Sumatra Deep Gas & Meeting Indonesia’s Growing Gas Demand Jerry Sykora April 3-5, 2019, Singapore
Sumatra Deep Gas&
Meeting Indonesia’s Growing Gas Demand
Jerry Sykora
April 3-5, 2019, Singapore
• Southeast Asia’s largest energy producer and consumer• Per capita energy use in Indonesia is only 0.9 toe versus
1.8 toe in Thailand & 3.1 toe in Malaysia. Canada 7.6 toe• Indonesian energy demand increasing at 9% / annum• Indonesian per capita use forecast to double by 2030• Coal is forecast to drive energy growth
Indonesia’s Energy FutureIndonesian Energy Supply
gas consumptionprojected to quadruple
by 2050
Indonesia’s Energy FutureIndonesian Energy Supply
• Gas reserves are depleting– natural gas reserves decreased by 5.04% - 2017 vs 2016– Remaining reserves of 144 Tcf (MEMR 2016)
Indonesia Gas Resources
Includes 50 Tcf from East Natuna (Natuna D Alpha)Masila 16 Tcf
IDD 2 TcfSakakemang discovery 2+ Tcf
• Gas reserves are depleting– natural gas reserves decreased by 5.04% - 2017 vs 2016– Remaining reserves of 144 Tcf (MEMR 2016)
Indonesia Gas Resources
Natural Gas World 2018
• Indonesia turning to LNG make up gas shortfall
– Export of Eastern Indonesian LNG progressively being shifted to Western Indonesia
• LNG exports projected to cease in 2035
– Importing of foreign LNG to commence within the next few years
Indonesia Gas Resources
First foreign LNG
Indonesian Gas Supply/Demand
Gas consumption risingby 6.3%/annum *
* Assuming affordable available gas supply
Gas exports cease in 2035
(National Energy Policy)
Indonesia net gas importer 2024 -2028
Dependent on demand growth & increase indomestic supply – Masela, Kutei and Natuna
?
– Import of foreign LNG to commence in the early to mid 2020’s
– Becoming a net importer of gas later in the decade
Net Importer
2030
Cumulative Cost of Foreign LNG imports
Cumulative Cost of LNG imports to
Indonesian National Treasury
USD billion
BCF LNG IMPORTS
• LNG Pricing 2020 onwards forecast at USD 9.1.MMBTU esc.(Japan World Bank)
• Indonesia LNG imports will grow at ~ 300 MMcf/d / annum
• Treasury drain of USD 1 billion/ annum & growing at USD 1 billion every year
• By 2050 cumulative cost of foreign LNG imports est.
~USD 450 billion
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Domestic
Cost of LNG Imports vs Domestic Supply
• Direct cost to GOI treasury of USD 450 billion– Represents ~ 50 Tcf gas over 25 years
• Additional lost capital from not using available domestic gas resource– Gross domestic revenue from equivalent production (@ USD7/MMBTU) USD 400+ billion
– GOI portion of revenue from this business est. at USD 200 billion
– Oil companies will spend portion of USD 100+ billion profit furthering Indonesia business
• Lost construction and development– More than USD 100 billion in domestic Capex & Opex
• Lost employment– Thousands, possibly 10’s of 1000s highly paid skilled jobs not being created to support this
business
• Intangible benefits lost– Increase in national standard of living
• Sumatra to benefit most, but effect to be felt nation-wide
– Health benefits from displacing coal powered energy
– Accelerator effect of stimulating other industries and attracting more foreign investment
Tangible Monetary Benefit to GOI by Developing Deep Domestic Gas Business
USD ~ 750 billion
Is There a Material Domestic Gas Source?
First ‘Shale’ Gas
~ 2 bcf/d
Indonesia’s Energy FutureIndonesian Energy Supply
First ‘Shale’ Gas
~ 2 bcf/dIs the GOI Underestimating Unconventional Potential?
Indonesia’s Energy FutureIndonesian Energy Supply
First ‘Shale’ Gas
~ 2 bcf/d
YESSumatran Deep Basin gas can offset foreign LNG Imports for decades
Indonesia’s Energy FutureIndonesian Energy Supply
Is the GOI Underestimating Unconventional Potential?
Quantifying Sumatran Deep Basin Resource Potential
Williams and Eurbank, 1995
Central Sumatra Rift
Quantifying Sumatran Deep Basin Resource Potential
Williams and Eurbank, 1995
Central Sumatra Rift
Quantifying Sumatran Deep Basin Resource Potential
Central Sumatra Rift
Quantifying Sumatran Deep Basin Resource Potential
Central Sumatra Rift
Lacustrine Source Rx
Quantifying Sumatran Deep Basin Resource Potential
Pematang Paleosol
Central Sumatra Rift
Lacustrine Source Rx
Quantifying Sumatran Deep Basin Resource Potential
Pematang Paleosol
Central Sumatra Rift
Lacustrine Source Rx
A significant fraction (~ 30%) of generated oil migrates out of the source kitchens
Quantifying Sumatran Deep Basin Resource Potential
Pematang Paleosol
Central Sumatra Rift
Lacustrine Source Rx
~ 70% hydrocarbons generated remain trapped below the Paleolsol
Pematang Paleosol
Central Sumatra Rift
Lacustrine Source Rx
~ 70% hydrocarbons generated remain trapped below the Paleolsol> 100 billion BOE remains in-situ in Central Sumatra Basins
Pematang Paleosol
Central Sumatra Rift
Lacustrine Source Rx
Quantifying Sumatran Deep Basin Resource Potential
Primary Production Targets Syn-Rift Tight SandstonesSupercharged & Overpressured
Pematang Paleosol
Central Sumatra Rift
Lacustrine Source Rx
Primary Production Targetsaka
‘No Dry Hole Zone’
Quantifying Sumatran Deep Basin Resource Potential
* RESERVOIR IS IN THERMALLY MATURE WINDOWwith permeability < 0.1 mD or requires fracking for commercial production
INDONESIAN UNCONVENTIONAL CONTRACTS INCLUDES DEEP TIGHT* GAS SANDS
Quantifying Sumatran Deep Basin Resource Potential
Indonesia Unconventional Jonah Field (Cluff & Cluff 2004)
Gross section (m) 400 to 1000 m 760 m (av.)
N/G pay ~ 40% 25% (av.)
Pay porosity 5 to 12% 6 to 15% (7.4av.)
Pay permeability .001 to >1 mD .0005-0.01 mD
Gas saturation .4 to .6 .40 - .70 (.55 av.)
EUR/well (bcf) 10 est. 4 (2004) 7 recent. Up to 16
Pressure gradient .65 psi/ft. 0.7 psi/ft.
CGR 30 (tested) 10
Depositional Environment Lacustrine (intb'd qtz ss & sh) Lacustrine (intb'd qtz ss & sh)
• Deep Basin hydrocarbon resources in Sumatra remains unexploited• geologically de-risked in at least two Sumatran Basins
• Close geological analogy exists in the Jonah Field in Wyoming, USA• 10.5 Tcf GIP – over 2 Tcf recovered to date since 1993• Ground zero for ‘fracking’ of tight reservoirs previously considered uneconomic• ‘Compartmentalization’ model of overpressured reservoir* meant no dry holes• Current per well reserves 6.5 Bcf
USGS Open-File Report 2009-1290
BTE EUR 4 TCF(60 km² footprint)
Footprint comparison of Jonah Field/Green River Basin to Sumatra Source Kitchens
Quantifying Sumatran Deep Basin Resource Potential
• Estimated 40,000 km² of lacustrine source rock bearing back-arc basins in Sumatra.
• Est. 10% has optimized facies & thermal window (regional modelling by Bukit Energy)
• ~ 4000 km² of potentially commercial Sumatra deep basin• With Jonah-like reserve density ~ 300 Tcfe gas rec.
• CERA 2012 est. of 51 Tcf (risked)• ESDM 2015 est. of 574 Tcf (unrisked)• SKK Migas 2016 est. of 93 Tcf (risked?)
• Comparable to remaining national gas reserves of 144 Tcf
Consensus is a significant gas resourcedoes exist in the deep basins of Sumatra
Quantifying Sumatran Deep Basin Resource Potential
Monetization of Sumatra’s Deep Gas Potential
CHALLENGES
• Derisking - Proof of Concept– Belowground has been derisked in at least two Central Sumatran Basins
• Technology– Horizontal drilling and fracking capability exists and currently deployed in Indonesia
– Scale and knowledge required for this business in Sumatra resides within most IOCs
– Scaling up of these operations can be expedited by IOCs
• Scale of Investment– Too large for anybody except IOCs with long-term outlook for Indonesia
– Reward commensurate with risk & investment
– Potential for legacy asset development and 30 year production profile
• Aboveground Issues and Land Access Siloing amongst various government ministries
– GOI can force alignment and enable access for national security reasons
– Current technology minimizes aboveground footprint
• Commercial Environment & GOI Policies– GOI has created globally competitive unconventional (MNK) contracts to enable growth
– Recently introduced ‘Gross Split’ contracts will allow for long-term operational efficiencies through direct award of service contracts while preserving commercial returns for contractors
Multi-well Drilling Pad – Resource Play Hubs
Encana
Reduce natural gas production costs and environmental impacts.• Use in continental United States• A Play Hub of this size would target a recoverable resource of >500 bcf gas in Sumatra Deep Basins
200 MMcf/d capacity
Commercial750 Bcf Development
0
200
400
600
800
1000$8
Revenue $MM
Annual Production Bcfe
Cumulative Gas (equiv) Production (Bcfe)
-1000
-500
0
500
1000
1500
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2500
3000$8
NCF Cum NCF
-1000
-500
0
500
1000
1500
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3500
4000
4500
2019
2020
2021
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2028
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$8
Capital Cum Capital Cum NCF Cum Gov't Take
Gas
$/mmBTU
Brent
USD
IP/6 well
pad
MMcf/d
Pad Cost
USD MM NPV0 NPV5 NPV10 IRR PVPI Rev Costs Proj CF Cont Gov't
8 65 60 60 2391 1213 630 29% 1.63 9190 2957 6233 2391 3842
Assumptions114 wells; IP of 10 MMcf/d with typical unconventional declines; 200 MMcf/d plateau; 25 year production life; $8 gas, CGR 30; AT split contractor 45%: GOI 55%; av. well cost $10 MM; Opex $1/mcf & $10/bbl
Life of Project Contractor Net Cashflow of ~ $2.4 billion
What’s Next?
Partnership between the GOI and a Major IOC
• GOI must continue to create a fiscally welcoming environment to encourage and further incentivize the material investment required to make this business a reality
• A major IOC needs to step-up and demonstrate the long-term commercial viability of this business in Sumatra