Colombia Oil & Gas Report Q3 2015

Q3 2015www.bmiresearch.com

COLOMBIAOIL & GAS REPORTINCLUDES 10-YEAR FORECASTS TO 2024

ISSN 1748-3905Published by:BMI Research

Colombia Oil & Gas Report Q3 2015INCLUDES 10-YEAR FORECASTS TO 2024

Part of BMI’s Industry Report & Forecasts Series

Published by: BMI Research

Copy deadline: May 2015

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CONTENTS

BMI Industry View ............................................................................................................... 7

SWOT .................................................................................................................................... 9Oil & Gas SWOT ....................................................................................................................................... 9

Industry Forecast .............................................................................................................. 11Upstream Exploration .............................................................................................................................. 11

Table: Proven Oil and Gas Reserves (Colombia 2013-2018) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11

Table: Proven Oil and Gas Reserves (Colombia 2019-2024) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11

Upstream Projects ................................................................................................................................... 14Table: Colombia - Key Upstream Projects . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14

Upstream Production - Oil ........................................................................................................................ 18Table: Oil Production (Colombia 2013-2018) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18

Table: Oil Production (Colombia 2019-2024) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18

Upstream Production - Gas ....................................................................................................................... 26Table: Gas Production (Colombia 2013-2018) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26

Table: Gas Production (Colombia 2019-2024) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26

Refining ................................................................................................................................................. 29Table: Refining Capacity and Refined Products Production (Colombia 2013-2018) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29

Table: Refining Capacity and Refined Products Production (Colombia 2019-2024) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30

Refined Fuels Consumption ....................................................................................................................... 32Table: Refined Products Consumption* (Colombia 2013-2018) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32

Table: Refined Products Consumption* (Colombia 2019-2024) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32

Gas Consumption .................................................................................................................................... 34Table: Gas Consumption (Colombia 2013-2018) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34

Table: Gas Consumption (Colombia 2019-2024) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35

Trade - Oil ............................................................................................................................................. 37Table: Crude Oil Net Exports (Colombia 2013-2018) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 37

Table: Crude Oil Net Exports (Colombia 2019-2024) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 38

Table: Refined Fuels Net Exports (Colombia 2013-2018) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 40

Table: Refined Fuels Net Exports (Colombia 2019-2024) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 40

Table: Total Net Oil Exports - Crude and Products (Colombia 2013-2018) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 42

Table: Total Net Oil Exports - Crude and Products (Colombia 2019-2024) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 42

Trade - Gas (Pipeline and LNG) ................................................................................................................. 43Table: Gas Net Exports (Colombia 2013-2018) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 43

Table: Gas Net Exports (Colombia 2019-2024) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 44

Industry Risk Reward Index ............................................................................................. 48Latin America - Risk/Reward Index ............................................................................................................. 48

Table: Latin America Composite Risk/Reward Index, Out of 100 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 49

Upstream Risk/Reward Index: Reforms Prompting A Shake Up ....................................................................... 51Table: Latin America Upstream Risk/Reward Index, Out of 100 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 51

Downstream: Medium-Term Outlook Reinforces Current Dynamics ................................................................ 54

Colombia Oil & Gas Report Q3 2015

© Business Monitor International Ltd

Table: Latin America Downstream Risk/Reward Index, Out of 100 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 56

Colombia Risk/Reward Index ..................................................................................................................... 57

Colombia Upstream Index - Overview ........................................................................................................ 57

Colombia Upstream Index - Rewards ......................................................................................................... 57

Colombia Upstream Index - Risks ............................................................................................................. 58

Colombia Downstream Index - Overview .................................................................................................... 58

Market Overview ............................................................................................................... 60Colombia Energy Market Overview ............................................................................................................ 60

Overview/State Role ............................................................................................................................... 60

Licensing And Regulation ........................................................................................................................ 61Table: Royalty Rates . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 62

International Energy Relations ................................................................................................................. 65

Oil And Gas Infrastructure ........................................................................................................................ 66

Refineries ............................................................................................................................................. 66Table: Refineries In Colombia . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 66

Service Stations ..................................................................................................................................... 68

Oil Terminals/ Ports ............................................................................................................................... 68

Oil Pipelines ......................................................................................................................................... 68

LNG Terminals ...................................................................................................................................... 72

Gas Pipelines ........................................................................................................................................ 73

Competitive Landscape .................................................................................................... 74Competitive Landscape Summary ............................................................................................................... 74

Table: Key Players - Colombian Oil & Gas Sector . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 75

Company Profile ................................................................................................................ 76Empresa Colombiana de Petróleos (Ecopetrol) ............................................................................................. 76

Chevron ................................................................................................................................................. 83

Occidental .............................................................................................................................................. 86

Perenco ................................................................................................................................................. 90

Sinochem ............................................................................................................................................... 92

Pacific Rubiales Colombia ........................................................................................................................ 95

ExxonMobil Colombia .............................................................................................................................. 99

Other Summaries ................................................................................................................................... 102

Regional Overview .......................................................................................................... 113Latin America Oil&Gas Regional Overview ............................................................................................... 113

Global Industry Overview ................................................................................................ 122Oil Price Outlook .................................................................................................................................. 122

Table: BMI And Bloomberg Consensus Forecasts* WTI And Brent, Front Month - USD/bbl . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 122

Table: 2015-2016 - Fundamental Pressure On Oil Prices . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 123

Appendix .......................................................................................................................... 130Global - Crude Oil, Refined Fuels And Natural Gas Prices, 10-year Forecasts .................................................. 130



Table: Energy Price Forecasts, 2013-2018 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 130

Table: Energy Price Forecasts, 2019-2024 ( Global 2019-2024) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 131

Latin America - Regional Appendix ........................................................................................................... 132Table: Oil Consumption - Historical Data & Forecasts, 2012-2019 ('000b/d) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 132

Table: Oil Consumption - Long Term Forecasts, 2016-2024 ('000b/d) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 133

Table: Oil Production - Historical Data & Forecasts, 2012-2019 ('000b/d) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 134

Table: Oil Production - Long-Term Forecasts, 2016-2024 ('000b/d) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 134

Table: Refining Capacity - Historical Data & Forecasts, 2012-2019 ('000b/d) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 135

Table: Refining Capacity - Long-Term Forecasts, 2016-2024 ('000b/d) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 136

Table: Gas Consumption - Historical Data & Forecasts, 2012-2019 (bcm) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 136

Table: Gas Consumption - Long-Term Forecasts, 2016-2024 (bcm) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 137

Table: Gas Production - Historical Data & Forecasts, 2012-2019 (bcm) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 137

Table: Gas Production - Long-Term Forecasts, 2016-2024 (bcm) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 138

Table: LNG Exports - Historical Data & Forecasts, 2012-2019 (bcm) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 138

Table: LNG Exports - Long-Term Forecasts, 2016-2024 (bcm) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 139

Colombia - Total Hydrocarbons, 10-Year Forecasts ..................................................................................... 140Table: Total Hydrocarbons Production, Consumption and Net Exports (Colombia 2013-2018) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 140

Table: Total Hydrocarbons Production, Consumption and Net Exports (Colombia 2019-2024) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 140

Colombia - Refined Products Breakdown, 10-Year Forecasts ......................................................................... 141Table: Refined Petroleum Products, Production Breakdown (Colombia 2013-2018) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 141

Table: Refined Petroleum Products, Production Breakdown (Colombia 2019-2024) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 142

Table: Refined Petroleum Products, Consumption Breakdown (Colombia 2013-2018) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 143

Table: Refined Petroleum Products, Consumption Breakdown (Colombia 2019-2024) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 145

Table: Refined Petroleum Products, Net Exports Breakdown (Colombia 2013-2018) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 146

Table: Refined Petroleum Products, Net Exports Breakdown (Colombia 2019-2024) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 147

Table: LPG Production, Consumption and Net Exports (Colombia 2013-2018) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 148

Table: LPG Production, Consumption and Net Exports (Colombia 2019-2024) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 148

Glossary ........................................................................................................................... 149Table: Glossary Of Terms . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 149

Methodology .................................................................................................................... 151Industry Forecast Methodology .............................................................................................................. 151

Source ............................................................................................................................................... 153

Risk/Reward Index Methodology ............................................................................................................. 153Table: Bmi's Oil & Gas Upstream Risk/Reward Index . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 155

Table: Weighting . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 156



BMI Industry View

BMI View: Colombia's energy sector has approached an inflection point. While the past decade has

witnessed strong production growth due to improvements in the business and security environment, we

caution that the country will experience downward pressure on oil production over the longer term. The

tendency toward smaller finds, as well as recent increases in pipeline attacks have begun to show signs of

decreased investor interest in Colombia's resources, as witnessed in the 2014 licensing rounds.

Furthermore, sustained lower oil prices have threatened the development of upstream and downstream

projects by both national and international investors. Given ongoing below and above-ground challenges,

we maintain a cautious stance toward the future of Colombia's hydrocarbon productivity.

Table: Headline Forecasts (Colombia 2013-2019)

2013e 2014e 2015f 2016f 2017f 2018f 2019f

Crude, NGPL & other liquids prod, 000b/d 1,022.0 1,009.7 990.5 971.7 948.6 926.0 908.6

Refined products production & ethanol, 000b/d 347.2 347.2 377.4 389.0 413.2 422.9 433.1

Refined products consumption & ethanol, 000b/d 347.3 357.7 368.1 379.3 391.0 404.5 419.0

Dry natural gas production, bcm 10.2 10.3 10.2 10.1 9.9 9.8 9.8

Dry natural gas consumption, bcm 7.6 8.3 8.8 9.2 9.7 10.1 10.5

e/f = BMI estimate/forecast. Source: EIA, BMI

The key trends and developments in the Colombian oil and gas sector are:

■ Colombia's attractive fiscal regime, favourable contract terms, and amenable regulatory environment willbe unable to secure continued production growth over the next decade. As such, we maintain ourdownbeat Colombian oil production forecast, as decreased revenues from lower oil prices undermine theability of producers to maintain output levels. Moreover, the two main oil producers in Colombia, state-owned Ecopetrol and Pacific Rubiales, have both announced significant reductions to their 2015 capitalexpenditure (capex) plans, weakening upstream prospects throughout the course of our 10-year forecastperiod. We estimate output will decline by an average of -1.4% year-on-year (y-o-y) through to 2024.

■ Oil reserves will peak at 2.51bn barrels (bbl) in 2020, falling steadily thereafter in the absence ofsignificant upstream discoveries. Colombia's falling below ground prospectivity will temper investorinterest from the international community throughout this period and negatively impact reserves growth.Exploration activity will decline in spite of the country's favourable investment environment.

■ Major natural gas producers in Colombia have announced significant spending cuts, which will impactongoing and future upstream developments. Cutbacks will be particularly acute in associated gas fields,which represent the majority of natural production. We expect natural gas production to decline by anaverage rate of 1.3% y-o-y over the next four years as producers recalibrate their capex within a lower oil



price environment. Beginning in 2019, natural gas production will increase modestly by 1.0% y-o-ythrough to 2024 as crude prices begin to recover, encouraging greater upstream investment.

■ We believe natural gas consumption growth will outpace production gains over the course of the nextdecade, averaging 4.0% y-o-y versus 0.8% y-o-y through 2024, respectively. This will undermineColombia's ambitious export plans, as exhibited by the delay of Pacific Rubiales' 0.5mn tonnes perannum (mtpa) floating LNG project in January 2015. This trend will convert Colombia into a netimporter of natural gas by 2018, with the deficit to continue growing thereafter.

■ Rising oil demand is fuelling investment in the downstream sector. Ecopetrol's refinery in Cartagena, thecountry's second largest facility, is expected to complete its upgrades by mid-2015. The expansionproject, which received a USD2.84bn loan from the US export-import bank, will see the plant's capacityrise from 80,000b/d to 165,000b/d. However, Ecopetrol's Barrancabermeja refinery upgrade project isunder threat due to unfavourable project economics, highlighting mounting investment headwinds amid alower oil price environment.

■ As the US remains Colombia's primary crude export market, the expected fall in US oil imports on theback of its own oil production boom will threaten Colombian exports. Therefore, an increasing amount ofColombian exports will be sent to Asian importers instead. In this regard, we note that we have seenincreased interest, particularly from China and South Korea, in accessing Colombia's crude supplies.



SWOT

Oil & Gas SWOT

SWOT Analysis

Strengths ■ Improvements in security over the past decade, an increasingly investor-friendly

business environment, and a more robust macroeconomic backdrop propelled a

decade of output growth

■ The government favours the development of the sector, introducing incentives to

consume and produce

Weaknesses ■ Weak below-ground conventional discoveries continue to plague future production

prospects as fewer investors prove they are willing to sponsor the development of

Colombia's resources

■ Fuel price subsidies, although relatively small, have proven incredibly difficult to

irradiate as the country seeks to spur continued consumption of domestic resources

rather than illegally imported Venezuelan fuel

Opportunities ■ Vast swathes of the country, particularly offshore, remain underexplored, meaning

new hydrocarbon resources may yet be discovered

■ Significant untapped shale acreage offers a tremendous opportunity to bolster

Colombia's reserves and long-term output

■ Future licensing rounds can foster stronger exploration and production activity, with

the potential of upside risk to both our reserves and production forecasts

Threats ■ Lower oil prices have threatened the development of upstream, midstream and

downstream projects by both national and international companies due to a declining

availability of capex funds

■ Despite improvements, security threats continue to present a significant risk. Attacks

on oil and gas infrastructure by rebel groups remain a threat, and have increased in

frequency since 2010



SWOT Analysis - Continued

■ Demand for domestic fuel is eroded by cheap fuel in neighbouring Venezuela as

Colombians continue to illegally import and consume the heavily subsidised product

■ Ongoing market liberalisation in neighbouring Mexico, as well as increased

production in Brazil, undermine investment opportunities in ColombiaPoor relations

between oil companies, labour unions, and indigenous groups have resulted in

numerous protests that have temporarily stalled production



Industry Forecast

Upstream Exploration

BMI View: Colombia's relatively small hydrocarbon discoveries coupled with attacks on pipeline

infrastructure have discouraged greater upstream investment from international partners. We believe the

lower oil price environment will reinforce this trend over the coming decade as declining upstream

investments undermine efforts to expand Colombia's proven reserve base.

Table: Proven Oil and Gas Reserves (Colombia 2013-2018)

2013 2014 2015 2016f 2017f 2018f

Proven oil reserves, mn bbl 2,200.0 2,377.0 2,445.0 2,448.0 2,459.7 2,479.8

Proven oil reserves, bn bbl 2.2 2.4 2.4 2.4 2.5 2.5

Proven oil reserves, % y-o-y 10.7 8.0 2.9 0.1 0.5 0.8

Reserves to production ratio (RPR), years 5.9 6.4 6.8 6.9 7.1 7.3

Natural gas proven reserves, bcm 169.9 198.4 181.4 181.3 191.4 201.5

Natural gas proven reserves, tcm 0.2 0.2 0.2 0.2 0.2 0.2

Natural gas proven reserves, % y-o-y 26.7 16.8 -8.6 0.0 5.6 5.3

Natural gas reserves-to-production ratio, years 16.7 19.2 17.7 18.0 19.3 20.5

f = BMI forecast. Source: EIA, BMI

Table: Proven Oil and Gas Reserves (Colombia 2019-2024)

2019f 2020f 2021f 2022f 2023f 2024f

Proven oil reserves, mn bbl 2,506.5 2,486.5 2,469.6 2,454.4 2,440.7 2,425.4

Proven oil reserves, bn bbl 2.5 2.5 2.5 2.5 2.4 2.4

Proven oil reserves, % y-o-y 1.1 -0.8 -0.7 -0.6 -0.6 -0.6

Reserves to production ratio (RPR), years 7.6 7.6 7.6 7.6 7.6 7.5

Natural gas proven reserves, bcm 201.7 191.8 181.8 171.8 161.5 151.1

Natural gas proven reserves, tcm 0.2 0.2 0.2 0.2 0.2 0.2

Natural gas proven reserves, % y-o-y 0.1 -4.9 -5.2 -5.5 -6.0 -6.4

Natural gas reserves-to-production ratio, years 20.5 19.4 18.2 17.0 15.8 14.5




According to the Energy Administration Agency (EIA), Colombia's proven oil reserves were at 2.45bn

barrels (bbl) in 2015, up from 2.38bn bbl in 2014. The EIA reported the country's proven gas reserves at

181.4bn cubic meters (bcm) in 2015, down from the 2014 level of 198.4bcm. These resources are primarily

located in onshore, conventional resource basins in the Tolima, Boyacá, Casanare, and Meta departments.

The country's crude reserves represent approximately 7.0 years worth of supply at 2015 rates of production.

After a period of rapid output growth over the past several years, Colombia has struggled to boost its

reserves-to-production ratio beyond the seven-year timeframe. While we forecast modest reserve growth

over the course of our 10-year forecast period, averaging just under 1.0% per year, this will not be enough

to outpace declining production growth through 2024.

We note that while the national oil company (NOC), Ecopetrol, increased its audited proven (1P) reserves

by 5.7% in 2014, this increase was due to revisions at existing fields and failed to substantially increase

Colombia's reserve to production ratio. Proven reserves have been described as 'uncomfortably low' by the

vice president of the country's national hydrocarbon association, highlighting that production rates of 15

years and higher are considered desirable.

The government has taken concerted steps to attract both private and public investment in recent

years, enacting an attractive taxation regime and favourable licensing terms, in addition to dramatically

improving the country's security dynamics. However, while this has boosted inflows into exploration and

production (E&P), oil discoveries tend to be modest in size, encouraging our more cautious reserves and

production outlook.

Specifically, the Cano Sur Este and Akacias fields each have the potential to produce up to 25,000b/d in the

medium term, but offer less than other maturing fields. Depletion at the Cano Limon and Cusiana-

Cupiagua fields, which at their initial peaks produced 95,000b/d and 434,000b/d, respectively, has outpaced

discoveries in recent years, increasing pressure on the country to encourage reserve replenishment.



Minimum Momentum Amid Declining Profitability

Colombia - Proven Oil Reserves

Proven oil reserves, bn bbl (LHS)Reserves to production ratio (RPR), years (RHS)

2013

2014

2015

2016

f

2017

f

2018

f

2019

f

2020

f

2021

f

2022

f

2023

f

2024

f

0

1

2

3

5.5

6

6.5

7

7.5

8


In addition to smaller discoveries, above-ground risks, in the form of repeated insurgent attacks on

midstream infrastructure, have deterred investment in the sector. This dynamic was clearly observed by the

lacklustre July 2014 hydrocarbons licensing round, and its second failed attempt in August 2014 (see

'Lacklustre Auction Points To Declining Hydrocarbon Growth', July 30 2014). The first auction offered

both unconventional and offshore blocks in an effort to counteract limited onshore discoveries, but drew

bids on only 27% of available resources, well below the National Association of Hydrocarbon's (ANH)

predictions. The second round offered the resources once again and received only one bid, underscoring

declining interest as investors seek opportunities in more hydrocarbon-rich countries (see 'Persistent

Challenges Threaten Second Auction', August 18 2014).

Furthermore, the rapid decline in global oil prices will continue to dampen potential investment into the

sector, as total profitability from upstream operations is reduced. While this risk is not unique to Colombia,

it is particularly worrisome for the country due to greater opportunities for upstream investments in

neighbouring Mexico and Argentina.



Representing nearly 20% of total government revenues, royalties from the oil and gas sector are a crucial

component of the federal budget. In an effort to contain the expected deficit from declining oil production

profitability, the Colombian Congress enacted a tax law in December 2014 that will earn the government

COP53tn (USD22.3bn) over the next four years by extending and modifying existing taxes that would have

expired at the end of 2014. This law extends a three-year wealth tax at a rate of 1.3% in 2015, 1.0% in 2016,

and 0.4% in 2017, after which the tax will be removed. In addition, a profits tax called CREE will put a

5.0% charge on profits above COP800mn in 2015, 6.0% in 2016, 8.0% in 2017, and 9.0% in 2018. Though

President Santos said he does not plan to push for further tax increases this year, these measures have

received criticism from the industry as a deterrent to future investment amid declining profitability,

supporting our more downbeat outlook.

That being said, recent discoveries in the Llanos and Magdalena basins by Canacol Energy point to

potential growth from developed areas. While positive, however, these fit a broader trend in Colombian

reserve growth: small discoveries despite concerted efforts. As such, our more conservative reserve forecast

implies a continued struggle to substantially expand Colombia's hydrocarbon resources, resulting in a

stagnation of the reserve-to-production ratio to approximately 8.2 years by 2024.

Upstream Projects

Table: Colombia - Key Upstream Projects

Name Field Name Companies Status Select

Est.Peak Oil/Liquids Range(b/d)

Est.PeakGasOutput(bcm)

Type ofProject

UpperMagdalenaBasin, AbanicoBlock Abanico

Pacific Stratus Energy(100%) Production 107,258 0.6

Oil, NaturalGas

MiddleMagdelena Basin Abarco

Mansarovar Energy(100%) Production 5,700 - Oil

Orito Acae Sur Ecopetrol (100%) Production 5,400 - Oil

Llanos Basin,Block CPO-9 Akacias

Ecopetrol (55%), TalismanEnergy (45%) Production 25,000 -

Extra Heavyoil

Llanos Basin Apiay Ecopetrol (100%) Production 7,442 - Oil

Llanos (Block 34) Aruco GeoPark Holdings (45%) Exploration - Oil

Magdalena Basin Balcon Hocol (100%) Production 9,198 - Oil

La Guajira Ballena Chevron, Ecopetrol (57%) Production - - Natural Gas

Llanos Basin Cano LimonOccidental Petroleum(Oxy), Ecopetrol Production 95,000 - Oil

Llanos Basin Cano YarumalOccidental Petroleum(Oxy) (100%) Production 6,898 - Oil



Colombia - Key Upstream Projects - Continued




Type ofProject

Llanos Basin CapellaEmarald Energy Plc,Canacol Energy Ltd. (10%) Production 25,000 - Heavy Oil

Los Llanos Basin Caracara

Cepsa (CompaniaEspanola de Petroleos)(70%), Ecopetrol (30%) Production - - Oil

Catatumbo sub-basin, Carbonerablock Carbonera

Agencia Nacional deHidrocarburos - ANH Exploration - - Oil & Gas

Llanos Basin CaricareOccidental Petroleum(Oxy) (100%) Production 11,588 - Oil

Magdalena Valleybasin Casabe Ecopetrol (100%) Production 46,000 - Oil

Llanos Basin,Cubarral block Castilla Ecopetrol (100%) Production 200,000 - Oil

Llanos Basin,Castilla block Castilla Norte Ecopetrol (100%) Production 40,000 - Oil

Llanos Basin,Cubarral block Chichimene Ecopetrol (100%) Production 14,000 - Oil

La Guajira Chuchupa Chevron, Ecopetrol (57%) Production - 2.5 Natural Gas

Putumayo basin,Suroriente block Cohembi

VETRA Exploracion yProduccion ColombiaS.A.S Production 11,813 - Oil

Llanos Basin,Corcel block Corcel

Petrominerals ColombiaLtd (100%) Production 21,764 - Oil

Putumayo Basin,Chaza Block Costayaco Gran Tierra Energy (100%) Production 19,620 - Light Oil

Llanos Basin,OperaciónDirecta Cupiagua Cupiagua Ecopetrol (100%) Production 10,000 - Oil

Llanos Basin,Cuisiana block Cusiana Norte

Ecopetrol, Equion EnergiaLtd Production 8,368 - Oil

UpperMagdalena Basin Dina Terciarios Ecopetrol (100%) Production 5,824 - Oil

Llanos Basin,Dorotea block Dorotea B

New Granada Energy(100%) Production 7,847 - Oil

Llanos Basin,Piedemonteblock Florena

Equion Energia Ltd,Ecopetrol Production 8,287 - Oil

MiddleMagdelenaBasin, Block B Girasol

Mansarovar Energy(100%) Production 6,055 - Heavy Oil

MagdalenaBasin, Boqueronblock Guando

Petrobras (30%),Ecopetrol (50%), Nexen(20%) Production 20,000 - Medium Oil







Type ofProject

MagdalenaBasin, De Maresblock Infantas Ecopetrol (100%) Production 1,000 - Oil

MagdelenaBasin, Nareblock Jazmin

Mansarovar Energy(100%) Production 7,265 - Heavy Oil

Llanos Basin,Block LLA-16 Kona

Parex ResourcesColombia Ltd, ColumbusEnergy Sucursal Colombia Production 7,010 - Light Oil

MagdalenaBasin, De Mares

La Cira-Infantas Ecopetrol (100%) Expansion 60,000 - Oil

Llanos Basin,Los Ocarrosblock Las Maracas

Petroamerica oil (50%),Parex ResourcesColombia Ltd (50%) Production 12,500 - Light Oil

Llanos Basin Llanos-19Pacific Rubiales (50%),Petroamerica oil (50%) Exploration - - Oil & Gas

Llanos Basin,Los Hatos Los Hatos

Agencia Nacional deHidrocarburos - ANH,Global EnergyDevelopment Production - - Oil & Gas

MagdalenaBasin, EspinalBlock Matachin

Petroleo Brasileiro -Petrobras, Ecopetrol,Mich, CMS Oil & Gas,Dearborn Production - - Oil

MagdalenaBasin, NareBlock Moriche

Mansarovar Energy, ChinaPetroleum & ChemicalCorporation (Sinopec),ONGC Videsh (OVL) Production 12,765 - Heavy Oil

Llanos Basin,Guarrojo block Ocelote Hocol (100%) Production 15,000 - Heavy Oil

Putumayo Basin Orito Ecopetrol (100%) Production 5,994 - Light Oil

MiddleMagdalena Palagua-Caipal Ecopetrol (100%) Production 7,500 - Oil

Palmer ProspectPalmerProspect

Canacol Energy Ltd.(100%) Appraisal - - Gas

Llanos Basin,Alcaravan

Palo Blanco,Canacabare

Global EnergyDevelopment, Ecopetrol Production - - Oil & Gas

Llanos Basin,Piedemonteblock

Pauto SurPiedemonte Equion Energia Ltd (100%) Production 20,757 - Oil

Putumayo Basin,Suroriente Block Pinuna VETRA Group (100%) Production 7,609 - Oil

Putumayo Basin PlatanilloAmerisur Resources Ltd(100%) Production 7,500 - Oil

MiddleMagdelena Basin Provincia Ecopetrol (100%) Production 17,000 - Oil & Gas







Type ofProject

Llanos Basin,Quifa Quifa

Ecopetrol (40%), PacificRubiales (60%) Production 54,000 - Oil

Putumayo basin,Suroriente Quillacinga

VETRA Exploracion yProduccion ColombiaS.A.S Production - - Oil

Llanos BasinRanchoHermoso

Canacol Energy Ltd.(100%) Production 26,286 - Oil

UpperMagdalenaBasin, CaguanBlock Rio Ceibas

Empresa Colombiana dePetroleos (Ecopetrol)(100%) Production 11,900 0.039 Heavy Oil

Llanos Basin, RioVerde Rio Verde

Agencia Nacional deHidrocarburos - ANH,Global EnergyDevelopment Production - - Oil & Gas

La Guajira Riohacha Chevron, Ecopetrol (57%) Production - - Natural Gas

MiddleMagdalenaBasin, Bolivar

Rosa Blanca,Salada, Simiti,Tablazo and LaLuna

Global EnergyDevelopment, Ecopetrol Production - - Oil

Llanos Basin,Piriri/Rubiales Rubiales

Ecopetrol (53%), PacificRubiales (47%) Production 210,000 - Heavy Oil

San Francisco San Francisco Hocol (100%) Production 6,525 - Oil

Llanos Basin Suria Ecopetrol (100%) Production 5,728 -Extra Heavyoil

Superior delMagdalena Tello Huila (100%) Production 5,000 - Oil

Llanos Basin,Block 34 Tigana GeoPark Holdings (45%) Production 8,500 - Oil

MiddleMagdalenaBasin, Bocachico Torcaz

Global EnergyDevelopment, Ecopetrol Production - - Heavy oil

Llanos Basin,Llanos 34 block Tua GeoPark Holdings Production 10,000 - -

Llanos basin,Yamu block Yamu GeoPark Holdings Production - - Oil & Gas

MagdalenaBasin, Yariguiblock

Yarigui-Cantagallo Ecopetrol (100%) Production 14,869 - Oil

blank space = not available/applicable. Source: BMI Upstream Projects Database



Upstream Production - Oil

BMI View: We have downgraded our oil production forecast to reflect the impacts of a sustained lower oil

price environment and its effects on future investor sentiment. Over the next decade, Colombian production

will decline at an average rate of -1.25% per year amid mounting operational headwinds. Unconventional,

deepwater, and new field developments are unlikely to progress, maintaining our conservative outlook.

Table: Oil Production (Colombia 2013-2018)

2013 2014 2015f 2016f 2017f 2018f

Crude, NGPL & other liquids prod, 000b/d 1,022.0 1,009.7 990.5 971.7 948.6 926.0

Crude, NGPL & other liquids prod, mn bbl/year 373.0 368.5 361.5 354.7 346.2 338.0

Crude, NGPL & other liquids prod, % y-o-y 6.2 -1.2 -1.9 -1.9 -2.4 -2.4

Crude, NGPL & other liquids prod, USDbn 39.5 35.5 20.2 20.6 20.8 21.0

Crude, NGPL & other liquids prod, USDbn, % y-o-y 2.7 -10.2 -43.0 1.6 1.0 0.9

Crude, NGPL & other liquids prod, USDbn at USD50/bbl 18.7 18.4 18.1 17.7 17.3 16.9




Table: Oil Production (Colombia 2019-2024)

2019f 2020f 2021f 2022f 2023f 2024f

Crude, NGPL & other liquids prod, 000b/d 908.6 900.5 892.4 888.8 885.2 890.3

Crude, NGPL & other liquids prod, mn bbl/year 331.7 328.7 325.7 324.4 323.1 325.0

Crude, NGPL & other liquids prod, % y-o-y -1.9 -0.9 -0.9 -0.4 -0.4 0.6

Crude, NGPL & other liquids prod, USDbn 20.9 22.0 22.5 23.4 23.9 24.4

Crude, NGPL & other liquids prod, USDbn, % y-o-y -0.3 5.4 2.1 3.9 2.4 1.9







In 2013 Colombia achieved total liquids production growth of just over 1.0mn barrels per day (b/d) for the

first time, with nearly three-quarters of output attributed to the Llanos Orientales Basin. However,

following a period of substantial growth, a tendency toward smaller discoveries, coupled with a recent

uptick in security risk, will present downside pressure on future liquids production.

This trend will be exacerbated by low oil prices over the coming years, maintaining reduced rates of

upstream profitability. Specifically, we expect both WTI and Brent benchmark prices to not exceed an

average price of USD70 per barrel (bbl) through 2020 as a well supplied global market places continued

downward pressure on prices (see 'Comfortable Supply Will Bring Price Downside In H215', April 28). This

will encourage continued high-grading of upstream assets by international producers, stymieing

development of Colombian acreage.

Consequently, we have downgraded our Colombian oil production forecast, as decreased revenues from

lower oil prices undermine the ability of producers to maintain output levels. The two main oil producers in

Colombia, state-owned Ecopetrol and Pacific Rubiales, have both announced significant reductions to

their 2015 capital expenditure (capex) plans, weakening upstream prospects throughout the course of our

10-year forecast period. We now forecast Colombian oil production to experience a decrease of -2.0% year-

on-year (y-o-y) in 2015. We hold a bearish outlook on the sector across our 10-year forecast period, with

output declining by an average of -1.25% y-o-y through to 2024.



Oil Production Forecast

(2013-2024)

Crude, NGPL & other liquids prod, 000b/d (LHS)Crude, NGPL & other liquids prod, % y-o-y (RHS)

2013

2014

2015

f

2016

f

2017

f

2018

f

2019

f

2020

f

2021

f

2022

f

2023

f

2024

f

0

500

1,000

1,500

-5

-2.5

0

2.5

5

7.5


Colombia's increased recognition of shale and deepwater prospects has the potential to usher in a new

period of opportunity. However, much of the exploration, especially into Colombia's unconventional

resources, is in a nascent stage such that we have yet to account for its development in our current forecast.



Llanos Basin Still Major Producer

Colombian Oil Production By Basin, %

Source: Minminas, BMI

2015: Oil Production Growth To Decelerate Further

We do not believe the recent outperformance of Colombian crude production will be maintained. In May,

Ecopetrol - which produces over 60% of the country's total crude oil production - announced crude

production had exceeded expectations through the first four months of the year. Average non-consolidated

output reached 722,000b/d compared to a company target of 710,000b/d in 2015. However, this growth was

primarily attributed to a fall in pipeline attacks on infrastructure over this period, rather than an expansion

of upstream developments. The decline in attacks - from four through May 15 compared to 45 over the

same period in 2014 - are a direct result of the ongoing peace talks between the Colombian government and

the Fuerzas Armadas Revolucionarias de Colombia (FARC) as the insurgent group was largely responsible

for the uptick in attacks over the last several years (see 'Oil Production In Long-Term Decline', February

25).

However, these rates of output will prove increasingly difficult to maintain as producers within

Colombia refine and reduce their capital expenditures (capex) plans amid a lower oil price environment.



This was exhibited through the 82.5% decline in exploratory drilling and a 92.0% fall in seismic exploration

in Q115 versus Q114, as reported by the Colombian Petroleum Association (ACP). This decline occurred in

spite of recent efforts by the government to entice upstream investment, including reduced royalty rates on

certain assets and a higher oil price threshold on the windfall tax paid by producers. This underscores

waning interest for Colombia's upstream assets and supports our more bearish production outlook.

Furthermore, the recent rise in pipeline attacks will inhibit output growth such that we expect Colombian oil

production to contract in 2015. Ecopetrol and Pacific Rubiales, responsible for approximately 80% of total

oil production in Colombia, both forecast over 25% declines in crude output for the year, as a result of

lower investments. While this will translate into a substantial decrease in Colombian oil output, the

companies' estimates account for reductions from both domestic and foreign crude assets; we expect the

decline in Colombian output to be significantly lower.

Pipeline Attacks On The Rise

Colombia - Number Of Infrastructure Attacks By Insurgents

Source: Colombian Ministry of Defence, BMI



2016-2020: Production Declines To Continue Despite Modest Oil Price Increases

Over the medium term, output decline will decline as global oil prices begin to recover and producers focus

increased investment on boosting oil recovery from existing projects. We currently forecast WTI and Brent

crude benchmarks will steadily rise over the next several years, reaching USD62/bbl and USD70/bbl by

2020, respectively (see 'WTI-Brent Spread To Narrow', February 3). Increased profitability, coupled with

more targeted investments into field redevelopment and improved oil recovery techniques, will temper

production declines in key conventional areas such as the Chichimene and Castilla fields. However, total oil

production growth will remain negative over this period, given forthcoming production declines from the

Rubiales field, thereby averaging -2.0% y-o-y.

Modest Recovery Ahead

Front-Month Oil Price Forecasts

WTI, USD/bbl Brent, USD/bbl

2014 2015f 2016f 2017f 2018f 2019f 2020f 2021f 2022f 2023f

40

60

80

100

120

f = BMI forecast. Source: BMI, Bloomberg

Furthermore, Colombia's falling prospectivity below ground - with the repeatedly small size of discoveries

made - will temper investor interest from the international community throughout this period (see

'Lacklustre Auction Points To Declining Hydrocarbon Growth', July 30 2014). This growing disinterest will



negatively impact reserves growth, with exploration activity declining in spite of the country's favourable

investment environment.

2021-2024: Natural Depletion Rates Outweigh Production Gains

By 2021, a multi-year deficit of investment will see oil production declines begin to stagnate, averaging

-0.4% y-o-y through to the end of our forecast period. A lack of new production slated to come online will

combine with increased natural depletion rates at major producing fields to undercut overall output levels.

Despite a sizeable resource base in Colombia, more costly unconventional developments will also fail to

come online during this period. On February 10, ExxonMobil decided to defer its shale exploration plans in

Colombia, alongside Shell and ConocoPhillips. With only one of the 18 unconventional blocks offered in

the 2014 hydrocarbon licensing round having received a bid, extensive development of the country's liquid

shale resources is likely to remain elusive.

Potential, Although Still Lagging The Region's Big Guns

Latin America - Technically Recoverable Shale Oil Resources, mn bbl

Source: EIA



While we hold a conservative production outlook on Colombia, we note there are downside risks to our

forecasts including:

■ Lower Oil Price Environment: We expect Brent prices will hit a low in 2015 as a result of a supplysurplus, and will rise thereafter, averaging between USD55-72/bbl for the remainder of our forecastperiod (see 'WTI-Brent Spread To Narrow', February 3). As the benchmark rate for Colombian crude, asustained discount in this benchmark rate would undermine the ability of current investors to continueproducing, weakening our short-term outlook further.

■ Slow Permitting: In general, we believe Colombia has one of the better operating environments in theregion, but delays for obtaining environmental and drilling permits at new projects have often been citedas a major obstacle.

■ Insufficient Infrastructure: A lack of efficient transportation infrastructure has constrained thecountry's output. While the completion of the bicentennial pipeline will likely reduce this pressure, wenote the southern region of the country remains remarkably underserved.

■ Political Risk: Although the environment has improved significantly over the past decade, security risksremain a significant concern. FARC rebels to threaten the oil industry with continued attacks on pipelineinfrastructure. Ecopetrol estimates pipeline attacks cost the company 20,000 b/d in lostproduction, amounting to a total loss of USD552mn from January through September 2014, not includingenvironmental expenses

That said, we believe the negotiations will conclude in the next several quarters amid increased efforts by

both sides to come to a resolution. However, we remain sceptical that they will yield a dramatic

improvement in the short-to-medium term as progress is slow and vulnerable to delays. Moreover, an

agreement would not necessary guarantee a definitive end to the violence, given the high risk of

fragmentation within the group. Second, we have seen poor relations between oil companies and labour

groups lead to protests which have slowed production, a trend that is likely to continue in the near term.

■ Rising Competition: The forthcoming liberalization of neighbouring Mexico's hydrocarbon sector, inaddition to consistently large discoveries in Brazil's presalt regions, has created alternative investmentopportunities for investment in the sector. Although Colombia has highly-favourable contractual terms toinvest, large proven resource basins in other regional oil producing countries will likely undermineinvestment opportunities in Colombia's oil sector.

Indeed, Ecopetrol has recently announced plans to participate in Mexico's historic Round One licensing

auction next year, highlighting the company's need to further diversify its operations abroad (see 'Ecopetrol

Eyes Mexico To Boost Stagnant Production', October 1 2014). Although Ecopetrol already has operations

in Brazil, Peru, the US Gulf Coast, and recently Angola, the addition of Mexican onshore acreage would

present a unique opportunity for the company to expand its regional presence in an important oil-producing

country, but underscores declining investment opportunities at home.



Upstream Production - Gas

BMI View: Colombian natural gas production will be weak over the next decade as decreased profitability

from lower oil prices will reduce upstream investment, undermining upstream projects over the coming

decade.

Table: Gas Production (Colombia 2013-2018)

2013e 2014e 2015f 2016f 2017f 2018f

Dry natural gas production, bcm 10.2 10.3 10.2 10.1 9.9 9.8

Dry natural gas production, bcm, % y-o-y 0.0 1.5 -1.0 -1.5 -1.5 -1.0

Dry natural gas production, USDbn 5.4 5.0 2.9 2.9 3.0 3.0

Dry natural gas production, USDbn, % y-o-y -3.3 -7.7 -42.4 2.0 1.9 2.3

Dry natural gas production, USDbn at USD6/mn btu 2.2 2.2 2.2 2.2 2.1 2.1



Dry natural gas production, % of domestic consumption 134.0 124.7 116.5 109.3 102.5 97.6


Table: Gas Production (Colombia 2019-2024)

2019f 2020f 2021f 2022f 2023f 2024f

Dry natural gas production, bcm 9.8 9.9 10.0 10.1 10.2 10.4

Dry natural gas production, bcm, % y-o-y 0.0 0.5 1.0 1.0 1.5 1.5

Dry natural gas production, USDbn 3.1 3.3 3.4 3.6 3.8 3.9

Dry natural gas production, USDbn, % y-o-y 1.6 6.9 4.0 5.4 4.3 2.9




Dry natural gas production, % of domestic consumption 93.8 90.7 88.9 87.2 85.9 84.7


Natural gas production growth in Colombia will remain limited over the course of our 10-year forecast

period. Major natural gas producers have announced significant spending cuts, which will impact ongoing



and future upstream developments in Colombia. Cutbacks will be particularly acute in associated gas fields,

which represent the majority of natural production. In addition, repeatedly small discoveries will weaken

long-term investor enthusiasm, driving negative reserves replacement ratios over the coming decade.

We forecast Colombian natural gas output to decline by an average rate of 1.3% year-on-year (y-o-y) over

the next two years as producers recalibrate their capex within a lower oil price environment. Beginning in

2020, natural gas production will increase modestly by 0.5% y-o-y through to 2024 as crude prices begin to

recover, encouraging greater upstream investment. We caution, however, that natural gas consumption will

outpace production over the next decade, resulting in a domestic supply deficit by 2018.

Gas Production Forecast

(2013-2024)

Dry natural gas production, bcm (LHS)Dry natural gas production, bcm, % y-o-y (RHS)

2013

e

2014

e

2015

f

2016

f

2017

f

2018

f

2019

f

2020

f

2021

f

2022

f

2023

f

2024

f

0

5

10

15

-2

-1

0

1

2


Colombian natural gas output will suffer from a sharp decline in upstream investment, with the largest

impacts of this shift observed in 2015 and 2016, as producers reassess their production priorities. Notably,

investment into Colombia's Caribbean natural gas assets - which produced approximately 46.0% of the

country's total supply in 2014 and provide nearly all of the country's export capacity - will decline.



As the largest natural gas producers in the country, the reduction of Chevron and state-owned Ecopetrol's

2015 capex plans by 13% and 26% respectively, will damage overall output levels. Specifically, the

offshore Chuchupa field, which is Colombia's largest non-associated field, is operated through the Guajira

Association joint venture between the two companies, along with the Ballena and Riohacha onshore fields.

Production of associated gas in the Cusiana and Cupiaga fields, which are the biggest contributors to gas

production in the country, representing a combined 37.5% of Colombia's total output, will also suffer amid

declining investment into the oil sector (see 'Oil Production In Long Term Decline', February 24). With

approximately 56.0% of the country's natural gas reinjected to optimise oil production efforts, this practice

will become increasingly important to oil producers in an effort to maximise value from existing crude

assets.

While we expect global oil prices to recover over the next decade, total investment into the hydrocarbon

sector will remain below historic levels, hindering natural gas production growth for the foreseeable future.

Beginning in 2020, we believe natural gas output will begin to rise steadily as recovering Brent and WTI

prices encourage further development of upstream assets. We forecast Brent, the benchmark for Colombian

crude, will increase from an average of USD55/bbl in 2015 to USD70/bbl by 2020 (see 'Comfortable

Supply Will Bring Price Downside In H215', April 28). This will support greater production of natural gas

from associated fields through the latter half of our forecast period, albeit at more modest rates than in years

past.

Furthermore, while output from major non-associated gas fields in the northern Guajira region falls by an

estimated 13.0% per year, investments into new prospects and improved recovery will mitigate production

declines. Specifically, Canacol announced additional investments into the Lower Magdalena region

following their acquisition of the VIM 5 and VIM 19 exploration and production contracts from OGX in

December 2014. Canacol expects to increase its total natural gas output from 0.6mn cubic metres per day

(mcm/d) in 2015 to 5.1mcm/d by 2017, reflected in our long-term production outlook.

However, output growth will be unable to repeat the success of years past whereby production rose by an

average rate of 7.0% y-o-y between 2000 and 2010. This is due to declining international interest in

Colombian hydrocarbon assets as a result of weak below-ground prospects, despite having one of the most

favourable investment environments in Latin America. Furthermore, a weaker domestic currency, which our

Country Risk team forecast will average COP2,320/USD over the next decade, will not provide a sufficient

incentive to increase upstream investment, as producers seek higher returns from more hydrocarbon-rich

countries (see 'COP: Struggling Oil Sector To Weigh On Peso', October 6 2014).



Moreover, the Colombian government's attempts to support the development of its unconventional

resources will prove unsuccessful. With one of the most favourable investment environments in the region,

Colombia was able to attract significant investment into the sector over the past decade. The country

published its long-awaited guidelines for exploration using fracking technology in 2014, with preferential

terms for shale resources including a 40% reduction in royalties. However, investor sentiment has soured

over the past year as repeatedly small finds and attacks on midstream infrastructure have weakened the

overall outlook for further upstream developments (see 'Oil Production In Long Term Decline', February

25).

Refining

BMI View: Colombia's downstream sector will expand in the coming quarters with the completion of

planned upgrades to the two largest refining facilities. This will raise the capacity of its five state-owned

refineries from 336,000 barrels per day (b/d) to 471,000b/d. The proposed construction of a sixth refinery

in 2015 poses upside risk to our current forecast.

Table: Refining Capacity and Refined Products Production (Colombia 2013-2018)

2013e 2014e 2015f 2016f 2017f 2018f

Crude oil refining capacity, 000b/d 335.9 335.9 420.9 420.9 420.9 420.9

Crude oil refining capacity, % y-o-y 0.0 0.0 25.3 0.0 0.0 0.0

Crude oil refining capacity, utilisation, % 103.4 103.4 89.7 92.4 98.2 100.5

Refined products production & ethanol, 000b/d 347.2 347.2 377.4 389.0 413.2 422.9

Refined products production & ethanol, % y-o-y 2.0 0.0 8.7 3.1 6.2 2.4

Refined products production, 000b/d 363.1 363.6 394.3 406.4 431.1 441.4

Refined products production, % y-o-y 2.0 0.1 8.4 3.1 6.1 2.4




Table: Refining Capacity and Refined Products Production (Colombia 2019-2024)

2019f 2020f 2021f 2022f 2023f 2024f

Crude oil refining capacity, 000b/d 420.9 420.9 420.9 420.9 420.9 420.9

Crude oil refining capacity, % y-o-y 0.0 0.0 0.0 0.0 0.0 0.0

Crude oil refining capacity, utilisation, % 102.9 105.4 108.0 110.7 113.6 116.5

Refined products production & ethanol, 000b/d 433.1 443.6 454.6 466.1 478.0 490.4

Refined products production & ethanol, % y-o-y 2.4 2.4 2.5 2.5 2.6 2.6

Refined products production, 000b/d 452.1 463.2 474.8 486.8 499.4 512.5

Refined products production, % y-o-y 2.4 2.5 2.5 2.5 2.6 2.6


According to state-owned NOC Ecopetrol's latest company data, Colombia's crude distillation capacity is

currently at 335,850b/d. With the NOC in the midst of a refinery expansion programme, we are forecasting

an increase in nameplate refining capacity to 420,850b/d in 2015 from updates to the Barrancabermeja and

Reficar facilities.

The Reficar refinery in Cartagena is currently undergoing an expansion and modernisation project that will

increase its total capacity from 80,000b/d to 165,000 b/d while improving the fuel quality to meet

international environmental specifications. As the country's second-largest refining facility, the doubling of

its overall capacity will significantly increase Colombia's ability to process refined fuels.

Colombia's largest refinery, Ecopetrol's Barrancabermeja facility in Bucaramanga, has a current capacity of

250,000b/d. With the refinery in the midst of a modernization project, the facility is planning on increasing

its capacity to 300,000b/d with plans for completion in H115.

The announcement of a potential sixth facility by independently-owned Petróleos del Llano-Llanopetrol

would contribute an additional 260,000b/d in refining capacity, posing upside risk our current downstream

projections. Due to limited details regarding financing and production prospects, we are waiting for more

information before upgrading our forecast.



Refining Capacity Forecast

(2013-2024)

Crude oil refining capacity, 000b/d (LHS)Refined products production & ethanol, 000b/d (LHS)Crude oil refining capacity, utilisation, % (RHS)

2013

e

2014

e

2015

f

2016

f

2017

f

2018

f

2019

f

2020

f

2021

f

2022

f

2023

f

2024

f

0

200

400

600

80

90

100

110

120


With regard to refined fuel production, an interesting trend we are watching is Colombia's LPG production

potential growth over the medium term. The government is seeking to increase production in the coming

years and has enacted clear policies and incentives to support its growth.

Currently, about 67% of the country's LPG production is obtained through refining crude oil. The remaining

portion is derived from dry natural gas but we could begin to see this trend reverse. As highlighted by a

recent UPME report, we could see a significant uptick in LPG produced from gas processing alongside

Colombia's gas production growth and forecast total LPG output to increase to nearly 22,000b/d by 2023.



Refined Fuels Consumption

BMI View: Colombia's demand for fuels will remain robust, growing an average rate of 2.5% per year over

our forecast period. However, the government's efforts to eliminate the remaining fuel price subsidies have

increased illegal imports of heavily subsidised Venezuelan petroleum, and these are likely to continue,

despite Venezuela's nightly closure of the porous border.

Table: Refined Products Consumption* (Colombia 2013-2018)

2013 2014e 2015f 2016f 2017f 2018f

Refined products consumption, 000b/d 324.0 329.4 334.9 340.6 346.4 353.3

Refined products consumption, % y-o-y 0.9 1.7 1.7 1.7 1.7 2.0


Table: Refined Products Consumption* (Colombia 2019-2024)

2019f 2020f 2021f 2022f 2023f 2024f

Refined products consumption, 000b/d 360.4 367.7 375.2 383.0 391.0 399.2

Refined products consumption, % y-o-y 2.0 2.0 2.0 2.1 2.1 2.1


The latest EIA figures indicate total refined product consumption in Colombia stood at 324,000 barrels per

day (b/d) in 2013. Owning to continued economic growth over the coming years, albeit at a more modest

rate than in years past, we forecast continued fuel consumption growth at an average rate of 2.2% per year,

reaching 360,400b/d in 2019 and 399,200b/d by 2024 ,

In the coming quarters, we see demand for imported refined products, especially diesel and to a lesser extent

gasoline, to remain elevated. This is mostly due to the continued price disparity between Colombian and

Venezuelan fuel whereby heavily subsidised gasoline and diesel have encouraged illegal shipments of fuel

into Colombia, totalling upwards of 100,000b/d.



Furthermore, planned upgrades to existing downstream facilities have been called into question due to

declining investment funding amid a lower oil price environment. Given Colombia's crude production is

growing steadily heavier, refinery utilisation rates would steady decline in the absence of further upgrades.

Refined Products Production And Consumption Forecast

(2013-2024)

Refined products production & ethanol, 000b/d (LHS)Refined products consumption, 000b/d (LHS)Refined products consumption, % y-o-y (RHS)

2013

e

2014

e

2015

f

2016

f

2017

f

2018

f

2019

f

2020

f

2021

f

2022

f

2023

f

2024

f

0

200

400

600

1

1.5

2

0.5

2.5


Diesel has been particularly vulnerable to increased imports given the steady rise in its use for the

transportation of cargo and passengers in recent years. Moreover, with Colombia enacting legislation to

limit sulphur content in diesel fuel from 500 parts per million (ppm) to 50 ppm, the country's total available

supply for domestic consumption has declined in recent years.

While Colombia reportedly imported 74,000b/d of diesel in 2013, we believe this trend will improve over

the next several years as Colombia's Reficar refinery upgrade is completed in 2015. This will not only

restore output levels, but also produce cleaner fuels for domestic use.

With the Colombian Ministry of Mines and Energy (MME) attempting to gradually eliminate fuel subsidies,

the price of diesel, and more significantly gasoline, have risen since 2003. However, due to political



pressures, the government has been unable to completely remove the subsidy as of yet. Moreover, on

February 23, the government announced a COP300 decline in the price of both gasoline and diesel fuels in

an attempt to curb inflation and bring trends closer in line to international prices.

This policy will help mitigate the downward pressure on consumption levels amid less robust

macroeconomic growth. In addition, this could reduce incentives to purchase illegal imports, although we

believe this is unlikely given the significant price differential between Colombian and Venezuelan fuel.

Over the longer term, we believe fuel consumption growth will increase beyond 2017 as Colombia's

economy begins to recover. However, demand will remain relatively weak amid less robust economic

growth compared to years past (see 'Weaker Oil Sector To Dampen Growth', December 9 2014).

Gas Consumption

BMI View: Colombia's gas consumption will increase an average rate of 4.0% per year over the course of

our 10-year forecast period. Recent subsidies for domestic natural gas consumption are poised to boost

long-term consumption rates as the country seeks to reduce its heavy reliance on intermittent hydropower.

Table: Gas Consumption (Colombia 2013-2018)

2013 2014e 2015f 2016f 2017f 2018f

Dry natural gas consumption, bcm 7.6 8.3 8.8 9.2 9.7 10.1

Dry natural gas consumption, % y-o-y -0.7 9.0 6.0 5.0 5.0 4.0

Dry natural gas consumption, USDbn 4.0 4.0 2.4 2.7 2.9 3.1

Dry natural gas consumption, USDbn % y-o-y -3.9 -0.9 -38.4 8.8 8.6 7.5




Table: Gas Consumption (Colombia 2019-2024)

2019f 2020f 2021f 2022f 2023f 2024f

Dry natural gas consumption, bcm 10.5 10.9 11.2 11.6 11.9 12.3

Dry natural gas consumption, % y-o-y 4.0 4.0 3.0 3.0 3.0 3.0

Dry natural gas consumption, USDbn 3.3 3.6 3.9 4.1 4.4 4.6

Dry natural gas consumption, USDbn % y-o-y 5.7 10.6 6.1 7.5 5.9 4.4


Colombia's consumption of natural gas will expand an average of 4.0% over the next decade, from an

estimated 8.8bn cubic metres (bcm) in 2015 to 12.3bcm by 2024. While Colombian real GDP growth will

face headwinds due to a weaker hydrocarbon sector, our Country Risk team expects average growth

of 3.5% year-on-year between 2015 and 2024 as a result of continued growth in the infrastructure,

construction, and mining sectors (see 'Oil Sector Weakness Will Prompt Further Economic Deterioration',

April 15).

As such, we believe demand for electricity will remain robust, encouraging the continued use of natural gas-

fired generation to mitigate the unreliability of hydropower electricity (see 'LNG Imports Mitigate Power

Mix Uncertainty', November 12 2014).

Colombia's oil production requires the majority of the country's produced gas, nearly 60%, to be re-injected

to bolster recovery efforts which will become increasingly prevalent as producers seek to enhance oil

recovery efforts amid declining exploration investment. In addition, the Barrancabermeja and

Reficar refineries require a significant supply of natural gas to power their daily operations.



Gas Production And Consumption Forecast

(2013-2024)

Dry natural gas production, bcm (LHS)Dry natural gas consumption, bcm (LHS)Dry natural gas consumption, % y-o-y (RHS)

2013

e

2014

e

2015

f

2016

f

2017

f

2018

f

2019

f

2020

f

2021

f

2022

f

2023

f

2024

f

0

5

10

15

0

5

10

-5


The government's 2011 Natural Gas Mass Consumption Plan aims to increase consumer gas use, especially

for electricity generation and public transportation, while decreasing domestic dependency on hydropower.

Although there are virtually no plans for to add gas-fired power generation facilities over the next decade,

we believe natural gas consumption growth will outpace production gains over the course of the next

decade, averaging 4.0% y-o-y versus 0.8% y-o-y through 2024, respectively. This will undermine

Colombia's ambitious export plans, as exhibited by the delay of Pacific Rubiales' 0.5mn tonnes per annum

(mtpa) floating LNG project on January 29. This trend will convert Colombia into a net importer of natural

gas by 2017, with the deficit to continue growing thereafter.

Specifically, power demand will increase in the industrial and residential sectors, due in part to government

subsidies enacted in 2013 to encourage consumption in underprivileged areas (see 'Natural Gas On The

Upswing', September 4 2014). Moreover, Colombia's growing Petrochemical sector will demand greater

quantities of natural gas over the coming decade due to growing demand for these goods domestically.



We highlight upside risks to our forecast based on weather related occurrences. Specifically, with Colombia

reliant on hydropower for nearly 75% of the country's total power generation, it is highly vulnerable to

droughts. As such, we have observed huge demand increases for natural gas in periods of low rain as the

country is forced to turn to other sources of power.

As a result of declining hydropower capacity, state-owned Ecopetrol suspended gas shipments to Venezuela

as a result of increased domestic demand. While pipeline exports resumed in 2015, enduring concerns over

the potential for short-term surges in demand explain why Colombia awarded the country's first LNG

import terminal in November 2014. A second LNG import facility has since been proposed as well.

Trade - Oil

BMI View: Colombian exports of crude oil will decline over the next 10 years due to steadily falling

production growth coupled with rising domestic consumption. Exports of refined petroleum products will

increase throughout the course of our forecast period as planned upgrades to the country's Reficar refinery

are completed in 2015.

Table: Crude Oil Net Exports (Colombia 2013-2018)

2013e 2014e 2015f 2016f 2017f 2018f

Crude & other liquids net export, 000b/d 674.8 662.5 613.1 582.7 535.4 503.1

Crude & other liquids net export, % y-o-y 8.5 -1.8 -7.5 -5.0 -8.1 -6.0

Crude & other liquids net export, USDbn 26.1 23.3 12.5 12.3 11.7 11.4

Crude & other liquids net export, USDbn, % y-o-y 4.9 -10.7 -46.2 -1.6 -5.0 -2.9

Crude & other liquids net export, USDbn at USD50/bbl 12.3 12.1 11.2 10.6 9.8 9.2






Table: Crude Oil Net Exports (Colombia 2019-2024)

2019f 2020f 2021f 2022f 2023f 2024f

Crude & other liquids net export, 000b/d 475.6 456.8 437.8 422.7 407.2 399.9

Crude & other liquids net export, % y-o-y -5.5 -3.9 -4.2 -3.4 -3.7 -1.8

Crude & other liquids net export, USDbn 10.9 11.2 11.0 11.1 11.0 10.9

Crude & other liquids net export, USDbn, % y-o-y -4.0 2.2 -1.3 0.8 -1.0 -0.5





Crude Oil

We forecast Colombian net crude exports will fall at an average rate of 4.8% per year over the course of our

10-year period, from 613,000barrels per day (b/d) in 2015 to 399,900b/d by 2024. This decline is primarily

due to weaker production growth from less upstream investment amid lower oil prices. Moreover, a sizeable

share of crude has been intercepted by insurgent attacks, leading Ecopetrol to announce a logistical

overview of its transportation strategy in June 2015.

After a tremendous surge in production in 2003-2013, crude output has slowed as the lack of large

discoveries has made it increasingly difficult to sustain double digit growth. Consumption, however, will

steadily rise over our forecast period owing to Colombia's continued macroeconomic strength, resulting in a

smaller proportion of available crude oil for export.



Crude Oil Net Exports Forecast

(2013-2024)

Crude & other liquids net export, 000b/d (LHS)Crude & other liquids net export, % y-o-y (RHS)

2013

e

2014

e

2015

f

2016

f

2017

f

2018

f

2019

f

2020

f

2021

f

2022

f

2023

f

2024

f

0

250

500

750

-10

-5

0

5

10


The primary export destination for Colombian crude oil is the US, followed by Panama, China, and Spain.

Chinese exports will likely make up a larger share of future exports as the US continues to displace imports

with domestic and Canadian crude (see 'Latin American Crude Cannot Rely On US Market', May 7).

Notably, in June 2015 Ecopetrol announced it had signed a second memorandum of understanding with

Hyundai Oilbank for the sale of 1mn barrels of Castilla-blend heavy crude to be shipped in July.

Moreover, in September 2014, crude shipments from Colombia to China surged 389.6% year-on-year (y-o-

y) as China reduced its deliveries of Saudi Arabian crude by 2.7%. This was a result of declining global oil

prices as the price of Colombian crude relative to output proved more favourable than Saudi crude at

USD94.56 per barrel (bbl) vs. USD102.30/bbl, respectively.

In addition, the two countries signed a preliminary agreement in 2012 to finance a 600,000 b/d pipeline,

reflecting China's growing demand for oil. While no major developments have been made since, growing

export volumes to China point to changing market dynamics amid the lower oil price environment.



Table: Refined Fuels Net Exports (Colombia 2013-2018)

2013e 2014e 2015f 2016f 2017f 2018f

Refined products net exports, 000b/d 23.2 17.8 42.5 48.4 66.8 69.6

Refined products net exports, % y-o-y 20.9 -23.2 138.3 13.9 38.0 4.3

Refined products net exports, USDbn 0.4 0.3 0.6 0.7 1.2 1.2

Refined products net exports, USD, % y-o-y 21.5 -17.9 96.4 13.3 71.8 1.7

Refined products net exports, USDbn at USD50/bbl 0.2 0.2 0.5 0.6 0.9 0.9




Table: Refined Fuels Net Exports (Colombia 2019-2024)

2019f 2020f 2021f 2022f 2023f 2024f

Refined products net exports, 000b/d 72.7 75.9 79.4 83.1 87.0 91.2

Refined products net exports, % y-o-y 4.4 4.5 4.6 4.7 4.7 4.8

Refined products net exports, USDbn 1.3 1.4 1.5 1.6 1.7 1.8

Refined products net exports, USD, % y-o-y 7.2 6.5 6.7 7.2 7.1 7.1





Refined Petroleum Products

Colombia's net refined oil exports are expected to increase an average rate of 19.0% y-o-y from 42,500b/d

in 2015 to 91,240b/d in 2024. This growth is driven primarily by increased refining capacity as the Reficar

and Barrancabermeja facilities complete planned expansions and upgrades by 2016. Consumption of refined

fuels will rise in the coming years, but at a less rapid pace than total output.

The government's recently announced delay of the Barrancabermeja upgrade project poses downside risk to

our forecast. However, given the project's limited effects on total petroleum production, raising utilisation

rates by approximately 5.0%, an indefinite suspension would not derail the upward trend of our forecast.



Refined Products Net Exports Forecast

(2013-2024)

Refined products net exports, 000b/d (LHS)Refined products net exports, % y-o-y (RHS)

2013

e

2014

e

2015

f

2016

f

2017

f

2018

f

2019

f

2020

f

2021

f

2022

f

2023

f

2024

f

0

25

50

75

100

-50

0

50

100

150


Although Colombia is a net exporter of refined products, it currently imports some diesel as domestic

demand outweighs supply. Higher prices from declining fuel subsidies have also increased illegal shipments

of cheap Venezuelan fuel, resulting in increased efforts to plug the notoriously porous border over the past

several months.



Table: Total Net Oil Exports - Crude and Products (Colombia 2013-2018)

2013e 2014e 2015f 2016f 2017f 2018f

Total net oil exports (crude & products), 000b/d 704.5 686.8 662.3 638.0 609.3 580.1

Total net oil exports (crude & products), % y-o-y 8.7 -2.5 -3.6 -3.7 -4.5 -4.8

Total net oil exports (crude & products), USDbn 26.5 23.6 13.1 13.0 12.9 12.6

Total net oil exports (crude & products), USDbn, % y-o-y 5.1 -10.8 -44.3 -0.9 -0.9 -2.5

Total net oil exports (crude & prod.), USDbn at USD50/bbl 12.5 12.2 11.7 11.2 10.7 10.1




Table: Total Net Oil Exports - Crude and Products (Colombia 2019-2024)

2019f 2020f 2021f 2022f 2023f 2024f

Total net oil exports (crude & products), 000b/d 555.8 540.5 525.1 514.0 502.7 499.8

Total net oil exports (crude & products), % y-o-y -4.2 -2.7 -2.8 -2.1 -2.2 -0.6

Total net oil exports (crude & products), USDbn 12.2 12.5 12.5 12.7 12.7 12.8

Total net oil exports (crude & products), USDbn, % y-o-y -2.9 2.6 -0.4 1.5 0.0 0.5







Trade - Gas (Pipeline and LNG)

BMI View: Colombian exports of natural gas will decline substantially over the course of our forecast

period as a result of declining output coupled with robust domestic demand. Efforts to increase domestic

gas consumption will turn the country into a net importer by 2018.

Table: Gas Net Exports (Colombia 2013-2018)

2013e 2014e 2015f 2016f 2017f 2018f

Dry natural gas net exports, bcm 2.6 2.1 1.5 0.9 0.2 -0.2

Dry natural gas net exports, % y-o-y 2.0 -20.6 -29.3 -40.9 -71.5 -199.4

Dry natural gas net exports, USDbn 1.4 1.0 0.4 0.2 0.1 -0.1

Dry natural gas net exports, USDbn % y-o-y -1.3 -27.8 -58.9 -38.8 -70.5 -202.7

Dry natural gas net exports, at USD50/bbl USDbn 0.6 0.5 0.4 0.2 0.1 -0.1

Dry natural gas net exports, at USD100/bbl USDbn 1.3 1.0 0.7 0.4 0.1 -0.1

Pipeline gas net exports, bcm 2.6 2.1 1.5 1.9 1.2 1.3

Pipeline gas net exports, % y-o-y 2.0 -20.6 -29.3 28.1 -33.0 1.0

Pipeline gas net exports, % of total 100.0 100.0 100.0 216.7 509.4 -518.0

Pipeline gas net exports, USDbn 1.4 1.0 0.4 0.5 0.4 0.4

Pipeline gas net exports, USDbn % y-o-y -1.3 -27.8 -58.9 32.6 -30.7 4.4

LNG net exports, bcm 0.0 0.0 0.0 -1.0 -1.0 -1.5

LNG net exports, % of total gas exports 0.0 0.0 0.0 -116.7 -409.4 618.0

LNG net exports, USDbn 0.0 0.0 0.0 -0.3 -0.3 -0.5




Table: Gas Net Exports (Colombia 2019-2024)

2019f 2020f 2021f 2022f 2023f 2024f

Dry natural gas net exports, bcm -0.6 -1.0 -1.2 -1.5 -1.7 -1.9

Dry natural gas net exports, % y-o-y 166.1 57.3 22.5 19.0 13.2 12.2

Dry natural gas net exports, USDbn -0.2 -0.3 -0.4 -0.5 -0.6 -0.7

Dry natural gas net exports, USDbn % y-o-y 170.4 67.3 26.1 24.2 16.4 13.7

Dry natural gas net exports, at USD50/bbl USDbn -0.2 -0.3 -0.3 -0.4 -0.4 -0.5

Dry natural gas net exports, at USD100/bbl USDbn -0.3 -0.5 -0.6 -0.7 -0.8 -0.9

Pipeline gas net exports, bcm 0.9 0.5 0.8 0.5 0.3 0.1

Pipeline gas net exports, % y-o-y -32.1 -43.3 56.2 -31.4 -37.7 -63.0

Pipeline gas net exports, % of total -132.3 -47.7 -60.8 -35.0 -19.3 -6.4

Pipeline gas net exports, USDbn 0.3 0.2 0.3 0.2 0.1 0.0

Pipeline gas net exports, USDbn % y-o-y -31.0 -39.7 60.8 -28.4 -36.0 -62.6

LNG net exports, bcm -1.5 -1.5 -2.0 -2.0 -2.0 -2.0

LNG net exports, % of total gas exports 232.3 147.7 160.8 135.0 119.3 106.4

LNG net exports, USDbn -0.5 -0.5 -0.7 -0.8 -0.8 -0.8


Net natural gas exports will decline over the course of our forecast period from 1.45bn cubic metres (bcm)

in 2015 to -1.88bcm in 2024. This decline is driven primarily by falling rates of natural gas

production following the sharp decline in upstream investment from lower oil prices. However, this

dynamic also reflects rising consumption in the wake of price subsidies for low-income earners, resulting in

an overall deficit in the near term,

With the rise in private investment in 2007-2008, Colombia's total natural gas output grew enough to

outpace consumption and allow for exports. Although the majority of production - about 56% of total output

- is reinjected to enhance oil recovery, exported quantities grew steadily until 2014.



Gas Net Exports Forecast

(2013-2024)

Pipeline gas net exports, bcm LNG net exports, bcm

2013

2014

e

2015

f

2016

f

2017

f

2018

f

2019

f

2020

f

2021

f

2022

f

2023

f

2024

f

-2

0

2

-4

4


Colombia's primary export destination is neighbouring Venezuela. Following the construction of the Trans-

Caribbean Gas pipeline in 2007, up to 250,000mn cubic feet per day of Colombian natural gas has been sent

from the northeast region into western Venezuela, steadily increasing in send-out volume as Venezuelan

demand for natural gas thermal power plants and reinjection for oil production increases.

While the pipeline was subsequently extended into Ecuador and Panama in 2011, the vast majority of

exported quantities continue to be sent to Venezuela as they struggle to develop their own domestic

resources. The drop in total exports in 2014 is attributed to the suspension of gas shipments to Venezuela

that began in May as a result of severe drought conditions and expectations of El Niño weather patterns

which increased domestic demand requirements. As of the start of 2015, pipeline exports to Venezuela have

since resumed.

Although Colombia has high hopes of becoming a 'gas hub' for the Andean region, having developed a

series of cost-effective LNG export plans over the past several years, we believe the country will be unable

to achieve this goal. Specifically, while we expect global oil prices to recover over the next decade, total



investment into the hydrocarbon sector will remain below historic levels, hindering natural gas production

growth for the foreseeable future. This will undermine Colombia's ambitious export plans, as exhibited by

the delay of Pacific Rubiales' 0.5mn tonnes per annum (mtpa) floating LNG project in January 2015. This

trend will convert Colombia into a net importer of natural gas by 2018, with the deficit to continue growing

thereafter.

In an effort to mitigate their power mix uncertainty, Colombia awarded the contract for the country's first

LNG import terminal to Höegh LNG in November 2014. This facility advances the country's desire to

increase natural gas supplies to decrease its heavy reliance on hydropower electricity generation. The

contract allows Höegh LNG to operate the terminal for 20 years but includes options to reduce the term to

five, 10, or 15 years. Although the project is subject to SPEC obtaining environmental licensing, the unit is

currently under construction and is expected to start up in mid-2016 (see 'LNG Imports Mitigate Power Mix

Uncertainty', November 12 2014).

With a capacity of 3.6bcm per year, the new facility will serve to mitigate the effects of adverse weather

conditions which reduce hydropower reservoirs, and help offset declining reserve potential. This will also

allow Colombia to expand its use of natural gas for power generation (see 'South American Power: Natural

Gas To Grow In Importance', September 30 2014).



Hydropower To Continue Dominating The Electricity Mix

Colombia - Power Generation By Source

Coal, TWh Natural Gas, TWh Generation, Oil, TWhHydropower, TWh Non-Hydropower Renewables, TWh

2012

e

2013

e

2014

e

2015

f

2016

f

2017

f

2018

f

2019

f

2020

f

2021

f

2022

f

2023

f

2024

f

0

25

50

75

100


A second LNG import terminal was proposed in June 2015, supports our view that Colombia is seeking to

increase natural gas consumption to reduce its heavy reliance on hydropower electricity. While our Power

Team estimates that Colombia will remain highly dependent on hydropower for the foreseeable future, the

use of natural gas a source of peaking demand will come under pressure as domestic supplies wane (see

'LNG Imports Mitigate Power Mix Uncertainty', November 12 2014).

Strong macroeconomic activity, with real GDP growth averaging 3.5% year-on-year (y-o-y) through 2024,

will boost power demand within Colombia, particularly from the expanding mining and manufacturing

industries (see 'Positive Power Outlook Resilient To Lower Oil Prices', March 9). As such, we expect

Colombia to become increasingly reliant on imported supplies of natural gas in the absence of large

hydropower capacity additions. The first such facility, the 2,400MW Ituango project, is not slated to be

commissioned before 2021. A heavier reliance on natural gas will be particularly prevalent in 2015 as dryer

weather from El Niño reduces hydropower supply, threatening the suspension of pipeline exports to

Venezuela before the end of this year



Industry Risk Reward Index

Latin America - Risk/Reward Index

BMI View: BMI's Q315 Latin American Oil & Gas Risk/Reward Index (RRIs) saw a marked reduction in

scores across several countries owning to the negative effects on project development amid a lower oil

price environment. Brazil and Colombia, long top contenders within the sector, will struggle to maintain

their top rankings over the next several quarters due to declining growth prospects. Ecuador, Bolivia, and

Venezuela will remain regional underperformers as continued political uncertainty, resource nationalism

and an unfavourable regulatory environment weigh on upstream prospectivity. Historic energy sector

reforms in Mexico and regulatory improvements in Argentina could merit a significant shift in these

countries' future rankings.

The ranking order of our overall Oil & Gas Risk/Reward Index (RRI) for Latin America has

experienced limited change this quarter. However, the negative effects of lower oil prices have begun to

materialise within our upstream and downstream indices.

Within our current rankings, important long-term trends continue to take shape, which manifest themselves

through revisions to our regional scores as significant above-ground changes occur. Namely, we have long

anticipated downside risk to perennial outperformers Brazil and Colombia as both countries confront

growing headwinds to upstream development. In addition, we expect lower-ranking Mexico and Argentina

will climb up the ranks over the coming quarters. In Q315, these expectations have begun to take shape

within our regional RRI.



Table: Latin America Composite Risk/Reward Index, Out of 100

Upstream R/R Index Downstream R/R Index Oil & Gas R/R Index

Brazil 56.8 56.9 56.9

Colombia 54.1 48.2 51.2

Peru 54.5 43.9 49.2

Chile 43.2 45.3 44.2

Mexico 39.2 48.4 43.8

Trinidad and Tobago 48.3 35.4 41.9

Argentina 39.4 44.2 41.8

Venezuela 43.8 34.5 39.2

Bolivia 40.6 33.1 36.8

Ecuador 29.6 39.8 34.7

Regional Average 44.9 43.0 44.0

Note: Data is accurate at time of writing and is subject to updates. Source: BMI

Composite Index: Change Is Around The Corner

Brazil maintains its first place position in our composite upstream and downstream RRI with a score of

56.9, buoyed by its promising oil resources, particularly in the offshore pre-salt basins. That said, this

represents a downgrade from its Q215 score of 58.5 as mounting above-ground headwinds begin to affect

the country's overall score. Specifically, the ongoing 'Lava Jato' corruption scandal surrounding national oil

company (NOC) Petrobras combined with lower profitability from upstream projects have dampened our

long-term outlook on production growth. Moreover, continued uncertainty regarding the scandal's impact on

future developments poses downside risk to our forecast, threatening Brazil's top position within our

rankings.

Colombia and Peru have maintained their respective second and third place rankings. While both countries

have a comparatively modest resource potential, favourable business environments and stable political

systems support their relatively strong upstream and downstream scores. However, compared to Q215,

Colombia's overall score declined as lower oil prices have reduced available funds to key upstream

developers including state-owned Ecopetrol and Pacific Rubiales. Combined with declining interest from

international oil companies, the long-term prospectivity of its resources has been called into question.

Meanwhile, Peru's overall score also declined driven by a weaker downstream score.



With the exception of Chile, the remaining countries rank below the regional average of 44.0, but signs of

future shifts in our rankings continue to show, namely within regional reformers. Mexico's overall score

continued its rise from Q414, increasing from 42.1 to 43.8 on the back of historic energy sector reforms.

Moreover, following the completion of the country's historic Round One licensing round in 2015, we

believe the upstream outlook for Mexico has further upside potential over the coming quarters, despite the

lower oil price environment.

Similarly, we see long-term upside for Argentina. Following YPF's settlement with Repsol in February

2014, the country has experienced a significant uptick in investor interest, highlighted by the USD1.6bn

expansion of a 2013 shale development agreement with Chevron in April 2014 and the USD550mn

development plan with Malaysian NOC Petronas in September 2014. Argentina's passage of more

favourable hydrocarbon production regulations in the fall of 2014 and early 2015 support investment into

the country's nascent shale sector and pose upside risk to the country's RRI in future quarters.

Brazil Maintains Its Lead Despite Strong Headwinds

Latin America - Composite Upstream and Composite Downstream Index, Out of 100

Source: BMI RRI



Upstream Risk/Reward Index: Reforms Prompting A Shake Up

Top Three Facing Increased Challenges

Brazil has maintained its top ranking in the upstream segment this quarter with a score of 56.8 despite

falling from 58.1 in Q215. Furthermore, we acknowledge continued risks to its Industry Risk score of 45.0,

which is already below the regional average of 52.5. Brazil will fail to meet its ambitious production targets

over the coming decade due to mounting headwinds faced by Petrobras. Specifically, high debt coupled

with the continued escalation of the accounting scandal will weaken the NOC's ability to both fulfil its

upstream objectives and attract greater investor interest.

Colombia, a long-held favourite within the sector, fell from second to third place this quarter with a score

of 54.1. In Q215, Colombia lost its first place rank as a result of weak reserve and production growth

coupled with increasing attacks on pipelines infrastructure by insurgent groups. The sharp decline in oil

prices has exacerbated negative investor sentiment and will weigh on production prospects. However, the

current score is still significantly above the regional average of 44.9, highlighting Colombia's favourable

investor environment.

Table: Latin America Upstream Risk/Reward Index, Out of 100

UpstreamIndustryRewards

UpstreamCountryRewards

UpstreamRewards

UpstreamIndustry

Risks

UpstreamCountry

RisksUpstream

RisksUpstream R/

R Index

Brazil 56.3 70.0 59.7 45.0 59.1 49.9 56.8

Peru 48.8 55.0 50.3 70.0 53.4 64.2 54.5

Colombia 33.8 80.0 45.3 85.0 55.3 74.6 54.1

Trinidad andTobago 32.5 70.0 41.9 80.0 32.7 63.4 48.3

Venezuela 55.0 47.5 53.1 25.0 16.5 22.0 43.8

Chile 30.0 15.0 26.3 85.0 78.2 82.6 43.2

Bolivia 52.5 32.5 47.5 20.0 32.9 24.5 40.6

Argentina 32.5 42.5 35.0 45.0 58.5 49.7 39.4

Mexico 33.8 35.0 34.1 50.0 53.0 51.1 39.2

Ecuador 32.5 30.0 31.9 20.0 32.1 24.2 29.6

RegionalAverage 40.8 47.8 42.5 52.5 47.2 50.6 44.9




Rounding out the top three is Peru with an overall upstream score of 54.5. While this is a slight downgrade

from last quarter's score of 55.1, the country has moved up the ranks to second place. However, continued

high levels of local opposition to oil and gas developments have encouraged us to take an increasingly

cautious stance toward the country's long-term outlook.

Operating Environment: The Major Challenge For the Middle Of the Pack

Ranked fourth in the region, Trinidad and Tobago's score fell from 51.0 to 48.3. The Caribbean nation has

long faced considerable challenges relating to the technical difficulty and expense involved in the

exploration and production (E&P) of its hydrocarbon resources. Lower oil prices pose downside risk the

country's long term development, despite the December 2014 start up of the Starfish gas field by joint

partners BG Group and Chevron.

Although Venezuela maintained its fifth place rank with a score of 43.8, this illustrates a significant

downgrade from Q215 when the country scored 48.2. This underscores Venezuela's continued inability to

reach its full potential given the country's tremendous below-ground potential. The precipitous rise in

PdVSA's debt, from USD2.9bn in 2006 to USD43.4bn in 2013, coupled with declining profitability from

upstream operations amid lower oil prices, significantly threatens the country's future production prospects

and Upstream Risk/Reward score.



Debt Continues To Climb

PdVSA - Debt, USDmn

Source: Bloomberg, PdVSA, BMI

Chile moved up the ranks from seventh to sixth place, with a total upstream score of 43.2, due primarily

to Bolivia's declining score for Upstream Rewards. Chile's score is supported by its top ranked Upstream

Risks score of 82.6 but is weighed down by its last placed Upstream Rewards score of 26.3 due to a small

proven reserve base and high state ownership of assets. Bolivia earned an upstream score of 40.6, having

fallen from 43.9 last quarter. This decline was driven by a fall in the country's Upstream Industry Rewards

score, reflecting an increasingly unfavourable investment environment.

Reforms Suggest Potential Move Higher For Underperformers

Having swapped ranks since last quarter, Argentina is now ranked eighth with a score of 39.4, followed by

Mexico with a score of 39.2. Despite scoring below the regional average, these countries either increased or

maintained their previous scores, illustrating their resilience within the lower oil price environment.

Moreover, we believe energy sector reforms suggest both are well positioned to climb up the rankings in the

coming quarters. Ecuador maintains its last place position and fell from a score of 35.5 to 29.6. This was

due primarily to a weak Upstream Risk score, highlighting an unfavourable investment environment.



Reforms Suggest Room For A Rebound

Mexico - Production And Net Exports

Crude, NGPL & other liquids prod, 000b/dTotal net oil exports (crude & products), 000b/d

2001

2002

2003

2004

2005

2006

2007

2008

2009

2010

2011

2012

2013

e

2014

e

2015

f

2016

f

2017

f

2018

f

2019

f

2020

f

2021

f

2022

f

2023

f

2024

f

0

2,000

4,000

6,000


Downstream: Medium-Term Outlook Reinforces Current Dynamics

Latin America's expanding population and rising power demand will keep hydrocarbon consumption

elevated and ensure continued opportunities in the downstream sector. With consumption set to tick steadily

higher, refining capacity is unlikely to keep up. A lack of sufficient investment and continued project delays

suggest rising imports of refined products over the coming decade, keeping the regional downstream

average score relatively low at 43.0.



Import Burden On The Rise

Latin America - Refined Fuel Capacity (LHS), Oil Consumption (LHS), and Net Oil Imports (RHS)

Oil consumption, 000b/d Oil refinery capacity, 000b/dOil net exports, 000b/d

2011

2012

2013

2014

2015

f

2016

f

2017

f

2018

f

2019

f

2020

f

2021

f

2022

f

2023

f

2024

f

0

5,000

10,000

15,000

500

1,000

1,500

2,000


Top Three To Maintain Their Lead

Our Downstream RRI experienced notable shifts in Q315, owning to continued shifts in industry dynamics

within a lower oil price environment. While still in first place, Brazil's downstream score fell from 59.0 to

56.9 due to the cancellation of the Premium I and II refineries. This fell in line with our previous

assumptions with respect to project delays and reduced investment funds due to lower oil prices.

Colombia and Mexico have switched positions in the rankings, but have very different downstream

dynamics. Colombia's success in the downstream sector is driven by its top-ranked Industry Risk score of

80.0, reflecting economic and political continuity and a favourable legal framework. However, Colombia's

Downstream Rewards are significantly weaker, falling short of the regional average due to low domestic

demand. Alternatively, Mexico is more balanced between risk and rewards, driven mostly by a Downstream

Country Risk score of 64.6 coupled with continued investment into the sector. In February 2015, Mexican

NOC Pemex announced a USD4.1bn budget cut in 2015. This poses downside risk to the company's



USD2.8bn refinery upgrade spending plan as well as our downstream forecast. However, we believe there is

still potential for some investments to continue as planned.

Bottom Three Face Continued Headwinds

The final three countries in the downstream segment - Venezuela, T&T and Bolivia - continue to suffer

from a weak macroeconomic outlook and sluggish investment. In eighth place, T&T maintained its

downstream score of 35.4, despite earning the second-highest Industry Risk score in the region. This

component reflects a strong regulatory environment and a strong privatisation trend. However, the country

continues to struggle with upgrade delays due to labour disputes.

With a downstream score of 34.5, Venezuela suffers from continued refining deficiencies related to poor

maintenance and underinvestment resulting in a downgrade from last quarter's score of 36.5. Finally,

Bolivia maintains its position in last place, reflecting a poor operating environment, weak domestic demand,

and a lack of private sector involvement.

Table: Latin America Downstream Risk/Reward Index, Out of 100

DownstreamIndustryRewards

DownstreamCountryRewards

DownstreamRewards

DownstreamIndustry Risks

DownstreamCountry Risks

Down-streamRisks

Down-stream R/R

Index

Brazil 47.8 66.0 52.3 75.0 56.8 67.7 56.9

Mexico 50.0 46.0 49.0 35.0 64.6 46.8 48.4

Colombia 34.4 50.0 38.3 80.0 58.3 71.3 48.2

Chile 33.3 30.0 32.5 80.0 68.1 75.2 45.3

Argentina 41.1 54.0 44.3 40.0 50.0 44.0 44.2

Peru 37.8 42.0 38.8 55.0 57.2 55.9 43.9

Ecuador 42.2 36.0 40.7 35.0 42.3 37.9 39.8

TrinidadandTobago 27.8 30.0 28.3 75.0 17.5 52.0 35.4

Venezuela 42.2 35.0 40.4 20.0 21.9 20.7 34.5

Bolivia 31.1 25.0 29.6 30.0 57.9 41.1 33.1

RegionalAverage 38.8 41.4 39.4 52.5 49.4 51.3 43.0




Colombia Risk/Reward Index

Colombia's overall oil and gas Risk/Reward Index score of 51.2 represents a slight downgrade of 0.2 points

from Q215. However, the country maintains its rank as second in the region behind Brazil and well above

the regional average of 44.0 out of 100.0. This is primarily driven by Colombia's strong upstream industry

score, reflecting the country's exceedingly favourable regulatory and legal environment. With Colombia

eager to attract foreign investment into the sector, further progress in the ongoing peace negotiations would

provide upside to this score and could potentially outweigh some of the below-ground challenges currently

faced.

Colombia Upstream Index - Overview

Colombia maintains its high ranking in BMI's upstream Risk/Reward Index (RRI), scoring 54.1 points and

outperforming the regional average of 44.9. This represents a downgrade of 0.3 points versus Q215,

reflecting the country's relatively modest resource base. Although Colombia's business environment has

some of the most favourable licensing terms in the region, the country has struggled to increase its reserves-

to-production ratio above seven years. This contrasts with a number of the other major players in the region

with stronger below-ground assets who have been unable to fully leverage their resources due to less

amenable above-ground environments.

That said, we acknowledge some risks to the country's current position. First, we have seen a considerable

uptick in attacks on oil pipelines which has stymied production and export potential. Second, despite broad

improvements in violence in recent years, the competitive climate within the sector is rapidly changing in

favour of neighbouring competitors. Most notably, Mexico recently passed dramatic energy sector reform,

and is ripe for widespread international investment in the coming years.

Colombia Upstream Index - Rewards

Industry Rewards: Colombia's Industry Rewards score of 33.8 reflects its modest proven

reserves supply and below-average reserves-to-production ratios (RPR). While current rates of oil

production remain high, the lacklustre reception at the country's 2014 hydrocarbon licensing rounds

threatened Colombia's long-term production growth. Although disappointing, the auction did attract some

investment in onshore and unconventional resources that could potentially provide additional productive

resources. We recognise, however, that this scenario is unlikely.

Country Rewards: Largely contributing to Colombia's upstream rewards section is a strong Country

Rewards score of 80.0. Colombia has successfully attracted private investor interest in recent quarters as a



result of attractive taxation regimes and providing equitable terms for all international competitors. This has

occurred in spite of the state having retained some indirect ownership of upstream assets in a region where

government control is the norm. We caution, however, a lower oil price environment poses downside risk to

this score in the coming quarters as reduced profitability disincentivises upstream investment.

Colombia Upstream Index - Risks

Industry Risks: Colombia has an excellent Industry Risks score of 85.0 which is well above the regional

average of 52.5. Colombia's high score is attributable to a transparent and investor-friendly licensing

environment, a good privatisation trend, and the fact that the government appears willing to let foreign

investors participate in the country's upstream operations on equal terms. Compared to its peers in the

region, including Brazil and Mexico who score 45.0 and 50.0 respectively, Colombia is well ahead of the

industry curve.

Country Risks: Scoring 55.3, long-term policy continuity of across governments substantially reduces the

operational risks for private companies in Colombia. On the other hand, their ability to operate is

undermined by a weak rule of law, with corruption and physical infrastructure also areas of concern. It must

be noted that despite significant improvements in recent years, rebel-led attacks on pipeline infrastructure

have increased. We see scope for improvement in this score over the coming quarters given our view for a

peace accord sometime later this year which would decrease the rate of midstream attacks.

Colombia Downstream Index - Overview

Colombia ranks third in BMI's downstream RRI for Latin America, scoring 48.2, reflecting a lower import

demand, favourable regulatory environment, and moderate country risk. Colombia's market fundamentals

are strong thanks to moderate demand growth potential and plans to expand capacity. However, the absence

of foreign operators in the refining sector penalises the country as physical infrastructure and legal

framework fall short of the region's best. Colombia fares much better in terms of short-term external

economic risk and policy continuity, reducing operational risks for private companies.

Colombia Downstream Index - Rewards

Industry Rewards: Colombia's Industry Rewards earned a score of 34.4, reflecting lower than average

demand trends for both oil and gas and an overall deficit in refining capacity. With the regional average at

38.8, Colombia's downstream rank is below that of all other regional peers with the exception of Chile,

Trinidad & Tobago and Bolivia.



Country Rewards: Colombia's Downstream Country Rewards scored a total of 50.0, due to a relatively

high number of non-state competitors and sizeable nominal GDP growth. This score was well above the

regional average of 41.4 despite the downgrade. Although Colombia has a favourable regulatory

environment and broad macroeconomic stability, we believe there is potential downside risk to this score

over the next several quarters given the sustained lower price environment and its effects on investor

enthusiasm.

Colombia Downstream Index - Risks

Industry Risks: Colombia ties with Chile for first in the region for Industry Risks with a score of 80.0 out

of a possible 100. This reflects Colombia's highly favourable regulatory environment as well as an

established trend of privatisation. We believe Colombia will remain at the top of the region's rankings for

this metric given a concerted effort to increase international investment.

Country Risks: Short-term policy continuity, low economic external risk, and favourable legal framework

have earned Colombia a Country Risk score of 56.1. Ranking third in the region behind Chile and Mexico,

Colombia scores above Latin America's average Country Risk score of 58.3, reflecting the country's

favourable investment environment as it pertains to the oil and gas sector.



Market Overview

Colombia Energy Market Overview

Overview/State Role

Colombia's business environment in the oil and gas sector improved significantly over the past decade,

particularly due to the partial privatisation of state-owned Ecopetrol in 2003. The government's attempts to

improve the country's security situation, particularly vis-à-vis the Fuerzas Armadas Revolucionarias de

Colombia (FARC) guerrilla group, also led to increased foreign investment into the country over the past

several years, translating into record oil and gas production growth.

Continued progress, however, has grown increasingly tenuous as a result of weak below-ground rewards

amid a lower oil price environment. With large direct investments still needed to ensure growth within the

sector, we note that less favourable project economics will undermine further investment over the coming

decade. Furthermore, while attacks on oil pipelines have declined versus last year a result of the ongoing

unilateral ceasefire, such disturbances continue to negatively impact the investment appeal of Colombia's

hydrocarbon resources.

The government's role is largely reserved to regulating oil and gas developments as private investment into

the sector through joint ventures or individual companies are permitted to explore and produce

hydrocarbons within Colombia. The company or entity must be registered with the Ministry of Mines and

Energy (MME) as an exploration and production company in order to participate in the domestic market.

Government Policy

Four main government entities are responsible for the regulation of oil and natural gas development:

■ The MME administers non-renewable natural resources and creates guidelines for the use and regulationof hydrocarbons to guarantee their supply and ensure their continued protection.

■ The National Hydrocarbons Agency (ANH), which reports into the MME, regulates concessions,royalties, oil-demand projections and the promotion of foreign investment. The ANH also manages andcontrols exploration and production (E&P) contracts and develops studies about areas with potential forhydrocarbon exploration.

■ The Mining and Energy Planning Unit (UPME) is the country's technical authority responsible forplanning the development and use of Colombia's mining and energy resources, including itshydrocarbons. It is also responsible for managing the country's energy and mining information system.

■ The Gas and Energy Regulation Commission (CREG) is the sector regulator.



Although private foreign investment is allowed, all of the country's refineries are 100% owned and operated

by Ecopetrol. The company also operates approximately 64% of the country's total oil and gas production.

The MME has actively attempted to eliminate fuel subsidies since 2003 with the price of diesel and gasoline

having gradually increased over the last decade. However, due to political pressures, the agency cut

gasoline and diesel prices by COP300 (USD0.12) in February 2015 in an effort to stem rising inflation and

boost domestic demand.

Direct LNG utility subsidies were established in the fall of 2013 to increase usage rates for lower income

earners and facilitate reduced dependence on electricity sourced from hydropower. Their expansion in April

of 2014 cemented the state's commitment to increasing natural gas-generated power from its current rate of

18% of total electricity.

Licensing And Regulation

Colombia has taken significant steps towards the creation of an attractive investment environment for

foreign companies. While the Colombian Constitution states that the country's sub-soil and non-renewable

natural resources belong to the state, any qualified local or foreign company is permitted to explore and

produce hydrocarbons without having to partner with the NOC. The state believes in equal treatment of

foreign and local investors, with all having the same legal rights to produce Colombia's hydrocarbons in

accordance with local regulations.

Specifically, the MME stipulates that foreign companies are allowed to own 100% stakes in

ventures, royalty rates are comparatively low, and no local content requirements are in place. However,

Colombian contractors are preferred, all things being equal. Moreover, a more attractive fiscal and tax

regime has been implemented. Rather than a flat 20% tax rate, there is now a sliding-scale royalty rate, with

discounts for natural gas and heavy oil. Colombia has also begun to incentivise unconventional exploration

with a 40% discount over the royalty rate.



Table: Royalty Rates

Field Production (b/d) Royalty Rate

0-5,000 8%

5,001-125,000 8%-20%

125,001-400,000 20%

400,001-600,000 plus 20%-25%

Source: BMI, Baker Mckenzie

Under the jurisdiction of the ANH, the state supports the tendering of hydrocarbon areas for exploration and

production through competitive licensing rounds. However, there are two other types of bidding processes

practiced by the state:

■ Open Competitive Bidding: The most common type of licensing rounds whereby the ANH tendersblocks through a public process. The ANH chooses the highest bids presented by companies that havereceived prior qualification based on specific capacity requirements. Criteria for selecting bids varies foreach round but is often based on the additional percentage share produced after royalties are allocated tothe ANH or how much additional exploration investments are made beyond the mandated minimum.

■ Closed Competitive Bidding: Licensing rounds where the ANH invites a predetermined number ofbidders that meet certain established capacity requirements to choose the most favourable proposal.

■ Direct Contracting Process: The least common type of licensing round whereby the ANH directlyawards a hydrocarbon block to a bidder that meets all pre-determined requirements. This process mayonly be conducted with prior approval from the ANH Board of Directors and must represent a clearcomparative advantage versus a competitive selection process.

In February 2015, the government proposed a new royalty framework whereby extra crude would be treated

as a new discovery, making it eligible for lower levies. Furthermore, the proposed plan would allow the

country's oil regulator to provide drillers with more time to explore for oil, and reduce restrictions on

investment with permission of the oil producing company. These plans forms part of the government's

proposed four-year National Development Plan, which needs to be approved by Congress to become law.

In May 2015, the Colombian government announced its plans to introduce new upstream licensing rules

which would do away with annual, high-profile rounds. This is a direct response to a disappointing set of

rounds in 2014 coupled with industry calls for increasingly competitive terms. Under the new licensing

process, which would likely begin in H215, companies would enter into direct negotiation with the ANH on

a rolling basis under a new legal framework which is currently being developed.



Open Round Colombia 2014

Colombia's 2014 licensing round was officially launched in February with road shows in Canada, the US,

the UK, and Indonesia. The round was open to local and foreign companies who met capacity requirements

and aimed to raise USD2.6bn through the sale of 22mn hectares at the July auction.

Offering a total of 95 onshore, offshore, and unconventional blocks, the round was projected to spur the

development of the country's nascent shale resources. The auction included 61 conventional blocks

scattered offshore and onshore through the southern province of Putumayo, the Middle Magdalena Valley

and Los Llanos. A total of 1.9mn hectares of unconventional acreage were also offered, under either E&P or

Technical Evaluation Agreement contracts. Coal bed methane blocks totalling 2.0mn hectares were also

included, though due to differing regulations, these were tendered separately from the rest of the round.

However, only one of 19 unconventional blocks received a bid, dampening the prospects of future shale

production. Six offshore blocks and 20 onshore blocks received bids. Ecopetrol and its subsidiary Hocol

offered bids on five blocks, including four conventional and one offshore. Ecopetrol also bid on the Sin Off

7 offshore block in the Caribbean in partnership with Shell. Hocol placed bids for the developed SN8,

SN15, and SN18 blocks in addition to the undeveloped YDSN1 onshore block. Exxon Mobil, Repsol, and

Statoil also collaborated on a bid for the COL 4 offshore block. Other investors included Trayectoria Oil

& Gas, Andes Energia, Ventra E&P, Mompos Oil, Geopark, and Anadarko.

However, this represented a total uptake of 27%, generating USD1.4bn in investment, nearly half of the

ANH's projected amount of USD2.6bn. As such, a second open round was conducted on August 20 with

hopes of tendering previously abandoned resources. With only one confirmed proposal offered and

subsequently rejected, the results of the second round confirmed our previous assumptions, underscoring a

declining interest in the country's resources.


The ANH offered 115 hydrocarbon blocks, covering an area of 134,776 square kilometres (sq km). Included

in the bid were 102 onshore and 13 offshore blocks, 31 of which contain unconventional potential.

Preliminary results from the first and second calls of offer revealed continued investor interest in the

Colombian oil industry and were on par with the ANH's expectations: 115 offers were received for 50

blocks, from 37 different companies The 50 awarded blocks cover an area in excess of 70,150sq km, spread



across the following basins: Caguán-Putumayo, Catatumbo, Colombia, Cordillera, Guarija, Guarija

Offshore, Llanos, Sinú-San Jacinto, Urabá, Vaupés-Amazonas, and the Lower, Middle and Upper

Magdalena Valley. The maturing Llanos basin, which already accounts for about 70% of Colombia's

production, received the largest interest.

Shell, ExxonMobil, Statoil and Anadarko, amongst others, made bids for frontier acreage. In particular,

offshore potential was sought after with six of the 12 offshore blocks receiving offers. Successful

companies were Ecopetrol, Anadarko, ONGC Videsh Limited, Shell and Repsol. Furthermore, of the 50

blocks awarded, five contain unconventional resource potential. Because these blocks are considered

frontier basins with little or no geological knowledge, prospectivity is significant.


The Colombian government successfully auctioned nearly 100 onshore and offshore exploratory blocks as

part of the country's 2010 licensing round. A total of 225 blocks, including 29 offshore blocks, were made

available to investors with the rights to 96 blocks eventually sold. ,With the ANH expecting 50-60 blocks to

receive offers, the 2010 round highlighted a strong level of investor interest. A total of USD1bn was

pledged from investors seeking to acquire acreage in the round.

Colombia's Ecopetrol said that it had offered the highest bid for nine blocks, one in partnership with South

Korea's SK Energy, and committed USD102mn in investment for three years. Brazilian explorer OGX

reported the award of five blocks for a total three-year investment of USD125mn and Canadian junior

Canacol said it had won four blocks. Other winners included Colombia-focused Canadian explorers Pacific

Rubiales, Petrominerales and Alange.

2008 Licensing Round

In late July 2008, the ANH awarded eight heavy oil blocks in the Llanos Basin in eastern Colombia to local

and foreign oil companies. It awarded stakes in three blocks to Ecopetrol, which will explore Blocks CPE-2

and CPE-4 alongside Royal Dutch Shell and Block CPE-8 with Talisman. A consortium of Korea

National Oil Corporation (KNOC), Argentina's Pluspetrol and China National Petroleum Corporation

(CNPC) was awarded a three-year exploration licence for Block CPE-7. Canada's Pacific Rubiales Energy

received full ownership of Block CPE-1 and a stake in Block CPE-6 alongside Talisman. ExxonMobil was

awarded Block CPE-3 and Australia's BHP Billiton and South Korea's SK Energy jointly received the

rights to Block CPE-5. Under the agreements, the companies committed to investing a total of



USD322.1mn in the exploration of the blocks. Ecopetrol and Shell made the highest financial commitment,

and plan to spend USD79.4mn on the exploration of Block CPE-4.

In November 2008, the ANH awarded 22 out of the 43 areas on offer in the Colombia 2008 licensing round.

Ten different companies were chosen as operators of the blocks, including Canada-based Pacific Rubiales

Energy, Ecopetrol, France's Maurel et Prom, SK Energy and India's OVL.

2007 Licensing Round

The ANH awarded nine of 13 offshore blocks on offer in the Caribbean in September 2007. As expected,

Ecopetrol was the dominant player and signedjoint ventures (JVs) with foreign partners in eight of the

concessions. Of the nine blocks awarded, Ecopetrol won 11 and 12 outright, and planned partnerships with

Petrobras, India's ONGC, Hess and BP in a further six. The companies agreed to commit USD5.3mn-

USD5.8mn in exploration funding and offered varying royalty payments. In return, they received 10-year

oil and gas exploration rights and will also have production rights for the field's lifetime.

International Energy Relations

United States

Colombia's primary export destination for oil is the United States with approximately 38% of total volumes

sent there. The amount of exportable resources to the US is likely to decrease, however, as the US continues

to produce record amounts of domestic crude to supply itself. Given the shift in the US' energy consumption

profile, Colombia has begun to develop relationships with other emerging markets for its oil exports.

Venezuela

In early 2007, the 224.4km Antonio Ricaurte (Trans-Caribbean) gas pipeline between Colombia and

Venezuela came online. Since its establishment, the pipeline has allowed Colombia to export natural gas

from the Punta Ballenas area to the western Venezuelan state of Zulia at varying flow rates. According to

Colombia's mining and energy minister , the pipeline was supplying about 2.2bn cubic metres (bcm) of gas

to Venezuela by 2010.

In November 2011 the Venezuelan President signed an agreement with President Santos to extend the

pipeline to Panama and Ecuador to supply these countries gas in the spirit of integrationist policies.

However, there has been no progress on the extension at the time of writing. Moreover, the country's heavy



reliance on hydropower combined with recent drought conditions has resulted in a temporary suspension of

gas exports to Venezuela, redirecting them to domestic power plants instead.

China

Chinese exports are likely to make up a larger share of future exports following a preliminary agreement

signed in 2012 between the two governments to finance a 600,000 b/d pipeline. This agreement reflects

China's growing demand for oil and Colombia's desire to diversify their trade portfolio, highlighted by the

398.6% y-o-y growth of crude exports to China in October 2014, reflecting Colombian crude's favourable

pricing versus Saudi Arabian crude imports.

Oil And Gas Infrastructure

Refineries

According to Ecopetrol, Colombia's current refining capacity is 335,850 barrels per day (b/d). However, the

government is currently in the middle of a refinery expansion programme to increase yields and allow the

downstream segment to process the country's heavy crude, thereby decreasing total output. We currently

forecast capacity to reach 470,850b/d by 2016, although note it could expand to as much as 730,850b/d if

Llanopetrol's new Meta refinery comes online.

The Barrancabermeja and Reficar refineries process the vast majority of the country's capacity. Although

Colombia is a net exporter, domestic demand for certain products outstrips refining capacity, such that the

country imports some products, primarily diesel fuel.

Table: Refineries In Colombia

Location Name Capacity, b/d Status Main Owner

Apiay Apiay 2,250 Active Ecopetrol

Santander Tibu 1,800 Active Ecopetrol

Cartagena Bolivar (Reficar) 80,000 Active Ecopetrol

Putumayo Putumayo 1,800 Active Ecopetrol

Santander Barrancabermeja 250,000 Active Ecopetrol

Source: BMI



Barrancabermeja

The country's largest refinery is the Barrancabermeja (Santander) facility, with a capacity of 250,000b/d

according to Ecopetrol. In November 2008, US engineering group Foster Wheeler was awarded a front-

end engineering and design (FEED) and project management consultancy (PMC) contract by Ecopetrol to

upgrade the refinery in the aim of increasing the conversion factor from 76% to 95%. This will enable the

refinery to obtain more products such as gasoline and diesel, and will improve the refinery's ability to

process heavier crude oil.

Furthermore, the upgrade will increase the refinery's production of cleaner fuels and expand its distillation

capacity. In addition to a 50,000b/d capacity increase, fuel and coke will fall while much-needed gasoline

and middle distillate yields will rise.

Due to mounting investment headwinds from a lower oil price environment, at the time of writing, the

expansion has been temporarily suspended and is pending a full investment review.

Reficar

Colombia's second largest facility is the Reficar refinery in Cartagena with a capacity of 80,000b/d. In 2006,

Switzerland's Glencore International and Ecopetrol launched an USD800mn expansion of the facility to

increase overall capacity to 165,000b/d. In May 2009, Ecopetrol completed the acquisition of Glencore's

stake in Refineria de Cartagena. It said in October 2009 that it planned to spend a total USD3.78bn on the

Cartagena refinery expansion. In November 2009, US-based Chicago Bridge & Iron (CB&I) was awarded a

USD 1.4bn contract by Ecopetrol to provide engineering, procurement services for the modernisation of the

plant.

The refinery is expected to go back online by H215 and will have increased conversion efficiency from 74%

to 96%. Once finished, the upgrade will enable the company to produce ultra-low-sulphur gasoline and

diesel from heavy crude. As of time of writing, the refinery upgrade was reported to be nearly complete and

is expected to come online as planned.

However, the project has not been without problems. Construction costs have been higher than expected

such that Ecopetrol approved the allocation of an extra USD502mn for the modernisation project, after the

management team of Reficar asked for the additional funds based on an estimated budget of USD 6,467mn.

Moreover, a series of protests and labour disputes have caused delays to the project and drove up costs,



including a three-day strike in September 2013 which saw workers obtain pay increases of up to 40% in

some cases.

Other Refineries

Additionally, Colombia has several minor facilities, including the Apiay and Putumayo refineries, which are

reported to have around 6,000b/d in refining capacity each.

Proposed Refineries

La Empresa de Petroleos del Llano-Llanopetrol is planning a USD1.5bn facility, with a capacity of 40,000b/

d by end-2015.

At peak capacity, it could be capable of processing 260,000b/d of heavy crude a day, making it the largest

refinery in Colombia after the expanded Barrancabermeja plant. However, has yet to be made on a partner

to help provide financing for the project.

Service Stations

Terpel has the largest fuel retail network in Colombia, with 1,460 service stations. ExxonMobil is the

country's leading foreign fuel retailer, operating about 700 service stations under the Esso and Mobil

brands. Chevron is also well represented, operating 331 service stations.

Oil Terminals/ Ports

Colombia has ports that serve both its Pacific and Atlantic coastlines. The Buenavista port is Colombia's

main port on the Pacific Ocean and receives oil by pipeline from Puerto Berrio. The Tumaco port is the

other Pacific Ocean port and is served by the Transandina pipeline.

On the Atlantic coast, the main port is at Coveñas. It is served by three oil pipelines: the Caño Limon-

Coveñas pipeline, the Colombia pipeline and the OCENSA (Oleoducto Central SA) pipeline. Other ports on

the Atlantic coast are in Cartagena and Santa Marta.

Oil Pipelines

According to the EIA, Colombia currently has six major oil pipelines, the vast majority of which (80%) are

owned by Ecopetrol. Four of these connect producing fields in the centre of the country to the Caribbean



export terminals in Coveñas. As Colombian oil production booms, it has been a struggle to ensure sufficient

capacity. Infrastructure bottlenecks have weighed on the country's oil production growth rates, especially in

the heavy oil fields of the eastern Meta, Casanare and Arauca states.

Moreover, the difficulty in accessing sufficient takeaway capacity has only been exacerbated by the steady

uptick in pipeline attacks, with an increasing number every year since 2010. The first phase of the

bicentennial pipeline has helped to ease some of the production bottlenecks.

Ocensaa

The longest of the country's pipelines, this pipeline runs a little under 500 miles (805km) from Cusiana to

Conveñas, with transport capacity of 600,000b/d. This is expected to increase by 110,000b/d in 2014 and by

another 135,000b/d in 2015.

Caño Limón Pipeline

The second longest pipeline in Colombia, at 772km, the Caño Limón pipeline can carry up to 220,000b/d

capacity from the Caño Limon oilfield, in the department of Arauca (near the border of Venezuela) to

Coveñas. As production at the oilfield slows through, throughput has averaged between 70,000b/d and

80,000b/d in recent quarters. Alto Magdalena (OAM) (Upper Magdalena) and Colombia Oil Pipeline

(ODC)

These pipelines connect at Vasconia station, allowing oil to flow from Tenay to Covenas. More specifically,

the OAM was completed in 1990, and transports crudes produced in the Upper Magdalena Valley to

Vasconia station, while the ODC conveys the crude 300 miles from Vasconia to Coveñas, with a capacity of

236,000b/d as of 2013. Llanos Orientales

Links the massive Rubiales heavy oilfield in the southern province of Meta to the Ocensa pipeline.

Completed in 2009, it has a capacity of 340,000b/d according to the EIA. Transandino Pipeline

This is the only of the major pipeline that operates in the south of the country. It has a capacity of 190,000b/

d, and conveys crude from the Orito field in the Putumayo basin to Colombia's Pacific port, in Tumaco.



Takeaway Capacity Coming Online

Colombia - Major Pipelines

Source: BMI, Bicentenario

Oleoducto Bicentenario (Bicentennial Pipeline)

The Bicentennial Pipeline will be the longest in the country when all phases of Colombia's newest pipeline

are completed. The first phase of the Oleoducto Bicentenario (Bicentennial Pipeline) came online in

2013. Phase I runs 235km, from Araguaney to Banadía, before crude is transferred to the Caño Limon

pipeline to be conveyed to Coveñas - taking advantage of the fact that the older pipeline has been running



well under capacity. This section has a total capacity of 110,000 b/d but was suspended in February of 2014

following a series of insurgent attacks.

Full operational capacity is still several years off. We highlight that the political environment acts as a

continued threat. Recently delays at the bicentennial pipeline have suspended operations for several months.

A series of attacks by insurgent groups took the pipeline offline, and this was only exacerbated as local

indigenous groups refused to allow repairs until the government promised to address environmental damage

and increase security in the area.

Pacific Coast Pipeline (Tentatively Named)

Plans for a pipeline to the Pacific Coast are also progressing. Enbridge revealed in March 2012 that an

800km pipeline linking Colombia's heavy oil-rich Llanos basin to the Pacific Coast could be operational by

end-2016 and carry up to 400,000b/d.

Crucially, Colombia's geographic position is ideal for supplying the Asian markets, as it provides a direct

shipping route from its Pacific Coast ports (such as Tumaco or Buenaventura) to Asia's east cost terminals.

The fact that tankers would not have to navigate through any of the five strategic chokepoints of oil trade

routes (Strait of Hormuz, Strait of Malacca, Suez Canal, Bab el-Mandab, Bosporus Straits), gives this

pipeline a crucial cost and risk advantage.

However, existing pipeline infrastructure in Colombia is not conducive for oil exports to Asia, which

connects oil fields only to the Caribbean coast. Oil exports to China currently leave from the Caribbean port

of Covenas, through the Cape of Good Hope in South Africa to get to China. A Pacific route would provide

cost savings of as much as USD2 per barrel (bbl), according to Enbridge's estimates, making Colombian oil

more attractive to prospective Asian consumers.

Finally, while transport capacity is ramping up in the rest of the country, much of the Caguan-Putumayo

basin in the south of the country remains highly underserved. Only the Trans-Andean pipeline offers

takeaway capacity, but while it is an important outlet for crude from the basin, it does not cover all the

productive areas in the region.

Although local news sources indicate that there have been some government and private sector attempts to

improve midstream connectivity in the region, we have also seen moves to find other takeaway capacity -

namely Ecuador's Oleoducto de Crudos Pesados (OCP, Heavy Crude Oil Pipeline).



Specifically, in mid-2013 a bi-national crude agreement was signed between Ecuador and Colombia

(Interconexión Petrolera Ecuador-Colombia) for the transport of crude from the southeast of Colombia

through Ecuador's OCP pipeline. In August 2013, contracts were signed with 10 companies operating in the

basin, including Vetra, Amerisur and Grantierra. We note that this not only benefits the companies

operating in Colombia, but also the operators of the OCP pipeline, which runs substantially under capacity.

In June 2015, Ecuadorian state-owned oil company Petroamazonas signed an agreement with

Amerisur Resources to build a crude pipeline from the Ecuadorian border into southern Colombia. This

pipeline will transport a minimum of 5,000b/d of crude from the southern Putumayo Basin into the Lago

Agrio field. These supplies will ultimately make their way to the coast to be exported.

LNG Terminals

Plans were announced to build Colombia's first liquefied natural gas (LNG) export terminal in September

2011. However, due to unfavourable market conditions, the project was suspended indefinitely in January

2015. The proposed project has a planned initial liquefaction capacity of 1.98mn cubic metres per day

(mcm/d), which corresponds to 0.7bn cubic metres (bcm) annually or 0.5mn tonnes per annum (tpa).

Pacific Rubiales was expected to provide the gas and the port for the facility and Belgium's Exmar built the

liquefaction plant and the barge. The two companies also signed a natural gas liquefaction, regasification,

storage and loading services agreement in March 2012. According to this agreement, the project is to take

the form of the world's first floating liquefaction regasification and storage unit (FSRU) and was expected

to be completed by the fourth quarter 2014.

In addition, the contract for the country's first LNG import terminal was awarded to Höegh LNG in

November 2014 by by Socieded Portuaria El Cayao (SPEC), advancing the country's desire to increase

natural gas supplies to decrease its heavy reliance on hydropower electricity generation. The contract allows

Höegh LNG to operate the terminal for 20 years but includes options to reduce the term to five, ten, or

fifteen years. Although the project is subject to SPEC obtaining environmental licensing, the unit is

currently under construction and is expected to start up in mid-2016.

With a capacity of 3.6bn cubic metres (bcm) per year, the new facility will serve to mitigate the effects of

adverse weather conditions which reduce hydropower reservoirs and help offset declining reserve potential.

This will also allow Colombia to expand its use of natural gas for power generation.



In June 2015, UPME announced that an 11.3mcm/d LNG import terminal could be installed on the Pacific

coast by 2021. This second terminal would benefit from the expansion of the Panama Canal which will

allow LNG vessels to transit beginning in 2016. Furthermore, the advent of LNG exports from the US will

be well placed to service this facility in the coming decade.

Gas Pipelines

Domestically there are three main gas pipelines in Colombia: the Ballena-Barrancabermeja, linking

Chevron's Ballena field on the north-east coast to Barrancabermeja in central Colombia; the

Barrancabermeja-Nevia-Bogota line, which integrates the Colombian capital into the transmission network,

and the Mariquita-Cali line through the western Andean foothills.

In April 2003, Colombia and Venezuela agreed to build a USD 120mn, 215km pipeline that would allow

Colombia to export gas from the Guajira Basin to Venezuela's Maracaibo region. The pipeline, inaugurated

in October 2007, allows Colombia to export gas to Venezuela. However, Colombia's growing gas

consumption needs have reduced its export capacity to Venezuela, rendering this proposed project idle.



Competitive Landscape

Competitive Landscape Summary

■ Ecopetrol accounts for more than half of the country's oil and gas production, all refining capacity, andalmost 40% of the fuels retail segment. It also controls the downstream gas industry. Ecopetrol expects itsannual investment budgets to amount to around USD6bn through 2020, it said in a strategic planpublished in late May 2015, down from recent years as it pursues a structural savings target of USD1bn ayear. The plan is the first since Juan Carlos Echeverry took over as CEO in early April 2015. It foreseesproduction of 870,000 barrels per day (b/d) by 2020, up from 722,000b/d currently, and for the companyto add 1.7bn barrels (bbl) of proven reserves by the same year.

■ Colombia plans to introduce new upstream licensing rules as the industry demands more competitiveterms after a disappointing upstream round in 2014. 'We plan a continuous and dynamic process forassigning acreage,' national hydrocarbons agency ANH's President Mauricio de la Mora said (ArgusMedia). Under the new licensing process, companies would enter into direct negotiation with the ANH ona rolling basis, 'with a legal framework that we're currently structuring', Mora added. The ANH isexpected to introduce the new measures within the next two months. Colombia awarded 26 blocks out of95 on offer in 2014.

■ International oil company (IOC) involvement is extensive, but mostly in partnership with the state underproduction sharing contracts (PSCs). Key partners are US independent Occidental, China's Sinochemand Pacific Rubiales (currently subject to an agreed USD1.7bn takeover offer). Other market participantsinclude ExxonMobil, Chevron and Perenco, which in September 2013 agreed to buy the bulk ofColombian upstream assets from Brazil's Petrobras.

■ After completing a deal with Total, Sinochem holds 19% stakes in the Cusiana and Cupiagua fields, plusshares in two major oil export pipelines. It also owns Emerald Energy with eight Colombian licences.

■ Occidental has operations in the Llanos Norte Basin of the Arauca province near the north eastern border,and in the Middle-Magdalena Basin in the Santander province. In Arauca, Oxy operates the Caño Limónoilfield. More than 1bn bbl of oil has been produced at Caño Limón since Oxy discovered the field in1983. In the Middle-Magdalena Basin, Oxy holds working interests in the La Cira-Infantas (LCI) field,which it operates in partnership with Ecopetrol.

■ In Colombia, Repsol has rights over eight onshore blocks, three exploration blocks, with a surface area of1,436sq km and five development blocks, with a net area of 274 square kilometres (sq km). ExxonMobilwas in July 2014 one of the higher bidders in the latest Colombian offshore licensing round, biddingalongside Repsol and Norway's Statoil for one block. Repsol has acquired Canada's Talisman Energy,with interests in Colombia.

■ Ecopetrol and US-based Chevron are working together to increase the recovery factor to more than 90%at the offshore Chuchupa natural gas field in Colombia. The announcement, made by Ecopetrol, comesafter the completion of maintenance work and the installation of a new gas compression system.Ecopetrol, in partnership with Chevron, operates the field as part of an agreement called the GuajiraAssociation contract. The two oil companies have invested USD106mn between 2012 and 2014 toenhance the field's lifespan and to cater to local demand, according to Ecopetrol.

■ Chevron's net gas production in 2014 was 1.92bcm, down from 2.2bcm in 2013. Chevron operates anddevelops the fields as part of the Guajira Association contract. It receives 43% of the production for theremaining life of each field and a variable production volume based on prior Chuchupa capitalcontributions. Chevron operates a nationwide network of more than 400 Texaco-branded service stations.It has a 15% market share in automotive fuels, plus 20% of the aviation fuels market and 15% oflubricants.



■ ExxonMobil operates a network of around 700 Esso- and Mobil-branded service stations in Colombia. Ithas signed an agreement to explore the Tayrona Block off the Caribbean coast. Exxon was in July 2014one of the higher bidders in the latest Colombian offshore licensing round, bidding alongside Spanishfirm Repsol and Norway's Statoil for one block.

■ Petrobras agreed the sale of 100% of shares in its Colombian subsidiary to Perenco for USD380mn. Thedeal saw Petrobras divest 11 onshore exploration and production blocks with a net production rate of6,530boe/d as well as the Colombia and Alto Magdalena oil pipelines. Petrobras provides distributionservices for fuels and lubricants through a network of 86 service stations in all regions of the country.

■ Spanish company CEPSA has holdings in 19 exploration and production (E&P) projects in the LosLlanos Basin and in the Upper Magdalena River Valley, 12 of which are operated by the group.

■ Pacific Rubiales Energy Corporation in May 2015 agreed to a USD1.7bn cash offer from Mexico's AlfaSab de CV and investment firm Harbor Energy. The transaction is expected to close in the third quarterof 2015. Pacific Rubiales owns 100% of Pacific Stratus and Meta Petroleum, two Colombian oil and gasoperators which operate and own interests in, among others, the Rubiales and Piriri oil fields inColombia's Llanos Basin and the La Creciente natural gas field in northern Colombia. In 2013, thecompany bought Petrominerales. State-controlled Ecopetrol and Pacific Rubiales in March 2015 agreednot to extend the Rubiales and Pirirí Field Association Contracts, expiring in June 2016. Ecopetrol willevaluate different alternatives for the operation of the Rubiales Field. Meanwhile, Pacific Rubiales willconsider submitting a new proposal to operate the field after the contract expiry.

■ The Colombian National Hydrocarbons Agency (ANH) expects oil companies to invest USD8bn to drill1,086 development wells in existing fields in Colombia in 2015, reports Reuters. The estimated USD8bninvestment will be used to boost recovery rates from oil wells in Colombia, according to ANH's VicePresident Haydee Daisy Cerquera. 'These are wells to develop certified reserves,' Cerquera said, addingthat the purpose of drilling the wells is to provide additional points of access in fields that are alreadyproducing oil.

Table: Key Players - Colombian Oil & Gas Sector

Company 2012 Sales(COPbn)

% Share ofglobal sales

No. ofemployees

Yearestablished

2012 TotalAssets

(COPbn)

Ownership (%)

Ecopetrol 59,525 91 6,695 1951 100,648 89.9% state

ExxonMobilColombia na na 750e 1918 na 100% ExxonMobil

ChevronColombia na na 550 1926 na 100% Chevron

OccidentalColombia na na 900 1980 na 100% Occidental

PetrobrasColombia* na na na 1972 na 100% Petrobras

Shell Colombia na na na 1956 na 100% RD Shell

PerencoColombia na na 198 1993 na 100% Perenco

*Sold to Perenco; e = BMI estimate; na = not available. Source: Company data 2011/12, BMI



Company ProfileEmpresa Colombiana de Petróleos (Ecopetrol)

SWOT Analysis

Strengths ■ Control of all key hydrocarbons interests.

■ Unrivalled access to exploration acreage.

■ Ownership of national refining system.

■ Partnerships with IOCs.

Weaknesses ■ Limited financial or operational freedom.

■ Cost and efficiency disadvantages.

■ Lack of geographical diversification.

Opportunities ■ Renewed IOC interest in Colombia.

■ Considerable untapped gas potential.

■ Large areas of unexplored territory.

Threats ■ Guerrilla disruptions to supply and exports.

■ Changes in national energy policy.

Company Overview The company carries out direct hydrocarbon exploration activities in 32 Colombian

blocks and works with other companies in 15 more concession areas. Ecopetrol is

responsible for the total production of crude oil and gas in the country. It has four

divisions to handle the operation of 163 producing fields, and is also responsible for

transportation, refining and fuels distribution in Colombia. Ecopetrol´´s production

(direct and associated) is concentrated in the Upper, Middle and Lower Magdalena, the

Eastern Plans and the Caribbean, and the provinces of Putumayo, Cesar and Norte de

Santander. The transportation system extends to 8,500km, which converge at the

Coveñas and Santa Marta terminals in the Atlantic, and Buenaventura and Tumaco in

the Pacific.



Strategy Ecopetrol expects its annual investment budgets to amount to around USD6bn through

2020, it said in a strategic plan published in late May 2015, down from recent years as it

pursues a structural savings target of USD1bn a year. The plan is the first since Juan

Carlos Echeverry took over as CEO in early April 2015. It foresees production of

870,000 barrels per day (b/d) by 2020, up from 722,000b/d currently, and for the

company to add 1.7bn bbl of proven reserves by the same year. Ecopetrol plans to

invest around USD4bn per year in production and boost reserves by increasing the

amount of oil that can be recovered from existing fields through technologies including

injection of liquids and gas. The state company carries out direct hydrocarbon

exploration activities in 32 Colombian blocks and works with other companies in 15

more concession areas. It has four divisions to handle the operation of 163 producing

fields, and is also responsible for transportation, refining and fuels distribution in

Colombia.

Ecopetrol intends to farm-out some production assets as part of its effort to improve its

portfolio, according to the head of the National Planning Department, Simon Gaviria.

The company seeks to focus on core oil operations amid a sharp decline in international

oil prices. The company owns stakes in sectors such as petrochemicals, electricity

transmission and generation, and could sell its stake in energy investment company

Invercolsa in 2015, Gaviria said. Ecopetrol may ask for as much as USD450mn for

Invercolsa, which is nearly four times its book value, according to two people with direct

knowledge of the matter. Ecopetrol could also accept bids from companies looking to

operate its Rubiales field in Colombia, if it decides not to do so itself in 2015.

Ecopetrol will refine its production strategy, according to CEO Juan Carlos Echeverry.

The company will focus on about 20 oilfields that produce 80% of its onshore crude

and have output costs of between USD7 and USD17 a barrel, leaving wells with higher

extraction expenses to other companies. The company will also focus its efforts in

areas like the Gulf of Mexico, Echeverry said. 'We have to be very selective about where

we invest - Colombia's coast, the Gulf of Mexico and key production in the country to

keep cash flow - are the three priority focuses at this moment,' he explained (Reuters).

Ecopetrol and US-based Chevron are working together to increase the recovery factor

to more than 90% at the offshore Chuchupa natural gas field in Colombia. The

announcement, made by Ecopetrol, comes after the completion of maintenance work

and the installation of a new gas compression system. Ecopetrol, in partnership with

Chevron, operates the field as part of an agreement called the Guajira Association

contract. The two oil companies have invested USD106mn between 2012 and 2014 to

enhance the field's lifespan and to cater to local demand, according to Ecopetrol.

Colombia plans to introduce new upstream licensing rules as the industry demands

more competitive terms after a disappointing upstream round in 2014. 'We plan a

continuous and dynamic process for assigning acreage,' national hydrocarbons agency

ANH's President Mauricio de la Mora said (Argus Media). Under the new licensing

process, companies would enter into direct negotiation with the ANH on a rolling basis,

'with a legal framework that we're currently structuring', Mora added. The ANH is



expected to introduce the new measures within the next two months. Colombia

awarded 26 blocks out of 95 on offer in 2014.

Ecopetrol will supply crude oil to a new refinery that will commence operations in 2015,

according to Alan Jara, governor of the country's central Meta province. 'There is a

letter of intent that guarantees the oil necessary to supply the refinery,' Jara said

(Bloomberg). The refinery, which will be based in the province of Meta, will supply fuel

to the region. Moreover, it will supply diluents to Ecopetrol for the pipeline

transportation of heavy crudes. Jara added that nearly USD1.5bn will go towards

construction of the refinery, which is expected to have a refining capacity of 40,000

barrels of crude per day.

The company has reported that it and its affiliate Hocol have submitted the best offers

for five exploratory blocks in Round Colombia 2014, following the opening of bidding by

the National Hydrocarbons Agency (ANH) in Cartagena.

For the offshore block 'Sin Off 7', located in the Colombian Caribbean, the best bid was

submitted by the Union Temporal (joint association) between Ecopetrol and Royal

Dutch Shell, the latter as operator. Hocol made the best offers for four blocks in the

Sinu San Jacinto basin: SN-8, SN-15, SN-18 and the YDSN1 (Discovered

Underdeveloped Reservoir). The investment by Ecopetrol and Hocol in the five blocks is

estimated at approximately USD80mn during the initial phase of exploration, which

includes the minimum mandatory commitments and the additional investment offered in

the round.

Ecopetrol is seeking to invest in Mexican onshore fields to open up its energy sector,

according to Magda Manosalv, the company's chief financial officer. Ecopetrol aims a

turnaround in output of up to 1mn barrels of oil equivalent per day (boe/d) in 2015.

Production was at this level in 2013, but has been reduced to an average 750,000boe/d

in 2014 to date as a result of rebel group attacks. The company is working with the

Colombian government to streamline approval of explorations, which can take around

two years to receive.

A tax reform law passed by Colombian congress has raised royalty rates on crude and

natural gas production to 75% from its current 70%, discouraging further exploration

and development, according to oil industry trade association, the Colombian Petroleum

Association (ACP). The increase in the government's share of revenue generated by oil

companies remained in the bill despite lobbying by the sector for its exclusion, ACP

President Francisco Lloreda. The new tax law will also help fill the fiscal gap by

extending financial transaction tax and wealth tax that were due to expire or begin

fading out in 2014.

The Colombian National Hydrocarbons Agency (ANH) expects oil companies to invest

USD8bn to drill 1,086 development wells in existing fields in Colombia in 2015, reports

Reuters. The estimated USD8bn investment will be used to boost recovery rates from

oil wells in Colombia, according to ANH's Vice President Haydee Daisy Cerquera.

'These are wells to develop certified reserves,' Cerquera said, adding that the purpose



of drilling the wells is to provide additional points of access in fields that are already

producing oil.

Ecopetrol will collaborate with US independent Anadarko Petroleum to explore oil

deposits in two blocks in the Caribbean Sea. Anadarko will hold a 50% stake in the

Fuerte Sur and Fuerte Norte blocks offshore Colombia. Moreover, the partners have

secured government approval for oil exploration in the Purple Angle block. The three

blocks cover an area of 10,320sq km. However, Ecopetrol declined to reveal any

financial details related to the partnership.

Ecopetrol and Canada-based Talisman Energy have announced plans to move forward

with the development of the Akacias field in Block CPO-9 in Colombia. Subsequent to

the Akacías discovery in 2010, the co-venturers are in the process of completing a nine-

well appraisal proramme. The co-venturers have submitted a Declaration of

Commerciality to the regulator and a conceptual field development plan will be

submitted within the next 90 days. Ecopetrol is the operator of Block CPO-9 with a 55%

stake, working alongside Talisman with the remaining 45%.

Key elements of Ecopetrol's strategy include boosting exploration in Colombia to

increase oil and gas reserves and maximise profitability, diversifying risk and extending

the company's portfolio, increasing the recovery factor in mature fields, improving the

efficiency of the refining system, providing competitive transportation services and

developing heavy crude and gas assets.

Downstream, Ecopetrol plans to carry out upgrades and expansion at both its major

refineries. The company plans to invest USD2.9bn in the Barrancabermeja refinery and

USD1.3bn in Cartagena. Ecopetrol is boosting investment in refining and

petrochemicals by 59% year-on-year (y-o-y), earmarking USD1.3bn for the divisions.

Around USD679mn will be spent on upgrading the Barrancabermeja refinery, while

USD470mn will go to the modernisation of the Cartagena oil processing plant. In the

midstream segment, the majority of investment will go on raising the capacity of the

Pozos-Galán pipeline from 18,000b/d to 60,000b/d.

The Cartagena refinery is due to resume operations in May 2015 after the completion of

expansion works, reports Reuters, citing the company's executive vice-president. The

refinery's crude distillation unit was closed in March 2014, while the cracking unit was

shut down in 2013. The company is expanding the capacity of the Cartagena Refinery

from the existing 80,000b/d to 165,000b/d in an attempt to increase exports and reduce

imports.

Market Position Ecopetrol carries out direct hydrocarbon exploration activities in 32 Colombian blocks

and works with other companies in 15 more concession areas. Ecopetrol is responsible

for the total production of crude oil and gas in the country. It has four divisions to

handle the operation of 163 producing fields, and is also responsible for transportation,

refining and fuels distribution in Colombia. Ecopetrol´´s production (direct and



associated) is concentrated in the Upper, Middle and Lower Magdalena, the Eastern

Plans and the Caribbean, and the provinces of Putumayo, Cesar and Norte de

Santander. The transportation system extends to 8,500 kilometres, which converge at

the Coveñas and Santa Marta terminals in the Atlantic, and Buenaventura and Tumaco

in the Pacific.

Ecopetrol has announced a 5.7% increase in its audited proven (1P) reserves to 2.08bn

barrels of oil equivalent (boe) in 2014, reports BNamericas. The figure comprises

Ecopetrol reserves and from interests in affiliates and subsidiaries. The company added

355mn boe to its proven reserves in 2014, up from the 340mn boe increase in 2013.

'The increase in proven reserves is mainly the product of revisions at existing fields, and

increased gas reserves,' Ecopetrol said in a statement (BNamericas). The company has

raised its net reserves by 22%, with an average reserve replacement ratio of 150% over

the last five years.

Net profit tumbled 96% in the first quarter of 2015 from the same period a year earlier,

largely due to the sharp drop in crude oil prices. Ecopetrol posted a consolidated net

profit of COP160bn in the quarter, compared with COP3.88trn in the same period a year

earlier.

Earnings before interest, taxes, depreciation and amortisation, EBITDA, fell 60% to

COP3.15trn in the first quarter. The company's consolidated oil and gas production,

which includes subsidiaries, rose 1% year-on-year to 773,400boe/d. The non-

consolidated figure for Ecopetrol alone was 722,000boe/d.

Ecopetrol has found oil at the Embrujo-1 ST2 horizontal well on the eastern block of the

Cano Sur licence in Colombia. The well was drilled to 1,560 metres and its results

indicate that the well has an average production rate of 434b/d. The discovery was

Ecopetrol's seventh discovery at Cano Sur.

Ecopetrol has discovered crude oil at Aullador-I exploratory well in Colombia's

Santander province. The well was drilled to a depth of 3,472 metres and produced

300b/d. The well is part of the Playon exploration and production agreement signed

between Ecopetrol and the National Hydrocarbons Agency in April 2008. The well

indicated low water cut and sediment of just 0.1%, and a gas-oil ratio of 200.

Ecopetrol has discovered heavy crude oil at the Pastinaca 1 exploratory well on

CPO-10 Block in the Colombian town of Puerto López. The well, which was drilled to a

total depth of 2,398 metres, is part of the CPO-10 exploration and production

agreement signed between Ecopetrol and ANH in 2008. The company said that the

Pastinaca 1 well yielded average crude oil production of 202b/d. Accumulated

production to date is more than 1,448b/d. The Pastinaca 1 well is 100% owned by

Ecopetrol.

Ecopetrol has discovered hydrocarbons at its Guainiz-1 exploratory well, Scandinavian

Oil-Gas Magazine reports. The well, located in the Municipality of San Carlos de

Guaroa, Meta Province, has provided initial test results of 409b/d of 14.4o API crude



and a water cut of 8.4%. It was the third discovery on the CPO-10 block by Ecopetrol in

2013.

The company has reached a deal to sell a 50% stake in its Capachos oil block to

Canadian-listed Parex Resources Inc, which would be the operator. Parex will pay the

full cost of the first two wells to be developed on the block under the terms of the deal

reached on May 5 2014, Ecopetrol said in a statement.

Ecopetrol said the Capachos block in Colombia's eastern plains may contain light crude

at a depth of around 16,000 feet. Drilling would start in the first quarter of 2015 under

the terms of the deal which must still be approved by the National Hydrocarbons

agency.

Ecopetrol has achieved a production record at the Chichimene field in Colombia, as it

increased extra-heavy crude output in the central department of Meta. Chichimene field

production reached 86,389 barrels on January 2, up from an estimated 85,000 barrels.

The company has increased production at the Chichemene-Castilla complex by 78%

year-on-year to more than 200,000 barrels per day (b/d) in 2014. The Chichimene field,

which is the third largest crude producer, has the highest extra-heavy crude output

among any field in Colombia.

Ecopetrol and Canada-based oil exploration company Talisman Energy have

discovered hydrocarbons in the Nueva Esperanza-1 well on block CPO-9 in Colombia's

Meta department. The well was spud on July 18 and was drilled to a final depth of 3,675

metres. In the initial test, the well showed a stabilised daily flow rate of 910b of 8-

degree API oil. The companies will continue to analyse the well's results and seek

government permission to conduct further testing. Nueva Esperanza-1 is the second oil

discovery made by the companies in block CPO-9. Ecopetrol is the operator of the

block with a 55% interest, while Talisman holds the remaining 45% interest.

Financial Data Revenue:

■ COP58.1trn (2014)■ COP62.51trn (2013)■ COP59.52trn (2012)■ COP65.7trn (2011)■ COP36.7trn (2010)■ COP30.4trn (2009)■ COP33.9trn (2008)■ COP22.33trn (2007)■ COP18.39trn (2006)

Net income:

■ COP7.8trn (2014)■ COP13.4trn (2013)■ COP14.9trn (2012)■ COP15.5trn (2011)



■ COP8.3trn (2010)■ COP5.1trn (2009)■ COP11.6trn (2008)■ COP5.2trn (2007)■ COP3.4trn (2006)

Operational Data ■ Net Oil production: 498,500b/d (2014)■ Net Oil production: 523,400b/d (2013)■ Net Oil production: 502,400b/d (2012)■ Net Oil production: 483,000b/d (2011)■ Net Gas production: 103,800boe/d (2014)■ Net Gas production: 106,800boe/d (2013)■ Net Gas production: 89,200boe/d (2012)■ Net Gas production: 78,200boe/d (2011)■ Proven oil reserves: 2.08bn boe (2014)



Chevron

SWOT Analysis

Strengths ■ Dominant domestic gas producer.

■ E&P upside potential.

■ Significant share of fuels retail segment.

Weaknesses ■ Absence of oil production.

■ No role in oil refining.

■ No integration between upstream and downstream operations in Colombia.

Opportunities ■ Considerable untapped gas potential.

■ Growth in domestic oil demand.


Threats ■ Extensive state involvement.


■ Delays in environmental licensing.

■ Security risks.

Company Overview Chevron, in partnership with Ecopetrol, operates the offshore Chuchupa natural gas

field in the Caribbean Sea as well as the onshore Ballena and Riohacha natural gas

fields in the province of La Guajira, in northern Colombia. Net gas production in

2014 was 1.92bn cubic metres, down from 2.2bcm in 2013. Chevron operates and

develops the fields as part of the Guajira Association contract. It receives 43% of the

production for the remaining life of each field and a variable production volume based

on prior Chuchupa capital contributions. Chevron operates a nationwide network of

more than 400 Texaco-branded service stations. It has a 15% market share in

automotive fuels, plus 20% of the aviation fuels market and 15% of lubricants.



Strategy Ecopetrol and Chevron are working together to increase the recovery factor to more

than 90% at the offshore Chuchupa natural gas field in Colombia. The announcement,

made by Ecopetrol, comes after the completion of maintenance work and the

installation of a new gas compression system. Ecopetrol, in partnership with Chevron,

operates the field as part of an agreement called the Guajira Association contract. The

two oil companies invested USD106mn between 2012 and 2014 to enhance the field's

lifespan and to cater to local demand, according to Ecopetrol.

The US firm took advantage of a gas transport network, inaugurated in October 2007,

which transfers Colombian gas to Venezuela's energy-poor western regions. This

infrastructure opened up an entirely new market for the firm and provided an incentive

to expand production. Comments from the firm's head of Latin American operations, Ali

Moshiri, indicate that the group is targeting output of 7.7bcm from the Punta Ballenas

fields. Chevron and other gas producers will pump gas through to Venezuela, but when

these reserves run out, the gas flow will be reversed. Venezuela has significantly more

gas reserves than Colombia, but has yet to connect its production facilities to the

poorer western regions of the country. Once a new network is built, Caracas will be able

to export excess gas to Colombia.

Colombia, which hopes to become a 'gas hub for the Andean region', has ambitious

plans for its gas sector. The end of controlled gas prices in 2003 made the possibility of

gas trade more attractive. The net balance allows for limited export volumes to the Latin

American region. This means that Chevron's leading position in the gas market creates

significant opportunity for the company to benefit from the rise in domestic gas

consumption. While no such intentions have been announced, Chevron is also well

placed to participate in the government's liquefied natural gas (LNG) push.

A tax reform law passed by the Colombian congress has raised royalty rates on crude

and natural gas production to 75% from its current 70%, discouraging further

exploration and development, according to oil industry trade association, the

Colombian Petroleum Association (ACP). The increase in the government's share of

revenue generated by oil companies remained in the bill despite lobbying by the sector

for its exclusion, ACP President Francisco Lloreda. The new tax law will also help fill the

fiscal gap by extending financial transaction tax and wealth tax that were due to expire

or begin fading out in 2014.







producing oil.



Market Position Chevron's activities in Colombia are focused on the production and commercialisation

of natural gas from properties in the Caribbean Sea and adjacent coastal areas of the

Guajira Peninsula. Chevron, in partnership with Ecopetrol operates the offshore

Chuchupa natural gas field in the Caribbean Sea as well as the onshore Ballena and

Riohacha natural gas fields in the province of La Guajira, in northern Colombia. Net

gas production in 2014 was 1.92bcm, down from 2.2bcm in 2013. Chevron operates

and develops the fields as part of the Guajira Association contract. Chevron receives

43% of the production for the remaining life of each field and a variable production

volume based on prior Chuchupa capital contributions. In 2014, additional compression

facilities for existing fields were installed.

Chevron has been involved in the marketing and distribution of fuels and lubricants

since the 1950s. The company operates a nationwide network of 400 Texaco-branded

stations, equal to a 15% share of the automotive fuels sector and 15% of the lubricants

market in the country. The company also has a 20% market share in aviation fuel and

has interests in 10 fuel terminals in the country.

Chevron and Ecopetrol have a long-term purchase and sales agreement with

Venezuela's national gas company, PdVSA, to deliver an average of 150mn cubic feet

of natural gas per day from Colombia to Venezuela. Since its signing in 2007, this trade

agreement has contributed to the regional and national economies. The agreement also

allows for a separate deal for future deliveries of natural gas from Venezuela to

Colombia.

Operational Data Net gas production:

■ 1.9bcm (2014)■ 2.2bcm (2013)■ 2.2bcm (2012)■ 2.4bcm (2011)■ 2.6bcm (2010)■ 2.5bcm (2009)■ 2.16bcm (2008)■ 1.84bcm (2007)■ 1.80bcm (2006)■ 1.91bcm (2005)

Company Details ■ Chevron Colombia

■ Calle 100No 7-A-81

Bogotá

Colombia

■ Tel: +57 (1) 639 4510



Occidental

SWOT Analysis

Strengths ■ Substantial domestic oil producer.

■ Significant exploration portfolio.

■ Ownership of export infrastructure.

• Good relationship with Ecopetrol.

Weaknesses ■ Oil volumes in decline.

■ Need to increase investment.

Opportunities ■ Improved fiscal terms.

■ Renewed IOC interest in Colombia.

■ Considerable untapped oil/gas potential.


Threats ■ Resurgence of guerrilla disruptions to supply and exports.

■ Declining near-term volumes and revenues.


■ Conflict with Venezuela cutting off gas trade.

Company Overview The company's 2014 Colombian crude production averaged 27,000 barrels per day (b/

d), according to the firm's website. Currently, Oxy has operations in the Llanos Norte

Basin of the Arauca province near the north-eastern border, and in the Middle-

Magdalena Basin in the Santander province. In Arauca, Oxy operates the Caño Limón

oilfield. The Caño Limón field, which held up to 1.3bn barrels (bbl) of reserves, was

discovered in 1983. Production peaked at 208,000b/d in 1990, with output still

accounting for around one-third of Colombia's total oil supply. The field is operated

under an association contract with Ecopetrol, which was extended in April from the



original 2008 end date through to the end of the field's economic life in around 2018. In

the Middle-Magdalena Basin, Oxy holds working interests in the La Cira-Infantas (LCI)

field, which it operates in partnership with Ecopetrol.

Strategy Occidental expects to reduce its total 2015 capital spending by 33% to USD5.8bn from

USD8.7bn spent in 2014. Oil and gas capital spending is expected to be approximately

USD4.5bn during the year.

Oxy remains upbeat regarding Colombian prospects, despite of guerrilla attacks on

pipelines. It expects to see production growth, particularly in heavy oil, according to

CEO Stephen Chazen. In June 2014, Oxy and Colombian state oil firm Ecopetrol formed

a partnership to enhance recovery at Ecopetrol's Teca-Cocorná heavy oil field. The

company's fourth quarter Colombian crude production was 32,000 barrels per day (b/

d), according to the firm's most recent quarterly report.

Colombia accounts for Oxy's entire production base in Latin America. Despite declining

output and bomb attacks on oil pipelines, the US-based firm has maintained its

presence and is now beginning to reap some benefit, with recently revised fiscal terms

making Colombia a more attractive investment environment. This position contrasts

sharply with the firm's difficulties in other parts of Latin America.

Production in Colombia is roughly equivalent to 4% of Oxy's total production. There is

scope for upside though, especially in light of renewed investor interest in Colombia

and the government's willingness to meet ambitious targets.















producing oil.

Market Position International average daily production volumes decreased to 279,000boe for the 12

months of 2014 from 289,000boe/d in 2013. The decrease was primarily due to lower

cost recovery barrels in Iraq and insurgent activities in Colombia, Libya and Yemen. The



company's fourth quarter Colombian production averaged 32,000b/d, with Oxy

reporting 27,000b/d as the average for the whole of 2014.

Oxy has operations in the Llanos Norte Basin of the Arauca province near the north-

eastern border, and in the Middle-Magdalena Basin in the Santander province. In

Arauca, Oxy operates the Caño Limón oilfield where output still accounts for around a

third of Colombia's total oil output. The field is operated under an association contract

with Ecopetrol, which was extended in April from the original 2008 end date through to

the end of field's economic life in around 2018. In the Middle-Magdalena Basin, Oxy

holds working interests in the La Cira-Infantas (LCI) field, which it operates in

partnership with Ecopetrol.

Other interests include the Cosecha Block in the Llanos Basin, located nearby the Caño

Limón field and close to the Venezuelan border. Occidental also has a 44% interest in

the Caño Limón pipeline, linking its Arauca oil fields to the port of Coveñas on the

Caribbean coast. This pipeline has been a popular target for Colombia's guerrilla groups

and was bombed 17 times between 2004 and 2007. When operational it moves some

90,000-95,000b/d.

Ecopetrol reached an agreement with Occidental (Oxy) to take full control of the Caño

Limón-Covenas oil pipeline, the country's second largest. The pipeline has been a

popular target for militants and, as a result, operates at only about 35% of its full

225,000b/d capacity.

Restoring capacity on the pipeline will likely require significant investment, but will be

crucial to transporting increased production from the east of the country to export

infrastructure on the Caribbean coast. For Oxy, the deal means it maintains its access

to the pipeline, which is crucial for transporting crude from its 1.3bn bbl Caño Limón

field to export infrastructure on the Caribbean coast, but allows it to move out of an

asset that has required significant investment in security and maintenance.

Financial Data Group Net sales:

■ USD19.32bn (2014)■ USD20.17bn (2013)■ USD20.10bn (2012)■ USD16.13bn (2011)

Group Net Income:

■ USD616mn (2014)■ USD5.9bn (2013)■ USD4.6bn (2012)■ USD6.8bn (2011)



Operational Data Oil production:

■ 27,000b/d (2014)■ 29,000b/d (2013)■ 29,000b/d (2012)■ 29,000b/d (2011)■ 32,000b/d (2010)■ 39,000b/d (2009)

Company Details ■ Occidental de Colombia

■ Calle 77-ABogotá

Colombia

■ Tel: +57 (1) 345 4155

■ Fax: +57 (1) 628 8444



Perenco

SWOT Analysis

Strengths ■ Growing portfolio of producing assets.

■ Significant exploration acreage.

Weaknesses ■ Heavy investment requirement.

■ Oil price exposure

Opportunities ■ Large areas of unexplored territory.

Threats ■ Changes in national energy policy.

Company Overview Perenco has been operating in Colombia since the acquisition of Elf Aquitaine Colombia

SA assets in the llanos in 1993. Following the completion of further successful

transactions, namely the 2011 acquisition of the Oropendola and Vireo fields and the

recent major acquisition of Petrobras Colombia in 2014, Perenco's operated production

in 2014 reached 35,000b/d. Petrobras said the sale to Perenco included 11 onshore

exploratory and production blocks that had average output of 6,530boe/d.

Strategy Brazil's Petrobras said in September 2013 that its board had approved the sale of its

Colombian oil pipelines and some of its onshore oil blocks to Perenco for USD380mn.

Petrobras said the sale to Perenco included 11 onshore exploratory and production

blocks that currently have average output of 6,530boe/d. Perenco also acquired

Petrobras' oil pipelines Colombia and Alto Magdalena, with respective capacities of

14,950b/d and 9,180b/d.

The 2014 drilling campaign included seven development wells and four exploration

wells (Katmandú Norte -1, Chácharo-1, Zamuro-1, Uraca-1), as well as more than 100

well interventions (including, production optimisation, oil behind casing, ESP/PCP

changes and stimulations). In total these wells have added close to 10,500b/d through

production optimisation.

Since receiving commerciality of the Guando South West field from Ecopetrol (the

Colombian State Company), Perenco has successfully completed its first phase of

development drilling.



Market Position Perenco has been operating in Colombia since the acquisition of Elf Aquitaine Colombia

SA assets in the llanos in 1993. Following the completion of further successful

transactions, namely the 2011 acquisition of the Oropendola and Vireo fields and the

recent major acquisition of Petrobras Colombia in 2014, Perenco's operated production

is now 35,000b/d (2014).

The acquisition of Petrobras Colombia's (PEC) assets was concluded on April 30th

2014, this included interests in 11 onshore exploration and production blocks and

participation in the Colombia and Alto Magdalena oil pipelines. Perenco assumed

operatorship of PEC's assets on May 1 2014 and these assets are now known as

Perenco Oil and Gas Colombia Limited.

In Casanare, Perenco is the operator of a large number of contracts including five

association contracts (Casanare, Estero, Garcero, Corocora, Orocue), four ANH

contracts (Oropendola, Balay, Llanos-45 and Cerrero blocks) and one concession

contract (Yalea.)

In Tolima, Perenco is the operator of the Boqueron and Espinal association contracts.

Guando is one of the three largest discoveries made in Colombia in the last 15 years.

Perenco has a share in seven non-operated contracts in both exploration and

production phases, three in Casanare (Tiple, Puntero and Merecure blocks), two in Huila

(San Jacinto and Rio Paez blocks), one in Cordoba (Sinu-3 block, (ANH round 2012) in

exploration phase, and one in La Guarija (CR-1 block, in exploration phase.)

On May 28 2014, Colombian environmental regulator Anla suspended Perenco's crude

transportation operations in the eastern Casanare department, Colombia, reports

BNamericas. The regulator asked the company to halt the pipeline carrying crude from

the LGL-19 and La Gloria wells on the Casanare A1a block to protect local water source

Caño Palo Blanco. There had been two leaks in the pipeline in less than two years that

could have been prevented with proper maintenance, Anla added.



Sinochem

SWOT Analysis

Strengths ■ Strategic partnership with Ecopetrol.

■ Substantial exploration portfolio.

• Ownership of export infrastructure.

Weaknesses ■ Oil volumes in decline.

■ Low capex.

■ No involvement in refining or distribution.


■ Considerable untapped oil/gas potential.


Threats ■ Guerrilla disruptions to supply and exports.

■ Declining near-term volumes and revenues.


Company Overview Tepma BV holds a working interest in the Santiago de las Atalayas and Tauramena y

Rio Chitamena concessions. The main producing asset - the Cusian oil field is part of

the Tauramena concession. In all these fields the Sinopec subsidiary holds a 19%

interest. Sinochem subsidiary Emerald Energy holds 50%-100% interests of eight

exploration and production blocks in Colombia through Emerald Energy Sucursal

Colombia.

Strategy China has been increasing its footprint in Latin America and Colombia has been at the

forefront of their ventures. The country's natural resource potential is of major interest to

the Asian giant, which is looking at the continent as a major source natural resources.



Sinochem Group is China's fourth biggest oil producer, and its acquisition of highlights

the growing Chinese ambitions in Colombia's oil and gas sector, and in the region as a

whole. The deal is intended to give Sinochem a launch pad for operations that will lead

to a bigger presence in the Latin American market. This in turn is the first step towards

its ambitions to be a global presence and an integrated oil and gas company.

Tempa is now a full subsidiary of Sinochem and the Chinese company will use it as a

vehicle to increase the exploration and production of crude oil in the country and to

increase its footprint in the region. This acquisition was fully in line with Sinochem's 'Go

Global' strategy that (as the name clearly indicates) was prioritising overseas expansion,

specifically in Latin America and the Middle East.

Sinochem said the deal will help it explore and develop existing oil fields and further lay

its foundation in Latin America, where the company aims to produce 5mn tonnes of oil

equivalent (100,000boe/d) by the end of 2020.

This latest step follows on Sinochem's agreement in January 2012 to buy a 10% stake

in five offshore oil blocks in the Espirito Santo basin in Brazil from the Anglo-French oil

company Perenco.

Since the acquisition, Tepma Sinopec has made rapid advances across Colombia,

supported by the Chinese government. In May 2012, Sinochem and Ecopetrol signed

an agreement to jointly develop a new oil pipeline that will link oil fields to the Pacific

coast. China Development Bank is going to financially back the venture. This agreement

was the harbinger for the long-term strategic cooperation agreement that Ecopterol and

Sinochem signed, giving the Chinese company a major strategic advantage in the

country.

Market Position Tepma BV holds a working interest in the Santiago de las Atalayas and Tauramena y

Rio Chitamena concessions. The main producing asset - the Cusian oil field is part of

the Tauramena concession. In all these fields the Sinopec subsidiary holds 19%

participation.

On January 10 2013, Sinochem Petroleum Exploration & Production carried out a test of

the Vigia_Sur1 well (located at the CR Block of Colombia) in the UNE layer and

confirmed its output of 600 barrels per day (b/d). The discovery of the commercial oil

flow is a signal that Sinochem has made a new oil find in CR Block.

In October 2009, Sinochem Group acquired 100% equity of Emerald Energy and

obtained its oil and gas assets in Syria, Colombia and Peru, including 50%-100% equity

of eight exploration and production blocks in Colombia. The CR Block formed part of

the Emerald package.



Financial Data Revenues (Sinochem Group)

■ HKD504.0bn (2014)■ HKD426.5bn (2013)■ HKD402.3bn (2012)■ HKD412.6bn (2011)■ HKD293.7bn (2010)

Net Income:

■ HKD3.9bn (2014)■ HKD5.4bn (2013)■ HKD6.8bn (2012)■ HKD4.7bn (2011)



Pacific Rubiales Colombia

SWOT Analysis

Strengths ■ Strong footprint in Colombia.

■ Largest foreign upstream player in Colombia.

■ Prolific assets.

• Strong E&A and development pipeline.

Weaknesses ■ Frequent operational problems at fields.

■ Poor relations between oil companies and labour as well as local indigenous groups

have led to protests that have shut down production.

Opportunities ■ Government support for of LNG exports as gas production outpaces domestic

consumption.

■ Exploration and field development upside.

■ Volume and synergy benefits from Petrominerales acquisition.

Threats ■ High security risk with rebel activity increasingly targeting oil sector and foreign oil

workers.

■ Inadequate midstream

■ Loss of Rubiales field to Ecopetrol.

Company Overview Pacific Rubiales owns 100% of Pacific Stratus and Meta Petroleum, two Colombian oil

and gas operators which operate and own interests in, among others, the Rubiales and

Piriri oil fields in Colombia's Llanos Basin and the La Creciente natural gas field in

northern Colombia. In 2013, the company bought Petrominerales. The company is

focused on identifying growth opportunities in almost all the hydrocarbon basins in

Colombia. The agreed offer of USD1.7bn from Alfa Sab de CV and Harbor Energy

implies a potential shift in investment strategy.



Strategy Pacific Rubiales Energy Corporation in May 2015 agreed to a USD1.7bn cash offer from

Mexico's Alfa Sab de CV and investment firm Harbor Energy. The transaction is

expected to close in the third quarter of 2015. Pacific Rubiales owns 100% of Pacific

Stratus and Meta Petroleum, two Colombian oil and gas operators which operate and

own interests in, among others, the Rubiales and Piriri oil fields in Colombia's Llanos

Basin and the La Creciente natural gas field in northern Colombia. In 2013, the

company bought Petrominerales. Ecopetrol and Pacific Rubiales in March 2015 agreed

not to extend the Rubiales and Pirirí Field Association Contracts, expiring in June 2016.

Ecopetrol will evaluate different alternatives for the operation of the Rubiales Field.

Meanwhile, Pacific Rubiales will consider submitting a new proposal to operate the field

after the contract expiry.

Pacific Rubiales' subsidiary Meta Petroleum has purchased a 100% interest in

Colombia's Sabanero oil block from France-based Maurel & Prom's Colombian

subsidiary, reports BNamericas. As part of the transaction, Pacific Rubiales agreed to

cancel Maurel & Prom's USD94mn debt and offer a USD10mn cash settlement. Pacific

Rubiales announced in early 2013 that it will invest USD555mn in developing the Quifa,

Cajua, Rubiales and Sabanero fields as well as its Oleoductio Bicentenario pipeline and

CPE-6 oil block.

Pacific Rubiales has decided to postpone the start-up of the Caribbean floating

liquefied natural gas (FLNG) project due to unfavourable market conditions, according

to its project partner Exmar. However, the company has confirmed that it would take

delivery of the Caribbean FLNG in H215. The company is committed to the project and

is assessing different options, including relocation of the Caribbean FLNG barge to a

different site, Exmar stated. The project includes a non-propelled barge that will be

operated off the Caribbean coast of Colombia for Pacific Rubiales, and is equipped to

convert 2.04mn cubic metres of natural gas into LNG (about 500,000 tonnes of LNG a

year) for temporary storage and export. Exmar will utilise carriers with an LNG capacity

of 125,000-151,000 cubic metres to deliver the shipments.

'The significant drop in oil prices has meant that we have had to reconsider all of our

capital expenditures,' Peter Volk, General Counsel at Pacific Rubiales, told Reuters.

Under a deal signed last year, Russia's Gazprom was contracted to receive half a

million tonnes of LNG per annum over four years from the Colombian project. 'Gazprom

is aware of the postponement and we are working with them in evaluating the

alternative options,' he said.

Petroamerica Oil has signed a definitive agreement with Pacific Stratus to purchase a

50% stake in the Llanos-19 block, excluding the Tormento Field where PSE will retain

its 100% working interest. The agreement will see Petroamerica pay 100% of the

capital and operational expenditures of the next exploration well up to a maximum of

USD17mn. Drilling activities in Llanos-19 could start by Q414, contingent on securing

approval from hydrocarbons agency ANH.

The company has entered into a three-year Memorandum of Understanding and

Cooperation (MOU) with Mexico's state oil company Petróleos Mexicanos (Pemex) and



its subsidiary entities, establishing a framework for cooperating in potential oil and gas

projects in Mexico.

Market Position Pacific Rubiales, via its 100%-owned subsidiary Meta Petroleum, has stakes in 35

blocks in northern and central Colombia, six of them awarded in the 2008 licensing

round. It was awarded six additional blocks in 2010. Its main producing assets are the

Rubiales and Piriri oil fields in the Llanos Basin where it works alongside Ecopetrol.

Revenues for the first quarter of 2015 were USD800mn, a decrease of 19% year-on-

year, due to the decline in crude oil market prices. Average oil and gas sales (including

trading) for the first quarter were a record 180,086boe/d, an increase of 19% compared

with the same period in 2014.

Adjusted EBITDA decreased by 36% to USD270mn from USD419mn in the fourth

quarter of 2014.Net loss for the first quarter of 2015 was USD722mn, reflecting the

significant decline from crude oil price realisation as well as a non-cash impairment on

assets. Other non-cash items affecting earnings included unrealized foreign exchange

losses and DD&A.

Eight exploration wells (including stratigraphic and appraisal wells) were drilled in the

quarter, resulting in six discoveries. This was a 75% success rate for the quarter,

compared to 56% in the same period of 2014. Exploration successes primarily located

in the Central and Deep Llanos in Colombia have added approximately 10,000 bbl/d of

light oil production over the past year.

Financial Data Revenues (Group)

■ USD4.95bn (2014)■ USD4.63bn (2013)■ USD3.89bn (2012)■ USD3.38bn (2011)■ USD1.66bn (2010)■ USD639mn (2009)■ USD579mn (2008)■ USD83.5mn (2007)

Net Income/(loss)

■ (USD1,334.8mn) (2014)■ USD416.6mn (2013)■ USD527.7mn (2012)■ USD554.3mn (2011)■ USD265mn (2010)■ (USD125mn) (2009)■ USD76.7mn (2008)■ USD13.75mn (2007)

Operational Data Year established: 2004



Oil production (Colombia):

■ 134,435b/d (2014)■ 117,089b/d (2013)■ 85,123b/d (2012)■ 75,539 b/d (2011)■ 58,055 b/d (2010)

Natural gas production (Colombia):

■ 10,347boe/d (2014)■ 10,942boe/d (2013)■ 10,961boe/d (2012)



ExxonMobil Colombia

SWOT Analysis

Strengths ■ Strong fuels supply presence.

• Growing exploration portfolio.

Weaknesses ■ No oil or gas production.

■ Lack of refining involvement.


■ Growth in domestic oil demand.


Threats ■ Changes in national energy policy.

Company Overview ExxonMobil is the second largest foreign fuels retailer in Colombia, with a market share

thought to be in excess of 40% through the supply of its brands and products to third

party-owned and operated Esso and Mobil retail outlets. ExxonMobil has an interest in

four blocks and a technical evaluation agreement for one block in the emerging tight

liquids play of the Magdalena Basin. In the heavy oil play, ExxonMobil holds a technical

evaluation agreement in Block CPE-3 onshore Colombia covering more than 3.2mn net

acres. In 2013, 2D seismic data was collected to evaluate potential core hole locations.

Strategy Exxon was in July 2014 one of the higher bidders in the latest Colombian offshore

licensing round, bidding alongside Spanish firm Repsol and Norway's Statoil for one

block. ExxonMobil has an interest in four blocks and a technical evaluation agreement

for one block in the emerging tight liquids play of the Magdalena Basin. The drilling and

initial short-term test of its first unconventional exploration well, Manati Blanco-1 on the

western edge of Block VMM-37 began in late April 2015.

The Manati Blanco-1 drilling programme calls for a vertical well, drilled with Parker Rig

271, which is projected to contact the top of the Lower Tertiary Wedge conventional

sandstone formation at approximately 8,000-9,000 ft. After exiting the Tertiary interval,

electric and formation test logs may be run. The well will then continue through multiple



unconventional formations and is projected to reach its target depth of 16,000 ft in the

third quarter of 2015.

In the heavy oil play, ExxonMobil holds a technical evaluation agreement in Block

CPE-3 onshore Colombia covering more than 3.2mn net acres. In 2013, 2D seismic

data was collected to evaluate potential core hole locations.

Canacol Energy in January 2013 announced that ExxonMobil has discovered

conventional and unconventional oil at its Mono Arana (Spider Monkey) 1 well in

Colombia's Middle Magdalena Valley. The well was drilled to a depth of 3,030m to test

the oil potential of both the shallow conventional Tertiary Lisama sandstone reservoir

and deeper shale and carbonate reservoirs within the La Luna and Tablazo oil source

rocks. The well encountered about 231m of La Luna, with good oil and gas shows

observed throughout drilling of the La Luna section.

After long term production testing of the shallow Lisama reservoir, the Canacol and its

partners approved an appraisal drilling programme to delineate and develop the shallow

Lisama discovery. The appraisal programme consists of the drilling of up to six wells

and the construction of production facilities related to the appraisal and development of

the Tertiary aged Lisama discovery at Mona Arana. The first appraisal well, Mono Arana

2, is expected to be drilled to a depth of approximately 6,675 feet to test the oil

potential of the Lisama reservoir approximately 0.6km to the south of the Mono Arana 1

discovery well.















producing oil.

Market Position ExxonMobil is the second largest foreign fuels retailer in Colombia, with a market share

thought to be in excess of 40% through the supply of its brands and products to third

party-owned and operated Esso and Mobil retail outlets.



In the Colombian offshore, ExxonMobil was awarded a 33% interest in the COL-4

technical evaluation agreement covering 889,000 net acres in deep water during the

2014 tender round.

Company Details ■ ExxonMobil de Colombia

■ Calle 90No 19c - 32

Bogotá

Colombia

■ Tel: +57 (1) 628 0460

■ Fax: +57 (1) 628 3445



Other Summaries

Talisman Energy Canada-based explorer Talisman (now part of Spain's Repsol group) holds a 49%

equity interest in Equion. The remaining 51% interest is held by Ecopetrol. Equion

currently holds upstream licences in a number of blocks and also holds equity and

capacity interests, or both, in three pipelines. Annualised 2014 production averaged

17,000boe/d.

Equion made progress on the Piedemonte Expansion Project in 2014. Two wells were

completed and three wells were drilling as at year-end. In addition, the first phase of the

Florena gas expansion started up in late 2014 and completion of the facility is expected

to occur in 2015. Equion plans to drill up to three additional wells in 2015.

Repsol Prior to acquiring Canada's Talisman Energy, Repsol held equity in nine Colombian

blocks. Its exploration blocks comprise Tayrona, El Queso, Guadual, Cebucan, Caporal

and Catleya, while its production blocks comprise Cosecha, Capachos, Chipiron, Cravo

Norte and Rondon. It is also a co-owner of the Caño Limón-Covenas export pipeline.

The Spanish company has 15% of the Caño Limón oil field in the Cravo Norte block

and 100% in the Capachos block in the Llanos Basin, which came on-stream in April

2008. Exploration assets include Caporal, Tingua, Orquídea and El Queso, which the

company received in 2007.

Repsol agreed to farm-in to two offshore blocks off Colombia's north-east coast, near

Repsol's Tayrona Block and the maritime boundary with Venezuela, operated by

Ecopetrol, according to an April 6 2011 Ecopetrol announcement. The proximity of all

three blocks to the Venezuelan border suggests that Repsol may believe the area has

similar potential to the Gulf of Venezuela, where it was part of the consortium that made

the giant Perla gas discovery in 2009.

ExxonMobil was in July 2014 one of the higher bidders in the latest Colombian offshore

licensing round, bidding alongside Repsol and Norway's Statoil for one block.

Statoil and Spanish oil major Repsol has signed a farm-in agreement whereby Statoil

will secure a minority share in two Colombia offshore blocks. 'We are gaining access to

a vast underexplored frontier area through early access at scale, which is in line with

Statoil's exploration strategy,' said Nick Maden, a senior vice president for Statoil's

exploration activities in the Western Hemisphere. Financial details of the transaction

were not disclosed.

Royal Dutch Shell Colombia's state-controlled oil company Ecopetrol partnered with Royal Dutch Shell to

bid on an offshore block in the 2014 Colombian offshore licensing round. Shell holds a

70% equity interest in Guajira Offshore 3 Block, offshore Colombia. It is the operator of

the block. The block is held under a Technical Evaluation Agreement (TEA) and a 3D

seismic programme has been undertaken. Shell has said that it will keep assessing its



onshore portfolio in Colombia, and that it has just finished exploration drilling in the

Magdalena Valley on its VMM-3 onshore block.

Gran Tierra Energy Average production has grown from approximately 368b/d in 2006 to approximately

24,000b/d gross or 18,000b/d net in 2014. This growth has been driven by exploration

and subsequent development success, including the discovery of the Costayaco field,

one of the largest light oil discoveries in Colombia in the last decade. Today, Gran Tierra

Energy holds an interest in 23 blocks in Colombia. Gran Tierra Energy is the largest

producer, the largest reserve holder and the largest exploration landholder in the

Putumayo Basin of southern Colombia.

Appraisal drilling in the Moqueta field in Colombia resulted in 1P reserves increasing

45% to approximately 8.7mn bbl, 2P reserves increasing 54% to 14.9mn bbl and 3P

reserves increasing 108% to 26.9mn bbl on a company interest basis, and 1P reserves

increasing to approximately 6.8mn bbl, 2P reserves increasing to 11.2mn bbl and 3P

reserves increasing to 19.4mn bbl on a NAR basis. The limits of the field have not yet

been defined.

Gran Tierra has announced that its Moqueta-12 and Mayalito-1 delineation wells,

located in the Putumayo and Llanos basins onshore Colombia, continue to find oil.

Based on log interpretations, water has not been encountered in the Moqueta-12 well,

suggesting that the company is yet to define the boundaries of the Moqueta field,

according to CEO Dana Coffield. Log interpretations from Mayalito-1 indicated the

presence of oil in the Mirador formation, further extending the known lateral extent of

the oil accumulation in the Ramiriqui discovery, Coffield added.

In Colombia, the Moqueta-13 development well was successfully drilled in Q214, tested

at approximately 1,500b/d and tied in. Similarly, the Costayaco-21 development well

was successfully drilled and tested, with production start-up imminent. Production from

both is expected to start in the third quarter of 2014.Exploration drilling in Colombia for

the remainder of the year is expected to include the Eslabón Sur Shallow-1, Eslabón

Sur Deep-1, Corunta-1A and the Cabañas-1 wells, all in the Putumayo Basin.

Gran Tierra failed to encounter commercial hydrocarbons at its Eslabón Sur exploration

well in Colombia. The exploration well has reached a true vertical depth of 2,958 metres

(m). Mud log and electric log data acquired during and after drilling indicated only non-

commercial hydrocarbons present in the primary Caballos Reservoir. The secondary Kg

Reservoir was encountered twice as a result of faulting in the structure, while the upper

Kg Reservoir encountered 7.3m of net oil pay and the lower Kg Reservoir encountered

1.2m of net oil pay. Eslabón Sur has been suspended for further evaluation of the pay

zones.

Cepsa Spain's Compañía Española de Petróleos SA (CEPSA), which is owned by Abu Dhabi's

state investment vehicle International Petroleum Investment Company (IPIC), began



exploration in Colombia in 2001. At present it has holdings in 18 Exploration and

Production (E&P) projects in the Los Llanos Basin and the Upper Magdalena River

Valley, 9 of which are operated by CEPSA.

In the Upper Magdalena Valley, the Espinal Block is currently in operation, in which

CEPSA has a 15% stake. In the North Cañada field CEPSA has a 16.7% holding.

In the Los Llanos Basin it operates the Caracara and Tiple blocks after acquiring 70% of

the exploitation rights. The result of the latest geological studies carried out in Caracara

was the recognition of 5mn barrels of crude oil reserves, with CEPSA being entitled to

3.2mn barrels of this total.

In this same basin, CEPSA and Petrobras announced the discovery of oil in the Balay-1

well. Another discovery was also made in the Garibay block, in which CEPSA is the

operator with a 50% holding. Extensive tests are currently underway to determine their

commercial viability.

In 2011 CEPSA acquired a 5% holding in Oleoducto Central S.A. (OCENSA), the

company that owns Colombia's main oil pipeline. This investment has given CEPSA

access to the petroleum infrastructure and has strengthened its position in the country.

Maurel Et Prom French independent Maurel et Prom (M&P) entered Colombia in 2005. The company

currently operates at five licences: CPO-17, Sabanero, Tangara, SSJN-9 and Muisca. In

the years 2007 and 2008, Colombia represented the company's only producing assets,

totalling 12,365b/d and 15,704b/d respectively.

In March 2009, M&P agreed to sell its subsidiary Hocol Colombia to Ecopetrol. The sale

of Hocol is in line with M&P's near-term strategy to divest developed assets in order to

finance expansion of its core exploration and development activities. Currently, M&P

has only exploratory assets in Colombia.

The company announced it had struck oil at a second exploration well drilled in the

Llanos Basin's Sabanero Permit in September 2010. The crude was of API 12 gravity

and M&P recorded test flows of about 500b/d. M&P estimated the recovery rate for

heavy oil in the Llanos Basin to be 10-12%. The explorer intends to drill a third

exploration well (SE-2) and envisions two more exploration wells, pending

environmental permits.

Amerisur Resources South America-focused Amerisur Resources is operator and has a 100% working

interest in the block. The 14,341 hectare block is located in the Putumayo Basin, in the

south of Colombia. The company has continued to make great progress with the drilling

and production programme in Platanillo, having successfully drilled 12 wells since 2012,

maintaining a 100% success rate. Further progress is being made on the completion of

a pipeline connecting production from Platanillo to Ecuador, this will lift current

production capacity constraints.



Put-12 was acquired following a successful bid in November 2012, in a joint venture

with Pluspetrol. It is a 55,000 hectare block which is adjacent to Platanillo and shares its

geology. The Company is operator with a 60% working interest. The bid included a

commitment to a seismic acquisition programme and the drilling of one exploration well

during the first three year exploration phase.

The company intends to undertake 2D and 3D seismic studies in the first half of 2014,

which will form the basis of a multiple well drilling programme, planned for late 2014.

In December 2007 the company acquired, through its subsidiary companies, 100%

control and benefit of the Fenix area. The 24,117 hectare area is located in the Middle

Magdalena Basin of Colombia.

The Middle Magdalena basin lies between the eastern and central ranges of the Andes

mountains and has been a prolific producer of oil over many years with discovered

reserves of approximately 1.9bn barrels of oil and 2.5trn cubic feet of gas in over 41

distinct fields. The Fénix Block is located in a thrusted section of the basin which is

structurally complex, and is on trend with some of the most significant discoveries in

the area. Recent renewed exploration success in the basin by other operators has been

largely due to the application of modern 3D seismic technology and enhanced structural

modelling techniques which have enabled the accurate mapping of complex structures.

Amerisur in April 2014 provided an update on the well Platanillo-15 in the Platanillo

Field, Colombia, the third of a planned seven firm well drilling campaign during 2014.

Following the completion of Platanillo-17 the Serinco D-10 rig was moved from Platform

3N to Platform 9S in order to drill a further three wells. The rig was inspected and a 15

day maintenance and upgrade programme was completed.

Platanillo-15 was spud on 23rd April 2014 and will be drilled directionally to a reservoir

target approximately 1,602ft south-west of the surface location. The total depth of the

well will be approximately 8,589ft MD with a maximum inclination of 17°. The company

expects log data from this well by the end of May.

When the three wells at Platform 9S are completed and placed on production the

company intends to shift drilling operations to Platform 5S from which a further 2 wells

will be drilled. At that point the Platanillo field South and Central Lobes will benefit from

17 new wells and 3 side-tracks which the company considers, on success, will support

a prudent plateau oil rate in the absence of export constraints of some 12,000b/d.

Amerisur Resources has announced the discovery of oil with the Platanillo-20 well in

Colombia. The well, which is the 15th new well of the company's current drilling

campaign, was drilled to a total depth of 2,547m and was cored over the N, U, T and

Caballos basal sands. The reservoir cores recovered from the well are currently being

analysed to allow a refinement of its resource model, according to the company's

announcement in its interim results for H113/14 ended June 30. The reservoir sections

in Platanillo-20 were logged, with the interpretation indicating the presence of 16.74m

gross, 8.2m net oil column in the U sand formation and the presence of 6.09m gross,



4.3m net oil column in the T sand formation using Schlumberger's Anadrill logging while

drilling and wire line tools.

Others Canada-based oil and gas explorer Parex Resources completed its acquisition of the

remaining working interest in four blocks in Colombia's Llanos Basin in April 2011. The

company has gained the outstanding 50% share in the blocks by successfully

completing a buyout of the company that previously owned the stake. The acquisition

has been valued at around USD255mn cash.

Ecopetrol said it had reached a deal to sell a 50% stake in its Capachos oil block to

Parex Resources Inc, which would be the operator. Parex will pay the full cost of the

first two wells to be developed on the block under the terms of the deal reached on May

5, Ecopetrol said in a statement.

US-based Raven Pipeline is considering completing its first greenfield project with the

OXL pipeline in the department of Casanare, Colombia by 2015, reports BNamericas,

citing COO Robert Russell. Starting with a 100km first phase, OXL will carry light crude

(32-38 API) from northern Casanare to the Oleoducto Bicentenario (OBC) pipeline

utilising a 25.4 centimetre diameter pipeline. This is expected to be followed by a

40-55km second phase. The company has been approved of alternative environmental

diagnosis (DAA) and now awaits a second environmental permit, following which it

expects to begin operations by mid-2015, added Russell.

China's state-run Sinopec acquired four Colombian blocks from US-based Hupecol at

end-2011, on the basis of a deal agreed in August 2010. The deal value was

USDUSD281mn.

Ecopetrol has teamed with Anadarko Petroleum to search for oil deposits in the

Caribbean Sea. Anadarko owns 50% of rights in the Fuerte Norte and Fuerte Sur blocks

in Colombian territory. The two companies also won a government concession to

explore for oil in the Purple Angel block, it said. Ecopetrol did not provide any financial

details in the statement. The three blocks span 1.03mn hectares (2.55mn acres),

according to Ecopetrol. Anadarko has acquired interests to explore in six deepwater

blocks in Colombia covering about 8mn acres, spokesman John Christiansen said.

Ecopetrol will drill three offshore wells in 2015, two off its Caribbean Coast and a third

in the Gulf of Mexico, after slashing its offshore exploration budget to USD200mn down

from USD632mn in 2014, the company said. The two Caribbean wells, Calasu and

Kronos, will be operated by Anadarko Petroleum.

Canadian firm Canacol Energy has encountered 19m of net oil pay at its Labrador-3

exploration well, in the Llanos basin of Colombia. The well reached a total depth of

3,320m last month and is located in Block LLA23, approximately five kilometres (km) to

the north of the corporation's Rancho Hermoso field, in the Llanos basin of

Colombia. The company announced that the oil was encountered within three

reservoirs. The C7 reservoir was perforated and is reported to flow at a stable gross rate

of 1,460b/d of 30 degree API oil, with a 3% water cut. The well was placed on



production, and will remain on a long-term production test subject to approval from the

Agencia Nacional de Hidrocarburos (ANH). Canacol Energy estimates the Labrador-3

well's resources at 5mn bbl.

The well is the third to be drilled in the LLA 23 Labrador discovery, where Canacol

Energy already has commercial production underway. The Labrador-1 well tested on

December 2012 at a rate of 1,832b/d; the Labrador-2 well tested in May at a stable rate

of 1,618b/d. The company has an 80% operated working interest in the LLA23 contract

with Petromont Colombia, Sucursal Colombia holding the remaining 20% interest.

Canacol Energy has posted an update on its drilling operations in Colombia and

Ecuador, announcing that it has brought online the first two of nine planned wells

spread across the two nations. The Labrador 2 well in Colombia has tested at a gross

rate of 1,618b/d while the Secoya 44D well, part of the Atacapi oilfield in Ecuador, came

into production at 968b/d.

Canacol Energy has discovered oil at the Oso Pardo 1 exploration well in Colombia, Oil

Voice reports. The well, located on the Santa Isabel Explorationa and Production

contract in the Middle Magdalena Valley, was spud on June 10 2013. It was initially

designed to drill to a measured depth of 10,199 feet; however, technical problems were

encountered which compromised the integrity of the well bore. The company

subsequently exercised its option to continue shallow operations. The well encountered

two oil filled sandstone intervals at 3,665 feet and 3,800 feet.

Canacol has announced positive flow test results from the Leono 1 exploration well

located on the LLA23 exploration and production (E&P) contract in Colombia's Leono

Basin. The initial test recorded 40.53 metres (m) of net oil pay in four different reservoirs

and flowed at a stable gross rate of 1,863b/d. Canacol now plans to conduct

production testing operations on the Gacheta reservoir at the discovery in the LLA23

licence. Canacol holds an 80% operated working interest in the LLA23 contract with

partner Petromont holding the remaining 20% interest.

Canacol Energy has tested 0.44mn standard cubic metres per day (mmscmd) of dry gas

at the Palmer 1 well, which is the first well of its three well gas exploration programme

for the Esperanza exploration and production contract in the Lower Magdalena Basin of

Colombia. The Palmer 1 well encountered 26.52 metres of gas pay within the primary

target of the Cienaga de Oro sandstone reservoir. The Cienaga de Oro sandstone

reservoir was perforated from 2,076 to 2,104.94m measured depth and flowed naturally

at a rate of 0.44mn metric standard cubic metres per day of dry gas with no water on a

36/64 inch choke during the course of a 36-hour isochronal flow test.

Canacol Energy's subsidiary CNE Oil and Gas has acquired a 100% interest in two

exploration and production licences onshore Colombia from OGX Petroleo E Gas

(OGPars). The two new licences, VIM 5 and VIM 19, are near Canacol's existing

Esperanza and VIM 21 gas contracts in the lower Magdalena Basin. The National

Agency of Hydrocarbons of Colombia (ANH) has approved the transfer of title and

operatorship of the explorations contracts. 'The acquisition of these two contracts adds



significant gas resource to our core gas position in Colombia,' said CNE Oil and Gas

President and CEO Charle Gamba.

Canacol has announced a 6.6bcm or 41mn boe increase in its 2P gas reserves.

Canacol's working interest before royalty 2P gas reserves as of February 28 were

9.77bcm or 61mn boe with a pre-tax net present value discounted at 10% of

USD852mn. The increase in reserves has been attributed to exploration success at the

recent Clarinete discovery on the VIM 5 Exploration and Production (E&P) contract and

the recent Palmer discovery on the Esperanza E&P contract. A positive technical

revision related to original gas in place at the Nelson field on the Esperanza E&P

contract has also supported the increase in 2P gas reserves.

ONGC Videsh, the foreign investment arm of India's state-owned Oil and Natural Gas

Corporation, has discovered oil with the Kama-1X well on the CPO-5 exploration block

in the Llanos Basin onshore Colombia. The oil was found in two intervals in the primary

target horizon of the Mirador formation, with the first interval producing oil at a rate of

120-300 bpd. The company is likely to conduct an extended production test on the

second interval to evaluate the potential and commerciality of the discovery. The well

was drilled to a total depth of 3,200m. ONGC Videsh owns a 70% stake in the block,

working alongside partner Petrodorado Energy with the remaining 30%.

UK-listed oil and gas explorer GeoPark Holdings has divested a 20% stake to Korea's

LG International (LGI). The deal includes GeoPark Colombia's interests in 10

hydrocarbon blocks in the country. LGI will pay USDUSD20.1mn in cash for the assets.

The deal also includes an incremental equity provision, under which GeoPark is eligible

to buy back a maximum of 12% stake in GeoPark Colombia; however, this provision is

contingent on the successful functioning of GeoPark Colombia.

GeoPark Holdings has released production test results from its Tua-3 well located on

the Tua oil field in Colombia's Llanos 34 Block. Tua-3, which was drilled to a total depth

of 3,276m, flowed oil at a rate of 1,127b/d of 19.4 degree API oil through a 17 millimetre

(mm) choke. An electrical submersible pump was used to perform testing in the Mirador

formation at a depth of around 3,031m. The company said it requires more production

history to determine stabilised flow rates and the extent of the resource.

GeoPark has reported that it has drilled, tested and brought into production the

Tarotaro 1 exploration well in Colombia. The well is part of a recently discovered field in

the Llanos 34 block and has been drilled to a total depth of 3,175 metres. Testing in its

Guadalupe formation saw a production rate achieved of 2,239 barrels of oil per day,

with oil of 15.5 degree API quality. Further monitoring of well flows will now be carried

out until production has stabilised.

The company has announced the successful drilling, testing and placing on production

of the Tarotaro 1 exploration well on the Llanos 34 Block in Colombia's Llanos basin.

The company had earlier hit oil in the Tua-4 well in the Tua oil field on the same block

less than a week ago. The Tarotaro 1 exploration well was drilled to a total depth of



3,175m and a production test was conducted at 2,955m that flowed 15.5 degree API

oil, with a 0.6% water cut, with a production rate of about 2,239b/d of oil.

GeoPark has announced the successful drilling, testing and placing on production of its

well in the Tua oil field on Colombia's Llanos 34 Block. The company drilled the Tua-4

well to a total depth of 3,432m. The first test was carried out in the Gacheta formation at

a depth of 3,260m. During the test, the well flowed 526 barrels of 11 degree API oil per

day, with 3% water cut, through a 51mm choke. Another test conducted on the

Guadalupe formation at a depth of about 3,260m flowed 857 bbl of 16.1 degree API oil

per day with 1.3% water cut on a 19mm choke.

GeoPark has announced successful drilling and testing of its fifth discovery at the

Tigana 1 exploration well in the Llanos 34 block in Colombia's Llanos basin. The well

was drilled to a total depth of 3,692metres (m) using a submersible pump and produced

15.3 degree API oil with a 0.2% water cut. GeoPark has a 45% stake in Llanos 34.

GeoPark Holdings reported a 57% rise in average oil production to 20,441 barrels of oil

equivalent per day in Q214, compared with the same quarter in 2013, reports

BNamericas. The increase was attributed to new discoveries at Colombia's Llanos 34

block. The start of production at its Tierra del Fuego blocks in Chile also contributed.

GeoPark's Colombian oil production rose 68% in Q214, driven mainly by growth at

Llanos 34, where it has a 45% working interest. The company drilled 13 new wells

during the quarter as part of its USD220-250mn work and investment programme for

2014. Of the total number of wells, seven were drilled in Chile and six in Colombia.

GeoPark Holdings estimates that there are 45mn-65mn barrels of recoverable reserves

in the Tigana oilfield in Columbia's Llanos 34 block. The company's estimate for so-

called 3P reserves, which include proved, probable and possible reserves, was made

based on eight drilled wells, production information and 3D seismic surveys. GeoPark

estimates Tigana to hold around 140mn-170mn barrels of heavy to medium grade oil in

place. Tigana oilfield currently produces oil from two formations at the field - with the

Mirador formation producing crude rated 21-29 API and the Guadalupe formation

producing crude rated 15.5 API.

Canadian oil company Petroamerica Oil has released initial test results for the Las

Maracas-8 well in Colombia. According to Petroamerica, the well produced over

3,250b/d of 36 degree API oil. It was tested over a 23-hour period from a 3.66m

perforated interval in the Mirador reservoir. Petroamerica Oil's total proved reserves

increased 80% year-on-year to 3.25mn boe in 2012 after accounting for production,

compared with 1.78mn boe in 2011. The company's total proved plus probable

reserves rose 68% y-o-y to 5.081mn boe in 2012, up from 3.03mn boe in 2011. The

company's total proved plus probable plus possible reserves grew 78% y-o-y to

7.92mn boe in 2012, compared with 4.44mn boe in 2011. These rises have been

primarily attributed to extensions and discoveries in new reservoirs at the Las Maracas

field and the La Casona discovery.

Petroamerica Oil has announced its latest discovery at the Mirador formation in

Colombia's Llanos Basin, the Curiara-1 well. Petroamerica said the well produced 40



API oil at a rate of 800boe/d during testing. Records indicate the presence of 2.44m of

net oil play and a possible gross hydrocarbon column of 15.2m.

Petroamerica has announced the discovery of light oil at the La Guira-1 exploration well

on the Los Ocarros Block, Colombia, Oil Voice reports. The well encountered 11 feet of

net pay in the Mirador formation which was flow tested on a fully open choke for a

period of 24.5 hours and started producing 1,000 barrels of oil a day. The company is

also pleased to announce that its total working interest production reached a new high

with an average rate of 6,312b/d of oil in October 2013.

Petroamerica Oil has signed a definitive agreement with Pacific Stratus Energy

Colombia (PSE), a fully owned subsidiary of Pacific Rubiales Energy, to purchase a 50%

stake in the Llanos-19 block in Colombia, excluding the Tormento Field where PSE will

retain its 100% working interest. The agreement will see Petroamerica pay 100% of the

capital and operational expenditures of the next exploration well up to a maximum of

USD17mn. Drilling activities in Llanos-19 could start by Q414, contingent on securing

approval from hydrocarbons agency ANH.

Petroamerica Oil has signed an agreement to acquire all of the issued and outstanding

common shares of Canada's Suroco Energy in an effort to expand in the oil and gas

sector. Shareholders of Suroco will receive 1.7627 common share of Petroamerica for

each share of Suroco they currently own. The deal is expected to close on or around

June 30. Successful completion of the deal is contingent on customary closing

conditions, including the requisite Suroco shareholder, government and regulatory

approvals.

Petroamerica has reduced its capital expenditure for H115 by 35% to USD12.9mn from

USD20mn, reports BNamericas, citing the company's Q114 earning release. The

reduction in capex is due to the shifting of the drilling programme of its Langur-2

appraisal well on the LLA-19 block to Q315 and the removal of the Calatea-2

exploration well, a part of the El Porton block, from current drilling plans. The company

expects that production will decrease to 4,200 barrels of oil equivalent per day (boe/d)

for H115 from its previous estimates of 5,400boe/d in January, due to pump failures on

major production wells on both the Las Maracas and Suroriente fields.

Canada's Suroco Energy has acquired a 25% stake in the Putumayo 2 Block in the

Caguan-Putumayo Basin, Colombia. The block is currently operated by Colombian oil

and gas company PetroNova's subsidiary PetroNova Colombia. Under the terms of the

farm-in agreement, Suroco will pay USD3mn to PetroNova, including 25% of the back

costs for 2D and 3D seismic work on the block to date and another USD199,165

representing 25% of the costs incurred in preparation for the first exploration well to be

drilled on the block. Suroco has also agreed to fund the first USD6mn in costs for the

first exploration well drilled on the block. The 25% economic interest in the block

acquired by Suroco will convert into a full 25% undivided working interest in the block,

after it is approved by Agencia Nacional de Hidrocarburos of Colombia.

Peru-based oil company Baron Oil has agreed to farm out 50% of its interest in the

Nancy-Burdine-Maxime field, Colombia, Proactive Investors reports. The company sold



the stake for USD2mn in a deal with S&J Full Services. The first USD1mn will be

received in cash upon the closure of the deal with the second USD1mn paid in 10

monthly instalments from August 30 2013. Baron will use the money to expand and

upgrade surface infrastructure at the field.

Colombian oil and gas company PetroNova will sell its 20% stake in the CPO-06 block

to Argentina's Tecpetrol and focus on other Colombian blocks. The company now plans

to develop the CPO-07 and CPO-13 discoveries, which generated promising results

during previous explorations, according to PetroNova CEO Antonio Vincentelli. The

explorer made a hydrocarbons discovery with Pendare-1 and Atarraya-1 on the CPO-07

and CPO-13 blocks in 2012, with successful appraisal drilling on each.

PetroNova plans to spud its first exploration well on the Tinigua block in Colombia's

Caguan-Putumayo basin, after it received an environmental permit to begin drilling. The

proposed A3 well, which will be drilled to a depth of 1,981 metres, holds proven and

probable resources of 143 barrels of oil equivalent. The company will target the Mirador

and Macarena formations, based on 3D seismic data. PetroNova is the operator with a

90% stake in the block.UK-based, South America-focused oil company Global Energy

Development has provided an update on its Colombian operations. The company's total

oil production for H113 outperformed the same period of 2012, offsetting the worldwide

drop in the price of crude oil.

Canada's Santa Maria Petroleum has announced that the operator of its Llanos 21

block in Colombia, Omega Energy Colombia, has abandoned its Calacho No. 1 and

Rocamao No. 1 exploration wells at the site. The wells were part of a continuous two-

well drilling and testing programme carried out by Omega, a process delayed by poor

weather and protest demonstrations by local residents. Santa Maria is now expected to

terminate its interest in the block, having satisfied its prior financial commitments.

Canada's Vast Exploration has ended its farm-out agreement with Sagres Energy

concerning the Putumayo Basin in Colombia, citing unfulfilled contractual obligations,

according to Oil Voice. Sagres had taken on a 90% stake in the project, with Vast

retaining a 10% interest during the first exploration phase, which consisted of a

minimum expenditure of USDUSD12.9mn over a three-year period. Vast acquired the

148,005 acre block in June 2010 by winning an auction organised by the Agencia

Nacional de Hidrocarburos of Colombia.

Colombian natural gas transportation company Transportadora de Gas Internacional

(TGI) has signed an agreement to participate in the country's Pacific oil pipeline project,

reports BNamericas. Under the terms of the deal, TGI will acquire a 7.78% share in the

USD5bn project and future pipeline after completion of certain requirements.

The760km pipeline will connect oilfields in central Meta Department with the Pacific

coast port city of Buenaventura. The pipeline is scheduled to be operational in 2018.

The expansion of Transportadora de Gas del Perú (TGP)'s pipeline is to supply natural

gas to power and petrochemical plants, reports Bnamericas. The TGP consortium is on

track to complete the expansion of the Camisea duct by the end of 2015, according to



the company's general manager, Ricardo Ferreiro. The USD700mn project will expand

its capacity to 26.05mn cubic metres per day (Mcm/d), from 18.97Mcm/d currently.

Global Energy Development (GED) plans to divest its assets in Colombia's Llanos basin,

in a share purchase agreement valued at USD50mn. Canada-based Platino Energy

Corporation's subsidiary Platino Energy Holdings will acquire the rights and obligations

of GED's assets Rio Verde, Alcaravan and Los Hatos. The deal is in line with the

company's strategy of focusing development on its remaining Colombian assets,

including blocks Bolivar and Bocachico in the Middle Magdalena basin. GED stated that

proceeds from the transaction will be used to clear company debt of some USD7.5mn.

Australia-based exploration company Range Resources has decided to forego the

second farm-in deal for the PUT-6 block in Colombia's Putumayo basin, reports

BNamericas. The move comes after the company's exit from the PUT-7 block in May. In

the latest announcement, Range Resources noted that it is writing off USD3.48mn

related to a performance bond issued to fund work commitments on PUT-6. 'To

minimise our cost exposure on all fronts, we have taken pragmatic steps to exit our

position in PUT-6 and PUT-7 blocks, where the work programme would have been very

expensive for Range,' CEO Rory Scott Russell said.

Argentine oil and gas company Andes Energia has secured funding for three Colombian

exploration blocks under a multi-layered deal with local player Trayectoria Oil & Gas

(TOG). Under the terms of the agreement, TOG will provide USD6.2mn of cash and

working capital guarantees on the blocks. In return, TOG will receive 8.7mn Andes

shares worth 47p each. The company will get a further 8.9mn for paying off USD7mn of

Andes' debt. Andes Energia also has an option to hold a 45% interest in the Carbonera

field, along the southwest side of the Maracaibo basin, and a 10% interest in the Yamù

field in the Llanos basin.



Regional Overview

Latin America Oil&Gas Regional Overview

BMI View: Oil and gas output in Latin America will grow over the coming decade due to vast

below ground resource potential coupled with ongoing energy sector reforms in Mexico and Argentina.

However, the region will ultimately fail to reach its full production potential over the next decade as a

result of reduced investment from lower oil prices and an increasingly challenging above ground

environment in key producing countries including Brazil and Venezuela.

Q315 Regional Highlights:

■ Upstream activity within the oil and gas sector will slow amid a lower oil price environment. With pricesexpected to remain below USD80/bbl through 2020, public and privately-owned oil companies willremain under pressure to cut ambitious capital expenditure (capex) plans. This will cause firms toreassess investment plans over the next several years, particularly with respect to costly exploration andproduction. This trend is illustrated by less robust oil and gas output growth across the region, with somecountries experiencing outright declines over the course of the next decade.

■ Total oil production in Latin America will experience a slight downturn in 2015, followed by a steadyincrease from 2016 through 2024, averaging 1.2% year-on-year (y-o-y) growth. With an estimated outputof 10.3mn barrels per day (bbl/d) in 2015, we forecast production to reach 11.5mn bbl/d by the end of our10-year forecast period in 2024. This trend is primarily due to progress from sector reforms withinMexico and Argentina and continued upstream development in Brazil. However, while we recentlydowngraded our 10-year production forecast, the ongoing corruption scandal with Petrobras poses furtherdownside risk to project developments in Brazil and by extension to our regional hydrocarbonsproduction outlook.

■ Consumption of oil in Latin America will also increase over the next ten years by an average of 1.9% y-o-y, from 9.1mn bbl/d in 2015 to 10.8mn bbl/d in 2024. This will be supported by an increase ofapproximately 1mn b/d in refining capacity throughout the region through 2024.

■ Production of natural gas will rise at an average of 2.7% per year from 2015 to 2024. With an estimated271.3 billion cubic metres (bcm) of output in 2015, we believe this will reach 343.6bcm by the end of ourforecast period. This is primarily driven by government-led efforts to expand capacity of and createfeedstock for natural gas-powered electricity in a number of countries including Brazil and Colombia.

■ Natural gas consumption in Latin America will increase from 354.9bcm in 2015 to 470.7bcm in 2024 atan average y-o-y rate of 3.2%. This is due primarily to rising demand for gas-powered electricity withinseveral markets such as Mexico and Chile.

■ Given the vast below-ground potential in Latin America, the regulatory and security environments willultimately determine the prospects for long-term production growth. Poor regulatory environments inmajor producers like Venezuela and Bolivia, and to a lesser extent Brazil, have stymied the region'sgrowth potential. Continued development within Argentina and Mexico's upstream sector suggestsreforming countries will be better positioned to grow over the coming decade.



Regional Production Will Outpace Consumption

Latin America - Oil Production & Consumption

Latin America oil production, 000b/dLatin America oil consumption, 000b/d

2005

2006

2007

2008

2009

2010

2011

2012

2013

2014

2015

f

2016

f

2017

f

2018

f

2019

f

2020

f

2021

f

2022

f

2023

f

0

5,000

10,000

15,000


Key Themes In Latin America's Oil Sector:

The three major players - Venezuela, Brazil, and Mexico - are following very different growth trajectories

over the next decade.

Lower oil prices will continue to weigh heavily on Venezuelan crude production, tempering foreign

investment and negatively impacting state-owned Petróleos de Venezuela, S.A. (PdVSA) ability to

generate revenue.

Moreover, Venezuela's above-ground environment remains a major growth deterrent such that the country's

output will fall short of its potential. We expect 2015 oil output to decline 4.0% versus 2014 to 2.4mn b/d.

Production will continue to decline thereafter at an average rate of 1.6% y-o-y through 2024. This

represents a significant shortfall from the company's own target of 5.8mn bbl/d by 2018. The decline in

production is due to widespread economic mismanagement, chronic underinvestment, and unsustainable

social policies that have drained PdVSA of critical resources.



Squandering Their Potential

Venezuela - Total Liquids Production

Crude, NGPL & other liquids prod, 000b/dCrude, NGPL & other liquids prod, % y-o-y

2011

2012

2013

e

2014

e

2015

f

2016

f

2017

f

2018

f

2019

f

2020

f

2021

f

2022

f

2023

f

2024

f

0

1,000

2,000

3,000

0

-5

-2.5

2.5

5


Brazilian oil production will increase an average of 4.0% per year over the next decade due to a vast

below-ground potential coupled with ongoing efforts to expand output. However, the announcement by

Brazilian national oil company (NOC) Petrobras that it would reduce its USD221bn five-year spending

plan by a minimum of 25% in 2015 supports our view that upstream activity in Brazil will be less robust

over the next decade than originally forecasted by the NOC. While we remain broadly optimistic on long-

term output from Brazil's presalt acreage, our estimates reflect a five-year delay to Petrobras production

targets, beginning in 2018. Moreover, lower oil prices and mounting financial burdens, coupled with the

ongoing 'Lava Jato' corruption scandal, pose significant downside risk to our forecast, particularly over the

next three years. With reports of up to USD30bn in potential write-downs, the NOC could be forced to defer

investment spending to a greater extent than currently estimated.

Energy sector reforms enacted by President Enrique Pena Nieto in Mexico have opened up opportunities in

the hydrocarbon-rich market, which had previously been monopolised by national oil company

(NOC) Pemex. Driven by the legislation changes, Mexico is better positioned to withstand lower oil prices,

supporting our forecast for crude production growth from 2.9mn b/d in 2015 to 3.3mn b/d by 2024. More



robust investor interest poses upside risk to our more modest 1.3% y-o-y growth forecast. Mexico is also

supported by a favourable domestic market; our Latin America Country Risk team expects real GDP growth

to steadily increase from 3.3% in 2015 to 4.2% by 2019, reaching 4.5% by 2024. As such, we forecast

domestic oil consumption to increase an average of 2.2% y-o-y over the next 10 years, from 2.1mn b/d in

2015 to 2.6mn b/d by 2024.

Oil Production Preparing To Increase

Mexico - Annual Liquids Prodcution

Crude, NGPL & other liquids prod, 000b/d (LHS)Crude, NGPL & other liquids prod, % y-o-y (RHS)

2005

2006

2007

2008

2009

2010

2011

2012

2013

e

2014

e

2015

f

2016

f

2017

f

2018

f

2019

f

2020

f

2021

f

2022

f

2023

f

2024

f

0

1,000

2,000

3,000

4,000

-10

-5

0

5


Key Themes In Latin America's Gas Sector:

With several countries in Latin America hoping to increase their use of natural gas for power generation, we

factor in our forecasts an increase in the production of natural gas. Despite the threat of lower oil prices to

upstream investment, strong demand for natural gas will support continued investment into gas projects,

particularly in Mexico and Argentina. Vast resource potential in both countries, as well as in Brazil, will

boost overall natural gas supplies in the region but will fail to meet growing domestic needs, over the next

five years, increasing both pipeline and LNG imports as a result.



LNG Imports Will Grow Further

Latin America - Annual LNG Imports By Country (bcm)

Source: Bloomberg

With the world's second-largest technically recoverable shale gas resources at 22.7 trillion cubic meters

(tcm), Argentina's outlook has brightened due to an amended hydrocarbons law, passed on October 30

2014. As such, we forecast natural gas production to grow by 4.0% y-o-y through 2024. However, we

expect Argentina to maintain a deficit in natural gas supply over the coming decade, resulting in a negative

net export position through 2024 as consumption growth continues to outpace upstream development.

Beginning in 2018, more robust investment into Vaca Muerta acreage will yield greater domestic supplies

of associated natural gas and improve the country's net trade balance at a more rapid pace.



Abundance Of Potential

Technically Recoverable Shale Gas Resources, tcm

Source: EIA

We forecast Colombia's natural gas production to increase by a modest average rate of 0.8% per year over

the next decade despite the government's efforts to incentivise output amid reduced exploratory activity.

Major natural gas producers have announced significant spending cuts, which will impact ongoing and

future upstream developments in Colombia. Cutbacks will be particularly acute in associated gas fields,

which represent the majority of natural production. In addition, repeatedly small discoveries will weaken

long-term investor enthusiasm, driving negative reserves replacement ratios over the coming decade.



Production To Increase Despite Declining Reserves

Colombia - Natural Gas Proven Reserves & Production

Natural gas proven reserves, bcm (LHS)Dry natural gas production, bcm, % y-o-y (RHS)

2011

2012

2013

e

2014

e

2015

f

2016

f

2017

f

2018

f

2019

f

2020

f

2021

f

2022

f

2023

f

2024

f

0

100

200

300

-5

0

5

10


Natural gas production in Brazil is also expected to increase as a result of the country's efforts to diversify

its power mix away from hydropower electricity. While the country produced an estimated 22.1bcm of gas

in 2014, this was far below Brazil's domestic demands which totalled 41.4bcm. We believe Brazilian natural

gas production will increase at an average rate of 4.4% y-o-y between 2015 and 2024 which is still far

below the country's potential. However, the ongoing corruption scandal poses downside risk to our forecast,

particularly in the near-term. Supply deficits will encourage continued pipeline imports and increased LNG

shipments into the country to service power demands.

Mexico is currently the largest gas producer in the region at an estimated 46.7bcm in 2014. We expect

Mexico to lead the region in natural gas production growth as international oil companies (IOCs) favour its

more investor-friendly market. Mexico's positive macroeconomic trajectory and opening of the energy

sector will propel production of natural gas to an average rate of 1.9% y-o-y over the next ten years with

growth increasing to 2.3% y-o-y from 2019 to 2024 as new upstream developments begin to come online.

However, we caution that Mexican gas production will remain below potential due to the country's



accessibility to inexpensive pipeline imports from the US. This will disincentivise development of less

profitable conventional as well as nonconventional shale gas plays, despite a vast resource potential.

Limited Water Resources Discourage Shale Development

Mexico - Map of States With And Without Watersheds

Source: Conagua, BMI

Refined Product Imports Will Not Subside

Latin America's refining capacity deficit is expected to remain high in spite of plans to undertake refinery

expansion and modernisation efforts within several countries. Refined products consumption in Latin

America is expected to increase by an average rate of 1.9% y-o-y through 2024 due to relatively strong

macroeconomic growth in key markets, outpacing refining capacity growth of 1.3% y-o-y.



Regional Export Deficit Will Remain Elevated

Latin America - Net Refined Products Exports, 000b/d

Argentina Brazil Chile Mexico

2013

e

2014

e

2015

f

2016

f

2017

f

2018

f

2019

f

2020

f

2021

f

2022

f

2023

f

2024

f

-1,000

-750

-500

-250

0




Global Industry Overview

Oil Price Outlook

BMI View:The recent oil price rally has overshot the extent of the bullish shift in the fundamental picture.

We have adjusted our oil prices upwards to account for the impact the recent rally will have on the annual

average price, but we maintain our view of renewed weakness for oil prices in H215.

We have revised our average 2015 Brent Crude price forecast from USD53/bbl to USD59/bbl. Having

broken out of the USD45-63/bbl range, oil prices look to have further to run as markets focus on weekly US

oil production and rig numbers. We have raised our trading range for the remainder of 2015 from

USD40-65/bbl to USD50-75/bbl. We see the April 2015 resurgence as overdone. We believe the market is

currently underestimating the underlying resilience of US oil production, supply dynamics in other

major oil producers including Russia and Saudi Arabia, future demand weakness from China, and

the likelihood of a breakthrough in Iranian sanctions negotiations. We thus maintain our expectation for

renewed price weakness in H215. Moreover, we now forecast a weaker price increase year-on-year for 2016

than we were previously factoring in as supply growth will temper price rallies.

Table: BMI And Bloomberg Consensus Forecasts* WTI And Brent, Front Month - USD/bbl

2015f 2016f 2017f

Brent (BBG Consensus) 60 75 75

Brent (BMI) 59 61 63

WTI (BBG Consensus) 55 69 73

WTI (BMI) 52 55 56

*BMI is a contributor to Bloomberg Consensus. f= forecast. Source: Bloomberg, BMI



Temporary Rally For Brent

Front Month Brent Crude, (weekly, USD/bbl)

*Horizontal line = BMI 2015 Average Brent forecast. Source: Bloomberg, BMI

Main parameters of our oil price forecast are:

Table: 2015-2016 - Fundamental Pressure On Oil Prices

Downside Upside

US Oil Production Only Gradual Slowdown (not collapse) Dollar rally moderating

Iranian Nuclear Sanctions Breakthrough US Oil production Slowdown Intensifying (H215)

Chinese Demand Slowing

OPEC Maintaining 'No Cut' Policy

Supply Gains Outpace Demand Gains

Bullish Extreme In Net Speculative Long Positions

Peak Oil In Storage (China, US)

Source: BMI *Also see last month's Oil Price Outlook - 'Downside To Brent From Iranian Crude Exports', 30 March.



Global Supply Growth To Outpace Demand Growth In 2015-2016

Despite a continued slowdown in US production growth, we forecast an amply supplied market over

2015-2016. Indeed, US production is only part of the overall picture. We forecast global supply to grow by

2.2% compared to 1.3% for global oil consumption in 2015. We forecast that both OPEC and non-OPEC

producers will be increasing production and exports over 2015 and 2016. We expect Russian refiners to

consume less crude thus leaving more for exports. Declining domestic demand for fuels and the

unprofitability of teapot refineries will leave Russia with higher quantities earmarked for exports. We

forecast net crude exports from Russia to increase by 200,000b/d in 2015, to reach a total of 5.3mn b/d.

Saudi Arabia will continue to ramp up production and we forecast annual increase of 3% to 9.9mn b/d of

crude oil production for 2015. While the majority of this new production will supply new domestic refining

capacity, Saudi Arabia has indicated its willingness to supply its customers with as much oil as they need,

keeping the market well supplied.

No Supply Crunch Soon

Global Oil Production and Consumption Growth, % y-o-y

2015-2020= BMI forecast. Source: EIA,BMI



US Oil Production To Soften, Not Collapse

While we are forecasting a slowdown in US production growth, we are more positive than current market

expectations. The April 2015 price rally reflects the expectation that US oil production will be significantly

curtailed and erode some of the oversupply in the oil markets.

US crude oil production increased on average by 14% year-on-year in the first four months of 2015 as the

overhang of H214 drilling supports production resilience in a lower oil price environment. With a lower

number of wells fractured since December 2014, there is not the same backlog of new production to sustain

double - digit growth. We have already seen the first indications of a plateau in US oil production and year-

on-year slowdown in growth.

Year-on-Year Growth Slowing, But Not Negative

US Crude Oil Production and Growth

Source: EIA

We factor in a slowdown in oil production growth in the US, with our average 2015 oil production growth

at 6%. While this would be a significant slowdown from growth of 10.2% in 2014, we do not forecast a



collapse in US oil production. We forecast average daily crude oil production of 9.031mn b/d in 2015, up

from 8.520mn b/d in 2014.

US Production In The Black In 2015

US Crude Oil Production Forecasts

United States - Crude, NGPL & other liquids prod, 000b/d (LHS)United States - Crude, NGPL & other liquids prod, % y-o-y (RHS)

2013 2014 2015f 2016f 2017f 2018f 2019f

0

5,000

10,000

15,000

20,000

0

2.5

5

7.5

10

12.5

f=BMI forecast. Source: EIA, BMI

Firstly, efficiency gains are beginning to filter through with oil production per rig increasing. Secondly, we

expect production from new Gulf of Mexico projects will increase by over 180,000b/d in 2015 and by an

additional 120,000b/d in 2016. These new volumes will offset reduced production shale plays (see 'Gulf Of

Mexico Crude Will Support US Production Growth', 21 April).

Pricing In Iran

In last month's 'Oil Price Outlook' we incorporated our expectation for a breakthrough in Iranian

sanctions negotiations. Since then, the framework agreement has been reached, reinforcing our view that

Iran and the P5+1 group will reach a final agreement in June/July 2015. The framework agreement has also

given us more clarity (albeit with a significant level of uncertainty remaining) on how sanctions may be

rolled back.



We now expect a slower roll back of sanctions on oil quotas than we projected in March. We estimate first

additional Iranian volumes reaching the market in late 2015, early 2016. This means that the negative

impact on price in 2015 will be on sentiment, with a longer-lasting fundamental impact on prices happening

in 2016. This adjustment in Iranian post-sanctions expectations has also been a factor prompting us to adjust

upwards our 2015 average oil price and moderate the y-o-y growth in average price for 2016. (see 'Q116:

First Post-Sanctions Oil Exports', 21 April).

Slow Ramp- Up in Iranian Oil Exports

Iran Oil Production Without Sanctions Relief (000b/d - LHS), Additional Crude Oil Production WithSanctions Relief (000b/d - LHS), Floating Storage** (000b/d - RHS)

*2014 = BMI estimate. 2015-2017 = BMI forecast.

**Floating storage depletion based on assumption that half of Iran's additional exports in the case of sanctions relief will come

from storage, and half will come from additional production. Storage depleted by June 2016 based on this assumption.

Source: BMI calculations, EIA, IEA, OPEC, Bloomberg.

Extreme Positioning Suggests Bullish Sentiment Near Peak

We believe that the price-supportive fundamental shifts that will occur in the oil market over the coming 6-9

months, particularly in the US, have already been largely priced in. This is reflected in the record level of

bullish speculative positioning in the ICE Brent market. In particular, ICE net speculative long positions



are at a record high, surpassing even the 2014 peak that accompanied the surge of prices through

USD110/bbl. Sentiment towards oil has therefore already swing from a bearish to bullish extreme since

September 2014. Instead, we expect a significant uptick in selling pressure on Brent in H215 the market

remains well supplied and this year's price rally stalls.

Bullish Extreme In Managed Money

ICE Brent - Net Speculative Long Positions

Source: Bloomberg

Long-Term Outlook: L-shaped Recovery

We maintain our long term outlook that oil prices will not average above USD80/bbl to the end of our

forecast period. Price rallies will be curbed by the flexibility of US shale supply to ramp-up in response to

higher prices. Over our 10 year forecast period, we therefore see an L-shaped recovery in oil prices. We

forecast a price increase acceleration towards the tail end of our forecast period, as costly projects cancelled

now will moderate production growth towards the end of this decade and early next.



Supply-Side Dynamics Keep Pressure On Oil Prices

Front-Month Brent Forecast, Annual Average, USD/bbl

F=BMI forecast. Source: BMI

Risks To Price Outlook

The potential for a stronger upswing in demand in response to low prices than we currently forecast is

another upside risk to our price outlook. We increased our US and India fuels consumption forecasts for

2015 and 2016 in December 2014 to account for the impact of lower oil prices. In China, we have a sombre

outlook for Chinese fuels and crude consumption, which dovetails with our below-consensus China macro

view. Should the Chinese central government surprise us by changing tack and pursuing aggressive fiscal

economic stimulus in the coming quarters, then our current demand and price forecasts would prove too

low.



Appendix

Global - Crude Oil, Refined Fuels And Natural Gas Prices, 10-year Forecasts

Table: Energy Price Forecasts, 2013-2018

2013 2014 2015f 2016f 2017f 2018f

OPEC basket, USD/bbl 105.90 96.30 56.00 58.00 60.00 62.00

WTI, USD/bbl 98.00 93.06 52.00 55.00 58.00 59.00

Brent, USD/bbl 108.70 99.50 59.00 61.00 63.00 65.00

Urals, USD/bbl 107.90 98.09 57.00 59.00 61.00 63.00

Dubai, USD/bbl 105.40 96.50 55.00 57.00 59.00 61.00

Unleaded gasoline, Rotterdam, USD/bbl 115.19 110.71 70.25 69.90 69.95 70.50

Unleaded gasoline, New York, USD/bbl 118.70 114.83 70.75 71.15 72.20 73.00

Unleaded gasoline, Singapore, USD/bbl 115.89 112.46 69.75 70.65 72.00 73.20

Unleaded gasoline, global average, USD/bbl 116.59 112.67 70.25 70.57 71.38 72.23

Gasoil/diesel, Rotterdam, USD/bbl 124.81 111.00 67.85 71.50 75.00 78.00

Gasoil/diesel, Singapore, USD/bbl 123.15 112.45 67.75 72.00 75.50 78.20

Gasoil/diesel, global average, USD/bbl 124.84 111.82 67.90 71.73 75.10 78.00

Naphtha, Rotterdam, USD/bbl 100.27 98.30 59.30 64.00 67.20 70.56

Naphtha, Singapore, USD/bbl 100.27 98.62 59.60 64.40 67.60 71.00

Naphtha, global average, USD/bbl 100.27 98.46 59.45 64.20 67.40 70.78

Jet/kerosene, Rotterdam, USD/bbl 127.30 116.21 71.24 76.50 79.50 83.45

Jet/kerosene, New York, USD/bbl 125.10 117.36 72.25 77.50 80.50 84.20

Jet/kerosene, Singapore, USD/bbl 122.65 112.38 67.20 73.50 77.00 81.20

Jet/kerosene, global average, USD/bbl 125.02 115.32 70.23 75.83 79.00 82.95

Bunker fuel 180, Rotterdam, USD/bbl 95.07 83.64 44.14 44.00 46.00 45.50

Bunker fuel 180, New York, USD/bbl 97.52 96.85 52.09 50.00 51.50 50.50

Bunker fuel 180, Singapore, USD/bbl 93.96 86.96 45.80 46.50 48.50 47.75

Bunker fuel 180, global average, USD/bbl 95.52 89.15 47.34 46.83 48.67 47.92






Bunker fuel, Rotterdam, USD/bbl 93.16 88.04 42.15 43.25 45.25 44.00

Bunker fuel, New York, USD/bbl 95.33 94.02 48.13 47.50 49.13 47.50

Bunker fuel, Singapore, USD/bbl 94.90 90.23 45.37 46.00 48.00 46.38



Energy Price Forecasts, 2013-2018 - Continued

2013 2014 2015f 2016f 2017f 2018f

Bunker fuel, global average, USD/bbl 94.46 90.76 45.22 45.58 47.46 45.96

Henry Hub, USD/mn BTU 3.74 4.50 3.00 3.30 3.50 4.00

f=BMI forecast. Source: BMI/Bloomberg

Table: Energy Price Forecasts, 2019-2024 ( Global 2019-2024)

2019f 2020f 2021f 2022f 2023f 2024f

OPEC basket, USD/bbl 63.00 67.00 69.00 72.00 74.00 75.00

WTI, USD/bbl 60.00 62.00 65.00 68.00 72.00 73.00

Brent, USD/bbl 66.00 70.00 72.00 75.00 77.00 78.00

Urals, USD/bbl 64.00 68.00 70.00 73.00 75.00 76.00

Dubai, USD/bbl 62.00 66.00 68.00 71.00 73.00 74.00

Unleaded gasoline, Rotterdam, USD/bbl 71.00 71.00 71.00 71.00 71.00 71.00

Unleaded gasoline, New York, USD/bbl 73.70 73.70 73.70 73.70 73.70 73.70

Unleaded gasoline, Singapore, USD/bbl 74.50 74.50 74.50 74.50 74.50 74.50

Unleaded gasoline, global average, USD/bbl 73.07 73.07 73.07 73.07 73.07 73.07

Gasoil/diesel, Rotterdam, USD/bbl 79.00 80.00 81.00 81.00 81.00 81.00

Gasoil/diesel, Singapore, USD/bbl 79.30 80.20 81.00 81.00 81.00 81.00

Gasoil/diesel, global average, USD/bbl 79.10 80.07 81.00 81.00 81.00 81.00

Naphtha, Rotterdam, USD/bbl 71.60 72.50 73.40 73.40 73.40 73.40

Naphtha, Singapore, USD/bbl 71.80 72.60 73.30 73.30 73.30 73.30

Naphtha, global average, USD/bbl 71.70 72.55 73.35 73.35 73.35 73.35

Jet/kerosene, Rotterdam, USD/bbl 84.85 98.50 98.50 98.50 98.50 99.50

Jet/kerosene, New York, USD/bbl 85.60 98.50 98.50 98.50 98.50 99.50

Jet/kerosene, Singapore, USD/bbl 82.60 97.00 97.00 97.00 97.00 98.00

Jet/kerosene, global average, USD/bbl 84.35 98.00 98.00 98.00 98.00 99.00










Energy Price Forecasts, 2019-2024 ( Global 2019-2024) - Continued

2019f 2020f 2021f 2022f 2023f 2024f



Bunker fuel, Rotterdam, USD/bbl 44.18 44.18 44.18 44.18 44.18 44.18

Bunker fuel, New York, USD/bbl 47.68 47.68 47.68 47.68 47.68 47.68

Bunker fuel, Singapore, USD/bbl 46.55 46.55 46.55 46.55 46.55 46.55

Bunker fuel, global average, USD/bbl 46.13 46.13 46.13 46.13 46.13 46.13

Henry Hub, USD/mn BTU 4.20 4.20 4.20 4.20 4.20 4.20

f=BMI forecast. Source: BMI, Bloomberg

Latin America - Regional Appendix

The data contained in these appendix tables is correct as of 1 April 2015. It represents a snapshot of our

regional forecasts at the end of our last publishing quarter. It is included for reference purposes only. Latest

data, reflecting forecasts made for the market this quarter, can be found in the Industry Forecast Scenario

section of this report. Please note, that because this table represents a snapshot of our last regional forecasts,

whereas data included in the Industry Forecast Scenario represents our latest forecasts made this quarter,

country-specific data may not match.

Table: Oil Consumption - Historical Data & Forecasts, 2012-2019 ('000b/d)

2012 2013 2014 2015 2016 2017 2018 2019

Argentina 737 758 773 789 804 816 829 841

Bolivia 56 57 58 59 60 61 63 64

Brazil 2,864 2,998 3,049 3,086 3,124 3,163 3,206 3,249

Chile 342 341 347 356 367 378 391 405

Colombia 304 306 311 316 322 327 334 340

Ecuador 248 255 265 275 285 296 305 315

Mexico 2,086 2,044 2,095 2,148 2,201 2,257 2,302 2,348

Peru 207 221 228 235 242 249 256 261

Trinidad and Tobago 44 45 46 47 48 49 51 52

Venezuela 777 784 806 829 852 876 900 925

BMI Universe 7,663 7,808 7,978 8,139 8,305 8,472 8,636 8,800



Oil Consumption - Historical Data & Forecasts, 2012-2019 ('000b/d) - Continued

2012 2013 2014 2015 2016 2017 2018 2019

Other LatAm 904 950 964 979 993 1,008 1,023 1,039

Regional Total 8,568 8,758 8,943 9,117 9,299 9,481 9,659 9,839

f = forecast. Source: EIA, BMI

Table: Oil Consumption - Long Term Forecasts, 2016-2024 ('000b/d)

2016 2017 2018 2019 2020 2021 2022 2023 2024

Argentina 804 816 829 841 854 867 880 893 906.15

Bolivia 60 61 63 64 65 66 67 68 69.06

Brazil 3,124 3,163 3,206 3,249 3,296 3,344 3,394 3,445 3,496.82

Chile 367 378 391 405 419 435 453 471 489.86

Colombia 322 327 334 340 347 354 362 369 377.03

Ecuador 285 296 305 315 326 337 349 361 373.69

Mexico 2,201 2,257 2,302 2,348 2,395 2,443 2,491 2,541 2,592.04

Peru 242 249 256 261 267 272 277 283 288.69

Trinidad andTobago

48 49 51 52 53 55 56 57 58.75

Venezuela 852 876 900 925 951 978 1,005 1,033 1,062.28

BMI Universe 8,305 8,472 8,636 8,800 8,972 9,151 9,334 9,522 9,714

Other LatAm 993 1,008 1,023 1,039 1,054 1,070 1,086 1,086 1,087

Regional Total 9,299 9,481 9,659 9,839 10,027 10,221 10,420 10,608 10,802




Table: Oil Production - Historical Data & Forecasts, 2012-2019 ('000b/d)

2012 2013 2014 2015 2016 2017 2018 2019

Argentina 706 691 698 705 713 722 733 745

Bolivia 55 64 64 68 72 75 78 80

Brazil 2,149 2,114 2,277 2,365 2,503 2,648 2,777 2,845

Chile 12 11 11 11 11 11 11 11

Colombia 963 1,022 987 940 917 900 892 892

Ecuador 505 527 543 548 554 559 565 571

Mexico 2,911 2,883 2,867 2,857 2,854 2,857 2,886 2,928

Peru 156 174 178 181 185 190 195 199


Venezuela 2,475 2,475 2,496 2,432 2,382 2,333 2,281 2,225

BMI Universe 10,050 10,081 10,242 10,230 10,315 10,422 10,545 10,624

Other LatAm 93 100 100 100 100 100 100 100

Regional Total 10,143 10,181 10,342 10,330 10,415 10,522 10,645 10,724


Table: Oil Production - Long-Term Forecasts, 2016-2024 ('000b/d)

2016 2017 2018 2019 2020 2021 2022 2023 2024

Argentina 713 722 733 745 757 772 789 806 823.48

Bolivia 72 75 78 80 81 82 82 83 83.97

Brazil 2,503 2,648 2,777 2,845 2,928 3,014 3,103 3,194 3,287.46

Chile 11 11 11 11 11 11 12 12 11.84

Colombia 917 900 892 892 902 902 894 882 865.68

Ecuador 554 559 565 571 574 575 572 569 563.98

Mexico 2,854 2,857 2,886 2,928 2,983 3,052 3,123 3,196 3,270.70

Peru 185 190 195 199 203 208 213 218 223.14

Trinidad and Tobago 124 126 129 130 131 132 134 135 136.47

Venezuela 2,382 2,333 2,281 2,225 2,170 2,138 2,125 2,113 2,120.22



Oil Production - Long-Term Forecasts, 2016-2024 ('000b/d) - Continued

2016 2017 2018 2019 2020 2021 2022 2023 2024

BMI Universe 10,315 10,422 10,545 10,624 10,740 10,887 11,047 11,208 11,387

Other LatAm 100 100 100 100 100 100 100 101 102

Regional Total 10,415 10,522 10,645 10,724 10,840 10,987 11,147 11,309 11,489


Table: Refining Capacity - Historical Data & Forecasts, 2012-2019 ('000b/d)

2012 2013 2014 2015 2016 2017 2018 2019

Argentina 631 631 631 631 631 631 631 631

Bolivia 41 41 41 41 54 54 54 54

Brazil 1,917 2,102 2,217 2,332 2,497 2,497 2,497 2,497

Chile 227 227 227 227 227 227 227 227

Colombia 336 336 336 421 421 421 421 421

Ecuador 176 176 176 176 176 376 476 476

Mexico 1,690 1,690 1,690 1,714 1,714 1,714 1,749 1,867

Peru 193 193 193 193 193 193 228 228


Venezuela 1,282 1,282 1,282 1,282 1,332 1,495 1,495 1,495

BMI Universe 6,661 6,846 6,961 7,185 7,412 7,775 7,945 8,063

Other LatAm 1,672 1,680 1,688 1,697 1,705 1,714 1,722 1,731

Regional Total 8,333 8,526 8,649 8,881 9,117 9,489 9,667 9,794




Table: Refining Capacity - Long-Term Forecasts, 2016-2024 ('000b/d)

2016 2017 2018 2019 2020 2021 2022 2023 2024

Argentina 631 631 631 631 631 631 631 631 630.58

Bolivia 54 54 54 54 54 54 54 54 53.70

Brazil 2,497 2,497 2,497 2,497 2,497 2,497 2,497 2,497 2,497.00

Chile 227 227 227 227 227 227 227 227 226.80

Colombia 421 421 421 421 421 421 421 421 420.85

Ecuador 176 376 476 476 476 476 476 476 476.00

Mexico 1,714 1,714 1,749 1,867 1,867 1,867 1,867 1,867 1,867.00

Peru 193 193 228 228 228 228 228 228 228.10

Trinidad andTobago

168 168 168 168 168 168 168 168 168.00

Venezuela 1,332 1,495 1,495 1,495 1,495 1,495 1,495 1,495 1,495.10

BMI Universe 7,412 7,775 7,945 8,063 8,063 8,063 8,063 8,063 8,063

Other LatAm 1,705 1,714 1,722 1,731 1,740 1,748 1,757 1,757 1,758

Regional Total 9,117 9,489 9,667 9,794 9,803 9,811 9,820 9,820 9,821


Table: Gas Consumption - Historical Data & Forecasts, 2012-2019 (bcm)

2012 2013 2014 2015 2016 2017 2018 2019

Argentina 46.46 45.70 46.39 46.85 47.93 49.27 50.75 52.27

Bolivia 2.24 2.04 2.13 2.22 2.31 2.39 2.48 2.56

Brazil 30.32 37.60 41.36 42.80 44.52 46.52 48.61 52.50

Chile 5.04 4.70 4.91 5.13 5.39 5.66 5.94 6.24

Colombia 9.39 9.95 10.85 11.50 12.07 12.68 13.18 13.71

Ecuador 0.51 0.52 0.53 0.54 0.55 0.56 0.57 0.59

Mexico 68.63 64.58 66.51 69.51 72.63 75.90 79.32 82.09

Peru 5.99 6.28 6.66 7.06 7.48 7.93 8.37 8.83

Trinidad and Tobago 23.53 24.24 24.97 25.72 26.49 27.28 28.10 28.66

Venezuela 24.60 30.49 31.56 32.66 33.64 34.65 35.69 36.76



Gas Consumption - Historical Data & Forecasts, 2012-2019 (bcm) - Continued

2012 2013 2014 2015 2016 2017 2018 2019

Regional Total 318.20 330.62 343.52 354.88 367.23 380.49 394.19 409.02


Table: Gas Consumption - Long-Term Forecasts, 2016-2024 (bcm)

2016 2017 2018 2019 2020 2021 2022 2023 2024

Argentina 47.93 49.27 50.75 52.27 54.10 55.99 58.23 60.56 62.68

Bolivia 2.31 2.39 2.48 2.56 2.65 2.74 2.83 2.92 3.01

Brazil 44.52 46.52 48.61 52.50 54.86 57.06 59.34 61.42 63.57

Chile 5.39 5.66 5.94 6.24 6.55 6.88 7.22 7.58 7.96

Colombia 12.07 12.68 13.18 13.71 14.26 14.69 15.13 15.58 16.05

Ecuador 0.55 0.56 0.57 0.59 0.60 0.61 0.62 0.63 0.65

Mexico 72.63 75.90 79.32 82.09 84.97 87.94 91.02 94.20 97.50

Peru 7.48 7.93 8.37 8.83 9.31 9.78 10.27 10.89 11.65

Trinidad and Tobago 26.49 27.28 28.10 28.66 29.24 29.53 29.82 30.12 30.42

Venezuela 33.64 34.65 35.69 36.76 37.86 38.81 39.78 40.78 41.79

Regional Total 367.23 380.49 394.19 409.02 422.95 436.43 447.67 459.09 470.69


Table: Gas Production - Historical Data & Forecasts, 2012-2019 (bcm)

2012 2013 2014 2015 2016 2017 2018 2019

Argentina 37.62 35.50 36.21 36.93 37.97 39.22 40.71 42.34

Bolivia 17.35 19.07 20.97 22.65 24.23 25.45 26.29 27.07

Brazil 16.94 21.29 22.14 23.03 24.41 25.87 27.17 28.39

Chile 1.19 0.93 0.94 0.94 0.95 0.95 0.96 0.96

Colombia 11.93 12.29 12.47 12.22 12.10 12.10 12.22 12.34

Ecuador 0.51 0.87 1.13 1.24 1.25 1.26 1.28 1.29

Mexico 47.67 46.43 46.66 47.13 48.07 48.55 49.28 50.27

Peru 11.83 12.31 12.80 13.31 13.87 14.45 15.00 15.57



Gas Production - Historical Data & Forecasts, 2012-2019 (bcm) - Continued

2012 2013 2014 2015 2016 2017 2018 2019


Venezuela 22.72 28.40 28.68 29.54 31.02 31.33 31.64 32.75

Regional Total 245.02 257.96 264.46 271.29 279.74 286.76 293.86 302.54


Table: Gas Production - Long-Term Forecasts, 2016-2024 (bcm)

2016 2017 2018 2019 2020 2021 2022 2023 2024

Argentina 37.97 39.22 40.71 42.34 44.25 46.24 48.55 50.98 53.52

Bolivia 24.23 25.45 26.29 27.07 27.89 28.58 29.30 30.03 30.78

Brazil 24.41 25.87 27.17 28.39 29.67 30.85 32.09 33.05 34.04

Chile 0.95 0.95 0.96 0.96 0.97 0.97 0.98 0.98 0.99

Colombia 12.10 12.10 12.22 12.34 12.53 12.71 12.97 13.23 13.49

Ecuador 1.25 1.26 1.28 1.29 1.30 1.30 1.29 1.29 1.28

Mexico 48.07 48.55 49.28 50.27 51.27 52.30 53.60 54.94 56.32

Peru 13.87 14.45 15.00 15.57 16.13 16.71 17.28 17.87 18.48


Venezuela 31.02 31.33 31.64 32.75 33.73 34.40 35.09 35.79 36.51

Regional Total 279.74 286.76 293.86 302.54 311.57 319.81 327.35 334.84 343.56


Table: LNG Exports - Historical Data & Forecasts, 2012-2019 (bcm)

2012 2013 2014 2015 2016 2017 2018 2019

Argentina -3.00 -3.50 -3.70 -3.75 -3.85 -3.95 -4.30 -4.85

Bolivia 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

Brazil -3.85 -4.45 -6.75 -7.00 -7.50 -8.00 -8.00 -9.50

Chile -3.00 -3.00 -3.50 -3.50 -4.00 -4.00 -4.00 -4.00

Colombia 0.00 0.00 0.00 0.68 -0.32 -0.32 -0.82 -0.82



LNG Exports - Historical Data & Forecasts, 2012-2019 (bcm) - Continued

2012 2013 2014 2015 2016 2017 2018 2019

Ecuador 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

Mexico -4.26 -0.80 -0.88 -1.00 -2.00 -2.00 -2.00 -2.00

Peru 5.84 6.02 6.14 6.25 6.39 6.52 6.63 6.74


Venezuela 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

BMI Universe 7.99 12.33 9.06 9.32 5.93 5.11 4.00 2.39

Regional Total 7.99 12.33 9.06 9.32 5.93 5.11 4.00 2.39


Table: LNG Exports - Long-Term Forecasts, 2016-2024 (bcm)

2016 2017 2018 2019 2020 2021 2022 2023 2024

Argentina -3.85 -3.95 -4.30 -4.85 -5.50 -6.34 -7.24 -8.44 (9.64)

Bolivia 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 -

Brazil -7.50 -8.00 -8.00 -9.50 -7.00 -7.00 -7.00 -7.00 (8.00)

Chile -4.00 -4.00 -4.00 -4.00 -5.00 -5.00 -5.00 -5.00 (5.00)

Colombia -0.32 -0.32 -0.82 -0.82 -0.82 -1.32 -1.32 -1.32 (1.32)

Ecuador 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 -

Mexico -2.00 -2.00 -2.00 -2.00 -3.00 -4.00 -4.00 -4.00 (4.00)

Peru 6.39 6.52 6.63 6.74 6.82 6.93 7.01 6.98 6.83


Venezuela 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 -

BMI Universe 5.93 5.11 4.00 2.39 2.65 0.59 -0.05 -1.11 -3.28

Regional Total 5.93 5.11 4.00 2.39 2.65 0.59 (0.05) (1.11) (3.28)




Colombia - Total Hydrocarbons, 10-Year Forecasts

Table: Total Hydrocarbons Production, Consumption and Net Exports (Colombia 2013-2018)

2013 2014e 2015f 2016f 2017f 2018f

Total hydrocarbons production, 000boe 1,204.1 1,194.4 1,173.6 1,152.4 1,126.9 1,102.8

Total hydrocarbons production, 000boe, % y-o-y 5.2 -0.8 -1.7 -1.8 -2.2 -2.1

Total hydrocarbons production, USDbn 45.9 42.0 24.3 24.7 25.1 25.3

Total hydrocarbons production, USD, % y-o-y 1.2 -8.6 -42.1 1.6 1.5 0.7

Total hydrocarbons consumption, 000boe 455.1 472.3 486.4 499.6 513.4 527.0

Total hydrocarbons consumption, 000boe, % y-o-y 0.4 3.8 3.0 2.7 2.8 2.6

Total hydrocarbons consumption, USDbn 19.2 18.4 11.4 12.1 12.7 13.4

Total hydrocarbons consumption, USD, % y-o-y -4.2 -3.8 -38.1 5.7 5.6 5.2

Total net hydrocarbons exports, 000boe 749.0 722.1 687.3 652.8 613.5 575.9

Total net hydrocarbons exports, 000boe, % y-o-y 8.3 -3.6 -4.8 -5.0 -6.0 -6.1

Total net hydrocarbons exports, USDbn 27.8 24.6 13.5 13.3 13.0 12.5

Total net hydrocarbons exports, USDbn % y-o-y 4.8 -11.7 -44.9 -2.0 -2.2 -3.6

Total net hydrocarbons exports at USD50/bbl, USDbn 13.1 12.8 12.1 11.4 10.8 10.0


e/f = BMI estimate/forecast. Source: BMI, EIA

Table: Total Hydrocarbons Production, Consumption and Net Exports (Colombia 2019-2024)

2019f 2020f 2021f 2022f 2023f 2024f

Total hydrocarbons production, 000boe 1,085.6 1,078.5 1,072.4 1,070.8 1,070.1 1,078.0

Total hydrocarbons production, 000boe, % y-o-y -1.6 -0.7 -0.6 -0.2 -0.1 0.7

Total hydrocarbons production, USDbn 25.3 26.2 26.5 27.1 27.5 27.9

Total hydrocarbons production, USD, % y-o-y 0.0 3.6 1.3 2.2 1.4 1.5

Total hydrocarbons consumption, 000boe 541.0 555.5 568.7 582.3 596.2 610.6

Total hydrocarbons consumption, 000boe, % y-o-y 2.7 2.7 2.4 2.4 2.4 2.4

Total hydrocarbons consumption, USDbn 13.9 14.6 15.1 15.0 16.1 15.9

Total hydrocarbons consumption, USD, % y-o-y 3.7 5.2 3.4 -0.9 7.5 -1.3

Total net hydrocarbons exports, 000boe 544.6 523.0 503.7 488.5 473.8 467.4

Total net hydrocarbons exports, 000boe, % y-o-y -5.4 -4.0 -3.7 -3.0 -3.0 -1.4

Total net hydrocarbons exports, USDbn 12.0 12.2 12.1 12.2 12.1 12.1

Total net hydrocarbons exports, USDbn % y-o-y -3.9 1.5 -1.2 0.7 -0.7 -0.1



Total Hydrocarbons Production, Consumption and Net Exports (Colombia 2019-2024) - Continued

2019f 2020f 2021f 2022f 2023f 2024f




Colombia - Refined Products Breakdown, 10-Year Forecasts

We have released new data series of the breakdown of refined fuels into production, consumption and net

trade of different fuels over a 10-year period. The Liquefied Petroleum Gas (LPG) component is either

wholly accounted for in the refined products breakdown tables, or, if the country is a LPG producer at the

wellhead then it is contained at the end in its own separate table that includes refined and wellhead

production.

Table: Refined Petroleum Products, Production Breakdown (Colombia 2013-2018)

2013e 2014e 2015f 2016f 2017f 2018f

Motor gasoline production, 000b/d 85.1 85.1 110.6 112.8 121.8 125.5

Motor gasoline production, % y-o-y 6.5 0.0 30.0 2.0 8.0 3.0

Motor gasoline production, USDbn 3.7 3.6 2.9 2.9 3.2 3.3

Motor gasoline production, % of domestic production 24.5 24.5 29.3 29.0 29.5 29.7

Jet fuel/kerosene production, 000b/d 24.3 24.3 24.3 24.3 24.3 24.3

Jet fuel/kerosene production, % y-o-y -3.6 0.0 0.0 0.0 0.0 0.0

Jet fuel/kerosene production, USDbn 1.1 1.0 0.6 0.7 0.7 0.7

Jet fuel/kerosene production, % of domestic production 7.0 7.0 6.4 6.2 5.9 5.7

Jet fuel production, 000b/d 20.8 20.8 20.8 20.8 20.8 20.8

Jet fuel production, % y-o-y 1.1 0.0 0.0 0.0 0.0 0.0

Jet fuel production, USDbn 1.0 0.9 0.5 0.6 0.6 0.6

Jet fuel Production, % of domestic production 6.0 6.0 5.5 5.4 5.0 4.9

Kerosene production, 000b/d 3.5 3.5 3.5 3.5 3.5 3.5

Kerosene production, % y-o-y -24.5 0.0 0.0 0.0 0.0 0.0

Kerosene production, USDbn 0.2 0.1 0.1 0.1 0.1 0.1

Kerosene production, % of domestic production 1.0 1.0 0.9 0.9 0.8 0.8

Distillate fuel oil production, 000b/d 85.1 85.1 89.3 98.3 113.0 118.6

Distillate fuel oil production, % y-o-y -18.8 0.0 5.0 10.0 15.0 5.0



Refined Petroleum Products, Production Breakdown (Colombia 2013-2018) - Continued

2013e 2014e 2015f 2016f 2017f 2018f

Distillate fuel oil production, USDbn 3.9 3.5 2.2 2.6 3.1 3.4

Distillate fuel oil production, % of domestic production 24.5 24.5 23.7 25.3 27.3 28.1

Residual fuel oil production, 000b/d 76.4 76.4 76.4 76.4 76.4 76.4

Residual fuel oil production, % y-o-y -4.6 0.0 0.0 0.0 0.0 0.0

Residual fuel oil production, USDbn 2.7 2.6 1.3 1.3 1.4 1.3

Residual fuel oil production, % of domestic production 22.0 22.0 20.2 19.6 18.5 18.1

Refined LPG production, 000b/d 20.8 20.8 21.2 21.7 22.1 22.5

Refined LPG production, % y-o-y 43.7 0.0 2.0 2.0 2.0 2.0

Refined LPG production, USDbn 0.8 0.7 0.5 0.5 0.5 0.6

Refined LPG production, % of domestic production 6.0 6.0 5.6 5.6 5.4 5.3

Other products production, 000b/d 55.6 55.6 55.6 55.6 55.6 55.6

Other products production, % y-o-y 55.2 0.0 0.0 0.0 0.0 0.0

Other products production, USDbn 2.4 2.3 1.4 1.4 1.5 1.5

Other products production, % of domestic production 16.0 16.0 14.7 14.3 13.4 13.1


Table: Refined Petroleum Products, Production Breakdown (Colombia 2019-2024)

2019f 2020f 2021f 2022f 2023f 2024f

Motor gasoline production, 000b/d 129.2 133.1 137.1 141.2 145.5 149.8

Motor gasoline production, % y-o-y 3.0 3.0 3.0 3.0 3.0 3.0

Motor gasoline production, USDbn 3.5 3.6 3.7 3.8 3.9 4.0

Motor gasoline production, % of domestic production 29.8 30.0 30.2 30.3 30.4 30.5

Jet fuel/kerosene production, 000b/d 24.3 24.3 24.3 24.3 24.3 24.3

Jet fuel/kerosene production, % y-o-y 0.0 0.0 0.0 0.0 0.0 0.0

Jet fuel/kerosene production, USDbn 0.8 0.9 0.9 0.9 0.9 0.9

Jet fuel/kerosene production, % of domestic production 5.6 5.5 5.3 5.2 5.1 5.0

Jet fuel production, 000b/d 20.8 20.8 20.8 20.8 20.8 20.8

Jet fuel production, % y-o-y 0.0 0.0 0.0 0.0 0.0 0.0

Jet fuel production, USDbn 0.7 0.7 0.7 0.7 0.7 0.8

Jet fuel Production, % of domestic production 4.8 4.7 4.6 4.5 4.4 4.2

Kerosene production, 000b/d 3.5 3.5 3.5 3.5 3.5 3.5

Kerosene production, % y-o-y 0.0 0.0 0.0 0.0 0.0 0.0



Refined Petroleum Products, Production Breakdown (Colombia 2019-2024) - Continued

2019f 2020f 2021f 2022f 2023f 2024f

Kerosene production, USDbn 0.1 0.1 0.1 0.1 0.1 0.1

Kerosene production, % of domestic production 0.8 0.8 0.8 0.7 0.7 0.7

Distillate fuel oil production, 000b/d 124.6 130.8 137.3 144.2 151.4 159.0

Distillate fuel oil production, % y-o-y 5.0 5.0 5.0 5.0 5.0 5.0

Distillate fuel oil production, USDbn 3.6 3.8 4.1 4.3 4.5 4.7

Distillate fuel oil production, % of domestic production 28.8 29.5 30.2 30.9 31.7 32.4

Residual fuel oil production, 000b/d 76.4 76.4 76.4 76.4 76.4 76.4

Residual fuel oil production, % y-o-y 0.0 0.0 0.0 0.0 0.0 0.0

Residual fuel oil production, USDbn 1.3 1.3 1.3 1.3 1.3 1.3

Residual fuel oil production, % of domestic production 17.6 17.2 16.8 16.4 16.0 15.6

Refined LPG production, 000b/d 23.0 23.5 23.9 24.4 24.9 25.4

Refined LPG production, % y-o-y 2.0 2.0 2.0 2.0 2.0 2.0

Refined LPG production, USDbn 0.6 0.6 0.6 0.7 0.7 0.7

Refined LPG production, % of domestic production 5.3 5.3 5.3 5.2 5.2 5.2

Other products production, 000b/d 55.6 55.6 55.6 55.6 55.6 55.6

Other products production, % y-o-y 0.0 0.0 0.0 0.0 0.0 0.0

Other products production, USDbn 1.5 1.5 1.5 1.5 1.5 1.5

Other products production, % of domestic production 12.8 12.5 12.2 11.9 11.6 11.3


Table: Refined Petroleum Products, Consumption Breakdown (Colombia 2013-2018)

2013e 2014e 2015f 2016f 2017f 2018f

Motor gasoline consumption, 000b/d 84.2 85.9 87.6 89.4 91.2 93.9

Motor gasoline consumption, % y-o-y 1.9 2.0 2.0 2.0 2.0 3.0

Motor gasoline consumption, % of domestic consumption 26.0 26.1 26.2 26.2 26.3 26.6

Motor gasoline consumption, USDbn 3.6 3.6 2.3 2.3 2.4 2.5

Jet fuel/kerosene consumption, 000b/d 24.3 24.3 24.3 24.3 24.3 24.3

Jet fuel/kerosene consumption, % y-o-y -5.1 0.0 0.0 0.0 0.0 0.0

Jet fuel/kerosene consumption, % of domestic consumption 7.5 7.4 7.3 7.1 7.0 6.9

Jet fuel/kerosene consumption, USDbn 1.0 1.0 0.6 0.6 0.6 0.6

Jet fuel consumption, 000b/d 19.4 19.4 19.4 19.4 19.4 19.4

Jet fuel consumption, % y-o-y -7.4 0.0 0.0 0.0 0.0 0.0



Refined Petroleum Products, Consumption Breakdown (Colombia 2013-2018) - Continued

2013e 2014e 2015f 2016f 2017f 2018f

Jet fuel consumption, % of domestic consumption 6.0 5.9 5.8 5.7 5.6 5.5

Jet fuel consumption, USDbn 0.9 0.8 0.5 0.5 0.6 0.6

Kerosene consumption, 000b/d 4.9 4.9 4.9 4.9 4.9 4.9

Kerosene consumption, % y-o-y 5.7 0.0 0.0 0.0 0.0 0.0

Kerosene consumption, % of domestic consumption 1.5 1.5 1.5 1.4 1.4 1.4

Kerosene consumption, USDbn 0.2 0.2 0.1 0.1 0.1 0.1

Distillate fuel oil consumption, 000b/d 123.1 126.8 130.6 134.5 138.6 142.7

Distillate fuel oil consumption, % y-o-y -13.7 3.0 3.0 3.0 3.0 3.0

Distillate fuel oil consumption, % of domestic consumption 38.0 38.5 39.0 39.5 40.0 40.4

Distillate fuel oil consumption, USDbn 5.6 5.2 3.2 3.5 3.8 4.1

Residual fuel oil consumption, 000b/d 11.3 11.3 11.3 11.3 11.3 11.3

Residual fuel oil consumption, % y-o-y -32.1 0.0 0.0 0.0 0.0 0.0

Residual fuel oil consumption, % of domestic consumption 3.5 3.4 3.4 3.3 3.3 3.2

Residual fuel oil consumption, USDbn 0.4 0.4 0.2 0.2 0.2 0.2

LPG consumption, 000b/d 22.7 22.7 22.7 22.7 22.7 22.7

LPG consumption, % y-o-y 28.9 0.0 0.0 0.0 0.0 0.0

LPG consumption, % of domestic consumption 7.0 6.9 6.8 6.7 6.5 6.4

LPG consumption, USDbn 0.8 0.8 0.5 0.5 0.6 0.6

Other products consumption, 000b/d 58.3 58.3 58.3 58.3 58.3 58.3

Other products consumption, % y-o-y 62.5 0.0 0.0 0.0 0.0 0.0

Other products consumption, % of domestic consumption 18.0 17.7 17.4 17.1 16.8 16.5

Other products consumption, USDbn 2.5 2.4 1.5 1.5 1.5 1.6




Table: Refined Petroleum Products, Consumption Breakdown (Colombia 2019-2024)

2019f 2020f 2021f 2022f 2023f 2024f

Motor gasoline consumption, 000b/d 96.7 99.6 102.6 105.7 108.9 112.1

Motor gasoline consumption, % y-o-y 3.0 3.0 3.0 3.0 3.0 3.0

Motor gasoline consumption, % of domestic consumption 26.8 27.1 27.4 27.6 27.8 28.1

Motor gasoline consumption, USDbn 2.6 2.7 2.8 2.8 2.9 3.0

Jet fuel/kerosene consumption, 000b/d 24.3 24.3 24.3 24.3 24.3 24.3

Jet fuel/kerosene consumption, % y-o-y 0.0 0.0 0.0 0.0 0.0 0.0

Jet fuel/kerosene consumption, % of domestic consumption 6.7 6.6 6.5 6.3 6.2 6.1

Jet fuel/kerosene consumption, USDbn 0.6 0.6 0.6 0.6 0.6 0.6

Jet fuel consumption, 000b/d 19.4 19.4 19.4 19.4 19.4 19.4

Jet fuel consumption, % y-o-y 0.0 0.0 0.0 0.0 0.0 0.0

Jet fuel consumption, % of domestic consumption 5.4 5.3 5.2 5.1 5.0 4.9

Jet fuel consumption, USDbn 0.6 0.7 0.7 0.7 0.7 0.7

Kerosene consumption, 000b/d 4.9 4.9 4.9 4.9 4.9 4.9

Kerosene consumption, % y-o-y 0.0 0.0 0.0 0.0 0.0 0.0

Kerosene consumption, % of domestic consumption 1.3 1.3 1.3 1.3 1.2 1.2

Kerosene consumption, USDbn 0.2 0.2 0.2 0.2 0.2 0.2

Distillate fuel oil consumption, 000b/d 147.0 151.4 156.0 160.6 165.5 170.4

Distillate fuel oil consumption, % y-o-y 3.0 3.0 3.0 3.0 3.0 3.0

Distillate fuel oil consumption, % of domestic consumption 40.8 41.2 41.6 41.9 42.3 42.7

Distillate fuel oil consumption, USDbn 4.2 4.4 4.6 4.7 4.9 5.0

Residual fuel oil consumption, 000b/d 11.3 11.3 11.3 11.3 11.3 11.3

Residual fuel oil consumption, % y-o-y 0.0 0.0 0.0 0.0 0.0 0.0

Residual fuel oil consumption, % of domestic consumption 3.1 3.1 3.0 3.0 2.9 2.8

Residual fuel oil consumption, USDbn 0.2 0.2 0.2 0.2 0.2 0.2




LPG consumption, USDbn 0.6 0.6 0.6 0.6 0.6 0.6

Other products consumption, 000b/d 58.3 58.3 58.3 58.3 58.3 58.3

Other products consumption, % y-o-y 0.0 0.0 0.0 0.0 0.0 0.0

Other products consumption, % of domestic consumption 16.2 15.9 15.5 15.2 14.9 14.6



Refined Petroleum Products, Consumption Breakdown (Colombia 2019-2024) - Continued

2019f 2020f 2021f 2022f 2023f 2024f

Other products consumption, USDbn 1.6 1.6 1.6 1.6 1.6 1.6


Table: Refined Petroleum Products, Net Exports Breakdown (Colombia 2013-2018)

2013e 2014e 2015f 2016f 2017f 2018f

Total net exports motor gasoline, 000b/d 0.8 -0.9 22.9 23.4 30.6 31.6

Total net exports motor gasoline, % y-o-y -129.5 -204.0 -2,771.3 2.0 30.9 3.0

Total net exports motor gasoline, USDbn 0.0 0.0 0.6 0.6 0.8 0.8

Total net exports jet fuel/kerosene, 000b/d 0.0 0.0 0.0 0.0 0.0 0.0

Total net exports jet fuel/kerosene, % y-o-y -101.1 0.0 0.0 0.0 0.0 0.0

Total net exports jet fuel/kerosene, USDbn 0.1 0.0 0.0 0.1 0.1 0.1

Total net exports jet fuel, 000b/d 1.4 1.4 1.4 1.4 1.4 1.4

Total net exports jet fuel, % y-o-y -448.1 0.0 0.0 0.0 0.0 0.0

Total net exports jet fuel, USDbn 0.1 0.1 0.0 0.0 0.0 0.0

Total net exports kerosene, 000b/d -1.4 -1.4 -1.4 -1.4 -1.4 -1.4

Total net exports kerosene, % y-o-y 0.0 0.0 0.0 0.0 0.0

Total net exports kerosene, USDbn -0.1 -0.1 0.0 0.0 0.0 0.0

Total net exports distillate fuel oil, 000b/d -38.1 -41.7 -41.3 -36.3 -25.6 -24.1

Total net exports distillate fuel oil, % y-o-y 0.7 9.7 -1.1 -12.1 -29.5 -5.8

Total net exports distillate fuel oil, USDbn -1.7 -1.7 -1.0 -1.0 -0.7 -0.7

Total net exports residual fuel oil, 000b/d 65.0 65.0 65.0 65.0 65.0 65.0

Total net exports residual fuel oil, % y-o-y 2.6 0.0 0.0 0.0 0.0 0.0

Total net exports residual fuel oil, USDbn 2.3 2.2 1.1 1.1 1.2 1.1

Total net exports other products, 000b/d -2.8 -2.8 -2.8 -2.8 -2.8 -2.8

Total net exports other products, % y-o-y 2,666.7 0.0 0.0 0.0 0.0 0.0

Total net exports other products, USDbn -0.1 -0.1 -0.1 -0.1 -0.1 -0.1




Table: Refined Petroleum Products, Net Exports Breakdown (Colombia 2019-2024)

2019f 2020f 2021f 2022f 2023f 2024f

Total net exports motor gasoline, 000b/d 32.5 33.5 34.5 35.5 36.6 37.7

Total net exports motor gasoline, % y-o-y 3.0 3.0 3.0 3.0 3.0 3.0

Total net exports motor gasoline, USDbn 0.9 0.9 0.9 1.0 1.0 1.0

Total net exports jet fuel/kerosene, 000b/d 0.0 0.0 0.0 0.0 0.0 0.0

Total net exports jet fuel/kerosene, % y-o-y 0.0 0.0 0.0 0.0 0.0 0.0

Total net exports jet fuel/kerosene, USDbn 0.1 0.2 0.2 0.2 0.2 0.2

Total net exports jet fuel, 000b/d 1.4 1.4 1.4 1.4 1.4 1.4

Total net exports jet fuel, % y-o-y 0.0 0.0 0.0 0.0 0.0 0.0

Total net exports jet fuel, USDbn 0.0 0.1 0.1 0.1 0.1 0.1

Total net exports kerosene, 000b/d -1.4 -1.4 -1.4 -1.4 -1.4 -1.4

Total net exports kerosene, % y-o-y 0.0 0.0 0.0 0.0 0.0 0.0

Total net exports kerosene, USDbn 0.0 0.0 0.0 0.0 0.0 -0.1

Total net exports distillate fuel oil, 000b/d -22.4 -20.6 -18.6 -16.4 -14.0 -11.4

Total net exports distillate fuel oil, % y-o-y -6.8 -8.1 -9.7 -11.7 -14.5 -18.6

Total net exports distillate fuel oil, USDbn -0.6 -0.6 -0.6 -0.5 -0.4 -0.3

Total net exports residual fuel oil, 000b/d 65.0 65.0 65.0 65.0 65.0 65.0

Total net exports residual fuel oil, % y-o-y 0.0 0.0 0.0 0.0 0.0 0.0

Total net exports residual fuel oil, USDbn 1.1 1.1 1.1 1.1 1.1 1.1

Total net exports other products, 000b/d -2.8 -2.8 -2.8 -2.8 -2.8 -2.8

Total net exports other products, % y-o-y 0.0 0.0 0.0 0.0 0.0 0.0

Total net exports other products, USDbn -0.1 -0.1 -0.1 -0.1 -0.1 -0.1




Table: LPG Production, Consumption and Net Exports (Colombia 2013-2018)

2013e 2014e 2015f 2016f 2017f 2018f




LPG production (wellhead & refined), 000b/d 19.4 19.6 19.8 20.0 20.2 20.4

LPG production (wellhead & refined), % y-o-y 1.0 1.0 1.0 1.0 1.0 1.0

LPG production (wellhead & refined), USDbn 0.7 0.7 0.4 0.5 0.5 0.5

LPG net exports (wellhead & refined), 000b/d -3.2 -3.0 -2.8 -2.6 -2.4 -2.2

LPG net exports (wellhead & refined), % y-o-y -295.7 -6.0 -6.5 -7.0 -7.6 -8.3

LPG net exports (wellhead & refined), USDbn -0.1 -0.1 -0.1 -0.1 -0.1 -0.1

e/f = BMI estimate/forecast. Source: National Sources, BMI

Table: LPG Production, Consumption and Net Exports (Colombia 2019-2024)

2019f 2020f 2021f 2022f 2023f 2024f




LPG production (wellhead & refined), 000b/d 20.6 20.8 21.1 21.3 21.5 21.7

LPG production (wellhead & refined), % y-o-y 1.0 1.0 1.0 1.0 1.0 1.0

LPG production (wellhead & refined), USDbn 0.5 0.6 0.6 0.6 0.6 0.6

LPG net exports (wellhead & refined), 000b/d -2.0 -1.8 -1.6 -1.4 -1.2 -1.0

LPG net exports (wellhead & refined), % y-o-y -9.1 -10.1 -11.4 -13.0 -15.1 -17.9

LPG net exports (wellhead & refined), USDbn -0.1 0.0 0.0 0.0 0.0 0.0

f = BMI forecast. Source: National Sources, BMI



Glossary

Table: Glossary Of Terms

AOR additional oil recovery KCTS Kazakh Caspian Transport System

APA awards for predefined areas km kilometres

API American Petroleum Institute LAB linear alkyl benzene

bbl barrel LDPE low density polypropylene

bcm billion cubic metres LNG liquefied natural gas

b/d barrels per day LPG liquefied petroleum gas

bn billion m metres

boe barrels of oil equivalent mcm thousand cubic metres

BTC Baku-Tbilisi-Ceyhan Pipeline Mcm mn cubic metres

BTU British thermal unit MEA Middle East and Africa

Capex capital expenditure mn million

CBM coal bed methane MoU memorandum of understanding

CEE Central and Eastern Europe mt metric tonne

CPC Caspian Pipeline Consortium MW megawatts

CSG coal seam gas na not available/ applicable

DoE US Department of Energy NGL natural gas liquids

EBRD European Bank for Reconstruction &Development NOC national oil company

EEZ exclusive economic zone OECD Organisation for Economic Cooperation & Development

e/f estimate/forecast OPEC Organization of the Petroleum Exporting Countries

EIA US Energy Information Administration PE polyethylene

EM emerging markets PP polypropylene

EOR enhanced oil recovery PSA production sharing agreement

E&P exploration and production PSC production sharing contract

EPSA exploration and production sharingagreement q-o-q quarter-on-quarter

FID final investment decision R&D research and development

FDI foreign direct investment R/P reserves/production

FEED front end engineering and design RPR reserves to production ratio

FPSO floating production, storage and offloading SGI strategic gas initiative

FTA free trade agreement SoI statement of intent

FTZ free trade zone SPA sale and purchase agreement

GDP gross domestic product SPR strategic petroleum reserve



Glossary Of Terms - Continued

G&G geological and geophysical t/d tonnes per day

GoM Gulf of Mexico tcm trillion cubic metres

GS geological survey toe tonnes of oil equivalent

GTL gas-to-liquids conversion tpa tonnes per annum

GW gigawatts TRIPS Trade-Related Aspects of IntellectualProperty Rights

GWh gigawatt hours trn trillion

HDPE high density polyethylene T&T Trinidad & Tobago

HoA heads of agreement TTPC Trans-Tunisian Pipeline Company

IEA International Energy Agency TWh terawatt hours

IGCC integrated gasification combined cycle UAE United Arab Emirates

IOC international oil company USGS US Geological Survey

IPI Iran-Pakistan-India Pipeline WAGP West African Gas Pipeline

IPO initial public offering WIPO World Intellectual Property Organization

JOC joint operating company WTI West Texas Intermediate

JPDA joint petroleum development area WTO World Trade Organization

Source: BMI



Methodology

Industry Forecast Methodology

BMI's industry forecasts are generated using the best-practice techniques of time-series modelling and

causal/econometric modelling. The precise form of model we use varies from industry to industry, in each

case being determined, as per standard practice, by the prevailing features of the industry data being

examined.

Common to our analysis of every industry is the use of vector autoregressions. Vector autoregressions allow

us to forecast a variable using more than the variable's own history as explanatory information. For

example, when forecasting oil prices, we can include information about oil consumption, supply and

capacity.

When forecasting for some of our industry sub-component variables, however, using a variable's own

history is often the most desirable method of analysis. Such single-variable analysis is called univariate

modelling. We use the most common and versatile form of univariate models: the autoregressive moving

average model (ARMA).

In some cases, ARMA techniques are inappropriate because there is insufficient historic data or data quality

is poor. In such cases, we use either traditional decomposition methods or smoothing methods as a basis for

analysis and forecasting.

BMI mainly uses OLS estimators and in order to avoid relying on subjective views and encourage the use

of objective views, BMI uses a 'general-to-specific' method. BMI mainly mainly uses a linear model, but

simple non-linear models, such as the log-linear model, are used when necessary. During periods of

'industry shock', for example poor weather conditions impeding agricultural output, dummy variables are

used to determine the level of impact.

Effective forecasting depends on appropriately selected regression models. BMI selects the best model

according to various different criteria and tests, including but not exclusive to:

■ R2 tests explanatory power; adjusted R2 takes degree of freedom into account;

■ Testing the directional movement and magnitude of coefficients;

■ Hypothesis testing to ensure coefficients are significant (normally t-test and/or P-value);

■ All results are assessed to alleviate issues related to auto-correlation and multi-collinearity.



BMI uses the selected best model to perform forecasting.

Human intervention plays a necessary and desirable role in all of BMI's industry forecasting. Experience,

expertise and knowledge of industry data and trends ensure that analysts spot structural breaks, anomalous

data, turning points and seasonal features where a purely mechanical forecasting process would not.

Sector-Specific Methodology

There are a number of principal criteria that drive our forecasts for each energy indicator.

Energy Supply

This covers the supply of crude oil, natural gas, refined oil products and electrical power, which is

determined largely by investment levels, available capacity, plant utilisation rates and national policy. We

therefore examine:

■ National energy policy, stated output goals and investment levels;

■ Company-specific capacity data, output targets and capital expenditures, using national, regional andmultinational company sources;

■ International quotas, guidelines and projections from organisations such as OPEC, the InternationalEnergy Agency (IEA), and the US Energy Information Administration (EIA).

Energy Consumption

A mixture of methods is used to generate demand forecasts, applied as appropriate to each individual

country:

■ Underlying economic (GDP) growth for individual countries/regions, sourced from BMI publishedestimates;

■ Historic relationships between GDP growth and energy demand growth in an individual country areanalysed and used as the basis for predicting levels of consumption;

■ Government projections for oil, gas and electricity demand;

■ Third-party agency projections for regional demand, from organisations such as the IEA, EIA and OPEC;

Extrapolation of capacity expansion forecasts based on company- or state-specific investment levels.



Cross Checks

Whenever possible, we compare government and/or third-party agency projections with the declared

spending and capacity expansion plans of the companies operating in each individual country. Where there

are discrepancies, we use company-specific data as physical spending patterns to determine capacity and

supply capability. Similarly, we compare capacity expansion plans and demand projections to check the

energy balance of each country. Where the data suggest imports or exports, we check that necessary

capacity exists or that the required investment in infrastructure is taking place.

Source

Sources include those international bodies mentioned above, such as OPEC, IEA, and EIA, as well as local

energy ministries, official company information, and international and national news, plus international and

national news agencies.

Risk/Reward Index Methodology

BMI's Risk/Reward Index (RRI) provides a comparative regional ranking system evaluating the ease of

doing business and the industry-specific opportunities and limitations for potential investors in a given

market. The RRI system is divided into two distinct areas:

Rewards: Evaluation of sector's size and growth potential in each state, and also broader industry/state

characteristics that may inhibit its development. This is further broken down into two sub-categories:

■ Industry Rewards (this is an industry-specific category taking into account current industry size andgrowth forecasts, the openness of market to new entrants and foreign investors, to provide an overallscore for potential returns for investors);

• Country Rewards (this is a country-specific category, and the score factors in favourable political andeconomic conditions for the industry).

Risks: Evaluation of industry-specific dangers and those emanating from the state's political/economic

profile which call into question the likelihood of anticipated returns being realised over the assessed time

period. This is further broken down into two sub-categories:

■ Industry Risks (this is an industry-specific category whose score covers potential operational risks toinvestors, regulatory issues inhibiting the industry, and the relative maturity of a market);

• Country Risks (this is a country-specific category in which political and economic instability,unfavourable legislation and a poor overall business environment are evaluated to provide an overallscore).



We take a weighted average, combining Market and Country Risks, or Industry and Country Rewards.

These two results in turn provide an overall Risk/Reward Index score, which is used to create our regional

ranking system for the risks and rewards of involvement in a specific industry in a particular country.

For each category and sub-category, each state is scored out of 100 (with 100 the best), with the overall

Risk/Reward Index score a weighted average of the total score. Importantly, as most of the countries and

territories evaluated are considered by BMI to be 'emerging markets', our index is revised on a quarterly

basis. This ensures that the index draws on the latest information and data across our broad range of

sources, and the expertise of our analysts.

Sector-Specific Methodology

BMI's approach in assessing the Risk/Reward balance for oil and gas industry investors is three-fold:

■ First, we have disaggregated the upstream (oil and gas exploration and production) and downstream (oilrefining and marketing, gas processing and distribution), enabling us to take a more nuanced approach toanalysing the potential in each segment, and identifying the different risks along the value chain.

■ Second, we have identified objective indicators that may serve as proxies for issues and trends that werepreviously evaluated on a subjective basis.

■ Finally, we have used BMI's proprietary Country Risk Index in a more refined manner in order to ensurethat only those risks most relevant to the industry have been included.

Conceptually, the index is organised in a manner that enables us clearly to present the comparative strengths

and weaknesses of each state. The headline oil and gas index score is the principal score. However, the

differentiation of upstream and downstream and the articulation of the elements that comprise each segment

enable more sophisticated conclusions to be drawn, and also facilitate the use of the index by clients who

have varying levels of exposure and risk appetite.

Our sector-specific industry indices include:

■ Oil & Gas Risk/Reward Index: this is the overall index score, which comprises 50% upstream and 50%downstream;

■ Upstream Oil & Gas Risk/Reward Index: this is the overall upstream index score, which is composed ofrewards/risks (see below);

■ Downstream Oil & Gas Risk/Reward Index: this is the overall downstream index score, which comprisesrewards/risks (see below).

The following indicators have been used. Overall, the index uses three subjectively measured indicators and

41 separate indicators/datasets.



Table: Bmi's Oil & Gas Upstream Risk/Reward Index

Rationale

Upstream RRR: Rewards

Industry Rewards

Resource Base

- Proven oil reserves, mn bbl Indicators used to denote total market potential. High values givenbetter scores.

- Proven gas reserves, bcm

Growth Outlook

- Oil production growth, 2009-2014 Indicators used as proxies for BMI's market assumptions, with stronggrowth accorded higher scores.

- Gas production growth, 2009-2014

Market Maturity

- Oil reserves/production Indicator used to denote whether industries are frontier/emerging/developed or mature markets. Low existing exploitation in relation topotential is accorded a higher score.

- Gas reserves and production

- Current oil production versus peak

- Current gas production versus peak

Country Rewards

State ownership of assets, % Indicator used to denote opportunity for foreign NOCs/IOCs/independents. Low state ownership scores higher.

Number of non-state companies Indicator used to denote market competitiveness. Presence (and largenumber) of non-state companies scores higher.

Upstream RRR: Risks

Industry Risks

Licensing terms Subjective evaluation of government policy towards sector againstBMI-defined criteria. Protectionist states are marked down.

Privatisation trend Subjective evaluation of government industry orientation. Protectioniststates are marked down.

Country Risks

Physical infrastructure Score from BMI's Country Risk Index (CRI). It evaluates theconstraints imposed by power, transport and communicationsinfrastructure.

Long-term policy continuity risk From CRI. It evaluates the risk of a sharp change in the broad directionof government policy.

Rule of law From CRI. It evaluates government's ability to enforce its will withinthe state.

Corruption From CRI, to denote risk of additional legal costs and possibility ofopacity in tendering or business operations affecting companies'ability to compete.

NOC = national oil company; IOC = international oil company. Source: BMI



Weighting

Given the number of indicators/datasets used, it would be inappropriate to give all sub-components equal

weight. Consequently, the following weighting has been adopted:

Table: Weighting

Component Weighting, %

Upstream RRI 50, of which

Rewards 70 of Upstream RRI, of which

- Industry Rewards 75

- Country Rewards 25

Risks 30 of Upstream RRI, of which

- Industry Risks 65

- Country Risks 35

Downstream RRI 50 of Oil & Gas RRI, of which

Rewards 70 ,of which

- Industry Rewards 75

- Country Rewards 25

Risks 30, of which

- Industry Risks 60

- Country Risks 40

Source: BMI



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Colombia Oil & Gas Report Q3 2015

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