natural gas development based on non-pipeline options_technical feasibility study

NOIA

Natural Gas Development Based on Non-Pipeline Options - Offshore

NewfoundlandTechnical Feasibility Analysis

065/07129

7-Dec-00

07129/G49-0003D

Worley International Inc.

and

Worley EngineersWorley International Inc.

13105 Northwest Freeway, Suite 200Houston, Texas, 77040Tel: +1 713 690 1131Fax: +1 713 690 1981

Web: http://www.worley.org

© Copyright2001 Worley International Inc.

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NATURAL GAS DEVELOPMENT BASED ON NON-PIPELINE OPTIONS - OFFSHORE NEWFOUNDLAND -

TECHNICAL FEASIBILITY ANALYSIS

PROJECT 065/07129 - NATURAL GAS DEVELOPMENT BASED ON NON-PIPELINE OPTIONS - OFFSHORENEWFOUNDLAND

REV DESCRIPTION ORIG REVIEW WORLEYAPPROVAL

DATE CLIENTAPPROVAL

DATE

A Issued for internal reviewRichard A.

BreslerCatrionaDuncan

N/A 18-Feb-00 N/A

0 Issued to Client Richard A.


Richard A.Bresler

29-Mar-00

1 Issue to ClientRichard A.


Richard A.Bresler

1-May-00

2 Client commentsincorporated Richard A.


Richard A.Bresler

26-Jun-00

3 Final RevisionsRichard A.

BreslerSteve Worley Richard A.

Bresler

27-Sep-00



Bresler

2-Dec-00



Bresler

7-Dec-00

aforest:desktop folder:natural gas studies:development & transportation:technical nonpipeline final.docPage ii

Disclaimer and Limitation

This report has been prepared on behalf of and for the exclusive use of NOIA,and is subject to and issued in accordance with the agreement between NOIAand Worley International Inc. Worley International Inc accepts no liability or

responsibility whatsoever for it in respect of any use of or reliance upon thisreport by any third party.

Copying this report without the permission of NOIA or WorleyInternational Inc is not permitted.

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technical nonpipeline final.doc Page iii 065/07129 : Rev 5 : 7-Dec-00

CONTENTS

1. PURPOSE ............................................................................................................................................1

2. SCOPE .................................................................................................................................................2

3. METHODOLOGY .................................................................................................................................4

3.1 Onshore Compressed Natural Gas .....................................................................................................4

3.2 Onshore Liquefied Natural Gas ...........................................................................................................4

3.3 Offshore Compressed Natural Gas .....................................................................................................4

3.4 Offshore Liquefied Natural Gas ...........................................................................................................4

3.5 Onshore and Offshore Gas to Liquids.................................................................................................4

4. PRODUCTION SCENARIO SUMMARY.............................................................................................6

4.1 Offshore CNG.......................................................................................................................................6

4.2 Offshore LNG........................................................................................................................................7

4.3 Offshore GTL........................................................................................................................................7

4.4 Onshore CNG.......................................................................................................................................8

4.5 Onshore LNG........................................................................................................................................8

4.6 Onshore GTL........................................................................................................................................8

4.7 Gas Processing ....................................................................................................................................8

5. TECHNICAL FEASIBILITY ISSUES................................................................................................. 10

5.1 Reliability............................................................................................................................................ 10

5.2 Technology Status Summary............................................................................................................ 12

6. COST ANALYSIS SUMMARIES ...................................................................................................... 15

6.1 CNG Summary .................................................................................................................................. 16

6.2 Liquefied Natural Gas ....................................................................................................................... 18

6.3 Onshore Gas-to-Liquids .................................................................................................................... 19

6.4 Offshore Gas-to-Liquids .................................................................................................................... 21

7. CONVERSION FACTORS................................................................................................................ 24

8. GLOSSARY OF TERMS................................................................................................................... 25

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technical nonpipeline final.doc Page iv 065/07129 : Rev 5 : 7-Dec-00

Exhibits

I – GAS PROCESSING…………………………………………………...……………………………………..EI-1

II – OFFSHORE CNG…………………………………………………………..……………………………….EII-1

III – ONSHORE CNG…………………………………………………………..……………………………….EIII-1

IV – ONSHORE LNG……………………….……………………………...…..…………………...………….EIV-1

V – OFFSHORE LNG…………………………………………………………..……………………………….EV-1

VI – ONSHORE GTL…………………………………………………………..……………………………….EVI-1

VII – OFFSHORE GTL…………………………………………………………..…………………………….EVII-1

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technical nonpipeline final.doc Page 1 065/07129 : Rev 5 : 7-Dec-00

1. PURPOSE

Prior to this phase of work, a Pre-Screening Review was conducted to identify the many possibilities forutilizing natural gas. From that list, it was agreed that eight (8) different developments would beinvestigated, three onshore and five offshore, for the Industry Benchmark Analysis. As a result of theBenchmark Analysis, the scope of the Technical Feasibility Analysis was agreed:

• Onshore and offshore CNG.

• Onshore and offshore LNG.

• Onshore and offshore GTL.

a) Methanol

b) Fischer Tropsch (Diesel, Naphtha, etc.)

c) Methanol to Gasoline (MTG)

The purpose of the Technical Feasibility Analysis is to define and evaluate the technical feasibility ofthese non-pipeline options for Newfoundland’s offshore natural gas resources in terms of the resource, themarket opportunities identified, the development scenarios, gas processing, transportation of the products,

storage, and any other relevant technical considerations.

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2. SCOPE

The options selected for the Technical Feasibility Analysis are as follow:

a) Onshore Compressed Natural Gas

b) Onshore Liquefied Natural Gas

c) Onshore Conversion of Gas to Liquids

d) Offshore Compressed Natural Gas

e) Offshore Liquefied Natural Gas

f) Offshore Conversion of Gas to Liquids

Note that options a) through c) require that the gas be transported to shore prior to final processing. TheCAPEX cost of the pipeline and upstream production facilities are excluded from these three analyses.

For each of the options, the following key considerations were taken into account:

• Production Profile

− Gas production rates of 500 MMscfd

− Multi-field, sequential vs. stand alone developments

− Gas composition by field

− Gas vs. oil production rates (current and anticipated), field life, re-injection requirements,etc.

• Type of Production System

− Gravity-based, floating and subsea alternatives

− Reserve and financial implications of portable and modular production systems

− Utilization possibilities for existing and planned offshore production facilities and sharedservices.

• Processing Requirements

− Offshore vs. Onshore processing

− Composition of the raw natural gas

• Mode of Transportation

− Non-pipeline transportation; LNG, CNG, GTL

− Field to market vs. field to onshore and onshore to market

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• Infrastructure Requirements

− Site availability for landfall, storage requirements, and other infrastructure

− Possible utilization of Newfoundland site-specific infrastructure

• Cost Estimates

• Employment Impacts and Capture Rates

• Technology Status

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3. METHODOLOGY

3.1 Onshore Compressed Natural Gas

Cran and Stenning has undertaken most of the available work on this concept, and the informationpresented is primarily based on their work and cost estimates. Information on two other CNG conceptshave been reviewed. One utilizes carbon composite pressure vessels by Lorica Offshore Technology in

Newfoundland, and the other is a concept which is based on dense phase CNG by Suction MooringTechnologies.

Cran and Stenning have estimated costs for the CNG carriers, mooring systems, offloading berths,onshore equipment required to deliver the gas to market, and operating costs.

3.2 Onshore Liquefied Natural Gas

The Atlantic LNG facility in Trinidad, which was evaluated during the Benchmark Study, was used as thebasis for the technical feasibility analysis. That facility was designed for an inlet gas rate of 475 MMscfd,which is nearly identical to the assumed Jeanne d’Arc basin gas rates. Considerations for Newfoundlandproductivity factors were taken into account based on the estimates and results of the Hibernia and Terra

Nova projects, as furnished by the SGE Group. Additional cost information was supplied by Bechtel,ABB Randall, Black & Veatch, and by Worley from confidential projects undertaken in Europe, SouthEast Asia and Australia.

3.3 Offshore Compressed Natural Gas

In addition to the information supplied by Cran and Stenning mentioned above, published informationwas gathered from the Terra Nova, Hibernia, and Sable projects.

Cost data from previous Worley projects in South East Asia and Australia were also taken into account.

3.4 Offshore Liquefied Natural Gas

The facility that was evaluated is a proprietary ExxonMobil concept. Most of the information was

gathered from published technical papers and those written for “Offshore”, “World Oil” and fromwebsites. Cost estimates for this concept have not been provided by ExxonMobil. Worley has thereforeestimated the costs based on ExxonMobil reported savings over conventional LNG developments.

3.5 Onshore and Offshore Gas to Liquids

Worley Engineers have made several GTL proposals and have been a technical advisor to severaloffshore producers. They have technology secrecy agreements with ExxonMobil, Haldor Topsoe,

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Rentech, and ICI (Synetix) relating to non-published data for gas-to-liquids technologies. Usingconfidential information from these sources, several detailed cost estimates have been developed forpotential offshore projects for the North Sea, South Ease Asia, and West Africa. These estimates havebeen revised for applicability to Newfoundland.

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4. PRODUCTION SCENARIO SUMMARY

For all of the following cases, the average Btu content of the gas was calculated to average around 1117Btu/cubic foot. This was based on information and gas compositions supplied by C-NOPB and wasinfluenced greatly by the gas cap reservoirs which would provide the majority of the produced gas.

4.1 Offshore CNG

For the CNG concept, the most likely development scenario’s for use in the Jeanne d’Arc Basis would beone of the following:

• Combined Gas/Oil Hub

There is substantial merit for considering an oil and gas hub to be located near any major gas /condensate reservoir. Any new facility could perhaps be located at a central point between theHibernia, White Rose and Terra Nova developments, depending on the proximity to selected gas

storage/reinjection reservoirs. From purely technical considerations, either a GBS or FPSO couldprovide the means for this type of development.

The facility would gather available oil and gas from the various fields in the Jeanne d’Arc Basin,and condition the production to make it suitable for export to refinery’s and natural gas markets.Services such as field operations, gas processing, gas reinjection / gas storage could be provided

from the facility. This type of infrastructure could allow nearby fields, which might otherwise beuneconomic as stand-alone projects, to become viable projects in the future.

For this scenario, the production equipment would be sized for a minimum of 100,000 BOPD,injection of about 160,000 BWPD, and compression up to 250 MMscfd of gas to 5,600 psig for

injection. Export of up to 500 MMscfd of gas would be compressed up to approximately 3,100psig for loading CNG vessels or for delivery to a pipeline.

• Gas Hub

Similar to the Gas/Oil Hub mentioned above, either a strategically located GBS or FPSO vesselcould be a hub for gathering only natural gas and associated liquids from wells tied-back directly tothe hub. It could also possibly provide gas processing for the various developments in the Jeanne

d’Arc Basin.

• Existing GBS Hub

There is the possibility that the Hibernia facility could be modified to allow the facility to gathernatural gas and associated liquids from other developments in the Jeanne d’Arc Basin.

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4.2 Offshore LNG

An offshore LNG facility, as proposed by ExxonMobil for the Pacific Rim, would in essence be a floatinggas gathering hub. It could be designed to process total wellstream production from fields in the Jeanned’Arc Basin. The ExxonMobil concept was reportedly considered to handle from 500 MMscfd up to1,750 MMscfd, with the primary focus on 1,000 MMscfd.

4.3 Offshore GTL

In the past, the primary offshore application considered for this concept has been for oil developmentsthat have relatively small amounts of solution gas that can not be reinjected, can not be flared and isgeographically stranded from a market. Nevertheless, this study considers the offshore conversion ofnatural gas into easily transportable liquid methanol, gasoline, or diesel plus naphtha products.

By review of technical considerations and by comparison to the largest tankers and FPSO’s built to date,it is considered that the maximum practical size of conventional ship-shaped vessel for GTL applicationwould be about 54 meters wide by 375 meters long. Any size vessel would require special designconsiderations to have minimum wave motions resulting from wave forces and for optimum freeboard inboth loaded and unloaded conditions. It would also be desirable to have a higher than normal bow rise for

operation in the Jeanne d’Arc Basin to prevent unacceptable deck damage from “green water” and tominimize operational downtime. The vessel would require additional reinforcement for ice considerationsas is reported to have been done for the Terra Nova FPSO.

The selected maxmum size vessel can accommodate up to about 100,000 BOPD, 160,000 BPD of waterinjection, and four (4) GTL trains that would consume about 177 MMscfd for conversion to GTL

products. The GTL plant would produce about:

Methanol 6,000 TPD

Gasoline 21,100 BPD

F-T (Diesel / Naphtha) 18,100 BPD

A dedicated GTL vessel, without GOSP facilities, could accommodate 6 GTL trains and would consumeapproximately 266 MMscfd of natural gas for conversion to GTL products. This volume of gas would

produce about:

Methanol 9,000 TPD

Gasoline 31,650 BPD


One each of the above described vessels could be deployed as a hub, capable of consuming 443 MMscfdof natural gas. The vessels could also be located at two separate sites, one at a new development that

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required oil and gas handling equipment, and one at an existing development utilizing the gas that hadbeen previously injected.

4.4 Onshore CNG

For this concept, it is assumed that a pipeline has been selected to bring the gas onshore, and that excess

gas of approximately 490 MMscfd is available for transportation to markets in the U.S. or Nova Scotia.Onshore compression will consume approximately 2.0% of the inlet volume for fuel.

4.5 Onshore LNG

For this concept, it is assumed that a pipeline has been selected to bring the gas ashore, and that 490MMscfd of gas will be available at the plant fence for conversion into LNG. Since the LNG plant

consumes about 11% of the inlet gas as fuel, only about 89% of the inlet gas is converted to LNG. Someof the product would be used for revaporization of the LNG at the delivery point.

4.6 Onshore GTL

For this concept, it is assumed that a pipeline has been selected to bring the gas ashore, and that 490

MMscfd of gas are available for converting into liquids. There are no single existing plants of the sizerequired to convert these huge volumes of natural gas to either of the three products. For this reason, thestudy is based on multiples of nearly the largest state-of-the-art syngas trains for making the syngas to beconverted to liquids. Each train will consume 62.5 MMscfd. Eight trains would be used to consume 490

MMscfd. It is recognized that onshore plant design can be refined for greater thermal efficiencycompared to offshore plants. Credit is not taken for the increased efficiency for this study.

The eight train GTL plant would produce the following approximate volumes of products:

Methanol 16,500 TPD

Gasoline 58,100 BPD


For the onshore cases, the analyses will consider only the costs for the onshore facilities required afterdelivery of the gas by the pipeline. The cost of the F-T plant will reflect the approximate cost forecast by

Shell and ExxonMobil for a modernized plant using fluidized beds and slurry suspended catalysts.

4.7 Gas Processing

This analysis reviewed the costs and expected margins of gas processing, the factors that can impact theprocessing margins, like gas, oil and NGL prices; transportation; operating costs; plant efficiency; and

plant product recoveries.

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For this analysis, gas processing was not considered for offshore GTL on an FPSO, as there will not beenough space for the gas processing equipment and the gas can be utilized without extraction of NGL’s.For the same reasons, gas processing is considered unlikely for the offshore CNG and offshore LNGcases.

There is the possibility that the major gas reservoirs are retrograde reservoirs, requiring gas processingand gas cycling for a number of years, prior to blow-down. Otherwise, potentially valuable natural gasliquids and condensate would not be recovered, and gas deliverability could be impacted, depending onhow pronounced the liquid formation is around the wellbores. However, this is a reservoir managementissue that is beyond the scope of this study, but could dictate the manner in which the offshore gas is

produced and therefore impact the costs incurred to process and re-cycle the gas.

See Exhibit I for gas processing reviews.

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5. TECHNICAL FEASIBILITY ISSUES

5.1 Reliabili ty

Gas supply reliability is critical for the success of a natural gas industry. Reliability applies to each entityin the gas supply chain; producers, gas transporters, and the end-users. If the development is notconsidered reliable, with virtually no interruption in the gas supply, capital equity required to develop the

natural gas infrastructure may be very difficult to secure.

PROD UCER RELIABILIT Y

The producers must be able to deliver the agreed amount of gas for a specified period of time. AG(associated gas or solution gas) would be the most likely initial source of gas. However, as the AG

delivery rates decline, additional sources of gas must be ready and able to be delivered into theinfrastructure. If required, depending on cost and long term supply requirements, NAG (non-associatedgas) could provide “swing” volumes necessary to make up insufficient short term AG volumes.

GAS GATH ERER A ND TRAN SPORTE R RELIABILIT Y

The gas gatherer must likewise be able to receive gas from the producers at all times. If the gas gatherer

is unable to take possession of the gas for any reason, all NAG production would have to be shut-in, andthe AG would have to be flared while oil is produced. Otherwise, the oil wells would also have to beshut-in if flaring is not allowed. The producers may not tolerate frequent shut-ins.

END-USE R RELIABILIT Y

Similar to the gas transporter reliability issue above, if the end-users can not take delivery of theirallocated share of the gas, then the gas transporter must find an alternative use or costly storage for thegas to avoid forcing the producers to shut-in production.

GAS STOR AGE AN D SECU RITY O F SUPP LY

Gas storage will become a very important issue as it is very important to have flexibility in the gas supplychain. This is often times taken for granted in the oil supply chain, as oil developments have oil storage

available all along the supply chain. For example, at Hibernia there is storage in the GBS, there is storageat the Transshipment Terminal, and there is storage at the refineries. Without supply flexibility, nuisanceshutdowns may occur too often to be tolerated by the producer, gas transporter, and end-users. Theimportant thing to realize is that if any one entity has a problem, it will effect all other supply chain

entities, unless there is adequate supply flexibility.

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There are a several potential solutions to increase supply flexibility and thus improve gas supplyreliability:

• Gas reservoir storage

• Underground gas salt storage

• Peak-shaving NAG gas supply

• Line-pack

• Artificial Storage

If reservoir storage is available, either onshore or offshore, gas supply reliability is increasedtremendously. For example, if the end-user or transporter must shutdown, the operators can still continueto produce oil by injecting the associated gas instead of flaring or shutting in. Conversely, if the oilproduction is shut-in, the gas transporter and end-user can continue to operate by withdrawing gas fromstorage.

Salt dome storage is more commonly used when onshore. This is storage created by washing out a cavernwith fresh water deep underground, creating a void space that can be used for gas storage. Salt storage isin the planning stages at Point Tupper by Statia Terminals, and could be very useful in regards to use ofthe CNG concept. Salt storage is typically analogous with high deliverability and high injectioncapabilities. This would be ideal when offloading CNG vessels, whose instantaneous rate could be as

much as 1bcfd, which is probably more than a pipeline system or end-user could take. Aquifer reservoirsare also commonly used for gas storage, under the right conditions. Depending on the local geology, thismay or may not be an option for Newfoundland.

The same concepts apply with NAG gas, or what the authors like to refer as “swing gas”, “security ofsupply” or “back-up” gas. When onshore gas demand is reduced, gas from NAG sources can be reduced

with less financial consequences than from AG sources. Ample amounts of NAG gas can be producedwhen the AG gas volumes are low or depleted. In some cases, the NAG gas supply and gas storage canbe one and the same. The North White Rose reservoir may prove to be an ideal reservoir to provide forboth flexible delivery rates and variable gas injection rates. The Hibernia gas cap may also be well suited

to supplement AG volumes and to provide for gas injection when needed.

Line-pack is commonly associated with long pipelines. Typically, if the downstream users can not takedelivery of the gas, the pipeline operator can temporarily continue to take gas from producers byincreasing the pipeline pressure. This is considered “packing the line”, or “line pack”. Depending on theoperating conditions and parameters of the pipeline, this could provide from a couple of hours to as much

as a day of storage.

Artificial storage can be built using vessels, pipe, etc., similar to the CNG concept. A 500 MMscf storagefacility could help the producers stay on-line for a day or two when the end users can not take full

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delivery. Conversely, if the producer has scheduled downtime, the storage facility could be filled aheadof time, allowing the end-users to continue operations.

5.2 Technology Status Summary

FPSO HUB

An FPSO is being used as a hub in the North Sea on the Triton project. Three fields will be tied into anFPSO that can process 105,000 BOPD and 200 MMscfd. The vessel is located in 91 meters of water.and is positioned 20 km from the Bittern field and 12 km from the Guillemot West field. All productionis piped subsea to the FPSO. A gas pipeline to shore exists 12 km from the FPSO and is to be connected

to the FPSO via a 10-inch spur line. The vessel has 15 riser slots. The project has taken 3 _ years tocomplete.

The technical challenge is to limit the number of risers required. When one considers production lines,test lines, water injection, gas lift, gas injection, umbilicals, and gas export lines, the capacity of adisconnectable turret may be exceeded. Optimization of the subsea facilities and the turret design would

be required.

GRAV ITY BASE D STRU CTURE

There are no technical issues as this is proven technology based on the Hibernia GBS and about 15 otherstructures in the North Sea like Troll A GBS. However, water depth and iceberg size present significantsite-specific challenges that can not be taken lightly.

HIBE RNIA HUB

Adding gas risers to the Hibernia GBS is reported to be a concern, but the authors feel that a satisfactorysolution can be found.

COMP RESSED NATU RAL GAS

The CNG concept is an integration of various existing technologies for a new transport method.

Although this concept has not been utilized offshore, there are no other foreseeable technical reasonspreventing the concept to work except for the weight of the coselles, which is a concern. A 500 MMscfdship would contain 180 coselles, each weighting 445 tonnes. Including the weight of the pipingmanifolds, compression, fire and safety equipment, etc., the total weight of the equipment and coselles,

excluding the ship, will be in excess of 81,000 tonnes. The ability to dry dock a ship with this denseweight is a concern. Other means of inspection would have to be agreed with certification authoritiesprior to fabrication, which is a realistic expectation.

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OFFS HORE LNG

As with the coselle CNG carrier, the offshore LNG concept is a new way of bringing existingtechnologies together for a new solution. ExxonMobil has done a considerable amount of work todevelop the concept, both from a technology and a safety point of view, including LNG offloadingsystems. Several other companies are also active in developing new equipment for offshore LNG

offloading applications.

It is expected that a practical way can be established to safely avoid the threat of icebergs. Risers fromthe sea-bed to the floating structure must be able to be quickly disconnected as is planned for the TerraNova development.

OFFS HORE GTL

The processes for conversion of natural gas to synthesis gas then to methanol, gasoline, or a mixture ofdiesel and naphtha are very mature when using fixed catalyst beds.

Cost reducing methods using catalyst slurries have been proven onshore with the high possibility of beingproven for offshore applications very soon.

Offshore cryogenic separation of oxygen from air that is needed to prepare synthesis gas is reported byAir Products to be proven by model tests on floating vessel motion simulators. Similar methods can

probably be used for successful distillation of GTL products but model tests will be required. Analternative would be to transport the GTL products to an onshore location for distillation.

Floating structures to provide for lower wave induced motions, such as ExxonMobil’s LNG floater, andothers, are being proposed for maximizing production up-time leading to better economics.

OFFS HORE GAS PROC ESSING

Offshore gas processing has been done on several fixed platforms and on near-shore barges. However,the authors are not aware of gas processing being performed on an FPSO. There is one FPSO project thathas a debutanizer as part of the equipment to remove the heavier hydrocarbons from the gas prior toreinjection. A complete gas processing plant would require a deethanizer, and in some cases a

depropanizer. The existing debutanizer was proven for that service by model tests on a vessel motionsimulator.

Several companies are considering gas processing on FPSO’s, with the performance of the fractionationcolumns being a major concern in rough seas. However, if the fractionation column manufacturers willmake model tests and warrant the performance of their process vessels on an FPSO, then the major

obstacles will have been removed.

Producing a Y-grade product (i.e., a combined propane, butane and condensate liquid product underpressure) for fractionation at an onshore facility like Point Tupper may be more practical than offshore

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fractionation. Many such applications exist, including the 1.6 bcfd North Rankin platform to landfalloffshore the Northwest coast of Australia. The complexity issues with regards to offshore storage andoffloading of the various products, along with the performance of the columns, will drive these decisions.

SUBS EA DEVE LOPMEN TS

Due to the extreme ambient temperatures in the Jeanne d’Arc Basin, pipeline flow assurance andprevention of blockage in the flowlines due to hydrates and/or waxes is critical to the success of tie-backprojects. So long as fluid properties such as cloud point, pour point, etc., are known, it will be possible todesign the subsea facilities to minimize flow assurance problems, e.g., by a combination of insulation,chemical injection and routine pigging. For the purpose of this study, it has been assumed that all the

producing pipelines will be insulated and chemical injection facilities will be installed.

OTHE R FACT ORS

For producers to discontinue gas injection, the modifications required to reconfigure facilities andpossibly drill additional water injection wells can be a costly proposition if not planned for at the designstage.

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6. COST ANALYSIS SUMMARIES

For all cases, where applicable, the capital and operating costs include the “all-in” costs for a project. Inthis way the total costs to be incurred by the producers can be reviewed and established so that anaccurate economic analysis can be conducted in the future. The challenge in estimating total costs is thatthere are so many options to consider, such as:

• Floating vs. fixed facilities.

• Concrete vs. steel structures.

• Phased vs. all-at-once developments.

• Tie-back vs. stand-alone developments.

• Lease vs. purchase of facilities.

• Utilizing existing vs. new resources (i.e., helicopters, tugs, supply boats, transshipment, storage,etc.).

• Wet vs. dry wells.

• Flow assurance solutions.

The capital costs include:

• FPSO or GBS cost.

• Turret, mooring.

• Topsides.

• Shuttle tankers.

• Supply boats.

• Well costs; both “dry” and “wet” trees, glory holes, manifolds, etc.

• Subsea flowlines, pipelines, chemical injection, pigging, etc.

• Onshore berthing and equipment for CNG ship deliveries.

The operating costs include:

• FPSO/GBS operating: fixed, variable, logistics, staffing, etc.

• Shuttle tanker crew, fuel and maintenance.

• Supply boat crew, fuel and maintenance.

• Product transportation and storage.

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6.1 CNG Summary

The offshore CNG concepts considered three basic scenarios:

1. FPSO or GBS oil and gas development hub, delivering compressed gas to CNG carriers.

2. FPSO or GBS gas hub delivering compressed gas to CNG carriers.

3. Modifying the Hibernia GBS to be a gas hub, and delivering compressed gas to CNG carriers.

In each case, the offshore facility would furnish high pressure gas up to 3,000 psig to the CNG carriers fortransport to market.

The analysis was based on CNG ships being built, owned and operated by a third party. CNG shipcharter rates from offshore to the U.S. are estimated at C$36.43 million per ship per year. This equates to

a transportation fee of approximately C$1.27 per MMBtu.

The onshore CNG concept is based on a gas pipeline being built from the Grand Banks area toNewfoundland. Once the gas reaches Newfoundland, except for a portion of the gas that can be utilizedin Newfoundland, the excess gas would still be stranded and would require a means to be monitized.

For the onshore CNG concept an additional 2% of the inlet gas volume is used as fuel to compress the gasto 3,000 psig from an assumed pipeline delivery pressure of 750 psig. The CNG charter rates to the U.S.

would equate to a transportation fee of approximately C$1.09/MMBtu since only six ships would berequired.

A summary of the results of the Technical Feasibility are shown below:

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Table 6.1 Compressed Natural Gas (CNG) SummaryNote 1

OffshoreFPSO Oil

& GasHub

OffshoreFPSO

Gas Hub

OffshoreGBS Oil& GasHub

OffshoreGBS Gas

Hub

OffshoreHibernia

Hub

OnshoreCNGNote 2

Inlet Gas Capacity (MMscfd) 500 500 500 500 500 490

Oil/ Condensate Capacity(BOPD)

100,000 25,000 100,000 25,000 Existing None

Water Injection Capacity(BWPD)

160,000 None 160,000 None Upgraded None

Gas Processing Potential No Yes No Yes No Yes

Total CAPEX: (C$ MM) 4,583 3,308 4,716 3,570 2,578 297

Production OPEX Average(C$ MM/YR)

140.2 115 123.8 103 33.5 29.0

CNG Charter Rate(C$ MM/YR) for first 20 yrs

255 255 255 255 255 219

Gas Revenue(C$ MM/YR)

810 810 810 810 810 755

Liquid Revenue(C$ MM/YR)

393 121 393 121 121 0

Note 1: The above numbers do not include the costs of gas for feedstock.Note 2: The onshore CNG case does not include the cost for a pipeline to shore.

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6.2 Liquefied Natural Gas

ONSH ORE

The onshore LNG concept is based on the possibility of a gas pipeline being built from the Grand Banksarea to Newfoundland. However, except for a portion of the gas being utilized in Newfoundland, theexcess gas will still be stranded, and will require a means for monitization. This Onshore LNG optionevaluates a method of transporting the excess gas from Newfoundland to markets in the northeast U.S. or

to other economic markets.

OFFS HORE

The offshore LNG concept is based on the assumption that an FPSO or GBS can be replaced with anintegrated floating concrete LNG plant, pioneered by ExxonMobil for applications in Southeast Asia and

Australia. The floating LNG concept was considered to withstand typhoon environments and to handlefeed rates ranging from 500 MMscfd up to 1,750 MMscfd. The major focus and detail design was for a1,000 MMscfd size facility.

This analysis assumes a transportation and regasification cost of C$ 0.65/MMBtu (Based on the ICFmarket report titled “A Market Analysis of Natural Gas Resources Offshore Newfoundland”, page 47) to

markets in the Northeastern U.S. This is also based on the current spare capacity of LNG transportationand regasification facilities. However, as increasing world-wide LNG developments come onstream,surplus transportation and regasification capacity may disappear, resulting in increased transportationcosts.

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Table 6.2 Liquefied Natural Gas (LNG) Summary

Offshore LNG Onshore LNG

Inlet Gas Capacity(MMscfd)

500 MMscfd 490 MMscfd

Inlet Condensate / OilCapacity (BCPD)

100,000 None

Gas ProcessingPotential

Yes Yes

CAPEX(C$ MM)

6,030 1,553

LNG Plant OPEX(C$ C/YR)

162 65

LNG Transportation(C$ C/YR)

176 141

Gas Revenue($C MM/YR)

721 693

Liquid Revenue($C MM/YR)

393 0

Note: The above numbers do not include the cost of gas for feedstock. LNG plants consume approximately 11% of the inlet gasas fuel. This is reflected in the revenue streams above.

6.3 Onshore Gas-to-Liquids

The basis for sizing the inlet gas rate to the Methanol plant was the largest single ATR syngas train builtto date, which is for 2,400 tonnes per day of methanol. Thus, eight (8) near full size trains would berequired to process 490 MMscfd of inlet gas. The same number of trains would be required for the MTG(via TIGAS) process. The syngas portion of a Fischer Tropsch would be the same as for a methanol or

gasoline product.

The total Fischer Tropsch plant cost is assumed to be the current projected cost of US$ 30,000 per bbl/dayplant capacity, plus adjustments for construction camps, labor rates, and winterization of the plant beinglocated in a cold environment. The plant would use the latest fluidized bed and/or slurry catalyst contactreformers/synthesis process vessels as has been proven primarily by ExxonMobil, Shell and Sasol. These

technologies can be used onshore where there is no motion and where very heavy and tall process vesselscan be handled.

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Although it is recognized that the methanol and TIGAS/MTG processes can also benefit from the same orsimilar technologies, especially in producing syngas, they were not considered for this study. Thedecision resulted from the fact that no one is known to be proposing their use for methanol andTIGAS/MTG and no published or private plant costs are available for this analysis except for reference to

reported CAPEX in US$ per Bbl of product for Fischer Tropsch plants.

Table 6.3 is based on available technical and cost data from prior studies where the feed gas and grossheating value was 1,288 BU/ft3. This is greater than for Jeanne d’Arc gases. The data was modified toreflect the reported values for the average 1,117 BTU/ft3 quality gas reported for the Jeanne d’Arc Basingas. Adjustments to plant feed gas volumes would be required for each significant change in the heating

value of feed gases from Jeanne d’Arc reservoirs in order to maintain the design product volumes.

Onshore GTL plants require less fuel gas than offshore plants. This results from a need to simplifyequipment, operations and maintenance on a crowded and sometimes violently moving FPSO vessel. Useof fuel to drive compressors and generate electricity for electric motors on FPSO vessels is much saferthan the use of waste heat to generate and use steam at the many required locations as is common practice

onshore. The increased use of fuel offshore is normally of less concern because the stranded gas has alow or negative value when the alternative is to reinject this gas at a cost.

The use of high BTU/ft3 feed gas is less efficient from the standpoint of BTU/tonne of product. Thisresults from the fact that a pre-reformer is used to convert C2 and heavier gases to C1 and CO2 in order to

prevent soot from forming on the catalyst.

The best BTU conversion efficiencies result when most of the C3 and heavier components are removed bygas processing prior to the feed gas entering the syngas production equipment.

If gas processing were performed upstream of the GTL plant, only seven trains would be required for themethanol and MTG plants due to the “Btu shrinkage” of approximately twelve percent (12%).

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Table 6.3 Onshore Gas-to-Liquids Summary

OnshoreMethanol

Onshore MTG Onshore F-T

Inlet Gas Rate(MMscfd)

490 490 490

CAPEX GTLPlant(C$ MM)

2,186 2,990 2,494

OPEX:GTL Plant(C$ MM/YR)

67 101 75

Product Rate Design 16,500 TPD 58,100 BPD 49,700 BPD

Product Selling Price(2005)

C$ 171/tonne C$ 27/bbl C$ 30/bbl

Equivalent Value on aBtu Basis

C$ 7.97/MMBtu C$ 5.29/MMBtu C$ 5.56/MMBtu

Revenue Average (C$MM/Yr)

944 549 539

Note: The above numbers do not include the cost of gas for feedstock.

6.4 Offshore Gas-to-Liquids

The offshore GTL gas rates are limited by the size and weight of equipment that can be placed on anFPSO and then operate in all but the most severe sea states. For the GOSP / GTL (gas oil separation plant

/ gas-to-liquids plant) cases, it is has been established that four methanol trains, each with a capacity of1,500 tonnes per day, can be placed on an FPSO that also contains oil and gas separation equipment. Thisequates to three trains of MTG or three F-T trains. It has also been established that an FPSO without thegas/oil separation plant can have sufficient plot area for six methanol trains, six MTG trains or six F-T

trains. The GOSP facilities can process 100,000 BOPD and inject 160,000 BWPD.

The offshore GTL FPSO case (Table 6.5) is based on six trains of 1500 tonne/day methanol product formethanol and TIGAS/MTG. The F-T plant would use the same volume of syngas as for a six trainmethanol plant.

The GOSP/GTL FPSO includes the costs for all production and injection wells, subsea costs, two shuttle

tankers and a supply boat.

Tables 6.4 and 6.5 CAPEX values are based on a more rich-feed gas than exists in the Jeanne d’ArcBasin. Adjustments were made to account for the lower BTU/ft3 gas from Jeanne d’Arc fields. Volumes

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of feed gas would have to be adjusted to maintain design product volumes as the BTU/ft3 values vary.The data has been adjusted for 1117 Btu/scf of gas and includes the decreased efficiency effect of havingsignificant C3 and heavier gases and the choice of using more fuel gas instead of generating and usingsteam in an offshore environment.

Table 6.4 Offshore GOSP / GTL FPSO (4 Trains)

OffshoreMethanol

Offshore MTG Offshore F-T


177 177 177

CAPEX Note 3

(C$ MM)1744 2268 1601

OPEX(C$ MM /Year)

33.6 43.8 38.4

GTL Production 6,000 Tonnes/Day 21,100 Bbls/Day Note 1 18,100 BPD

Product Selling Price (2005) C$ 171/Tonne C$ 27/Bbl C$ 30/Bbl

Equivalent Value on a BTU Basis C$ 7.97/MMBtu C$ 5.29/MMBtu C$ 5.56/MMBtu

GTL Revenue(C$ MM/YR)

359 199 190

Oil Revenue(C$ MM/YR)

700 Note 2 700 Note 2 700 Nte 2

Note 1: With light ends and LPG used as fuel gas.Note 2: First six (6) years average.Note 3: Does not include well costs and subsea pipeline/equipment costs.

The GTL FPSO does not include CAPEX costs for wells, shuttle tankers or supply boats. It is assumedthat the oil development has paid for these and that only a share of the OPEX for the shuttle tankers andsupply boats are incurred.

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Table 6.5 Offshore GTL FPSO (6 Trains)

Offshore Methanol Offshore MTG Offshore F-T


266 266 266

CAPEX Note 4

(C$ MM)1,835 2,616 1,619

OPEX(C$ MM /Year)

33.6Note 2 43.8 38.4

GTL Production 9,000 Tonnes/Day 31,650 Bbls/Day Note 1 27,150BPD

Product Selling Price (2005) C$ 171/Tonne Note 3 C$ 27/Bbl C$ 30.59/Bbl

Equivalent Value on a Btu Basis C$ 7.97/MMBtu C$ 5.29/MMBtu C$ 5.56/MMBtu

Revenue Average – GTL(C$ MM /Year)

539 303 313

Note 1: With light ends and LPG used as fuel..

Note 2: Does not include C$24.25 /tonne for methanol transportation to U.S. Gulf Coast markets.

Note 3: Based on U.S. Gulf Coast long term contract prices.

Note 4: Does not include well costs or subsea pipeline/equipment costs.

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7. CONVERSION FACTORS

C $ = US$ 0.70

1 MMscf = 1,117 MMBtu

1 cubic foot = 1,117 Btu

29.6 MMBtu = 1 tonne methanol (excluding fuel)

10 MMBtu = 1 barrel F-T product (including fuel)

8.42 MMBtu = 1 barrel MTG product (excluding fuel)

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8. GLOSSARY OF TERMS

AG Associated Gas, sometimes referred to as “solution gas”

ATR Autothermal Reformer

Bbl Barrel

BBtu Billion British thermal units

Bcf Billion cubic feet

Bcf/yr Billion cubic feet per year

Btu British thermal unit

BOE Barrel of Oil Equivalent

BPD Barrels per day

cf cubic feet

C$ Canadian dollar

º C degrees Centigrade

CAPEX Capital expenditures

C-NOPB Canada-Newfoundland Offshore Petroleum Board

d day

DME Dimethylene

EIA Energy Information Administration

FPSO Floating production, storage and offloading vessel

F-T Fischer-Tropsch

GJ Gigajoule

GOSP Gas/Oil Separation Plant

GPM Gallons of Natural Gas Liquids per Mcf

GTL Gas-to-Liquids

GW Gigawatts

Henry Hub A location in South Louisiana where a number of natural gas pipelines converge

ICF ICF Resources Incorporated

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kWh Kilowatt hour

LNG Liquefied Natural Gas

LPG Liquefied Petroleum Gas – propane and butane

MFPSO Methanol floating production, storage and offloading vessel

MM Million

MMcf Million cubic feet

MMscfd Million standard cubic feet per day

MMBtu Million British thermal units

MMBtu/d Million British thermal units per day

MT Metric Ton

MTG Methanol to gasoline

MW Megawatts

NA Not Available

NAG Non-Associated Gas (not associated with oil production)

NGL Natural Gas Liquids – ethane, propane, butane and pentane plus

OPEX Operating expense

Offshore Nova Scotia Sable Island, Laurentian Sub Basin and the deepwater plays

SMR Steam methane reforming

Tcf Trillion cubic feet

US$ U.S. Dollar

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technical nonpipeline final.doc Page EI - 1 065/07129 : Rev 5 : 7-Dec-00

Exhibit I

Gas Processing

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1.0 GAS PROC ESSING

Gas processing margins were evaluated based on the following assumptions:

Parameter Assumption

Gas Price : Varied from US $0.0 to $3.00 per MMBtu’s

Oil Price : Varied from US $15 to $30 per barrel

Propane Price : Based on 75% of oil price

Butanes Price : Based on 85% of oil price

Pentanes Plus Price : Based on 92% of oil price

Plant Fuel Consumption : 1.5% of inlet gas volume

LPG Transportation Costs : 4 cents per gallon

Operating Costs : Based on 3 cents per inlet MCF

Ethane Recovery : None

Propane Recovery : 95%

Butanes Plus Recovery : 99.5%

Gas Composition : 1116.7 Btu/scf based primarily on White Rose – Ben Nevis Gas CapN-22

All of these assumptions have an effect on processing margins. The gas processing margin is thedifference between the value of the inlet BTU’s compared to the value of plant liquids and the residue

gas. In this study the value of the gas was varied from US$0.00 - $3.00/MMBtu, with a constant oil priceof $US 19.60/bbl to demonstrate the effect that gas pricing has on the processing margin. The results,based on an inlet plant volume of 500 MMscfd are as follows:

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Table EI.1 Effect of Gas Pricing on Processing Margin

Gas Price(US$/MMBtu)

Processing Margin(US$/MCF)

Annual Revenue(US$ MM)

0.0 0.429 78.2

1.0 0.279 51.0

2.0 0.13 23.7

3.0 -0.019 -3.5

As can be easily seen, the higher the value of the gas, the lower the gas processing margin. Similarly, theoil price has a dramatic effect on processing margins. Based on the same assumptions above, except tovary the oil price (i.e., varying the LPG prices) and holding the value of the gas constant atUS$2/MMBtu, the processing margins vary as follows:

Table EI.2 Effect of Oil Pricing on Processing Margin

Oil Price(US$/Bbl)

Processing Margin(US$/MCF)

Annual Revenue(US$ MM)

15 0.01 1.8

20 0.141 25.7

25 0.271 49.5

30 0.402 73.4

Sensitivities can be run on the many variables to see the effect they have on processing margins. Forexample, plant fuel consumption may be as high as 3.0% of the plant inlet, operating costs could be 4

cents per inlet MCF (Sable plant OPEX is 3.8 cents/Mcf), and LPG transportation may be as high as 5cents per gallon. If these three variables are realized, it could result in increased annual costs of US$ 10.2MM/yr.

Another very important variable is the gas composition. In comparison to the Sable gas compositions(SOEP website) the White Rose compositions are very similar. However, if the inlet gas stream is more

like Terra Nova, which has a Btu value of 1263 Btu/scf, the additional plant profit (based on $19.60/bbloil price and $2.00/MMbtu gas price) is approximately US$ 39 MM/yr.

Normally, all but two of the variables can usually be fixed, controlled or contractually agreed to at thebeginning of a project. The two variables that typically can not be controlled are the gas price and the

liquid prices, which are dictated by the market.

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technical nonpipeline final.doc Page EII - 1 065/07129 : Rev 5 : 7-Dec-00

Exhibit II

Offshore CNG

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Offshore Compressed Natural Gas

1.0 OVER VIEW

For the Compressed Natural Gas (CNG) concept, the development scenarios considered for theJeanne d’Arc Basis are as follows:

• Combined Gas/Oil Hub

There is substantial merit for considering an oil and gas hub in the Jeanne d’Arc Basin.From a technical standpoint, either a GBS or FPSO could provide the means for this type of

development.

This facility would gather available oil and gas from the various fields in the Jeanne d’ArcBasin, and process the production to make them suitable for export to refinery’s and naturalgas markets. Services such as field operations, gas processing, gas reinjection / gas storage

could all be provided. This type of infrastructure could allow the smaller fields which mightotherwise be uneconomic, to become viable projects in the future.

For this analysis, the hub facility would be capable of handling 100,000 BOPD, injection of160,000 BWPD, and gas injection compression for 250 MMscfd (up to 5,600 psig) and gassales compression for 500 MMscfd (up to 3,000 psig).

• Gas Hub

Similar to the Gas/Oil Hub mentioned above, either a strategically located GBS or FPSOcould be a hub for gathering only natural gas and/or gas condensate, with the option ofproviding gas processing.

• Existing GBS Hub

There is the possibility that Hibernia could make the necessary modifications that wouldallow this facility to gather natural gas from other developments in the Jeanne d’Arc Basin.

This would require rigorous evaluations and studies to determine if this is possible, and whenit would be possible. Hibernia may not be ready to make modifications until 2010 or later.

• CNG Carriers

This analysis was based upon the Cran and Stenning Coselle CNG concept. Other optionsare Lorica’s Composite Fiber Vessel concept which has the advantage of significant weightsavings, and the SMT dense phase concept.

The Coselle CNG carrier is essentially a double-hulled bulk carrier with its holds filled with“Coselles”. A Coselle is a huge carousel made up of 9.9 miles of 6.625-inch diameter pipe,

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rolled up in the shape of a compact cylinder. Each Coselle has a diameter of 50 feet , aheight of 11.25 feet and weighs 445 tonnes.

A Coselle CNG carrier capable of transporting 330 MMscf of gas would require 108Coselles loaded into a Panamax (60,000 DWT) sized ship. This is the size of carrier onwhich Cran and Stenning have conducted most of their detailed work.

A CNG carrier capable of transporting 540 MMscf of gas would require 180 Coselles and avessel of approximately 100,000 DWT would be required.

2.0 PROD UCTION PROF ILE

2.1 THRE SHOLD VOLU ME OF GAS AND GAS LIQU IDS

The production profile indicates that daily production of approximately 500 MMscfd can beexpected for the next 15 to 20 years.

In addition, the CNG carrier concept may be reaching its practical upper limit capacity of 180Coselles, or 540 MMscfd per carrier, in a 100,000 DWT vessel. Theoretically, the CNG carriercould be installed on a larger 200,000 DWT vessel, but no work has been done on anything ofthis size, and the dry weight of such a vessel would be a major concern.

2.2 GAS QUAL ITY

The gas quality is of little concern to the CNG carrier. The richer and cooler (i.e., denser) thegas the better as far as the amount of BTU’s the CNG carrier can transport. However, qualityof the gas is very important to the gas purchaser. If the gas is being sold into a pipeline grid,there are possible restrictions on the quality of gas. Typically the gas must meet the following

minimum requirements:

Maximum BTU/scf < 1,180, but many pipelines do not stipulate

Minimum BTU/scf > 975

Water Content < 7 lbs/Mcf

CO2 Content < 2%

H2S Content < 4 ppm or 1/4 grain

N2 < 3%

O2 < 0.1%

The dehydrated NF gas would seem to have no problems meeting the gas quality specifications

for most pipelines and transmission lines. The NF gas is sweet (i.e., virtually no H2S and low

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CO2) and has low nitrogen and oxygen content. With possible gas processing upstream of theCNG loading facilities, this gas will be ideal for export into virtually any gas market.

2.3 GAS VS. OIL PROD UCTION RATE S

Based on production profiles from the Jeanne d’Arc Basins, the gas rates of approximately 500MMscfd are expected, with corresponding oil and condensate production rates up to

approximately 92,000 barrels per day based on a simultaneous oil and gas development. Theserates were based on recoverable reserve and GOR (gas to oil ratio) estimates published by theC-NOPB with the production profile estimated by Worley in lieu of no other forecasts beingavailable. This excludes oil and condensate production from Hibernia, Terra Nova, Hebron,

and other developments with little or no estimated gas reserves.

For this study, only the liquid production associated from wells tied back to the “hub”, and notpart of a main oil development, will be credited towards the economics.

3.0 TYPE OF PROD UCTION SYST EM

Either a fixed gravity-based structure (GBS) or a floating production, storage and offloading

vessel (FPSO) could be used for the development of natural gas, offshore Newfoundland.Precedence has been made with both options, although the use of FPSO’s as hubs is limited.The most recent FPSO “hub” project is the Triton FPSO that is nearing completion in the NorthSea. Three (3) fields approximately 35 kilometers apart will be processed at a centrally located

FPSO, with gas sales via a 12 kilometer export line to a main gas trunkline.

In addition to the options for a new FPSO or GBS, there is potential to use the Hibernia GBS asa natural gas hub. Extensive modifications would have to be made, and there has been little, ifany, work done to determine the extent of the modifications, or when the modifications couldstart taking place. An estimate has been made for the cost of the modifications, but without

further work this cannot be confirmed.

The CNG carrier concept is based on an APL (Advanced Production and Loading AS, Norway)STL mooring system. The CNG ships are proposed to be equipped with dynamic positioningsuitable for EC operations.

In addition, the CNG vessels do have the flexibility to be deployed to other locations offshoreNF or around the world. Dual mooring systems at each site would be required to provide

continuous production.

4.0 PROC ESSING REQU IREMEN TS

The need for gas processing is based on either (1) gas quality specifications required by the gaspurchaser, (2) the economic benefits of recovering the ethane, propane, butanes and condensate

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from the gas, or (3) the need to process a retrograde reservoir. Since the NF gas, afterdehydration, is pipeline quality, the only reason for gas processing is for economic benefits orretrograde processing.

Based on the ICF market report titled “A Market Analysis of Natural Gas Resources OffshoreNewfoundland” (Page 30 and Table 3.3-1) indicating that gas is valued around C$ 4.00 per

MMBtu in the Northeast U.S., and that crude oil prices reach C$ 26.71/bbl, a “net” processingmargin loss of C$ 0.001 /MCF would be realized. This margin would not be enough to justifya gas processing facility.

If the gas were valued at C$ 0.0 (i.e., had no value) the net processing margin would be in the

range of C$ 0.56/MCF.

4.1 FPSO GAS PROC ESSING

Offshore gas processing has been done on several fixed platforms and near-shore barges.However, the authors are not aware of gas processing being performed on an FPSO. There isone FPSO project that has a debutanizer to remove the heavier hydrocarbons in the gas prior to

reinjection, but this is only a small part of a complete gas processing plant.

Several companies are considering gas processing on FPSO’s, with the performance of thefractionation columns being a major concern in rough seas. However, if the fractionationcolumn manufacturers will warrant their performance on an FPSO, then the major obstacleswill have been removed.

Producing a Y-grade product (i.e., a combined propane, butane and condensate liquid product)for fractionation at an onshore facility like Point Tupper may be more practical than offshorefractionation. The complexity issues with regards to storage of the various products, offloadingvarious products, along with the performance of the columns, will drive this decision.

4.2 FIXE D STRU CTURES

Gas processing on fixed structures can be done, provided there is enough deck space for the gasplant and storage for the LPG.

4.3 ONSH ORE GAS PROC ESSING

Onshore gas processing, based on offloading the CNG carriers and then processing the gas priorto delivery of gas into a pipeline grid, will not be practical, unless offloading into a gas storage

facility. The reason for this is to minimize the number of ships required by depressurizing theCNG carriers as quickly as possible, possibly in as little time as 12 hours. In many instances,there may not be a full CNG carrier to immediately succeed behind an empty one. Thus, flow

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rate variations of 0 – 1,000 MMscfd could be common place. These “batch” operations wouldmake gas plant operations impractical.

5.0 TRAN SPORTA TION MODE S

Each CNG ship would have a cruising speed of 15.5 knots. The distance from the Grand Banksto Boston is approximately 955 nautical miles. Thus, it takes 2.5 days to travel each way, and it

takes 24 hours to load a ship, and 12 hours to off-load.

The analysis assumed that the CNG carriers would take the gas directly to the Northeast U.S.Thus, this case would require seven ships and receive a gas price of approximately C$4.00/MMBtu’s. This would result in a CNG charter rate (i.e., transportation) of C$ 255

MM/year, which equates to approximately C$ 1.27/MMBtu’s.

If an eighth ship is required, the charter rate would increase to approximately C$ 1.57/MMBtu.

Another option is to supply NF with gas. One additional ship would be required initially,supplying gas to the North Atlantic Refinery at approximately 50,000 MMBtu/d. This wouldrequire approximately 11 days to de-pressure a CNG ship, assuming there is no gas storage.This would result in a transportation cost of approximately C$ 2.00 /MMBtu for the extra CNG

ship required to supply gas to the refinery. However, this cost would come down with thegrowth of a gas industry. In addition, if gas storage was available, the transportation cost couldfall to C$ 1.27/MMBtu’s. Since there is no known salt or reservoir storage nearby the PlacentiaBay, ground storage would have to be built.

Another alternative would be to deliver the gas to Nova Scotia into the Maritimes and NortheastPipeline, for transport to markets in Canada and the northeast U.S. The distance from theGrand Banks area to Point Tupper is approximately 625 miles, requiring only five (5) ships,and lowering the transportation cost to C$ 0.91/MMBtu’s. Of interest is the possibility of gasstorage being available in Point Tupper by Statia Terminals. Gas storage bundled with firm gas

capacity through the Maritimes and Northeast Pipeline stakeholders could be an attractivealternative to landing gas in the U.S.

5.1 NEWF OUNDLA ND GAS SUPP LY

The NF gas market would demand a reliable fuel gas supply, capable of handling load swingsthroughout the day and night. With an estimated average residential, commercial, industrial,

and electric utility load of approximately 100 MMscfd (ICF market report titled “A MarketAnalysis of Natural Gas Resources Offshore Newfoundland” (page 2)) by 2010, it would takeeach ship approximately five days to completely deliver its gas supply.

If gas storage is available, the gas could be off-loaded in 12 hours, dramatically increasing the

utility of the CNG ships, and increasing the reliability of supply to the natural gas consumers.

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5.2 U.S. GAS SUPP LY

The CNG deliveries to the U.S. can be accommodated in several ways. CNG deliveries couldbe handled much like LNG deliveries, either into the U.S. pipeline grid or into “niche” markets,depending on what kind of sales contracts can be negotiated. However, due to the approximate1,100-mile distance from the Grand Banks to the U.S. markets, it is not possible to deliver gas

at a constant rate, or supply gas on a peaking basis, without gas storage or more CNG vessels.The gas will most likely have to be “batch” delivered to unload each ship as fast as possible inorder to minimize the “turnaround” time and thus minimize the number of ships required.

If ships are detained and can not return to the Grand Banks on a seven day turnaround, either

additional ships will be required, or the produced gas will have to be flared, shut-in, or re-injected (the cost estimates provide for gas reinjection capability).

6.0 NEWF OUNDLA ND INFR ASTRUC TURE REQU IREMEN TS

There are two potential locations that may be suitable in Placentia Bay for a gas development.Both are in the general vicinity of the Newfoundland Transshipment Facility and North Atlantic

Refining.

Adams Head is a deep water site that was initially scheduled to be the site for construction ofthe Gravity Based Structure for Hibernia. As such, it would have the same generalcharacteristic as Bull Arm. Rough grading of this site would probably cost in the order ofC$150,000 per acre. An approximate 50 acre site would be required.

Argentia is an abandoned former U.S. Naval Base. This site is a large, generally level site. Itwould not require a lot of grading prior to development.

To create a gas market in Newfoundland, both industrial and residential, a pipeline anddistribution network would have to be installed to the main users. In addition, homes andbusinesses would have to be modified to receive natural gas and appliances replaced that can

burn the natural gas. These costs have not been considered.

7.0 COST ING

7.1 CAPITAL EXPE NSE (CAPEX)

For each of the three production options, Capital Cost (CAPEX) estimates were prepared. Forthe “oil and gas” hub options, it was assumed that two new shuttle tankers and two new supply

boats would be required. However, for the “gas only” hub options, it was assumed that existingfield shuttle tankers were available nearby, and that the gas projects would only share in aportion of those operating expenses (OPEX).

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Well costs were included for both the “oil and gas” hub and “gas only” hub options. For the“oil and gas” hub cases, all wells from a primary development (16 producers and 8 injectors),plus fourteen (14) well tie-backs from satellite fields like Springdale (4 producers), Ben Nevis(2 producers), North Ben Nevis (2 producers), North Dana (4 producers), and South Mara (2

producers) were included. Six (6) of the primary development wells are assumed to be from thenon-associated gas (NAG) reservoir. This gas would be the “swing” gas, necessary to make-upfor the difference between the solution gas from oil wells and the 500 MMscfd required fieldrate. In addition, it was assumed that the NAG gas wells could be used for gas injection when

required to keep the oil well gas from being flared during periods when gas exports werecurtailed.

For the “gas only” hub, the assumption was made that a GBS or FPSO would be located nearthe gas field, and only 6 additional gas wells were included in the well costs, plus the fourteen(14) gas wells from fields like Springdale , Ben Nevis, North Ben Nevis, North Dana, and

South Mara as mentioned above. As mentioned earlier, the gas wells will provide “swing” gasto make-up for the difference between the solution gas from oil wells and the 500 MMscfdrequired field rate, and can also be used for gas injection.

It was assumed that the gas wells from Springdale, Ben Nevis, North Ben Nevis, North Dana,and South Mara could be completed subsea and would produce at a high enough pressure to be

flowed back to either the GBS or FPSO for handling. Costs for these remote wells wereestimated to be C$51.4 MM each, based on the fact that there is not the same synergy asdrilling many wells in a major oil and gas field.

Wells drilled from a GBS were considered “dry wells”, with estimated costs of C$18 MM each.

Estimated costs to drill a “wet” well, at a primary development for an FPSO were estimated atC$36 MM each.

An additional C$120MM was included in the FPSO Oil and Gas case to account for the costs ofa turret or system capable of accommodating the high number of risers required.

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• FPSO Gas Hub

Gas Hub FPSO, turret, mooring, etc. : C$ 671,400,000

Well Costs (From various fields) : C$ 936,000,000

CNG Vessels (7) : C$ Chartered

Subsea Costs (flowlines, glory holes, etc.) : C$ 907,500,000

Topsides Equipment : C$ 550,500,000

CNG Mooring, Offloading Berths, etc. : C$ 172,900,000

Supply Boats : C$ 70,000,000

Total : C$ 3,308,300,000

• FPSO Oil and Gas Hub

Oil and Gas FPSO, turret, mooring, etc. : C$ 671,400,000

Well Costs (From various fields) : C$ 1,536,000,000


Subsea Costs (flowlines, glory holes, etc.) : C$ 1,140,700,000



Shuttle Tankers : C$ 230,000,000


Total : C$ 4,582,500,000

• New GBS Gas Hub

GBS Structure : C$ 927,100,000

Well Costs (From various fields) : C$ 874,300,000


Subsea Costs (flowlines, umbilicals, etc.) : C$ 810,200,000




Total : C$ 3,570,200,000

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• New GBS Oil and Gas Hub

Oil and Gas GBS : C$ 927,100,000

Well Costs (From various fields) : C$ 1,236,000,000


Subsea Costs (flowlines, glory holes, etc.) : C$ 1,140,700,000





Total : C$ 4,716,200,000

7.2 OPER ATING EXPE NSE (OPEX)

The OPEX for the various options are based on operating costs for Sable, Terra Nova andHibernia as reported on the project websites, and based on other projects that Worley has beeninvolved with. These costs do not include the value of any gas consumed as fuel.

The OPEX for an FPSO and a GBS is assumed to be about the same, except for the marinecrew and well intervention costs. The “dry” wells are less expensive to workover than “wet”wells.

Well intervention costs for subsea wells are estimated based on a rig with a rate of C$ 400,000per day. For the “gas hub” cases, 30 days per year were assumed for well intervention work.For the “oil and gas hub” cases, it was assumed that well intervention work would be required

60 days per year due to the higher number of wells.

For the new GBS, approximately half of the wells are assumed to be dry and can be workedover by a platform rig. The costs allocated to well intervention are therefore only for theworkover of the subsea gas wells and is assumed to be 15 days per year.

The CNG Charter Party rates of C$36.43 MM/yr were furnished by Cran and Stenning, whoobtained their estimates from Maersk, and were verified by calculating the unit cost based on an8% financing rate. The charter party rate was based on (1) CNG ship cost estimates of C$267MM each, and (2) annual operating costs for each ship estimated to be C$4.96 MM, assuming aCanadian crew, based on LPG ship operating costs.

A possible 25% duty was not considered in the economics.

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• FPSO Gas Hub (average yearly OPEX)

FPSO : C$ 48.8 MM/yr

Shuttle Tankers : C$ 13.9 MM/yr

Supply Boat : C$ 14.6 MM/yr

Transshipment Terminal : C$ 2.4 MM/yr

CNG Charter Rate : C$ 232.5 MM/yr

Well Workover Estimate Average : C$ 15.8 MM/yr

CNG U.S. Delivery Cost(C$0.10/MMBtu)

: C$ 19.8 MM/yr

Total : C$ 347.8 MM/yr

• FPSO Oil and Gas Hub (average yearly OPEX)

FPSO : C$ 51.1 MM/yr







: C$ 19.8 MM/yr


• GBS Gas Hub

GBS : C$ 44.6 MM/yr






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: C$ 19.8 MM/yr


• GBS Oil and Gas Hub (average yearly OPEX)

GBS : C$ 46.7 MM/yr







: C$ 19.8 MM/yr


7.3 ANNU AL EMPL OYMENT

• CNG Carrier

Each carrier would require a crew of 20, so that on an annual basis, 40 people would berequired. Considering the need for seven ships plus administration, the CNG Carrieroperation would require a staff of around 300.

In addition, service requirements for maintenance, catering, tugs, and the like would havea cascade effect on personnel required.

• FPSO Operation

FPSO: The marine crew is estimated at 40 employees on an annual basis. Oil and gasoperations and catering is estimated at another 70 annual employees.

Shuttle Tankers: For the cases that require shuttle tankers, an estimated 80 employeeswould be required to man the two (2) shuttle tankers on an annual basis.

Supply Vessel: An estimated 48 employees would be required to man the two supplyvessels on an annual basis.

Support Staff: Management staff, secretarial, accounting, procurement, engineeringsupport, etc. would be estimated at 25 annual employees.

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Drilling, Workover, Production Operations: Unknown

• GBS Operation

GBS: Production operations and catering is estimated at 60 annual employees.

Shuttle Tankers: For the cases that require shuttle tankers, an estimated 80 employeeswould be required to man the two (2) shuttle tankers on an annual basis.

Supply Vessel: An estimated 48 employees would be required to man the two (2) supplyvessels on an annual basis.

Support Staff: Management staff, secretarial, accounting, procurement, engineeringsupport, etc. would be estimated at 25 annual employees.

• Gas Plant Operations

If a gas plant were justified, an estimated additional 20 annual employees would beexpected for operations.

7.4 CAPT URE RATE S

• Vessels: FPSO, Shuttle Tankers, CNG Vessels, Supply boats

The ships would most likely be built in Asia, as they seem to be the most competitive shipbuilders in the world.

However, the authors feel that Bull Arm modifications could be made that would allow theconstruction of several vessels to occur. An investment of C$100 MM or more would berequired, but the long term payoffs could be well worth the investment if numerous new

ships were to be required for offshore, and hat they could be built competitively.

The smaller ships could be built at Irving Shipbuilding, if they were competitive.

• GBS Construction

The GBS could be built at Bull Arm.

• Topsides Equipment

Most of the topsides equipment could be built at Bull Arm.

• CNG Coselles or Composite Vessels

The coselles would most likely be fabricated near the pipe manufacturers, but could be builtin Newfoundland at a slight cost premium. Cran and Stenning estimated that Canadian

fabrication of the Coselles would add approximately 20% to the cost of each CNG carrier

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If composite vessels were utilized, a new facility would have to be built capable ofproducing large quantities of vessels. This facility could be built at Bull Arm or otherlocations in Newfoundland.

8.0 TECH NOLOGY STAT US

8.1 CNG CARR IERS

The technology is patented and has tremendous potential for worldwide commercialapplication. However, there is no commercial application to date. This concept applies existingtechnology in a new and creative way. The technology involved is basically the same as onewould find on a FPSO and a pipeline. The high-pressure swivels, flexible pipe, quick connects,

etc. all have been designed and are commercially available.

The design of a CNG carrier is relatively “low tech”. Cran and Stenning have had DNV andABS examine the concept. DNV, who carried out the safety study, concluded that “a (Coselle)CNG ship is at least as safe as other gas ships” and can be classed and allowed to trade as othergas ships (i.e., LNG and LPG). ABS provided the classification guidelines for the vessel,

which means that the Coselle CNG ship can be classed and registered as an ABA A1 E “GasCarrier”.

The only new technology is the way in which the pipe is wound. It is a spiral style versus a reelstyle, which would be typically found on a pipelay ship. However, this is of minor

significance.

8.2 GAS PROC ESSING ON FPSO’S

As mentioned previously (Exhibit II, Section 4.1), there are currently no FPSO’s with full gasprocessing (fractionation) capability. However a debutanizer column is installed and operatingsuccessfully on the Laminaria-Corallina in Australia, and Air Products have installed facilities

for cryogenic distillation of oxygen from air for the North Sea severe sea states with very goodresults. Further work will be required to prove this concept is acceptable in the sea states in theJeanne d’Arc Basin.

8.3 FLOW ASSU RANCE

The subsea production to the FPSO, and future gas production tie-backs from Ben Nevis,Springdale, etc. would need dehydration or methanol injection to keep hydrates from forming.Oil production would be of more concern depending on the cloud point and pour point of thecrude. The dehydrated gas from Terra Nova and Hibernia is not considered to be an issue.

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technical nonpipeline final.doc Page EIII - 1 065/07129 : Rev 5 : 7-Dec-00

Exhibit III

Onshore CNG

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Onshore Compressed Natural Gas

1.0 OVER VIEW

The onshore CNG concept is based on the possibility of a gas pipeline being built from theGrand Banks area to Newfoundland. Once the gas reaches Newfoundland, except for a smallportion of the gas being utilized in Newfoundland, the excess gas will still be stranded and will

require a means to be monitized. The Onshore CNG option evaluates a method of transportingthe excess gas from Newfoundland to markets in the northeast U.S. or other markets.

The Coselle CNG carrier is essentially a double-hulled bulk carrier with its holds filled with“Coselles”. A Coselle is a huge carousel made up of 9.9 miles of 6.625-inch diameter pipe,rolled up in the shape of a compact cylinder. Each Coselle has a diameter of 50 feet and a

height of 11.25 feet and weighs 445 tonnes.

A Coselle CNG carrier capable of transporting 330 MMscf of gas would require 108 Cosellesloaded into a Panamax (60,000 DWT) sized ship. This is the size of carrier that Cran andStenning have conducted most of their detailed work around.

A CNG carrier capable of transporting 540 MMscf of gas would require 180 Coselles, and avessel of approximately 100,000 DWT would be required. Costs for a project of this size have

been scaled up from the 330 MMscf CNG carrier cost estimates, with the help of Cran andStenning.



The production profile indicates that daily production of approximately 500 MMscfd can beexpected for the next 15 to 20 years.

In addition, the CNG carrier concept may be reaching its practical upper limit capacity of 180Coselles, or 540 MMscfd per carrier, in a 100,000 DWT vessel. Theoretically, the CNG carriercould be installed on a larger 200,000 DWT vessel, but no work has been done on anything of

this size, and the dry weight of such a vessel would be a major concern.

2.2 GAS QUAL ITY

The gas quality is of little concern to the CNG carrier. The richer and cooler (i.e., denser) thegas the better in regards to the amount of BTU’s the CNG carrier can transport. However, thequality of the gas is very important to the gas purchaser. If the gas is being sold into a pipeline

grid, there are possible restrictions on the quality of gas. Typically, the gas must meet thefollowing minimum requirements:

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Maximum BTU/scf < 1,180, but many pipelines do not stipulate

Minimum BTU/scf > 975

Water Content < 7 lbs/Mcf

CO2 Content < 2%

H2S Content < 4 ppm or 1/4 grain

N2 < 3%

O2 < 0.1%

The dehydrated NF gas would seem to have no problems meeting the gas quality specificationsfor most all pipelines and transmission lines. The gas is sweet (i.e., virtually no H2S or CO2)

and has low nitrogen and oxygen content. With possible gas processing upstream of the CNGloading facilities, this gas will be ideal for export into virtually any gas market.


For this case, the gas is coming from a pipeline and oil production is not applicable.


The type of production system is not applicable for this case.


The need for gas processing is based on either (1) gas quality specifications required by the gaspurchaser, or (2) the economic benefits of recovering the ethane, propane, butanes andcondensate from the gas. Since the NF gas, after dehydration, is pipeline quality, the onlyreason for gas processing is for economic benefits.

Based on the ICF market report titled “A Market Analysis of Natural Gas Resources OffshoreNewfoundland” (Page 30 and Table 3.3-1) indicating that gas is valued around C$ 4.00 perMMBtu in the Northeast U.S., and that crude oil prices reach C$ 26.71/bbl, a “net” processingmargin loss of C$ 0.001 /MCF would be realized. This margin would not be enough to justify

a gas processing facility.

If the gas were valued at C$ 0.0 (i.e., had no value) the net processing margin would be in therange of C$ 0.56/MCF.


The analysis assumed that the CNG carriers would take the gas directly to the Northeast U.S.This case would require six (6) ships and receive a gas price of approximately C$

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4.00/MMBtu’s. This would result in a CNG Charter Party rate (i.e., transportation) of C$36.4MM per year per CNG carrier, which equates to C$ 1.09/MMBtu’s.

CNG deliveries could be handled much like LNG deliveries, either into the U.S. pipeline gridor into “niche” markets, depending on what kind of sales contracts can be negotiated.However, due to the 910-mile distance from NF to the U.S. markets, it does not seem practical

to build enough ships to deliver a constant rate of 500 MMscfd, or supply gas on solely apeaking basis. The gas will most likely have to be “batch” delivered to unload each ship as fastas possible after arrival in order to minimize the “turnaround” time and thus minimize thenumber of ships required.

Another alternative would be to deliver the gas to Nova Scotia into the Maritimes and NortheastPipeline, for transport to markets in Canada and the northeast U.S. The distance from Argentiato Point Tupper is approximately 380 miles, requiring only four (4) ships, and lowering thetransportation cost to C$ 0.73/MMBtu’s. Of interest is the possibility of gas storage beingavailable in Point Tupper by Statia Terminals. Gas storage, along with favorable firm gas

capacity and transportation rates from the Maritimes and Northeast Pipeline stakeholders couldbe an attractive alternative to landing gas in the U.S.

5.1 NEWF OUNDLA ND GAS SUPP LY

The estimated average residential, commercial, industrial, and electric utility load will be

approximately 100 MMscfd (ICF market report titled “A Market Analysis of Natural GasResources Offshore Newfoundland” (page 2)) by 2010. The NF gas market would demand areliable fuel gas supply, capable of handling load swings throughout the day and night, andhandling varying rates from summer to winter. A long pipeline system, via its unique “line

pack” capability, offers needed flexibility with regards to gas delivery rates.

Gas consumption on NF will likely increase with the assurance of a guaranteed, long term, gassupply. Other commercial ventures (i.e., methanol plants, ammonia or fertilizer plants, steelplants, etc.) utilizing large amounts of natural gas may be attracted to NF once the majorinfrastructure is in place and the commodity price is attractive.

6.0 INFR ASTRUC TURE REQU IREMEN TS

Two potential locations that may be suitable for a gas development are in Placentia Bay. Bothare in the general vicinity of the Newfoundland Transshipment Facility and North AtlanticRefining:

Adams Head is a deep water site that was initially scheduled to be the site for construction ofthe Gravity Based Structure for Hibernia. As such, it would have the same general

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characteristic as Bull Arm. Rough grading of this site would probably cost in the order ofC$150,000 per acre. An approximate 50 to 60 acre site would be required.

Argentia is an abandoned former U.S. Naval Base. This site is a large, generally level site. Itwould not require a lot of grading prior to development.

To create a gas market in Newfoundland, both industrial and residential, a pipeline and

distribution network would have to be installed to the main users. In addition, homes andbusinesses would have to be modified to receive natural gas and appliances replaced that canburn the natural gas. These costs have not been considered.

7.0 COST ING


It is assumed that the CNG vessels would be built, owned and operated by a third party shipowner on a lease or charter basis. Therefore, the only capital costs would be what is requiredfor the onshore facility in Newfoundland and the off-loading berth and equipment at thedelivery site in the U.S.

The Newfoundland onshore facilities would require compression equipment to compress the gasfrom approximately 720 psig to 3,100 psig, gas metering equipment, and miscellaneousequipment to handle small amounts of liquid, rain water run-off, chemical storage, utilities, fireand safety equipment, etc. In addition, a CNG vessel loading terminal capable of berthing twovessels would be required.

If a gas plant is warranted, an onshore gas plant is estimated at C$330 MM (US$231 MM).

The CNG delivery site would require an off-loading terminal for one ship, plus equipment forgas heating, metering, compression, chemical storage, safety equipment, etc. See page A3-56for CAPEX cost details.

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• Onshore CNG

NF Onshore Berthing Facilities : C$ 28,571,000

U.S. Onshore Berthing Facilities : C$ 28,571,000

Miscellaneous Onshore Equipment/Civil : C$ 42,857,000

Additional Compression : C$ 157,143,000

Project Management, Engineering, Overhead : C$ 40,000,000

Grand Total : C$ 297,142,000


The OPEX for the various offshore facilities are based on operating costs for the Sable, TerraNova and Hibernia as reported on the project websites. These costs do not include the value ofany gas consumed as fuel. The CNG Charter Party rates were furnished by Cran and Stenning,

who obtained their estimates from Maersk, and verified by calculating the unit cost based on a8% financing rate.

CNG Charter Party – 6 ships : C$ 218.6 MM/yr

CNG Onshore OPEX : C$ 6.7 MM/yr

Gas Compression OPEX : C$ 3.6 MM/yr

CNG U.S. Delivery Cost : C$ 18.7 MM/yr



• CNG Carrier

Each carrier would require a crew of approximately 20 per rotation. Considering theneed for six ships plus administration, the CNG Carrier operation would require a staff ofaround 260 on an annual basis.

In addition, service requirements for maintenance, catering, tugs, and the like would havea cascade effect on personnel required.

• Onshore Facilities

Each facility would require approximately 20 people on an annual basis, totaling 40people per year.

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• Gas Plant

If a gas plant were required, the gas plant would require approximately 40 annualemployees.

• CNG Carrier Fabrication

The most competitive shipbuilders are located in Asia. The pricing for the CNG Carriersare based on Asian fabrication. However, the authors feel that Bull Arm modifications

could be made that would allow the construction of several vessels to occur. Aninvestment of C$100 MM or more would be required, but the long term payoffs could bewell worth the investment if numerous new ships were to be required for offshore, and ifthe ships could be built competitively.

The Coselles could be built in Newfoundland. Cran and Stenning estimated thatCanadian fabrication of the Coselles would add approximately 20% to the cost of eachCNG carrier.

7.4 CAPT URE RATE S

• CNG Tanker Construction

Again, the ships would most likely be built in Asia, however, some of the ships could be

built at Irving Shipbuilding if they were competitive. The coselles would have to befabricated near the pipe manufacturers, and this could be done in Newfoundland.

• Onshore Facilities

Most all of the operations could be manned from the people in Newfoundland.

The capture rate for gas production and gas processing equipment could be very high asmost of the equipment could be sourced and built within Canada. Compression equipment

would most likely have to be built outside Canada, however.


8.1 CNG CARR IERS

The technology is patented and has tremendous potential for worldwide commercialapplication. However, there is no commercial application to date. This concept applies existing

technology in a new and creative way. The technology involved is basically the same as onewould find on a FPSO and a pipeline. The high-pressure swivels, flexible pipe, quick connects,etc. all have been designed and are commercially available.

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The design of a CNG carrier is relatively “low tech”. Cran and Stenning have had DnV andABS examine the concept. DnV, who carried out the safety study, concluded that “a (Coselle)CNG ship is at least as safe as other gas ships” and can be classed and allowed to trade as othergas ships (i.e., LNG and LPG). ABS provided the classification guidelines for the vessel,

which means that the Coselle CNG ship can be classed and registered as an ABA A1 E “GasCarrier”.

The only new technology is the way in which the pipe is wound. It is a spiral style versus a reelstyle, which would typically be found on a pipelay ship. However, this is of minorsignificance.

The CNG concept is an integration of various existing technologies for a new transport method.Although this concept has not been utilized offshore, there are no other foreseeable technicalreasons preventing the concept to work except for the weight of the coselles, which is aconcern. A 500 MMscfd ship would contain 180 coselles, each weighting 445 tonnes.Including the weight of the piping manifolds, compression, fire and safety equipment, etc., the

total weight of the equipment and coselles will be in excess of 81,000 tonnes. The ability to drydock a ship with this dense weight is a concern. Other means of inspection would have to beagreed with certification authorities prior to fabrication, which is a realistic expectation.

Another possible solution to reduce the overall weight is to consider Lorica’s offshore

technology patented Carbon Composite Pressure Vessels, in lieu of the coselles.

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technical nonpipeline final.doc Page EIV - 1 065/07129 : Rev 5 : 7-Dec-00

Exhibit IV

Onshore LNG

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Onshore Liquefied Natural Gas

1.0 OVER VIEW

The onshore LNG concept is based on the possibility of a gas pipeline being built from theGrand Banks area to Newfoundland. However, except for a small portion of the gas beingutilized in Newfoundland, the excess gas will still be stranded, and require a means for

monitization. This Onshore LNG option evaluates a method of transporting the excess gasfrom Newfoundland to markets in the northeast U.S. or other economic markets.

The LNG plant analysis has been fashioned around the Atlantic Liquefied Gas Plant (ALNG) inTrinidad. Details from other LNG projects have been utilized where appropriate.



This analysis will be based on an LNG plant with capacities of 490,000 MMscfd. LNG plantcapacities have virtually no limit as additional “LNG trains” can be added as required.

2.2 GAS QUAL ITY

Upstream gas processing may be economic and may be necessary to extract out the butaneand/or heavier components, if their concentration is high enough to cause freezing problems.

Gas treating for CO2 and mercury removal is also required.


For this exercise, the 490 MMscfd of gas is coming from an offshore pipeline, and oilproduction is not applicable.


For this exercise, the gas is coming from an offshore pipeline, and the type of productionsystem is not applicable.


The need for gas processing is based on either (1) potential for the heavier components to causefreezing problems, or (2) the economic benefits of recovering the ethane, propane, butanes and

condensate from the gas.

Based on the ICF report “Market Analysis of Natural Gas Resources Offshore Newfoundland”(Page 30 and Table 3.3-1) indicating that gas is valued around C$ 4.00 per MMBtu in the

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Northeast U.S., and that crude oil prices average around C$ 26.71, a “net” processing marginloss of C$ 0.001 /MCF would be realized. This margin would not justify a gas processingfacility.

If the gas was valued at C$ 0.0 per MMBtu (i.e., had no value) the net processing margin wouldbe in the range of C$ 0.56/MCF. See the Gas Processing Section for more details.


With gas delivery points in the northeast United States approximately 1,100 miles away, LNGcarriers may be an attractive alternative to laying a pipeline to these markets. An LNG shipwould be required approximately every 4-5 days, based on 137,500 m3 LNG ships for inlet gas

rates of 490 MMscfd. LNG ships and regasification facilities are often times supplied by theLNG purchasers.

Based on the ICF report “Market Analysts of Natural Gas Resources Offshore Newfoundland”,estimated LNG and re-gasification costs are C$0.65/Mcf (US$0.45/Mcf) to U.S and Europe. Itwas assumed that these costs were based on existing LNG ships and re-gasification facilities.

However, there is a real concern that these costs could increase significantly if new LNG shipsand new re-gasification facilities are required. The cost of a 137,500 m3 LNG ship is in the US$175 – 200 MM range (Oil & Gas Journal, Dec. 6, 1999, pg. 62).

At the point of delivery, re-gasification facilities are required. If a gas purchaser must buildthese facilities, reported costs of US$300 - 500 MM can be expected for deliveries of 500MMscfd (3 MMTPA), depending to a large extent on the required port and site improvements

necessary.

For the purpose of this study, regasification and transportation costs of C$ 1.00/MMBtu wereassumed.


Two potential locations may be suitable in Placentia Bay for a gas development. Both are inthe general vicinity of the Newfoundland Transshipment Facility and North Atlantic Refining:

Adams Head is a deep water site that was initially scheduled to be the site for construction ofthe Gravity Based Structure for Hibernia. As such, it would have the same generalcharacteristic as Bull Arm. Rough grading of this site would probably cost in the order ofC$150,000 per acre. An approximate 50 - 60 acre site would be required.

Argentia is an abandoned former U.S. Naval Base. This site is a large, generally level site. Itwould not require a lot of grading prior to development. Due to millions of manhours required

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to construct an LNG facility, a construction camp would be required to support the estimated3,600 man construction crew.

For gas use in Newfoundland, a pipeline and distribution network would have to be installed tothe main users. These costs have not been considered.

7.0 COST ING


The cost of an LNG plant that can liquefy 490 MMscfd of gas is summarized as follows:

• LNG Plant Costs

LNG Plant – 490 MMscfd : C$ 1,174,750,000

Construction Camp : C$ 164,250,000

Project Management, Finance, etc. : C$ 214,000,000

LNG Total : C$ 1,553,000,000

These costs do not include the following:

• LNG ships (will be chartered).

• LNG re-gasification facilities (shown as OPEX based on cost per MMBtu’s).


The OPEX for the various options are based on the operating costs of the ALNG plant. Thesecosts do not include the value of any gas consumed as fuel.

LNG Plant

LNG Plant OPEX : C$/yr 64,286,000

LNG Transportation and Regasification : C$/yr 173,000,000

LNG Total OPEX : C$/yr 237,286,000


• Gas Plant Facilities

A gas plant, if justified, could require an additional 40 annual employees.

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• LNG Plant

Based on employment levels at the 3 MMTPA (475 MMscfd) ALNG plant in Trinidad,plant employees numbered 75, and the administration staff numbered 25.

7.4 CAPT URE RATE S

The capture rate on development expenditures should be over 90% for operating expenses.

Most all of the operations could be by Newfoundland employees.

The capture rate for gas production and gas processing equipment could be very high as most ofthe equipment could be sourced or built in Canada. Compression equipment would most likelyhave to be procured from outside Canada.

The capture rate for LNG plant construction should be very high. An estimated 14 millionman-hours will be required to design and construct a 3 MMTPA plant.


8.1 LNG PLAN TS

Onshore LNG plants have been in operation around the world for many years. There areseveral LNG processes, the most notable being the Phillips Optimized Cascade, Air ProductsLNG process, Black & Veatch Pritchard’s Prico process, and ABB Randall’s LNG.

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technical nonpipeline final.doc Page EV - 1 065/07129 : Rev 5 : 7-Dec-00

Exhibit V

Offshore LNG

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Offshore Liquefied Natural Gas

1.0 OVER VIEW

A number of floating LNG facilities have been proposed during the past few years. Most usededicated vessels for the cryogenic facilities where the gas and condensate production facilitiesare on a separate structure, which may be piled, gravity base or floating. Although no LNG

plants have yet been put offshore, the industry generally accepts that it is technically feasible toplace them on ship-shaped vessels or on a fixed position, moored floating structure providedthat the onboard equipment will operate properly with the expected motions of the structure.

The ExxonMobil Floating LNG Plant is the focus of this analysis for the following reasons:

• The plant details are available and the design includes co-production facilities for agas/condensate field similar to N. White Rose.

• Design confidence results from the fact that ExxonMobil has a long history of onshoreLNG production and experience with the use of massive offshore concrete productionfacilities.

• The concrete structure is designed so that the processing plant can continue to operate invery high sea states associated with a typhoon.

The number of oil and gas discoveries, plus the potential for more discoveries offshoreNewfoundland provides an opportunity for such a facility to be considered for producing gascondensate reservoirs and to use re-injected oil associated gas when it becomes available.

2.0 DESC RIPTIO N

The hull structure is very large and made of concrete providing a great mass and properdimensions for muting motions resulting from wave forces. The concrete structure is an

excellent material to resist the effect of very cold temperatures associated with stored LNG. Itmeasures 540 feet by 540 feet. It resembles a square doughnut where the central hole is used asa moon pool to receive risers from the seabed for delivery of produced gas and condensate.

The facility is designed to separate gas, condensate and water, then condition the gas prior to its

liquefaction. This procedure includes the removal of hydrogen sulfide, carbon dioxide andsome NGL's. The gas is then dehydrated to a very low water content to prevent natural gashydrate formation as it is cooled to minus 260°Fahrenheit. The C5+ portion of the NGL’s canbe mixed with the produced condensate. The plan was reported to provide for liquefying of theLPG portion with methane and ethane for a specific client.

The processing equipment was selected by ExxonMobil to minimize any effects of motion, sothat production would seldom, if ever, be interrupted for weather reasons. The hull structure

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was designed for a maximum roll or pitch motion of 8 degrees single amplitude in 100-yearreturn storm conditions including hurricanes West of Australia or at other Pacific Rimlocations. This condition equates to a wave height of about 70 feet, which is similar to manywave heights in the Grand Banks area. The basic hull design type can tolerate larger wave

heights in both operational and survival modes with little or no design modifications. It can bemoored in water depths of up to 4,000 feet without consideration of redesign. Model tests insimulated sea state design conditions indicated a maximum roll or pitch motion of only 6.2meters for the 100-year typhoon condition. Hull motions in predominant operating conditions

will range between about 1 and 3 degrees single amplitude.

The structure provides for warehousing, chemical storage and maintenance equipment.Necessary facilities are included for one day maintenance of complex areo-derivative engines,which are used for processing, that occurs only once each three years. Space is provided forgas booster compressors as field pressures decline. A 250-bed accommodation module is

included, for 206 staff personnel.

A basic double wall hull design provides for internal prefabricated LNG storage tanks having atotal capacity of 250,000 cubic meters. The hull also provides for storage of 650,000 bbls ofcondensate. It provides for water for ballast, cooling and potable. Two LNG offloadingfacilities are supplied at opposite corners of the concrete structure to facilitate offloading of

product in variable wind and wave directions in order to minimize LNG tanker delays andproduction down time.


3.1 THRE SHOLD VALU E OF GAS AND GAS LIQU IDS

The facilities that were studied and designed by ExxonMobil can accommodate 500, 750, 1,000and 1750 MMscfd size plants. The primary focus was 1,000 MMscfd of gas for 6 millionmetric tons per year of LNG. Their studies indicated that when scaling down to a 500 MMscfdfacility, it should maintain near the same storage volumes of condensate and LNG for tanker

shipping considerations. However, these precise storage volume features should be revisited atthe final design stage to accommodate optimum offloading schedules for intended destinationsand the selected LNG production rate.

A 500 MMscfd size unit would allow for up to 20 days storage of condensate at about 55 bblsper MMscf production characteristic, which usually covers most gas condensate reservoirs.

However, if necessary, the condensate storage can be modified at the time of final design toaccommodate anticipated needs for any size facility.

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3.2 GAS QUAL ITY

Facility sizing for the floating LNG unit included consideration of variable gas/condensatequalities and usual product specifications. Nevertheless, if something very unusual were tobecome known prior to fabrication, adjustments could very likely be made without a problemand would be handled in the normal course of final design activities.

The initial use would likely be for a gas/condensate reservoir, which inherently contains lessNGL's than oil associated gas. If the facility is subsequently used for large quantities of re-injected oil associated gas, relatively minor modifications to the gas processing equipment maybe desired to accommodate more NGL extraction prior to liquefaction. The condensate storage

provision for a gas condensate application will likely suffice for an oil-associated gas feedmode of operation.


The gas rate would not be predominately and directly related to simultaneous oil production.The initial gas feed would most likely come from a gas and condensate reservoir, where the

condensate and gas would always be in a fairly constant proportion. Subsequent feed gaswould likely come from one or more oil associated reservoirs from re-injected gas, such asHibernia or Terra Nova. The gas would be produced when it is no longer needed for pressuremaintenance of the reservoir for oil production, or when it can be replaced with water injection.

Oil production would therefore not suffer from meeting optimum gas production rates.

The ExxonMobil design basis was for up to 55 bbls of condensate per MMscfd of producedgas, which is greater than for most condensate production rates. If the actual condensatecontent of the gas is greater, adjustments could be made at the design phase of the project. Ifsomewhat larger volumes of condensate were encountered after the facility is fabricated, the

off-take of condensate would have to be more frequent than initially planned.


The production system is a floating concrete structure for fixed position mooring near gasproduction wells at a gas/condensate reservoir or from a reservoir where oil associated gas hasbeen stored. The facility provides for onboard processing, liquification, storage and offloading

of LNG and condensate. Provision could be made for storage and offloading LPG, if needed.

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4.1 RESE RVOIR RESE RVES A ND FINA NCIAL IMPL ICATIO NS OF PORT ABLE LNGPROD UCTION

The floating LNG plant use must be for in excess of about 15 consecutive years to provide foroptimum CAPEX utilization. The gas reserves suggest that a 500 MMscfd plant could operateat near full capacity if the reservoirs could produce at expected rates.

4.2 UTIL IZ ING EXIS TING FACIL IT IES (HIBE RNIA GBS, TERR A NOVA FPSO)

Existing facilities like Hibernia and Terra Nova could supply gas at high enough pressures suchthat inlet compression for these gas streams would not be required.

4.3 UTIL IZ ING SHAR ED SERV ICES (SUPP LY BOAT S, HELICOPTER S, SUPP LY BASE,

PERS ONNEL)

There is nothing unique with the floating LNG facility that would prevent operators fromsharing services for shuttle tankers, supply boats, helicopter transportation, etc.


5.1 OFFS HORE V S. ONSH ORE PROC ESSING

All the usual contaminants that must be removed from the gas that is to be liquefied, such ashydrogen sulfide, mercury, carbon dioxide and water vapor, can be easily removed offshore.NGL's can also be easily removed offshore where the C5+ fraction can be mixed with producedcondensate. If more LPG's are removed than can be used as fuel, this potential can beestablished at the final design stage where provision can be made for them on the LNG facility

before construction begins.

5.2 GAS COMP OSITIO N (GPM CONT ENT)

If the gas has a high GPM (Gallons of Natural Gas Liquids per Mcf) content, as will possiblybe the case when the facility is using oil-associated gas, it can be handled as indicated above.


6.1 FOR LNG AND OTHE R LIQU IDS

LNG requires very specially designed cryogenic liquid carriers for transport from the floatingunit, as is the case for onshore production of LNG. This fact is taken into account whenestablishing the economic viability of a LNG product.

In the event that surplus propane and butane (LPG) is extracted, it can be transported to shore

or to markets in pressured vessels of in refrigerated tankers, in the conventional manner.

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6.2 FIEL D-TO-MARK ET VS. FIEL D-TO-ONSH ORE AN D THEN ONSH ORE-TO-MARK ET

ExxonMobil's study indicated that the comparative cost for offshore liquefaction of gas wasabout 25% less than to first take the gas to shore. Their study basis was offshore WestAustralia where the cost of getting the gas to shore would probably be less than from the GrandBanks to Newfoundland because of weather factors.


No onshore facilities are needed other than for minimum requirements for movements ofpersonnel and supplies.

8.0 COST ING

8.1 CAPEX VS. OPEX

Receipt of specific information from ExxonMobil is pending. However, the costs used in theanalysis are listed below. The costs were estimated by taking 75% of the estimated cost of thetotal facilities that would be required offshore Western Australia for 1 billion scfd of 1,116BTU/ft3 gas.

• CAPEX

LNG Facility : C$ 3,053,000,000

Well Cost : C$ 1,536,000,000

Subsea Costs : C$ 1,141,000,000


Supply Boat : C$ 70,000,000

Total : C$ 6,030,000,000

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• OPEX

LNG Facility : C$ MM/YR 92.3

Shuttle Tanker : C$ MM/YR 18.9

Supply Boat : C$ MM/YR 14.6

LNG Transportation andRegasification

: C$ MM/YR 176.3

Well Workover : C$ MM/YR 24.0

Transshipment Terminal : C$ MM/YR 16.3

Total : C$ MM/YR 342.4


Approximately 300 persons for a 500 MMscfd plant, including personnel for production.


9.1 EXIS TING, DESIGN OR CONC EPTUAL

The processing technology is very mature. The ability to design massive concrete structureshas been well proven. The ExxonMobil concrete structure has been modeled and tested in amarine basin for the effect of wave induced motions using well proven methods. Theconceptual design was made from in-depth knowledge of process equipment operating onshore

and with the knowledge gained from multiple large concrete GBS structures. Several oiloperators, including ExxonMobil, as well as several reputable equipment suppliers have beeninvolved in the detail design and testing of cryogenic LNG offloading mechanisms.

The LNG facility would have to be designed to disengage and avoid an oncoming iceberg. Theconceptual work has not been performed for this specific concept, but has been successfully

engineered for other concepts, such as ship-shaped FPSO’s.

As a result, the industry would likely consider the concept of a concrete floating LNG plant tobe sufficiently proven to proceed while taking the customary precautions at the detail designstage.

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TECHNICAL NONPIPELINE FINAL.doc Page EVI - 1 065/07129 : Rev 5 : 7-Dec-00

Exhibit VI

Onshore GTL

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Onshore Gas-to-Liquids• Methanol

• Syncrude• Gasoline• Diesel and Naphtha

1.0 OVER VIEW

In the event that gas is delivered to onshore Newfoundland by pipeline, CNG or hydrates, aworld scale methanol plant can be an option to provide onshore value added activities for aproduct to be exported. A portion of the product could be used as feedstock for potentialsecondary industries.

A new plant located at Tjeldbergodden, Norway was selected for focus because of severalsimilar circumstances to those for stranded gas offshore Newfoundland and because itrepresents a recent state-of- the-art plant. It also addresses current environmental issues thatmay escalate worldwide.

Feed for the plant is oil-associated gas from a large offshore facility near the Arctic Circle. It is200 km from shore but a 250 km pipeline route was selected to a landfall area where adequate

infrastructure exists nearby and where a protected harbor with deep water exists. Due to theGulf Stream, the harbor and adjacent seas are clear of ice.

The gas could not be re-injected into its reservoir and re-injection into a nearby reservoir wasfound to be too costly. The gas could have been piped to the northern extremity of an extensivegas gathering pipeline system by adding about 400 km to the pipeline. Instead, a decision was

made to use the relatively small portion of Norwegian gas for an onshore methanol plant. Thepipeline was sized for about three times what was needed for the methanol plant.

There is no significant local use for methanol. However, the shipping time to a centralmethanol market at Rotterdam, The Netherlands is only 50 hours. This shipping time is much

less than from competitive plant locations in Russia, Libya, Chile, Venezuela and Trinidad.

Competition for methanol from Newfoundland will probably be mostly from the U.S. GulfCoast, where old plants convert gas at costs up to approximately US$ 2.70 per MMBTU’s.Most of those still operating are predicted to shut down when local gas costs reach about US$3.00 per MMBTU’s.

Raw gasoline and Fischer-Tropsch products can be sold as high quality crude. Distilledgasoline, diesel and naphtha can be marketed in Eastern Canada and Eastern U.S.

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2.0 DESC RIPTIO N

2.1 METH ANOL

The plant feed gas is compressed and heated, then passed through a purifier where any sulfur-containing gases are removed. The gas is then saturated with water from a source within theprocess. Steam is added to the feed gas prior to entering a pre-reformer where C2 and heavier

hydrocarbons are converted to methane and carbon dioxide. The gas and steam mixture thenenters an ATR reformer vessel. Oxygen that has been separated from air is injected into thereformer vessel through a burner. A small portion of the gas is burned to attain the desiredtemperature. The hot gas passes over a catalyst where hydrogen and carbon monoxide are

formed in a ratio of nearly two parts hydrogen to one part carbon monoxide. The resultingmixture, called syngas, is then cooled to condense most of the injected steam and water vapor.The syngas is then reheated and passed over a catalyst in a methanol synthesis reactor. The gasis cooled to condense and remove the methanol that is formed. The syngas is then heated and

repeatedly recycled over the catalyst until most of the syngas has been converted to methanol.The product is then distilled to meet specified methanol specifications.

2.2 MTG (METH ANOL T O GASO LINE)

A raw methanol product is heated and passed over a catalyst to convert a portion of themethanol to dimethyl ether. The mixture is then passed over another catalyst, developed by

ExxonMobil, where a portion is converted to hydrocarbons, having a maximum carbon count of13 per molecule. The vapor mixture of methanol and dimethyl ether is cooled to removeproduced gasoline. The mixture is then repeatedly recycled until most is converted to gasoline.

The product is approximately 80% gasoline and 18%, by weight, propane and butane. The

LPG portion can be used for fuel, be recycled to the feed gas stream ahead of the pre-formervessel, or sold as a separate product.

2.3 TIGAS/MTG

This is an integrated process where a mixture of methanol and dimethyl ether is produced,instead of methanol. It is then passed over a specific catalyst and the mixture is converted to

gasoline using the ExxonMobil-developed MTG catalyst. The TIGAS process was developedby Haldor Topsoe in conjunction with ExxonMobil at about the same time that ExxonMobilwas building an MTG plant in New Zealand in the mid-1980’s. The product is substantially thesame as that produced by the MTG process.

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The advantage of this process is that considerable equipment is eliminated and some equipmentis reduced in size because of the reduced need for recycling of the gas and vapors. As a result,CAPEX is substantially reduced.

2.4 FISC HER-TROP SCH HYDR OCARBO NS

The Fischer-Tropsch method of converting natural gas to liquid hydrocarbons starts with asyngas that is very similar to the syngas for methanol. It differs only by a slightly higher ratioof hydrogen to carbon monoxide. It has a ratio of 2 to 1, instead of nearly 2 to 1 for a methanolproduct.

The syngas is heated and contacted with an iron or cobalt catalyst. The product is mostly

paraffin hydrocarbons that can have a wide range of components. For maximum conversionefficiency to liquid hydrocarbons, the raw product is about half heavy wax and half diesel plusnaphtha. Most, if not all, owners of the technology produce the waxy mixture then hydrocrackthe wax to produce more diesel and naphtha.

2.5 SYNC RUDE

Both raw gasoline and raw diesel plus naphtha Fischer-Tropsch products may be mixed withcrude oil as "syncrude”.



The threshold volume of gas can be virtually any volume that is available in excess of about 80MMscfd. This results from varying the size of the equipment and the number of parallel trains.A volume of 500 MMscfd was used for this analysis, requiring seven trains of syngasproduction equivalent to 2400 tonnes/day of methanol, the largest ATR reformer that has beenmade to date.

This volume of gas is satisfactory for methanol, TIGAS/MTG and F-T liquids.

It would be advisable to recover C5+ and LPG from the gas stream prior to conversion of thegas to liquid if markets exist for economical extraction and transport.

3.2 GAS QUAL ITY

The use of a pre-reformer ahead of the primary reformer will allow all three processes to utilizegas from any of the Jeanne d’Arc reservoirs without creating soot to foul catalysts, although

there will be a moderate decrease in conversion efficiency when the gas contains any gasheavier than methane.

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The feed gas for an onshore methanol plant should not directly affect the offshore production ofoil or condensate.


Not applicable since the plant is onshore.


5.1 ONSH ORE VS. OFFS HORE GAS PROC ESSING

The gas that reaches the onshore plant will likely be adequate for feed stock for all three GTLproducts. If excessive NGL’s are present in the gas, the heavier components can be easilyremoved. The lighter NGL’s can be extracted as LPG product or be converted to methane and

carbon dioxide in the pre-reformer at a moderate expense due to lost conversion efficiency.The decision for selecting processing methods offshore should not be influenced by the fact thatthe gas will go to a methanol plant onshore.

5.2 GAS COMP OSITIO N

The feed gas to a methanol plant can contain about 17 % or more C2+ content with little effecton the plant operation. If higher than normal quantities of C5+ are present, it would usually bemore profitable to remove the excess liquid vapors for marketing and replace them with lightergases from the supply. The removal equipment is not capital intensive and can usually be paidout in a year or two from the value of C5+ liquids and LPG.


6.1 FOR METH ANOL/F-T LIQU IDS/MTG

Methanol is transported by small dedicated chemical tankers since it is essential that nocontaminants or water is contained in the tankers’ storage tanks. Some major producers arebeginning to use larger dedicated methanol tankers to reduce transportation costs.

The MTG and F-T liquids can be transported with the same shuttle tankers available in thefield, or if justified, transport with separate shuttle tankers to take advantage of potentialpremium pricing.

6.2 FIEL D-TO-MARK ET VS. FIEL D-TO-ONSH ORE AN D THEN TO-MARK ET

The cost of gas to be converted to liquids is affected by the unit cost of getting the gas to the

GTL plant. As a result, offshore GTL processing has a cost advantage over that made onshore

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for small gas volumes. Nevertheless, the Norwegian plant was justified with a pipeline inrelatively deep water to deliver the gas onshore. For large volumes of gas, an onshore facilitywould be required due to the size of the plant. Alternatively, more than one methanol FPSOvessel would be required offshore.


7.1 SITE AVAILABILITY FOR LAND FALL, STOR AGE REQU IREMEN TS, ETC.

The pipeline land-fall will be the responsibility of the pipeline owner. It is not anticipated thata GTL plant could justify a dedicated pipeline for only gas for a GTL plant. It will benecessary to locate an onshore plant at a site that would allow reasonable storage volumes for

flexibility of supply to markets. It will also require a nearby deep water port for export of theliquid product using ever increasing size carriers. The plant site should ideally includeadditional nearby space for potential secondary industries that could possibly use the liquids forits feed stock and perhaps to share utility requirements. Fresh cooling water is desirable.

8.0 COST ING

Some total cost information for the Norwegian methanol plant was provided by Statoil, butcompany policy prevented them from providing a breakdown. The total cost of the 250 km, 16inch pipeline was 1.8 billion NoK (US$ 252 MM). The total cost of the plant and plant site wasan additional 4.5 billion NoK (US$ 630 MM).

However, the total plant and plant site cost included many items that should not be included inan estimated cost for the Newfoundland study. The 4.5 billion NoK (US$ 630 MM) included:

• Gas Receiving Station.

• Oxygen Plant.

• Methanol Plant.

• A Bio-Protein Plant.

• A Small LNG Plant.

• Site and Extensive Site Preparation for the Future.

Another problem with trying to use the available total cost was the fact that the currencyexchange rate between the NoK and US$ varied substantially over the construction periodresulting in variations from this factor of about ± 25% depending on the date used for thecomparison.

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For these reasons the basic methanol plant cost estimate presented is based on total costsobtained from Halder Topsoe for a similar plant to be built at another site. The cost wasreported to have been confirmed by two major contractors. A list of estimated processing plantand site costs follows:

Gas Receiving Station : US$ 10,000,000

Oxygen and Processing Plant : US$ 225,000,000

Site and Site Preparation : US$ 50,000,000

Storage (MeOH) : US$ 20,000,000

Project Management (excludingprocess plant)

: US$ 20,000,000

Total : US$ 325,000,000

This compares favorably to the costs Worley has developed for onshore plants based on thedetailed estimate developed for offshore, allowing for technical modifications that are practicalonshore, but not so offshore. Based on seven trains of 2,400 MTPD methanol plant to process

490 MMscfd, or the equivalent for MTG and F-T, the conservative plant costs are as follows:

MeOH MTG F-T

Plant Cost (C$ MM) 1886 2690 2194

3000 MM Camp (C$ MM) 164 164 164

Other NF Factors (C$ MM) 135 135 135

Total 2186 2990 2494


One train would employ 100 persons. An additional 40 persons would be required for eachadditional train for methanol or TIGAS/MTG. The F-T plant for 490 MMscfd would requireabout 300 persons. An additional 40 to 50 persons would be required for maintenance supportfor each of the three products.

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8.2 CAPT URE RATE S

Approximately twelve (12) million man-hours are required to construct a plant of this size.Most all laborers could be from Newfoundland, if they have the resources. This would requirea workforce peaking at approximately 3,600 people.

Much of the equipment, valves, pipe, etc., could be procured in Canada.


Methanol plants are very mature. There are several process options that differ primarily in thespecific equipment design for making the syngas that is used to synthesize methanol. Nosignificant unproven elements exist.

The TIGAS/MTG plant was proven in the mid-1980’s at the La Porte, Texas demonstrationplant. The major reduction in oil prices that occurred in early 1986 caused the process to be set

aside. Haldor Topsoe has optimized several equipment items for application with TIGAS thatshould allow further economics and smooth operations.

The basic Fischer-Tropsch process is 76 years old. However, newly developed unit operationsmethods have been developed by several companies. Demonstration plants have provenfluidized bed catalytic reformers to be very efficient for making syngas onshore. Slurry

catalytic reactors have also been proven in both demonstration plants and fully commercialplants. It is anticipated that slurry catalytic reactors will be proven for offshore services verysoon, allowing greater economy of scale.

The fluidized bed reformer technique should equally apply to methanol and TIGAS/MTG

operations onshore.

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technical nonpipeline final.doc Page EVII - 1 065/07129 : Rev 5 : 7-Dec-00

Exhibit VII

Offshore GTL

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Offshore Gas-to-Liquids

1.0 OVER VIEW

Depending on local and nearby market circumstances, the most desirable gas-to-liquids (GTL)product would be one of the following:

− Methanol.

− Syncrude.

− Gasoline.

− Diesel and Naphtha.

This analysis will primarily focus on a methanol plant placed on an FPSO and integrated withan oil production plant. The similarity of the four GTL process operations results in them beingapplicable to basically the same reservoir and field circumstances. For this reason, commentswill be made about the other three processes only as warranted.

2.0 DESC RIPTIO N

2.1 METH ANOL

The plant feed gas is compressed, heated and passed through a purifier where any sulfur-containing gases are removed. The gas is then saturated with water from a source from withinthe process. Steam is added to the feed gas prior to entering a pre-reformer where C2 andheavier hydrocarbons are converted to methane and carbon dioxide. The gas and steam mixture

then enters an ATR reformer vessel. Oxygen that has been separated from air is injected intothe reformer vessel through a burner. A small portion of the gas is burned to attain the desiredtemperature. The hot gas passes over a catalyst where hydrogen and carbon monoxide areformed in a ratio of nearly two parts hydrogen to one part carbon monoxide. The resulting

mixture, called syngas, is then cooled to condense most of the injected steam and water vapor.The syngas is then reheated and passed over a catalyst in a methanol synthesis reactor. The gasis cooled to condense and remove the methanol that is formed. The syngas is then heated andrepeated recycled over the catalyst until most of the syngas has been converted to methanol.

The product is then distilled to meet specified methanol specifications.

2.2 MTG (METH ANOL T O GASO LINE)

A raw methanol product is heated and then passed over a catalyst to convert a portion of themethanol to dimethyl ether. The mixture is then passed over another catalyst (developed byExxonMobil), whereby a portion is converted to hydrocarbons having a maximum carbon count

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of 13 per molecule. The vapor mixture of methanol and dimethyl ether is then cooled toremove produced gasoline. The mixture is then repeatedly recycled until most is converted togasoline.

The product is approximately 80% gasoline and 18%, by weight, propane and butane. If it isnot economical to separate the LPG portion for a market, it can be used for fuel and/or be

recycled to the feed gas stream ahead of the pre-former vessel.

2.3 TIGAS/MTG

This is an integrated process where passing a mixture of methanol and dimethyl ether isproduced, instead of methanol. It is then passed over a specific catalyst where the mixture is

converted to gasoline using the ExxonMobil developed MTG catalyst. The TIGAS process wasdeveloped by Haldor Topsoe in conjunction with ExxonMobil at about the same time thatExxonMobil was building an MTG plant in New Zealand in the mid-1980’s. The product issubstantially the same as that produced by the MTG process.

The advantage of this process is that considerable equipment is eliminated and some equipment

is reduced in size due to the reduced need for recycling of the gasoline vapors. As a result,CAPEX is substantially reduced.

2.4 FISC HER-TROP SCH HYDR OCARBO NS

The Fischer-Tropsch method of converting natural gas to liquid hydrocarbons starts with asyngas that is very similar to syngas for methanol.

The syngas is heated and contacted with either an iron or cobalt catalyst. The product is mostlyparaffin hydrocarbons that can have a wide range of components. For maximum conversionefficiency to liquid hydrocarbons, the raw product is about half-heavy wax and half diesel plusnaphtha. Most, if not all, owners of the technology produce the waxy mixture then hydrocrackthe wax to produce more diesel and naphtha.

2.5 SYNC RUDE

Both raw gasoline or raw diesel plus naphtha Fischer-Tropsch products may be mixed withcrude oil as “syncrude”.

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Generally, about 29,600 MMBtu of associated gas is required for the production of 1,000tonnes/day of methanol, excluding fuel which is approximately 12.7% of the inlet gas for anoffshore application.

Offshore GTL plants require more fuel gas than onshore plants. This results from the need tosimplify equipment, operations and maintenance on a crowded and sometimes violently movingFPSO vessel. Use of fuel to drive compressors and generate electricity for electric motors ismuch safer than using waste heat to generate and use steam at the many required locations on

an FPSO vessel. The increased use of fuel offshore is normally of less concern because thestranded gas has a low or negative value when the alternative is to reinject the gas at asubstantial cost.

The use of high BTU/ft3 feed gas is less efficient from the standpoint of BTU/tonne of product.This results from the fact that a pre-reformer is used to convert C2 and heavier gases to C1 plus

CO2.

The best BTU conversion efficiencies result if most of the C2 and heavier components areremoved by gas processing prior to the feed gas entering the syngas production equipment.

The best economics for GTL plants result from sharing deck and storage space with a GOSP-FPSO vessel. Accordingly, a large tanker shaped vessel was selected for a case to include oilproduction and gas-to-liquids production on one GOSP / GTL FPSO vessel. The selected size

has 54m x 375m deck dimensions. This size vessel will allow four trains of syngas for 1,500tonnes/day methanol each. The same volume of gas can be converted to gasoline or F-Tliquids.

The selected oil production facility has a capacity for 80,000 Bbl/day and 160,000 Bbl/day

water injection.

With no GOSP facilities on board the same size vessel will allow six trains of syngas for 1,500tonnes/day methanol each. The same volume of gas can be converted to gasoline or to F-Tproducts on the selected large vessel.

The volume of GTL feed gas will vary with the BTU content of the gas, but will beapproximately 177 MMscfd for four trains or 236 MMscfd for six trains of syngas when the

feed gas has 1,117 BTU/ft3. Multiple vessels may be used if warranted.

Ideally, for a floating methanol plant, there should be sufficient gas reserves for at least tenyears operation at full capacity to typically meet minimum economic hurdles.

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3.2 MULT I-FIEL D OR STAN D-ALON E DEVE LOPMEN T

Because of its portability, a floating methanol or similar GTL plant can be applied in multi-field, sequential or stand-alone developments.

3.3 GAS QUAL ITY (COMP OSITIO N)

The composition of normal produced gas is not critical, since heavy ends in associated gas is

usually pre-reformed to methane and some carbon dioxide prior to entering the synthesis gasprocess. Dehydration of the wet gas in not required.

Produced water vapor, nitrogen and carbon dioxide inerts can generally be accommodated bythe process without any detrimental effect. Water vapor combines with steam that is requiredby the process. Nitrogen passes through the entire process as an inert, the only effect being the

increase in size of the piping, vessels, exchangers and compressors to accommodate theadditional volume. Carbon dioxide joins with that which is generated in the process.

Hydrogen sulfide and organic sulfur tend to poison catalysts, and must be removed prior toentering the synthesis gas loop. Almost all methanol plants have desulfurisers at the beginningof the process to remove any traces of hydrogen sulfide and organic sulfur that may be present

in the feed gas stream.

3.4 GAS VS. OIL PROD UCTION RATE S (CURR ENT AN D PROJ ECTED, RE-INJE CTION

REQU IREMEN TS, FIEL D LIFE , ETC.)

For the GOSP/GTL case, the analysis is based on the assumption that these facilities would beinstalled at a future discovery similar to the White Rose Field. The solution gas from the

development would have priority, and the remaining gas would be supplied from the non-associated gas. The oil and gas production is expected to peak at 80,000 BOPD and 41.1MMscf/d respectively. A gas field, like the N. White Rose gas, is expected to produce 33barrels of condensate for each MMscf/d of gas produced. Peak oil and condensate production

is approximately 83,000 BPD. Other gas volumes can be selected for similar field conditionsthat may be discovered in the future.

For the 9,000 tonne/day case, it is assumed that circa 268 MMscfd of gas is available fromnearby oil and gas fields. This case assumes all the production is handled at another facility(s)and the gas is sent to the GTL FPSO. In this case, there would be no oil or condensate

production to consider.

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4.1 GRAV ITY-BASE D, FLOA TING SYST EM, SUBS EA OPTIONS

This evaluation is limited to floating systems. A floating system can be either a dedicatedsystem, or integrated with oil production facilities (GOSP) on an FPSO.

4.2 RESE RVE AN D FINA NCIAL IMPL ICATIO NS OF PORT ABLE A ND MODU LAR

PROD UCTION SYST EMS

Floating GTL plants are, by their nature, very portable. Little, if any, modifications to theprocess system would be required to relocate the system to another field. The expected usefullife of such a system is at least twenty years.

4.3 UTIL IZATIO N OF EXIS TING FACIL IT IES (HIBE RNIA GBS, TERR A NOVA FPSO)

Dedicated, floating methanol plants can be positioned adjacent to existing facilities, with thefeed gas supplied by subsea pipeline.

4.4 UTIL IZ ING SHAR ED SERV ICES (SUPP LY BOAT S, HELICOPTER S, SUPP LY BASE,PERS ONNEL)

In the case of a floating GTL plant being integrated on an FPSO with oil production systems,there could be full sharing of logistical support equipment and services. In addition, therewould be no requirement for duplicated marine support, housekeeping and maintenancepersonnel.

In the case of a dedicated floating methanol plant located adjacent to other oil productionfacilities (either GBS or floating) logistical support equipment and services could also be

shared.


5.1 OFFS HORE V S. ONSH ORE PROC ESSING

Gas processing to remove LPG would not be practical for several reasons: there is not enough

space for the gas processing equipment; the performance of the process towers (de-ethanizers,etc.) in rough seas is not yet proven; and this would be the first time for both GTL and gasprocessing to be done on an FPSO under the rough sea-states in the Jeanne d’Arc Basin. Itwould be very challenging to undertake just one of these processes, let alone both at the sametime. This activity can be considered at a future date after offshore use of structural packing

fractionation towers is proven for FPSO applications.

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5.2 GAS COMP OSITIO N

The syngas plant for methanol and F-T applications can accommodate varying quantities of

C3+ because of the use of a pre-reformer to convert the heavier gaseous hydrocarbons to

methane and carbon dioxide prior to reaching the syngas reformer. The presence of heaviergases causes a moderate reduction in conversion efficiency.

In some cases, where the associated gas includes a high percentage of heavy hydrocarbons, it is

economical to knock out the liquids prior to entering the synthesis gas loop in a refrigeratedliquid recovery unit and recombine the heavy liquids with the produced crude oil. Removal ofLPG may be profitable in some circumstances.


6.1 FOR METH ANOL, SYNT HETIC CRUD E, OTHE R LIQU IDS

Methanol is usually transported by small dedicated chemical tankers since it is essential that nocontaminants or water is contained in the tankers’ storage tanks. Some major producers arebeginning to use larger dedicated methanol tankers to reduce transportation costs.

The MTG and F-T liquids can be transported with the same dedicated shuttle tankers availablein the field, or if justified, transport with separate shuttle tankers to take advantage of potential

premium pricing.

6.2 FIEL D-TO-MARK ET VS. FIEL D-TO-ONSH ORE AN D THEN ONSH ORE-TO-MARK ET

It is more economical to transport liquids directly to market instead of transport to onshore andthen to market because of the additional cost of tanker offloading/reloading and storagefacilities.


7.1 SITE AVAILABILITY FOR LAND FALL, STOR AGE REQU IREMEN TS, ETC.

Generally, no onshore site availability or storage is required in support of floating GTL plants.

7.2 POSS IBLE UTIL IZATIO N OF EXIS TING INFR ASTRUC TURE

Existing logistical infrastructure, delivery systems and personnel can be shared.

NOIA




8.0 COST ING


The following cost estimates are based on a typical 6-train 9,000 tonne/day dedicated floatingmethanol system producing Federal Grade AA methanol, a 31,650 BPD MTG syncrude plant,and a 27,150 BPD Fischer Tropsch plant with the same feed gas quantity.

Six (6) Train GTL FPSO

CAPEX – Millions C$ Methanol MTG F-T

54 m x 375m FPSO, including turret, mooring andmarine systems

652 652 652

GTL Topsides, including Installation andcommissioning

1,183 1,964 967

Total - Dedicated Facility 1,835 2,616 1,619

The following cost estimates are based on a stand alone GOSP/GTL FPSO that can consists ofa typical 4-train 6,000 tonne/day dedicated floating methanol system producing Federal Grade

AA methanol, or a 21,100 BPD MTG syncrude plant, or a 18,100 BPD Fischer Tropsch plantwith the same feed gas quantity. In addition, full production facilities capable of processing80,000 BOPD and 160,000 BWPD for injection are included, and the well costs and subseaequipment.

CAPEX – Millions C$ Methanol MTG F-T

46.5 m x 375m FPSO, including turret, mooring andmarine systems

807 807 807

GOSP + GTL Topsides, including Installation andcommissioning

937 1,461 794

Initial Well Costs 816 816 816

Initial Subsea Costs 428 428 428

Shuttle Tankers 230 230 230

Supply Boats 70 70 70

Future Wells and Subsea Costs 1,433 1,433 1,433


NOIA




There are cost and design optimization opportunities that could help bring the MTG CAPEXdown by 10% or more by integration of the syngas and MTG processes as proposed by HaldorTopsoe for their TIGAS process.


OPEX costs for the GTL FPSO are as follows:

Daily Operating Expense (OPEX) –C$/d Methanol MTG F-T

FPSO Operating Cost 92,143 120,000 105,357

Shuttle Tanker 32,676 27,152

Supply Boats 20,000 20,000 20,000

Transshipment Terminal 0 15,774 13,575

Methanol Transportation / Price Adjustment 221,714


The OPEX for the various options do not include the value of the feed gas.

OPEX costs for the GOSP/GTL FPSO are as follows:

Daily Operating Expense (OPEX) –C$/d Methanol MTG F-T

FPSO Operating Cost 92,143 120,000 105,357

Shuttle Tanker 25,928 25,928 25,928

Supply Boat 20,000 20,000 20,000

Transshipment Terminal 0 52,111 49,859

Methanol Transportation / Price Adjustment 141,000 0 0


The OPEX for the various options do not include the value of the feed gas.


Staffing of the floating methanol plant will be about 75 persons per operating tour, or a total ofabout 150 persons per vessel, excluding shore based logistical and administrative personnel. Toprocess 500 MMscfd, two FPSO’s would be required, resulting in employment of 300 people.

NOIA




9.1 CAPT URE RATE S

The capture rate on development expenditures should be over 90% for operating expenses.Most all of the operations could be by Newfoundlanders.

The capture rate on CAPEX will be less than 10% for the production/process facilities and thefloating platform as these vessels will most likely be built in Asia due to the price and schedule

advantages. The topsides could be built at Bull Arm.


10.1 EXIS TING DESIGN STAG E OR CONC EPTUAL

The design of the necessary marine and mooring equipment is both existing and mature.

Likewise, the design of methanol production/processing equipment is proven and is availablefrom a number of suppliers of this technology. The TIGAS/MTG process is available from

Haldor Topsoe. The F-T process can be supplied by several companies.

10.2 IDEN TIFY ADDITIONAL R&D WORK REQU IRED

The only technology that needs additional work is the distillation of methanol to Federal GradeAA specifications. Structured packing will be used and is a proven technology, however,vessel motion simulation studies need to be carried out to prove the distillation column design

for placement on a floating vessel.

natural gas development based on non-pipeline options_technical feasibility study

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