sumatra deep gas sykora - su… · lng imports to indonesian national treasury usd billion bcf lng...

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


• 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)


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


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



~ 2 bcf/dIs the GOI Underestimating Unconventional Potential?



~ 2 bcf/d

YESSumatran Deep Basin gas can offset foreign LNG Imports for decades


Is the GOI Underestimating Unconventional Potential?

Quantifying Sumatran Deep Basin Resource Potential

Williams and Eurbank, 1995

Central Sumatra Rift



Lacustrine Source Rx


Pematang Paleosol




Pematang Paleosol



A significant fraction (~ 30%) of generated oil migrates out of the source kitchens


Pematang Paleosol



~ 70% hydrocarbons generated remain trapped below the Paleolsol

Pematang Paleosol



~ 70% hydrocarbons generated remain trapped below the Paleolsol> 100 billion BOE remains in-situ in Central Sumatra Basins

Pematang Paleosol




Primary Production Targets Syn-Rift Tight SandstonesSupercharged & Overpressured

Pematang Paleosol



Primary Production Targetsaka

‘No Dry Hole Zone’


* RESERVOIR IS IN THERMALLY MATURE WINDOWwith permeability < 0.1 mD or requires fracking for commercial production

INDONESIAN UNCONVENTIONAL CONTRACTS INCLUDES DEEP TIGHT* GAS SANDS


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


• 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


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

2000

2500

3000$8

NCF Cum NCF

-1000

-500

0

500

1000

1500

2000

2500

3000

3500

4000

4500

2019

2020

2021

2022

2023

2024

2025

2026

2027

2028

2029

2030

2031

2032

2033

2034

2035

2036

2037

2038

2039

2040

2041

2042

2043

2044

2045

$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

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