Lng

CURACAO CNG-LNG TERMINAL FEASIBILITY STUDY

Table of Contents

CURACAO CNG-LNG TERMINAL FEASIBILITY STUDY

TRANSMITTAL LETTER DISCLAIMER NOTICE NOMENCLATURE 1

EXECUTIVE SUMMARY

1.1 1.2 1.3 1.4 1.5 2

GAS MARKET ASSESSMENT

2.1 2.2 2.3 2.4 2.5 2.6 2.7 2.8 3

Introduction CNG Option LNG Options Gas Import Pipeline Options

COMMERCIAL EVALUATION

4.1 4.2 4.3 4.4 4.5 4.6 4.7 4.8 5

Introduction Island Electric Utility (Aqualectra) Isla Refinery (CRUC) Seasonal, Daily and Hourly Demand Fluctuation Demand Growth Neighbouring Islands Natural Gas and Fuel Oil Price Forecasts Gas Quality Requirements

GAS SUPPLY CONCEPTS

3.1 3.2 3.3 3.4 4

Introduction Scope of Study Summary of Results Conclusions and Recommendations Next Steps for the Project

Introduction Commercial Evaluation Basis CAPEX and OPEX Estimates Delivered LNG Price (C.I.F. Curacao Terminal) Curacao Average Delivered Gas Price Curacao Gas Cost vs. Gas Rate Risk Matrix Analysis Conclusions

LNG SUPPLY

5.1 5.2 5.3 5.4 5.5

Introduction LNG Industry Overview LNG Quality Specification Typical LNG Supply Contract Terms Potential LNG Suppliers

i CURACAO CNG-LNG TERMINAL FEASIBILITY STUDY

Table of Contents

5.6 5.7 6

LNG SHIPPING AND TRANSPORTATION

6.1 6.2 6.3 6.4 6.5 7

Overview Marine and Unloading Facilities LNG Storage BOG and Ship Vapor Return System LNG Pumps, BOG Condenser and LNG Sendout System LNG Vaporization System Gas Sendout System Operations Control System Utility Systems Safety Systems Security Systems Buildings and Infrastructure Layout Plot Plan

CONCEPTUAL CURACAO GAS SENDOUT PIPELINE

9.1 9.2 9.3 9.4 9.5 10

Introduction LNG Terminal Site Locations Bullen Bay Site Option Schottegat Harbor Site Option LNG FSRU Option Advantages / Disadvantages Conclusions

CONCEPTUAL CURACAO LNG TERMINAL

8.1 8.2 8.3 8.4 8.5 8.6 8.7 8.8 8.9 8.10 8.11 8.12 8.13 9

Overview Availability of Ships Shipping Costs and Losses Port Requirements Conclusions

TERMINAL LOCATION ASSESSMENT

7.1 7.2 7.3 7.4 7.5 7.6 7.7 8

Pooling LNG Supply With Neighbouring Islands Conclusions

Overview Route Size, Capacity and Design Parameters Constructability Pipeline Operations Control

OPERATIONS AND MAINTENANCE

10.1 10.2 10.3 10.4

Overview Personnel Training Owner Staffing and Labor Costs Operations and Maintenance Budget

ii CURACAO CNG-LNG TERMINAL FEASIBILITY STUDY

Table of Contents

11

INTEGRATED SYSTEM PERFORMANCE

11.1 11.2 11.3 11.4 11.5 12

PROJECT EXECUTION PLANNING

12.1 12.2 12.3 12.4 13

Environmental, Social, Health and Safety Environmental Regulations and Global Standards Curacao Permitting Requirements Financial Institution Requirements ESHS Issues of Concern Conclusions and Recommendations

COMMENTS ON PROJECT FINANCING

14.1 14.2 14.3 14.4 14.5 14.6 14.7 15

Execution Plan Framework Development Planning Construction Strategy / Philosophy Typical Project Schedule

REGULATORY AND PERMITTING

13.1 13.2 13.3 13.4 13.5 13.6 14

Reliability Backup Fuel Supply Turndown Flexibility Expandability Conclusions

Overview Equity Requirements Typical Lending Organizations Terms and Criteria Risk Equator Principles Lenders’ Due Diligence Report

APPENDIX

A. B. C. D. E. F. G. H.

Conceptual Basis of Design Process Flow Diagram With Heat & Material Balance Terminal Layout Major Equipment List Utility Load Summary Key Milestone Project Schedule LNG Shipping Route Charts Historical Hurricane Tracking Charts

iii CURACAO CNG-LNG TERMINAL FEASIBILITY STUDY

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.

CURACAO CNG-LNG TERMINAL FEASIBILITY STUDY

Nomenclature

AAV ABS ACI ACQ AISC ANSI APCI API ASCE ASME ASNT ASTM AWS BACT bcf BOG Bscfd or Bcfd Btu bpd BOE CAER CAPEX CCR CO CFR CNG CP CPI CRUC CSP DCS DNV DWP F&G ECA EDIN EIA EIB EIAS EIS EPC ESD ESHS ETA FEED FERC FI FPSO FSRU

Ambient Air Vaporizer American Bureau of Shipping American Concrete Institute Annual Contract Quantity American Institute of Steel Construction American National Standards Institute Air Products & Chemical Inc. American Petroleum Institute American Society of Civil Engineers American Society of Mechanical Engineers American Society for Non-Destructive Testing American Society for Testing and Materials American Welding Society Best Available Control Technology Billion Cubic Feet Boil Off Gas from LNG Billion Standard Cubic Feet per Day British Thermal Unit Barrels per Day Barrel Oil Equivalent Community Awareness and Emergency Response Capital Expenditure Central Control Room Carbon Monoxide Code of Federal Regulations Compressed Natural Gas Conditions Precedent LNG Contract. Also Curacao Peil Reference Datum Consumer Price Index Published by U.S. Department of Labor Statistics Curacao Refinery Utility Company Contract Sales Price Distributed Control System Det Norske Veritas (A Ship Classification Society) Deep Water Port Fire and Gas Detection Export Credit Associations Energy Development in Island Nations U.S. Energy Information Administration European Investment Bank Environmental Impact Assessment Study Environmental Impact Statement Engineering, Procurement and Construction Emergency Shut Down Environmental, Social, Health and Safety Estimated Time of Arrival Front End Engineering Design Federal Energy Regulatory Commission Financial Intermediaries. Also Flow Indicator Floating Production Storage Offloading (Associated With Oil Production) Floating Storage Regasification Unit for LNG

CRUACAO CNG-LNG TERMINAL FEASIBILITY STUDY

Nomenclature

ft GOC H2S HAZOP HHW HM hp HP HSFO HTF HWS Hz IAS IBC IBRD ICSID ICSS IDB IDA IDC IEC IEEE IFC IMO IRR ISA ISO ITC ITS JBIC JV kV kW LLW LNG LNGC LS LSFO LWS m2 m3 m3/hr MAOP MCC MIGA MOU MMBtu MMscfd MP MPHEN

Feet Government of Curacao Hydrogen Sulfide Hazards and Operability High High Water Heating Medium (fluid used for heat transfer) Horsepower High Pressure High Sulfur Fuel Oil Heat Transfer Fluid High Water Spring Hertz (frequency cycles per second) Integrated Automation System International Building Code International Bank for Reconstruction and Development International Centre for Settlement of Investment Disputes Integrated Control and Safety System Inter-America Development Bank International Development Association Interest During Construction International Electrotechnical Commission Institute of Electrical and Electronic Engineers International Finance Corporation International Maritime Organization Internal Rate of Return Instrument Society of America International Standards Organization Independent Technical Consultant Interruptible Transportation Service Japan Bank for International Cooperation Joint Venture Kilovolt Kilowatt Low Low Water Liquefied Natural Gas LNG Carrier Lump Sum Low Sulfur Fuel Oil Low Water Spring Square Meter Cubic Meter Cubic Meter per Hour At Actual Flowing Conditions Maximum Allowed Operating Pressure (for pipelines) Motor Control Center Multilateral Investment Guarantee Agency Memorandum of Understanding Million British Thermal Units Million Standard Cubic Feet per Day Mile Post Curacao Ministry of Public Health, Environment and Nature

CRUACAO CNG-LNG TERMINAL FEASIBILITY STUDY

Nomenclature

MSS mtpa MW N2 NACE NBP NDE NEMA NFPA NOx NOI NOR NOT NPV NTP O&M OBE OC OCIMF OD OECD ORV OSHA OPEX PDVSA PLC PLEM PMT PO PPE ppmv PSA PSC psia psig PSV QA QC RAM RDK ROW SC SCF or scf SCV SIGTTO SO2 SPA SPCC SPL SSE

Manufacturer Standardization Society Million Tonnes per Annum Megawatt Nitrogen National Association of Corrosion Engineers National Balancing Point in the UK Non-Destructive Examination National Electric Manufacturers Association National Fire Protection Association Nitrous Oxide Notice of Intent Notice of Readiness Notice of Termination Net Present Value Notice To Proceed Operations and Maintenance Operating Basis Earthquake Operations Center Oil Companies International Marine Forum Outside Diameter Organization for Economic Cooperation and Development Open Rack Vaporizer Occupational Safety and Health Administration Operating Expenditure Petroleos de Venezuela S.A. Programmable Logic Controller Pipeline End Manifold (Used in Subsea Pipelines) Project Management Team Purchase Order Personal Protective Equipment Parts per million by volume Purchase Sales Agreement Project Services Contractor pounds per square inch (absolute) pounds per square inch (gauge) Pressure Safety Valve Quality Assurance Quality Control Reliability, Availability and Maintainability Refineria di Korsou N.V. Right of Way Shipping Charge (LNG shipping cost) Standard Cubic Feet @ 14.65 psia and 60oF Submerged Combustion Vaporizer Society of International Gas Tanker and Terminal Operations Sulfur Dioxide Sales Purchase Agreement Spill Prevention and Containment Control Sabine Pass Liquefication LLC Safe Shutdown Earthquake

CRUACAO CNG-LNG TERMINAL FEASIBILITY STUDY

Nomenclature

SSPC STL STS TCF or tcf or Tcf TEMA UCC UK UPS USCG V VIP VOC W WBG

Steel Structures Painting Council Submerged Turret Loading Side-to-Side LNG Transfer Trillion Standard Cubic Feet @ 14.65 and 60oF Tubular Exchanger Manufacturers’ Association Unit Capacity Charge (for Liquefaction) United Kingdom Uninterruptible Power Supply United States Coast Guard Volt Vacuum Insulated Pipe Volatile Organic Compounds Watt World Bank Group

CRUACAO CNG-LNG TERMINAL FEASIBILITY STUDY

Section 1 – Executive Summary

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 Curacao’s 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 Curacao’s 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.

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Section 1 – Executive Summary

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 allin 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.

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Section 1 – Executive Summary

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 Aqualectra’s 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

160 137.2

140

120.7

120

MMscfd

100 80 60 40 20 0 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031

Aqualectra

CRUC

Refinery

Total Pk Hour

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.

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Section 1 – Executive Summary

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

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Section 1 – Executive Summary

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

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Section 1 – Executive Summary

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 ArubaCuracao 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.

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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.

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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).

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Section 1 – Executive Summary

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 12”OD 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.

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Section 1 – Executive Summary



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 RDK’s 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

1 - 10 CURACAO CNG-LNG TERMINAL FEASIBILITY STUDY

Section 1 – Executive Summary

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 RDK’s 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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Section 1 – Executive Summary

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. 1.5

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

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 Owner’s 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;

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Section 1 – Executive Summary

 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.

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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 Agency’s (“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, Aqualectra’s 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.

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Section 2 – Curacao Gas Market Assessment

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.

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Section 2 – Curacao Gas Market Assessment

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.

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Section 2 – Curacao Gas Market Assessment

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

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

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Section 2 – Curacao Gas Market Assessment

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.

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Section 2 – Curacao Gas Market Assessment

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 Aruba’s infrastructure adopted an N+2 philosophy, which Shaw Consultants confirms is common practice. Aruba’s 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

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Section 2 – Curacao Gas Market Assessment

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 Aruba’s Annual Historical Power Demand

Source: EIA International Energy Statistics

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

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Section 2 – Curacao Gas Market Assessment

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 Bonaire’s 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 Bonaire’s 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.

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Section 2 – Curacao Gas Market Assessment

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 EIA’s Annual Energy Outlook 2012 Early Release utilizes a similar pricing assumption as illustrated in Figure 2.7-2.

1.2

12

1

10

0.8

8 0.6 6 0.4

4 2

0.2

0

0

Price Increase (%)

14

2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035

Price (US$/MMBTU)

Figure 2.7-2 Henry Hub Natural Gas Price Forecast

Henry Hub Price

Price Increase

Source: Annual Energy Outlook 2012 Early Release, EIA

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Section 2 – Curacao Gas Market Assessment

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 50 

300 

45  40  35 

200 

30  25 

150 

20  100 

15 

Price (US$/MMBTU)

Price (US$/bbl)

250 

10 

50 

5  ‐ 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035

‐

US$/bbl

US$/MMBTU

Source: Annual Energy Outlook 2012 Early Release, EIA

Figure 2.7-4 No.6 LSFO (Heavy Fuel Oil) Price Forecast

180 160 Price (US$/bbl)

140 120 100 80 60 40 20 Source: Annual Energy Outlook 2012 Early Release, EIA

2 - 10 CURACAO CNG-LNG TERMINAL FEASIBILITY STUDY

Section 2 – Curacao Gas Market Assessment

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

Max. Sendout Gas Pressure Peak Sendout Gas Rate Minimum Sendout Gas Rate Sendout Gas Temperature HHV

BULLEN BAY

SCHOTTEGAT HARBOR

780 psig

550 psig 137 MMscfd* 15 MMscfd* o

o

Minimum: 60 F

Maximum: 120 F

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 HC Dewpoint

7.0 lbs/MMscf o

Less than 30 F @ 500 psig

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

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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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Section 3 – Gas Supply Concepts

Figure 3.2-1 CNG Delivery System Schematic

Sea NG’s 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 NG’s 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 ship’s hull as illustrated in Figure 3.2-2. Figure 3.2-2 Schematic of Coselle™ and Ship Structure

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Section 3 – Gas Supply Concepts

A Coselle™ is Sea NG’s 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 ship’s design. Each container is designed to be integrated into the ships structure. The Coselles™ are stacked within the vessel’s 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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Section 3 – Gas Supply Concepts

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 NG’s 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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Section 3 – Gas Supply Concepts



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

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Section 3 – Gas Supply Concepts

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-IV’s 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

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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 SCV’s 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. Dechlorination of the effluent may also be required to meet environmental standards.

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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

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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 90°F) 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 countercurrent 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.

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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.

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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

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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 138,000m³ and five with a capacity of 150,900m³. 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

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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, Excelerate’s 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 Excelerate’s 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.

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Figure 3.3-12 Excelerate Energy Bridge Terminal – Gateway System

GasPorts (see Figure 3.3-13), such as Excelerate’s Bahia Blanca GasPort, are dockside applications of Excelerate’s 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 vessel’s 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 LNGC’s utilizing Excelerate’s STS transfer procedure. Figure 3.3-13 Excelerate Energy Bridge Terminal – GasPort System

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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 Excelerate’s 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 Excelerate’s 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 process. The STS System is capable of transferring up to 1,000 cubic meters of LNG per hour per line on each of six liquid lines and two vapor lines to manage vapor transfer between the two vessels involved in the STS transfer. The maximum transfer rate of 6,000 cubic meters per hour is the design rate of the system due in part to the assumption that two (2) cargo tanks with four (4) cargo tank pumps in operation at 1,500 cubic meters per hour each. The transfer rate has proven to be the most optimal rate while maintaining a safety margin to manage tank pressures and minimize the BOG generated. Figure 3.3-14 STS LNG Transfer Hoses and Manifolds

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Section 3 – Gas Supply Concepts

Mooring Arrangements. The FSRU requires a 16 line configuration 2-4-2 (2 head, 4 breast and 2 springs forward – 2 springs aft, 4 breast and 2 stern lines). In regard of the mooring configuration with the supply vessel, Excelerate recommends to have availability to send 2 shore lines at head and stern, although detailed mooring arrangements for STS will provide the mooring configuration for each class of supply vessel (see Figure 3.3-15). Figure 3.3-15 Mooring Arrangement For STS Transfer

In order to allow the mooring arrangement described above, the berth will be provided with the following set of quick release hooks: 

Mooring Dolphins (MD1, MD2, MD3 and MD4):

4 x 150 t each



Berthing Dolphins (BD1 and BD4):

2 x 150 t each

Vaporization and Regasification System. Each FSRU is capable of three modes of LNG vaporization: Closed-Loop, Open-Loop, and Combined Mode. In the Closed-Loop mode, steam from the FSRU propulsion steam boilers is used to heat fresh water circulated through the shell-and-tube vaporizers to regasify the LNG. There is no seawater intake or discharge used specifically for the regasification process in the Closed-Loop mode. In Open-Loop mode, the basic process is much the same as Closed-Loop with the exception that seawater is drawn in through the FSRU’s sea chests near the stern of the vessel. This seawater is used as a heat source and passed through the shell of the vaporizers. LNG is fed to the tubes of the vaporizer where it contacts the inner surface of the tubes and the heat required for vaporization is transferred. For this reason, the FSRUs are constrained from operating in the Open-Loop mode when water temperatures are below 45oF to minimize the risk of icing within the vaporizers. In Combined Mode of operation, seawater at temperatures between 45 and 58oF can be used and is further heated using steam from the FSRU’s boilers to provide sufficient heat for the vaporization of the LNG. A simple block flow diagram of the Excelerate Energy vaporization and regas system is illustrated in Figure 3.3-16.

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Figure 3.3-16 Excelerate Energy FSRU LNG Vaporization Block Flow Diagram

LNG Vaporizers. The FSRUs incorporate six LNG vaporizers. The vaporizer is a shell-and-tube heat exchanger where the LNG is vaporized to natural gas and heated to approximately 1°C (35°F) minimum by the seawater (open loop) or by the vessels internal heating system (closed loop). On leaving the LNG Vaporizer, natural gas flows through a Pressure Regulating Station that maintains a minimum pressure of approximately 75 barg in the regasification system, through a metering station and into the export pipeline and finally through the HP gas arm. Operation and Control. The regasification and gas delivery operation is continuously manned and is controlled utilizing the ship’s Integrated Automation System (IAS). The high pressure gas system is protected by means of high pressure trips, low temperature trips, and relief valves. The FSRU Emergency Shut Down (ESD) system will activate to shut down the regasification process in the event that a ship or shore side, including the power plant, ESD condition is present. The FSRU’s IAS ensures the safe operation of the regasification plant within the system design parameters. For each regasification nomination the FSRU operator will utilize a configuration screen to input three ordered parameters: 1. Required discharge rate. 2. Maximum discharge pressure. 3. Minimum discharge temperature. The GasPort or Gateway facility design provides for the following Operating Modes: 

Inerting



Warm Startup



Cold Startup



Startup from ambient temperature with air atmosphere within system



Steady-state Operation



Operation at minimum send out (turndown)

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Section 3 – Gas Supply Concepts



Normal shutdown and Warm-up



Emergency Shutdown



Depressurizing

Flexibility for LNG Supply Sources: The Excelerate LNG FSRU will be capable of handling and vaporizing a wide range of LNG supply sources. Data from various LNG supply sources that may supply/utilize the GasPort or Gateway terminal has been collected and is tabulated in Table 3.3-1. Table 3.3-1 LNG Supply Properties Properties 

Trinidad 

Idku 

Damietta 

Nigeria

Nigeria

Nigeria

Malaysia

Oman 

Qatar 

M.W.  LNG SpGr    NG  SpGr  HHV  Wobbe 

16.82  0.44 

16.55  0.43 

16.39  0.43 

17.44 0.45

17.64 0.45

17.51 0.45

18.05 0.46

18.20  0.47 

18.24  0.46 

Qatar  (lean)  17.02 ‐‐

0.58  1056  1385 

0.57  1037  1375 

0.57  1028  1367 

0.60 1084 1396

0.61 1095 1402

0.60 1086 1397

0.62 1114 1410

0.63  1119  1410 

0.63  1127  1420 

‐‐ 1052 ‐‐

Charter Lease Agreements and Customer CAPEX Costs: Excelerate Energy advised Shaw Consultants that they lease their LNG FSRU vessels under charter agreements. They are flexible with regard to the term of the lease which can range from 5-year to 20-year lease agreements. Typical indicative day rates for Excelerate’s 138,000m3 LNG FSRU ranges from US$125,000 to US$145,000 per day. The jetty and associated onshore facilities CAPEX costs are funded by the customer. As a reference, Excelerate was directly involved in the development of several LNG receiving terminals. Development of a GasPort starting from an existing jetty as in Bahia Blanca, the terminal infrastructure CAPEX cost paid by the customer was approximately US$50 million. In the case of a single buoy offshore Gateway configuration installed in the U.S. Gulf of Mexico, the CAPEX cost paid by the customer was approximately US$80 million. An FSRU connected to a Gasport can provide at base load rate up to 500 MMscfd in Open-Loop mode depending on downstream pipeline entry requirements. If pipeline pressure at the system entry point is between 65 bar (~940 psig) and 100 bar (or ~1450psig), then 500 MMscfd can be delivered. Each FSRU is provided with six independent LNG vaporizers and associated high pressure pumps. Each of these trains is rated for a nominal send-out capacity at 115 MMscfd, providing a high level of redundancy for Curacao’s 120 MMscfd base load capacity. BOG Handling Issues: When operating in Closed Loop mode at sendout rates in excess of approximately 200 MMscfd any boil off gas (BOG) generated onboard is used as fuel gas in the boilers and therefore there is no excess BOG that has to be processed. At lower sendout rates BOG will be generated in excess of what is normally consumed by the boilers. Given that sendout rates in the first years of the Curacao Project could be as low as 20 MMscfd, there will be excess BOG generated that will need to be handled in order to improve the efficiency of the facility. Excelerate Energy advises that gas sendout delivery rates less than 70 MMscfd will result in uncondensed BOG that must be handled onshore. During the first three years of operation with only the Aqualectra demand load, sendout gas rate is approximately 20 MMscfd. To accommodate low sendout rates, a BOG transfer arm and BOG pipeline compression equipment will have to be installed onshore. Without such onshore BOG equipment and modifications, the uncondensed BOG would otherwise have to be flared or vented. Shaw Consultants has estimated the CAPEX cost for the onshore BOG equipment required to achieve low gas sendout rates would be approximately US$25 million. Also, several modifications will

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have to be made to Excelerate’s standard FSRU design in order to maintain steady operational control of the low sendout delivery rates. The expected BOG rate during FSRU normal operation is expected to be 0.155% of the total LNG volume for the membrane tank containment system. The BOG generated during STS transfer is significantly higher and is impacted by a number of factors including the saturation vapor pressure of the FSRU LNG in storage, liquid temperature of the LNG cargo just prior to the start of the transfer on both the discharging and receiving vessel, the ambient temperature, and the transfer rate achievable based on the inventory of cargo on the receiving vessel. The FSRU does not require fuel oil as long as the vessel has LNG onboard to use for power production through consumption of natural and forced BOG. If the FSRU does not have sufficient LNG onboard beyond any heel retention that may be required, it consumes around 40 metric tons of fuel oil per day. On-Line Reliability: Reliability and availability guarantees will be based on final agreements for the installation and operation of the facility. For similar Excelerate facilities, availability is upwards of 98% including regularly scheduled maintenance of equipment. The FSRUs, as presently Classed, require dry-docking every 5 years and have maintenance requirements similar to a land based industrial facility. As an alternative, it is possible to add an additional Class notation to the FSRUs designating them as offshore facilities and allowing for extended periods of stationary service (10 to 20 years) without the need for dry-docking. The implementation of this additional Class notation can be elected upon finalization of the terminal requirements. Hoegh LNG FSRU Information NOTE: INFORMATION FURNISHED BY HOEGH IS SUBJECT TO CONFIDENTIALITY AGREEMENTS EXECUTED BETWEEN HOEGH, 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 HOEGH. History and Background Leif Hoegh & Company (“Hoegh”) was established in 1927 as a shipping company. The original company was subsequently restructured. Currently, there are now two shipping companies namely Hoegh LNG and Hoegh Autoliners. Hoegh LNG offers a complete package of floating LNG services as depicted in Figure 3.3-17. Hoegh’s business lines include: 

Floating Production Storage and Offloading (FPSO) for Oil and Gas Development Projects;



Maritime Transport Including LNG Carriers and Shuttle Regas Vessels (SRV);



LNG Regasification Floating Storage Regas Units (FSRU); and



Market Access by Deep Water Ports (DWP) or Dock Side Facilities.

Hoegh LNG existing fleet and customers are summarized in Figure 3.3-18.

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Figure 3.3-17 Hoegh Services

Figure 3.3-18 Hoegh Existing Customers & Fleet

Experience: Hoegh LNG has a proven track record in executing complex LNG regas projects. The Neptune SRV Project is an example. The Neptune SRV Project involved two LNG shuttle regas vessels (SRVs), one offshore terminal with two buoys and a gas pipeline to shore. GDF Suez Neptune was delivered November 30, 2009 and GDF Suez Cape Ann was delivered June 2, 2010. Operations meet design expectations. Another example is the Port Meridian Deep Water Port Project (see Figure 3.319). This project involved a stationary LNG FSRU offshore terminal located in UK waters. This project was fully funded by Hoegh LNG.

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Figure 3.3-19 Hoegh’s Port Meridian LNG FSRU Project

Port Dolphin Deep Water Port Project is also another example project (see Figure 3.3-20). This project involved a stationary LNG FSRU offshore terminal located offshore Gulf of Mexico near Tampa Florida. This project was approved by U.S. authorities and was fully funded by Hoegh LNG. Port Dolphin Energy LLC filed an application to construct and own the Port Dolphin Deepwater Port on March 29, 2007 and on January 31, 2011 it was announced that key environmental permits were receive for the project. The unloading facility of this new deepwater port would be located approximately 28 miles southwest of Tampa Bay. The terminal’s pipeline would be capable of transporting up to 1,200 MMscfd of natural gas per day, enough to serve more than one million homes. The Florida Public Service Commission predicted continued growth in Florida’s demand for natural gas, particularly for use in electric power generation. However, the recent downturn in U.S. gas prices has caused execution of this project to be suspended. Figure 3.3-20 Hoegh’s Port Dolphin LNG FSRU Project

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Hoegh also has significant experience in side-to-side (STS) LNG cargo transfer (see Figure 3.3-21). Operation history of Hoegh Galleon and Pioneer Knutsen have totaled 47 STS transshipments of LNG without any incidents. Figure 3.3-21 Hoegh Making STS LNG Cargo Transfer

Newbuilding Program: Hoegh has three purpose-built FSRUs are in queue at Hyundai Heavy Industries. Delivery of the three FSRUs is anticipated Q4 2013, Q1 2014, and Q2 2014. Hoegh has firm options for two additional FSRU newbuilds. These FSRU have flexible final specifications that can be tailored to specific projects. The base specifications call for 170,000m3 capacity, modular regas equipment and suitable for either jetty or offshore mooring (see Figure 3.3-22). Figure 3.3-22 Hoegh FSRU Newbuilt General Arrangement Plan

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Section 3 – Gas Supply Concepts

Regasification Facilities: The regasification facilities is an “open loop” system with seawater as the heating medium. An intermediate propane circuit is provided between the seawater and LNG for minimizing freezing risks. A modular design is used containing the required pumps, motors, heat exchangers, instrumentation and control systems to provide the required capacity with interconnecting piping between regas trains. Three regas trains each having 125 MMscfd of sendout capacity will be provided. An N+1 sparing philosophy is used in sparing critical equipment. A simplified process flow diagram of the LNG regasification system is illustrated in Figure 3.3-23. Figure 3.3-23 Hoegh Regasification Process Flow Diagram

STS LNG Transfer Equipment: Hoegh STS transfer system uses four flexible hoses for LNG cargo transfer from LNG carriers to the FSRU (2 for liquid and 2 for vapor return). The size and length of the hoses are 10 inches diameter and approximately 25 m long. The hoses are designed to EN-1474-II standards for cryogenic transfer hoses in offshore applications. Maximum LNG transfer rate is 9,000m3/hr. Emergency release couplers (ERC) are provided on each hose. Ship to ship communication link is provided by fiber optic and electric systems. Hoegh FSRU Charter Lease Agreements and Customer CAPEX Costs: Hoegh representatives advised Shaw Consultants that they lease their LNG FSRU vessels under charter agreements. They are flexible with regard to the term of the lease which can range from 5-year to 20-year lease agreements. Typical indicative annual lease fees for Hoegh’s LNG FSRU included US$50 million per annum based on a 10year lease term. Lease rate can be discounted by approximately 20% for a 20-year term. OPEX cost for the FSRU will be billed to customer in addition to the annual lease fee at actual costs which are estimated to be approximately US$20,000 per day. The customer would pay for the jetty or offshore mooring CAPEX cost. Hoegh estimates that the jetty option would cost approximately US$50 million and the offshore buoy option would cost approximately US$100 million.

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Section 3 – Gas Supply Concepts

BOG Handling Issues: Hoegh advises that gas sendout delivery rates less than 70 MMscfd will result in uncondensed BOG that must be handled onshore. During the first three years of operation with only the Aqualectra demand load, sendout gas rate is approximately 20 MMscfd. To accommodate low sendout rates, a BOG transfer arm and BOG pipeline compression equipment will have to be installed onshore. Without such onshore BOG equipment and modifications, the uncondensed BOG would otherwise have to be flared or vented. Shaw Consultants has estimated the CAPEX cost for the onshore BOG equipment required to achieve low gas sendout rates would be approximately US$25 million. Also, several modifications will have to be made to Hoegh’s standard FSRU design in order to maintain steady operational control of the low sendout delivery rates. The expected BOG rate during FSRU normal operation is expected to be designed for the membrane tank containment system at 0.155% of the total LNG volume. The BOG generated during STS transfer is significantly higher and is impacted by a number of factors including the saturation vapor pressure, liquid temperature of the LNG cargo just prior to the start of the transfer on both the discharging and receiving vessel, the ambient temperature, and the transfer rate achievable based on the inventory of cargo on the receiving vessel. The FSRU does not require fuel oil as long as the vessel has LNG onboard to use for power production through consumption of natural and forced BOG. On-Line Reliability: The FSRU annual on-line availability is 99% at a sendout rate of 92 MMscfd per train. The Hoegh FSRUs, as Classed, require dry-docking every 5 years and have maintenance requirements similar to a land based industrial facility. As an alternative, it is possible to add an additional Class notation to the FSRUs designating them as offshore facilities and allowing for extended periods of stationary service (10 to 20 years) without the need for dry-docking. The implementation of this additional Class notation can be elected upon finalization of the terminal requirements. 3.4

GAS IMPORT PIPELINE OPTIONS

The import of natural gas via pipeline from gas rich neighboring countries of either Colombia or Venezuela was evaluated as part of this study. This section discusses the results of research on the reported natural gas resources that may be considered as potential supply for Curacao and the gas import pipeline systems required. Colombian Supply Colombia’s natural gas reserves have declined from about 132 Bcm (4.6 Tcf) in 2002 to around 112 Bcm (4.0 Tcf) in 2010, as seen in Table 3.3-1 below. Table 3.4-2 Colombia Proved Reserves (CIA World Factbook) Year

2002

2003

2004

2005

2008

2010

Bcm

132

132

132

114

123

112

About 90 percent of Colombia’s natural gas reserves originate from two main fields, the Guajira and Cusiana fields. In 2009 Guajira supplied 65 percent of the country’s production, while Cusiana contributed about 25 percent. Guajira produced 663,000 MMBtud and Cusiana supplied about 250,000 MMBtud, on average in 2009. The producers active in Colombia at 2009, are as identified in the following table:

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Section 3 – Gas Supply Concepts

Table 3.4-3 Colombia Gas Supply by Company in 2009 Company

MMBtu/D

Share %

Ecopetrol

670,000

63

Chevron

236,000

22

BP

62,000

6

Tepma/Total

28,000

3

Pacific Rubiales

42,000

4

Others

25,000

2

Total

1,063,000

100

As a potential gas supplier to Curacao, it appears that the Guajira basin of Colombia would be geographically suited. The Guajira basin is located in the northeasten region of the country and produces natural gas from offshore as well as onshore fields. The Figure 3.4-24 identifies the location of the Guajira basin. Figure 3.4-24 Guajira Basin of Colombia

By comparison, the next largest natural gas producing region of Colombia is located in the eastern central region of the country from the Cusiana-Cupiagua fields, as depicted in Figure 3.4-25.

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Section 3 – Gas Supply Concepts

Figure 3.4-25 Cusiana Region of Colombia

Chevron discovered gas at Guajira in 1972. The Ballena onshore field began production in 1977, and the Chuchupa offshore field started up in 1979. Chevron is the operator of the fields at Guajira with a net interest of 43 percent and with Ecopetrol holding the remaining 57 percent interest. Despite the fields’ decline in recent years, Chevron has been able to slow the decline with improved production and recovery methods. Also, recent seismic tests indicated untapped potential in Guajira’s Riohacha field. In 2010 gross average production achieved by Chevron was 714 MMscfd. In 2003 Chevron was granted indefinite field concession as long as its fields remained productive. By comparison, most contracts in Colombia are limited to 20 or 30 year terms. Chevron remains Colombia’s largest natural gas producer, providing about two-thirds of the country’s needs from the Guajira fields. In 2007 a 225 km bi-national gas pipeline was commissioned to ship up to 250 MMscfd from the Guajira gas fields to industrial customers around Maracaibo, Venezuela. Shipments at the end of 2011 have averaged 200 MMscfd whereas the original agreement called for the reverse flow of gas from Venezuela to Colombia by 2012. The reverse flow has not materialized due to the delay in Venezuela’s development of its own substantial natural gas reserves. As conditions around the Venezuelan gas reserves have not improved, the agreement to ship gas from Colombia to Venezuela has been extended by 2.5 years through mid 2014. In response to this development and to meet rising domestic demand in Colombia, Chevron is reviving its Riohacha field in Guijara to provide a boost in its overall production by about 8 percent. In November 2011 Chevron saw production from its Guajira interests at only 600 MMscfd (information source, Platts). Problems to the sale of natural gas in Colombia have been identified as those seen in European countries before gas release programs were implemented. In Colombia the upstream market is constricted by a single dominant producer (Ecopetrol) causing an apparent under-supply of long-term firm gas contracts with consequential repercussions in the transport market. Loopholes in regulations have allowed producers to declare most/all available supplies as interruptible, to avoid selling gas in auctions, while

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Section 3 – Gas Supply Concepts

special treatment of Guajira gas distorts the Colombian gas market and producers’ incentives. There is no market price for gas established in Colombia. This information was taken from a paper entitled “Upstream Issues in the Colombian Natural Gas Market” by David Harbord, Market Analysis Ltd, Oxford; Congreso Annual de Naturgas, Certegana, 26 March 2010. While the geographic location of the predominant country reserves are favorable to the export of gas to Curacao, the diminishing supply and increasing demand, in addition to the evolving gas market politics in Colombia, relegate this supply option to being possible but unlikely. Venezuelan Supply Venezuela’s proven natural gas reserves have been reported by OGJ at 5,072 Bcm (179 Tcf) in 2011, making it the second largest in the Western Hemisphere after the US. Table 3.4-4 below identifies the natural gas reserves for Venezuela over the years from 2002 to 2010. Table 3.4-4 Venezuela Proved Reserves (CIA World Factbook) Year

2002

2003

2004

2005

2008

2010

Bcm

4,202

4,202

4,190

4,276

4,708

4,983

It is estimated that 90 percent of Venezuela’s reserves are associated gas. PDVSA’s plans over 20062012 were to be producing 11.5 Bcfd by 2012, with the additional discoveries of non-associated gas. However, because the plans did not materialize, the country is producing only 6.96 Bcfd, according to official figures (source: Platts). It is reported that PDVSA uses the majority of Venezuela’s natural gas to produce its heavy oil from the Orinoco Basin. Since 2005, the use of natural gas for enhanced oil recovery has increased by more than 50 percent. In addition, to meet the demand from industrial clients in the western region, Venezuela is importing gas from Colombia via the pipeline discussed above. The deficit production for the country is seen in Figure 3.4-26, where deficits are met with gas imports. Figure 3.4-26 Venezuela Consumption and Net Imports

Recent discoveries of natural gas offshore Venezuela are planned to be available in the future for oilfield operations and for the rising domestic consumption. In November 2009, Repsol announced its Perla 1X well, in the Cardon IV block, had discovered natural gas to the equivalent of 1 to 1.4 billion BOE (6 to

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Section 3 – Gas Supply Concepts

8.4 Tcf), among the fifth largest hydrocarbon discoveries in 2009. Additional drilling by ENI in the Cardon IV block has confirmed the discovery with a potential size of 14 Tcf of natural gas. The field of the Cardon IV block is found in relatively shallow water of 70 m, on the western side of Venezuela’s Paraguana Peninsula, as seen in Figure 3.4-27. Figure 3.4-27 Location of the Cardon IV Block

The resources discovery in the Cardon IV block encountered 840 ft (260 m) of net pay in carbonate sequence confirmed by 700 ft (210 m) of bottom hole recovered logs of the Perla-2 well. Production tests had the well flowing at 50 MMcfd and 1,500 bopd of condensate. Per well production is estimated at 70 MMcfd and 2,000 bopd of condensate. Formation depths and pressures were not available. ENI and Repsol jointly operate the Cardon IV block, each with an ownership of 50 percent. PDVSA owns a 35 percent back-in right, to be exercised in the development phase. In areas off of Venezuela’s northeast coast, PDVSA has awarded exploration blocks such as at Mariscal Sucre, where the Aban Pearl semi-submersible drilling rig sank in May 2010. This area was slated to begin production in 2012, with an ultimate target rate of 1.2 Bcfd delivered to shore with a 70-mile subsea pipeline. Since the sinking of the Aban Pearl, PDVSA has contracted with Technip to build a production platform for field development. The location of the Mariscal Sucre area is depicted in Figure 3.4-28. Figure 3.4-28 Location of the Mariscal Sucre Field

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Section 3 – Gas Supply Concepts

With immense potential for producing natural gas, Venezuela has talked of developing LNG export facilities. Three possible projects were cited by the EIA, and as late as 2010, a letter of intent had been signed with Iran for assistance in building an LNG plant in the Delta Caribe area (source, Tech Talk – Venezuelan Natural Gas Prodution; January 23, 2011). It is also noted that Venezuela has long-term contracts with Argentina and Cuba to supply these countries with their required gas by 2013. Under the agreement between Iran and Venezuela, part of these supply arrangements will be sourced by Iran’s LNG plant, where PDVSA has a 10 percent interest share (source, PressTV; Iran to Export LNG to Cuba, Argentina; December 5, 2010). In conclusion, Venezuela has significant reserves potential near Curacao at the Cardon IV block offshore of the northwestern edge of Venezuela’s Paraguana Peninsula. These resources are certain to be developed as Venezuela’s natural gas demand is greater than its current production capacity and imports from Colombia are expected to extend to only mid 2014. Due to the proximity and the sheer volume of resources, the potential to supply for Curacao is greater than other options reviewed. The uncertainty lies with the demand requirements of Venezuela’s domestic and export market commitments and the political environment/relationship. One final point, it would be of interest to know whether the productive interval found at Cardon IV extends to the waters of Curacao. It is not an unrealistic stretch to believe that hydrocarbon bearing carbonates, similarly as that encountered off of Venezuelan shores, are also present near Curacao. Gas Import Pipeline Cases Two gas import pipeline scenarios for Curacao were considered including a pipeline from Colombia and one from Venezuela. For each of these two scenarios, three cases were evaluated including:  Gas Import Pipeline For Aqualectria Load Only;  Gas Import Pipeline For Curacao Demand (Including Aqualectra Plus Isla Refinery); and  Gas Import Pipeline For Curacao Demand Plus Aruba. The pipeline systems required for these scenario cases are described in Table 3.4-5. The routes for the Colombia gas import pipeline scenarios are illustrated in Figure 3.4-29 and the routes for the Venezuela gas import pipeline scenarios are illustrated in Figure 3.4-31 and Figure 3.4-32. Table 3.4-5 Gas Import Pipeline Scenario Case Descriptions

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Section 3 – Gas Supply Concepts

Figure 3.4-29 Colombia to Curacao (Cases 1aa and 1aaa)

Figure 3.4-30 Colombia to Aruba to Curacao (Case 1a)

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Section 3 – Gas Supply Concepts

Figure 3.4-31 Venezuela to Curacao (Cases 1bb and 1bbb)

Figure 3.4-32 Venezuela to Aruba to Curacao (Case 1b)

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Section 4 – Commercial Evaluation

4.1

INTRODUCTION

This section of the reports documents the commercial evaluation of the gas supply options for Curacao including: 

CNG;



LNG; and



Gas Import Pipelines From Colombia and Venezuela.

The evaluations should be considered to have screening level accuracy with CAPEX and OPEX estimates within +/-40%. 4.2

COMMERCIAL EVALUATION BASIS

Each of the gas supply options were evaluated using a consistent set of assumptions. An evaluation period from 2015 to 2031 served as the evaluation basis for each case. A spreadsheet was developed to calculate the year-to-year delivered cost of gas to the Curacao customers taking into consideration gas purchase cost at the source, OPEX costs, and CAPEX amortization. The delivered cost of gas included local distribution cost required to deliver the gas to the customers’ gas purchase and sales meter located at their respective facility site. The evaluations assumed 100% equity funding and therefore no interest costs were incurred. Labor and material expenses were escalated annually based on an assumed CPI growth rate of 4% per annum. Gas purchase costs at the source were based on the following assumptions:

4.3



For the CNG and Gas Import Pipeline options, the gas purchase price (F.O.B. at the source) was assumed to be 100% of the Henry Hub price forecast as described and shown in Section 2 of this report.



For the CNG option Trinidad, Colombia, and Venezuela supply sources were considered.



For the Gas Import Pipeline option, a pipeline to Trinidad was determined to be too long and uneconomic. Only Colombian and Venezuelan gas sources were assumed to be viable for the Gas Import Pipeline option. CAPEX AND OPEX COST ESTIMATES

The CAPEX and OPEX were estimated for each scenario case. Accuracy of these estimates is believed to be +/-40%. CAPEX estimates reflect 1st Qtr 2012 costs. Local Sendout Gas Pipeline Two CAPEX cost estimates were prepared for the local sendout gas pipeline; one estimate assuming an 8-mile pipeline from the Bullen Bay terminal site to the gas customers located in the Isla Refinery area and another estimate assuming a ¾ mile pipeline within the Isla Refinery area from the alternate Schottegat terminal site. The estimated CAPEX costs are summarized in Table 4.3-1 and Table 4.3-2.

4-1 CURACAO CNG-LNG TERMINAL FEASIBILITY STUDY

Section 4 – Commercial Evaluation

Table 4.3-1 CAPEX Estimate for Local Sendout Gas Pipeline (From Bullen Bay Terminal Site)

Cost Item MOB RIGHT-OF-WAY COST / DAMAGES PIPE MATERIAL COST PIPE COATING COSTS VALVES & FITTINGS PIG LAUNCHER / RECEIVER METERING / CONTROLS SKID FREIGHT / SHIPPING SHORE CROSSING (TUNNEL BORING) SPREAD / LAYBARGE COST LABOR COST COMPRESSOR STATION COST DEMOB SURVEY PIPE STORAGE & ONSHORE SUPPLY BASE PROJECT ENGINEERING & MANAGEMENT TOTAL COST w/o CONTINGENCY CONTINGENCY TOTAL COST w/ CONTINGENCY

US$ 100,000 132,000 2,904,041 264,000 500,000 180,000 525,000 94,287 0 4,400,000 274,560 0 100,000 16,000 158,400 1,157,795 10,806,083 1,080,608 11,886,691

Table 4.3-2 CAPEX Estimate for Local Sendout Gas Pipeline (From Alternate Schottegat Site)

Cost Item

US$

MOB RIGHT-OF-WAY COST / DAMAGES PIPE MATERIAL COST PIPE COATING COSTS VALVES & FITTINGS PIG LAUNCHER / RECEIVER METERING / CONTROLS SKID FREIGHT / SHIPPING SHORE CROSSING (TUNNEL BORING) SPREAD / LAYBARGE COST LABOR COST COMPRESSOR STATION COST DEMOB SURVEY PIPE STORAGE & ONSHORE SUPPLY BASE PROJECT ENGINEERING & MANAGEMENT TOTAL COST w/o CONTINGENCY CONTINGENCY TOTAL COST w/ CONTINGENCY

100,000 0 272,254 24,750 500,000 180,000 525,000 8,839 0 618,750 38,610 0 100,000 1,500 14,850 286,146 2,670,700 267,070 2,937,770

CNG Option Since CNG tariff fees were calculated using the software posted on Sea NG’s web site, recovery of CAPEX and OPEX for the CNG export terminal facility, the CNG import terminal facility, and the CNG ships are embodied in the tariff fees. Therefore, the other CAPEX and OPEX costs stem from the installation and operation of the gas sendout pipeline installed from the terminal site to the Curacao customers. The estimated CAPEX for the local sendout gas pipeline from the Bullen Bay is US$11.9 million which is summarized in Table 4.3-1. If the terminal is located at the alternate Schottegat site, the estimated CAPEX for the local sendout gas pipeline is US$2.9 million which is summarized in Table 4.32. The OPEX was based on the following assumptions: 

Calculated tariff fees for export terminal, import terminal and CNG ships

4-2 CURACAO CNG-LNG TERMINAL FEASIBILITY STUDY

Section 4 – Commercial Evaluation

-

Trinidad Supply US$3.75/MMBtu.

-

Colombia Supply US$2.20/MMBtu.

-

Venezuela Supply US$2.05/MMBtu.



RDK operating staff annual expense of US$1.70 million inclusive of all benefits escalating annually with CPI of 4% per annum.



Annual maintenance and repair of the local sendout gas pipeline system equal to 0.25% of CAPEX escalating with CPI of 4% per annum.



Fuel costs based on 2% of throughput volume at purchased gas price.



Electrical power costs are covered within the contingency.

Conventional Onshore LNG Terminal Option The Bullen Bay site location was assumed in estimating the conventional onshore LNG terminal costs. The CAPEX costs were estimated using an in-house proprietary LNG terminal facility cost estimating spreadsheet. Input to the spreadsheet includes a complete equipment list with sizes and materials of construction for both equipment and interconnecting piping. Budget costs were obtained from vendors for most of the major equipment. LNG tank costs were bench marked against current cost data furnished by CB&I and other in-house LNG tank cost data. The budget equipment costs received from the vendors were used to calibrate the cost estimating spreadsheet to yield estimates based on 1st Qtr 2012 costs. The estimate accuracy is believed to be better than +/-40%. The estimated CAPEX for the LNG terminal sized for a sendout rate to serve the Curacao demand of 137 MMscfd with a 160,000m3 full containment LNG storage tank is US$421.3 million which is summarized in Table 4.3-3. Table 4.3-3 CAPEX Estimate Onshore LNG Terminal (137 MMscfd, 160,000m3 LNG Tank) CATEGORY CONTRACTOR DIRECT COSTS Equipment Bulk Materials Labor Subtotal Direct Costs CONTRACTOR UNDIRECT COSTS Engineering, Procurement & EPC Management Temporary Camp / Housing Construction Equipment Rental Site Grading & Preparation Transport & Unload Hook-Up Commissioning & Start-Up Spare Parts Freight MOB / DMOB Duties & Taxes Insurance Other Subtotal Other Costs Total Prime Contract Owner's PMT Owner's Startup Cost Subtotal w/o Contingency Owner's Contingency TOTAL ERECTED COST

US$k

%

225,523 40,878 8,978 275,380

65.84 11.93 2.62 80.40

33,046 5,000 13,320 2,000 2,754 1,476 6,660 1,500 1,377 67,133 342,513 6,850 1,713 351,076 70,215 $ 421,291

9.65 1.46 3.89 0.58 0.80 0.43 1.94 0.44 0.40 19.60 100.00 2.00 0.50

Notes and Comments 3

Includes 160,000M LNG Tank

12% Of Direct Costs Import Welders for 9% Ni Welding 5% Of Equip + Bulks N/A Offshore Only Included In Direct Costs 1.0% Of Direct Costs 2.5% Of Equipment + Bulks Rough Estimate Govt Project, No Duties and Taxes 0.5% Of Direct Costs

2% Of Total Prime Contract 0.5% Of Total Prime Contract

20.00

4-3 CURACAO CNG-LNG TERMINAL FEASIBILITY STUDY

Section 4 – Commercial Evaluation

The estimated CAPEX for the LNG terminal sized for a sendout rate of 137 MMscfd with an 80,000m3 full containment LNG storage tank is US$318.4 million which is summarized in Table 4.3-4. Table 4.3-4 CAPEX Estimate Onshore LNG Terminal (137 MMscfd, 80,000m3 LNG Tank) CATEGORY CONTRACTOR DIRECT COSTS Equipment Bulk Materials Labor Subtotal Direct Costs CONTRACTOR OTHER COSTS Engineering, Procurement & EPC Management Temporary Camp / Housing Construction Equipment Rental Site Grading & Preparation Transport & Unload Hook-Up Commissioning & Start-Up Spare Parts Freight MOB / DMOB Duties & Taxes Insurance Other Subtotal Other Costs Total Prime Contract Owner's PMT Owner's Startup Cost Subtotal w/o Contingency Owner's Contingency TOTAL ERECTED COST

US$k

%

165,523 31,878 8,978 206,380

63.95 12.32 3.47 79.73

24,766 5,000 9,870 2,000 2,064 1,296 4,935 1,500 1,032 52,463 258,843 5,177 1,294 265,314 53,063 $ 318,377

9.57 1.93 3.81 0.77 0.80 0.50 1.91 0.58 0.40 20.27 100.00 2.00 0.50

Notes and Comments 3

Includes 80,000m LNG Tank

12% Of Direct Costs Import Welders for 9% Ni Welding 5% Of Equip + Bulks N/A Offshore Only Included In Direct Costs 1.0% Of Direct Costs 2.5% Of Equipment + Bulks Rough Estimate Govt Project, No Duties and Taxes 0.5% Of Direct Costs

2% Of Total Prime Contract 0.5% Of Total Prime Contract

20.00

Table 4.3-5 CAPEX Estimate Onshore LNG Terminal (177 MMscfd, 160,000m3 LNG Tank) CATEGORY CONTRACTOR DIRECT COSTS Equipment Bulk Materials Labor Subtotal Direct Costs CONTRACTOR OTHER COSTS Engineering, Procurement & EPC Management Temporary Camp / Housing Construction Equipment Rental Site Grading & Preparation Transport & Unload Hook-Up Commissioning & Start-Up Spare Parts Freight MOB / DMOB Duties & Taxes Insurance Other Subtotal Other Costs Total Prime Contract Owner's PMT Owner's Startup Cost Subtotal w/o Contingency Owner's Contingency TOTAL ERECTED COST

US$k

%

227,245 41,306 9,406 277,957

65.75 11.95 2.72 80.42

33,355 5,000 13,428 2,000 2,780 1,519 6,714 1,500 1,390 67,685 345,642 6,913 1,728 354,283 70,857 $ 425,140

9.65 1.45 3.88 0.58 0.80 0.44 1.94 0.43 0.40 19.58 100.00 2.00 0.50

Notes and Comments Includes LNG Tank

12% Of Direct Costs Import Welders for 9% Ni Welding 5% Of Equip + Bulks N/A Offshore Only Included In Direct Costs 1.0% Of Direct Costs 2.5% Of Equipment + Bulks Rough Estimate Govt Project, No Duties and Taxes 0.5% Of Direct Costs

2% Of Total Prime Contract 0.5% Of Total Prime Contract

20.00

4-4 CURACAO CNG-LNG TERMINAL FEASIBILITY STUDY

Section 4 – Commercial Evaluation

A cost estimate was also prepared assuming that the conventional terminal is sized for a sendout rate of 177 MMscfd with a 160,000m3 full containment LNG storage tank. This sendout capacity is adequate to serve the Curacao demand plus provide 40 MMscfd of export gas to Aruba. The estimated CAPEX for this LNG terminal is US$425.1 million which is summarized in Table 4.3-5 above. The local onshore sendout pipeline CAPEX associated with each of the conventional LNG terminal estimates is US$11.9 million for the Bullen Bay site and US$2.9 million for the alternate Schottegat site. The sendout pipeline estimates were summarized previously in Table 4.3-1 and Table 4.3-2 above. The estimated CAPEX cost for a gas export pipeline from the Bullen Bay LNG terminal to Aruba is US$130.0 million which is summarized in Table 4.3-6. An estimate for the Aruba export pipeline was not made for the alternate Schottegat terminal site. Table 4.3-6 CAPEX Estimate for Gas Export Pipeline from Bullen Bay to Aruba

Cost Item MOB RIGHT-OF-WAY COST / DAMAGES PIPE MATERIAL COST PIPE COATING COSTS VALVES & FITTINGS PIG LAUNCHER / RECEIVER METERING / CONTROLS SKID FREIGHT / SHIPPING SHORE CROSSING (TUNNEL BORING) SPREAD / LAYBARGE COST LABOR COST COMPRESSOR STATION COST DEMOB SURVEY PIPE STORAGE & ONSHORE SUPPLY BASE PROJECT ENGINEERING & MANAGEMENT TOTAL COST w/o CONTINGENCY CONTINGENCY TOTAL COST w/ CONTINGENCY

US$ 10,100,000 82,500 22,172,947 4,653,000 500,000 180,000 300,000 719,901 20,000,000 30,866,000 3,732,960 0 10,100,000 690,000 1,445,400 12,665,125 118,207,832 11,820,783 130,028,616

The OPEX costs for the conventional onshore LNG terminal were based on the following assumptions: 

RDK operating staff annual expense of US$2.55 million inclusive of all benefits escalating annually with CPI of 4% per annum.



Annual maintenance and repair of the LNG terminal and gas pipeline system equal to 0.25% of CAPEX costs escalating with CPI of 4% per annum.



Fuel costs based on 0.15% of throughput volume.



Electrical power costs are covered within contingency.

LNG FSRU Jetty Terminal Option Bullen Bay was only considered for the LNG FSRU option. The LNG FSRU option has relatively low initial CAPEX costs. Based on information furnished by Excelerate Energy and Hoegh, the estimated CAPEX cost for the LNG FSRU configuration is US$50.0 million for the jetty, US$25.0 million for the onshore BOG compression equipment required to handle excess BOG produced at low gas sendout rates, and US$11.9 million for the local sendout gas pipeline yielding an estimated total CAPEX of US$86.9 million.

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Section 4 – Commercial Evaluation

The OPEX cost, however, are relatively high due to the FSRU rental fees which were assumed to be US$135,000 per day escalating at 1.5% per annum. Maintenance and operating cost for the FSRU were assumed to be included in the rental day rate. Other OPEX costs were based on the following assumptions: 

RDK operating staff annual expense of US$1.70 million inclusive of all benefits escalating annually with CPI of 4% per annum.



Annual maintenance and repair of the gas pipeline system equal to 0.25% of CAPEX costs escalating with CPI of 4% per annum.



Fuel costs based on 0.15% of throughput volume.



Electrical power costs are covered within contingency.

LNG FSRU Offshore Buoy Terminal Option Based on information furnished by Excelerate Energy and Hoegh, the estimated CAPEX cost for the LNG FSRU configuration moored offshore is US$80.0 million for the buoy mooring system, US$39.5 million for the offshore delivery pipeline, and US$11.9 million for the local sendout gas pipeline yielding an estimated total CAPEX of US$131.4 million. Shaw Consultants note that the basic FSRU facility for the offshore buoy moored system would have to be modified to include BOG compression equipment onboard to handle excess BOG during low sendout gas rates. If this option is pursued, handling excess BOG could be a major issue and the required modifications would need to be reviewed by the FSRU vendor. The OPEX cost assumptions for this option assumed the FSRU rental fees to be US$135,000 per day escalating at 1.5% per annum. Maintenance and operating cost for the FSRU were assumed to be included in the rental day rate. Other OPEX costs were based on the following assumptions: 

RDK operating staff annual expense of US$1.70 million inclusive of all benefits escalating annually with CPI of 4% per annum.



Annual maintenance and repair of the buoy mooring and gas pipeline system equal to 0.25% of CAPEX costs escalating with CPI of 4% per annum.



Fuel costs based on 0.15% of throughput volume.



Electrical power costs are covered within contingency.

Shaw Consultants note that the FSRU rental fees assumed in this option are probably low since the vendor will have to increase the rental fees to recover cost for onboard BOG compression equipment. Gas Import Pipeline Option CAPEX cost estimates were prepared for six import pipeline cases:  Import Pipeline from Colombia for Aqualectra Demand Only (Option 1aaa; 30 MMscfd))  Import Pipeline from Colombia for Curacao Total Demand (Option 1aa; 137 MMscfd)  Import Pipeline from Colombia for Curacao + Aruba Demand (Option 1a; 177 MMscfd)  Import Pipeline from Venezuela for Aqualectra Demand Only (Option 1bbb; 30 MMscfd)

4-6 CURACAO CNG-LNG TERMINAL FEASIBILITY STUDY

Section 4 – Commercial Evaluation

 Import Pipeline from Venezuela for Curacao Total Demand (Option 1bb; 137 MMscfd)  Import Pipeline from Venezuela for Curacao + Aruba Demand (Option 1b; 177 MMscfd) The CAPEX cost estimates are summarized in Table 4.3-7 and include the costs for the local onshore sendout pipeline for gas delivery to the Curacao customers. Table 4.3-7 CAPEX Estimate for Gas Import Pipeline Options

Colombia

Venezuela

Cost Item – US$

Option 1aaa 30 MMscfd

Option 1aa 137 MMscfd

Option 1a 177 MMscfd

Option 1bbb 30 MMscfd

Option 1bb 137 MMscfd

Option 1b 177 MMscfd

MOB RIGHT-OF-WAY COST / DAMAGES PIPE MATERIAL COST PIPE COATING COSTS VALVES & FITTINGS PIG LAUNCHER / RECEIVER METERING / CONTROLS SKID FREIGHT / SHIPPING SHORE CROSSING (TUNNEL BORING) SPREAD / LAYBARGE COST LABOR COST COMPRESSOR STATION COST DEMOB SURVEY PIPE STORAGE & ONSHORE SUPPLY BASE PROJECT ENGINEERING & MANAGEMENT TOTAL COST w/o CONTINGENCY CONTINGENCY TOTAL COST w/ CONTINGENCY

10,200,000 297,000 50,420,673 10,362,000 3,250,000 270,000 675,000 1,637,035 20,000,000 73,785,800 8,798,328 10,200,000 1,516,000 3,286,800 23,363,836 218,062,472 21,806,247 239,868,720

10,200,000 297,000 75,475,436 10,362,000 3,250,000 270,000 675,000 2,450,501 20,000,000 73,785,800 8,798,328 16,647,525 10,200,000 1,516,000 3,286,800 28,465,727 265,680,117 26,568,012 292,248,128

10,300,000 379,500 79,609,250 10,791,000 3,500,000 360,000 825,000 2,584,716 30,000,000 78,515,800 9,220,728 24,949,195 10,300,000 1,566,000 3,465,000 31,963,943 298,330,131 29,833,013 328,163,144

10,100,000 132,000 35,937,509 6,534,000 3,250,000 270,000 675,000 1,166,802 10,000,000 45,346,400 5,461,104 10,100,000 966,000 2,039,400 15,837,386 147,815,601 14,781,560 162,597,161

10,100,000 132,000 46,538,741 6,534,000 3,250,000 270,000 675,000 1,510,998 10,000,000 45,346,400 5,461,104 13,584,225 10,100,000 966,000 2,039,400 18,780,944 175,288,812 17,528,881 192,817,694

10,200,000 214,500 51,591,180 6,930,000 3,750,000 450,000 975,000 1,675,038 25,000,000 51,638,400 5,904,624 24,095,563 10,200,000 996,000 2,257,200 23,505,301 219,382,806 21,938,281 241,321,087

The OPEX costs for gas import pipeline options were based on the following assumptions: 

RDK operating staff annual expense of US$2.55 million inclusive of all benefits escalating annually with CPI of 4% per annum.



Annual maintenance and repair of the LNG terminal and gas pipeline system equal to 0.50% of CAPEX costs escalating with CPI of 4% per annum.



Fuel costs based on operating compression horsepower consuming 9,000 Btu/hp-hr valued at the gas purchase price (F.O.B.).



Electrical power costs are covered within contingency.

4.4

DELIVERED LNG PRICE (C.I.F. CURACAO TERMINAL)

The delivered LNG prices (C.I.F. Curacao) were calculated using the following method: 

LNG supply was assumed to be sourced from the Atlantic LNG Plant located in Trinidad. The LNG purchase price (F.O.B. the Plant) was assumed to be priced at 115% of the Henry Hub price forecast plus a UCC liquefaction fee of US$2.50/MMBtu. Fifteen percent (15%) of the UCC liquefaction fee was assumed to escalate annually with the CPI which was assumed to be 4% per annum.



LNG shipping costs were calculated using Shaw Consultants’ shipping model based on a ship charter rate of US$120,000 per day for standard 140,000m3 capacity LNG carriers. LNG losses during transshipment were assumed to be 0.145% of the cargo volume per day. The LNG ship charter day rate was assumed to escalate with the CPI of 4% per annum. Cruse speed of the LNG ship was assumed to be 17 knots.

4-7 CURACAO CNG-LNG TERMINAL FEASIBILITY STUDY

Section 4 – Commercial Evaluation

This LNG pricing mechanism was compared to an alternate pricing mechanism where LNG pricing was based on clearing the European gas market price at the UK National Balancing Point (NBP) plus a premium to pull small volumes for Curacao from Trinidad. The premium was assumed to be ½ the difference between the shipping cost to Europe versus shipping cost to Curacao. It was determined that the Henry Hub indexing formula yielded a higher delivered LNG cost to Curacao (see Figure 4.4-1 and Figure 4.4-2). Therefore to be conservative, the Henry Hub pricing formula was used in this study. Figure 4.4-1 Henry Hub and UK NBP Gas Price Forecast

Figure 4.4-2 LNG Pricing Mechanism

4-8 CURACAO CNG-LNG TERMINAL FEASIBILITY STUDY

Section 4 – Commercial Evaluation

4.5

CURACAO AVERAGE DELIVERED GAS PRICE

The average delivered gas price over the evaluation period (2015 to 2031) was calculated for each of the gas supply option cases. Although the CNG option was dropped from consideration as a viable delivery option due to the high commercial and technical risks, the results have been reported below for documentation purposes. The following results were calculated. CNG Option

CAPEX US$MM

Gas Purchase Price $/MMBtu

CAPEX + OPEX Recovery $/MMBtu

Delivered Gas Price $/MMBtu

% Parity To #2 LSFO

% Parity To #6 LSFO

137

11.90

6.90

4.63

11.53

36.5

47.3

CNG Colombia Curacao Demand

137

11.90

6.90

4.94

11.84

37.5

48.6

CNG Trinidad Curacao Demand

137

11.90

6.90

8.24

15.14

47.9

62.1

CAPEX + OPEX Recovery $/MMBtu

Delivered Gas Price $/MMBtu

% Parity To #2 LSFO

% Parity To #6 LSFO

Gas Capacity MMscfd

CNG Venezuela Curacao Demand

CASE DESCRIPTION

Conventional Onshore LNG Terminal Option Gas Capacity MMscfd

CAPEX US$MM

LNG Purchase Price $/MMBtu

137 (30)

433.2

10.58

3.91

14.86

47.0

61.0

Bullen Bay Site Curacao Demand

137

433.2

10.58

1.94

12.88

40.8

52.9

Schottegat Site Curacao Demand

137

424.2

10.58

1.90

12.85

40.7

52.7

Bullen Bay Site Curacao Demand 80,000m3 Tank

137

330.3

10.58

1.57

12.56

39.7

51.5

Bullen Bay Site Curacao + Export To Aruba

177

567.1

10.58

1.51

12.46

39.4

51.1

Gas Capacity MMscfd

CAPEX US$MM

LNG Purchase Price $/MMBtu

CAPEX + OPEX Recovery $/MMBtu

Delivered Gas Price $/MMBtu

% Parity To #2 LSFO

% Parity To #6 LSFO

137 (30)

86.9

10.58

7.38

18.32

58.0

75.2

Bullen Bay Jetty Option Curacao Demand

137

86.9

10.58

2.98

13.92

44.1

57.1

Bullen Bay Buoy Option Curacao Demand

137

131.4

10.58

3.14

14.08

44.6

57.8

CASE DESCRIPTION Bullen Bay Site Aqualectra Demand Only

LNG FSRU Terminal Option

CASE DESCRIPTION Bullen Bay Jetty Option Aqualectra Demand Only

4-9 CURACAO CNG-LNG TERMINAL FEASIBILITY STUDY

Section 4 – Commercial Evaluation

Gas Import Pipeline Option

CAPEX US$MM

Gas Purchase Price $/MMBtu

CAPEX + OPEX Recovery $/MMBtu

Delivered Gas Price $/MMBtu

% Parity To #2 LSFO

% Parity To #6 LSFO

30

239.9

6.90

2.30

9.20

29.1

37.8

Colombia Curacao Demand

137

292.3

6.90

1.26

8.16

25.8

33.5

Colombia Curacao + Aruba Demand

177

328.2

6.90

0.85

7.75

24.5

31.8

Venezuela Aqualectra Demand Only

30

162.6

6.90

1.68

8.58

27.2

35.2

Venezuela Curacao Demand

137

192.8

6.90

0.92

7.82

24.7

32.1

Venezuela Curacao + Aruba Demand

177

241.3

6.90

0.66

7.56

23.9

31.0

Gas Capacity MMscfd

Colombia Aqualectra Demand Only

CASE DESCRIPTION

The average delivered gas costs for the case study results are illustrated graphically in Figure 4.5-3. Figure 4.5-3 Case Study Results

4 - 10 CURACAO CNG-LNG TERMINAL FEASIBILITY STUDY

Section 4 – Commercial Evaluation

Shaw Consultants note that the average delivered cost of gas was less than the average cost of No.6 LSFO for all the scenario cases. 4.6

DELIVERED GAS COST VS. GAS RATE

A series of cases were calculated to evaluate the relationship between delivered gas cost and gas rate. The two gas import pipeline options and the two LNG options were considered in the analysis. The results are illustrated in Figure 4.6-4. Figure 4.6-4 Delivered Gas Cost vs. Gas Rate

The delivered gas costs shown in the graph are the calculated costs averaged over the evaluation period from 2015 to 2031. As a comparison, the average forecast price of No.6 LSFO over the evaluation period is US$153/Bbl. Using a thermal conversion factor of 6.287 MMBtu/Bbl, the Btu equivalent price of No.6 LSFO is US$24.36/MMBtu which is shown as the black dashed line in the graph. 4.7

RISKS MATRIX ANALYSIS

A risk analysis was made for the gas supply options. This analysis was not “Quantitative” but rather “Qualitative” in nature reflecting the general judgments of Shaw Consultants. The risk matrix is shown in Figure 4.7-5.

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Section 4 – Commercial Evaluation

Figure 4.7-5 Risk Matrix Analysis CNG

Low

Overall Risk Rating CAPEX Costs OPEX Costs Technology Environmental and Permitting Gas Supply Facility Reliability Turndown Flexibility Project Schedule Operating Performance Geo-Political

GAS IMPORT PIPELINE - COLOMBIA Overall Risk Rating CAPEX Costs OPEX Costs Technology Environmental and Permitting Gas Supply Facility Reliability Turndown Flexibility Project Schedule Operating Performance Geo-Political

GAS IMPORT PIPELINE - VENEZUELA Overall Risk Rating CAPEX Costs OPEX Costs Technology Environmental and Permitting Gas Supply Facility Reliability Turndown Flexibility Project Schedule Operating Performance Geo-Political

ONSHORE LNG TERMINAL Overall Risk Rating CAPEX Costs OPEX Costs Technology Environmental and Permitting LNG Supply Facility Reliability Turndown Flexibility Project Schedule Operating Performance Geo-Political

LNG FSRU TERMINAL Overall Risk Rating CAPEX Costs OPEX Costs Technology Environmental and Permitting LNG Supply Facility Reliability Turndown Flexibility Project Schedule Operating Performance Geo-Political

RISK LEVEL ----------------> High X X X X X X X X X X X

Low

RISK LEVEL ----------------> High X X

X X X X X X X X X

Low

RISK LEVEL ----------------> High X X

X X X X X X X X X

Low

RISK LEVEL ----------------> High

X X X X X X X X X X X

Low

RISK LEVEL ----------------> High X X X

X X X X X X X X

4 - 12 CURACAO CNG-LNG TERMINAL FEASIBILITY STUDY

Section 4 – Commercial Evaluation

CNG Option As noted in the Risk Matrix, the CNG option is judged to have “High” overall risk. This judgment stems from the fact that this would be a “First Time” application of the technology and no CNG ships have ever been fabricated. As a result of the high risk rating, the CNG option has been dropped from further consideration. Gas Import Pipeline Options The Colombia and Venezuela gas import pipeline options are judged to have “Moderately Low” to “Moderate” overall risk. The Venezuela option has a slightly higher risk rating than the Columbia option due to assumed higher geo-political and project schedule risks. LNG Options The onshore LNG terminal and LNG FSRU options are judged to have “Low” to “Moderately Low” overall risk. The risk of the LNG FSRU option is rated slightly higher than the onshore LNG terminal option due to uncertainty of the FSRU rental day rates after the initial lease term expires. The FSRU option also has a higher risk ranking because of uncertainty in operating flexibility at low turndown rates. 4.8

CONCLUSIONS

Based on the commercial evaluations, Shaw Consultants has developed the following conclusions: 

The CNG option should be dropped from further consideration because of high technical and commercial risks.



The calculated average delivered gas cost for all options is lower than the average forecast price for No.6 LSFO. Therefore, conversion from No.6 LSFO to natural gas should reduce the fuel costs for electric power generation and the Isla Refinery process steam boilers.



The gas import pipeline options will provide the lowest delivered cost of gas. However, contracting for a long-term reliable gas supply will likely be challenging and may require a long-lead time to obtain a Memorandum Of Understanding (MOU) on a gas purchase contract.



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.

4 - 13 CURACAO CNG-LNG TERMINAL FEASIBILITY STUDY

Section 4 – Commercial Evaluation



If RDK’s 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.

4 - 14 CURACAO CNG-LNG TERMINAL FEASIBILITY STUDY

Section 5 –LNG Supply

5.1

INTRODUCTION

This section of this report provides an overview of the LNG industry and addresses the LNG supply issues for Curacao. These include the typical LNG quality specifications, principal LNG Sales and Purchase Agreement contract terms, potential LNG suppliers, the potential for partnering in LNG procurement with neighboring islands or the potential for the sale and export of regasified LNG to neighboring islands. 5.2

LNG INDUSTRY OVERVIEW

LNG is simply natural gas that has been chilled to approximately -161°C (-259°F) to its liquid state via a special refrigeration process. In order to liquefy natural gas, it must first be produced from a field and then piped to a LNG Liquefaction Plant. The gas goes through a liquefaction process that, in addition to chilling the gas, removes the small quantities of nitrogen, oxygen, carbon dioxide, sulfur compounds, and water that are typically found in "pipeline" natural gas. The LNG delivery value chain is comprised of three principle segments including a Liquefaction Plant, LNG Ships and LNG Regas Terminal. The LNG delivery value chain is illustrated in Figure 5.2-1. Figure 5.2-1 LNG Delivery Value Chain

In the liquefaction process, the natural gas is chilled by large refrigeration systems to a temperature where the natural gas remains in the liquid state at atmospheric pressure. This liquid is called LNG. After liquefaction, the LNG occupies only 1/600th of the original natural gas volume making it compact and easier to transport in large LNG ships. LNG is stored as a "boiling cryogen liquid," a very cold liquid at its boiling point at storage tank pressure which is slightly above atmospheric pressure. Because LNG

5-1 CURACAO CNG-LNG TERMINAL FEASIBILITY STUDY

Section 5 –LNG Supply

must be kept very cold in order to remain a liquid, LNG storage requires heavily insulated tanks at the Liquefaction Plant, in the LNG Ships and at the LNG Regas Terminal. A typical LNG ship transport capacity ranges from 125,000m3 to 150,000m3 of LNG, the equivalent of approximately 60 to 70 Olympic size swimming pools. There are both larger and smaller capacity ships in the LNG fleet, but approximately 63% of the ships are in the capacity range mentioned above. LNG that evaporates during the journey is used by the LNG ship to fuel its engines. At the receiving terminals, the LNG is unloaded from the LNG ship, stored, and the regasified for sendout by gas pipeline to meet the gas customers’ daily demands. Based on data published by Drewry Maritime Research in 2011, the range of sendout gas prices worldwide ranged from an average low of US$3.21/MMBtu to an average high of US$7.24/MMBtu. The regasification fees charged at the LNG Regas Terminals ranged from US$0.50 to US$1.00/MMBtu. Cost of shipping LNG is dependent upon the transport distance between the Liquefaction Plant and the LNG Regas Terminal. Drewry reported for 2011 that LNG shipping costs ranged between US$0.21 to US$1.64/MMBtu. The fees charged for liquefying the natural gas at the Liquefaction Plants ranged from US$1.75 to US$2.55/MMBtu. Taking into consideration all of the costs and fees in the LNG value chain, the gas producers behind the Liquefaction Plants realized wellhead netbacks prices ranging between US$0.75 to US$2.05/MMBtu. LNG Historical Track Record LNG has had a long track record of successful and safe operations. Natural gas liquefaction dates back to the 19th century when British chemist and physicist Michael Faraday experimented with liquefying different types of gases, including natural gas. German engineer Karl Von Linde built the first practical compressor refrigeration machine in Munich in 1873. The first LNG plant was built in West Virginia in 1912 and began operation in 1917. Since that early beginning, the LNG industry has experienced solid growth and expansion. LNG technology has a proven track record in liquefaction, shipping and regasification applications worldwide. Several liquefaction processes have been developed and patented. Among them, two of the most prevalent are the Air Products & Chemicals Inc. (“APCI”) Propane Pre-Cooled MCR process and the ConocoPhillips Cascade process. Although the APCI liquefaction process technology has been selected for the vast majority of LNG liquefaction plants, several recent plants to come on stream, used the optimized ConocoPhillips Cascade process. There are currently 31 liquefaction plants in operation worldwide and 10 liquefaction plants under construction. Another 15 liquefaction projects are in the planning stage. The number of ships in the LNG fleet has also experienced significant growth over the years. At the end of 2011, there were 352 LNG ships in service – 9% with capacity ranging between 18,000 to 125,000 m3, 63% ranging between 125,000 to 150,000 m3, and 28% ranging between 150,000 to 250,000+ m3. The number of LNG regas terminals around the world has exhibited significant growth over the years as well. There are currently 85 LNG regas terminals in operation worldwide and 21 terminals under construction. Another 28 terminals are in the planning stage. The price of natural gas in the U.S. market has been on a roller coaster ride from 2000 to 2011. In 2002, domestically produced natural gas in the U.S. was declining and a gas shortage was looming on the horizon. U.S. gas prices at Henry Hub strengthened to a level attracting LNG imports back to the U.S. market. A flurry of applications for new LNG import terminals were submitted to F.E.R.C. and several

5-2 CURACAO CNG-LNG TERMINAL FEASIBILITY STUDY

Section 5 –LNG Supply

new LNG terminals were constructed including Sabine Pass Terminal, Golden Pass Terminal, Cameron LNG Terminal, Gulf Gateway GasPort, Gulf LNG Terminal, Neptune Deepwater LNG Port, Northeast Gateway GasPort, and Freeport LNG Terminal. A major recent trend impacting Atlantic Basin LNG trade has been shale gas development in the U.S. New drilling and completion technology for developing shale gas has been a “game changer”. A flurry of shale gas development projects starting in mid-2008 to 2011 dramatically increased U.S. natural gas production capacity driving gas prices below the threshold required to attract LNG imports into the U.S. (see Figure 5.2-2). Today, several of the U.S. LNG import terminals have filed applications to produce and export LNG. Sabine Pass and Freeport are now in FEED for liquefaction facilities to be installed at their respective terminals which were originally permitted for importing LNG. Figure 5.2-2 Recent Global Natural Gas Price History

SHALE GAS DEVELOPMENT CREATES EXCESS GAS SUPPLY IN U.S.

The downward pressure on Henry Hub gas prices will likely impact the Atlantic Basin LNG trade. As LNG supplies come into the market place from new liquefaction facilities located in the U.S. Gulf Coast, Shaw Consultants would anticipate slight downward pressure on LNG prices in the Atlantic Basin. If this occurs, it will have favorable impact on the potential LNG import project being considered for Curacao. In summary, LNG has a proven track record in liquefaction, shipping, and regasification projects worldwide. LNG technologies are well established. LNG trade today currently accounts for over 31% of the total international gas market. At the end of 2011, LNG global statics were published by Drewry Maritime Research:   

LNG Liquefaction Capacity Regas Terminal Capacity LNG Fleet

277.4 mtpa 514.0 mtpa 352 ships

5-3 CURACAO CNG-LNG TERMINAL FEASIBILITY STUDY

Section 5 –LNG Supply

Historical charts for LNG Exports and LNG Imports volumes illustrating a breakdown by country are shown in Figure 5.2-3 and Figure 5.3-4, respectively. Figure 5.2-3 Global LNG Export (Billion m3/Yr)

Figure 5.3-4 Global LNG Import (Billion m3/Yr)

5.3

LNG QUALITY SPECIFICATION

Recently executed LNG Sale and Purchase Agreements (“SPA”) for LNG off-take have included the following general specification for the LNG to be regasified or vaporized into the gaseous phase by the Buyer: Minimum Gross Heat Content (dry) Maximum Gross Heat Content (dry) Minimum methane (C1)

1,000 Btu/scf 1,150 Btu/scf 84.0 Mol%

5-4 CURACAO CNG-LNG TERMINAL FEASIBILITY STUDY

Section 5 –LNG Supply

Maximum H2S Maximum Sulfur Maximum N2 Maximum Ethane (C2) Maximum Propane (C3) Maximum Butane (C4) and heavier

0.25 grains per 100 SCF 1.35 grains per 100 SCF 1.5 Mol% 11 Mol% 3.5 Mol% 2.0 Mol%

LNG shall contain no water, active bacteria or bacterial agents (including sulfate-reducing bacteria or acid producing bacteria) or other contaminants or extraneous material. SCF means standard cubic foot of natural gas obtained by vaporizing the LNG, with such natural gas under the standard conditions of sixty degrees Fahrenheit (60°F) and at a pressure of fourteen decimal six nine six pounds per square inch absolute (14.696 psia). 5.4

TYPICAL LNG SUPPLY CONTRACT TERMS

Typical LNG Sale and Purchase Agreements generally contain the following principal terms and provisions: Approvals and Conditions Precedent Buyer shall obtain all governmental and regulatory Approvals and Permits required to engineer, procure, construct, and operate the LNG Receiving and Regasification Facilities (the “Facilities”) and any other required facilities necessary for the full and complete operation of the Facilities and for the performance of this Agreement. Buyer has secured the necessary financing arrangements to construct and operate the Facilities and any other additional facilities required for the performance of this Agreement. Buyer has taken a positive Final Investment Decision (“FID”) to construct the Facilities and any other required facilities, and the Buyer has issued an unconditional Notice To Proceed (“NTP”) to the EPC Contractor(s) to commence with the execution of such EPC Contracts to design and construct all such facilities. Note: the Conditions Precedent typically also contain a CP Deadline date, such the LNG Seller may terminate this Agreement if all Conditions Precedent have not been satisfied (typically no more than one year after the scheduled CP completion date. Term Until very recently, most LNG SPAs were negotiated with a Term of twenty (20) years following the Date of the First Commercial Delivery, which will follow the official Commercial Operation Date (“COD”), when all Project Finance Completion requirements, including Performance Testing, etc. has been concluded, taking into account development and construction schedules. However, more recently LNG suppliers have been increasingly reluctant to execute LNG SPAs with Terms lasting longer than ten (10) years, but with provisions included for extension of the Term. Note: project finance Lenders will likely insist on a Term at least as long as the loan term, typically ten (10) years. Contract Years correspond to calendar years. Shaw Consultants would anticipate that the duration of the EPC Contract schedule to design and construct the Regas Terminal and other additional facilities from NTP to the Commercial Operation Date would be approximately forty-two (42) months. Thus, the First Window Period for the Date of the First Commercial Delivery would commence approximately forty-two (42) months after NTP and extend for

5-5 CURACAO CNG-LNG TERMINAL FEASIBILITY STUDY

Section 5 –LNG Supply

180 days. Successive Window Periods would gradually decrease the widow periods to ninety days, sixty days, thirty days, and then the specific delivery date. LNG to be used for commissioning and testing shall be subject to analogous window periods for its delivery date. The LNG tanker delivering commissioning LNG shall be in the cargo size range of 120,000 to 150,000 cubic meters (m3). Annual Contract Quantity (“ACQ”) The ACQ for any Contract Year shall be approximately [45,000,000] MMBtu/year, which is approximately equivalent to [120.3] MMscfd of exported natural gas from the Regas Terminal. The Adjusted Annual Contract Quantity will be the ACQ plus any Round-Up Quantity in the current Contract Year and any Round-Down Quantity carried forward from the previous Contract Year, as necessary to receive full-cargo lots of LNG less scheduled Major Maintenance Quantities for the Contract Year. It would be advantageous for RDK to utilize a “Flexible” LNG SPA that would allow RDK to reduce the ACQ by the 325,000 tonnes per annum amount to be supplied to CRUC, in the event that PDVSA ends its CRUC Lease Agreement and the refinery shuts down. Thereafter, the LNG SPA should allow RDK to increase or decrease the ACQ unilaterally by at least ten percent per annum, and by more if by mutual consent. Annual Delivery Program At least one hundred twenty (120) days before the start of each Contract Year, Buyer will notify the Seller in writing (i) the LNG quantity in MMBtu that the buyer expects to receive for the coming year (ii) and any scheduled maintenance periods for the Regas terminal. Within thirty (30) days of the receipt of this information Seller shall propose to Buyer the Annual Delivery Program (“ADP”). The ADP will specify the (a) number of LNG cargoes required to deliver the LNG quantity specified in (i), (b) the proposed delivery windows for each cargo, (c) the name of the LNG Tanker to be utilized for each cargo (the “Scheduled LNG Tankers”), the tanker cargo size, and the proposed Loading Port for each Scheduled LNG Tanker. The SPA will also include terms under which the ADP may be amended. No later than the twenty-fifth (25th) day of each Month, the seller shall issue a forward plan for deliveries for the next three-month period of deliveries (the “Ninety Day Schedule”), which shall follow the ADP with the same but updated LNG cargo information provided under the ADP. Contract Sales Price The LNG purchase price shall be comprised of the total the Contract Sales Price (“CSP”) for the natural gas feedstock energy cost, the Unit Capacity Charge (“UCC”) imposed by the Seller, and the LNG Shipping Charge (“SC”), as follows: Contract Sales Price = [Henry Hub x 1.15] Where Henry Hub is the final settlement price in USD per MMBtu for the New York Mercantile Exchange’s Henry Hub natural gas futures contract for the Month in which the relevant cargo’s Delivery Window is scheduled to begin. UCC = [0.85 x BASE + 0.15 x BASE x CPIy/CPI0]

BASE = the base Seller Capacity Charge (typically) ranging from [US$2.50 to US$5.00] CPIy = The simple average of the US Department of Labor Bureau of Labor Statistics CPI (All Urban Consumers, U.S., All Items, 1982 – 1984, Not Seasonally

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Section 5 –LNG Supply

Adjusted, Series I.D. CUUR0000SA0) for the twelve (12) Months immediately preceding the beginning of the relevant Contract Year; and CPI0 = The simple average of the US Department of Labor Bureau of Labor Statistics CPI (All Urban Consumers, U.S., All Items, 1982 – 1984, Not Seasonally Adjusted, Series I.D. CUUR0000SA0) for the twelve (12) Months immediately preceding the Month during which the Date of First Commercial Delivery occurs. SC = Depends on Seller and Loading Port (typically) ranging between [US$0.50 to US$1.50] per MMBtu. Total LNG Price = CSP + UCC + SC Invoices Seller shall issue to Buyer by the tenth (10th) day of the Month an Invoice for LNG delivered and received by Seller in the immediately preceding Month. In the event that any of the relevant pricing information is unavailable in final form to calculate an accurate Total LNG Price, Seller may issue a provisional Invoice (“Provisional Invoice”) best estimate of the unavailable information. A Provisional Invoice shall be due and payable as a regular Invoice, subject to subsequent adjustment as soon as reasonable practicable after the Seller receives the unavailable information required to issue an accurate Invoice. Seller and Buyer shall settle or reconcile such debit or credit amounts as soon as reasonable practicable in subsequent Invoices. Invoices issued shall be due and payable by the Buyer by the twentieth (20th) day of the Month in which the Invoice was issued. Transportation and Unloading (a)

Buyer shall make available, or cause to be made available, port facilities at the Regasification Terminal capable of safely receiving LNG Tankers for the discharging of LNG purchased hereunder. Port facilities shall be constructed such as to permit all maneuvers to be carried out in accordance with Maritime Best Practices and applicable law within a reasonable time.

(b)

Buyer shall receive LNG at a safe berth which Buyer shall provide or cause to be provided free of charge at the Regasification Terminal which the LNG Tankers can safely reach and leave and at which they can lie and unload always safely afloat and safely moored alongside.

(c)

Any expense of the LNG Tankers shifting away from the Regasification Terminal berth at Buyer’s direction shall be for Buyer’s account except for shifting required in order to comply with port rules and/or for safety reasons and only to the extent that the need for such shifting did not arise as a result of (i) the act or omission of Seller or its agents or contractors (including, for the avoidance of doubt, the failure of the LNG Tanker’s Master to issue a Notice of Readiness on or prior to the Scheduled Unloading Date) or (ii) any modification of a Scheduled LNG Tanker and/or the Regasification Terminal.

(d)

Buyer shall make available or cause to be made available to Seller at no cost to Seller at the Unloading Port in which the Regasification Terminal is situated berthing and discharging facilities (Unloading Port Facilities) which are compatible with the equipment on the LNG Tankers used by Seller including: (i)

mooring equipment;

(ii) lighting sufficient to permit customary docking and undocking maneuvers by day or by night;

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(iii) unloading arms, pipes and other appropriate facilities permitting the discharging of LNG at an average rate of twelve thousand (12,000) cubic meters per hour against a head of one hundred twenty-five (125) meters of LNG at the Delivery Point, provided that the maximum operating pressure of the such facilities shall be 19 bar; (iv) vapor delivery and return facilities (including pipelines and compressors) adequate to maintain appropriate operating pressure in the tanks of the LNG Tanker during full rate cargo transfer between one thousand eighty (1,080) and one thousand two hundred (1,200) millibars absolute; (v) safe access for personnel between the LNG Tanker and the jetty of the Regasification Terminal; (vi) terminal operating personnel capable of writing, understanding and speaking fluently the English language; (vii) line handling boats, if necessary, and mooring personnel capable of understanding and speaking fluently the English language; (viii) an appropriate security system to protect the LNG Tanker at berth, which is compliant with ISPS Code and certified by the relevant Competent Authority; and (ix) emergency shut-down systems that can be linked to and are compatible with LNG Tankers. (e)

The facilities described in paragraphs (d)(i) to (iv), (viii) and (ix) above shall be provided, operated and maintained in good working condition at no cost to Seller and shall not be modified in a manner so as to be incompatible with any Scheduled LNG Tanker.

Unloading Port Obligations (a)

LNG Tankers shall utilize the Unloading Port Facilities subject to observance of all relevant port and terminal regulations and procedures. Any tugs, pilots or escort vessels required (or other support vessels and personnel required in connection with the safe berthing of an LNG Tanker) shall be employed by Seller, with Seller being responsible for all variable costs related to its usage and the lesser of (i) all fixed costs related to its usage and (ii) a portion of the fixed costs proportionate to the quantity of all deliveries of LNG by Seller to Buyer under this Contract at the Delivery Point as a percentage of the Initial Maximum ACQ. The specifications reasonably required for all such vessels shall be notified by Seller to Buyer in writing by the date that is no later than twelve (12) Months after the Effective Date.

(b)

Seller shall be responsible for payment of amounts due for supplies and services requested by Masters of LNG Tankers, for port charges and for any other charges incurred during the safe transportation of LNG from the Unloading Port Facilities to the Delivery Point.

(c)

Seller shall obtain or cause to be obtained all Approvals required for each LNG Tanker to enter and travel in the territorial waters of the Republic of Curacao, to berth and unload its cargo and to depart from the Regasification Terminal and Unloading Port and leave the territorial waters of the Republic of Curacao. Each LNG Tanker shall comply with all laws, rules, regulations, authority instructions and interpretations to which it is subject in the Republic of Curacao, including those for the protection of the environment. If requested to do so by Seller, Buyer shall use reasonable efforts to assist Seller in complying with this paragraph (c).

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(d)

Buyer shall provide reasonable assistance to Seller, at Seller’s expense, in coordinating delivery of equipment, supplies and services for the LNG Tankers.

(e)

The Unloading Port Facilities shall conform to the specifications and standards set out in Clause 6.3. Unloading of LNG at the Regasification Terminal shall be carried out in accordance with all safety rules, regulations and procedures of the Regasification Terminal and the LNG Tankers, as the same may be amended from time to time, and with all applicable safety laws, rules, authority instructions and regulations (collectively, Maritime Best Practices).

(f)

Seller shall have the right at any reasonable time during the period of this Contract, at Seller’s risk, time and expense, to inspect the Regasification Terminal. After reasonable notification, and in any case not less than three (3) Business Days, has been given to Buyer by Seller of such intention to inspect the Regasification Terminal, Buyer shall afford Seller all reasonable cooperation and accommodation. Such inspection shall be made without undue interference with, delay to or hindrance to the Regasification Terminal’s safe and efficient operation. Neither the exercise nor the non-exercise, or anything done or not done by Seller in the exercise or nonexercise of such right shall in any way reduce Buyer’s authority over or responsibility for the Regasification Terminal nor increase Seller’s responsibility to Buyer or any third parties for the same; provided that Seller complies with all of Buyer’s and the Regasification Terminal Company’s safety rules and regulations during such inspection. Following Seller’s inspection of the Regasification Terminal, and in the event the Regasification Terminal (whether in whole or in part) does not meet the criteria in this Clause, Seller may so notify Buyer in writing and Buyer shall as soon as practicable procure the remedy of the defect so notified.

(g)

Buyer shall ensure that any terminal operator complies with the ship-shore interface and safety specifications stated herein (or any applicable future ship-shore interface and safety specification/s) throughout the term of this Contract.

(h)

Seller shall cause the owner of any Scheduled LNG Tanker to comply with the ship-shore interface and safety specifications stated herein (or any applicable future ship-shore interface and safety specification/s) and any applicable conditions of use for the Unloading Port throughout the term of this Contract.

Notifications of ETA (a)

Promptly after departing from the Loading Port, the Scheduled LNG Tanker’s Master shall give Buyer notice by facsimile, e-mail or other mutually agreed form of communication of the date and hour on which such Scheduled LNG Tanker departed from the Loading Port and the estimated time of arrival at the Unloading Port (the Estimated Time of Arrival or ETA). If thereafter the ETA changes by more than twenty-four (24) hours, the Scheduled LNG Tanker Master shall give notice of the corrected ETA promptly to Buyer. The Scheduled LNG Tanker’s Master shall include in such notice a statement of any operational deficiencies in the Scheduled LNG Tanker that may affect its performance in the Unloading Port or at berth.

(c)

Nine (9) Days prior to the Scheduled LNG Tanker’s arrival at the Unloading Port and each Day thereafter until ninety-six (96) hours prior to the Scheduled LNG Tanker’s arrival at the Unloading Port, the Scheduled LNG Tanker’s Master shall give notice by facsimile, e-mail or other mutually agreed form of communication to Buyer stating its then ETA.

(d)

Ninety-six (96) hours prior to the Scheduled LNG Tanker’s arrival at the Unloading Port, the Scheduled LNG Tanker’s Master shall give notice by facsimile, e-mail or other mutually agreed

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form of communication to Buyer stating its then ETA. If thereafter this ETA changes by more than nine (9) hours, the Scheduled LNG Tanker’s Master shall give notice of the corrected ETA promptly to Buyer. (e)

Forty-eight (48) hours prior to the Scheduled LNG Tanker’s arrival at the Unloading Port, the Scheduled LNG Tanker’s Master shall give notice by facsimile, e-mail or other mutually agreed form of communication to Buyer confirming or amending the previous ETA notice. If thereafter this ETA changes by more than six (6) hours, the Scheduled LNG Tanker’s Master shall give notice of the corrected ETA promptly to Buyer.

(f)

Twenty-four (24) hours prior to the Scheduled LNG Tanker’s arrival at the Unloading Port, the Scheduled LNG Tanker’s Master shall give notice by facsimile, e-mail or other mutually agreed form of communication and radio to Buyer confirming or amending the last ETA notice. If thereafter this ETA changes by more than three (3) hours, the Scheduled LNG Tanker’s Master shall give notice of the corrected ETA promptly to Buyer in the same manner.

(g)

The Scheduled LNG Tanker’s Master shall give a final ETA notice to Buyer by facsimile, email or other mutually agreed form of communication and radio six (6) hours prior to the Scheduled LNG Tanker’s arrival at the Unloading Port.

(h)

The Scheduled LNG Tanker’s Master shall give notice of its arrival to Seller by facsimile, email or other mutually agreed form of communication and radio immediately upon the Scheduled LNG Tanker’s arrival at the PBS at the Unloading Port.

Notice of Readiness (“NOR”) (a)

As soon as the Scheduled LNG Tanker has arrived at the PBS or an agreed location off the Unloading Port and is ready to unload LNG and follow Buyer’s instructions in accordance with the provisions hereof, the Scheduled LNG Tanker’s Master shall so notify Buyer (with such other information as Buyer may reasonably request) via facsimile, e-mail or other mutually agreed form of communication (such notification constitutes a Notice of Readiness).

(b)

Notice of Readiness shall not be effective, and the Scheduled LNG Tanker shall not proceed to berth, (1) prior to the start of the Delivery Window without Buyer’s prior written agreement or (2) if another LNG Tanker delivering cargoes under this Contract is proceeding to or occupying the Regasification Terminal berth and has not exceeded its applicable Allotted Unloading Time. If the Scheduled LNG Tanker arrives at the Unloading Port prior to the start of the Delivery Window and tenders Notice of Readiness prior to the start of the Delivery Window and Buyer agrees to permit such Scheduled LNG Tanker to berth at such time in accordance with the previous sentence, Notice of Readiness shall be deemed effective at the earlier of (i) the commencement of the start of the Delivery Window and (ii) the time the LNG Tanker is “all fast” at the Regasification Terminal berth. In all other cases a Notice of Readiness shall be deemed effective at the later of (A) the time at which the Notice of Readiness is given and (B) the commencement of the start of the Delivery Window.

(c)

In the event of a failure to issue the Notice of Readiness by the end of the Delivery Window, Buyer shall advise Seller of Buyer’s reasonable estimate of its ability, from both a timing and physical perspective, to berth and unload the Scheduled LNG Tanker without materially adversely affecting any other scheduled deliveries at the Regasification Terminal or any deliveries of natural gas to Gas Buyers. Bearing this estimate in mind, the Scheduled LNG Tanker’s Master may tender a Notice of Readiness to Buyer. If such Notice of Readiness is

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tendered it shall be deemed effective upon the later of (i) the time at which such Notice of Readiness is issued and (ii) Buyer’s notice to the Scheduled LNG Tanker that Buyer is ready to receive the Scheduled LNG Tanker at the Regasification Terminal berth, provided the Scheduled LNG Tanker is then ready to follow Buyer’s instructions in accordance with the provisions hereof. Buyer shall use reasonable efforts to receive and unload the Scheduled LNG Tanker; provided that Seller shall reimburse Buyer for all reasonable additional costs incurred by Buyer in receiving and unloading such Scheduled LNG Tanker that are attributable to the Scheduled LNG Tanker’s having failed to provide a Notice of Readiness on or prior to the end of the Delivery Window scheduled for such Scheduled LNG Tanker. (d)

For the avoidance of doubt, Buyer has no obligation to take any cargo for which Notice of Readiness is provided after the end of the relevant Delivery Window as provided in the relevant 90 Day Schedule.

Allotted Berth Time, Allowed Bert Time & Unloading Time The allotted berth time for each LNG Tanker (“Allotted Berth Time”) shall be (i) for an LNG Tanker with an LNG cargo containment capacity of one hundred forty thousand (140,000) Cubic Meters or less, thirty-six (36) hours and (ii) for an LNG Tanker with an LNG cargo containment capacity of greater than one hundred forty thousand (140,000) Cubic Meters, according to the following formula: 36 + x = Allotted Berth Time (in hours) Where: x = y/12,000 Cubic Meters; and y = the LNG cargo containment capacity of the LNG Tanker in excess of one hundred forty thousand (140,000) Cubic Meters) Allotted Berth Time shall be extended by any period of delay that is caused by: 1. Reasons attributable to Buyer, a Governmental Authority, Transporter, the LNG Tanker or its master, crew, owner or operator or any Third Party outside of the reasonable control of Seller (but excluding the operator of the Sabine Pass Facility, Sabine Pass Tug Services, LLC and any other Affiliate of Seller); 2. Force Majeure; 3. Unscheduled curtailment or temporary discontinuation of operations at the Sabine Pass Facility necessary for reasons of safety, except to the extent such unscheduled curtailment or temporary discontinuation of operations is due to Seller’s or Seller’s Affiliate’s failure to operate and maintain its facilities as a Reasonable and Prudent Operator; 4. Time at berth during cool-down; and 5. Nighttime transit restrictions. The actual berth time for each LNG Tanker (“Actual Berth Time”) shall commence when the NOR is effective and shall end when the LNG transfer and return lines of the LNG Tanker are disconnected from the Sabine Pass Facility’s LNG transfer and return lines and the LNG Tanker is cleared for departure and able to depart.

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In the event Actual Berth Time exceeds Allotted Berth Time (including any extension in accordance with Section 0) (“Demurrage Event”), Seller shall pay to Buyer, as liquidated damages, demurrage in USD (which shall be prorated for a portion of a Day) calculated pursuant to the following formula: Daily Demurrage Rate = USD 64,000 + (USD 16,000 x (CPIM /CPI0)) Where: CPIM: the monthly Consumer Price Index for All Urban Consumers, U.S. city average for all items, not seasonally adjusted (base period: 1982-1984 = 100), as published by the Bureau of Labor Statistics for the U.S. Department of Labor for the third (3rd) Month prior to the Month in which the Delivery Window occurs; and CPI0: the CPI applicable to the Month and year in which the Date of First Commercial Delivery occurs. An LNG Tanker shall complete LNG transfer and vacate the berth as soon as possible but not later than the following allowed berth time: 1. Twenty-four (24) hours from the time the LNG Tanker is all fast at the berth, in the case of an LNG Tanker with an LNG cargo containment capacity less than or equal to one hundred forty thousand (140,000) Cubic Meters; or 2. In accordance with the following formula, in the case of an LNG Tanker with an LNG cargo containment capacity greater than one hundred forty thousand (140,000) Cubic Meters: 24 + x =

allowed berth time (in hours)

Where: x =

y/12,000 Cubic Meters; and

y = the LNG cargo containment capacity of the LNG Tanker in excess of one hundred forty thousand (140,000) Cubic Meters. Provided that the Sabine Pass Facility supplies a suitable vapor return line meeting the requirements set forth herein, then: 1. An LNG Tanker with an LNG cargo containment capacity less than or equal to one hundred forty thousand (140,000) Cubic Meters shall be capable of loading a full cargo of LNG in a maximum of fifteen (15) hours; and 2. An LNG Tanker with an LNG cargo containment capacity greater than one hundred forty thousand (140,000) Cubic Meters shall be capable of loading a full cargo of LNG in the number of hours derived after applying the following formula: 15 + x = maximum LNG UnloadingTime (in hours) Where: x = y/12,000 Cubic Meters; and y = the LNG cargo containment capacity of the LNG Tanker in excess of one hundred forty thousand (140,000) Cubic Meters.

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Time for connecting, cooling, draining, purging and disconnecting of liquid arms shall not be included in the computation of pumping time. Each LNG Tanker shall procure and maintain Hull and Machinery Insurance and P&I Insurance. Measurements, Tests, and Analysis Typical measurement, testing and analytical procedures are voluminous but can be supplied, if requested, separately from this Report. Force Majeure Neither Party shall be liable to the other Party for any delay or failure in performance under this Agreement if and to the extent such delay or failure is a result of Force Majeure. To the extent that the Party so affected fails to use commercially reasonable efforts to overcome or mitigate the effects of an event of Force Majeure, it shall not be excused for any delay or failure in performance that would have been avoided by using such commercially reasonable efforts. Subject to the provisions of this Section, the term “Force Majeure” shall mean any act, event or circumstance, whether of the kind described herein or otherwise, that is not reasonably within the control of, does not result from the fault or negligence of, and would not have been avoided or overcome by the exercise of reasonable diligence by, the Party claiming Force Majeure or an Affiliate of the Party claiming Force Majeure, such Party and, as applicable, its Affiliate having observed a standard of conduct that is consistent with a Reasonable and Prudent Operator, and that prevents or delays in whole or in part such Party’s performance of one or more of its obligations under this Agreement. Force Majeure may include circumstances of the following kind, provided that such circumstances satisfy the definition of Force Majeure set forth above: 1. Acts of God, the government, or a public enemy; strikes, lockout, or other industrial disturbances; 2. Wars, blockades or civil disturbances of any kind; epidemics, Adverse Weather Conditions, fires, explosions, arrests and restraints of governments or people; 3. The breakdown or failure of, freezing of, breakage or accident to, or the necessity for making repairs or alterations to any facilities or equipment; 4. In respect of Seller: (i) loss of, accidental damage to, or inaccessibility to or inoperability of the terminal facility or any connecting pipeline or the liquefaction and loading facilities at the alternate source agreed by the Parties, but only with respect to those cargoes that Buyer has agreed may be supplied from such alternate source; and (ii) any event that would constitute an event of force majeure under any of the Common Facilities Agreements, provided, however, that an event of force majeure under any of the Common Facilities Agreements affecting Seller or an Affiliate of Seller shall constitute Force Majeure under this Agreement only to the extent such event meets the definition of Force Majeure in this Section; and 5. In respect of Buyer: (i) loss of, accidental damage to, or inoperability of any LNG Tanker; (ii) events affecting the ability of LNG Tankers to reach the Regasification Terminal or any alternate source agreed by the Parties not arising from loss of, accidental damage to or inoperability of such LNG Tanker; (iii) loss of, accidental damage to, or inaccessibility to or inoperability of a Discharge Terminal; or (iv) the unavailability of services provided by the Tugboat Services Supplier or the failure of the Tugboat Services Supplier to provide such tug, fireboat and/or escort vessel services.

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5.5

POTENTIAL LNG SUPPLIERS

LNG World Trade LNG world trade is divided into basically two LNG marketing regions – the Atlantic Basin and the AsiaPacific Basin (see Figure 5.5-5). Figure 5.5-5 LNG Market Regions

ASIA-PACIFIC BASIN

ATLANTIC BASIN

With regard to the world LNG supply/demand balance, the combination of increased new LNG supplies becoming available, the current economic slow-down, and increased unconventional natural gas production in the U.S. from shale gas and coal seam gas will introduce new dynamics into Global LNG markets for the time period spanning beyond 2012. The Atlantic Basin provides a great deal of flexibility with access to natural gas hubs in the world’s two largest natural gas markets (Europe and the U.S.). Spare import terminal capacity is available offering ample market entrance for LNG. Europe’s gas import requirements are likely to increase which in turn will result in greater demand for LNG in this market region. Europe is particularly in need of LNG during winter and will have to compete with the Asia-Pacific market to attract the required quantities. The U.S. will have ample domestic production from its conventional and unconventional sources to serve its domestic demand and will have additional significant quantities of gas available for export as LNG. The traded natural gas hubs in the U.S. (Henry Hub) and Europe (UK NBP) will offer swift market response and price will determine the balancing point for LNG export/import volumes within the Atlantic Basin. The Asia-Pacific Basin is still dominated by long-term contracts based on prices linked to oil. Surging LNG demand in the Asian-Pacific region has shocked global market dynamics, sending Asian-Pacific prices soaring and driving global price spreads. Increased gas consumption in the wake of Japan’s nuclear disaster has increased demand from the world’s largest, most mature LNG market, while a wave of

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demand from emerging and new markets including China, India and Thailand is being accelerated by economic growth. The result is unprecedented cargo diversions and re-exports, the results of which are being felt worldwide. New Australian LNG liquefaction projects will have a competing role with existing Middle East LNG sources in serving the Asia-Pacific markets in the future. Currently, the Asia-Pacific supply/demand balance is somewhat volatile due to the surge in LNG shipments to Japan. Longer term, it is anticipated that some LNG producers will take advantage of the liquidity of the Atlantic Basin markets as the AsianPacific markets stabilize. A list of the LNG liquefaction plants are shown in Table 5.5-1. Table 5.5-1 LNG Liquefaction Plants ON-STREAM

UNDER CONSTRUCTION

PLANNED

Adgas LNG Plant (UAE)

Angola LNG Plant (Angola)

Abadi LNG Plant (Indonesia)

Algeria LNG Plants (Algeria)

Gladstone LNG Plant (Australia)

Arrow LNG Plant (Australia)

Arun LNG Plant (Indonesia)

Gorgon LNG Plant (Australia)

Australia Pacific LNG Plant (Australia)

Atlantic LNG Plant (Trinidad & Tobago)

Pluto LNG Plant (Australia)

Baltic LNG Plant (Russia)

Bontang LNG Plants (Indonesia)

PNG LNG Plant (Papua New Guinea)

Brass LNG Plant (Nigeria)

Brunei LNG Plant (Brunei)

Queensland Curtis LNG Plant (Australia)

Browse LNG Plant (Australia)

Damietta LNG Plant (Egypt)

Wheatstone LNG (Australia)

Cameron Liquefaction Plant (USA)

Darwin LNG Plant (Australia)

Cove Point Liquefaction Plant (USA)

EG LNG Plant (Equatorial Guinea)

Donggi-Senoro LNG Plant (Indonesia)

Egyptian LNG Plant (Egypt)

Fisherman’s Landing LNG (Australia)

Kenai LNG Plant (Alaska, USA)

Freeport Liquefaction Plant (USA)

Marsa El Brega LNG Plant (Libya)

Gulf LNG Plant (Papua New Guinea)

MLNG Satu Plant (Malaysia)

Gulf LNG Liquefaction Plant (USA)

MLNG Dua Plant (Malaysia)

Ichthys LNG Plant (Australia)

MLNG Tiga Plant (Malaysia)

Jordan Cove Liquefaction Plant (USA)

Nigeria LNG Plant (Nigeria)

Kitimat LNG Plant (Canada)

Nordic (Skangass) LNG Plant (Norway)

Lake Charles Liquefaction Plant (USA)

North West Shelf LNG Plant (Australia)

Olokola LNG Plant (Nigeria)

Oman & Qalhat LNG Plant (Oman)

Prelude LNG Plant (Australia)

Peru LNG Plant (Peru)

Sabine Pass Liquefaction Plant (USA)

Qatargas I LNG Plant (Qatar)

Scarborough LNG Plant (Australia)

Qatargas II LNG Plant (Qatar)

Shtokman LNG Plant (Russia)

Qatargas III & IV LNG Plant (Qatar)

Sunrise LNG Plant (Australia)

RasGas I LNG Plant (Qatar) RasGas II LNG Plant (Qatar) RasGas III LNG Plant (Qatar) Sakhalin LNG Plant (Sakhalin, Russia) Snohvit LNG Plant (Norway) Tangguh LNG Plant (Indonesia) Yemen LNG Plant (Yemen)

Integrated LNG projects designed with the physical and commercial flexibility to serve volatile market conditions will likely do well as the “spot” LNG market develops. LNG world trade will also likely become more complex when LNG shipments through the Panama Canal ensue after the canal expansion project is completed. Currently, the Asia-Pacific market offers a premium price for LNG. As Atlantic

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Basin LNG producers gain better access to the premium Asian-Pacific markets, the equilibrium balancing price for these two market regions may tend to converge. LNG Supply for Curacao Curacao is in the Atlantic Basin marketing region. LNG supply and pricing for Curacao will be driven by conditions and LNG market forces prevalent in the Atlantic Basin. The most desirable source for LNG supply will likely be Atlantic LNG, located at Point Fortin, Trinidad and Tobago, as it is only 560 nautical miles from Curacao (see Figure 5.5-6). The short distance will greatly reduce shipping costs. Atlantic LNG Company consists of four LNG trains with a combined LNG production capacity of approximately 14.8 million tonnes per annum (“mtpa”). Shaw Consultants does not know how much of this capacity is locked up in long-term contracts, but it is not inconceivable that the small ACQ required for Curacao might be available from this source. The three principal equity owners of Atlantic LNG are British Petroleum (“BP”), British Gas (“BG”) and Repsol.

Figure 5.5-6 Shipping Route (Atlantic LNG – Curacao)

Another existing LNG Liquefaction plant that might also be a viable source of LNG supply is Peru LNG. While Peru is in the Asia-Pacific region, the expansion of the Panama Canal, which is to be completed by the end of 2014, will permit LNG carriers to traverse the Panama Canal. Such passages have been heretofore denied. Peru LNG is reasonable close to Curacao at only 2,485 nautical miles (see Figure 5.57).

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Figure 5.5-7 Shipping Route (Peru LNG – Curacao)

Due to increased production and supply of natural gas derived from the development of shale gas resources in the U.S., several LNG liquefaction plants permits have been filed with the Federal Energy Regulatory Commission (“FERC”). Most of the current FERC permit applicants currently own LNG receiving and regasification terminals in the U.S. that have been made idle by natural gas prices too low to attract LNG imports. Seven U.S. based LNG import terminals that have submitted permit applications to FERC for the construction of liquefaction facilities for exporting LNG including: 

Sabine Pass Lousiana (Cheniere Energy);



Lake Charles Louisiana (Southern Union and BG);



Cameron Louisiana (Sempra Energy);



Freeport Texas (Macquarie Group and ConocoPhillips);



Gulf LNG Pascagoula Mississippi (Gulf LNG Liquefaction Company, LLC)



Jordan Cove Oregon (Fort Chicago Energy Partners and Energy Projects Development); and



Cove Point Maryland (Dominion).

The Sabine Pass Liquefaction LLC (“SPL”) project is further along than the other competing projects. SPL will initially consist of two LNG liquefaction trains, each with a capacity of approximately 4.4 mtpa. SPL is approximately 2,040 nautical miles from Curacao (see Figure 5.5-8). Two identical additional trains are to be added in due course. SPL already has executed LNG off-take contracts for all four trains: with BG for Train 1, Gas Natural for Train 2, Kogas for Train 3, and Gail for Train 4. SPL is currently the lone applicant that has received approval from the U.S Department of Energy (“DOE”) to export LNG to all international markets. Subsequent applicants may receive approval to export only to countries having free trade agreements with the U.S.

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Figure 5.5-8 Shipping Route (Sabine Pass LNG – Curacao)

Other potential LNG suppliers that are already in operation include several West African LNG liquefaction plants: Nigerian LNG, Angola LNG, and Equatorial Guinea LNG, but these are all over 5,000 nautical miles away, as are several LNG liquefaction plants in North Africa, in Algeria, Libya, and Egypt. An existing LNG liquefaction plant in Norway, Snohvit LNG will soon be joined by another Norwegian LNG liquefaction plant Skangass LNG, would also be potential LNG suppliers. RDK would likely find that both BG and Gas Natural would be receptive to supplying LNG to Curacao. Gas Natural operates and maintains the LNG Regas Terminal in Puerto Rico, and thus might also be quite comfortable and receptive to operating and maintaining a LNG terminal in Curacao. Having a proven supplier and operator would be quite beneficial in terms of obtaining project financing as well. 5.6

POOLING LNG SUPPLY WITH NEIGHBORING ISLANDS

In Shaw Consultants’ opinion, constructing separate LNG terminals at each of the ABC Islands makes no sense, given the high capital cost for the LNG terminals. However, if an LNG terminal is built in Curacao, it could perhaps provide sendout gas to the other islands. Aruba is approximately sixty-two nautical miles away from Curacao over an ocean span with a maximum water depth of approximately 4,000 feet. Bonaire is 45 nautical miles away with a maximum water depth of 5,350 feet. It is technically feasible to lay pipeline in these water depths. However, the potential Bonaire gas demand is too small to be considered economically feasible. If Curacao were to construct an LNG terminal sized to handle both the Curacao and Aruba gas demand load, a subsea natural gas pipeline could be constructed to export sendout gas from Curacao to Aruba.

5 - 18 CURACAO CNG-LNG TERMINAL FEASIBILITY STUDY

Section 5 –LNG Supply

With the refinery in Aruba now idle, the potential natural gas demand from Aruba would be for power generation only. The additional natural gas consumption from Aruba when added to the Curacao demand would help justify the investment for an LNG terminal in Curacao. This is especially the case if the Isla Refinery in Curacao is also idled. 5.7

CONCLUSIONS

With respect to LNG supply, Shaw Consultants has developed the following conclusions. 

Although the Curacao LNG annual supply requirement is relatively small when compared to the traditional large LNG regas terminal contracts, it will be feasible to contract for LNG supply. Since the annual quantities are small, Curacao may have to pay a slight premium for the LNG (US$0.40 to US$0.50/MMBtu).



Atlantic LNG in Trinidad will likely be the most attractive LNG supply source considering the short transport distance. However, LNG supply from Sabine Pass and Freeport Liquefaction Plants will be competitive alternatives.



Curacao should consider either contracting with a major LNG supplier (such as BP, BG, Shell, Total, etc.) or perhaps contracting with a reputable marketer/terminal operator such as Gas Natural (e.g. the Puerto Rico LNG Terminal operating strategy).



Based on the Curacao gas demand forecast, the LNG supply requirements will be as follows:  Years 2015 to 2018 Aqualectra Only (20 MMscfd) -

Approximately 0.138 mtpa LNG.

-

One LNG ship load every 5 months based on 140,000m3 capacity ship.

 Years 2018+ With Aqualectra + CRUC + Refinery Steam Boiler Loads (110 to 120 MMscfd) -

Approximately 0.759 to 0.833 mtpa LNG.

-

One LNG ship load every 28 to 26 days based on 140,000m3 capacity ship.



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.

5 - 19 CURACAO CNG-LNG TERMINAL FEASIBILITY STUDY

Section 6 – LNG Shipping and Transportation

6.1

OVERVIEW

Worldwide events in the natural gas and LNG sectors over the last five years have triggered major changes in the overall framework for LNG shipping. The LNG industry and gas markets have seen increased production from Nigeria, Peru, Qatar, and Yemen. In addition, major increases in production of shale gas in the United States and worldwide are impacting the global gas industry and the LNG shipping sector. Several projects to export LNG from the U.S. Gulf Coast are moving forward and will impact the LNG market in the Atlantic Basin. The companies producing LNG on the Gulf Coast and shipping the LNG eastward into the Atlantic basin will be potential sources of supply for the Curacao LNG project. The following table provides a snapshot of the worldwide LNG fleet, the order book for new vessels, and spot and long-term freight rates. Table 6.1-1 Worldwide LNG Fleet

Source: Drewry – Monthly Analysis of Shipping Markets, May 2012

Another major change over the last five years is a shift in emphasis in the LNG value chain from companies concentrating on access to natural gas resources over to companies emphasizing the ability to control LNG shipping. Only about 25% of the current LNG Carrier (LNGC) new buildings shown in the table above are dedicated to specific projects. The remainder of the vessels on order is either speculative, without specific charter trades, or dedicated to trading companies for use in their short and medium-term trading activities. The secondary market for LNGCs has become more active. The LNG shipping market is splitting into long-term, medium-term, and spot access to shipping. However, it will be more difficult for small LNG import projects such as Curacao to get direct access to LNG shipping. Concurrent with changes in the overall worldwide supply and distribution of natural gas and LNG, and from a cost perspective the LNG shipping industry has gone through a period of oversupply of shipping five years ago to a situation today where access to shipping has become very tight. Over the last five years spot charter rates for LNG carriers have increased from approximately $50,000 per day in 2007 to spot charter rates in the range of $100,000 to as high as $130,000 per day in 2012. This analysis is based, in part, on information derived from the following sources: 

Drewry LNG Shipping Market – 2011 Annual Review and Forecast;



Drewry Shipping Insight – Monthly Analysis May 2012;



Zeus Development Corp LNG Ship Database;



Update on LNG Shipping – February 2012 Platou LNG; and



Port to Port Distance Tables – UK Hydrographic Office.

6-1 CURACAO CNG-LNG TERMINAL FEASIBILITY STUDY

Section 6 – LNG Shipping and Transportation

The ship databases from the Drewry Report and Zeus Development Corporation are included in the appendices for future reference. 6.2

AVAILABILITY OF SHIPS

As of April 2012, the worldwide LNG fleet has 357 ships with an additional 76 ships on order. It is important to note that only vessels in the size range of 75,000 to 140,000 m³ would be suitable for delivering LNG cargoes into Curacao (see Figure 6.2-1). Approximately 2/3rds of the current LNGC fleet is in this range:

Ship Size Range

Number of Ships

75,000m3 to 120,000m3

15

125,000m3 to 140,000m3

221

Total Ships Within Target Window

236

Figure 6.2-1 LNG Fleet Size Distribution and Vessel Count

Figure 6.2-2 is taken from the February 2012 presentation “Update on LNG Shipping: What a Difference a Year Makes” by Platou LNG. Over the next five years in this projection, control of shipping would be approximately 290 ships (76%) dedicated to projects; 60 ships (16%) controlled by traders; and 30 ships (8%) open for charter. The most likely scenarios for getting access to LNG shipping for the Curacao project will be by purchasing the LNG either directly from a project or an LNG trader with access to shipping.

6-2 CURACAO CNG-LNG TERMINAL FEASIBILITY STUDY

Section 6 – LNG Shipping and Transportation

Figure 6.2-2 Total LNG Fleet Historical Control

Potential shippers associated with projects or traders who might provide LNGC capacity to deliver cargoes into Curacao include: 

Teekay;



Bonny Gas Transport;



BW Gas;



BG Group;



Shell Group;



Exmar;



GDF Suez;



Golar; and



Hoegh.

As noted previously, only ships in the size range from 75,000 m³ to 140,000 m³ would be acceptable for delivering LNG to the Curacao terminal assuming the terminal is equipped with a 160,000m3 LNG storage tank. Approximately 2/3 of the worldwide LNG shipping fleet fit within this size range. For ship sizes above 145,000 m³ the Curacao terminal would not have enough ullage to completely discharge the cargo.

6-3 CURACAO CNG-LNG TERMINAL FEASIBILITY STUDY

Section 6 – LNG Shipping and Transportation

Table 6.2-2 provides a listing of all LNGC owners, ranked by sizes of their fleets as of April 2011. Table 6.2-2 LNG Fleet Ownership Summary

6-4 CURACAO CNG-LNG TERMINAL FEASIBILITY STUDY

Section 6 – LNG Shipping and Transportation

Table 6.2-3 lists LNGCs available on the spot market last year and provides a perspective on the relatively small numbers of LNG carriers available in the worldwide spot market. In this case only 8% of worldwide LNG ships were available on the spot market.

Table 6.2-3 Vessels That Were Available On March 15, 2011

Source: Drewry Maritime Research

The availability of spot LNGCC tonnage is very unpredictable and cannot be relied on for planning longer-term cargo deliveries to the terminal at Curacao. Table 6.2-4 extracted from the Zeus Database shows the LNGC fleet operating in the Atlantic Basin. Each of these operators are potential sources of LNG shipping capacity for cargo deliveries into Curacao.

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Section 6 – LNG Shipping and Transportation

Table 6.2-4 LNG Fleet Operating In Atlantic Basin

Operator Anglo Eastern Group BW Europe Ltd. BW Gas ASA BW Gas ASA Exmar NV Golar LNG Höegh LNG Hyproc Shipping Co. Hyproc Shipping Co. Knutsen OAS Shipping Nippon Yusen Kabushiki Kaisha Shell Sovcomflot Teekay Corporation

Number of Ships 5 1 1 7 1 2 2 8 2 2 2 9 2 2

Average Size 3 (m ) 135,000 145,000 138,000 145,000 131,000 132,000 107,000 116,000 132,000 138,000 150,000 132,000 72,000 139,000

Route Nigeria-Europe Nigeria-Various Algeria-Various Nigeria-Various Algeria-Spain Trinidad & Tobago-USA Trinidad & Tobago-Spain Algeria-Turkey Algeria-France Trinidad & Tobago-Spain Nigeria-Various Nigeria-Europe Trinidad & Tobago-Spain Trinidad & Tobago-Spain

Target Delivery Window The 160,000 m³ storage tank proposed for Curacao provides approximately 29 days storage at a sendout rate 120 MMscfd (0.828 mtpa LNG). In order to completely discharge an LNGC, ullage (space available in tank) approximately equal to the ship parcel size will be required. In the case of a 135,000m³ ship, for example, the operator of the Curacao terminal must schedule ship arrivals such that the LNGC cannot arrive until the level in the LNG storage tank is below 28,000m³, or about a 6 day storage margin. This will require tight scheduling of arrival of the incoming LNG carrier. Table 6.2-5 below shows the impact, in terms of additional scheduling flexibility, when smaller ship sizes are used for importing LNG. This table shows the tank ullage required to discharge an LNGC and storage margin at the time the ship is scheduled to arrive at the terminal. Table 6.2-5 Analysis of Ship Size and Required Ullage Ship Size 3 (m ) 90,000 125,000 135,000

Tank Ullage Required 3 (m ) 86,400 120,000 129,600

Max LNG Inventory on 3 Arrival (m ) 73,600 40,000 30,400

Days Storage Remaining 14.3 7.8 5.9

The potential shipping fleets described above should be considered in developing a list of LNG supply strategies. As the project approaches a final investment decision (FID), the analysis of LNG supply options must be closely integrated with obtaining LNG shipping for the project. The most likely supply/shipping scenario will be one in which project/producers with control over shipping also provide shipping for the project. The figure at the left is taken from the February 2012 presentation” Update on LNG Shipping: What a Difference a Year Makes” by Plateau LNG. 6.3

SHIPPING COSTS AND LOSSES

Shipping costs have increased significantly over the last five years. Figure 6.3-3 is taken from the February 2012 presentation “Update on LNG Shipping: What a Difference a Year Makes” by Platou LNG which illustrates this point.

6-6 CURACAO CNG-LNG TERMINAL FEASIBILITY STUDY

Section 6 – LNG Shipping and Transportation

Figure 6.3-3 LNG Charter Rate Trend

Movements in LNG tanker charter day rates over the next year will provide insight and perspectives as to whether or not LNG tanker prices have leveled out at values comparable to the historic highs. Considering the recent LNGC ship order book, it is likely that charter day rates will not increase significantly beyond current levels. Shipbuilding costs have come down slightly over the last four years (see Figure 6.3-4). This is one leading indicator for future LNCG charter costs and an indication that charter costs in the near future will be no higher than current levels. Figure 6.3-4 Newbuilding Orders and Price Trend

The Drewry 2011 LNG shipping analysis provides generic estimates of LNG transportation costs based on round-trip distances between loading and discharge ports (see Table 6.3-6 below). This is an excellent "rule of thumb” for LNG shipping costs for medium to long-term charters, but not spot charter rates.

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Section 6 – LNG Shipping and Transportation

Table 6.3-6 Generic LNG Transportation Costs (US$/MMBtu)

Shaw Consultants developed a shipping cost model which reflects LNGC charter rates, all costs associated with LNG routes including port fees, and LNG characteristics (heating value / specific gravity). The model also estimates shipping costs for a range of potential LNG supply locations. The shipping route charts are included in Appendix G of this report. Table 6.3-7 Ship Model Results (US$120k/Day; 17 knots)

The shipping cost shown in Table 6.3-7 is based on a charter rate of $120,000 per day and an average cruse speed of 17 knots. This is a conservative "high" estimate in that it is likely that ships can achieve average cruse speeds above 17 knots. Also, with longer-range planning the project will likely be able to avoid having to charter shipping on the high cost spot term market.

LNG SOURCE Atlantic LNG, Trinidad Sabine Pass LNG, Texas Freeport Peru LNG Algerian LNG, Arzew Algeria Bonny LNG, Nigeria Angola Qatar LNG

ROUND TRIP  DISTANCE        Natucal Miles                 1,006                 3,564                 3,636                 4,336                 8,686                 9,224               10,182               17,546

TOTAL  UNIT  SHIPPING  SHIPPING  COST          COSTS  US$ US$/MMBTU 519,216 0.17 1,271,569 0.41 1,292,745 0.42 1,498,627 0.47 2,778,039 0.85 2,936,275 0.90 3,218,039 0.99 5,383,922 1.66

Table 6.3-8 Ship Model Results (US$120k/Day; 18.5 knots)

A sensitivity case based on an average cruse speed of 18.5 knots and a charter rate of $120,000 per day was calculated using the shipping model. The results of this sensitivity case are shown in Table 6.3-8. Although this is not as conservative as the 17 knot case, it is likely that the LNGCs can be chartered on the basis of achieving an 18.5 knot average speed.

LNG SOURCE Atlantic LNG, Trinidad Sabine Pass LNG, Texas Freeport Peru LNG Algerian LNG, Arzew Algeria Bonny LNG, Nigeria Angola Qatar LNG

ROUND TRIP  DISTANCE        Natucal Miles                 1,006                 3,564                 3,636                 4,336                 8,686                 9,224               10,182               17,546

TOTAL  UNIT  SHIPPING  SHIPPING  COST         COSTS  US$ US$/MMBTU 495,225 0.16 1,186,577 0.38 1,206,036 0.39 1,395,225 0.43 2,570,901 0.79 2,716,306 0.83 2,975,225 0.91 4,965,495 1.53

6-8 CURACAO CNG-LNG TERMINAL FEASIBILITY STUDY

Section 6 – LNG Shipping and Transportation

Table 6.3-9 Ship Model Results (US$100k/Day, 18.5 knots)

Table 6.3-9 shows another sensitivity case based on a ship average speed of 18.5 knots and a charter rate of $100,000 per day which is more consistent with day rates for mid-term to long-term charters agreements. It is reasonable to assume that the Curacao LNG project will be able to contract for mid-term charters for LNG shipping and achieve charter costs below the spot charter rates.

6.4

LNG SOURCE Atlantic LNG, Trinidad Sabine Pass LNG, Texas Freeport Peru LNG Algerian LNG, Arzew Algeria Bonny LNG, Nigeria Angola Qatar LNG

ROUND TRIP  DISTANCE        Natucal Miles                 1,006                 3,564                 3,636                 4,336                 8,686                 9,224               10,182               17,546

TOTAL  UNIT  SHIPPING  SHIPPING  COST          COSTS  US$ US$/MMBTU 432,688 0.14 1,008,814 0.33 1,025,030 0.33 1,182,688 0.37 2,162,417 0.66 2,283,589 0.70 2,499,354 0.77 4,157,913 1.28

PORT REQUIREMENTS

An assessment of the port requirements and port characteristics was made based on Bullen Bay – Jetty No. 1 as the port location (see Figure 6.4-5). Figure 6.4-5 Bullen Bay

6-9 CURACAO CNG-LNG TERMINAL FEASIBILITY STUDY

Section 6 – LNG Shipping and Transportation

The general approaches to Curacao are excellent with no significant marine risks or hazards. Bullen Bay is an open, large bay on the southwest side of Curacao, where the biggest vessels can enter safely. This naturally sheltered, deep-water bay is an excellent location for LNG shipping operations. The port has a state-of-the-art, fully-equipped Vessel Traffic Control Center (VTCC). Maximum draft of LNG carriers is typical 12m. To provide a margin for maneuvering and bottom clearance, a minimum water depth of approximately 15m is typical needed for midsized LNG carriers. This includes both water depth at the jetty and also turning basin water depths to allow for maneuvering the ship during approache to and at the berth. Jetty No. 1 at Bullen Bay is in a water depth of 21m. This depth is more than adequate for all LNG carriers in current service. Considering the fact that future LNG carrier construction will likely be for ship sizes below 200,000m³, any future LNG carrier will also be able to operate within the water depths available at Bullen Bay. Pilotage is compulsory. The pilots are employed by the Curacao Pilots Organization (CPO), which offers a 24 hour pilotage service. Discussions with the pilots Association will be required during next phases of the project in order to establish all parameters associated with LNG carrier operations. It is anticipated that LNGCs, similar to worldwide practice, will be able to berth at night as well as during daylight hours. This should be verified in next phases of the project studies. Tugs are required for crude, product, and gas carriers. For planning purposes, it is estimated that three tugs will be required for berthing operations. Limits on wind, wave height, and visibility conditions must be considered when determining when LNGCs can safely approach the berth. The following table lists typical wind speed thresholds which would limit ship operations. Table 6.2-10 Wind Speed Thresholds Vessel Activity Berthing Loading Loading Loading

Wind Speed Threshold (knots) 25.0 30.0 35.0 40.0

Vessel Action Berthing prohibited Stop cargo transfer Disconnect arms Leave berth

Typical wave limits for LNGCs approaching and mooring at the berth are in the range of 2.5m with an upper limit of 3.0m Hs (significant wave height). A minimum visibility of approximately 1.0 nautical mile. It is not anticipated that wind, wave height or fog and reduced visibility will significantly impact shipping operations. However, a review of historical data for wind, wave and visibility conditions should be included in next phases of project studies in order to estimate what, if any, impact these weather conditions will have on the LNG carrier operations. Appendix H contains plots of the most severe hurricane years in the Caribbean and Gulf of Mexico over the last decade. Nearly all hurricanes tracked north of Curacao. It is not anticipated that hurricanes will have a significant impact on imports of LNG into the terminal. 6.5

CONCLUSIONS

The Bullen Bay terminal, from a perspective of LNG ship operations, is among the best worldwide terminals for overall LNGC operations.

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Section 6 – LNG Shipping and Transportation

Weather conditions (wind, waves, visibility, and hurricanes) will not likely significantly impact shipping. The "window" when ship operations might be restricted due to weather conditions is likely on the order of 5%. The schedules for receiving cargo can accommodate a one or two day delay due to weather. It is recommended that a more detailed analysis of overall weather conditions be conducted in next phases of the project. LNG shipping costs will not likely vary significantly from current estimates in the Shaw Consultants shipping cost model. In any case, total cost to deliver LNG will be dominated by the F.O.B. price at the LNG liquefaction plant, with LNG shipping only a minor complement of total LNG costs at the Curacao terminal. Establishing access to shipping will be critical. The project will require approximately one delivery by an LNGC in the 125,000m3 to 135,000m3 size range approximately every 25 to 27 days. Relying on spot charters is not an option. It is recommended that access to shipping be closely integrated with obtaining the LNG supply for the project. A preferred supply and shipping scenario will be to find a producer (which also controls its shipping) in the Atlantic Basin and which has the flexibility to integrate a small LNG purchase on a fixed delivery schedule, into their overall portfolio of LNG deliveries. Trading companies which currently control shipping will provide another option.

6 - 11 CURACAO CNG-LNG TERMINAL FEASIBILITY STUDY

Section 7 – Terminal Location Assessment

7.1

INTRODUCTION

During the meetings and site visit to Curacao on March 15 and 16, 2012, various potential site locations were discussed and reviewed with representatives of RDK, Department Environmental Services of Curacao and the Curacao Port Authority. Two sites were selected for further evaluation including Bullen Bay and Schottegat Harbor. Other potential sites that were considered, discussed, and eliminated included: 

Strip of land at Mansalina Bay which was eliminated due to low water depth for LNG ships;



Vaersen Bay and Mansalina Bay which was eliminated since it is considered to be a tourist site area and only applicable for an offshore FSRU option; and



Caracas Bay which was eliminated since it too is designated as a tourist development area and has issues with pipeline routing to the refinery and Aqualectra power plant sites..

Key requirements for the establishing suitable LNG terminal site include: 

Sea access with a minimum water depth of 12m at low tide for the large LNG transport ships;



Ability to install the required ship LNG offloading dock near the LNG Terminal site;



Reasonable distance for installing the LNG transfer lines from the offloading dock to the LNG storage tank;



Suitable site area and subsurface conditions for development and installation of required LNG storage tank and process facility;



Ability to maintain required safe distance radii for thermal and vapor dispersion zones from the LNG facility to adjacent occupied facilities; and



Ability to permit and construct the gas pipeline from the LNG terminal site to the power plant delivery locations within the Isla Refinery area.

To further assess the LNG Terminal and FSRU options, additional design criteria has been evaluated for Curacao, including: 

Meteorological Conditions;



Tide and Current Conditions;



Hurricanes and Tropical Storms;



Geologic Conditions;



Seismicity and Tectonics; and



Tsunami Hazard.

Meteorological Conditions Curacao is an island located in the so called Southern Caribbean Dry Zone and is characterized by a semiarid to arid climate with a distinguishable dry and rainy season. Winds are sustained moderate to fresh easterlies. The dry season runs from February through June, whereas the rainy season starts in September

7-1 CURACAO CNG-LNG TERMINAL FEASIBILITY STUDY

Section 7 – Terminal Location Assessment

and ends in January. The island is characterized by warm tropical temperatures with the highest mean temperatures occurring in September. The prevailing trade wind directions vary slightly East North East to East South East, with an average velocity of 5.2 to 6.6 m/s. The seawater around the island averages around 27° C and is coldest (average 25.9° C) around FebruaryMarch and warmest (average 28.2° C) around September-October. Design criteria considerations for the ambient air temperatures and relative humidity are: PARAMETER

Max

Min

Avg.

Ambient Air Temperature - C

36.9

20.3

27.9

Average Relative Humidity - %

89

74

80

o

Design criteria considerations for wind and weather design data are: PARAMETER

Design Value

Prevailing Wind Direction The prevailing trade wind directions vary slightly East North East to East South East, with an average velocity of 5.2 to 6.6 m/s. Maximum gust to 25.7 m/s. Maximum Design Wind Load (Hurricane)

67 m/s

Wind Rose Data North = 0 deg & clockwise

Wind Direction %

0

22.5

45

TBD

TBD

67.5

90

112.5

TBD

TBD

TBD

135

157.5

180

TBD

TBD

TBD

202.5

225

247.5

TBD

TBD

TBD

270

292.5

315

TBD

TBD

TBD

337.5

TBD

TBD

Rainfall Rate Maximum 1- Hour Maximum 24 - Hour

4.5 inches 10.1 inches (September)

Average Annual

21.3 inches

Maximum Annual

42.9 inches

Barometric Pressure Maximum

30.61 “Hg

Mean

30.13 “Hg

Minimum

29.64 “Hg

Maximum Rate Of Change (Assumed)

0.5”Hg/hr

Tide and Current Conditions Tide measurement data has been evaluated using summary documents titled “Subject: The Tides of Curacao”, dated June 14, 1998 and “Some Notes on Tide in Annabaai Harbour, Curacao, Netherlands Antilles”, Bulletin of Marine Science of the Gulf of Caribbean, Vol. 9, No. 2, pp 224-236, June 1959. Under normal meteorological conditions (wind barometric pressure) there are two high tides every day. There heights are not the same for there is a higher high water (HHW) or high water spring (HWS) and a lower low water (LLW) or low water spring (LWS). For Curacao, the maximum difference between the HHW (or HWS) and LLW (or LWS) is 80cm. The tidal differences generally range between 30 and

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Section 7 – Terminal Location Assessment

35cm. In Curacao, the tide fluctuation levels are measured from the Curacao Peil (CP) reference datum level. For Curacao, the HWS is +47 cm CP and LWS is -33cm CP. The near shore current of Curacao usually sets a West North West direction, with a maximum velocity of 0.5 m/s. The regular velocity is generally not more than 0.26 m/s. Hurricanes and Tropical Storms The data source for evaluating hurricanes and tropical storms was the “Hurricanes and Tropical Storms in the Netherland Antilles and Aruba”, dated April 2010. Curacao is not outside of the hurricane belt and history indicates that roughly once every 100 years, considerable damage is experienced by a tropical cyclones passing over or just south of the island. A major hurricane passed just south of Curacao on September 23, 1877 causing considerable structural damage. On the average, once every four years a tropical cyclone occurs within a radius of 150 km, but passing mostly north of the island without causing serious bad weather conditions. Hurricane Hazel passed approximately 90 km to the north on October 7, 1954 and wind speeds at Curacao were observed at 50 km/h with gusts to 90km/h. Curacao received approximately 125 mm of rain within a 48 hour period, which resulted in local flash floods. Hurricane charts are included in Appendix H of this report. Eight tropical storms passing near the island since 1988 have caused structural damage and rough seas pounding exposed harbors and beach facilities. Excessive rains have caused widespread flooding over the island for several days. Wind gusts of form 75 to over 90 km/h are typically recorded. The storm surge during a hurricane or major tropical storm event can result in a storm surge of approximately 6 m along the coast of Curacao. Geologic Conditions Curacao geology is characterized by two main rock types, Cretaceous basalt (lava) and Tertiary limestone. The basalt (diabase) is of deep sea volcanic origin and represents the oldest geologic unit of the island. The limestone represents fossil reef and fore-reef deposits. The limestone units form the seaward-dipping limestone hogbacks seen on the leeward side of the island. The island of Curacao is a result of tectonic uplift that initiated in the Middle Miocene and continued into the Pleistocene and Holocene periods. The geologic map of Curacao is presented in Figure 7.1-1. Figure 7.1-1 Geologic Map of Curacao

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Section 7 – Terminal Location Assessment

The majority of bedrock observed at Bullen Bay, along the proposed gas pipeline route and in the Schottegat Harbor area appears to be weathered, moderately hard and slightly porous coral limestone near surface. At Bullen Bay, massive limestone beds were exposed as a cliff face at the water edge, at the Jetty 1 location. The geologic map in Figure 1 indicates that the diabase may be encountered along some sections of the proposed gas pipeline. The diabase is generally weathered and highly fractured where encountered near surface. Seismicity and Tectonics No major tectonic fault zones are located near Curacao. The nearest distance to the Caribbean Plate contact is in northern Venezuela. A check with the US Geological Survey National Earthquake Information Center (NEIC) indicates that Curacao can experience nearby random earthquakes with earthquake magnitudes of 4.6. Also larger magnitude earthquakes in the Venezuela have resulted in measured ground shaking with a magnitude of 3 and 4 in Curacao. The seismic design for design criteria, per NFPA 59A, for a LNG tank and plant is based on an Operating Basis Earthquake (OBE) defined as the ground motion having a 10 percent probability of exceedance within a 50-year period (mean return interval of 475 years). The design for Safe Shutdown Earthquake (SSE) is defined as the ground motion that has a 2 percent probability of exceedance in a 50-year period. In this Standard, the LNG facility is designed to contain the LNG and prevent catastrophic failure of critical facilities under an SSE event. The facility is not required to remain operational following the SSE event. No specific earthquake seismic design code could be found for Curacao. The Uniform Building Code 1997 (UBC97) is a well respected design code and lists an OBE earthquake magnitude of 0.30g for Curacao. For this feasibility study, this seismic design value should be sufficient. It is recommended that a site specific seismic and tectonic assessment be performed for Curacao in accordance with current industry practice to develop OBE and SSE seismic design criteria, should the LNG tank and process facility optimum be selected for use. Tsunami Hazard The “Tsunami Hazard for the Territory of Curacao (2010)” was used as the source to evaluate the tsunami hazard for the proposed site locations. This study is based on three different major earthquakes events occurring within the Caribbean: 1. An earthquake of magnitude M = 7.5 in the Southern Caribbean Deformation zone (SCDB) 2. An earthquake of magnitude M = 8.0 in the subduction zone south of Puerto Rico (MT) 3. An earthquake of magnitude M = 8.0 in the subduction zone east of the island arc (PT/LAT) These three events are considered reasonable to establish the maximum probable tsunami runoff that could occur along the Curacao coast. This study is considered to use for design of a near shore LNG tank and facility. It is not necessary to consider these tsunami events for design of the offloading jetty. Based on the results and recommendations of this study, the design level tsunami for the Bullen Bay site should be designed for a tsunami wave run-up inundation limit of 7.68m, which is based on the MT earthquake event. The eastern portion of Schottegat Harbor would be protected from surge flooding by the narrow and curved St. Anna Bay (6.93m at Bay inlet) and areas adjacent to the Willemstad coast (6.75m) near the inlet, thus minimizing any wave run-up at the proposed LNG site location within the Schottegat Harbor area.

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Section 7 – Terminal Location Assessment

7.2

LNG TERMINAL SITE LOCATIONS

Evaluating the above siting and design criteria with the various site locations screened during these meetings, only two site options appear to be feasible for consideration for a LNG terminal location. The two site locations that may be suitable for the Curacao LNG terminal include a site on Parcel A at the existing Bullen Bay Oil Storage Terminal and a fill area within Busca Bay in the Schottegat Harbor area. Figure 7.2-2 illustrates the general location of these site options. Figure 7.2-2 Curacao LNG Terminal Location Options

A LNG FSRU could be berthed at the Jetty No.1 location at Bullen Bay or at an offshore single point buoy mooring location along the coast connected by a gas pipeline to the Curacao customer end-use locations. The FSRU offshore buoy site could be located 1 to 1.5 miles offshore from Bullen Bay or along the coast to near the inlet of Schottegat Harbor at St. Anne Bay. The offshore FSRU buoy site locations will be limited along the section of coast identified since massive limestone cliffs and rock outcrops will limit where offshore to onshore gas pipelines can be installed from the offshore buoy locations. Installation of the buoy gas pipeline will likely involve tunnel boring at the shore crossing. 7.3

BULLEN BAY SITE OPTION

The Bullen Bay LNG terminal site location at the south end of the existing Curacao Oil Storage Terminal is shown in Figure 7.3-3. The LNG tank and process facility are proposed to be located on Parcel A, shown in Figure 7.3-5 and Figure 7.3-6. There is adequate area to place the LNG tank, process facility and, if desired, a gas fired generating power plant at this location. Jetty No.1 will require total redesign and upgrading to handle offloading of a LNG carrier or the mooring of a LNG FSRU.

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Section 7 – Terminal Location Assessment

Figure 7.3-3 Bullen Bay Site Option

A new buried gas sendout pipeline will be installed from this site location and will follow the presently purchased right-of-way (ROW), which contains the existing oil pipeline from Bullen Bay Oil Storage Terminal to the Isla Refinery at Schottegat Bay (see Figure 7.3-4 below). Figure 7.3-4 New Gas Sendout Pipeline Route from Bullen Bay Site to Refinary

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Section 7 – Terminal Location Assessment

Figure 7.3-5 shows a plot of Parcel “A” located adjacent to Jetty No.1 at Bullen Bay. This plot is available and could be used for a LNG terminal. A close-up of the proposed Bullen Bay facilities location is shown in Figure 7.3-6 with Parcel “A” outlined. The previous tanks and foundations in Parcel “A” were removed a few years ago. Boring logs near this location at the site visit indicate that the proposed LNG tank, process facility, and a possible future gas fired power plant in Parcel “A” will be founded on competent limestone rock. It is anticipated that minimal site preparation will be required for construction of the LNG facility. The existing site grade is at approximately elevation +7m. A retention berm will be required around the perimeter of the tank and process area, which can be built to an elevation to prevent overtopping for the design tsunami run-up elevation. Jetty No.1 can be redesigned for offloading LNG transport ships or for a FSRU docking berth and gas offloading. Jetty No.1 will require total redesign and rebuilding to accommodate a larger LNG transport ships and the special LNG unloading facility. The water depth at Jetty No.1 is 21 m, which is more than adequate for the large LNG tankers and an FSRU (can accommodate 400m long ships). This jetty can be designed and built to accommodate both LNG and oil tanker offloading systems, if necessary. Presently it is Shaw Consultants’ recommendation to use Jetty No.1 only for LNG ships, to keep the LNG facility totally separate from the Oil Storage Terminal operation. Ship approach and exit is excellent for this jetty location and operation. Figure 7.3-5 Bullen Bay Site Parcel “A” Plot

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Section 7 – Terminal Location Assessment

Figure 7.3-6 Bullen Bay Site Aerial View

Figure 7.3-7 Bullen Bay Site Thermal Exclusion/Gas Dispersion Zones

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Section 7 – Terminal Location Assessment

Preliminary thermal exclusion and gas dispersion zones for the onshore LNG terminal option at Bullen Bay (based on NFPA 59A requirements) are illustrated in Figure 7.3-7 above. The zones plots assume a 160,000m3 “full containment” LNG tank is installed. As noted from the illustration, the Bullen Bay site provides adequate space to safely operate the terminal. The thermal exclusion zone required for a “single containment” LNG tank will be significantly larger and Shaw Consultants anticipates that the site will not be large enough to safely accommodate a “single containment” type LNG tank. 7.4

SCHOTTEGAT HARBOR SITE OPTION

The Schottegat Harbor Site Option is illustrated in Figure 7.4-8 through Figure 7.4-11. The jetties identified for the Schottegat site option are potentially available for conversion/upgrade for use as both an LNG unloading terminal and refinery product ship loading. The proposed LNG facility option location is also shown. LNG pipelines will run from the offloading jetty to a LNG tank and process facility location. The Schottegat Harbor is not considered suitable for a FSRU location and operation due to major limitations for Harbor operation and safety reasons. Gas lines will run from the LNG facility location to the power plants at the refinery location. Figure 7.4-8 Schottegat Harbor Site Overview

The approach to the Schottegat Harbor from the Caribbean through the narrow St. Anna Bay inlet has water depths ranging between 13 to 23 meters. The bridge over the St. Anna Bay has a maximum air draft (height above water level) of 55 meters. The Harbor water depths traversing from the narrow Bay entry to the jetty sites ranges from 13 to 23 meters and can just accommodate the minimum draft requirements of the large LNG transport ships. The two jetties identified are presently being used for refinery product ship loading and should be considered

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Section 7 – Terminal Location Assessment

for dual use for new design and upgrading if this location is chosen for an LNG offloading and storage facility. Figure 7.4-9 Schottegat Harbor Entry

The entry into and exit from the Schottegat Harbor by a LNG transport ship will require the narrow St. Anna Bay entrance to be cleared of all ships during the entry and exit. Also all other ship movement within the Schottegat Harbor will be restricted when the LNG ship is moving. The narrow St. Anna Bay entrance is presently used to dock cruise ships and is the location of major Curacao tourist businesses along each side of the Bay. Restricting use of cruise ship docking in the Bay during LNG delivery will also present a restriction for the tourist business. The March 13, 1976 Map for Sint Anna Bay and Schottegat Bay which indicates sounding depths in meters for low tide conditions, was used to identify depths within the Harbor and narrow entrance. The Harbor Master has indicated that the large LNG ships can be moved into the identified jetty locations shown on the figures. These water depths will have to be confirmed to determine that adequate draft for the LNG ships is available.

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Section 7 – Terminal Location Assessment

Figure 7.4-10 Schottegat Harbor Jetty Options

Figure 7.4-11 Schottegat LNG Terminal Facilities Site

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The site area identified is the only location within this working Harbor that has an adequate area for locating an LNG tank and process facility, along with the ability to maintain the required safe distance radii for thermal and vapor dispersion zones from the LNG Terminal facility to adjacent occupied facilities. Preliminary thermal exclusion and gas dispersion zones for the onshore LNG terminal option at Bullen Bay (based on NFPA 59A requirements) are illustrated in Figure 7.4-12 below. The zone plots assume a 160,000m3 “full containment” LNG tank is installed. As noted from the illustration, the Schottegat site provides adequate space to safely operate the terminal. The thermal exclusion zone required for a “single containment” LNG tank, however, will be significantly larger and Shaw Consultants anticipates that the site will not be large enough to safely accommodate a “single containment” type LNG tank. Figure 7.4-12 Schottegat Site Thermal Exclusion/Gas Dispersion Zones

Dredging in this area of the Harbor is not recommended since the bottom sediments are expected to be contaminated and it is also located in the area of the intake for the refinery cooling water system. The cooling water system cannot tolerate an increase in suspended solids that would occur if dredging is required to increase water depth. Also suspected contamination of bottom sediments would be difficult to control and prevent from entering the intake for the cooling water system. Available site photographs for the land area defined for the proposed LNG Facility Option indicates that it is a random fill area, with large rock blocks visible on the surface. The 1976 Map indicates that this land area had from less than 1 m to over 4 m of water depth prior to fill placement within the present land area. On this basis it is anticipated that from approximately 2 to 6 m of random fill may have been place at this location. A detailed geotechnical exploration program will be required to define the thickness of random fill at the LNG tank and process facility locations. Only then can the type of foundation system and site preparation requirements be defined to adequately support the LNG tank and facilities for static and seismic design

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Section 7 – Terminal Location Assessment

requirements. It is known that soft marine bottom sediments are present within the Bay, just south of this fill area. Based on limited geologic information for this area, it is assumed that the depth to bedrock is not deep, but the fill may still be overlying soft marine sediments that may be contaminated. It is anticipated that general site grading, roads, parking areas and perimeter berms can be constructed on top of the present fill, since it has been place for several years. Berm heights will be low and settlement is anticipated to be minor. Site preparation and foundation treatment required for the LNG tank and process facility foundation support is expected to be extensive. The control room and other type of maintenance and support facilities will be located on the west side of the cooling water intake water way, across from the LNG Tank and process facility. A bridge will be required across the cooling intake canal to provide access for heavy equipment and construction loads for installation of the LNG facility and to provide access during plant operation. The design and construction of a heavy duty access bridge over the intake water canal is estimated to add cost above the base development cost for development of the Schottegat Harbor LNG site. The LNG pipeline from the LNG transport ship to the LNG tank will also require a special pipe bridge across the intake water canal. It is anticipated that this special pipe bridge will add cost above the base development cost for development of the Bullen Bay LNG site. Gas pipelines from the LNG facility to the relative short and within a present industrial to the existing power plants. It is estimated that the site preparation and development cost to provide suitable foundation support for critical LNG facility structures will add cost well above the base development cost for development of the Bullen Bay LNG site. The site development cost increase for developing the Schottegat Harbor LNG site will be offset by the cost of the gas pipeline from the Bullen Bay LNG site. 7.5

LNG FSRU OPTION

The LNG FSRU option is considered a suitable option located either at Jetty No.1 of the Bullen Bay Oil Storage Terminal or offshore using a buoy mooring system. The Schottegat site was not considered to be viable for a LNG FSRU operation. The location of the LNG FSRU buoy mooring system could conceivably be any location along the coast where a convenient connection can be made to the new onshore gas sendout pipeline. A tentative offshore location for a buoy moored facility is shown in Figure 7.5-13. This location can be revised as may be required to minimize traffic impact for ship movement along the coast and to optimize a gas pipeline connection to the new land based gas sendout pipeline. The location shown in Figure 7.5-13 is such that a gas pipeline connection from the buoy can installed to the new sendout gas pipeline that is tentatively planned from the Bullen Bay Oil Storage Terminal to the Isla Refinery (refer to Figure 7.3-4). The offshore site would be located approximately 1.0 to 1.5 miles offshore from Bullen Bay as illustrated in Figure 7.5-13. The offshore site contemplates mooring the FSRU using a single point buoy or turret type mooring system with a single gas pipeline from the offshore mooring to shore. Water depths in this area are 300 to 400 meters. As can be seen from Figure 7.5-13, there is adequate depth to locate and moor the FSRU in the general area shown. This option eliminates the need to establish an onshore jetty, LNG storage tank and process facility for offloading and processing the LNG. The shoreline in this area has rock cliff features, so further study will

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Section 7 – Terminal Location Assessment

be required to establish a suitable pipeline construction method for shoreline crossing should this option be considered feasible. The offshore mooring and gas pipeline design will need to consider the shoreline terraine avoiding rock cliffs, sensitive environmental reefs, fisheries, and popular local and tourist coastal and beach areas. Figure 7.5-13 LNG FSRU Offshore Buoy Location Near Bullen Bay

Environmental studies will be required for any of the offshore mooring and gas pipeline routing options. Since rock can be very shallow along this coastline section, a geotechnical exploration program with geophysical seismic profiles will be required to determine the feasibility of mooring location and the gas pipeline routing and burial requirements. These offshore studies will be costly and require considerable time to complete.

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Section 7 – Terminal Location Assessment

7.6

ADVANTAGES / DISADVANTAGES

Bullen Bay LNG Site Option Advantages 1. Base LNG facility cost can be used for design/construction of LNG tank, process, support facilities and protective berms. 2. Short access length for jetty redesign and upgrade for handling LNG. 3. Jetty redesign and construction considered to be within base cost rate with Schottegat Bay Option. 4. Good LNG transport ship access and depth. 5. Short LNG transfer line length from ship to tank. 6. Minimal site preparation cost. 7. Can be used for a jetty location to moor a LNG FSRU. 8. Site space available for adding a future gas fired power generation plant. Disadvantages 1. Requires construction of a new gas sendout pipeline (8 miles long) site to Isla Refinery which passes through and adjacent to some urban housing areas. 2. Ocean cooling water intake and discharge construction required near shoreline rock cliffs. Schottegat Harbor Site Option Advantages 1. Base LNG facility cost can be used for design/construction of LNG tank, process, support facilities and protective berms. 2. Short access length for jetty redesign and upgrade for handling LNG. 3. Jetty redesign and construction considered to be within base cost rate with Bullen Bay option. 4. Short sendout gas pipeline required for delivery of gas to the Curacao customers located at the Isla Refinery. Disadvantages 1. Higher initial base cost than Bullen Bay site. 2. Marginally meets the water depth requirements for LNG carriers at the jetty locations. 3. Poor foundation conditions with unknown random fill and possible contaminated soft marine clay below fill. 4. Substantial geotechnical studies and costly site preparation work required to provide adequate foundation support for critical LNG tanks, process and other operating equipment.

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Section 7 – Terminal Location Assessment

5. Heavy load capacity bridge required across cooling water intake water canal to access LNG site area. 6. LNG pipeline crossing bridge required across cooling water intake water canal to access LNG site area. 7. Potential dredging may be required of closest jetty site, which is not considered practical in cooling water intake area. 8. Items 3-7 have potential to add considerable cost above base cost for LNG facility. 9. Narrow access into Harbor entrance requires clearing of all ships for access and stoppage of all ship movement in harbor area until LNG ship is docked. 10. Cruise ships could limit harbor entrance where tourist business are located as well as other impacts to industrial shipping. 11. Items 9 and 10 have undesirable local cost impacts to other business sectors important to Curacao. 12. Schottegat Harbor is not considered suitable for LNG FSRU mooring location. LNG FSRU Offshore Buoy Moored Option Advantages 1. No jetty work required. 2. Onshore gas power plant can still be installed in Parcel A at Bullen Bay Oil Storage Terminal. Disadvantages 1. More costly than the jetty moored LNG FSRU alternative. 2. Limited locations for establishing offshore to onshore gas pipeline route from mooring location. 3. Costly environmental and geotechnical studies will be required for offshore mooring and offshore to onshore gas pipeline. 4. Shallow bedrock expected to increase cost for installing buried sections of offshore gas pipeline. 5. Long term operation cost is expected to be higher. 7.6

CONCLUSIONS

No site conditions were identified that would preclude installation of an LNG terminal at either Bullen Bay or Schottegat Harbor. The Bullen Bay option provides the best overall conditions for design and installation of an onshore LNG terminal facility. The Schottegat Bay site has significant issues including higher site development costs, marine traffic rules that may hamper access for LNG carriers to reach the jetty and unload its cargo, and more public visibility which could result in public opposition to the Curacao LNG terminal project.

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Shaw Consultants believe that the installation of a new sendout gas pipeline from Bullen Bay to the Curacao gas customers located at the refinery area will not have significant issues making the Bullen Bay site the better choice. Limitation of cruise ships and other marine terminal traffic issues for the Schottegat Harbor LNG site make this site location unattractive. Shaw Consultants recommends that the Bullen Bay site be selected. The offshore buoy moored LNG FSRU options presents more risks that cannot be defined without further study due to environmental and geotechnical issues for buried offshore gas pipeline installation. The sendout gas pipeline will require minimum soil coverage of at least 30 inches (750mm). Weathered rock is expected to be encountered over much of the pipeline length. It is anticipated that much of the pipeline can be installed using conventional trenching methods for weathered and fractured rock. Where harder rock is encountered, it is anticipated that rock excavation can be achieved using backhoe mounted hydraulic rams and conventional excavators.

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Section 8 – Conceptual Curacao LNG Terminal

8.1

OVERVIEW

As part of Shaw Consultants’ scope of work, a conceptual design was developed for a traditional onshore LNG Regasification Terminal for Curacao (“Terminal”). The Terminal is assumed to be located in Parcel “A” at the Bullen Bay site and includes all systems and equipment required for a fully functional LNG receiving, storage, and regasification facility. The Terminal will be equipped with a 160,000m3 “full containment” LNG storage tank. Marine jetty and LNG transfer facilities are provided at the Terminal to unload LNG carriers at a rate of 12,000m3/hr. LNG ships ranging in size from 75,000m3 to 150,000m3 will be able to berth and unload LNG cargo at this facility. The Terminal is sized to meet a maximum gas sendout demand of 137 MMscfd providing gas capacity to serve Curacao’s energy demand for natural gas through 2031 assuming Aqualectra, CRUC, and Isla Refinery convert from fuel oil to natural gas. Interconnecting piping and the vent/flare system within the facility were sized to accommodate future capacity expansion requiring minor pre-investment costs. The Terminal sendout gas capacity can easily be doubled by adding LNG pumps, vaporizers (ORVs), seawater pumps, and larger capacity sendout metering equipment. Operation and control of the facility will be from a central control room equipped with state-of-the-art computerized DCS control systems requiring minimal number of operating personnel to safely operate the Terminal. Infrastructure required to operate and maintain the Terminal is provided in the design. The Terminal will be designed and equipped with all necessary security, safety, and fire protection systems as required to meet NFPA 59A requirements. The facilities will be designed to meet all environmental and regulatory requirements necessary to comply with local, national, and global standards. The following conceptual design documents are included in the Appendix of this report: 

Conceptual Design Basis (Appendix A);



Process Flow Diagrams With Heat & Material Balances (Appendix B);



Terminal Layout Drawing (Appendix C);



Major Equipment List (Appendix D);



Utility Load Summary (Appendix E); and



Project Schedule Illustrating Key Milestones (Appendix F).

Following is a brief description of the typical facilities and systems that will be included in the Terminal design. Please refer to the process flow diagrams in Appendix B. 8.2

MARINE AND UNLOADING FACILITIES

LNG will be delivered to the terminal in 75,000 - 150,000 m3 LNG tankers. LNG will be unloaded from the tankers via the ship in-tank pumps through three 16" LNG Unloading Arms located on the jetty and routed to the LNG Storage Tanks. A 16" vapor return arm will also be provided at the jetty for return of vapor from the storage tanks to replace the LNG volume pumped from the ship. A total of 4-16” arms will be provided including two LNG arms, one hybrid LNG/vapor return, and one vapor return. All four

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Section 8 – Conceptual Curacao LNG Terminal

cryogenic arms are of identical design. A removable spool piece will be provided to allow one arm to be used as vapor return arm. Each arm is provided with a bolted flange coupler and a PERC (Powered Emergency Release System). The PERC provides a spill free break between the tanker and the shore in the event of an emergency disconnection. It is comprised of a break flange connection between two ball valves at the tanker end of the unloading arm. In the event of disconnection, the ball valves close rapidly and the break flange connection parts. LNG discharged from the LNG unloading arms will be carried in one 36" vacuum jacket insulated transfer line from the jetty to the LNG storage tank. The LNG transfer line will be provided with cryogenic internal bellows to compensate thermal contraction due for the cryogenic temperature of the LNG. Vacuum insulated pipe does not require the bulky thermal expansion loops and therefore reduces the cost of the jetty and pipe supports. At the design unloading rate of 12,000 m3/hr, the largest ship can be unloaded in approximately 11 to 13 hours. A 3” chill-down recycle line (vacuum jacket insulated) will be provided from the In-Tank LNG Pump discharge header to the unloading jetty to provide LNG circulation to maintained cryogenic temperatures in the LNG transfer line during periods when a ship is not offloading cargo. At the beginning of unloading, the liquid arms must be cooled down using LNG from the ship. This is done by starting one pump on the ship and utilizing the 2" bypasses provided around the isolation valves at the base of the unloading arms. Once the arms have cooled down, more pumps can be started and the isolation valves can be opened fully to unload LNG at the design rate. At the end of the unloading operation the liquid unloading arms must be drained. With the unloading arm isolation valve closed on the jetty, the LNG is drained to the LNG tanker using nitrogen pressure. With the tanker isolation valve closed the remaining LNG is gravity drained to the LNG Drain Drum (V-2). Nitrogen pressure is available to assist the draining operation, if required. LNG in the drain drum is pumped into the LNG unloading lines by a small pot-mounted LNG pump (P-3A/B). The 36” LNG unloading line carry the LNG from the LNG Dock to the LNG Storage Tank (TK-1) over a length of approximately 1,050 feet. The LNG transfer line will be vacuum jacket insulated and the pipe material will be Stainless Steel ASTM 304L. No ship bunkering facilities will be provided at the Curacao marine terminal. Neither ship stores supply, ship fresh water supply, ship bilge water handling, nor ship sewage disposal will be provided at the marine terminal. Secured access between the Terminal and the marine facilities will be provided for Terminal personnel. A separate controlled entry/departure point to the marine facilities that complies with Curacao Port Authority and immigrations control requirements will be provided for ship personnel and services so that access through the Terminal is avoided. 8.3

LNG STORAGE

One LNG Storage Tank (TK-1) will be provided. The tank will be a nominal 160,000m3 “full containment” type design and will hold a net volume of approximately 153,800m3 (minimum to maximum level). The tank is above ground, double walled construction by API 620 Appendix Q definition, with the two walls separated by insulation material. The tank meet "Double Containment" design as defined by EEMUA 147. The inner tank is made of 9% nickel steel and the outer tank is made of pre-stressed concrete with a carbon steel plate roof.

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All connections to the tank are through the roof. There are no penetrations through the sides or the bottom of the tank. This configuration is made possible by use of submerged In-Tank LNG Pumps (P-1 A/B) for LNG sendout. The tank is provided with both top and bottom filling connections to alleviate the possibility of roll-over conditions. Multiple temperature detectors will be furnished in the wall and the floor of the storage tank to monitor the temperature profile. A density monitoring system will be provided to detect stratification and potential roll-over conditions. The tank will be equipped with independent level transmitters, to protect against overfilling during unloading. A high-high level, if detected by the level instruments, will lead to closing of the inlet valve delivering LNG to the tank. The tank will also be provided with overpressure and vacuum relief valves. The design pressure of the LNG storage tank will be 2.8 psig (190 mbarg). The tank will generally operate in a pressure range of 0.7 to 2.0 psig (50 to 140 mbarg). The pressure in the tank will be maintained by sending gas to the boil-off gas compressor system. During upset situations the BOG will be vented to the flare/vent system. If the pressure drops to 0.6 psig (40 mbarg), the BOG compressors (K-2 A/B/C) will be stopped, and at 0.45 psig (30 mbarg) the vacuum break gas will be introduced into the tanks to avoid lifting the vacuum relief valve. If the pressure continues to drop, at -0.22 psig (-15 mbarg) the vacuum breaker introduces atmospheric air into the tank. If the pressure goes above 2.2 psig (150 mbarg), the standby BOG compressor will start. If the pressure continues to rise, at 2.5 psig (170 mbarg) the flare control valve opens to send gas to the flare/vent system. If the pressure rises above 2.8 psig (190 mbarg), the pressure safety valves release gas to the atmosphere from the tank top. The maximum estimated boil-off gas from the LNG storage tank inventory is 0.05% of the tank volume per day. The storage tank contains two submerged motor low pressure send-out pumps. Each pump is designed for 100% of the required design sendout capacity. To meet the 137 MMscfd of natural gas sendout capacity from the Terminal, one pump is required and one pump is for standby. These pumps serve the following functions:  LNG send-out;  Circulation of the LNG in the unloading line system from the tank area to the dock and back;  Condensation of boil-off gas; and  Re-circulation of the tank inventory, if required to prevent roll-over conditions. 8.4

BOG AND SHIP VAPOR RETURN SYSTEM

At atmospheric pressure LNG boils at about –256 °F. BOG is continuously generated in the tanks due to the following reasons:  Heat leak from the atmosphere through the insulation in the tanks and the unloading/recirculation lines;  Electrical energy supplied to the LNG tanker pumps;  Electrical energy supplied to the send-out pumps;  A small quantity of BOG is also generated when the barometric pressure decreases; and  Displacement of gas from the storage tanks during ship unloading.

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Section 8 – Conceptual Curacao LNG Terminal

BOG Compression The BOG quantity created during unloading operation is significantly larger than that created during normal sendout operations. The BOG handling system will be designed for these vastly different quantities and is comprised of the following elements: 

Three BOG compressors ( Two equal size small compressors one operating and one standby for normal operation and large compressor for unloading operation);



Ship Vapor Return Blower system;



BOG Condenser;



BOG Pipeline Compressor; and



Flare/Vent System.

The BOG from the tank is sent to the BOG compressors. LNG injection spray is provided at inlet of BOG Compressor Suction Drum (V-3) to reduce the temperature of BOG from tank. The discharge of the Small BOG Compressors (K-1A/B) is normally directed to the BOG Condenser or, if fuel gas is required for the Heat Medium Heaters (HTR-1A/B), it is partially directed to the fuel gas heater and the fuel gas distribution system. The BOG Pipeline Compressor (K-3) is provided to compress the BOG generated during normal operation for low gas sendout scenarios and during ship unloading operations when all of the BOG cannot be recondensed by the BOG Condenser (V-1). The BOG Pipeline Compressor takes suction from the Small and Large BOG Compressor discharge and compresses the gas to the pipeline sendout pressure of 800 psig at the battery limit. The BOG flow rate is higher, when the tank is operated at the lower end of the pressure range due to the larger amount of flashed vapor. LNG Unloading Operation During the unloading operation BOG is displaced from the LNG storage tank and the Ship Vapor Return Blower is used to return cold BOG to the ship, this gas replaces the volume of the liquid pumped out by the ship pumps. The vapor return rate is volumetrically equivalent to the unloading rate of 12,000m3/hr to maintain pressure in the ship tanks. A 12” vacuum jacket insulated line fabricated from 304L stainless steel is provided for vapor return to the ship. The ship can only accept LNG vapors at -220° F or colder. The BOG is compressed and returned to ship. In order to insure required cooldown of return vapors to ship, LNG injection spray into the vapor return stream is provided at jetty upstream of LNG drain drum. 8.5

LNG PUMPS, BOG CONDENSER, AND LNG SENDOUT SYSTEM

LNG is first pumped out from the storage tank to the BOG Condenser (V-1). The pumps are of the submerged in-tank type with the motor and pump mounted as one enclosed unit in wells installed inside the tank. Two such cryogenic pumps (In-Tank LNG Pumps P-1A/B) will be installed in the tank. LNG from the In-Tank LNG Pumps is sent to the BOG Condenser (V-1). The BOG compressor (K-2 A/B/C) discharge is fed to the BOG Condenser where it is condensed back into the main LNG sendout stream. The BOG Condenser has a packed section on the top of the horizontal drum at the bottom. The horizontal drum provides surge volume to the LNG Sendout Pumps (P-2A/B).

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Section 8 – Conceptual Curacao LNG Terminal

BOG enters at the bottom of the packed bed, to be absorbed into the LNG sendout liquid in the packed section of the vessel. LNG from the sendout pumps is divided into two parts, one entering the top of the packed bed under flow control, through a liquid distributor ring and the other entering the top of the horizontal drum, under level control. The flow controller feeding LNG to the top is in cascade pressure control and is automatically adjusted as required to maintain pressure control on the BOG Condenser assuring an equilibrium balance required to totally condense the BOG. This is the primary pressure control circuit is set to maintain 100 psig. If all of the BOG cannot be condensed under the primary control circuit, the pressure on the BOG Condenser will start to increase. If the BOG Condenser pressure reaches 10 psig above the primary pressure control set point, a secondary pressure controller assume control. A control valve on the vapor overhead line leaving the BOG Condenser is provided which will be throttled by the secondary pressure controller to release uncondensed BOG from the BOG Condenser as required to maintain pressure at the secondary pressure set point of 110 psig. When BOG cannot be totally condensed in the BOG Condenser, the BOG Pipeline Compressor must be started to compress the uncondensed BOG to 800 psig and deliver it for pipeline sendout. Otherwise, the excess BOG will be flared/vented. The LNG Sendout Pumps (P-2A/B) take liquid from the bottom of the BOG Condenser surge drum and boost the pressure to 820 psig. These pumps are 2-100% multi-stage LNG pot mounted pumps. Discharge from the LNG Sendout Pumps is routed to the LNG Vaporization System. 8.6

LNG VAPORIZATION SYSTEM

In the Curacao LNG Terminal, seawater will provide the heat to vaporize LNG using traditional Open Rack Vaporizers (E-1A/B). The ORV data sheet furnished by Kobe Steel is shown in Table 8.6-1. Table 8.6-1 Curacao ORV Performance Data Sheet

8-5 CURACAO CNG-LNG TERMINAL FEASIBILITY STUDY

Section 8 – Conceptual Curacao LNG Terminal

Two 100% ORVs are provided in the design each rated for 78.34 MMBtu/Hr (22.96 MW). Kobe Steel, one of the largest manufacturers of open rack vaporizers, was requested to provide a preliminary design for the Curacao ORV units. Seawater enters the top of the ORV under flow control at a temperature of 78oF (25.6oC) and is uniformly distributed over the five heat exchange panels. LNG is fed into the ORV panels from the bottom at a temperature of approximately -192oF (-124oC). As seawater flows down the outside of the panels, the LNG is vaporized and natural gas exits from the top of the ORV panels at a temperature of approximately 40oF (4.4oC). This cool temperature creates a need for a superheater to raise the gas temperature to 60ºF before sending it to the pipeline. This is accomplished by the two 100% Sendout Gas Superheaters (E-2A/B). These exchangers are a conventional shell and tube design and are heated by a separate Heating Medium (HM) circulation system which circulates a water/glycol solution through two 100% direct gas fired HM Heaters (HTR-1A/B) and returns it hot to the heat exchanger units. 8.7

GAS SENDOUT SYSTEM

After superheating, the sendout gas then passes through the Terminal gas metering station where the flow is recorded before entering the pipeline system. An automated gas sampler is provided to collect and measure the heating value of the gas for use in monthly custody transfer accounting. The natural gas is transported in the Curacao sendout pipeline and delivered to the meter station at each respective gas customer. The sendout system has a robust design pressure rated to ANSI 600 pressure class (1,440 psig). At the peak sendout rate of 137 MMscfd of gas, the calculated inlet pressure to the pipeline is 780 psig. Pressure control of the pipeline is achieved by controlling the LNG flow feeding the Vaporization System with cascade reset of the LNG flow set point being automatically adjusted by the Terminal gas pressure control unit which monitors the sendout gas pressure to the pipeline. 8.8

OPERATIONS CONTROL SYSTEM

Operations control and shutdown of the Terminal facilities will be conducted from a Central Control Room (“CCR”) located at the Terminal site. The Terminal will incorporate world class integrated control and safety systems (“ICSS”) and an information management system that will provide the capability to operate the facility safely, reliably, and at optimum operating conditions at all times. Multiple operator consoles will be provided in the CCR for monitoring and controlling Plant operations. Graphical display of the process flow and operating conditions will be provided from the operator interface consoles. This system will maximize the use of automation to the extent economically justified and minimize local manual control and the need for operator intervention. It will include interfaces to a comprehensive suite of applications for use in monitoring, reporting, troubleshooting, planning, accounting, communicating, etc. The systems will be completely functional for initial facility start-up and will enable the Terminal operator to achieve its objectives for the entire life of the facilities. The operations control system and the CCR are designed for easy integration if the Terminal capacity is expanded. Key objectives of the operating and control design philosophy are as follows:   

Safety of personnel; Protection of the environment; Remote monitoring and diagnosis of the facility and equipment;

8-6 CURACAO CNG-LNG TERMINAL FEASIBILITY STUDY

Section 8 – Conceptual Curacao LNG Terminal

  

Start-up and shutdown of all LNG Plant facilities from the CCR; Maximum use of automation as practicable; and Independent design of the telecommunications system for ship-to-shore communications, LNG unloading activities, Terminal operations and sendout pipeline control.

Operation will be completely automated with separate control and shutdown systems. The Terminal will control the total delivery rate for the pipeline based upon pipeline operating pressure and customer demand. The facility will operate as an integrated system including the Terminal and sendout pipeline facilities. 8.9

UTILITY SYSTEMS

Process Heating Medium System A process Heating Medium System (HM) will be provided to service the process utility heating requirements. The heat transfer fluid will be 30 wt% ethylene glycol aqueous solution used in the closed loop system. Operating conditions for the HM are as follows: 

Hot Supply Temperature:

180°F



Hot Supply Pressure:

55 psig

The equipment comprising the HM System includes: 

1x100% HM Surge Drum (V-5)



2x100% HM Circulation Pumps (P-5A/B)



1x100% HM Storage Tank (TK-2)



1x100% HM Transfer/Unloading Pump (P-6)



2x100% Slip stream HM 5 micron Filters (F-1A/B)



2x100% Direct Fired HM Heaters (HTR-1A/B)

Seawater System A Seawater System will be provided to supply seawater to the LNG Open Rack Vaporizers. Three 50% Seawater Pumps (P-7A/B/C) will be installed on the jetty platform. These pumps will be a vertical can pump design driven by a top mounted electric motor. Minimum flow control protection will be provided. Large self-cleaning seawater intake screen will be provided surrounding the pump inlets. The screens will be designed to meet environmental criteria to prevent small sea life and other biological materials from entering the Seawater System. Velocity through the screens will be limited to 0.5 feet/second. A manual filter screen trap will also be installed at the discharge side of each Seawater Pump. A hypochlorite unit will be provided to chlorinate the seawater which prevents the growth of algae and other biological life forms within the system. Chlorination injection points will be provided at the suction of each Seawater Pump and at the ORVs for “shock chlorination”. Chlorination concentrations will be controlled to comply with the environmental regulations.

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Section 8 – Conceptual Curacao LNG Terminal

Warm seawater is supplied by the pumps at a pressure of 50 psig and flows to the ORV units. Cool seawater exits from the bottom collection basin of the ORV at a temperature of approximately 65oF (18.3oC) and flows by gravity to the seawater outflow discharge back into the sea. The seawater outflow discharge pipe returns will be designed to discharge the cool seawater at a subsea depth of approximately 250m where the ambient seawater temperature is approximately equal to the seawater effluent discharge temperature. Environmental regulation guidelines for thermal discharge require that the temperature at the edge of the thermal mixing zone (defined to be 100m from the point of discharge) be within +/-3oC of the natural ambient temperature. A site specific EIAS will need to be prepared to validate compliance with environmental regulation guidelines. Pressure Relief and Flare/Vent Systems Flares/Vents will be sized for the maximum credible relief scenario. The following flare systems are provided: 

HP flare/vent designed for dry and cold vapor and blowdown; and



LNG marine/storage flare/vent designed for low pressure boil-off gas from the storage and jetty.

Flare/Vent systems will be designed for long term reliable operation from the minimum to the maximum flaring/venting rate. Flared/Vented gas will be metered to support environmental reporting requirements. Design of the flare/vent stacks should make allowance for a solar radiation contribution of 0.8 kW/m2. The flare/vent tips will be located such that the radiation limits specified in API RP 520 and API RP 521 are not exceeded. Radiation level from the flares/vents will be limited to the following maximum radiant heat exposure criteria: 

Base of flare/vent stack

9.46 W/m2



Sterile area boundary

6.31 W/m2



Flare/Vent knock-out drum

4.73 W/m2



Nearest process equipment limit

3.15 W/m2



Areas where operators work continuously

1.58 W/m2

The HP flare/vent stack will be an elevated derrick supported structure. All flare/vent stacks will be retractable type that provides flexibility to lower down tips for maintenance. The HP flare/vent system will be designed to accommodate future expansion. The HP flare/vent system design will also facilitate controlled depressurisation of the sendout pipeline and pig launcher. A mechanical interlock PSV valve locking system (uniquely keyed) will be installed for pressure relief services equipped with multiple PSVs to ensure clear indication to operating personnel that an adequate number of PSVs are on-line. Fuel Gas System The Fuel Gas Supply System will be designed in combination with all consumers to enable all possible fuel gas composition changes due to operational upsets to be effectively managed without resultant loss of consumers. Fuel gas heaters will be provided for both cold start and normal operation.

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Section 8 – Conceptual Curacao LNG Terminal

The Fuel Gas System provides gas for the HM Heaters as well as blanket gas and purge gas for to the flare headers. Where possible, blanketing gas/pad gas uses nitrogen rather than fuel gas. The required minimum fuel gas pressure is 30 psig. For startup, fuel gas is provided from the BOG system. Since electrical power will be supplied from the Aqualectra power grid, BOG compressors (driven by electric motors) will be operable for cold start. Utility and Instrument Air System Compressed air will be provided to supply utility air and to feed the instrument air-dryer package for the production of instrument air and nitrogen for the Terminal. Compressed air will be supplied from two electric motor driven air compressor packages, each of which is capable of supplying 100% of the total air required for the Terminal. All compressors will supply oil-free air. Utility Air will meet the following specifications: 

Pressure

140 psig



Maximum Temperature

130°F

Instrument quality air will be produced by an instrument air-dryer package (2 x 100% packages). Instrument Air will meet the following specifications: 

Normal Pressure

125 psig



Minimum Pressure

85 psig



Maximum Temperature

130°F



Maximum Dew point

-40°F

The Instrument Air Receiver and Plant Air Receiver will be sized to provide a minimum of 15 minutes of surge capacity between the normal and minimum operating pressures based on the design air flow rates including design margin. Compressed air prioritization and secured instrument air supplies shall be implemented to maximize instrument air availability. Nitrogen System A nitrogen generating system will be furnished to supply the nitrogen requirement for the equipment purging, pad gas, compressor gas seal, blanketing, inerting and additional requirements during shutdown and turnarounds. The primary system (a membrane-type, or equal) will use instrument air for nitrogen generation, and shall contain multiple membrane units such that one individual membrane unit can be removed from service while the balance of the membranes continue to supply nitrogen at the full design rate. Nitrogen produced will meet the following specifications: 

Supply pressure

110 psig



Maximum Oxygen Content

1.5% - 4%



Minimum Nitrogen Content

96% - 98.5%



Oil & Hydrocarbon Content

None



Maximum Water Content

30 ppmv

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Section 8 – Conceptual Curacao LNG Terminal

The nitrogen generating system uses dehydrated instrument air as feed gas. The instrument air is from an instrument air-dryer package that continuously delivers -40ºF dew point air at normal operating pressure. Using the dried instrument air as the feed to the nitrogen generator ensures that the nitrogen produced is sufficiently dry for the various applications and operations within the LNG Plant. A secondary (back-up) liquid nitrogen system may be provided, designed to furnish the nitrogen requirements for startup purging. Wastewater Treatment Wastewater generated from the operation of the Terminal will include sanitary sewage, oily storm water, process oily water and clean storm water runoff. The collection, treatment, reuse and/or discharge of the wastewater shall be designed to meet the effluent discharge limits established by the regulatory authority. Bulk Storage HM storage (ethylene glycol/water solution) will be sized based on 6 months of average HM losses, considering that the volume of the standard delivery container is 20 m3. Diesel fuel will be stored on site for supply to diesel engine driven equipment including the firewater pumps and the emergency generator. Storage volume shall be sized to hold the volume from one large road tankers (34 m3 capacity). Storage for other miscellaneous bulk chemicals required in operating the facility such as lube oil will be provided. Electric Power Supply and Distribution Primary electric power required during the construction and operational phases of the project will be supplied from Aqualectra’s power grid. The maximum peak power demand for the Terminal will be approximately 5,250kW when a ship is unloading. During normal operations, power demand will be approximately 1,800kW. The electrical power distribution will be supplied at the voltages and frequency listed in Table 8.9-2. Table 8.9-2 Electrical Power Distribution Frequency Service Medium Voltage Power

Low Voltage Power

Voltage

Phase

(Hz)

6.6 kV

3

50

11 kV

3

50

220 V

1

50

380 V

3

50

Emergency power will be supplied from a diesel driven Emergency Generator to be installed at the Terminal. The calculated emergency power load is approximately 625kW. The critical services that are included in the emergency power load are shown in Table 8.9-3. An uninterruptible power supply (“UPS”) will be installed to provide a reliable source of power for:  Critical instrumentation and control;  Security;  The telecommunication systems;  Fire and gas detection;

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Section 8 – Conceptual Curacao LNG Terminal

 ESD systems; and  Emergency lighting. The batteries for all of the UPS systems will be sized based on supplying the rated load of the UPS for a minimum of 30 minutes. Table 8.9-3 Emergency Power Distribution Frequency Service

Voltage

Phase

(Hz)

kW

Instrument Air Package

380V

3

50

75

Jockey Water Pump

220V

3

50

2

Large Stormwater Sump Pump

380V

3

50

105

Small Stormwater Sump Pump

380V

3

50

10

Unloading Platform

220V/110V

1

50

20

Control Room

220V/110V

1

50

36

Office

220V/110V

1

50

36

Workshop/Warehouse/Lab

220V/110V

1

50

96

220V

1

50

200

MCC Building

220V/110V

1

50

36

Guard House

220V/110V

1

50

9

Terminal & Jetty Lighting

Total Emergency Load

625

Lightning protection and transient over-voltage will be provided in accordance with applicable codes and standards. Water Supply Systems There is no identified source of ground or well water available at the Terminal site. Water supply to the Terminal will be required for wash water, potable water and sanitary use. Additional information must be gathered to determine the best method for supplying water to the Terminal. Aqualectra may currently have water supply sources currently available at the existing Bullen Bay Oil Terminal Facility which can be tapped into for use at the LNG Terminal. 8.10

SAFETY SYSTEMS

Fire Protection System The fire protection system will comprise a combination of passive techniques and active techniques. Passive fire protection functions without relying on external intervention and is implemented where immediate protection is required. Passive protection operates only for a limited period of time. In case of a long duration fire, active fire protection and fire-fighting must also be deployed. The design of the active fire protection system is based on the assumptions that (i) there will be only one major fire at any one time and fires will not occur simultaneously at different places within the facility, and (ii) external fire-fighting resources are not available in case of an emergency within the premises. The system will be designed around maximum use of fixed fire-fighting systems such as water spray systems, which do not require fire-fighting vehicles or trained personnel for water or foam solution

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Section 8 – Conceptual Curacao LNG Terminal

supply. In addition to the facility fire water system described previously, additional fixed and portable fire-fighting equipment is provided at identified potential hazards. The Marine Terminal Control Shelter at the jetty which is remote from the main facility will be provided with a fixed clean agent fire extinguishing system, as are any sub-floors in local MCC rooms that cannot be quickly accessed. The overall arrangement for the firewater system will provide deluge systems in selected areas, remote controlled fire monitors, and fire hydrants. A firewater ring main will cover the Terminal vaporization and sendout facilities, the LNG storage area, marine jetty facilities, and infrastructure buildings. A firewater storage tank will be provided with a total combined capacity for 8 hours of firewater supply. Two 100% percent freshwater main firewater pumps (diesel) rated at 5,000 gpm each will be provided along with two 100% freshwater jockey pumps. In case of a prolonged incident where the firewater requirement exceeds the storage capacity, an auxiliary firewater connection is provided at the jetty for external seawater supply from fire fighting marine vessels. All main firewater pumps will have the capability of being automatically started upon low ring main pressure and manually by switches for each pump located local to the pump and in the control room. Portable foam units located on the jetty and around the Terminal will be used to control spills and fires in LNG spill containment areas (at the LNG storage area, LNG loading platform, and spill containment sumps). Portable fire extinguishers will also be located strategically throughout the facility. A Terminal fire truck will be provided for response to incipient fires and grass fires. Fire and Gas Detection System A fire and gas detection system (F&G system) will be provided to continuous monitor and alert personnel when fire, smoke or gas release is detected. The function of the F&G system will be to: 

Detect the presence of fire or loss of containment of flammable gas and the ingress of smoke or flammable gas into areas where it may present a hazard;



Allow manual alarm initiation by personnel throughout the installation by means of manual alarm call points;



Alert the central control room of any fire or flammable gas leak;



Give local warning alarm to the specific area/building where the alarm initiating device(s) is activated; and



Provide a plant-wide warning alarm upon confirmed fire or gas alarm.

In general, the F&G system raises alarms only, rather than directly initiating executive actions. Automatic activation of fire protection systems is determined on an individual basis. Emergency Shutdown System The Emergency Shutdown System (“ESD”) will be designed to provide for the protection of personnel, environment, and equipment by providing the safe shutdown of the Plant and/or process equipment during a hazardous event. Shutdown, isolation of process inventories into manageable volumes and depressuring will be used to manage and limit escalation of any event.

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Section 8 – Conceptual Curacao LNG Terminal

Emergency Evacuation The plot plan and layout will be designed to ensure adequate emergency escape routes. A minimum of two evacuation routes must be provided for pipe racks, structures, and major access platforms. Escape routes of all buildings will be designed in accordance with NFPA 59A. LNG Spill Impoundment System NFPA 59 A (2009 Edition) section 5.3.2.1 specifies that each impounding system serving an LNG storage tank must have a minimum volumetric liquid capacity of 110 percent of the LNG tank’s maximum design liquid capacity for an impoundment serving a single tank. This design for the Curacao Terminal proposes to use a “full containment” LNG storage tank in which the outer tank wall serves as the impoundment system. The volumetric capacity of the outer concrete wall will exceed the 110% percent requirement. The process area impoundment basin will be located in the process area, and spills from the LNG tanks, process area equipment, and portions of the unloading line will be routed to the process area impoundment basin by a series of collection troughs. An impoundment basin will not be required for the LNG transfer lines and jetty since vacuum jacketed insulated pipe will be used. The outer wall of the vacuum jacketed insulated LNG transfer line will serve as the secondary containment in the event of failure of the inner pipe. Both the inner pipe and outer pipe of the vacuum jacket insulated pipe will be fabricated from 304L stainless steel and will therefore have a minimum design temperature rating well below the LNG temperature. Both the Darwin and Freeport LNG facilities have used vacuum jacketed insulated pipe with excellent results and no issues. The impoundment basin in the process area will be sized for a design spill rate based on Section 5.3 NFPA 59A (2009 Edition). A spill of a 10-minute duration at the design spill rate will define the volume required for the process area impoundment sump. This volume is relatively small. The maximum LNG sendout rate to the BOG Condenser and LNG Vaporization system is 250m3/hr. A 10-minutes spill would result in a required impoundment volume of approximately 41m3. The approximate dimensions of the process LNG impoundment sump would be approximately 12’x12’ and approximately 10’ deep. The proposed terminal would also be designed to provide drainage of water to disposal areas in accordance with NFPA 59 A (2009 Edition) section 5.3.2. Drainage and disposal of water would be accomplished by a series of ditches and swales. Water that is collected within the curbed LNG containment areas would be directed by gravity to the LNG impoundment trenches and eventually to the impoundment basin. Stormwater pumps in the impoundment basins would remove the water at a rate equal to or greater than 25% percent of the 10-year frequency, one-hour duration storm. The pumps would discharge the water into the Terminal storm drainage system. The stormwater pumps would be automatically operated via level control and would be interlocked using low temperature detectors to prevent the pumps from operating if LNG would be present. LNG Hazards LNG’s principal hazards result from its cryogenic temperature (-260°F), flammability, and vapor dispersion characteristics. As a liquid, LNG will neither burn nor explode. Although it can cause freeze burns and, depending on the length of exposure, more serious injury or death, its extremely cold state does not present a significant hazard to the public, which rarely, if ever, comes in contact with it as a liquid. As a cryogenic liquid, LNG will quickly cool materials it contacts, causing extreme thermal stress in materials not specifically designed for such conditions. These thermal stresses could subsequently subject the material to brittleness, fracture, or other loss of tensile strength. These hazards, however, are not substantially different from the hazards associated with the storage and transportation of liquid

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Section 8 – Conceptual Curacao LNG Terminal

oxygen (-296°F) or several other cryogenic gases that have been routinely produced and transported in world trade. LNG vaporizes rapidly when exposed to ambient heat sources such as water or soil. When released from its containment carrier and/or transfer system, LNG will generally produce approximately 600 standard cubic feet of natural gas for each cubic foot of liquid. A large quantity of LNG spilled without ignition would form a vapor cloud that would travel with the prevailing wind until it either dispersed below the flammable limits or encountered an ignition source. If a large quantity of LNG is spilled in the presence of an ignition source, the resulting pool fire would produce high levels of radiant heat in the area surrounding the LNG pool. A rapid phase transition (RPT) can occur when a portion of LNG spilled onto water changes from liquid to gas, virtually instantaneously. Unlike an explosion that releases energy and combustion products from a chemical reaction, an RPT is the result of heat transferred to the liquid inducing a change to the vapor state. The rapid expansion from the liquid to vapor state can cause locally large overpressures. RPTs have been observed during LNG test spills onto water. In some test cases, the events were strong enough to damage test equipment in the immediate vicinity of the LNG release point. The sizes of the overpressure events have been generally small and are estimated to be equivalent to several pounds of trinitrotoluene (TNT). Although such a small overpressure is not expected to cause significant damage to an LNG carrier, the RPT may increase the rate of LNG pool spreading and the LNG vaporization rate for a spill on water. Methane vapors, the primary component of natural gas, are colorless, odorless and tasteless, and are classified as a simple asphyxiant. Methane vapors may cause extreme health hazards, including death, if inhaled in significant quantities within a limited time. Although very cold methane vapors may cause freeze burns, any cloud resulting from an LNG spill would be continuously mixing with the warmer air surrounding the spill site. Dispersion modeling indicates the majority of the cloud would generally be within 25°F of the surrounding atmospheric temperature, with colder temperatures closest to the spill source. In addition, this modeling estimates that most of the cloud would be below concentrations resulting in oxygen deprivation effects, including asphyxiation, with the highest methane concentrations closest to the spill source. Therefore, asphyxiation and freezing normally represent a negligible risk to the public from LNG facilities. Although LNG will not burn, methane vapors in a 5% to 15% mixture by volume with air are flammable. Once a flammable vapor-air mixture from an LNG spill has been ignited, the flame front will propagate back to the spill site if the vapor concentration along this path is sufficiently high to support the combustion process. Combustible materials within the flammable portion of the cloud may be within the flame and could be ignited. However, any events leading to a containment failure would most likely be accompanied by a number of ignition sources. The result would be an LNG pool fire, and subsequent radiant heat hazards, rather than the formation of a large unconfined vapor cloud. Although, LNG is not explosive as it is normally transported and stored, natural gas vapors (primarily methane) can explode if contained within a confined space, such as a building or structure, and ignited. Occasionally, various parties have expressed the energy content of an LNG storage tank or LNG carrier in equivalent tons of TNT, as an implied measure of explosive potential. However, such a simplistic analogy fails to consider that explosive forces are not just a function of the total energy content but also of the rate of energy release. For a detonation to occur, the rate of energy release must be nearly instantaneous, such as with a TNT charge initiated by a blasting cap. Unlike TNT or other explosives which inherently contain an oxidizer, an unconfined vapor cloud must be mixed with oxygen within the flammability range of the fuel for combustion to occur. For a large unconfined vapor cloud, the flammability range tends to

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Section 8 – Conceptual Curacao LNG Terminal

exist at the mixing zone at the edges of the cloud. When ignited, flame speeds about 20 to 25 meters per second (66 to 82 feet per second) and local over pressures up to 0.2 psig have been estimated for unconfined methane-rich vapor clouds. These are well below the flame speeds and over pressures associated with detonation. The potential for unconfined LNG vapor cloud detonations was investigated by the U.S. Coast Guard in the late 1970s at the Naval Weapons Center at China Lake, California. These experiments, as well as other subsequent tests, are mentioned in Appendix C of the Sandia National Laboratories report entitled, Guidance on Risk Analysis and Safety Implications of a Large Liquefied Natural Gas (LNG) Spill Over Water, December 2004 (2004 Sandia Report). Using methane, the primary component of natural gas, several experiments were conducted to determine if unconfined vapor clouds would detonate. The tests indicated unconfined methane-air mixtures could be ignited, but no test produced unconfined detonation. There is no evidence suggesting that methane-air mixtures will detonate in unconfined open areas. Further tests were conducted in the late 1970s to examine the level of sensitivity of an unconfined cloud to the presence of heavier hydrocarbons such as ethane and propane. As stated in Section 5 of Appendix C of the 2004 Sandia Report, detonation sensitivity is affected by the level of refinement of natural gas stored as LNG. The series of tests on ambient-temperature fuel mixtures of methane-ethane and methanepropane indicated that the addition of heavier hydrocarbons influenced the tendency of an unconfined vapor cloud to detonate. Less processed product with greater amounts of heavier hydrocarbons is more sensitive to detonation. During these experiments, all successful detonations were initiated with an explosive charge in well mixed vapor clouds at correct stoichiometric proportions. These are not representative of conditions which would be expected during a large-scale LNG spill. The precise timing, necessary mixing, and required amount of initiating explosives render the possibility for detonation of a large unconfined vapor cloud as unrealistic. Detonation of the unconfined natural gas cloud is extremely difficult to achieve and is generally considered by scientists and researchers to be very unlikely to occur during an LNG spill. Consequently, the primary hazards to the public from an LNG spill either on land or water would be from dispersion of the flammable vapors or from radiant heat generated by a pool fire. Thermal Exclusion Zone If a large quantity of LNG is spilled in the presence of an ignition source, the resulting LNG pool fire could cause high levels of radiant heat in the area surrounding the impoundment. Exclusion distances for various flux levels will need to be calculated during FEED according to NFPA 59A (2009 Edition) section 5.3.3 using available software models such as the "LNGFIRE III" computer program model developed by the Gas Research Institute. NFPA 59A establishes certain atmospheric conditions (0 mph wind speed, 70°F, and 50 percent relative humidity), which are to be used in calculating the distances. However, Part 193.2057 supersedes these requirements and stipulates that wind speed, ambient temperature, and relative humidity which produce the maximum exclusion distances must be used, except for conditions that occur less than 5% of the time based on recorded data for the area. Based on preliminary estimates, Shaw Consultants concluded that the thermal exclusion zone from a fire centered at the LNG storage tank would present no issues based on the size of Parcel A and the proposed location of the LNG tank assuming that a “full containment” type tank is installed. However, rigorous thermal exclusion zone calculations have not been performed. Thermal exclusion zones will need to be confirmed by rigorous calculations in subsequent design work.

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Section 8 – Conceptual Curacao LNG Terminal

Vapor Dispersion Zone A large quantity of LNG spilled without ignition would form a flammable vapor cloud that would travel with the prevailing wind until it either dispersed below the flammable limits or encountered an ignition source. Sections 5.3.3.6 of NFPA 59A (2009 Edition) require that provisions be made to minimize the possibility of flammable vapors reaching a property line that can be built upon and that would result in a distinct hazard. Code requires that dispersion distances be calculated for a 2.5% average gas concentration (one-half the lower flammability limit [LFL] of LNG vapor) under meteorological conditions which result in the longest downwind distances at least 90% of the time. Alternatively, maximum downwind distances may be estimated for stability Class F, a wind speed of 4.5 mph, 50% relative humidity, and the average regional temperature. The section allows the use of the DEGADIS (Dense Gas Dispersion) Model, or the FEM3A model, to compute dispersion distances. Design spills into impounding areas serving LNG containers, transfer systems, and piping are to be determined in accordance with Table 5.3.3.7 of NFPA 59A (2009 Edition). In accordance with the code, an average concentration of methane in air of one-half of the LFL cannot cross the property line from a design spill into the tank impoundment. Based on preliminary estimates, Shaw Consultants concluded that the vapor dispersion zones around the spill impoundment sumps as located in the layout will meet these requirements. However, rigorous vapor dispersion calculations have not been performed. Vapor dispersion zones will need to be confirmed by rigorous calculations in subsequent design work. Quantitative Risk Assessment (QRA) Study A HAZOP will need to been performed during FEED for each of the systems that comprise the Terminal facility. A full QRA study will need to be completed during detail design. 8.11

SECURITY SYSTEMS

The Terminal will have an 8-foot high security fence surrounding the facility. Access to the facility will be controlled by guarded entry. Video security cameras will be provided at key locations to allow the security guard to monitor the Terminal from the guard access building. Display from the security cameras will also be provided in the central control room. Lighting will be provided through out the Terminal and at the marine jetty facilities. 8.12

BUILDINGS AND INFRASTRUCTURE

The following infrastructure will be provided at the Terminal: 

Office/Central Control Room Building with Employee Parking;



Parking Area for Jetty;



Work Shop/Warehouse/Lab Building;



MCC Building;



Sheds for BOG Compressors and Ship Vapor Return Blowers; and



Entry Guard House.

8.13

LAYOUT PLOT PLAN

Layout drawings were developed for the Curacao LNG Terminal. The layout was based on using Parcel “A” located adjacent to Jetty No.1 at Bullen Bay. The drawings are included in Appendix C of this

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Section 8 – Conceptual Curacao LNG Terminal

report. Since the LNG FSRU option is still being considered as the leading option, a layout drawing was prepared for that option. The layout drawings should be considered as CONCEPTUAL in nature and subject to change as future detail design work is completed.

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Section 9 – Conceptual Curacao Gas Sendout Pipeline

9.1

OVERVIEW

A gas sendout pipeline will need to be constructed to transport gas from the LNG Terminal at Bullen Bay to the Curacao customers located in and around the Isla Refinery. The Curacao customers include:   

Aqualectra Power Plant(s); CRUC Power Plant(s); and Isla Refinery Process Utility Steam Boilers.

This section of the report provides a brief description of the new Curacao gas sendout pipeline. This is a very preliminary conceptual design and significant additional work is required to fully define the sendout pipeline. A new survey will be required to confirm right-of-way, topography, possible encroachment, and soil characteristics along the route. 9.2

ROUTE

The new gas sendout pipeline will utilize the right-of-way of the existing oil pipeline which traverses from the Curacao Oil Terminal at Bullen Bay to the Isla Refinery. The existing oil pipeline is still in service to deliver crude from Bullen Bay to the Isla Refinery. The measured length of the route is 7.86 miles. The overall pipeline route is shown in Figure 9.2-1. Mile Posts are shown in Figure 9.2-2 through Figure 9.2-9. The oil pipeline is above ground except at road crossings. The new gas sendout pipeline will be a buried line with minimum backfill cover of 1 meter. Each road crossing will be cased and vented. There are approximately twelve road crossing. Figure 9.2-1 New Gas Sendout Pipeline Route

0.0

1.0

2.0

3.0

4.0

5.0 6.0

7.0

7.9

9-1 CURACAO CNG-LNG TERMINAL FEASIBILITY STUDY

Section 9 – Conceptual Curacao Gas Sendout Pipeline

The pipeline route between mile posts (MP) 0.0 and 1.0 is in open country. The pipeline comes within approximately 80 meters of a small residential area located approximately half way between MP0.0 and MP1.0.

Figure 9.2-2 Gas Sendout Pipeline Mile Post 0.0 – 1.0

9-2 CURACAO CNG-LNG TERMINAL FEASIBILITY STUDY

Section 9 – Conceptual Curacao Gas Sendout Pipeline

The pipeline route between mile posts MP1.0 and MP2.0 is in open country. The pipeline comes within approximately 95 meters of a small rural residence located south of MP2.0.

Figure 9.2-3 Gas Sendout Pipeline Mile Post 1.0 – 2.0

9-3 CURACAO CNG-LNG TERMINAL FEASIBILITY STUDY

Section 9 – Conceptual Curacao Gas Sendout Pipeline

The pipeline route between mile posts MP2.0 and MP3.0 parallels the highway crossing St. Michiels Bay on the bridge sholder. The pipeline comes within approximately 115 meters of a residential area north of St. Michiels Bay. At MP3.0, the pipeline route enters a dense residential area.

Figure 9.2-4 Gas Sendout Pipeline Mile Post 2.0 – 3.0

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Section 9 – Conceptual Curacao Gas Sendout Pipeline

From MP3.0 to MP4.0, the pipeline route passes through a dense residential area.

Figure 9.2-5 Gas Sendout Pipeline Mile Post 3.0 – 4.0

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Section 9 – Conceptual Curacao Gas Sendout Pipeline

From MP4.0 to MP5.0, the pipeline route is passes on the north side of Piscadera Bay. The Google satellite photo indicates the area to be open, but it was taken October 2, 2007. Since that time, there may have been residential development in this area. Piscadera Bay area is used for recreation.

Figure 9.2-6 Gas Sendout Pipeline Mile Post 4.0 – 5.0

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Section 9 – Conceptual Curacao Gas Sendout Pipeline

Most of the pipeline route from MP5.0 to MP6.0 appears to be in open country with the last 1/3 mile passing through a commercial/residential area. MP6.0 is within the security fence of the Isla Refinery.

Figure 9.2-7 Gas Sendout Pipeline Mile Post 5.0 – 6.0

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Section 9 – Conceptual Curacao Gas Sendout Pipeline

MP6.0 to MP7.9 is on Isla Refinery property. The route of the pipeline shown is preliminary. Additional work with Isla Refinery will be required to identify the actual path of the pipeline. It is very likely that the pipeline will be above ground using existing pipe rack space available.

Figure 9.2-8 Gas Sendout Pipeline Mile Post 6.0 – 7.0

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Section 9 – Conceptual Curacao Gas Sendout Pipeline

Figure 9.2-9 Gas Sendout Pipeline Mile Post 7.0 – 7.9

Shaw Consultants did not walk the existing pipeline route. However, Right-of-Way drawings were furnished by RDK and were used to prepare the preliminary pipeline route figures. RDK advised Shaw Consultants that there may be some minor encroachment on the pipeline easement, but this will not be an issue that will impede construction of the new gas sendout pipeline based on discussion with RDK. 9.3

SIZE, CAPACITY AND DESIGN PARAMETERS

The new gas sendout pipeline is designed to provide a gas delivery capacity of up to 137 MMscfd of natural gas based on an inlet pressure of 780 psig at Bullen Bay and a minimum outlet delivery pressure of 500 psig at the customers’ meter stations located in the vicinity of MP7.9 in the Isla Refinery. The size of the pipeline will be a 12.75-inch OD line. The design of the pipeline outside the Isla Refinery fence will be designed in conformance with ANSI B31.8. Wall thickness calculations (ANSI B31.8) have assumed that the entire pipeline route could eventually be a densely populated residential area requiring greater wall thickness for public safety than

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Section 9 – Conceptual Curacao Gas Sendout Pipeline

pipe laid in open country. Inside the refinery fence, the pipeline will be designed in conformance with ANSI B31.3. The pipe required for this pipeline will be a 0.500-inch wall thickness grade X-65 seamless steel pipe. A minimum corrosion allowance of 0.050-inch is provided. The pipeline will also be protected from corrosion by an electrically induced cathodic protection system. The pipe joints will all be coated with a robust epoxy coating system. The MAOP of the pipeline outside the refinery fence will be 1,440 psig and will be buried to a minimum depth of 1.0 meter from Bullen Bay to the Isla Refinery pipe rack. Within the refinery fence the MAOP is derated to 1,245 psig since it is design rated per the refinery piping code (ANSI B31.3). A pig launcher and receiver will be provided such that the pipeline can be pigged from the inlet at Bullen Bay to the Isla Refinery fence. The system is designed to accommodate “smart” pigs. 9.4

CONSTRUCTABILITY

The sendout gas pipeline will be designed with back fill coverage of 1.0 meter. Weathered rock is expected to be encountered over much of the pipeline length. It is anticipated that much of the pipeline can be installed using conventional trenching methods for weathered and fractured rock. Where harder rock is encountered, it is anticipated that rock excavation can be achieved using backhoe mounted hydraulic rams and conventional excavators. The width of the existing Right-of-Way (ROW) easement from Bullen Bay to the Isla Refinery fence is 10 meters wide. This is a relatively narrow ROW and it will be challenging pipe lay construction. However, Shaw Consultants is of the opinion that it will not present significant constructability issues. The oil pipeline is not buried and is sitting on ground sleeper supports. Depending on the position of the existing oil pipeline, the oil line may have to be moved to facilitate ditching equipment for installing the new gas sendout pipeline. The oil line is fairly old and RDK may want to consider replacing it when the new gas pipeline is installed. However, no costs have been included to replace the existing oil pipeline. 9.5

PIPELINE OPERATIONS CONTROL

Pressure letdown regulators will be provided at each of the customer’s meter delivery stations to maintain fuel pressure supply to the customer’s facility. Inlet pressure to the gas sendout pipeline at Bullen Bay will be controlled by pressure control within the LNG Terminal. Telecommunication systems will be installed at each of the customer meter stations to monitor gas delivery volumes, pressure, and temperature. This data will be transmitted to the central control room at the LNG Terminal and available to the operator from the display control consoles. If in the unlikely event the LNG Terminal experiences an outage, the LNG Terminal operators will contact each gas customer to alert them as to how long gas deliveries will be interrupted. Each customer is expected to have a backup fuel oil system capable of fueling its facilities for a period of up to seven (7) days without gas supply.

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Section 10 – Operations and Maintenance

10.1

OVERVIEW

In developing guidelines for the planned the operation and maintenance of Curacao LNG Project, Shaw Consultants has limited its focus to the stand-alone LNG import terminal. The FSRU option will likely be contracted to include operations and maintenance of the facilities and the pipeline has lower operational staff requirements the terminal provides the largest responsibility to the RDK organization. We anticipate that the majority of the terminal O&M staff personnel will be permanent employees of RDK. However, we also expect that major maintenance and surveillance activities will be subcontracted out to original equipment manufacturers and specialty maintenance organizations generally following the patterns and practices established at the refinery. Operations and maintenance (“O&M”) programs, including proposed O&M budgets are very preliminary at this point and will depend on the mixture of permanent personnel and contract operators actually employed. Nevertheless, since this is a new grassroots facility, all personnel will be new and will require comprehensive training during the construction, and mechanical acceptance periods. 10.2

PERSONNEL TRAINING

The presence of a mature operating refinery on Curacao provides a legacy of workers with experience in operations and maintenance of petroleum facilities. Requirements at an LNG regasification terminal are different from those of a refinery but are in many cases intrinsically simpler. Shaw Consultants does not consider that developing a workforce with the necessary skills will be a major problem. In our new owners with no previous LNG regasification experience often include a substantial amount of the training both for operations and maintenance as part of the EPC Contract to be provided by the Contractor. At least one year ahead of the expected completion date, the EPC contractor can provide a complete technical training plan outlining the curriculum, content and schedule of the training program. This program can also include as part of the contract price the following manuals and training:      

Startup manual and startup procedures; Operating procedures including startup, shutdown, normal, upset, and emergency procedures; Initial training for all operations personnel; Accommodations in which to conduct the training; Equipment training, maintenance training, maintenance procedures; Equipment training provided by vendor specialists.

Such training would conform to normal industry practices, and could also include support or onshore pipeline operations and metering at customer sites. In addition to the Operations and Maintenance RDK will also require staff for normal business and accounting functions as well as analytical and general office administration to ensure the efficient and cost effective operation of the business. Again, these aspects are not considered unduly onerous nor likely to present problems to RDK. 10.3

OWNER STAFFING AND LABOR COSTS

The overall staffing plan for the terminal facility has not been developed at this stage of the Project. However, based on information from recent terminals an initial schedule has been formulated below. This schedule includes those permanent employees in the administrative, operations, and maintenance

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Section 10 – Operations and Maintenance

departments that we would expect to be hired. The schedule may be modified depending on the level of out-sourcing normally accepted in Curacao but it provides RDK with a “sanity check” when considering development of alternatives. We estimate that a grass-roots terminal with the small send-outs proposed will require between 50 and 70 people. The range recognizes that many of the administrative functions by be efficiently combined with existing RDK administration if the volume of work does not justify duplication at the terminal site. At this time, Shaw Consultants has not calculated the costs of this organization but based on wages and salaries applicable along the US Gulf Coast we expect costs to average about $3.5 million per year at current prices. Table 10.3-1 Curacao LNG Terminal Initial Staffing Position/Job Function (* Shift Position)

Plant Manager

Employee Count 1

Admin Asst

1

Admin Manager

1

Admin Assistant

1

Accounting/Procurement

2

Warehouse Supt

1

Stock Clerk

2

EHS Superintendent

1

Safety Technician

1

*Security officers

12

Administrative Subtotals

23

Marine Manager

1

Admin Assistant

1

Engineering Manager

1

Admin Assistant

1

Plant Engineer

1

DCS Technician

1

IT Technician

1

Chemist/Environ Tech

2

Document Clerk

1

Operations Manager

1

*Shift Supervisor

4

*Panel Operator

4

* Loading Operator

4

*Field Operator

4

Operations Subtotals

27

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Section 10 – Operations and Maintenance

Position/Job Function (* Shift Position)

Maintenance Manager

10.4

Employee Count 1

Maintenance Engineer

1

Admin Assistant

1

Bldg & Grounds Supt

1

Laborer/Roustabout

4

Mechanics/Millwrights

2

Asst Mechanics

2

I&E Technicians

2

Electricians

2

Pipefitter/Welder

2

CMMS Planner

1

Maintenance Subtotals

19

GRAND TOTALS

69

OPERATIONS & MAINTENANCE BUDGET

Overall operations and maintenance costs for the terminal will vary depending on the activity. The throughput of the facility is expected to grow as time progresses but is always likely to be lower than most comparative LNG regasification terminals. Based on Shaw Consultants’ experience at similar LNG receiving and regasification terminals of similar design, the average O&M cost appears to equate to approximately US$0.04 per MMBtu.

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Section 11 – Integrated System Performance

11.1

RELIABILITY

Conceptual design of the LNG Terminal embodies an N+1 sparing philosophy for all major equipment critical for maintaining gas sendout. Although a RAM analysis has not been made, Shaw Consultants estimates that the online-reliability of the Curacao integrated gas delivery system to be 99.0% based the conceptual design developed for this study. The only failure within the LNG Terminal that could result in an extended outage would be a failure of the LNG storage tank. It is highly unlikely after commissioning that an LNG tank failure might occur with the probability of occurrence estimated to be 1x10-4. Delays in LNG cargo delivery due to tropical storms or hurricanes are not expected to have any impact on gas sendout reliability. The 160,000m3 LNG storage tank, planned ullage, and the shipping schedule will assure a minimum storage margin of at least 5 to 8 days which will provide more than enough time for rerouting the LNG ship around the storm event. Shaw Consultants estimate that LNG supply reliability should be at least 99.5% taking into consideration a ship load of LNG will only be required every 27 to 29 days based on 135,000m3 cargo sizes. It will be critical to contract with a reputable company to assure reliable supply and scheduling of LNG deliveries to Curacao. In selecting a LNG supplier, RDK will want to obtain information on the company’s track record performance for meeting LNG delivery obligations. The objective would be to select a company having a 99+% on-time delivery track record. The gas sendout pipeline will be a typical pipeline system which historically has extremely high reliability (greater than 99.5%). 11.2

BACKUP FUEL SUPPLY

The gas customers are expected to have a backup fuel supply system for each of their facilities. Since fuel oil is currently being used in these facilities, it is assumed that the existing fuel oil tankage and supply pumps will be available for use as a backup to natural gas. This assumes that upon conversion to natural gas, the converted facilities have dual fuel capability (natural gas and LSFO). The backup fuel supply should be designed to provide up to seven (7) days of continuous operation without natural gas. 11.3

TURNDOWN FLEXIBILITY

The LNG Terminal is designed to have a minimum turndown capacity of 20 MMscfd of sendout gas. When a ship is unloading LNG, the offloading rate must be reduced to approximately 4,500m3/hr. Otherwise, the BOG exceeds the gas sendout rate of 20 MMscfd. At an LNG unloading rate of 4,500m3/hr, charges for demurrage will likely be incurred. No LNG is required from the LNG tank at this low turndown rate when a ship is unloading cargo. All of the sendout gas is provided from BOG which must be compressed by the BOG Pipeline Compressor to sendout gas pressure. When no ship is unloading, the sendout gas rate can be reduced to 20 MMscfd by adjusting the LNG flow to the vaporization system. At this rate, pumps and control valves are operating at approximately 15% of the design rates which is the lower limit for control stability of the system. 11.4

EXPANDABILITY

The LNG Terminal has been designed with flexibility to easily increase gas sendout capacity. The major flowlines and the flare/vent system have been sized to accommodate double the current sendout capacity. This required a small pre-investment in piping which had virtually insignificant impact in the total

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Section 11 – Integrated System Performance

CAPEX. To double capacity while maintaining the N+1 sparing philosophy requires the installation of the following equipment items:  Add One In-Tank LNG Pump (P-1C);  Add One LNG Sendout Pump (P-2C);  Add One LNG Open Rack Vaporizer (E-1C);  Add One Sendout Gas Superheater (E-2C);  Add Two Seawater Pumps (P-7D/E);  Add One HM Transfer Pump (P-5C); and  Add One HM Heater (HTR-1C). To accommodate future expansion, two spare pump wells have been provided in the LNG Storage Tank. The manifold of all the equipment (pumps, vaporizers, and heat exchangers) include blind flange connections for adding future equipment. Layout space in the Terminal has been reserved for the additional equipment listed above. The LNG Terminal, as currently designed, has the capability to maintain gas sendout at 150% of the design rate (or approximately 205 MMscfd) without installation of additional equipment. However, equipment sparing is less than the N+1 philosophy. The on-line reliability for the integrated LNG Terminal would be approximately 85% at 205 MMscfd sendout if no spares are added. The gas sendout pipeline would have to be looped or a new line laid to the market requiring the expanded sendout capacity. 11.5

CONCLUSIONS

The conceptual designs of the LNG Terminal and gas sendout pipeline are robust and highly reliable. A 99.0% on-line availability can be expected at the design sendout rate. The Terminal sendout can be turned down to 20 MMscfd. At this minimum turndown rate, ship unloading rates will have to be reduced and demurrage charges will likely be incurred. Alternatively, smaller capacity ships could possibly be used during extended periods of low sendout demand to reduce the cost of demurrage. The system can easily be expanded to accommodate future growth and potential other markets such as gas export to Aruba.

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Section 12 – Project Execution Planning

12.1

EXECUTION PLAN FRAMEWORK

The scope of the Curacao LNG Import Project includes supply of the LNG, business development of natural gas use in Curacao together with design, construction and installation of import and regasification facilities and the distribution pipelines to the core users. The development of the on-island facilities is expected to be funded and executed as one project by a new business venture that will be responsible for the long-term operations of the facility. The project effort to design and construct the correct facilities to support the business is a significantly different endeavor from the day-to-day operations. The skills required for this part of the venture are not required once the facility is operation. Classic project execution practices therefore separate these activities enabling each to staff with the appropriate skills at the required point in the business cycle. In the simplest organization a “Venture Team” is appointed to implement the Business. This team defines the requirements, sets the schedules and will operate the business for the duration. The Venture Team appoints a Project Team to design and construct the facilities to meet the business requirements in accordance with the defined schedule and budgets. The Project Team completes this task using external contractors and returns an operating facility to the Venture team. The Project Team then disbands – its goal is to go out of business -successfully. The table below sets out in broad terms the principle activities and philosophies that are generally adopted at each stage of the project as it has moved from initial feasibility to the current state.

Venture Management

Feasibility Identify business opportunities

Basic Development Define project scope & optimize processes

Execution Provide assets to support execution

Assess business alternatives

Set schedules & budgets to meet Business Drivers Negotiate required commercial contracts

Develop Start-up plans

Identify required commercial agreements Evaluate technologies and execution strategies Project Management

Front end engineering and design (FEED)

Set specifications to meet regulatory and reliability requirements Prepare Environmental Impact Assessment

Monitor project progress, cost, quality and timing Award contracts for engineering, procurement and construction Implement Quality Assurance & Control to meet specifications

Start-up Implement start-up plans and business systems Perform and acceptance tests Operate Business

Prepare end-of-job documents and reports Hand over facility to Venture Management Disband

Implement Environmental Management Plans

A system of formal approvals (Management Decision Gates) should be implemented as the Project advances from one phase to the next. These formal reviews ensure that appropriate strategies and conclusions have been developed at each point in the project and provide management with a regular assurance that the final Project continues to meet the business need and has the best chance to:

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Section 12 – Project Execution Planning



Meet the gas supply, sales and availability commitments within the timescale established by the Venture Team and the overall Business Plan;



Provide a reliable development program, regasification facilities and pipeline system that complies with all applicable project specifications, Curacao and industry standards and regulatory requirements;



Design and Construct cost effective facilities that are safe, operable, and maintainable and are consistent with existing infrastructure while conforming to applicable safety, health and environmental standards;



Minimizes impacts to any stakeholder during installation, commissioning and operation of the system.

12.2

Development Planning

As the Project moves from one stage to the next, the focus of the Venture and Project Management teams changes. Different skills are required and a dynamic organization is normal, consistent with good management and delegation of authority. An important consideration in developing the Owner organization is the role that the Owner’s staff will play in the overall management of the Project. Shaw Consultants considers the current organization may not be the best group to staff a Project Management Team (“PMT”). Projects of the magnitude contemplated for an onshore regasification terminal normally require full time multi-discipline teams to provide effective oversight and stewardship of the owner’s resources during the Basic Development and Execution phases. The skills required for this period are unlikely to be present in the current RDK organization. A core Project Management team of about eight senior individuals with different areas of expertise will be required for the Project’s development, with a probable need for additional personnel as the Project progresses through engineering into construction. This PMT could be developed by one (or a combination) of the three basic strategies: 

build an in-house project development group by hiring permanent staff and supplement this core team with short-term agency or contract staff. However, we note that if recruited, this PMT is unlikely to be fully utilized once the Project is complete ;



engage a Project Services Contractor (“PSC”) to which overall project management duties and responsibilities are delegated. The PSC would act on behalf of the Venture organization for all aspects of the work including development of engineering and construction contracts, selection of qualified contractors, and oversight of the Project through engineering, procurement, construction, commissioning and start-up leading to final handover to the permanent business organization.



form a joint venture or partnership arrangement with a large existing gas producer (or distributer) which can provide the appropriate owner management expertise to supplement the RDK organization and assume the role of a PSC and perhaps develop the operating company.

Of these options, the most common route for new Owners is to hire an experienced engineering, procurement and construction (EPC) contractor as a PSC. However, assigning large areas of responsibility to a PSC can also be difficult. Shaw Consultants notes that a PSC may not make its best personnel available to a “once-off” project such as this as most qualified PSCs are often EPC Contractors. They not unnaturally want to keep their best personnel for the execution of their own lump sum EPC contracts. However, successful PSC have the in-house project management systems (procedures and software required to manage large projects) and the experience to successfully implement these procedures and systems in many different environments including those similar to the Curacao regasification terminal.

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Section 12 – Project Execution Planning

In the absence of a Joint Venture with a recognized international gas provider/distributer, Shaw Consultants recommends the appointment of a qualified PSC as the next step should RDK elect to proceed with an onshore regasification terminal. The initial PSC responsibilities should include: 

development of Plant Performance Specifications and guarantees;



development of detailed execution plan including contracting strategy



potential bidder prequalification and development of Contract terms;



issue Invitations to Tender;



evaluation and clarifications of the technical and commercial bid submissions;



review of bids with Owners;



prepare recommendation of Contractor;



provide assistance with contract and negotiations;



provide technical and, as appropriate, commercial support to contracts and agreements required to support the project including feedstock supply, off-take agreements, operating agreements, and dealings with insurance, financial and government entities, etc.

12.3

CONSTRUCTION STRATEGY / PHILOSOPHY

Implementation of the Floating Regasification Option provides a relatively simple forward execution path. However, the Owner remains responsible for the development of the jetty and the export pipeline. For the full onshore regasification facilities this scope is supplemented by the addition of the storage tank and the terminal. Effective implementation of either option requires a defined program to ensure that the work is cost effectively completed according to the schedule. The typical execution stages are: 

Stage 1 – Front End Engineering and Design (“FEED”). A qualified EPC contractor is engaged to develop the design for the LNG terminal and prepare the engineering definition, budgets and documentation to allow permitting and regulatory approvals to be initiated and to serve as a basis to solicit bids for the detailed engineering, procurement and construction of the Terminal. Concurrent with this effort geotechnical studies of the site are concluded and a separate FEED package for the jetty and marine facilities may be developed. . Under the same (or a different) contract another engineering company would be engaged to develop the FEED package for the pipeline and support construction permits for that portion of the work.

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Stage 2 – Bid, Procurement and Permitting. Normal practices include competitive bids for the award of the contract for detailed engineering, procurement and construction of the facilities. This provides transparency in award of the contract and in some locations such competitive bidding is required by local regulations. However, rather than solicit competitive tenders from several qualified engineering and construction contractors, organizations have opted to negotiate a lump sum turnkey contract with the successful FEED contractors. The natural pressures of competition typically yield the best prices on lump sum projects but it is often suggested that the period of several months required for tender development and subsequent evaluation of bids by the owner can extend the overall project schedule. Also, attempts by owners to minimize this period by continuing project development during the bidding period can be counterproductive as engineering progress during this time must be communicated to the successful bidder making it difficult to finalize the contract scope and costs. For the current project where RDK may not be able to commit to a lump sum EPC contract immediately

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after the FEED, a decision to negotiate a price with the FEED contractor could represent a realistic approach to maintaining project momentum by defining the costs to be financed. 

Stage 3 – Detailed Engineering, Construction and Installation. The scope of the EPC contract includes all engineering, procurement, construction, precommissioning, commissioning, start-up and testing of the LNG storage and vaporization facility. The contract should also require the contractor to procure all spare parts and if possible, to train Owner’s operating personnel. The construction of the LNG tank is a specialized skill and depending on the selected contractor, a subcontractor may be appointed with responsibility for design, procurement, construction and cool-down of the LNG tanks. Separate subcontracts are also likely for the construction for the marine facilities. Substantial completion of the terminal facility is likely to be about 36-40 months after a Notice to Proceed is issued to the EPC contractor (normally, at contract award or when finance commitments are obtained). A separate contract (or additional subcontract) may be awarded for the EPC of the gas transmission pipeline. Decisions on the exact execution strategy for the construction and installation of the remainder of the pipeline will depend on the availability of local qualified contractors and it is possible a small number of lump-sum or unit rate contracts with local qualified contractors may be adopted.

As noted earlier, RDK does not have in-house corporate departments with the necessary experience and expertise to oversee the project implementation. This is not uncommon for newly formed or government agencies. To overcome this potential shortcoming, we recommend the appointment of a PSC which will to be a significant benefit to the Project and expect that it will facilitate prompt resolution of the detailed technical and execution queries that inevitably arise during execution of a Project of this nature and provide comfort to potential finance organizations. All recommended options for the Project will utilize established technology. Meteorological conditions for the site are not severe and are well understood. A temporary construction jetty may be fabricated to aid delivery of major equipment and any heavy lifts removing any concerns relating to road access or weight limitations on internal roads. However, this will not obviate the need for increased road traffic throughout the construction period and regular deliveries of materials by road can also be expected. Except for specialized equipment, the majority of the engineering, procurement and fabrication efforts will likely be completed in the Gulf Coast “oil patch” bringing the support of an experienced infrastructure for transport, communications and services. Also, in spite of any up-tic in the general economy, the construction labor market in the vicinity of Curacao remains generally weak and contractors should have little difficulty in importing sufficient workers (in the region of 500) with the appropriate level of skills in a timely manner. Given the proper planning and conscientious execution, Shaw Consultants does not expect logistics to be a major concern or to detrimentally impact timely project execution or costs. The proposed site for the overall LNG Terminal layout includes sufficient physical space for all the necessary equipment and utility systems required for the Project. In addition, the overall plot provides adequate space to allow various construction activities to proceed in parallel, i.e., there is adequate construction laydown area and construction access. Although construction activities will occur throughout the plant site, the most labor-intensive activities are generally focused in specific areas. This will allow the EPC Contractor’s personnel to enforce the

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requisite safety and security management during construction. Individual aspects of the construction activities include: 

Temporary Facilities: The Project will utilize dedicated areas suitable for equipment and supply laydown, and temporary facilities will be needed to provide power, water, communications and waste control during the construction phase of the Project. Access to the site is available by road, or by barge if a construction dock is installed. The EPC Contractor will provide independent security and safety control for construction traffic and materials.

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LNG Storage Tanks: The location for the storage tank has adequate access although we expect that tank plate may well be delivered by barge. The tanks will be constructed a sufficient distance from the other process areas to allow piling for foundations and the tank construction activities to proceed without interference to other construction activities.

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Vaporization Area: This vaporization area will likely be position to be open on two sides, thereby providing good construction access while enabling appropriate security and safety controls to be enforced during construction as well as operations.

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Transfer Pumps: LNG transfer pumps will be in-tank pumps submerged within deepwells extending from the top of the domed roof to the floor of the storage tank. The pump deep wells will be constructed as part of the tank construction. There will be three deepwells installed in each tank, each containing a transfer pump. Close coordination between the tank fabricator and the main EPC contractor will be required to ensure that installation of these pumps is properly scheduled to minimize delays.

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Receiving Facilities: For the full terminal a single LNG unloading berth will be constructed close to the storage and vaporization site. LNG receipt piping together with vapor return lines will run above a concrete spill trough. Again, close coordination during the installation of the send-out pipeline, the jetty and the terminal will be essential to minimize interference between the different workforces.

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Pipeline: The installation of the send-out pipeline should present no construction problems other than the normally recognized and accepted challenges associated with installation close to urban areasterrain.

In summary, Shaw Consultants confirms that it has identified no construction risks that are could have a detrimental impact on the proposed Project or are outside the experience levels of typical contractors selected for this type of project. 12.4

TYPICAL PROJECT SCHEDULE

Overall project durations for an LNG regasification terminal including a full containment tank are about 40 months from award of the EPC contract. FEED durations range from eight months to about one year and bidding and award of a competitive EPC contract can require a further six to nine months giving a reasonable overall program of about 54 months from the initial decision to proceed. These durations might be shortened by proceeding with several activities in parallel. This reduces management flexibility but given the relatively simple technology associated with the project and the ability to select experienced and well qualified EPC contractors to perform the work this option is realistic providing the risks are accepted. The schedule below assumes this execution strategy. The critical path for the construction of the terminal is likely to be defined by the time required for design, material procurement, construction, cool-down and commissioning of the LNG tank. These activities can

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proceed largely independently from work at the rest of the site. However, purchase commitments on 9Nickel steel are unlikely to be made before the tank contract is signed or project finance is fully committed and available. Additionally, final foundation designs will depend on results from test piles driven in the tank area. Installation of the send-out pipeline is not expected to be on the critical path and can be accomplished with the time available. Similarly, the construction of the jetty is not expected to define the completion date as long as the procurement of the loading arms is progressed in a timely manner. The schedule below shows the relationship between the various activities. Figure 14.4-1 LNG Terminal Outline Schedule

Management and co-ordination of construction activities present challenges that can generally be overcome by early planning. This is especially true at locations where portions of the skilled workforce must be imported. However, subject to timely allocation of appropriate resources, in Shaw Consultants’ opinion, the necessary interfaces and systems to facilitate project execution integration can be established to successfully complete either of the LNG regasification scopes.

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13.1

ENVIRONMENTAL, SOCIAL, HEALTH AND SAFETY

This section discusses the environmental, social, health and safety (“ESHS”) issues which are potentially applicable to the Project. ESHS issues may be defined as follows:    

Environmental issues include the Project’s ecological setting in terms of its physical, climatic and biotic properties; Social issues include the needs, concerns and expectations of the Project’s host community, including property acquisition and Project security; Health issues include potential risks to the Project’s host community (i.e., people and property located outside the Project fenceline); and Safety issues include potential risks to the Project itself (i.e., Project workers and equipment).

All of these ESHS aspects need to be addressed in order for the Project to be successful. 13.2

ENVIRONMENTAL REGULATIONS AND GLOBAL STANDARDS

Shaw Consultants envisions that the following sets of governmental regulations and other standards are potentially applicable to the Project:      

Curacao laws and regulations Kingdom of the Netherlands laws and regulations European Union laws and regulations United States of America laws and regulations Financial institution standards and guidelines Recognized industry codes and standards

The sets of governmental regulations and other standards which will guide implementation of the Project need to be defined at the very onset of the Project. 13.2.1 Curacao Ministry of Public Health, Environment and Nature

Shaw Consultants understands that the Curacao Ministry of Public Health, Environment and Nature (“MPHEN”) is the agency within Curacao which will be responsible for Project review, authorization and supervision. However, Shaw Consultants also understands that the environmental regulatory regime in Curacao is a “work in progress” with respect to design standards, permitting and monitoring requirements. Accordingly, the Project will need to work closely with MPHEN in order to help develop a regulatory system which is protective of the environment, sensitive to the needs of the community and beneficial to the Project. 13.2.2 Kingdom of the Netherlands

Curacao is a self-governing country within the Kingdom of the Netherlands. Accordingly, the Netherlands retains the responsibility for foreign affairs and defense, while Curacao has the right to develop its own laws and international agreements. In the process of developing its own laws and regulations, Curacao tends to mimic the existing laws and legal structure of the Netherlands. Accordingly, where the Curacao regulations are silent on an issue, the Project will first look to the laws and regulations of the Netherlands for guidance.

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Curacao is an independent signatory to a number of international agreements, including the International Maritime Organization (“IMO”) and the International Convention for the Prevention of Pollution from Ships (“MARPOL”), as is the Netherlands. Conversely, Curacao is not a signatory to the Kyoto Protocol regarding climate change, whereas the Netherlands is such a signatory. 13.2.3 European Union

Since the Netherlands is a member of the European Union (“EU”), Curacao and the Project will also look to the EU regulations for guidance in order to supplement and/or reinforce the Netherlands regulations. 13.2.4 United States of America

Since Shaw Consultants is headquartered in the United States of America (“USA”) and is most familiar with its laws and regulations, the Project has directed Shaw Consultants to use the USA regulations as our primary reference for the purposes of this study. In our experience, Shaw Consultants has determined that the USA regulations are generally equivalent to the laws and regulations of the EU in general and the Netherlands in particular. In addition, the USA regulations are generally accepted for use as a reference worldwide. 13.2.5 Financial Institutions

Shaw Consultants understands that the Project is considering financing from global financial institutions such as the following:   

Multi-lateral financial institutions – e.g., World Bank Group (“WBG”) and Inter-American Development Bank (“IDB”); Export Credit Associations (“ECA”) – e.g., Export-Import Bank of the United States (“US Ex-Im Bank”) and Japan Bank for International Cooperation (“JBIC”); and Private-sector development banks – e.g., banks which have adopted the Equator Principles.

Each of these financial institutions has developed its own set of ESHS standards to guide its internal processes. However, most of these are based upon and/or derived from the WBG standards and guidelines. More information on the various types of financial institutions and their standards and guidelines is provided below. World Bank Group

The World Bank Group consists of five closely associated institutions, all owned by member countries that carry ultimate decision-making power. Each institution plays a distinct role in the World Bank Group’s mission to fight poverty and improve living standards for people in the developing world. 

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International Bank for Reconstruction and Development (“IBRD”) – The IBRD aims to reduce poverty in middle-income and creditworthy poorer countries by promoting sustainable development through loans, guarantees, risk management products, and analytical and advisory services. Established in 1944 as the original institution of the World Bank Group, IBRD is structured like a cooperative that is owned and operated for the benefit of its 185 member countries. Income generated by IBRD loans over the years has allowed the agency to fund important development activities and ensures the agency’s strong financial position. This enables borrowing in capital markets at low cost. Thus, IBRD is able to offer its clients good borrowing terms. International Development Association (“IDA”) – The IDA offers interest-free credits and grants to the world’s poorest countries. This highly concessional financing is vital because these

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countries have little or no capacity to borrow on market terms. IDA resources and technical assistance support country-led poverty reduction strategies in key areas: increased productivity, better governance and accountability, improved private investment climate, and access to education and health care for poor people. International Finance Corporation (“IFC”) – The IFC fosters sustainable economic growth in developing countries by financing private sector investment, mobilizing private capital in local and international financial markets, and providing advisory and risk mitigation services to businesses and governments. IFC’s vision is that people should have the opportunity to escape poverty and improve their lives. It seeks to reach businesses in regions and countries that have limited access to capital and provides finance in markets deemed too risky by commercial investors. IFC also adds value to the projects it finances through its corporate governance, environmental and social expertise. It is the largest multilateral source of debt and equity financing for private enterprise in developing countries. Multilateral Investment Guarantee Agency (“MIGA”) – Concerns about investment environments and perceptions of political risk often inhibit foreign direct investment, a key driver of economic growth in developing countries. The MIGA addresses these concerns by providing political risk insurance (guarantees), offering investors protection against noncommercial risks such as expropriation, currency inconvertibility, breach of contract, war and civil disturbance. MIGA also provides advisory services to help countries attract and retain foreign investment, mediates investment disputes to keep current investments intact and remove potential obstacles to future investment, and disseminates information on investment opportunities to the international business community. International Centre for Settlement of Investment Disputes (“ICSID”) – The ICSID is an institution specifically designed to facilitate the settlement of investment disputes between governments and private foreign investors through conciliation and arbitration. Its aim is to foster an atmosphere of mutual confidence between states and investors in order to promote increased flows of international investment. Recourse to ICSID conciliation and arbitration is entirely voluntary. ICSID also issues publications on dispute settlement and foreign investment law.

The term “World Bank Group” encompasses all five institutions. The term “World Bank” refers specifically to two of the five, IBRD and IDA. Depending on whether the Project is structured as a private or public sector project, either the World Bank or the IFC would be the corresponding group to provide project finance to the Project. For the purposes of this study, Shaw Consultants has assumed that financing will come from the IFC. IFC fosters sustainable economic growth in developing countries by financing private sector investment, mobilizing capital in the international financial markets, and providing advisory services to businesses and governments. IFC applies environmental and social standards to all the projects it finances to minimize project-related impacts on the environment and affected communities. In February 2006, IFC completed a rigorous process of updating its standards:  

Policy on Social and Environmental Sustainability – defines IFC’s role and responsibility in supporting project performance in partnership with clients. Policy on Disclosure of Information – defines IFC’s obligations to disclose information about itself as an institution and its activities.

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Environmental and Social Review Procedure – gives direction to IFC officers in implementing the Polity on Social and Environmental Sustainability and reviewing compliance and implementation by private sector projects. Performance Standards – defines clients’ roles and responsibilities for managing their projects and the requirements for receiving and retaining IFC support. The standards include requirements to disclose information. Environmental, Health and Safety Guidelines – technical guidance informing those parts of the new policy structure related to environmental, health and safety issues.

IFC’s Policy on Social and Environmental Sustainability and Policy on Disclosure of Information are collectively referred to as IFC’s “Sustainability Framework,” which articulates IFC’s strategic commitment to sustainable development and is an integral part of IFC’s approach to risk management. The Sustainability Framework provides guidance on how to develop a management system approach to identify risks and deal with them, and is designed to help clients avoid and mitigate adverse impacts and manage risk as a way of doing business in a sustainable way. IFC’s Sustainability Framework is now considered to be a leading benchmark for environmental and social risk management for private sector investors worldwide. The Equator Principles, a voluntary set of standards developed by private sector banks based on IFC’s Performance Standards, are evidence of this global recognition. IFC recently completed a fresh revision to its Sustainability Framework and Performance Standards:   

April 14, 2011 – IFC posted its revised policies, procedures and standards on its web site; May 12, 2011 – These revisions were formally approved by IFC’s Board of Directors; and January 1, 2012 – These revisions become effective.

These revisions are summarized below: 



Sustainability Policy o Strengthens IFC’s commitments to climate change, business and human rights, corporate governance and gender o Revises and strengthens categorization system  Greater emphasis on inherent risks and project context  Categorizes actions by Financial Intermediaries (“FIs”) according to the level of their environmental and social risks o Strengthens due diligence for FIs o Clarifies due diligence for Advisory Services o Strengthens disclosure requirements for extractive industry projects Performance Standard 1 o Changes name to “Assessment and Management of Environmental and Social Risks and Impacts” o Refers to private sector responsibility to respect human rights o Introduces better applicability to investments other than project finance (non-defined assets concept) o Requires stakeholder engagement beyond Affected Communities o Clarifies levels of stakeholder engagement under different circumstances o Requires development of a formal environment and social policy reflecting principles of the Performance Standards o Introduces participatory monitoring (when appropriate) as an option during implementation

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o Requires period performance reviews by senior management Performance Standard 2 o Establishes requirement for comparable terms and conditions for migrant workers compared to non-migrant workers o Introduces quality requirements for workers’ accommodation o Requires ongoing monitoring of working conditions for workers under the age of 18 o Requires establishing policies and procedures to manage and monitor compliance of third parties with Performance Standard 2 o Requires alternatives analysis in case of retrenchment o Requires ongoing monitoring of primary supply chain o Introduces “safety” trigger in primary supply chain Performance Standard 3 o Changes name to “Resource Efficiency and Pollution Prevention” o Introduces a resource efficiency concept for energy, water and core material inputs o Strengthens focus on energy efficiency and greenhouse gas measurement o Reduces greenhouse gas emissions thresholds for reporting to IFC from 100,000 tons of CO2 to 25,000 tons of CO2 per year o Requires determination of accountability with regards to historical pollution o Introduces concept of “duty of care” for hazardous waste disposal Performance Standard 4 o Considers risks to communities associated with use and/or alteration of natural resources and climate change through an ecosystems approach Performance Standard 5 o Extends scope of application to restrictions on land use o Strengthens requirements regarding consultations o Introduces a requirement for a completion audit under certain circumstances Performance Standard 6 o Changes name to “Biodiversity Conservation and Sustainable Management of Living Natural Resources” o Clarifies definitions of and requirements for various types of habitats o Introduces stronger requirements for biodiversity offsets o Introduces specific requirements for plantations and natural forests o Introduces specific requirements for management of renewable natural resources o Strengthens supply chain scope Performance Standard 7 o Expands consideration of Indigenous Peoples’ specific circumstances in developing mitigation measures and compensation o Introduces requirement for land acquisition due diligence with regards to lands subject to traditional ownership or under customary use o Introduces the concept of Free, Prior and Informed Consent (“FPIC”) under certain circumstances Performance Standard 8 o Requires clients to allow access to cultural sites

The 2011 revisions became effective on January 1, 2012. Significantly, the 2011 revisions to IFC’s Sustainability Framework do not preclude the IFC from participating in oil and gas exploration and

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development, mining and other “extractive” projects. In addition, the IFC’s 2011 revisions discussed above do not affect the EHS Guidelines. IFC applies its Performance Standards to manage social and environmental risks and impacts and to enhance development opportunities in its private sector financing in its member countries eligible for financing. The Performance Standards may also be applied by other financial institutions electing to apply them to projects in emerging markets. Together the IFC’s eight Performance Standards establish standards that the client must meet throughout the life of an investment by IFC or other relevant financial institution (the term “client” is used throughout the Performance Standards broadly to refer to the party responsible for implementing and operating the project that is being financed, or the recipient of the financing, depending on the project structure and type of financing).        

Performance Standard 1 – Social and Environmental Assessment and Management System Performance Standard 2 – Labor and Working Conditions Performance Standard 3 – Pollution Prevention and Abatement Performance Standard 4 – Community Health, Safety and Security Performance Standard 5 – Land Acquisition and Involuntary Resettlement Performance Standard 6 – Biodiversity Conservation and Sustainable Natural Resource Management Performance Standard 7 – Indigenous Peoples Performance Standard 8 – Cultural Heritage

The Social and Environmental Assessment conducted in compliance with Performance Standard 1 is analogous to the Environmental Impact Assessment (“EIA”) or Environmental Impact Statement (“EIS”) required by other financial institutions. In meeting the requirements of the IFC Performance Standards, clients must comply with applicable national laws, including those laws implementing host country obligations under international law. As of April 30, 2007, new versions of the World Bank Group Environmental, Health and Safety Guidelines (“EHS Guidelines”) are now in use. The EHS Guidelines replace those documents previously published in Part III of the Pollution Prevention and Abatement Handbook and on the IFC website. The EHS Guidelines are technical reference documents with general and industry-specific examples of “good international industry practice” as defined in IFC’s Performance Standard 3. The EHS Guidelines contain performance levels and measures that are generally considered to be achievable in new facilities at reasonable costs by existing technology. When host country regulations differ from the levels and measures presented in the EHS Guidelines, projects are expected to achieve whichever is more stringent. If less stringent levels or measures are appropriate in view of specific project circumstances, a full and detailed justification for any proposed alternatives is needed as part of the site-specific environmental assessment. This justification should demonstrate that the choice for any alternate performance levels is protective of human health and the environment. Shaw Consultants identified the following EHS Guidelines which are relevant to this Project: 

Environmental, Health and Safety General Guidelines – contain information on cross-cutting environmental, health and safety issues potentially applicable to all industry sectors. These guidelines should be used together with the relevant industry sector guideline.

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 

Environmental, Health and Safety Guidelines for LNG Facilities – include information relevant to base load liquefaction plants, transport by sea, and regasification and peak shaving terminals. Environmental, Health and Safety Guidelines for Ports, Harbors and Terminals – are applicable to commercial ports, harbors and terminals for cargo and passengers transfer.

Compliance with the appropriate World Bank Group standards and guidelines will be determined by the World Bank Group lending institution, provided that the World Bank Group is participating in a given project’s financing. Otherwise, the World Bank Group will withhold comment on a given project’s compliance with the World Bank Group standards and guidelines. Export Credit Associations

The mission of Export Credit Associations (“ECAs”) is to assist in financing the export to international markets of goods and services produced in each ECA’s home country. The intent is to enable home country companies to turn export opportunities into real sales which will help and maintain home country jobs and contribute to a stronger home country economy. ECAs do not compete with private sector lenders, but provide export financing products which fill gaps in trade financing. Specifically, ECAs assume credit and country risks which the private sector is unable or unwilling to accept. ECAs also help to level the playing field for home country exporters by matching the financing that other governments provide to their home country exporters. To this end, ECAs provide working capital guarantees (preexport financing), export credit insurance, and loan guarantees and direct loans (buyer financing). To further promote a level playing field worldwide, the Organisation for Economic Cooperation and Development (“OECD”) sponsored an agreement among its member organizations regarding Common Approaches on the Environment and Officially Supported Export Credits (the “Common Approaches”). The general objectives of the Common Approaches are listed below: 

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Promote coherence between policies regarding officially supported export credits and policies for the protection of the environment, including relevant international agreements and conventions, thereby contributing towards sustainable development; Develop common procedures and processes relating to the environmental review of new projects and existing operations benefiting from officially supported export credits, with a view to achieving equivalence among the measures taken by OECD members and to reducing the potential for trade distortion; Promote good environmental practice and consistent processes for new projects and existing operations benefiting from officially supported export credits, with a view to achieving a high level of environmental protection; Enhance efficiency of official support procedures by ensuring that the administrative burden for applicants and export credit agencies is commensurate with the environmental protection objectives of the Common Approaches; Promote a level playing field for officially supported export credits and increase awareness and understanding, including both OECD and non-OECD member economies, of the benefits of applying the Common Approaches.

To achieve these objectives, OECD members should: 

Foster transparency, predictability and responsibility in decision making by encouraging disclosure of relevant environmental information with due regard to any legal stipulations, business confidentiality and other competitive concerns;

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Encourage prevention and mitigation of adverse environmental impacts of new projects and the environmental risks associated with existing operations, and take into account the benefits of any new projects and existing operations supported; Enhance financial risk assessment of new projects and existing operations by taking into account environmental aspects; and Build a body of experience on the practical application of the Common Approaches.

Some ECAs have developed their own sets of ESHS standards and guidelines, while others simply reference the IFC standards and guidelines. In either case, each ECA is responsible for determining a given project’s compliance with the appropriate ESHS standards and guidelines. 13.2.6 Recognized Industry Codes

Several international trade groups have developed their own sets of standards for use by their members worldwide in the absence of or to supplement the host country regulations. Examples follow:   

American Petroleum Institute (“API”) – process equipment design and operation; American Society of Mechanical Engineers (“ASME”) – piping design and operation, both inside the plant and cross-country; and Society of International Gas Tanker and Terminal Operators (“SIGTTO”) – design and operation of ships and terminals, including LNG ships and terminals.

Shaw Consultants anticipates that the Project will compile a comprehensive set of industry codes and standards which will be used to guide Project designs and operations. 13.3

CURACAO PERMITTING REQUIREMENTS

Shaw Consultants understands that the permitting regime within Curacao is still developing. Currently, the Project would require the following permits from MPHEN:   

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Safety Permit, Construction Permit, Public Nuisance Permit, which would include the following: o Air emission limits and o Waste disposal requirements; and Wastewater Disposal Permit.

In order to obtain a Public Nuisance Permit, Shaw Consultants understands that public notice is required and a public hearing may be required. Conversely, Shaw Consultants understands that an EIA would not be required in order to satisfy Curacao’s current permitting requirements. 13.4

FINANCIAL INSTITUTION REQUIREMENTS

As mentioned previously, Shaw Consultants understands that the Project is considering financing from global financial institutions; i.e., project finance. The concept of project finance and the associated requirements of the financial industry, which may be imposed upon a project in addition to the requirements of the project’s host country, are discussed in the following sections.

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13.4.1 Project Finance

Project finance is “a method of funding in which the Lender looks to the revenues generated by a single project both as the source of repayment and as security for the exposure. This type of financing is usually for large, complex and expensive installations that might include, for example, power plants, chemical processing plants, mines, transportation infrastructure, environment and telecommunications infrastructure. Project finance may take the form of financing of the construction of a new capital installation or refinancing of an existing installation, with or without improvements. In such transactions, the lender is usually paid solely or almost exclusively out of the money generated by the contracts for the facility’s output, such as the electricity sold by a power plant. The borrower is usually a Special Purpose Entity (“SPE”) that is not permitted to perform any function other than developing, owning and operating the installation. The consequence is that repayment depends primarily on the project’s cash flow and collateral value of the project’s assets.” – the Basel Committee on Banking Supervision, International Convergence of Capital Measurement and Capital Standards (“Basel II”), November 2005. Shaw Consultants understands that the Project will be implemented by a SPE which will be wholly owned by the Curacao government, but which will be operated similarly to a private company (as opposed to a government agency). 13.4.2 Project Exclusions

The following types of projects are typically not eligible for project finance: 

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Production or trade in any product or activity deemed illegal under host country laws or regulations or international conventions and agreements, or subject to international bans, such as pharmaceuticals, pesticides/herbicides, ozone depleting substances, PCBs, wildlife or products regulated under the Convention on International Trade in Endangered Species (“CITES”); Production or trade in weapons and munitions; Production or trade in alcoholic beverages (excluding beer and wine); Production or trade in tobacco; Gambling, casinos and equivalent enterprises; Production or trade in radioactive materials – this does not apply to the purchase of medical equipment, quality control (measurement) equipment and any equipment where the radioactive source is trivial and/or adequately shielded; Production or trade in unbonded asbestos fibers – this does not apply to purchase and use of bonded asbestos cement sheeting where the asbestos content is less than 20%; and Drift net fishing in the marine environment using nets in excess of 2.5 km. in length.

As far as Shaw Consultants can determine, none of the foregoing exclusions applies to the Project. 13.4.3 Project Screening

Projects which are not excluded from financing must be screened in accordance with criteria established by the financial community in order to determine if a sensitive environmental or social receptor may be impacted by the project. Typical criteria used by the financial community include a given project’s potential impact on any of the following: 

Tropical forests or other areas with high biological diversity;

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     

Nationally or internationally designated protected areas (e.g., wetlands, seashores, wildlands, refuges or national parks); Habitat for rare, threatened or endangered species; Indigenous, tribal or other vulnerable populations; Cultural, historical or archaeologically significant properties; Residential areas which will need to be resettled (moved); and Properties on the United Nations Educational, Scientific and Cultural Organization (“UNESCO”) World Heritage list.

The presence of one or more of these features within a given project’s area of influence does not exclude the project from obtaining financing from the worldwide community, although it does complicate the matter. If one or more of these features is present, the project’s sponsor will need to document the following:       

Location, spacial extent and temporal nature of the feature; Ecological, social, economic and/or cultural importance of the feature; Relationship of the feature with respect to the project (e.g., distance from the project); Potential impacts which implementation of the project may have upon the feature; Avoidance and/or mitigation measures which the project will implement in order to eliminate or minimize its impacts upon the feature, Monitoring measures to document the project’s impacts for an appropriate period of time (up to and including the life of the project), and Compensation which the project will implement in recompense for its impacts (if impacts cannot be suitably eliminated or avoided).

Enforceable commitments, bonds, insurance or some other form of financial guarantee may be required by the financing institution(s), depending upon the relative importance of the feature and the potential impacts associated with the project. Initial screening of the Project by Shaw Consultants indicates that none of the features listed above are present within the Project’s area of influence. 13.4.4 Project Categorization

Based upon screening results, the Project will need to be categorized in accordance with the following criteria (or similar criteria used by the financial institutions involved) to determine the type and degree of review to which the project will need to be subjected:  



Category A – Projects with potentially significant adverse social or environmental impacts that are diverse, irreversible or unprecedented; Category B – Projects with potential limited adverse social or environmental impacts that are few in number, generally site-specific, largely reversible and readily addressed through mitigation measures; and Category C – Projects with minimal or no social or environmental impacts.

Based upon our initial review of the Project, Shaw Consultants believes that the Project should be characterized as a Category B project for the following reasons:

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   

 

The Project will reuse existing infrastructure, including jetty, terminal and pipeline right-of-way (“ROW”); The Project’s risks are well known, making quantification and assessment straightforward; The Project’s risks can be readily eliminated or minimized through mitigation measures; The Project should not involve any involuntary resettlement as defined by the financial community (removal of unauthorized pipeline ROW encroachment is not defined as involuntary resettlement); The Project should not impact any critical or unique habitats; and The Project does not require dredging.

However, the financial institutions involved will ultimately make their own decision regarding the Project’s categorization. 13.4.5 Environmental Impact Assessment

All Category A and some Category B projects will require a comprehensive Environmental Impact Assessment (“EIA”) to document their potential ESHS impacts, guide public consultation, revise project designs in order to eliminate or minimize potential impacts to the extent practicable, prepare socially acceptable compensation plans, and prepare project management and monitoring plans for use throughout operations. EIAs are of two types: 1. Project-specific EIA, where the EIA focuses on the project’s potential impacts within its area of influence, only; and 2. Non-project-specific EIA; i.e., cumulative, regional, sectoral or strategic EIAs, such as master economic development plans that encompass multiple projects in order to better assess the cumulative impacts of projects within a defined physical and/or economic area. An EIA’s scope and level of detail should be commensurate with the project’s potential impacts. Typically, an EIA will comprise the following elements:   





Executive Summary – Concisely discusses significant findings and recommended actions. Policy, Legal and Administrative Framework – Discusses the policy, legal and administrative

framework within which the EIA is conducted. Project Description – Describes the proposed project and its geographic, ecological, social and temporal context, including any offsite investments that may be required (e.g., dedicated pipelines, access roads, power plants, water supply, housing, and raw material and product storage units). Indicates the need for any resettlement or social development plan. Normally includes a map showing the project site and the project’s area of influence. Baseline Data – Assesses the dimensions of the study area and describes the relevant physical, biological and socio-economic conditions, including any changes anticipated before the project commences. Also takes into account current and proposed development activities within the project areas, but not directly connected to the project. Data should be relevant to decisions about project location, design, operation or mitigation measures. Documents the relative accuracy, reliability and sources of the data. Environmental Impacts – Predicts and assesses the project’s likely positive and negative impacts in quantitative terms to the extent possible. Identifies mitigation measures and any

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





residual negative impacts which cannot be mitigated. Explores opportunities for environmental enhancement. Identifies and estimates the extent and quality of available data, key data gap and uncertainties associated with predictions, and specifies topics which do not require further attention. Analysis of Alternatives – Systematically compares feasible alternatives to the proposed project site, technology, design and operation, including the “without project” situation, in terms of their potential environmental impacts, the feasibility of mitigating these impacts, their capital and recurrent costs, their suitability under local conditions, and their institutional, training and monitoring requirements. For each of the alternatives, quantifies the environmental impacts to the extent possible and attaches economic values where feasible. States the basis for selecting the particular project design proposed and justifies recommended emission levels and approaches to pollution prevention and abatement. Environmental Management Plan – Describes mitigation, monitoring and institutional measures to be taken during construction and operation to eliminate adverse impacts, offset said impacts or reduce said impacts to acceptable levels. Consultation – Record of consultation meetings, including consultations for obtaining the informed views of the affected people, local non-governmental organizations (“NGOs”) and regulatory agencies.

For the Project, the EIA will need to encompass the unloading and storage terminal, the regasification plant and the pipeline to deliver natural gas to the power plant, refinery and other designated industrial users. 13.4.6 Public Consultation

For all Category A and, as appropriate, Category B project located in non-OECD countries and OECD countries not designated as High-Income as defined by the World Bank Development Indicators Database, the Borrower must consult with affected individuals and communities in a structured and culturally appropriate manner. Affected communities are communities of the local population within a given project’s area of influence who are likely to be affected by the project, either adversely or beneficially. Where such consultation needs to be undertaken in a structured manner, the financial institution(s) “may” (read: “will”) require the preparation of a Public Consultation and Disclosure Plan. The intent of the public consultation process goes well beyond simple distribution of information regarding the project by the Borrower to the community. Rather, the intent is for the Borrower to solicit comments, concerns, preferences and other information regarding the project, its proposed location and its interaction with affected communities from the affected communities for the purposes of project development and refinement. In other words, a proper public consultation process means that the affected communities will have a say as to how, when and where the project is implemented. For projects with potentially significant adverse impacts on affected communities, the process will ensure free, prior and informed consultation, and facilitate informed community participation as a means to establish, to the satisfaction of the financial institution, that a project has adequately incorporated concerns of the affected communities. Consultation should be “free” (free of external manipulation, interference or coercion, and intimidation), “prior” (timely disclosure of information) and “informed” (relevant, understandable and accessible information), and apply to the entire project process and not only to the early stages of the project. The Borrower must tailor its consultation process to the language preferences of the affected communities, their decision making processes and the needs of disadvantaged or vulnerable groups.

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In order to accomplish this, the EIA documentation must be made available to the public by the Borrower for a reasonable minimum period in the relevant local language and in a culturally appropriate manner. The Borrower must take account of and document the process and results of the consultation, including any actions resulting from the consultation on which the community and the Borrower have agreed. For projects with potentially adverse social or environmental impacts, disclosure must occur early in the EIA process and, in any event, before commencement of project construction as well as on an ongoing basis. 13.5

ESHS ISSUES OF CONCERN

Shaw Consultants has reviewed the Project and identified a number of ESHS issues which may be of concern and which warrant further investigation by the Project. 13.5.1 LNG Regasification

There are a number of technologies used worldwide to regasify LNG, depending upon the technical, social and environmental conditions extant at each location. The primary technologies in use are listed below:    

Open cycle heat exchange with adjacent surface water; Closed cycle heat exchange with recirculating heating water; Open cycle heat exchange with ambient air; and Submerged combustion.

The conventional technology used to regasify LNG is an “open cycle” heat exchange system, whereby the LNG is contacted with a stream of water which is sourced from and discharged to adjacent surface water. Open cycle water systems regasify LNG by transferring heat from the surface water to the LNG. In so doing, open cycle water systems cause a resulting decrease in the temperature of the surface water (analogous to the increase in temperature resulting from open cycle systems associated with power plants). In order to minimize thermal effects upon biota resident within the surface water, the Project would be required to maintain the decrease in temperature attributable to the Project to less that 3ºC at the outer boundary of a 100 meter diameter mixing zone about the Project’s open cycle water discharge point. However, even if the thermal effects of an open cycle water system are maintained within acceptable limits, such a system may continue to adversely impact its environment due to impingement and/or entrainment of aquatic organisms within the water cycle. In order to minimize such impacts, the open cycle water intake units must be designed to minimize impingement of aquatic organisms on intake screens and entrainment of organisms within the system itself. Among other constraints, this entails keeping the intake velocity below 0.5 feet per second in order to allow aquatic organisms the opportunity to escape and avoid capture. Closed cycle water systems use a tower to heat a stream of recirculating water which has been cooled by contact with LNG against ambient air, so that the water may be recirculated on a continuous basis. In this manner, heat is drawn from the atmosphere with minimal effects upon the environment. However, the recirculating water must be chemically treated with biocides and corrosion inhibitors, and a percentage of the recirculating water must be purged periodically from the system in order to maintain chemical concentrations within prescribed ranges. This purge stream must be treated prior to discharge to the environment and represents a potentially adverse impact. Open cycle air systems use a tower to heat LNG directly without the use of a recirculating water stream. Such a unit eliminates the potential impacts associated with both open and closed cycle water systems. However, open cycle air systems typically require the use of massive fans to move the quantities of

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ambient air necessary to regasify the LNG. As a result, open cycle air systems may have a greater energy demand than either open or closed cycle water systems. In addition, open cycle air systems are not effective within colder climates (which is not a concern for the Project). Submerged combustion units burn vaporized LNG within a tank of water to heat the water which is then used to regasify the LNG. Submerged combustion units actually create significant quantities of fresh water through the combustion process by converting methane (“CH4”) and atmospheric oxygen (“O2”) to carbon dioxide (“CO2”) and water (“H2O”). However, submerged combustion units also cause emissions of various air pollutants such as nitrogen oxides (“NOx”) and greenhouse gases (“GHG”) such as CO2. Submerged combustion units also consume significant quantities of fuel (LNG). Each feasible regasification technology will need to be assessed so that the “best” technology for the Project may be selected. This assessment process will need to be documented for agency and public review within the EIA. 13.5.2 Transportation and Infrastructure

LNG carriers (ships) are typically massive vessels which require extensive, dedicated harbor facilities, including specialized jetties and tugs. In addition, LNG carriers are typically provided with a “buffer zone” during transit within designated harbors, harbor entrances and other channels. As a result, harbor congestion and maritime traffic congestion associated with LNG carrier transits must be investigated. Typically, this involves computer modeling and consultation with harbor pilots as well as with the Harbor Master. 13.5.3 LNG Risk

The potential risks associated with the shipment, unloading, storage and regasification of LNG and distribution of natural gas via cross-country pipeline with regard to human health and welfare as well as upon the environment must be assessed. Fortunately, the risks associated with LNG regasification terminals are well documented, understood and quantifiable. In addition, these risks are amenable to mitigation. The risks associated with LNG and natural gas are largely a function of their physical and chemical properties as presented below: 

  

 

Physical properties – LNG and natural gas are colorless and odorless (for this reason, natural gas is commonly odorized prior to distribution). LNG, as a liquid, is heavier than air. However, natural gas is significantly lighter than air and disperses quickly. Toxicity – LNG and natural gas are classified as simple asphyxiants and are otherwise relatively non-toxic. Corrosivity – LNG and natural are non-corrosive with regard to metal piping and structures. Temperature – LNG is typically transported and stored at cryogenic temperatures (minus 260ºF). Accordingly, LNG will adversely affect humans, wildlife and vegetation upon dermal/surface contact. In addition, LNG will adversely affect unprotected equipment and piping due to embrittlement effects. Pressure – LNG is stored at atmospheric pressure, whereas the Project pipeline will be operated within the range of 10 to 15 bar (500 to 750 psig). Flammability – In order to burn, LNG must be vaporized into natural gas, which has a relatively narrow flammability range; i.e., the lower explosive limit (“LEL”) for methane is 5% by volume in air, while its upper explosive limit is 15%. However, public perception is that LNG is an

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“explosive” material. This perception will need to be addressed during the public consultation process. The Project’s risks will need to be assessed in terms of two simultaneous variables: (1) the severity of consequences in the event an incident occurs and (2) the probability that such an event could occur. In other words, a highly significant incident that would pose the greatest risk is one which would result in dire consequences and which is highly likely to occur. Conversely, an insignificant incident is one which would result in minimal consequences and is unlikely to occur. Potential incidents will need to be identified, their consequences quantified and their probabilities calculated/estimated based upon data compiled by industry and government. Attention can then be focused on eliminating or at least minimizing the consequences and/or probabilities of significant incidents on a site specific basis to levels which are acceptable to the Project’s government and host communities. 13.5.4 Mitigation and Control

There are two basic types of controls which can be applied to the Project to mitigate its potential risks: (1) passive controls and (2) active controls. Passive controls are related to equipment design and construction features which inherently reduce either the severity or probability of an incident occurring. Examples of passive controls include the following:   

Piping wall thickness and strength per “class” designation; Additional piping wall thickness and strength at locations where people and/or wildlife are likely to be present (e.g., road crossings); and Natural gas odorizing for leak detection.

Active controls are related to operating and maintenance procedures in that they require human interface in order to function. Examples of active controls include the following:   

Supervisory Control and Data Acquisition (“SCADA”) systems; Emergency Shutdown (“ESD”) systems for jetty, regasification and pipeline; and Emergency Preparedness and Response system.

The Project will need to establish and maintain an Emergency Preparedness and Response system to prevent and respond to various emergencies. This system will need to be prepared in collaboration with local governments and affected communities, particularly where the participation of such parties is required to ensure an effective response. In the case of the Project, there is an existing infrastructure for emergency response already in place, which can be supplemented to encompass the Project. 13.5.5 Property Acquisition

Project-related property acquisition and restrictions on land use can have adverse impacts on communities and persons that use the property in question. Involuntary resettlement refers both to physical displacement (relocation or loss of shelter) and to economic displacement (loss of assets or access to assets that leads to loss of income sources or other means of livelihood). Resettlement is considered involuntary when affected persons or communities do not have the right to refuse land acquisition or restrictions on land use that result in physical or economic displacement. This includes the following:  

Lawful expropriation of temporary or permanent restrictions on land use; and Negotiated settlements in which the buyer can resort to expropriation or impose legal restrictions on land use if negotiations with the seller fail.

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In the case of the Project, the properties in questions are already the property of the government. Accordingly, property acquisition should not involve the general public. In the event that the Project discovers that there are unauthorized structures constructed on the pipeline ROW, removal of these structures does not constitute involuntary resettlement. 13.5.6 Dredging

Shaw Consultants understands that the Project will be able to use existing harbors and that dredging of new harbors or approaches will not be required for this Project. 13.5.7 Security

Use of public and/or private security forces to safeguard personnel and property associated with the Project carries the risk that these forces may overstep their authority in conflict with individual rights. In order to avoid this situation, the Project should align its security procedures with the Voluntary Principles on Security and Human Rights (“VPSHR”) which have been adopted by governments of the United States and the United Kingdom, companies in the extractive and energy sectors and several nongovernmental organizations (“NGOs”). The VPSHR incorporate international law enforcement principals, such as the United Nations (“UN”) Code of Conduct for Law Enforcement Officials and the UN Basic Principles on the Use of Force and Firearms by Law Enforcement Officials. 13.5.8 Environmental and Social Management System

The Project will need to prepare and implement an Environmental and Social Management System (“ESMS”) to ensure compliance with the Project’s permits and other governmental authorizations. 13.5.9 Non-Governmental Organizations

There are several non-governmental organizations (“NGOs”) which will be interested in the Project. Typically, NGOs focus upon a particular issue. Some of these NGOs will be supportive of the Project, while others may not. In either case, the Project will need to reach out to the NGOs active within Curacao to solicit their input and cooperation regarding the Project. 13.6

CONCLUSIONS AND RECOMMENDATIONS

Shaw Consultants reviewed the environmental laws and regulations promulgated by Curacao, the Kingdom of the Netherlands, the European Union, the United States of America in order to determine what the Project’s statutory requirements would be. In addition, since we understand that the Project is considering project finance as a method of funding the Project, we reviewed the standards and guidelines developed by multi-lateral financial institutions, export credit associations and private sector banks. Furthermore, we reviewed codes and standards developed by relevant industry groups. Shaw Consultants reviewed the permitting requirements within Curacao with regard to the Project. We also reviewed documentation requirements of the financial community. Based on this brief analysis, Shaw Consultants determined that Curacao does not currently require the Project to conduct a comprehensive EIA; however, the financial community does. This EIA should be commensurate with the requirements for a Category B project. In concert with preparation of the Curacao permitting documents and the financial community EIA, the Project needs to conduct a public consultation process to (1) inform the governmental agencies and general public regarding the Project specifics (to the extent that they are currently known); (2) solicit input from the affected communities on how the Project should be located structured, designed and

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operated; (3) counter misinformation regarding the Project which has been accidently or purposely distributed; and (4) reach a mutually agreeable resolution with the Project’s host communities. Shaw Consultants identified a number of ESHS issues which may be of concern for the Project. Alternatives were discussed in terms of their relative impacts upon sensitive receptors. In summary, Shaw Consultants believes that the Project can be successfully implemented with minimal adverse impacts upon environmental and social receptors. However, the potential adverse impacts associated with the Project cannot be eliminated altogether. Accordingly, the Project will need to mitigate its adverse impacts to the extent practicable. To this end, the Project will need to prepare an ESMS Plan to document and monitor its efforts to mitigate its potentially adverse environmental and social impacts throughout Project design, construction and operation.

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14.1

OVERVIEW

In this section of the report, Shaw Consultants provides a brief overview of Project Finance and its potential application to the Curacao LNG Project. Shaw Consultants has been actively engaged in providing due diligence support since the mid-1980’s when the emergence of independent power projects became a catalyst for Project Financing. Until then utility companies used corporate finance for the development of new assets. Loans for new infrastructure were part of the public utility company’s debt. As security, the lenders had full recourse to the assets and revenue stream of the public utility, not just those associated with the new infrastructure (the “project”). Project Finance is a method of funding in which the Lenders rely on the revenues generated by a single project both as the source of repayment and as security for the exposure. A special purpose vehicle – generally a Project Company – is established to own the Project assets. Power industry transactions generally use non-recourse Project Finance – Lenders carry full risk at Financial Close. Conversely, process industries transactions generally use limited recourse Project Finance – Sponsors provide financial guarantees which fall away once the project is constructed and tested and Completion Criteria have been met. Thereafter the Lenders’ security is limited to the physical asset and associated permits and contracts. Shaw Consultants has acted as the Lenders’ Independent Technical Consultant (“ITC”) on 20 LNG receiving terminals worldwide. In our opinion, the Project is a suitable candidate for some form of Project Finance funding. 14.2

EQUITY REQUIREMENTS

A Project Finance transaction will generally utilize funds from two sources – Debt (the Lenders) and Equity – funds contributed by the owners (shareholders) of the Project. Equity takes risk and in return receives dividends and capital gains based on net profits. Traditionally, the shareholders would have been one or more utility companies with a vested interest in the function of the Project, e.g. LNG supplier, gas offtaker and electricity generator. Recently, equity houses have demonstrated an appetite for buying into Project Companies. Typically, equity input is likely to be at least 20-percent of total installed cost, although some projects achieve a 15 percent equity infusion requirement. The typical range is between 20 and 40 percent of total installed cost. As a general observation, Lenders prefer high equity participation as an indication of Sponsor commitment whereas Sponsors prefer a relatively low equity participation to minimize utilization of corporate resources. Factors that influence the acceptable debt to equity ratio include project location, sponsor creditworthiness and the overall risk determined by the lenders and their advisors. Table 14.2-2 provides an example of sources and uses for the financing of a LNG terminal. In this case the debt to equity ratio is 70:30. In Shaw Consultants this would be a reasonable assumption for Project Finance funding of the Curacao Project. It should be noted that the Project will incur substantial fees and interest during the construction period. In this instance, we have assumed that some of the equity will be derived from income generated in the period between start-up and Completion. Even so, hard equity requirements would be of the order of US$140 million.

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Table 14.2-2 Example Sources and Uses SOURCES Senior Facilities Debt tranche 1 Debt tranche 2 Project's Debt

Equity injected Owner #1 Owner #2 Sum Equity injected Pre-Completion revenue (less Operating Costs) Project's Equity SOURCES USES Construction Capex Senior Debt Financing interest & fees Pre-FID costs DSRA USES

14.3

Committed Debt 240 115 355 Project Equity 80 60 140 14 154 509

430 62 2 15 509

TYPICAL LENDING ORGANIZATIONS

The financial community comprises a broad range of institutions. These include: 

Multilateral Development Agencies (“MDAs”) which include global institutions, such as the World Bank and its affiliates (the International Finance Corporation (“IFC”), the International Development Association (“IDA”) and the Multilateral Investment Guarantee Agency (“MIGA”)), the international Bank for Reconstruction and Development (“IBRD”) and regional development agencies such as the Inter-American Development Bank (“IDB”) and the European Investment Bank (“EIB”). Typically MDAs will provide a relatively small proportion of the funding of the project (unless it is state-sponsored) but their involvement provides considerable comfort to both equity and commercial lenders



Export Credit Associations (“ECAs”), a subset of Bilateral Agencies, include US Ex-Im Bank, Japan Bank for Industrial Cooperation (“JBIC”) and the Korea Eximbank (“K-Exim”). These agencies’ participation is normally linked to their national involvement in a project. This can include the supply of equipment and materials and the supply of LNG;



Commercial Lenders such as ING, Credit Suisse, CitiBank, HSBC, Barclays, BNP Paribas, Societe Generale, Credit Agricole – Commercial and Industrial Bank;



Equity Houses – there are a growing number of equity houses. These include investment banks, private equity funds, pension funds and foreign investment arms of state-owned oil and gas companies;

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

Participating contractors and suppliers – major EPC contractors can often arrange financing packages from the above.

The IDB is the oldest regional development agency. It was established in 1959 and has 46 member countries, 17 of which are non-regional industrialized countries. Loans are made to public entities but must be backed by a government guarantee. IDB has established two affiliates to facilitate loans to the private sector. These are the Inter-American Investment Corporation (“IIC”) and the Multilateral Investment Fund. The IIC provides equity and loans to private companies without a requirement for government support. Moreover, it is able to arrange syndicated loans. This is advantageous to commercial banks within the syndicate as the IIC is the Lender of Record and administers the loan. Therefore, any default is a default against the IIC. The European Investment Bank (“EIB”) was established in 1958 to finance capital investment projects that promote balanced development throughout the European Union. It has participated in projects in Africa, the Caribbean and the Pacific Rim. The Organization for Economic Co-operation and Development (“OECD”) was established in 1961 and currently has 34 members. All member countries have substantial investment and technical development assistance programs which are administered through various bilateral agencies. Typically, the functions of bilateral agencies are one of the following:  Provision of grants and concessional loans to developing countries based on economic, social and political considerations – by way of example the US Agency for International Development (“USAID”);  Provision of loans, guarantees and insurance to promote the export of goods and services (including EPC of the Project) from the donor country – by way of example the US ExportImport Bank (“US Exim”). 14.4

TERMS AND CRITERIA

In Shaw Consultants’ experience, the criteria and terms that would most likely apply to the Curacao LNG Project include:              

Term – 12 to 25 years; Environmental and Social Impact Assessment (“ESIA”) must be submitted and preferably approved – see Section 14.6; Primary permits obtained (prior to Financial Close); Low Environmental and Social risk – reputation issue for Equator Principles Finance Institutions (“EPFI”); Front End Engineering and Design (“FEED”) complete; Use of proven technology; Lump sum contracting strategy (preferred but not essential); CAPEX profile developed; Schedule developed; Engineering, Procurement and Construction (“EPC”) or Lease Contract invitation to bid (“ITB”) package developed and preferably issued; Bids received prior to Financial Close; LNG SPA negotiated for a term that exceeds the life of loan; Gas reserves to LNG supplier must exceed life of loan; Gas Offtake Agreement with credit rating agency(Moodys or Standard and Poors) “rated” entity;

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 

Operations philosophy established; Operation and Maintenance Contract Term Sheet developed in the event of contracted-out operations;  OPEX profile developed;  Realistic financial model developed that reflects the above;  Completion support package identified. The lenders will require surety over the Project assets, including the facilities and supporting permits and contracts. 14.5

RISK

Lenders to Project Finance transactions undertake a careful and robust assessment of risk. Therefore, the Owner/Developer must prepare a robust definition of the Project and progress early critical path items such as undertaking environmental impact assessments and applying for long-lead permits. An LNG Import Project will be subject to due diligence review by legal, technical, environmental and social, market, shipping and insurance consultants. Independent Technical Consultants such as Shaw Consultants will assess different aspects of the implementation and operation and assign risk categories. These in turn are assessed by the potential lenders’ deal teams and used in their applications to their respective credit committees. Table 14.5-1 presents a typical risk summary for a LNG regasification terminal project. Table 14.5-1 Typical Risk Assessment Results Project Risk Component Project Definition Lng Supply Regasification Technology Independent Power Supply Scale-Up Regulatory Effluents And Emissions

Risk Category Low Low Low

Project Risk Component Interface Management Schedule Capex

Contracting Strategy Facility Implementation

Low To Medium Medium

Construction Logistics Supporting Infrastructure Implementation

Low To Medium Low To Medium

Risk Category Medium Medium Low To Medium

Low

Opex

Low To Medium

Low To Medium Low Low

Operations Operations Logistics Operations Performance Product Offtake Completion And Performance Geography

Medium Medium Medium Low Low To Medium Low To Medium

Each risk category would be supported by a narrative explaining the nature of the risk and the associated mitigation measures that are in place or planned to be put into place. As a general observation, “high” risks are not financeable.

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14.6

EQUATOR PRINCIPLES

14.6.1 Background

On June 4, 2003, ten leading banks from seven countries adopted the “Equator Principles”. Implementation of these principles promotes responsible environmental stewardship and socially responsible development, particularly on projects within developing countries. The number of financial institutions which have adopted the Equator Principles, hereafter referred to as Equator Principles Financial Institutions (“EPFIs”), has since grown to over 60 financial institutions, representing over 85 percent of the global project loan market. Therefore, it is likely that any project funded through project finance will involve one or more of the banks which have adopted the Equator Principles. Compliance with the requirements of the Equator Principles is a fundamental requirement of any credit application to these banks. The Equator Principles are based on the policies and guidelines of the World Bank Group in general and those of the International Finance Corporation (“IFC”), the private-sector investment arm of the World The Equator Principles are applicable to projects with a capital cost of US$10 million or more and are intended to serve as a common baseline and framework for implementation of each adoptive bank’s individual, internal environmental and social procedures and standards for project financing activities across all industry sectors. In adopting the Equator Principles, a bank undertakes to provide loans only to those projects whose sponsors can demonstrate, to the satisfaction of the bank, the sponsors’ ability and willingness to comply with comprehensive processes aimed at ensuring that projects are developed in a socially responsible manner and according to sound environmental management practices. In implementing the Equator Principles, banks must establish internal policies and processes consistent with the principles. EPFIs will only provide loans to projects which conform to the following Equator Principles: 







Equator Principle 1 - Review and Categorization - Each project must be categorized according to the magnitude of its potential impacts and risks in accordance with the environmental and social screening criteria of the IFC: o Category A – Projects with potentially significant adverse social or environmental impacts that are diverse, irreversible or unprecedented; o Category B – Projects with potential limited adverse social or environmental impacts that are few in number, generally site-specific, largely reversible and readily addressed through mitigation measures; and o Category C – Projects with minimal or no social or environmental impacts; Equator Principle 2 - Social and Environmental Assessment - The borrower must conduct a Social and Environmental Assessment (“Assessment”) process to address the relevant social and environmental impacts and risks of the proposed project. The Assessment must also propose mitigation and management measures relevant and appropriate to the nature and scale of the proposed project; Equator Principle 3 - Applicable Social and Environmental Standards - The Assessment must establish the project’s overall compliance with, or justified deviation from, the applicable IFC Performance Standards and the World Bank Group Industry-Specific EHS Guidelines; Equator Principle 4 - Action Plan and Management System - The borrower must prepare an Action Plan which addresses the relevant findings and draws on the conclusions of the Assessment to describe and prioritize the actions required to implement mitigation measures,

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











corrective actions and monitoring measures necessary to management the impacts and risks identified in the Assessment. The borrower must establish a project management system to implement the action plan; Equator Principle 5 - Consultation and Disclosure - The borrower, government or third party expert must consult with communities potentially affected by the proposed project in a structured and culturally appropriate manner. For projects with significant adverse impacts on affected communities, the consultation process must ensure free, prior and informed consultation and facilitate informed participation to establish that a project has adequately incorporated affected community concerns. The borrower must document the consultation process, including any agreed actions resulting from the consultation. Disclosure of potential impacts must occur early in the Assessment process (i.e., before project construction commences) and continue on an ongoing basis throughout the construction and operation phases of the project; Equator Principle 6 - Grievance Mechanism - The borrower must establish a grievance mechanism as a part of the project’s environmental and social management system to allow the borrower to receive and resolve concerns and grievances concerning the project’s social and environmental performance raised by individuals or groups from project-affected communities; Equator Principle 7 - Independent Review - An independent social or environmental expert not directly associated with the borrower must review the Assessment, action plan and consultation process documentation in order to assist the EPFIs’ due diligence and assess compliance with the Equator Principles; Equator Principle 8 – Covenants - The borrower must covenant, as part of its financing documentation, to the following: o Comply with all relevant host country social and environmental laws, regulations and permits; o Comply with the project-specific action plan during construction and operation; o Provide periodic reports (not less than annually) to the EPFI to document compliance with the action plan and relevant host country social and environmental laws, regulations and permits; o Decommission the project facilities in accordance with an agreed decommissioning plan; Equator Principle 9 – Independent Monitoring and Reporting - The EPFIs must appoint, or the borrower must retain, qualified and experienced external experts to verify the project’s monitoring information as shared with the EPFIs; and Equator Principle 10 – EPFI Reporting - Each EPFI adopting the Equator Principles commits to periodic public reports (at least annually) concerning its Equator Principles implementation processes and experience, taking into account appropriate confidentiality considerations. At a minimum, this reporting must include the number of transactions screened by each EPFI, including the categorization accorded to transactions (and may include a breakdown by sector or region), and information regarding implementation.

Category A, B and C projects must comply with the Equator Principles listed above in accordance with the following conditions:   

Equator Principle 1 applies to all projects; Equator Principles 2 through 9 do not apply to Category C projects; Equator Principle 2 applies to all Category A and B projects;

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Section 14 – Comments On Project Financing



 

Equator Principles 3 through 6 do not apply to projects located in countries which are defined by the World Bank Development Indicators Database as High-Income Organization of Economic Cooperation and Development (“OECD”) countries. The regulatory, permitting and public comment requirements in High-Income OECD countries generally meet or exceed the requirements of the IFC Performance Standards and the WBG EHS Guidelines. Accordingly, successful completion of an Assessment (or its equivalent) process in compliance with host country laws in High-Income OECD countries is considered to be an acceptable substitute for Equator Principle’s 3 through 6. However, the OECD currently lists Mexico as an “upper middle income” country eligible for borrowing from the IDA. Consequently, Equator Principle’s 3 through 6 apply to the Project; Equator Principle’s 7 through 9 apply to all Category A projects and, as appropriate, Category B projects; and Equator Principle 10 applies to the EPFIs, rather than to the borrower.

14.6.2 World Bank

The World Bank Group consists of five closely associated institutions, all owned by member countries that carry ultimate decision-making power. Each institution plays a distinct role in the World Bank Group’s mission to fight poverty and improve living standards for people in the developing world. 







International Bank for Reconstruction and Development (“IBRD”) – The IBRD aims to reduce poverty in middle-income and creditworthy poorer countries by promoting sustainable development through loans, guarantees, risk management products, and analytical and advisory services. Established in 1944 as the original institution of the World Bank Group, IBRD is structured like a cooperative that is owned and operated for the benefit of its 185 member countries. Income generated by IBRD loans over the years has allowed the agency to fund important development activities and ensures the agency’s strong financial position. This enables borrowing in capital markets at low cost. Thus, IBRD is able to offer its clients good borrowing terms; International Development Association (“IDA”) – The IDA offers interest-free credits and grants to the world’s poorest countries. This highly concessional financing is vital because these countries have little or no capacity to borrow on market terms. IDA resources and technical assistance support country-led poverty reduction strategies in key areas: increased productivity, better governance and accountability, improved private investment climate, and access to education and health care for poor people; International Finance Corporation (“IFC”) – The IFC fosters sustainable economic growth in developing countries by financing private sector investment, mobilizing private capital in local and international financial markets, and providing advisory and risk mitigation services to businesses and governments. IFC’s vision is that people should have the opportunity to escape poverty and improve their lives. It seeks to reach businesses in regions and countries that have limited access to capital and provides finance in markets deemed too risky by commercial investors. IFC also adds value to the projects it finances through its corporate governance, environmental and social expertise. It is the largest multilateral source of debt and equity financing for private enterprise in developing countries; Multilateral Investment Guarantee Agency (“MIGA”) – Concerns about investment environments and perceptions of political risk often inhibit foreign direct investment, a key driver of economic growth in developing countries. The MIGA addresses these concerns by providing political risk insurance (guarantees), offering investor’s protection against noncommercial risks such as expropriation, currency inconvertibility, breach of contract, war and civil disturbance. MIGA

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Section 14 – Comments On Project Financing



also provides advisory services to help countries attract and retain foreign investment, mediates investment disputes to keep current investments intact and remove potential obstacles to future investment, and disseminates information on investment opportunities to the international business community; International Centre for Settlement of Investment Disputes (“ICSID”) – The ICSID is an institution specifically designed to facilitate the settlement of investment disputes between governments and private foreign investors through conciliation and arbitration. Its aim is to foster an atmosphere of mutual confidence between states and investors in order to promote increased flows of international investment. Recourse to ICSID conciliation and arbitration is entirely voluntary. ICSID also issues publications on dispute settlement and foreign investment law.

The term “World Bank Group” encompasses all five institutions, while the term “World Bank” refers specifically to two of the five, IBRD and IDA. The IFC fosters sustainable economic growth in developing countries by financing private sector investment, mobilizing capital in the international financial markets, and providing advisory services to businesses and governments. It applies environmental and social standards to all the projects it finances to minimize project-related impacts on the environment and affected communities. In February 2006, the World Bank Group completed a rigorous process of updating its standards, namely: 



IFC Sustainability Framework, which includes the following policies, procedures and standards: o Policy on Social and Environmental Sustainability – defines IFC’s role and responsibility in supporting project performance in partnership with clients; o Disclosure Policy – defines IFC’s obligations to disclose information about itself as an institution and its activities; o Environmental and Social Review Procedure – gives direction to IFC officers in implementing the Polity on Social and Environmental Sustainability and reviewing compliance and implementation by private sector projects; o Performance Standards – defines clients’ roles and responsibilities for managing their projects and the requirements for receiving and retaining IFC support. The standards include requirements to disclose information; and World Bank Group Environmental, Health and Safety (“EHS”) Guidelines – industry sector specific technical guidance informing those parts of the new policy structure related to environmental, health and safety issues (replaces and combines the World Bank Group Pollution Prevention and Abatement Handbook and the IFC EHS Guidelines).

The IFC applies its Performance Standards to manage social and environmental risks and impacts and to enhance development opportunities in its private sector financing in its member countries eligible for financing. Performance Standards may also be applied by other financial institutions electing to apply them to projects in emerging markets. Together, the IFC’s eight Performance Standards establish standards that the client must meet throughout the life of an investment by IFC or other relevant financial institution (the term “client” is used throughout the Performance Standards broadly to refer to the party responsible for implementing and operating the project that is being financed, or the recipient of the financing, depending on the project structure and type of financing).

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Section 14 – Comments On Project Financing

       

Performance Standard 1 – Social and Environmental Assessment and Management System; Performance Standard 2 – Labor and Working Conditions; Performance Standard 3 – Pollution Prevention and Abatement; Performance Standard 4 – Community Health, Safety and Security; Performance Standard 5 – Land Acquisition and Involuntary Resettlement; Performance Standard 6 – Biodiversity Conservation and Sustainable Natural Resource Management; Performance Standard 7 – Indigenous Peoples; and Performance Standard 8 – Cultural Heritage.

In meeting the requirements of the IFC Performance Standards, clients must comply with applicable national laws, including those laws implementing host country obligations under international law. IFC recently completed a fresh revision to its Sustainability Framework:   

April 14, 2011 – IFC posted its revised policies, procedures and standards on its web site; May 12, 2011 – These revisions were formally approved by IFC’s Board of Directors; and January 1, 2012 – These revisions become effective.

These revisions are summarized below: 





Sustainability Policy o Strengthens IFC’s commitments to climate change, business and human rights, corporate governance and gender o Revises and strengthens categorization system  Greater emphasis on inherent risks and project context  Categorizes actions by Financial Intermediaries (“FIs”) according to the level of their environmental and social risks o Strengthens due diligence for FIs o Clarifies due diligence for Advisory Services o Strengthens disclosure requirements for extractive industry projects Performance Standard 1 o Changes name to “Assessment and Management of Environmental and Social Risks and Impacts” o Refers to private sector responsibility to respect human rights o Introduces better applicability to investments other than project finance (non-defined assets concept) o Requires stakeholder engagement beyond Affected Communities o Clarifies levels of stakeholder engagement under different circumstances o Requires development of a formal environment and social policy reflecting principles of the Performance Standards o Introduces participatory monitoring (when appropriate) as an option during implementation o Requires period performance reviews by senior management Performance Standard 2 o Establishes requirement for comparable terms and conditions for migrant workers compared to non-migrant workers

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Section 14 – Comments On Project Financing

Introduces quality requirements for workers’ accommodation Requires ongoing monitoring of working conditions for workers under the age of 18 Requires establishing policies and procedures to manage and monitor compliance of third parties with Performance Standard 2 o Requires alternatives analysis in case of retrenchment o Requires ongoing monitoring of primary supply chain o Introduces “safety” trigger in primary supply chain Performance Standard 3 o Changes name to “Resource Efficiency and Pollution Prevention” o Introduces a resource efficiency concept for energy, water and core material inputs o Strengthens focus on energy efficiency and greenhouse gas measurement o Reduces greenhouse gas emissions thresholds for reporting to IFC from 100,000 tons of CO2 to 25,000 tons of CO2 per year o Requires determination of accountability with regards to historical pollution o Introduces concept of “duty of care” for hazardous waste disposal Performance Standard 4 o Considers risks to communities associated with use and/or alteration of natural resources and climate change through an ecosystems approach Performance Standard 5 o Extends scope of application to restrictions on land use o Strengthens requirements regarding consultations o Introduces a requirement for a completion audit under certain circumstances Performance Standard 6 o Changes name to “Biodiversity Conservation and Sustainable Management of Living Natural Resources” o Clarifies definitions of and requirements for various types of habitats o Introduces stronger requirements for biodiversity offsets o Introduces specific requirements for plantations and natural forests o Introduces specific requirements for management of renewable natural resources o Strengthens supply chain scope Performance Standard 7 o Expands consideration of Indigenous Peoples’ specific circumstances in developing mitigation measures and compensation o Introduces requirement for land acquisition due diligence with regards to lands subject to traditional ownership or under customary use o Introduces the concept of Free, Prior and Informed Consent (“FPIC”) under certain circumstances Performance Standard 8 o Requires clients to allow access to cultural sites o o o













Although the 2011 revisions are not technically effective until January 1, 2012, Shaw Consultants notes that several of these revisions have already been implemented by IFC staff on an “unwritten rule” basis. Significantly, the 2011 revisions to IFC’s Sustainability Framework do not preclude the IFC from participating in oil and gas exploration and development, mining and other “extractive” projects. In addition, the IFC’s 2011 revisions discussed above do not affect the EHS Guidelines.

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Section 14 – Comments On Project Financing

As of April 30, 2007, new versions of the EHS Guidelines are now in use. The EHS Guidelines replace those documents previously published in Part III of the Pollution Prevention and Abatement Handbook and on the IFC website. The EHS Guidelines are technical reference documents with general and industry-specific examples of “good international industry practice” as defined in IFC’s Performance Standard 3. They contain performance levels and measures that are generally considered to be achievable in new facilities at reasonable costs by existing technology. When host country regulations differ from the levels and measures presented in the EHS Guidelines, projects are expected to achieve whichever is more stringent. If less stringent levels or measures are appropriate in view of specific project circumstances, a full and detailed justification for any proposed alternatives is needed as part of the site-specific environmental assessment. This justification should demonstrate that the choice for any alternate performance levels is protective of human health and the environment. Shaw Consultants identified the following EHS Guidelines which are relevant to the Project: 



14.7

Environmental, Health and Safety General Guidelines – contain information on cross-cutting environmental, health and safety issues potentially applicable to all industry sectors. These guidelines should be used together with the relevant industry sector guideline; and Environmental, Health and Safety Guidelines for Onshore Oil and Gas Development – include information relevant to seismic exploration; exploratory and production drilling; development and production activities; transportation activities including pipelines; other facilities including pump stations, metering stations, pigging stations, compressor stations and storage facilities; ancillary and support operations; and decommissioning. LENDERS’ DUE DILIGENCE REPORT

A typical due diligence review of a LNG regasification project entails the following:         

  

Review of the condition of any existing facilities that required rework, repair and/or refurbishment prior to their inclusion into the Project; Review of technology, engineering design and specifications for the proposed new facilities; Review of interfaces with existing infrastructure; Review of the Sponsors’ overall Project execution strategy; Review of the Project capital cost estimate and supporting data for completeness and reasonableness; Review of LNG supply market and shipping logistics; Review of the Sponsors’ forecast operating and maintenance costs for reasonableness; Review of projected performance data utilized in economic analyses to assess the facilities’ ability to meet minimum net outputs and performance standards during the term of the debt; Review of the technical aspects of all major contracts currently available pertaining to the Project for compatibility of contract terms and conditions with the design objectives and with the forecast operating parameters of the facility; Review of the Project’s ability to obtain and comply with the requirements of applicable permits and licenses for construction and operation of the Project facilities; Review of compliance with the requirements of the Equator Principles; Review of the reasonableness of the technical inputs to the pro forma economic model;

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Section 14 – Comments On Project Financing

 

Recommendation of sensitivity analyses to be undertaken on the input assumptions to the financial model and comment on their impact on debt service coverage ratios; and Preparation of a written report describing the results of the reviews above.

The ITC has to ensure that the individual technical and commercial components of the Project are consistent. Shaw Consultants likens this to assembling a jigsaw puzzle, see Figure 14.7-1. Figure 14.7-1 Due Diligence Process

The output from the review process provides a check on the inputs to the financial model.

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CURACAO LNG TERMINAL ONSHORE OPTION CONCEPTUAL FEASIBILITY STUDY

CONCEPTUAL DESIGN BASIS

Project No. 145790

DESIGN BASIS CONCEPTUAL Date 06/25/12

REV: B

CURACAO LNG TERMINAL ONSHORE OPTION CONCEPTUAL FEASIBILITY STUDY

DESIGN BASIS CONCEPTUAL Date 06/25/12

REV: B

TABLE OF CONTENTS 1. 

OVERVIEW....................................................................................................................... 5 

2. 

LNG TERMINAL DESIGN CAPACITY.............................................................................. 5 

3. 

LNG FEEDSTOCK DESIGN COMPOSITION .................................................................. 5 

4. 

LNG SPECIFICATIONS.................................................................................................... 6 

5. 

TERMINAL SITE LOCATION ........................................................................................... 7 

6. 

FUNCTIONAL REQUIREMENTS ..................................................................................... 9  6.1 

Sendout Gas Capacity and Quality Specifications ................................................ 9 

6.1 

On-Line Availability ............................................................................................... 9 

6.2 

Sendout Gas Demand Forecast............................................................................ 9 

6.3 

Design Life .......................................................................................................... 10 

6.4 

General Requirements ........................................................................................ 10  6.4.1  Jetty, Berthing and Cargo Unloading Facility .......................................... 10  6.4.2  LNG Storage ........................................................................................... 11  6.4.3  Boil Off Gas Handling System ................................................................. 12  6.4.4  LNG Pumping and Sendout System ....................................................... 12  6.4.5  LNG Vaporization System ....................................................................... 12  6.4.6  Gas Sendout System .............................................................................. 13  6.4.7  Operations Control System ..................................................................... 13  6.4.8  Process Heating Medium System ........................................................... 14  6.4.9  Seawater System .................................................................................... 14  6.4.10  Pressure Relief and Flare/Vent Systems ................................................ 15  6.4.11  Fuel Gas System ..................................................................................... 16  6.4.12  Utility and Instrument Air System ............................................................ 16  6.4.13  Nitrogen System ...................................................................................... 17  6.4.14  Wastewater Treatment ............................................................................ 18  6.4.15  Bulk Storage ............................................................................................ 18  6.4.16  Electric Power Supply and Distribution ................................................... 18  6.4.17  Water Supply Systems ............................................................................ 19 

6.5 

Safety System Requirements.............................................................................. 20 

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6.5.1  Fire Protection System ............................................................................ 20  6.5.2  Fire and Gas Detection System .............................................................. 21  6.5.3  Ignition Source Control ............................................................................ 21  6.5.4  Emergency Shutdown System ................................................................ 21  6.5.5  Emergency Evacuation ........................................................................... 22  6.5.6  LNG Spill Impoundment System ............................................................. 22  6.5.7  Thermal Exclusion Zone .......................................................................... 23  6.5.8  Vapor Dispersion Zone............................................................................ 23  6.5.9  Quantitative Risk Assessment (QRA) Study ........................................... 24 

7. 

6.6 

Security Systems ................................................................................................ 24 

6.7 

Buildings and Infrastructure ................................................................................ 24 

SITE DESIGN DATA....................................................................................................... 24  7.1 

Location............................................................................................................... 24 

7.2 

Ambient Air Temperatures and Relative Humidity .............................................. 25 

7.3 

Bathymetric Design Data .................................................................................... 25 

7.4 

Wind and Weather Design Data .......................................................................... 25 

7.5 

Seawater Physical Properties ............................................................................. 26 

7.6 

Seismic Design Criteria ....................................................................................... 26 

8. 

ENVIRONMENTAL PERMITTING .................................................................................. 26 

9. 

DESIGN STANDARDS AND CODES............................................................................. 26  9.1 

Marine Facilities (Dock, Mooring Systems, Berthing and Jetty) .......................... 27 

9.2 

Onshore Facilities within Terminal Fence ........................................................... 27 

9.3 

Onshore Gas Pipelines Outside Terminal Fence ................................................ 28 

10. 

GAS SENDOUT PIPELINE TIE-IN ................................................................................. 28 

11. 

PRIME MOVERS ............................................................................................................ 28 

12. 

NOISE ABATEMENT ...................................................................................................... 28 

13. 

MISCELLANEOUS DESIGN SPECIFICATIONS ............................................................ 29  13.1 

Corrosion Allowance ........................................................................................... 29  13.1.1  Equipment Corrosion Allowance ............................................................. 29  13.1.2  Piping Corrosion Allowance .................................................................... 29 

13.2 

Unloading Transfer Lines .................................................................................... 30 

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13.3 

DESIGN BASIS CONCEPTUAL Date 06/25/12

REV: B

Sendout Heat Exchangers .................................................................................. 30  13.3.1  Open Rack Vaporizers (ORVs) ............................................................... 30  13.3.2  Gas Sendout Superheater Shell & Tube Exchanger ............................... 30 

13.4 

BOG Condenser.................................................................................................. 30 

13.5 

Line Sizing Criteria .............................................................................................. 31  13.5.1  Vapor Lines ............................................................................................. 31  13.5.2  Liquid Lines ............................................................................................. 31 

14. 

DEFINITION OF TERMS ................................................................................................ 32 

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1.

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REV: B

OVERVIEW

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 Curacao‘s energy supply mix to improve security of supplies, achieve long-term stability in energy prices and to improve the environmental sustainability of providing energy. Under this strategy, it is proposed to import liquefied natural gas (LNG) to Curacao under long-term contractual arrangements to initially meet the needs of the local power generation and expandable to meet the needs of the Isla Refinery operation and its associated utility plant. Refineria di Korsou N.V. (RDK) owns the refinery in Curacao which is currently leased and operated by PDVSA. RDK is owned and controlled by the GOC. RDK engaged Shaw Consultants International, Inc. (Shaw Consultants) to complete a conceptual design for a conventional onshore LNG receiving and regasification terminal (LNG Terminal). This document is the Design Basis (DB) used in the conceptual design of the LNG Terminal. This DB is “CONCEPTUAL” in nature and may be subject to change as more information is gathered and the project is more clearly defined. 2.

LNG TERMINAL DESIGN CAPACITY

The Design Capacity of the Curacao LNG Terminal shall be 137,000 MMBtu per day. The Terminal shall be designed to accommodate a range of LNG feedstock compositions with the higher heating value (HHV) of the resulting sendout gas ranging between a maximum of 1,150 Btu/scf and a minimum of 1,000 Btu/scf. Based on processing LNG supplied from Atlantic LNG Trinidad with an average HHV of approximately 1,024 Btu/scf, the volumetric gas sendout rate will be approximately 133.7 MMscfd. Actual volumetric sendout rate will depend on the HHV of the LNG feedstock. 3.

LNG FEEDSTOCK DESIGN COMPOSITION

The Terminal shall be designed with the flexibility to process LNG feedstock ranging from rich to lean compositions as listed in Table 1. The Design Composition is noted in the table. Contractor shall make heat and material balance calculations for the Design Composition and shall verify that the equipment provided in the design is capable of processing the richest LNG feedstock composition shown in Table 1 at the Design Capacity throughput.

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CONCEPTUAL

CONCEPTUAL FEASIBILITY STUDY

Date

REV:

06/25/12

B

Table 1 Range of LNG Feedstock Compositions PROPERTIES Molecular Weight 3 LNG Density lb/ft NG Sp.Gr. HHV Btu/scf Wobbe Index COMPOSITION CO2 N2 C1 C2 C3 i-C4 n-C4 i-C5 n-C5 + C6 Total

4.

Trinidad

16.82 27.46 0.58 1,056 1,385 Mole% 0.00 0.01 96.07 2.75 0.77 0.21 0.18 0.01 0.00 0.00 100.00

Idku

16.55 26.83 0.57 1,037 1,375 Mole% 0.00 0.01 97.06 2.41 0.36 0.08 0.07 0.01 0.00 0.00 100.00

Damietta

16.39 26.83 0.57 1,028 1,367 Mole% 0.00 0.02 97.81 2.01 0.07 0.04 0.01 0.00 0.04 0.00 100.00

Nigeria

Oman

Algeria

17.44 28.08 0.60 1,084 1,396 Mole% 0.00 0.08 92.85 4.69 1.93 0.24 0.19 0.02 0.00 0.00 100.00

18.20 29.32 0.63 1,119 1,410 Mole% 0.00 0.43 89.68 6.19 2.31 0.71 0.66 0.02 0.00 0.00 100.00

18.34 29.60 0.63 1,110 1,396 Mole% 0.00 1.40 86.90 9.00 1.95 0.25 0.50 0.00 0.00 0.00 100.00

Peru

17.55 28.42 0.61 1,083 1,391 Mole% 0.00 0.55 89.20 10.21 0.04 0.00 0.00 0.00 0.00 0.00 100.00

Sabine Pass

16.51 27.14 0.57 1,027 1,360 Mole% 0.00 0.50 97.19 1.92 0.25 0.06 0.05 0.02 0.01 0.00 100.00

DESIGN

16.67 27.09 0.57 1,044 1,376 Mole% 0.00 0.00 95.50 4.50 0.00 0.00 0.00 0.00 0.00 0.00 100.00

LNG SPECIFICATIONS

The LNG Terminal shall be designed to accept both Lean and Rich LNG cargoes. The terms “Lean” and “Rich” in this context are used to characterize the relative quantity of ethane and heavier components (C2+) contained in the LNG. LNG cargoes unloaded from an LNG ship into the Curacao LNG Terminal shall meet or exceed the quality LNG specifications given in Table 2. Table 2 LNG CARGO QUALITY SPECIFICATIONS LNG CARGO QUALITY SPECIFICATION Ship LNG Saturation Pressure N2 O2 H2S

SPECIFICATION VALUE Less than 16.2 psia Less than 1.50 Mol % Less than 1 ppm by vol Less than 0.25 grains/100 scf (vaporized)

Total Sulfur

Less than 0.5 grains/100 scf (vaporized)

Mercaptans

Less than 0.25 grains/100 scf (vaporized)

+

Less than 0.3 mol %

+

Less than 1.0 ppm by volume

C5 C6

Water, CO2 or Mercury

None

Hazardous or Toxic Substances

None

Higher Heating Value

Between 1,150 and 1,000 Btu/scf

Page 6

CURACAO LNG TERMINAL ONSHORE OPTION CONCEPTUAL FEASIBILITY STUDY

5.

DESIGN BASIS CONCEPTUAL Date 06/25/12

REV: B

TERMINAL SITE LOCATION

Wind: The prevailing trade wind directions vary slightly East North East to East South East, with an average velocity of 11 to 16 knots. Tides: The tidal range in the Ports of Curacao rarely exceeds two feet. Currents: The current usually sets about West North West near the shores of Curacao, with a maximum velocity of 3 knots for short periods. The regular velocity is not more than 0.5 knots. Sometimes an easterly current occurs, but this is of lesser strength. Pilot: Pilot is compulsory for vessels of 50 GT and higher. Pilots are provided from Schottegat for all ports. Arrival time should be sent 72, 48, 24 and 12 hours in advance via the local agent and when in radio range to Fort Nassau Traffic Control. The Bullen Bay site has been selected for the Curacao LNG Terminal and is illustrated in Figure 1 and Figure 2. The Terminal facilities will be installed on Parcel A located adjacent to Jetty No.1. Jetty No.1 is potentially available for use in this project and will be upgraded / modified for a LNG unloading facility. Jetty No.1 has sufficient clearance and access for accommodating carrier up to 400 meters in length with a maximum draft of 21 meters. Figure 1 Bullen Bay Site

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REV: B

Figure 2 Bullen Bay Site Option Close-up

Jetty No. 1 will be upgraded for LNG service and shall be dedicated to serve the Curacao LNG Terminal. With respect to tug assistance at Bullen Bay, tugs are compulsory and availably from the Schottegat Harbor at Willemstad, although there is a tugboat jetty at Bullen bay for tugs, which can accommodate tugs up to 7 meters in draft. Tug support current requirements are summarized as follows: Arrival Support 

Tankers up to 150,000 SDW 2 tugs;



Tankers over 150,000 SDW up to 350.000 SDW 3 tugs; and



Tankers over 350,000 SDW 4 tugs.

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Departure Support  6.

On departure 2 tugs for all tankers.

FUNCTIONAL REQUIREMENTS

The Curacao LNG Terminal shall be designed to meet the following functional requirements. 6.1

Sendout Gas Capacity and Quality Specifications

The sendout gas capacity and quality specifications for the LNG Terminal are given in Table 3. Table 3 Sendout Gas Capacity and Specifications PARAMETER \ SITE

BULLEN BAY

Max. Sendout Gas Pressure Peak Sendout Gas Rate Minimum Sendout Gas Rate Sendout Gas Temperature HHV

20,000 MMBtu/Day o

o

Minimum: 60 F

Maximum: 120 F

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 HC Dew Point

6.1

780 psig 137,000 MMBtu/Day

7.0 lbs/MMscf o

Less than 30 F @ 500 psig

On-Line Availability

It is desired that the sparing philosophy and design configuration used in the Curacao LNG Terminal will yield a highly reliable operating facility. The target on-line availability of the integrated gas sendout system is 99.0%. Certain situations and equipment failures shall be considered as conditions of Force Majeure. These shall include Hurricanes and severe weather, explosions, fire, acts of terrorism, and other events that are not within the direct control of the Terminal operations. This facility shall not be designed to prevent outages that may occur resulting from conditions of Force Majeure. 6.2

Sendout Gas Demand Forecast

The Curacao LNG Terminal sendout gas demand forecast is illustrated in Figure 3. The Terminal shall be designed taking into consideration the sendout demand forecast illustrated below.

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CONCEPTUAL Date

REV:

06/25/12

B

Figure 3 Curacao Sendout Gas Demand Forecast

NOTE: Volumes shown in Figure 3 are based on a gas equivalent HHV of 1,000 Btu/scf.

6.3

Design Life

The design life of this Terminal shall be 25 years. 6.4

General Requirements

Some of the more important design criteria established for the Terminal include the following. 6.4.1

Jetty, Berthing and Cargo Unloading Facility

A single berth shall be provided at the Terminal dedicated for LNG operations. The marine berthing facility will include the berth, jetty, breasting dolphins, mooring dolphins, dock drain trough and sump, catwalks to dolphins, approach and pipe trestles, shoreline protection, and navigation aids (as needed). Handrails, a gangway, gangway access tower, concrete insert installation for topsides, mooring hooks, and a complete vessel approach, mooring line load monitoring system will be included in this scope. Electrical, lighting, and power will be provided for the docking area. The jetty facilities shall be designed to accommodate LNG cargo transfer from LNG Carriers in the 75,000 m3 class up to the new 150,000 m3 class. Four standard size 16” LNG unloading arms shall be provided at the platform jetty – 2 liquid, 1 hybrid liquid/vapor and 1 vapor.

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CURACAO LNG TERMINAL ONSHORE OPTION CONCEPTUAL FEASIBILITY STUDY

DESIGN BASIS CONCEPTUAL Date

REV:

06/25/12

B

The LNG Terminal shall be designed to receive LNG cargo transfer from the LNG carriers at a maximum unloading rate of 12,000 m3/hr to facilitate LNG carrier unloading within a 14 to 18 hour period. The following requirement shall apply at the LNG carrier interface; 

BOG Vapor Return Conditions at Ship Flange



LNG Unloading Minimum Pressure at Ship Flange 80 psig. 6.4.2

2.0 psig, Max Temperature -220oF.

LNG Storage

One LNG Storage Tank will be provided. The tank shall be a nominal 160,000m3 “full containment” type design and shall hold a net volume of approximately 153,800m3 (minimum to maximum level). The tank shall be above ground, double walled construction per API 620 Appendix Q definition, with the two walls separated by insulation material. The tank shall meet "Double Containment" design criteria as defined by EEMUA 147. The inner tank shall be made of 9% nickel steel and the outer tank shall be made of pre stressed concrete with a carbon steel plate roof. However, a single containment type tank will be considered if Contractor can demonstrate that the thermal and gas dispersion zones fit within the terminal plot space in compliance with NFPA 59 A requirements. All connections to the LNG tank shall be through the roof. There will be no penetrations through the sides or the bottom of the tank. This configuration is made possible by use of submerged In-Tank LNG Pumps for LNG sendout. The tank shall be provided with both top and bottom filling connections to alleviate the possibility of roll-over conditions. Multiple temperature detectors shall be furnished in the wall and the floor of the storage tank to monitor the temperature profile. A density monitoring system shall be provided to detect stratification and potential roll-over conditions. The tank shall be equipped with independent level transmitters, to protect against overfilling during unloading. A highhigh level, if detected by the level instruments, shall lead to closing of the inlet valve delivering LNG to the tank. The tank shall also be provided with overpressure and vacuum relief valves. The design pressure of the LNG storage tank shall be 2.8 psig (190 mbarg). The tank will generally operate in a pressure range of 0.7 to 2.0 psig (50 to 140 mbarg). The pressure in the tank will be maintained by sending gas to the boil off gas (BOG) compressor system. During upset situations the BOG will be vented to the flare/vent system. If the pressure drops to 0.6 psig (40 mbarg), the BOG compressors will be stopped, and at 0.45 psig (30 mbarg) the vacuum break gas will be introduced into the tanks to avoid lifting the vacuum relief valve. If the pressure continues to drop, at -0.22 psig (15 mbarg) the vacuum breaker introduces atmospheric air into the tank. If the pressure goes above 2.2 psig (150 mbarg), the standby BOG compressor will started. If the pressure continues to rise, at 2.5 psig (170 mbarg) the flare control valve opens to send gas to the flare/vent system. If the pressure rises above 2.8 psig (190 mbarg), the pressure safety valves release gas to the atmosphere from the tank top. The LNG tank insulation system shall be designed to limit BOG generated from ambient heat influx to 0.05% of the tank volume per day.

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CURACAO LNG TERMINAL ONSHORE OPTION CONCEPTUAL FEASIBILITY STUDY

6.4.3

DESIGN BASIS CONCEPTUAL Date 06/25/12

REV: B

Boil Off Gas Handling System

During unloading operations, no BOG shall be flared or vented. The BOG system located in the Terminal shall be designed and sized to compress and recover all BOG to prevent flaring or venting of gas at any time during LNG cargo transfer or during normal sendout operations. Flaring or venting will only be permitted during emergency conditions when the sendout pipeline is unavailable. Contractor shall calculate the maximum BOG produced during LNG unloading operations and size the BOG compressors and other BOG handling equipment accordingly. During the unloading operation BOG will be displaced from the LNG storage tank and Ship Vapor Return Blowers shall be provided to return cold BOG to the ship. This gas replaces the volume of the liquid pumped out by the ship pumps. The vapor return rate should be volumetrically equivalent to the unloading rate up to 12,000m3/hr to maintain pressure in the ship tanks. The ship can only accept LNG vapors at -220° F or colder. The BOG to be returned to the ship shall be compressed and chilled. In order to chill the return vapors to ship, LNG injection spray into the vapor return stream shall be provided at the jetty. A LNG drain drum shall be located on the ship vapor return downstream of the spray to separate any liquids from the vapor prior to entering the vapor return arm. 6.4.4

LNG Pumping and Sendout System

LNG shall be pumped out from the LNG storage tank to the BOG Condenser. The pumps shall be of the submerged in-tank type with the motor and pump mounted as one enclosed unit in wells installed inside the tank. Two 100% pumps shall be provided in the tank. For future expansion, two spare intank wells shall also be provided in the LNG tank design. A BOG Condenser/Absorber shall be provided to re-condense BOG produced from the LNG Storage Tank. LNG from the In-Tank LNG Pumps shall be sent to the BOG Condenser to condense the BOG vapors. LNG from the bottom of the BOG Condenser/Absorber shall be pumped to sendout pressure by two 100% multi-stage pot mounted LNG Sendout Pumps and sent to the Vaporization System. 6.4.5

LNG Vaporization System

In the Curacao LNG Terminal, seawater shall provide the heat to vaporize LNG using traditional Open Rack Vaporizers (ORVs). Two 100% ORVs shall be provided in the design. The ORVs shall be designed by Kobe Steel or an approved alternate vendor. Seawater shall enter the top of the ORV under flow control at a temperature of approximately 78oF (25.6oC) and shall be uniformly distributed over the heat exchange panels. LNG shall be fed into the ORV panels from the bottom at a temperature of approximately -192oF ( -124oC). As seawater flows down the outside of the panels, the LNG shall be vaporized and natural gas shall exit from the top of the ORV panels at a temperature of not less than 40oF (4.4oC).

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CURACAO LNG TERMINAL ONSHORE OPTION CONCEPTUAL FEASIBILITY STUDY

DESIGN BASIS CONCEPTUAL Date 06/25/12

REV: B

This cool temperature creates a need for a superheater to raise the gas temperature to 60ºF before sending it to the pipeline. This shall be accomplished by two 100% Sendout Gas Superheaters. These exchangers shall be a conventional shell and tube design and shall be heated by a separate Heating Medium (HM) circulation system which circulates a water/glycol solution through two 100% direct gas fired HM Heaters and returns it hot to the heat exchanger units. 6.4.6

Gas Sendout System

After superheating, the sendout gas shall then passes through the Terminal gas metering station where the flow will recorded before entering the pipeline system. An automated gas sampler shall be provided to collect and measure the heating value of the gas for use in monthly custody transfer accounting. The natural gas from the LNG Terminal shall be transported in the Curacao sendout pipeline and delivered to the meter station at each respective gas customer. The sendout system shall have a robust design pressure rated to ANSI 600 pressure class. Pressure control of the pipeline shall be achieved by controlling the LNG flow feeding the Vaporization System with cascade reset of the LNG flow set point being automatically adjusted by the Terminal gas pressure control unit which monitors the sendout gas pressure to the pipeline. Normal gas sendout pressure will be approximately 780 psig. 6.4.7

Operations Control System

Operations control and shutdown of the Terminal facilities shall be conducted from a Central Control Room (“CCR”) located at the Terminal site. The Terminal will incorporate world class integrated control and safety systems (“ICSS”) and an information management system that will provide the capability to operate the facility safely, reliably, and at optimum operating conditions at all times. Multiple operator consoles shall be provided in the CCR for monitoring and controlling Plant operations. Graphical display of the process flow and operating conditions shall be provided from the operator interface consoles. This system shall maximize the use of automation to the extent economically justified and minimize local manual control and the need for operator intervention. It shall include interfaces to a comprehensive suite of applications for use in monitoring, reporting, troubleshooting, planning, accounting, communicating, etc. The systems shall be completely functional for initial facility start-up and shall enable the Terminal operator to easily and efficiently conduct operations for the entire life of the facilities. The operations control system and the CCR shall be designed for easy integration with future equipment controls if the Terminal capacity is expanded. Key objectives of the operating and control design philosophy are as follows: 

Safety of personnel;



Protection of the environment;

Page 13

CURACAO LNG TERMINAL ONSHORE OPTION CONCEPTUAL FEASIBILITY STUDY

DESIGN BASIS CONCEPTUAL Date

REV:

06/25/12

B



Remote monitoring and diagnosis of the facility and equipment;



Start-up and shutdown of all LNG Terminal facilities from the CCR;



Maximum use of automation as practicable; and



Independent design of the telecommunications system for ship-to-shore communications, LNG unloading activities, Terminal operations and sendout pipeline control.

Operation will be completely automated with separate control and shutdown systems. The Terminal will control the total delivery rate for the pipeline based upon pipeline operating pressure and customer demand. The facility will operate as an integrated system including the Terminal and sendout pipeline facilities. 6.4.8

Process Heating Medium System

A process Heating Medium System (HM) shall be provided to service the process utility heating requirements. The heat transfer fluid will be a 30 wt% ethylene glycol aqueous solution used in the closed loop system. Operating conditions for the HM shall be as follows: 

Hot Supply Temperature:

180°F



Hot Supply Pressure:

55 psig

As a minimum, the equipment comprising the HM System shall include: 

1x100% HM Surge Drum;



2x100% HM Circulation Pumps;



1x100% HM Bulk Storage Tank;



1x100% HM Transfer/Unloading Pump;



2x100% Slip stream HM (5 micron) Filters; and



2x100% Direct Gas-Fired HM Heaters. 6.4.9

Seawater System

A Seawater System shall be provided to supply seawater to the LNG Open Rack Vaporizers. Three 50% Seawater Pumps shall be installed on the jetty platform. These pumps shall be a vertical can pump design driven by a top mounted electric motor. Minimum flow control protection shall be provided.

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CURACAO LNG TERMINAL ONSHORE OPTION CONCEPTUAL FEASIBILITY STUDY

DESIGN BASIS CONCEPTUAL Date 06/25/12

REV: B

Large self-cleaning seawater intake screen shall be provided surrounding the pump inlets. The screens shall be designed to meet environmental criteria to prevent small sea life and other biological materials from entering the Seawater System. Velocity through the screens shall be limited to 0.5 feet/second. A manual filter screen trap shall also be installed at the discharge side of each Seawater Pump. A hypochlorite unit shall be provided to chlorinate the seawater which prevents the growth of algae and other biological life forms within the system. Chlorination injection points shall be provided at the suction of each Seawater Pump and at the ORVs for “shock chlorination”. Chlorination concentrations shall be controlled to comply with the environmental regulations. Warm seawater shall be supplied by the pumps at a pressure of 50 psig and will flow to the top of the ORV units. Cool seawater shall exit from the bottom collection basin of the ORV at a temperature not colder than 65oF (18.3oC) and shall flows by gravity to the seawater outflow discharge pipe back into the sea. The seawater outflow discharge pipe return shall be designed to discharge the cool seawater at a subsea depth of approximately 250m where the ambient seawater temperature is approximately equal to the seawater effluent discharge temperature (65oF). Environmental regulation guidelines for thermal discharge require that the temperature at the edge of the thermal mixing zone (defined to be 100m from the point of discharge) be within +/-3oC of the natural ambient temperature. A site specific EIAS will need to be prepared to validate compliance with environmental regulation guidelines. 6.4.10 Pressure Relief and Flare/Vent Systems Flares/Vents shall be sized for the maximum credible relief scenario. The following flare/vent systems shall be provided: 

HP flare/vent designed for dry and cold vapor and blowdown; and



LNG low pressure marine/storage flare/vent designed for boil-off gas from the storage and jetty.

Flare/Vent systems shall be designed for long term reliable operation from the minimum to the maximum flaring/venting rate. Flared/Vented gas shall be metered to comply with environmental reporting requirements. Design of the flare/vent stacks should make allowance for a solar radiation contribution of 0.8 kW/m2. The flare/vent tips shall be located such that the radiation limits specified in API Standards 520 and 521 are not exceeded. Radiation level from the flares/vents shall be limited to the following maximum radiant heat exposure criteria: 

Base of flare/vent stack

9.46 W/m2



Sterile area boundary

6.31 W/m2

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CURACAO LNG TERMINAL ONSHORE OPTION CONCEPTUAL FEASIBILITY STUDY



Flare/Vent knock-out drum

4.73 W/m2



Nearest process equipment limit

3.15 W/m2



Areas where operators work continuously

1.58 W/m2

DESIGN BASIS CONCEPTUAL Date 06/25/12

REV: B

The HP flare/vent stack shall be an elevated derrick supported structure. All flare/vent stacks shall be retractable type that provides flexibility to lower down tips for maintenance. The HP flare/vent system shall be designed to accommodate future expansion. The HP flare/vent system design shall also be designed to facilitate controlled depressurisation of the sendout pipeline and pig launcher. A mechanical interlock PSV valve locking system (uniquely keyed) shall be installed for pressure relief services equipped with multiple PSVs to ensure clear indication to operating personnel that an adequate number of PSVs are on-line. 6.4.11 Fuel Gas System The Fuel Gas Supply System shall be designed in combination with all consumers to enable all possible fuel gas composition changes due to operational upsets to be effectively managed without resultant loss of consumers. Fuel gas heaters shall be provided for both cold start and normal operation. The Fuel Gas System shall provide gas for the HM Heaters as well as blanket gas and purge gas for to the flare headers. Where possible, blanketing gas/pad gas shall use nitrogen rather than fuel gas. The required minimum fuel gas pressure shall not be less than 30 psig. A high pressure fuel system will not be required since all prime movers will be electric motor drive. No gas-fired turbine units are envisioned to be installed at this facility. For startup, fuel gas shall be provided from the BOG system. Since electrical power will be supplied from the Aqualectra power grid, BOG compressors (driven by electric motors) will be operable for cold start. 6.4.12 Utility and Instrument Air System Compressed air shall be provided to supply utility air and to feed the instrument air dryer package for the production of instrument air and nitrogen for the Terminal. Compressed air shall be supplied from two electric motor driven air compressor packages, each of which is capable of supplying 100% of the total air required for the Terminal. All compressors shall supply oil-free air. Utility Air shall meet the following specifications: 

Pressure

140 psig

Page 16

CURACAO LNG TERMINAL ONSHORE OPTION CONCEPTUAL FEASIBILITY STUDY



Maximum Temperature

DESIGN BASIS CONCEPTUAL Date 06/25/12

REV: B

130°F

Instrument quality air shall be produced by an instrument air dryer package (2 x 100% packages). Instrument Air must meet the following specifications: 

Normal Pressure

125 psig



Minimum Pressure

85 psig



Maximum Temperature

130°F



Maximum Dew point

-40°F

The Instrument Air Receiver and Plant Air Receiver shall be sized to provide a minimum of 15 minutes of surge capacity between the normal and minimum operating pressures based on the design air flow rates including design margin. Compressed air prioritization and secured instrument air supplies shall be implemented to maximize instrument air availability. 6.4.13 Nitrogen System Nitrogen generating systems shall be furnished to supply nitrogen requirements for equipment purging, pad gas, compressor gas seal, blanketing, inerting and additional requirements during shutdown and turnarounds. The primary system (a membrane-type nitrogen generator, or equal) shall use instrument air for nitrogen generation, and shall contain multiple membrane units such that one individual membrane unit can be removed from service while the balance of the membranes continue to supply nitrogen at the full design rate. Nitrogen produced must meet the following specifications: 

Supply pressure

110 psig



Maximum Oxygen Content

1.5% - 4%



Minimum Nitrogen Content

96% - 98.5%



Oil & Hydrocarbon Content

None



Maximum Water Content

30 ppmv

The nitrogen generating system shall use dehydrated instrument air as feed gas. The instrument air shall be from an instrument air dryer package that continuously delivers -40ºF dew point air at normal operating pressure. Using the dried instrument air as the feed to the nitrogen generator ensures that the nitrogen produced is sufficiently dry for the various applications and operations within the LNG Terminal.

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CURACAO LNG TERMINAL ONSHORE OPTION CONCEPTUAL FEASIBILITY STUDY

DESIGN BASIS CONCEPTUAL Date 06/25/12

REV: B

Connections shall be provided for a temporary (back-up) liquid nitrogen system designed to furnish nitrogen requirements for startup purging of the LNG Storage Tank. 6.4.14 Wastewater Treatment Wastewater generated from the operation of the Terminal shall include sanitary sewage, oily storm water, process oily water and clean storm water runoff. The collection, treatment, reuse and/or discharge of the wastewater shall be designed to meet the effluent discharge limits established by the regulatory authority in Curacao and must meet global environmental performance standards (“Equator Principles”). 6.4.15 Bulk Storage HM storage (ethylene glycol/water solution) shall be sized based on 6 months of average HM losses, considering that the volume of the standard delivery container is 20 m3. Diesel fuel shall be stored on site for supply to diesel engine driven equipment including the firewater pumps and the emergency generator. Storage volume shall be sized to hold the volume from one large road tankers (34 m3 capacity). Storage for other miscellaneous bulk chemicals required in operating the facility such as lube oil shall be provided. 6.4.16 Electric Power Supply and Distribution Primary electric power required during the construction and operational phases of the project shall be supplied from Aqualectra’s power grid. Contractor shall calculate and guarantee the maximum peak power demand for the Terminal when a ship is unloading and during normal operation when a ship is not unloading cargo. The electrical power distribution shall be supplied at the voltages and frequency listed in Table 4. Table 4 Electrical Power Distribution Frequency Service Medium Voltage Power

Low Voltage Power

Voltage

Phase

(Hz)

6.6 kV

3

50

11 kV

3

50

220 V

1

50

380 V

3

50

Emergency power shall be supplied from a diesel driven Emergency Generator to be installed at the Terminal. Contractor shall calculate and guarantee the emergency power loads. The critical services that shall be included in the emergency power load are listed in Table 5.

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CURACAO LNG TERMINAL ONSHORE OPTION CONCEPTUAL FEASIBILITY STUDY

DESIGN BASIS CONCEPTUAL Date 06/25/12

REV: B

Table 5 Emergency Power Distribution Services Frequency Service

Voltage

Phase

(Hz)

Instrument Air Package

380V

3

50

Jockey Water Pump

220V

3

50

Large Stormwater Sump Pump

380V

3

50

Small Stormwater Sump Pump

380V

3

50

Unloading Platform

220V/110V

1

50

Control Room

220V/110V

1

50

Office

220V/110V

1

50

Workshop/Warehouse/Lab

220V/110V

1

50

220V

1

50

MCC Building

220V/110V

1

50

Guard House

220V/110V

1

50

Terminal & Jetty Lighting

An uninterruptible power supply (“UPS”) shall be installed to provide a reliable backup source of power for: 

Critical instrumentation and control;



Security;



The telecommunication systems;



Fire and gas detection;



ESD systems; and



Emergency lighting.

The batteries for all of the UPS systems shall be sized based on supplying the rated load of the UPS for a minimum of 30 minutes. Lightning protection and transient over-voltage shall be provided in accordance with applicable codes and standards. 6.4.17 Water Supply Systems There is no identified source of ground or well water available at the Terminal site. Water supply to the Terminal will be required for wash water, potable water and sanitary use. Additional information must be gathered to determine the best method for supplying water to the Terminal. Aqualectra may

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CURACAO LNG TERMINAL ONSHORE OPTION CONCEPTUAL FEASIBILITY STUDY

DESIGN BASIS CONCEPTUAL Date 06/25/12

REV: B

currently have water supply sources currently available at the existing Bullen Bay Oil Terminal Facility which can be tapped into for use at the LNG Terminal. 6.5

Safety System Requirements 6.5.1

Fire Protection System

The fire protection system shall be comprised of a combination of passive techniques and active techniques. Passive fire protection functions without relying on external intervention and is implemented where immediate protection is required. Passive protection operates only for a limited period of time. In case of a long duration fire, active fire protection and fire-fighting must also be deployed. The design of the active fire protection system shall be based on the assumptions that (i) there will be only one major fire at any one time and fires will not occur simultaneously at different places within the facility, and (ii) external fire-fighting resources are not available in case of an emergency within the premises. The system shall be designed around maximum use of fixed fire-fighting systems such as water spray systems, which do not require fire-fighting vehicles or trained personnel for water or foam solution supply. In addition to the facility fire water system, additional fixed and portable fire-fighting equipment shall be provided at identified potential hazards. The Marine Terminal Control Shelter at the jetty which is remote from the main facility shall be provided with a fixed clean agent fire extinguishing system, as well as any sub-floors in local MCC rooms that cannot be quickly accessed. The overall arrangement for the firewater system shall provide deluge systems in selected areas, remote controlled fire monitors, and fire hydrants. A firewater ring main shall be provided to cover the Terminal vaporization and sendout facilities, the LNG storage area, marine jetty facilities, and infrastructure buildings. A firewater storage tank shall be provided with a total combined capacity for 8 hours of firewater supply. At least two 100% percent freshwater main firewater pumps (diesel) shall be provided along with two 100% freshwater jockey pumps. Contractor shall calculated the required firewater rate and size the firewater system as appropriate. If a three 50% firewater configuration makes more sense, then the Contractor should opt for that configuration. In case of a prolonged incident where the firewater requirement exceeds the firewater storage capacity, an auxiliary firewater connection shall be provided at the jetty for external seawater supply from fire fighting marine vessels. All main firewater pumps shall have the capability of being automatically started upon low ring main pressure and manually by switches for each pump located local to the pump and in the control room. Portable foam units located on the jetty and around the Terminal shall be used to control spills and fires in LNG spill containment areas (at the LNG storage area, LNG loading platform, and spill containment sumps). Portable fire extinguishers shall also be located strategically throughout the facility. A Terminal fire truck shall be provided for response to incipient fires and grass fires.

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CURACAO LNG TERMINAL ONSHORE OPTION CONCEPTUAL FEASIBILITY STUDY

6.5.2

DESIGN BASIS CONCEPTUAL Date 06/25/12

REV: B

Fire and Gas Detection System

A fire and gas detection system (F&G system) shall be provided to continuously monitor and alert personnel when fire, smoke or gas release is detected. The function of the F&G system will be to: 

Detect the presence of fire or loss of containment of flammable gas and the ingress of smoke or flammable gas into areas where it may present a hazard;



Allow manual alarm initiation by personnel throughout the installation by means of manual alarm call points;



Alert the central control room of any fire or flammable gas leak;



Give local warning alarm to the specific area/building where the alarm initiating device(s) is activated; and



Provide a plant-wide warning alarm upon confirmed fire or gas alarm.

In general, the F&G system alarms only, rather than directly initiating executive actions. Activation of fire protection systems will be determined on an individual basis by operating personnel. 6.5.3

Ignition Source Control

Smoking and non-process ignition sources within the protective enclosures shall be prohibited. Smoking shall be permitted only in designated and properly signposted areas. Welding, cutting and similar operations shall be conducted only at times and in places specifically authorized and then in compliance with NFPA 51B. Vehicles and other mobile equipment that constitute potential ignition sources shall be prohibited within impounding areas or within 50 feet of containers or equipment containing LNG, flammable liquids, or flammable refrigerants except when specifically authorized and under constant supervision or when at loading or unloading facilities specifically for the purpose. 6.5.4

Emergency Shutdown System

An Emergency Shutdown (ESD) system shall be designed and installed to provide for safety of operating personnel and to protect equipment from abnormal operating conditions that could result in mechanical damage to such equipment. Design of the ESD system shall comply with the requirements of Chapter 9 of NFPA 59A. The ESD system shall be an independent and failsafe design. Activation of the ESD system shall either be manual, automatic, or both manual and automatic, depending upon the potential consequence of the defined event and a system analysis. The design logic of the ESD system shall be described in the form of a Safe Chart (or ESD Logic Diagram), which defines the events, and resultant actions that will be taken by the ESD system when activated by such events. The ESD shall be capable of automatically performing the following functions when activated:

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CURACAO LNG TERMINAL ONSHORE OPTION CONCEPTUAL FEASIBILITY STUDY

DESIGN BASIS CONCEPTUAL Date 06/25/12

REV: B



Close isolation valves as required to shut-off a source of LNG, flammable liquid, flammable refrigerant or flammable gases;



Shutdown equipment whose continued operation could add to or prolong an emergency condition; and



De-pressure vessels that are subject to metal overheating and catastrophic failure from fire exposure if not otherwise protected.

A detailed emergency procedure shall be developed to describe the potential emergency conditions that may develop whether or not a fire has occurred. Such procedure shall describe as a minimum the following: 

Shutdown or isolation of various portions of the equipment and other steps so that escape and release of gas or liquids are stopped or minimized;



Activation and use of the fire protection facility and equipment;



Notification of public authorities;



First aid; and



Operations personnel responsibilities. 6.5.5

Emergency Evacuation

The plot plan and layout shall be designed to ensure adequate emergency escape routes. A minimum of two evacuation routes must be provided for pipe racks, structures, and major access platforms. Escape routes of all buildings shall be designed in accordance with NFPA 59A. 6.5.6

LNG Spill Impoundment System

NFPA 59 A (2009 Edition) section 5.3.2.1 specifies that each impounding system serving an LNG storage tank must have a minimum volumetric liquid capacity of 110% of the LNG tank’s maximum design liquid capacity for an impoundment serving a single tank. This design for the Curacao Terminal proposes to use a “full containment” LNG storage tank in which the outer tank wall serves as the impoundment system. The volumetric capacity of the outer concrete wall should exceed the 110% percent requirement. Contractor shall calculate and verify the outer containment volume and assure that it complies with NFPA 59 A. The process area impoundment basin will be located in the process area and any spills from the BOG Condenser and LNG Vaporization system shall be routed to the impoundment basin by a series of collection troughs.

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CURACAO LNG TERMINAL ONSHORE OPTION CONCEPTUAL FEASIBILITY STUDY

DESIGN BASIS CONCEPTUAL Date 06/25/12

REV: B

The LNG transfer line and the LNG recycle line traversing from the marine unloading platform to the LNG Storage Tank shall be vacuum jacketed insulated piping. Both the internal and external pipes of the vacuum jacketed lines shall be fabricated from 304L stainless steel. Therefore, the outer pipe shall serve as a secondary containment in the even the inner pipe fails. This eliminates the need for a large LNG impoundment sump for the jetty and LNG transfer lines. Contractor shall calculate the design spill volume over a 10-minute period and use the volume to size the process area LNG spill impoundment to contain such design spill as defined by NFPA 59A (2009 Edition). The LNG Terminal shall be designed to provide drainage of water to disposal areas in accordance with NFPA 59 A (2009 Edition) section 5.3.2. Drainage and disposal of water shall be accomplished by a series of ditches and swales. Water that is collected within the curbed LNG containment areas shall be directed by gravity to the LNG impoundment trenches and eventually to the impoundment basins sump. Stormwater pumps in the impoundment basins shall remove the water at a rate equal to or greater than 25% percent of the 10-year frequency, one-hour duration storm. The pumps shall discharge the water into the Terminal storm drainage system. The stormwater pumps shall be automatically operated via level control and shall be interlocked using low temperature detectors to prevent the pumps from operating if LNG is present. 6.5.7

Thermal Exclusion Zone

If a large quantity of LNG is spilled in the presence of an ignition source, the resulting LNG pool fire could cause high levels of radiant heat in the area surrounding the impoundment. Exclusion distances for various flux levels will need to be calculated by the Contractor during FEED according to NFPA 59A (2009 Edition) section 5.3.3 using available software models such as the "LNGFIRE III" computer program model developed by the Gas Research Institute. NFPA 59A establishes certain atmospheric conditions which are to be used in calculating the distances. Thermal exclusion zones will need to be confirmed by Contractor using rigorous calculations in subsequent design work. Contractor shall overlay the calculated Thermal Exclusion zones on the layout drawing and shall be responsible for assuring the facility complies with NFPA 59A Thermal Exclusion zone requirements. 6.5.8

Vapor Dispersion Zone

A large quantity of LNG spilled without ignition would form a flammable vapor cloud that would travel with the prevailing wind until it either dispersed below the flammable limits or encountered an ignition source. Sections 5.3.3.6 of NFPA 59A (2009 Edition) require that provisions be made to minimize the possibility of flammable vapors reaching a property line that can be built upon and that would result in a distinct hazard. Code requires that dispersion distances be calculated for a 2.5% average gas concentration (one-half the lower flammability limit [LFL] of LNG vapor) under meteorological conditions which result in the longest downwind distances at least 90% of the time. Alternatively, maximum downwind distances may be estimated for stability Class F, a wind speed of 4.5 mph, 50% relative humidity, and the average regional temperature. The section allows the use of the DEGADIS

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CURACAO LNG TERMINAL ONSHORE OPTION CONCEPTUAL FEASIBILITY STUDY

DESIGN BASIS CONCEPTUAL Date 06/25/12

REV: B

(Dense Gas Dispersion) Model, or the FEM3A model, to compute dispersion distances. Design spills into impounding areas serving LNG containers, transfer systems, and piping are to be determined in accordance with Table 5.3.3.7 of NFPA 59A (2009 Edition) by the Contractor. In accordance with the code, an average concentration of methane in air of one-half of the LFL cannot cross the property line from a design spill into the tank impoundment. Rigorous vapor dispersion calculations shall be performed by Contractor and overlaid on the Terminal layout drawing. Contractor shall confirm and verify that the vapor dispersion zones calculated for the LNG Terminal comply with the requirements of NFPA 59A. 6.5.9

Quantitative Risk Assessment (QRA) Study

A HAZOP will need to been performed by Contractor during FEED for each of the systems that comprise the LNG Terminal facility. A full QRA study will need to be completed by Contractor during detail design. 6.6

Security Systems

The Terminal shall have an 8-foot high security fence surrounding the facility. Access to the facility shall be controlled by guarded entry. Video security cameras shall be provided at key locations to allow the security guard to monitor the Terminal from the guard access building. Display from the security cameras shall also be provided in the central control room. Lighting shall be provided through out the Terminal and at the marine jetty facilities. 6.7

Buildings and Infrastructure

The following infrastructure shall be provided at the Terminal:

7.



Office/Central Control Room Building with Employee Parking;



Parking Area for Jetty;



Work Shop/Warehouse/Lab Building;



MCC Building;



Sheds for BOG Compressors and Ship Vapor Return Blowers; and



Entry Guard House.

SITE DESIGN DATA 7.1

Location

The Terminal shall be located in Curacao at Bullen Bay as discussed in Section 4 of this document.

Page 24

DESIGN BASIS

CURACAO LNG TERMINAL ONSHORE OPTION

CONCEPTUAL

CONCEPTUAL FEASIBILITY STUDY

7.2

REV:

06/25/12

B

Ambient Air Temperatures and Relative Humidity PARAMETER

Max

Min

Avg.

Ambient Air Temperature - C

36.9

20.3

27.9

Average Relative Humidity - %

89

74

80

o

7.3

Date

Bathymetric Design Data PARAMETER

Bullen Bay Site

Highest Astronomical Tide (Above MSL)

+0.52 m

Mean Sea Level (MSL)

0.00 m

Lowest Astronomical Tide (Below MSL)

-0.35 m

Normal/Typical Wave

1.2 - 1.5 m

Maximum Design Wave

2.1 m

Storm Surge (Category 3 Hurricane)

+5.8 m

Maximum Current

3.0 knots o

o

Bay Water Surface Temperature C ( F)

7.4

Maximum

28.3 (83)

Minimum

25.6 (78)

Average

27.2 (81)

Wind and Weather Design Data PARAMETER

Design Value

Prevailing Wind Direction The prevailing trade wind directions vary slightly East North East to East South East, with an average velocity of 5.2 to 6.6 m/s. Maximum gust to 25.7 m/s. Maximum Design Wind Load (Hurricane)

67 m/s

Wind Rose Data North = 0 deg & clockwise

Wind Direction %

0

22.5

45

TBD

TBD

TBD

67.5

90

112.5

TBD

TBD

TBD

135

157.5

180

TBD

TBD

TBD

202.5

225

247.5

TBD

TBD

TBD

270

292.5

315

TBD

TBD

TBD

337.5

TBD

Rainfall Rate Maximum 1- Hour Maximum 24 - Hour

4.5 inches 10.1 inches (September)

Average Annual

21.3 inches

Maximum Annual

42.9 inches

Barometric Pressure Maximum

30.61 “Hg

Mean

30.13 “Hg

Minimum

29.64 “Hg

Maximum Rate Of Change (Assumed)

0.5”Hg/hr

Page 25

CURACAO LNG TERMINAL ONSHORE OPTION CONCEPTUAL FEASIBILITY STUDY

7.5

DESIGN BASIS CONCEPTUAL Date

REV:

06/25/12

B

Seawater Physical Properties SEAWATER PHYSICAL PROPERTIES Suspended Solids and Organic Materials Total Dissolved Solids o

7.6

TBD 39,391 mg/l

Sp. Gr. @ 60 F Relative to Fresh Water

1.025

pH

6.98

Seismic Design Criteria

Curacao seismic design acceleration is in the range of 0.8 to 1.6 m/sec2 for 10% probability of exceedance in 50 years, 475-year return period. Earthquake tremors of less than magnitude 3 on the Richter scale have been recorded on Curacao. [HOLD. Subject to confirmation] 8.

ENVIRONMENTAL PERMITTING

The Ministry of Public Health, Environment and Nature in Curacao is the regulatory authority having jurisdiction over permitting of the Terminal. There is currently no requirement to prepare and submit an Environmental Impact Assessment Study (EIAS). However, an EIAS will be prepared and the following permits will be required: 

Safety Permit;



Construction Permit;



Nuisance Permit (Requiring Public Notice and Possibly A Public Hearing); and



Waste Water Disposal Permit.

This Terminal will require bank financing. Since there is no requirement for issuing an EIAS, the facility design will need to conform to the criteria defined in the “Equator Principles” which have been adopted for projects located in countries not requiring an EIAS. 9.

DESIGN STANDARDS AND CODES

In addition to the permits and agency consultations listed in the sections above, the Curacao Terminal and associated pipeline facilities shall comply with all applicable standards and codes. The Terminal design and operation shall be compliant with the Curacao Ports Authority rules and regulations as well as all local and national environmental regulations, codes and permitting requirements applicable to Curacao. The facility must also be compliant with “Equator Principles” since the GOC regulations do not require an Environmental Impact Assessment Study (EIAS). The LNG Terminal shall be designed in compliance with NFPA 59A (2009 Edition) and all of the codes and standards referenced therein.

Page 26

DESIGN BASIS

CURACAO LNG TERMINAL ONSHORE OPTION CONCEPTUAL FEASIBILITY STUDY

CONCEPTUAL Date 06/25/12

REV: B

Flare/Vent system shall be designed to comply with API Standard 521 and 520. 9.1

Marine Facilities (Dock, Mooring Systems, Berthing and Jetty)

Design of all structures shall be carried out and comply with the following codes and standards: 

American Institute of Steel Construction -



“Manual of Steel Construction” Allowable Stress Design, 9th Ed. Load and Resistance Factor Design, 3rd Ed.

American Concrete Institute -

“Building Code Requirements for Structural Concrete (ACI 318-02)”



American Society of Civil Engineers



“Minimum Design Loads for Buildings and Other Structures” SEI/ASCE 7-02



American Petroleum Institute -



Permanent International Association of Navigation Congresses -



“Prediction of Wind Loads on Large Liquefied Gas Carriers”, 1985 SIGTTO/OCIMF

Oil Companies International Marine Forum -



“Guidelines for the Design of Fender Systems”, 2002

Society of International Gas Tankers and Terminal Operators, Ltd. -



API LRFD RP2A, 2002 API ASD RP2A, 2002

“Prediction of Wind and Current Loads on VLCCs”, 1995

American Association of State Highway and Transportation Officials 9.2

“Standard Specifications for Highway Bridges”, 17th Ed.-2002 Onshore Facilities within Terminal Fence



NFPA 59A Standard for the Production, Storage, and Handling of Liquefied Natural Gas



API Standard 521 and 520 For Flare/Vent Systems

Page 27

DESIGN BASIS

CURACAO LNG TERMINAL ONSHORE OPTION CONCEPTUAL FEASIBILITY STUDY

CONCEPTUAL Date

REV:

06/25/12

B



American Society for Testing and Materials (ASTM) – pressure vessels



American Petroleum Institute (API) – hydrocarbon storage, processing, transportation



American National Standards Institute (ANSI) – piping codes ANSI B31.3. 9.3



Onshore Gas Pipelines Outside Terminal Fence

American National Standards Institute (ANSI) – pipeline codes ANSI B31.8.

10. GAS SENDOUT PIPELINE TIE-IN The natural gas from the LNG Terminal shall be connected to the gas sendout pipeline at the Terminal fence line downstream of the Terminal’s custody transfer metering and sampling skid. An ESDV shall be provided at the tie-in point. 11. PRIME MOVERS Prime movers including pumps, compressors, fans, and other equipment that requires mechanical drive shall be powered by electric motor drives. Use of electric motor driven equipment reduces the CO2 and NOx emissions for the facility since the primary source of electrical power for the Terminal can be provided from the existing electrical power grid. 12. NOISE ABATEMENT The most significant noise levels in the Terminal will correspond to those produced by the following equipment: 

Generators and gas turbine drivers;



Emergency generator (diesel);



Compressors and drivers;



Flare, vent and pressure relief systems;



Pumps and motors;



Diesel firewater pump;



Air-coolers (vents and motors);



Control valves in gas service with large pressure drops in emergency operations only; and

Page 28

CURACAO LNG TERMINAL ONSHORE OPTION CONCEPTUAL FEASIBILITY STUDY



DESIGN BASIS CONCEPTUAL Date 06/25/12

REV: B

Gas piping with high velocity flowrates.

Table 6 below shows the recommended limits of daily exposure (per OSHA Regulations, Occupational Noise Exposure 1910.95) at various levels of noise for normally unmanned areas or with intermittent entry of personnel. Table 6 Noise Exposure Guidelines PERSONNEL MAXIMUM EXPOSURE NOISE LEVEL (db @ A)

(Hours per Day)

90

8

92

6

95

4

97

3

100

2

102

1.5

105

1

110

0.5

Design of facilities installed in the Terminal shall allow operation of the Terminal in compliance with the noise exposure criteria contained in OSHA Regulations, U.S. CFR 29 Part 1910 Occupational Safety and Health Standards and EEMUA 140/141 for Measuring and Calculating Noise or as required by local code and regulations, whichever is more restrictive. 13. MISCELLANEOUS DESIGN SPECIFICATIONS 13.1 Corrosion Allowance 13.1.1 Equipment Corrosion Allowance CS Non Corrosive Service

0.125 in

CS Water/Glycol System

0.125 in

Stainless and Other Alloys

0.000 in

13.1.2 Piping Corrosion Allowance CS Non Corrosive Service

0.125 in

CS Water/Glycol System

0.125 in

Stainless and Other Alloys

0.000 in

Page 29

CURACAO LNG TERMINAL ONSHORE OPTION CONCEPTUAL FEASIBILITY STUDY

DESIGN BASIS CONCEPTUAL Date 06/25/12

REV: B

13.2 Unloading Transfer Lines Transfer Lines

One Primary LNG Transfer Line; One LNG Recirculation Line; One Ship Vapor Return Line

Size

36-in Primary LNG; 4-in Recirculation; 12-in Ship Vapor Return

Material of Construction

304L Stainless Steel

Insulation

Vacuum Insulated Pipe (VIP) shall be used to insulate the LNG Transfer and Recycle Lines. Foam glass insulation will be used to insulate the Ship Vapor Return Line.

13.3 Sendout Heat Exchangers 13.3.1 Open Rack Vaporizers (ORVs) ORV Panel Tube Pressure Drop at Design Flow Rate

10 psi

Manufacturer

Kobe Steel or Approved Equal

Fouling Factor

Mfg Standard o

Gas Outlet Temperature (Minimum)

40 F

Seawater Temperature o

Inlet

78 F

Outlet (Minimum)

65 F

o

13.3.2 Gas Sendout Superheater Shell & Tube Exchanger Tube Side Pressure Drop at Design Flow Rate

10 psi

Shell Side Pressure Drop at Design Flow Rate

15 psi

Fouling Factor Tube Side (Gas) Shell Side (HM) Gas Outlet Temperature (Minimum)

o

2

o

2

0.001 F-ft -hr/Btu 0.001 F-ft -hr/Btu o

60 F

13.4 BOG Condenser Absorber Section Packing

Absorber Section Pressure Drop (Maximum) Pump Drum Section Liquid Residence Time (Minimum)

Packing #50 IMPT (Norton) Random 0.25 in WC per foot 5 minutes

Page 30

DESIGN BASIS

CURACAO LNG TERMINAL ONSHORE OPTION

CONCEPTUAL

CONCEPTUAL FEASIBILITY STUDY

Date

REV:

06/25/12

B

13.5 Line Sizing Criteria 13.5.1 Vapor Lines Line Sizing Method

Darcy Equation Velocity (ft/s) ∆P (psi/100’)

Service

Normal

Maximum

Compressor Piping Recip Suction Header

0.15

20 to 40

7% sonic

Recip Suction Branch

0.25

20 to 40

7% sonic

Recip Discharge Header

0.60

20 to 40

7% sonic

Recip Discharge Branch

0.60

20 to 40

7% sonic

Centrifugal Suction Over 50 psig

0.50

40 to 80

13% sonic

Centrifugal Suction Under 50 psig

0.25

40 to 80

13% sonic

Centrifugal Discharge

0.60

40 to 80

13% sonic

0.016 to 0.20

150 to 250

50% sonic

0 to 50 psig

0.08 to 0.20

100 to 150

50% sonic

50 to 300 psig

0.08 to 0.60

80 to 100

50% sonic

300 to 1000 psig

0.08 to 1.00

50 to 80

50% sonic

0.20 to 2.0

30 to 50

50% sonic

0.50 to 1.0

30 to 50

In Plant Piping Vacuum

Over 1000 psig o

Any Pressure below -50 F Maximum Velocity (ft/sec) - Continuous Maximum Velocity (ft/sec) - Intermittent

50% sonic 100/ρ

0.5

lb/ft

3

150/ρ

0.5

lb/ft

3

13.5.2 Liquid Lines Line Sizing Method

Darcy Equation Velocity (ft/s)

Service

∆P (psi/100’)

Normal

Maximum

Centrifugal Pump Suction Liquids Close or At Bubble Point

0.05 to 0.25

3 to 4

4

Other Liquids

0.20 to 0.40

5

6

0.40 to 1.50

16

Centrifugal Pump Discharge Liquids Close or At Bubble Point Other Liquids

0.80 to 2.00

16

100/ρ

0.5

lb/ft

3

100/ρ

0.5

lb/ft

3

100/ρ

0.5

lb/ft

Recip Pump Suction All Liquids

0.05 to 0.25

1 to 3

Discharge All Liquids

0.80 to 2.00

5 to 6

5 3

13.6 Cold Insulation Process Area Cryogenic Piping, Cryogenic Exchangers, Cryogenic Separators and Other Pressure Vessels.

Foam Glass w/ thickness to yield 2 o U< 0.10 Btu/hr-ft - F

Page 31

DESIGN BASIS

CURACAO LNG TERMINAL ONSHORE OPTION

CONCEPTUAL Date

CONCEPTUAL FEASIBILITY STUDY

06/25/12

REV: B

14. DEFINITION OF TERMS Barrel or Bbl

42 US gallons or 5.615 ft2

Bbl/D

Barrels per day at 14.696 psia and 60oF

Building and Area Classification

The fire hazard classification for a Building or Area as established in accordance with NFPA recommendations

Bunkering

The loading of a ship’s bunker or tank with fuel oil for use in connection with propulsion or auxiliary equipment

C2+

Ethane and heavier hydrocarbons

C3+

Propane and heavier hydrocarbons

CPA

Curacao Ports Authority which operates the Ports at Bullen Bay and Schottegat Harbor

Commercial Natural Gas

Gaseous form of petroleum consisting of a mixture of light hydrocarbons predominately comprised of methane that has been processed as required to meet commercial quality pipeline specifications

Design Pressure

The pressure used in the design of equipment, a container, or a vessel for the purpose of determining the minimum allowable thickness or physical characteristics of its parts; were applicable, static head is included in the design pressure to determine the thickness of any specific part

Dike

A structure used to establish an impounding area

ESD

Emergency Shut Down

Exclusion Zone (Marine)

A perimeter around a LNG vessel through which other vessels not directly involved in the maneuvering of the LNG vessel are not allowed to operate

standard conditions of

Page 32

CURACAO LNG TERMINAL ONSHORE OPTION CONCEPTUAL FEASIBILITY STUDY

DESIGN BASIS CONCEPTUAL Date

REV:

06/25/12

B

Exclusion Zone (Thermal)

Area surrounding an LNG impoundment assumed to be holding an LNG spill that is on fire with such area defined by radiant heat flux limits as specified in NFPA 59A.

Exclusion Zone (Gas Dispersion)

Area surrounding an LNG impoundment assumed to be holding an LNG spill (not on fire) with such area defined to be that area which has an average concentration of methane in air exceeding 50% of the lower flammability limit determined in accordance with NFPA 59A

Failsafe

A design feature that provides for the maintenance of safe operating conditions in the event of malfunction of control devices or the interruption of an energy source

Fired Equipment

Any piece of equipment in which the combustion of fuels takes place

FSRU

Floating Storage and Regasification Unit

g

The normal or standard constant of gravity at sea level, “g” equal approximately 32.2 ft/sec2.

gpm

gallons per minute at flowing temperature and pressure

HHV or Higher Heating Value

The amount of heat obtained from the total combustion of one standard cubic foot of gas at a pressure of 14.696 psia with the resulting products of combustion being cooled to 60oF and the water vapor formed during such combustion being totally condensed (expressed in Btu/scf)

Ignition Source

Any source of energy, such as welding activities, flames or unclassified electrical equipment, that could cause the initiation of combustion of an air fuel mixture

Impounding Area

An area defined through the use of dikes or site topography for the purpose of containing any accidental spills of LNG or refrigerants

Page 33

CURACAO LNG TERMINAL ONSHORE OPTION CONCEPTUAL FEASIBILITY STUDY

DESIGN BASIS CONCEPTUAL Date

REV:

06/25/12

B

LHV or Lower Heating Value

The amount of heat obtained from the total combustion of one standard cubic foot of gas at a pressure of 14.696 psia with the resulting products of combustion being cooled to 60oF and the water vapor formed during such combustion not being condensed (expressed in Btu/scf)

Liquefied Natural Gas or LNG

A fluid in the liquid state that is composed predominantly of methane and that can contain quantities of ethane, propane, nitrogen, or other components normally found in natural gas

Maximum Allowable Working Pressure

(MAWP) The maximum guage pressure permitted at the top of completed equipment, a container, or vessel in its installed operating position at design temperature

m3/hr

Cubic meters per hour at flowing temperature and pressure

MMscf

Million standard cubic feet at standard conditions of 14.696 psia and 60oF

MMscfd

Million standard cubic feet per day at standard conditions of 14.696 psia and 60oF

NGL or Natural Gas Liquids

Mixtures of light hydrocarbons including ethane, propane, butanes and natural gasoline in liquid state with potentially small amounts of methane

psia

Pounds pressure per square inch absolute

psig

Pounds pressure per square inch gauge

RDK

Refineria di Korosou N.V.

Scf or Standard cubic foot

The quantity of gas that occupies one cubic foot of volume at standard conditions of pressure and temperature of 14.696 psia and 60oF

Sendout Gas

Regasified LNG product at pipeline quality heat value, pressure and temperature ready for export to the gas pipeline network

Standard Conditions

Pressure of 14.696 psia and temperature of 60oF

Page 34

CURACAO LNG TERMINAL ONSHORE OPTION CONCEPTUAL FEASIBILITY STUDY

Transfer Area

DESIGN BASIS CONCEPTUAL Date 06/25/12

REV: B

That portion of an LNG plant containing a piping system were LNG, flammable liquids, or flammable refrigerants are introduced into or removed from the facility such as truck loading or ship unloading areas or were piping connections are connected or disconnected routinely

Page 35

Section 15 – Appendix B

PROCESS FLOW DIAGRAMS HEAT & MATERIAL BALANCES

CURACAO CNG-LNG TERMINAL FEASIBILITY STUDY

ARM-1,2,3,4 LNG LOADING ARMS

V-2 LNG DRAIN DRUM

P-3A/B LNG DRAIN DRUM PUMP

TK-1 LNG STORAGE TANK

V-3 BOG COMPRESSOR SCRUBBER

K-1A/B SHIP VAPOR RETURN BLOWER

CONCEPTUAL

K-2A/B SMALL BOG COMPRESSORS

K-1A/B

K-2A/B

K-2C

K-3

Elec

Elec

K-3 BOG PIPELINE COMPRESSOR

K-2C LARGE BOG COMPRESSOR

Elec

PIC

Elec

022

(NOTE 5)

PFD-01-02 015

Sampler

009

010

FI

FIC

FIC

FIC

017

014

FIC

021

020

016

PFD-01-02

Ship Vapor Retrun Line 023 008

LIC

V-3 TIC

Ground Flare

018

N2

Vacuum Break Gas from LP Fuel

019

Blowcase

HC

013

(NOTE 4)

Vapor To Ship

PIC ARM-4

TIC

PSVs

NC

Cascade Reset PIC

LI

PIC

PIC

002

N2 Purge

FIC

004

PIC

011

Arm Drain TK-1

LNG From Ship

005

012

LIC

FI ARM-1,2,3

FIC

PIC

Top Filling

(NOTE 1) 001

Pump Min Flow Recycle Bottom TI Filling

N2 Purge

LNGTransfer Line

V-1

003

P-1A/B (NOTE 2)

007

P-2A/B

PFD-01-02 006

FIC

Sampler LNG Chill-Down Recycle Line (NOTE 3)

Arm Drains LIC

V-2

Start/Stop Pump

P-1A/B IN-TANK LNG PUMPS

P-3A/B

NOTES: 1. Cargo transfer arms comprised of 2 liquid, 1 vapor and 1 hybrid liquid/vapor. Offloading capacity is 10,000 m3/hr. 2. Two 100% capacity in-tank pumps are provided. In addition, two spare pump wells are provided in TK-1 for future capacity expansion. 3. The LNG Chill-Down Recycle Line normally has no flow. Before the LNG cargo ship arrives, LNG is circulated to chill-down the LNG Transfer Line. 4. Temperature of Ship Vapor Return maintained at -220oF. 5. During periods when the ship is offloading and low sendout gas rate, the K-2C and K-3 are required to dispose of the excess BOG. Otherwise, these compressor are out of service.

REV

DATE

A

04-02-2012

REVISION DESCRIPTION Internal Review

CK #1 DH

CK #2 -

V-1 BOG CONDENSER CK #3 -

P-2A/B LNG SENDOUT PUMPS

Approve HGW

CURACAO CONCEPTUAL LNG TERMINAL BULLEN BAY PORT CURACAO, NETHERLAND ANTELIES

PROCESS FLOW DIAGRAM LNG UNLOADING AND STORAGE SYSTEMS SCALE: None

JOB NO.:

FILE: PFD-01-01 REVA.VSD DATE:

04-02-2012

By:

Shaw Consultants

145790 DWG NO.: PFD-01-01

REV A

E-1A/B LNG OPEN RACK VAPORIZERS

E-4 BOG PIPELINE COMPRESSOR DISCH COOLER

E-2A/B SENDOUT GAS SUPERHEATERS

E-3 LP FUEL GAS HEATER

E-4

022

CONCEPTUAL

PFD-01-01 023

PFD-01-01

Custody Transfer Measurement

HM5 025

E-2A/B

026

PR

FR

TR

PIC

027

Sampler Sendout Gas

To Pipeline

TIC HM6

EG/Water Ht Medium (Cool)

PFD-01-03 HM1

HM4

TIC

EG/Water Ht Medium (Hot) FIC

High Signal Select

PFD-01-03

HM3

PIC 028

029

E-3 LP Fuel Gas

PFD-01-03

TIC

PIC Backup LP Fuel Supply HM2

LIC

Normally No Flow

E-1A/B 024

SW1

Seawater (Warm)

PFD-01-03

TIC 007

FIC SW2

Seawater (Cool)

PFD-01-01

NOTES:

PFD-01-03

REV

DATE

A

04-02-2012

REVISION DESCRIPTION Internal Review

CK #1 DH

CK #2 -

CK #3 -

Approve HGW

CURACAO CONCEPTUAL LNG TERMINAL BULLEN BAY PORT CURACAO, NETHERLAND ANTELIES

PROCESS FLOW DIAGRAM LNG VAPORIZATION AND GAS HEATING SYSTEMS SCALE: None

JOB NO.:

FILE: PFD-01-02 REVA.VSD DATE:

04-02-2012

By:

Shaw Consultants

145790 DWG NO.: PFD-01-02

REV A

V-6 LP FUEL GAS SCRUBBER

HTR-1A/B HM HEATERS

P-7A/B/C SEAWATER PUMPS

V-5 HM SURGE DRUM

P-5A/B HM PUMPS

P-6 HM TRANSFER PUMP

TK-2 HM STORAGE

CONCEPTUAL HM8

Vacuum Break Gas To BOG Header 029

HTR-1A/B

TIC

Vent/Flare Header Purge and Pilot Fuel Miscellaneous Fuel

PFD-01-02

LP Fuel Gas

V-6

Water/Glycol Heaters P-6 Minimum Flow Recycle TK-2 FIC

HM1

PFD-01-02

P-5 Minimum Flow Recycle

EG/Water Ht Medium (Hot)

P-6

v

PIC HM6

PIC

PFD-01-02

N2

EG/Water Ht Medium (Cool) V-5

FIC HM7

+

SW1

~

-

P-5A/B FIC

Seawater (Warm)

PFD-01-02

Chlorination Unit

P-7A/B/C

SW2

Seawater (Cool)

PFD-01-02

400 m 80oF Surface ~~~~~~~~~~~~~~~~~~~~ 250 m Water Depth 65oF

NOTES: 1.

Cool Seawater Discharge Outlet At Ocean Depth Where Temperature Difference of Ocean and Seawater Discharge Is +/- 3oC REV

DATE

A

04-02-2012

REVISION DESCRIPTION Internal Review

P-7 Minimum Flow

SEAWATER INTAKE SCREEN ~~~~~~~~~~~~~~~~~~~~ (Velocity Not to Exceed 0.5 feet/sec)

CK #1

CK #2

CK #3

Approve

DH

-

-

HGW

CURACAO CONCEPTUAL LNG TERMINAL BULLEN BAY PORT CURACAO, NETHERLAND ANTILLIES

PROCESS FLOW DIAGRAM HEAT MEDIUM AND FUEL GAS SYSTEM SCALE: None

JOB NO.:

FILE: PFD-01-03 REVA.VSD DATE:

04-02-2012

By:

Shaw Consultants

145790 DWG NO.: PFD-01-03

REV A

CASE:  Lean 137 No Ship Unloading.xlsx

CURACAO CNG‐LNG FEASIBILITY STUDY HEAT AND MATERIAL BALANCE

Stream ID Temperature [F] Pressure [psia] Molar Flow [lbmole/h] Mass Flow [lb/hr] Molecular Weight Mass Density [lb/ft3] Std Gas Flow [MMSCFD] Actual Gas Flow [ACFM] Actual Liquid Flow [m3/h] Heat Flow [MMBtu/hr] Mole Frac (Nitrogen) Mole Frac (CO2) Mole Frac (Methane) Mole Frac (Ethane) Mole Frac (Propane) Mole Frac (i‐Butane) Mole Frac (n‐Butane) Mole Frac (i‐Pentane) Mole Frac (n‐Pentane) Mole Frac (EGlycol) Mole Frac (H2O) Total Mole Fraction

1 ‐254.9 85.0 0 0 16.67 27.09 0.00 0 0.0 0.00 0.0000 0.0000 0.9550 0.0450 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 1.0000

2

3 ‐256.1 120.0 14333 239090 16.68 27.17 0.00 0 249.2 ‐556.56 0.0000 0.0000 0.9545 0.0455 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 1.0000

4 ‐256.1 120.0 1258 20989 16.68 27.17 0.00 0 21.9 ‐48.86 0.0000 0.0000 0.9545 0.0455 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 1.0000

5 ‐256.1 120.0 13075 218101 16.68 27.17 0.00 0 227.3 ‐507.70 0.0000 0.0000 0.9545 0.0455 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 1.0000

6 ‐250.1 112.0 14548 242530 16.67 26.85 0.00 0 255.8 ‐563.63 0.0000 0.0000 0.9552 0.0448 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 1.0000

7 ‐244.9 835.0 14548 242530 16.67 26.89 0.00 0 255.4 ‐562.02 0.0000 0.0000 0.9552 0.0448 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 1.0000

8 ‐227.5 15.2 228 3657 16.04 0.10 2.08 608 0.0 ‐7.91 0.0000 0.0000 0.9999 0.0001 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 1.0000

9 ‐227.6 15.0 0 0 16.04 0.10 0.00 0 0.0 0.00 0.0000 0.0000 0.9999 0.0001 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 1.0000

10 ‐174.7 28.1 0 0 16.04 0.15 0.00 0 0.0 0.00 0.0000 0.0000 0.9999 0.0001 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 1.0000

11 ‐175.0 0.0 0 0 16.04 0.00 0.00 0 0.0 0.00 0.0000 0.0000 0.9999 0.0001 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 1.0000

12

13

0.0 0.0 0 0 0.00 0.00 0.00 0 0.0 0.00 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

0.0 0.0 0 0 16.67 0.00 0.00 0 0.0 0.00 0.0000 0.0000 0.9550 0.0450 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 1.0000

0.0 0.0 0 0 0.00 0.00 0.00 0 0.0 0.00 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000

14 ‐227.6 15.0 228 3657 16.04 0.10 2.08 616 0.0 ‐7.91 0.0000 0.0000 0.9999 0.0001 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 1.0000

Stream ID Temperature [F] Pressure [psia] Molar Flow [lbmole/h] Mass Flow [lb/hr] Molecular Weight Mass Density [lb/ft3] Std Gas Flow [MMSCFD] Actual Gas Flow [ACFM] Actual Liquid Flow [m3/h] Heat Flow [MMBtu/hr] Mole Frac (Nitrogen) Mole Frac (CO2) Mole Frac (Methane) Mole Frac (Ethane) Mole Frac (Propane) Mole Frac (i‐Butane) Mole Frac (n‐Butane) Mole Frac (i‐Pentane) Mole Frac (n‐Pentane) Mole Frac (EGlycol) Mole Frac (H2O) Total Mole Fraction

25 40.0 805.0 14548 242530 16.67 2.96 132.50 1363 0.0 ‐483.74 0.0000 0.0000 0.9552 0.0448 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 1.0000

26 40.0 805.0 14548 242530 16.67 2.96 132.50 1363 0.0 ‐483.74 0.0000 0.0000 0.9552 0.0448 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 1.0000

27 60.0 795.0 14548 242530 16.67 2.74 132.50 1473 0.0 ‐480.55 0.0000 0.0000 0.9552 0.0448 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 1.0000

28 ‐11.2 60.0 14 217 16.04 0.20 0.12 18 0.0 ‐0.45 0.0000 0.0000 0.9999 0.0001 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 1.0000

29 100.0 45.0 14 217 16.04 0.12 0.12 30 0.0 ‐0.43 0.0000 0.0000 0.9999 0.0001 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 1.0000

HM1 180.0 70.0 2212 50620 22.89 62.33 0.00 0 23.0 ‐284.63 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.1106 0.8894 1.0000

HM2 180.0 70.0 9 204 22.89 62.41 0.00 0 0.1 ‐1.15 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.1106 0.8894 1.0000

HM3 110.0 25.0 9 204 22.89 64.40 0.00 0 0.1 ‐1.16 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.1106 0.8894 1.0000

HM4 180.0 70.0 2203 50415 22.89 62.41 0.00 0 22.9 ‐283.19 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.1106 0.8894 1.0000

HM5 110.0 25.0 2203 50415 22.89 64.40 0.00 0 22.2 ‐286.39 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.1106 0.8894 1.0000

HM6 117.4 25.0 2212 50620 22.89 64.12 0.00 0 22.4 ‐287.55 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.1106 0.8894 1.0000

HM7 117.4 25.0 2212 50620 22.89 64.12 0.00 0 22.4 ‐287.55 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.1106 0.8894 1.0000

HM8 117.4 80.0 2212 50620 22.89 64.13 0.00 0 22.4 ‐287.54 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.1106 0.8894 1.0000

SW1 78.1 65.0 329586 5937528 18.02 62.23 0.00 0 2701.6 ‐40378.58 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 1.0000 1.0000

15 ‐5.3 130.0 228 3657 16.04 0.44 2.08 138 0.0 ‐7.52 0.0000 0.0000 0.9999 0.0001 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 1.0000 SW2 65.0 15.0 329586 5937528 18.02 62.33 0.00 0 2697.6 ‐40456.86 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 1.0000 1.0000

16 ‐227.6 15.0 0 0 16.04 0.10 0.00 0 0.0 0.00 0.0000 0.0000 0.9999 0.0001 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 1.0000

17

18

0.0 130.0 0 0 16.04 0.00 0.00 0 0.0 0.00 0.0000 0.0000 0.9999 0.0001 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 1.0000

‐5.7 125.0 214 3440 16.04 0.43 1.95 135 0.0 ‐7.07 0.0000 0.0000 0.9999 0.0001 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 1.0000

 

                                           

0.0000

0.0000

19 ‐200.5 110.0 0 0 16.05 0.74 0.00 0 0.0 0.00 0.0000 0.0000 0.9993 0.0007 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 1.0000

21 28.7 815.0 0 0 16.05 2.96 0.00 0 0.0 0.00 0.0000 0.0000 0.9993 0.0007 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 1.0000

22 28.1 805.0 0 0 16.05 2.92 0.00 0 0.0 0.00 0.0000 0.0000 0.9993 0.0007 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 1.0000

23 ‐5.7 125.0 14 217 16.04 0.43 0.12 8 0.0 ‐0.45 0.0000 0.0000 0.9999 0.0001 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 1.0000

24 ‐244.9 815.0 14548 242530 16.67 26.87 0.00 0 255.6 ‐562.02 0.0000 0.0000 0.9552 0.0448 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 1.0000

0.0000

0.0000

0.0000

0.0000

0.0000

                                           

0.0000

20 ‐200.5 110.0 0 0 16.05 0.74 0.00 0 0.0 0.00 0.0000 0.0000 0.9993 0.0007 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 1.0000

                                          0.0000

SHAW CONSULTANTS INTERNATIONAL, INC. HOUSTON, TEXAS 6/5/2012

CASE:  Lean 137 Ship Unloading.xlsx

CURACAO CNG‐LNG FEASIBILITY STUDY HEAT AND MATERIAL BALANCE

Stream ID Temperature [F] Pressure [psia] Molar Flow [lbmole/h] Mass Flow [lb/hr] Molecular Weight Mass Density [lb/ft3] Std Gas Flow [MMSCFD] Actual Gas Flow [ACFM] Actual Liquid Flow [m3/h] Heat Flow [MMBtu/hr] Mole Frac (Nitrogen) Mole Frac (CO2) Mole Frac (Methane) Mole Frac (Ethane) Mole Frac (Propane) Mole Frac (i‐Butane) Mole Frac (n‐Butane) Mole Frac (i‐Pentane) Mole Frac (n‐Pentane) Mole Frac (EGlycol) Mole Frac (H2O) Total Mole Fraction Stream ID Temperature [F] Pressure [psia] Molar Flow [lbmole/h] Mass Flow [lb/hr] Molecular Weight Mass Density [lb/ft3] Std Gas Flow [MMSCFD] Actual Gas Flow [ACFM] Actual Liquid Flow [m3/h] Heat Flow [MMBtu/hr] Mole Frac (Nitrogen) Mole Frac (CO2) Mole Frac (Methane) Mole Frac (Ethane) Mole Frac (Propane) Mole Frac (i‐Butane) Mole Frac (n‐Butane) Mole Frac (i‐Pentane) Mole Frac (n‐Pentane) Mole Frac (EGlycol) Mole Frac (H2O) Total Mole Fraction

1 2 ‐254.9 ‐254.8 85.0 33.5 689112 688889 11490329 11486693 16.67 16.67 27.09 27.06 0.00 0.00 0 0 12011.2 12020.2 ‐26745.77 ‐26737.71 0.0000 0.0000 0.0000 0.0000 0.9550 0.9550 0.0450 0.0450 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 1.0000 1.0000 25 40.0 805.0 11357 188767 16.62 2.95 103.43 1066 0.0 ‐377.41 0.0000 0.0000 0.9587 0.0413 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 1.0000

26 37.3 805.0 14684 242180 16.49 2.94 133.74 1371 0.0 ‐487.69 0.0000 0.0000 0.9679 0.0321 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 1.0000

3 ‐256.1 120.0 10351 172661 16.68 27.17 0.00 0 179.9 ‐401.93 0.0000 0.0000 0.9546 0.0454 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 1.0000

4 ‐256.1 120.0 10351 172661 16.68 27.17 0.00 0 179.9 ‐401.93 0.0000 0.0000 0.9546 0.0454 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 1.0000

5 ‐256.1 120.0 0 0 16.68 27.17 0.00 0 0.0 0.00 0.0000 0.0000 0.9546 0.0454 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 1.0000

6 ‐199.6 112.0 11357 188767 16.62 23.90 0.00 0 223.7 ‐431.53 0.0000 0.0000 0.9587 0.0413 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 1.0000

7 ‐192.2 835.0 11357 188767 16.62 24.02 0.00 0 222.6 ‐430.12 0.0000 0.0000 0.9587 0.0413 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 1.0000

8 ‐256.0 15.0 6565 105324 16.04 0.11 59.79 15387 0.0 ‐229.27 0.0000 0.0000 0.9999 0.0001 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 1.0000

9 ‐256.1 14.8 2217 35573 16.04 0.11 20.19 5268 0.0 ‐77.43 0.0000 0.0000 0.9999 0.0001 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 1.0000

10 ‐211.3 27.3 2217 35573 16.04 0.17 20.19 3484 0.0 ‐76.68 0.0000 0.0000 0.9999 0.0001 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 1.0000

11 ‐193.5 21.5 2217 35573 16.04 0.12 20.19 4797 0.0 ‐76.34 0.0000 0.0000 0.9999 0.0001 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 1.0000

12 ‐254.7 84.9 241 4011 16.67 27.08 0.00 0 4.2 ‐9.33 0.0000 0.0000 0.9550 0.0450 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 1.0000

13 ‐220.1 16.4 2440 39209 16.07 0.11 22.22 6224 0.0 ‐84.54 0.0000 0.0000 0.9982 0.0018 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 1.0000

14 ‐256.1 14.8 275 4404 16.04 0.11 2.50 652 0.0 ‐9.59 0.0000 0.0000 0.9999 0.0001 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 1.0000

15 ‐58.2 130.0 275 4404 16.04 0.51 2.50 144 0.0 ‐9.18 0.0000 0.0000 0.9999 0.0001 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 1.0000

27 60.0 795.0 14684 242180 16.49 2.70 133.74 1493 0.0 ‐484.08 0.0000 0.0000 0.9679 0.0321 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 1.0000

28 ‐65.5 60.0 15 233 16.04 0.23 0.13 17 0.0 ‐0.48 0.0000 0.0000 0.9999 0.0001 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 1.0000

29 100.0 45.0 15 233 16.04 0.12 0.13 32 0.0 ‐0.46 0.0000 0.0000 0.9999 0.0001 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 1.0000

HM1 180.0 70.0 2502 57259 22.89 62.33 0.00 0 26.0 ‐321.96 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.1106 0.8894 1.0000

HM2 180.0 70.0 14 322 22.89 62.41 0.00 0 0.1 ‐1.81 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.1106 0.8894 1.0000

HM3 110.0 25.0 14 322 22.89 64.40 0.00 0 0.1 ‐1.83 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.1106 0.8894 1.0000

HM4 180.0 70.0 2488 56936 22.89 62.41 0.00 0 25.8 ‐319.82 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.1106 0.8894 1.0000

HM5 110.0 25.0 2488 56936 22.89 64.40 0.00 0 25.0 ‐323.43 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.1106 0.8894 1.0000

HM6 117.4 25.0 2502 57259 22.89 64.12 0.00 0 25.3 ‐325.26 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.1106 0.8894 1.0000

HM7 117.4 25.0 2502 57259 22.89 64.12 0.00 0 25.3 ‐325.26 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.1106 0.8894 1.0000

HM8 117.4 80.0 2502 57259 22.89 64.13 0.00 0 25.3 ‐325.25 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.1106 0.8894 1.0000

SW1 78.1 65.0 221903 3997598 18.02 62.23 0.00 0 1819.0 ‐27185.95 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 1.0000 1.0000

SW2 65.0 15.0 221903 3997598 18.02 62.33 0.00 0 1816.2 ‐27238.65 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 1.0000 1.0000

16 ‐256.1 14.8 4073 65347 16.04 0.11 37.09 9677 0.0 ‐142.25 0.0000 0.0000 0.9999 0.0001 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 1.0000

17 ‐58.2 130.0 4073 65347 16.04 0.51 37.09 2141 0.0 ‐136.18 0.0000 0.0000 0.9999 0.0001 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 1.0000

18 ‐58.7 125.0 4333 69519 16.04 0.49 39.46 2370 0.0 ‐144.87 0.0000 0.0000 0.9999 0.0001 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 1.0000

 

                                           

0.0000

0.0000

19 ‐200.5 110.0 3327 53414 16.05 0.74 30.30 1202 0.0 ‐115.27 0.0000 0.0000 0.9993 0.0007 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 1.0000

21 28.7 815.0 3327 53414 16.05 2.96 30.30 301 0.0 ‐110.28 0.0000 0.0000 0.9993 0.0007 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 1.0000

22 28.1 805.0 3327 53414 16.05 2.92 30.30 305 0.0 ‐110.28 0.0000 0.0000 0.9993 0.0007 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 1.0000

23 ‐58.7 125.0 15 233 16.04 0.49 0.13 8 0.0 ‐0.48 0.0000 0.0000 0.9999 0.0001 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 1.0000

24 ‐192.2 815.0 11357 188767 16.62 24.00 0.00 0 222.7 ‐430.12 0.0000 0.0000 0.9587 0.0413 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 1.0000

0.0000

0.0000

0.0000

0.0000

0.0000

                                           

0.0000

20 ‐200.5 110.0 3327 53414 16.05 0.74 30.30 1202 0.0 ‐115.27 0.0000 0.0000 0.9993 0.0007 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 0.0000 1.0000

                                          0.0000

SHAW CONSULTANTS INTERNATIONAL, INC. HOUSTON, TEXAS 6/5/2012

Section 15 – Appendix C

TERMINAL LAYOUT DRAWINGS

CURACAO CNG-LNG TERMINAL FEASIBILITY STUDY

2500'-0"

2400'-0"

2300'-0"

2200'-0"

2100'-0"

2000'-0"

1900'-0"

1800'-0"

1700'-0"

1600'-0"

1500'-0"

1400'-0"

1300'-0"

1200'-0"

1100'-0"

1000'-0"

900'-0"

800'-0"

700'-0"

600'-0"

500'-0"

400'-0"

300'-0"

200'-0"

100'-0" 1300'-0"

1200'-0" NEW GAS SENDOUT PIPELINE Elec Substation V-7

MCC

1100'-0"

G-1

V-8

PIG-1 TK-6

Gas Meter Skid MTR-1

700'-0"

600'-0"

500'-0"

K-2A K-2B K-1A A P-1 B P-1

K-1B

E-2A/B LP Fuel System V-6

E-4

V-5

HTR-1A

F-1A/B

P-5B P-10 V-9

V-3

TK-1

P-5A

HTR-1B P-6 TK-2

V-1

V-10 V-11

P-2A/B E-1A E-1B

V-12

K-100A K-100B K-200A K-200B

Office CCR

HM System

Ø 255.00

PARKING AREA PARKING

K-2C

P-9 TK-7

InstAir/Nitrogen Systems

Future

LP BOG Vent Storm Sump

LNG Spill Sump

P-12A/B

TK-2 Firewater Tank

P-11A/B

P-13B P-14B

800'-0"

P-8 K-3

IN-TANK PUMPS LNG SENDOUT PUMPS HM PUMPS HM TRANSFER PUMP SEAWATER PUMPS HC SUMP PUMP SLOP OIL TRANSFER PUMP NON-HAZARDOUS SUMP PUMP JOCKEYWATER PUMPS FIREWATER PUMPS LARGE STORMWATER SUMP PUMPS SMALL STORMWATER SUMP PUMPS DIESEL TRANSFER PUMP SHIP VATOR RETURN BLOWERS SMALL BOG COMPRESSORS LARGE BOG COMPRESSOR BOG PIPELINE COMPRESSOR INSTRUMENT AIR PACKAGE NITROGEN GEN PACKAGE BOG CONDENSER LNG DRAIN DRUM HM SURGE DRUM LP FUEL GAS SCRUBBER HP FLARE KO CRYOGENIC CLOSED DRAIN SUMP NON-HAZARDOUS DRAIN SUMP INSTRUMENT AIR RECEIVER UTILITY AIR RECEIVER NITROGEN RECEIVER HM FILTERS LNG OPEN RACK VAPORIZERS SENDOUT GAS SUPERHEATERS LP FUEL GAS HEATER BOG PIPELINE DISCH COOLER HM FIRED HEATERS LNG STORAGE TANK HM STORAGE TANK FIREWATER TANK EMERGENCY GENERATOR HP VENT TOWER BOG/LP VENT TOWER LNG UNLOADING ARMS GAS SENDOUT METER/SAMPLER SENDOUT GAS PIPELINE PIG LAUNCHER

P-13A P-14A

900'-0"

P-1A/B P-2A/B P-5A/B P-6 P-7A/B/C P-8 P-9 P-10 P-11A/B P-12A/B P-13A/B P-14A/B P-15 K-1A/B K-2A/B K-2C K-3 K-100A/B K-200A/B V-1 V-2 V-5 V-6 V-7 V-8 V-9 V-10 V-11 V-12 F-1A/B E-1A/B E-2A/B E-3 E-4 HTR-1A/B TK-1 TK-2 TK-5 G-1 VENT-1 VENT-2 ARM-1/2/3/4 MTR-1 PIG-1

PREVAILING WIND

1 2 3 4 5 6 7 8 9 10 11 12 13 14 16 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44

BOG Compressor Shed

EQUIPMENT LIST 1000'-0"

P-15

Shop/Lab Warehouse

HP Vent

400'-0"

300'-0"

200'-0"

P-7A/B/C

100'-0"

0ft.

150ft.

250ft.

V-2 P-3A/B

SCALE 500ft.

ARM-1/2/3 /4

NOTES:

REV

DATE

A

05-31-2012

REVISION DESCRIPTION Internal Review

CK #1

CK #2

CK #3

Approve

DH

-

-

HGW

CURACAO CONCEPTUAL LNG TERMINAL BULLEN BAY PORT CURACAO, NETHERLAND ANTELIES

PLOT PLAN LAYOUT CURACAO ONSHORE LNG TERMINAL SCALE: 1" = 100'-0"

JOB NO.:

FILE: LAY-01-01 REV A.VSD DATE: By:

05-31-2012 Shaw Consultants

145790 DWG NO.: LAY-01-01

REV A

2500'-0"

2400'-0"

2300'-0"

2200'-0"

2100'-0"

2000'-0"

1900'-0"

1800'-0"

1700'-0"

1600'-0"

1500'-0"

1400'-0"

1300'-0"

1200'-0"

1100'-0"

1000'-0"

900'-0"

800'-0"

700'-0"

600'-0"

500'-0"

400'-0"

300'-0"

200'-0"

100'-0" 1300'-0"

1200'-0" EQUIPMENT LIST

800'-0"

700'-0"

MCC

G-1

V-8

PIG-1 TK-6

Gas Meter Skid MTR-1

K-2A K-2B K-1A A P-1 B P-1

K-1B

E-2A/B LP Fuel System V-6

E-4

V-5

P-5A

HTR-1A

F-1A/B

P-5B P-10 V-9

V-3

TK-1

P-9 TK-7

HTR-1B P-6 TK-2

HM System

Ø 255.00 V-1

V-10 V-11

P-2A/B E-1A E-1B

V-12

K-100A K-100B K-200A K-200B

PARKING PARKING AREA

K-2C

P-15

Shop/Lab Warehouse

P-8 K-3

InstAir/Nitrogen Systems

Future

LP BOG Vent Storm Sump

LNG Spill Sump

P-12A/B

TK-2 Firewater Tank

P-11A/B

P-13A P-14A

600'-0"

V-7

Office CCR

900'-0"

Elec Substation HP Vent

BOG Compressor Shed

1000'-0"

NEW GAS SENDOUT PIPELINE

IN-TANK PUMPS LNG SENDOUT PUMPS HM PUMPS HM TRANSFER PUMP SEAWATER PUMPS HC SUMP PUMP SLOP OIL TRANSFER PUMP NON-HAZARDOUS SUMP PUMP JOCKEYWATER PUMPS FIREWATER PUMPS LARGE STORMWATER SUMP PUMPS SMALL STORMWATER SUMP PUMPS DIESEL TRANSFER PUMP SHIP VATOR RETURN BLOWERS SMALL BOG COMPRESSORS LARGE BOG COMPRESSOR BOG PIPELINE COMPRESSOR INSTRUMENT AIR PACKAGE NITROGEN GEN PACKAGE BOG CONDENSER LNG DRAIN DRUM HM SURGE DRUM LP FUEL GAS SCRUBBER HP FLARE KO CRYOGENIC CLOSED DRAIN SUMP NON-HAZARDOUS DRAIN SUMP INSTRUMENT AIR RECEIVER UTILITY AIR RECEIVER NITROGEN RECEIVER HM FILTERS LNG OPEN RACK VAPORIZERS SENDOUT GAS SUPERHEATERS LP FUEL GAS HEATER BOG PIPELINE DISCH COOLER HM FIRED HEATERS LNG STORAGE TANK HM STORAGE TANK FIREWATER TANK EMERGENCY GENERATOR HP VENT TOWER BOG/LP VENT TOWER LNG UNLOADING ARMS GAS SENDOUT METER/SAMPLER SENDOUT GAS PIPELINE PIG LAUNCHER

P-13B P-14B

1100'-0"

P-1A/B P-2A/B P-5A/B P-6 P-7A/B/C P-8 P-9 P-10 P-11A/B P-12A/B P-13A/B P-14A/B P-15 K-1A/B K-2A/B K-2C K-3 K-100A/B K-200A/B V-1 V-2 V-5 V-6 V-7 V-8 V-9 V-10 V-11 V-12 F-1A/B E-1A/B E-2A/B E-3 E-4 HTR-1A/B TK-1 TK-2 TK-5 G-1 VENT-1 VENT-2 ARM-1/2/3/4 MTR-1 PIG-1

PREVAILING WIND

1 2 3 4 5 6 7 8 9 10 11 12 13 14 16 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44

500'-0"

400'-0"

300'-0"

200'-0"

P-7A/B/C

V-2 P-3A/B

100'-0"

SCALE 0ft.

NOTES:

150ft.

250ft.

500ft.

ARM-1/2/3 /4

REV

DATE

A

05-31-2012

REVISION DESCRIPTION Internal Review

CK #1

CK #2

CK #3

Approve

DH

-

-

HGW

CURACAO CONCEPTUAL LNG TERMINAL BULLEN BAY PORT CURACAO, NETHERLAND ANTELIES

PLOT PLAN LAYOUT CURACAO ONSHORE LNG TERMINAL SCALE: 1" = 100'-0"

JOB NO.:

FILE: LAY-01-02 REV A.VSD DATE: By:

05-31-2012 Shaw Consultants

145790 DWG NO.: LAY-01-02

REV A

2500'-0"

2400'-0"

2300'-0"

2200'-0"

2100'-0"

2000'-0"

1900'-0"

1800'-0"

1700'-0"

1600'-0"

1500'-0"

1400'-0"

1300'-0"

1200'-0"

1100'-0"

1000'-0"

900'-0"

800'-0"

700'-0"

600'-0"

500'-0"

400'-0"

300'-0"

200'-0"

100'-0" 1300'-0"

1200'-0" NEW GAS SENDOUT PIPELINE Elec Substation MCC

1100'-0"

G-1 PIG-1

HP Vent V-2

800'-0"

700'-0"

K-3 K-2

E-3 E-2

K-1

V-5 V-6 V-7

K-100A K-100B K-200A K-200B

InstAir/Nitrogen Systems

LP BOG Vent

V-4

Storm Sump

P-3A P-4A

600'-0"

PARKING AREA PARKING

E-1 Shop/Lab Warehouse

V-1

Storm Sump

P-3B P-4B

900'-0"

P-2

P-1

V-3

HC DRAIN SUMP PUMP SLOP OIL TRANSFER PUMP LARGE STORMWATER SUMP PUMPS SMALL STORMWATER SUMP PUMPS 1st STAGE BOG COMPRESSOR 2nd STAGE BOG COMPRESSOR 3rd STAGE BOG COMPRESSOR INSTRUMENT AIR PACKAGE NITROGEN GEN PACKAGE BOG SUCTION SCRUBBER HP VENT KO HC DRAIN SUMP BOG VENT KO INSTRUMENT AIR RECEIVER UTILITY AIR RECEIVER NITROGEN RECEIVER 1st STAGE BOG COMPRESSOR DISCH COOLER 2nd STAGE BOG COMPRESSOR DISCH COOLER 3rd STAGE BOG COMPRESSOR DISCH COOLER EMERGENCY GENERATOR HP VENT TOWER LP BOG VENT TOWER GAS AND BOG UNLOADING ARMS GAS SENDOUT METER/SAMPLER SENDOUT GAS PIPELINE PIG LAUNCHER SLOP OIL TANK

BOG Compressor Shed

1000'-0"

P-1 P-2 P-3A/B P-4A/B K-1 K-2A/B K-2C K-100A/B K-200A/B V-1 V-2 V-3 V-4 V-5 V-6 V-7 E-1 E-2 E-3 G-1 VENT-1 VENT-2 ARM-1/2/3 MTR-1 PIG-1 TK-1

PREVAILING WIND

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26

TK-1

Office CCR

EQUIPMENT LIST

Gas Meter Skid MTR-1

500'-0"

400'-0"

300'-0"

200'-0"

100'-0"

SCALE 0ft.

150ft.

250ft.

500ft. ARM-1/2/3

NOTES:

REV

DATE

A

05-31-2012

REVISION DESCRIPTION Internal Review

CK #1

CK #2

CK #3

Approve

DH

-

-

HGW

CURACAO CONCEPTUAL LNG TERMINAL BULLEN BAY PORT CURACAO, NETHERLAND ANTELIES

PLOT PLAN LAYOUT CURACAO FSRU LNG TERMINAL SCALE: 1" = 100'-0"

JOB NO.:

FILE: LAY-02-01 REV A.VSD DATE: By:

05-31-2012 Shaw Consultants

145790 DWG NO.: LAY-02-01

REV A

Section 15 – Appendix D

MAJOR EQUIPMENT LIST

CURACAO CNG-LNG TERMINAL FEASIBILITY STUDY

CURACAO CNG-LNG FEASIBILITY STUDY MAJOR EQUIPMENT LIST

Tag ID

Service

Drawing No.

Qty

%

Type

Material

Capacity of One Unit (Max for Each Phase) Liq Aqueous Gas MMscfd m 3 /hr m 3 /hr

Design P psig

T F

o

Operating T P o psig F

Heat Duty One Unit

Power One Unit

MMBtu/Hr

kW

Dimension of One Unit Height feet

W or Dia feet

Length feet

Total Weight Metric Tons Dry

Oper

Design Notes

POWER GENERATION

G‐1

EMERGENCY GENERATOR SWITCH GEAR AND MCC BUILDING

1

100 DIESEL ENGINE

           625              7.0              7.8            11.0       13.8             14.2                 ‐              64.0            32.0       59.9             59.9  DIMENSSIONS ARE FOR MCC BLDG.

SHIP VAPOR RETURN BLOWER SMALL BOG COMPRESSOR LARGE BOG COMPRESSOR BOG PIPELINE COMPRESSOR INSTRUMENT AIR PACKAGE NITROGEN GENERATOR PACKAGE

2 2 1 1 2 2

100 CENTRIFUGAL BLOWER 100 RECIPROCATING 100 RECIPROCATING 100 RECIPROCATING 100 RECIPROCATING 100 RECIPROCATING

SS 304L SS 304L SS 304L SS 304L CS CS

P‐1A/B P‐2A/B P‐3A/B

IN‐TANK LNG PUMP LNG SENDOUT PUMP LNG DRAIN DRUM PUMP

P-5A/B P-6 P-7A/B/C P-8 P-9 P-10 P-11A/B P-12A/B P-13A/B P-14A/B P-15

HM PUMP HM TRANSFER PUMP SEAWATER PUMP HC SUMP PUMP SLOP OIL TRANSFER PUMP NON-HAZARDOUS SUMP PUMP JOCKEY WATER PUMP FIREWATER PUMP (DIESEL) LARGE STORMWATER SUMP PUMP SMALL STORMWATER SUMP PUMP

2 2 2 2 1 3 1 1 1 2 2 2 2 1

100 CRYO STORAGE DEEPWELL 100 CRYO MULTI‐STAGE CAN 100 CRYO MULTI‐STAGE CAN 100 IN‐LINE CENTRIFUGAL 100 IN‐LINE CENTRIFUGAL 50 DEEPWELL V‐TOP DRIVE 100 DEEPWELL V‐TOP DRIVE 100 H‐CENTRIFUGAL 100 DEEPWELL V‐TOP DRIVE 100 IN‐LINE CENTRIFUGAL 100 H‐CENTRIFUGAL (DIESEL ENGINE) 50 DEEPWELL V‐TOP DRIVE 50 DEEPWELL V‐TOP DRIVE 100 H‐CENTRIFUGAL

AL AL AL CS CS Ni‐Bz‐Al CS CS CS Ni‐Bz‐Al Ni‐Bz‐Al Ni‐Bz‐Al Ni‐Bz‐Al CS

1 1 1

100 H 2‐PHASE  100 H 2‐Phase Sep 100 H Scrubber 100 H 2-Phase Sep 100 V Scrubber 100 H Scrubber 100 H Scrubber 100 H Scrubber 100 H Scrubber 100 H Scrubber 100 H Scrubber

2 1 3

100 Charcoal Bed Liquid Filter 100 Self Cleaning (0.5 fps velocity) 50 Filter Trap Manual Cleanout

2 1 1

100 Shell & Tube 100 Brown Fin‐Tube 100 Air Fan Cooler

COMPRESSORS

K‐1A/B K‐2A/B K‐2C K‐3 K‐100A/B K‐200A/B

             20              2.5               37               30 

      275        275        275     1,440        285        285 

‐260 ‐260 ‐260 ‐260 350 350

         12        115        115        790        150        150 

‐256 ‐58 ‐58 ‐200 290 290

           250              5.5             150              5.5         1,800              7.5         1,500              7.5               75              4.5               75              4.5 

      275     1,440        275        260        260        150        150        150        150        200        200        150        150        150 

‐260 ‐260 ‐260 200 150 100 100 100 100 100 100 100 100 100

      120        820        115           65           65           50           50           50           50        150        150           50           50           50 

‐256 ‐250 ‐220 117 80 78 80 80 80 80 80 80 80 80

           100             480                 6 

SS 304L SS 304L SS 304L CS CS SS 304L SS 304L CS CS CS CS

      150        150        150               25        260              0.5        150             250               23        150                 2               23        150                 2               25        150        175        175        175 

‐260 ‐260 ‐260 200 150 ‐260 ‐260 200 150 150 150

      100             7         0.5           10           30           50             5             5        125        125        125 

‐250 ‐220 ‐228 117 100 ‐200 ‐260 180 120 120 120

CS Ni‐Bz‐Al Ni‐Bz‐Al

               3        260         2,700         1,350 

299          50 

117

   1,440        150     1,440 

200       790  200          30  300       790 

            5.5              5.5              7.5              7.5              4.5              4.5 

          11.0            11.0            18.0            18.0              9.4              9.4 

     20.2       16.8       26.2       29.8       12.2       12.2 

           20.8             17.3             27.0             30.7             12.6             12.6 

        1.1          4.7          1.0          0.5          0.4          2.8          0.5          1.0          0.5          0.5          5.7          1.5          0.5          1.0 

             1.1               4.8               1.3               0.5               0.4               2.8               0.5               1.0               0.5               0.5               5.9               1.5               0.5               1.0 

        8.5          1.6          2.7          3.6          0.3          6.5          6.5          2.8          5.3          5.3          5.3 

           18.5  ABSORBER MOUNTED ATOP VESSEL              2.9               3.5               8.6               0.4               6.9               6.9             12.3               5.6               5.6               5.6 

PUMPS

DIESEL TRANSFER PUMP

PRESSURE VESSELS V-1 BOG CONDENSER V-2 LNG DRAIN DRUM PUMP V-3 BOG COMPRESSOR SCRUBBER V-5 V-6 V-7 V-8 V-9 V-10 V-11 V-12

HM SURGE DRUM LP FUEL GAS SCRUBBER HP FLARE/VENT KO CRYOGENIC CLOSED DRAIN SUMP NON-HAZARDOUS DRAIN SUMP INSTRUMENT AIR RECEIVER UTILITY AIR RECEIVER NITROGEN RECEIVER

1 1 1 1 1 1 1 1

           250             260               23               25               12         1,350               26               26               26                 5         1,150             575               58                 5             260               23                 1 

            9.5              5.5              6.3              5.3              2.0              7.5              7.5              5.7              7.0              7.0              7.0 

          24.0            12.0            14.0            12.0              8.0            30.0            30.0            12.0            14.0            14.0            14.0 

FILTERS

F‐1A/B Sp Sp

HM FILTER SEAWATER PUMP INTAKE SCREEN SEAWATER PUMP FILTER TRAPS

            0.7              4.1          0.2               0.3  SCREEN SERVES ALL SW PUMPS FILTER TRAP ON PUMP DISCHARGE

HEAT EXCHANGERS

E‐2A/B E‐3 E‐4

SENDOUT GAS SUPPERHEATER LP FUEL GAS HEATER BOG PIPELINE COMPRESSOR DISCH COOLER

CS CS CS

           137              0.5               20 

60             3.20   17 in            20.0          3.1               4.3  100             0.10   4 in              6.0          0.4               0.4  250             3.14                 8              7.3            11.7            13.0          0.9               1.0  Air Temp Delta = 50 DegF

SHAW CONSULTANTS INTERNATIONAL , INC. Equipment List Rev 1.xlsx  6/7/2012

CURACAO CNG-LNG FEASIBILITY STUDY MAJOR EQUIPMENT LIST

Tag ID

Service

Drawing No.

Qty

%

Type

VAPORIZERS AND HEATERS E-1A/B LNG OPEN RACK VAPORIZER HTR-1A/B HM GAS FIRED HEATER

2 2

100 ORV 100 Horizontal Fire Tube Bath Heater

TANKS TK-1 TK-2 TK-3 TK-4 TK-5 TK-6 TK-7

1 1 2 1 1 1 1

100 Full Containment Type Tank 100 API 100 Pipe Tank 100 Pipe Tank 100 API 100 API 100 API

LNG STORAGE TANK (160,000 M3) HM STORAGE TANK FIREWATER PUMP DIESEL DAY TANK EMERGENCY GEN DIESEL DAY TANK FIREWATER TANK (8HR @ 5,000gpm) SLOP OIL TANK DIESEL STORAGE TANK

MISC. EQUIPMENT sP HP FLARE/VENT TIP AND TOWER sP LP BOG FLARE/VENT TIP AND TOWER sP OFFICE / CONTROL ROOM BUILDING sP WORKSHOP / LAB / WAREHOUSE sP MCC ROOM + EMERG GEN ROOM sP BOG & SHIP VAPOR COMPRESSOR SHED sP SENDOUT GAS CUSTODY METER sP COMMUNICATIONS SYSTEM sP sP sP sP sP sP sP

UPS SYSTEM DCS COMPUTER SYSTEM & PROGRAMING LNG UNLOADING ARMS (STD. 16") LNG UNLOADING PLATFORM / STRUCTURE GUARD HOUSE LNG JETTY AND MOORING EQUIPMENT SEAWATER PUMP PLATFORM

1 1 1 1 1 1 1 1 1

Sonic Tip; Tower Structure Tower Stucture Modular Unit Modular Unit Cender Block Building Open Side Building Ultrasonic w/ Gas Analyzer Ship‐to‐Shore, In‐Plant PA 30‐Minute Backup Critical Services

4 1 1

2 LNG, 1 Hybrid LNG/Vapor, 1 Vapor 100' X 60' Piled Tubular Substructure 14' X 14' Modular Unit

1

Supported From LNG Unloading Platform

Material

AL‐6XN CS

Capacity of One Unit (Max for Each Phase) Liq Aqueous Gas MMscfd m 3 /hr m 3 /hr

     137.00 

9% Ni CS CS CS CS CS CS

Design P psig

   1,440               23        245         2.8             2             2             2             2             2             2 

T F

o

Operating T P o psig F

Heat Duty One Unit

Power One Unit

MMBtu/Hr

kW

Dimension of One Unit Height feet

W or Dia feet

Length feet

Total Weight Metric Tons Dry

Oper

‐260       800  250          65 

‐245          78.28  180             2.91 

          29.0            15.0            23.0       42.2             99.6              6.3              6.5            16.0       14.8             15.4 

‐260 100 100 100 100 100 100

‐256 80 80 80 80 80 80

        129.0          255.4              8.0            10.0              3.0            17.7              3.0            17.7            45.4          100.0              8.0            10.0              8.0            10.0 

       1.0             0             0             0             0             0             0 

        2.1          1.8          1.8     455.2          2.1          2.1 

Design Notes

           20.3  100 Bbl Capacity              7.6  20 Bbl Capacity              7.6  20 Bbl Capacity    10,554.1  57,200 Bbl Capacity            16.2  100 Bbl Capacity            16.4  100 Bbl Capacity

           250               60            36.0            36.0            35.0            32.0 

          72.0            72.0            64.0          150.0 

2,600 Square Feet 2,600 Square Feet 2,050 Square Feet 4,800 Square Feet

           140 

SAFETY & FIRE PROTECTION sP FIREWATER RING MAIN/LATERIALS W/ DELUGE sP FIRE/SMOKE/GAS DETECTION & ESD SYSTEM sP MISC PORTABLE FIRE EXTINGUISHERS sP CO2 SYSTEM FOR MCC BUILDING POTABLE WATER & SEWAGE TREATMENT sP Sewage Treatment Unit

1

100 Conventional Aerobic Sewage Plant

SHAW CONSULTANTS INTERNATIONAL , INC. Equipment List Rev 1.xlsx  6/7/2012

Section 15 – Appendix E

UTILITY LOAD SUMMARY

CURACAO CNG-LNG TERMINAL FEASIBILITY STUDY

CURACAO CNG‐LNG FEASIBILITY STUDY ELECTRICAL UTILITY LOAD SUMMARY

Electrical Equipment Tag ID K-1A/B K-2A/B K 2C K-2C K-3 K-100A/B K-200A/B P-1A/B P-2A/B P-3A/B P-5A/B P-6 P-7A/B/C P-8 P-9 P-10 P-11A/B P-13A/B P-14A/B E-4 HTR-1A/B

Service SHIP VAPOR RETURN BLOWER SMALL BOG COMPRESSOR LARGE BOG COMPRESSOR BOG PIPELINE COMPRESSOR INSTRUMENT AIR PACKAGE NITROGEN GEN PACKAGE IN-TANK LNG PUMP LNG SENDOUT PUMP LNG DRAIN DRUM PUMP HM PUMP HM TRANSFER PUMP SEAWATER PUMP HC SUMP PUMP SLOP OIL TRANSFER PUMP NON-HAZARDOUS SUMP PUMP JOCKEY WATER PUMP LARGE STORMWATER SUMP PUMP SMALL STORMWATER SUMP PUMP BOG PIPELINE COMPRESSOR DISCH COOLER HEATING MEDIUM FIRED HEATER UNLOADING PLATFORM CENTRAL CONTROL ROOM OFFICE WORKSHOP / LAB / WAREHOUSE PLANT LIGHTING MCC BUILDING GUARD HOUSE

Qty 2 2 1 1 2 2 2 2 2 2 1 3 1 1 1 2 2 2 1 2 1 1 1 1 1 1 1

% 100 100 100 100 100 100 100 100 100 100 100 50 100 100 100 100 50 50 100 100 100 100 100 100 100 100 100

Units Ship Unload Run Duty hp 300 1 200 1 2 2,385 385 1 1,965 1 100 1 100 1 120 1 640 1 8 1 5 1 2 1 240 2 5 1 5 1 5 1 3 1 70 2 7 2 10 6 1 30 1 48 1 48 1 129 1 265 1 48 1 12 1

Normal Run 1 1 1 1 1 1 1 2 1 1 1 1 2 2 1 1 1 1 1 1 1 1

Duty kW 224 149 1 1,779 779 1,466 75 75 90 477 6 4 1 179 4 4 4 2 52 5 7 4 22 36 36 96 198 36 9 TOTALS

Connected

Ship Unload

Load kW 448 298 1 1,779 779 1,466 149 149 179 955 12 7 1 537 4 4 4 4 104 10 7 9 22 36 36 96 198 36 9 6,562

Load kW 224 113 1 1,779 779 1,466 75 75 90 477 6 4 1 358 4 4 4 2 104 10 4 22 36 36 96 198 36 9 5,234

Normal

Load kW 149 75 75 90 477 4 1 358 4 4 4 2 104 10 4 22 36 36 96 198 36 9 1,795

Emergency

Load kW

75

2 104 10

22 36 36 96 198 36 9 625

SHAW CONSULTANTS INTERNATIONAL, INC. Electrical Load Summary Rev 1.xlsx  6/7/2012

Section 15 – Appendix F

KEY MILESTONE PROJECT SCHEDULE

CURACAO CNG-LNG TERMINAL FEASIBILITY STUDY

Act ID 1000 1010 1020 1030 1040 1050 1060 1070 1080 1090 1100 1110 1120 1130 1140 1150 1160 1170 1180 1190 1200 1210 1220

Description 1

Start FEED FEED Engineering Commence EPC Contract Effort EPC Contract Bid and Award Award EPC Contract

2

3

4

5

6

7

8

9

MONTH 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60 61 62 63 64 65 66 67 68 69 70 71 72 73 74 75 76 77 78 79 80 81 82 83 84 85 86 87 88 89 90

Start FEED FEED Engineering Commence EPC Contract Effort EPC Contract Bid and Award Award EPC Contract Detailed Engineering

Detailed Engineering Engineering 50% Model Review P&IDs Issue for Cnstruction Engineering 90% Model Review

Engineering 50% Model Review P&IDs Issue for Cnstruction Engineering 90% Model Review Procurement

Procurement Award PO Vaporizers Award PO LNG Pumps Commence Delivers - Steel Award Tank Subcontract

Award PO Vaporizers Award PO LNG Pumps Commence Delivers - Steel Award Tank Subcontract Tank Engineering and Construction

Tank Engineering and Construction Commence Tank Piles / Foundation Mobilize Mechanical Construction Foundations - Balance of Terminal

Commence Tank Piles / Foundation Mobilize Mechanical Construction Foundations - Balance of Terminal Construction - Balance of Terminal

Construction - Balance of Terminal

Ready for Cooldown

Ready for Cooldown

Cool Down - Mechanical Completion

Cool Down - Mechanical Completion

Start-up

Start-up

Gas Sendout

Gas Sendout

Start date 09MAY12 Finish date 16AUG16 Data date 09MAY12 Run date 07JUN12 Page number 1A © Primavera Systems, Inc.

Curacao LNG Terminal

Early bar Progress bar Critical bar Summary bar Start milestone point Finish milestone point

Section 15 – Appendix G

LNG SHIPPING ROUTE CHARTS

CURACAO CNG-LNG TERMINAL FEASIBILITY STUDY

Freeport to Curacao 

Sabine Pass to Curacao 

 

Atlantic LNG Point Fontin to Curacao 

   

 

   

Qatar to Curacao 

   

 

Peru LNG to Curacao 

 

 

 

Nigeria LNG to Curacao 

     

 

Algeria LNG to Curacao 

   

 

Angola LNG to Curacao 

     

Section 15 – Appendix H

HURRICANE HISTORICAL TRACKING CHARTS

CURACAO CNG-LNG TERMINAL FEASIBILITY STUDY

2005

Source: http://www.nhc.noaa.gov/tracks/

1

2006

Source: http://www.nhc.noaa.gov/tracks/

2

2007

Source: http://www.nhc.noaa.gov/tracks/

3

2008

Source: http://www.nhc.noaa.gov/tracks/

4

2009

Source: http://www.nhc.noaa.gov/tracks/

5

2010

Source: http://www.nhc.noaa.gov/tracks/

6

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