independent review and audit of prospective resources ...vesta italy c.r149.np 100% exploration...

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Reference:

PRJ11086541

Reporting date:

November 2018

Report status:

Final

Independent Review and Audit of Prospective

Resources - Vesta Prospect, Offshore Italy

A Competent Person’s Report for:

Cabot Energy plc.

PRJ11086541 / November 2018

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Lloyd’s Register has made every effort to ensure that the interpretations, conclusions and recommendations presented

herein are accurate and reliable in accordance with good industry practice and its own quality management

procedures. Lloyd’s Register does not, however, guarantee the correctness of any such interpretations and shall not

be liable or responsible for any loss, costs, damages or expenses incurred or sustained by anyone resulting from any

interpretation or recommendation made by any of its officers, agents or employees. This report has not been prepared

to be compliant with the regulations of any specific financial exchange.

Author(s)

Jon Wix

Technical Audit

Joanne Cranswick

Quality Audit

Jennifer Ives

Release to Client

David Tobias

Date Released 16th November 2018 (final report)


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The Directors

Cabot Energy Plc

93-95 Gloucester Place

London, W1U 6JQ.

16th November 2018

Dear Sirs,

In accordance with the instructions of the Directors of Cabot Energy Plc, Lloyd’s Register (LR or Senergy (GB) Limited) has

undertaken an independent review and audit of Prospective Resources of the Vesta prospect, offshore Italy.

Recoverable volumes are expressed as gross resources and are the total estimated petroleum to be produced. The portion of the

gross resources attributable to the 100% Working Interest currently owned by Cabot’s associate companies is not the same as net

entitlement as the latter will be net of any applicable contract and fiscal terms attributing a portion of the recoverable volumes to

the government as per the contractual terms of the licence at the time of any eventual hydrocarbon production and can only be

estimated by economic analysis which has not been carried out for this report.

The content of this report and LR’s estimates of resources are based on data provided by Cabot and its associate companies in

September and October 2018. LR confirms that to its knowledge there has been no material change of circumstances or available

information since the report was compiled.

This report covers the estimation of Low (1U), Best (2U) and High (3U) Prospective Resources corresponding to stochastic P90, P50

and P10 volume estimates respectively. In auditing the estimation and allocation of resources to these categories, we have assessed

their consistency with the 2018 Petroleum Resources Management System (PRMS) prepared by the Oil and Gas Reserves Committee

of the Society of Petroleum Engineers (SPE) and reviewed and jointly sponsored by the World Petroleum Council (WPC), the

American Association of Petroleum Geologists (AAPG), the Society of Petroleum Evaluation Engineers (SPEE), the Society of

Exploration Geophysicists (SEG), the Society of Petrophysicists and Well Log Analysts (SPWLA) and the European Association of

Geoscientists and Engineers (EAGE) (Reference 3). The report has not been prepared to be compliant with the regulations of any

specific financial exchange.

In conducting this review, LR has used information and interpretations supplied directly or indirectly by Cabot, its associate

companies and independent third parties, comprising basic geological, geophysical, petrophysical and engineering data, digital

models and technical reports. LR has carried out independent analyses of these data as appropriate to audit the work conducted

by Cabot and its associate companies to derive the gross Prospective Resources attributable to the prospects. Site visits were not

considered necessary for the purposes of this report. LR has not verified the legal entitlement of Cabot and its associate companies

to the interests covered in this report since this is outside the remit of this technical evaluation.

Standard geological and engineering techniques accepted by the petroleum industry were used in reviewing the estimates of

recoverable hydrocarbons. These techniques rely on engineering and geo-scientific interpretation and judgement; hence the

resources included in this evaluation are estimates only and should not be construed to be exact quantities. It should be recognised

that such estimates of hydrocarbon resources may increase or decrease in future if there are changes to the technical interpretation,

economic criteria or regulatory requirements.

Yours faithfully,

David Tobias

Head of Reserves and Asset Evaluations

For and on behalf of Lloyd’s Register


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Executive Summary

This report comprises an evaluation of the Vesta prospect, offshore Italy.

Table ES.1 gives a summary of the licence for the Vesta prospect:

* Working Interest is defined here as the interest held in the licence that gives the owner of the interest the right to drill and produce oil and gas

on the leased acreage. It requires the owner to pay the Working Interest percentage of the costs of operations. The share of production to which

a working interest owner is entitled will always be smaller than the share of costs that the working interest owner is required to bear.

Table ES 1: Cabot Licence Interests

The primary data provided by Cabot includes subsurface data, reports, technical notes and meeting presentations.

The effective date is 29th October 2018 incorporating data provided by Cabot during September and October 2018.

LR have reviewed and evaluated the available technical data and reports for the Vesta prospect, as requested by

Cabot. Independent volumetric stochastic calculations and risk evaluations were carried-out by LR for the prospect.

The Prospective Resources for oil are reported in Table ES 2. The Prospective Resources assume that licence extensions

will be granted. Gross volumes apply to the total accumulation which may extend onto adjacent licences in which

Cabot does not hold equity. Net volumes are those wholly contained within the licenses held by Cabot, in all of which

the company has 100% working interest.

Oil Prospective Resources (MMstb) Unrisked

Prospect Low (1U) – P90 Best (2U) – P50 High (3U) – P10 Chance of

Discovery %

Gross* Net* Gross* Net* Gross* Net*

Vesta 31 31 187 187 642 642 13

* Gross volumes apply to the total accumulation which may extend onto adjacent licences in which Cabot does not hold equity. Net volumes are

those wholly contained within the licenses held by Cabot, in all of which the company has 100% working interest. Assuming Geological Discovery,

with its estimated chance of success, the Low Estimate then implies at least a 90% probability (P90) that the quantities actually recovered will equal

or exceed the low estimate. The Best Estimate then implies at least a 50% probability (P50) that the quantities actually recovered will equal or

exceed the best estimate. The High Estimate then implies at least a 10% probability (P10) that the quantities actually recovered will equal or exceed

the high estimate.

Chance of Geologic Discovery is defined and discussed in Section 2.2.1 and pertains to the chance of finding a sufficient quantity of petroleum to

justify estimating the in-place volume demonstrated by a well(s) and for evaluating the potential for technical recovery and does not relate

specifically to the discovery of Low, Best or High volumes quoted.

Table ES 2: Oil Prospective Resources at October 2018 (MMstb)

Prospect Country Licence Cabot Working

Interest* Status

Vesta Italy C.R146.NP 100%

Exploration License

Suspended pending

Government approvals

Vesta Italy C.R149.NP 100% Exploration License


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LR estimate the unrisked Gross (which is the same as the Net) Mean Prospective Resources to be 280 MMstb oil.

PRMS 2018 guidelines have been used in the Resources evaluation in this project. LR acknowledges that this is a new

amendment to the PRMS guidelines. LR has used its best endeavours to assess the new guidelines and apply them

to this project, but cannot be responsible for alternative interpretations of the guidelines.

Prospective Resources are quantities of petroleum which are estimated, as of a given date, to be potentially

recoverable from undiscovered accumulations. There is no certainty that any hydrocarbons will be discovered when

exploration well(s) is/are being drilled. Furthermore, should any hydrocarbons be discovered there is no assurance

that it is commercially viable to produce any portion of these resources.


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Contents

1. Introduction 1

1.1 Sources of Information 1

1.2 Requirements 1

1.3 Standards Applied 1

1.4 Site Visit 2

1.5 Liability 2

1.6 Consent 2

2. Vesta Prospect, Licences C.R146.NP & C.R149.NP 3

2.1 Introduction 3

2.2 Subsurface Evaluation 3

2.2.1 Prospect Risk 4

2.2.2 Prospect Volumes 6

3. References 10

Appendix 1 – Lloyd’s Register and Author Credentials 11

Appendix 2 - Resource and Risk Evaluation Method 12

Nomenclature 21

Figures 24


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List of Tables

Table ES 1: Cabot Licence Interests ...................................................................................................................... iii Table ES 2: Oil Prospective Resources at October 2018 (MMstb) ...................................................................... iii

Table 2.1: Vesta Prospect, Chance of Geologic Discovery Assessment ............................................................. 6 Table 2.2: Vesta Prospect Volumetric Input Parameters ..................................................................................... 7 Table 2.3: Vesta Prospect, Unrisked STOIIP .......................................................................................................... 8 Table 2.4: Vesta Prospect, Unrisked Prospective Resources ............................................................................... 8

List of Figures

Figure 2.1 Location of Licenses C.R146.NP & C.R149.NP

Figure 2.2 Vega Field Seismic & Structure

Figure 2.3 Vesta Play Concept

Figure 2.4 Better Quality 2D Seismic Data Example

Figure 2.5 Poorer Quality 2D Seismic Data Example

Figure 2.6 Mapping Basis for Low/Best/High GRVs


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1. Introduction

This report was prepared in October 2018 by Lloyd’s Register (LR or Senergy (GB) Limited) at the request of

and for the benefit of the Directors of Cabot Energy Plc (Cabot or the Company). The report consists of an

evaluation of the Vesta Prospect in the Sicily Channel (Licence C.R146.NP and C.R149.NP), offshore Italy.

The rights of Cabot in the licences have not been verified by LR as this is considered outside the scope of this

technical geological and engineering report. Therefore, LR makes no comment on the legal entitlement of

Cabot or its affiliates to these areas.

LR was requested to provide an independent review and audit of the Prospective Resources.

Some of the resources for these prospects attributable to Cabot assume licence extensions are granted.

1.1 Sources of Information

In conducting this review LR has utilised information and interpretations supplied by Cabot and its affiliates

comprising subsurface, field and other data along with various technical reports and presentations. The

report is based on data and information made available to LR by Cabot during September and October 2018.

LR has reviewed the information provided and modified assumptions where appropriate. LR has accepted,

without independent verification, the accuracy and completeness of the data.

LR has had access to a dataset supplied by Cabot and its affiliates of both raw and interpreted data. However,

LR has not attempted a systematic re-interpretation of the raw data but has performed a critical assessment

of the existing interpretations.

1.2 Requirements

In accordance with your instructions LR confirms that:

LR is professionally qualified and a member in good standing of a self-regulatory organisation of

engineers and/or geoscientists;

LR has at least five years’ relevant experience in the estimation, assessment and evaluation of oil and gas

assets;

LR is independent of Cabot, its directors, senior management and advisers;

LR will be remunerated by way of a time-based fee and not by way of a fee that is linked to the value

of Cabot or its assets;

LR is not a sole practitioner;

LR has the relevant and appropriate qualifications, experience and technical knowledge to appraise

professionally and independently the assets, being all assets, licences, joint ventures or other

arrangements owned or proposed to be exploited or utilised (“Assets”) and liabilities, being all liabilities,

royalty payments, contractual agreements and minimum funding requirements relating to the work

programme and Assets (“Liabilities”).

1.3 Standards Applied

In compiling this report, LR has been guided by the definitions and guidelines set out in the Petroleum

Resources Management System (PRMS) (2018) prepared by the Oil and Gas Reserves Committee of the

Society of Petroleum Engineers (SPE) and reviewed and jointly sponsored by the World Petroleum Council

(WPC), the American Association of Petroleum Geologists (AAPG) and the Society of Petroleum Evaluation

Engineers (SPEE), the Society of Exploration Geophysicists (SEG), the Society of Petrophysicists and Well Log

Analysts (SPWLA) and the European Association of Geoscientists and Engineers (EAGE) (References 1 to 4).


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The report has not been prepared to be compliant with the regulations of any specific financial exchange.

1.4 Site Visit

A site visit has not been required as all the data pertaining to this project is subsurface information available

digitally.

1.5 Liability

All interpretations and conclusions presented herein are opinions based on inferences from geological,

geophysical, engineering or other data. The report represents LR’s best professional judgment and should

not be considered a guarantee of results. Our liability is limited solely to the Company for the correction of

erroneous statements or calculations. The use of this material and report is at the user’s own discretion and

risk.

1.6 Consent

The report relates specifically and solely to the subject assets and is conditional upon various assumptions

that are described herein. The report must therefore be read in its entirety. This report was provided for the

use of the Company on a fee basis.

Lloyd’s Register assumes no responsibility and shall not be liable to any person for any loss, damage or

expense caused by reliance on the information or advice in this document or howsoever provided, unless

that person has signed a contract with the relevant Lloyd’s Register entity for the provision of this information

or advice and in that case, any responsibility or liability is exclusively on the terms and conditions set out in

that contract.


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2. Vesta Prospect, Licences C.R146.NP & C.R149.NP

2.1 Introduction

The Vesta prospect lies on licenses C.R146.NP and C.R149.NP in the Sicily Channel offshore region of Italy

(Figure 2.1). The licenses lie approximately 60 km from the coastline in around 120 m water depth. Cabot

operate the licenses with 100% Working Interest (Table ES-1). The Vesta prospect comprises platform shoal

carbonates with both primary and secondary (fracture and karst) porosity and is considered analogous to the

currently producing Vega field, which lies 60 km to the north-west and is operated by Edison.

The C.R146.NP licence was awarded in September 2004 for an initial six year period. The work programme

for this licence comprised the acquisition of 150 km of 2D seismic and the drilling of an exploration well to

3,500 m TD within 42 months of award. In 2006, 508 km of 2D seismic was acquired in C.R146.NP. EIA

approval to drill a well was granted in April 2018, and the C.R146.NP permit is currently in suspension

pending drilling. As it is believed that the Vesta prospect extends eastwards into the C.R149.NP permit, this

acreage was applied for by the Company, and subsequently awarded in July 2014. Licence C.R149.NP has

a first exploration period of six years, with a work programme consisting of one exploration well to 3,500 m

TD within 60 months of award. The Company is looking for partners to help progress the work programmes

offshore Sicily.

2.2 Subsurface Evaluation

The Vesta prospect is considered an analogous dip-closed structure to the Vega field, but with upside

potential in the form of a possible stratigraphic trapping element. The prospect is mapped on variable quality

2D seismic and constrained by a few key wells in its vicinity. The proposed reservoirs are the same Liassic

fractured oolitic limestones and dolomites as encountered in the Vega field.

The Vega field

The Vega oil field lies approximately 60 km to the northwest of Vesta. Vega was discovered in 1981 by

Edison, and has an estimated STOIIP in the order of 431 MMstb and an EUR of 95 MMbbl. 63.4 MMstb of

heavy 15.5o API oil have been produced to date from 21 wells. The oil density is high and the amount of gas

dissolved in the oil is negligible (10-20 Sm3 / m3). Vega is described by Edison in a 2011 technical report

supporting the extension of the term of the field’s production concession (Reference: Concession “C.C6.EO”

Depository, Technical Report of Campo Vega, November 2011, Edison).

The trap is a 4-way dip closure located on the platform margin and is believed to be full to spill (Figure 2.2).

The Liassic Siracusa Formation reservoir is a low porosity fractured carbonate, with a variety of facies belts

including platform top, emergent areas dominated by paleo-karstic porosity, and more marginal facies

towards the Streppenosa Basin to the north. The two main lithologies of the reservoir sequence are limestone

and dolomite, with the latter thought to originate in a fresh/salt water mixing zone within a karst system.

The dolomites are generally characterised by better reservoir properties. Five main stages of diagenesis have

been identified by Edison from a study of cored material and regional analogues. Tectonic fractures played

an important role in the development of the karst system and subsequent dolomitisation, and their continued

development through the complex structural history to the present-day impacts on reservoir storage and

productivity.

The sealing unit of the Vega oil field is the Buccheri Formation which was deposited following an extensive

regional carbonate platform drowning event during the latest Liassic. The main source rock for the Vega oil

field is considered to be the Late Triassic Noto Formation.

Vega and Vesta are interpreted to occupy a similar Siracusa Platform margin location. Comparable reservoir

properties are expected due to the analogous depositional patterns along the platform margin, similar


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diagenetic and post-diagenetic histories, analogous tectonic histories and comparable reservoir depths (Vega

crest ~2,450 m TVDSS and Vesta crest ~2,670 m TVDSS).

2.2.1 Prospect Risk

Trap

The Vesta prospect low case scenario is a 4-way, dip-closed structure. The High case scenario invokes

stratigraphic trapping arising from facies changes, effectively from reservoir to non-reservoir, across the

Siracusa Platform margin to the north and represents substantially higher exploration risk. A sketch cross-

section illustrating the play concept is shown in Figure 2.3. Vesta is mapped on a grid of 2D seismic data of

varying vintages and quality. Figure 2.4 and Figure 2.5 illustrate the variation in 2D seismic data quality over

the Vesta prospect, the former showing one of the better quality lines, and the latter, one of the poorer.

Unfortunately, there is a lack of coverage of better quality data to the north and east of the prospect, resulting

in significant uncertainty in mapping in this critical area. This data coverage-related mapping uncertainty is

compounded by the additional uncertainties introduced by the ambiguity in the key seismic pick, top Liassic,

and the difficulty in interpreting this event reliably on the often poorly imaged seismic data. Synthetic

seismograms for key wells Spigola Mare-1 and Alexia-2, which both penetrate the top Liassic, suggest that

the existing Cabot seismic pick (a trough across the 2D dataset) does not represent a consistent ‘near top

Liassic’ event. In Spigola Mare-1 the existing Cabot top Liassic seismic pick appears to correspond with a

strong trough event, but at the top Buccheri Formation rather than its base; the top being in the order of

150 m above the base Buccheri/top Liassic reservoir in this well. However, in Alexia-2 the existing seismic

pick appears to loosely correspond to an intra-Buccheri lithology change 40 m above the base Buccheri/top

Liassic reservoir, and the top Buccheri Formation in this well is a clear peak due to the different lithologies in

the formations in the two wells. In addition to this uncertainty in identifying the top Liassic reservoir event,

at best the 2D seismic data over Vesta allows a ‘near top Liassic’ pick to be interpreted with some degree of

confidence. However, there are a number of lines where the imaging is insufficient to allow a reliable

interpretation to be made. This becomes critical in the north-eastern area of Vesta where the seismic dips

required to set up the 4-way dip closure in time are not clearly demonstrated on the reprocessed dataset.

A layer-cake depth conversion methodology was used based on mapping well interval velocities for key

overburden velocity units. This single deterministic depth conversion appears to be reasonable as far as it

goes, but no alternative velocity models have been generated to assess the uncertainty in the mapped Vesta

depth closure. LR consider that the size of the 4-way dip closure will be sensitive to the depth conversion

methodology and have taken this into account in the Monte Carlo volumetric assessment, together with the

uncertainty due to the time interpretation of the seismic.

In addition to the uncertainty in presence and size of a 4-way dip closed trap, LR consider that the

‘stratigraphic’ trapping element cannot be clearly defined on the existing seismic and well database. The

existing well data, the Vega field analogue and the semi-regional depositional model potentially support the

concept of a northwards and basinwards change in facies from carbonate platform associations to marginal

and basinal associations (refer to Cabot’s non-unique interpretation of the time equivalent stratigraphic

intervals in Spigola Mare-1 and Cernia-1 to the north). However, LR do not consider that the quality of the

existing 2D seismic data is sufficient to clearly define the location of the change from reservoir to sealing

facies at the platform margin and northern edge of Vesta which is necessary to delineate the ‘stratigraphic’

trapping element. Cabot themselves state that: “the available seismic data do not allow a clear definition of

the platform to basin transition” (Reference: 2018_09_07 Vesta Prospect Technical Report), and the seismic

can only give suggestions of the required transition on one or two better imaged lines. This upside trapping

element is thus considered very uncertain and subject to significantly higher level of risk than a smaller 4-way

dip closed structure.

LR consider that the case for acquiring 3D data prior to drilling is very strong.


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Prospect Trap Chance = 57% (contributes to Chance of Geologic Discovery).

Reservoir

Cabot propose that reservoir at Vesta will comprise similar Liassic Siracusa Formation platform shoal

carbonates to those present in the Vega field. Edison’s work on this field has shown that the reservoirs are

complex, with the original depositional variations in quality being modified significantly by a multi-phase

diagenetic and tectonic post-depositional evolution to produce a system with both primary and secondary

porosity. The fact that approximately 50% of the total Vega oil production arises from 4 of the 21 wells

illustrates the marked differences in reservoir quality and productivity which are present within the reservoir.

Well Spigola Mare-1 was drilled by Elf Italiana in 1984 and lies on the western flank of the Vesta prospect.

A DST in the upper reservoir section recovered 11.5 m3 of fluids comprising water with a salinity of 58g/l,

and an emulsion of gas (C1 to C4) with traces of bituminous oil without direct fluorescence. Elf reported

that the calculated permeability from the test was only in the order of 2 mD from a productive zone of

cumulative thickness around 5 m with reported average porosity in excess of 11%. The Siracusa Formation

in this well does not appear to have been fully logged and hence there is uncertainty over the reservoir quality

deeper in the drilled interval. Therefore the well does not prove effective reservoir quality at this down-flank

location to Vesta, and increases the risk on encountering better reservoir quality up-dip to the east.

Given the absence of a fully logged reservoir interval in Spigola Mare-1, Cabot have used the data from the

Vega field for the volumetric assessment of the Vesta prospect. LR have accepted this approach, but have

ensured that reservoir risk takes into account the results of Spigola Mare-1.

There is also the risk that the amount of net reservoir within the proposed Siracusa Formation interval may

be reduced by the presence of interbedded volcanic rocks, such as those proven in some of the offset wells.

Cabot have used seismic amplitudes to assess the risk of a significant proportion of volcanics within Vesta,

and consider that this is relatively low.

Prospect Reservoir Chance = 64% (contributes to Chance of Geologic Discovery).

Seal

An effective top seal, the basal part of the Buccheri Formation, is proven in the Vega field, and this interval

is also present in nearby wells Alexia-2 and Spigola Mare-1. However, the main clay-rich sealing interval

appears to be thinning from Vega south-eastwards towards Vesta, as indicated by the thicknesses in wells

Vega-1 (>120 m), Alexia-2 (~70 m) and Spigola Mare-1 (~10 m). There is thus the risk that an effective top

seal may not be present over the whole of Vesta, and this is considered the main risk element for the 4-way

dip-closed prospect trap.

Side/lateral seal is also required for the upside ‘stratigraphic’ trapping mechanism at Vesta. This element is

not thought to be present at Vega, and is thus a new play element and only supported at the conceptual

level by the existing well and seismic data. This upside seal element is considered very high risk at present.

Prospect Seal Chance = 45% (contributes to Chance of Geologic Discovery).

Charge

The proposed source rock for Vesta is the same Triassic Noto Formation anoxic back-lagoonal shales as

identified from the geochemical fingerprint in the oils of the Vega field. These shales are expected to be

present to the south of Vesta in the same general depositional environment found in the Vega field. The

presence of shows in some of the offset Vesta wells suggests the presence of migrating oil.

Maturity modelling carried out by Cabot suggests that most of the oil charge took place during the

Cretaceous for the Vega field, with the potential for a later charge in the Tertiary at Vesta depending on the

poorly constrained depth of the Noto Formation source in the Vesta catchment area. The key outcome of


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the modelling work is that hydrocarbon migration is thought to post-date Jurassic to Cretaceous trap

formation and modification.

One interpretation of the available data for the Spigola Mare-1 well is that live oil shows were present in

poor quality rock. It is also possible that the shows correspond to residual oil, but in either case this provides

support for hydrocarbons having passed through the rocks at this location at some point in time.

In summary, hydrocarbon charge is considered to be relatively low risk with the key sub-element being the

available volumes of generated and expelled oil.

Prospect Oil Charge Chance = 80% (contributes to Chance of Geologic Discovery).

Chance of Geologic Discovery

The LR assessment for the chance of geologic discovery for Vesta is summarised in Table 2.1. The Chance of

Geologic Discovery is defined (PRMS 2018) as the chance that the potential accumulation will result in the

discovery of a significant quantity of petroleum. “Significant” in this context implies that there is then

evidence of a sufficient quantity of petroleum to justify estimating the in-place quantity demonstrated by the

discovery well(s) and for evaluating the commercial discovery. Such volume can best be estimated by

identifying a development scenario and evaluating its potential economic threshold but this has not been

undertaken for this report. The Chance of Geologic Discovery thus pertains to discovery of volumes

corresponding at a maximum to the lowest end of the Prospective Resource range. No risking has been

attempted to correspond to the mid or high range of resource estimates for which there would be a

correspondingly higher risk element.

Prospective Resources are also subject to further risking associated with the Chance of Development. (see

Section 2.2.2).

In assessing Prospective Resources, a recovery factor has been applied which corresponds to a nearby

developed field analogue.

Prospect Trap % Reservoir % Seal % Charge % Chance of

Discovery %

Vesta 57 64 45 80 13

Table 2.1: Vesta Prospect, Chance of Geologic Discovery Assessment

2.2.2 Prospect Volumes

The input parameters and volumes are based on the work presented by Cabot which itself draws heavily on

the Vega studies undertaken by Edison.

LR has reviewed Cabot’s 2D seismic interpretation and mapping, and has accepted the most recent top Liassic

depth grid as the basis for calculating gross rock volumes (GRVs) within Kingdom for input to the REP Monte

Carlo software.

LR have used a Beta distribution for GRV, with a best-case input value anchored to the largest 4-way dip-

closed depth structure which can be mapped on the present 2D data (Figure 2.6). This is consistent with the

main Vega field analogue, which is a full-to-spill, 4-way dip closed accumulation based on the work we have

seen from Edison. The best-case GRV results from a lowest closing contour at 2,910 m TVDSS, producing a

column height of 240 m which compares well with the average 260 m column in the five Vega wells for

which we have information. The low case GRV is based on a lowest closing contour of 2,825 m TVDSS, and

is driven by assuming an oil column half of the maximum height seen in the Vega field (which is 310 m). A

reduced oil column at Vesta in comparison with Vega is considered a distinct possibility given that the top


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seal is thinning towards Vesta. This level of low case GRV is considered appropriate to capture a realistic

downside scenario, which although based on column height, may in effect arise for a variety of reasons such

as the large uncertainty in mapping the structure due to well ties, poor quality 2D data, depth conversion

uncertainty, etc. LR emphasise that confidence in the existing top Liassic depth map is moderate at best,

given the quality and availability of data and the complex geology of the play. The high case GRV is based

on a lowest closing contour of 3,190 m TVDSS and is the maximum closure which can be mapped given the

results of Spigola Mare-1. In the high-case the necessary lateral ‘stratigraphic’ trapping element is taken as

the east-west line interpreted by Cabot. The ‘P1’ lowest closing contour (3,280 m TVDSS) which equates to

the GRV defined by the input Beta distribution would require an oil column of 610 m which can be

accommodated by the Siracusa Formation reservoir thickness seen in well Alexia-2. The fact that the ‘P1’

lowest closing contour lies beyond Spigola Mare-1 can be accepted on the basis of the large uncertainty in

depth mapping due to well ties, poor quality 2D data, and depth conversion uncertainty.

Cabot’s dual-porosity system reservoir parameters are based on the Vega work undertaken by Edison. This

work accounts for porosity variation due to limestone and dolomite matrix properties and relative proportion,

karst zone variation, fracture intensity range and the variation in net reservoir (via a NTG) due to the presence

of interbedded volcanic rocks within the Siracusa Formation reservoir. LR have benchmarked Cabot’s

parameters using our broad experience with fractured carbonate reservoirs worldwide: they are considered

reasonable, with a realistic range to capture the significant uncertainty within the complex reservoir system,

and hence suitable for input to the REP volumetric calculation.

Edison’s reported figures for the Vega field (STOIIP 431 MMstb, EUR c. 94.5 MMstb) suggest a recovery factor

of 21.9%, which has been rounded down to by Cabot to a best case input of 20%. LR have used an input

recovery factor range of 10%-20%-30%, considering that Cabot’s presented range (15%-20%-25%) was

too narrow for this type of complex carbonate reservoir.

Table 2.8 presents the dual-porosity system reservoir parameters used by LR.

Vesta Volumetric Input Parameters

Low Best High

Gross Rock Volume (MMm3) 1,089 4,070 32,580

Matrix Net to Gross (%) 50 70 90

Matrix Porosity (%) 0.4 2.5 4.6

Matrix Water Saturation (%) 30 40 50

Fracture Net to Gross (%) 50 70 90

Fracture Porosity (%) 0.2 0.5 0.8

Matrix Water Saturation (%) 0 0 0

Formation Volume Factor (oil) (vol/vol) 1.08 1.11 1.16

Matrix Oil Recovery Factor (%) 10 20 30

Fracture Oil Recovery Factor (%) 10 20 30

Table 2.2: Vesta Prospect Volumetric Input Parameters

The Prospective Resources are expressed as a range of gross technical resources estimated to be potentially

recoverable from the accumulation, subject to successful exploration. Prospective Resources are not the same

as net entitlement as the latter will be net of any applicable contract and fiscal terms attributing a portion of

the recoverable volumes to the government as per the contractual terms of the licence at the time of any

eventual hydrocarbon production. Cabot have informed LR that the applicable Government royalty is 7%.


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Net entitlement can only be estimated after discovery, definition of a development project and by economic

analysis none of which stages have been reached by this project.

Low (P90), Best (P50) and High (P10) oil in place (Table 2.3) and Prospective Resources (Table 2.4) are

tabulated below for the Gross accumulation (which is the same as the Net volumes).

The Mean case STOIIP is calculated as 1,392 MMstb.

Oil Initially in Place (STOIIP) Unrisked

Vesta Gross equals Net (Total Accumulation Is On Licence, 100% Cabot Equity) Low Estimate – P90 Best Estimate – P50 High Estimate – P10

MMstb 173 991 3,104

Table 2.3: Vesta Prospect, Unrisked STOIIP

Prospective Resources Unrisked

Vesta Gross equals Net (Total Accumulation Is On Licence, 100% Cabot Equity) Low Estimate (1U) P90 Best Estimate (2U) P50 High Estimate (3U) P10

MMstb 31 187 642

Table 2.4: Vesta Prospect, Unrisked Prospective Resources

LR estimate the unrisked Gross (which is the same as the Net) Mean Prospective Resources to be 280 MMstb

oil.

The volatility ratio for the high to low cases is approximately 21, indicating a high level of uncertainty for this

unexplored play due to the significant but high-risk upside volumes associated with an unproven

‘stratigraphic’ lateral sealing element to the trap.

With regards to Chance of Development, the evaluation of a development scenario, regulatory and

contractual context and the economic threshold of the project were outside of the scope of LR’s technical

project review and so the Chance of Development could not be assessed nor quantified. LR have insufficient

information to assess if a discovery at the low end of the estimated probabilistic volume range would be

commercial. However, subject to favourable commercial terms and based solely on volume considerations,

a discovery in the estimated P50 to P10 probabilistic range would likely provide a basis for a commercial

project considering the size of the developed Vega field, an apparently economic analogue.

Vesta Triassic Potential, Licences C.R146.NP and C.R149.NP

Cabot have identified a possible Triassic exploration play at depth below the Vesta Liassic prospect. The

Triassic Gela Formation fractured carbonates form the reservoir in number of oil fields producing in the

region, for example the Gela field, onshore Sicily, in the northern part of the basin. This deep play remains

to be explored to any great degree in the offshore area. These deep Triassic reservoirs are likely to contain

light oil and condensate, with a potentially significant amount of gas.

Cabot describe how “the characterization of the Triassic prospectivity over the Vesta prospect is hindered by

the poor quality of the seismic data for those depths and by the lack of any deep Triassic penetration near

the prospect which could be used to constrain the Triassic horizon interpreted in TWT”. However, by

mimicking the shallower Liassic structure (which is itself poorly imaged by seismic), Cabot have reported that

a “large structure has been mapped covering an area of appr. 115.8km2 down to the closing contour of

4100m ss”. Using the same dual-porosity system reservoir parameters as for the Liassic, Cabot have assessed


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possible P50 STOIIP and Prospective Resource Triassic oil volumes of 1,940 MMstb and 380 MMstb

respectively for their Vesta Triassic ‘lead’.

LR have reviewed Cabot’s presentation of this deeper Triassic reservoir target in an interpreted 4-way dip

closed structure. It is considered that there are presently very significant risks on reservoir, seal and structure,

and the source/charge aspects are also somewhat uncertain. The reservoir and seal elements are

demonstrated elsewhere in the area, but the platform-margin location means that finding effective reservoir

and seal in the correct spatial configuration given the lateral facies changes is uncertain. Structure cannot

be mapped on the existing low quality 2D data which does not image the reservoir target. Creating a

structure map by hanging a Liassic-top Gela isopach (based on nearby well Alexia-2) on a top Liassic depth

grid is also considered extremely unreliable, as variation in the true isopach beneath Vesta could dramatically

change the shape of any 4-way dip closure, or completely kill it. LR also note that if a top Triassic depth grid

was created by isochoring down from the current top Liassic depth grid (as used for the Liassic evaluation)

rather than the older version as presented by Cabot, a significantly smaller depth closure would result. It

would thus appear that Cabot’s volumes are likely to be optimistic and also to not reflect the downside

sufficiently.

For these reasons, LR believes the definition of the feature is insufficiently mature to regard it as a lead and

hence that prospective volumes and risks for the feature cannot at this time be reliably estimated. The

acquisition of 3D seismic data would be expected to assist in maturing any potential at this level, provided

that the recording parameters of such survey are designed to image the Triassic as a secondary objective.


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3. References

1. “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserve information”, published by the

Society of Petroleum Engineers (SPE) in June 2001, SPE website (www.spe.org).

2. “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserve Information Approved by SPE

Boards June 2001 - Revision as of February 19, 2007”, published by the Society of Petroleum Engineers (SPE);

SPE website (www.spe.org).

3. “Petroleum Resources Management System”, Sponsored by SPE, AAPG, WPC, SPEE, SEG, SPWLA and EAGE,

published 2018; SPE website (www.spe.org).

4. “Petroleum Reserves Definitions” approved by SPE and WPC March 1997; SPE website (www.spe.org).

http://www.spe.org/

http://www.spe.org/

http://www.spe.org/

http://www.spe.org/


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Appendix 1 – Lloyd’s Register and Author Credentials

LR is a global engineering, technical and business services organisation wholly owned by the Lloyd’s Register

Foundation, a UK charity dedicated to research and education in science and engineering. Founded in 1760 as a

marine classification society, LR now operates across many industry sectors, with over 8,000 employees based in 78

countries.

In September 2013, Senergy became a member of the LR Group. The LR Group provides a broad service portfolio to

the upstream sector of the energy industry, from reservoir to refinery and beyond. LR specialises in petroleum reservoir

engineering, geology and geophysics and petroleum economics. All of these services are supplied under an accredited

ISO9001 quality assurance system. Except for the provision of professional services on a fee basis, LR has no

commercial arrangement with any person or Company involved in the interest that is the subject of this report.

Jon Wix – Principal Geophysicist

Jon is a highly experienced, and business focused Principal Geophysicist and Technical Project Manager with a strong

record of achievement and extensive experience of international exploration and exploitation projects. With over 30

years of industry experience, he has the ability to work in both leadership and technical roles to deliver successful

projects within timeframes and budgets. Jon also has a demonstrable record of technical excellence and creativity

making a material difference to geoscience challenges. Having a working knowledge of many petroleum basins in

the world, with specialised experience in plays in the North Sea, Africa, Europe, FSU, Americas and the Middle & Far

East, Jon is equally happy working on major integrated studies or short-fuse, dataroom style evaluations. He has broad

experience gained in both operating oil companies (Marathon, Petrobras, Chevron, Hess) and premium consulting

companies (LR Senergy, Gaffney-Cline). Jon holds an MSc in Applied Geophysics and a BSc in Geological Sciences

both from the University of Birmingham.

David Tobias – Head of Reserves and Asset Evaluations

David Tobias is a Geoscientist with a broad commercial and economics background obtained over 40 years in projects

and project management in diverse cultural settings with LR, Texaco, Phillips Petroleum, the Lundin Group, Enterprise

Oil and BHP Billiton Petroleum. Resource assessment and valuation activities span geological and geophysical

interpretation, commercial and economic analysis and petroleum resource classification for fields and prospective

acreage. Worldwide experience with an Africa, Europe, South America and South East Asia focus. David leads the

London-based Reserves and Asset Evaluation team delivering a range of Competent Persons Reports, Due Diligence

Reports and Acreage and Asset Evaluation studies. David (FGS) has a BSc (Hons) Geology, MSc. Marine Geotechnics

and MBA.

Neville Brookes – Principal Commercial Geoscientist

Neville Brookes has a BSc degree in Geology and Chemistry and an MSc in Stratigraphy from London University. He

is a Principal Commercial Geoscientist with over 30 years of oil industry experience working the full exploration-

development-production life cycle for several mid-sized independent oil companies. Neville has a strong technical

background and has working in several world class basins. Neville has extensive experience of geological analyses and

evaluation of oil and gas prospects and fields, including auditing and classification of resources. He is a Fellow of the

Geological Society of London and a member of the AAPG and PESGB.


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Appendix 2 - Resource and Risk Evaluation Method

LR was requested to provide an independent evaluation of the recoverable hydrocarbons expected for the asset.

Standard geological and engineering techniques accepted by the petroleum industry were used in estimating

recoverable hydrocarbons. These techniques rely on engineering and geo-scientific interpretation and judgement;

hence the resources included in this evaluation are estimates only and should not be construed to be exact quantities.

It should be recognised that such estimates may increase or decrease in future if there are changes to the technical

interpretation, economic criteria or regulatory requirements.

The recoverable hydrocarbons expected for each asset are categorised in accordance with the Petroleum Resources

Management System (2018) prepared by the Oil and Gas Reserves Committee of the Society of Petroleum Engineers

(SPE) and reviewed and jointly sponsored by the World Petroleum Council (WPC), the American Association of

Petroleum Geologists (AAPG), the Society of Petroleum Evaluation Engineers (SPEE), the Society of Exploration

Geophysicists (SEG), the Society of Petrophysicists and Well Log Analysts (SPWLA) and the European Association of

Geoscientists & Engineers (EAGE).

Prospective Resources can be defined for projects at one of three stages of maturity: play, lead or prospect. In each

case the opportunities are verified through review of Operator data, studies and maps, and by comparison with

analogue play type and basin information where available.

A prospect is an opportunity at a sufficient level of maturity to be drilled. A lead is an opportunity that requires

additional data and/or analysis before it is considered to be ready for drilling. In addition, LR refer to a potentially

drillable opportunity as a prospect if the database is adequate for us to quantify the potential resource size and

undertake a meaningful risk assessment. If the database is inadequate we assign lead status and assess the resource

size potential of the play to which the lead or leads belong. In some circumstances, a lead may be sufficiently well

defined to quantify the prospective resource size range.

A play is defined as a project associated with a prospective trend of potential prospects, but which requires more data

acquisition and/or evaluation in order to define specific leads or prospects. Project activities are focused on acquiring

additional data and/or undertaking further evaluation designed to define specific leads or prospects for more detailed

analysis of their chance of discovery and, assuming discovery, the range of potential recovery under hypothetical

development scenarios.

Estimating a total resource volume for a portfolio of opportunities can be performed arithmetically or stochastically.

In this report, we have arithmetically summed the predicted low, best and high case volumes.


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Appendix 3 - PRMS Reserves and Resources Definitions

The following figures and tables have been extracted from the 2018 Petroleum Resources Management System (PRMS)

prepared by the Oil and Gas Reserves Committee of the Society of Petroleum Engineers (SPE) and reviewed and jointly

sponsored by the World Petroleum Council (WPC), the American Association of Petroleum Geologists (AAPG) and the

Society of Petroleum Evaluation Engineers (SPEE). The complete document is available from:

https://www.spe.org/en/industry/Petroleum-Resources-Management-System-2018

The following two illustrations;

Figure A1-1 and Figure A1-2 pertain to the Classification Framework and the Project maturity sub-classes of the PRMS,

which are discussed in Table A1-1 to Table A1-3.

Figure A1-1: Petroleum Resources Classification Framework

https://www.spe.org/en/industry/Petroleum-Resources-Management-System-2018


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Figure A1-2: Project Maturity Sub-Classes


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Class/Sub-Class Definition Guidelines

Reserves Reserves are those

quantities of petroleum

anticipated to be

commercially

recoverable by

application of

development projects

to known

accumulations from a

given date forward

under defined

conditions.

Reserves must satisfy four criteria: discovered, recoverable, commercial,

and remaining based on the development project(s) applied. Reserves

are further categorized in accordance with the level of certainty

associated with the estimates and may be sub-classified based on

project maturity and/or characterized by the development and

production status.

To be included in the Reserves class, a project must be sufficiently

defined to establish its commercial viability. This includes the

requirement that there is evidence of firm intention to proceed with

development within a reasonable time-frame.

A reasonable time-frame for the initiation of development depends on

the specific circumstances and varies according to the scope of the

project. While five years is recommended as a benchmark, a longer

time-frame could be applied where, for example, development of an

economic project is deferred at the option of the producer for, among

other things, market-related reasons or to meet contractual or strategic

objectives. In all cases, the justification for classification as Reserves

should be clearly documented.

To be included in the Reserves class, there must be a high confidence in

the commercial maturity and economic producibility of the reservoir as

supported by actual production or formation tests. In certain cases,

Reserves may be assigned on the basis of well logs and/or core analysis

that indicate that the subject reservoir is hydrocarbon-bearing and is

analogous to reservoirs in the same area that are producing or have

demonstrated the ability to produce on formation tests.

On Production The development

project is currently

producing and selling

petroleum to market.

The key criterion is that the project is receiving income from sales,

rather than the approved development project necessarily being

complete. Includes Developed Producing Reserves.

The project decision gate is the decision to initiate or continue

economic production from the project.

Approved for

Development

All necessary approvals

have been obtained,

capital funds have been

committed, and

implementation of the

development project is

under way.

At this point, it must be certain that the development project is going

ahead. The project must not be subject to any contingencies, such as

outstanding regulatory approvals or sales contracts. Forecast capital

expenditures should be included in the reporting entity’s current or

following year’s approved budget.

The project decision gate is the decision to start investing capital in the

construction of production facilities and/or drilling development wells.

Justified for

Development

Implementation of the

development project is

justified on the basis of

reasonable forecast

commercial conditions

at the time of

reporting, and there

are reasonable

expectations that all

necessary

approvals/contracts will

be obtained.

To move to this level of project maturity, and hence have Reserves

associated with it, the development project must be commercially

viable at the time of reporting and the specific circumstances of the

project. All participating entities have agreed and there is evidence of a

committed project (firm intention to proceed with development within

a reasonable time-frame}) There must be no known contingencies that

could preclude the development from proceeding (see Reserves class).

The project decision gate is the decision by the reporting entity and its

partners, if any, that the project has reached a level of technical and

commercial maturity sufficient to justify proceeding with development

at that point in time.

Contingent

Resources

Those quantities of

petroleum estimated,

as of a given date, to

be potentially

Contingent Resources may include, for example, projects for which

there are currently no viable markets, where commercial recovery is

dependent on technology under development, where evaluation of the

accumulation is insufficient to clearly assess commerciality, where


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recoverable from

known accumulations

by application of

development projects,

but which are not

currently considered to

be commercially

recoverable owing to

one or more

contingencies.

the development plan is not yet approved, or where regulatory or social

acceptance issues may exist.

Contingent Resources are further categorized in accordance with the

level of certainty associated with the estimates and may be sub-

classified based on project maturity and/or characterized by the

economic status.

Development

Pending

A discovered

accumulation where

project activities are

ongoing to justify

commercial

development in the

foreseeable future.

The project is seen to have reasonable potential for eventual

commercial development, to the extent that further data acquisition

(e.g., drilling, seismic data) and/or evaluations are currently ongoing

with a view to confirming that the project is commercially viable and

providing the basis for selection of an appropriate development plan.

The critical contingencies have been identified and are reasonably

expected to be resolved within a reasonable time-frame. Note that

disappointing appraisal/evaluation results could lead to a reclassification

of the project to On Hold or Not Viable status.

The project decision gate is the decision to undertake further data

acquisition and/or studies designed to move the project to a level of

technical and commercial maturity at which a decision can be made to

proceed with development and production.

Development

on Hold

A discovered

accumulation where

project activities are on

hold and/or where

justification as a

commercial

development may be

subject to significant

delay.

The project is seen to have potential for commercial development.

Development may be subject to a significant time delay. Note that a

change in circumstances, such that there is no longer a probable

chance that a critical contingency can be removed in the foreseeable

future, could lead to a reclassification of the project to Not Viable

status.

The project decision gate is the decision to either proceed with

additional evaluation designed to clarify the potential for eventual

commercial development or to temporarily suspend or delay further

activities pending resolution of external contingencies.

Development

Unclarified

A discovered

accumulation

where project activities

are under evaluation

and where justification

as a commercial

development

is unknown based on

available information.

The project is seen to have potential for eventual commercial

development, but further appraisal/evaluation activities are ongoing to

clarify the potential for eventual commercial development.

This sub-class requires active appraisal or evaluation and should not be

maintained without a plan for future evaluation. The sub-class should

reflect the actions required to move a project toward commercial

maturity and economic production.

Development

Not Viable

A discovered

accumulation for which

there are no current

plans to develop or to

acquire additional data

at the time because of

limited production

potential.

The project is not seen to have potential for eventual commercial

development at the time of reporting, but the theoretically recoverable

quantities are recorded so that the potential opportunity will be

recognized in the event of a major change in technology or commercial

conditions.

The project decision gate is the decision not to undertake further data

acquisition or studies on the project for the foreseeable future.

Prospective

Resources

Those quantities of

petroleum that are

Potential accumulations are evaluated according to the chance of

geologic discovery and, assuming a discovery, the estimated quantities


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estimated, as of a given

date, to be potentially

recoverable from

undiscovered

accumulations.

that would be recoverable under defined development projects. It is

recognized that the development programs will be of significantly less

detail and depend more heavily on analog developments in the earlier

phases of exploration.

Prospect A project associated

with a potential

accumulation that is

sufficiently well defined

to represent a viable

drilling target.

Project activities are focused on assessing the chance of geologic

discovery and, assuming discovery, the range of potential recoverable

quantities under a commercial development program.

Lead A project associated

with a potential

accumulation that is

currently poorly defined

and requires more data

acquisition and/or

evaluation to be

classified as a Prospect.

Project activities are focused on acquiring additional data and/or

undertaking further evaluation designed to confirm whether or not the

Lead can be matured into a Prospect. Such evaluation includes the

assessment of the chance of geologic discovery and, assuming

discovery, the range of potential recovery under feasible development

scenarios.

Play A project associated

with a prospective

trend of potential

prospects, but that

requires more data

acquisition and/or

evaluation to define

specific Leads or

Prospects.

Project activities are focused on acquiring additional data and/or

undertaking further evaluation designed to define specific Leads or

Prospects for more detailed analysis of their chance of geologic

discovery and, assuming discovery, the range of potential recovery

under hypothetical development scenarios.

Table A1-1: Recoverable Resources Classes and Sub-Classes


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Status Definition Guidelines

Developed

Reserves

Expected quantities to be

recovered from existing

wells and facilities.

Reserves are considered developed only after the necessary equipment has

been installed, or when the costs to do so are relatively minor compared

to the cost of a well. Where required or when facilities become

unavailable, it may be necessary to reclassify Developed Reserves as

Undeveloped. Developed Reserves may be further sub-classified as

Producing or Non-Producing.

Developed

Producing Reserves

Expected to be recovered

from completion intervals

that are open and

producing at the time of

the estimate.

Improved recovery reserves are considered producing only after the

improved recovery project is in operation.

Developed Non-

Producing Reserves

Shut-in and behind-pipe

Reserves.

Shut-in Reserves are expected to be recovered from (1) completion

intervals which are open at the time of the estimate, but which have not

yet started producing, (2) wells which were shut-in for market conditions

or pipeline connections, or (3) wells not capable of production for

mechanical reasons. zones in existing wells that will require additional

completion work or future re-completion before start of production with

minor cost to access these reserves.

In all cases, production can be initiated or restored with relatively low

expenditure compared to the cost of drilling a new well.

Undeveloped

Reserves

Quantities expected to be

recovered through future

investments:

Undeveloped Reserves are to be produced (1) from new wells on undrilled

acreage in known accumulations, (2) from deepening existing wells to a

different (but known) reservoir, (3) from infill wells that will increase

recovery, or (4) where a relatively large expenditure (e.g., when compared

to the cost of drilling a new well) is required to (a) recomplete an existing

well or (b) install production or transportation facilities for primary or

improved recovery projects.

Table A1-2: Reserves Status Definitions and Guidelines

Category Definition Guidelines

Proved Reserves Those quantities of

petroleum that, by

analysis of geoscience

and engineering data, can

be estimated with

reasonable certainty to be

commercially recoverable

from a given date forward

from known reservoirs

and under defined

economic

conditions, operating

methods, and

government regulations.

If deterministic methods are used, the term “reasonable certainty” is

intended to express a high degree of confidence that the quantities will be

recovered. If probabilistic methods are used, there should be at least a

90% probability (P90) that the quantities actually recovered will equal or

exceed the estimate.

The area of the reservoir considered as Proved includes (1) the area

delineated by drilling and defined by fluid contacts, if any, and (2) adjacent

undrilled portions of the reservoir that can reasonably be judged as

continuous with it and commercially productive on the basis of available

geoscience and engineering data.

In the absence of data on fluid contacts, Proved quantities in a reservoir

are limited by the LKH as seen in a well penetration unless otherwise

indicated by definitive geoscience, engineering, or performance data. Such

definitive information may include pressure gradient analysis and seismic

indicators. Seismic data alone may not be sufficient to define fluid contacts

for Proved.

Reserves in undeveloped locations may be classified as Proved

provided that:


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A. The locations are in undrilled areas of the reservoir that can be judged

with reasonable certainty to be commercially mature and economically

productive.

B. Interpretations of available geoscience and engineering data indicate

with reasonable certainty that the objective formation is laterally

continuous with drilled Proved locations.

For Proved Reserves, the recovery efficiency applied to these reservoirs

should be defined based on a range of possibilities supported by analogs

and sound engineering judgment considering the characteristics of the

Proved area and the applied development programme.

Probable Reserves Those additional Reserves

that analysis of

geoscience and

engineering data

indicates are

less likely to be recovered

than Proved Reserves but

more certain to be

recovered than Possible

Reserves.

It is equally likely that actual remaining quantities recovered will be greater

than or less than the sum of the estimated Proved plus Probable Reserves

(2P). In this context, when probabilistic methods are used, there should be

at least a 50% probability that the actual quantities recovered will equal

or exceed the 2P estimate.

Probable Reserves may be assigned to areas of a reservoir adjacent to

Proved where data control or interpretations of available data are less

certain. The interpreted reservoir continuity may not meet the reasonable

certainty criteria. Probable estimates also include incremental recoveries

associated with project recovery efficiencies beyond that assumed for

Proved.

Possible Reserves Those additional reserves

that analysis of

geoscience and

engineering data

indicates are less likely to

be recoverable than

Probable Reserves.

The total quantities ultimately recovered from the project have a low

probability to exceed the sum of Proved plus Probable plus Possible (3P),

which is equivalent to the high-estimate scenario. When probabilistic

methods are used, there should be at least a 10% probability (P10) that

the actual quantities recovered will equal or exceed the 3P estimate.

Possible Reserves may be assigned to areas of a reservoir adjacent to

Probable where data control and interpretations of available data are

progressively less certain. Frequently, this may be in areas where

geoscience and engineering data are unable to clearly define the area and

vertical reservoir limits of economic production from the reservoir by a

defined, commercially mature project.

Possible estimates also include incremental quantities associated with

project recovery efficiencies beyond that assumed for Probable.

Probable and

Possible Reserves

See above for separate

criteria for Probable

Reserves and Possible

Reserves.

The 2P and 3P estimates may be based on reasonable alternative technical

and commercial interpretations within the reservoir and/or subject project

that are clearly documented, including comparisons to results in successful

similar projects.

In conventional accumulations, Probable and/or Possible Reserves may be

assigned where geoscience and engineering data identify directly adjacent

portions of a reservoir within the same accumulation that may be

separated from Proved areas by minor faulting or other geological

discontinuities and have not been penetrated by a wellbore, but are

interpreted to be in communication with the known (Proved) reservoir.

Probable or Possible Reserves may be assigned to areas that are structurally

higher than the Proved area. Possible (and in some cases, Probable)

Reserves may be assigned to areas that are structural lower than the

adjacent Proved or 2P area.

Caution should be exercised in assigning Reserves to adjacent reservoirs

isolated by major, potentially sealing, faults until this reservoir is penetrated

and evaluated as commercially productive. Justification for assigning


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Reserves in such cases should be clearly documented. Reserves should not

be assigned to areas that are clearly separated from a known accumulation

by non-productive reservoir (i.e., absence of reservoir, structurally low

reservoir, or negative test results); such areas may contain Prospective

Resources.

In conventional accumulations, where drilling has defined a highest known

oil elevation and there exists the potential for an associated gas cap, Proved

oil Reserves should only be assigned in the structurally higher portions of

the reservoir if there is reasonable certainty that such portions are initially

above bubble point pressure based on documented engineering analyses.

Reservoir portions that do not meet this certainty may be assigned as

Probable and Possible oil and/or gas based on reservoir fluid properties and

pressure gradient interpretations.

Table A1-3: Reserves Category Definitions and Guidelines


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Nomenclature

Variable Meaning Units

2D Two dimensional

3D Three dimensional

1U Denotes the unrisked low estimate qualifying as Prospective Resources

2U Denotes the unrisked best estimate qualifying as Prospective Resources

3U Denotes the unrisked high estimate qualifying as Prospective Resources

AAPG American Association of Petroleum Geologists

API American Petroleum Institute Api

bbl/d Barrels per day bbl/d

Best Estimate With respect to resources categorisation, the most realistic assessment of

recoverable quantities if only a single result were reported. If probabilistic

methods are used, there should be at least a 50% probability (P50) that the

quantities are actually recovered will equal or exceed the best estimate

Bscf Billions of standard cubic feet Bscf

COD (PRMS 2018) Chance of Development is the estimated probability that a known

accumulation, once discovered, will be commercially developed

COGD (PRMS 2018) Chance of Geologic Discovery the estimated probability that exploration

activities will confirm the existence of a significant accumulation of

potentially recoverable petroleum

Contingent Resources Contingent Resources are those quantities of petroleum estimated, as of a

given date, to be potentially recoverable from known accumulations by

application of development projects, but which are not currently considered

to be commercially recoverable owing to one or more contingencies

d Day d

DST Drill stem test

º F / º C Degrees Fahrenheit / Centigrade

EAGE European Association of Geoscientists and Engineers

EUR Estimated ultimate gas recovery

GRV Gross Rock Volume

Mean The arithmetic average of a set of values ft or m

m ss Meters subsea

MM Million

MM m3 Million cubic meters

MMbbl Million barrel/s

MMbo Million barrels of oil

MMboe Millions of barrels of oil equivalent


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MMscf/d Million standard cubic feet per day

MMstb Millions of barrels of stock tank oil

OWC Oil water contact

P99 The probability of that a stated volume will equal or exceed. In this example

a 99% chance that the actual volume will be greater than or equal to that

stated.

PRMS Petroleum Resources Management System

Producing Related to development projects (e.g. wells and platforms): Active facilities,

currently involved in the extraction (production) of hydrocarbons from

discovered reservoirs.

Prospective Resources Prospective Resources are those quantities of petroleum estimated, as of a

given date, to be potentially recoverable from undiscovered accumulations

by application of future development projects. Prospective Resources have

both an associated chance of geologic discovery and a chance of

development.

Proved Proved Reserves are those quantities of petroleum, which, by analysis of

geosciences and engineering data, can be estimated with reasonable

certainty to be commercially recoverable, from a given date forward, from

known reservoirs and under defined economic conditions, operating

methods, and government regulations. If deterministic methods are used,

the term reasonable certainty is intended to express a high degree of

confidence that the quantities will be recovered. If probabilistic methods are

used, there should be at least a 90% probability that the quantities actually

recovered will equal or exceed the estimate.

Proved plus Probable Probable Reserves are those additional Reserves which analysis of

geosciences and engineering data indicate are less likely to be recovered

than Proved Reserves but more certain to be recovered than Possible

Reserves. It is equally likely that actual remaining quantities recovered will be

greater than or less than the sum of the estimated Proved plus Probable

Reserves (2P). In this context, when probabilistic methods are used, there

should be at least a 50% probability that the actual quantities recovered will

equal or exceed the 2P estimate.

Proved plus Probable

plus Possible

Possible Reserves are those additional reserves which analysis of geosciences

and engineering data suggest are less likely to be recoverable than Probable

Reserves. The total quantities ultimately recovered from the project have a

low probability to exceed the sum of Proved plus Probable plus Possible (3P)

Reserves, which is equivalent to the high estimate scenario. In this context,

when probabilistic methods are used, there should be at least a 10%

probability that the actual quantities recovered will equal or exceed the 3P

estimate.

psi Pounds per square inch psi


www.lr.org 23 Final

Reserves Reserves are those quantities of petroleum anticipated to be commercially

recoverable by application of development projects to known accumulations

from a given date forward under defined conditions. Reserves must further

satisfy four criteria: they must be discovered, recoverable, commercial, and

remaining (as of the evaluation date) based on the development project(s)

applied. Reserves are further categorised in accordance with the level of

certainty associated with the estimates and may be sub-classified based on

project maturity and/or characterized by development and production

status.

RF Recovery Factor dec

or %

scf Standard cubic foot scf

SEG Society of Exploration Geophysicists

SPE Society of Petroleum Engineers

SPEE Society of Petroleum Evaluation Engineers

SPWLA Society of Petrophysicists and Well Log Analysts

stb/d Stock tank barrels per day stb/d

STOIIP Stock tank oil initially in place

TD Total depth

TVDSS True vertical depth sub-sea ft or m

WPC World Petroleum Council


www.lr.org 24 Final

Figures

Figure 2.1 – Location of Licenses C.R146.NP & C.R149.NP

Lloyd's Register 1

Source: Cabot/LR

Approximate marginof Siracusa Platform

Figure 2.2 – Vega Field Seismic & Structure

Lloyd's Register 2

Source: Cabot

NB: Mapped LCC corresponds

with OOWC @2,750 m TVDSS

Figure 2.3 – Vesta Play Concept

Lloyd's Register 3

Source: Cabot

South North

proposed

Figure 2.4 – Better Quality 2D Seismic Data Example

Lloyd's Register 4

Source: LR

Top Liassic grid Cyan

SW NE

Top Liassic horizon Yellow

Cabot possible Top Triassic grid Green

Figure 2.5 – Poorer Quality 2D Seismic Data Example

Lloyd's Register 5

Source: LR

SW NE

Top Liassic grid Cyan

Top Liassic horizon Yellow

Cabot possible Top Triassic grid Green

Figure 2.6 – Mapping Basis for Low/Best/High GRVs

Lloyd's Register 6

Source: LR

LR Best Case GRV‘Full to Spill’lcc 2,910 m TVDSS

LR/Cabot High Case GRVlcc 3,190 m TVDSS

Cabot Low Case GRVlcc 2,875 m TVDSS

LR Low Case GRV

lcc 2,825 m TVDSS (half max Vega column of 310 m, so

crest 2670+155 m)

Spill Point

Cabot Top Liassic Depth Grid (c.i.=30 m)

LR ‘P1’ Case GRVlcc 3,280 m TVDSS

Lloyd’s Register

(Senergy (GB) Limited)

71 Fenchurch Street

London, EC3M 4BS

T +44 (0)20 7438 4700

F +44 (0)20 7438 4701

Lloyd’s Register Group Limited, its subsidiaries and affiliates and their respective officers, employees or agents are, individually and collectively, referred to in

this clause as ‘Lloyd’s Register’. Lloyd’s Register assumes no responsibility and shall not be liable to any person for any loss, damage or expense caused by

reliance on the information or advice in this document or howsoever provided, unless that person has signed a contract with the relevant Lloyd’s Register entity

for the provision of this information or advice and in that case, any responsibility or liability is exclusively on the terms and conditions set out in that contract.

Lloyd’s Register and variants of it are trading names of Lloyd’s Register Group Limited, its subsidiaries and affiliates.

Copyright © LR2018. A member of the Lloyd’s Register group.

www.lr.org

independent review and audit of prospective resources ...vesta italy c.r149.np 100% exploration...

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