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
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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
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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
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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
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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.
Colombia Oil & Gas Report Q3 2015
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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
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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
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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
f = BMI forecast. Source: EIA, BMI
Colombia Oil & Gas Report Q3 2015
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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.
Colombia Oil & Gas Report Q3 2015
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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
f = BMI forecast. Source: EIA, BMI
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.
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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 Oil & Gas Report Q3 2015
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Colombia - Key Upstream Projects - Continued
Name Field Name Companies Status Select
Est.Peak Oil/Liquids Range(b/d)
Est.PeakGasOutput(bcm)
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
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Colombia - Key Upstream Projects - Continued
Name Field Name Companies Status Select
Est.Peak Oil/Liquids Range(b/d)
Est.PeakGasOutput(bcm)
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
Colombia Oil & Gas Report Q3 2015
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Colombia - Key Upstream Projects - Continued
Name Field Name Companies Status Select
Est.Peak Oil/Liquids Range(b/d)
Est.PeakGasOutput(bcm)
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
Colombia Oil & Gas Report Q3 2015
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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
Crude, NGPL & other liquids prod, USDbn at USD100/bbl 37.3 36.9 36.2 35.5 34.6 33.8
Crude, NGPL & other liquids prod, USDbn at USD150/bbl 56.0 55.3 54.2 53.2 51.9 50.7
f = BMI forecast. Source: EIA, BMI
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
Crude, NGPL & other liquids prod, USDbn at USD50/bbl 16.6 16.4 16.3 16.2 16.2 16.2
Crude, NGPL & other liquids prod, USDbn at USD100/bbl 33.2 32.9 32.6 32.4 32.3 32.5
Crude, NGPL & other liquids prod, USDbn at USD150/bbl 49.7 49.3 48.9 48.7 48.5 48.7
f = BMI forecast. Source: EIA, BMI
Colombia Oil & Gas Report Q3 2015
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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.
Colombia Oil & Gas Report Q3 2015
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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
f = BMI forecast. Source: EIA, BMI
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.
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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.
Colombia Oil & Gas Report Q3 2015
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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
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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
Colombia Oil & Gas Report Q3 2015
© Business Monitor International Ltd Page 23
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
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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.
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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, USDbn at USD12/mn btu 4.4 4.4 4.4 4.3 4.3 4.2
Dry natural gas production, USDbn at USD18/mn btu 6.6 6.6 6.6 6.5 6.4 6.3
Dry natural gas production, % of domestic consumption 134.0 124.7 116.5 109.3 102.5 97.6
e/f = BMI estimate/forecast. Source: EIA, BMI
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, USDbn at USD6/mn btu 2.1 2.1 2.1 2.2 2.2 2.2
Dry natural gas production, USDbn at USD12/mn btu 4.2 4.2 4.3 4.3 4.4 4.5
Dry natural gas production, USDbn at USD18/mn btu 6.3 6.4 6.4 6.5 6.6 6.7
Dry natural gas production, % of domestic consumption 93.8 90.7 88.9 87.2 85.9 84.7
f = BMI forecast. Source: EIA, BMI
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
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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
e/f = BMI estimate/forecast. Source: EIA, BMI
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.
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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).
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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
e/f = BMI estimate/forecast. Source: EIA, BMI
Colombia Oil & Gas Report Q3 2015
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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
f = BMI forecast. Source: EIA, BMI
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.
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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
e/f = BMI estimate/forecast. Source: EIA, BMI
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.
Colombia Oil & Gas Report Q3 2015
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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
e/f = BMI estimate/forecast. Source: EIA, BMI
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
f = BMI forecast. Source: EIA, BMI
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.
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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
e/f = BMI estimate/forecast. Source: EIA, BMI
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
Colombia Oil & Gas Report Q3 2015
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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
e/f = BMI estimate/forecast. Source: EIA, BMI
Colombia Oil & Gas Report Q3 2015
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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
f = BMI forecast. Source: EIA, BMI
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.
Colombia Oil & Gas Report Q3 2015
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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
e/f = BMI estimate/forecast. Source: EIA, BMI
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.
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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
Crude & other liquids net export, USDbn at USD100/bbl 24.6 24.2 22.4 21.3 19.5 18.4
Crude & other liquids net export, USDbn at USD150/bbl 36.9 36.3 33.6 31.9 29.3 27.5
e/f = BMI estimate/forecast. Source: EIA, BMI
Colombia Oil & Gas Report Q3 2015
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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 & other liquids net export, USDbn at USD50/bbl 8.7 8.3 8.0 7.7 7.4 7.3
Crude & other liquids net export, USDbn at USD100/bbl 17.4 16.7 16.0 15.4 14.9 14.6
Crude & other liquids net export, USDbn at USD150/bbl 26.0 25.0 24.0 23.1 22.3 21.9
f = BMI forecast. Source: EIA, BMI
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.
Colombia Oil & Gas Report Q3 2015
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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
e/f = BMI estimate/forecast. Source: EIA, BMI
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.
Colombia Oil & Gas Report Q3 2015
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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
Refined products net exports, USDbn at USD100/bbl 0.3 0.3 1.0 1.1 1.9 1.9
Refined products net exports, USDbn at USD150/bbl 0.5 0.5 1.5 1.7 2.8 2.8
e/f = BMI estimate/forecast. Source: EIA, BMI
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 products net exports, USDbn at USD50/bbl 1.0 1.0 1.0 1.0 1.1 1.2
Refined products net exports, USDbn at USD100/bbl 2.0 2.0 2.0 2.1 2.2 2.3
Refined products net exports, USDbn at USD150/bbl 2.9 2.9 3.1 3.1 3.3 3.5
f = BMI forecast. Source: EIA, BMI
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.
Colombia Oil & Gas Report Q3 2015
© Business Monitor International Ltd Page 40
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
e/f = BMI estimate/forecast. Source: EIA, BMI
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.
Colombia Oil & Gas Report Q3 2015
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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
Total net oil exports (crude & prod.), USDbn at USD100/bbl 25.0 24.5 23.4 22.4 21.4 20.2
Total net oil exports (crude & prod.), USDbn at USD150/bbl 37.5 36.7 35.1 33.6 32.1 30.3
e/f = BMI estimate/forecast. Source: EIA, BMI
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
Total net oil exports (crude & prod.), USDbn at USD50/bbl 9.7 9.3 9.0 8.8 8.5 8.5
Total net oil exports (crude & prod.), USDbn at USD100/bbl 19.3 18.6 18.0 17.5 17.1 16.9
Total net oil exports (crude & prod.), USDbn at USD150/bbl 29.0 28.0 27.0 26.3 25.6 25.4
f = BMI forecast. Source: EIA, BMI
Colombia Oil & Gas Report Q3 2015
© Business Monitor International Ltd Page 42
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
e/f = BMI estimate/forecast. Source: EIA, BMI
Colombia Oil & Gas Report Q3 2015
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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
f = BMI forecast. Source: EIA, BMI
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.
Colombia Oil & Gas Report Q3 2015
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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
e/f = BMI estimate/forecast. Source: EIA, BMI
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
Colombia Oil & Gas Report Q3 2015
© Business Monitor International Ltd Page 45
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).
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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
e/f = BMI estimate/forecast. Source: EIA, BMI
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
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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.
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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.
Colombia Oil & Gas Report Q3 2015
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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
Colombia Oil & Gas Report Q3 2015
© Business Monitor International Ltd Page 50
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
Note: Data is accurate at time of writing and is subject to updates. Source: BMI
Colombia Oil & Gas Report Q3 2015
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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.
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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.
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© Business Monitor International Ltd Page 53
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
e/f = BMI estimate/forecast. Source: EIA, BMI
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.
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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
f = BMI forecast. Source: EIA, BMI
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
Colombia Oil & Gas Report Q3 2015
© Business Monitor International Ltd Page 55
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
Note: Data is accurate at time of writing and is subject to updates. Source: BMI
Colombia Oil & Gas Report Q3 2015
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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
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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.
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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.
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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.
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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.
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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.
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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.
Open Round Colombia 2012
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
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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.
Open Round Colombia 2010
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
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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
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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
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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,
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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
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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.
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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
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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).
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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.
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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.
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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.
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■ 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
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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.
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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
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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
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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
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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
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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)
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■ 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)
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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.
■ Large areas of unexplored territory.
Threats ■ Extensive state involvement.
■ Changes in national energy policy.
■ 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.
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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.
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.
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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
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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.
■ Large areas of unexplored territory.
Threats ■ Resurgence of guerrilla disruptions to supply and exports.
■ Declining near-term volumes and revenues.
■ Changes in national energy policy.
■ 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
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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.
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.
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.
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
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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)
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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
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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.
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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.
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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.
Opportunities ■ Renewed IOC interest in Colombia.
■ Considerable untapped oil/gas potential.
■ Large areas of unexplored territory.
Threats ■ Guerrilla disruptions to supply and exports.
■ Declining near-term volumes and revenues.
■ Changes in national energy policy.
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.
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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.
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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)
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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.
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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
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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
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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)
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ExxonMobil Colombia
SWOT Analysis
Strengths ■ Strong fuels supply presence.
• Growing exploration portfolio.
Weaknesses ■ No oil or gas production.
■ Lack of refining involvement.
Opportunities ■ Renewed IOC interest in Colombia.
■ Growth in domestic oil demand.
■ Large areas of unexplored territory.
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
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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.
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.
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.
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.
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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
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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
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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
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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.
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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,
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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
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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
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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
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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
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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
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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
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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.
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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.
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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
e/f = BMI estimate/forecast. Source: EIA, BMI
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.
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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
e/f = BMI estimate/forecast. Source: EIA, BMI
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
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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
e/f = BMI estimate/forecast. Source: EIA, BMI
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.
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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.
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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.
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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
e/f = BMI estimate/forecast. Source: EIA, BMI
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
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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.
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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
e/f = BMI estimate/forecast. Source: EIA, BMI
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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
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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.
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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
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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
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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.
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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
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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.
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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.
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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 380, Rotterdam, USD/bbl 91.24 79.84 40.16 42.50 44.50 42.50
Bunker fuel 380, New York, USD/bbl 93.13 83.55 44.16 45.00 46.75 44.50
Bunker fuel 380, Singapore, USD/bbl 95.84 83.27 44.94 45.50 47.50 45.00
Bunker fuel 380, Singapore, USD/bbl 95.84 83.27 44.94 45.50 47.50 45.00
Bunker fuel 380, global average, USD/bbl 93.40 82.22 43.09 44.33 46.25 44.00
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
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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
Bunker fuel 180, Rotterdam, USD/bbl 45.35 45.35 45.35 45.35 45.35 45.35
Bunker fuel 180, New York, USD/bbl 50.35 50.35 50.35 50.35 50.35 50.35
Bunker fuel 180, Singapore, USD/bbl 47.60 47.60 47.60 47.60 47.60 47.60
Bunker fuel 180, global average, USD/bbl 47.77 47.77 47.77 47.77 47.77 47.77
Bunker fuel 380, Rotterdam, USD/bbl 43.00 43.00 43.00 43.00 43.00 43.00
Bunker fuel 380, New York, USD/bbl 45.00 45.00 45.00 45.00 45.00 45.00
Bunker fuel 380, Singapore, USD/bbl 45.50 45.50 45.50 45.50 45.50 45.50
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Energy Price Forecasts, 2019-2024 ( Global 2019-2024) - Continued
2019f 2020f 2021f 2022f 2023f 2024f
Bunker fuel 380, Singapore, USD/bbl 45.50 45.50 45.50 45.50 45.50 45.50
Bunker fuel 380, global average, USD/bbl 44.50 44.50 44.50 44.50 44.50 44.50
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
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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
f = forecast. Source: EIA, BMI
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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
Trinidad and Tobago 119 120 121 122 124 126 129 130
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
f = forecast. Source: EIA, BMI
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
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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
f = forecast. Source: EIA, BMI
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
Trinidad and Tobago 168 168 168 168 168 168 168 168
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
f = forecast. Source: EIA, BMI
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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
f = forecast. Source: EIA, BMI
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
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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
f = forecast. Source: EIA, BMI
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
f = forecast. Source: EIA, BMI
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
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Gas Production - Historical Data & Forecasts, 2012-2019 (bcm) - Continued
2012 2013 2014 2015 2016 2017 2018 2019
Trinidad and Tobago 39.79 42.30 42.72 43.36 43.71 44.14 44.58 45.48
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
f = forecast. Source: EIA, BMI
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
Trinidad and Tobago 43.71 44.14 44.58 45.48 46.39 46.85 47.32 47.79 48.27
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
f = forecast. Source: EIA, BMI
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
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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
Trinidad and Tobago 16.25 18.05 17.75 17.64 17.22 16.86 16.48 16.81
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
f = forecast. Source: EIA, BMI
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
Trinidad and Tobago 17.22 16.86 16.48 16.81 17.15 17.32 17.49 17.67 17.85
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)
f = forecast. Source: EIA, BMI
Colombia Oil & Gas Report Q3 2015
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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
Total net hydrocarbons exports at USD100/bbl, USDbn 26.3 25.5 24.1 22.8 21.5 20.1
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
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Total Hydrocarbons Production, Consumption and Net Exports (Colombia 2019-2024) - Continued
2019f 2020f 2021f 2022f 2023f 2024f
Total net hydrocarbons exports at USD50/bbl, USDbn 9.5 9.1 8.7 8.4 8.1 8.0
Total net hydrocarbons exports at USD100/bbl, USDbn 19.0 18.1 17.4 16.8 16.2 16.0
f = BMI forecast. Source: EIA, BMI
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
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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
e/f = BMI estimate/forecast. Source: EIA, BMI
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
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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
f = BMI forecast. Source: EIA, BMI
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
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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
e/f = BMI estimate/forecast. Source: EIA, BMI
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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, 000b/d 22.7 22.7 22.7 22.7 22.7 22.7
LPG consumption, % y-o-y 0.0 0.0 0.0 0.0 0.0 0.0
LPG consumption, % of domestic consumption 6.3 6.2 6.0 5.9 5.8 5.7
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
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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
f = BMI forecast. Source: EIA, BMI
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
e/f = BMI estimate/forecast. Source: EIA, BMI
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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
f = BMI forecast. Source: EIA, BMI
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Table: LPG Production, Consumption and Net Exports (Colombia 2013-2018)
2013e 2014e 2015f 2016f 2017f 2018f
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 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 consumption, 000b/d 22.7 22.7 22.7 22.7 22.7 22.7
LPG consumption, % y-o-y 0.0 0.0 0.0 0.0 0.0 0.0
LPG consumption, % of domestic consumption 6.3 6.2 6.0 5.9 5.8 5.7
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
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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
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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
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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.
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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.
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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).
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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.
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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
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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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