Natural Gas Development Based on Non- Pipeline Options - Offshore Newfoundland

Transcription

1 Natural Gas Development Based on Non- Pipeline Options - Offshore Newfoundland Final Report 065/ Dec /G D Worley International Inc. and Worley Engineers Inc. Worley International Inc Northwest Freeway, Suite 200 Houston, Texas, Tel: Fax: Web: Copyright 2000 Worley International Inc.

2 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 NOIA and Worley International Inc. Worley International Inc accepts no liability or responsibility whatsoever for it in respect of any use of or reliance upon this report by any third party. Copying this report without the permission of NOIA or Worley International Inc is not permitted. PROJECT 065/ NATURAL GAS DEVELOPMENT BASED ON NON-PIPELINE OPTIONS - OFFSHORE NEWFOUNDLAND REV DESCRIPTION ORIG REVIEW WORLEY APPROVAL DATE CLIENT APPROVAL DATE A Issued for client comment Richard A. Bresler Steve Worley N/A 10-Aug-00 N/A 0 Issued as final Richard A. Bresler Steve Worley Richard A. Bresler 27-Sept-00 1 Revise charts Richard A. Bresler Steve Worley Richard A. Bresler 20-Oct-00 2Revise tables Richard A. Bresler W. Locke Richard A. Bresler 7-Dec-00 aforest:desktop folder:natural gas studies:development & transportation:working:non-pipeline final.doc Page ii

3 CONTENTS 1. SUMMARY Background Scope of Work Principal Findings PROJECT OVERVIEW Pre-Screening Study Benchmark Analysis Other Considerations Technical Feasibility Analysis ECONOMIC FEASIBILITY ANALYSIS Case Descriptions Compressed Natural Gas - FPSO Gas Hub Compressed Natural Gas - FPSO Incremental Gas Hub Compressed Natural Gas - GBS Gas Hub Compressed Natural Gas - GBS Incremental Gas Hub Liquefied Natural Gas Floating Gas Hub Liquefied Natural Gas - Incremental FPSO Gas Hub Gas-to-Liquids - Incremental to FPSO Development Methodology Parameters Project Economics and Sensitivities Ringfence Analysis CNG Ringfence LNG Ringfence GTL Ringfence Onshore Analysis Summary Results non-pipeline final.doc Page iii 065/07129 : Rev 2 : 7-Dec-00

4 Appendices A1 CNG OFFSHORE SENSITIVITIES...A1-1 A2 LNG OFFSHORE SENSITIVITIES...A2-1 A3 GTL OFFSHORE SENSITIVITIES...A3-1 B1 NATURAL GAS DEVELOPMENT BASED ON NON-PIPELINE OPTIONS, OFFSHORE NEWFOUNDLAND, PRE-SCREENING STUDY...B1-1 B2 NATURAL GAS DEVELOPMENT BASED ON NON-PIPELINE OPTIONS, OFFSHORE NEWFOUNDLAND, INDUSTRY BENCHMARK ANALYSIS SUMMARY...B2-1 B3 NATURAL GAS DEVELOPMENT BASED ON NON-PIPELINE OPTIONS, OFFSHORE NEWFOUNDLAND, TECHNICAL FEASIBILITY ANALYSIS...B3-1 non-pipeline final.doc Page iv 065/07129 : Rev 2 : 7-Dec-00

5 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 CIT Corporate income tax 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 kwh Kilowatt hour non-pipeline final.doc Page v 065/07129 : Rev 2 : 7-Dec-00

6 LNG LPG MeOH MFPSO MM MMcf MMscfd MMBtu MMBtu/d MT MTG MW NA NAG NGL OPEX Offshore Nova Scotia SMR Tcf US$ Liquefied Natural Gas Liquefied Petroleum Gas propane and butane Methanol Methanol floating production, storage and offloading vessel Million Million cubic feet Million standard cubic feet per day Million British thermal units Million British thermal units per day Metric Ton Methanol to gasoline Megawatts Not Available Non-Associated Gas (not associated with oil production) Natural Gas Liquids ethane, propane, butane and pentane plus Operating expenses Sable Island, Laurentian Sub Basin and the deepwater plays Steam methane reforming Trillion cubic feet U.S. Dollar non-pipeline final.doc Page vi 065/07129 : Rev 2 : 7-Dec-00

7 1. SUMMARY 1.1 Background When this project started in December 1999, the estimated proven and probable recoverable gas resources from the Grand Banks area were trillion cubic feet (tcf). By May 2000 the Canada-Newfoundland Offshore Petroleum Board (C-NOPB) had updated its estimates to 5.05 tcf. The potential recoverable gas in the Jeanne d Arc Basin and Ridge Complex, both discovered and undiscovered is now 18.8 Tcf, according to C-NOPB s latest news release on May 2, Gas resources of this magnitude offer potential economic benefits to all the stakeholders; e.g., the oil and gas producers, mid-stream gas development and supply companies, government, and the province of Newfoundland. A better understanding of the options available to monetize the offshore gas resources is taking place through an all-stakeholder study involving the Newfoundland Ocean Industries Association (NOIA), the Atlantic Canada Opportunities Agency (ACOA), the Canada-Newfoundland Offshore Petroleum Board (C-NOPB), Canadian Association of Petroleum Producers (CAPP), the Department of Industry, Trade and Technology (Government of Newfoundland and Labrador), Department of Mines and Energy (Government of Newfoundland and Labrador), Industry Canada, Natural Resources Canada, Newfoundland and Labrador Hydro, and Newfoundland Power. This study analyzes the potential to commercialize the natural gas offshore via the non-pipeline options. The options given primary consideration were: Compressed Natural Gas (CNG); Liquefied Natural Gas (LNG); and Gas-to Liquids (GTL) from which methanol, gasoline, diesel and/or naphtha are derived. 1.2 Scope of Work The economic analysis of non-pipeline options evaluated seven (7) offshore cases, three (3) ringfence cases that only considered the conversion segment, and four (4) onshore cases utilizing CNG, LNG, and GTL technologies. The economics were evaluated using two different measurement criteria: a) The Net Present Value (NPV) of the project based on a fifteen percent (15%) discount rate (expressed as NPV 15 ), and b) The $/MMBtu available for sharing after corporate income tax is paid and a 15% rate of return (NPV 15 = 0) is earned on the investment in production, gas processing and transportation facilities. This criteria represents an approximate value of the gas available for revenue sharing among the various stakeholders: government, natural gas producers, and any third-party project developer(s). This measure could be interpreted as comprising royalties and/or the project risk premium required above a 15% real rate of return on the investment. non-pipeline final.doc Page 1 065/07129 : Rev 2 : 7-Dec-00

8 Sensitivities were run on the various parameters affecting economics such as capital costs (CAPEX), operating costs (OPEX), transportation costs, project financing, tax burdened vs. unburdened, product pricing, and inflation. Pricing information was based on a market study by ICF Consulting, Inc., entitled A Market Analysis of Natural Gas Resources Offshore Newfoundland. The ICF base case price forecast used for this analysis is the New England city-gate prices of $2.72/Mcf (U.S. 2000$) in 2005 increasing to $3.56/Mcf in Principal Findings The economics for a gas project are greatly enhanced if it is done in conjunction with an oil project (i.e., incremental-to-oil) instead of as a stand-alone gas project. The offshore CNG, LNG, and Methanol/Fischer Tropsch GTL options may have potential for monetizing Newfoundland s natural gas resources. The $/MMBtu available for revenue sharing after tax on a 15% ROR project could be as high as C$2.09/MMBtu based on the CNG option, and based on structuring a project such that lease financing can be utilized to offset the huge amount of CAPEX required at the front end of such a development. These results are summarized in Table 1 Offshore Economic Summary. The onshore options of CNG, LNG, and Methanol / GTL may also be economically feasible depending on the feedstock price of the gas at the plant gate. The onshore scenarios would require a pipeline transportation system to the Island, the cost of which is beyond the scope of this study. The results of the onshore cases are shown in Table 3 Onshore Economic Summary. In addition to the transportation cost of delivering natural gas to the Newfoundland market for utilization, one must also consider the end use market impact. For example, although the onshore methanol example looks very robust, the reality is that a methanol facility would have to be built in phases. For gas rates of 490 MMscfd, seven world class methanol trains would be required, each capable of producing 2,400 tonnes per day. The methanol market, in all likelihood, would not be able to absorb this amount of methanol production without a significant impact on the supply demand balance and price. For a phased approach, the first train will be more expensive than the second train, and so forth. Nevertheless, the 490 MMscfd gas availability would likely be phased. The parameters of this analysis were predetermined simply to show the potential by comparing projects on a common basis. Delivery reliability along the gas supply chain will be very important. This could be a major issue with regards to obtaining financing and the ultimate success of the venture(s). Economic sensitivities were evaluated by varying the following parameters; Capex, Product Pricing, Operating Costs, Transportation Costs, Escalation, and Equity Financing. In almost every case, product pricing had the biggest impact on economics as a 25% increase would make most projects economic, and a 25% decrease would make most projects uneconomic. Capex reductions of 25% would also result in most projects being economic. non-pipeline final.doc Page 2 065/07129 : Rev 2 : 7-Dec-00

9 The general conclusion is that an economic non-pipeline option, either onshore or offshore, could be viable under favorable circumstances. There are many different ways in which a gas project could be structured, depending on the goals, cooperation, and objectives of all the stakeholders (i.e., producers, mid-stream developers, financial institutions, government, etc.). non-pipeline final.doc Page 3 065/07129 : Rev 2 : 7-Dec-00

10 2. PROJECT OVERVIEW Prior to the economic feasibility analysis, the progression of the study phases included: a pre-screening study of all the various types of non-pipeline concepts, a benchmark analysis based on other stranded gas developments or proposals, and a technical feasibility analysis of the CNG, LNG and GTL concepts. 2.1 Pre-Screening Study There are four basic non-pipeline methods to efficiently transport and monetize stranded gas. A summary of these options is as follows: a) Compression of natural gas (CNG) to high-pressure for marine transport. b) Cryogenic liquefaction of natural gas (LNG) for marine transport. c) Conversion of natural gas to electric power (Gas-to-wire) for subsea cable transmission. d) Conversion of natural gas to valuable liquids (GTL) for marine transport. There are general advantages and disadvantages for each method but the viability of each is ultimately dependent on their facility costs and the total market circumstances. The pre-screening study was based upon the assumptions that: Recoverable gas reserves offshore Newfoundland are a minimum of 4.0 Tcf and could exceed 19 Tcf. To deplete these gas reserves over a year period would equate to a daily rate of production in the range of 500 MMscfd. Over 30 processes were considered and pre-screened for the recommended benchmark studies. See Appendix B Benchmark Analysis From the list generated in the Pre-Screening Study, the following eight (8) benchmark projects were selected: Process Owner Onshore/Offshore Compressed Natural Gas (CNG) Cran & Stenning Technologies Onshore or Offshore Liquefied Natural Gas (LNG) ExxonMobil Offshore Liquefied Natural Gas (LNG) BP Amoco-Trinidad ALNG Plant Onshore Fischer-Tropsch GTL Chevron/Sasol-Escravos, Nigeria Onshore non-pipeline final.doc Page 4 065/07129 : Rev 2 : 7-Dec-00

11 Process Owner Onshore/Offshore Fischer-Tropsch GTL Rentech, Sasol, Snytroleum, Others Offshore Methanol GTL Statoil/Conoco-Norway Onshore Methanol GTL GTL Resources-Vietnam Offshore Gas-to-Methanol-to-Gasoline (MTG) GTL Peak Petroleum-W. Africa Offshore The scope of the Benchmark Analysis included an evaluation of the following areas of interest: Minimum resource requirements. Market factors. Facility/plant size. Technological risks. CAPEX and OPEX costs. Employment levels. Other considerations. Only the onshore Atlantic LNG and onshore Statoil/Conoco Methanol Plant projects are currently existing. The onshore Chevron/Sasol Gas-to-Liquids project is being planned based on a background of existing operating onshore plants. Peak Petroleum and GTL Resources have potential offshore projects in Vietnam and West Africa, respectively, that have been investigated in detail from a background of existing operating onshore plants. The remaining three (3) analyses are offshore concepts that have not been studied from the standpoint of a specific site, but are based on well-proven principles and/or existing operating onshore plants. A combination of both offshore and onshore benchmark projects was recommended based on the reality that a pipeline solution to transport the gas to Newfoundland is a possibility, but once onshore, most of the gas will still be stranded, and require additional processing or transportation to make it marketable. Thus, we believe that non-pipeline options for both onshore and offshore applications have merit. Preference was given to those types of projects that could utilise volumes of feed gas of 100 MMscfd or more. We refer to these types of projects as anchor projects or primary projects. Those projects that utilise lower volumes of gas are considered secondary projects, and although these smaller projects will undoubtedly be very important to the overall growth of Newfoundland s natural gas industry, they are not directly relevant to the scope of this study. In fact, it is realistic to expect that a combination of secondary projects may at some point become a significant part of the natural gas industry in Newfoundland, and could be the subject of future studies. non-pipeline final.doc Page 5 065/07129 : Rev 2 : 7-Dec-00

12 2.3 Other Considerations There is too much gas offshore Newfoundland to produce only electric power, due to a limited onshore local market and long overland distances to other markets. In addition, the cost for offshore-generated electric power and subsea cable would be about the same as a gas pipeline to shore with onshore generation of electricity. Based on these factors, this concept was not recommended as a pre-screening option. Consideration of offshore methanol production should be on the basis of justifying one or two plants at a time, each with a capacity of 3,000 tonne/day on an FPSO or 2,400 tonne/day onshore. Larger volumes of new methanol on the market would likely adversely affect world market prices. There is a potential for production of large volumes of diesel and naphtha by the Fischer-Tropsch process without significantly affecting world market prices. It is unlikely that only one development concept, by itself, will utilize and monetize all of the gas production from the Grand Banks. There is a much higher probability that multiple non-pipeline and pipeline concepts will be desired or required. This is based on constraints due to the market s ability to absorb certain products, swings in market pricing, practical plant size constraints, ability to finance, the need to spread the risks out among several projects, the risks associated with taking on world-class size projects, and the needs or preferences of the oil operators that are involved. Ultimately, the ability to provide project financing may be the primary driver. The guarantee of long term gas supplies and gas sales contracts, government policy, tax incentives, technology improvements, environmental and safety concerns, etc. will significantly influence project financing. Any one, two, or a combination of concepts can potentially create the foundation from which the building blocks of a world-class natural gas industry can be built in Newfoundland. This overall growth could ultimately create significant employment. 2.4 Technical Feasibility Analysis Based on the results of the Benchmark Analysis, the offshore projects selected for the Technical Feasibility Analysis were as follows: a) Compressed Natural Gas. b) Liquefied Natural Gas. c) Conversion of Gas to Liquids (methanol, MTG, and F-T). For each of the projects, the following key considerations were taken into account: non-pipeline final.doc Page 6 065/07129 : Rev 2 : 7-Dec-00

13 Production Profile Gas production rates of 500 MMscfd in the year 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 shared services. Processing Requirements Offshore vs. Onshore processing. Composition of the raw natural gas. Mode of Transportation Non-pipeline transportation; LNG, CNG, GTL via seagoing vessels. Field to market vs. field to onshore and onshore to market. Infrastructure Requirements Site availability for landfall, storage requirements, and other infrastructure. Possible utilization of Newfoundland site-specific infrastructure. Cost Estimates CAPEX vs. OPEX. Annual employment. Capture rates. Technology Status Existing, design stage, or conceptual. Identify additional R&D work required. For detailed information on the above, refer to Appendices B1 (Pre-Screening Study), B2 (Industry Benchmark Analysis Summary), and B3 (Technical Feasibility Analysis). non-pipeline final.doc Page 7 065/07129 : Rev 2 : 7-Dec-00

14 3. ECONOMIC FEASIBILITY ANALYSIS 3.1 Case Descriptions Based on the findings of the Technical Feasibility Analysis, the following seven (7) offshore cases were agreed upon for economic feasibility analysis and sensitivities Compressed Natural Gas - FPSO Gas Hub The gas and liquid production would be processed on an FPSO that has separation, dehydration and gas compression equipment sized for 500 MMscfd of natural gas and 25,000 barrels of oil / condensate. A minimum of seven (7) CNG vessels would be chartered to transport the gas from the FPSO to markets in the U.S. and Canada. Onshore facilities to offload the CNG ships are also included Compressed Natural Gas - FPSO Incremental Gas Hub This case accounts for only the incremental cost to produce and market the gas, excluding what is attributed to a stand alone oil project. Thus, only the incremental increase in costs for a larger FPSO, additional topside equipment, additional operating costs, gas wells, glory holes and subsea equipment, etc. are taken into account. Seven (7) CNG vessels would be chartered to transport the gas from the FPSO to markets in the U.S. and Canada. Onshore facilities to offload the CNG ships are also included Compressed Natural Gas - GBS Gas Hub The gas and liquid production would be processed on a gravity based structure (GBS) that has separation, dehydration and gas compression equipment sized for 500 MMscfd of natural gas and 25,000 barrels of oil / condensate. Seven (7) CNG vessels would be chartered to transport the gas from the GBS to markets in the U.S. and Canada. Onshore facilities to offload the CNG ships are also included Compressed Natural Gas - GBS Incremental Gas Hub This case accounts for only the incremental increase in cost to produce and market the gas, excluding what is attributed to a stand alone oil project utilizing the GBS concept. Only the costs for additional gas wells and subsea equipment, additional topside equipment, additional operating costs, etc., are taken into account. Seven (7) CNG vessels would be chartered to transport the gas from the GBS to markets in the U.S. and Canada. Onshore facilities to offload the CNG ships are also included Liquefied Natural Gas Floating Gas Hub All gas and liquid production would be processed on a floating LNG concrete barge that has separation, dehydration and LNG equipment sized for 500 MMscfd of natural gas and 100,000 barrels of oil / non-pipeline final.doc Page 8 065/07129 : Rev 2 : 7-Dec-00

15 condensate. LNG transportation vessels were assumed to be chartered by the LNG purchaser to transport the LNG from the barge to markets in the U.S. and/or Europe Liquefied Natural Gas - Incremental FPSO Gas Hub This case accounts for only the incremental increase in cost to produce and market the LNG, excluding what is attributed to a stand alone FPSO oil project. Thus, only the costs for more wells and subsea equipment, additional topside equipment, additional operating costs, etc. are taken into account. LNG transportation vessels were assumed to be chartered by the LNG purchaser to transport the LNG from the barge to markets in the U.S. and/or Europe Gas-to-Liquids - Incremental to FPSO Development This case accounts for only the incremental increase in cost to produce and market the GTL products, excluding what is attributed to a stand alone FPSO oil project. Thus the costs for one larger production/gtl FPSO vessel and one additional GTL FPSO are included, as well as additional gas wells and subsea equipment, additional GTL topsides equipment, additional operating costs, etc. Only 440 MMscfd of gas can be processed in the costed development scenario. 3.2 Methodology The economic analysis was based on two measurement criteria: a) The Net Present Value (NPV) of the project based on a fifteen percent (15%) discount rate (expressed as NPV 15 ), and b) The $/MMBtu available for sharing after corporate income tax is paid and a 15% rate of return (NPV 15 = 0) is earned on the investment in production, gas processing and transportation facilities. This criteria represents an approximate value of the gas available for revenue sharing among the various stakeholders: government, natural gas producers, and any third-party project developer(s). This measure could be interpreted as comprising royalties and/or the project risk premium required above a 15% real rate of return on the investment. This criteria is calculated based as an average unit value over the life of the project in real dollar terms. Project economics were run based on all costs and revenues incurred from the wellhead to market, including drilling costs. This approach takes into account the costs incurred by the upstream (producer), midstream (project developer), and downstream (transporter) stakeholders. This methodology was chosen as a way to simplify the requirements for each stakeholder since they will all have their own criteria for determining what minimum economic threshold must be achieved before committing to a project. A 15% ROR project, with some upside for each stakeholder, was deemed a reasonable return on investment on which to compare the various methods of marketing the gas. non-pipeline final.doc Page 9 065/07129 : Rev 2 : 7-Dec-00

16 For each offshore case, both a stand-alone gas project and an incremental-to-oil project were evaluated. An incremental-to-oil project has many advantages compared to a stand-alone project. For example, the oil revenues from an incremental-to-oil project will payout the majority of CAPEX and OPEX costs on its own merits with only a portion of the gas revenues required to pay out the incremental costs required to process and send the gas to market. Offshore gas volumes of 500 MMscfd was the assumed production forecast for the offshore CNG and LNG cases. The GTL cases were limited to process a daily volume of 443 MMscfd to avoid incurring disproportionate cost increases to process 500 MMscfd. 3.3 Parameters Timing The analysis is based on a twenty-year production profile; commencing in 2005 and lasting until Project Development Schedule A 48-month project development schedule was assumed. This would allow time to prepare the development application, obtain regulatory approvals, obtain financing, perform concept-screening studies, conduct pre-engineering, detailed engineering, construction, and installation. Product Pricing The pricing on many LNG long term contracts is based upon market index pricing at the delivery point. It is reasonable to assume that this would occur with Newfoundland LNG as well. Any extra value for the LNG because of its application to niche markets, such as peak shaving, is likely to be retained by the terminal owners. Because of the current over supply situation in the market place, LNG cargoes have also sold for a discount (i.e. close to their variable cost). Since it is unlikely that a new LNG project in Newfoundland would go forward without some long term contractual commitments for the LNG product, the discounted prices near variable costs are probably too pessimistic. The CNG market is immature at the moment, but is reasonable to assume that CNG would compete with pipeline gas in the market place that it serves. So again, it is reasonable to assume that city-gate pricing would be an appropriate price indicator for project evaluation purposes. Downtime Production curtailments due to weather, mechanical failure, etc. were assumed to be 10 days per year. non-pipeline final.doc Page /07129 : Rev 2 : 7-Dec-00

17 Burdened versus Unburdened All cases were burdened with corporate income tax (CIT), but no royalty. The following methodology and definitions were used in calculating CIT: Drilling costs are separated from other capital costs. Drilling costs are depreciated at a 30% declining balance. For the purpose of this exercise, we have assumed that all wells are production type wells or can be converted into production type wells. If they were pure exploration wells, then they would be fully expensed. Non-drilling capital costs are depreciated at a 25% declining balance. Profits are defined as revenue less operating costs less depreciation allowances less interest costs. A resource allowance is deducted from the profit base. This resource allowance is 25% of the profit base exclusive of interest costs. A 10% investment tax credit is applicable to non-drilling costs. The provincial tax rate is 14%, the federal rate is 28% and federal surtax of 4% is also applicable. Full Flow Through Analysis versus Stand-Alone Analysis Full Flow Through Analysis allows the project to write-off any yearly losses against other revenues a company would have from other projects. Stand-Alone Analysis requires the project to carry forward any annual losses and write them off against future profits of the project. Debt versus Equity Project sensitivities were run on equity participation of 100%, 50%, and 25%. Finance borrowing rates used were a conservative 10% real per annum with a 15-year repayment schedule that commences with production. The summary table presented represents the case for 100% equity participation and 0% financed (debt). MMscfd and MMBtu/d Gas is measured on a volume basis (i.e. cubic feet in North America). However, gas is sold on a Btu basis ($/MMBtu), which gives credit for the heating value of the gas. For offshore Newfoundland, the average BTU value of the gas was assumed to be 1,116 Btu/cubic foot. Selection of Base Case Evaluation Criteria Full Flow Through Analysis was selected because the likelihood is high that any company involved in natural gas development for offshore Newfoundland will have other revenues from which to write-off any negative cash flows. non-pipeline final.doc Page /07129 : Rev 2 : 7-Dec-00

18 Base cases were run using the 100% equity base. In terms of decision criteria, NPV 15 reflects a 15% real ROR on production, gas processing and transportation. The $/MMBtu criteria is what is available for sharing after Corporate Income Tax (CIT) is paid and a 15% ROR is earned on the investment. Economics were calculated on an after CIT basis to show a clearer picture of how much money would be available for revenue sharing. 3.4 Project Economics and Sensitivities Project economic results of the seven (7) offshore cases are summarized in Table 1. All cases have a positive rate of return, however the offshore GTL case is the only case that didn t exceed the 15% rate of return threshold. The incremental cases all show favorable economics as compared to the stand-alone cases, as would be expected. And generally, the lower capital cost (Capex) projects have better economics than the higher cost projects. Economic sensitivities were evaluated only for the offshore cases by varying many different parameters to determine how they affected the economics. The sensitivities were calculated around a base case, which assumed 100% equity financing. The results of these sensitivities are shown graphically in Appendices A1 through A3. The various parameters where varied as follows: Product Pricing The CNG, LNG, methanol and F-T product pricing forecasts varied from +25% to 25% of the base case. Product prices were supplied by ICF Consulting, Inc. In almost every case, the product pricing had the biggest impact on economics. If product prices increase by 25%, most of the project scenarios would be economic. If product prices decrease by 25%, except for a couple of the CNG scenarios, the project scenarios become uneconomic. Capital Cost Sensitivities Capital costs (CAPEX) were varied from + 25% to 25%. CAPEX costs were developed during the Technical Feasibility Analysis (see Appendix B3). The sensitivity results indicate that if the CAPEX can be reduced by 25%, the project economics improve significantly. For capital-intensive projects like LNG, a 25% CAPEX reduction will increase the $/MMBtu available for revenue sharing by $0.50 to $1.00/MMBtu. Increased CAPEX for the capital-intensive projects, LNG and GTL, make them uneconomic. For less capital-intensive CNG projects, increased CAPEX has a smaller impact on economics. Operating Cost Sensitivities Operating costs (OPEX) were varied from + 25% to 25%. OPEX costs were developed during the Technical Feasibility Analysis. Fluctuations in OPEX costs showed very little impact on the non-pipeline final.doc Page /07129 : Rev 2 : 7-Dec-00

19 overall economics for the CNG and incremental LNG cases. However, for the stand alone LNG and the incremental GTL cases, a 25% increase in OPEX had a more significant negative effect on the overall economics. Equity Financing Equity Financing was varied from 100% equity to 25% equity. The assumed borrowing rate was 10% per annum. The results show that financing a project improves the economics due to the impact of leveraging. However, there are many factors that a company must consider when leveraging its capital structure with debt. For this reason, we have assumed 100% equity financing as a base case assumption. Escalation Sensitivity All costs and revenues are in real terms. Project sensitivities were run to determine the impact of incremental cost and revenue escalation of 1, 2 and 3 percent per annum on costs and revenues. Escalation had a positive effect on economics as the revenue increase outweighed the increase in costs. Transportation Costs Transportation costs for the gas products to market by means of CNG, LNG or Methanol transportation carriers were varied by +25% to 25% in most cases. Costs for CNG and LNG transport ships were not capitalized. It was assumed that the CNG vessels would be built, owned and operated by a third party on charter basis. CNG transportation costs were based on work developed by Cran and Stenning Technologies who previously analyzed costs with regards to Newfoundland. These costs have been verified by Worley International, Inc. A 25% increase in CNG transportation costs results in an approximate C$0.35 cent reduction in the amount available for revenue sharing. LNG transportation and regasification facilities were assumed to be furnished by the purchaser. Based on the ICF Marketing Report, a Newfoundland net-back price for LNG would be the market price in the U.S. or Europe less C$ 1.00/ Mcf. A 25% increase in LNG transportation costs results in an approximate C$0.25 cent reduction in the amount available for revenue sharing. Methanol transportation costs were estimated at C$ per tonne to the U.S. Gulf Coast. The Fischer Tropsch product pricing was based on a Newfoundland net-back price per the ICF Marketing Report, that had estimated that transportation to the U.S. Gulf Coast would be C$1.276 per barrel. A 25% increase in GTL transportation costs results in an approximate C$0.40 cent reduction in the amount available for revenue sharing. It should be noted that capital lease commitments could impact a corporation s ability to raise capital. Though not reflected in this analysis, some would argue that lease payments must be non-pipeline final.doc Page /07129 : Rev 2 : 7-Dec-00

20 converted into capital equivalents in order to quantify the full financial impact of a particular project. 3.5 Ringfence Analysis As an alternative to a wellhead to market economic analysis, a ringfence economic analysis was conducted that considered only the capital costs, operating costs, and revenues of the conversion segment. The purpose of the ringfence analysis is to provide a comparative net back price for each case after taking into account revenues and deducting a cost of service for the conversion scheme: in other words, the price paid to the producer. This project netback is a typical indicator by which alternative development options are compared in the petroleum industry, but are not a measure of the wellhead-to-market economics. None of the ringfence cases were burdened with inter-field flowline costs and other production costs. The results of the three (3) ringfence cases are summarized in Table 2, and described below: CNG Ringfence This case evaluated the economics of transporting the gas via CNG vessels after leaving either an FPSO or a GBS. The type of production facility used does not matter, as the majority of the capital costs and operating costs are attributable to the CNG vessels. The CAPEX costs are drastically reduced as only the mooring system and onshore receiving facilities are required in this case, yet the gas revenues are the same. The only revenue reduction is that there is no credit for associated liquids that were produced with the gas. With the base assumption that the CNG fleet of ships are chartered, the economics are very attractive, with an IRR of 88.8% and an NPV 15% of C$1.45 billion dollars LNG Ringfence This case evaluated the economics of placing a floating LNG facility near an FPSO or a GBS facility. Due to the fact that the gas revenues alone must payout the huge capital cost of the LNG facility, the economics are very poor compared with a combined development, which was marginal. This case assumes that the LNG transportation ships are chartered GTL Ringfence In this scenario, two FPSO s with only GTL required equipment were assumed to be located nearby an existing FPSO or GBS production. Each FPSO was required to be 375m long x 54m wide to support all of the equipment and process 530 MMscfd of natural gas. In this case, the incremental GTL revenue and reduced upstream capital costs mostly offset the disadvantage of losing the associated oil and condensate revenue. Thus the economics remain virtually unchanged, but still marginal at best. non-pipeline final.doc Page /07129 : Rev 2 : 7-Dec-00

21 3.6 Onshore Analysis The study investigated these non-pipeline options onshore in the event that an offshore pipeline would be justified to transport the gas from the Grand Banks to the Island. The results of the four (4) onshore cases are summarized in Table 3. The onshore cases analyzed are as follows: a) Compressed Natural Gas. b) Liquefied Natural Gas. c) Conversion of Gas to Liquids (methanol and F-T). Each onshore project was calculated based on all costs and revenues from the inlet of the CNG, LNG, or MeOH facilities plant fence to market. This approach takes into account the costs incurred only by the onshore project developer and the final product transporter. The upstream and pipeline costs will be determined by a study being conducted by the Department of Mines and Energy, and were not included in this analysis. The onshore cases were based on inlet volumes of 490 MMscfd. This was based on the net amount of gas after compression offshore to move the gas to shore. For comparison purposes, all onshore cases were evaluated on this same basis. The onshore methanol plant would consist of seven (7) trains of 2,370 tonnes each. One of the largest existing modern single train onshore plant is rated at 2,400 tonnes per day. It is prudent to note that with regards to a methanol plant, it is not suggested that a seven (7) train methanol plant be built at one time. The plant would realistically be built one train at a time, phasing in a new train only when justified based on favorable long term price projections for methanol, and to coincide with the economic availability of gas from offshore developments. There are concerns that the supply of methanol could exceed demand, especially if MTBE is globally banned from the gasoline pool. Some forecasters believe that any significant increases in methanol supplies could seriously impact the price. In addition, the first train and infrastructure would be more expensive to build than the second and third trains, etc. On the upside, there are forecasts that many of the old methanol plants in the U.S. will be shut down as the average cost of gas exceeds US$3.00/MMBtu, requiring more methanol plants to be built elsewhere using low cost gas. In September 2000, the cost of gas reached US$5.00/MMBtu and at least three old plants have been shut down. This economic evaluation did not try to capture all of these issues. non-pipeline final.doc Page /07129 : Rev 2 : 7-Dec-00

22 3.7 Summary Results The results of the economic analysis of non-pipeline development options can be summarized as follows: Offshore CNG options are more economic than either LNG or GTL based on the given product price forecasts. LNG economics are more favorable than the GTL options. These results are summarized in Table 1. Ringfencing shows that capital intensive projects like LNG are not economic as a stand-alone project. This is shown is Table 2. Onshore, the economics of CNG are more favorable than LNG and FT. The methanol plant economics also look attractive, however, this is based on the assumption that the methanol market could absorb the huge increase in methanol production without a negative price impact. Incremental cases improve project economics over non-incremental cases because a significant portion of the overall CAPEX and OPEX burden is attributed to what would otherwise have been a stand alone oil project. Table 1 shows that the incremental cases are much more attractive than the non-incremental (i.e., stand-alone) cases. Full Flow Through Analysis improves project economics because an owner s negative cash flow during the early years of the project can be written off against taxable revenues earned from other operations. Sensitivities indicate the project economics are most sensitive to gas prices and CAPEX. Increased OPEX and transportation costs have less of an effect on the economics. non-pipeline final.doc Page /07129 : Rev 2 : 7-Dec-00

23 ECONOMIC SUMMARIES Assumptions: Full Flow Through Analysis, CIT burdened, No royalty, 100% Equity, 2000 $ Offshore CNG FPSO Gas Hub 1 TABLE 1 OFFSHORE ECONOMIC SUMMARY Offshore CNG GBS Gas Hub 1 Offshore CNG Incremental to FPSO Oil Development 1 Offshore CNG Incremental to GBS Oil Development 1 Offshore LNG (Oil & Gas) 1 Offshore LNG Incremental to FPSO Oil Development 1 Offshore GTL MeOH / F-T Incremental to FPSO Oil Development 2 Capex (C$ M) 3,308 3,570 2,431 2,528 6,030 3,674 4,800 OPEX (C$/yr) Revenue (C$ M) 21,860 21,860 21,860 21,860 25,686 19,722 18,194 NPV@15% (C$ M) ,085 1, (213) Real IRR % 20.5% 18.8% 34.4% 35.2% 16.4% 18.3% 13.4% $/MMBtu Available for Sharing $0.90 $0.69 $2.03 $2.09 $0.42 $0.59 ($0.43) Notes: 1. Based on 500 MMscfd of Inlet Gas. 2. Based on 440 MMscfd of Inlet Gas, 2 FPSO s, 1 with F-T only and 6 trains, the GOSP FPSO has 4 MeOH trains 3. Exchange rate = $0.70 US/CDN, Methanol price = $130 US/tonne and ICF natural gas prices were based on 1031 BTU per SCF and were adjusted for the expected Newfoundland gas BTU content of 1116 BTU per SCF. non-pipeline final.doc Page /07129 : Rev 2 : 7-Dec-00

24 ECONOMIC SUMMARIES Assumptions: Full Flow Through Analysis, CIT burdened, No royalty, 100% Equity, 2000 $ TABLE 2 RINGFENCE ECONOMIC SUMMARY Ringfence CNG Transportation 1 Ringfence LNG Gas Conversion and Transport 1 Ringfence GTL (Gas Only Hub) 2 Capex (C$ M) ,891 3,799 OPEX (C$/yr) Revenue (C$ M) 19,196 17,085 20,789 NPV@15% (C$ M) 1,446 (263) (163) Real IRR % 88.8% 12.7% 14.0% $/MMBtu Available for Sharing $ 2.71 $(0.49) $ (0.27) Notes: 1. Based on 500 MMscfd of Inlet Gas. 2. Ringfence MeOH / GTL case: Based on 530 MMscfd, 2 FPSO s, each with 6 trains. One F-T FPSO and one MeOH FPSO. 3. The estimated CAPEX for CNG vessels are based on an applicable charter rate of C$36.4 MM/year per CNG vessel. These costs are reflected in the OPEX. 4. Exchange rate = $0.70 US/CDN, Methanol price = $130 US/tonne and ICF natural gas prices were based on 1031 BTU per SCF and were adjusted for the expected Newfoundland gas BTU content of 1116 BTU per SCF. non-pipeline final.doc Page /07129 : Rev 2 : 7-Dec-00

25 ECONOMIC SUMMARIES Assumptions: Full Flow Through Analysis, CIT burdened, No royalty, 100% Equity, 2000 $ TABLE 3 ONSHORE ECONOMIC SUMMARY (excludes feed-gas costs) Onshore LNG Onshore CNG Onshore GTL: Methanol Onshore GTL: F-T Capex (C$ M) ,186 2,494 OPEX (C$/yr) Revenue (C$ M) 18,581 20,074 25,554 13,367 NPV@15% (C$ M) 573 1,404 1,213 (119) Real IRR % 22.5% 68.1% 26.3% 13.9% $/MMBtu Available for Sharing $ 1.08 $ 2.64 $ 2.30 $ (0.25) Notes: 1. Exchange rate = $0.70 US/CDN, Methanol price = $130 US/tonne and ICF natural gas prices were based on 1031 BTU per SCF and were adjusted for the fact that Newfoundland gas has 1116 BTU per SCF. 2. The New England city-gate price is the basis for evaluating the CNG and LNG options for Newfoundland natural gas. non-pipeline final.doc Page /07129 : Rev 2 : 7-Dec-00

26 Appendix A1 CNG Offshore Sensitivities A1-1 Offshore CNG FPSO Gas Hub A 1-2 Offshore CNG GBS Gas Hub A 1-3 Offshore CNG - FPSO Incremental Gas Hub A 1-4 Offshore CNG Incremental to GBS Oil Development non-pipeline final.doc Page A /07129 : Rev 2 : 7-Dec-00

27 A 1-1 Offshore CNG, FPSO Gas Hu Gas Price (+/- 25%) CAPEX (+/- 25%) OPEX (+/- 25%) $0.90 Equity Financing (100-25%) Escalation (0-3%) Transportation (+/- 25%) -$2.00 -$1.50 -$1.00 -$0.50 $0.00 $0.50 $1.00 $1.50 $2.00 $2.50 $3.00 $3.50 $/MMBtu Available for Sharing non-pipeline final.doc Page A /07129 : Rev 2 : 7-Dec-00

28 A 1-2 Offshore CNG, GBS Gas Hub Gas Price (+/- 25%) CAPEX (+/- 25%) OPEX (+/- 25%) $0.69 Equity Financing (100-25%) Escalation (0-3%) Transportation (+/- 25%) -$2.00 -$1.50 -$1.00 -$0.50 $0.00 $0.50 $1.00 $1.50 $2.00 $2.50 $3.00 $3.50 $/MMBtu Available for Sharing non-pipeline final.doc Page A /07129 : Rev 2 : 7-Dec-00

29 A 1-3 Offshore CNG, FPSO Incremental Gas Hub Gas Price (+/- 25%) CAPEX (+/- 25%) $2.03 OPEX (+/- 25%) Equity Financing (100-25%) Escalation (0-3%) Transportation (+/- 25%) -$2.00 -$1.50 -$1.00 -$0.50 $0.00 $0.50 $1.00 $1.50 $2.00 $2.50 $3.00 $3.50 $/MMBtu Available for Sharing non-pipeline final.doc Page A /07129 : Rev 2 : 7-Dec-00

30 A 1-4 Offshore CNG, Incremental to GBS Oil Development Gas Price (+/- 25%) CAPEX (+/- 25%) $2.09 OPEX (+/- 25%) Equity Financing (100-25%) Escalation (0-3%) Transportation (+/- 25%) -$2.00 -$1.50 -$1.00 -$0.50 $0.00 $0.50 $1.00 $1.50 $2.00 $2.50 $3.00 $3.50 $/MMBtu Available for Sharing non-pipeline final.doc Page A /07129 : Rev 2 : 7-Dec-00

31 Appendix A2 LNG Offshore Sensitivities A 2-1 Offshore LNG Oil and Gas A 2-2 Offshore LNG Incremental to FPSO Oil Development non-pipeline final.doc Page A /07129 : Rev 2 : 7-Dec-00

32 A2-1 Offshore LNG - Oil and Gas Gas Price (+/- 25%) CAPEX (+/- 25%) OPEX (+/- 25%) Equity Financing (100-25%) Escalation (0-3%) $0.42 Transportation (+/- 25%) -$2.00 -$1.50 -$1.00 -$0.50 $0.00 $0.50 $1.00 $1.50 $2.00 $2.50 $3.00 $3.50 $/MMBtu Available for Sharing non-pipeline final.doc Page A /07129 : Rev 2 : 7-Dec-00

33 A 2-2 Offshore LNG, Incremental to FPSO Oil Development Gas Price (+/- 25%) CAPEX (+/- 25%) OPEX (+/- 25%) $0.59 Equity Financing (100-25%) Escalation (0-3%) Transportation (+/- 25%) -$2.00 -$1.50 -$1.00 -$0.50 $0.00 $0.50 $1.00 $1.50 $2.00 $2.50 $3.00 $3.50 $/MMBtu Available for Sharing non-pipeline final.doc Page A /07129 : Rev 2 : 7-Dec-00

34 Appendix A3 GTL Offshore Sensitivities A 3-1 Offshore GTL Methanol/F-T Incremental to FPSO Oil Development non-pipeline final.doc Page A /07129 : Rev 2 : 7-Dec-00

35 A 3-1 Offshore GTL Methanol/F-T Incremental to FPSO Oil Development Methanol/FT Price (+22% to -17%) CAPEX (+25% to -10%) OPEX (+25% to -10%) -$0.43 Equity Financing (100-25%) Escalation (0-3%) Transportation (+20% - 10%) -$2.00 -$1.50 -$1.00 -$0.50 $0.00 $0.50 $1.00 $1.50 $2.00 $2.50 $3.00 $3.50 $/MMBtu Available for Sharing non-pipeline final.doc Page A /07129 : Rev 2 : 7-Dec-00

36 Appendix B1 Natural Gas Development Based on Non-Pipeline Options, Offshore Newfoundland, Pre-Screening Study Pre-Screening Study non-pipeline final.doc Page B /07129 : Rev 2 : 7-Dec-00

37 Appendix B2 Natural Gas Development Based on Non-Pipeline Options, Offshore Newfoundland, Industry Benchmark Analysis Summary Industry Benchmark Analysis Summary non-pipeline final.doc Page B /07129 : Rev 2 : 7-Dec-00

38 Appendix B3 Natural Gas Development Based on Non-Pipeline Options, Offshore Newfoundland, Technical Feasibility Analysis Technical Feasibility Analysis non-pipeline final.doc Page B /07129 : Rev 2 : 7-Dec-00