions, we will disclose such amendment or waiver on our website at the same address.

ITEM 16C. Principal Accountant Fees and Services

Audit and Non-Audit Fees

Our consolidated financial statements for fiscal years ended December 31, 2011 was audited by KPMG Ltda. and December 31, 2010 were audited by PricewaterhouseCoopers. The following table sets forth the fees billed to us by KPMG and PricewaterhouseCoopers during the fiscal years ended December 31, 2011 and 2010, respectively:

	At December 31,
	2011		2010
	(in millions of pesos, excluding 16% value added tax)
Audit fees		5,411		6,021
Audit-related fees		1,013		792
Tax Fees		287		-
All Other fees(1)		1,553		-
Total		8,264		6,813

(1) Provision of advice that helps Ecopetrol develop its documents, procedures and policies related to Business Continuity Planning in certain areas of the organization.

Audit Fees. The audit fees listed in the table above are the aggregated fees billed by KPMG and PricewaterhouseCoopers in connection with its audits of our annual consolidated financial statements (under Colombian Government Entity GAAP and U.S. GAAP), interim consolidated financial statements (under Colombian Government Entity GAAP), subsidiary audits (under local GAAP) and review of periodic documents filed with the SEC. In addition, these audit fees include fees related to our independent auditors’ audits of our internal controls over financial reporting.

Audit-related Fees. The audit–related fees listed in the table above are the fees billed by KPMG and PricewaterhouseCoopers in connection with their agreed-upon procedures of our variable compensation bonus system.

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Tax Fee.The tax fees listed in the table above correspond to (i) assisting some subsidiaries in the preparation and filing of appropriate tax returns with the tax authorities (including electronic filings), (ii) advising some subsidiaries about the tax consequences associated with new or proposed legislation and (iii) rendering advice to some subsidiaries on the likely tax consequences of proposed transactions and the appropriate methods of structuring and reporting.

Audit Committee Approval Policies and Procedures

Our audit committee has not established pre-approval policies and procedures for the engagement of our independent auditors for services. Our audit committee expressly approves on a case-by-case basis any engagement of our independent auditors for audit and non-audit services provided to us.

ITEM 16D. Exemptions from the Listing Standards for Audit Committees

Not applicable.

ITEM 16E. Purchases of Equity Securities by the Issuer and Affiliated Purchasers

None.

ITEM 16F. Change in Registrant’s Certifying Accountant

At the ordinary shareholders’ meeting held on March 24, 2011, the shareholders approved the appointment of KPMG Ltda., as recommended by the Company’s Audit Committee as the new independent registered public accounting firm to replace PricewaterhouseCoopers Ltda., as previously reported in the Company’s annual report on Form 20-F for the fiscal year ended December 31, 2010 as amended.

During the Company’s two most recent fiscal years ended December 31, 2010 and 2009 and subsequent interim periods through May 2, 2011, there were no disagreements with PricewaterhouseCoopers Ltda. on any matter of accounting principles or practices, financial statement disclosure, or auditing scope or procedure, which disagreements if not resolved to the satisfaction of PricewaterhouseCoopers Ltda. would have caused them to make reference thereto in their reports on the consolidated financial statements for such periods.

During the Company’s two most recent fiscal years ended December 31, 2011 and 2010 and the subsequent periods through May 2, 2011, there have been no reportable events (as defined in Item 304(a)(1)(v)) of Regulation S-K).

We have not previously consulted with KPMG Ltda regarding either (i) the application of accounting principles to a specific completed or contemplated transaction; (ii) the type of audit opinion that might be rendered on our financial statements; or (iii) a reportable event (as provided in Item 304(a)(1)(v) of Regulation S-K) during the years ended December 31, 2010 and 2009, or any later interim period, including the interim period up to and including the date the relationship with Pricewaterhouse ceased. KPMG Ltda has reviewed the disclosure required by Item 304(a) of Regulation S-K before it was filed with the SEC and has been provided an opportunity to furnish the SEC with a letter addressed to the SEC containing any new information, clarification of the expression of our views, or the respects in which it does not agree with the statements made by us in response to Item 304(a) of Regulation S-K. KPMG Ltda did not furnish a letter to the SEC.

ITEM 16G. Corporate Governance

Pursuant to the requirements of Section 303A.11 of the NYSE’s Listed Company Manual, the following is a summary of the significant differences between our corporate governance practices and those required for U.S. companies under the NYSE listing standards.

116

The following discloses the significant differences between our corporate governance practices and the NYSE standards.

NYSE Standards	Our Corporate Governance Practices
Director Independence
The majority of board of directors must be independent. §303A.01. “Controlled companies,” which would include Ecopetrol if we were a U.S. issuer, are exempt from this requirement. A controlled company is one in which more than 50% of the voting power is held by an individual, group or another company, rather than the public. §303A.00.	Law No. 964/2005 establishes that (i) the board of directors of listed companies must be comprised of a minimum of five directors and a maximum of ten directors and (ii) at least 25% of board members must be independent.  Under our corporate governance guidelines, our board of directors must be comprised of nine directors, of which at least three must be independent.  As of the date of this annual report, we have five (5) independent directors.
Executive Sessions
The non-management directors of each listed company must meet at regularly scheduled executive sessions without management. §303A.03.	A comparable rule does not exist under Colombian law.  Except for our Audit Committee, our Board of Directors does not meet without management.
Nominating/Corporate Governance and Sustainability Committee
A nominating/corporate governance and sustainability committee composed entirely of independent directors is required. The committee must have a charter specifying the purpose, duties and evaluation procedures of the committee. §303A.04. “Controlled companies” are exempt from these requirements. §303A.00.	Colombian law does not require the establishment of a nominating and corporate governance and sustainability committee composed entirely of independent directors.  Pursuant to our bylaws, both our corporate governance and sustainability committee, and our nomination and compensation committee shall be composed of at least one independent director which acts pursuant to a written charter.
Compensation Committee
A compensation committee composed entirely of independent directors is required, which must evaluate and approve executive officer compensation. The committee must have a charter specifying the purpose, duties and evaluation procedures of the committee. §303A.05. “Controlled companies” are exempt from this requirement. §303A.00.	Colombian law does not require the establishment of a compensation committee composed entirely of independent directors.  Pursuant to our bylaws, our nomination and compensation committee shall be composed of at least one independent director which acts pursuant to a written charter.
Audit Committee
An audit committee with a minimum of three independent directors satisfying the independence and other requirements of Rule 10A-3 under the Exchange Act and the more stringent requirements under the NYSE standards is required. §303A.06, §303A.07.	According to Law No. 964/2005, Colombian companies that are authorized to issue securities by the Superintendency of Finance must have an audit committee that satisfies the requirements of Law No. 964/2005, including its minimum number of members, independence criteria and audit related duties.  Our audit committee is composed by Joaquín Moreno Uribe, Amilcar Acosta Medina, Roberto Steiner Sampedro and Luis Carlos Villegas Echeverri, all of whom are independent directors, and the committee meets the requirements of Law No. 964/2005 and Rule 10A 3 under the Exchange Act.
Equity Compensation Plans
Equity compensation plans and all material revisions thereto require shareholder approval, subject to limited exemptions. §§303A.08 and 312.03.	Under Colombian law, no similar right to vote on equity compensation plans and material revisions thereto is given to shareholders.  We do not give our shareholders the right to vote on equity compensation plans and material revisions thereto.

117

Corporate Governance Guidelines
Listed companies must adopt and disclose corporate governance guidelines. §303A.09.	The Superintendency of Finance does recommend the adoption of corporate governance guidelines.  However, according to Superintendency of Finance Circular No. 007/2011, the adoption of corporate governance guidelines is voluntary.  Listed companies must annually publish a corporate governance survey comparing their corporate governance standards with those recommended by the Superintendency of Finance.  Our corporate governance guidelines (Code of Good Corporate Governance) are listed on our website at http://www.ecopetrol.com.co.
Code of Ethics for Directors, Officers and Employees
Corporate governance guidelines and a code of business conduct and ethics is required, with disclosure of any waiver for directors or executive officers. The code must contain compliance standards and procedures that will facilitate the effective operation of the code. §303A.10.	We have adopted a code of ethics which complies with applicable U.S. and Colombian law.  Our code of ethics applies to our chief executive officer, chief financial officer, principal accounting officer, persons performing similar functions and generally to all the employees, members of the board of directors, suppliers, and contractors of Ecopetrol S.A. and its corporate group.  Our code of ethics is available on our website at: http://www.ecopetrol.com.co/english/especiales /Ethics_Code2010_English/index_eng.html

ITEM 16H. Mine Safety Disclosure

Not applicable.

ITEM 17. Financial Statements

Not applicable.

ITEM 18. Financial Statements

See our audited consolidated financial statements beginning on page F-1, incorporated herein by reference.

118

ITEM 19.    Exhibits

Exhibit No.	Description
1.1	Bylaws of Ecopetrol S.A. dated November 6, 2007 as recorded under Public Deed No. 5314 of November 14, 2007 (incorporated by reference to Exhibit 1.1 on Form 20-F filed with the U.S. Securities and Exchange Commission on September 12, 2008 (File No. 001-34175)).
1.2	Amended and Restated Bylaws of Ecopetrol S.A., dated March 24, 2011, as recorded under Public Deed No. 560 of May 23, 2011(incorporated by reference to Exhibit 1.2 on Form 20-F filed with the U.S. Securities and Exchange Commission on July 15, 2011 (File No. 001-34175)).
4.1	Transportation Agreement between Ecopetrol S.A. and Oleoducto Central S.A., dated March 31, 1995 (incorporated by reference to Exhibit 4.1 on Form 20-F filed with the U.S. Securities and Exchange Commission on September 12, 2008 (File No. 001-34175)).
4.2	Natural Gas Transportation Agreement between Ecopetrol S.A. and Empresa Colombiana de Gas-Ecogas, dated October 6, 2006 (incorporated by reference to Exhibit 4.2 on Form 20-F filed with the U.S. Securities and Exchange Commission on September 12, 2008 (File No. 001-34175)).
4.3	Indenture, dated as of July 23, 2009, between the Company and The Bank of New York Mellon, as trustee (incorporated by reference to Exhibit 4.2 to the Company’s Form F-4 filed with the U.S. Securities and Exchange Commission on July 31, 2009 (File No. 333-160965)).
8.1	List of subsidiaries of Ecopetrol S.A.
12.1	Section 302 Certification of the Chief Executive Officer.
12.2	Section 302 Certification of the Chief Financial Officer.
13.1	Section 906 Officer Certification.
15.1	Consent of KPMG Ltda.
15.2	Consent of PricewaterhouseCoopers Ltda.
15.3	Consent of Ryder Scott.
15.4	Consent of Gaffney, Cline & Associates.
15.5	Consent of DeGolyer and MacNaughton.
99.1	Third Party Reserve Report of Ryder Scott.
99.2	Third Party Reserve Report of Gaffney, Cline & Associates.
99.3	Third Party Reserve Report of DeGolyer and MacNaughton.

The amount of long-term debt securities of Ecopetrol authorized under any given instrument does not exceed 10% of its total assets on a consolidated basis. Ecopetrol hereby agrees to furnish to the SEC, upon its request, a copy of any instrument defining the rights of holders of its long-term debt or of its subsidiaries for which consolidated or unconsolidated financial statements are required to be filed.

119

ANNEX I
DESCRIPTION OF EXPLORATION AND PRODUCTION CONTRACTS

Region	Contract Name	Type of Agreement	Purpose	Operator	Partners	Ownership Percentage	Partnership Percentage	Term of Contract	Expiration Date	Right of Reversion Upon Termination	Royalty
Southern	Abanico	Joint Venture	E&P	Pacific Stratuss Energy	Pacific Stratuss Energy	50%	Pacific Stratus Energy 50%	28 years	October 10, 2024	Yes	5% to 25%
Minor Fields	Alcaravan	Joint Venture- Sole Risk	E&P	Colombia Energy Development Co.	Colombia Energy Development Co.	0%	Colombia Energy Development Co. 100%	28 years	February 13, 2021	Yes	20% - 5%
	Alcaravan	Joint Venture				50%	Colombia Energy Development Co. 50%				20% - 8%
Minor Fields	Arjona	Discovered Undeveloped Field	CDND/I	Vetra- Suroco Consortium	Vet ra- Suroco Consortium	40%	Consorcio Vetra - Suroco 60% Volumen A (Escalonada)	10 years	March 9, 2017	Yes	8% to 25%
Southern	Ambrosia	Joint Venture	E&P	Interoil	Interoil	30%	Interoil Colombia E&P 70%	25 years	December 27, 2027	Yes	8% to 25%
Minor Fields	Barranca Lebrija	Discovered Undeveloped Field	CDND/I	Union Temporal Mocam SAS	Union Temporal Mocam SAS (ASER INGENIERIA ING S.A., CONEQUIPOS ING LTDA. MOVE S.A. Y MONTECZ S.A.)	19%	Unión Temporal Mocam S.A.S. 81%	10 years	December 29, 2013	Yes	20%
Minor Fields	Bocachico	Joint Venture- Sole Risk	E&P	Colombia Energy Development Co.( antes Harken)	Colombia Energy Development Co.( antes Harken)	0%	Colombia Energy Development Co. 100%	28 years	March 7, 2022	Yes	20%
Minor Fields	Bolivar	Joint Venture- Sole Risk	E&P	Colombia Energy Development Co.( antes Harken)	Colombia Energy Development Co.( antes Harken)	0%	Colombia Energy Development Co. 100%	28 years	June 12, 2024	Yes	20%
Minor Fields	Camoa	Discovered Undeveloped Field	CDND/I	Drilling and Workover Services Ltda.	Drilling and Workover Services Ltda.	20%	Drilling and Workover Services Ltda. 80%	10 years	December 28, 2013	Yes	6%
Minor Fields	Carbonera la Silla	Discovered Undeveloped Field	CDND/I	Mompos Oil Company Inc.	Mompos Oil Company Inc.	6%	Mompos Oil Company Inc. 94%	10 years	October 25, 2014	Yes	20%
Southern	Boqueron	Joint Venture	E&P	Petrobras	Petrobras/Nexen	50% (actualmente 75%  por factor R)	Petrobras Colombia Ltd. 15% Nexen Petroleum Colombia Ltd. 10 %	28 years	September 30, 2023	Yes	5% to 25%
Minor Fields	Cerrito	Joint Venture	E&P	Pacific Stratus Energy	Pacific Stratus Energy	30%	Pacific Stratus Energy 70%	27.5 years	August 17, 2029	Yes	20%

120

Region	Contract Name	Type of Agreement	Purpose	Operator	Partners	Ownership Percentage	Partnership Percentage	Term of Contract	Expiration Date	Right of Reversion Upon Termination	Royalty
Southern	Caguan	Joint Venture	E&P	Petrobras	Petrobras/ Pacific Stratus Energy	50%	Petrobras Iternational Braspetro BV 22.7268% Pacific Stratus Energy 27.2732%	28 years	December 31, 2011	Yes	20% Crudo Rio Ceibas 8% Crudo Espino 6.4% Gas Espino
Minor Fields	Chaparral	Joint Venture	E&P	Vetra Exploracion y Produccion Colombia	Vetra Exploracion y Produccion Colombia	50%	Vetra Exploración y Producción Colombia S.A.S. 50%	28 years	October 4, 2015	Yes	8%
Minor Fields	Chenche	Discovered Undeveloped Field	CDND/I	Vetra Exploracion y Produccion Colombia	Vetra Exploracion y Produccion Colombia	70%	Vetra Exploración y Producción Colombia S.A.S. 30%	10 years	December 28, 2013	Yes	8%
Catatumbo-Orinoquía	Campo Rico	Joint Venture	E&P	Emerald Energy PLC Sucursal Colombia	Emerald Energy PLC Sucursal Colombia	50%	Emerald Energy PLC Sucursal Colombia 50% minus R factor	25 years	May 24, 2027	Yes	8%
Minor Fields	Chipalo	Joint Venture- Sole Risk	E&P	Pacific Stratus Energy	Pacific Stratus Energy	0%	Pacific Stratus Energy 100%	28 years	February 27, 2026	Yes	6%
Minor Fields	Dindal	Joint Venture- Sole Risk	E&P	Pacific Stratus Energy	Pacific Stratus Energy	0%	Pacific Stratus Energy 100%	28 years	March 22, 2021	Yes	20%
Minor Fields	Entrerrios	Discovered Undeveloped Field	CDND/I	Union Temporal Andina	Union Temporal Andina	61%  Pozos desde superficie hasta 9000 pies. Pozos mayor a 9000 pies, 40% más clausula de Precios altos	Unión Temporal Andina  39%  Pozos desde superficie hasta 9000 pies. Pozos mayor a 9000 pies, 60% más clausula de Precios altos	10 years	December 28, 2013	Yes	8% to 25%
Orient	Caracara	Joint Venture	E&P	CEPCOLSA	CEPCOLSA	30%	Cepcolsa 70%	28 years	April 8, 2029	Yes	8% to 25%
Mid – Magdalena Valley	Carare las Monas	Joint Venture	E&P	Petrosantander	Petrosantander	30% (Pozos Payoa West-ST y Corazón 09  se encuentran en solo riesgo 100% a cargo de la Asociada)	Petrosantander Colombia Inc. 70%	Until economic limit	Until economic limit	Yes	8% to 20%
Minor Fields	Guachiria	Joint Venture	E&P	Lewis Energy	Lewis Energy	13%	Lewis Energy 87%	28 years	September 30, 2031	Yes	8%
Catatumbo-Orinoquía	Casanare	Joint Venture	E&P	Perenco	Perenco - Hocol and Homcol	64% 60% para WTI <28 USD/bl y 64% WTI >= 28USD/bl	Hocol 7.2% Homcol 7.2% Perenco 25.6%	Until economic limit	Until economic limit	Yes	20%

121

Region	Contract Name	Type of Agreement	Purpose	Operator	Partners	Ownership Percentage	Partnership Percentage	Term of Contract	Expiration Date	Right of Reversion Upon Termination	Royalty
Minor Fields	La Punta	Discovered Undeveloped Field	CDND/I	Vetra Exploracion y Produccion Colombia	Vetra Exploracion y Produccion Colombia	70%	Vetra Exploración y Producción Colombia S.A.S. Volumen de Desarrollo 30%	10 years	December 28, 2013(Amendment 2 august 3, 2020)	Yes	8%
Minor Fields	Las Quinchas	Joint Venture- Sole Risk	E&P	Pacific Stratus Energy	Pacific Stratus Energy	0%	Pacific Stratus Energy 100%	28 years	February 19, 2024	Yes	6%
Minor Fields	Lebrija	Joint Venture- Sole Risk	E&P	Petroleos del Norte S.A.	Petroleos del Norte S.A.	0%	Petroleos del Norte S.A. 100%	28 years	July 19, 2014	Yes	20%
Minor Fields	Magangué	Joint Venture	E&P	Solana Petroleum Exploration (Colombia Limited)	Solana Petroleum Exploration (Colombia Limited)	58%	Solana Petroleum Exploration (Colombia Limited)  42%	28 years	December 31/2017	Yes	20%
Minor Fields	Maracas	Joint Venture- Sole Risk	E&P	Texican Oil Ltd.	Texican Oil Ltd.	0%	Texican Oil Ltd. 100%	28 years	March 5, 2024	Yes	20%
Catatumbo-Orinoquía	Chipiron	Joint Venture	E&P	Occidental de Colombia Inc.	Occidental de Colombia Inc. and Occidental Andina	30%   JIBA UNIFICADO : 34.14 + 0.1657 * (%PAP de ACN)	Occidental de Colombia 35% Occidental Andina 35% Minus PAP Promedio	25 years	February 13, 2028	Yes	Variable from  8%
Minor Fields	Nancy-Burdine- Maxine	Discovered Undeveloped Field	CDND/I	Union Temporal II&B	Union Temporal II&B	41%	Unión Temporal II&B 59%	10 years	September  2, 2015	Yes	20%
Minor Fields	Opon	Joint Venture	E&P	Compañía Operadora Petrocolombia SAS	Compañía Operadora Petrocolombia SAS	50%	Compañía Operadora Petrocolombia S.A.S. 50%	28 years	July 14, 2015	Yes	20%
	Opon-6	Joint Venture- Sole Risk				0%
Catatumbo-Orinoquía	Corocora	Joint Venture	E&P	Perenco	Hocol S.A - Perenco	56%	Hocol S.A. 27.91% Perenco 16.09%	Until economic limit	Until economic limit	Yes	8% and 20%
Catatumbo-Orinoquía	Cosecha	Joint Venture	E&P	Occidental de Colombia Inc.	Occidental de Colombia Inc.	30%	Occidental de Colombia Inc. 70%	28 years	December 30, 2030	Yes	Variable from 8%
Minor Fields	Pavas- Cachira	Discovered Undeveloped Field	CDND/I	Unión Temporal Ismocol, Joshi - Parko	Unión Temporal Ismocol, Joshi - Parko	7%	Unión Temporal I.J.P. 93%	10 years	December 29, 2013	Yes	20%
Southern	CPR Santana	Risk participation contract	E&P	Gran Tierra Colombia	Gran Tierra Colombia	65%	Gran Tierra Colombia 35%	28 years	July 27, 2015	Yes	20%
Minor Fields	Playon	Discovered Undeveloped Field	CDND/I	Serinpet	Serinpet, DYAS COLOMBIA BV	53%	Serinpet 9,4%   Dyas Colombia BV 37,6%	10 years	July 12, 2015	Yes	8%

122

Region	Contract Name	Type of Agreement	Purpose	Operator	Partners	Ownership Percentage	Partnership 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. and Occidental Andina, LLC	68.94% 55% más % PAP Real promedio año 2010.	Occidental de Colombia 22.5% Occidental Andina 22.5% minus PAP Promedio	Until economic limit	Until economic limit	Yes	5% - 20%
Minor Fields	Puerto Barco	Discovered Undeveloped Field	CDND/I	Avante Ltd.	Vetra Exploracion y Produccion Colombia - Avante Ltd.	6%	Vetra Exploración y Producción Colombia S.A.S. 47% Avante Ltd. 47%	10 years	December 29, 2013	Yes	20%
Minor Fields	Quebrada Roja	Discovered Undeveloped Field	CDND/I	Campos de Producción Consortium	Campos de Producción Consortium	54%	Campos de Producción Consortium  46%	10 years	october 15, 2016	Yes	8%
Minor Fields	Rio de Oro	Discovered Undeveloped Field	CDND/I	Avante Ltd.	Vetra Exploracion y Produccion Colombia - Avante Ltd.	12%	Vetra Exploración y Producción Colombia S.A.S. 44% Avante Ltd. 44%	10 years	December 29, 2013	Yes	20%
Southern	Espinal	Risk participation contract	E&P	Petrobras	Petrobras / Cepsa	55%	Petrobras Colombia Ltd. 30% Cepcolsa 15%	28 years	October 19, 2015	Yes	20%
Minor Fields	La Rompida	Discovered Undeveloped Field	CDND/I	Vetra Exploracion y Produccion Colombia	Vetra Exploración y Producción Colombia	12%	Vetra Exploración y Producción Colombia S.A.S. 88%	10 years	December 30, 2013 (amendment Area No.2 until december 30, 2023)	Yes	6%
Catatumbo-Orinoquía	Estero	Joint Venture	E&P	Perenco	Perenco - Hocol and Homcol	89%	Perenco 4.02% Hocol 5% Homcol 1.98%	Until economic limit	Until economic limit	yes	20%
Minor Fields	San Luis	Joint Venture	E&P	Vetra Exploracion y Produccion Colombia	Vetra Exploración y Producción Colombia	50%	Vetra Exploración y Producción Colombia S.A.S. 50%	28 years	May 8, 2014	Yes	20%
Catatumbo-Orinoquía	Garcero	Joint Venture	E&P	Perenco	Perenco - Hocol and Homcol	76%	Perenco 8.78% Hocol 10.9% Homcol 4.32%	Until economic limit	Until economic limit	Yes	5%, 8% and 20%
Minor Fields	Tapir	Joint Venture- Sole Risk	E&P	Petrolco S.A.	Petrolco S.A. and Doreal Energy	0%	Petrolco S.A. and Doreal Energy 100%	28 years	February 5, 2023	Yes	20%
Northeastern	Guajira	Joint Venture	E&P	Chevron Petroleum Company	Chevron Petroleum Company	57%	Chevron Petroleum Company 43%	Until economic limit	Until economic limit	Yes	20%

123

Region	Contract Name	Type of Agreement	Purpose	Operator	Partners	Ownership Percentage	Partnership Percentage	Term of Contract	Expiration Date	Right of Reversion Upon Termination	Royalty
Minor Fields	Toca	Discovered Undeveloped Field	CDND/I	Campos de Producción Consortium	Campos de Producción Consortium	58%	Campos de Producción Consortium 42%	10 years	March 12, 2015	Yes	8%
Minor Fields	Tolima B	Joint Venture	E&P	Vetra Exploracion y Produccion Colombia	Vetra Exploracion y Produccion Colombia	50%	Vetra Exploración y Producción Colombia S.A.S. 50%	28 years	June 12, 2014	Yes	20%
		Joint Venture- Sole Risk				0%
Southern	Guayuyaco	Joint Venture	E&P	Gran Tierra Colombia	Gran Tierra Colombia	30%	Gran Tierra Colombia 70%	27.5 years (oil). 39.5  years (gas).	March 31, 2030 (oil), march 31 2042 (gas)	Yes	8% to 25%
Minor Fields	Colorado	Services and Technical Cooperation	Production	Universidad Industrial de Santander	Universidad Industrial de Santander	100%	Universidad Industrial de Santander 0%	10 Years	june 30, 2016	Yes	20%
Minor Fields	El Piñal	Joint Venture- Sole Risk	E&P	Petrosantander	Petrosantander	0%	Petrosantander Colombia Inc.100%	28 years	July 28, 2018	Yes	20%
Southern	Hobo	Joint Venture	E&P	Petrobras	Petrobras	50%	Petrobras International Braspetro BV 50%	28 years	December 31, 2011	Yes	20%
Minor Fields	Fortuna	Joint Venture- Sole Risk	E&P	Emerald Energy PLC Sucursal Colombia	Emerald Energy PLC Sucursal Colombia	5%	Emerald Energy PLC Sucursal Colombia 95%	28 years	December 18, 2031	Yes	6% to 20%
Mid – Magdalena Valley	La Cira	Business Cooperation	E&P	Ecopetrol S.A.	Occidental de Colombia and Ecopetrol S.A.	52% Actualmente        63%  por Precios altos	Occidental Andina  48% Actualmente 37%  por precios altos	Until economic limit	Until economic limit	Yes	8% to 20%
Minor Fields	Buganviles	Joint Venture- Sole Risk	E&P	Pacific Stratus Energy	Pacific Stratus Energy	0%	Pacific Stratus Energy 100%	28 años	17-Nov-28	Yes	8% to 25%
Minor Fields	Valdivia - Almagro	SPBR	SPBR	Vetra Exploración y Producción Colombia	N/A	100%	Vetra Exploración y Producción Colombia S.A.S. 0%	Until economic limit	Until economic limit	Yes	20%
Southern	Mana	Joint Venture	E&P	Interoil	Interoil	30%	Interoil Colombia E&P 70%	25 years	November 11, 2028 (oil), November 11, 2040 (gas)	Yes	8% to 25%
Minor Fields	Hato Nuevo	Discovered Undeveloped Field	CDND/I	EMPESA - NTC Consortium	EMPESA -NTC Consortium	41%	EMPESA -NTC Consortium 59%	10 years	May 17, 2017	Yes	5%
Southern	Matambo	Joint Venture	E&P	Emerald Energy PLC Sucursal Colombia	Emerald Energy PLC Sucursal Colombia	50%	Emerald Energy PLC Sucursal Colombia 50%	28 years	November 29, 2024	Yes	20%
Catatumbo-Orinoquía	Ranchohermoso	SPBR	SPBR	CANACOL	N/A	100%	N/A	Until economic limit	Until economic limit	Yes	20%
Catatumbo-Orinoquía	Ranchohermoso	Operation Agreement	Operation Agreement	CANACOL	CANACOL	70% más % PA por clausula de precios altos	CANACOL 30%	Until economic limit	Until economic limit	Yes	8%

124

Region	Contract Name	Type of Agreement	Purpose	Operator	Partners	Ownership Percentage	Partnership Percentage	Term of Contract	Expiration Date	Right of Reversion Upon Termination	Royalty
Mid – Magdalena Valley	Nare	Joint Venture	E&P	Mansarovar Energy Colombia Ltd.	Mansarovar Energy Colombia Ltd.	50%  (Pozo Jazmin R05 en solo riesgo 100% a cargo de la Asociada)	Mansarovar Energy Colombia 50%	28 years	November 5, 2021	Yes	20%  - 6%
Southern	Neiva	Incremental Production	E&P	Ecopetrol S.A.	Petrominerales	31%	Petrominerales 69%	22 years	June 5, 2023	Yes	8% to 25%
Southern	Orito	Incremental Production	E&P	Ecopetrol S.A.	Petrominerales	21%	Petrominerales 79%	22 years	June 5, 2023	Yes	8% to 25%
Catatumbo-Orinoquía	Orocue	Joint Venture	E&P	Perenco	Perenco and Hocol	63%	Perenco 13.53% Hocol 23.47%	Until economic limit	Until economic limit	Yes	20%
Southern	Ortega	Incremental Production	E&P	Ecopetrol S.A.	Hocol S.A.	31%	Hocol S.A.   69% (Producción Incremental)	22 years	February 28, 2023	Yes	8% incremental, 20% base
Mid – Magdalena Valley	Palagua	Incremental Production	E&P	Union Temporal IJP	Union Temporal Ismocol, Joshi- Parko	34%	Unión Temporal I.J.P. 66%	22 years	July 14, 2023	Yes	20%
Southern	Palermo	Joint Venture	E&P	Hocol S.A.	Hocol S.A.	50%	Hocol S.A. 50%	28 years	April 30, 2012	Yes	20%
Northeastern	Piedemonte	Joint Venture	E&P	BP	BP	50%	Equion 50%	28 years	February 29, 2020	Yes	20%
Orient	Piriri	Joint Venture	E&P	Metapetroleum	Metapetroleum Corp. And Tethys Petroleum Company Limited	50%	Metapetroleum Corp. Tethys Petroleum Company Limited 50%	28 years	June 30, 2016	Yes	20%
Southern	Puli	Joint Venture	E&P	Interoil	Interoil	50%	Interoil Colombia E&P 50%	28 years	February 29, 2012	Yes	20%
Northeastern	Recetor	Joint Venture	E&P	BP	BP Explotarion  Co (Colombia) Ltd. - BP Santiago	50%	Equion 40% Santiago Oil Company 10%	28 years	May 29, 2017	Yes	20%
Northeastern	Rio Chitamena	Joint Venture	E&P	BP	BP Explotarion  Co (Colombia) Ltd. - BP Santiago - Total	50%	Equion 19% Santiago Oil 12% Total 19%	28 years	January 31, 2019	Yes	20%
Southern	Rio Opia	Joint Venture	E&P	Interoil	Interoil	30%	Interoil Colombia E&P 70%	28 years	June 23, 2030	Yes	8% to 25%
Catatumbo-Orinoquía	Rondon	Joint Venture	E&P	Occidental de Colombia Inc.	Occidental de Colombia Inc. and Occidental Andina, LLC	50%	Occidental de Colombia 25% Occidental Andina 25%	28 years	January 8, 2023	Yes	Variable desde el 8%
Orient	Rubiales	Risk participation contract	E&P	Metapetroleum	Metapetroleum Corp. And Tethys Petroleum Company Limited	60%	Metapetroleum Corp. Tethys Petroleum Company Limited 40%	28 years	June 30, 2016	Yes	20%

125

Region	Contract Name	Type of Agreement	Purpose	Operator	Partners	Ownership Percentage	Partnership Percentage	Term of Contract	Expiration Date	Right of Reversion Upon Termination	Royalty
Southern	San Jacinto (La Cañada Norte)	Joint Venture	E&P	Hocol S.A.	Hocol S.A. Petrobras Cepsa	50%	Hocol S.A. 18.335% Petrobras 15% Cepsa 16.665%	28 years	December 22, 2024	Yes	8% La Cañada Norte
Southern	Suroriente	Incremental Production	E&P	Vetra Colombia Exploración y Producción	Consorcio Colombia Energy (Vetra Colombia Exploración y Producción y Suroco)	48%	Vetra Exploración y Producción Colombia S.A.S. 52%	22 years	June 11, 2024	Yes	8% to 25%
Northeastern	Tauramena	Joint Venture	E&P	BP	BP Explotarion  Co (Colombia) Ltd. - BP Santiago  - Total	50%	Equion 19% Santiago Oil 12% Total 19%	28 years	July 3, 2016	Yes	20%
Mid – Magdalena Valley	Tisquirama	Joint Venture	E&P	Petroleos del Norte S.A.	Petroleos del Norte S.A – Petrosantander	60%	Petrosantander Colombia Inc 40%	Until economic limit	Until economic limit	Yes	20%
Orient	Upia B	Joint Venture	E&P	Petrobras	PETROBRAS	50%	Petrobras 50%	28 years	Feb 29, 2012	Yes	20%
Southern	Doima	Joint Venture	E&P	Hocol S.A.	Hocol S.A	39%	Hocol S.A. 61%	28 years (oil), 40 years (gas)	February 16, 2029. February 16, 2041	Yes	6.4% Gas
Mid – Magdalena Valley	CRC-2004-01 (Guariquies)	Risk participation contract exploration and productions (CRC)	E&P	Ecopetrol S.A.	Ramshorn	55% and R Factor	Ramshorn 45%	25 years	May 24, 2029	Yes	8% to 20%
Southern	Río Paez	Joint Venture - Sole risk	E&P	Hocol S.A.	Hocol S.A.	50% (Campo La Hocha en solo riesgo 100% a cargo de la Asociada)	Hocol S.A. 18.335% Petrobras 15% Cepsa 16.665%	25 years	April 27,2026	yes	5% La Hocha
Minor Fields	Río Seco	Joint Venture -  Sole Risk	E&P	Pacific Stratus Energy	Pacific Stratus Energy	0%	Pacific Stratus Energy 100%	28 years	August 22, 2023	yes	20%
Mid – Magdalena Valley	Alianza Tecnológica Casabe	Technological Alliance agreement	E&P	Ecopetrol S.A.	Schlumberger	100%	Schlumberger 0%	16 years	April 26, 2020	yes	8% to 20%
Southern	Rio Magdalena	Joint Venture - Sole risk	E&P	Grantierra Energy Colombia	Gran tierra Energy Colombia	30%	70%	28 years	February 8, 2030	Yes	6%

126

ANNEX II
DESCRIPTION OF EXPLORATION AND PRODUCTION CONTRACTS (EXPLORATION PHASE)

Contract Name	Type of Agreement	Purpose	Operator	Partners	Ownership Percentage	Term of Contract	Expiration Date	Ecopetrol´s Right of Reversion upon Termination	Royalty
BOROJO NORTE	E&P	E&P	RELIANCE INDUSTRIES LIMITED	RELIANCE INDUSTRIES LIMITED	20%	30 YEARS	18 DEC 2038	NO	8% to 25%
BOROJO SUR	E&P	E&P	RELIANCE INDUSTRIES LIMITED	RELIANCE INDUSTRIES LIMITED	20%	30 YEARS	18 DEC 2038	NO	8% to 25%
CPE 8	TEA	TEA	TALISMAN	TALISMAN	50%	3 YEARS	23 SEPT 2011	NO	8% to 25%
CPO 11	E&P	E&P-	ECOPETROL	NONE	100%	30 YEARS	18 DEC 2038	NO	8% to 25%
LL 4	E&P	E&P	ECOPETROL	NONE	100%	30 YEARS	APRIL 7 2039	NO	8% to 25%
LL 9	E&P	E&P	ECOPETROL	NONE	100%	30 YEARS	APRIL 7 2039	NO	8% to 25%
LL 14	E&P	E&P	ECOPETROL	NONE	100%	30 YEARS	APRIL 7 2039	NO	8% to 25%
ODISEA	E&P	E&P	ECOPETROL	NONE	100%	30 YEARS	AUGUST 6 2038	NO	8% to 25%
RC 4	E&P	E&P-	EQUION	EQUION AND PETROBRAS	32%	30 YEARS	NOV 28 2037	NO	8% to 25%
RC 5	E&P	E&P	EQUION	EQUION AND PETROBRAS	32%	30 YEARS	NOV 28 2037	NO	8% to 25%
SILVESTRE	E&P	E&P	ECOPETROL	NONE	100%	30 YEARS	NOV 30 DE 2037	NO	8% to 25%
SSJN 4	E&P	E&P	ECOPETROL	NONE	100%	30 YEARS	DEC 18 2038	NO	8% to 25%
CAÑO SUR	E&P	E&P E&P	ECOPETROL	NONE	100%	30 YEARS	JUNE 20 2035	NO	8% to 25%
CPE 2	TEA	TEA	ECOPETROL	SHELL	50%	2 YEARS	MAY 23 2012	NO	8% to 25%
CPE 4	TEA	TEA	ECOPETROL	SHELL	50%	2 YEARS plus extension	JUNE  23 2012	NO	8% to 25%
CPO 8	E&P	E&P	ECOPETROL	NONE	100%	30 YEARS	DEC 18 2038	NO	8% to 25%
CPO 9	E&P	E&P	ECOPETROL	TALISMAN	55%	30 YEARS	JANUARY 26 2039	NO	8% to 25%
CPO 10	E&P	E&P	ECOPETROL	NONE	100%	30 YEARS	DECEMBER 18 2038	NO	8% to 25%
FUERTE NORTE	E&P	E&P	ECOPETROL	NONE	100%	30 YEARS	APRIL 7 2036	NO	8% to 25%
FUERTE SUR	E&P	E&P	ECOPETROL	NONE	100%	30 YEARS	APRIL 7 2036	NO	8% to 25%
RC6	E&P	E&P	PETROBRAS	PETROBRAS AND HESS	30%	30 YEARS	NOV 30 2037	NO	8% to 25%
RC 7	E&P	E&P	PETROBRAS	PETROBRAS AND HESS	30%	30 YEARS	NOV 30 2037	NO	8% to 25%
RC 8	E&P	E&P	ONGC VIDESH	ONGC VIDESH AND PETROBRAS	40%	30 YEARS	NOV 30 2037	NO	8% to 25%
RC 9	E&P	E&P	ECOPETROL	ONGC	50%	30 YEARS	NOV 30 2037	NO	8% to 25%
RC 10	E&P	E&P	ONGC VIDESH	ONGC VIDESH	50%	30 YEARS	NOV 30 2037	NO	8% to 25%
RC 11	E&P	E&P	ECOPETROL	REPSOL	50%	30 YEARS	NOV 30 2037	NO	8% to 25%

127

RC 12	E&P	E&P	ECOPETROL	REPSOL	50%	30 YEARS	NOV 30 2037	NO	8% to 25%
TAYRONA	E&P	E&P	PETROBRAS	PETROBRAS AND REPSOL	30%	34 YEARS	AUGUST 13 2038	NO	8% to 25%
URIBANTE	E&P	E&P	ECOPETROL	NONE	100%	30 YEARS	MAY 16 2035	NO	8% to 25%
VMM 6	E&P	E&P	ECOPETROL	NONE	100%	30 YEARS	APRIL 7 2039	NO	8% to 25%
CATLEYA	SHARED RISK AGREEMENT	E&P	ECOPETROL	REPSOL	34%	UNDETERMINED	UNDETERMINED		8% to 25%
MUNDO NUEVO	JOINT VENTURE	E&P	HOCOL	HOCOLTOTAL E&P COLOMBIETALISMAN	30%	UNDETERMINED	UNDETERMINED		The applicable law is the law in force when the discovery took place
RIO RANCHERIA	JOINT VENTURE	E&P	DRUMMOND	DRUMMOND	30%	UNDETERMINED	UNDETERMINED		The applicable law is the law in force when the discovery took place
QUIFA	RISK PARTICIPATION CONTRACT	E&P	METAPETROLEUM LTD	METAPETROLEUM LTD	30%	28 YEARS	DEC 22 2031		8% to 25%
CONDOR	JOINT VENTURE	E&P	LUKOIL	LUKOIL	30%	UNDETERMINED	UNDETERMINED		The applicable law is the law in force when the discovery took place
VMM 32	E&P	E&P	ECOPETROL	CPVEN	51%	30 YEARS	NOV 2  2041	NO	8% to 25%
SAMICHAY A	E&P	E&P	ECOPETROL	NONE	100%	30 YEARS	DEC 13 2041	NO	8% to 25%
SAMICHAY B	E&P	E&P	ECOPETROL	NONE	100%	30 YEARS	DEC 13 2041	NO	8% to 25%
TUMACO OFFSHORE 3	E&P	E&P	ECOPETROL	NONE	100%	30 YEARS	NOVEMBER 16 2041	NO	8% to 25%
SSJS1	E&P	E&P	ECOPETROL	SK INNOVATION CO., LTD	70%	30 YEARS	DECEMBER 17 2041	NO	8% to 25%
LL 6	E&P	E&P	ECOPETROL	NONE	100%	30 YEARS	DEC 17 2041	NO	8% to 25%
LL 8	E&P	E&P	ECOPETROL	NONE	100%	30 YEARS	SEPT 30 2041	NO	8% to 25%
LL 37	E&P	E&P	ECOPETROL	NONE	100%	30 YEARS	AUGUST 31 2041	NO	8% to 25%
LL 38	E&P	E&P	ECOPETROL	NONE	100%	30 YEARS	NOV 21 2041	NO	8% to 25%
LL 52	E&P	E&P	ECOPETROL	NONE	100%	30 YEARS	SEPT 30 2041	NO	8% to 25%

128

Ecopetrol S.A. and Subsidiaries

Consolidated Financial Statements

Years ended December 31, 2011, 2010 and 2009

F-1

Ecopetrol S.A. and Subsidiaries

Consolidated Financial Statements

Years ended December 31, 2011, 2010 and 2009

Contents

Report of Independent Registered Public Accounting Firm – KPMG Ltda.	F-3
Report of Independent Registered Public Accounting Firm – PricewaterhouseCoopers Ltda.	F-4
Consolidated Balance Sheets	F-5
Consolidated Statements of Financial, Economic, Social and Environmental Activities	F-6
Consolidated Statements of Changes in Shareholders’ Equity	F-7
Consolidated Statements of Cash Flows	F-8
Notes to Consolidated Financial Statements	F-10

F-2

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Shareholders

Ecopetrol S.A.:

We have audited the accompanying consolidated balance sheet of Ecopetrol S.A. and subsidiaries as of December 31, 2011, and the related consolidated statements of Financial, Economic, Social and Environmental Activities, Changes in Stockholders’ Equity, and Cash Flows for the year ended December 31, 2011. We also have audited Ecopetrol S.A.’s internal control over financial reporting as of December 31, 2011, based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Ecopetrol S.A.’s management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in ITEM 15 of the FORM 20-F for the fiscal year ended December 31, 2011. Our responsibility is to express an opinion on these consolidated financial statements and an opinion on the Company’s internal control over financial reporting based on our audit.

We conducted our audit 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 and whether effective internal control over financial reporting was maintained in all material respects. Our audit of the consolidated financial statements included 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. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of consolidated financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Ecopetrol S.A. and subsidiaries as of December 31, 2011, and the results of its operations and its cash flows for the year ended December 31, 2011, in conformity with accounting principles generally accepted in Colombia, promulgated by the National Accounting Office (Contaduría General de la Nación or CGN). Also in our opinion, Ecopetrol S.A. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2011, based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

Accounting principles generally accepted for Colombian Government Entities vary in certain significant respects from accounting principles generally accepted in the United States of America. Information relating to the nature and effects of such differences is presented in Note 34 to the consolidated financial statements.

/s/ KPMG Ltda.

Bogotá, Colombia
April 30, 2012

F-3

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Shareholders of Ecopetrol S. A.

In our opinion, the accompanying consolidated balance sheet and the related consolidated statements of financial, economic, social and environmental activities, of changes in shareholders´s equity and of cash flows present fairly, in all material respects, the financial position of Ecopetrol S. A. and its subsidiaries (the “Company”) at December 31, 2010, and the results of their operations and their cash flows for each of the two years in the period ended December 31, 2010, in conformity with generally accepted accounting principles for Colombian Government Entities issued by the Contaduría General de la Nación. 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 generally accepted auditing standards in Colombia and the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement. Our audits of the financial statements included 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. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinion.

Accounting principles generally accepted for Colombian Government Entities vary in certain significant respects from accounting principles generally accepted in the United States of America. Information relating to the nature and effects of such differences is presented in Note 34 to the consolidated financial statements.

As discussed in Note 32 , which appears in the Company's Form 20-F for the year ended December 31, 2010, the Company has restated its 2009 consolidated financial statements reconciled to accounting principles generally accepted in the United States of America to correct some errors.

/s/ PricewaterhouseCoopers Ltda.

Bogotá, Colombia

July 15, 2011

F-4

Ecopetrol S.A. and Subsidiaries

Consolidated Balance Sheets

	As of December 31,
	2011			2010
	(In millions of Colombian pesos)
Assets
Current assets:
Cash and cash equivalents (Notes 2 and 3)	$	6,585,628			3,726,778
Investments (Notes 2 and 4)		1,531,911			327,782
Accounts and notes receivable, net (Notes 2 and 5)		4,635,834			2,736,592
Inventories, net (Note 6)		2,761,605			2,192,088
Advances and deposits (Notes 2 and 7)		3,459,942			3,620,317
Deferred tax assets		10,019			4,134
Prepaid expenses (Note 8)		52,374			21,947
Total current assets		19,037,313			12,629,638
Non-current Assets:
Investments (Notes 2 and 4)		5,474,805			5,177,491
Accounts and notes receivable, net (Note 5)		407,929			372,273
Advances and deposits (Notes 2 and 7)		144,482			288,735
Property, plant and equipment, net (Note 10)		30,033,380			22,266,258
Natural and environmental resources, net (Note 11)		15,440,787			11,774,539
Deferred charges (Note 12)		3,950,060			2,040,140
Deposits under trust funds (Note 9)		283,504			-
Other assets (Note 13)		3,929,248			3,151,606
Revaluations (Note 14)		13,575,878			11,068,676
Total assets	$	92,277,386			68,769,356
Liabilities and Shareholders' Equity
Current liabilities:
Financial obligations (Note 15)		831,594			1,079,169
Accounts payable and related parties (Notes 2 and 16)		4,374,890			4,062,602
Taxes payable (Note 17)		8,617,438			3,589,263
Labor and pension plan obligations (Note 18)		233,322			160,247
Estimated liabilities and provisions (Notes 2 and 19)		1,695,193			1,151,297
Total current liabilities		15,752,437			10,042,578
Long-term liabilities:
Financial obligations (Notes 2 and 15)		7,969,978			7,833,715
Accounts payable and related parties (Note 16)		518,143			504,046
Labor and pension plan obligations (Note 18)		3,190,229			2,814,021
Taxes payable (Note 17)		1,035,971			-
Estimated liabilities and provisions		4,084,829			3,398,603
Other long-term liabilities (Notes 2 and 20)		2,784,313			2,362,261
Total liabilities		35,335,900			26,955,224
Non-controlling interest (Note 21)		2,252,631			485,951
Shareholders’ equity:
(Note 20 and see accompanying statement)		54,688,855			41,328,181
Total liabilities and shareholders’ equity	$	92,277,386			68,769,356
Memorandum Debtor Accounts  (Note 23)		130,221,872			119,039,595
Memorandum Obligations Accounts (Note 23)	$	(111,784,600	)		(96,981,023	)

The accompanying notes are an integral part of these financial statements.

F-5

Ecopetrol S.A. and Subsidiaries

Consolidated Statements of Financial, Economic, Social and Environmental Activities

	Years ended December 31,
	2011			2010			2009
	(In millions of Colombian pesos, except for net income
	per share amounts expressed in pesos)
Revenues (Note 24):
Local Sales	$	23,339,383		$	18,084,425		$	14,058,534
Foreign sales		42,412,885			23,883,886			16,345,856
Total revenue		65,752,268			41,968,311			30,404,390
Cost of sales (Note 25)		36,665,056			25,959,001			19,906,073
		29,087,212			16,009,310			10,498,317
Operating expenses (Note 26):
Administration		1,018,917			603,523			662,336
Selling and projects		2,377,332			2,526,945			1,962,642
Operating income		25,690,963			12,878,842			7,873,339
Non-operating income (expenses):
Financial income (expenses), net (Note 27)		(904,302	)		37,789			495,833
Pension expenses (Notes 18 and 28)		(706,298	)		(377,626	)		(595,157	)
Inflation gain (Note 29)		21,836			22,030			22,355
Other income (expenses), net (Note 30)		(460,767	)		(1,068,418	)		(545,526	)
Income before tax and Non-controlling interest		23,641,432			11,492,617			7,250,844
Income tax (Note 17)		7,955,721			3,238,650			2,114,029
Non-controlling income (expenses)		(233,377	)		(107,496	)		(4,761	)
Net income	$	15,452,334		$	8,146,471		$	5,132,054
Net income per share	$	380.27		$	201.28		$	126.80

The accompanying notes are an integral part of these financial statements.

F-6

Ecopetrol S.A. and Subsidiaries

Consolidated Statements of Changes in Shareholders’ Equity

(In millions of Colombian pesos, except for the dividend per share amounts)

For the years ended on December 31, 2011, 2010 and 2009

	Subscribed									Surplus					Public
	and		Additional			Legal and		Incorporated		from			Surplus		accounting
	paid-in capital		paid-in Capital			other reserves		institutional equity		equity method			from revaluations		application effect			Retained earnings			Total equity
Balance as of December 31, 2009	$	10,117,791		4,720,320			5,159,504		155,529		1,192,147			6,391,417		(298,805	)		5,132,054			32,569,957
Distribution of dividends ($91 per share)		-		-			-		-		-			-		-			(3,682,998	)		(3,682,998	)
Unpaid subscribed capital and additional paid-in capital		337		243			-		-		-			-		-			-			580
Additional receivable paid-in capital		-		(55	)		-		-		-			-		-			-			(55	)
Surplus from revaluations		-		-			-		-		-			4,677,259		-			-			4,677,259
Devaluation in property, plant and equipment		-		-			-		-		-			-		(403,670	)		-			(403,670	)
Adjustment for effect of foreign exchange difference in equity method surplus		-		-			-		-		(105,364	)		-		-			-			(105,364	)
Appropriation to legal reserve		-		-			525,624		-		-			-		-			(525,624	)		-
Appropriation to investment programs reserves		-		-			1,047,610		-		-			-		-			(1,047,610	)		-
Addition to the incorporated institutional equity		-		-			-		1,823		-			-		-			-			1,823
Unrealized income																			124,178			124,178
Net income		-		-			-		-		-			-		-			8,146,471			8,146,471
Balance as of December 31, 2010		10,118,128		4,720,508			6,732,738		157,352		1,086,783			11,068,676		(702,475	)		8,146,471			41,328,181
Distribution of dividends ($145 per share)		-		-			-		-		-			-		-			(5,868,514	)		(5,868,514	)
Capitalization - Second tier of the public offering		161,047		-			-		-		-			-		-			-			161,047
Unpaid subscribed capital and additional paid-in capital		-		2,222,459			-		-		-			-		-			-			2,222,459
Addition to paid-in capital - Execution of warranties		-		(154,823	)		-		-		-			-		-			-			(154,823	)
Valuation surplus		-		-			-		-		-			2,507,202		-			-			2,507,202
Revaluation of property, plant and equipment		-		-			-		-		-			-		6,114			-			6,114
Appropriation to legal reserve		-		-			834,610		-		-			-		-			(834,610	)		-
Appropriation to investment program reserves		-		-			1,065,465		-		-			-		-			(1,065,465	)		-
Appropriation to Regulatory Decree 2336/95 reserves		-		-			96,695		-		-			-		-			(96,695	)		-
Appropriation to payment of dividends for shares issued in 2011 reserves		-		-			449,904		-		-			-		-			(449,904	)		-
Appropriation of reserves to payment of dividends		-		-			-		-		-			-		-			(30,909	)		(30,909	)
Addition to incorporated institutional equity		-		-			-		16,728		-			-		-			-			16,728
Adjustment for effect of foreign exchange difference in equity method surplus		-		-			-		-		(824,155	)		-		-			-			(824,155	)
Unrealized income																			(126,809	)		(126,809	)
Net income		-		-			-		-		-			-		-			15,452,334			15,452,334
Balance as of December 31, 2011	$	10,279,175		6,788,144			9,179,412		174,080		262,628			13,575,878		(696,361	)		15,125,899			54,688,855

The accompanying notes are integral part of these financial statements.

F-7

Ecopetrol S.A. and Subsidiaries

Consolidated Statements of Cash Flows

	Years ended December 31,
	2011			2010			2009
	(In millions of Colombian pesos)
Cash flows from operating activities:
Net income	$	15,452,334			8,146,471			5,132,054
Adjustments to reconcile net income to cash provided by operating activities:
Non-controlling interest		233,377			107,495			4,761
Deferred income tax, net		394,087			37,609			165,210
Depreciation of property, plant and equipment		1,960,007			1,624,009			1,262,643
Amortizations:
Natural resources		2,306,269			2,003,771			1,274,979
Abandonment of installations		285,814			241,842			199,939
Health and education pension liabilities		517,345			166,211			502,665
Intangibles		295,670			189,261			152,235
Deferred charges		111,811			107,422			94,288
Deferred monetary correction, net		(21,836	)		(22,030	)		(22,355	)
Provisions:
Accounts receivable		32,422			169,789			30,734
Inventories		8,505			9,743			33,161
Property, plant and equipment		41,948			227,266			127,826
Legal proceedings		360,351			125,888			271,091
Pension commutation		241,624			-			-
Others		122,395			19,834			-
Recovery of provisions:
Accounts receivable		(365	)		(68,772	)		-
Inventories		(3,263	)		(29,481	)		(118,652	)
Property, plant and equipment		(46,019	)		(55,717	)		(17,091	)
Legal proceedings		(229,345	)		(80,237	)		(83,258	)
Others		(387,117	)		(138,397	)		(5,564	)
Write-off of property, plant and equipment		418			3,395			-
Loss on retirement of property, plant and equipment		-			38,945			-
Losses in retirement of investment in natural and environmental resources		-			39,668			-
Write-off of other assets		300			287,918			-
Gain in equity method		(141,275	)		(82,772	)		(55,143	)
Net changes in operating assets and liabilities:
Accounts and notes receivable		(1,324,033	)		794,512			2,030,376
Inventories		(561,846	)		(129,823	)		(291,819	)
Deferred charges and other assets		(2,165,464	)		698,423			(1,408,834	)
Accounts payable and related parties		(121,422	)		1,248,736			1,536,580
Taxes payable		5,073,370			(618,440	)		(1,473,446	)
Labor obligations		(85,757	)		(26,737	)		37,684
Estimated liabilities and provisions		86,805			(64,028	)		(24,809	)
Other long-term assets		559,201			(507,467	)		-
Net cash provided by operating activities		22,996,311			14,464,307			9,355,255
Cash flows from investing activities:
Payments and advances for acquisition of companies, net of the cash acquired		(868,954	)		(1,163,131	)		(1,082,580	)
Increase in investments		(11,685,030	)		(11,808,784	)		(7,939,870	)
Investments redemption and sale		9,667,021			10,578,200			15,972,339
Investment in natural and environmental resources		(4,311,149	)		(3,874,824	)		(3,613,355	)
Additions to property, plant and equipment		(10,189,522	)		(6,445,151	)		(9,239,234	)
Proceeds from sales of property and equipment		-			4,751			1,927
Net cash used in investing activities		(17,387,634	)		(12,708,939	)		(5,900,773	)
								(Continue)

F-8

	2011			2010			2009
Cash flows from financing activities:
Non-controlling interest		1,027,567			(562,855	)		693,599
Financial obligations		136,263			2,761,449			6,161,793
Debt from credit operations and financing		(245,454	)		-			-
Capitalizations		2,228,683			525			41,044
Dividends		(5,896,886	)		(3,789,828	)		(8,902,602	)
Net cash used in financing activities		(2,749,827	)		(1,590,709	)		(2,006,166	)
Net increase in cash and cash equivalents		2,858,850			164,659			1,448,316
Cash and cash equivalents at beginning of year		3,726,778			3,562,119			2,113,803
Cash and cash equivalents at end of year	$	6,585,628			3,726,778			3,562,119

The accompanying notes are an integral part of these consolidated financial statements. 

F-9

ECOPETROL S. A. and Subsidiaries

Notes to the Consolidated Financial Statements

Years ended December 31, 2011, 2010 and 2009

(Amounts are expressed in millions of Colombian pesos, except amounts stated in other currencies; exchange rates and income per share, which are expressed in Colombian pesos – throughout these financial statements pesos or Ps refer to Colombian pesos and U.S. dollar refers to United States dollars)

(1) Economic Entity and Principal Accounting Policies and Practices

Reporting Entity

ECOPETROL S.A. and subsidiaries (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 nature, 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, corresponding to 10.1% of the authorized capital, at the end of 2007, the Company became a Mixed Economy Entity of a commercial nature, at a national level, related to the Ministry of Mines and Energy.

Ecopetrol entered into a deposit agreement with JP Morgan Chase Bank, N.A., as depositary, for the issuance of ADSs evidenced by ADRs. Each of the ADSs represents 20 of Ecopetrol´s common shares or the right to receive 20 common shares of Ecopetrol.

On September 12, 2008, Ecopetrol submitted to the Securities and Exchange Commission of the United States (“SEC”) an application to register and list the Company’s ADSs represented by ADRs on the New York Stock Exchange (NYSE). The Company’s ADSs began trading on the NYSE under the symbol “EC” on September 18, 2008.

On December 3, 2009 the National Commission for the Surveillance of Companies and Securities of Peru – CONASEV approved the listing of Ecopetrol’s ADRs on the Lima Stock Exchange and the registration of such securities with the Public Registry of the Securities Market. The ADRs began trading on the Lima Stock Exchange on December 4, 2009, in the Peruvian market under the “EC” symbol.

On August 13, 2010, Ecopetrol began trading its Company´s ADRs on the Toronto Stock Exchange – Canada, one of the biggest Stock Exchange in the world in the energy sector . Thus, Ecopetrol became the first Colombian company to list its ADRs in the Toronto Stock Exchange.

Between July 27 and August 17, 2011, Ecopetrol carried out a second tier of the public offering, authorized by Law 1118 of 2006. As a result of this process 644,185,868 shares were placed at a nominal price of $3,700 Colombian pesos per share, for a total amount of $2,383,488. The common shares were registered on the National Registry of Securities and Issuers in accordance with Decree 2555 of 2010. After the placement, the equity participation of the Colombian Nation in Ecopetrol is 88.49%.

On February 13, 2008, Ecopetrol S. A., as parent company, announced the registration of documentation evidencing the existence of a Corporate Group (Grupo Empresarial, the term which under Colombian law describes when a company acquires subsidiaries) considering its controlling acquisition of the following subsidiaries: Black Gold Re Limited, Ecopetrol Oleo é Gas do Brazil Ltda., Ecopetrol del Perú S.A. and Ecopetrol America Inc. Subsequently, Andean Chemicals Ltd., parent company of Bioenergy and investor in Propilco S. A., which in turn is the parent company of Compounding and Masterbatching Industry Ltda. (“Comai”), was incorporated into the Corporate Group

F-10

Likewise, in 2009 the companies ODL Finance, parent Company of ODL; Hocol Petroleum Limited, parent company of Homcol Cayman Inc. and Hocol Limited, which branch in Colombia is Hocol S.A.; Ecopetrol Transportation Company, parent company of Ecopetrol Pipelines International Ltd.; Ecopetrol Global Energy, and Refinería de Cartagena S.A., were all incorporated into the Corporate Group.

On September 20, 2010, Ecopetrol S.A. incorporated its subsidiary company Oleoducto Bicentenario de Colombia S.A.S into the Corporate Group.

On January 17, 2011, the following companies: Capital S.L.U, Ecopetrol Capital AG and Ecopetrol Transportation Investments Ltd, domiciled outside the country, were incorporated into the Corporate Group of Ecopetrol S.A.,

On February 23, 2011, Ecopetrol S.A incorporated its subsidiariy companies Colombia Pipelines Limited, Equion Energia Limited, Santiago Oil Co, Santiago Oil Company y Santiago Pipelines Co into the Corporate Group.

In December 2011, the Board of Directors of Andean Chemicals Ltd, approved the capitalization of a liability (capital plus interest) with Ecopetrol S.A.. Andean placed 615,677,799 ordinary shares at a nominal value of US$1 per share for this process. The liability was originated by a loan contract between Andean and Ecopetrol in May 2009, to acquire the Refinería de Cartagena through Andean Ltd as an investment vehicle.

On December 16, 2011, the extraordinary shareholders’ meeting of Oleoducto Bicentenario S.A.S., approved the placement of 156,448 shares at a value of $173,925 per share. Of said amount, $1,564 are shareholders´s equity, and $172,361 are an additional paid-in capital.

The companies consolidated by Ecopetrol in its financial statements as of December 31, 2011, 2010 and 2009 are:

	Percentage of Ownership %
Company	2011	2010	2009	Activity	Subsidiaries
Ecopetrol Oleo é Gas do Brasil Ltda.	100	100	100	Exploration and exploitation of hydrocarbons	-
Ecopetrol del Peru S. A.	100	100	100	Exploration and exploitation of hydrocarbons	-
Ecopetrol America Inc.	100	100	100	Exploration and exploitation of hydrocarbons	-
Black Gold Re Ltd.	100	100	100	Reinsurance Company of Ecopetrol and itssubsidiaries	-
Andean Chemicals Ltd.	100	100	100	Investment vehicle	Bioenergy S. A., Refinería de Cartagena S.A. and Polipropileno del Caribe S.A.
ODL Finance S. A.	65	65	65	Crude oil transportation through pipelines	ODL S. A. ODL - Sucursal Colombia
Polipropileno del Caribe. Propilco S. A.	100	100	100	Production and selling of polypropylene resin	Comai Ltda.
Bioenergy S. A.	88.6	88.6	80	Bio-fuel production	-
Ecopetrol Global Energy	100	100	100	Investment vehicle	Ecopetrol America Inc.
Ecopetrol Transportation Company Limited	100	100	100	Investment vehicle	Ecopetrol Pipelines International Limited, Ecopetrol Transportation Investment Ltd
Oleoducto Central S. A. - Ocensa	72.6	60	60	Crude oil transportation through pipelines	-

F-11

	Percentage of Ownership %
	2011	2010	2009	Activity	Subsidiaries
COMAI - Compounding and Masterbatching Industry Ltda.	100	100	100	Manufacturing of polypropylene compounds and masterbatches for a wide range of uses.	-
Refineria de Cartagena S. A.	100	100	100	Refining, sale and distribution of hydrocarbons.	-
Hocol Petroleum Limited	100	100	100	Investment vehicle	Hocol Limited, Hocol S. A., Homcol Cayman Inc.
Oleoducto de Colombia S. A. – ODC	73	66	66	Transportation of crude oil through pipelines	-
Oleoducto Bicentenario de Colombia SAS	55.97	55.97	-	Transportation of crude oil through pipelines	-
Ecopetrol Transportation Invesment Ltd.	100	100	-	Investment vehicle	-
Ecopetrol Capital AG	100	100	-	Financing, liquidation of financing of group partnerships or any type of business and any activity related thereto.	-
Equion Energía Limited	51	-	-	Exploration and development of Hydrocarbons.	Santiago Oil Company
Ecopetrol Global Capital SLU	100	-	-	Investment vehicle	-
Bioenergy Zona Franca SAS	88.59	88.59	88.59	Exploration and operation of plants for productions of biofuels	-
Hocol Limited	100	100	100	Investment Vehicle
Hocol S.A.	100	100	100	Exploration and development of Hydrocarbons	-
Homcol Cayman Inc.	100	100	100	Investment Vehicle	-
ODL S.A. Panamá	65	65	65	Desing, build and operate pipelines for transportation of hydrocarbons	-
Oleoducto de los Llanos Orientales S.A.	100	100	100	Desing, build and operate pipelines for transportation of hydrocarbons	-

 Company and some of its subsidiaries develop operations of exploration and production through exploration and production contracts (E&P), Technical Evaluation Contracts (TEAs), and agreements entered into with the ANH, as well as joint ventures and other kind of contracts, in different modalities. The situation at the end of December, 2011 was the following:

	No. Contracts
Contract Type	Ecopetrol S. A.		Hocol Petroleum Ltd.		Ecopetrol Oleo é Gas do Brasil Ltda.		Ecopetrol America Inc.		Ecopetrol del Perú S. A.		Equion Energia Limited
Exploration
E&P Contracts -ANH		37		15		-		-		6		2
E&P Agreements -ANH		5		-		-		-		-		-
TEA’s – ANH		3		-		-		-		-		-
Association contracts		4		1		10		44		5		-
Production
Association		56		9		-		1		-		4
Contracts E&P-ANH		-		1		-		-		-		-
undeveloped discovered fields and inactive (CDNDI)		16		-		-		-		-		-
Only risk		-		-		-		-		-		1
Incremental Production		5		1		-		-		-		-
Share of risk		3		-		-		-		-		-
Technological alliance		1		-		-		-		-		-
Business collaboration		1		-		-		-		-		1
Services and technical collaborationa		1		-		-		-		-		-
Participation Shared Risk		1		-		-		-		-		-
Operation		1		-		-		-		-		-
Services of production with risk		2		-		-		-		-		-
		136		27		10		45		11		8

F-12

Principal Accounting Policies and Practices

The Contaduría General de la Nación or CGN adopted new accounting principles for Colombian state-owned entities in September, 2007, stipulating its conformation and defining scope and application thereof. These accounting principles are known as the Régimen de Contabilidad Pública (Regime of Public Accounting or RCP). Pursuant to CGN Communication No. 20079-101345 of September 28, 2007, RCP became effective for Ecopetrol beginning January 1, 2008.

Principles of Consolidation

The consolidated financial statements have been prepared pursuant to the provisions of Article 27 of the Commerce Code and Articles 23 and 122 of Decree 2649/1993. The latter article states that the economic entities that holds more than 50% of the capital of other economic entities are required to provide, along with their basic financial statements, the consolidated financial statements and the accompanying notes using the Full Integration consolidation method established in External Circular No. 005 issued on April 6, 2000 by the Superintendence of Companies.

Presentation Basis

The preparation of the consolidated financial statements was carried out under Colombian Government Entity GAAP standards and principles issued by the CGN and other legal provisions. These principles may differ in certain aspects from those established by other accounting standards and other control authorities and the opinions on specific matters issued by CGN prevail over other regulations.

The accrual method was applied for the accounting recognition of financial, economic, environmental and social aspects.

In accordance with the rules for the inspection, supervision, and/or control of Ecopetrol and the companies that apply Colombian Government Entity GAAP to record operations at the level of source documents or for purposes of standardization, a structure was established to define the accounting treatment of operations not envisaged by the CGN, which is as follows: i) Principal and permanent inspection, supervision, and control: Superintendence of Domiciliary Public Services; ii) Residual control: Superintendence of Corporations and iii) Concurrent control: Superintendence of Finance, on the activities of the Company in its capacity as issuer in the stock market. International Financial Reporting Standards (IFRS) are applied when accounting guidance under Colombian Government Entity GAAP does not address specific accounting issues applicable to the Company, while accounting standards under accounting principles generally accepted in the United States (US GAAP) are applied for accounting issues related to crude oil and natural gas reserves.

The consolidated financial statements include the accounts of the companies in which the Company holds, either directly or indirectly, more than 50% of their voting capital, or over which it has a significant influence despite not being the majority shareholder. All intercompany transactions and balances have been eliminated. The financial statements attached hereto consolidate the assets, liabilities, equity and income of the Ecopetrol subsidiaries.

Certain reclassifications have been made to prior years’ financial information to conform to the current year, presentation.

Materiality Concept

An economic fact is material when, due to its nature and amount and the circumstances that surround it, its knowledge or lack thereof can significantly alter the economic decisions of the users of the financial information.

As set forth by the RCP, the information revealed in the financial statements and financial accounting reports must include the principal issues of the public accounting entity, in such a way that it must be significantly close to the truth, and be reliable for decision making and evaluation, in accordance with the accounting information objectives. The materiality depends on the nature of the facts or the magnitude of the amounts revealed or not revealed.

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 income, as appropriate. In addition, lower amounts are shown when they are deemed to contribute to a better interpretation of financial information.

Use of Estimates

Preparation of the consolidated financial statements requires that management of the Corporate Group companies make estimates and assumptions that could affect the recorded amounts of assets, liabilities, results of operations and the attached notes. These estimates are carried out in accordance with technical criteria pursuant to regulations and current legal provisions. Actual market values could differ from such estimates.

F-13

Transactions in Foreign Currency

Transactions in foreign currency are entered into in accordance with applicable regulations and 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 at the end of each period.

The adjustment for exchange differences generated by foreign currency assets and liabilities is recorded against results of operations, except when such adjustment is charged to capital investments in controlled entities, in which case is recorded as equity.

The financing costs, including the foreign currency, associated with assets purchased under construction, are part of the overall cost of these assets until they are ready for use.

The financing costs, including the foreign currency, associated with assets purchased under construction, are part of the overall cost of these assets until they are ready for use.

Ecopetrol and the Corporate Group Companies associated to crude oil exploration and production activities can freely deal in foreign currency provided that they comply with the provisions of the foreign exchange regime.

With respect to those companies whose financial statements were originally presented in a currency other than the Colombian pesos, the financial statements were first converted into US dollars and then into Colombian pesos. Market exchange rates at December 31, 2011 were used to convert the balance sheet accounts, weighted average exchange rates were used to translate income statement accounts and historical exchange rates were used to translate equity statement accounts.

Joint Venture Contracts

Joint venture contracts are entered into between Ecopetrol or the Corporate Group companies and third parties in order to share the risk, raise capital, maximize operating efficiency and optimize the recovery of reserves.

In these joint ventures, one party is designated as the operator and each party takes its share of the crude oil production according to its agreed participation. When any of the Corporate Group companies participates as a non-operating party, it records these assets, revenues, costs and expenses on a timely basis based on information reported by the operators. When any of the Corporate Group companies directly operates the facilities, it recorded to 100% of assets, revenues, costs and expenses, recognizing on a monthly basis the distribution in accordance with the participation interests of each partner in the line items corresponding to investments, inventories, expenses, costs and revenues for the associate.

Cash and Cash Equivalents

Cash and cash equivalents are represented by negotiable investments with maturity dates within ninety (90) days following their acquisition date and are recorded as cash management investments.

Cash from joint venture contracts in which the Company is the operating partner corresponds to advances from partners (including Corporate Group companies), according to their contractually agreed participation percentages, and funds are managed in a joint operation exclusive-use bank account.

Financial Derivative Instruments

Ecopetrol S.A. and the Corporate Group companies enter into hedging agreements to hedge against the fluctuations of international crude oil, products prices and exchange rates. The difference between amounts paid and income received under hedging operations is recognized as financial income or expense in the statements of financial, economic, social and environmental activities. Ecopetrol and its Corporate Group companies do not use these financial instruments for speculative purposes.

According to the Ecopetrol corporate governance policies, the Company’s Management and Finance Committee makes periodic evaluations of hedging operations based on the market risk determining the need for extension or early termination of the subscribed contracts, when the result is ineffective against the hedged items. In the event of settlement, the financial and contractual effects are recognized in the results of the period.

Investments

The investments are classified as: i) Liquidity Management Investments, ii) Investments for Policy Purposes and iii) Equity Investments.

i. Liquidity management investments correspond to resources invested in debt and equity securities with the objective of obtaining profits through short-term price fluctuations. Their initial recording corresponds to their historical cost and they are updated based upon valuation methodologies issued by the Colombian Superintendence of Finance.

ii. Policy purpose investments are made up of debt securities of national or foreign issuers, acquired in compliance with macroeconomic or internal policies of the Corporate Group, which include investments held through their maturity date and those available for sale, being those which are kept for at least one (1) year, as of the first day on which they were classified for the first time, or when they were reclassified.

F-14

Investments held to maturity are updated based on the Internal Rate of Return (IRR) included in the methodologies adopted by the Superintendence of Finance and the investments for the purpose of macroeconomic policy and available for sale should be updated based on methodologies adopted by the Superintendence of Finance for tradable investments.

iii. Equity investments are classified in controlled and uncontrolled entities. Equity investments in controlled entities are recognized at their acquisition cost whenever it is less than the net book value; otherwise, they are recognized at the net book value and the difference between the purchase price and the net book value corresponds to goodwill. Their values are updated using the equity method, as established in Resolution 145 of 2008, issued by the CGN.

Investments in associated entities which are defined as entities where the Company exerts significant influence, are recorded using the equity method.

Significant influence is defined as the power that the entity has, regardless if the ownership percentage is less than or equal to 50%, to participate in the setting and overseeing of financing and operational policies of another entity for the purpose of obtaining profits from that entity.

Significant influence may be present in one or more of the following aspects:

• Representation on the Board of Directors or equivalent governmental body of the associated entity.

• Participation in policy-making processes.

• Significant transactions between the investor and the associated entity.

• Secondment of officers, or

• Supply of essential technical information.

Equity investments in non-controlled entities include shares of low or minimum liquidity or shares without any trading volume on a stock exchange, which do not permit any type of control or significant influence and are recognized at historical cost; their change in value arises from the periodic comparison of the cost of the investment to its net book value or its value in the stock market.

Equity variances generated by adjustments in the conversion of the controlled entity are recognized as surplus under equity method, without prejudice of the subaccount with a debit balance, in agreement with Resolution 193 of July 27, 2010 issued by the Contaduria General de la Nación.

Investments made in foreign currency are recognized by applying the Representative Market Exchange Rate (TRM, per its Spanish acronym) of the transaction date. The value shall be re-expressed periodically based on the TRM, as long as this is not considered by the updating methodology.

When the technical standards for assets and liabilities do not consider specific methodologies for updating of the rights and obligations in foreign currency, they must be recalculated monthly into the local currency, using the closing exchange rate at the end of the month, certified by the Superintendencia Financiera de Colombia, and previously converted in to US dollars, in case it is expressed in a different currency. For that purpose, the exchange rate used is the one provided by the Banco de la República.

Receivables and Provision for Doubtful Accounts

Receivables of the Corporate Group companies are recognized at their original amount or at the amount accepted by the debtor, which is subject to periodic updating in accordance with current legal provisions or agreed contractual terms.

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

Write-offs of accounts and notes receivable against the provisions will only proceed when there is reasonable legal or material certainty on the total or partial loss of the incorporated or represented right.

Inventories

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

F-15

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

The valuation of inventories is measured using the weighted average method, considering the following parameters:

• Crude oil inventories for the Company´s own production, at production cost

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

• Finished goods inventory, at total production costs

• Work in progress inventory, at production costs

• Raw material inventory, at weighted average cost

• Raw material 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). Inventory consumption is charged to the joint venture as an expense or as an investment, as appropriate.

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

Property, plant and equipment and depreciation

Property, plant and equipment are recorded at the historical cost, adjusted for inflation until 2001, which includes financial expenses and exchange differences from acquisition costs in foreign currency until the asset is put into operation, and the financial revenues corresponding to the still unused portion of financial obligations acquired to finance investment projects. 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 useful lifes. Annual depreciation rates used are:

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

Regular disbursements for maintenance and repairs are included in expenses. Significant disbursements which improve efficiency or extend asset’s useful life are capitalized as an increase in the value of the respective asset.

The value of property, plant and equipment is subject to periodic update by comparing the net book value with the value determined through technical appraisals. When the value of the asset technical appraisals is greater than its net book cost, the difference is recorded an asset valuation credit to the surplus account for equity valuation; otherwise, it is recorded as provision for devaluations charged to results.

Upon termination of an association contract, Ecopetrol S.A. receives, at no cost, the property, plant and equipment, the materials and the oil amortizable investment owned by the associate company. This transaction does not affect the Company results. The results of the technical valuation of the property, plant and equipment are recognized as valuation in the respective asset and equity accounts.

Natural and Enviromental Resources

The Corporate Group applies the successful efforts method of accounting for investments in exploration and production areas. The geological and geophysical seismic information is expensed as incurred, before the discovery of proved reserves. Acquisition and exploration costs are capitalized until the time in which it is determined if that exploratory drilling was successful. If exploratory drilling results are unsuccessful, all incurred costs are recorded as an expense. When a project is authorized for development, the accumulated acquisition and exploration costs are transferred to the oil investment account. Costs capitalized also include assets retirement costs. Asset and liability balances related to asset retirement costs are updated every six months. Production and support equipment are accounted for on a cost basis and are part of the property, plant and equipment subject to depreciation.

F-16

Oil investments are amortized by applying the production technical units method on the basis of royalty-free proven developed reserves per field, estimated as of December 31st of the immediate preceding year. The amortization charged to results is adjusted at the close of December, recalculating the DD&A (Depletion, Depreciation and Amortization) as of January 1 of every year, based on the reserve study updated at the end of the current year.

Ecopetrol has established a reserves corporate process, controlled by the reserves group, which reports directly to the Corporate Financial Vice-president. The reserves are audited by internationally recognized external consultants, approved by the Company Reserves Committee of Ecopetrol and the Boards of Directors of each subsidiary, as applicable. Proved reserves consist of estimated quantities of crude oil and natural gas which geological and engineering data demonstrated 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.

Since Ecopetrol became an issuer on the Colombian Stock Exchange (Bolsa de Valores de Bogotá - BVC) and the New York Stock Exchange (NYSE), the Corporate Group companies has applied the methodology approved by the SEC (Securities Exchange Commission) for the calculation of natural gas and crude oil reserves. As per such methodology, the reference price is the arithmetical average of the WTI crude oil price in the last twelve (12) months.

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 period that this is known.

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

Deferred Charges

Deferred charges include deferred income tax, which results from the temporary differences arising due to the different methods for determining book profit and taxable income at the end of each year.

Other Assets

Other assets include goodwill, which corresponds to the difference between the purchase value of the equity investments in controlled or under shared control entities and their book intrinsic value, which reflects the economic benefits expected to be achieved from the investment, originating in goodwill, specialized personnel, reputation of privileged credit, prestige due to sale of better products and services, favorable location and expectations of new business, among others.

Goodwill is amortized based on methodologies of acknowledged technical value over the term in which recovery of the investment is expected. At the close of each accounting period, the corporate goodwill shall be assessed to determine if the conditions for generation of future economic benefits still exist; otherwise, the asset shall be retired. If the book value of equity investment, plus the book value of goodwill which includes its historical cost added to all price adjustments and amortizations, is greater than the market value, the asset shall, as a result of such difference, be retired in the related period, with charge to results of operation, and the reasons by which such decision was based shall be disclosed.

Software, licenses and patents are recognized at their development or production cost. Intangible assets are amortized using the straight line method during the periods when it is expected to receive the benefits from the incurred costs and expenses, or during the term of the legal or contractual coverage of the granted rights.

Reappraisals assets

a. Investments

Revaluations correspond to the difference between the net book value and the intrinsic value or the price quoted on a stock exchange.

b. Property, Plant and Equipment

Revaluation and Revaluation surplus of property, plant and equipment correspond to the difference between net book value and the market value for real estate or the current value in use (VAU) for property, plant and equipment, determined by specialists registered with the Colombian Real Estate Association or by suitable technical personnel, as appropriate.

The methodology used to appraise property, plant and equipment is the current value of the assets in use (VAU) by going businesses for economic valuation of assets, considering current facilities condition and their useful lives in terms of production capability and ability to generate income.

For office equipment, the historical value to the appraisal value adjustment is not mandatory when the historical value is lower than 35 current monthly legal minimum wages, or when the property, plant and equipment is located in a high risk zone.

F-17

Financial Obligations

Public credit operations pertain to any action or contract which, in compliance with legal regulations on public credit, are addressed to supply the Company with resources, goods and services under specific payment terms such as loans, issue and placement of bonds and public credit securities, and vendors’ credit.

With respect to loans, public credit operations must be recorded for the actual disbursed amount while bonds and securities placed are recorded at their par value. Placement costs are booked directly to expenses.

Accounts payable – Suppliers

Accounts payable correspond to obligations incurred by Corporate Group companies with third parties in order to comply with its corporate purpose.

Income Tax

The provision for income tax at the end of the year was calculated in each company by applying the income before tax effective rate of taxation, determined based on the reconciliation of commercial income and the taxable income.

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 asset or liability, as applicable, provided that a reasonable expectation exists that such differences will reverse in the case of the deferred tax asset, that sufficient taxable income will be generated to recover the tax with regard to the deferred tax liability. The deferred tax balance was calculated at the applicable rate of 33%.

Labor and Pension Obligations

The system for salaries and fringe benefits for Ecopetrol S.A. personnel is governed by the Collective Labor Agreement 01 of 1977, and in the absence thereof, by the Labor Code. In addition to fringe benefits, the employees are entitled to receive additional benefits covered by previous regulations that depend on the place, type of work, length of service, and basic salary. Annual interest of 12% is recognized 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 and indefinite term contract, retirees and heirs, and for pension concepts, health care and education plans; it likewise includes pensions bonds for temporary employees, active employees and voluntary retirements. It is important to note that health and education are not part of the pension liabilities.

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 mortality table, prepared on the basis of facts occurring during 2011. 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 type of studies: pre-school, primary, high school and university.

For employees who joined the Company subsequent to the enactment 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 January 29, 2003 determined that Ecopetrol employees who joined the Company as of that date, will be subject to the provisions of the General Pension Regime.

By virtue of Legislative Act 01 of 2005, enacted by Congress, the pension regimes excluded from the General Social Security System in Colombia expired on July 31, 2010. In accordance with provisions therein, the decision of the Ministry of Social Protection and the analyses conducted by the labor advisers of Ecopetrol S.A., it was concluded that those workers who complied with the age and continuous or discontinuous service time requirements of the law, the Collective Bargaining Agreement currently in force and/or Agreement 01 of 1977, prior to August 1, 2010, consolidated their right to the pension, while for other workers who were not covered, it is mandatory to be affiliated with the General Pension System. The agency responsible for paying the respective pension will be the pension administrator chosen by the worker (either the Social Security Institute or private pension funds). The transferred liability corresponds only to pensional and pension bonds; the portion relating to health care and education services remain as Ecopetrol’s direct labor obligations. In case the yields of the autonomous equity are not sufficient to cover 100% of the actuarial calculation as updated every year, Ecopetrol shall draw the resources to complete funding of the pension liabilities, since Ecopetrol remains liable for payment of pension liabilities transferred (“commuted”).

Through Resolution 1555 of July 30, 2010, the Superintendence of Finance replaced the Mortality Tables used to prepare actuarial calculations and stipulated that the effects from such change could be recognized gradually. Subsequently, Decree 4565 of December 7, 2010 modified the accounting standards for amortization of the actuarial calculation in force up to that date. Pursuant to the new decree, the companies that had amortized 100% of their actuarial calculation at December 31, 2009, may gradually amortize up to the 2029, the increase in the actuarial calculation for 2010 estimated by using the new Mortality Tables.

F-18

In view of the foregoing, in 2010 Ecopetrol modified its accounting policy for amortization of the actuarial calculation of monthly pension payments, pension quotas, parts and bonds (transferred liabilities) and health bonds, and adopted a 5-year term as of 2010 to amortize the increase in the 2010 actuarial calculation. Up to 2009, the yearly increase in the actuarial calculation was recorded as expenses of the period, considering that the actuarial calculation was 100% amortized.

Advances Received from Ecogas to Cover, Build, Operate, Mantain and Transfer (BOMT) Obligations

As a result of the sale of Ecogas by the National Government, and following specific instructions from CGN, the net present value of future payments was recognized as deferred income, in connection with Ecopetrol´s liability related to BOMT contractors. These liabilities are due in 2017, the year when the contractual obligations end.

Purchase of Hydrocarbons

Ecopetrol purchases hydrocarbons that the ANH receives as royalty payments from all of the production in Colombia, at prices established according to section 4 of Law 756 of 2002 and Resolution 18-1709 of 2003 of the Ministry of Mines and Energy, considering the international prices of reference.

Additionally, it purchases hydrocarbons both from partners as well as from other producers in Colombia and abroad to meet the needs and operating plans of the corporate group.

Recognition of Income

Income from crude oil and natural gas sales is recognized at the time of transfer of title to the buyer, including its risks and benefits. 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 is recognized when products are transported and delivered to the buyer in accordance with sale terms. In other cases, income is recognized at the time it is earned and a true, probable and quantifiable right to demand its payment arises.

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

By virtue of the current regulations, Ecopetrol S.A. and the Refinería de Cartagena S.A., sell at a regulated price and the Government recognizes the amount of the subsidy granted by these companies for regular motor gasoline and diesel, for local consumers, which is generated by adding the differences, for every day of the month, between the producer’s regulated revenues and the daily price equivalent to the U.S. Gulf reference market price, calculated as per its origin, multiplied by the daily volumes sold. Resolution 182439 and Decree 4839 of December 2008 establish the procedure to recognize subsidies in the event they are negative (negative value between parity and regulated prices).

In March 2010, the Ministry of Mines and Energy issued Resolution No. 180522, which revoked provisions contrary to Resolutions 181496 of September 2008, 182439 of December 30, 2008 and 180219 of February 13, 2009 and modified the formula for calculating the gasoline and diesel international reference prices.

Cost of Sales and Expenses

Costs are recognized at their historical value both for goods purchased for sale and for accumulated production costs of goods produced and services rendered. Costs are disclosed according to the operation which generates them.

Expenses correspond to amounts required for the development of the ordinary activity and include those caused by extraordinary events. Expenses are disclosed in accordance with their nature and the occurrence of extraordinary events.

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

Abandonment of Fields

The Corporate Group recognizes the liability for future environmental obligations and its corresponding entry is capitalized as a greater value of natural and environmental resource assets. The estimation includes plugging costs and abandonment of wells, dismantling of facilities and environmental recovery of areas and wells. Amortization expense is recorded as 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 capitalized to the respective asset.

Based on the extension of certain association contracts, the abandonment costs are assumed by the associates in the percentages of participation established in each contract.

F-19

Ecopetrol has not allocated funds in order to cover these obligations, with the exception of association contracts Casanare, Guajira, Tisquirama, Caño Limon Coveñas and Cravo Norte Pipeline; However, to the extent that activities are generated which are related to abandonment, these will be covered by the Corporate Group.

In 2010, the policy for estimating the portion of abandonment/retirement obligations, previously due in U.S. dollars, was changed to Colombian pesos as most payments (greater than 70%) are made in pesos.

Accounting for Contingencies

As of the date that these consolidated financial statements were issued, conditions that result in losses for the Company might exist, which will only be known if future specific circumstances arise. Management, the legal Vice Presidency and legal counsels evaluate these situations based on their nature, the likelihood that they will materialize, and the amounts involved, to decide on any changes to amounts accrued and/or disclosed. This analysis includes current legal proceedings against the Corporate Group.

The methodology applied to assess current legal proceedings and any contingent obligation is based on the credit system of the Nation, which is used by the Ministry of the Interior and the Ministry of Justice.

A provision is allocated for legal proceedings when there is a first instance conviction or the risk assessment results are “Likely to Losses”.

Risk and Uncertainties

The Corporate Group companies are subject to certain operational risks which are customary to this industry in Colombia and abroad, such as terrorism, product theft, crude oil international price changes, environmental damage, and variations in the estimations of hydrocarbon reserves.

Memorandum Accounts

Creditor and debtor memorandum accounts represent the estimation of facts or circumstances from which rights or obligations could affect the Corporate Group companies’ financial, economic, social and environmental position. They also disclose the value of goods, rights and obligations that must be controlled and include, additionally, the differences between the accounting information and the information used for tax purposes.

Earnings per Share

Earnings per share are calculated based in the annual weighted average of outstanding issued shares.

(2) Assets and Liabilities Denominated in Foreign Currency

Transactions and balances in foreign currency are translated into Colombian pesos at the market exchange rate certified by the Superintendence of Finance of Colombia.

F-20

At December 31, 2011 and 2010, the consolidated financial statements of Ecopetrol included the following assets and liabilities denominated in foreign currency which are translated into Colombian pesos at the closing exchange rates of, $1,942.70 and $1,913.98 for US$1, respectively.

	2011				2010
	Thousands of US$		Equivalent millions of COP		Thousands of US$		Equivalent millions of COP
Assets
Cash and cash equivalents		1,387,341		2,695,187		822,496		1,574,241
Investments		3,142,338		6,104,620		2,400,833		4,595,146
Accounts and notes receivables		2,722,535		5,289,069		766,604		1,467,265
Advances and deposits		58,644		113,928		681,508		1,304,393
Other assets		4,024		7,817		47,498		90,910
		7,314,882		14,210,621		4,718,939		9,031,955
Liabilities
Financial obligations		1,700,334		3,303,239		1,668,906		3,194,253
Estimated liabilities and provisions		248,652		483,056		55,081		105,424
Accounts payable and affiliates		1,135,850		2,206,616		757,365		1,449,581
Other liabilities		663,960		1,289,875		422,251		808,180
		3,748,796		7,282,786		2,903,603		5,557,438
Net Asset position		3,566,086		6,927,835		1,815,336		3,474,517

(3) Cash and cash equivalents

The following is a detail of cash and cash equivalents:

	As of December 31,
	2011		2010
Banks and saving entities (1)		5,258,620		2,124,461
Special funds (2)		1,043,726		555,716
Sight investments (3)		279,583		1,046,131
Cash		3,699		470
		6,585,628		3,726,778

(1) Corresponds to advances made by the partners to Ecopetrol S.A. for use in the joint operation for $52,533 (2010 – $11,217) and the Corporate Group´s own resources for $5,206,087 (2010 - $2,113,244).

(2) Includes savings in special funds denominated in Colombian pesos and foreign currency $945,035 (2010 - $400,795) and investments in overnight operations of $80,109 (2010- $154,899).

(3) Mainly represented by time deposits TDs (CDT) and overnight operations, between which the most representative are: $99,435 of Ocensa S.A, $83,482 of Reficar, $56,358 of Hocol, $14,838 of Ecopetrol Óleo E Gas Do Brasil and $11,934 of Equión.

The decrease corresponds mainly to Time Deposit Certificates (CDT) established in foreign currency that Ecopetrol S.A. held as of December 31, 2010. At December 31, 2011 all of these investments were consumed by working capital requirements for its scheduled of expected and realized payments.

F-21

(4) Investments

The following is a detail of investments:

	As of December 31,
	2011		2010
Current
Fixed yield: (1)
Bonds and securities of private or foreign entities		512,378		132,261
Bonds issued by the Colombian Government		398,959		-
Term deposits		194,309		-
Treasury Securities – TES		191,204		1,463
Investment funds administered by third parties		149,021		188,461
Other investments		86,026		5,597
Hedging financial instruments		14		-
Total current		1,531,911		327,782
Long-Term
Variable yield – Shares (2)		1,020,059		830,170
Fixed yield:
Bonds and securities of foreign entities		3,303,859		2,275,466
Bonds issued by the Colombian Government		869,710		642,449
Treasury Securities – TES		-		1.067,799
Specific destination funds – Legal contingencies		273,805		361,607
Other investments		7,372		-
Total long-term		5,474,805		5,177,491

(1) The changes in these investments correspond to the schedule that the money desk carries out to cover working capital requirements that the Company must abide by in its debt operations.

(2) Variable Income - Stock:

A summary of long-term investments of variable yield as of December 31, 2011, valued under the cost method is set forth below:

Equity Share	Number of shares and/or quotes		Participation percentage	Valuation month in 2011	Historical Cost		Intrinsec/ Market value		Revaluation/Provisions
Strategic
Amandine Holding		500	100	March		6,657		6,657		-
Los Arces Group		10,001	100	March		5,100		5,100		-
Zona Franca Cartagena S.A.		290	10	November		392		1,755		1,363
Concentra S.A.		84,000	5	October		85		92		7
Sociedad Portuaria del Dique		200	1	November		5		17		12
Total strategic						12,239		13,621		1,382
Non-strategic
Empresa de Energía de Bogotá (1)		631,098,000	6.87	December		154,376		741,540		587,164
Interconexión Eléctrica S.A		58,925,480	5.32	December		69,549		659,966		590,417
Total non-strategic						223,925		1,401,506		1,177,581

F-22

A summary of long-term investments of variable yield as of December 31, 2010 valued under the cost method is set forth below:

Equity Share	Number of shares and/or quotes		Participation percentage		Valuation month	Cost		Intrinsec/ Market value		Valuation/devaluation
STRATEGIC
Sociedad Portuaria Oleofinas		249,992		50	December		333		390		57
Zona Franca Cartagena S.A.		290		10	November		393		745		352
Sociedad Portuaria el Dique		200		0.5	November		5		5		-
							731		1,140		409
NON STRATEGIC
Empresa de Energía de Bogotá		6,310,980		7.35	December		169,421		1,101,266		931,845
Interconexión Eléctrica S.A		58,925,480		5.32	December		69,550		830,850		761,300
							238,971		1,932,116		1,693,145

A summary of variable yield long-term investments, valued under the equity method, is set forth below:

	Number of shares		Participation	Valuation month
Equity share	and/or quotes		percentage	2011	Historical cost		Adjusted cost		Equity method effect
Significant Influence
Serviport S.A.		53,714,116	49	November		2,081		5,129		3,048
Ecodiesel Colombia S.A.		10,500,000,000	50	December		10,500		10,681		181
Offshore International Group		250	50	December		408,517		493,171		84,654
Invercolsa S.A.		1,213,801,146	43.35	November		61,672		232,757		171,085
Sociedad Portuaria Olefinas		249,992	50	November		333		329		(4	)
Transgas		27,372,771	20	November		4,051		41,828		37,777
Total						487,154		783,895		296,741

A summary of variable yield long-term investments as of December 31,2010, valued under the equity method, is set forth below:

	Number of shares		Participation						Equity method
Equity share	and/or quotes		percentage	Valuation month	Historical cost		Book value		effect
Significant influence
Offshore International Group		250	50	December		404,664		390,479		(14,185	)
Invercolsa S.A.		889,410,047	31.76	November		60,282		170,523		110,241
Ecodiesel Colombia S.A.		7,750,000,000	50	November		10,500		11,706		1,206
Serviport S.A.		53,714,116	49	November		2,081		7,182		5,101
Amadine Holding		500	100	March		6,657		6,658		1
Arces Group		10,001	100	March		6,000		3,920		(2,080	)
Total						490,184		590,468		100,284

Restrictions over long-term investments – Variable income:

Among the advances of the legal process of INVERCOLSA as of December 31, 2011, the appeal (recurso de casación) stands out based on the Appelate Court of the Judicial District of Bogotá and the setting of a $4,354 fee, which was deposited at Banco Agrario de Colombia, suspending the execution of the judgment issued on January 11, 2011. Since December 14, 2011, the appeal (recurso de casación) is in the Office of the Presiding Judge for purposes of admission. It is important to remember that the appeal sentence of January 11, 2011 stated the following: i) Cancellation of the purchase of 145,000,000 shares of Invercolsa made by Fernando Londoño Hoyos, ii) Maintained record in shareholders books for the cancellation of such acquisition, including the pledge in favor of Bancos del Pacifico Colombia and Panama; and the transfer payment of shares of Arrendadora Financiera Internacional Bolivariana S.A., and iii) maintained records in shareholders books for the number of shares in favor of Ecopetrol and issued the respective tittles, as if the sale had never taken place.

During the months of October and November 2011, the third and the fourth dividend quotas were declared and were paid to Ecopetrol in March 2011.

F-23

The economic activity and the net income for companies in which Ecopetrol has investments in for 2011 and 2010 are set forth below:

				Net Income (Loss)
		Net Income (Loss)		December
Company	Economic Activity	December  2011		2010
Interconexión Eléctrica S.A. (2)	Operation, maintenance, transmission and sale of electrical energy power	336,776			305,496
Empresa de Energía de Bogotá S.A. E.S.P (1)	Electric power transmission	226,124			1,074,394
Invercolsa S.A.  (3)	Investments in energy sector companies including activities inherent to the industry and commerce of hydrocarbons and mining	59,946			87,755
Serviport S.A. (3)	Provision of support services for loading and unloading of crude oil ships, supply of equipment for the same purpose, load inspections measurements	(368	)		(1,637	)
(*) Ecodiesel Colombia S.A.  (2)	Production, sale and distribution of bio-fuels and oleochemicals	-			2,073
Offshore International Group (2)	Exploration, development, production and processing of Hydrocarbons	76,680			109,283

(1)          Information as of September 2011

(2)          Information as of December 2011

(3)          Information as of November 2011

(*) Entities in pre-operational stage and/or exploration activities.

F-24

A summary of Ecopetrol’s consolidated subsidiary balances as of December 31, 2011 are set forth below:

Company	Assets		Liabilities		Equity			Net income (loss)
Hocol Petroleum Limited		3,014,227		735,644		2,278,583			629,920
Equion Energía Limited		3,173,242		954,496		2,218,746			426,454
ODL Finance S. A.		2,141,360		1,463,605		677,755			82,046
Polipropileno del Caribe S.A.		1,174,623		518,385		656,238			31,827
Compounding and Masterbatching Industry Ltda - COMAI		122,153		39,706		82,447			25,698
Black Gold Re Ltd		288,870		37,296		251,574			24,350
Ecopetrol Transportation Investments		701,151		68		701,083			9,029
Ecopetrol Transportation Company		1,236,623		-		1,236,623			5,541
Ecopetrol Global Capital SL		8		-		8			-
Oleoducto Central S.A.		4,612,852		1,268,189		3,344,663			-
Ecopetrol Capital AG		1,870,902		1,872,127		(1,225	)		(1,440	)
Oleoducto Bicentenario de Colombia S.A.S.		1,499,815		776,390		723,425			(3,501	)
Oleoducto de Colombia S.A.		493,935		38,322		455,613			(8,101	)
Bioenergy S.A.		275,011		176,614		98,397			(10,099	)
Ecopetrol del Perú S.A.		73,638		5,226		68,412			(15,914	)
Ecopetrol Oleo é Gas do Brasil Ltda.		241,331		257,838		(16,507	)		(128,537	)
Refineria de Cartagena		7,061,030		4,500,437		2,560,593			(161,993	)
Ecopetrol América Inc		1,017,061		58,074		958,987			(197,372	)

A summary of the Ecopetrol’s consolidated subsidiaries balances as of December 31, 2010 are set forth below:

Company	Assets		Liabilities		Equity		Net income (Loss)
Oleoducto Central S.A.		2,140,871		1,560,321		580,550		277,468
Hocol Petroleum Limited		2,348,365		712,051		1,636,314		232,762
Polipropileno del Caribe S.A.		1,062,360		426,305		636,055		65,439
Compounding and Masterbatching Industry Ltda - COMAI		110,107		39,527		70,580		43,243
ODL Finance S. A.		1,854,165		1,414,707		439,458		18,553
Black Gold Re Ltd		236,143		12,928		223,215		12,215
Ecopetrol Capital AG		254,095		253,890		205		-
Ecopetrol Transportation Investments		681,468		18		681,450		(18	)
Bioenergy S.A.		120,502		19,208		101,294		(3,536	)
Oleoducto de Colombia S.A.		333,934		55,526		278,408		(6,052	)
Oleoducto Bicentenario de Colombia S.A.S.		271,960		1,105		270,855		(16,615	)
Ecopetrol del Perú S.A.		68,031		22,274		45,757		(94,920	)
Ecopetrol Oleo é Gas do Brasil Ltda.		153,490		33,957		119,533		(211,460	)
Refineria de Cartagena		4,201,911		1,475,395		2,726,516		(305,187	)
Ecopetrol América Inc		950,578		27,140		923,438		(543,198	)

The classification of treasury investments depends on the use of the funds, their destination and maturity. Investments whose maturity or realization is shorter than one year are classified as short-term.

A summary of the non-current fixed yield investments as of December 31, 2011 is set forth below:

Maturity	1 - 3 Years		3 - 5 Years		> 5 Years		Total
Bonds and other foreign securities		3,218,402		85,457		-		3,303,859
Bonds and other government securities		768,385		-		101,325		869,710
Specific destination fund		139,427		15,827		118,551		273,805
Other investments		7,372		-		-		7,372
		4,133,586		101,284		219,876		4,454,746

F-25

A summary of the non-current fixed yield investments as of December 31, 2010 is set forth below:

Maturity	1 - 3 Years		3 - 5 Years		> 5 Years		Total
Bonds and other foreign securities		1,968,578		306,888		-		2,275,466
Bonds and securities issued by the Colombian Government		473,358		123,532		45,560		642,450
Treasury Securities – TES		485,038		217,793		364,968		1,067,799
Specific destination fund		144,035		11,872		205,699		361,606
		3,071,009		660,085		616,227		4,347,321

(5) Accounts and Notes Receivable

The following is a detail of the accounts and notes receivable:

	As of December 31,
	2011			2010
Current portion
Customers
Local		964,697			868,238
Foreign		2,578,421			1,282,132
Price differential to be received from the Ministry of Mines and Energy (1)		571,742			163,386
Other debtors		432,610			287,594
Reimbursements and investment yields		2,968			3,141
Association contracts – Joint operations		12,234			60,026
Accounts receivable from employees		61,005			33,171
Doubtful accounts		131,750			100,218
Industrial service customers		19,005			26,241
Notes receivable		75			13,845
Total		4,774,507			2,837,992
Less: Allowance for doubtful accounts		(138,673	)		(101,400	)
Total current portion		4,635,834			2,736,592
Long-term portion
Local		1,183			-
Foreign		3,143			-
Cavipetrol - Loans to employees (2)		282,947			245,824
Credit portfolio (3)		5,836			20,156
Other		114,820			106,293
Total Long–term portion		407,929			372,273

The aging determination and classification of the accounts receivable to customers as of December 31, 2011, pursuant to maturity is set forth below:

	Maturity in days
	0 – 180		181 – 360		More than 361*
Current accounts receivable		3,210,484		1,051		-
Past due accounts receivable		225,900		105,683		4,326
		3,436,384		106,734		4,326
Local customers		963,646		1,051		1,183
Foreign customers		2,472,738		105,683		3,143
		3,436,384		106,734		4,326

F-26

The aging determination and classification of the accounts receivable to customers as of December 31, 2010, pursuant to maturity is set forth below:

	Maturity in days
	0 – 180		181 – 360		More than 361*
Current accounts receivable		1,898,641		33		-
Past due accounts receivable		92,043		107,757		-
		1,990,684		107,790		-
Local customers		818,783		1,554		-
Foreign customers		1,171,901		106,236		-
		1,990,684		107,790		-

* Customer receivables included in doubtful accounts.

The changes in the allowance for doubtful accounts are set forth below:

	For the years ended December 31,
	2011			2010			2009
Initial Balance		101,400			64,063			33,679
Additions (New provisions)		32,422			169,789			34,608
Recoveries of allowances		(365	)		(68,772	)		(779	)
Receivables write-off		(770	)		(60,866	)		-
Adjustment to existing allowances		5,986			(2,814	)		(3,445	)
Ending Balance		138,673			101,400			64,063

(1) Corresponds to accounts receivable from the Ministry of Finance and Public Credit, regarding the calculation of the regular motor gasoline and diesel price differential pursuant to Resolution 180522 issued on March 29, 2010.

(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.

The future collections of accounts receivable from Cavipetrol, as of December 31, 2011, are as follows:

Year	Amount
2012		-
2013		34,531
2014		32,931
2015 and following		215,485
		282,947

There are no other important restrictions to the recovery of accounts and notes receivable’s recovery.

F-27

(3) A summary of the long-term recovery credit portfolio, for each of the following five years, is provided below:

Applicable interest rate	Year 1		Year 2		Year 3		Year 4		Year 5
	Dec-12 to		Dec-13 to		Dec-14 to		Dec-15 to		Dec-16 to		Over 5
	Nov-13		Nov-14		Nov-15		Nov-16		Nov-17		years
DTF  previous month		33		-		-		-		-		-
CPI+6		115		-		-		-		-		-
CPI		37		19		19		19		19		79
ECP- opportunity rate -Bank average		285		-		-		-		-		-
DTF + 6 points		10		-		-		-		-		-
Greater between 6% EA and PCI  for semester starting July 2009		5,201		-		-		-		-		-
Total annual recovery		5,681		19		19		19		19		79

DTF:	Average of interest rates for fixed term deposits, promulgated by the Superintendency of Finance.
IPC:	Consumer Price Index, as indicated by the Colombian Government
ECP:	Ecopetrol
EA:	Effective Annual Rate

(6) Inventories

The following is a detail of the inventories:

	As of December 31,
	2011			2010
Finished products
Crude oil		1,094,691			772,405
Fuels		701,665			491,565
Petrochemicals		85,411			103,007
Purchased products
Fuels		43,527			165,067
Crude oil		116,398			91,696
Petrochemicals		24,042			4,081
Natural gas		392			-
Raw materials
Crude oil		187,048			157,390
Petrochemicals		32,087			21,753
In-process products
Fuels		396,270			335,613
Petrochemicals		12,523			10,398
Packing Material		5,139			-
Materials for the production of goods		65,706			53,252
In transit materials		24,359			5,158
Total		2,789,258			2,211,385
Less: Allowance for inventories		(27,653	)		(19,297	)
Total		2,761,605			2,192,088

F-28

Below are the adjustments made to the allowance for inventories:

	For the years ended December 31,
	2011		2010			2009
Initial balance		19,297		45,012			127,464
Adjustments to allowance, net		8,356		(25,715	)		(82,452	)
Ending balance		27,653		19,297			45,012

(7) Advances and Deposits

The following is a detail of the advances and deposits:

	As of December 31,
	2011		2010
Short-term
Official entities (1)		2,851,195		1,674,428
Advances to investment projects (2)		1,749		1,163,132
Partners in joint ventures (3)		232,492		562,779
Custom agents		62,074		37,824
Advances to contractors		40,129		65,245
Agreements (4)		18,911		18,733
Advances to employees		1,084		968
Advance to suppliers		252,308		97,208
Total short-term		3,459,942		3,620,317
Long-term
Advances and deposits		144,482		288,735
Total		3,604,424		3,909,052

(1) As of December 31, 2011, it includes mainly transactions with National Tax and Customs Administration - DIAN, for advanced income tax for 2011 in the amount of $1,728,960; self-withholdings for $640,769 a balance in favor of value-added tax – IVA $287,261 and others in the amount of $194,205.

(2) The variation corresponds mainly from an advance payment made by Ecopetrol S.A. in 2010 for the acquisition of the Colombian Branch of BP, which was made in January 2011. As of December 2011, corresponds to advances for the acquisition of assets by Bioenergy S.A. for $1,532 and Propilco S.A. for $217.

F-29

(3) Joint Ventures:

	As of December 31,
	2011		2010
Contracts in which Ecopetrol is not the operator:
Meta Petroleum Ltd.		45,140		287,853
Equion Energía Limited		-		11,204
Occidental de Colombia Inc.		15,012		14,721
Mansarovar Energy Colombia Ltd.		3,386		3,753
Petrobras Colombia Limited		13,406		12,507
Other operations		26,027		22,046
Perenco Colombia Limited		27,324		13,122
Chevron Petroleum Company		4,197		81,171
Repsol		50		-
Vector Group		48		-
Larsen & Toubro		3,919		-
Petrobras Internacional Braspetro B.V.		4,866		2,321
CEPSA Colombia S. A.		583		4,337
Talisman Perú BV, Sucursal del Perú		563		19,200
Petróleo Brasileiro S.A. Petrobras		1,107		10
Petrobras Energía Perú S.A.		147		3,815
HESS BRASIL		-		3,142
Contracts in which Ecopetrol is the operator:
Oleoducto Caño Limón		36,137		47,429
Other operations		27,138		15,951
La Cira		17,289		5,381
JOA Caño Sur		3,681		14,816
CRC 2004 - 01		2,401		-
JOA Platanillo		71		-
Total		232,492		562,779

(4) Represents amounts delivered to personnel as advances under the personnel educational plan.

(8) Prepaid expenses

The following is a detail of the prepaid expenses:

	As of December 31,
	2011		2010
Insurance (1)		44,049		16,514
Others (2)		8,325		5,433
Total		52,374		21,947

(1) Of the contractual insurance policies, $24,007 correspond to Ecopetrol S.A. and are effective until May 2012 are comprised of: i) Operating with a cost of $43,739 and amortization of $21,814 as of December 31, 2011, ii) Administrative expense for $4,207 and an amortization at the same date of $2,124. The other Corporate Group companies have contracted insurances of $20,041.

(2) Corresponds to amounts for purchase and maintenance of vehicles assigned to senior officers of Ecopetrol through leasing, which are administered through Contract No. 5203585 by Cavipetrol.

F-30

(9) Trust Funds

Correspond to pension and abandonment cost trust funds that had been established in the name of OXY and were received upon expiration of the Cravo Norte Association contract, which came into effect in February 2011.

(10) Property, Plant and Equipment, Net

The following is a detail of the property, plant and equipment, net:

	As of December 31,
	2011			2010
Plant and equipment		17,611,968			15,916,349
Construction in progress (1)		12,715,494			6,955,251
Pipelines, networks and lines		17,991,918			15,388,663
Buildings		3,559,907			3,362,595
Equipment on deposit and in transit		1,198,856			1,240,606
Computer equipment		569,159			343,633
Transportation equipment and other fixed assets		1,674,135			1,556,915
Agricultural plantations		21,846			16,145
Operating materials		76,986			63,896
Land		679,998			354,601
Total		56,100,267			45,198,654
Accumulated depreciation		(25,009,147	)		(21,868,192	)
Provision for devaluation of property, plant and equipment (2)		(1,057,740	)		(1,064,204	)
Total		30,033,380			22,266,258

(1) The representative amounts correspond to projects of Ecopetrol S.A. such as the Castilla and Chichimene developments, GLP Cusiana´s plant, master plan of industrial services, modernization of the Barrancabermeja Refinery and the optimization of the Galan – Pozos Colorados transportarion system, heavy crude and Naftaducto through facilities, and the conversion of the 16” Apiay-Monterrey and the 12” Monterrey-El Porvenir to multi-purpose pipeline. With regards to the joint operation, the additional Piedemonte, La Cira Infantas, Rubiales, Pauto and Moriche Buffer development projects are to be highlighted.

It also includes interest derived from payments of the syndicate loan for $158,255, from bonds issued in US dollars and from bonds issued in Colombian pesos for $209,600 and $75,390, respectively, which were allocated to investment projects amounting to $198,108.

(2) The provision for devaluation of property, plant and equipment is made up mainly of: $879,062 of Ecopetrol S.A. and $167,054 of the Cartagena Refinery $5,427 by America Inc.; $4,567 of Oleoducto Central S.A., $1,091 of Equión Energía Limited, $429 of Oleoducto de Colombia S.A., $62 by Bioenegy and $48 by COMAI.

A summary of property, plant and equipment at December 31, 2011 is set forth below:

Type of assets	Adjusted cost		Accumulated depreciation			Revaluations		Allowances
Plant and equipment		17,611,968		(11,551,625	)		4,354,890		(348,240	)
Pipelines, networks and lines		17,991,919		(10,876,272	)		4,360,294		(354,404	)
Construction in progress		12,715,494		-			-		-
Buildings		3,559,908		(1,432,962	)		1,595,248		(122,010	)
Equipment on deposit and in transit		1,198,856		(11	)		-		-
Computer equipment		569,159		(448,025	)		42,014		(15,612	)
Transportation equipment and other fixed assets		1,695,980		(700,252	)		396,355		(215,419	)
Land		679,997		-			1,648,057		(145	)
Operating materials		76,986		-			-		(1,910	)
Total		56,100,267		(25,009,147	)		12,396,858		(1,057,740	)

F-31

Summary of property, plant and equipment as of December 31, 2010:

			Accumulated
Type of Assets	Adjusted cost		depreciation			Revaluations		Allowances
Plant and equipment		15,916,349		(9,774,126	)		4,308,464		(408,265	)
Pipelines, networks and lines		15,388,663		(9,946,601	)		1,234,652		(353,284	)
Construction in progress		6,955,251		-			-		-
Agricultural plantations		16,145		-			-		-
Buildings		3,362,595		(1,277,854	)		1,544,947		(122,037	)
Equipment on deposit and in transit		1,240,606		-			-		-
Computer equipment		343,633		(252,714	)		39,448		(13,357	)
Transportation equipment and other fixed assets		1,556,915		(616,897	)		414,596		(165,542	)
Operating materials		63,895		-			-		(1,574	)
Land		354,602		-			1,833,015		(145	)
Total		45,198,654		(21,868,192	)		9,375,122		(1,064,204	)

There are no restrictions, pledges or bonds over these assets.

(11) Natural and environmental resources, Net

The following is a detail of the natural and environmental resources:

	As of December 31,
	2011			2010
Amortizable crude oil investments (1)		29,991,872			20,245,470
Less: Accumulated amortization		(18,055,338	)		(10,574,904	)
		11,936,534			9,670,566
Plugging and abandonment, dismantling of facilities and environmental recovery costs (2)		3,703,535			3,074,552
Less: Accumulated amortization		(1,626,621	)		(1,443,451	)
		2,076,914			1,631,101
Reservoirs and appraisals (3)		701,590			701,590
Less: accumulated depletion		(622,040	)		(612,310	)
		79,550			89,280
Exploration in progress (4)		1,347,789			383,592
Total		15,440,787			11,774,539

(1) Are comprised by Ecopetrol S.A. investments for $22,334,657; Equión for $6,168,235 and Hocol $1,488,980.

(2) The abandonment costs correspond mainly to Ecopetrol S.A. for $3,636,717 and increased due to the update of the abandonment cost study presented by the Production Vice Presidency as of June 30, 2011 by approximately $603,981, including new fields, namely, Abarco, Los Angeles – 12, Boquete, Cicuco, Torare, Acacías, Los Potros, Clamaro and Casabe Sur. There have been some decreases as a result of use of approximately $49,326, mainly from the La Cira, Tibú, Galán, Casabe, Capachos, Llanito, Lisama, Tesoro and Yariquí fields.

(3) The appraisals of these reserves were received from the reversal of concession contracts for $520,218, currently administered by Gerencia Sur (an Ecopetrol division), and $181,372 by Magdalena Medio (an Ecopetrol division), respectively.

(4) Corresponds to: i) Ecopetrol S.A. for $803,137, generated due to the purchase of 50% of participation in Caño Sur to Shell and the exploratory drillings in the fields of Caño Sur, Hidrocarburos non-conventional, Asociación Quifa, Tinkhana 1, Rumbero 1-Side Track 1 and Nunda that have an approximate value of $286,491; ii) Ecopetrol Óleo e Gas Do Brasil for $207,644; iii) Hocol for $182,125 and iv) Equión for $154,883.

F-32

(12) Deferred Charges

The following is a detail of the deferred charges:

	As of December 31,
	2011		2010
Deferred income tax		1,582,996		1,492,942
Equity tax and surtax (see Note 17)		1,630,362		-
Other deferred charges, net (1)		696,476		497,826
Charges of deferred monetary correction, net		40,226		49,372
		3,950,060		2,040,140

(1) Includes the investments made in execution of the Business Cooperation Contract entered into by Ecopetrol and Schlumberger, the purpose of which is to obtain incremental production in the Casabe field; such investments are amortized based on the field’s technical production units.

(13) Other Assets

The following is a detail of the other assets

	As of December 31,
	2011		2010
Goodwilll (1)		3,163,762		2,508,402
Intangibles (net): brands, licenses, patents, software		405,582		129,610
Trust funds (2)		83,129		80,490
National Royalties Fund (3)		72,909		79,653
Other assets (4)		166,009		58,552
Deposits held in trust		321,361		294,899
		4,212,752		3,151,606

(1) Goodwill corresponds mainly to Ecopetrol S.A. for $3,162,862 and is comprised by:

Company	Acquisition Date		Commercial credit value	Goodwill amount		Pending amortization		Years of amortization
Propilco S.A.	04/07/2008	$	327,986		68,002		259,984	17.8
Andean Chemicals	04/07/2008		357,629		74,152		283,477	17.8
IPL Enterprises	03/17/2009		537,093		101,451		435,642	15
Offshore International	02/06/2009		749,699		130,766		618,933	14
Hocol Petroleum Limited	05/27/2009		801,911		109,686		692,225	16
Equión Energía Limited	01/27/2011		957,513		84,912		872,601	10
Total		$	3,731,831		568,969		3,162,862

  During 2011, there was an increase of goodwill, mainly due to the recognition of $957,513, corresponding to the purchase of Equión Energía Limited, whose value initially established was adjusted for the transfer of taxes and the investment valuation of the initial balance of purchase.

F-33

Earn Outs in acquired companies

Hocol Petroleum Ltd.

On January 26, 2011, Ecopetrol paid to Maurel & Prom an additional US$65 million for the acquisition of Hocol as a result of the increase in the average price per barrel of oil. The equivalent in pesos was recognized as an increase in goodwill.

On March 31, 2011, the equivalent in pesos of US$27.3 million was recognized as greater goodwill based on the exploration results of the Huron well.

Offshore International Group (OIG)

On February 22, 2011, through a bank transfer from Ecopetrol S.A. to Offshore Exploration and Production amounting to US$146 million, the acquired commitment was met, which depended on the behavior of the average price per barrel of oil.

(2) Includes mainly: i) Contributions and shares in amount of $66,177 into the National Hydrocarbons Fund created to support future hydrocarbon investment, exploration and production contracts in minor fields, projects managed by the private equity fund of Hydrocarbons of Colombia; ii) Contributions of $3,410 to the Procuraduría Fund created for general benefit projects in municipalities near the Cicuco field under the Company’s direct operation: Cicuco, Mompox and Talaigua Nueva (the objective of the fund is to disburse the amounts according to each project’s development, which will be carried out by the municipalities through agreements with Incoder and the Ministry of Environment); and iii) Contributions of $9,442 to the Colpet, Cóndor and Sagoc Fund for possible contingencies in the liquidation of these former subsidiaries.

(3) Corresponds to the FAEP deposits to the National Royalties Fund in favor of Ecopetrol S.A. Its sole purpose is the payment of debts and financing for development projects and programs in hydrocarbon producing and non-producing municipalities and departments. Ecopetrol S.A. disburses amounts after the Ministry of Finance issues the corresponding approvals.

(4) Constituted by goods acquired in financial leasing for $73,140 and restricted funds for $47,751, mainly represented by legal deposits destined to attend labor, civil and tax claims. Furthermore, other assets owned by ODL Finance S.A. for $19,672; Ecopetrol del Perú S.A. for $876 and $233 of Ecopetrol Oleo é Gas Do Brasil.

F-34

(14) Valuations

	As of December 31,
Property, plant and equipment (1)	2011		2010
Plant and equipment		4,354,890		4,308,465
Buildings		1,595,248		1,544,947
Lands		1,648,057		1,833,015
Pipelines, networks and lines		4,360,294		1,234,652
Transportation equipment and other fixed   assets		396,355		414,596
Computer equipment		42,014		39,447
		12,396,858		9,375,122

In Ecopetrol S.A. was performed during 2011, the update of technical valuation for property, plant and equipment of the marketing and supply Vicepresidency area and the departments of Cundinamarca and Santander to $32,341. In addition, there was a disposal of fixed assets that caused a decrease of $33,682. The society Ocensa S.A. updated its valuations for $2,818,520, mainly due to valuations recorded of pipelines, networks and lines for $2,797,647 and lands for $13,058.

	As of December 31,
Variable income investment	2011		2010
Empresa de Energía de Bogotá S. A. ESP.		587,164		931,845
Interconexión Eléctrica S. A.		590,417		761,300
Propaise S.A.		-		57
Zona Franca de Cartagena S.A.		1,363		-
Sociedad Portuaria del Dique		12		-
Sociedad Portuaria Olefinas		57		-
Concentra S.A.		7		-
Zona Franca Industrial		-		352
		1,179,020		1,693,554
Total		13,575,878		11,068,676

F-35

(15) Financial Obligations

Financial obligations at December 31, 2011 are composed of:

	As of December 31,
	2011		2010
Short-term
Foreign currency debt		171,408		226,726
Issued bonds		-		133,285
Local currency debt (1)		660,186		719,158
Total Short-term		831,594		1,079,169
Long-term
Foreign currency debt (2)		3,706,961		2,870,970
Local currency debt (1)		3,263,017		3,962,745
Issued bonds (3)		1,000,000		1,000,000
Total Long-Term		7,969,978		7,833,715
Total		8,801,572		8,912,884

(1) Includes mainly the syndicated loan with eleven local banks for an initial value of $2,220,200 destined to finance the Company’s investment programs. According to the payment conditions, in 2011, $176,470 of the principal amount was amortized. It is estimated that the principal will be amortized in 2012 in an amount of $440,041. The conditions applicable to this loan are the following:

Term:	7 years, including a 2 year grace period
Payment of interest:	Starting November 2009
Rate:	DTF + 4% (anticipated quarterly rate)
Amortization:	Every six months

Guarantee: Ecopetrol S.A. granted a plegde over the stock shares owned either directly or indirectly on the following companies, thus reaching a 120% coverage of the loan amount. The shares given in guarantee were replaced by another contract between some banks and Ecopetrol S.A, on November 17, 2011. The value of guarantees according to the intrinsic value of the shares of companies in June, 2011 and translated into Colombian pesos with the current TRM at June 30, 2011 as follows:

Company	Amount
Hocol Petroleum Limited	$	1,918,119
Offshore International Group		769,277
Polipropileno del Caribe S. A.		320,387
Total	$	3,007,783

The detail of the long term payments comprises mainly to Ecopetrol S.A. as follows:

2013	$	444,040
2014		444,040
2015		444,040
2016		267,570
	$	1,599,690

Actually Ecopetrol S.A. does not expected any situation that could represent non-compliance of its obligations in the near future.

It also includes other financial obligations acquired by Corporate Group such as Ocensa S.A. for $1,100,000 and ODL Finance S.A. for $805,896.

F-36

On July 23, 2009, Ecopetrol S.A. issued unsubordinated bonds (notes), with right to registry in the Securities and Exchange Commission of the United States (the “SEC”), due on 2019, for US$1,500 million. This issue was recorded on October 6, 2009, as per Rule 144A/Regulation S.

(2) The terms of the notes as follows:

Coupon interest: 7.625%

Make whole insurance premium: 50 basis points over equivalent U.S. Treasury Securities.

Interest payment dates: July 23 and January 23 of each year, starting January 23, 2010. Maturity date: July 23, 2019.

Multiple and denomination: US$1,000 / US$1,000

Likewise, the Company is obliged to comply with certain covenants, among which are the due and timely payment of principal and interest; the restriction on the creation of collateral guaranties by Ecopetrol and its subsidiaries, with the exception of certain collateral guaranties duly authorized, and the obligation to submit a purchase offer for the bonds in the event of a change of control, pursuant to the definitions of the offering documents.

It also includes subordinated loans granted to partners as Oleoducto Bicentenario for $605,985 and financial obligations of Propilco S.A. by the local and foreign financial institutions for $120,879.

(3) Through Resolution No. 3150 of October 20, 2010, Ecopetrol S.A. was authorized by the Ministry of Finance and Public Credit to issue, subscribe and place internal government debt bonds for up to one billion pesos, aimed at financing the Investment Plan of Ecopetrol in 2010. Subsequently, through Resolution No. 2176 of November 11, 2010, the Company obtained authorization from the Finance Superintendence of Colombia to register its internal government debt bonds with the National Register of Securities and Issuing Agencies and to place its public offering.

Results of the issuing and placing of internal government debt bonds:

Placed sum:	1 billion pesos
Date of issue:	December 1, 2010
Amortization:	Upon maturity
Series A:	Bonds in pesos with a CPI-based variable rate
Redemption Term:	5 years		7 years	10 years	30 years
Rate:	IPC + 2.80%		IPC + 3.30%	IPC + 3.94%	IPC + 4.90%
Sum(millions)	$	97,100	$138,700	$479,900	$284,300

F-37

(16) Accounts Payable and transactions with Related Parties

The following is a detail of the accounts payable and transactions with related parties

	As of December 31,
	2011		2010
Short-term
Dividends payable (1)		3,424		3,431
Suppliers		1,974,233		1,762,461
Purchase of hydrocarbons to Agencia Nacional Hidrocarburos-ANH		775,329		554,381
Advances from partners		532,282		713,405
Deposits received from third parties		777,444		521,781
Other payables		269,381		442,115
Reimbursement of exploratory costs		42,797		65,028
Total Short-term		4,374,890		4,062,602
Long-term
Other payables		518,143		504,046
Total Long-term		518,143		504,046

Corresponds to dividends payable to shareholders whose installment payment for the purchase of their stock are in arrears, and whose economic and political rights have been suspended pursuant to Article 397 of the Commercial Code, and will be restored once the installment payments are brought up to date.

(17) Tax Payable

The following is a detail of the taxes payable:

	As of December 31,
	2011		2010
Short-term
Income tax and other taxes		7,517,178		3,175,500
Income and sales withholdings		308,258		197,294
Global tax and surcharge on gasoline (1)		118,257		110,128
Sale tax payable		21,670		47,418
Equity tax		594,391		-
Industry and commerce and other minor taxes		57,684		58,923
Short-term total		8,617,438		3,589,263
Long-term
Equity tax		1,035,971		-
Total Long-term		1,035,971		-
Total taxes payable		9,653,409		3,589,263

(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 and/or regional entities. The special tax is paid on the basis of the percentage participation of each beneficiary in the national monthly consumption of regular and premium gasoline.

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Income tax provision

Income tax charged to expenses includes:

	For the years ended December 31,
	2011			2010			2009
Current income tax		7,561,634			3,201,041			1,948,819
Asset		(49,865	)		(100,899	)		(69,230	)
Liability		443,952			138,508			234,440
		394,087			37,609			165,210
		7,955,721			3,238,650			2,114,029

The deferred tax asset is calculated based on the value of accounting provisions not accepted for tax purposes, which are deductible at the time of their utilization, and the value of asset inflation adjustments originated from 2004 and 2006. The deferred tax liability results from the differences in the policy for amortization of crude oil investments, which for accounting purposes are amortized by technical units of production whereas for tax purposes are amortized through the straight-line method; from the difference in the method of valuation of fixed income investment, which for accounting purposes are valued at the market price, while for tax purposes are valued by the straight-line method; and from the difference in the amortized value of the goodwill that for tax purposes was accelerated in 2010. Income tax returns may be reviewed by the tax authorities within two years of their filing date. At this date, the terms of filings for the years 2009 and 2010 are open for review.

Currently, differences exist with the National Tax and Customs Administration (DIAN) regarding the calculation and payment method of the first installment of the 2004 income tax returns because, in the opinion of the DIAN, the surtax of such years should have been included in the base. The result of this proceeding will not affect the Company’s cash flow, since the amounts being questioned have been directly compensated by the DIAN by positively adjusting the Company´s balances with adjustments the Company had previously requested in unrelated cases.

The balance of the deferred tax asset and liability is as follows:

	As of December 31,
	2011			2010
Deferred tax asset (Note 12)
Initial balance		1,497,076			1,408,659
Acquisition of company		47,291			-
Period movement		49,864			88,417
Conversion report currency		(1,216	)		-
Final balance		1,593,015			1,497,076
Deferred tax liability(Note 20):
Initial balance		1,333,356			1,194,848
Acquisition of company		10,917			-
Period movement		443,951			138,508
Final balance		1,788,224			1,333,356

As of 2004, income tax payers performing transactions with foreign related or associated parties and/or residents in countries considered tax havens, shall be obligated, for income tax purposes, to determine their ordinary and extraordinary revenues, their costs and deductions, and their assets and liabilities, considering for these transactions the market prices and profit margins. Based on the opinion of the external advisors of the Company, no significant changes are foreseen for taxable year 2012 regarding compliance with the full free competition principle stated in Article 260-1 of the Tax Statute, neither adjustments are expected for the determination of the Company’s income tax expense in such year.

Based on the foregoing and pursuant to the accounting management decrees, Ecopetrol recognized the value of the equity tax to be paid and the respective income charge for the proportional 2011 value. The outstanding balance payable was booked as a deferred charge to be amortized in subsequent years and a short term liability for the amount payable in 2012 and a long-term liability for the amount corresponding to the next two years.

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The reconciliation between the accounting income and the net taxable income which is the basis for the income tax is shown below for illustrative purposes since Colombian regulations do not either require or allow filing an income tax return on a consolidated basis: 

	For the years ended December 31,
	2011			2010			2009
Income before income taxes		23,641,432			11,492,617			7,250,844
Monetary correction gain		-			(1,921	)		(3,471	)
Effect of tax inflation adjustment		-			(99,527	)		108,615
Non deductible costs and expenses		336,463			2,184,555			1,256,081
Special deductions and deductible tax expenses		2,219			(3,849,066	)		(3,287,324	)
Other taxable income		1,013			158,949			182,199
Income not constituting income or capital gains		(463	)		(160,600	)		(126,460	)
Non taxable income		(380,201	)		(1,037,204	)		(727,029	)
Non deductible provisions		42,397			681,644			574,403
Income pension trusts		-			(96,695	)		-
Non-taxable trust funds yields		-			-			(250,265	)
Net exempt income		-			(199,949	)		(29,538	)
Amortization of tax loss		-			65,578			-
Excess of presumptive over ordinary income		9,156			1,001,082			403,226
Net effect of consolidation of taxable income		164,305			(814,687	)		(443,951	)
Net taxable income		23,816,321			9,324,776			4,907,330
Net current income tax		7,552,686			3,183,605			1,950,188

In accordance with that provided for in Decree 1370 of 2009, on January 1, 2011, the one-time equity tax was recognized and is payable in eight equal installments during the years 2011, 2012, 2013 and 2014, within the deadlines established by the Government.

The 2011 effective consolidated tax rate was 33.7% (2010 - 28.2%). The variation in the effective tax rate was mostly in the elimination of deductions on investment in real productive fixed assets by 2011. This elimination is contemplated in Law 1430 of 2010.

Equity tax

According to Law 1370 of 2009, for 2011 the equity tax is responsability of natural or legal persons and factual associations, taxpayers and declarants of income tax.

Additionally, the law establishes the following in regard to equity tax for 2011:

(Amounts are shown in millions of pesos.)

Taxable event	Recognition	Tax base	Rate
The equity tax is generated due to the possesion of wealth equal to or exceeding to $3,000,000 at January 1, 2011.	The equity tax will be registered at January 1, 2011, for just once.  This tax must be paid in eight equal payments during the years 2011, 2012, 2013 and 2014 between the limits stablished by the National Government	The taxable basis of the equity tax is comprised by the liquid equity of the taxpayer at January 1, 2011.
			Equal or exceeding 3,000 and less than or equal to 5,000 millions *	2.4%
			Higher than 5,000 million*	4.8%
			Less than 3,000 millions	Not defined

Note: For tax application purposes, the wealth concept is equal to total liquid equity.

On February 16, 2010, the Ministry of Finance and Public Credit issued Decree 514 applicable to accounting matters, which partially amends Decree 2649 of 1993 (which regulates general accounting and accounting principles issues or regulations generally accepted in Colombia).

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Decree 514 of 2010 establishes a provisional paragraph addressing two fundamental aspects:

(1) The taxpayers may, once a year, charge against the equity revaluation account the value of payable installments in the respective equity tax that is set forth in Law 1370 of 2009.

(2) When the equity revaluation account does not have a balance or it is insufficient to charge the equity tax thereto, the taxpayers can then record in the annual income statements the value of the required installments in the respective period.

Due to the application of Decree 514 of 2010, and due to the fact that Ecopetrol capitalized the total amount of the equity revaluation account, the accounting recognition of the equity tax affects the annual accounts, for the amount of the quotas in the respective period. However, in accordance with the Law 1370 of 2009, the tax income was registered only once on January 1, 2011, therefore the obligation must be recognized at that date since it is an instant execution tax.

In accordance with the Decree 514, the amount of the quotas for each period must be annually in results accounts. In that regard, the amortization for each period equity tax must be recorded on January 1 of each year (2011, 2012, 2013 and 2014) .

Also, on December 31, 2011 the liability was recorded as a short-term tax payable, for the portion payable in 2012, and the remaining amount (values payable in 2013 and 2014) as a long-term liability.

In accordance with Decree 1370 of 2009, on January 1, 2011, the one-time equity tax was recognized and is payable in eight equal installments during the years 2011, 2012, 2013 and 2014 within the deadlines established by the Government.

Based on the foregoing and pursuant to the accounting management decrees, Ecopetrol recognized the value of the equity tax to be paid and the respective income charge for the proportional 2011 value. The outstanding balance payable was booked as a deferred charge to be amortized in subsequent years as a short term liability for the amount payable in 2012 and as a long-term liability for the amount corresponding to the next two years.

The detail of the amounts relate mainly to Ecopetrol S.A. and are as follows:

Deferred charges
Equity tax	1,524,780
Equity tax amortization	(381,195	)
Surcharge equity tax	381,195
Surcharge equity tax amortization	(95,299	)
Net balance (see Note 12)	1,429,481
Balance liabilities
Short-term equity tax	381,195
Long-term equity tax	762,390
Short-term Surcharge equity tax	95,299
Long-term Surcharge equity tax	190,597
Total (see Note 12)	1,429,481

The equity tax recorded by Ecopetrol in 2011 was $1,905,974,of which paid was $476,494.

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(18) Labor and Pension Plan Obligations

The following is a detail of the estimated liabilities and provisions:

	As of December 31,
	2011		2010
Short-term
Vacation		71,838		63,217
Bonuses and allowances		75,691		26,487
Severance		42,241		39,828
Salaries and pension payable		21,453		24,712
Interest on severance		4,438		3,884
Other		17,661		2,119
Total Short-term (1)		233,322		160,247
Long-term
Health and education actuarial liabilities (2)		3,109,480		2,729,318
Retirement pensions joint operations		70,789		76,725
Other		9,960		7,978
Total long-term		3,190,229		2,814,021
Total		3,423,551		2,974,268

(1) The increase of social benefits item is mainly due to the payment of performance bonuses for results in 2011 for approximately $47,000. The health and education actuarial calculations were based on the new Mortality Tables replaced in 2010. As a result of the change in the amortization accounting principle in 2010, as of December 2011, pending amortization is 17% of the pension obligation, equivalent to $555,894.

The amortized health actuarial liability is indicated below:

	As of December 31,
Item	2011			2010
Health obligation actuarial calculation		3,310,894			2,884,558
Less - actuarial calculation pending amortization		(555,894	)		(645,445	)
Amortized actuarial liabilities		2,755,000			2,239,113

(2) The health and education actuarial calculations were prepared using a 4.8% technical interest rate. The variations in the amortized actuarial liability are described below:

	As of December 31,
	2011		2010		Variation
Health
Active personnel		229,309		302,553		(73,244	)
Pensioned retirees		2,525,691		1,936,560		589,131
Education
Active personnel		27,996		104,606		(76,610	)
Pensioned retirees		326,484		385,599		(59,115	)
Total		3,109,480		2,729,318		380,162

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A summary of personnel covered by the actuarial calculation for 2011 and 2010 is detailed below:

	Headcount
		2011	2010
Health care and education reserve (active and pensioned retirees)		18,902	18,337

(19) Estimated Liabilities and Provisions

The following is a detail of the estimated liabilities and provisions:

	As of December 31,
		2011	2010
Short-term
Provision for legal proceedings (1) (see Note 31)		688,191	663,932
Provision for pension obligations (2)		500	102,478
Provision for abandonment, dismantling of facilities and environmental recovery costs (3)		120,128	139,106
Other provisions (4)		589,181	206,179
Provisions for contingencies (5)		297,193	39,602
Total Short-term		1,695,193	1,151,297
Long-term
Provision for abandonment, dismantling of facilities and environmental recovery costs (3)		3,634,229	2,995,281
Provision for royalties (6)		418,318	391,021
Provision for legal proceedings		11,079	12,301
Other provisions		21,203	-
Total long-term		4,084,829	3,398,603
Total		5,780,022	4,549,900

(1) The movement of the provisions for legal proceedings is as follows during the years 2011 and 2010:

	Number of cases			Provisions amount
Initial balance as of December 2009		691			680,022
Additions (new provisions)		235			63,020
Adjustments to existing provisions		-			19,320
Reincorporation for transfer of processes		76			43,548
Finished processes		(141	)		(80,237	)
Transfer of processes		(39	)		(61,741	)
Initial balance as of December 31, 2010		822			663,932
Additions (new provisions)		271			42,859
Adjustments to existing provisions		-			60,067
Recoveries		71			227,542
Finished processes		(273	)		(229,644	)
Transfer of processes		(107	)		(76,565	)
Ending balance as of December 31, 2011		784			688,191

(2) Corresponds to the estimated pending pension contributions of employees who joined Ecopetrol after January 29, 2003 (Law 797 of 2003) and until the first quarter of 2004, who were covered by the General Pension Regulations. In addition the provision for the contingency of losing legal actions for the protection of labor related rights.

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(3) The provisions for the abandonment cost had a net increase for $619,970 per adjustment in June and December of 2011. The following are the entire changes of the provision for abandonment cost, facility dismantling, and environmental recovery.

	For the years ended December 31,
	2011		2010			2009
Initial Balance		3,134,387		3,017,203			1,964,756
Retirements and other		-		(27,414	)		(21,964	)
Additions – (Reductions)		619,505		282,229			1,188,670
Changes in estimation		-		-			80,243
Transfer to short-term		-		(136,151	)		-
Exchange rate effect		465		(1,480	)		(194,502	)
Final Balance		3,754,357		3,134,387			3,017,203

4) Includes provisions created to anticipate potential nature events and other events that could affect the transportation plant and impact the areas where Ecopetrol has presence. Starting at January 2012, three new large scale projects were created: Dosquebradas Project, Integrity Program and Contingencies Program.

(5) It is comprised of: (i) $54,202 for possible payment claims from PDVSA related to spillages having an environmental impact; (ii) $500 related to the retirement bonus for Hocol S.A. personnel still in process; (iii) $149 related to the success commission payable to the attorney in law attending the suit filed by Industrias Crizasa against Ecopetrol S.A.; (iv) $718 related to potential liabilities in arbitration decisions, and (v) in December 2011, an actuarial reserve provision was established for $241,624. (see Note 23 (7)).

(6) It includes the provision to cover the claim from the Community of Santiago de las Atalayas and Pueblo Viejo of Cusiana, originated in Royalty Contracts N. 15, 15ª, 16 and 16ª executed with Ecopetrol, but declared null and void by the State Council. From said amount, $90,752 corresponds to the amount initially recognized by Ecopetrol, together with the valuation of the fund where the amounts are invested and $327,566 of interests generated. The ruling on the extraordinary appeal presented by the Community is pending.

(20) Other Long-Term Liabilities

The following is a detail of the other long-term liabilities:

	As of December 31,
	2011		2010
Deferred income tax liability (See Note 17)		1,788,224		1,333,356
Advances received from Ecogas for BOMT obligations		676,628		799,950
Credit for deferred monetary correction		138,064		169,048
Other liabilities (1)		181,397		59,907
Total		2,784,313		2,362,261

(1) Includes other liabilities of Ecopetrol S.A. for $65,677; Reficar for $94,949 and Hocol remittance tax of $20,356.

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(21) Non-Controlling Interest

The Non-Controlling Interest is the following

	As of December 31,
	2011		2010			% of other shareholders 2011
Bioenergy		11,219		11,550			11.4
ODL Finance S.A.		237,214		153,810			35
Oleoducto Central S.A.		508,389		232,244			72.6
Oleoducto de Colombia		90,473		95,856			73
Oleoducto Bicentenario		318,147		(7,509	)		44
Equion		1,087,189		-			49
Total		2,252,631		485,951

(22) Equity

The following is a detail of the equity

	As of December 31,
		2011		2010
Authorized capital		15,000,000		15,000,000
Capital to be subscribed		(4,720,825	)	(4,881,872	)
Subscribed capital		10,279,175		10,118,128
Subscribed capital pending payment		-		-
Subscribed and paid-in capital		10,279,175		10,118,128
Additional paid-in capital		6,944,159		4,721,700
Additional paid-in capital receivable		(156,015	)	(1,192	)
Additional paid-in capital		6,788,144		4,720,508
Surplus from revaluations		13,575,878		11,068,676
Devaluation of assets		(695,579	)	(701,694	)
Responsibilities from pending rulings		(782	)	(781	)
Effects of RCP application		(696,361	)	(702,475	)
Net income		15,452,334		8,146,471
Cumulative loss		(326,435	)	-
Legal reserve		4,951,629		4,117,020
Investment programs occasional reserve		4,227,783		2,615,718
Accounting clearance		17,804		17,804
Surplus from equity method		2,884,467		1,377,240
Incorporated institutional equity		156,276		139,548
Translation adjustment		(2,621,839	)	(290,457	)
Total equity		54,688,855		41,328,181

Subscribed and Paid-in Capital

The authorized capital of Ecopetrol is $15,000,000 divided into 60,000,000,000 common shares, with a $250 par value each, of which 41,116,698,456 shares have been subscribed, represented by 11.51% held by private shareholders and 88.49% in Colombia. The value of shares under reserve amounts to $4,720,825 represented by 18,883,301,544 common shares.

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Shares Placement Premium

Corresponds mostly to: (i) Surplus with respect to its par value derived from the sale of shares at the time of capitalization in 2007 for $4,700,883, (ii) To the value resulting in the new shares offering for the secondary market equal to $20,817, which resulted from foreclosing the guarantees of delinquent debtors pursuant to Article 397 of the Commercial Code and (iii) To the excess over nominal value from the sale of shares awarded in the second public offering, held in September 2011 for $2,222,441.

Effects of RCP applications

Corresponds to the transfer of negative balances originated from the devaluation of property, plant and equipment required by the RCP since 2008.

This line-item also includes responsibilities from pending rulings related to inventory losses, as required by RCP.

Legal Reserve

The legal reserve is set up with 10% of net income and it may be used to absorb losses or to be distributed at the liquidation of the Company.

On March 24, 2011, the General Shareholders’ Meeting decided to increase the legal reserve by $834,610 to $4,951,629.

Similarly, reserves were established for: corporate group unrealized reserves amounting $571,854 to reach $1,086,070; compliance with Regulatory Decree 2336 of 1995 (valued at market price) for $96,695; new exploration for $493,611 adding up to $1,477,675, and $480,813 for payment of dividends for shares issued in 2011.

Incorporated Institutional Equity

Corresponds to the product of commerciability, related mostly to the association contracts Nare, Matambo, Garcero, Corocora, Estero, Caracara, for the Sardinas 6, Remache Norte 3, Abejas 3, Jaguar T5 and T6, Orocué, Guarilaque 7 Well, Campo Rico for the Candalay, Jordan 5, Remache Norte 2 and 5, Abejas 2 and Vigia Wells, and the incorporation of the Cocorná material warehouse.

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(23) Memorandum Accounts

The following is a detail of the memorandum accounts

		As of December 31,
		2011		2010
Debtor/Rights:
Exploitation rights - Decree 727 of 2007  (1)			67,496,739		72,619,793
Other contingent rights and debtor accounts (2)			21,023,083		15,562,589
Costs and expenses (deductible and non-deductible)			19,534,605		14,027,907
Pension trust funds  (3)			11,303,177		11,202,556
Securities given in custody and guarantee			5,314,653		4,290,149
Execution of investment projects			751,827		751,827
Legal proceedings			584,810		584,774
Tax differences			4,212,978		-
	Total		130,221,872		119,039,595
Creditor/Obligations
Legal proceedings			34,791,375		32,228,241
Goods received in custody (4)			28,326,369		17,981,352
Contractual guarantees (5)			7,648,023		14,864,210
Pension trust funds (7)			11,544,801		10,861,969
Non-tax liabilities			9,890,185		6,817,853
Other contingent obligations (6)			10,939,385		7,096,874
Potential obligations – Pension liabilities (7)			1,222,955		1,603,998
Non-taxable income			4,818,819		1,555,073
Mandate contracts (8)			1,400,596		1,433,804
Goods and rights received in guarantee (9)			-		1,220,162
Administration funds - Dec 1939 of 2001 and 2652 of 2002			973,151		964,872
Future BOMT payments			228,941		352,615
	Total		111,784,600		96,981,023
			242,006,472		216,020,618

(1) Valued as of December 31, 2011 and 2010 based on the volumes of the audited reserves study (see Note 32) and applying the average price determined in accordance with the SEC methodology. The variation as of December 2011 corresponds to the annual update.

However during this period there were higher operating incomes of 23%, due to price increases based on the WTI from 79 to 96 US$/barrel and the reserves volume 129 Mbls. This effect was offset by an increase of 62% of operation and abandonment costs, generating a lower amount in the valuation process of exploitation rights. The main fields where the value is impacted by this effect were Rubiales, Pauto, Chichimene, Gibraltar, Chuchupa, and Cravo Norte.

(2) Balance of the tax memorandum accounts groups the differences between the values of both equity and results accounts, taken from the tax return for 2010 and the accounting balances. Differences correspond to concepts such as revaluations and provisions not accepted by tax regulations, the difference in the method for amortization of crude oil investments, which was made by production units for accounting purposes and by the straight-line method for tax purposes and by the effect of the generated inflation adjustment, among others.

(3) Reflects the contingent right (debt account) for resources allocated to the Pension Autonomous Equity, for payment of the commuted pension liability, in order to control the existence of liquid resources in the autonomous equity. The commuted value (transferred) as of December 31, 2011 amounts to $11,303,177 (on commuting date at December 31, 2008 - $10,092,528), and corresponds to the pension liability by monthly payments, parties installments and pension bonuses; health and education related items are Ecopetrol’s responsability. The destination of commuted resources, as well as their yield, cannot be changed, nor returned to the Company, before complying in full with all pension liabilities.

F-47

A detail of the trust funds is set forth below:

	As of December 31,
	2011		2010
Consorcio Ecopensiones 2011		2,716,510		2,206,364
Porvenir S.A		2,493,719		-
Consorcio Pensiones Ecopetrol 2011		2,052,000		1,929,035
Unión temporal Skandia-HSBC		2,032,891		-
Consorcio. Bogotá-Colpatria-Occidente		2,008,057		-
Consorcio Fiducafé - Fiduprevisora – Fidupetrol		-		2,349,054
Consorcio Fidupopular – Fiduoccidente		-		2,061,664
Consorcio Fidubogotá – Fiducolpatria		-		1,328,292
Consorcio Fiduagraria - Fiducoldex - Helm Trust		-		1,328,147
Total		11,303,177		11,202,556

On July 5, 2011, contracts to manage pension trusts were terminated; for this reason, a public selection process was held to select the new resource management pursuant to Article 4 of Decree 941 of 2002. The process began in April 2011 and ended in July 2011, giving the resources to the new contractor.

(4) It comprises mainly royalties corresponding to Ecopetrol’s reserve balance for $28,215,023, calculated at SEC prices. In addition, the balance is represented by the inventory of products sold and materials pending, delivery to clients, in the amount of $41,850, and goods received in concession custody: Coveñas, $41,660; Pozos Colorados, $21,058; and Tumaco, $6,084.

On March 7, 2007, Decree 727 was issued, replacing Decree 2625 of 2000, which includes regulations related to the valuation of reserves and the posting of State owned hydrocarbon reserves in the Financial Statements of the Company. Furthermore, the decree stipulates the posting of hydrocarbon exploration or production rights owned. This is posted under Memorandum Accounts pursuant to the opinion given by the CGN; nonetheless, the Memorandum Accounts are not part of the Company’s balance sheet.

(5) It comprises mainly contracts pending execution and entered into in Pesos, Dollars and Euros, updated to the market representative rate at December 31, 2011 for $7,459,089; stand-by letters of credit, which guarantee the contracts executed by Ecopetrol in the amount of $186,967 and documentary letters for $79.

(6) It includes mainly, contingency of Reficar S.A. for $4,422,942 and Ocensa S.A. for $2,829,936 and a closed pledge for $2,663,576 on the shares owned by Ecopetrol S.A. directly or indirectly in Hocol Petroleum Limited, Offshore International Group and Polipropileno del Caribe S. A., guaranteeing 120% of the amount of the syndicated loan granted by the local banks. (see Note 14).

(7) Comprises the actuarial calculation value of monthly pension payments, pension quotas, parts and bonuses as of December 31, 2010 plus the amortized portion of the increase in the 2010 actuarial calculation as a result of the change in the amortization accounting under Colombian GAAP in 2010. At the end of December, 2011 there was a reserve pending amortization of 11%, equivalent to $1,222,955.

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The balance of the amortized actuarial liability is comprised as follows:

	As of December 31,
Concept	2011			2010
Actuarial calculation of monthly pension payments and bonuses		12,767,756			12,465,967
Less - actuarial calculation pending amortization		(1,222,955	)		(1,603,998	)
Amortized actuarial liabilities		11,544,801			10,861,969

In December 2011, the value of pension obligations is higher than the balance reported for autonomous equities; therefore, it was necessary to record a provision for $241,624 to cover this difference. (see Note 18 (5)).

The balance of pension autonomous equity, the value of the actuarial calculation and the amortized value of pension liability by monthly payments are included in memorandum accounts.

The actuarial calculation was prepared using a 4% technical interest rate. The growth in salaries, cash pensions and in kind pensions, was calculated using the average inflation rate calculated by the National Statistics Administrative Department - DANE during the three year period preceding the calculation year.

Breakdown of personnel covered in the actuarial calculation updated as of December 31, 2011:

Item	Number of people
Bonus reserve- retired personnel		9,890
Bonus reserve- active personnel		2,962
Pension reserve (active and retirees)		13,280

(8) It includes the value of assets received in custody from Refinería de Cartagena S. A. to fulfill obligations acquired by virtue of the mandate agreement subscribed between the Company and this corporation for the operation of the refinery.

(9) It corresponds to the guarantees given by BP Exploration Company resulting from the purchase transaction with this company in August 2010 for US$637.5 million. Due to the acquisition of this company in the first quarter of 2011, these were reversed.

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(24) Revenues

The following is a detail of the revenues:

	For the years ended December 31,
	2011		2010		2009
Local Sales
Medium distillates		9,742,346		7,099,176		5,738,586
Gasoline		5,206,873		4,302,282		4,374,781
Services		1,762,060		1,947,829		1,113,075
Natural gas		1,212,310		1,159,245		1,000,517
Other products		1,803,979		1,763,927		833,067
LPG and propane		727,111		627,361		469,551
Asphalt		402,923		326,737		314,230
Crude oil (1)		230,459		117,186		18,194
		21,088,061		17,343,743		13,862,001
Recognition of price differential		2,251,322		740,682		196,533
		23,339,383		18,084,425		14,058,534
Foreign sales
Crude oil  (1)		33,418,191		18,073,357		11,815,512
Fuel oil		4,447,657		2,377,266		2,325,507
Natural gas (1)		508,066		146,063		311,734
Gasoline and turbo		1,663,222		698,068		687,206
Propylene		-		109,271		-
Other products		871,105		831,129		642,877
Diesel		1,482,625		1,638,044		551,263
		42,390,866		23,873,198		16,334,099
Premium income net		22,019		10,688		11,757
		42,412,885		23,883,886		16,345,856
		65,752,268		41,968,311		30,404,390

(1) It corresponds to the application of Decree 4839 of December 2008, which determines the price differential (value generated between the parity price and the regulated price, which may be positive or negative).

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(25) Cost of Sales

The following is a detail of the cost of sales:

	For the years ended December 31,
	2011			2010			2009
Variable cost:
Purchase of hydrocarbons from the ANH (1)		8,048,981			5,335,946			4,358,408
Imported products		8,840,450			5,680,601			2,739,681
Purchase of crude oil in association and concession		6,701,500			4,548,193			4,130,116
Amortization and depletion		2,642,132			2,280,355			1,474,918
Transportation services for hydrocarbon		898,508			540,555			637,029
Purchase of natural gas and other products		673,545			316,192			57,335
Electrical power		257,110			205,102			156,405
Material in process		219,548			146,941			180,602
Initial and final inventory		(551,718	)		(251,431	)		(55,042	)
Adjustment in volumes and other allocations		191,553			(212,332	)		(334,658	)
Premium cost, Net		-			2,825			554
Depreciation by production units		125,482			55,473			48,834
		28,047,091			18,648,420			13,394,182
Fixed cost:
Services contracted with associations		1,791,681			1,469,586			1,290,177
Maintenance		1,593,327			1,267,637			1,274,618
Labor costs		1,219,219			1,084,149			918,188
Depreciation		1,809,546			1,548,797			1,239,846
Contracted services		669,072			599,179			451,165
Project expenses not capitalized		450,103			413,692			524,441
Materials and operations supplies		278,740			345,326			302,534
Taxes and contributions		387,788			254,489			326,767
Amortization of deferred charges, intangibles and insurance premiums		61,762			72,680			94,288
General costs		287,987			236,604			7,055
Amortization of health and education actuarial liability		68,740			18,442			82,812
		8,617,965			7,310,581			6,511,891
		36,665,056			25,959,001			19,906,073

(1) It corresponds to the crude oil and natural gas purchases of Ecopetrol S.A. from Agencia Nacional de Hidrocarburos derived from national production, both under the Company’s direct operation and under the operation of third parties.

(2) Corresponds mainly to naphtha, used to facilitate the transport of heavy crude, gas and low sulfur diesel. This last one decreased its volume, nevertheless the purchase cost increase due to the behavior of the prices of international reference.

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(26) Operating Expenses

The following is a detail of the operating expenses:

	For the years ended December 31,
	2011		2010		2009
Administration
Amortization (1)		294,612		189,261		152,235
Labor expenses		269,828		213,739		281,123
General expenses		192,123		149,772		149,644
Depreciation		24,979		19,739		22,797
Leases and rentals		10,878		7,986		17,322
Amortization of health and education actuarial liability		4,715		1,052		12,770
Maintenance		5,294		2,611		17,361
Taxes		216,488		19,363		9,084
		1,018,917		603,523		662,336
Selling and projects:
Projects expenses (2)		293,478		321,580		296,645
Crude oil pipeline transportation		3,388		1,455		141,889
Exploration expenses (3)		959,938		1,465,537		1,099,837
General expenses (4)		606,461		300,837		166,480
Labor expenses		190,166		69,490		43,495
Taxes		192,064		155,662		181,109
Natural gas pipeline transportation		122,780		125,376		-
Maintenance		5,488		1,786		5,336
Default in gas supply		2,511		85,222		27,851
Amortizations		1,058		-		-
		2,377,332		2,526,945		1,962,642
		3,396,249		3,130,468		2,624,978

(1) Balance comprises mainly goodwill amortization in 2011 for $262,984 (2010 - $172,660)

(2) It includes other projects mainly: Vicepresidency of Transport (extension and infrastructure development transportation, Naftaducto heavy crude by $126,046), Colombian Institute of Oil (biofuels research and development, petrochemical, adjustments of $63,176) Information and Technology staff (Shared Services Center, Telecommunications, Transformatión $35,784) and Production Vicepresidency (Exploratory studies, integrated development Cupiagua).

(3) Exploration and project costs as of December 2011 correspond mostly to seismic studies for $649,308, of which the most important was realized by Ecopetrol S.A for $343,756, Ecopetrol Brasil for $101,194, Ecopetrol America Inc for $87,815 and Hocol for $112,561. Also this includes unsuccessful exploration cost for $242,940, the most representative being: Rio Zulia $27,802; Kaxan Norte N°1 $19,990; Trueno $17,295; Prados $11,785; Kantaka $11,225 and other estimates for $20,282.

The main reasons for the variation were: i) the decrease in dry well losses of América Inc from $380,324 in 2010 to $61,521 in 2011 and ii) a similar decrease occurred in Hocol, from $178,553 in 2010 to $17,387 in 2011.

(4) It comprises mainly river transportation costs of $39,421, reclassification from cost to expenses of agreements with military forces for $73,364 and responsible operation of $123,040 (integral handling of waters, construction of projects to improve mobility, road improvement, sewage system, reforestation activities and environmental culture training).

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(27) Financial Income, Net

The following is a detail of the financial (expenses) income net:

	For the years ended December 31,
	2011			2010		2009
Income:
Exchange difference gain		7,783,658			4,265,882		6,517,914
Yields and interest		193,087			156,336		479,694
Equity method investment gain		141,647			83,574		55,143
Income on valuation of investment portfolio		100,373			80,111		168,442
Hedging operations (1)		88,317			80,445		159,245
Dividends in cash		10,135			30,941		31,687
Other		5,144			9,202		1,802
		8,322,361			4,706,491		7,413,927
Expenses:
Exchange difference loss		7,819,025			4,412,224		6,643,557
Hedging operations (1)		890,008			99,139		84,492
Interest		415,222			145,910		138,801
Other minor		57,621			10,101		27,806
Administration and securities issuance		44,415			526		23,438
Loss in equity method		372			802		-
		9,226,663			4,668,702		6,918,094
Net		(904,302	)		37,789		495,833

(1) The results of the hedging operations at December 31, 2011, are explained mainly by the following net effects of income or (expense): i) Valuation index management ($596,148); and ii) WTI and JET price ($202,295).

In 2010, Ecopetrol recorded net losses and asphalt hedges for $11,909 and net refining margin of $9,971, with net income by WTI $389 and other for $1,529. Also the Cartagena Refinery reported net profit on hedging for $1,268.

(28) Pension Expenses

The following is a detail of the pension expenses:

	For the years ended December 31,
	2011		2010		2009
Amortization of pension actuarial calculation (1)		443,890		146,717		407,083
Healthcare services		205,928		171,636		132,322
Education services		56,480		59,273		55,752
		706,298		377,626		595,157

(1) At December 31, 2011, the education reserve was adjusted, based on the actuarial study as of December 31 2010, updated with the CPI (consumer price index).

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(29) Inflation Gain

It corresponds to the net amortization of the deferred monetary correction of $21,836 ($22,030 in 2010 and $22,335 in 2009).

(30) Other Income (Expenses), Net

The following is a detail of the other income (expenses), net

	For the years ended December 31,
	2011			2010			2009
Other income
Recovery of associated services (1)		219,952			15,535			14,219
Long-term crude oil testing		121,434			104,970			-
Recovery of provisions (2)		666,109			365,515			224,565
Expense recovery		127,580			99,900			61,972
Other minor income		265,824			81,716			134,885
Income from transferred rights		30,396			19,222			28,116
Recovery of exploration cost		25,543			40,336			148,996
Indemnities received		10,045			9,253			16,305
Income from undeveloped fields		855			28,097			19,257
Income on sale of materials and property, plant and equipment		9,443			18,837			3,579
Income for services		6,720			28,779			48,878
		1,483,901			812,160			700,772
Other expenses
Taxes		641,947			343,128			352,459
Provisions (3)		807,245			552,520			462,812
Gas pipelines availability from BOMT contracts		12,026			63,947			89,906
Fuel losses		78,816			140,153			99,771
Inspection quota		49,884			49,435			26,986
Contributions and donations		27,940			23,906			40,497
Write-off of goodwill		300			287,918			-
Other minor costs (4)		275,367			413,276			151,034
Loss in sales of fixed assets		51,143			6,295			(193	)
Surveillance and security		-			-			23,026
		1,944,668			1,880,578			1,246,298
		(460,767	)		(1,068,418	)		(545,526	)

(1) Mainly for recovery of pension obligations of the association between Ecopetrol S.A. and Occidental de Colombia S.A. for $104,835 and income from commercial fields with associates for $95,379.

F-54

(2) Details of recovery of provisions are as follows:

			For the years ended December 31,
	2011		2010		2009
Legal proceedings		229,345		80,237		83,258
Other recoveries (*)		387,117		131,308		5,564
Products inventories		3,263		29,481		118,652
Property, plant and equipment		46,019		55,717		17,091
Accounts receivable recovery		365		68,772		-
		666,109		365,515		224,565

(*) The main recoveries were: Recovery of the allowance for pension liabilities for $135,724 million, updated abandonment costs $105,722 million and recovery of labor provisions for $101,478 million.

(3) The detail of provisions is as follows:

			For the year ended December 31,
	2011		2010		2009
Legal proceedings		330,468		125,888		271,091
Inventories products		8,505		9,743		33,161
Property, plant and equipment and materials		41,948		227,266		127,826
Accounts receivable		32,422		169,789		30,734
Potential obligations		29,883		-		-
Pension commutation (*)		241,624		-		-
Other provisions		122,395		19,834		-
		807,245		552,520		462,812

(*)Corresponds to the effect of the comparison between the yields of the autonomous equities and the commuted obligations of Ecopetrol, which has been larger than the generated yields.

(4) Includes, among other, agreements for social investment (reduction of illiteracy, endowment auditorium, cultural and sports center) of $180,254.

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(31) Contingencies

Ecopetrol S.A.

A summary of the most significant proceedings with amounts of claims greater than $10,000, for which provisions have been recognized according to the evaluations of the internal and external attorneys of the Company, as of December 31, 2011 and 2010:

Proceeding	Claim	Provision amount December 2011	Provision amount December 2010
Foncoeco (1)	Profit participation fund of the employees and ex-employees of Ecopetrol S. A.	-	143,692
Garcero partnership agreement	Class Action of Luis Enrique Olivera Petro against ECOPETROL, the nation, Ministry of mines and others by extension of the Garcero Association contract..	204,189	-
Municipio de Aguazul, Tauramena	Class action. Contributions to the solidarity and redistribution of income fund as a consequence of the generation of electricity, according to the Law 142 of 1994.	139,688	139,688
Municipio de Arauca	Class action. Contributions to the solidarity and redistribution of income fund as a consequence of the generation of electricity, according to the Law 142 of 1994.	121,051	121,051
Departamento del Tolima	Class Action for the recalculation of royalties with  a 20% epecified rate in Law 141 of 1994.	82,287	82,287
Incidencial Salary – Savings  encouragement	Apply salary incidence to payments under the figure of the encouragement to the savings and consequently , reassess social benefits(legal and extralegal) and  monthly pension from the date on which ECOPETROL began to recognize.	18,175	-

As of December 31, 2011, the balance of the provision for legal proceedings amounts to $699,270.

(1) The advisor report of 2005 calculated that the damages owed by Ecopetrol in the Ordinary Civil Action filed by Foncoeco which claims that Ecopetrol must pay principal and interest on the profit participation fund for the employees of the Company which was established by the Board of Directors amounts to $542,000. On June 29, 2011, the Administrative Court Civil Room of the Bogota Judicial District revoked the ruling issued in 2005 by Civil Judge 23 of the Bogota Circle; instead, the second instance ruling ordered the company to pay Foncoeco only $6.6 million pesos, an amount that was paid on July 15, 2011.

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Other companies into the corporate group

The following summarizes the most significant processes of other companies into the Corporate Group as of December 31, 2011 and 2010:

Corporate Group Company	Claim	Stage of the proceedings	Provision amount December 2011	Provision amount December 2010
Refineria de Cartagena S.A.	Class Action - Stamp pro-Culture	First instance – The resolution of this matter is still pending.	591	536
	Class Action- Contribution by generation of electricity.	First instance- starting evidence phase.	1,181	1,181
	Regular labor process of Luis Aníbal Ramírez Sánchez and others against ODL and other.	By order of September 2011 the Second Labor Court of the Circuit of Villavicencio ordered remittance of the proceedings for the second labor court enclosed.	672	-
Oleoducto de los Llanos ODL	Administrative inquiry with Superintendency of Companies	Appeal for reversal against resolution issued by the Superintendency of Corporations whereby a sanction was imposed to the company for lateness in form No. 13 of additional investment capital allocated.	3,587	-
	Extraordinary remedy of cassation San Jacinto, La Hocha Contract only risk	Hidrocarbon Services presented a cassation lawsuit; in April, the appeal was admitted and ordered to transfer to recurrent. In September, the Company filed the respective cassation lawsuit. The resolution of this matter is still pending.	1,500	1,500
Hocol S.A.	Ordinary/Labor	Was favorably resolved by the Court. The plaintiff appealed the sentence  arguing that the amount taken into account for  the claim does not correspond to the ruling. The Company deposited the amount of the main ruling with the pension fund, in the amount that the court ordered, the resolution of this liquidation is still pending.	1,040	1,040

(32) Commitments

Agreement for Gas Comercialization

A mandate contract with the Agencia Nacional de Hidrocarburos (ANH) was established with the purpose that Ecopetrol commercializes on behalf of the ANH, natural gas belonging to the Nation and the ANH´s participation, which will be effective on April 1, 2012 until December 31, 2013.

Natural Gas Supply Contracts

In addition to existing contracts, the Company has entered into the natural gas sale or supply contracts with third parties, including, Empresas Públicas de Medellín E.S.P., Gases del Caribe, Gases de Occidente S.A. E.S.P., Gas Natural S.A. E.S.P and Gecelca, among others. As of December 2011, Ecopetrol sold an average of 582.44 GBTUD for $1,614,249 (including exports).

F-57

Options

Forward Structures

Hedges were performed on exchange rate through forwards, in order to reduce the risk of currency exchange rate fluctuations and certainty of future cash flows

Forwards

Starting date	Ending date	Amount			Forward rate
December 29, 2011	January 6, 2012	US$	5,000,000	$	1,943.03

Ship or Pay contracts

Ecopetrol S.A. and ODL Finance S. A. have signed the following Ship or Pay contracts: i) The first contract supports the debt (Financing Tariff) to “Grupo Aval” for 5 years and is collected through a trust fund responsible for paying the debt amortization payments. This contract was replaced by a new one, executed in May 2010, with a validity of 7 years, to reflect new conditions agreed with Grupo Aval and ii) The second contract supports the securitization (Autonomous Equity Titles) with a validity of 7 years. The equity titles are under the administration, since the issuance day, of a trust fund structured for that purpose; the trust fund is responsible for billings, collections and payments on behalf of the owners.

Under the first Ship or Pay contract, ODL Finance S.A. has committed to transport 75,000 barrels of crude oil daily, during the two years grace facility period and 90,000 daily barrels of crude oil during the next five years. Under the second contract ODL Finance S.A. has committed to transport 19,500 daily barrels of crude oil during the first construction phase of the project (which began operations in September 2009) and 39,000 daily barrels of crude oil from the start of the second phase which was carried out in the first quarter of 2010.

(33) Subsequent Events

Incidents at Transportation Facilities

Salgar-Cartago multipurpose pipeline spill

On December 23, 2011, our Salgar-Cartago pipeline ruptured. We believe this incident occurred as a result of creep movement caused by severe weather conditions in the area, causing the surrounding soil to exercise strong pressure on the pipeline and rupturing it. Due to the rupture, approximately 1,428 gallons of gasoline spilled into the surrounding area in La Divisa and Villa Carola in the Municipality of Dosquebradas, Risaralda. The spilled gasoline from the pipeline subsequently came into contact with a heat source which ignited it, causing several explosions that tragically resulted in 33 fatalities and 77 injuries, as well as damages to the neighboring houses and buildings

In connection with this incident, the Corporacion Autónoma Regional de Risaralda or CARDER, the Regional Environmental Authority for the Department of Risaralda, has launched an investigation into the causes of the incident. As of the date of this Annual Report, CARDER has not filed any legal action  against us. We launched our own internal investigation and hired a local engineering firm as well as a highly renowned international consultant to investigate the causes of this incident. Our internal investigation and the investigation conducted by the Colombian engineering firm confirmed that the pipeline had ruptured as a result of creep movement and the pressure exercised by the soil on the pipeline. The investigation conducted by the international engineering firm is still in progress.

As of March 21, 2012, we have made contributions of approximately Ps $4.2 billion to assist those affected by the incident. These contributions include transfers to “Gente Ecopetrol” foundation , the local red cross, and other organizations. 

As of January 4, 2012, we have cleaned the totality of affected water bodies and the majority of our remediation activities in connection with the product spill have been completed. In addition, we are currently carrying out activities to restore the site according to the guidelines provided by the CARDER.

Together with the victims, we filed a joint request before the District Attorney of Pereira to promote an extrajudicial settlement of the amount of damages caused by this incident. We recently reached to an extrajudicial settlement agreement with the 180 victims of this incident pursuant to which we agreed to indemnify them for an aggregate amount of approximately Ps$ 8,000 million.  This settlement agreement was promoted by us under our principles of solidarity and social responsibility and does not imply an admission of our culpability for the damages caused by this incident. This settlement agreement still has to be approved by court of Risaralda.

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Caño Limon – Coveñas crude oil pipeline spill

In December 11, 2011, our Caño Limon - Coveñas oil pipeline ruptured. We believe this incident occurred as a result of an unusual movement of soil and the tensioning of the pipeline, resulting from severe weather conditions. The incident caused the spill of approximately 3,267 barrels of crude oil into the Iscala creek, which connects with the Pamplonita River, located in the Municipality of Chinácota in the Department of Norte de Santander, which capital city is Cúcuta. The incident did not cause any fatalities or injuries.

At the time of the incident, the pipeline was not in operation. We activated the corresponding contingency plan and called for the support of the CREPAD, which is the regional committee for attention and prevention of disasters. Five hundred workers were assigned to the decontamination of the Iscala creek and the Pamplonita River. In addition, the authorities decided to close Cúcuta’s aqueduct gates as a preventive measure, while certified laboratories performed tests to determine its water quality.

Notwithstanding a technical commission’s determination that the incident was caused by an unforeseeable event unrelated to our operation, as a result of negotiations with national, regional, and local authorities alongside representatives of the local community, we agreed to construct, at our own expense, an aqueduct intake in the upstream of the Caño Limon – Coveñas pipeline in order to prevent the water supply to Cúcuta and its surrounding area from being affected by any unexpected, irresistible, or unforeseen events caused by soil movements or terrorist attacks. In order to meet this commitment, as of December 2011, we allocated a provision of Ps$67 billion.

In connection with this incident, the Regional Environmental Authority of Norte de Santander, or Corporación Autónoma Regional de la Frontera Nororiental - CORPONOR, has launched an investigation into the causes of the incident and has initiated enforcement actions against us for the alleged  wrong implementation of the contingency plan. Our response to the charge is aimed at demonstrating that CORPONOR does not have jurisdiction to launch an investigation for the alleged breach.

We launched our own internal investigation and hired a highly renowned international consultant to investigate the causes of this incident. We believe investigations will continue for the foreseeable future, and we cannot provide any indication as to their outcome, including whether we will be found liable or subject to enforcement actions.

In addition, we have paid Ps$17.2 billion in the decontamination of the Iscala creek and Pamplonita river and additional remediation activities.

As of January 4, 2012, we have cleaned the totality of affected water bodies and the majority of our remediation activities in connection with the product spill have been completed.

We have third-party general liability insurance coverage that applies to damages resulting from incidents such as the ones that occurred in Dosquebradas and Cucuta.

Given the uncertainty of the outcome of current investigations and of potential future claims regarding these two incidents, we recorded in our financial statements a provision for payments and disbursements as if we had been found liable for all damages caused by the incidents. Nevertheless, the provision is only a reasonable estimate of the costs associated with the incident and not a definitive amount. We will continue to review the amount of any necessary accruals, potential asset impairments, or other related expenses and record the charges in the period in which the determination is made and an adjustment is required.

Legal agreements

According to Decree 2100 of 2011, Ecopetrol signed a mandate agreement establishing Ecopetrol will not buy natural gas royalties from its oil & gas properties, exception made for the royalties committed on the contracts in force before Law 1118 of 2006 issuance.  From July 2012, Ecopetrol will trade on behalf of the Asociación Nacional de Hidrocarburos the natural gas royalties of 2012 and 2013. It is expected from this agreement that Ecopetrol natural gas sales to third parties will decrease.

On March, 2012 Petróleos de Venezuela S.A. (PDVSA) and Ecopetrol  agreed to incorporate a new company for improving operating conditions of four fields located in Venezuela so that those fields production increase from 40,000 to 100,000 barrels per day.

Asset Retirement Obligation

On April 2012, Hocol renegotiated asset retirement costs with Asociación Palermo for the abandonment of Palermo field. The impact of this agreement is an additional USD$2,912,249.

Dry Wells

As disclosed in Note xiv. Ecopetrol charged to expense an amount of $54,409 of capitalized exploratory costs regarding dry wells declared during first quarter of 2012.

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34. Differences between Colombian Governmental Entity accounting principles and U.S. GAAP

The Company's consolidated financial statements are prepared in accordance with Colombian Government Entity GAAP (RCP).  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 RCP 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 RCP.

A) Reconciliation of net income attributable to Ecopetrol S.A.:

The following table presents the reconciliation of net income under Colombian Government Entity GAAP to net income under U.S. GAAP attributable to Ecopetrol S.A. for the years ended December 31, 2011, 2010 and 2009:

		2011			2010			2009
	Consolidated net income under Colombian Government Entity GAAP	$	15,452,334		$	8,146,471		$	5,132,054
i.	Investment securities:
	a.  Unrealized gain (loss)		(224	)		63,545			702,876
	b.  Impairment		21,423			(36,818	)		28,083
ii.	Investments in non-marketable securities:
	a.  Equity method		(27,825	)		(25,063	)		(181,991	)
	b.  Variable Interest Entity (VIE)		-			(13	)		320,600
	c.  Impairment		13,136			(61,371	)		(4,810	)
iii.	Derivatives		(768	)		(24,736	)		20,521
iv.	Exchange of non-monetary assets		425,521			23,640			23,640
v.	Deferred charges		(1,710,944	)		(7,167	)		(35,702	)
vi.	Employee benefit plans		288,616			336,276			342,451
vii.	Provisions, allowances and contingencies		335,983			67,629			12,779
viii.	Assets and liabilities fair value		126,861			-			-
ix.	Deferred income taxes		(647,139	)		(1,159,147	)		(779,934	)
x.	Revenue recognition:
	a.  Cost of sales – over and under		(449,225	)		158,609			(110,087	)
	b.  Other income		70,658			(11,685	)		8,906
xi.	Inflation adjustment		289,470			320,374			177,300
xii.	Inventories		76,126			(87,797	)		16,853
xiii.	Lease accounting		(47,372	)		(36,298	)		(43,163	)
xiv.	Property, plant and equipment:
	a.  Interest		(122,177	)		(168,527	)		(63,779	)
	b. Revaluation of property plant and equipment and public accounting effect
	c.  Impairment		(120,225	)		(157,446	)		(248,765	)
	d.  Capitalized expenses		7,472			38,751			(118,376	)
	e.  Exchange difference		(5,769	)		-			(16,028	)
xv.	Depreciation, Depletion and Amortization		462,333			702,527			563,145
xvi.	Asset retirement obligations		(217,430	)		140,959			297,702
xvii.	Equity contributions:
	a.  Incorporated institutional equity		29,446			20,281			20,692
	b.  Reversal of concession rights contributed as capital		2,464			81,058			18,199
xviii.	Public Offering cost and discount on issuance of shares		103,949			-			-
xix.	Indebtedness cost		(652	)		(1,670	)		8,800
xx.	Business combinations:
	a.  Goodwill		229,646			172,660			139,909
	b.  Fair value adjustments to assets and liabilities acquired		89,387			(176,590	)		(362,216	)
xxi.	Non-controlling interest		(7,015	)		(124,394	)		(151,355	)
xxii.	Cumulative Translation Adjustment		149,147			16,977			-
	Consolidated net income under U.S. GAAP attributable to Ecopetrol S.A.	$	14,817,207		$	8,211,035		$	5,718,304

F-60

B) Reconciliation of Shareholders’ equity attributable to Ecopetrol S.A.:

The following table presents the reconciliation of Ecopetrol shareholders’ equity under Colombian Government Entity GAAP to Ecopetrol shareholders’ equity under U.S. GAAP attributable to Ecopetrol S.A for the years ended December 31, 2011 and 2010:

		2011			2010
	Consolidated shareholders’ equity under Colombian Government Entity GAAP	$	54,688,855		$	41,328,181
i.	Investment securities:
	a.  Unrealized gain		1,145,134			1,660,975
ii.	Investments in non-marketable securities:
	a.  Equity method		(1,578,658	)		(1,496,057	)
	b.  Variable Interest Entity (VIE)		320,587			320,587
	c.  Valuation surplus		(1,179,024	)		(1,693,553	)
	d.  Impairment		(53,045	)		(66,182	)
iii.	Derivatives		-			769
iv.	Exchange of non-monetary assets		1,135,175			709,654
v.	Deferred charges		(1,646,275	)		17,026
vi.	Employee benefit plans		(2,985,447	)		(1,795,081	)
vii.	Provisions – allowance and contingencies		350,535			121,718
viii.	Assets and liabilities Fair Value		98,600			-
ix.	Deferred income taxes		(2,335,269	)		(2,039,099	)
x.	Revenue recognition:
	a.  Cost of sales – over and under		(386,427	)		(63,690	)
	b.  Other income		(1,128	)		(1,128	)
xi.	Inflation adjustment		(3,237,529	)		(3,515,570	)
xii.	Inventories		(38,473	)		(114,868	)
xiii.	Lease accounting		315,923			363,315
xiv.	Property, plant and equipment:
	a.  Interest		(314,700	)		(192,538	)
	b.  Revaluation of property, plant and equipment and public accounting effect		(12,396,858	)		(9,375,123	)
	c.  Impairment		(128,210	)		(1,870	)
	d.  Capitalized expenses		(577,734	)		(577,976	)
	e.  Exchange difference		(253,782	)		(233,563	)
xv.	Depreciation, Depletion and Amortization		5,152,512			4,342,688
xvi.	Asset retirement obligations		253,327			460,668
xvii.	Equity contributions:
	a.  Incorporated institutional equity		(51,693	)		(64,412	)
	b.  Reversal of concession rights contributed as capital		(19,738	)		(22,202	)
xviii.	Indebtedness cost		6,479			7,130
xix.	Business combinations:
	a.  Goodwill		383,075			142,611
	b.  Fair value adjustments to assets and liabilities acquired		(1,405,659	)		(772,416	)
xx.	Non-controlling interest		981,572			206,626
xxi.	Cumulative Translation Adjustment		(186,952	)		(481,335	)
	Consolidated Ecopetrol shareholders’ equity under U.S. GAAP	$	36,055,173		$	27,175,285

F-61

C) Supplemental condensed consolidated financial statements under U.S. GAAP

1.  Supplemental condensed consolidated balance sheets the condensed balance sheets of the Company as of December 31, 2011 and 2010 under U.S. GAAP are presented below:

	2011		2010
Assets
Current assets:
Cash and cash equivalents	$	7,073,550	$	3,910,745
Investments
Available for sale		909,161		58,935
Held to maturity		19,002		17,369
Accounts and notes receivable, net		5,474,883		3,249,046
Inventories		2,696,103		2,055,736
Prepaid expenses and other assets		408,194		491,762
Deferred income taxes		1,228,552		1,438,988
Total current assets		17,809,445		11,222,581
Investments
Available for sale		5,476,838		5,807,075
Held to maturity		98,372		110,755
Equity Method		1,037,012		932,721
Accounts and notes receivable, net		406,944		1,538,450
Restricted assets		549,882		391,021
Property, plant and equipment, net		25,604,983		17,744,665
Natural and environmental resources, net		15,690,887		10,191,727
Goodwill		1,388,568		1,380,632
Deferred charges and other assets		1,374,470		1,590,565
Deferred income taxes		1,158,314		1,405,987
Capital lease		313,364		15,969
Total assets	$	70,909,079	$	52,332,148
Liabilities and shareholders’ equity
Current liabilities:
Financial obligations	$	837,408	$	1,091,079
Accounts payable and related parties		5,043,569		4,344,528
Capital lease liability		108,848		74,681
Taxes payable		6,236,515		2,222,073
Labor and pension plan obligations		233,322		160,248
Estimated liabilities and provisions		1,521,444		1,173,401
Deferred income tax liability		21		-
Other short-term liabilities		2,370		-
Total current liabilities		13,983,497		9,066,010
Financial obligations, long-term		7,896,125		7,830,812
Accounts payable, long-term		640,469		651,692
Capital lease liability		351,809		242,592
Taxes payable		1,003,442		-
Pension plan obligation and other labor obligations, long-term		6,354,272		4,787,698
Estimated liabilities and provisions		2,081,776		1,783,282
Deferred income tax liability		144,149		-
Other long-term liabilities		110,248		485,426
Total non-current liabilities		18,582,290		15,781,502
Total liabilities		32,565,787		24,847,512
Shareholders’ equity of Ecopetrol		36,055,173		27,175,285
Non-controlling interest		2,288,119		309,351
Total equity		38,343,292		27,484,636
Total liabilities and shareholders’ equity	$	70,909,079	$	52,332,148

F-62

2.  Supplemental consolidated statements of income

The statements of income of the Company for the years ended December 31, 2011, 2010 and 2009 under U.S. GAAP are presented below:

	2011			2010			2009
Revenue:
Local sales	$	23,109,208		$	18,291,606		$	13,808,720
Foreign sales		39,606,607			22,587,718			15,742,854
Total revenue		62,715,815			40,879,324			29,551,574
Cost of sales		32,988,977			24,059,620			18,651,187
		29,726,838			16,819,704			10,900,387
Operating expenses:
Administration		3,826,298			856,880			1,027,031
Selling and projects		2,226,753			2,084,310			1,818,143
Operating income		23,673,787			13,878,514			8,055,213
Non-operating income, net		(217,102	)		(1,037,793	)		713,170
Income before income tax		23,456,685			12,840,721			8,768,383
Income tax:
Current income tax		7,501,002			3,201,040			1,948,819
Deferred income tax		898,084			1,196,757			945,144
		8,399,086			4,397,797			2,893,963
Net income		15,057,599			8,442,924			5,874,420
Less: Net (income) attributable to Non-controlling interest		(240,392	)		(231,889	)		(156,116	)
Net Income attributable to Ecopetrol S.A.	$	14,817,207		$	8,211,035		$	5,718,304
Earnings per share (Basic and diluted) attributable to Ecopetrol common shareholders	$	364.64		$	202.88		$	141.29
Weighted-average shares outstanding (Basic and diluted)		40,634,882,725			40,472,512,588			40,472,512,588

F-63

3.  Supplemental condensed consolidated statements of cash flows

The statements of cash flows of the Company for the years ended December 31, 2011, 2010 and 2009 under U.S. GAAP are presented below:

	2011			2010			2009
Cash flows provided by operating activities:
Net income	$	14,817,207		$	8,211,035		$	5,718,304
Adjustments to reconcile net income to cash provided by operating activities:
Non controlling interest		240,392			231,889			156,116
Equity method in non-marketable securities		(545,421	)		25,063			40,635
Depreciation, depletion and amortization		5,109,820			3,608,292			4,106,221
Impairment		116,154			157,446			248,765
Provisions		481,191			(141,038	)		362,424
Deferred income tax		898,084			1,196,757			945,144
Exchange gain (loss)		58,380			(137,054	)		(544,622	)
Loss on retirement of property, plant and equipment		418			42,340			-
Losses in retirement of investment in natural and environmental resources		-			39,668			-
Other asset write-offs		300			359,981			4,810
Net changes in operating assets and liabilities:
Accounts and notes receivable		(2,004,645	)		7,910			3,730,221
Inventories		(642,888	)		(90,512	)		(45,289	)
Deferred charges and other assets		76,208			(520,175	)		171,413
Accounts payable and related parties		(235,888	)		1,294,450			1,398,162
Taxes payable		3,857,834			553,613			(4,384,524	)
Labor obligations		631,036			(369,839	)		304,686
Estimated liabilities and provisions		(935,789	)		(639,758	)		121,387
Bargain purchase gain		(89,387	)		-			(264,085	)
Fair value of pre-existing participation of business combination		-			-			107,545
Net cash provided by operating activities		21,833,006			13,830,068			12,177,313
Cash flows from investing activities:
Payment for purchase of companies, net of cash acquired		(262,009	)		(1,163,131	)		(4,061,289	)
Purchase of investment securities		(11,685,030	)		(11,808,784	)		(7,921,615	)
Redemption of investment securities		12,019,376			9,952,542			12,250,387
Proceeds from sales of property, plant and equipment		-			4,751			1,927
Investment in natural and environmental resources		(4,258,922	)		(3,759,410	)		(2,934,666	)
Additions to property, plant and equipment		(10,100,158	)		(5,946,298	)		(6,419,793	)
Net cash used in investing activities		(14,286,743	)		(12,720,330	)		(9,085,049	)
Cash flows from financing activities:
Return on capital through spin-off		-			(325,367	)		(340,178	)
Repayment of financial obligations		132,542			(43,677	)		(310,420	)
Proceeds from financial obligations		(217,383	)		2,959,345			6,152,400
Proceeds from issuance of shares		2,499,062			525			41,044
Cash paid to acquire a non-controlling interest		(884,946	)		-			(998,903	)
Dividends paid		(5,896,886	)		(3,782,966	)		(8,902,602	)
Net cash used in financing activities		(4,367,611	)		(1,192,140	)		(4,358,659	)
Effect of exchange rate changes on cash		15,846			(155,476	)		(291,470	)
Net increase (decrease) in cash and cash equivalents		3,162,805			73,075			(974,925	)
Cash and cash equivalents at beginning of year		3,910,745			3,837,670			4,812,595
Cash and cash equivalents at end of year	$	7,073,550		$	3,910,745		$	3,837,670

F-64

	2011		2010		2009
Supplemental cash flows information
Cash paid during the year
Interest	$	509,177	$	404,708	$	107,343
Income taxes	$	3,631,331	$	982,783	$	3,934,441
Non-cash transactions
Liabilities assumed in business combinations	$	382,456	$	-	$	891,239
Assets acquired through Capital Lease contracts	$	72,784	$	-	$	-
Increase of natural and environmental resources through asset retirement obligations	$	637,238	$	779,913	$	96,766

Under Colombian Government Entity GAAP as in effect for 2007, some deposits with banks were considered as short-term investments since they produce yields and the Company has defined them to be used for specific purposes. Under U.S. GAAP, these deposits are considered cash.  The amounts reclassified as of December 31, 2011, 2010 and 2009 were $487,922, $183,967 and $275,552. These deposits are valued at fair value.

Certain reclassifications have been made to prior years’ cash flow statement to conform to current year presentation.

F-65

4.  Supplemental consolidated statements of shareholders’ equity.

The statements of shareholders’ equity of the Company for the years ended December 31, 2011, 2010 and 2009 under U.S. GAAP as follows:

	Common Stock
	Millions of shares		Value		Additional paid- in-capital			Comprehensive Income			Retained earnings			Accumulated Other Comprehensive income (loss)			Ecopetrol’s Equity			Non- Controlling Interest			Total Equity
Balance at December 31, 2008		40,473		10,117,791		4,436,391						12,432,901			438,652			27,425,735			818,772			28,244,507
Business combination		-		-		-			-			-			-			-			21,530			21,530
Acquired non-controlling interest		-		-		(432,766	)		-			-			-			(432,766	)		(281,692	)		(714,458	)
Other non-controlling interest		-		-		-			-			-			-			-			22,775			22,775
Issuance of company shares		-		-		41,044			-			-			-			41,044			-			41,044
Distribution of dividends		-		-		-			-			(8,903,953	)		-			(8,903,953	)		(89,736	)		(8,993,689	)
Comprehensive income:		-		-		-			-			-			-			-			-			-
Net income		-		-		-		$	5,874,420			5,718,304			-			5,718,304			156,116			5,874,420
Other Comprehensive income, net of tax:
Unrealized earnings on investment securities, net of tax effect of $226,832		-		-		-			136,600			-			-			136,600			-			136,600
Actuarial (loss), net of tax effect of $482,535		-		-		-			(979,694	)		-			-			(979,694	)		-			(979,694	)
Translation adjustment		-		-		-			(634,606	)		-			-			(621,559	)		(13,047	)		(634,606	)
Total other comprehensive income		-		-		-			(1,477,700	)		-			(1,464,653	)		-			-			-
Comprehensive income		-		-		-		$	4,396,720			-			-			-			-			-
Balance at December 31, 2009		40,473		10,117,791		4,044,669						9,247,252			(1,026,001	)		22,383,712			634,718			23,018,430
Acquired non-controlling interest		-		-		(804	)		-			-			-			(804	)		804			-
Other non-controlling interest		-		-		-			-			-			-			-			4,444			4,444
Issuance of company shares		-		337		188			-			-			-			525			-			525
Distribution of dividends		-		-		-			-			(3,682,998	)		-			(3,682,998	)		(418,558	)		(4,101,556	)
Return of Capital due to a Spin-Off		-		-		-			-			-			-			-			(144,251	)		(144,251	)
Comprehensive income:		-		-		-			-			-			-			-			-			-
Net income		-		-		-		$	8,442,925			8,211,035			-			8,211,035			231,889			8,442,925
Other Comprehensive income, net of tax:
Unrealized earnings on investment securities, net of tax effect of $8,819		-		-		-			997,425			-			-			997,425			-			997,425
Actuarial (loss), net of tax effect of $206,699		-		-		-			(419,661	)		-			-			(419,661	)		-			(419,661	)
Translation adjustment		-		-		-			(313,642	)		-			-			(313,947	)		305			(313,642	)
Total other comprehensive income		-		-		-			264,122			-			263,817			-			-			-
Comprehensive income		-		-		-		$	8,707,047			-			-			-			-			-
Balance at December 31, 2010		40,473	$	10,118,128	$	4,044,053					$	13,775,291		$	(762,184	)	$	27,175,285		$	309,351		$	27,484,636
Business combination		-		-		-			-			-			-			-			1,425,702			1,425,702
Acquired non-controling interest		-		-		(792,440	)		-			-			-			(792,440	)		(92,506	)		(884,946	)
Issuance of shares		644		161,047		1,963,687			-			-			-			2,124,734			374,328			2,499,062
Distribution of dividends		-		-		-			-			(5,868,515	)		-			(5,868,515	)		-			(5,868,515	)
Comprehensive income:		-		-		-			-			-			-			-			-			-
Net income		-		-				$	15,057,599			14,817,207			-			14,817,207			240,392			15,057,599
Other Comprehensive income, net of tax:
Unrealized earnings on investment securities, net of tax effect of $7,086		-		-		-			(529,751	)		-			-			(529,867	)		116			(529,751	)
Actuarial (loss), net of tax effect of $488,064		-		-		-			(990,918	)		-			-			(990,918	)		-			(990,918	)
Translation adjustment		-		-		-		$	150,424			-			-			119,688			30,736			150,424
Total other comprehensive income		-		-		-			(1,370,245	)		-			(1,401,097	)		-			-			-
Comprehensive income		-		-		-		$	13,687,354			-			-			-			-			-
Balance at December 31, 2011	$	41,117	$	10,279,175	$	5,215,300					$	22,723,983		$	(2,163,281	)	$	36,055,173		$	2,288,119		$	38,343,292

F-66

5. Supplemental Consolidated Comprehensive Income

	2011			2010			2009
Net Income	$	15,057,599		$	8,442,925		$	5,874,420
Other Comprehensive income, net of tax:
Unrealized gain (loss) on investment securities, net of tax:		(529,956	)		997,425			136,600
Unrealized actuarial (loss), net of tax		(990,918	)		(419,661	)		(979,694	)
Translation gain (loss) adjustment		150,424			(313,642	)		(634,606	)
Total other comprehensive income		(1,370,450	)		264,122			(1,477,700	)
Comprehensive income		13,687,149			8,707,047			4,396,720
Comprehensive income attributable to the non-controlling interest		(271,039	)		(232,194	)		(143,069	)
Comprehensive income attributable to Ecopetrol	$	13,416,110			8,474,853		$	4,253,651

A detail of accumulated other comprehensive income attributable to Ecopetrol, including the related income tax effects, is presented below:

	2011
	Before-Income Tax Amount			Income Tax   (Expense)    Benefit			Net of Income Tax Amount
Unrealized gain (loss) on securities available for sale	$	1,197,304		$	(18,718	)	$	1,178,586
Pension liability - net unamortized actuarial gain  (loss)		(4,118,015	)		1,358,945			(2,759,070	)
Cumulative translation adjustment		(582,797	)		-			(582,797	)
Other comprehensive income (loss)	$	(3,503,508	)	$	1,340,227		$	(2,163,281	)

	2010
	Before-Income Tax Amount			Income Tax (Expense) Benefit			Net   of Income Tax Amount
Unrealized gain (loss) on securities available for sale	$	1,734,255		$	(25,802	)	$	1,708,453
Pension liability – net unamortized actuarial gain  (loss)		(2,639,033	)		870,881			(1,768,152	)
Cumulative translation adjustment		(702,485	)		-			(702,485	)
Other comprehensive income (loss)	$	(1,607,263	)	$	845,079		$	(762,184	)

	2009
	Before-Income Tax Amount			Income   Tax (Expense) Benefit			Net   of Income Tax Amount
Unrealized gain (loss) on securities available for sale	$	745,649		$	(34,621	)	$	711,028
Pension liability – net unamortized actuarial gain (loss)		(2,012,673	)		664,182			(1,348,491	)
Cumulative translation adjustment		(388,538	)		-			(388,538	)
Other comprehensive income (loss)	$	(1,655,562	)	$	629,561		$	(1,026,001	)

F-67

D) Summary of significant differences between Colombian Government Entity GAAP and U.S. GAAP and required U.S. GAAP disclosures

i. INVESTMENT SECURITIES

The Company’s investments include both marketable securities and non-marketable securities.  Under RCP, 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 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.  In the absence of 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 in ASC Sub-topic 320-10-25, Accounting for Certain Investments in Debt and Equity Securities. 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 any other than temporary impairment of the values of the investments occurs, the impairment loss is recorded in income.

The Company’s short-term and long-term investments at December 31, 2011, 2010, and 2009 consist of the following:

As of December 31, 2011	Aggregated Fair Value		Gross Unrealized Holding Gains		Gross Unrealized Holding Losses			Gross Recognized Losses			Cost Basis
Short-term Investments – Available for Sale Securities:
Securities issued or secured by Colombian government	$	496,184	$	17,151	$	(279	)	$	(10,257	)	$	489,569
Securities issued or secured by government sponsored enterprise  (GSEs)		48,672		270		-			-			48,402
Securities issued or secured by financial entities		293,111		1,613		(36	)		(1,430	)		292,964
Other debt securities		71,194		338		(10	)		(136	)		71,002
Total Short-term Investments Classified as Available for Sale		909,161		19,372		(325	)		(11,823	)		901,937
Long-term Investments – Available for Sale Securities:
Securities issued or secured by Colombian government		806,961		22,083		(9,075	)		(9,397	)		803,350
Securities issued or secured by government sponsored enterprise (GSEs)		2,100,055		7,422		(1,374	)		(56	)		2,094,063
Securities issued or secured by financial entities		259,745		100		(1,818	)		-			261,463
Securities issued or secured by the U.S government		700,237		503		(16	)		(60	)		699,810
Other debt securities		208,334		631		(153	)		-			207,856
Securities issued by mixed- economy governmental entities		1,401,506		1,140,507		-			-			260,999
Total Long-term Investments Classified as Available for Sale		5,476,838		1,171,246		(12,436	)		(9,513	)		4,327,541
Total  Available for Sale	$	6,385,999	$	1,190,618	$	(12,761	)	$	(21,336	)	$	5,229,478

	Aggregated Fair Value		Gross Unrealized Holding Gains		Gross Unrealized Holding Losses			Net Carrying Amount
Short-term Investments – Held to Maturity Securities:
Other debt securities	$	3,477	$	-	$	(3,322	)	$	6,798
Securities issued or secured by Colombian government		12,285		81		-			12,204
Total Short-term Investments Classified as Held to Maturity		15,762		81		(3,322	)		19,002
Long-term Investments- Held to Maturity Securities:
Securities issued or secured by Colombian government		109,629		11,257		-			98,372
Total Long-term Investments Classified as Held to Maturity		109,629		11,257		-			98,372
Total Held to Maturity	$	125,391	$	11,338	$	(3,322	)	$	117,374

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As of December 31, 2010	Aggregated Fair Value		Gross Unrealized Holding Gains		Gross Unrealized Holding Losses			Gross Recognized Losses			Cost Basis
Short-term Investments – Available for Sale Securities:
Securities issued or secured by Colombian government	$	19,527	$	255	$	-		$	-		$	19,272
Securities issued or secured by financial entities		39,408		-		(1,338	)		(156	)		40,902
Total Short-term Investments Classified as Available for Sale		58,935		255		(1,338	)		(156	)		60,174
Long-term Investments – Available for Sale Securities:
Securities issued or secured by Colombian government		1,622,809		35,723		(5,546	)		(19,654	)		1,612,286
Securities issued or secured by government sponsored enterprise (GSEs)		1,498,957		33,141		(1,021	)		(21,382	)		1,488,219
Securities issued or secured by financial entities		80,636		201		(458	)		(1,430	)		82,323
Securities issued or secured by the U.S government		642,974		9,061		(1,924	)		-			635,837
Other debt securities		29,585		459		-			(136	)		29,262
Securities issued by mixed-economy governmental entities		1,932,115		1,656,071		-			-			276,044
Total Long-term Investments Classified as Available for Sale		5,807,076		1,734,656		(8,949	)		(42,602	)		4,123,971
Total  Available for Sale	$	5,866,011	$	1,734,911	$	(10,287	)	$	(42,758	)	$	4,184,145

	Aggregated Fair Value		Gross Unrealized Holding Gains		Gross Unrealized Holding Losses		Net Carrying Amount
Short-term Investments – Held to Maturity Securities:
Other debt securities	$	7,700	$	-	$	-	$	7,700
Securities issued or secured by the U.S government		9,867		199		-		9,669
Total Short-term Investments Classified as Held to Maturity		17,567		199		-		17,369
Long-term Investments-Held to Maturity Securities:
Securities issued or secured by Colombian government		120,322		9,567		-		110,755
Total Long-term Investments Classified as Held to Maturity		120,322		9,567		-		110,755
Total Held to Maturity	$	137,889	$	9,766	$	-	$	128,124

As of December 31, 2009	Aggregated Fair Value		Gross Unrealized Holding Gains		Gross Unrealized Holding Losses			Gross Recognized Losses			Cost Basis
Short-term Investments – Available for Sale Securities:
Securities issued or secured by Colombian government	$	126,376	$	5,472	$	(965	)	$	(6,813	)	$	128,682
Securities issued or secured by government sponsored enterprise  (GSEs)		41,863		4,472		-			-			37,391
Securities issued or secured by financial entities		10,593		1,093		-			-			9,500
Total Short-term Investments Classified as Available for Sale		178,832		11,037		(965	)		(6,813	)		175,573
Long-term Investments – Available for Sale Securities:
Securities issued or secured by Colombian government		597,761		51,997		(375	)		(5,001	)		551,140
Securities issued or secured by government sponsored enterprise  (GSEs)		1,670,687		48,476		-			-			1,622,211
Securities issued or secured by financial entities		592		-		(412	)		-			1,004
Securities issued or secured by government USA		153,186		-		(20,667	)		-			173,852
Securities issued by mixed- economy governmental entities		764,853		640,740		-			-			124,113
Total Long-term Investments Classified as Available for Sale		3,187,079		741,213		(21,454	)		(5,001	)		2,472,320
Total  Available for Sale	$	3,365,911	$	752,250	$	(22,419	)	$	(11,814	)	$	2,647,893

	Aggregated Fair Value		Gross Unrealized Holding Gains		Gross Unrealized Holding Losses		Net Carrying Amount
Short-term Investments – Held to Maturity Securities:
Other debt securities	$	8,280	$	404	$	-	$	7,876
Total Short-term Investments Classified as Held to Maturity		8,280		404		-		7,876
Long-term Investments- Held to Maturity Securities:
Securities issued or secured by Colombian government		129,769		9,655		-		120,114
Securities issued or secured by government USA		10,950		636		-		10,314
Total Long-term Investments Classified as Held to Maturity		140,719		10,291		-		130,428
Total Held to Maturity	$	148,999	$	10,695	$	-	$	138,304

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The maturities of fixed-income investments at December 31, 2011 and 2010 are as follows:

As of December 31, 2011
	Available for Sale				Held to Maturity
	Cost Basis		Fair Value		Cost Basis		Fair Value
Due in one year or less	$	901,937	$	909,161	$	19,002	$	15,762
Due in one to five years		3,961,965		3,974,007		98,372		109,629
Due in five to ten years		365,576		1,502,831		-		-
Total	$	5,229,478	$	6,385,999	$	117,374	$	125,391

As of December 31, 2010

	Available for Sale				Held to Maturity
	Cost Basis		Fair Value		Cost Basis		Fair Value
Due in one year or less	$	60,174	$	58,935	$	17,369	$	17,567
Due in one to five years		3,719,718		5,396,547		110,755		120,322
Due in five to ten years		404,253		410,529		-		-
Total	$	4,184,145	$	5,866,011	$	128,124	$	137,889

Amounts recorded in Other Comprehensive Income in prior years realized on securities available for sale sold at December 31, 2011, 2010 and 2009 were:

	2011		2010		2009
Losses	$	5,837	$	67,225	$	727,697
Gains	$	41,331	$	24,322	$	38,539

Foreign Exchange Gains and Losses on Securities Available for Sale

Under RCP, changes in account balances resulting from variations in foreign currency exchange rates are reflected in the 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 ASC subtopic 320-10-35.  The amount reclassified from earnings under RCP purposes to other comprehensive income for U.S. GAAP purposes includes $197,664, $18,931 and $88,278 in 2011, 2010 and 2009, respectively that correspond to exchange rate differences.

Unrealized loss

Available-for-sale securities in an unrealized loss position as of December 31, 2011 and 2010 are as follows:

As of December 31, 2011
	Less than 12 months				12 Months or Greater				Total
Descriptions of Securities	Fair Value		Unrealized Losses		Fair Value		Unrealized Losses		Fair Value		Unrealized Losses
Securities issued or secured by Colombian government	$	248,874	$	279	$	171,756	$	9,075	$	420,630	$	9,354
Securities issued or secured by financial entities		84,860		36		241,208		1,818		326,068		1,854
Securities issued or secured by government sponsored enterprise (GSEs)		-		-		757,494		1,374		757,494		1,374
Securities issued or secured by the U.S. government		-		-		48,759		16		48,759		16
Other debt securities		30,488		10		89,532		153		120,020		163
Total	$	364,222	$	325	$	1,308,749	$	12,436	$	1,672,971	$	12,761

As of December 31, 2010
	Less than 12 months				12 Months or Greater				Total
Descriptions of Securities	Fair Value		Unrealized Losses		Fair Value		Unrealized Losses		Fair Value		Unrealized Losses
Securities issued or secured by Colombian government	$	346,690	$	5,432	$	6,483	$	115	$	353,173	$	5,547
Securities issued or secured by financial entities		69,756		912		121		883		69,877		1,795
Securities issued or secured by government sponsored enterprise (GSEs)		149,485		1,021		-		-		149,485		1,021
Securities issued or secured by the U.S. government		186,224		1,924		-		-		186,224		1,924
Total	$	752,155	$	9,289	$	6,604	$	998	$	758,759	$	10,287

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Restricted Assets

Under U.S. GAAP the Company classifies as restricted assets, those assets where their availability depends on a court decision, such as cash, trust funds or investments. The detail of restricted assets as of December 31, 2011 and 2010 is as follows:

Concept	2011		2010
Investment securities	$	423,020	$	391,022
Specific destination funds		78,515		-
Cash		48,347		-
Total	$	549,882	$	391,022

The most significant restricted asset is related to Santiago de las Atalayas Fund which is detailed in the chart below:

Concept	2011		2010
Investments available for sale	$	415,722	$	361,607
Specific destination funds *		1,999		1,251
Cash		597		28,164
Total	$	418,318	$	391,022

*This fund receives the coupons and principal payments of the Santiago de las Atalayas investments in U.S. dollars.

The investments related to the Santiago de las Atalayas at December 31, 2011and 2010 consist of the following:

As of December 31, 2011	Aggregated Fair Value		Gross Unrealized Holding Gains		Gross Unrealized Holding Losses			Gross Recognized Losses			Cost Basis
Long-term Investments - Available for Sale Securities:
Securities issued or secured by Colombian government		415,722		19,656		(300	)		(10,062	)		406,427
Total  Long-term Investments Classified as Available for Sale	$	415,722	$	19,656	$	(300	)	$	(10,062	)	$	406,427

As of December 31, 2010	Aggregated Fair Value		Gross Unrealized Holding Gains		Gross Unrealized Holding Losses			Gross Recognized Losses			Cost Basis
Long-term Investments - Available for Sale Securities:
Securities issued or secured by Colombian government	$	201,172	$	7,835	$	(2,126	)	$	(10,062	)	$	205,525
Securities issued or secured by the U.S. government		160,435		3,920		-			-			156,515
Total Long-term Investments Classified as Available for Sale	$	361,607	$	11,755	$	(2,126	)	$	(10,062	)	$	362,040

The unrealized gains and losses of the restricted assets are recognized in Other Comprehensive Income

a. Impairment

Impairment of investment securities are reported differently under RCP and U.S. GAAP.  Under RCP, 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 are included in Other Comprehensive Income.

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;

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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) carry out the analysis as instructed in ASC paragraph 320-10-65-1 which includes the comparison of the fair value and the amortized cost, evaluates the intention to sell the security and if it is more-likely-than-not that the company will be required to sell the security prior to recovery, including the existence of a credit loss.

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 treasury investments, bonds, and commercial papers. 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

The Company recognized impairment on its investment securities amounting to $116, $44,851 and $5,724 in 2011, 2010 and 2009, respectively.

ii. INVESTMENTS IN NON-MARKETABLE SECURITIES

a. Equity Method and Valuation Surplus

Under RCP, equity securities for which prices are not quoted, 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’ 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’ equity of the investee. The proportionate share of shareholder’s equity is considered as the market value for this purpose and is known as book value. Under this method, the Company only records dividends as income when received. From 2008 the RCP incorporated the concept of significant influence for the recognition of investments in associated entities and established the equity method to update these investments.

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. 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 differences between the application of the cost and the equity method under U.S. GAAP were:

· Reversal of valuations and allowances for losses recorded under RCP

· Reversal of inflation adjustments recorded under RCP

· Reversal of Goodwill amortization and impairment

· 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

· Recognition of impairment under US GAAP

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The summary of the investments valued by the equity method for U.S. GAAP purposes is shown in the following table:

For the Year Ended December 31, 2011

Company	Percentage of Voting Interest			Equity Calculated under U.S. GAAP		Equity Under Colombian GAAP		Assets Under Colombian GAAP		Liabilities Under Colombian GAAP		Net Income (Loss) Under Colombian GAAP			Investment Under U.S. GAAP Equity Method		Equity Method Accounting Adj (*)			Total Equity Method Investment
Invercolsa S.A.		43	%	$	226,891	$	536,924	$	537,332	$	408	$	89,713		$	98,357	$	-		$	98,357
Serviport S.A.		49	%		2,503		10,469		50,005		39,536		(750	)		1,226		-			1,226
Offshore International Group		50	%		882,435		882,435		1,807,581		925,145		157,644			441,218		476,596			917,814
Ecodiesel S.A.		50	%		15,889		21,362		138,170		116,808		-			7,944		-			7,944
Sociedad Portuaria de Olefinas		50	%		420		772		1,042		270		6			208		-			208
Transgas de Occidente S.A.		20	%		121,455		209,114		415,669		206,555		20,007			24,291		(12,828	)		11,463
															$	573,244	$	463,768		$	1,037,012

For the Year Ended December 31, 2010

Company	Percentage of Voting Interest			Equity Calculated under U.S. GAAP		Equity Under Colombian GAAP		Assets Under Colombian GAAP		Liabilities Under Colombian GAAP		Net Income (Loss) Under Colombian GAAP			Investment Under U.S. GAAP Equity Method		Equity Method Accounting Adj (*)		Total Equity Method Investment
Invercolsa S.A.		32	%	$	312,711	$	536,744	$	537,319	$	575	$	87,755		$	99,348	$	-	$	99,348
Serviport S.A.		49	%		3,111		14,656		17,312		2,656		(1,637	)		1,524		-		1,524
Offshore International Group		50	%		712,375		780,957		1,187,267		406,310		109,283			356,188		469,851		826,039
Ecodiesel S.A.		50	%		11,191		23,411		132,028		108,617		2,073			5,596		-		5,596
Sociedad Portuaria de Olefinas		50	%		427		780		1,022		242		33			213		-		213
															$	462,869	$	469,851	$	932,720

(*) Represents the purchase price allocation adjustments to assets and liabilities resulting from acquisitions .

Concept	2011			2010
Fair Value of Property, Plant and Equipment	$	(9,414	)	$	3,665
Goodwill		473,182			466,186
Total	$	463,768		$	469,851

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.  Lower court decisions had ruled in favor of both the Company and the other shareholder and a final court decision in January 2011 determined that 324 million shares, equivalent to 11.58% of the capital stock of Invercolsa should be returned to Ecopetrol.  As a result Ecopetrol controls 43.35%. The dividends paid with respect of the shares returned to Ecopetrol are still in dispute, as well as the ownership of shares constituting 8.53% of Invercolsa. The resolution of these matters is still pending.

b. Impairment

Under Colombian Government Entity GAAP it is not mandatory to perform impairment tests of the Equity Method Investments unless positive evidence is identified of impairment. For 2011 and 2010, the investment in Offshore International Group was evaluated for impairment resulting in a loss of $13,136 and $287,662, respectively.

The impairment under U.S. GAAP ASC paragraph 325-20-35 1A and 2, 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. During 2011 the Company evaluated its investments and concluded that they were not impaired. During 2010 the Company evaluated its investments and concluded there was impairment in Offshore International Group “OIG” under both Colombian Government Entity GAAP and U.S. GAAP. This 2010 impairment loss under U.S. GAAP equaled $349,033. For 2009 the Company experienced a U.S. GAAP impairment loss of $4,810.

c. Variable Interest Entity (VIE)

Under U.S. GAAP, ASC paragraph 810-10-15-13 requires that consolidated financial statements include subsidiaries in which the Company has a controlling financial interest, i.e., a majority voting interest.  However, 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.  Thus, the U.S. GAAP rules also require a Company to consolidate a variable interest entity if that company is the primary beneficiary of the VIE, with that has the power to direct the activities of the VIE that most significantly affect the entity’s economic performance and 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 RCP, consolidated financial statements only include subsidiaries in which the Company has the majority voting interest.

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As of December 31, 2008, although Ecopetrol only owned 35.29% of Oleoducto Central S.A. (hereinafter “Ocensa”) it was determined that Ecopetrol was the primary beneficiary based on the variable interests in Ocensa. In addition, in March 2009, through a direct transaction with Enbridge Inc., Ecopetrol acquired an additional 24.71% ownership interest for $998,903 in cash.  As of such date, Ecopetrol’s participation in Ocensa became 60%. Until March 2009, Ocensa was valued at cost under RCP.

According to Colombian Government Entity GAAP, the acquisition of the 24.71% of the non-controlling interest is accounted for as an increase in the investment and goodwill; under U.S. GAAP, the ownership interest increase in a subsidiary is an equity transaction, which decreases the Non-controlling Interests balance and adjusts additional paid-in-capital in by the difference between the non-controlling interest carrying amount and the consideration paid. Under U.S. GAAP, the additional paid-in capital effect of the transaction was a decrease of $610,007.  A corresponding deferred income tax effect of $177,241 was recorded, resulting in a net effect of $432,766.

The adjustment of Ocensa as a VIE according to financial information under U.S. GAAP as of and for the years ended December 31, 2009, is as follows:

	2009
Assets	$	320,600
Liabilities		-
Equity		320,600
Net income	$	320,600

The financial information summary of Ocensa according to financial information under U.S. GAAP as of and for the years ended December 31, 2009, is as follows:

	2009
Assets	$	1,268,681
Liabilities		(61,566	)
Equity		1,207,115
Net income	$	497,471

In October 2009, the subsidiary Oleoducto de los Llanos Orientales (hereinafter “ODL”) assigned its rights under a "Ship or Pay” contract for the completion of a securitization for the purpose of obtaining the funds required to finish the second phase of the project, the refund of capital to the associates, and maintain the capital structure initially agreed. The structure of this issuance was made through assets in a trust fund (hereinafter “Fideicomiso P.A. ODL - ECOPETROL”) administered by Corficolombiana S.A., who has to pay the security holder on the due dates. Additionally, each month, the trust company must report to ODL income and expenses that are generated in this process and that are paid, if applicable, to ODL as advances.

Based on the ASC 810, ODL determined that it must consolidate Fideicomiso P.A. ODL - ECOPETROL, since it is a VIE and ODL is the primary beneficiary and therefore, consolidated its financial statements for U.S. GAAP purposes.

The adjustments of Fideicomiso P. A. ODL - ECOPETROL, according to financial information under U.S. GAAP as of and for the years ended December 31, 2011 and 2010, are as follows:

	2011			2010
Assets	$	6,580		$	5,464
Liabilities		(6,593	)		(5,477	)
Equity	$	13		$	13
Net income	$	0		$	13

F-74

The financial information summary of Fideicomiso P. A. ODL - ECOPETROL according to U.S. GAAP as of and for the years ended December 31, 2011 and 2010, are as follows:

	2011			2010
Assets	$	530,969		$	522,342
Liabilities		(510,405	)		(509,288	)
Equity	$	20,564		$	13,054
Net income	$	8,336		$	11,015

In 2011, the subsidiary Bioenergy forfeited its rights over eight properties as well as the cash related to the last payment of the acquisition of these lands. The structure of these issuances where made through eight trust funds administered by Fiduciaria Fiducor S.A.; on a monthly basis, the trust company must report to Bioenergy, income and expenses that are generated in regards to the administrative process.

Based on the ASC 810 definition, Bioenergy determined that they are the primary beneficiaries of the followings trust funds:

• Fideicomiso 732 - 1149 Nohora Jaramillo y otros

• Fiduciaria Mercantil Administración y Pagos 732-1564

• Fideicomiso 732 - 1148 Rafael Urrea Martinez

• Fiduciaria Mercantil Administración y Pagos 732-1572

• Fideicomiso 732 - 1161 Jorge Ernesto Ortiz Torres

• Fiduciaria Mercantil Administración y Pagos 732-1640

• Fideicomiso 732 - 1189 John Antonio Montoya Villa

• Fiduciaria Mercantil Administración y Pagos 732-1580

Thus, these trust funds qualified as Variables Interest Entities and are in this consolidated financial statements for U.S. GAAP purposes.

The consolidation of these trust funds did not impact the equity and net income according to financial information under U.S. GAAP as of and for the year ended December 31, 2011.

Under U.S. GAAP, the aggregate summary of the trust funds, according to financial information as of and for the years ended December 31, 2011, is as follows:

	2011
Assets	$	6,049
Liabilities		(1	)
Equity		6,048
Net income	$	0

iii. 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 U.S. dollar; however, Ecopetrol manages its foreign currency risk position internally, using non-deliverable forwards, according to the size of the mismatches between its asset-liability position in U.S. dollars and its asset-liability position in Colombian pesos. If no mismatches occur Ecopetrol has a perfect natural hedge. Ecopetrol also utilizes other derivative agreements to mitigate changes in the fair value of commodities. None of the derivatives were designated or documented for hedge accounting.

The Company periodically enters into call and put option contracts to cover the price risk associated with fluctuations in market prices of asphalt. The option contracts limit the unfavorable effect that the price increase will have on asphalt. The maximum term over which the Company is managing its exposure to the variability for commodity price risk is 12 months.

As of December 31, 2011, the Company had entered into one (1) non-deliverable forwards with an effective date of December 29, 2011 and a termination date in January 2012.

The subsidiary Hocol S.A. is exposed to foreign currency fluctuations.  Such exposures arise primarily from expenditures that are denominated in currencies other than the functional currency. The Company constantly monitors its exposure to foreign currency risks. To reduce its foreign currency exposure associated with operating expenses incurred in COP, the Company may enter into foreign currency derivatives to manage such risks. These derivatives are recognized at their fair value as either a financial asset or obligation with the corresponding income or expense recognized.

F-75

Total results recognized related to derivative activities during the years are as follows:

	2011						2010						2009
	Realized			Unrealized			Realized			Unrealized			Realized			Unrealized
Options (1)	$	(199,402	)	$	(2,370	)	$	(13,175	)	$	(1,474	)	$	66,889		$	25,943
Swaps		(613,387	)		-			(7,031	)		2,242			(23,757	)		(438	)
Forwards		2,549			14			245			107			5,862			-
Total	$	(810,240	)	$	(2,356	)	$	(19,961	)	$	875		$	48,994		$	25,505

(1) Amounts include premiums paid

Under RCP, each derivative has its own accounting treatment depending on the type of derivative. Option premiums paid are recorded as deferred charges and amortized to the income statement as financial expense on a straight-line basis over the life of the contract, the option contract is recognized in memo accounts unless it is likely to be exercised, and the gain is recognized as an investment.  Swap and forward contract net results are recorded as an investment. In all cases, gains and losses are recognized in earnings as financial income or expense. Amounts receivable or payable upon maturity resulting from net payments are recorded using current rates for the period.

U.S. GAAP requires that all derivative instruments be recorded on the balance sheet at fair value.  Changes in the fair value of derivatives are recorded each period in current earnings.  The fair value of derivatives instruments is recorded as other assets and other liabilities.

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 ASC paragraph 815-15-15-10 through 13 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. In other cases, contracts indexed to inflation considered clearly and closely related.

Gas imbalance agreements were evaluated to identify if they were derivatives. Management concluded that these agreements are not derivatives since they do not contain fixed notional amounts.

iv. EXCHANGE OF NON-MONETARY ASSETS

During 2007, the Company exchanged a refinery business with a book value of $234,371 for a 49% interest in Refinería de Cartagena S.A.  The Company estimated the fair value of the 49% investment as $1,369,546.  Under RCP, this difference between the cost of the assets given and the fair value of the assets received was recorded as an increase to asset revaluation and equity.  However, under ASC Subtopic 845-10-30, 51% of the difference between the book value of the Refinery and the fair value of the assets received, which the Company determined to be a more reliable indicator of the value of the exchange since the fair value of the investment was greater, was recorded in the results of operations as a gain in the amount of $578,939. The remaining 49% of unrealized gain was recorded as a deferred gain with a corresponding increase to the investment, equivalent to a deferred gain of $556,236, to be amortized over the expected useful life of the equipment. In 2011, the Company determined that in 2009, as a result of the acquisition of 51% of the remaining participation in Reficar S.A., the unamortized unrealized gain should have been recorded at fair value since the Company obtained control of Refinería de Cartagena S.A. in 2009 in line with the acquired entity’s fair value of the assets and liabilities acquired as of May 27, 2009. However, according to ASC 250 and SAB 108, we do not consider such amount significant and decided to fully amortize the remaining balance as of 2011. As a result, the net income reconciliation includes amortized income of $425,521 in 2011, $ 23,640 in 2010 and $23,640 in 2009, corresponding to the amortization of the deferred gain.

v. DEFERRED CHARGES

Under Colombian Government Entity GAAP, the Equity Tax is recognized as a deferred expense for the total amount due payable during the years 2011 through 2014. The deferred expense is amortized as an expense of the year that payments are made. The local regulatory entities also allowed companies that applied inflation adjustments and still have outstanding balances in the Equity Revaluation account to reduce such balance instead of recognizing a deferred expense. Other deferred assets recognized under RCP are related to certain pre-operating expenses and other charges that include normal recurring maintenance and fees.

For U.S. GAAP purposes, in 2011, deferred expenses related to equity tax amounting to $1,663,816 were recognized as expense. The other deferred charges amounting to $47,128 in 2011, $7,167 in 2010; and $35,702 in 2009 were written-off for U.S. GAAP purposes.

F-76

vi. EMPLOYEE BENEFIT PLANS

Under Colombian Government Entity GAAP, the Company estimates the net present value of its actuarial liability for all pension plans and other post-retirement obligations. 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.

For other post-retirement benefits, the payments are made according to seniority and the salary at the time of retirement, as stipulated in the Collective Labor Agreement and Agreement No. 01.

Under the post-retirement benefits plan for Ecopetrol personnel, the Company covers 90% of educational expenses for children of employees, including enrollment fees, tuition and other associated costs. A fixed annual sum, depending on grade level, is also provided for the acquisition of textbooks. Educational coverage includes kindergarden, elementary school, high school and college. Ecopetrol´s financial statements must also show the cost of post-retirement educational benefits for children of retired employees, since benefits continue irrespective of retirement or death.

According to the Collective Labor Agreement and Agreement No. 01, the Company will pay for health services for employees and enrolled family members. Health services include: office visits and required laboratory services, drugs, diagnostic examinations, ambulatory treatment, hospitalization due to illness or accident, surgery due to illness or accident, maternity and rehabilitation treatments and orthopedic parts. Therefore, such post-retirement health benefit costs are recorded in the RCP Ecopetrol financial statements, since retired workers and enrolled family members continue to receive full medical coverage. The same is true for deceased non-retired employees.

U.S. GAAP requires the recognition of pension, health care and education plans costs based on actuarial computations under a prescribed methodology which differs from that used under RCP. For purposes of the U.S. GAAP reconciliation, the transition obligation is calculated at the date the Company adopted the ASC Topic 420, 715, 805, 835 and 980 Employers Accounting for Pensions and is being amortized as of January 1, 1989. The transition obligation for the education and medical plan is being amortized from January 1, 1995.

Under Colombian law, employees are entitled to one month salary for each year of service. This benefit is known as the “severance obligation” or “cesantias”. This benefit accumulates during the time of employment and is paid to employees upon their termination or retirement from Ecopetrol. However, employees may request advanced benefit payments at any time. In 1990, the Colombian government revised its labor regulations to permit companies, subject to employee approval, to pay the severance obligation to their employees on a current basis. Law 50 of 1990 also enabled each employee to freely choose yearly which trust fund would manage the amount accrued during each year in which they are eligible for severance payments. This amount must be transferred by the company to the trust fund no later than the next subsequent year.

In addition, the Company under Colombian law must pay pension bonds for certain employees when they leave Ecopetrol. Those bonds payable accrue interest at the DTF rate, according to the class of bonds, as follows:

1) For pension bonds type B, CPI + 4%;

2) For pension bonds type A, with date of transfer before December 31, 1998, CPI + 4%;

3) For the remaining pension bonds type A, CPI + 3%.

The economic assumptions used in the determination of pension obligations under U.S. GAAP differ from those used under RCP since the latter are established annually by the Colombian regulations.

Ecopetrol has not made any change to its methodology or accounting policy for the determination of disclosure information. However, they are based on the calculations of a new actuary and therefore have a new valuation system.

The combined costs for the above mentioned benefit plans, determined using U.S. GAAP, for the years ended December 31, 2011, 2010 and 2009 are summarized below: (all obligations were measured at year-end)

	2011									2010									2009
				Other
Components of net periodic benefit				Benefits									Other									Other
costs:	Pension			(*)			Total			Pension			Benefits (*)			Total			Pension			Benefits (*)			Total
Service cost	$	-		$	788		$	788		$	46,686		$	32,840		$	79,526		$	21,126		$	40,279		$	61,405
Interest cost		830,411			371,698			1,202,109			845,144			386,159			1,231,303			1,037,577			446,502			1,484,079
Expected Return on plan assets		(714,757	)		(164,644	)		(879,401	)		(1,303,018	)		(290,075	)		(1,593,093	)		(1,013,399	)		(238,744	)		(1,252,143	)
Amortization of net (gain) or loss		592,582			24,564			617,146			22,977			41,293			64,270			-			10,009			10,009
Net periodic pension cost under U.S. GAAP - (gain) or loss		708,236			232,406			940,642			(388,211	)		170,217			(217,994	)		45,304			258,046			303,350
Net periodic pension cost under Colombian GAAP (gain) or loss		565,725			663,536			1,229,261			264,693			(146,411	)		118,282			118,677			527,124			645,801
Difference to be recognized under U.S. GAAP (income) loss	$	142,511		$	(431,130	)	$	(288,619	)	$	(652,904	)	$	316,628		$	(336,276	)	$	(73,373	)	$	(269,078	)	$	(342,451	)

(*) Other benefits include education, health, pension bonds and accrued severance.

F-77

The changes in the benefit obligations and  in plan assets for the above mentioned benefit plans, determined using U.S. GAAP, for the years end December 31, 2011 and 2010, are summarized below:

	Pension Plans						Other Benefits
	2011			2010			2011			2010
Reconciliation of project benefit obligation:
Project benefit obligation as of January 1	$	(10,686,243	)	$	(10,338,890	)	$	(4,888,821	)	$	(4,844,216	)
Cost of Service		-			(46,686	)		(788	)		(32,840	)
Cost of interest		(830,411	)		(845,144	)		(371,698	)		(386,159	)
Actuarial (gain) loss		(332,635	)		(58,216	)		(1,640,621	)		120,377
Benefit payments		652,769			602,693			273,189			254,017
Projected benefit obligation as of December 31		(11,196,520	)		(10,686,243	)		(6,628,739	)		(4,888,821	)
Reconciliation of plan assets :
Fair value of plan assets as of January 1		9,105,179			8,973,955			2,097,376			1,997,767
Fund Contribution		1,568,695			-			(1,568,695	)		-
Actual return on plan assets		714,757			1,303,018			164,644			290,075
Benefits paid		(652,769	)		(602,693	)		(3,137	)		(6,776	)
Actuarial (gain) loss on plan assets		(104,030	)		(569,101	)		(18,842	)		(183,690	)
Fair value of plan assets as of December 31		10,631,832			9,105,179			671,346			2,097,376
Projected net benefit obligation and assets, as of December 31		940,601			80,142			(3,344,667	)		(1,813,618	)
Amounts recognized in other comprehensive (income) loss		(1,505,289	)		(1,661,206	)		(2,612,726	)		(977,827	)
Net liability		(564,688	)		(1,581,064	)		(5,957,393	)		(2,791,445	)
Net liability under RCP		(949,105	)		(383,380	)		(2,587,529	)		(2,194,048	)
Net effect under pension plan and other benefits	$	384,417		$	(1,197,684	)	$	(3,369,864	)	$	(597,397	)

Under U.S. GAAP, the method of allocating the comingled asset fund as of the valuation date between the Pension an Pension Bond plan have been changed from allocating the asset fund in proportion to the amounts of the respective liabilities.

While under Colombian GAAP, to allocating the total return for the year between the two plans by calculating a return for each plan, equal to the fund´s total return, given the beginning balances and actual payments for the year. The allocated return added to the beginning balance plus contributions and less the actual payments results in the year-end balance.

Net liability of employee benefit plans, net of other employee benefits, is classified as follows:

	Pension Plans						Other Benefits						TOTAL
	2011			2010			2011			2010			2011			2010
Current portion		-			-			(268,647	)		(468,350	)		(268,647	)		(468,350	)
Long-term portion		(564,688	)		(1,581,064	)		(5,688,746	)		(2,323,095	)		(6,253,434	)		(3,904,159	)
Net liability		(564,688	)		(1,581,064	)		(5,957,393	)		(2,791,445	)		(6,522,081	)		(4,372,509	)

Under U.S. GAAP, the Company applies the provisions of Statement on ASC Topic 420, 715, 805, 835, 958 and 980, as amended by Statement on ASC Topic No. 450 and 715, Employers Disclosure about Pension and Other Post-retirement Benefits, an amendment to ASC Topic No. 420, 715, 805, 835, 980, 712 and 710. The Company adopted Statement on ASC Topic No. 715 and 958 Employers Accounting for Defined Benefit Pension and Other Postretirement Plans effective January 1, 2006, in respect of its defined benefits pension, health and education plans. Accordingly, the Company recognizes the overfunded and 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, 2011 and 2010, net obligation amounts recognized in the balance sheet related to pension, health, education, bonds and severance obligations consist of:

	2011			2010
Long-term liability
Pension	$	(564,688	)	$	(1,581,064	)
Health		(5,286,782	)		(2,799,628	)
Education		(399,142	)		(413,241	)
Bonds		-			899,400
Severance		(2,822	)		(9,626	)
Total long-term liability	$	(6,253,434	)	$	(3,904,159	)

F-78

As of December 31, 2011 and 2010, the amounts recognized in accumulated other comprehensive loss, related to pension, health and education obligations consist of:

	2011			2010			2009
Other comprehensive income
Actuarial income (loss)
Pension	$	(1,505,289	)	$	(1,661,206	)	$	(1,056,866	)
Health		(3,795,848	)		(1,373,096	)		(951,590	)
Education		(109,493	)		(139,445	)		(144,247	)
Bonds		1,284,430			534,714			140,030
Severance		8,185			-			-
Total other comprehensive income (loss)		(4,118,015	)		(2,639,033	)		(2,012,673	)
Deferred income tax effect		1,358,945			870,881			664,182
Total	$	(2,759,070	)	$	(1,768,152	)	$	(1,348,491	)

The significant variation in the other comprehensive income from 2010 to 2011 relates to Health and Bonds plans due to changes in actuarial assumptions since the last actuarial valuation.

The Company expects the following amounts in other comprehensive income to be recognized as components of net periodic pension cost during 2012:

	Years for
	Amortization		Amortization
Pension		20.81	$	18,531
Bonds		14.70	$	82,809
Health		20.06	$	161,780
Education		20.06	$	3,229
Severance		12.56	$	611

As of December 31, 2011 and 2010, the amounts of gain (loss) in the year and accumulated related with pension, health, education bonds and severance consist of:

	2011						2010
	Gain						Gain
	(loss) in			Cumulative Gain			(loss) in
	the year			(loss)			the year			Cumulative gain (loss)
Pension	$	(332,635	)	$	(1,505,289	)	$	(58,216	)	$	(1,661,206	)
Health		(2,473,272	)		(3,795,848	)		(457,941	)		(1,373,096	)
Education		25,757			(109,493	)		(56	)		(139,445	)
Bonds		798,709			1,284,430			578,374			534,714
Severance		8,185			8,185			-			-

The economic assumptions adopted are shown below in nominal terms. Those assumptions used in determining the actuarial present value of the pension obligation and the projected pension obligations for the plan years were as follows:

	2011															2010
	Pension			Health			Education			Bonds			Severance			Pension			Health			Education			Bonds			Severance
Discount rate		7.75	%		8.25	%		7.50	%		7.50	%		5.75	%		8.00	%		8.50	%		8.00	%		8.00	%		8.00	%
Rate of compensation and pension increases		4.50	%		18.40	%		4.50	%		4.50	%		4.50	%		3.48	%		3.48	%		3.48	%		3.48	%		3.48	%
Expected rate of return		3.38	%		-			-			3.38	%		-			4.37	%		-			-			4,37	%		-
Mortality table			*			*			*			*			*			*			*			*			*			*

* Colombian Mortality Table ISS, male and female, 2005-2008.

F-79

The Superintendency of Finance concluded a mortality study based on the experience of the affiliated workers to the pension funds and to the Social Security Institute ISS, during the years 2005-2008. The resulting mortality table from such study reflects the current mortality of the Colombian workers. As it was expected, the new table shows a lower mortality rate compared with those of the actual mortality table, ISS, experience 1981-1989. For such reason, the new table was applied for purposes of executing the different actuarial calculations included in this valuation in 2009.

The rate of return of the plan assets during 2011 was 6.93%. We have considered the expected rate of return on plan assets of 7.00% and an expected inflation rate equal to 3.50% at December 31, 2011, with a real discount rate of 3.38%.

In 2011, the health plan had an increase in the obligation since the amount reflects the current medical cost trend during the last 3 years in increases in health costs in Colombia . In the past 2 years, the Company did not consider generating an increase in health care obligation due to projections by the health department in 2009 and 2010. However, in 2011, the most recent analysis by the health department shows a tendency to the decrease and control of the high costs.

The actuarial assumptions of Health Plan have changed since the last actuarial valuation as of December 31, 2010:

The 2010 valuation used a medical trend rate equal to general inflation. The 2011 valuation uses a trend rate that starts at 18.4% and grades down to general inflation +1% over 10 years.

The 2010 valuation considered the current family group for active participants. For 2011 the valuation was valued as an assumed family group, projected to retirement eligibility based on the demographics of the currently inactive population near first retirement eligibility.

The 2010 valuation does not consider spouses of active or inactive female participants. For 2011 the valuation was valued for all eligible spouses of female inactive participants and projected spouses for active female participants.

The 2010 valuation uses a retirement age that depends on the employee completing the service requirement for retirement with Social Security using only with Ecopetrol. For 2011 valuation, we have assumed an employee´s labor history and Social Security participation starting at age 25.

As mentioned above, as of December 31, 2011, the actuarial assumptions of Pension have changed since the last actuarial valuation as of December 31, 2010, with main updates as follows:

The 2010 liability was calculed as if a participant´s first employer was Ecopetrol. Since employment with other employers before and after employment with the Company is unknown, for the 2011 valuation assumptions have been established to estimate the employee labor history.

The 2010 liability was calculated as if all participants have a Bond type B. For 2011 the valuation was established assumptions that depend on the hire date and the Social Security system in which participants are enrolled.

The 2010 liability was calculated as if all participants would retire immediately. For 2011 the valuation establishes retirement dates depending on whether the participants is eligible for the Company pension plan or the general Social Security retirement benefit.

Estimated future benefit payments

The benefit payments, which reflect expected future service, as appropriate, are expected to be paid as follows:

	Pension		Health Care		Education				Severance
Period	benefits		benefits		benefits		Pension Bonus		Plan
2012	$	691,272	$	218,264	$	48,140	$	49,417	$	2,243
2013		710,522		254,870		50,586		12,864		179
2014		732,569		292,470		51,161		11,335		192
2015		754,903		329,367		50,000		1,006		237
2016		777,413		371,507		48,843		4,516		221
Years 2017 – 2021		4,227,085		2,239,704		214,528		166,271		1,626

 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 in the future.

Furthermore, to the Company currently does not intend to contribute to the fund in the upcoming fiscal year. Management believes that the plan assets will provide for a sufficient return 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:

	1% Percentage Point
	Increase		Decrease
Effect on total of service and interest cost components	$	31,307	$	25,845
Effect on postretirement benefit obligation	$	773,864	$	633,774

F-80

Plan assets

Pension and pension bonds are covered by assets in a single fund with the following investment allocation:

	2011			2010
Government securities		47	%		50	%
Investments funds		33	%		29	%
Equity instruments		1	%		2	%
Other		19	%		19	%
		100	%		100	%

The plan assets do not contain any shares of stock of Ecopetrol or any of its related parties.

In 2007, the Company outsourced administration of its pension plan to a third party (known as a partial transfer). As a result, on October 28, 2008, the Ministry of Finance and Public Credit approved the partial transfer (“commutation”) of the pension obligation of the Company, which was then approved by the Ministry of Social Security, according to the actuarial calculation at December 31, 2008 of $10,092,528. Since Ecopetrol continues to be financially responsible for the transferred pension liability, this amount continues being considered in the calculations for U.S. GAAP purposes.

vii. PROVISIONS, ALLOWANCES AND CONTINGENCES

For U.S. GAAP, Accounting for Contingencies (ASC 450), provides the guidance for recording contingencies. Under ASC 450, there are three levels of assessment of contingent events – probable, reasonably possible and remote. The term probable in ASC 450 is defined as “the future event or events that 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”. While the term remote is defined as “the chance of the future event or events occurring is slight”.

Under ASC 450, an estimated loss related to a contingent event shall 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.

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 with amount of loss that is reasonably possible.

As a result of the difference in the definition of “probable” between RCP 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 proceedings.

The effects of this adjustment in the reconciliation of income were $335,983; $67,629 and $12,779, in December 2011, 2010 and 2009, respectively. There was a difference in the amount the provision for loss contingencies as described above.

Guarantees Granted.

Under Colombian Government Entity GAAP, the guarantees at December 31, 2011 are recognized in memo accounts as follow:

a. The nature of the guarantees (Letters of credit):

		Completion	Amount in
Beneficiary	Start Date	Date	USD	Nature
Agencia Nacional de Hidrocarburos	28-Nov-10	28-Feb-14	2,352,480	Ensure compliance and execution of contract No. 33 of Caribbean Round Sector – Block RC-5
Agencia Nacional de Hidrocarburos	28-Nov-10	28-Feb-14	2,230,800	Ensure compliance and execution of contract No. 32 of Caribbean Round Sector – Block RC-4

b. In the current status, Equión has completed the required program for both exploration phases of the E&P contracts. Taking into account that Equión has executed the obligations contained in the letters of credit, the Company considers that the potential losses for guarantees against it are remote, and therefore there is no need to register such liability.

c. No additional risks have been identified by Equión, which would prevent the fulfillment of the obligations contained in the guarantees.

F-81

viii. ASSETS AND LIABILITIES FAIR VALUE

Under Colombian government Entity GAAP, accounts receivable and payable are recognized at amortized cost, represented by any uncollected or unpaid balances, regardless if such balances are due within the year or not. For U.S. GAAP purposes, the Company measures the long-term balances at present value by discounting future cash flows at the appropriate discount rate. Such balance is amortized using the effective interest method.

The estimated discount rate for long-term liabilities was calculated by our Treasury department and is based on the Colombian Government Treasury bonds as it was considered that the Company has a similar credit risk.

As a result of the measurement of the Equity Tax liability recognized by Ecopetrol and its subsidiaries in the year 2011, an adjustment for $126,861was recorded

ix. DEFERRED INCOME TAXES

Under both, RCP (Colombian Government Entity GAAP) and U.S. GAAP the deferred income taxes are recognized for all temporary differences between the financial and tax basis of assets and liabilities using the liability method. Under U.S. GAAP 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.

Under RCP, deferred income taxes are calculated using the current statutory tax rate. Under U.S. GAAP, deferred income taxes are calculated based on rates and tax laws enacted at the reporting date considering the future tax rate that will apply when the deferred income tax difference will be realized.

Under RCP, since 2009, goodwill is deductible and does not generate differences between tax laws and the RCP, except by the difference in the time of amortization. Under U.S. GAAP, the goodwill is not amortizable and generates a temporary difference since it is deductible for tax purposes. As a result it is necessary to compute and recognize deferred income taxes for temporary differences, as a result it is necessary to compute and recognize deferred income taxes for differences originated by deductions since the acquisition date.

Under RCP, the fair value of assets is not recorded; the difference between this value (zero) and the value recorded under U.S. GAAP generates deferred taxes calculated under ASC 740.

The Company and its subsidiaries file separate income tax returns since tax regulations do not allow consolidated income tax returns. There are no requirements to file tax returns by segments. Tax returns are required for each legal entity.

The following information regarding income taxes has been prepared under U.S. GAAP:

Income Taxes

Total income taxes for the years ended December 31, 2011, 2010 and 2009 were comprised as follows:

	2011		2010		2009
Income tax expense	$	8,399,086	$	4,397,797	$	2,893,963
Income tax effects based on items of Other Comprehensive Income:
Pension Plan Liability		488,064		206,699		482,535
Available-for-sale securities		7,086		8,819		226,833
Additional paid-in capital		-		-		177,241
	$	8,894,236	$	4,613,315	$	3,780,572

Income tax expense attributable to income from continuing operations consists of:

	2011		2010		2009
Current provision	$	7,501,002	$	3,201,040	$	1,948,819
Deferred tax		898,084		1,196,757		945,144
	$	8,399,086	$	4,397,797	$	2,893,963

In 2011, 2010 and 2009, there are foreign subsidiaries that do not pay income taxes and therefore do not generate income tax expense or deferred tax effects. Those entities that do pay taxes and are currently not generating taxable income will record a valuation allowance against any deferred tax asset recorded.

F-82

Amount of foreign and domestic pretax income:

	2011			2010
Domestic pretax income	$	23,770,905		$	13,680,753
Foreign pretax income		(314,220	)		(840,032	)
Income before income tax	$	23,456,685		$	12,840,721

All of the income tax effects are the results of pretax adjustments

Tax Rate Reconciliation

Income tax expense attributable to income from continuing operations was $8,399,086,$4,397,797 and $2,893,963 for the years ended December 31, 2011, 2010 and 2009, respectively, and differs from the amounts computed by applying the statutory income tax rate for Colombian entities that is 33% in 2011, 2010 and 2009 to pretax income from continuing operations as follows:

	2011			2010			2009
Statutory income tax		33.00	%		33.00	%		33.00	%
Non – taxable income		(1.82	)%		(2.37	)%		1.39	%
Non – deductible expenses		3.64	%		4.64	%		(1.91	)%
Others		1.08	%		(0.45	)%		0.26	%
Exempt revenue		(0.24	)%		(0.52	)%		(0.11	)%
Effect of foreign earnings taxed at other rate		(0.02	)%		(0.05	)%		0.02	%
Business combination		-			-			0.35	%
Effective income tax under U.S. GAAP		35.64	%		34.25	%		33.00	%

According with ASC 740 Ecopetrol has no unrecognized tax benefit. The open tax years to the Tax Authority’s reviews in major jurisdictions are as follows:

Country	Tax years
Colombia (*)	2010 and 2011
Peru	2008 to 2011
Brazil	2007 to 2011

(*) Except for ODC S.A., which open tax years are 2006 through 2011.

Deferred Taxes

The significant components of deferred income tax expense attributable to income from continuing operations for the years ended December 31, 2011, 2010 and 2009 are as follows:

	2011			2010			2009
Deferred income tax expense (exclusive of the effects of other components below):
Accounts payable	$	(129,334	)	$	(6,586	)	$	(21,075	)
Inventories		35,226			(6,949	)		52,705
Property, plant and equipment, principally due to DD&A		(36,884	)		(1,223,111	)		(666,473	)
Deferred charges		(580	)		92,747			(845	)
Prepaid expenses		62,930			(52,613	)		55,679
Capital lease asset		(39,109	)		11,597			43,120
Monetary correction and other		150,603			212,482			(103,012	)
DD&A and inflation adjustments		(305,288	)		890,348			295,638
Investment		164,276			(111,530	)		125,899
Direct finance lease		39,922			-			-
Estimated liabilities and provisions		(58,663	)		87,423			(178,468	)
Accounts and notes receivable		2,337			(3,734	)		13,375
Carry forward loss		(43,515	)		16,652			(42,681	)
Pension and benefits obligations		(390,205	)		(98,280	)		(360,488	)
Deferred income		140,422			7,811			8,052
Natural and environmental resources capitalized expenses		1,069,749			23,841			241,725
Valuation allowance		27,079			91,712			(11,475	)
Additional tax discount on the acquisition of productive assets according to ASC 740 (1)		6,939			1,276,705			1,107,934
Excess in presumptive income tax		14,225			(217,577	)		(106,437	)
Other		(18,565	)		5,654			369
Amortization of actuarial loss recorded in OCI		488,064			206,699			482,535
Unrealized loss in available for sale securities		7,086			8,819			226,835
Amortization of fiscal goodwill according to (ASC 830)		(288,631	)		(15,353	)		(217,768	)
	$	898,084		$	1,196,757		$	945,144

(1) This value corresponds to the deferred tax generated by the calculation of ASC 740, due to the implementation of the special deduction for investment in real productive assets.

F-83

The tax effects of temporary differences that give rise to significant portions of the deferred tax assets and deferred tax liabilities at December 31, 2011 and 2010 are presented below:

	2011			2010
Deferred income tax assets and liabilities
Deferred income tax assets:
Inventories	$	33,919		$	69,145
Investments		937,774			1,048,981
Accounts and notes receivable		702			3,039
Deferred income		-			140,422
Property, plant and equipment, principally due to DD&A		3,069,279			3,032,395
Deferred charges		17,164			16,583
Prepaid expenses		95			63,024
Financial obligation, principally due to capitalized leasing		146,626			107,517
Pension obligations		1,047,213			657,008
Accounts payable		270,587			141,253
Carry forward loss (1)		173,795			130,280
Excess in presumptive income tax (2)		318,094			332,320
Other		561			1,585
Amortization of tax goodwill		574,472			472,536
Estimated liabilities and provisions		844,815			786,153
Total gross deferred income tax assets		7,435,096			7,002,241
Variation valuation allowance (4)		(222,218	)		(195,139	)
Deferred income tax assets		7,212,878			6,807,102
Deferred income tax liabilities
Natural and environmental properties due to the difference between the methods of amortization		1,534,084			464,335
Monetary correction and other		781,082			630,481
DD&A and inflation adjustments		880,699			1,185,986
Investments		1,734,394			1,681,325
Direct finance lease		39,923			-
Deferred income tax liabilities		4,970,182			3,962,127
Net deferred income tax assets (3)	$	2,242,696		$	2,844,975

(1) Carry forward losses are generated by subsidiaries and according to local tax laws, these losses do not expire.

(2) The excess in presumptive income tax are generated by subsidiaries and will expire in 5 years.

(3) The Company has specific plans to reorganize the business structure in such a way that profits that had already paid taxes in a jurisdiction will not be required to be taxed again when transferred to another entity within the same group. For this reason, the deferred income taxes just include the deferred income taxes recognized by the subsidiaries. Additionally, it is not practical to compute such liability. The amount estimated of such temporary difference is $5,862,173 at December 31, 2011.

(4) The changes in the valuation allowance is mainly due to 2011 tax losses originated by Ecopetrol Oleo é Gas do Brazil and Ecopetrol del Peru amounting $44,694 approximately, offsetted by utilizations in Hocol and ODC, amounting $17,615 approximately, as detailed below.

	2010		Variation			2011
Ecopetrol do Brazil	$	121,008	$	37,266		$	158,274
Ecopetrol del Peru		40,436		7,426		$	47,862
ODC		20,252		(4,700	)	$	15,552
Hocol		12,915		(12,915	)	$	-
Bioenergy		463	$	-		$	463
Refineria de Cartagena		65		2			67
	$	195,139	$	27,079		$	222,218

F-84

x. REVENUE RECOGNITION

a.1 Over and Under

Under RCP, the Company recognizes receivables from or payables to partners based on the cost of the inventory.

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, and revenue is recognized based on market prices. The Company’s crude oil over balance position at December 31, 2011 was $659,535 and at December 31, 2010 was $28,836 equivalent to 4,184,690 and 193,411 barrels, respectively.

a.2 Cost of Sales

Under U.S. GAAP, the related cost of sale for over and under transactions described at a.1 above amounted to $(449,225), $158,609 and $(110,087) during 2011, 2010 and 2009, respectively, in comparison with the amount recognized under RCP.

a.3 Natural Gas Imbalance

For U.S. 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 interest in the properties.  The Company’s natural gas imbalance net positions were $13,187 in favor, equivalent to 1,733,334 MBTU at December 31, 2011 and 2010. Under RCP, natural gas imbalances are settled with a purchase or sale to the partner that are accounted for at the end of each period.

a.4 Net vs. Gross sales

The Company has sales transactions where it transports crude oil, from the supplier to the customer, using its pipelines. For U.S. GAAP purposes, when price is fixed, there are no changes made to the product and the Company has no physical inventory loss risk, among other criteria, the Company records such sales on a net basis. Under RCP, such crude oil sales are recognized gross.

xi. INFLATION ADJUSTMENTS

The RCP 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 for Ecopetrol S.A. and from January 1, 1992 to December 31, 2006 for Oleoducto de Colombia S.A. (ODC), Hocol S.A., Oleoducto Central S.A. (Ocensa), Equion, and Reficar S.A. The adjustment was applied monthly to non-monetary assets, equity (except for the valuation surplus) and memorandum accounts.

Under U.S. GAAP, the aforementioned inflation adjustments under RCP are not applicable and have been reversed.

F-85

xii. INVENTORIES

Under RCP, 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. Inventories are also affected by the effect of adjustments to cost of sales included in this reconciliation. These adjustments are related to depreciation, expenses capitalized in property, plant and equipment, asset retirement cost and impairment of long-lived assets.

The effects of this adjustment (loss) gain in the reconciliation of income were $76,126, $(87,797), and $16,853 in December 2011, 2010 and 2009, respectively.

The effects of these adjustments in the reconciliation of equity and the corresponding effect in inventory were $(38,473) and $(114,868) at December 31, 2011 and 2010, respectively.

xiii. LEASE ACCOUNTING

Under both RCP and U.S. GAAP, lease accounting for capital leases and operating leases is identical.  However, the tests used to determine if a lease is a capital or an operating lease differs between RCP and U.S. GAAP. In applying the tests in accordance with RCP, 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 ASC 840-10. 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.

Embedded Leasing

Under RCP, there is no requirement to identify whether the arrangements or contracts contain leases.

Under U.S. 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 existence 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 the 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, ASC 840 is applied by both purchaser and supplier for recognition, measurement, classification and disclosure purposes.

F-86

Build, Operate, Maintain and Transfer (BOMT)

	BOMT
Future Payments	Ecogas (1)				Dina – Tello (2)				Gibraltar (3)
	USD				USD				USD
Year	(million)		Pesos		(million)		Pesos		(million)		Pesos
2012	$	18.3	$	35,625	$	2.9	$	5,632	$	2.2	$	4,266
2013		17.3		33,595		3.3		6,427		1.1		2,101
2014		17.0		33,000		3.8		7,307		1.2		2,276
2015		17.0		33,001		4.3		8,277		1.3		2,467
2016		16.2		31,526		4.8		9,349		1.4		2,674
Payments after 2016		10.4		20,157		5.4		10,531		15.0		29,257
	$	96.2	$	186,904	$	24.5	$	47,523	$	22.2	$	43,041

(1) 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. In 2007, Ecopetrol received a prepayment of all amounts to be received during the term of the sublease contract.

(2) In 2010, we entered in a new BOMT, corresponding to the gas treatment plant located in the Dina-tello field with an estimated value of construction of US$28 million. This BOMT is accounted as a capital lease in accordance with ASC 840 same as the contracts described previously, this contract had an original term of 8 years, ending in 2017.

(3) Ecopetrol subscribed a contract with Unión Temporal Gas Gibraltar firm to develop the design, build, operation and maintenance of a treatment plant with a capacity of 30 mpcd. Likewise, for the marketing of this product a contract with Natural Gas E.S.P was signed, company that it contracted with the company TransOriente E.S.P the construction of the pipeline that will transport the treated gas from the Gibraltar field to Bucaramanga, where it will be connected with the national system of gas transport. The plant of gas processing of Gibraltar is located between the populations of Toledo (Norte de Santander) and Cubará (Boyacá). This BOMT is accounted for as a capital lease in accordance with ASC 840. Such as the previously described contracts, this contract had an original term of 15 years, ending in 2026.

xiv. PROPERTY, PLANT AND EQUIPMENT

Under RCP, property, plant and equipment are recorded at cost and are adjusted for inflation until 2001. The 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 ASC 740-10, Accounting for Acquired Temporary Differences in Certain Purchase Transactions that are not Accounted for as Business Combinations, since the investment in productive assets creates an additional tax deduction of 30% in 2010 and 40% in 2009. Starting in January 2011, income tax deductions from investments in productive fixed assets will no longer be available.

The following table reflects the net changes in capitalized exploratory wells during 2011, 2010 and 2009 it does not include amounts that were capitalized and posted as expenses during the same period under successful efforts method.

	2011			2010			2009
Beginning balance at January 1	$	418,740		$	363,922		$	218,413
Additions from business combination		2,278			-			143,541
Additions to capitalized exploratory well costs		918,955			1,029,203			349,162
Reclassifications to wells, facilities and equipment based on the determination of proved reserves		(32,157	)		(132,672	)		(149,130	)
Capitalized exploratory well costs charged to expense*		(378,959	)		(841,713	)		(198,064	)
Ending balance at December 31	$	928,857		$	418,740		$	363,922

* Includes $54,409, $7,514 and $32,351 of capitalized exploratory well costs at December 31, 2011, 2010 and 2009, respectively, which were declared as dry wells during 2012, 2011 and 2010 respectively.

F-87

Accounting For Suspended Exploratory Wells

The following table provides an aging of capitalized exploratory well costs based on the date the drilling was completed and the number of projects for which exploratory well costs have been capitalized for a period greater than one year since the completion of the drilling:

Aging of Exploratory Well Cost	Year ended December 31,
	2011		2010
Capitalized exploratory well costs that have been capitalized for a period of one year or less	$	337,617	$	140,078
Capitalized exploratory well costs that have been capitalized for a period greater than one year		184,217		152,238
Ending balance	$	521,834	$	292,316
Number of projects that have exploratory well costs that have been capitalized for a period greater than one year		22		20

Next Table shows the detail by aging, wells and entity, thus status and activities pending of execute for determining proved reserves during 2011.

Entity	Well	Balance Dec/10		Balance Dec/11		Comment
BRAZIL	Ituana-1	$	128,696	$	207,384	Pending field exploratory well
ECP	Rumbero-1		10,109		50,337	Exploratory well drilled.
ECP	Nunda		367		12,059	Appraisal drilling
ECP	Ambar-3		189		116	Appraisal drilling
ECP	Jaspe-2		-		226	Appraisal drilling
ECP	Opalo-2		-		1,779	Appraisal drilling
ECP	Opalo-1		-		1,128	Appraisal drilling
ECP	Opalo-6 ST		-		616	Appraisal drilling
ECP	Ambar-4		47		529	Appraisal drilling
ECP	Opalo-3		-		2,859	Appraisal drilling
ECP	Azabache-1		-		946	Appraisal drilling
ECP	Ambar-5		-		1,413	Appraisal drilling
ECP	Rubi-1		-		79	Appraisal drilling
ECP	Ambar-7		-		722	Appraisal drilling
ECP	Jaspe-4 (Q-S2)		-		70	Appraisal drilling
HOCOL	Corocora Surbz-1		671		4,446	Exploratory well, pending environmental license extension to install a production line and to request commerciality.
HOCOL	Merlin-2		-		9,029	Appraisal well
HOCOL	Merlin-1		-		3,548	Appraisal well
HOCOL	Guarrojo Oriental		-		601	Producing well in assessment
HOCOL	Granate-1		6,220		-	Written off in 2011
HOCOL	Bonga-1		-		39,730	Appraisal well
Total		$	146,299	$	337,617

F-88

Next Table shows the detail by aging, wells and entity, thus status and activities pending of execute for determining proved reserves during 2010.

Entity	Well	Balance Dec/10		Balance Dec/11		Comment
ECP	Akacias-1	$	8,934	$	20,955	Appraisal drilling
ECP	Oripaya		54,222		53,876	Gas well. Pending drilling a boundary well.
ECP	Tinkhana-1		8,956		27,795	Appraisal drilling
ECP	Quifa 13		210		228	Appraisal drilling
ECP	Quifa 18		269		269	Appraisal drilling
ECP	Quifa 6		2,569		2,560	Appraisal drilling
ECP	Quifa 31		1,807		1,810	Appraisal drilling
ECP	Quifa Q2 24X				15	Appraisal drilling
ECP	Quifa 32		695		697	Appraisal drilling
ECP	Ambar-1		1,051		2,104	Appraisal drilling
ECP	Quifa B2		38		38	Appraisal drilling
ECP	Quifa F4 26X				2	Appraisal drilling
ECP	Quifa K 20X				8	Appraisal drilling
Total		$	78,751	$	110,357

Next Table shows the detail by aging, wells and entity, thus status and activities pending of execute for determining proved reserves during 2009.

Entity	Well	Balance Dec/10		Balance Dec/11		Comment
ECP	Pachaquiaro	$	20,131	$	20,131	Pachaquiaro North  -  Commercial production declaratory in process
ECP	Rio Zulia West-3		17,255		17,255	ANH approval pending over cession of interests
ECP	Quifa 12		151		72	Appraisal drilling
ECP	Quifa 17		244		222	Appraisal drilling
ECP	Quifa 11		333		332	Appraisal drilling
ECP	Quifa 10		481		534	Appraisal drilling
ECP	Quifa 8		382		298	Appraisal drilling
ECP	Quifa 7		833		817	Appraisal drilling
ECP	Quifa 9		580		600	Appraisal drilling
HOCOL	Huron 1		33,100		33,597	Well assessment, First appraissal well in process
Total		$	73,490	$	73,858

a. Interest

Under RCP, all interest paid net of interest income is subject to capitalization regardless of the utilization of the funds. The exchange rate differential is also capitalized as part of the asset.

The Company´s assessment of the methodology followed to determine the capitalization amount under U.S. GAAP considered more detailed information available to estimate the interest to be capitalized. Previous to 2010, the calculations were made based on the average monthly disbursements, as an improvement, the Company obtained a detail of the assets associated to the debt and was able to apply the analysis and calculations based on each project, providing further detail of interest capitalized. The impact was recognized during 2010 as it was considered a change in an accounting estimate per ASC 250-10-45-17 and 18, Change in Accounting Estimates.

The total interest capitalized during 2011 under RCP was $207,514 while $85,337, under U.S. GAAP. The effect of this adjustment in the reconciliation of income was $122,177. The total interest capitalized during 2010 under RCP was $319,326 and the total interest capitalized under U.S. GAAP was $150,800. The effect of this adjustment in the reconciliation of income was $168,527. The total interest capitalized during 2009 under RCP was $127,026 and the total interest capitalized under U.S. GAAP was $63,247. The effect of this adjustment in the reconciliation of income was $63,779.

F-89

b. Revaluation of property, plant and equipment and public accounting effect

Valuation surplus of property, plant and equipment and public accounting effect correspond to the difference between net book value and the market value for real estate or the current value in use for property, plant and equipment, determined by specialists. These accounts are reflected as Valuations and as Valuation Surplus from reappraisals of assets and the public accounting effect (components of equity) in the Company’s consolidated balances sheets. The last valuation was in December 2009. Technical appraisals are valid for three years.

Under U.S. GAAP, the valuation surplus of assets and the public accounting effect are not permitted.

c. Impairment

Under RCP, 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 ASC 360-10, Property, Plant, and Equipment - Impairment or Disposal of Long-Lived Assets (ASC 360-10), 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, 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, 2011, 2010, 2009, and recorded impairment losses when required. For U.S. GAAP purposes, the Company recorded in 2011, 2010 and 2009, $136,357, $135,469, and $395,044, respectively, as additional impairment charges to reduce the net book value of certain wells and pipelines to their estimated values.

xv. DEPRECIATION, DEPLETION AND AMORTIZATION

Under RCP, all tangible equipment, including those used in crude oil and natural gas, are 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 resources are depleted on a units-of-production basis.

In the case of HOCOL, all tangible and intangible assets used in the production of crude and natural gas production are depreciated or depleted using the units of production method, using developed proved reserves, except for the pipeline asset which is depreciated on a straight-line basis over the related estimated useful life (20 years). For REFICAR, in the case of the unit “Viscorreductora”, this is depreciated based on a 4 year life on a straight line basis, ending in December 2012. For BIOENERGY, in relation to agricultural sugarcane crops, the company develops the plantations that it will use as base for the production of Bioethanol. The cost of the agricultural plantations will be amortized during productive cycle time frame, in agreement with recognized technical value methods.

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. In addition, the financial statements reflect the amortization of those assets affected by the application of ASC 740-10, Accounting for Acquired Temporary Differences in Certain Purchase Transactions That Are Not Accounted for as Business Combinations. Therefore, an adjustment to net income per U.S. GAAP has been recorded to account for the difference in depreciation, depletion and amortization expense.

F-90

xvi. ASSET RETIREMENT OBLIGATIONS

Under RCP, 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. Until 2009 the elements of the liability originated 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 Accounting Standards Codification (ASC) 410-20 Asset Retirement Obligations.  ASC 410-20 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 asset retirement cost (asset).  Each period the liability is accreted using the effective interest rate method. The accretion is included as an operating expense. The cost associated with the abandonment obligation, 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 ASC 410-20.

It is not possible at this time to reasonably estimate the amount of any obligation for Asset Retirement Obligation related to refineries since the Company undergoes major renovations. In addition, The Company believes there is not sufficient information available to estimate the fair value of the asset retirement obligation because the settlement date or the range of potential settlement dates have not been specified by others and information is not available to apply an expected present value technique.

The following table presents the changes in abandonment obligations for 2011 and 2010 as is required by ASC 410-20.

	2011			2010
Balance at beginning of period	$	1,817,791		$	1,904,096
Liabilities incurred in the current period		49,748			30,748
Abandonment Cost from Business combination		81,046			-
Revisions in estimated cash flows		93,687			(237,906	)
Liabilities settled in the current period		(50,168	)		(30,663	)
Accretion expense		133,796			151,516
Balance at end of period	$	2,125,900		$	1,817,791

F-91

xvii. EQUITY CONTRIBUTIONS

a. 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 RCP, 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 2011 was a reduction in equity of $50,479 (original value of $148,999 net of $98,520 of accumulated depreciation of the assets received), holds materials of $1,214.

The adjustment to conform to U.S. GAAP in 2010 was a reduction in equity of $62,592 (original value of $137,010 net of $74,418 in accumulated depreciation of the assets received) and holds materials of $1,819.

b. Reversal of Concession Rights Contributed as Capital

Under RCP, the Company recorded as reservoirs the contributions of the Nation represented by crude oil and natural gas reserves deriving from the reversal of concessions of oilfield areas in favor of the Nation, provided 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 reversals 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, 2011 and 2010 was $19,737 and $22,202 respectively. Since 2003 (year of creation of the Agencia Nacional de Hidrocarburos - ANH) there has not been any concession reversals.

xviii. INDEBTEDNESS COST

Under RCP, the borrowing costs correspond to interest paid, lender commissions and other costs related to the debt transactions, the exchange difference for the interest rate to be paid, the amortization of premiums and discounts in the placement of bonds and securities, and any income results earned on the temporary investment of such loans.

Under U.S. GAAP, the borrowing costs correspond to interest payable, lender commissions and other costs related to the debt transactions, the amortization of premiums and discounts in the placement of bonds and securities, should not offset interest expense with interest income, unless the financing transaction involves restricted, tax-exempt borrowings. Unlike RCP, the borrowing cost do not include the exchange rate difference for the interest rate to be paid, unless such difference forms part of the negotiation of the interest rate for the transaction.

The total indebtedness cost incurred during 2011 under RCP was $608,261 and the total indebtedness cost incurred under U.S. GAAP was $608,912. The effects of this adjustment in the reconciliation of income was the difference of $652. The total indebtedness cost incurred during 2010 under RCP was $519,697 and the total indebtedness cost incurred under U.S. GAAP was the difference of $521,367. The effects of this adjustment in the reconciliation of income was $1,670. The total indebtedness cost incurred during 2009 under RCP was $ 210,362 and the total indebtedness cost incurred under U.S. GAAP was the difference of $201,562.The effect of this adjustment in the reconciliation of income was $8,800.

xix. BUSINESS COMBINATIONS

a. Goodwill

Under Colombian Government Entity GAAP, goodwill corresponds to the difference between the acquisition price and the book value of the acquired company recognized as an intangible asset. Separate intangibles are not identified under RCP nor are assets stepped up to fair values as a result of acquisitions; if the book value is higher than the acquisition price, the resulting difference is recorded as a gain. The amount recognized as goodwill is amortized during the period in which the Company expects to receive future benefits; in addition, it is subject to an annual impairment test

Under U.S. GAAP, goodwill is not amortized, but it is subject to an annual impairment test with the option of an initial qualitative test. In addition, the tax effect on temporary difference between tax basis and fair values is allocated to goodwill.

F-92

The following table shows, by company, the goodwill balance at the end of 2011, 2010 and 2009, net of the amount of deferred income tax on goodwill and the translation adjustment:

			Goodwill		Exchange			Balance		Deferred			Accumulated
	Balance		acquired   during		Rate			before   tax		income			Impairment		Balance
Company	2009		2010		Effect			2010		tax			2010		2010
Propilco - Andean Chemicals	$	652,049	$	-	$	-		$	652,049	$	(1,472	)	$	-	$	650,577
Refineria de Cartagena S.A.		770,132		-		(49,070	)		721,062		-			-		721,062
Bioenergy		8,993		-		-			8,993		-			-		8,993
Total	$	1,431,174	$	-	$	(49,070	)	$	1,382,104	$	(1,472	)	$	-	$	1,380,632

			Goodwill
			acquired		Exchange		Balance		Deferred			Accumulated
	Balance		during		Rate		Before tax		Income			Impairment			Balance
Company	2010		2011		Effect		2011		tax			2011			2011
Propilco	$	650,577	$	-	$	45,282	$	695,859	$	(1,472	)	$	(46,691	)	$	647,696
Refineria de Cartagena S.A.		721,062		-		10,817		731,879		-			-			731,879
Bioenergy		8,993		-		-		8,993		-			-			8,993
Equion		-		226,592		-		226,592		(226,592	)		-			-
Total	$	1,380,632	$	226,592	$	56,099	$	1,663,323	$	(228,064	)	$	(46,691	)	$	1,388,568

Under RCP, the following table shows the amounts deductible for income tax purposes for 2011 and 2010.

	2011
			Accumulated							Remaining
Company	Goodwill		Amortization			Balance		Net Effect		time-years
Andean Chemicals Ltd	$	357,629	$	(74,152	)	$	283,477	$	93,547		15.8
Offshore International Group – “OIG”		749,699		(130,766	)		618,933		204,248		12.0
Hocol		801,911		(109,686	)		692,225		228,434		14.0
Equion		957,513		(84,912	)		872,601		287,958		9.3
Total	$	2,866,752	$	(399,516	)	$	2,467,236	$	814,187

	2010
			Accumulated							Remaining
Company	Goodwill		Amortization			Balance		Net Effect		time-years
Andean Chemicals Ltd	$	357,629	$	(53,903	)	$	303,726	$	100,230		16.8
Offshore International Group – “OIG”		788,043		(76,376	)		711,667		234,850		13.0
Hocol		805,046		(62,039	)		743,007		245,192		15.0
Total	$	1,950,718	$	(192,318	)	$	1,758,400	$	580,272

Under RCP in 2011 and 2010, $262,984 and $172,660 were amortized in regard to goodwill acquired from OIG, Ecopetrol Transportation Company, Hocol, Andean Chemicals, Propilco and Equion. The amortization in the table above represents the accumulated amortization of the companies that could be deductible for income tax purposes. Under U.S. GAAP, goodwill acquired from OIG, which is recognized by the equity method, is included as part of the investment.

Under U.S. GAAP, Ecopetrol tests goodwill for impairment at least annually using a two step process that begins with an estimation of the fair value of a reporting unit.  The first step is a screen for potential impairment and the second step measures the amount of impairment. Ecopetrol did not perform a qualitative analysis although allowed.

Fair value is determined by reference to market value, if available, or by a qualified evaluator or pricing model. Determination of a fair value by a qualified evaluator or pricing model requires management to make assumptions and use estimates.  Management believes that the assumptions and estimates used are reasonable and supportable in the existing market environment and commensurate with the risk profile of the assets valued.  However, different assumptions and estimates could be used which would lead to different results.  The valuation models used to determine the fair value of these companies are sensitive to changes in the underlying assumptions.  For example, the prices and volumes of product sales to be achieved and the prices which will be paid for the purchase of raw materials are assumptions which may vary in the future.  Adverse changes in any of these assumptions could lead the Company to record a goodwill impairment charge.

F-93

During 2011, Ecopetrol performed an impairment test of goodwill which showed that goodwill had been impaired in Propilco by $46,691, due to the increase in book value during current year as a result of a change in functional currency from Colombian pesos to US dollars. In addition during 2011 Propilco change their raw material suppliers due to Ecopetrol stopped providing it. New suppliers are more expensive than Ecopetrol so in the foreseeable a cost increase on Ecopetrol investment in Propilco is expected.

b. Business Combination

In August 2010, we entered in into a memorandum of understanding with Talisman Colombia Holdco Limited, or Talisman, a Canadian oil and gas company, to acquire BP Exploration Company (Colombia) Limited, a British Petroleum subsidiary operating in Colombia; the acquired company was renamed as Equion Energia Limited. After obtaining required authorizations, we completed the acquisition, in January 24, 2011, which includes assets in oil and gas exploration and production as well as oil transportation and gas marketing. As a result of this acquisition, we increased our participation in the ownership of the Ocensa from 60.00% to 72.65%, in ODC from 66% to 73% and in Oleoducto del Alto Magdalena, or OAM assets, from 83.00% to 85.12%.  We also acquired a 10.20% interest in Transgas de Occidente.

The total acquisition price, paid in cash, was US$1,596,157 thousands, Ecopetrol totals 51% ownership, the remaining 49% represents Talisman Energy Inc. share. The following table details the purchase price calculation (USD in thousands) as well as the Colombian peso equivalent (in millions) of the transaction using the effective exchange rate on the dates of the payments.

	Amount USD			Amount COP
Purchase Price	$	1,750,000
Less: Purchase Price Adjustment		(153,842	)
Adjusted Purchase Price		1,596,157
Participation (%)		51	%
Total Purchase Price	$	814,040		$	1,483,891

The acquisition was accounted for as a business combination (ASC 805) which, among other things, requires assets acquired and liabilities assumed to be measured at their acquisition date fair values. Fair value measurements and Purchase Price Allocation process was finalized in fourth quarter 2011.

Pro-forma financial information is not presented as it would not be materially different from the information presented in the Consolidated Statement of Income.

The following table summarizes the measurement at fair value of the assets acquired and liabilities assumed:

	Amount USD
Current assets	$	293,465
Investments and long-term receivables		508,242
Property, plant and equipment and reserves		1,367,948
Deferred tax asset		15,073
Other assets		24,913
Total assets acquired		2,209,641
Current liabilities		331,145
Long term debt		3,601
Deferred tax liability		283,332
Other liabilities		131,835
Total liabilities acquired		749,913
Net assets acquired	$	1,459,728
Non controlling interest in goodwill		66,850
Goodwill		69,579
Total Consideration paid in cash	$	1,596,157

Property, Plant and Equipment and Reserves were measured primarily using an income approach. The fair values of the acquired oil and gas properties were based on significant inputs not observable in the market and thus represent Level 3 measurements. Significant inputs included estimated resource volumes, assumed future production profiles, and assumptions on the timing and amount of future operating and development costs.

The Net Assets Acquired for US$1,459,728, represent $2,682,999 pesos and goodwill of $226,592 pesos. The goodwill represents the amount of the consideration transferred in excess of the values assigned to the individual assets acquired and liabilities assumed. Goodwill represents the future economic benefits arising from other assets acquired that could not be individually identified and separately recognized. The fair value of the 49% share of Talisman Energy Inc. is US$782,117.

F-94

In Colombia, the goodwill is deductible for tax purposes, thus, a deferred tax asset of $315,979 was recognized for the difference between the tax goodwill and the goodwill, resulting in a Bargain Purchase Gain of $89,387 recorded in earnings for the year 2011.

In addition, Ecopetrol increased its ownership interest in Ocensa and ODC while retaining control, as a result, the difference between the fair value and the carrying amount of the non-controlling interest was recognized in a decrease in additional paid-in-capital for the amount of $792,440.

xx. NON-CONTROLLING INTEREST

For purposes of calculating the carrying amount of total equity (net assets) attributable to the non-controlling interest as of December 31^st of 2011, 2010 and 2009 Ecopetrol used the net equity from all subsidiaries at the beginning of each period and considered all activity (net income, retained earnings, non-controlling interest, distribution of dividends, purchase price allocation, translation adjustments, and others) to adjust the non-controlling interest.

In August 2010 Ecopetrol incorporated an additional 54.80% participation in Oleoducto Bicentenario de Colombia S.A.S (i.e., hereinafter “OBC”), for a total participation of 55.97%.

The following table sets the information for Ecopetrol’s non-controlling interest from 2009 to 2011.

	OCENSA			ODC			ODL			BIOENERGY			OBC			EQUION		TOTAL
Balance 2008	$	578,251		$	-		$	234,263		$	6,258		$	-		$	-	$	818,772
Acquired Non Controlling Interest(*)		(300,377	)		21,495			-			(2,810	)		-			-		(281,692	)
Other Non Controlling Interest		-			-			(78,405	)		-			-			-		(78,405	)
Net income (loss), restated		198,968			(26,691	)		(15,325	)		(836	)		-			-		156,116
Distribution of dividends		(89,736	)		-			-			-			-			-		(89,736	)
Retained Earnings		95,790			(2,142	)		991			6,541			-			-		101,180
Purchase Price Allocation		-			21,530			-			-			-			-		21,530
Translation Adjustments		-			-			(13,047	)		-			-			-		(13,047	)
Balance 2009		482,896			14,192			128,477			9,153			-			-		634,718
Other Non Controlling Interest		-			3,902			-			1,346			-			-		5,248
Net income (loss)		223,403			(7,173	)		21,676			(975	)		(5,042	)		-		231,889
Distribution of dividends		(99,888	)		-			-			-			-			-		(99,888	)
Return of capital through and due to Spin-Off		(144,251	)		-			-			-			-			-		(144,251	)
Dividends for Spin-Off		(318,670	)		-			-			-			-			-		(318,670	)
Translation Adjustments		-			-			305			-			-			-		305
Balance 2010		143,490			10,921			150,458			9,524			(5,042	)		-		309,351
Acquired Non Controlling Interest(**)		(88,970	)		(3,536	)		-			-			-			1,425,702		1,333,196
Issuance of company shares		-			-			53,284			-			321,044			-		374,328
Net income (loss)		37,787			(4,739	)		22,493			(2,294	)		(9,114	)		196,259		240,392
Other comprehensive income		-			-			-			-			-			116		116
Translation Adjustments		-			-			1,404			-			-			29,332		30,736
Balance 2011	$	92,307		$	2,646		$	227,639		$	7,230		$	306,888		$	1,651,409	$	2,288,119

* Corresponds to the acquisition of an additional 24.71% ownership interest in Ocensa for $998,903 in cash. The difference of $610,007 was registered as an additional paid in capital net of income tax in an amount of $171,241 as a result of the difference between local deductible goodwill.

** Ecopetrol acquired 51.00% of Equion Energia Limited on January 24, 2011. As a result of this business combination, Ecopetrol increased its participation in Ocensa by a 12.65% and its participation in ODC by a 7.43%. The amount of $1,425,702 in Equion includes $205 related to its unrealized gains on bonds.

xxi. CUMULATIVE TRANSLATION ADJUSTMENT

Under RCP, the companies domiciled outside of the country, regardless of its functional currency, must report in USD and then translated to Colombian pesos with the impact recorded as cumulative translation adjustment.

For U.S. GAAP, the Company must remeasure all subsidiary financial information to its functional currency and then translate it to the reporting currency. This difference in methodology results in a difference in the translated amounts recorded in the financial statements.

As such an adjustment is made to appropriately reflect amounts under translated U.S.GAAP.

F-95

xxii. PUBLIC OFFERING COST

In August 2011, the Company issued shares in a second public offering in Colombia. Under RCP, 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 $103,949 was recorded to recognize the effect of these amounts.

xxiii. EARNINGS PER SHARE

Under RCP, 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.  However, although the Company has presented EPS under RCP for informational purposes, the presentation of EPS is not required for financial statements issued under RCP. 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, 2011, 2010 and 2009, the Company had a simple capital structure.  There are no stock compensation plans or any other compensation plan involving shares. Therefore, the Company is not required to present diluted EPS for these years.

xxiv. CONCENTRATIONS

In 2011 there are no customers in excess of 10% of total sales. In 2010 one customer of the refining segment accounted for 11.4% of total sales. One customer of the production segment and market and supply segment accounted for 10.5% from total sales. No other customers accounted for more than 10% of total sales in 2010. In 2009, one customer of the refining segment accounted for 13.1% of total sales. No other customers accounted for more than 10% of total sales in 2009. There is no exposure that affects the financial position of Ecopetrol if the Company lost the client.

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.

xxv. CHANGES IN ACCOUNTING PRINCIPLES

During 2011, the functional currency of the subsidiary Propilco changed from the Colombian peso to U.S. dollar. The change was due to the fact that the analysis showed an increase in the activities performed by the Company in U.S. dollars: higher export sales in U.S. dollars than in local sales in Colombian pesos; increase in the supply components of raw materials imported and paid in U.S. dollars consistent with the business strategy defined by Ecopetrol; the financial debt is mainly in U.S. dollars, among others. As a result, the U.S. dollar reflects the primary economic environment where Propilco has its operations. This change does not affect the functional currency of Ecopetrol and, in accordance with ASC 250, it is considered a change in an accounting principle. The effect of the accounting principle change is $54,563; in addition, as the recognition of a deferred tax liability or asset for tax consequences of differences related to assets and liabilities that, under ASC 830, are remeasured from the local currency into the functional currency using historical exchange rates and that result from changes in exchange rates, the deferred tax related to inflation adjustments was derecognized with an effect of $15,228. The total impact in the Cumulative Translation Adjustment as a result of the change in the functional currency of Propilco was $69,791.

Recent U.S. Adopted Accounting Standards

In December 2010, the FASB issued ASU No. 2010-29 Business Combination (Topic 805) - Disclosure of Supplementary pro-forma information for Business Combination, to address diversity in practice about the interpretation of the pro-forma revenue and earnings disclosure requirements for business combinations. This accounting standard update was applied in Ecopetrol as of January 1, 2011. The adoption of this guidance did not have a significant impact on our consolidated financial statements and related disclosures.

In September 2011, the FASB issued ASU No. 2011-08 Intangibles - Good will and other (Topic 350) Testing Goodwill for impairment, The objective of this update is to simplify how entities, both public and nonpublic, test goodwill for impairment. The amendments in the Update permit an entity to first assess qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount as a basis for determining whether it is necessary to perform the two-step goodwill impairment test described in Topic 350. The amendment is effective for annual and interim goodwill impairment tests performed for fiscal years beginning after December 15, 2011, anticipated adoption is permitted. This optional adoption of this guidance did not have an impact on the financial statements since it was not applied by the Company as of December 31, 2011.

Recently issued Accounting Standards and U.S. GAAP Pronouncements

F-96

In May 2011, the FASB issued ASU No. 2011-04 Fair Value Measurement (Topic 820) - Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRS, the amendments in this Update are the result of the work by the FASB and the IASB to develop common requirements for measuring fair value and for disclosing information about fair value measurements in accordance with U.S. generally accepted accounting principles (GAAP) and International Financial Reporting Standards (IFRSs). This amendment is effective prospectively, for public entities, the amendments are effective during interim and annual periods beginning after December 15, 2011. Ecopetrol will be adopting this standard on January 2012. Ecopetrol is evaluating the impact of the adoption of this guidance on the disclosures and measurements of the Company.

In June 2011, the FASB issued ASU No. 2011-05 Comprehensive Income (Topic 220) - Presentation of Comprehensive Income, the amendments require that all non-owner changes in stockholders’ equity be presented either in a single continuous statement of comprehensive income or in two separate but consecutive statements in order to improve the comparability, consistency, and transparency of financial reporting and to increase the prominence of items reported in other comprehensive income. The amendments in this Update should be applied retrospectively. For public entities, the amendments are effective for fiscal years, and interim periods within those years, beginning after December 15, 2011. In December 2011, the FASB issued ASU No. 2011-12 Comprehensive Income (Topic 220) Deferral of the Effective Date for Amendments to the Presentation of Reclassifications of Items Out of Accumulated Other Comprehensive Income In Accounting Standards Update No. 2011-05, Ecopetrol will be adopting this standards in January 2012. Currently, Ecopetrol is evaluating the impact of the implementation of this requirement.

In December 2011, the FASB issued ASU No. 2011-11 Balance Sheet (Topic 210) - Disclosures about Offsetting Assets and Liabilities, the amendments in this Update require an entity to disclose information about offsetting and related arrangements to enable users of its financial statements to understand the effect of those arrangements on its financial position. An entity is required to apply the amendments for annual reporting periods beginning on or after January 1, 2013, and interim periods within those annual periods. Ecopetrol will be adopting this standard at December 2013. Ecopetrol does not expect a significant impact on the disclosures of the company.

xxvi. SEGMENT INFORMATION

The following segment information has been prepared according to ASC 280, Disclosure about Segments of an Enterprise and Related Information.  Financial information by business segment is reported in accordance with the internal reporting system under RCP and shows internal segment information that is used by the chief operating decision maker to manage and measure the performance of Ecopetrol.

The financial information among segments is reported considering each business as a separate entity. Prices between segments are established by referencing those that would apply in an arm’s length transaction. Each segment should bear the costs and expenses required to put the product in terms of use or marketing. Each segment assumes its administrative expenses and all non-operational transactions related to their activity.

The Company operates under the following segments, which are described as follows:

Exploration and Production — this segment includes the Company’s oil & gas exploration and production activities. Revenue is derived from the sale of crude oil and natural gas to inter-company segments, at market prices, 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 capitalized.

Refining and Petrochemicals – 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 at market prices. 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 transportation activities.

Market and Supply – this segment includes the Company’s revenues, costs and expenses associated with distribution, including distribution of purchases from third parties and the ANH (Agencia Nacional de Hidrocarburos)

These functions have been defined as the operating segments of the Company since these 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 market prices.

F-97

The following presents the Company’s balance sheet by segment in accordance with RCP:

	As of December 31, 2011
	Exploration & Production			Refining Activities			Transportation			Market and Supply			Eliminations			Total
Current assets
Cash and cash equivalents	$	5,314,385		$	402,250		$	1,065,357		$	61,336		$	(257,700	)	$	6,585,628
Accounts and notes receivable		3,652,699			(41,433	)		231,897			1,007,032			(214,361	)		4,635,834
Inventories		1,147,213			1,343,072			855			503,991			(233,526	)		2,761,605
Investments		1,534,013			47,043			366,014			41,490			(456,649	)		1,531,911
Other current assets		1,519,940			1,563,270			342,980			98,726			(2,581	)		3,522,335
		13,168,250			3,314,202			2,007,103			1,712,575			(1,164,817	)		19,037,313
Investments in non-consolidated companies		962,906			20,888			16,902			19,363			-			1,020,059
Property, plant and equipment and natural environmental resources, net		24,817,733			10,774,630			9,909,505			72,529			(100,229	)		45,474,168
Other non-current assets		17,233,545			5,841,229			6,463,476			594,169			(3,386,573	)		26,745,846
Non-current assets		43,014,184			16,636,747			16,389,883			686,061			(3,486,802	)		73,240,073
Total assets	$	56,182,434		$	19,950,949		$	18,396,986		$	2,398,636		$	(4,651,619	)	$	92,277,386
Accounts payable	$	(2,517,237	)	$	(957,932	)	$	(231,786	)	$	(890,392	)	$	222,457		$	(4,374,890	)
Financial obligations (short-term)		(331,490	)		(321,391	)		(263,892	)		(1,890	)		87,069			(831,594	)
Other current liabilities		(6,756,197	)		(2,650,023	)		(1,013,975	)		(125,758	)		-			(10,545,953	)
Current liabilities		(9,604,924	)		(3,929,346	)		(1,509,653	)		(1,018,040	)		309,526			(15,752,437	)
Financial obligations (long-term)		(3,617,652	)		(2,429,766	)		(3,038,809	)		-			1,116,249			(7,969,978	)
Other non current liabilities		(10,049,747	)		(1,671,795	)		(1,435,931	)		(332,958	)		1,876,946			(11,613,485	)
Non-current liabilities		(13,667,399	)		(4,101,561	)		(4,474,740	)		(332,958	)		2,993,195			(19,583,463	)
Total liabilities		(23,272,323	)		(8,030,907	)		(5,984,393	)		(1,350,998	)		3,302,721			(35,335,900	)
Non-controlling interest		(1,087,189	)		(11,219	)		(1,154,223	)		-			-			(2,252,631	)
Shareholders’ equity of Ecopetrol		(31,822,922	)		(11,908,823	)		(11,258,370	)		(1,047,638	)		1,348,898			(54,688,855	)
Total equity		(32,910,111	)		(11,920,042	)		(12,412,593	)		(1,047,638	)		1,348,898			(56,941,486	)
Total liabilities and equity	$	(56,182,434	)	$	(19,950,949	)	$	(18,396,986	)	$	(2,398,636	)	$	4,651,619		$	(92,277,386	)
Capital expenditures	$	8,067,968		$	3,044,252		$	3,382,463		$	5,988		$	-		$	14,500,671
Goodwill	$	2,102,481		$	629,037		$	432,244		$	-		$	-		$	3,163,762

F-98

	As of December 31, 2010
	Exploration & Production			Refining Activities			Transportation			Market and Supply			Eliminations			Total
Current assets
Cash and cash equivalents	$	2,319,046		$	150,236		$	1,239,258		$	18,238		$	-		$	3,726,778
Accounts and notes receivable		1,485,854			1,126,737			559,147			565,442			(1,000,588	)		2,736,592
Inventories		1,083,572			1,105,022			4,669			173,906			(175,081	)		2,192,088
Investments		243,000			57,419			24,086			3,277			-			327,782
Other current assets		2,588,375			807,608			208,294			42,121			-			3,646,398
		7,719,847			3,247,022			2,035,454			802,984			(1,175,669	)		12,629,638
Investments in non-consolidated companies		773,821			11,309			29,167			15,873			-			830,170
Property, plant and equipment and natural and environmental resources, net		20,104,180			7,511,806			6,322,588			120,843			(18,620	)		34,040,797
Other non-current assets		12,350,678			5,773,967			3,564,576			272,258			(692,728	)		21,268,751
Non-current assets		33,228,679			13,297,082			9,916,331			408,974			(711,348	)		56,139,718
Total assets	$	40,948,526		$	16,544,104		$	11,951,785		$	1,211,958		$	(1,887,017	)	$	68,769,356
Accounts payable	$	(2,663,441	)	$	(920,862	)	$	(513,038	)	$	(855,040	)	$	889,779		$	(4,062,602	)
Financial obligations (short-term)		(555,665	)		(709,968	)		(195,578	)		(2,958	)		385,000			(1,079,169	)
Other Current Liabilities		(2,938,090	)		(1,367,859	)		(538,577	)		(64,437	)		8,156			(4,900,807	)
Current Liabilities		(6,157,196	)		(2,998,689	)		(1,247,193	)		(922,435	)		1,282,935			(10,042,578	)
Financial obligations (long-term)		(3,638,479	)		(1,912,991	)		(2,667,276	)		(40	)		385,071			(7,833,715	)
Other non Current Liabilities		(6,539,180	)		(1,299,702	)		(1,002,119	)		(260,467	)		22,537			(9,078,931	)
Non-current liabilities		(10,177,659	)		(3,212,693	)		(3,669,395	)		(260,507	)		407,608			(16,912,646	)
Total Liabilities		(16,334,855	)		(6,211,382	)		(4,916,588	)		(1,182,942	)		1,690,543			(26,955,224	)
Non-controlling interest		-			(11,550	)		(474,401	)		-			-			(485,951	)
Shareholders’ equity of Ecopetrol		(24,613,671	)		(10,321,172	)		(6,560,796	)		(29,016	)		196,474			(41,328,181	)
Total Equity		(24,613,671	)		(10,332,722	)		(7,035,197	)		(29,016	)		196,474			(41,814,132	)
Total liabilities and equity	$	(40,948,526	)	$	(16,544,104	)	$	(11,951,785	)	$	(1,211,958	)	$	1,887,017		$	(68,769,356	)
Capital expenditures	$	5,878,246		$	2,084,554		$	2,351,662		$	5,513		$	-		$	10,319,975
Goodwill	$	1,423,801		$	613,152		$	471,449		$	-		$	-		$	2,508,402

F-99

The Company’s statement of net income by segment is as follows in accordance with RCP:

	Year ended December 31, 2011
	Exploration & Production			Refining Activities			Transportation			Market and Supply			Eliminations			Total
Revenues:
Local sales	$	1,513,877		$	19,062,797		$	1,724,270		$	1,116,599		$	(78,160	)	$	23,339,383
Foreign sales, net		24,443,145			8,403,561			806			15,143,416			(5,578,043	)		42,412,885
Inter-segment net operating revenues		13,558,328			1,566,700			2,644,741			14,483			(17,784,252	)		-
Total Revenue		39,515,350			29,033,058			4,369,817			16,274,498			(23,440,455	)		65,752,268
Cost of sales		10,108,169			27,583,170			2,233,220			15,409,591			(23,388,065	)		31,946,085
Depreciation, depletion and amortization		3,311,969			607,446			798,355			1,201			-			4,718,971
Selling and projects		1,592,457			397,129			301,315			86,431			-			2,377,332
Administration expenses		552,900			261,456			200,134			4,427			-			1,018,917
Costs and expenses		15,565,495			28,849,201			3,533,024			15,501,650			(23,388,065	)		40,061,305
Operating income		23,949,855			183,857			836,793			772,848			(52,390	)		25,690,963
Financial income (expenses), net		(241,989	)		(302,293	)		(115,164	)		(273,373	)		28,517			(904,302	)
Pension expenses		(292,011	)		(318,995	)		(94,664	)		(628	)		-			(706,298	)
Other non-operating income (expenses)		76,127			(331,629	)		(89,657	)		(92,926	)		(846	)		(438,931	)
Other expenses, net		(457,873	)		(952,917	)		(299,485	)		(366,927	)		27,671			(2,049,531	)
Income before income taxes and non-controlling		23,491,982			(769,060	)		537,308			405,921			(24,719	)		23,641,432
Income tax benefit (expense)		(7,938,519	)		270,062			(179,620	)		(107,644	)		-			(7,955,721	)
Non-Controlling interest		(208,962	)		1,151			(25,566	)		-			-			(233,377	)
Net income for the year attributable to Ecopetrol	$	15,344,501		$	(497,847	)	$	332,122		$	298,277		$	(24,719	)	$	15,452,334

	Year ended December 31, 2010
	Exploration & Production			Refining Activities			Transportation			Market and Supply			Eliminations			Total
Revenues:
Local sales	$	1,302,275		$	14,166,202		$	1,819,125		$	955,576		$	(158,753	)	$	18,084,425
Foreign sales, net		13,629,198			5,641,545			717			8,163,371			(3,550,945	)		23,883,886
Inter-segment net operating revenues		9,032,898			1,024,563			1,876,594			47,061			(11,981,116	)		-
Total Revenue		23,964,371			20,832,310			3,696,436			9,166,008			(15,690,814	)		41,968,311
Cost of sales		6,990,223			20,421,756			1,538,713			8,542,971			(15,510,409	)		21,983,254
Depreciation, depletion and amortization		2,759,835			487,911			727,970			31			-			3,975,747
Selling and projects		2,014,600			338,349			91,512			82,484			-			2,526,945
Administration expenses		242,717			184,420			164,985			11,401			-			603,523
Costs and expenses		12,007,375			21,432,436			2,523,180			8,636,887			(15,510,409	)		29,089,469
Operating income		11,956,996			(600,126	)		1,173,256			529,121			(180,405	)		12,878,842
Financial income (expenses), net		115,361			(55,244	)		983			(7,242	)		(16,069	)		37,789
Pension expenses		(157,035	)		(171,547	)		(48,706	)		(338	)		-			(377,626	)
Other non-operating income (expenses)		(443,165	)		(230,956	)		(178,391	)		(193,876	)		-			(1,046,388	)
Other expenses, net		(484,839	)		(457,747	)		(226,114	)		(201,456	)		(16,069	)		(1,386,225	)
Income before income taxes and non-controlling		11,472,157			(1,057,873	)		947,142			327,665			(196,474	)		11,492,617
Income tax benefit (expense)		(3,127,944	)		266,997			(294,616	)		(83,087	)		-			(3,238,650	)
Non-Controlling interest		-			403			(107,899	)		-			-			(107,496	)
Net income for the year attributable to Ecopetrol	$	8,344,213		$	(790,473	)	$	544,627		$	244,578		$	(196,474	)	$	8,146,471

F-100

	Year ended December 31, 2009
	Exploration & Production			Refining Activities			Transportation			Market and Supply			Eliminations			Total
Revenues:
Local sales	$	2,865,478		$	11,838,570		$	964,194		$	2,083,460		$	(3,693,168	)	$	14,058,534
Foreign sales, net		6,838,783			4,196,143			836			5,310,094			-			16,345,856
Inter-segment net operating revenues		7,801,225			958,026			1,703,915			67,607			(10,530,773	)		-
Total Revenue		17,505,486			16,992,739			2,668,945			7,461,161			(14,223,941	)		30,404,390
Cost of sales		5,490,208			16,512,052			1,340,638			7,725,926			(14,103,449	)		16,965,375
Depreciation, depletion and amortization		1,893,936			411,512			635,186			64			-			2,940,698
Selling and projects		1,569,576			250,862			69,927			72,277			-			1,962,642
Administration expenses		260,901			231,497			161,344			10,122			(1,528	)		662,336
Costs and expenses		9,214,621			17,405,923			2,207,095			7,808,389			(14,104,977	)		22,531,051
Operating income		8,290,865			(413,184	)		461,850			(347,228	)		(118,964	)		7,873,339
Financial income (expenses), net		530,074			(79,891	)		(2,802	)		48,452			-			495,833
Pension expenses		(249,252	)		(272,284	)		(73,085	)		(536	)		-			(595,157	)
Other non-operating income (expenses)		(256,842	)		(8,364	)		(159,406	)		(97,031	)		(1,528	)		(523,171	)
Other expenses, net		23,980			(360,539	)		(235,293	)		(49,115	)		(1,528	)		(622,495	)
Income before income taxes and non-controlling interest		8,314,845			(773,723	)		226,557			(396,343	)		(120,492	)		7,250,844
Income tax benefit (expense)		(2,330,443	)		183,019			(77,441	)		110,836			-			(2,114,029	)
Non-controlling interest		(39,270	)		31,272			3,237			-			-			(4,761	)
Net income for the year attributable to Ecopetrol	$	5,945,132		$	(559,432	)	$	152,353		$	(285,507	)	$	(120,492	)	$	5,132,054

The following tables illustrate sales by geographic zones:

Sales by Geographic Zones for the year ended December 31, 2011

Zone	Products	Value		Participation
Colombia*	Crude oil, Refined, Petrochemicals and natural gas	$	23,444,744		35.7	%
United States of America	Crude oil, Refined and Petrochemicals		27,450,466		41.8	%
Asia	Crude oil, Refined and Petrochemicals		4,351,492		6.6	%
Africa	Refined and Petrochemicals		140,512		0.2	%
South America	Crude oil, Refined, Petrochemicals and natural gas		2,458,953		3.7	%
Central America and Caribbean	Crude oil, Refined and Petrochemicals		5,054,208		7.7	%
Europe	Crude oil, Refined and Petrochemicals		2,768,359		4.2	%
Other	Petrochemicals		83,534		0.1	%
			65,752,268		100.0	%

*Includes sales due to the free trade agreement of $105,361

Sales by Geographic Zones for the year ended December 31, 2010

Zone	Products	Value		Participation
Colombia*	Crude oil, Refined, Petrochemicals and natural gas	$	18,229,158		43.4	%
United States of America	Crude oil, Refined and Petrochemicals		14,965,911		35.7	%
Asia	Crude oil, Refined and Petrochemicals		3,952,186		9.4	%
South America (excluding Colombia)	Crude oil, Refined, Petrochemicals and natural gas		1,031,808		2.5	%
Central America and Caribbean	Crude oil, Refined and Petrochemicals		2,311,529		5.5	%
Europe	Crude oil, Refined and Petrochemicals		1,431,301		3.4	%
Other	Petrochemicals		46,418		0.1	%
		$	41,968,311		100.0	%

*Includes sales due to the free trade agreement of $144,734

F-101

Sales by Geographic Zones for the year ended December 31, 2009

Zone	Products	Value		Participation
Colombia*	Crude oil, Refined, Petrochemicals and natural gas	$	14,134,884		46.5	%
United States of America	Crude oil, Refined and Petrochemicals		10,875,221		35.8	%
Asia	Crude oil, Refined and Petrochemicals		2,151,854		7.1	%
South America	Crude oil, Refined, Petrochemicals and natural gas		561,221		1.8	%
Central America and Caribbean	Crude oil, Refined and Petrochemicals		1,473,225		4.8	%
Europe	Crude oil, Refined and Petrochemicals		1,207,367		4.0	%
Other	Petrochemicals		618		0.0	%
		$	30,404,390		100.0	%

 * Includes sales to free trade zone of $76,350

The following tables illustrate sales of products by Segment:

 Sales of products by Segment for the year ended December 31, 2011

Local Sales	Exploration & Production		Refining Activities			Transportation	Market and Supply		Eliminations			Total
Medium distillates	$	6,141	$	9,045,328	$	-	$	690,877	$	-		$	9,742,346
Gasolines		-		5,185,831		-		21,042		-			5,206,873
Crude Oil		245,345		-		-		-		(14,886	)		230,459
Other products		63,979		1,086,384		-		9,117		-			1,159,480
Services		52,218		6,850		1,724,270		58,167		(54,861	)		1,786,644
Natural Gas		1,093,079		-		-		334,441		(8,413	)		1,419,107
L.P.G.		53,115		671,041		-		2,955		-			727,111
Diesel and gasoline subsidies		-		2,251,322		-		-		-			2,251,322
Plastic and rubber		-		816,041		-		-		-			816,041
Total local sales	$	1,513,877	$	19,062,797	$	1,724,270	$	1,116,599	$	(78,160	)	$	23,339,383

Sales of products by Segment for the year ended December 31, 2011

Foreign Sales	Exploration & Production		Refining Activities		Transportation		Market and Supply		Eliminations			Total
Crude oil	$	24,039,881	$	-	$	-	$	14,790,487	$	(5,412,176	)	$	33,418,192
Fuel oil		-		4,447,657		-		-		-			4,447,657
Gasolines		-		1,484,245		-		178,976		-			1,663,221
Diesel		-		1,482,625		-		-		-			1,482,625
Natural Gas		381,000		-		-		173,540		(46,474	)		508,066
Plastic and rubber		-		804,835		-		-		-			804,835
Other products		22,264		184,199		806		413		(119,393	)		88,289
Total foreign sales	$	24,443,145	$	8,403,561	$	806	$	15,143,416	$	(5,578,043	)	$	42,412,885

Sales of products by Segment for the year ended December 31, 2010

Local Sales	Exploration & Production		Refining Activities		Transportation		Market and Supply		Eliminations			Total
Medium distillates	$	5,058	$	6,588,097	$	-	$	506,021	$	-		$	7,099,176
Gasolines		-		4,324,551		-		-		(22,269	)		4,302,282
Crude Oil		123,797		-		-		-		(6,611	)		117,186
Other products		189,833		1,214,831		-		16,124		(68	)		1,420,720
Services		97,350		32,546		1,819,125		54,492		(55,684	)		1,947,829
Natural Gas		854,427		-		-		378,939		(74,121	)		1,159,245
L.P.G.		31,810		595,551		-		-		-			627,361
Diesel and gasoline price differentials		-		740,682		-		-		-			740,682
Plastic and rubber		-		669,944		-		-		-			669,944
Total local sales	$	1,302,275	$	14,166,202	$	1,819,125	$	955,576	$	(158,753	)	$	18,084,425

F-102

Sales of products by Segment for the year ended December 31, 2010

Foreign Sales	Exploration & Production		Refining Activities		Transportation		Market and Supply		Eliminations			Total
Crude oil	$	13,515,877	$	-	$	-	$	8,108,425	$	(3,550,945	)	$	18,073,357
Fuel oil		-		2,377,266		-		-		-			2,377,266
Gasoline		-		687,984		-		10,084		-			698,068
Diesel		-		1,638,044		-		-		-			1,638,044
Natural Gas		101,363		-		-		44,700		-			146,063
Plastic and rubber		-		673,574		-		-		-			673,574
Other products		11,958		264,677		717		162		-			277,514
Total foreign sales	$	13,629,198	$	5,641,545	$	717	$	8,163,371	$	(3,550,945	)	$	23,883,886

Sales of products by Segment for the year ended December 31, 2009

Local Sales	Exploration & Production		Refining Activities		Transportation		Market and Supply		Eliminations			Total
Medium distillates	$	9,808	$	5,087,659	$	-	$	-	$	-		$	5,097,467
Gasolines		-		5,001,527		-		14,373		-			5,015,900
Crude Oil		1,943,410		-		-		1,692,832		(3,618,048	)		18,194
Other products		128,038		446,647		-		1,605		-			576,290
Services		75,322		82,616		964,194		38,284		(47,341	)		1,113,075
Natural Gas		691,930		-		-		336,366		(27,779	)		1,000,517
L.P.G.		16,970		452,581		-		-		-			469,551
Diesel and gasoline price differentials		-		196,533		-		-		-			196,533
Plastic and rubber		-		571,007		-		-		-			571,007
Total local sales	$	2,865,478	$	11,838,570	$	964,194	$	2,083,460	$	(3,693,168	)	$	14,058,534

Sales of products by Segment for the year ended December 31, 2009

Foreign Sales	Exploration & Production		Refining Activities		Transportation		Market and Supply		Eliminations		Total
Crude oil	$	6,613,961	$	-	$	-	$	5,201,551	$	-	$	11,815,512
Fuel oil		-		1,660,911		-		-		-		1,660,911
Gasoline		-		1,713,823		-		10,712		-		1,724,535
Natural Gas		214,091		-		-		97,643		-		311,734
Plastic and rubber		-		544,912		-		-		-		544,912
Other products		10,731		276,497		836		188		-		288,252
Total foreign sales	$	6,838,783	$	4,196,143	$	836	$	5,310,094	$	-	$	16,345,856

xxvii. RELATED PARTIES

In addition to the transactions disclosed in Note 15, unconsolidated financial statements of Ecopetrol are controlled by the Colombian Government which owns a majority stake in the Company. Hence, Ecopetrol has numerous transactions with other governmental entities as well as state-owned companies in the ordinary course of its business. The most significant of these transactions are disclosed below:

Price differentials: Ecopetrol sell prices are regulated and the National Government pays to Ecopetrol the amount of the benefit price for the refined products generated between the income of the regulated producer and the equivalent price quoted in the international market. The amount of the price differential included in revenue in 2011, 2010 and 2009 was $2,251,322, $740,682 and $196,533, respectively. Additionally, in 2010 and 2009, the Company recognized interests amounting to $929 and $235,704, respectively, which corresponds to the price differentials recorded.

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 references international prices. For more information on this transaction, please see Notes 1 and 30.

F-103

The following table presents consolidated accounts receivable and payable with related parties of Ecopetrol S.A., Bioenergy S.A., Polipropileno del Caribe S.A., Compounding and Masterbaching - COMAI, Refineria de Cartagena, Oleoducto Central - Ocensa, Oleoducto de Colombia, as of December 31, 2011 and:

	2011				2010
	Assets		Liabilities		Assets		Liabilities
Ministerio de Hacienda y Crédito Público	$	1,367,554	$	108	$	1,930,947	$	332
Ministerio de Minas y Energía		30,619		-		-		-
U.A.E. Agencia Nacional de Hidrocarburos		55		133		66,913		-
E.S.P. Empresa de Energía de Bogotá S.A.		741,724		-		1,101,455		-
E.S.P. Generadora de Energía del Caribe S.A.		19,749		1,299		37,219		-
Interconexión Eléctrica S.A. – ESP		662,499		-		833,206		74
Entidades Territoriales (Departamentos, Municipios)		46,034		35,840		37,232		24,099
Empresas Públicas de Medellín		13,813		2		8,568		113
Isagen S.A.		9,286		7,694		199		23
E.S.P. Transportadora de Gas Internacional S.A.		857		-		3,982		434
Central Hidroeléctrica de Caldas S.A. E.S.P.		27		856		-		937
Banco Agrario de Colombia		18		177,136		-		-
Universidad Industrial de Santander		27		-		11		-
Dirección de Impuestos y Aduanas Nacionales DIAN		2,224,871		1,763,035		1,341,223		3,288,780
Other		27,285		4,288		1,498		5,124
	$	5,144,418	$	1,990,391	$	5,362,453	$	3,319,916

Other transactions with related parties during 2011, 2010 and 2009 are:

	2011				2010				2009
	Income		Expenses		Income		Expenses		Income		Expenses
Ministerio de Minas y Energía	$	705	$	-	$	-	$	-	$	-	$	-
Dirección de Impuestos y Aduanas Nacionales DIAN		-		706,206		1		3,523,700		19		4,295,093
Entidades Territoriales (Departamentos, Municipios)		233		60,005		1,328		30,986		15		121,396
Contraloría General de la República		-		55,082		-		52,876		-		33,106
Ministerio de Defensa Nacional		68		-		124		-		-		12,128
E.S.P. Generadora de Energía del Caribe S.A.		165,828		-		-		-		-		-
Empresas Públicas de Medellín		96,373		2,281		-		-		-		-
Banco Agrario de Colombia		-		15,392		-		-		-		-
Isagen S.A.		113,447		230		46,236		17,930		-		4
Unidad de Planeación Minero Energética		-		2,208		-		2,557		-		2,308
Other		35,046		40,459		330,476		31,417		745		19,522
	$	411,700	$	881,863	$	378,165	$	3,659,466	$	779	$	4,483,557

Material Related Party Agreements

Set forth below is a description of the Company's material related party agreements:

We entered into a supply agreement with Ecodiesel Colombia S.A., or Ecodiesel, a company in which we have a 50% equity interest. This agreement has been operative since August 1, 2010. Pursuant to the terms of this agreement, Ecodiesel must deliver to us and we must purchase from Ecodiesel at least the guaranteed amount of 48,100 bls of Ecodiesel's biodiesel production each month. Payments vary depending on the purchased volumes of biodiesel. This agreement expires on December 31, 2017.

In 2010, we renewed the service agreement with Sociedad Colombiana de Servicios Portuarios S.A. or Serviport S.A., a company in which we have 49% equity interest. Pursuant to the terms of the agreement, Serviport assists the Company in its maritime operations in the Coveñas port. This agreement expires on May 27, 2019.

The Technical Service Agreement signed between SAVIA and us consists of management, administration, technical and business advice in order to implement all the necessary operations of several offshore oil and gas concessions in Peru, the Technical Services shall be implemented in Peru and will mainly concentrate on the following matters: Technical, Geological, Drilling, Operation, HSE, Administration, Legal, Human Resources, and Information Technology. Ecopetrol has a 50% equity interest in Offshore International Group which owns SAVIA Peru S.A. The Technical Service Agreement is worth US$ 1,000,000 per year.

The Company also paid in kind royalties over certain fields as set forth in Law 141 of 1994, The Administrative Agreement of Collaborative Collection of Liquid Hydrocarbon Royalties signed on September 16, 2010, with the ANH, and Decree 4923 of 2011. The quantities of oil and gas paid as royalties in-kind to the ANH for the years ended December 31, 2011, 2010, 2009 were 59,059,539 boe, 52,518,111 boe and 46,718,768 boe, respectively.

F-104

xxviii. FAIR VALUE

Accounting standards for fair value measurement (ASC 820) establish a framework for measuring fair value and stipulate disclosures about fair value measurements. The standards apply to recurring and nonrecurring financial and nonfinancial assets and liabilities that require or permit fair-value measurements. Among the required disclosures is the fair-value hierarchy of inputs the company uses to value an asset or a liability. The three levels of the fair-value hierarchy are described as follows:

Level 1: Quoted prices (unadjusted) in active markets for identical assets and liabilities. For the Company, Level 1 inputs include marketable securities that are actively traded.

Level 2: Inputs other than Level 1 that is observable, either directly or indirectly. For the Company, Level 2 inputs include quoted prices for similar assets, prices obtained through third-party broker quotes, and prices that can be corroborated with other observable inputs for substantially the complete term of a contract.

Level 3: Unobservable inputs – The Company does not use Level 3 inputs for any of its recurring fair-value measurements. Level 3 inputs may be required for the determination of fair value associated with certain nonrecurring measurements of nonfinancial assets and liabilities. In 2010, the Company used Level 3 inputs to determine the fair value of certain nonrecurring nonfinancial assets.

The fair value hierarchy for recurring assets measured at fair value at December 31, 2011, and December 31, 2010, is as follows:

				Fair Value at Reporting Date Using									Fair Value at Reporting Date Using
				Quoted Price in Active Markets  for Identical Assets		Significant Other Observable Inputs			Significant Unobservable Inputs				Quoted Price in  Active Markets  for Identical Assets		Significant Other Observable Inputs		Significant Unobservable Inputs
Description	2011			(Level 1)		(Level 2)			(Level 3)		2010		(Level 1)		(Level 2)		(Level 3)
ASSETS
Available for sale debt securities
Securities issued by mixed – economy governmental entities	$	1,401,505		$	1,401,505	$	-		$	-	$	1,932,115	$	1,932,115	$	-	$	-
Securities issued or secured by Colombian government		1,303,145			1,303,145		-			-		1,642,336		1,642,336		-		-
Securities issued or secured by government sponsored enterprise (GSEs)		2,148,727			2,148,727		-			-		1,498,957		1,498,957		-		-
Securities issued or secured by financial entities		552,857			361,653		191,204			-		120,044		120,044		-		-
Other debt securities		279,528			279,528		-			-		29,585		29,585		-		-
Securities issued or secured by USA government		700,237			700,237		-			-		642,974		642,974		-		-
Total available for sale debt securities		6,385,999			6,194,795		191,204			-		5,866,011		5,866,011		-		-
Derivatives
Option		(2,370	)		-		(2,370	)		-		12,651		-		12,651		-
Swap		-			-		-			-		21,191		-		21,191		-
FX Forward		14			-		14			-		107		-		107		-
Total derivatives		(2,356	)		-		(2,356	)		-		33,949		-		33,949		-
Total Recurring Assets at fair value	$	6,383,643		$	6,194,795	$	188,848		$	-	$	5,899,960	$	5,866,011	$	33,949	$	-

Marketable Securities: The Company calculates fair value for its marketable securities based on quoted market prices for identical assets and liabilities. The fair values reflect the cash that would have been received if the instruments were sold at December 31, 2011.

Derivatives: The Company records its derivative instruments on the Consolidated Balance Sheet at fair value, with the offsetting amount to the Consolidated Statement of Income. For derivatives with identical or similar provisions as contracts that are publicly traded on a regular basis, the company uses the market values of the publicly traded instruments as an input for fair-value calculations.

The Company’s derivative instruments principally include foreign exchange and refined-product (asphalt) swaps, options and forward contracts, principally with financial institutions and other oil and gas companies, the fair values for which are obtained from third-party broker quotes, industry pricing services and exchanges.

The Company obtains multiple sources of pricing information for the Level 2 instruments. Since this pricing information is generated from observable market data, it has historically been very consistent. The Company does not materially adjust this information.

F-105

The fair value hierarchy for non-recurring assets measured at fair value at December 31, 2011 is as follows:

			Fair Value Measurements Using
Description	2011		Quoted Price in  Active Markets  for Identical Assets Level 1		Significant Other Observable Inputs Level 2		Significant Unobservable Inputs Level 3		Total Gains (Losses)		2010
Goodwill	$	1,388,568	$	-	$	-	$	1,388,568	$	46,691	$	1,380,632
Production fixed assets with impairment		144,106		-		-		144,106		95,314		93,069
Transportation fixed assets with impairment (*)		-		-		-		-		41,043		-
Other fixed assets		15,389,893		-		-		15,389,893		-		11,609,275
Total Fixed Assets	$	15,533,999	$	-	$	-	$	15,533,999	$	136,357	$	11,702,344
Total Non-Recurring Assets	$	16,922,567	$	-	$	-	$	16,922,567	$	183,048	$	13,082,976

* Transportation fixed assets were written down to their fair value of $0, resulting in an impairment charge of ($41,043). Under U.S. GAAP, in 2011 one transport system was measured at fair value, in 2010 two transportation systems was measured at fair value.

Impairment of “Goodwill”- During 2011 in accordance with the accounting standard for Intangibles – Goodwill Impairment Test (ASC 350 - 20), the Goodwil in Propilco with a carrying amount of $694,388 was written down to a fair value of $647,697, resulting in a before-tax loss of $46,691. The fair value was determined from internal cash-flow models, using discount rates consistent with those used by the company to evaluate cash flows of other assets of a similar nature.

Impairment of “Properties, plant and equipment”- During 2011 and in accordance with the accounting standard for the impairment or disposal of long-lived assets (ASC 360), long-lived assets “held and used” with a carrying amount of $15,670,357 were written down to a fair value of $15,533,999, resulting in a before-tax loss of $95,314. The fair values were determined from internal cash-flow models, using discount rates consistent with those used by the Company to evaluate cash flows of other assets of a similar nature. The respective long-lived assets were reviewed for impairment on a well-by-well basis.

Assets and Liabilities Not Required to Be Measured at Fair Value

The Company holds cash and cash equivalents. The instruments held are primarily time deposits and money market funds. The fair values reflect the cash that would have been received or paid if the instruments were settled at year-end. Cash equivalents had carrying/fair values of $7,073,550 and $3,910,745 at December 31, 2011 and 2010, respectively. Fair values of other financial instruments at the end of 2011 and 2010 were not material.

The company measures the long term receivables and payables at present value and records any effects considered to be material. For the year 2011, the Equity Tax liability recognized by Ecopetrol and its subsidiaries was adjusted in $126,861. The estimated rate to discount the long term liability is based on the Colombian Government Treasury bonds as it was considered that the Company has a similar credit risk.

The Company’s financial instruments that are exposed to concentrations of credit risk consist primarily of cash and accounts receivables. The carrying value of cash and accounts receivable reflects management’s assessment of credit risk. At December 31, 2011, cash and cash equivalents includes balances in savings and checking accounts, as well as term deposits and certificates of deposit, placed primarily with governments and financial institutions with strong investment grade ratings.

Fair value of financial instruments: The estimated fair value amounts presented below have been determined by the Company using available market information or other appropriate valuation methodologies that require considerable judgment in developing and interpreting the estimates of fair value.  Accordingly, the estimates presented herein are not necessarily indicative of the amounts that the Company could realize in a current market exchange.  The use of different market assumptions and/or estimation methodologies may have a material effect on the estimated fair value amounts.

The carrying amounts of the Company’s accounts receivable, accounts payable and current notes payable approximate fair value because they have relatively short-term maturities and bear interest at rates tied to market indicators, as appropriate.  The Company’s long-term debt consists of debt instruments that bear interest at fixed or variable rates tied to market indicators. 

The carrying amount and estimated fair values of the Company’s financial instruments that are not recognized in the balance sheets at fair value as of December 31 are as follows:

	2011				2010
Description	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Long-term notes payable	$	4,724,355	$	4,726,610	$	4,958,658	$	4,963,459
Long-term debt (including current portion):	$	4,009,178	$	4,624,413	$	3,963,233	$	4,424,370
Total	$	8,733,533	$	9,351,023	$	8,921,891	$	9,387,829

xxix. SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)

In accordance with the requirements of the United States Securities and Exchange Commission (SEC), Accounting Standards Codification 932 and the ASU- 2010-03 “Oil and Gas reserve Estimation and Disclosures” Rule, 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) presents 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 2011, 2010 and 2009 in direct and joint operations.

Under the final SEC rule, optional disclosure of possible and probable reserves is allowed. However, the Company opted not to disclose such information. Ecopetrol estimated its reserves without considering non-traditional resources.

F-106

Table i – Capitalized costs relating to oil and gas producing activities

	Year ended December 31
Consolidated Companies	2011			2010			2009
Natural and environmental properties – proved properties	$	21,795,716		$	16,977,248		$	12,188,806
Wells, equipment and facilities – property, plant and equipment		8,460,137			6,564,590			5,359,419
Construction in progress		4,912,199			2,490,365			2,321,427
Accumulated depreciation, depletion and amortization		(15,850,932	)		(11,864,137	)		(9,883,704	)
Net capitalized costs	$	19,317,120		$	14,168,065		$	9,985,947

It includes information of the subsidiary companies of the sector of E & P and Savia.

In accordance with ASC 410-20, Asset Retirement Obligations, during 2011, 2010 and 2009 were added $79,930, $30,748 and $6,857, respectively, have been added to the cost basis of oil and gas wells for wells drilled

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.

	Year ended December 31
	2011		2010		2009
Acquisition of Proved Properties (1)	$	1,483,891	$	-		2,879,233
Acquisition of Unproved Properties (2)		336,824		-		-
Exploration costs		941,600		1,307,379		1,258,827
Development costs		8,875,850		5,835,141		4,717,550
Total costs incurred	$	11,638,165	$	7,142,520	$	8,855,610

(1) Includes wells, equipment and facilities associated with Equion.

(2) Includes wells, equipment and facilities associated with Caño Sur.

F-107

Table iii - Results of operations for oil and gas producing activities

	2011			2010			2009
Net revenues
Sales	$	26,222,068		$	15,245,110		$	9,957,793
Transfers		13,558,328			9,032,898			7,801,224
Total	$	39,780,396		$	24,278,008		$	17,759,017
Production cost (1)		4,879,884			3,577,780			3,117,872
Depreciation, depletion and amortization (2)		2,622,867			1,856,118			1,184,584
Other production costs (3)		5,486,537			3,554,315			2,533,031
Exploration expenses (4)		1,149,937			1,696,383			1,357,147
Other expenses (5)		1,078,564			593,257			535,494
Total		15,217,789			11,277,853			8,728,128
Income before income tax		24,562,607			13,000,155			9,030,889
Income tax expenses		(8,105,660	)		(4,290,051	)		(2,980,193	)
Results of operations for oil and gas producing activities	$	16,456,947		$	8,710,104		$	6,050,696

Note: Effects of naphtha addition are included into results of operations in the table above. During 2011, 2010 and 2009 the additional total barrels (million boe) were 15.4, 12.2 and 8.5.

(1) 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. In addition it also include accretion expense related to asset retirement obligations that were recognized during 2011, 2010 and 2009 in production costs which were approximately $ 133,796, $ 151,516, and $(25,980) respectively. The Company’s results of operations from oil and gas producing activities for the years ending December 31, 2011, 2010 and 2009 are shown above.

(2) In accordance with ASC 410-20, the expenses related to asset retirement obligations that were recognized during 2011, 2010 and 2009 in depreciation, depletion and amortization were approximately $28,676, $180,484 and $69,371 respectively.

(3) Relate to transportation costs and naphtha that do not form part of the company´s lifting cost.

(4) Exploration expenses include the costs of geological and geophysical activities and non-productive exploratory wells.

(5) Correspond to administration expenses and marketing expenses.

The Company transferred approximately 34%, 37% and 44% of its crude oil and gas production; (percentages are based on the sales value in Colombian pesos) to inter-company business units in 2011, 2010 and 2009, respectively. Using volumes, those transfers were 42%, 47% and 57% respectively (included Reficar), in 2011, 2010 and 2009. The inter-company transfers were recorded at values equal to the Company’s market prices.

Table iv – Reserve information

The reserve information presented in this section is based on the definitions and rules used for U.S. GAAP purposes. The estimates for proved oil and gas reserves used in the preparation of the consolidated financial statements were prepared by Ecopetrol’s engineers, audited in a 99% by the “external engineers” and approved by the Company’s reserves committee, consisting of the Chief Financial Officer, the Exploration and Production Executive Vice-President and the Vice-President of strategy. Decisions of the Reserves Committee have to be unanimous. Finally, results are ratified by the Audit Committee of the Board of Directors and presented to the Board of Directors.

Information concerning the technical definitions used for the estimated proved reserves is included in this annual report. The information provided in this annual report about our 2011 net proved reserves is based on the 2011 audited reserve reports for 99% of our total reserves prepared by experts under the SEC definitions and rules. The remaining 1% corresponds to calculations made by us internally using SEC definitions and rules set forth in Rule 4-10(a) of Regulation S-X and the disclosure guidelines contained in the SEC’s “Modernization of Oil and Gas Reporting” final rule dated December 31, 2008 and effective as of January 1, 2010.

Reserves were audited by Ryder Scott, DeGolyer and MacNaughton and Gaffney Cline & Associates (collectively, the “External Engineers”). By corporate definition, Ecopetrol reports the reserves values obtained from the External Engineers. Our 2011 crude oil and natural gas net proved reserves include reserves from production assets located in the United States, Perú and Hocol and Equion’s assets in Colombia.

The Company’s proved reserves as of December 31, 2011, 2010 and 2009 are based on the SEC average price methodology for U.S. GAAP purposes, which mirrors the average price methodology used by the Company in Colombia during this period.

F-108

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.

The arbitrary valuation methodology prescribed under ASU 2010-03 and ASU-2010-14 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.

Ecopetrol used deterministic methods that are commonly used internationally to estimate reserves. These methods have some uncertainty in degradation, and thus, the estimates should not be interpreted as being exact amounts. These methods have some uncertainty in gradation, and thus, the estimates should not be interpreted as being exact amounts. However, the technology used to estimate reserves is considered reliable.

Estimates of reserves were prepared by geological and engineering methods commonly used in the oil industry. The method or combination of methods used in the analysis of each reserve was adopted from experience with similar reserves, stage of development, quality and completeness of basic data and production history.

The majority of the producing proved reserves were estimated by applying appropriate decline curves or other performance relationships. In analyzing decline curves, reserves were estimated by calculating economic limits that are based on current economic conditions. In certain cases, where the methods previously employed could not be used, reserves were estimated by analogy with similar reserves where more complete data was available.

Most of the Company’s activities and reserves are located in Colombia. 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 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 table below sets forth the Company’s total proved oil and gas reserves together with their changes therein as of and for the years ended December 31, 2011, 2010 and 2009. The estimates (oil in million barrels, gas in billion cf, gas converted to million barrels at 5.7 billion cf per million barrels) using the SEC rules in effect for each respective year.

	2010				2011
Company	Reserves incorporated (BOE) millions		%  reserves provided / Total proved reserves Ecopetrol		Reserves incorporated (BOE) millions		%  reserves provided / Total proved reserves Ecopetrol
America Inc		-		-		0,35		0,22%
Savia		3.0		0.20%		(9,09)		1,26%
Hocol		9.5		0.60%		4,96		2,44%
Equion		-		-		34,62		1,64%

F-109

The following is the reserve quantity information:

	2011									2010									2009
	Oil			Gas			Total			Oil			Gas			Total			Oil			Gas			Total
	million barrels			billion cf			million boe			million barrels			billion cf			Million boe			Million barrels			billion cf			million boe
Proved Reserves:
Beginning of year		1,236.4			2,722.6			1,714.0			1,123.3			2,329.4			1,538.2			798.9			1,898.9			1,137.0
Revisions of previous estimates (1)		107.6			(260.8	)		61.8			99.1			558.7			190.9			246.0			537.2			341.6
Improved recovery		14.8			3.6			15.4			47.4			-			47.4			-			-			-
Purchases of minerals in place		18.3			93.3			34.6			-			-			-			84.2			33.2			90.1
Extensions and discoveries		184.5			386.2			252.3			126.3			0.3			126.5			126.1			16.8			129.1
Production		(190.5	)		(176.5	)		(221.5	)		(159.8	)		(165.9	)		(188.9	)		(131.9	)		(156.6	)		(159.7	)
End of year		1,371.0			2,768.4			1,856.7			1,236.4			2,722.6			1,714.0			1,123.3			2,329.4			1,538.2
Proved developed reserves:
Beginning of year		800.7			2,261.7			1,197.5			630.5			1,732.6			939.0			518.4			720.6			646.7
End of year		855.8			2,229.5			1,246.9			800.7			2,261.7			1,197.5			630.5			1,732.6			939.0
Proved undeveloped reserves:
Beginning of year		435.6			460.9			516.5			492.8			596.9			599.2			280.5			1,178.3			490.3
End of year		515.2			538.9			609.8			435.7			460.9			516.5			492.8			596.9			599.2

(1) Includes enhances oil recovery component for years 2010 and 2009

The Company’s revisions, on a consolidated basis, during 2011 amounted to 61.8 million boe, corresponding primarily to the following:

· Castilla Field: New development project in K1 unit and better production performance (lower decline rates), representing a 70 million boe increase.

· Chuchupa Field: Reevaluation of the Original Gas in Place, derived from new pressure data, representing a decrease in sales gas forecast (26 million boe).

· Gibraltar Field: Reevaluation of the Original Gas in Place from the reservoir, representing a decrease in sales gas forecast (20 million boe).

· Rubiales and Cusiana Fields: Better production performance representing a 16 million boe increase

The revisions described above represented 64% of the additions to reserves revisions in 2011, while the revisions with respect to the remaining 22 million boe resulted from varying increases and decreases from a variety of fields like Tibú, Moriche and others.

The Company’s improved recovery during 2011 amounted to 15.4 million boe, which corresponded mainly to new proved areas under waterflooding in the La Cira-Infantas and Yarigui- Cantagallo fields.

The Company’s extensions and discoveries during 2011 amounted to 252.3 million boe, which corresponded to 5 million boe of newly discovered fields and 248 million boe of extensions of proved acreage. In terms of extensions of proved acreage, 81% was associated with activities in the followings fields: 123 million boe was associated with Castilla Field where the Company to plans additional drilling activities in order to cover new proved areas, 41 million boe associated with new gas sales agreements in Cupiagua Field and the availability of a new gas processing plant and 40 million boe associated with new proved areas in Quifa and Chichimene Fields. The remaining 19% is distributed in smaller changes in several fields of the Company.

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 ASU 2010-03. Estimated future cash inflows from production under U.S. GAAP are computed by applying unweighted arithmetic average of the first-day-of-the-month for oil and gas price to year-end quantities of estimated net proved reserves.

	2011			2010			2009
Future cash inflows	$	251,939,319		$	186,295,426		$	137,518,875
Future production and development costs		(87,262,683	)		(57,267,518	)		(52,670,688	)
Future income tax expenses		(56,743,761	)		(36,783,230	)		(27,574,537	)
Future net cash flow		107,932,875			92,244,678			57,273,650
10% annual discount for estimated timing of cash flows		(38,932,148	)		(36,690,043	)		(21,813,763	)
Standardized measure of discounted future net cash flows	$	69,000,727		$	55,554,635		$	35,459,887

F-110

The following are the principal sources of change in the standardized measure of discounted net cash flows:

	2011			2010			2009
Net change in sales and transfer prices and in production (lifting) cost related to future production	$	21,725,178		$	23,136,538		$	11,522,615
Changes in estimated future development costs		(3,602,471	)		(2,936,160	)		(4,585,987	)
Sales and transfer of oil and gas produced during the period		(34, 900,512	)		(24,278,008	)		(17,759,017	)
Net change due to extension discoveries		9,500,676			4,102,951			1,129,590
Net change due to purchase and sales of minerals in place		1,239,446			-			2,387,443
Net change due to revisions in quantity estimates		3,912,856			10,577,037			13,532,916
Previously estimated development costs incurred during the period		8,265,106			4,352,080			3,369,970
Accretion of discount		7,770,745			3,545,989			1,865,831
Timing and other		13,658,144			6,674,884			11,859,363
Net change in income taxes		(14,123,076	)		(5,080,563	)		(6,521,148	)
Aggregate change in the Standardized measure of discounted future net cash flows for the year	$	13,446,092		$	20,094,748		$	16,801,576

F-111

SIGNATURES

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

Ecopetrol S.A.
By:	/s/ Adriana M. Echeverri
	Name:	Adriana M. Echeverri
	Title:	Chief Financial Officer
By:	/s/ Javier G. Gutiérrez
	Name:	Javier G. Gutiérrez
	Title:	Chief Executive Officer

Dated: April 30, 2012