Comparisons between LNG Terminals

Customer: Document Title:

Date of Issue:

The United States Department of Energy National Energy Technology Laboratory

24 April 2003

Report III: Comparisons Between LNG Receiving Conventional, Salt cavern Based, and “Energy Bridge®”

Terminals:

Doc # & Version:

Doc 07 r2.0

Page 1 of 7

Comparisons between LNG Receiving Terminals: Conventional, Salt cavern Based, and “Energy Bridge®”

BY MICHAEL M. MCCALL WILLIAM M. BISHOP D. BRAXTON SCHERZ

r 1.0

For client review

02/09/03

Version

Reason for Issue

Issue Date

Document Title: Comparisons Between LNG Receiving Terminals: Conventional, Salt cavern Based, and “Energy Bridge®”

BS

MM

Orig. Chk. Appr. Chk. Appr. CGI NETL

Review

Document No: CGI/DOE_DOC 07 DE-FC26-02NT41653

Filename: 41653R01

Customer: Document Title:

Date of Issue:

The United States Department of Energy National Energy Technology Laboratory Report III: Comparisons Between LNG Receiving Conventional, Salt cavern Based, and “Energy Bridge®”

24 April 2003 Terminals:

Doc # & Version:

Doc 07 r2.0

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TABLE OF CONTENTS

1. EXECUTIVE SUMMARY ..................................................................................................................................3 2. TYPICAL LNG TERMINALS ............................................................................................................................3 3. EL PASO’S ENERGY BRIDGE........................................................................................................................4 4. SUMMARY OF ESTIMATED CAPITAL, OPERATION, AND FUEL COSTS..................................................6

Filename: 41653R01

Customer: Document Title:

Date of Issue:

The United States Department of Energy National Energy Technology Laboratory Report III: Comparisons Between LNG Receiving Conventional, Salt cavern Based, and “Energy Bridge®”

24 April 2003 Terminals:

Doc # & Version:

Doc 07 r2.0

Page 3 of 7

1. EXECUTIVE SUMMARY The technologies in the LNG industry have remained essentially unchanged over the years. “Energy Bridge,” a notable exception developed by El Paso Global LNG Co., combines LNG shipping and regasification on a single ocean-going vessel. Energy Bridge because of its mobility, “zero footprint”, and offloading flexibility may have advantages in markets where spot trades command higher prices. The LNG spot market continues to grow, but long term baseload LNG sales contracts have yet to be eclipsed. Whether or not Energy Bridge realizes its true competitive advantage has yet to be confirmed. Five representative LNG terminals were evaluated to determine an indicative cost of service required to achieve a 15% IRR on each project. A summary review of the findings (Table 4.1) prepared for this Document 07, indicates that the Bishop Process Exchanger LNG terminals generate the lowest terminal fees required to achieve the 15% IRR condition. This is attributable to competitive CAPEX costs, very high sendout rates, excellent fuel efficiencies, and lower operating costs. 2. LNG TERMINALS – FIVE CASES Five generally defined LNG terminals were selected for the basis of this study. There were no attempts to “equalize” the terminals by establishing a base line capacity, or any other common element that might skew the results of the matrix. Rather, each terminal is based upon an actual or proposed LNG project. The Bishop Process Onshore and Offshore terminals in this section are representative also and are not to be confused with the onshore and offshore terminals in Task 2.0. Terminals in Task 2.0 are site specific and estimated costs reflect each terminal location. Terminal send-out is a product of design, and the results of the comparisons have been based on a 100% load factor for each project and unitized on a BTU basis. Regarding El Paso’s Energy Bridge®, there are no provisions for a land based receiving terminal. For cost comparison purposes the estimate for an LNG vessel of 138,000 m3 of membrane tank design was used. An LNG specific cost estimating model using factored analysis was chosen as a basis of the calculated results. LNG receiving terminals have many machinery items in common and the costs for these items remain common throughout the comparison. There are of course major differences in the methods used to store LNG, the design of the marine facility, and the methods used to vaporize LNG. These major differences are reflected in capital costs, fuel cost, and personnel required to staff the terminals. For the first case, an LNG terminal located on the Pacific Coast of the Americas (North or South) was selected. Pacific coast LNG sites typically share several major design similarities including, (1) the requirement for a breakwater and a long approach trestle to protect and access the LNG berth, and (2) large LNG storage tanks to allow for adequate reserve due to the long distances from LNG supplier (Asia in most cases) to the receiving terminal. These requirements generally increase the cost of the terminal as indicated in the following tables. An estimate of an LNG terminal located on the Atlantic coast of North America forms the basis of the second case. This terminal will serve as a baseload LNG receiving facility, and benefits from a good location directly adjacent to deep water. For this reason a short approach trestle connects the dock with the shore facility, and no breakwater is required. Storage can be optimized because there are several LNG supply terminals located within reasonable shipping distances from the receiving facility. Cases three and four reflect LNG receiving terminals based on the use of the Bishop Process Heat Exchanger (BPT) and use salt caverns for storage. A detailed discussion of the Onshore and Offshore BPT terminal is included in Task 2.0 of this study. El Paso’s Energy Bridge® concept represents the fifth case.

Filename: 41653R01

Customer: Document Title:

Date of Issue:

The United States Department of Energy National Energy Technology Laboratory Report III: Comparisons Between LNG Receiving Conventional, Salt cavern Based, and “Energy Bridge®”

24 April 2003 Terminals:

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Doc 07 r2.0

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3. EL PASO - ENERGY BRIDGE®

Fig. 3.1

The fifth LNG terminal used in the comparison is based on El Paso’s Energy Bridge concept. EL PASO’S ENERGY BRIDGE developed by El Paso Global LNG Co., combines LNG shipping and regasification on a single ocean-going vessel. Proven technologies are employed by Energy Bridge allowing natural gas to be delivered directly to coastal markets. With this new system, scheduled gas delivery from remote regions could take place on a baseload or seasonal basis, using highly reliable offshore moorings and subsea pipelines to shore. Figure 3.1 above is an artist’s rendering of what an EPEB vessel might look like. A new ship design is not required, simply modification of an existing LNG carrier. Shown are some of the major components, such as onboard vaporizers and a view of the turret with the docking buoy attached to the receiving housing. The EPEB inter-connection design uses the APL Submerged Turret Loading (APL) system, with a docking buoy that provides a single-point mooring system with high reliability for offshore LNG-vessel unloading. The APL system has been proven in actual conditions and under very severe conditions in the North Sea off the coast of Norway. Connections with the APL buoy have been made in seastates over 5 meters and operational loading has taken place on seastates over 13 meters. There are currently 19 APL buoys in service, used for traditional oil and gas

Filename: 41653R01

Customer: Document Title:

Date of Issue:

The United States Department of Energy National Energy Technology Laboratory Report III: Comparisons Between LNG Receiving Conventional, Salt cavern Based, and “Energy Bridge®”

24 April 2003 Terminals:

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Doc 07 r2.0

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production operation. Over 1,000 connections have been made to date in the North Sea with a 100% success rate. El Paso envisions a fleet of specially equipped EPEB vessels bringing LNG to market. Figure 3.2 shows the general system layout. Upon arrival in the terminal area, the EPEB ship connects to a submerged offloading system which moors the vessel and connects it to an offload pipeline. This takes place well offshore and

Fig. 3.2

typically over the horizon. Once connected to the offload pipeline, the ship begins onboard regasification to provide safe LNG conversion to vaporous natural gas at pressures up to 1,400 psi. Referring to Figure 3.2, the gas is sent through the offloading system and riser to a seabed pipeline that leads to an onshore customer’s facility, or a nearby as transmission pipeline. At conclusion of the transfer the ship releases the offloading system to its idle position safely beneath the ocean’s surface where it remains until the next ship arrives. Each 138,000 m3 tanker carries about 3 Bcf of gas and will typically off load in 7 to 10 days. At 100% load factor the vessel can discharge its cargo in about 5.5 days. Figure 3.3 shows how the system will look when gas is being offloaded. The APL system is suitable for water depths of 35 meters to well over 100 meters. Once the ship is connected to the mooring buoy, it freely weathervanes with the wind and the current, thus mitigating much of the stress on the mooring lines and anchors. Once connected send-out to shore can occur in seas of 10 to 11 m, providing for high reliability. The typical offshore gas installation have two offloading buoys and risers to accommodate simultaneous docking and undocking assuring continuous flow.

Filename: 41653R01

Customer: Document Title:

Date of Issue:

The United States Department of Energy National Energy Technology Laboratory Report III: Comparisons Between LNG Receiving Conventional, Salt cavern Based, and “Energy Bridge®”

24 April 2003 Terminals:

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Doc 07 r2.0

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A detailed review of the marketing aspects of this innovative design is beyond the scope of this study. However, general reactions to Energy Bridge and its comparison to the other four LNG terminal options will be assessed in the matrix of Doc 08 of this study Task.

Fig. 3.3

4. SUMMARY OF LNG TERMINAL ESTIMATED CAPITAL, OPERATION, AND FUEL COSTS LNG terminal estimated Operating and Maintenance costs are based on historical LNG operation and maintenance data. The major engineering firms estimate OPEX costs at 1.5% of the TIC capital cost of the terminal for the first year of operation and 1% thereafter. For the purposes of this study, CGI will use that assumption for all five terminal examples and average costs over a 20 year period. The O&M costs do not include fuel gas or imported power. The estimated fuel consumption of each terminal and fuel efficiencies have been derived from engineering studies listing the power requirements, or from fuel requirements published in existing tariffs. Table 4.1 includes a summary of all critical elements involved in the analysis, and it is understood that the results are indicative rather than actual. As the table indicates, the BPT LNG terminals due to competitive CAPEX costs, excellent fuel efficiencies, and lower operating costs generate the lowest terminal fees required to achieve the 15% IRR condition. The equipment list used to generate the factored analysis and the summary sheet of the financial model for each terminal is included in Doc 07 Attachment I. The following document (Doc 08) includes the matrix used to summarize the advantages and disadvantages of each LNG terminal design.

Filename: 41653R01

(percent of through-put

($/mmBtu)

500 182,500 194,727,500 3.75

67 202,906,294 1.04 2,079,790 6,610,000 0.045 0.85% 0.220

800 292,000 311,564,000 6.00

107 415,827,479 1.33 4,262,232 11,200,000 0.050 1.20% 0.250

0.094

0.33%

0.017

8,500,000

3,013,726

0.43

294,022,086

235

639,000 681,546,250 13.10

1750/3000 peak

Bishop Process/Salt Store

Offshore Terminal

0.090

0.33%

0.016

8,000,000

3,048,409

0.44

0.295

1.00%

0.046

5,600,000

2,944,502

1.54

287,268,472

64

235 297,405,735

175,200 186,938,400 3.60

480

Direct to Gas Pipeline

Energy Bridge

639,000 681,546,250 13.10

1750/3000 peak

Bishop Process/Salt Store

Onshore Process

Report III: Comparisons Between LNG Receiving Conventional, Salt cavern Based, and “Energy Bridge®”

Fee Required to Realize Project Pre-Tax IRR of 15%

Fuel Consumption

($USD/yr)

($/mmBtu)

(TIC $USD)

($USD/yr @ 3.00/mcf)

OPEX (O&M + Fuel) / Plant Capacity

Estimated Fuel Cost

Estimate O & M

TIC per Plant Capacity

Estimated Total Installed Cost

Maximum Cargoes per year

(mmBtu) Million Metric Tonnes per Anum

(m mcf)

(daily full design rate in mmcfd)

Est. Annual Sendout 100% load factor

Sendout

Atlantic North East

Traditional Terminal

Pacific Coast

Traditional Terminal

Document Title:

Cavern Terminals are ship limited

Customer:

The United States Department of Energy National Energy Technology Laboratory Date of Issue:

Terminals:

24 April 2003

Doc 07 r2.0

Doc # & Version:

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Table 4.1 – LNG Terminal Cost Comparison

Note : Table 4.1 references LNG terminals representative of geographic locations and as such do not refer specifically to the Pro-Forma estimates for the LNG Onshore and Offshore terminals presented in Task 2.0

Filename: 41653R01

PACIFIC COAST LNG TERMINAL PROFORMA ECONOMICS Project Summary SUMMARY FACILITY ASSUMPTIONS Facility Basis - Firm Service Cargos per Year LNG Discharge per Ship, cubic meters LNG LNG Btu content, Btu/scf Storage Working Gas Volume, Bcf Storage Base Gas Volume, Bcf

Pricing Throughput Fee, $/MmBtu Other Revenue - % of Terminal Throughput Rev. Terminal Energy Use Charge, % of throughput Assumed Henry Hub Index for initial year Gas Storage Net Revenue Realized $MM/year Other Assumptions Base Gas Price (Delivered), $/Mcf Base Gas Source ("Lease" or "Buy") Total Operations Cost, $M/Year - Labor & Maintenance, $M/Yr - Electrical Demand Charge, $M/Yr Management Overhead, $M/Year Property Taxes (assumed amount), $M/Yr Storage Site Lease Fee, $M/yr % Revenue Stream to Inflation Protect, %/yr General Inflation Rate Inflation applied to certain annual costs, %/yr Energy Use for Terminal ops., % of throughput Full storage cavern compression charge rate % of throughput requiring compression at cavern Project & Technology Rights Running Royalty, as % of Henry Hub index Project & License Upfront Payment, $MM

107 138,000 1067 16.00 7.30

0.250 0.0% 0.00% $3.50 $0.0

3.50 buy 2,499 2,299 200 360 4,000 500 100% 3.0% 1.5% 1.20% 0.00% 0%

Facility Costs, $ Marine Port Facilities LNG Vaporization & Process Terminal Utility System Storage Surface Facility Site Specific Misc Header Pipeline Engineering & Const. Mgmt. Project Acquisition & Tech. Rights Owner Costs, Permits, Misc. Financing Fees Contingency Total Facility Cost

FINANCIAL ASSUMPTIONS 50,910,255 74,108,000 28,288,700 166,070,000 31,423,797 0 19,674,248 50,000 7,191,583 21,048,045 56,133,750 454,898,378

LNG Terminal Project Metrics 100% Load Factor (based on 240 cargos/yr max) Reference Annual throughput, mcf/yr 291,076,745 Annual LNG Offloaded, BCF/yr 291 Reference throughput, million mmBtu/yr 310,578,887 Daily equivalent amount (mcf/day) 808,547 Tax Rates Federal, %/YR 35.0% State, %/YR 4.50% Blended Rate, %/Yr. 37.93% Property, %/YR, initial year/capital cost 0.88% Capital Gain Rate for Terminal Value 20% Depreciation Depreciation (Straight-Line or Accel) Straight-Line Depreciable Life, Years 20 Project Life, Years 20

0.00% based on mmBtu throughput 0

Financial Structure Sr. Debt Percent of Capital Jr. Debt Percent of Capital Equity Percent of Capital Senior Debt Term Junior Debt Term Base Gas Lease Carrying Cost, %/YR

% Capital 50.0% 0.0% 50.0% 20 5 6.75%

FINANCIAL RESULTS Cost of Capital Pretax WACC WACC Equity Return (assumed from above)

10.88% 9.60% 15.0%

Project Economics Project NPV@Pretax WACC, $M Project Pretax IRR NPV @ WACC (tax-effected), $M Project IRR (tax-effected)

218,660 15.7% 142,174 12.5%

Yr. 1 EBITDA $M/year Avg. EBITDA, Yrs 1-5, $M/year

$57,241 $61,059

Equity Returns, AFTER-Tax Equity NPV@ Assumed Equity Return, $M

Equity IRR (calculated) Debt Coverage Minimum EBITDA/Interest Coverage Minimum EBITDA/Debt Service

41,816 17.1% Pre-tax

3.7 2.7

Rate 6.75% 0.0% 15.0%

LNG Terminals Cost Comparison Equipment Summary Sheet Bare Equipment

Traditional Land Based Terminal West Coast w/Breakwater Capacity - 0.8 Bcfd Description

Cost ($M)

LNG STORAGE TANK 2 x (160,000 m3) 6.4 Bcf LNG Storage Tank Subtotal

62,000.0

Steel Concrete I/E & Piping Cost ($M) 27,280.0 27280

Installed Direct & Indirect Cost ($M)

Freight Spares Other Cost ($M)

54,684.0 54684

Taxes Duties Insurance Cost ($M)

1,364.0 1364

Contract Engineering (12%) Cost ($M)

Total Cost Cost ($M)

1639.3 1639.28

9835.7 9835.68

94,803 94,803

PROCESS VESSELS Recondenser, 9'ID x 45', 304 SS BOG Compressor Knock Out Drum 70 m3 HP Fuel Gas Knock Out Drum, 3 m3 HP Flare Knock Out Drum, 50 m3 Service Water Storage Tank, 20 m3 Diesel Storage Tank, 50 m3 Foam Tank, 4 m3 Process Vessels Subtotal

142.0 35.6 10.5 28.8 12.2 16.8 6.5 252.4

85.9 25.5 7.5 20.6 8.1 11.1 4.3 162.9

172.2 51.0 15.0 41.3 16.1 22.2 8.6 326.5

15.7 4.1 1.2 3.3 1.4 1.9 0.7 28.3

8.1 2.3 0.7 1.8 0.7 1.0 0.4 15.0

48.0 13.4 4.0 10.9 4.4 6.0 2.3 89.0

472 132 39 107 43 59 23 874.2

VAPORIZERS Open Rack Vaporizers, 170 ton/hr (3 each) Submerged Combustion Vaporizers, 170 Tons/hr (2 each) Shell & Tube Vaporizers Subtotal

5,940 1,736 0 7,676

4,574 1,337 0 5,911

9,168 2,680 0 11,848

703.9 205.7 0.0 910

397.2 116.1 0.0 513

2361.9 690.3 0.0 3,052

23,145 6,764 0 29,909

HEAT EXCHANGERS Standby glycol/fuel gas heater 127 kW HP knockout drum heater 20 kW Gaseous N2 Vaporizer 35 kW Gaseous N2 Vaporizer (Spare) 35 kW Liquid N2 Pressurization vaporizer 35 kW Liquid N2 Vaporizer 35 kW Heat Exchangers Subtotal

6.1 0.8 0.66 0.66 0.66 0.66 9.5

4.03 0.53 0.74 0.74 0.74 0.74 7.5

8.07 1.06 1.48 1.48 1.48 1.48 15.0

0.7 0.1 0.1 0.1 0.1 0.1 1.1

0.4 0.0 0.1 0.1 0.1 0.1 0.6

2.2 0.3 0.3 0.3 0.3 0.3 3.8

21 3 3 3 3 3 37.7

0

0

0

0

0

0

0

Pumps Subtotal

$640 $825 $452 15.00 7.10 17.40 203.70 2,160.20

668.8 862.1 472.3 21.5 10.2 24.9 213 2,273

1340.6 1728.2 946.8 43.0 20.4 49.9 426.7 4,556

84.6 109.1 59.8 2.3 1.1 2.6 26.9 286

53.4 68.8 37.7 1.6 0.8 1.9 17.0 181

317.9 409.8 224.5 9.5 4.5 11.1 101.2 1,079

3,105 4,003 2,193 93 44 108 988 10,534

Compressors Subtotal

800.00 1,000.00 2,200.00 4,000.00

440 550 1155 2,145

882 1102.5 2315.3 4,300

86.0 107.5 233.8 427

42.9 53.7 114.7 211

254.6 318.3 680.4 1,253

2,506 3,132 6,699 12,337

SEAWATER INTAKE SYSTEM (Incl Electrochlorination) Electrochlorination Unit, 12,000 m3/hr Seawater Intake Structure (12,000 m3/hr each) Seawater Outfall Structure (12,000 m3/hr each) Seawater Intake Screens (13,200 m3/hr each) Seawater Rotary Screens (13,200 m3/hr each) Seawater Intake System Subtotal

20 1,100 1,100 400 400 3,020

29 1150 1755 858 1078 4,869

57.33 2304 3517 1720 882 8,480

3.0 145.5 175.7 74.9 85.9 485

2.1 91.7 128.1 59.8 47.4 329

12.7 546.4 764.6 357.3 283.2 1,964

124 5,337 7,440 3,470 2,777 19,148

507

84 2,850 63.3 990.0 165.1 60.1 198.0 4,410.5

167.6 126.8 1,984.5 331.0 120.4 396.9 3,127.1

44.7 142.5 21.6 409.5 32.2 9.2 33.9 693.7

15.5 57.0 8.5 152.2 16.1 5.2 18.1 272.6

90.9 342.1 50.4 896.9 95.5 31.0 107.4 1,614.2

909 3,392 501 8,933 940 304 1,054 16,032.5

0 0 0 0 0

450.0 0.0 1,200.0 0.0 1650

180.0 341.0 480.0 0.0 1001

1080.0 2046.0 2880.0 0.0 6006

10,710 19,437 28,560 0 58707

WASTE HEAT RECOVERY Waste Heat Recovery Subtotal PUMPS First stage sendout pump, 416 m3/hr (intank) Second stage sendout pump, 325 m3/hr Seawater pump, 2187 m3/hr Sub combustion Vap. Overflow pump, 5hp Process Area Sump Pump, 10 hp, 5 m3/hr Service Water Pump, 5 hp, 57 m3/hr Firewater Pumps

COMPRESSORS BOG Compressors Ship Vapor Return Blower Ship Unloading Compressor

UTILITIES HP Flare, 415,000 kg/hr Electrical Switchgear & Power Distrib (5% of FC) Emergency Generator - Diesel Driven, 500 kW Gas Turbine Generator, 4 MW, Centaur 50 Instrument air compressor and drier, 100 scfm N2 Dewar for Terminal, Vac. insul. tank, 42 m3 Firewater Protection System (Foam Sys, dry powder, tanks) Utilities Subtotal MARINE FACILITIES - JETTY Topworks (Road/750 meter Trestle/Pipeway) Cryogenic Piping (I/E, piping w/ insulation) Berth (Mooring, Breasting Dolphins) Dredging Marine Facilities - Jetty Subtotal

230.0 4,500.0 299.8 78.0 300.0 5,914.4

9,000 17,050 24,000 50,050

MARINE FACILITIES - UNLOADING Unloading Arms Marine Facilities - Unloading Subtotal BREAKWATER Breakwater Subtotal

8,650 8,650

963 963

1930.6 1,931

0 0

60,000 60,000

0 0

740.2 740

236.1 236

1385.2 1,385

13,905 13,905

3,000 3,000

1,200 1,200

7,200 7,200

71,400 71,400

70.0 17.5 26.3 113.75

28.0 7.0 10.5 45.5

168.0 42.0 63.0 273

1,666 417 625 2707.25

2,850 2,850

142.5 143

57.0 57

342.1 342

3,392 3,392

12,000 0 $7,981 9000 28,981

600.0 0.0 399.1 450.0 1,449

240.0 0.0 159.6 180.0 580

1440.0 0.0 957.8 1080.0 3,478

14,280 0 9,498 10,710 34,488

NAVIGATIONAL AIDS (lighting and buoys) Navigational Aids Subtotal BUILDINGS Administration Office/Control Center Compressor Building (Included in cost of compressors) Warehouse/Maintenance Building, 10,000 ft2 Buildings Subtotal

1400 350 525 2275

SITE PREPARATION Site Preparation Subtotal BULKS Piping (exclud. trestle) Piling Insulation and Paint Electrical/Instrumentation Bulks Subtotal

3,000 3,000

REAL ESTATE Real Estate Subtotal OSBL INFRASTRUCTURE Includes access roads, bldgs, hospitals, stores, bridges OSBL Infrastructure Subtotal UNADJUSTED GRAND TOTAL CONTINGENCY 12% OF THE TOTAL ADJUSTED GRAND TOTAL

3,000 3,000

0 62,683

195,177

0 89,267

11,291

6,282

37,575

371,275 44,553 415,827

ATLANTIC COAST LNG TERMINAL PROFORMA ECONOMICS Project Summary SUMMARY FACILITY ASSUMPTIONS Facility Basis - Firm Service Cargos per Year LNG Discharge per Ship, cubic meters LNG LNG Btu content, Btu/scf Storage Working Gas Volume, Bcf Storage Base Gas Volume, Bcf

Pricing Throughput Fee, $/MmBtu Other Revenue - % of Terminal Throughput Rev. Terminal Energy Use Charge, % of throughput Assumed Henry Hub Index for initial year Gas Storage Net Revenue Realized $MM/year Other Assumptions Base Gas Price (Delivered), $/Mcf Base Gas Source ("Lease" or "Buy") Total Operations Cost, $M/Year - Labor & Maintenance, $M/Yr - Electrical Demand Charge, $M/Yr Management Overhead, $M/Year Property Taxes (assumed amount), $M/Yr Storage Site Lease Fee, $M/yr % Revenue Stream to Inflation Protect, %/yr General Inflation Rate Inflation applied to certain annual costs, %/yr Energy Use for Terminal ops., % of throughput Full storage cavern compression charge rate % of throughput requiring compression at cavern Project & Technology Rights Running Royalty, as % of Henry Hub index Project & License Upfront Payment, $MM

67 138,000 1067 16.00 7.30

0.220 0.0% 0.00% $3.50 $0.0

3.50 buy 2,499 2,299 200 360 4,000 500 100% 3.0% 1.5% 0.85% 0.00% 0%

Facility Costs, $ Marine Port Facilities LNG Vaporization & Process Terminal Utility System Storage Surface Facility Site Specific Misc Header Pipeline Engineering & Const. Mgmt. Project Acquisition & Tech. Rights Owner Costs, Permits, Misc. Financing Fees Contingency Total Facility Cost

FINANCIAL ASSUMPTIONS 50,910,255 48,250,000 28,288,700 57,000,000 1,116,097 0 11,634,948 50,000 7,191,583 11,133,903 30,142,500 245,717,986

LNG Terminal Project Metrics 100% Load Factor (based on 240 cargos/yr max) Reference Annual throughput, mcf/yr 182,263,008 Annual LNG Offloaded, BCF/yr 182 Reference throughput, million mmBtu/yr 194,474,630 Daily equivalent amount (mcf/day) 506,286 Tax Rates Federal, %/YR 35.0% State, %/YR 4.50% Blended Rate, %/Yr. 37.93% Property, %/YR, initial year/capital cost 1.63% Capital Gain Rate for Terminal Value 20% Depreciation Depreciation (Straight-Line or Accel) Straight-Line Depreciable Life, Years 20 Project Life, Years 20

0.00% based on mmBtu throughput 0

Financial Structure Sr. Debt Percent of Capital Jr. Debt Percent of Capital Equity Percent of Capital Senior Debt Term Junior Debt Term Base Gas Lease Carrying Cost, %/YR

% Capital 50.0% 0.0% 50.0% 20 5 6.75%

FINANCIAL RESULTS Cost of Capital Pretax WACC WACC Equity Return (assumed from above)

10.88% 9.60% 15.0%

Project Economics Project NPV@Pretax WACC, $M Project Pretax IRR NPV @ WACC (tax-effected), $M Project IRR (tax-effected)

108,531 15.3% 69,959 12.2%

Yr. 1 EBITDA $M/year Avg. EBITDA, Yrs 1-5, $M/year

$29,640 $31,751

Equity Returns, AFTER-Tax Equity NPV@ Assumed Equity Return, $M

Equity IRR (calculated) Debt Coverage Minimum EBITDA/Interest Coverage Minimum EBITDA/Debt Service

17,846 16.7% Pre-tax

3.6 2.6

Rate 6.75% 0.0% 15.0%

LNG Terminals Cost Comparison Equipment Summary Sheet Bare Equipment

Traditional Land Based Terminal East Coast no Breakwater reqd. Capacity - 0.5 Bcfd Description

Cost ($M)

LNG STORAGE TANK 2 x (125,000 m3) 5.0 Bcf LNG Storage Tank Subtotal

45,000.0

Steel Concrete I/E & Piping Cost ($M)

Installed Direct & Indirect Cost ($M)

19,800.0 19800

Freight Spares Other Cost ($M)

22,500.0 22500

Taxes Duties Insurance Cost ($M)

Contract Engineering (12%) Cost ($M)

Total Cost Cost ($M)

990.0 990

846.0 846

5076.0 5076

49,212 49,212

PROCESS VESSELS Recondenser, 9'ID x 45', 304 SS BOG Compressor Knock Out Drum 70 m3 HP Fuel Gas Knock Out Drum, 3 m3 HP Flare Knock Out Drum, 50 m3 Service Water Storage Tank, 20 m3 Diesel Storage Tank, 50 m3 Foam Tank, 4 m3 Process Vessels Subtotal

142.0 35.6 10.5 28.8 12.2 16.8 6.5 252.4

85.9 25.5 7.5 20.6 8.1 11.1 4.3 162.9

172.2 51.0 15.0 41.3 16.1 22.2 8.6 326.5

15.7 4.1 1.2 3.3 1.4 1.9 0.7 28.3

8.1 2.3 0.7 1.8 0.7 1.0 0.4 15.0

48.0 13.4 4.0 10.9 4.4 6.0 2.3 89.0

472 132 39 107 43 59 23 874.2

VAPORIZERS Open Rack Vaporizers, 168 ton/hr (3 each) Submerged Combustion Vaporizers, 170 ton/hr (1 each) Shell & Tube Vaporizers Subtotal

0.0 898.0 1,100.0 1,998

0.0 691.5 847.0 1,538

0.0 1,386.1 1,697.9 3,084

0.0 106.4 130.4 237

0.0 60.0 73.6 134

0.0 357.1 437.4 794

0 3,499 4,286 7,785

HEAT EXCHANGERS Standby glycol/fuel gas heater 127 kW HP knockout drum heater 20 kW Gaseous N2 Vaporizer 35 kW Gaseous N2 Vaporizer (Spare) 35 kW Liquid N2 Pressurization vaporizer 35 kW Liquid N2 Vaporizer 35 kW Heat Exchangers Subtotal

$6 $1 $1 $1 $1 $1 9.5

4.03 0.53 0.74 0.74 0.74 0.74 7.5

8.07 1.06 1.48 1.48 1.48 1.48 15.0

0.7 0.1 0.1 0.1 0.1 0.1 1.1

0.4 0.0 0.1 0.1 0.1 0.1 0.6

2.2 0.3 0.3 0.3 0.3 0.3 3.8

21 3 3 3 3 3 37.7

0

0

0

0

0

0

0

Pumps Subtotal

$640 $825 $452 $15 $7 $17 203.70 2,160.20

668.8 862.1 472.3 21.5 10.2 24.9 213 2,273

1340.6 1728.2 946.8 43.0 20.4 49.9 426.7 4,556

84.6 109.1 59.8 2.3 1.1 2.6 26.9 286

53.4 68.8 37.7 1.6 0.8 1.9 17.0 181

317.9 409.8 224.5 9.5 4.5 11.1 101.2 1,079

3,105 4,003 2,193 93 44 108 988 10,534

Compressors Subtotal

800.00 1,000.00 2,200.00 4,000.00

440 550 440 1,430

882 1102.5 2315.3 4,300

86.0 107.5 198.0 392

42.9 53.7 100.4 197

254.6 318.3 594.6 1,168

2,506 3,132 5,848 11,486

SEAWATER INTAKE SYSTEM (Incl Electrochlorination) Electrochlorination Unit, 12,000 m3/hr Seawater Intake Structure (12,000 m3/hr each) Seawater Outfall Structure (12,000 m3/hr each) Seawater Intake Screens (13,200 m3/hr each) Seawater Rotary Screens (13,200 m3/hr each) Seawater Intake System Subtotal

20 1,100 1,100 500 500 3,220

29 1150 1755 1073 1348 5,353

57.33 2304 3517 2150 2701 10,730

3.0 145.5 175.7 93.6 107.4 525

2.1 91.7 128.1 74.7 91.3 388

12.7 546.4 764.6 446.7 545.8 2,316

124 5,337 7,440 4,337 5,293 22,532

506.6

83.6 1,908.1 63.3 0.0 165.1 60.1 165.1 2,445.2

167.6 126.8 0.0 331.0 120.4 331.0 1,076.7

44.7 95.4 21.6 0.0 32.2 9.2 32.3 235.4

15.5 38.2 8.5 0.0 16.1 5.2 16.1 99.6

90.9 229.0 50.4 0.0 95.5 31.0 95.5 592.4

908.8 2,270.6 500.5 0.0 939.7 303.9 940.0 5,863.6

9,000.0 1,915.0 17,000.0 0.0 27,915.0

0.0 0.0 0.0 0.0 0.0

450.0 95.8 850.0 0.0 1,395.8

180.0 38.3 340.0 0.0 558.3

1,080.0 229.8 2,040.0 0.0 3,349.8

10,710.0 2,278.9 20,230.0 0.0 33,218.9

WASTE HEAT RECOVERY Waste Heat Recovery Subtotal PUMPS First stage sendout pump, 416 m3/hr (intank) Second stage sendout pump, 325 m3/hr Seawater pump, 2187 m3/hr Sub combustion Vap. Overflow pump, 5hp Process Area Sump Pump, 10 hp, 5 m3/hr Service Water Pump, 5 hp, 57 m3/hr Firewater Pumps

COMPRESSORS BOG Compressors Ship Vapor Return Blower Ship Unloading Compressor

UTILITIES HP Flare, 415,000 kg/hr Electrical Switchgear & Power Distrib (5% of FC) Emergency Generator - Diesel Driven, 500 kW Gas Turbine Generator Instrument air compressor and drier, 100 scfm N2 Dewar for Terminal, Vac. insul. tank, 42 m3 Firewater Protection System (Foam Sys, dry powder, tanks) Utilities Subtotal MARINE FACILITIES - JETTY Topworks (Road/150 meter Trestle/Pipeway) Cryogenic Piping (I/E, piping w/ insulation) Berth (Mooring, Breasting Dolphins) Dredging Marine Facilities - Jetty Subtotal

230.0 0.0 299.8 78.0 300.0 1,414.4

MARINE FACILITIES - UNLOADING Unloading Arms Marine Facilities - Unloading Subtotal

0.0 0.0

0.0 0.0

1,470.0 1,470.0

0.0 0.0

29.4 29.4

176.4 176.4

1,675.8 1,675.8

0.0 0.0

0.0 0.0

0.0 0.0

0.0 0.0

0.0 0.0

0.0 0.0

0.0 0.0

1,400.0 350.0 525.0 2,275.0

70.0 17.5 26.3 113.8

28.0 7.0 10.5 45.5

168.0 42.0 63.0 273.0

1,666.0 416.5 624.8 2,707.3

Site Preparation Subtotal

2,850.5 2,850.5

142.5 142.5

57.0 57.0

342.1 342.1

3,392.0 3,392.0

Bulks Subtotal

12,000.0 0.0 5,342.7 9,000.0 26,342.7

600.0 0.0 267.1 450.0 1,317.1

240.0 0.0 106.9 180.0 526.9

1,440.0 0.0 641.1 1,080.0 3,161.1

14,280.0 0.0 6,357.8 10,710.0 31,347.8

Real Estate Subtotal

500.0 500.0

500.0 500.0

OSBL INFRASTRUCTURE Includes access roads, bldgs, hospitals, stores, bridges OSBL Infrastructure Subtotal

0.0

0.0

BREAKWATER Breakwater Subtotal NAVIGATIONAL AIDS (lighting and buoys) Navigational Aids Subtotal BUILDINGS Administration Office/Control Center Compressor Building (Included in cost of compressors) Warehouse/Maintenance Building, 10,000 ft2 Buildings Subtotal SITE PREPARATION

BULKS Piping (exclud. trestle) Piling Insulation and Paint Electrical/Instrumentation

REAL ESTATE

UNADJUSTED GRAND TOTAL CONTINGENCY 12% OF THE TOTAL ADJUSTED GRAND TOTAL

35,555

92,892

48,057

5,664

3,078

18,420

181,166 21,740 202,906

LNG ONSHORE TERMINAL WITH CAVERN STORAGE PROFORMA ECONOMICS Project Summary SUMMARY FACILITY ASSUMPTIONS Facility Basis - Firm Service Cargos per Year LNG Discharge per Ship, cubic meters LNG LNG Btu content, Btu/scf Storage Working Gas Volume, Bcf Storage Base Gas Volume, Bcf

Pricing Throughput Fee, $/MmBtu Other Revenue - % of Terminal Throughput Rev. Terminal Energy Use Charge, % of throughput Assumed Henry Hub Index for initial year Gas Storage Net Revenue Realized $MM/year Other Assumptions Base Gas Price (Delivered), $/Mcf Base Gas Source ("Lease" or "Buy") Total Operations Cost, $M/Year - Labor & Maintenance, $M/Yr - Electrical Demand Charge, $M/Yr Management Overhead, $M/Year Property Taxes (assumed amount), $M/Yr Storage Site Lease Fee, $M/yr % Revenue Stream to Inflation Protect, %/yr General Inflation Rate Inflation applied to certain annual costs, %/yr Energy Use for Terminal ops., % of throughput Full storage cavern compression charge rate % of throughput requiring compression at cavern Project & Technology Rights Running Royalty, as % of Henry Hub index Project & License Upfront Payment, $MM

235 138,000 1067 16.00 7.30

0.090 0.0% 0.00% $3.50 $0.0

3.50 lease 4,832 4,632 200 360 4,000 500 100% 3.0% 1.5% 0.35% 0.00% 0%

Facility Costs, $ Marine Port Facilities LNG Process & HP PIpeline Terminal Utility System Storage Surface Facility Site Specific Misc Header Pipeline Engineering & Const. Mgmt. Project Acquisition & Tech. Rights Owner Costs, Permits, Misc. Financing Fees Contingency Total Facility Cost

FINANCIAL ASSUMPTIONS 47,118,345 51,374,800 28,288,700 108,000,000 17,788,105 0 18,630,050 50,000 7,385,958 15,154,197 41,242,500 335,032,655

LNG Terminal Project Metrics 98% Load Factor (based on 240 cargos/yr max) Reference Annual throughput, mcf/yr 639,280,701 Annual LNG Offloaded, BCF/yr 639 Reference throughput, million mmBtu/yr 682,112,508 Daily equivalent amount (mcf/day) 1,775,780 Tax Rates Federal, %/YR 35.0% State, %/YR 4.50% Blended Rate, %/Yr. 37.93% Property, %/YR, initial year/capital cost 1.19% Capital Gain Rate for Terminal Value 20% Depreciation Depreciation (Straight-Line or Accel) Straight-Line Depreciable Life, Years 20 Project Life, Years 20

0.00% based on mmBtu throughput 0

Financial Structure Sr. Debt Percent of Capital Jr. Debt Percent of Capital Equity Percent of Capital Senior Debt Term Junior Debt Term Base Gas Lease Carrying Cost, %/YR

% Capital 50.0% 0.0% 50.0% 20 5 6.75%

FINANCIAL RESULTS Cost of Capital Pretax WACC WACC Equity Return (assumed from above)

10.88% 9.60% 15.0%

Project Economics Project NPV@Pretax WACC, $M Project Pretax IRR NPV @ WACC (tax-effected), $M Project IRR (tax-effected)

162,142 15.7% 106,352 12.5%

Yr. 1 EBITDA $M/year Avg. EBITDA, Yrs 1-5, $M/year

$41,618 $44,576

Equity Returns, AFTER-Tax Equity NPV@ Assumed Equity Return, $M

Equity IRR (calculated) Debt Coverage Minimum EBITDA/Interest Coverage Minimum EBITDA/Debt Service

31,006 17.1% Pre-tax

3.7 2.7

Rate 6.75% 0.0% 15.0%

LNG Terminals Cost Comparison Equipment Summary Sheet LNG On-shore Terminal with Salt Cavern Storage Bishop Process

Bare Equipment

Average capacity 1.75 Bcfd

Cost ($M)

Description

GLNG Storage Caverns: 6 ea x 2 BCF = 12 BCF (608,000 m3)

Process Vessels Subtotal VAPORIZERS Open Rack Vaporizers, 168 ton/hr Submerged Combustion Vaporizers, 168 ton/hr Bishop Process Vaporizers Subtotal HEAT EXCHANGERS Standby glycol/fuel gas heater 127 kW HP knockout drum heater 20 kW Gaseous N2 Vaporizer 35 kW Gaseous N2 Vaporizer (Spare) 35 kW Liquid N2 Pressurization vaporizer 35 kW Liquid N2 Vaporizer 35 kW

Installed Direct & Indirect Cost ($M)

Freight Spares Other Cost ($M)

Taxes Duties Insurance Cost ($M)

60,000 60,000

-

3,000 3,000

142.0 35.6 10.5 28.8 12.2 16.8 3.3 249.2

85.9 25.5 7.5 20.6 8.1 11.1 2.1 160.7

172.2 51.0 15.0 41.3 16.1 22.2 4.3 322.2

15.7 4.1 1.2 3.3 1.4 1.9 0.4 28.0

0 0 6,020 6,020

0 0 3,973 3,973

0 0 7,964 7,964

0.0 0.0 680.3 680

Salt Cavern Storage 2 each at 15 BCF total 30 BCF PROCESS VESSELS Recondenser, 9'ID x 45', 304 SS BOG Compressor Knock Out Drum 70 m3 HP Fuel Gas Knock Out Drum, 3 m3 HP Flare Knock Out Drum, 50 m3 Service Water Storage Tank, 20 m3 Diesel Storage Tank, 50 m3 Foam Tank, 4 m3

Steel Concrete I/E & Piping Cost ($M)

Contract Engineering (12%) Cost ($M)

1,200 1,200

Total Cost Cost ($M)

3,600 3,600

67,800 67,800

8.1 2.3 0.7 1.8 0.7 1.0 0.2 14.8

48 13 4 11 4 6 1 87.9

472 132 39 107 43 59 11 862.7

0.0 0.0 362.8 363

1,077.5 1,077

0 0 20,078 20,078

Heat Exchangers Subtotal

6.1 0.8 0.66 0.66 0.66 0.66 9.5

4.03 0.53 0.74 0.74 0.74 0.74 7.5

8.1 1.1 1.5 1.5 1.5 1.5 15.0

0.7 0.1 0.1 0.1 0.1 0.1 1.1

0.4 0.0 0.1 0.1 0.1 0.1 0.6

2.2 0.3 0.3 0.3 0.3 0.3 3.8

21 3 3 3 3 3 37.7

Waste Heat Recovery Subtotal

0

0

0

0

0

0

0

Pumps Subtotal

0.0 225.0 2,100.0 0.0 0.0 3.6 203.7 2,532.3

0.0 5386.5 2194.5 0.0 0.0 0.0 213 7,794

0.0 1583.6 527.9 0.0 0.0 17.4 426.7 2,556

0.0 287.3 277.7 0.0 0.0 0.3 26.9 592

0.0 144.0 97.7 0.0 0.0 0.4 17.0 259

0.0 431.7 289.3 0.0 0.0 2.5 101.2 825

0 8,058 5,487 0 0 24 988 14,558

Compressors Subtotal

800.0 1,000.0 0.0 1,800.0

264 330 0 594

529.2 661.5 0.0 1,191

77.2 96.5 0.0 174

32.3 40.4 0.0 73

191.2 239.0 0.0 430

1,894 2,367 0 4,261

SEAWATER INTAKE SYSTEM (Incl Electrochlorination) Electrochlorination Unit, 12,000 m3/hr Seawater Intake Structure (12,000 m3/hr each) Seawater Outfall Structure (12,000 m3/hr each) Seawater Intake Screens (13,200 m3/hr each) Seawater Rotary Screens (13,200 m3/hr each) Seawater Intake System Subtotal

20 1,100 1,100 500 500 3,220

29 1150 1755 1073 1348 5,353

57.33 2304 3517 2150 2701 57.33

3.0 145.5 175.7 93.6 107.4 525

2.1 91.7 128.1 74.7 91.3 388

12.7 546.4 764.6 446.7 545.8 2,316

124 5,337 7,440 4,337 5,293 22,532

507

84 3,618 63.3 2,420.0 82.4 60.1 198.0 6,525.1

167.6 126.8 4,851.0 165.3 120.4 396.9 5,827.9

44.7 180.9 21.6 1,001.0 28.1 9.2 33.9 1,319.4

15.5 72.4 8.5 372.0 11.1 5.2 18.1 502.8

90.9 434.1 50.4 2192.5 65.7 31.0 107.4 2,972.1

909 4,305 501 21,837 652 304 1,054 29,561.7

4,500.0 17,000.0 0.0 1,400.0 22,900.0

0.0 0.0 0.0 0.0 0.0

225.0 850.0 0.0 70.0 1,145.0

90.0 340.0 0.0 28.0 458.0

540.0 2,040.0 0.0 168.0 2,748.0

5,355.0 20,230.0 0.0 1,666.0 27,251.0

WASTE HEAT RECOVERY

PUMPS First stage sendout pump, 416 m3/hr (intank) Second stage sendout pump, 28 each @270 m3/hr Seawater pump, 3160 m3/hr Sub combustion Vap. Overflow pump, 5hp Process Area Sump Pump, 10 hp, 5 m3/hr Service Water Pump, 5 hp, 57 m3/hr Firewater Pumps

COMPRESSORS BOG Compressors Ship Vapor Return Unit w/Blower Ship Unloading Compressor

UTILITIES HP Flare, 415,000 kg/hr Electrical Switchgear & Power Distrib (5% of FC) Emergency Generator - Diesel Driven, 500 kW Gas Turbine Generator, 22MW, GE LM2500 (back-up) Instrument air compressor and drier, 100 scfm N2 Dewar for Terminal, Vac. insul. tank, 42 m3 Firewater Protection System (Foam Sys, dry powder, tanks) Utilities Subtotal

MARINE FACILITY - TRADITIONAL WHARF Platform and topworks Berth, walkways and dolphins Dredging Marine Facilities - Jetty Subtotal

230.0 11,000.0 299.8 78.0 300.0 12,414.4

UNLOADING ARMS Arms: Unloading and Vapor Return Marine Facilities - Unloading Subtotal

1,960.0 1,960.0

788.0 788.0

1,930.6 1,930.6

196.2 196.2

94.7 94.7

561.4 561.4

22,500 22,500

Piepline to Caverns 15 miles @ 1.5 mmUSD/mile Pipeline Subtotal

5,531.0 5,531.0 22,500 22,500

NAVIGATIONAL AIDS (lighting and buoys) Navigational Aids Subtotal BUILDINGS Administration Office/Control Center Compressor Building (Included in cost of compressors) Warehouse/Maintenance Building, 10,000 ft2 Buildings Subtotal

850 200 525 1,575

SITE PREPARATION Site Preparation Subtotal BULKS Piping (exclud. trestle) Piling Insulation and Paint Electrical/Instrumentation Bulks Subtotal

Real Estate Subtotal OSBL INFRASTRUCTURE Includes access roads, bldgs, hospitals, stores, bridges OSBL Infrastructure Subtotal

CONTINGENCY 12% OF THE TOTAL ADJUSTED GRAND TOTAL

17.0 4.0 10.5 31.5

102.0 24.0 63.0 189

1,012 238 625 1874.25

2,171 2,171

108.5 109

43.4 43

260.5 260

2,583 2,583

19,853 0 9264.8 9000 38,118

992.7 0.0 463.2 450.0 1,906

397.1 0.0 185.3 180.0 762

2382.4 0.0 1111.8 1080.0 4,574

23,625 0 11,025 10,710 45,360

750 750

REAL ESTATE

UNADJUSTED GRAND TOTAL

42.5 10.0 26.3 78.75

750 750

0 28,205

173,209

0 25,200

9,754

4,191

19,645

265,541 31,865 297,406

LNG OFFSHORE TERMINAL WITH CAVERN STORAGE PROFORMA ECONOMICS Project Summary SUMMARY FACILITY ASSUMPTIONS Facility Basis - Firm Service Cargos per Year LNG Discharge per Ship, cubic meters LNG LNG Btu content, Btu/scf Storage Working Gas Volume, Bcf Storage Base Gas Volume, Bcf

Pricing Throughput Fee, $/MmBtu Other Revenue - % of Terminal Throughput Rev. Terminal Energy Use Charge, % of throughput Assumed Henry Hub Index for initial year Gas Storage Net Revenue Realized $MM/year Other Assumptions Base Gas Price (Delivered), $/Mcf Base Gas Source ("Lease" or "Buy") Total Operations Cost, $M/Year - Labor & Maintenance, $M/Yr - Electrical Demand Charge, $M/Yr Management Overhead, $M/Year Property Taxes (assumed amount), $M/Yr Storage Site Lease Fee, $M/yr % Revenue Stream to Inflation Protect, %/yr General Inflation Rate Inflation applied to certain annual costs, %/yr Energy Use for Terminal ops., % of throughput Full storage cavern compression charge rate % of throughput requiring compression at cavern Project & Technology Rights Running Royalty, as % of Henry Hub index Project & License Upfront Payment, $MM

235 138,000 1067 16.00 7.30

0.095 0.0% 0.00% $3.50 $0.0

3.50 lease 8,039 7,839 200 360 4,000 500 100% 3.0% 1.5% 0.35% 0.00% 0%

Facility Costs, $ Marine Port Facilities LNG Process & HP Pipeline Terminal Utility System Storage Surface Facility Site Specific Misc Header Pipeline Engineering & Const. Mgmt. Project Acquisition & Tech. Rights Owner Costs, Permits, Misc. Financing Fees Contingency Total Facility Cost

FINANCIAL ASSUMPTIONS 127,722,695 51,374,800 28,288,700 55,900,000 -10,670,245 0 15,733,050 50,000 7,653,250 15,156,957 40,814,850 332,024,057

LNG Terminal Project Metrics 98% Load Factor (based on 240 cargos/yr max) Reference Annual throughput, mcf/yr 639,280,701 Annual LNG Offloaded, BCF/yr 639 Reference throughput, million mmBtu/yr 682,112,508 Daily equivalent amount (mcf/day) 1,775,780 Tax Rates Federal, %/YR 35.0% State, %/YR 4.50% Blended Rate, %/Yr. 37.93% Property, %/YR, initial year/capital cost 1.20% Capital Gain Rate for Terminal Value 20% Depreciation Depreciation (Straight-Line or Accel) Straight-Line Depreciable Life, Years 20 Project Life, Years 20

0.00% based on mmBtu throughput 0

Financial Structure Sr. Debt Percent of Capital Jr. Debt Percent of Capital Equity Percent of Capital Senior Debt Term Junior Debt Term Base Gas Lease Carrying Cost, %/YR

% Capital 50.0% 0.0% 50.0% 20 5 6.75%

FINANCIAL RESULTS Cost of Capital Pretax WACC WACC Equity Return (assumed from above)

10.88% 9.60% 15.0%

Project Economics Project NPV@Pretax WACC, $M Project Pretax IRR NPV @ WACC (tax-effected), $M Project IRR (tax-effected)

167,500 15.9% 110,676 12.7%

Yr. 1 EBITDA $M/year Avg. EBITDA, Yrs 1-5, $M/year

$41,821 $44,792

Equity Returns, AFTER-Tax Equity NPV@ Assumed Equity Return, $M

Equity IRR (calculated) Debt Coverage Minimum EBITDA/Interest Coverage Minimum EBITDA/Debt Service

33,937 17.4% Pre-tax

3.7 2.7

Rate 6.75% 0.0% 15.0%

LNG Terminals Cost Comparison Equipment Summary Sheet LNG Offshore Terminal with Salt Cavern Storage Bishop Process Average capacity 1.75 Bcfd

Bare Equipment Cost ($M)

Description

Salt Storage Caverns: 6 x 3.5 BCF = 21 BCF (1,065,000 m3) Salt Cavern Storage 6 each at 3.5 Bcf total 21 bcf

Steel Concrete I/E & Piping Cost ($M)

Installed Direct & Indirect Cost ($M)

Freight Spares Other Cost ($M)

Taxes Duties Insurance Cost ($M)

20,000 20,000

30,000 30,000

1,000 1,000

Contract Engineering (12%) Cost ($M)

1,000 1,000

Total Cost Cost ($M)

6,000 6,000

58,000 58,000

PROCESS VESSELS Recondenser, 9'ID x 45', 304 SS BOG Compressor Knock Out Drum 70 m3 HP Fuel Gas Knock Out Drum, 3 m3 HP Flare Knock Out Drum, 50 m3 Service Water Storage Tank, 20 m3 Diesel Storage Tank, 50 m3 Foam Tank, 4 m3 Process Vessels Subtotal

142.0 35.6 10.5 28.8 12.2 16.8 3.3 249.2

85.9 25.5 7.5 20.6 8.1 11.1 2.1 160.7

172.2 51.0 15.0 41.3 16.1 22.2 4.3 322.2

15.7 4.1 1.2 3.3 1.4 1.9 0.4 28.0

8.1 2.3 0.7 1.8 0.7 1.0 0.2 14.8

48 13 4 11 4 6 1 87.9

472 132 39 107 43 59 11 862.7

VAPORIZERS Open Rack Vaporizers, 168 ton/hr Submerged Combustion Vaporizers, 168 ton/hr Bishop Process Vaporizers Subtotal

0 0 6,020 6,020

0 0 3,973 3,973

0 0 7,964 7,964

0.0 0.0 680.3 680

0.0 0.0 362.8 363

1,077.5 1,077

0 0 20,078 20,078

HEAT EXCHANGERS Standby glycol/fuel gas heater 127 kW HP knockout drum heater 20 kW Gaseous N2 Vaporizer 35 kW Gaseous N2 Vaporizer (Spare) 35 kW Liquid N2 Pressurization vaporizer 35 kW Liquid N2 Vaporizer 35 kW Heat Exchangers Subtotal

6.1 0.8 0.66 0.66 0.66 0.66 9.5

4.03 0.53 0.74 0.74 0.74 0.74 7.5

8.1 1.1 1.5 1.5 1.5 1.5 15.0

0.7 0.1 0.1 0.1 0.1 0.1 1.1

0.4 0.0 0.1 0.1 0.1 0.1 0.6

2.2 0.3 0.3 0.3 0.3 0.3 3.8

21 3 3 3 3 3 37.7

0

0

0

0

0

0

0

Pumps Subtotal

0.0 6,300.0 2,100.0 0.0 0.0 17.4 192.5 8,609.9

0.0 6583.5 2194.5 0.0 0.0 24.9 201 9,004

0.0 13196.9 4399.0 0.0 0.0 49.9 403.2 18,049

0.0 833.2 277.7 0.0 0.0 2.6 25.5 1,139

0.0 525.4 175.1 0.0 0.0 1.9 16.1 718

0.0 1564.8 1043.2 0.0 0.0 11.1 95.6 2,715

0 29,004 10,190 0 0 108 934 40,235

Compressors Subtotal

800.0 1,000.0 0.0 1,800.0

264 330 0 594

529.2 661.5 0.0 1,191

77.2 96.5 0.0 174

32.3 40.4 0.0 73

191.2 239.0 0.0 430

1,894 2,367 0 4,261

SEAWATER INTAKE SYSTEM (Incl Electrochlorination) Electrochlorination Unit, 12,000 m3/hr Seawater Intake Structure (12,000 m3/hr each) Seawater Outfall Structure (12,000 m3/hr each) Seawater Intake Screens (13,200 m3/hr each) Seawater Rotary Screens (13,200 m3/hr each) Seawater Intake System Subtotal

20 0 0 250 250 520

29 0 0 69 69 166

57.33 0 0 56 56 170

3.0 0.0 0.0 23.4 23.4 50

2.1 0.0 0.0 7.7 7.7 17

6.4 0.0 0.0 22.5 22.5 51

117 0 0 429 429 975

507

84 3,001 31.6 2,420.0 82.4 60.1 198.0 5,876.7

167.6 63.4 4,851.0 165.3 120.4 396.9 5,764.5

44.7 150.0 10.8 1,001.0 28.1 9.2 33.9 1,277.8

15.5 60.0 4.3 372.0 11.1 5.2 18.1 486.2

90.9 360.1 25.2 2192.5 65.7 31.0 107.4 2,872.9

909 3,571 250 21,837 652 304 1,054 28,577.5

50,000.0 6,480.0 5,000.0 0.0 61,480.0

0.0 0.0 0.0 0.0 0.0

2,500.0 324.0 250.0 0.0 3,074.0

1,000.0 129.6 100.0 0.0 1,229.6

6,000.0 777.6 600.0 0.0 7,377.6

59,500.0 7,711.2 5,950.0 0.0 73,161.2

WASTE HEAT RECOVERY Waste Heat Recovery Subtotal PUMPS First stage sendout pump, 416 m3/hr (intank) Second stage sendout pump, 28 ea @ 270 m3/hr Seawater pump, 3160 m3/hr Sub combustion Vap. Overflow pump, 5hp Process Area Sump Pump, 10 hp, 5 m3/hr Service Water Pump, 5 hp, 57 m3/hr Firewater Pumps

COMPRESSORS BOG Compressors Ship Vapor Return Unit w/Blower Ship Unloading Compressor

UTILITIES HP Flare, 415,000 kg/hr Electrical Switchgear & Power Distrib (5% of FC) Emergency Generator - Diesel Driven, 500 kW

Gas Turbine Generator, 32MW, GE LM2500+ Instrument air compressor and drier, 100 scfm N2 Dewar for Terminal, Vac. insul. tank, 42 m3 Firewater Protection System (Foam Sys, dry powder, tanks) Utilities Subtotal

MARINE UNLOADING STRUCTURE Platforms and Hex Bridge Cryogenic Piping (2 each 32" dia x L 1800 meters @ 1800 $/m)) Big Sweep Arm Marine Facilities - Subtotal

115.0 11,000.0 299.8 78.0 300.0 12,299.4

MARINE UNLOADING ARMS Arms: Unloading and Vapor Return Marine Facilities - Unloading Subtotal

1,500.0 1,500.0

963.0 963.0

1,930.6 1,930.6

168.2 168.2

88.8 88.8

527.2 527.2

5,177.8 5,177.8

1,120.0 3,500.0 4,620.0

0.0 0.0 0.0

56.0 175.0 231.0

22.4 70.0 92.4

134.4 420.0 554.4

1,332.8 4,165.0 5,497.8

500.0 0.0 0.0 500.0

25.0 0.0 0.0 25.0

10.0 0.0 0.0 10.0

30.0 0.0 0.0 30.0

565.0 0.0 0.0 565.0

Site Preparation Subtotal

0.0 0.0

0.0 0.0

0.0 0.0

0.0 0.0

0.0 0.0

Bulks Subtotal

9,003 0 4201.4 9000 22,204

180.1 0.0 84.0 180.0 444

540.2 0.0 252.1 540.0 1,332

SUBSEA PIPELINE To Cavern (total 6 = I mile long)

To existing subsea infrastructure (5 miles to tie in) Pipeline Subtotal NAVIGATIONAL AIDS (lighting and buoys) MODULAR STRUCTURES Administration Office/Control Center Compressor Building (Included in cost of compressors) Warehouse/Maintenance Building, 10,000 ft2 Buildings Subtotal SITE PREPARATION

BULKS Piping (exclud. trestle) Piling Insulation and Paint Electrical/Instrumentation

0 0

REAL ESTATE Real Estate Subtotal OSBL INFRASTRUCTURE Includes access roads, bldgs, hospitals, stores, bridges OSBL Infrastructure Subtotal UNADJUSTED GRAND TOTAL CONTINGENCY 12% OF THE TOTAL ADJUSTED GRAND TOTAL

450.1 0.0 210.1 450.0 1,110

0 0

0 31,008

129,550

10,173 0 4,748 10,170 25,091

0 65,406

8,958

4,538

23,060

262,520 31,502 294,022

Energy Bridge® LNG TERMINAL PROFORMA ECONOMICS Project Summary SUMMARY FACILITY ASSUMPTIONS Facility Basis - Firm Service Cargos per Year LNG Discharge per Ship, cubic meters LNG LNG Btu content, Btu/scf Storage Working Gas Volume, Bcf Storage Base Gas Volume, Bcf

Pricing Throughput Fee, $/MmBtu Other Revenue - % of Terminal Throughput Rev. Terminal Energy Use Charge, % of throughput Assumed Henry Hub Index for initial year Gas Storage Net Revenue Realized $MM/year Other Assumptions Base Gas Price (Delivered), $/Mcf Base Gas Source ("Lease" or "Buy") Total Operations Cost, $M/Year - Labor & Maintenance, $M/Yr - Electrical Demand Charge, $M/Yr Management Overhead, $M/Year Property Taxes (assumed amount), $M/Yr Storage Site Lease Fee, $M/yr % Revenue Stream to Inflation Protect, %/yr General Inflation Rate Inflation applied to certain annual costs, %/yr Energy Use for Terminal ops., % of throughput Full storage cavern compression charge rate % of throughput requiring compression at cavern Project & Technology Rights Running Royalty, as % of Henry Hub index Project & License Upfront Payment, $MM

65 138,000 1067 16.00 7.30

0.295 0.0% 0.00% $3.50 $0.0

3.50 lease 8,039 7,839 200 360 4,000 500 100% 3.0% 1.5% 1.00% 0.00% 0%

Facility Costs, $ Marine Port Facilities LNG Vaporization & Process Terminal Utility System Storage Surface Facility Site Specific Misc Header Pipeline Engineering & Const. Mgmt. Project Acquisition & Tech. Rights Owner Costs, Permits, Misc. Financing Fees Contingency Total Facility Cost LNG Terminal Project Metrics Load Factor (based on 65 cargos/yr max) Reference Annual throughput, mcf/yr Annual LNG Offloaded, BCF/yr Reference throughput, million mmBtu/yr Daily equivalent amount (mcf/day) Tax Rates Federal, %/YR State, %/YR Blended Rate, %/Yr. Property, %/YR, initial year/capital cost Capital Gain Rate for Terminal Value Depreciation Depreciation (Straight-Line or Accel) Depreciable Life, Years Project Life, Years

0.00% based on mmBtu throughput 0

FINANCIAL ASSUMPTIONS 25,067,080 19,981,000 175,000,000 0 3,640,466 0 12,001,454 50,000 7,653,250 13,421,313 35,916,000 292,730,563

100% 176,822,322 177 188,669,417 491,173 35.0% 4.50% 37.93% 1.37% 20%

Financial Structure Sr. Debt Percent of Capital Jr. Debt Percent of Capital Equity Percent of Capital Senior Debt Term Junior Debt Term Base Gas Lease Carrying Cost, %/YR

% Capital 50.0% 0.0% 50.0% 20 5 6.75%

FINANCIAL RESULTS Cost of Capital Pretax WACC WACC Equity Return (assumed from above)

10.88% 9.60% 15.0%

Project Economics Project NPV@Pretax WACC, $M Project Pretax IRR NPV @ WACC (tax-effected), $M Project IRR (tax-effected)

121,293 15.1% 77,396 12.1%

Yr. 1 EBITDA $M/year Avg. EBITDA, Yrs 1-5, $M/year

$34,430 $36,944

Equity Returns, AFTER-Tax Straight-Line 20 20

Equity NPV@ Assumed Equity Return, $M

Equity IRR (calculated) Debt Coverage Minimum EBITDA/Interest Coverage Minimum EBITDA/Debt Service

17,392 16.4% Pre-tax

3.5 2.5

Rate 6.75% 0.0% 15.0%

LNG Terminals Cost Comparison Equipment Summary Sheet Energy Bridge Shipboard Regasification

Bare Equipment

Capacity 0.48 Bcfd

Cost ($M)

Description

GLNG Storage Caverns: 2 ea x 3 BCF = 6 BCF (304,400 m3) LNG Storage Tank Subtotal - NA -

Steel Concrete I/E & Piping Cost ($M)

Installed Direct & Indirect Cost ($M)

-

-

Freight Spares Other Cost ($M)

Taxes Duties Insurance Cost ($M)

Contract Engineering (12%) Cost ($M)

Total Cost Cost ($M)

-

-

-

-

NA

PROCESS VESSELS Recondenser, 9'ID x 45', 304 SS BOG Compressor Knock Out Drum 70 m3 HP Fuel Gas Knock Out Drum, 3 m3 HP Flare Knock Out Drum, 50 m3 Service Water Storage Tank, 20 m3 Diesel Storage Tank, 50 m3 Foam Tank, 4 m3 Process Vessels Subtotal

0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

0.0

0 0 0 0 0 0 0 0.0

VAPORIZERS Shell and TubeVaporizers, 168 ton/hr Submerged Combustion Vaporizers, 168 ton/hr Bishop Process Vaporizers Subtotal

1,200 0 0 1,200

924 0 0 924

1,852 0 0 1,852

142.2 0.0 0.0 142

80.2 0.0 0.0 80

477 477

4,676 0 0 4,676

HEAT EXCHANGERS Standby glycol/fuel gas heater 127 kW HP knockout drum heater 20 kW Gaseous N2 Vaporizer 35 kW Gaseous N2 Vaporizer (Spare) 35 kW Liquid N2 Pressurization vaporizer 35 kW Liquid N2 Vaporizer 35 kW Heat Exchangers Subtotal

0 0 0 0 0 0 0.0

0.00 0.00 0.00 0.00 0.00 0.00 0.0

0.0 0.0 0.0 0.0 0.0 0.0 0.0

0.0 0.0 0.0 0.0 0.0 0.0 0.0

0.0 0.0 0.0 0.0 0.0 0.0 0.0

-

0

0

0

0

0

Pumps Subtotal

0.0 1,800.0 0.0 0.0 0.0 17.4 0.0 1,817.4

0.0 1881.0 0.0 0.0 0.0 24.9 0 1,906

0.0 3770.6 0.0 0.0 0.0 49.9 0.0 3,820

0.0 238.1 0.0 0.0 0.0 2.6 0.0 241

0.0 150.1 0.0 0.0 0.0 1.9 0.0 152

0 0 0 0

0 0 0.0 0

0.0 0.0 0.0 0

0.0 0.0 0.0 0

-

Compressors Subtotal

0.0 0.0 0.0 0.0

SEAWATER INTAKE SYSTEM (Incl Electrochlorination) Electrochlorination Unit, 12,000 m3/hr Seawater Intake Structure (12,000 m3/hr each) Seawater Outfall Structure (12,000 m3/hr each) Seawater Intake Screens (13,200 m3/hr each) Seawater Rotary Screens (13,200 m3/hr each) Seawater Intake System Subtotal

0 0 0 0 0 0

0 0 0 0 0 0

0 0 0 0 0 57.33

0.0 0.0 0.0 0.0 0.0 0

0.0 0.0 0.0 0.0 0.0 0

-

0

0 429 0.0 0.0 41.2 60.1 0.0 530.0

0.0

0.0 21.4 0.0 0.0 14.1 9.2 0.0 44.7

600.0 115.0 0.0 450.0 1165

0.0

0 0 0 0 0 0 0.0

0

0

WASTE HEAT RECOVERY Waste Heat Recovery Subtotal PUMPS First stage sendout pump, 416 m3/hr (intank) Second stage sendout pump, 325 m3/hr Seawater pump, 2187 m3/hr Sub combustion Vap. Overflow pump, 5hp Process Area Sump Pump, 10 hp, 5 m3/hr Service Water Pump, 5 hp, 57 m3/hr Firewater Pumps

COMPRESSORS BOG Compressors Ship Vapor Return Unit w/Blower Ship Unloading Compressor

UTILITIES HP Flare, 415,000 kg/hr Electrical Switchgear & Power Distrib (5% of FC) Emergency Generator - Diesel Driven, 500 kW Gas Turbine Generator, 22 MW, GE LM2500 Instrument air compressor and drier, 100 scfm N2 Dewar for Terminal, Vac. insul. tank, 42 m3 Firewater Protection System (Foam Sys, dry powder, tanks) Utilities Subtotal

Offshore Platform and APL Subsea Installation APL Buoy Pipeline to Plem 1 mile @ 2.3 mmUSD Plem Turret, riser, moorings, and installation (EP supplied) Marine Facilities - Platform Subtotal

0.0 0.0 149.9 78.0 0.0 227.9

12000 2300 0 9000.0 23300

0.0 0.0 82.6 120.4 0.0 203.0

894.2 11.1 905

0

0 8,734 0 0 0 108 0 8,842

0 0 0 0

0

0 0 0 0 0 0

0.0 8.6 0.0 0.0 5.6 5.2 0.0 19.4

51.4 32.9 31.0 115.3

0 510 0 0 326 304 0 1,140.3

240.0 46.0 0.0 180.0 466

1,440.0 276.0 1,080.0 2796

14,280 2,737 0 10,710 27727.0

MARINE FACILITIES - UNLOADING Arms: Unloading and Vapor Return Marine Facilities - Unloading Subtotal

175,000.0 175,000.0

SUBSEA PIPELINE To Cavern Platform (2 pipes 1 mile) To existing subsea infrastructure (11 miles) Pipeline Subtotal

0.0 0.0

0.0 0.0

14,000.0 14,000.0

3,605.0 3,605.0

10,500.0 10,500.0

203,105.0 203,105.0

0.0 2,000.0 2,000.0

0.0 100.0 100.0

0.0 40.0 40.0

0.0 240.0 240.0

0.0 2,380.0 2,380.0

100 100

5.0 0.0 0.0 5

2.0 0.0 0.0 2

12.0 12

119 0 0 119

NAVIGATIONAL AIDS (lighting and buoys) MODULAR STRUCTURES Administration Office/Control Center Compressor Building (Included in cost of compressors) Warehouse/Maintenance Building, 10,000 ft2 Buildings Subtotal

257 257

12.9 13

5.1 5

30.9 31

306 306

Bulks Subtotal

1,286 0 600.2 5000 6,886

64.3 0.0 30.0 250.0 344

25.7 0.0 12.0 100.0 138

154.3 0.0 72.0 600.0 826

1,531 0 714 5,950 8,195

Real Estate Subtotal

0.0 0

OSBL INFRASTRUCTURE Includes access roads, bldgs, hospitals, stores, bridges OSBL Infrastructure Subtotal

0

SITE PREPARATION Site Preparation Subtotal BULKS Piping (exclud. trestle) Piling

Insulation and Paint Electrical/Instrumentation

REAL ESTATE

UNADJUSTED GRAND TOTAL CONTINGENCY 12% OF THE TOTAL ADJUSTED GRAND TOTAL

178,245

35,904

0 0

0 5,904

16,055

4,507

15,903

256,490 30,779 287,268

Customer: Document Title:

Date of Issue:

The United States Department of Energy National Energy Technology Laboratory

24/04/2003

Task 3 Doc 08: Matrix for Comparison of Five LNG Terminal Designs

Doc # & Version:

Doc 08 r1.0

Page 1 of 4

Matrix for Comparison of Five LNG Terminal Designs

BY MICHAEL M. MCCALL WILLIAM M. BISHOP D. BRAXTON SCHERZ

r 1.0

For client review

02/09/03

Version

Reason for Issue

Issue Date

Document Title: Matrix for Comparison of Five LNG Terminal Designs

BS

MM

Orig. Chk. Appr. Chk. Appr. CGI NETL

Review

Document No: CGI/DOE_DOC 08 DE-FC26-02NT41653

Filename: 41653R01

Customer: Document Title:

The United States Department of Energy National Energy Technology Laboratory Task 3 Doc 08: Matrix for Comparison of Five LNG Terminal Designs

Date of Issue:

24/04/2003 Doc # & Version:

Doc 08 r1.0

Page 2 of 4

TABLE OF CONTENTS

1. MATRIX FOR COMPARISON PURPOSES.....................................................................................................3

Filename: 41653R01

Customer: Document Title:

Date of Issue:

The United States Department of Energy National Energy Technology Laboratory

24/04/2003

Task 3 Doc 08: Matrix for Comparison of Five LNG Terminal Designs

Doc # & Version:

Doc 08 r1.0

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1. MATRIX FOR COMPARISON PURPOSES This matrix is based on a five tiered rating system with indicators depicting “Excellent to Acceptable” as follows:

= Excellent = Very Good = Good = Fair = Acceptable The first section of the matrix is based on the quantitative results of the factored analysis (see Doc 07 for Summary Table) discussed in prior sections and other calculated parameters. The quantitative analysis for the five terminals lends itself to a ranking whereby each terminal is uniquely rated “Acceptable through Excellent” unless the numerical results were equivalent. To better interpret the quantitative results of the matrix below, the reader should refer to Table 4.3 in Doc 07 “LNG Terminal Cost Comparison.” All subjective parameters are based on a qualitative analysis and represent the experience of the Study Team and industry polling. Because the rankings in each parameter under the qualitative analysis are subjective, the five terminals may share a common ranking from time to time. Parameter

Pacific Coast

Atlantic Coast

BPT Onshore

BPT Offshore

Energy Bridge

Quantitative Annual Sendout TIC per Capacity OPEX per Capacity Fuel Consumption Service Fee Qualitative Security Capacity Economy Buyer Response Filename: 41653R01

Customer: Document Title:

The United States Department of Energy National Energy Technology Laboratory Task 3 Doc 08: Matrix for Comparison of Five LNG Terminal Designs

Date of Issue:

24/04/2003 Doc # & Version:

Doc 08 r1.0

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Netback to Seller Construction Time Permitting Complexity

Filename: 41653R01