curacao cng-lng terminal feasibility study

CURACAO CNG-LNG TERMINAL FEASIBILITY STUDY

Table of Contents

i CURACAO CNG-LNG TERMINAL FEASIBILITY STUDY


TRANSMITTAL LETTER DISCLAIMER NOTICE NOMENCLATURE

1 EXECUTIVE SUMMARY 1.1 Introduction 1.2 Scope of Study 1.3 Summary of Results 1.4 Conclusions and Recommendations 1.5 Next Steps for the Project

2 GAS MARKET ASSESSMENT

2.1 Introduction 2.2 Island Electric Utility (Aqualectra) 2.3 Isla Refinery (CRUC) 2.4 Seasonal, Daily and Hourly Demand Fluctuation 2.5 Demand Growth 2.6 Neighbouring Islands 2.7 Natural Gas and Fuel Oil Price Forecasts 2.8 Gas Quality Requirements

3 GAS SUPPLY CONCEPTS

3.1 Introduction 3.2 CNG Option 3.3 LNG Options 3.4 Gas Import Pipeline Options

4 COMMERCIAL EVALUATION

4.1 Introduction 4.2 Commercial Evaluation Basis 4.3 CAPEX and OPEX Estimates 4.4 Delivered LNG Price (C.I.F. Curacao Terminal) 4.5 Curacao Average Delivered Gas Price 4.6 Curacao Gas Cost vs. Gas Rate 4.7 Risk Matrix Analysis 4.8 Conclusions

5 LNG SUPPLY

5.1 Introduction 5.2 LNG Industry Overview 5.3 LNG Quality Specification 5.4 Typical LNG Supply Contract Terms 5.5 Potential LNG Suppliers

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ii CURACAO CNG-LNG TERMINAL FEASIBILITY STUDY

5.6 Pooling LNG Supply With Neighbouring Islands 5.7 Conclusions

6 LNG SHIPPING AND TRANSPORTATION

6.1 Overview 6.2 Availability of Ships 6.3 Shipping Costs and Losses 6.4 Port Requirements 6.5 Conclusions

7 TERMINAL LOCATION ASSESSMENT

7.1 Introduction 7.2 LNG Terminal Site Locations 7.3 Bullen Bay Site Option 7.4 Schottegat Harbor Site Option 7.5 LNG FSRU Option 7.6 Advantages / Disadvantages 7.7 Conclusions

8 CONCEPTUAL CURACAO LNG TERMINAL

8.1 Overview 8.2 Marine and Unloading Facilities 8.3 LNG Storage 8.4 BOG and Ship Vapor Return System 8.5 LNG Pumps, BOG Condenser and LNG Sendout System 8.6 LNG Vaporization System 8.7 Gas Sendout System 8.8 Operations Control System 8.9 Utility Systems 8.10 Safety Systems 8.11 Security Systems 8.12 Buildings and Infrastructure 8.13 Layout Plot Plan

9 CONCEPTUAL CURACAO GAS SENDOUT PIPELINE

9.1 Overview 9.2 Route 9.3 Size, Capacity and Design Parameters 9.4 Constructability 9.5 Pipeline Operations Control

10 OPERATIONS AND MAINTENANCE

10.1 Overview 10.2 Personnel Training 10.3 Owner Staffing and Labor Costs 10.4 Operations and Maintenance Budget

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iii CURACAO CNG-LNG TERMINAL FEASIBILITY STUDY

11 INTEGRATED SYSTEM PERFORMANCE 11.1 Reliability 11.2 Backup Fuel Supply 11.3 Turndown Flexibility 11.4 Expandability 11.5 Conclusions

12 PROJECT EXECUTION PLANNING

12.1 Execution Plan Framework 12.2 Development Planning 12.3 Construction Strategy / Philosophy 12.4 Typical Project Schedule

13 REGULATORY AND PERMITTING

13.1 Environmental, Social, Health and Safety 13.2 Environmental Regulations and Global Standards 13.3 Curacao Permitting Requirements 13.4 Financial Institution Requirements 13.5 ESHS Issues of Concern 13.6 Conclusions and Recommendations

14 COMMENTS ON PROJECT FINANCING

14.1 Overview 14.2 Equity Requirements 14.3 Typical Lending Organizations 14.4 Terms and Criteria 14.5 Risk 14.6 Equator Principles 14.7 Lenders Due Diligence Report

15 APPENDIX

A. Conceptual Basis of Design B. Process Flow Diagram With Heat & Material Balance C. Terminal Layout D. Major Equipment List E. Utility Load Summary F. Key Milestone Project Schedule G. LNG Shipping Route Charts H. Historical Hurricane Tracking Charts


Disclaimer Notice

This document was prepared by Shaw Consultants International, Inc. (Consultant) for the benefit of the Refineria di Korsou N.V. (Company) and their respective lenders (collectively, the Beneficiaries). With regard to any use or reliance on this document by any party other than the Beneficiaries and those parties intended by the Beneficiaries to use this document (Additional Parties), Consultant, its parent, and affiliates: (a) make no warranty, express or implied, with respect to the use of any information or methodology disclosed in this document; and (b) specifically disclaims any liability with respect to any reliance on or use of any information or methodology disclosed in this document.

Any recipient of this document, other than Beneficiaries and the Additional Parties, by their acceptance or use of this document, releases Consultant, its parent, and affiliates from any liability for direct, indirect, consequential, or special loss or damage whether arising in contract, warranty, express or implied, tort or otherwise, and irrespective of fault, negligence, and strict liability of Consultant.

Nomenclature

CRUACAO CNG-LNG TERMINAL FEASIBILITY STUDY

AAV Ambient Air Vaporizer ABS American Bureau of Shipping ACI American Concrete Institute ACQ Annual Contract Quantity AISC American Institute of Steel Construction ANSI American National Standards Institute APCI Air Products & Chemical Inc. API American Petroleum Institute ASCE American Society of Civil Engineers ASME American Society of Mechanical Engineers ASNT American Society for Non-Destructive Testing ASTM American Society for Testing and Materials AWS American Welding Society BACT Best Available Control Technology bcf Billion Cubic Feet BOG Boil Off Gas from LNG Bscfd or Bcfd Billion Standard Cubic Feet per Day Btu British Thermal Unit bpd Barrels per Day BOE Barrel Oil Equivalent CAER Community Awareness and Emergency Response CAPEX Capital Expenditure CCR Central Control Room CO Carbon Monoxide CFR Code of Federal Regulations CNG Compressed Natural Gas CP Conditions Precedent LNG Contract. Also Curacao Peil Reference Datum CPI Consumer Price Index Published by U.S. Department of Labor Statistics CRUC Curacao Refinery Utility Company CSP Contract Sales Price DCS Distributed Control System DNV Det Norske Veritas (A Ship Classification Society) DWP Deep Water Port F&G Fire and Gas Detection ECA Export Credit Associations EDIN Energy Development in Island Nations EIA U.S. Energy Information Administration EIB European Investment Bank EIAS Environmental Impact Assessment Study EIS Environmental Impact Statement EPC Engineering, Procurement and Construction ESD Emergency Shut Down ESHS Environmental, Social, Health and Safety ETA Estimated Time of Arrival FEED Front End Engineering Design FERC Federal Energy Regulatory Commission FI Financial Intermediaries. Also Flow Indicator FPSO Floating Production Storage Offloading (Associated With Oil Production) FSRU Floating Storage Regasification Unit for LNG

Nomenclature


ft Feet GOC Government of Curacao H2S Hydrogen Sulfide HAZOP Hazards and Operability HHW High High Water HM Heating Medium (fluid used for heat transfer) hp Horsepower HP High Pressure HSFO High Sulfur Fuel Oil HTF Heat Transfer Fluid HWS High Water Spring Hz Hertz (frequency cycles per second) IAS Integrated Automation System IBC International Building Code IBRD International Bank for Reconstruction and Development ICSID International Centre for Settlement of Investment Disputes ICSS Integrated Control and Safety System IDB Inter-America Development Bank IDA International Development Association IDC Interest During Construction IEC International Electrotechnical Commission IEEE Institute of Electrical and Electronic Engineers IFC International Finance Corporation IMO International Maritime Organization IRR Internal Rate of Return ISA Instrument Society of America ISO International Standards Organization ITC Independent Technical Consultant ITS Interruptible Transportation Service JBIC Japan Bank for International Cooperation JV Joint Venture kV Kilovolt kW Kilowatt LLW Low Low Water LNG Liquefied Natural Gas LNGC LNG Carrier LS Lump Sum LSFO Low Sulfur Fuel Oil LWS Low Water Spring m2 Square Meter m3 Cubic Meter m3/hr Cubic Meter per Hour At Actual Flowing Conditions MAOP Maximum Allowed Operating Pressure (for pipelines) MCC Motor Control Center MIGA Multilateral Investment Guarantee Agency MOU Memorandum of Understanding MMBtu Million British Thermal Units MMscfd Million Standard Cubic Feet per Day MP Mile Post MPHEN Curacao Ministry of Public Health, Environment and Nature

Nomenclature


MSS Manufacturer Standardization Society mtpa Million Tonnes per Annum MW Megawatt N2 Nitrogen NACE National Association of Corrosion Engineers NBP National Balancing Point in the UK NDE Non-Destructive Examination NEMA National Electric Manufacturers Association NFPA National Fire Protection Association NOx Nitrous Oxide NOI Notice of Intent NOR Notice of Readiness NOT Notice of Termination NPV Net Present Value NTP Notice To Proceed O&M Operations and Maintenance OBE Operating Basis Earthquake OC Operations Center OCIMF Oil Companies International Marine Forum OD Outside Diameter OECD Organization for Economic Cooperation and Development ORV Open Rack Vaporizer OSHA Occupational Safety and Health Administration OPEX Operating Expenditure PDVSA Petroleos de Venezuela S.A. PLC Programmable Logic Controller PLEM Pipeline End Manifold (Used in Subsea Pipelines) PMT Project Management Team PO Purchase Order PPE Personal Protective Equipment ppmv Parts per million by volume PSA Purchase Sales Agreement PSC Project Services Contractor psia pounds per square inch (absolute) psig pounds per square inch (gauge) PSV Pressure Safety Valve QA Quality Assurance QC Quality Control RAM Reliability, Availability and Maintainability RDK Refineria di Korsou N.V. ROW Right of Way SC Shipping Charge (LNG shipping cost) SCF or scf Standard Cubic Feet @ 14.65 psia and 60oF SCV Submerged Combustion Vaporizer SIGTTO Society of International Gas Tanker and Terminal Operations SO2 Sulfur Dioxide SPA Sales Purchase Agreement SPCC Spill Prevention and Containment Control SPL Sabine Pass Liquefication LLC SSE Safe Shutdown Earthquake

Nomenclature


SSPC Steel Structures Painting Council STL Submerged Turret Loading STS Side-to-Side LNG Transfer TCF or tcf or Tcf Trillion Standard Cubic Feet @ 14.65 and 60oF TEMA Tubular Exchanger Manufacturers Association UCC Unit Capacity Charge (for Liquefaction) UK United Kingdom UPS Uninterruptible Power Supply USCG United States Coast Guard V Volt VIP Vacuum Insulated Pipe VOC Volatile Organic Compounds W Watt WBG World Bank Group

Section 1 Executive Summary

1 - 1 CURACAO CNG-LNG TERMINAL FEASIBILITY STUDY

1.1 INTRODUCTION

In order to improve its international competitiveness and reduce its dependence on imported petroleum, the Government of Curacao (GOC) has implemented a strategy to diversify its energy supply. The strategy aims at introducing imported natural gas into Curacaos energy supply mix to improve security of supplies, achieve long-term stability in energy prices and to improve the environmental sustainability of providing energy. Importation of natural gas to Curacao could conceivably be by means of liquefied natural gas (LNG), compressed natural gas (CNG) or a gas import pipeline.

Environmental issues in Curacao stem from stack gas emissions containing significant quantities of sulfur dioxide (SO2). No. 6 high sulfur fuel oil (HSFO) is the primary fuel used to generate electrical power on the island with minor quantities of No. 2 HSFO. The HSFO is supplied by Isla Refinery, the local Curacao refinery currently being operated under a lease agreement with Petroleos de Venezuela S.A. (PDVSA). Aqualectra, the local public utility company, provides electrical power and water to the citizens of Curacao. The Curacao Refinery Utility Company (CRUC) operates electrical power generation facilities to supply the Isla Refinery with electric power. Also contributing to stack gas emissions is the Isla Refinery process steam boilers which burn high sulfur bitumen; essentially the bottom of the barrel.

The stated goals and objectives of GOC include the following:

Convert Curacaos power generation and refinery fuel to lower-cost, clean-burning natural gas; Reduce fuel cost for electric power generation and refinery operations; Reduce electrical power costs paid by the citizens of Curacao; and Reduce SO2 emissions to clean-up Curacao air pollution.

Refineria di Korsou N.V. (RDK) has undertaken the lead role in advancing the goals and objectives for the GOC. It is a nonprofit, government owned refining company in Curacao. RDK owns the Isla Refinery and the crude oil terminal and storage facilities located at Bullen Bay. These facilities are currently under long-term lease to PDVSA which expire in 2018. The Isla Refinery is an old refinery designed to process heavy Venezuelan crude originally owned and operated by Shell. The refinery was constructed and started up in 1918. Several years ago, Shell decided to abandon operation of the refinery and conveyed ownership of the facility to the GOC which was subsequently structured in ownership to RDK by the GOC.

In March 2012, RDK solicited competitive bids from multiple engineering firms to perform a study to evaluate the feasibility of bringing natural gas to Curacao. Shaw Consultants International, Inc. (Shaw Consultants) was the successful bidder and was awarded a contract for the study on March 12, 2012. Shaw Consultants has completed the study and this report documents the work, conclusions and recommendations.

1.2 SCOPE OF STUDY

RDK requested that Shaw Consultants evaluate the fundamental options for bringing natural gas supply to Curacao. Three gas supply options were evaluated including LNG, CNG, and natural gas import by pipeline. The scope of work for this study involved a broad examination of both technical and commercial aspects of the gas supply options.



The starting point for the study was an assessment of the potential local market demand for natural gas. Gas demand forecasts were prepared for Aqualectra, CURC and the Isla Refinery process steam boiler system (collectively referred to as the Curacao Demand). The assessment also considered potential gas demand loads from neighboring islands including Aruba and Bonaire.

Energy pricing forecasts were developed for natural gas at Henry Hub and UK National Balancing Point (NBP). LNG netback pricing mechanisms were evaluated for both UK NBP and Henry Hub indexation. Fuel oil price forecasts for No.6 and No.2 LSFO were also developed. Price forecast data published by the U.S. Energy Information Administration (EIA) served as the basis for such forecasts.

As part of this study, Shaw Consultants made a site selection study of alternative terminal site locations on Curacao including jetty sites at Schottegat Harbor and Bullen Bay.

One of the primary objectives of the study was to determine the delivered cost of gas for each of the gas supply options. A matrix of cases were defined and analyzed for each of the various gas supply options which included a total of 17 scenario cases. Rough CAPEX and OPEX estimates (+/-40%) were prepared for each of the scenarios. The delivered gas costs to the Curacao customers were then calculated for each scenario case. In determining the delivered gas costs, the CAPEX costs were amortized on a 10-year straight line basis and rolled in with the purchase costs the gas (or LNG) plus OPEX cost to obtain the all-in delivered cost of gas for each case.

An overview of LNG trade/shipping costs was prepared using Shaw Consultants in-house shipping model and data taken from the LNG Shipping Market 2011 Annual Review and Forecast published by Drewry Maritime Research June 13, 2011. The terms and provisions of a typical LNG purchase and sales agreement (PSA) were summarized and included in this report. Potential LNG supply sources for Curacao were identified and listed.

Shaw Consultants provided discussion of fuel supply reliability and suggestions for back-up fuel parameters. A preliminary risk assessment was made to identify project risks and mitigation steps were developed to minimize project risks.

Conceptual design documents were prepared for a conventional onshore LNG terminal including a preliminary basis of design, process flow diagrams, heat and material balances, layout drawing, equipment list, and utility load summaries.

To round out the study, Shaw Consultants prepared discussion on the following topics which are included in this report:

Integrated Operations/Maintenance Support; Integrated System Performance; Project Execution and Schedule Planning; Regulatory Issues; and Comments on Project Financing.



1.3 SUMMARY OF RESULTS

Curacao Gas Demand

If Aqualectra, CRUC, and the Isla Refinery process steam boilers were converted to natural gas fuel their combined current demand would average approximately 110 MMscfd with 19 MMscfd attributed to Aqualectra, 55 MMscfd attributed to CRUC and 36 MMscfd attributed to Isla Refinery process boiler fuel. Looking forward, the total Curacao demand is projected to grow to an average demand rate of 120.7 MMscfd by the year 2031. From historical records it was determined that the peak hourly demand rate for Aqualectras customer service load was approximately 25% above the annual average daily rate. Peak hourly demand for CRUC and Isla Refinery steam boiler fuel demand was assumed to be 10% above their respective annual average daily demand rates. To accommodate hourly peaking demand, a peak delivery capacity of 137.2 MMscfd would be required by the year 2031 based on Shaw Consultants analysis. The decision to switch CRUC and Isla Refinery to natural gas fuel was assumed to be deferred until 2018 based on the guidance provided by RDK. Figure 1.3-1 illustrates the Curacao gas demand forecast developed from this study.

Figure 1.3-1 Curacao Natural Gas Demand

Shaw Consultants note that there is risk of uncertainty in the Curacao demand forecast. At this time there is no surety that the Isla Refinery will continue to be in operation for the long-term. An expensive upgrade to the Isla Refinery will be needed to meet potential new air emissions standards for SO2 and to improve product quality slate for producing low sulfur fuel oil products. Until it is confirmed that the Isla Refinery will continue to operate long-term, the Curacao Demand Forecast should likely be risk weighted downward with a biased toward the Aqualectra demand load only. RDK will need to weigh the risks of potential closure of the Isla Refinery as it advances a project to bring natural gas to Curacao.

137.2

0

20

40

60

80

100

120

140

160

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031

MMscfd

Aqualectra CRUC Refinery TotalPkHour

120.7



Driving Force for Switching to Natural Gas

This study is based on the premise that Curacao environmental emission standards will be tightened to limit SO2 emissions form combustion gas stack discharge sources. If new tighter emission standards are adopted by the Curacao authorities, stack gas emissions will either have to be treated and cleaned-up to reduce SO2 emission levels or alternatively low sulfur content fuels will be mandated for used in combustion services (i.e. boilers, engines, turbines, etc.). This study assumes that existing combustion services will either have to burn No.2 or No.6 LSFO or otherwise convert to clean-burning natural gas in order to comply with potentially new tighter emission standards. Since No.6 LSFO has historically always been less expensive than No.2 LSFO, it is presumed in this study that the fuel cost comparison for natural gas conversion logically must be compared to the alternative of burning No.6 LSFO.

In this study, Shaw Consultants used the U.S. Energy Information Administration (EIA) forecasted prices for No.6 LSFO and Natural Gas at Henry Hub as reported in the EIA Annual Energy Outlook 2012 Early Release Report. The UK NBP price forecast was developed assuming that the recent historic differential between Henry Hub and UK NBP (~US$5.00/MMBtu) is maintained throughout the forecast period. Figure 1.3-2 illustrates the forecasts.

Figure 1.3-2 Price Forecast of No.6 LSFO and Natural Gas

An evaluation period from 2015 to 2031 was used to analyze the various gas supply options. The average price of No.6 LSFO over the evaluation period was determined to be US$153/Bbl or converted to Btu pricing US$24.36/MMBtu based on the forecasted prices illustrated in Figure 1.3-2.

The average delivered gas cost for each option was calculated over the evaluation period and compared to the corresponding average price of No.6 LSFO over such period (i.e. US$24.36/MMBtu). The delivered gas costs for each option were calculated with a base starting price indexed to Henry Hub with CAPEX



amortization and OPEX costs added in to determine the total delivered gas costs. Liquefaction fees, FSRU rental costs, and LNG shipping fees for the LNG options were added to the CAPEX amortization and OPEX costs in calculating the delivered gas costs for the LNG options. In principle, the difference between the average price of No.6 LSFO and the average delivered gas costs are the fuel cost savings realized in switching from No.6 LSFO to natural gas.

Switching from LSFO to natural gas fuel will, however, involve some conversion cost to modify the fired equipment to burn natural gas. These conversion costs will need to be deducted from the calculated fuel savings in order to derive the overall net fuel saving costs. The net fuel cost saving is the Driving Force for Switching to Natural Gas.

Estimating the cost of converting fired equipment from fuel oil to natural gas was not within the scope of this study. Separate studies have been made by others to quantify the fuel conversion costs. The results of these third-party studies will need to be integrated with the results of Shaw Consultants study in order to determine the overall net fuel saving costs for switching to natural gas.

Gas Supply Options

Figure 1.3-3 illustrates the average delivered gas cost for the scenario cases calculated for the various gas supply options.

Figure 1.3-3 Curacao Average Delivered Gas Cost

Gas Import Pipeline Option: The gas import pipeline option yields the lowest delivered gas cost to the Curacao customers. The calculated delivered cost of gas to serve the Curacao demand for this option ranged between US$7.82 to US$8.16/MMBtu. These costs reflect the average delivered price over the



evaluation period from 2015 to 2031 assuming gas supply is contracted at a purchase price (F.O.B. Columbia or Venezuela) equal to 100% of the Henry Hub forecasted price. Compared to the average price of No.6 LSFO (US$24.36/MMBtu or $153/Bbl), this option yields an average fuel cost savings of approximately US$16/MMBtu.

If Curacao and Aruba were to both participate and share costs in a gas import pipeline project, the delivered cost of gas to Curacao would be lower. The delivered cost of gas estimated for an Aruba-Curacao coop pipeline is US$7.56 to US$7.75/MMBtu depending on whether the supply is from Venezuela or Colombia.

If only the Aqualectra demand is served, the delivered cost of gas increases to a range of US$8.58 to US$9.20/MMBtu. With only the Aqualectra demand load, the average fuel cost savings is more than US$15/MMBtu compared to burning No.6 LSFO.

The estimated CAPEX for the gas import options range between US$193 to US$292 million depending on whether the supply is sourced from Venezuela or Colombia. If the pipeline is extended to include supply to Aruba, the CAPEX cost increases to US$328 million. If the pipeline is sized for only the Aqualectra demand load, the CAPEX cost is US$162 million. The pipeline project completion schedule is estimated to require approximately 42 months after obtaining an MOU for a gas supply contract.

Installing the gas import pipeline is clearly feasible. The maximum water depth of the subsea gas import pipeline would be approximately 4,000 feet which is well within the current capability of deep-water pipeline lay vessel companies such as AllSeas and Eni Saipem. Pipelines have been successfully installed in water depths up to 9,000 feet.

The major challenge for the pipeline option will be contracting for a long-term reliable gas supply. Both Venezuela and Columbia have gas supply that could potentially be tapped for export to Curacao via pipeline. It is uncertain how much time it would take to successfully negotiate a gas supply contract. However, until Curacao officials set down and discuss potential gas supply contracts with Columbian and Venezuelan producers, gas supply availability is only conjecture at this time.

Shaw Consultants research indicates in Columbia that the Guajira Basin has the greatest potential for exportable gas. Also, a recent press release by Pacific Stratus Columbia Corporation (a wholly owned subsidiary of Pacific Rubiales Energy Corp.) indicates that incremental gas supply could potentially be available for export from the La Creciente Field. Regarding possible Venezuelan gas supply, the new Cardon IV Block discovery may offer the best potential for a long-term gas contract supply.

To meet the total Curacao demand for 25 years requires approximately 1.1 tcf of natural gas. Total gas reserves reported for Columbia and Venezuela are 4 tcf and 179 tcf, respectively. Shaw Consultants note that Venezuela has the second largest proven natural gas reserves in the Western Hemisphere, but the pace of development of such resources has been very slow.

Onshore LNG Terminal Option: The onshore LNG terminal option, although not as attractive as the gas import pipeline option, also yields a considerable cost savings in comparison to burning No.6 LSFO. For this option, the calculated delivered cost of gas to serve the Curacao demand is approximately US$12.88/MMBtu. Again, cost reflects the average delivered price of gas over the evaluation period from 2015 to 2031. This option yields an average fuel cost savings of approximately US$11.50/MMBtu versus the alternative of burning No.6 LSFO.

If only the Aqualectra demand is served, the delivered cost of gas increases to US$14.86/MMBtu which is approximately US$9.50/MMBtu lower than the average cost of burning No.6 LSFO.



The estimated CAPEX for this option is approximately US$433 million based on a terminal equipped with a 160,000m3 LNG storage tank. The project completion schedule is estimated to require approximately 50 months.

If the terminal were sized with sendout capacity to supply gas for both Curacao and Aruba, the estimated CAPEX (including the cost of the export gas pipeline from Curacao to Aruba) is approximately US$567 million. The economy of scale and incremental gas delivery volumes to Aruba act to reduce the overall delivered gas cost for Curacao customers by approximately US$0.42/MMBtu.

FSRU LNG Terminal Option: The LNG FSRU option also yields a considerable cost savings in comparison to burning No.6 LSFO. The calculated delivered cost of gas to serve the Curacao demand for this option is US$13.92/MMBtu. Again, this cost reflects the average delivered gas price over the evaluation period from 2015 to 2031. This option indicates an average fuel cost savings of approximately US$10.44/MMBtu compared to burning No.6 LSFO.

If only the Aqualectra demand is served, the delivered cost of gas for this option increases to US$18.32/MMBtu. Even with only the Aqualectra demand load, the average fuel gas cost is approximately US$6.00/MMBtu lower than No.6 LSFO.

The estimated CAPEX for this option is approximately US$87 million which is significantly lower than the onshore LNG terminal option. The LNG FSRU would be leased from one of the leading vendors possibly Excelerate Energy, Hoegh, Exmar or Golar. The out-of-pocket CAPEX covers the cost for the jetty facility to permanently moor the FSRU and onshore gas handling systems. The project completion schedule for this option is estimated to require approximately 36 months.

A scenario case was also evaluated for an offshore submerged turret moored FSRU LNG terminal with a short (1.5 mile) interconnecting gas sendout pipeline to shore. The offshore moored scenario offers no apparent benefit over the jetty moored scenario and costs approximately US$45 million more than the jetty moored alternative.

CNG Option: The CNG option was dropped from consideration as a potential alternative for bringing natural gas to Curacao. The use of large CNG ships has never been applied in a commercial scale operation. Although the technology is theoretically sound on paper and the CNG ships can receive certified Class approval from both DNV and ABS, it has yet to be deployed in any commercial project application of this scale. If Curacao were to engage in using the CNG ship technology, it would be the first application. In Shaw Consultants opinion, there are technical and commercial risks in using unproven technology. Obtaining bank financing would be difficult to impossible. As a result, a decision was made to drop the CNG option from further consideration as a practical alternative.

Terminal Site Location Selection

Shaw Consultants considered several site locations for the terminal. After initial screening, two site locations were identified for further review, namely a site at Bullen Bay and one at Schottegat Harbor at Willemstad.

After careful review and consideration, the site at Bullen Bay was selected as the preferred location for the terminal. The Schottegat Harbor site was deemed less desirable since the Curacao Port Authority advised that it would impose restrictions and rules of navigation on LNG ships entering Schottegat Harbor. During the peak tourist season, large cruise ships frequent the Willemstad area and often moor at the wharf located in the narrows entry to Schottegat Harbor. LNG ships could be delayed as a result of the cruise ship traffic and the navigation rules/restrictions.



The site at Bullen Bay, on the other hand, is remotely located from the major population centers of Curacao and will have easy access for approach and departure of LNG ships with no interference from cruise ship traffic. Jetty #1 at Bullen Bay was selected as the preferred jetty for access to the site. Adequate space is available onshore from Jetty#1 to easily accommodate thermal and gas dispersion zones required for a 160,000m3 full containment LNG tank and the LNG spill impoundment sumps. There is adequate space available to accommodate all of the terminal process equipment and operating infrastructure (control room, workshop, and vehicle parking) required by the terminal. The site is cleared and will require minimal site preparation. There is adequate space at this site to accommodate the future installation of a new power plant should a decision be made to do so. Figure 1.3-4 illustrates a Google Earth view of the proposed Bullen Bay terminal site.

Figure 1.3-4 Bullen Bay Proposed Terminal Site

Onshore Customer Gas Delivery Pipeline System

The power generation facilities for both Aqualectra and CRUC are located within the Isla Refinery complex at Willemstad. An existing crude transfer pipeline traverses from Bullen Bay to the refinery. A new gas pipeline will be installed from Bullen Bay to the refinery complex using the right-of-way easement of the existing crude transfer pipeline (see Figure 1.3-5).



Figure 1.3-5 Onshore Customer Gas Delivery Pipeline Route

The existing crude pipeline is above ground except at street crossings. The new gas delivery pipeline system will be buried the entire route to assure public safety and compliance with typical pipeline codes.

The gas pipeline will be approximately 8 miles in length and will be a nominal 12OD line. Gas delivery pressure to the customers will not be less than 500 psig. Capacity of the new gas delivery pipeline will be approximately 137 MMscfd.

CAPEX and OPEX costs for this new gas pipeline have been included in calculating the delivered cost of gas for each of the options previously discussed. The estimated CAPEX for the new gas pipeline is approximately US$12 million. The estimated project completion schedule including FEED, equipment and material procurement, delivery, pipeline construction, hydro-testing and commissioning is approximately 24 months.

1.4 CONCLUSIONS AND RECOMMENDATIONS

Based on the results of the study, Shaw Consultants offer the following conclusions and observations.

Based on the evaluation results of the gas supply options, Shaw Consultants conclude that importing natural gas or LNG to Curacao is technically and economically feasible. All of the options evaluated will yield significant fuel cost savings compared to the alternative of burning No.6 LSFO.



The gas import pipeline option will yield the lowest delivered gas cost to Curacao. Securing a contract commitment for long-term reliable gas supply will likely be challenging and may take an extended effort.

In comparison to the conventional onshore LNG terminal option, the estimated delivered cost of gas for the gas import pipeline option is US$4.50 to US$5.50/MMBtu lower than gas delivered via LNG. This is a significant incentive to pursue a gas import pipeline supply.

The traditional onshore LNG terminal option yields a lower delivered gas cost to Curacao customers than the LNG FSRU option since the OPEX cost are not burdened with the high daily rental lease cost of the FSRU vessel. However, the initial CAPEX cost for the onshore LNG terminal is higher than any other gas supply option evaluated. The advantage of the onshore LNG terminal option is that after 10 years of operation, the CAPEX amortization will be complete and Curacao will own a fully paid asset. From a long-term perspective, the traditional onshore LNG terminal is a good investment that will yield lower cost gas benefits to Curacao.

The advantage of the LNG FSRU option is its significantly lower CAPEX commitment compared to the traditional onshore LNG terminal option. However, the rental cost of the FSRU will be expensive (US$130,000 to US$140,000 per day) and the resulting average delivered cost of gas will be approximately US$1.05/MMBtu higher than the traditional onshore LNG terminal option. If RDKs objective is to minimize the amount of its initial CAPEX commitment, then the LNG FSRU option should be given priority consideration. With respect to asset ownership, Curacao will not be accumulating equity ownership in the FSRU facility. At the end of a 10-year lease agreement, Curacao will have paid approximately US$500 million in rental payments for the FSRU and will not have accumulated any equity in an asset.

The term of the FSRU rental agreement is flexible ranging from 5-years to 20-years. A longer term lease agreement generally results in a lower cost for the FSRU rental day rate fee. Based on discussions with the vendors, the daily rental cost under a 20-year lease could be 20% lower than that of a 10-year lease.

The typical LNG FSRU is designed for large gas sendout rates (500 to 800 MMscfd). At sendout rates below 70-80 MMscfd, handling boil off gas (BOG) becomes problematic for the typical FSRU. The sendout rates for Curacao could range from a low of 19 MMscfd up to 137 MMscfd. Modifications and onshore BOG compression equipment will be required for an FSRU capable of serving the full range Curacao demand.

Although the LNG supply volumes required to service Curacao demand are small when compared to most LNG terminals, it will be feasible to obtain LNG supply for transport and delivery to Curacao. A slight premium (US$0.40 to US$0.50/MMBtu) will likely have to be paid for LNG supply due to small annual volumes. Shaw Consultants conclude that a good strategy for Curacao LNG supply management might involve either

- Contracting with major LNG suppliers such as BP, BG, Shell, etc.; or - Contracting with an LNG marketer/terminal operator such as Gas Natural (e.g. the Puerto

Rico LNG terminal operating strategy).

With the recent large-scale shale gas development projects in the U.S., gas production has exceeded demand and prices at Henry Hub have declined significantly during the past few years. As a result, new liquefaction projects are being advanced to produce LNG for export from the



existing LNG receiving terminals at U.S. Gulf Coast locations such as Sabine Pass, Freeport, and possibly others. As new U.S. Gulf Coast LNG export supply comes on stream during 2016 to 2018, it is anticipated that LNG prices in the Atlantic Basin marketing region will remain stable at current pricing levels or perhaps experience some slight downward pricing pressure due to LNG on LNG competition. The LNG market conditions will likely make LNG imports to Curacao attractive since Atlantic Basin LNG pricing is not linked to crude oil and fuel oil prices.

Historically LNG pricing mechanism for Atlantic Basin LNG sources have a market clearing netback price based on the UK or European NBP gas prices. However, LNG supply is currently being contracted from U.S. Gulf Coast LNG suppliers with pricing provisions linked to 110% to 120% of Henry Hub monthly gas prices plus liquefaction fees of approximately US$2.50/MMBtu. These Gulf Coast LNG contract terms reflect calculated netback clearing prices exceeding the UK or European NBP price. Shaw Consultants used the Henry Hub pricing mechanism for LNG to assure that the calculated delivered gas costs are conservative.

Shaw Consultants, in collaboration with RDK representatives, developed the following recommendations:

1. The gas pipeline options yield lowest delivered gas cost, but development lead time and EIAS could be long and politics could take time. However, the fuel cost savings is US$4.50 to US$5.50/MMBtu or approximately $197 to $240 million per year. This is a significant potential savings and should be pursued further to determine gas supply feasibility.

2. Make initial inquiries to producers and determine their level of interest in supplying gas for pipeline export to Curacao. Make inquiries to following producers: a) Repsol; b) Eni; c) Chevron; d) Pacific Stratus Energy Colombia Corp and e) PDVSA.

3. If, after extensive discussions with the producers, it is confirmed that a reliable long-term gas supply can be contracted (confirmed by MOU), make a decision to go with the gas import pipeline option and then:

a. Proceed with FEED for gas import pipeline and onshore customer delivery pipeline.

b. Prepare EIAS and file for permits.

c. After completing FEED, obtain competitive bids for EPC.

d. With a firm budget in hand, rework economics and if attractive, make FID.

4. On the other hand, if after extensive discussion with Venezuelan / Columbian producers it becomes apparent contracting for gas supply is not feasible within a reasonable timeline; then pursue either the conventional onshore LNG terminal option or the FSRU LNG option. The FSRU option has significantly lower initial CAPEX exposure and if RDKs objective is to minimize CAPEX, then pursue the FSRU option. Otherwise, Shaw Consultants recommends the traditional onshore LNG terminal option. Either of the LNG options will significantly reduce fuel cost compared to burning No. 6 LSFO.

5. Pursue negotiations for an FSRU rental agreement with at least three FSRU vendor/operators and execute a MOU for an FSRU conditioned on completion of FEED to define the jetty design and modifications required to solve BOG handling issues at the low sendout rates. With a MOU in hand for a FSRU lease agreement, then:

a. Prepare Plans for Project Execution and Operation.

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b. Prepare documents required for FEED, prepare the RFQ package and obtain bids for FEED. Evaluate the bids.

c. Proceed with FEED for the FSRU jetty, onshore BOG handling equipment and the onshore customer delivery pipeline.

d. Prepare the EIAS and file for permits.

e. After completing FEED, obtain competitive bids for EPC.

f. With a firm budget in hand, rework economics and if attractive, make FID.

1.5 NEXT STEPS FOR THE PROJECT

Shaw Consultants note that there will be significant engineering work and preparation required on the part of RDK to complete the future tasks required in project execution. RDK may want to consider engaging a company to assist in project management (PMT) and to serve as Owners Engineer. Following is a list of project execution tasks that will be required in executing a project.

FEED Tasks

Preparing, reviewing and confirming a Plan of Execution and Master Schedule; Obtaining all site information, surveys, geotechnical studies and other technical information

required for executing the FEED;

Setting up project management controls, QA/QC procedures and document approval procedures; Preparing RFQ documents and packages required for soliciting bids for FEED; Identifying and pre-qualifying engineering firms to be included in the FEED bid list; Tendering and evaluating bids for FEED including both technical and commercial; Monitoring progress and interfacing with FEED contractor; Checking FEED contractor technical data, calculations, drawing and specification performance; Preparing documents for soliciting bids for EIAS; Identifying and pre-qualifying firms to be included in the EIAS bid list; Tendering and evaluating bids for EIAS; Interfacing and monitoring EIAS contractor progress; Manage and monitor permitting activities and regulatory compliance; and Managing and monitoring cost and schedule.

EPC Tasks

Preparing documents and contracts for soliciting bids for EPC; Identifying and pre-qualifying contractors to be included in the EPC bid list; Tendering and evaluating bids for EPC;



Monitoring progress and interfacing with EPC contractor; Checking EPC contractor technical data, calculations, drawing and specification performance. Reviewing and approving technical detail design documents and drawings; Monitoring QA/QC of equipment fabrication, welding, and construction; Monitoring procurement activities; Witnessing equipment testing and performance run tests; Monitoring field construction; and Monitoring costs and schedule.

Facility Operations

Preparing Startup and Operation Manuals; Preparing Plan of Operation for Facilities; Preparing Plans for Managing LNG or Gas Supply; Preparing Plans for Maintenance and Repair Programs; Coordinating staffing plans; Coordinating operator training program; and Preparing Procedures for Managing Health, Safety and Environmental Compliance for the

Project.

Section 2 Curacao Gas Market Assessment


2.1 INTRODUCTION

An assessment of the Curacao gas market has been performed to determine the peak gas demand requirements. Shaw Consultants has based its assessment on data provided by Aqualectra, the local utility company in Curacao, together with independent review of information available through online resources.

2.2 ISLAND ELECTRIC UTILITY (AQUALECTRA)

Power on the island of Curacao is currently generated by Aqualectra using No. 6 high sulfur fuel oil (HSFO) supplied by the Isla Refinery. Based on the government of Curacao initiative to diversify its energy supply, Aqualectra has developed an estimate of the natural gas quantities needed to satisfy the power generation needs of the island of Curacao over the next twenty years. This estimate is based on an assumed power demand growth of two percent per annum starting in 2016. The US Energy Information Agencys (EIA) International Energy Outlook 2011 report notes natural gas fired electricity generation worldwide is expected to increase 2.6 percent annually over the 2008 to 2035 period. The EIA report attributes this increase to the relatively low emissions, low capital costs, fuel efficiency and operating flexibility that make natural gas fired electricity generation an attractive choice for new power plant installations. Thus, Aqualectras assumed growth of 2.0 percent annually, as shown in Figure 2.2-1, is conservative and generally in accordance with expected trends worldwide.

Figure 2.2-1 Aqualectra Forecasted Power Demand

The average rate shown in Figure 2.2-2 is the required natural gas supply condition to meet the Aqualectra power demand noted in Figure 2.2-1. A review of the Aqualectra electricity dispatch quantities conveyed the peak rate is normally no more than 25 percent above the average daily rate. Thus, to ensure power generation capability, Shaw Consultants has assumed a peaking rate of 25 percent above the average daily rate shown in Figure 2.2-2.



Figure 2.2-2 Aqualectra Forecasted Natural Gas Demand

2.3 ISLA REFINERY (CRUC)

There are two main power consumers in the Isla refinery, namely the refinery electric utility power generation operated by CRUC and the refinery process steam boiler system. Electric power generation for the refinery is currently fueled by No.6 HSFO. The process steam boiler system is currently fueled by bitumen asphalt and other heavy hydrocarbon streams leftover from the refinery processing applications. These streams are commonly termed the bottom of the barrel streams in the refinery industry. Some modifications to the existing equipment may be needed to permit electricity and steam generation via natural gas. In addition, Shaw Consultants understands that the Isla Refinery would require a significant investment to process and refine these bottom of the barrel streams into saleable products. The required modifications are currently being studied by the Isla Refinery, who anticipates completing the required changes by 2018 if delivery of natural gas for power and steam generation is pursued. Based on discussions between the Isla Refinery and Aqualectra, it is estimated the natural gas demand needed to satisfy the Isla Refinery systems will be as shown in Figures 2.3-1 and 2.3-2. Peak utilization in each case was assumed to be 10 percent above the annual average rate.

The viability of the Isla Refinery long-term is uncertain. Originally built in 1918 by Shell, the Isla Refinery is currently leased through 2019 to Venezuelan state oil company Petroleos de Venezuela, S.A. (PDVSA). PDVSA has operated the facility under a lease agreement with the Government of Curacao since 1985, when Shell sold its interest in the Isla Refinery to the Curacao Government. Shaw Consultants note that conversion of the refinery fuel systems to natural gas will essentially eliminate the current environmental issues and the operation of the Isla Refinery will likely continue beyond 2018.



Figure 2.3-1 Refinery Utility System (CRUC) Natural Gas Demand Forecast

Figure 2.3-2 Refinery Processes Natural Gas Demand Forecast

2.4 SEASONAL, DAILY AND HOURLY DEMAND FLUCTUATION

Shaw Consultants was provided with the electricity dispatched by Aqualectra on four separate days of operation. This data is presented on an hourly basis for October 11, 2011 and March 10th through 12, 2012. As seen in Figures 2.4-1 through 2.4-4 the electricity demand has a little fluctuation on a daily basis and relatively similar demand seasonally.



Figure 2.4-1 Electricity Dispatch October 11, 2011 (Weekday max 2011)

Figure 2.4-2 Electricity Dispatched March 10, 2012 (Saturday)



Figure 2.4-3 Electricity Dispatched March 11, 2012 (Sunday)

Figure 2.4-4 Electricity Dispatched March 12, 2012 (Weekday)

In addition, Aqualectra states that electricity demand over the course of a year does not vary significantly as the island of Curacao has a temperate climate with little variation in temperatures year round. Shaw Consultants notes that based on limited amount of data points provided for review, this assertion by Aqualectra seems quite reasonable.



2.5 DEMAND GROWTH

Based on the Aqualectra data, peaking above the average rate was determined to be approximately 25 percent for the worst case scenario. Thus, to accommodate peak sendout gas demand, Shaw Consultants has assumed that the highest reasonably likely peak demand during any 24 hour period will be as follows:

Aqualectra Maximum Peak Rate: 25 Percent above the annual average daily rate Refinery Process Heat Maximum Peak Rate: 10 Percent above the annual average daily rate CRUC Maximum Peak Rate: 10 Percent above the annual average daily rate

The assumptions detailed above result in the natural gas demand forecast presented in Figure 2.5-1.

Figure 2.5-1 Total Curacao Natural Gas Demand Forecast

2.6 NEIGHBORING ISLANDS

Natural gas supply via CNG or LNG may be more economically feasible to implement in Curacao if the adjacent islands of Aruba and Bonaire develop mutual natural gas power generation capability in coordination with the island of Curacao.

Aruba

As of 2009, Aruba has 0.266 GW (2330 GWh per year) of installed power generation capacity. Annual power generation and consumption in Aruba was 880 GWh and 818GWh, respectively, in 2009 suggesting Arubas infrastructure adopted an N+2 philosophy, which Shaw Consultants confirms is common practice. Arubas power generation, consumption and capacity have nearly tripled in the past twenty years, as shown in Figure 2.6-1.

Power generation in Aruba is achieved currently through the combustion of petroleum products (likely No.6 HSFO) rather than natural gas. Thus, like Curacao, investment to modify/upgrade existing power



generation systems may be necessary in Aruba. Figure 2.6-2 depicts the predicted natural gas requirements in Aruba assuming the 2009 demand of 880 GWh increases by two percent per year compared to the Aqualectra natural gas demand in Curacao.

Figure 2.6-1 Arubas Annual Historical Power Demand

Source: EIA International Energy Statistics

Figure 2.6-2 Natural Gas Demand for Public Power Generation (Aruba and Curacao)



If Curacao were to build an LNG import terminal, it is conceivable that Curacao could possibly supply natural gas by pipeline to Aruba for power generation. This may be a challenging proposition since a project to build a LNG import terminal in Aruba already exists.

Bonaire

Shaw Consultants gathered information on Bonaires power generation from the public domain. In effect, Bonaire has become the first country to be powered almost exclusively by clean energy. Thus, natural gas supply to Bonaire from Curacao is an unlikely scenario given the apparent success of their clean energy initiative. The Bonaire power demand is only 10 percent of the power demand seen in Curacao, thereby needing a very small quantity of natural gas to satisfy Bonaires power generation needs. Figure 2.6-3 compares the forecasted natural gas demand in Curacao to that of Bonaire, which is based on a power demand growth rate of two percent per annum.

Figure 2.6-3 Forecasted Natural Gas Demand Comparison between Bonaire and Curacao

In Shaw Consultants opinion, the minute power demand requirements in Bonaire do not justify the costs to lay a pipeline from Curacao to Bonaire.

2.7 NATURAL GAS AND FUEL OIL PRICE FORECAST

The price of natural gas, supplied to Curacao (via pipeline, LNG or CNG), will likely be indexed to the Henry Hub price. Historical Henry Hub pricing is shown in Figure 2.7-1.

The price at Henry Hub has declined sharply starting in 2008. A key driver for the decrease in the natural gas Henry Hub pricing in recent years has been the shale gas development within the continental US. Shaw Consultants anticipates exploration, development and production from shale gas plays will continue. Thus, it is anticipated Henry Hub natural gas prices will remain relatively stable in the upcoming years, likely increasing at rate of one percent per annum.



Figure 2.7-1 Henry Hub Spot Natural Gas Price (January 1997 February 2012)

Source: Henry Hub Gulf Coast Natural Gas Spot Price, EIA

The Henry Hub price forecast published in the EIAs Annual Energy Outlook 2012 Early Release utilizes a similar pricing assumption as illustrated in Figure 2.7-2.

Figure 2.7-2 Henry Hub Natural Gas Price Forecast

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Figures 2.7-3 and Figure 2.7-4 depict the EIA forecast of low sulfur spec fuel oil for No.2 (Distillate) and No.6 (Heavy Fuel Oil) used to generate power.

Figure 2.7-3 No.2 LSFO (Distillate) Price Forecast

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2.8 GAS QUALITY REQUIREMENTS

The commercial quality natural gas specifications for the Curacao Feasibility Study are listed in Table 2.8-1.

Table 2.8-1 Gas Delivery Specifications

PARAMETER \ SITE BULLEN BAY

SCHOTTEGAT HARBOR

Max. Sendout Gas Pressure 780 psig 550 psig Peak Sendout Gas Rate 137 MMscfd* Minimum Sendout Gas Rate 15 MMscfd* Sendout Gas Temperature Minimum: 60oF Maximum: 120oF HHV 1,000 - 1,150 Btu/scf Max. N2 2.00 mol% Max. CO2 2.00 mol% Max. Non-Hydrocarbon Content 4.00 mol% Max. O2 10 ppm by volume Max. H2S 0.25 grains/100 scf Max. Mercaptans 0.25 grains/100 scf Max. Total Sulfur 0.50 grains/100 scf Max. Water Vapor Content 7.0 lbs/MMscf HC Dewpoint Less than 30oF @ 500 psig

*Sendout rate is based on gas equivalent assuming HHV of 1,000 Btu/scf.

Section 3 Gas Supply Concepts


3.1 INTRODUCTION

This section of the report documents the gas supply concepts that were considered and evaluated for Curacao in the study. Three basic supply options were analyzed including CNG, LNG, and Gas Import Pipeline option. With respect to the LNG option, two configurations were considered including a traditional onshore LNG terminal facility and a LNG FSRU jetty facility.

What Is Commercial Quality Pipeline Natural Gas

Commercial quality pipeline natural gas is predominately methane with small amounts of ethane, propane, and butanes. It can contain up to 2 mol% nitrogen and 2 mol% carbon dioxide. Hydrogen sulfide must be less than 0.25 grains/100scf and total sulfur compound content must be less than 0.50 grains/100scf. The water content is typically less than 7 lbs/MMscf. The commercial gas pipeline pressure is typically less than 1,440 psig with the temperature of the gas ranging between 40oF to 120oF. The hydrocarbon dew point temperature of the gas must be sufficiently low to assure that no hydrocarbon liquids will condense in the pipeline over its range of operating pressure and temperature. The higher heating value (HHV) of commercial quality natural gas is dependent on the quantity of ethane and heavier hydrocarbon content. Typically, the HHV ranges between a minimum of 950 Btu/scf to a maximum of 1,150 Btu/scf.

What Is CNG

CNG is commercial quality natural gas which has been compressed to 4,000 psig. After compression the CNG is cooled, stored and transported at a temperature ranging between 60oF and 120oF.

What Is LNG

LNG is liquefied commercial quality natural gas with essential all of the water and carbon dioxide removed. The C6+ hydrocarbon content is less than 1 to 2 ppm by volume. It is a cryogenic liquid at a bubble point temperature of approximately -259oF stored at essentially atmospheric pressure.

3.2 CNG OPTION

In the Scope of Work, Shaw Consultants was requested to consider and evaluate CNG technology offered by Sea NG Corporation. Shaw Consultants contacted Sea NG and requested that they furnish information on their patented CNG Coselle delivery system. The following is a recap of the information obtained from Sea NG.

NOTE: INFORMATION FURNISHED BY SEA NG IS SUBJECT TO CONFIDENTIALITY AGREEMENTS EXECUTED BETWEEN SEA NG, SHAW CONSULTANTS, REFINERIA DI KORSOU, AND SOLOMON ASSOCIATES. THIS INFORMATION SHALL BE TREATED AS CONFIDENTIAL AND SHALL NOT BE DISCLOSED TO ANY OUTSIDE THIRD PARTY THAT HAS NOT EXECUTED A CONFIDENTIALITY AGREEMENT WITH SEA NG.

Compared to an LNG system, a CNG delivery system avoids liquefaction, regasification and onshore storage of gas. The gas is compressed into ships which provide both the storage and transportation. The system is illustrated schematically Figure 3.2-1.

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Figure 3.2-1 CNG Delivery System Schematic

Sea NGs CNG transportation solution is based on the Coselle System, which is an integrated system that combines loading and unloading facilities with transportation and storage in specially designed CNG ships. These ships provide marine transport of natural gas for distances up to 1,000 nautical miles. The system is based on Sea NGs patented Coselle technology. It uses coiled pipe to safely and effectively store gas at high pressure (4,000 psig). The CNG is transported in the CNG Coselle ships to receiving destinations where it is decompressed for delivery.

A Coselle is a coiled pipeline contained within a supporting structure mounted within a ships hull as illustrated in Figure 3.2-2.

Figure 3.2-2 Schematic of Coselle and Ship Structure

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A Coselle is Sea NGs patented storage vessel comprised of approximately 17 km (13 miles) of 168 mm (6 in) diameter ERW high-strength steel pipe that has been coiled into a reel-like support structure called a carousel. The name Coselle is derived from a coil in a carousel. Coselles can be stacked up to seven units high, as required to meet the ships design. Each container is designed to be integrated into the ships structure. The Coselles are stacked within the vessels hold, and connected together using a proprietary manifold and control system. The unique, patented part of the cargo system is the use of high and low pressure manifolds to efficiently load and unload the Coselles (or Coselle stacks) in a cascade fashion allowing more rapid loading and unloading while maintaining control of the temperatures and using less compression horsepower.

Coselle CNG ships have been fully approved for construction by the American Bureau of Shipping (ABS). To achieve this approval a full design of a C16 ship and a full design of the mid-body of a C25 ship (integrated design) was carried out. These designs, plus all supporting safety studies, plus all of the Coselle analysis and testing, plus HAZIDs and HAZOPs were submitted to ABS for formal review. The achievement of full class approval is the final step before construction. This guarantees that a Coselle CNG ship can be constructed and receive full Class Approval. Once a ship has Class Approval it is then internationally accepted as a safe means of shipping and will receive the international certificates.

In 2008, representatives Sea NG visited Curacao to investigate the potential of delivering CNG to the Isla Refinery. The concept at the time was to import 30 MMscfd. The current delivery requirements assume a peak rate of 137 MMscfd by year. To accommodate the current peak rate requirements, four C16 ship would be required with a ship arriving daily at Curacao. Two ships will load and two ships will discharge each day. At the Curacao discharge terminal there would be substantial overlap of the ships. This means that 50% of the time there will be two ships at the discharge terminal, one full and one discharging. Both the export and import receiving terminals will require berths for two ships.

Sea NG has a web site which provides access to computer modeling software that can be used to analyze the shipping and terminal facility tariff fees for CNG delivery using the patented CNG Coselle ships. Shaw Consultants used this web site to prepare an analysis of the shipping and terminal facility tariff fees for gas supplies from Trinidad, Venezuela, and Columbia. The results are illustrated in Figure 3.2-3.

Figure 3.2-3 CNG Tariff Fees vs. Transport Distance

NOTE: The tariff fees include cost for both shipping and terminal facilities

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The CNG tariffs illustrated in Figure 3.2-3 include costs for CNG ships and the facilities at both the export and import terminals. As noted in the figure, CNG tariff cost for importing gas from Trinidad is approximately US$3.75/MMBtu which has a transport distance of 560 nautical miles. As the transport distance is reduced, the tariff costs decline. For gas supply transported from Venezuela and Columbia, the calculated tariff costs are US$2.05/MMBtu and US$2.30/MMBtu, respectively.

Sea NGs business model for deploying the CNG Coselle gas delivery system is structured around a time charter agreement. Sea NG retains ownership of the CNG ships and will lease CNG ships under a long term charter agreement. A day rate will be charged for each CNG ship required to service the gas delivery capacity required by the project. A minimum 10-year charter will be required. On-loading facilities will be the responsibility of the producer (or alternatively Sea NG). The Off-loading facilities will be the responsibility of the gas customer (or alternatively Sea NG).

Based on Shaw Consultants review of the Sea NG information and after analyzing the CNG Coselle delivery system concepts, the following conclusions were developed.

Technical Feasibility - Design safety of CNG Coselle containment has been confirmed by ABS and DNV. - CNG ships with the Coselle containment system can be Classed. - CNG delivery to Curacao is theoretically feasible.

Potential Gas Supply - Trinidad, Columbia and Venezuela have potential gas supply that might be tapped. However,

contract negations with producers could require a long-lead time.

- Gas supply may be available, but infrastructure may not exist. Pipelines, treating, dehydration, and CNG compression will be needed at the CNG export terminal.

Schedule - Likely to have a schedule of 30 to 40 months. - Schedule driven by fabrication of multiple CNG ships (4 to 6).

Economic Viability - Significant uncertainty exists in costs of CNG ships and export infrastructure. No actual

fabrication history is available for CNG ships. No CNG ships have ever been built.

- Tariff calculations by Sea NG indicate CNG is competitive with LNG. Operability

- Scheduling and ship logistics will be challenging and complex. - Lot of equipment to operate and maintain. - One ship arriving daily makes for potential complex shipping.

Reliability - High frequency arrival schedule makes this option less reliable.

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- Not as reliable as the LNG and Gas Import Pipeline options. Historical Track Record

- No CNG Coselle ships have been built. - Curacao would be the first application of this technology. - Technology is unproven in real commercial application. - This option has high risk from both a commercial and technical perspective.

Based on Shaw Consultants analysis, it was recommended that the CNG option be dropped from consideration because of the risks and lack of having any commercial projects in service.

3.3 LNG OPTIONS

Two LNG terminal configurations were considered including the traditional onshore LNG terminal and the LNG FSRU jetty terminal.

Onshore LNG Terminal Option

The onshore LNG terminal option is based on the traditional LNG regas terminal design. Open Rack Vaporizer (ORV) technology was selected for this conceptual design since it is highly reliable and has the lowest OPEX costs. A 160,000m3 full containment LNG storage tank is assumed in this option. All critical equipment has been spared and the expected on-line reliability is 99%. Design life is based on 25 years. Gas sendout capacity is 137 MMscfd at pressures up to 780 psig.

A simplified process flow diagram for the terminal is illustrated in Figure 3.3-4.

Figure 3.3-4 Typical LNG Regas Terminal Simplified PFD

BOG PIPELINE COMPRESSOR

SENDOUT GAS SUPERHEATER



The Curacao onshore LNG terminal option includes the following major systems and equipment:

Berthing Jetty for LNG Ship Ranging from 80,000m3 to 155,000m3. Unloading Platform Equipped With 2-LNG Arms (16 inch), 1-Hybrid LNG/Vapor Arm (16 inch),

and 1-Vapor Arm (16 inch) Designed for an Offloading Rate of up to 12,000m3/hr.

One LNG Drain Drum and LNG Drain Drum Pumps (2x100%) At Unloading Platform. LNG Transfer Line (36), Ship Vapor Transfer Line (12) and LNG Cool Down Circulation Line

(3).

One LNG Storage Tank (160,000m3 capacity). LNG In-Tank Pumps (2x100%) and HP LNG Sendout Pumps (2x100%). Small BOG Compressors (2x100%), Large BOG Compressor (1x100%), BOG Pipeline

Compressor (1x100%) and Ship Return Vapor Blowers (2x100%).

BOG Condenser/Absorber. LNG Vaporizers Using Open Rack Vaporizer (ORV) Technology (2x100%). Sendout Gas Superheaters (2x100%). Seawater Lift Pumps for ORVs (3x50%). Gas Sendout Metering and Odorization. Process Control System. Flare/Vent/Drain Systems. Safety Systems Including Fire Protection, Gas/Smoke/Fire/Spill Detection, Emergency Shut

Down (ESD), LNG Spill Impoundment, Emergency Generator, and UPS Emergency Power.

Miscellaneous Utility Support Systems Including Electrical Power (Purchased from Aqualectra), Process Utility Heat Medium, Fuel Gas, Nitrogen Supply, Instrument and Utility Air, Plant Lighting, etc.

Infrastructure at the terminal will include a control room, operating offices, a laboratory, workshop/warehouse, employee parking area, potable water supply and sewage treatment. Security fencing and guarded entry are required to control access to the terminal facilities.

LNG Vaporization Technology

CH-IV International, a company recognized within the industry as having expertise in LNG, published a technical paper on LNG vaporizer alternatives in 2007 which is still valid today. The following discussion draws from the information contained in CH-IVs technical paper.

The choice of a vaporization system is an important first step in the development of a LNG import terminal, since it impacts capital expenditure, operating costs, operating flexibility and reliability, emissions as well as public perception and regulatory compliance.

Historically, LNG import terminals have generally used either Open Rack Vaporizers (ORV) or Submerged Combustion Vaporizers (SCV) for LNG regasification purposes. ORVs are widely used in



Asia and Europe, and are well proven in baseload LNG regasification service. SCVs have been used in the four existing import terminals in the U.S. When compared to other vaporization technologies, the higher emissions from SCVs have prompted requirements to evaluate alternative vaporization systems. Recent developments in alternative vaporizer technologies include ambient air vaporizers and shell and tube vaporizers with or without intermediate fluid and/or combinations of each and there now exists proven design and operating experience.

The process of returning LNG to a gaseous state requires the introduction of heat energy. Heat sources include ambient temperature sources (air or seawater) or above-ambient temperature sources such as burning fuel either directly or to heat an intermediate fluid. In either arrangement, LNG absorbs heat as it passes through thermal conductors that are surrounded by a higher temperature medium. As the LNG is heated, it vaporizes into natural gas, which is then delivered to customers via distribution pipelines at controlled flow rates, pressures and temperatures. There are many heating mediums in general use for this type of process and the particulars of the energy exchange process may be governed by any number of alternative vaporization processes currently available.

The various vaporization technologies include:

Open Rack Vaporizers (ORVs). Submerged Combustion Vaporizers (SCVs). Shell and Tube Vaporizer. Ambient Air Vaporizers (AAVs) including

- Direct Natural draft Ambient Air Vaporizer and - Direct Forced Draft Ambient Air Vaporizer.

Air-Water Tower Vaporization Technology Open Rack Vaporizers: The ORV is commonly considered in the design of LNG import terminals. The relatively low mechanical, electrical, and process complexity and reduced air emissions present good engineering arguments in its favor. However, life-cycle operating costs must also be considered. The ORV uses seawater as the sole heat source to vaporize LNG. The vaporizer consists of a heat conductor panel with multiple tubes through which the LNG passes. A typical ORV arrangement is illustrated in Figure 3.3-5.

LNG enters at the bottom of the vaporizer through a distribution header and moves up through the tubes while seawater flows down along the outer surface of the tube panels. Vaporized natural gas is removed from the top of the vaporizer and is sent to the distribution pipeline. The cooled seawater collects in a trough at the bottom of the vaporizer and is discharged to an outfall.

Chlorination of the seawater is used to prevent bio-fouling. Typically, sodium hypochlorite would be injected continuously to maintain a concentration of 0.2 ppm. In order to shock the system, elevated concentrations of 2.0 ppm would be injected for 20 minutes every 8 hours, during ORV operation. De-chlorination of the effluent may also be required to meet environmental standards.



Figure 3.3-5 Open Rack Vaporizers (ORVs)

Submerged Combustion Vaporizer (SCV): SCV systems are also commonly considered in the design of LNG import terminals. Their proven operational history, low capital cost, simplicity in design and operational flexibility combine to make this an attractive option. The SCV system uses natural gas as its heat source and requires electrical power to operate combustion air blowers and circulating water pumps.

LNG is routed to a stainless steel tube bundle that is submerged in a water bath heated with flue gases generated by a submerged combustion burner. A schematic of typical SCV operation is presented in Figure 3.3-6.

Figure 3.3-6 Submerged Combustion Vaporizers



The forced air draft combustion burner is fueled by low-pressure gas from either the Boil-Off Gas (BOG) header or from the natural gas sendout pipeline. Hot exhaust gases from combustion are sparged into the water bath creating a relatively low temperature (typically in the range of 55 to 90F) thermally stable heat source for the vaporization of LNG flowing through the coil bundle. Natural gas exits the coils at pipeline pressure and temperature for pipeline distribution.

Shell and Tube Vaporizer: There are many configurations of shell and tube vaporizer technologies that are available for LNG applications. One such system uses a closed loop heated water-glycol system to provide heat to vaporize the LNG using a shell and tube exchanger design patented by Chicago Power & Process, Inc. A Heat Transfer Fluid (HTF) warmed from an external heat source, is used to vaporize the LNG. For the vertical configuration shell and tube LNG vaporizer illustrated in Figure 3.3-7, LNG enters the exchanger tubes from the bottom and vaporized natural gas exits from the top. The HTF is split fed to the shell side of the vaporizer from both the bottom and top. In the bottom section of the exchanger, the heat transfer is achieved from co-current exchange while the top section is in counter-current exchange. This vaporization technology is used by Excelerate Energy and Exmar on their LNG FSRU facilities.

Figure 3.3-7 Shell and Tube LNG Vaporizer

Ambient Air Vaporizers (AAVs): Direct AAVs transfer heat from the ambient air directly into the LNG through a heat exchanger heat transfer surface. In typical Direct AAVs, the LNG is passed through a manifold that divides the flow into a number of vaporizer units where a series of smaller flows are directed through individual heat transfer tubes. Each tube has aluminum fins for increased heat exchange area and is in direct contact with the ambient air. Figure 3.3-8 illustrates the Direct AAVs.



Figure 3.3-8 Ambient Air Vaporizers (AAVs)

There are two types of direct ambient air vaporizers natural draft and fan induced forced draft air flow. These units typically are designed with a thaw cycle to remove ice buildup. In forced draft AAVs, airflow into the unit is controlled by fans installed on top of the vaporizer. Each unit can be equipped with shrouds on each side to direct airflow through the vaporizer. Direct forced draft vaporizers are approximately 1.7 times more effective than natural draft AAVs becaus they move 1.7 times more air across the tubes of the unit. AAVs installed at locations having a cool to cold winter require supplemental heating during cool weather operation.

AAVs produce a substantial flow of fresh water which is condensed from the moisture in the air. Up to 100 gpm of pure fresh water is produced for each 100 MMscfd of vaporized LNG. The production rate of fresh water, of course, is dependent on the relative humidity and ambient air temperature. For the forced draft units, electrical power required for the fan motors adds operating cost for vaporization. Overall, AAVs have low OPEX and minimal fuel requirements during cool weather periods of operation. However, the natural draft AAVs required proportionally a much larger area plot space than the other types of vaporizers. A large number of AVVs must be installed to provide the vaporization duty. Since the airflow through the forced draft units is higher than natural draft units, fewer forced draft units are required to achieve the same duty.

Emissions and effluents for forced draft and natural draft units are similar, except that with forced draft AAVs the formation of fog is diminished by the forced airflow. There is also more ice formed in forced draft units because the increased air flow over the tubes increases the rate of water condensation and consequently the rate of ice formation. The shrouds around the tube bundles impede the amount of radiant heat reaching the ice forming on the tubes, which can increase the ice buildup rate.

Air-Water Tower Vaporization Technology: This type of vaporization system consists of shell and tube vaporizers, air-water towers (i.e a reverse cooling water tower), plate frame water/heat medium heat exchangers, and a heat medium circulation loop with direct fired heaters. The heat medium is typically a water-glycol solution. A schematic of this process is illustrated in Figure 3.3-9.



Figure 3.3-9 Ambient Air-Water Tower Vaporization System Schematic

The LNG Terminal at Freeport, Texas selected the air-water tower vaporization technology. The Freeport vaporization air-water towers are shown in Figure 3.3-10.

Figure 3.3-10 Freeport LNG Terminal Air-Water Tower Vaporization System



LNG FSRU Option

This option involves the leasing of a LNG Floating Storage Regasification Unit (FSRU). There are four leading vendors that have experience in LNG FSRUs including Excelerate Energy, Hoegh, Exmar, and Golar.

Shaw Consultants contacted Excelerate Energy and Hoegh to obtain information on LNG FSRU vessels. Both companies responded with information for their respective FSRU vessels. Following is a recap of the information obtained from these two vendors.

Excelerate Energy LNG FSRU Information

NOTE: INFORMATION FURNISHED BY EXCELERATE ENERGY IS SUBJECT TO CONFIDENTIALITY AGREEMENTS EXECUTED BETWEEN EXCELERATE ENERGY, SHAW CONSULTANTS, REFINERIA DI KORSOU, AND SOLOMON ASSOCIATES. THIS INFORMATION SHALL BE TREATED AS CONFIDENTIAL AND SHALL NOT BE DISCLOSED TO ANY OUTSIDE THIRD PARTY THAT HAS NOT EXECUTED A CONFIDENTIALITY AGREEMENT WITH EXCELERATE ENERGY.

History and Background

Excelerate is a provider of LNG storage and regasification services, an importer of LNG, and a developer of unique market access points around the world (see Figure 3.3-11). In 2001, Excelerate placed the first shipyard order to incorporate regasification equipment into the design of a new type of LNG vessel that would be referred to as Energy Bridge Regasification Vessels or across the industry today as FSRUs. As of 2011, Excelerate operates a fleet of eight purpose-built FSRUs, three with an LNG cargo capacity of 138,000m and five with a capacity of 150,900m. Excelerate has also taken the conventional LNG carrier (LNGC) Excalibur under long term charter to support our global efforts and is currently developing the largest FSRU in the industry for Petrobras, expected to enter into service in May 2014.

Figure 3.3-11 Excelerate Energy Historical Milestones

Since taking delivery of the first FSRU in January 2005, Excelerate has been at the forefront of technical innovation in the LNG industry, achieving several World Firsts in the process. These include Excelerate being the first company in the world to design, build, and operate offshore and dockside LNG regasification terminals (Gateways and GasPorts respectively). In addition, Excelerate was the first to



utilize its own fleet of LNG regasification vessels to service these facilities, and the first in the industry in developing side-to-side (STS) LNG transfer capabilities to maximize the efficiency of its fleet.

Excelerate developed, owns and operates two offshore LNG regasification terminals, Gulf Gateway (GGEB) Deepwater Port in the US Gulf of Mexico and Northeast Gateway (NEG) Deepwater Port in Massachusetts, as well as the Teesside GasPort (TGP) dockside regasification terminal at Teesside in the UK. Internationally, Excelerate developed, operates, and provides LNG storage and regasification services at three GasPorts, the Bahia Blanca (BBGP) and GNL Escobar (GNLE) GasPorts in Argentina and at the Mina Al Ahmadi GasPort (MAAGP) in Kuwait.

In the course of developing and operating these terminals, Excelerate has amassed a highly experienced group of project management and operations professionals to design, permit, construct, and operate the port facilities and associated vessels. Excelerate brings this experience, as well as excellent long standing relationships with critical equipment manufacturers, design consultants, installation contractors, and operations and maintenance contractors to each project we develop.

With eight FSRUs currently in service, Excelerate is the unquestioned world leader in floating offshore and dockside regasification solutions. This, in conjunction with unique design, construction and operational experience derived from the completion of six such facilities worldwide, leaves Excelerate uniquely suited to manage the challenges involved with the timely implementation and safe, efficient operation of the LNG importation infrastructure for the Curacao GasPort or Gateway. Furthermore, Excelerates global reputation for utilizing available local resources in facilitating the development of the facilities will allow the seamless integration of many qualified local businesses and personnel as progress is made in the design, fabrication, installation and operation of the LNG terminal.

Energy Bridge Terminal Technology

Energy Bridge is the propriety offshore LNG regasification and delivery system developed by Excelerate. This system involves the use of the purpose-built FSRUs for the transportation and vaporization of LNG through specially designed offshore and near shore receiving facilities. Energy Bridge is a combination of proven technology and equipment in a new application and represents an innovative step forward in LNG importation technology.

Gateways (see Figure 3.3-12), such as Excelerates Gulf Gateway and Northeast Gateway, consist of:

One or more submerged turret loading (STL) buoys that connect to the FSRU and serve as both a mooring for the vessel and a conduit for the discharge of natural gas;

Chains, wire rope, and anchors used to secure each of the buoys to the seabed; A flexible riser designed to connect the buoy to a seabed pipeline end manifold (PLEM)

allowing tie-in to a subsea pipeline;

A subsea PLEM that incorporates necessary control instrumentation and related valves; and, An interconnecting subsea pipeline to tie into downstream delivery infrastructure.



Figure 3.3-12 Excelerate Energy Bridge Terminal Gateway System

GasPorts (see Figure 3.3-13), such as Excelerates Bahia Blanca GasPort, are dockside applications of Excelerates Energy Bridge technology. Using the dockside delivery method, the FSRU moored at the GasPort is connected to a shore-mounted high-pressure gas unloading arm via the vessels gas manifold. Natural gas vaporized onboard is delivered from the FSRU at a prescribed pipeline pressure. Effectively, this allows an FSRU to function as a highly flexible LNG receiving terminal, and the low cost of construction of a GasPort allows for short-term, seasonal, or peaking service, in addition to long-term base load deliveries. The FSRU, permanently moored at the GasPort, receives LNG supplies from conventional LNGCs utilizing Excelerates STS transfer procedure.

Figure 3.3-13 Excelerate Energy Bridge Terminal GasPort System



FSRU Technology. FSRUs are new, purpose-built LNG tankers that incorporate onboard equipment for the vaporization of LNG and delivery of high pressure natural gas. Excelerate currently has eight FSRUs in its young fleet (the oldest vessel delivered in January 2005).

Excelerate initially developed the FSRU to facilitate its trading activities and to supply LNG to its own Gateway and GasPort importation terminals, but a greater potential for this technology was recognized. Today, Excelerate also makes its FSRUs available to third parties under LNG storage and regasification agreements as part of a complete floating LNG importation solution. Excelerate FSRUs are currently providing storage and regasification services for Repsol-YPF at the Bahia Blanca and GNL Escobar GasPorts in Argentina and to Kuwait National Petroleum Corporation at the MAAGP Project in Kuwait. In May 2014, Excelerate will be providing storage and regasification services for Petrobras at Guanabara Bay Terminal in Brazil.

As all vessels in Excelerates FSRU fleet are built essentially the same and positioned strategically around the globe, they can be interchanged and substituted as needed, avoiding the need for a facility to be down while a vessel conversion or FSRU is sent to a shipyard. This inventory of vessels allows our clients unsurpassed regasification up-time, and virtually eliminates gaps in service. This cannot be said of competing companies who may provide a single, older converted LNG carrier, constituting a single point of failure mode.

LNG STS Transfer. Excelerate can affect the transfer of LNG cargos from a traditional LNG carrier to Excelerates FSRU utilizing its proprietary, commercial STS transfer process (see Figure 3.3-14). Excelerate has undertaken over 142 STS transfers using flexible hoses, transferring almost 14 million cubic meters of LNG in the pr

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