Field Appraisal: role, uncertainty, tools, cost benefit and practical aspect

Yales Vivadinar

2014

Field Appraisal – Objectives and Tools

Reduce uncertainty Cost effective information Other

• Interference test• Drill additional well

– Drill the well in the flank– Drill horizontal well

• Coring• Production test• Deepening

Appraisal Tools

• Interference test• Drill additional well

– Drill the well in the flank– Drill horizontal well

• Coring• Production test• Deepening

Typical E&P cash flow project is getting higher along with the progress of the project

Exploration cost is much lower compare to further cost but having the highest risk Cost will get higher along with the progress of the project Evaluation and appraisal are required prior to take further high investment commitment

Source of uncertainty

Field Appraisal

Appraisal is a major part of the exploration life cycle Appraisal activity is worthwhile if the outcome value is greater than the value without appraisal

information (($C & $D are greater than $A & $B )

Exploration Appraisal and Development

Commercialization

Appraise

Develop

Not develop

Exploration well

Not Appraise

Develop

Not develop

$ A

$ B

$ C

$ D

Supporting Evaluations to help the business decision making

Comprehensive evaluation should involve the subsurface data, surface assessment and commercial perspective.

Business decision making

NPV/EMV

Commercial Data

Technical Data & Evaluation

Basin and Reservoir Model

Raw subsurface Data

Supporting evaluation

Business decision

Seismic Data and Subsurface Modeling

Raw information of Seismic and well data are among the key initial information

Reservoir Model

Key Parameter: Gross Rock Volume Porosity Hydrocarbon saturation Recovery Factor Formation volume factor

Petroleum Resource Classification Scheme

Reserve Classification to weight the risk of the reserves along understanding of the geology and reservoir Reserve Classification will help the risk mitigation on the decision of next investment Reserves certificate will be based on the above classification and issued by independent party

modified from Ross, 2004 and SPE/WPC/AAPG, 2000

Factor Controlling Reserves

reserves estimates are affected by many factors, not necessarily technical, and not all transparent. The major factors are reservoir-specific, which relate to the geological/rock/fluid system and form the

basis for reservoir modeling. Development scheme, operations, and technology also play a role (Horizontal drilling and multilateral-

completion technology) have boosted reserves significantly in many fields

Ferruh Demirmen, 2007

6500 ft

Zone A

Zone C

Zone C

Zone D

Zone E

WH Platform

Liquid & gasinfield lines

FPSO

Dynamic risers

Calm buoyoff-loading

Possible future gas export line

Possible future flow lines

4500 ft

Gas re-injection

• Primary depletion• 5 production horizontal wells• 2 injection wells

Development Scenario

Offshore Transportation to East Java

Gas can be delivered to Gresik at 60-70 MMscfd.

100 km gas pipeline need to be installed that requires additional compression to give 100% back up as well as facility modifications.

requires an onshore receiving facility (ORF). The facility is expected to be minimal that comprise of slug catcher, metering, flare and office support.

The location of this facility is envisaged to be in the vicinity of industrial area.

The gas reserve could potentially support 7-10 years of gas sales.

Offshore Transportation to Madura The potential gas demand in Madura would

be from power generation segment of around 20 MMscfd to fuel +100 MW power plant capacity.

The capacity of gas handling would be 20 MMscfd for sales to Madura and the rest up to 50 MMscfd would still be re-injected.

The additional facility to be installed are: sales gas compressor with 100% back up, 35 km pipeline to Madura and onshore receiving facility in Madura Island, and probably around Ketapang village. With the size of the market, the gas reserve could support 15-20 years of gas sales.

Any disruption to the gas sales would require undelivered gas to be flared as the re-injection capacity is designed to only 50 MMscfd.

The disruption to the gas sale could be caused by buyer facilities, ORF shutdown, pipeline leak or rupture.

On-Site Gas Sales – Buyer Transports

The Buyer will build their facility adjacent to the gas facility.

There will be a sub-sea gas manifold provided by CPKL and the buyer would need to make connection to the manifold.

The gas will be on sales specification, i.e. dew pointed to avoid potential liquid drop out along the line.

The compression installed is up to the operating condition of the DPCU (around 600-800 psig) and there will be 100% back up.

The buyer has to take all gas produced (after fuel gas and utility usage) as there is no re-injection facility.

If the buyer fail to take the gas for any reason, the gas has to be flared otherwise oil production has to stop.

www.nuenergygas.com

NNE SSW

TOP COAL ZONE A

TOP COAL ZONE B

TOP COAL ZONE C

TOP BINIO FM.

TOP LAKAT FM.

TOP COAL ZONE D

TOP KELESA FM.

AGHA - 1W LIRIK-1RONO-2

C

A

B

CA B

Regional Seismic Overview

Three Layers Zones Have Been Identified

The preliminary study shows some sweet spots distribution in the western part of the PSC Total sweet spot area is between 537 Km2 (low case) and 1571 Km2 (High case)

The potential area is located at the Western area of the PSC Very limited data (seismic data and well controls) to support the evaluation of eastern area Two coring and exploration wells at both prospect (Northwest and Southwest) to confirm the model and

assumptions

Low

Cas

eH

igh

Case

Zone B Zone C

272 Km2 654 Km2 645 Km2

107 Km2 303 Km2 127 Km2

Zone A

• Proposed wells location

18

Resources Estimation and Potential Development Area

Zone Area (Km2) Thickness (m) Gas In Place

(TCF)

Min Mod Max Min Mod Max

Zone A 107 4.87 7.12 8.58 0.08 0.11 0.14

Zone B 304 5.66 7.72 7.74 0.26 0.35 0.35

Zone C 126 1.80 5.69 5.76 0.04 0.12 0.12

0.37 0.58 0.61

Total development area is circa 500 Km2

Required land to drill +100 well (50 pairs of SIS well) Well site is circa 100 wells x 2500 m2 = 0.25 Km2

Maximum distance to the gas transmission line is 15 Kms Pipeline RoW for 50 locations x (2 m x 15 Km) = 2.5 Km2

19

Drilling Program and Production Profile

No of wells 48

Potential Reserves 580.0 BCFMaximum Daily Rate 1.94 MMSCFD/wellMax Total Daily Production 2.32 MMSCFDMax Total Daily Production 49.36 MMSCFDTotal Acumulative Production 216.2 BCFRecovery factor 37%

20

Key Parameter and assumption

Development period 2018-2028Production period 2018-2039PSC Split GoI 21.875% Contratctor 78.125% FTP 10%

Tax 44% Annual Cost recovery cap 90% Depreciation rate 25% Depreciation period 10 yearInflation rate 2.5%p.a.Investment credit 0%p.a.Drilling cost ($000) $4,500 Facilities & pipeline cost ($000) $2,150 Total ($000) $6,650

Exploration Sunk Cost ($000) $17,320 Development Cost ($000) $319,200 Total Investment ($000) $336,520 Gas price 7.5 $/MSCFVariable cost ($/MSCF) 0.5 Fixed cost ($000/well-year) 150

Time Value of Money

Net Present Value

Year 1 Year 2 Year 3 Year 4 Year 5 Year 6 Year 7 Year 8 Year 9 Year 10 S(100,000) 10,000 10,000 10,000 10,000 10,000 10,000 10,000 10,000 10,000 10,000 100,000

5.0% 501 1,026 1,578 2,157 2,766 3,405 4,076 4,780 5,520 6,297 32,106 (100,000) 10,501 11,026 11,578 12,157 12,766 13,405 14,076 14,780 15,520 16,297 132,106

NPV(0%) 32,106 NPV(5%) 0

23

Project Cash Flow

24

Revenue Split and NGY’s Net Cash flow

Cap on Cost Recovery

Investment Credit IRR (@NPV=0)

90% 011.92%

90% 3% 12.92%100% 0 12.13%100% 3% 13.18%

Sensitivity Analysis

Given current cost and schedule premises, Buyer break-even NPV13 ($0MM) could be achieved by (Either OR): 1. reducing ~40% of total Capex (drilling and facilities ) from $959MM to $550MM (gross); OR 2. selling gas at $20.7/mmbtu (flat) or at $19.2/mmbtu (esc. 2.5% per annum starts in 2019 forward): OR 3. having contractor 65% after-tax gas split.