MAYOR AND COUNCIL AGENDA CODE: WS

DATE SUBMITTED: March 25, 2005 DATE TO GO BEFORE COUNCIL: March 28, 2005

SUBMITTED BY: Stuart Eisenberg

STAFF MEMBER: Darsey Nicklasson

SUBJECT: Proposed Liquefied Natural Gas Plant and Storage Facility at Chillum near West Hyattsville Metro

RECOMMENDATION: To discuss and to develop a policy statement in the form of a resolution that can be shared and jointly signed by the area Municipalities and Civic Associations.

SPECIFIC ACTION TO BE TAKEN: To adopt a Resolution of Opposition to the proposed location of the Washington Gas Light LNG Plant and Storage Facility. BACKGROUND: Washington Gas Light Company is requesting the Prince George’s County Planning board to approve a minor change to a special exception (SE-245) for a natural gas storage tank facility located at 2130 Chillum Road. The location is within the West Hyattsville Metro Transit District Overlay Zone (TDOZ) and adjacent to the Northwest Branch and stream valley park.

Washington Gas is proposing to reinstate the currently decommissioned site as a liquefied natural gas (LNG) plant and storage facility to meet projected customer demand in the developing tier. The site was decommissioned in 1999. The proposed storage tank is approximately 144 feet in diameter and 153 feet tall and will be located in the footprint of one of the prior gas holding tanks. Additional piping and gas processing equipment will be required. CH-IV is the engineering firm out of Benville, MD that is designing the proposed facility and is expected to oversee its construction.

The proposed facility would be located within 1,500 feet of the Metro station and within 2,000 feet distance of the homes of 3,000 residents.

If the special exception is approved, Washington Gas proposes to begin construction in November 2006. It will take three (3) years to complete the project.

Washington Gas has not made any community outreach efforts other than community meetings hosted by County Councilman Will Campos. A public meeting was hosted at the Hyattsville Municipal meeting on Wednesday, March 16th and at the Chillum Community Center on Thursday, March 24th.

STAFF COMMENT: Recommend that the Mayor and Council adopt a resolution of opposition to the proposed location of the Washington Gas Light LNG Plant and Storage Facility and their request for a minor change to the special exception. Washington Gas is proposing to change the use of the facility not just the footprint of the site. Previously it was a natural gas storage facility, but it was decommissioned in 1999 and has not been used as such since. The proposed installation of the LNG is a different and therefore should be classified as a new use of the site.

The proposal for the installation of the LNG does not complement other land uses in the area. The land uses surrounding the West Hyattsville Metro Station should be transit-oriented which calls for a higher density use in order to better utilize the metro to meet residents’ transportation needs.

Furthermore, staff recommends the development of a community outreach effort, in coordination with other civic organizations, to inform residents of the proposal, impacts on our community, organize a campaign to sign residents as Persons of Record, write to elected officials and speak at upcoming public meetings and hearing. FUNCTION AND OBJECTIVES: Improve the safety and quality of life for all residents

SUPPORTING DOCUMENTATION: Title 49 – Transportation, Chapter I, Part 193 – Liquefied Natural Gas Facilities: Federal Safety Standards, Statement of Qualifications – CH-IV, International, Safety History of International LNG Operations. Washington Gas special exception application, Statement of Justification and site plans are available for viewing upon request.

BUDGET IMPACT: None * CODE: WS = Work Session CM = Council Meeting

Draft Resolution of Opposition

We, the undersigned Municipalities and Civic Associations, on behalf of the residents we represent, wish to declare and resolve to all County, State, and Federal authorities, lawmakers, regulators, planners, transit authorities and utility operators in the Washington Metropolitan region that we oppose the placement of any Liquefied Natural Gas Storage Plant and Re- gasification facility or Peak-shaving facility within, adjacent, or in proximity to densely- populated residential neighborhoods, important commuter transit stations, transit-oriented development planning areas, or previously-planned-for residential developments of an urban design orientation.

Whereas the Washington Gas and Light Company has proposed and applied for a “minor change” to its Special Exception and a permit to build a Liquefied Natural Gas Storage Plant and Re-gasification Peak-shaving facility for its Chillum, Maryland property, and

Whereas the proposed change in use from the previous storage of Natural Gas, to the proposed use as a Liquefied Natural Gas Storage Plant and Re-gasification Peak-shaving facility is a use change that is a “major change” and substantial, hazardous, and industrial in nature, and

Whereas the site is located within a densely populated and long established residential neighborhood where approximately 3000 people currently reside within 2000 feet of the proposed facility, and

Whereas, the site is located within 1500 feet of the West Hyattsville Metro Station and within the proposed Transit District Overlay Zone and is a critical property in the Transit District Development Plan of the West Hyattsville Metro Station, and is not a compatible land use, and

Whereas the Washington Gas and Light Company did not forthrightly and openly participate in any public forum, discussion, or regional planning processes that openly and frankly discussed the implications of siting a Liquefied Natural Gas Storage Plant and Re-gasification Peak- shaving facility in Prince Georges County in a timely fashion that would allow for the County to develop model guidelines for the Master Planning of such a facility, despite opportunities to do so, and

Whereas the Washington Gas and Light Company has no organizational experience in the management and maintenance of a Liquefied Natural Gas Storage Plant and Re-gasification Peak-shaving facility, and

Whereas there is a widespread consensus that valid Environmental Justice issues relating to the placement of this facility need to be a foremost concern amongst lawmakers and regulators who are considering the permitting of this facility, because the projected service capacity increase is targeted to serve growth in areas of Prince Georges County that are located in the Developing Tier and not in this economically challenged and under-performing Inner Beltway community in the Developed Tier, and

Whereas this proposed use will have a severe and negative effect upon the local economy and proposed private development projects and investments currently under discussion for properties in the vicinity,

We the undersigned, request that the following actions be taken to preserve the health, safety, and welfare of residents in Prince George’s County, and the economic viability of our communities:

That a State and County legislative moratorium be immediately enacted to prevent the permitting of this or any LNG facility of its kind in the County until such time as facilities such as this can be properly studied and guidelines for siting them can be developed by MNCPP-C and incorporated into the Master Planning process of the County, and

That the full Environmental Justice policy dimensions of this proposed location for the facility be addressed by the Prince George’s County Council, and other relevant agencies, and

That the application for a permit to build the proposed facility at this location be denied for the aforementioned reasons, and

That the County Council, acting as the District Council, request economic impact reports be drafted by independent analysts, at the applicants’ expense, in light of the applicant’s foreknowledge of the planning and redevelopments efforts underway for the adjoining Metro- owned properties within the Transit District Development Plan.

Draft prepared by Council Pres. S.Eisenberg From http://www.access.gpo.gov/nara/cfr/waisidx_02/49cfr193_02.html To access files go to site and link to applicable standard Title 49--Transportation

CHAPTER I--RESEARCH AND SPECIAL PROGRAMS ADMINISTRATION, DEPARTMENT OF TRANSPORTATION

PART 193--LIQUEFIED NATURAL GAS FACILITIES: FEDERAL SAFETY STANDARDS

193.2001 Scope of part.

193.2005 Applicability.

193.2007 Definitions.

193.2009 Rules of regulatory construction.

193.2011 Reporting.

193.2013 Incorporation by reference.

193.2017 Plans and procedures.

193.2019 Mobile and temporary LNG facilities.

193.2051 Scope.

193.2057 Thermal radiation protection.

193.2059 Flammable vapor-gas dispersion protection.

193.2067 Wind forces.

193.2101 Scope.

193.2119 Records

193.2155 Structural requirements.

193.2161 Dikes, general.

193.2167 Covered systems.

193.2173 Water removal.

193.2181 Impoundment capacity: LNG storage tanks.

193.2187 Nonmetallic membrane liner.

193.2301 Scope.

193.2303 Construction acceptance.

193.2304 Corrosion control overview.

193.2321 Nondestructive tests.

193.2401 Scope.

193.2441 Control center.

193.2445 Sources of power.

193.2501 Scope.

193.2503 Operating procedures.

193.2505 Cooldown.

193.2507 Monitoring operations.

193.2509 Emergency procedures.

193.2511 Personnel safety.

193.2513 Transfer procedures.

193.2515 Investigations of failures.

193.2517 Purging.

193.2519 Communication systems.

193.2521 Operating records.

193.2601 Scope.

193.2603 General.

193.2605 Maintenance procedures.

193.2607 Foreign material.

193.2609 Support systems.

193.2611 Fire protection.

193.2613 Auxiliary power sources.

193.2615 Isolating and purging.

193.2617 Repairs.

193.2619 Control systems.

193.2621 Testing transfer hoses.

193.2623 Inspecting LNG storage tanks.

193.2625 Corrosion protection.

193.2627 Atmospheric corrosion control.

193.2629 External corrosion control: buried or submerged components.

193.2631 Internal corrosion control.

193.2633 Interference currents.

193.2635 Monitoring corrosion control.

193.2637 Remedial measures.

193.2639 Maintenance records.

193.2701 Scope.

193.2703 Design and fabrication.

193.2705 Construction, installation, inspection, and testing.

193.2707 Operations and maintenance.

193.2709 Security.

193.2711 Personnel health.

193.2713 Training: operations and maintenance.

193.2715 Training: security.

193.2717 Training: fire protection.

193.2719 Training: records.

193.2801 Scope.

193.2901 Scope.

193.2903 Security procedures.

193.2905 Protective enclosures.

193.2907 Protective enclosure construction.

193.2909 Security communications.

193.2911 Security lighting.

193.2913 Security monitoring.

193.2915 Alternative power sources.

193.2917 Warning signs.

Statement of Qualifications Owner’s Engineering, Lender's Engineer and Due Diligence

H | H — C — H | H

LNG

LNG

H H C H H CH·IV International The LNG Specialists

Baltimore / DC Office Houston Office 1120C Benfield Boulevard 1221 McKinney, Suite 3325 Millersville, MD 21108 Houston, TX 77010 Phone: 410-729-4255 Phone: 713-964-6775 Fax: 410.729.4273 Fax: 713.622.5513 E-mail: [email protected] Email: [email protected]

www.CH-IV.com August 2004 H H C H H CH·IV International Statement of Qualifications

OVERVIEW OF CH·IV CAPABILITIES

CH·IV International (CH·IV) has provided engineering services relating to the design and operation of LNG facilities since its founding in 1991. CH·IV’s senior staff has a combined total of over 125 years of engineering experience covering the whole LNG chain, from gas treatment and liquefaction through marine and land transportation to the final import and delivery of the gas to the pipeline, power plant or LNG powered vehicle. CH·IV’s parent company, MPR Associates, Inc., of Alexandria, Virginia, complements the CH·IV LNG experts with a technical staff of over 100 experienced engineers and a long history in the power industry. CH·IV is further supported by a five-person design and drafting department and an extensive 75,000 volume library with three full time professional librarians. In addition to our primary office in Millersville, MD, CH·IV maintains a permanent office in Houston, TX. Additionally, MPR has affiliate engineering offices in Houston, Brazil and Los Angeles.

CH·IV and its parent company have teaming agreements and successful working relationships with national and local environmental engineering firms including URS Corporation, EarthTech, TRC Environmental, CH2M Hill, Golder, and Schnabel for providing specific environmental permitting services, site contamination evaluations, detailed geotechnical investigation of brown field sites, and design and evaluation of marine structures. Similarly, CH·IV has a close working relation with Lanier & Associates of New Orleans and Houston to assist in marine logistics studies and facility design.

SOME OF CH·IV’S STRENGTHS RELATING TO LNG FACILITIES INCLUDE:

1. In-depth understanding and experience in LNG systems, safety and marine logistics: ♦ CH·IV is recognized as a top quality provider of independent design review and troubleshooting services for LNG facilities, systems and equipment. ♦ This core competence in component engineering makes CH·IV particularly effective in: • Technical due diligence, • Design and safety reviews, fabrication audits, and oversight of acceptance testing, and • Specification and integration of new and challenging systems.

2. Our rigorous and systematic development of support for regulatory applications: ♦ CH·IV has worked on support of the permitting process on five of the recent Federally permitted LNG import projects (Cove Point Reactivation, Dominion; Lake Charles Expansion, Trunkline; TREC (Baja), Marathon; Cameron LNG, Sempra; and Energía Costa Azul, Sempra). ♦ CH·IV led the technical side in submission for a Deep Water Port Application (DWPA) for Crystal Clearwater Port (California) and are currently doing the same for an unannounced DWPA port in the Gulf of Mexico. ♦ CH·IV has direct involvement with filing applications for to the FERC, the U.S.C.G. under the Deep Water Ports Act, and to the Mexican Comisión Reguladora de Energía (CRE).

August 2004 Page 1 of 9 H H C H H CH·IV International Statement of Qualifications

3. Selective application of world-class, specialized technical expertise in areas such as: ♦ LNG terminal operations ♦ LNG tanker operations ♦ LNG storage tank design ♦ Cryogenic pump and compressor design and operation ♦ LNG facility siting and permitting ♦ Waste heat/waste cold utilization ♦ Vapor handling evaluations ♦ Together with our parent company, MPR, we also can provide expertise in: • materials and corrosion engineering, • thermodynamics, • structural mechanics, • instrumentation and controls, • electrical systems, and • emissions controls.

Specific details of CH·IV capabilities include: 9 CH·IV has a deep understanding on the development of Resource Report 11 and 13 (18 CFR 380) for FERC applications. Similarly, CH·IV provided similar support to U.S.C.G. Deep Water Port Act applications and applications to the Comisión Reguladora de Energía (CRE). 9 LNG shipping modeling is performed using CH·IV-developed proprietary software. We also can perform LNG vapor dispersion from LNG spills and thermal radiation from LNG fires modeling. 9 Cost estimating is performed using LNG import facility-specific, CH·IV-developed software that is adaptable to the format requirements of client proforma evaluations. 9 Determination of hazard exclusion zones with LNGFIRE III and Degadis. 9 Project scheduling is typically performed using Microsoft Project. Other PC based software such as TimeLine and Primevera can also be used as required. 9 The drafting department uses AutoCAD 2000 (with translation to other versions and drafting programs available). 3-D modeling capability for both analysis and drafting; architectural (artist’s concept) drawings for LNG facilities are produced with this capability. 9 Process Simulation software, Design II by WinSim Inc., is used for design review and process optimization and verification.

August 2004 Page 2 of 9 H H C H H CH·IV International Statement of Qualifications

TYPICAL OWNER’S ENGINEER ACTIVITY IN LNG TERMINAL DEVELOPMENT:

1. Site Selection ♦ Research location of resources required to support LNG development (land, marine access, pipeline take-away capacity, electrical transmission access,1 zoning, etc.); ♦ Map review of potential sites; ♦ On-site survey of potential locations; ♦ Review of potential thermal exchange partners; and ♦ Evaluation and ranking of potential sites.

2. Site Due Diligence ♦ Collect available information concerning previous site use, including geotechnical information and sub-surface obstructions; ♦ Collect information concerning site water resources, including existing wells, surface waters, and municipal/industrial water sources; ♦ Collect marine access details such as existing traffic, mean low water draft available, air draft obstructions, channel width, etc.; ♦ Identify applicable zoning and permitting requirements for the site, ♦ Collect information on the potential thermal exchange for the site; ♦ Review gas (and electric) transportation capacity in the area of the site; ♦ Characterize the ability of the planned facility to fit the available land; and ♦ Evaluate the major impacts on project feasibility to determine the acceptability of the project site for development.

3. Conceptual Engineering ♦ Prepare alternative designs and perform initial sizing of components; ♦ Develop heat balance for site; ♦ Prepare conceptual engineering report including process flow diagrams and material balances, detailed project schedule, construction cost estimate and O&M cost estimate; ♦ Support development of detailed project proforma and financing approval; ♦ Prepare project description and inputs for air and water permit modeling; and ♦ Coordinate site land survey and geotechnical sampling performed by others.

1 Both from a purchase power and integrated LNG import / power plant perspective.

August 2004 Page 3 of 9 H H C H H CH·IV International Statement of Qualifications

4. Preliminary Engineering ♦ Obtain specific component operating characteristics for site from vendors; ♦ Develop project specific specification for major components; ♦ Coordinate development of additional owner permits and update information in existing permits, as necessary; ♦ Prepare site drainage and surface run-off containment drawings; ♦ Detail interface requirements with connecting pipelines utilities or thermal exchange partners; ♦ Finalize component selection, project cost estimates, and project schedule; ♦ Prepare EPC (Engineer, Procure, and Construct) specification and assist in pre-qualification of EPC bidders; ♦ Define contractor guarantees for facility performance (LNG tank heat leak, facility fuel utilization, total facility electrical power consumption), emissions control, maintenance, operation, documentation, and training; ♦ Prepare technical portions of regulatory filing; ♦ Prepare preliminary engineering report documenting details of plant design; and ♦ Provide technical support to evaluate bids and award EPC scope of work.

5. Detailed Design and Construction Support Engineering ♦ Prepare or perform technical review of specifications, drawings, and engineering calculations performed by EPC; ♦ Provide on-site engineering support of construction activities, including site preparation, monitoring activities and review of commissioning, cooldown and startup procedures; ♦ Technical resolution of problems during construction; ♦ Provide independent assessment of project schedule and corrective actions to ensure schedule compliance; ♦ Review and approve proposed field changes to design; ♦ Maintain project files during construction and review EPC as-built information; ♦ Evaluate change orders to EPC scope; and ♦ Coordinate activities between EPC, vendors and other organizations.

6. Start-Up Support Engineering ♦ Provide independent assessment of activity schedule during start-up; ♦ Review test procedures for acceptance testing of performance and emissions; ♦ Review results of acceptance testing for performance and emissions; ♦ Prepare and provide operator/technician training; and ♦ Maintain punchlist of items to be corrected by the EPC.

August 2004 Page 4 of 9 H H C H H CH·IV International Statement of Qualifications

RELATED EXPERIENCE IN OWNER’S AND LENDER’S ENGINEERING AND DUE DILIGENCE:

A quick review of the list that follows will show that CH·IV International is and has been involved in a number of active, major LNG projects as well as other projects supporting the claim of “The LNG Specialists.” This list of current activities includes the very recent reactivation of the fourth U.S. LNG import terminal, Cove Point; successfully supporting the permitting process of three new import terminals (Cameron, Louisiana and two Baja, Mexico projects); Owner’s Engineering supporting a world-class LNG export project (Bioko Island, Equatorial Guinea) and project management of a California offshore LNG import terminal for Crystal Energy.

Project: Port Arthur LNG Terminal Client: Sempra Energy International Date: 2004 to Present Scope: Owner’s Engineer for Sempra during preparation for FERC filing on their Port Arthur (TX) 1.5 BCFD LNG import and regasification terminal project.

Project: Canadian LNG Terminal Client: Confidential Date: Present Scope: Provide feasibility study of expanding an existing industrial location to integrate an LNG/CNG import terminal. Feasibility study to include unique integration possibilities as well as more traditional design, safety, security, pipeline interconnect, operational and economic considerations.

Project: Crystal Clearwater Port Client: Crystal Energy Date: 2001 to Present Scope: Project management, public outreach, preliminary design and permitting support to Crystal Energy on their offshore LNG regasification facility located on Platform Grace.

Project: Costa Azul LNG Terminal Client: Sempra Energy International Date: 2003 to Present Scope: Owner’s Engineer for Sempra during FEED phase for their Baja, Mexico import and regasification terminal project.

Project: Cameron LNG Terminal Client: Sempra Energy International Date: 2002 to Present Scope: FERC permit support and Owner’s Engineer for Sempra during FEED phase for their Cameron, LA import and regasification terminal project. Assist with EPC bid evaluation.

August 2004 Page 5 of 9 H H C H H CH·IV International Statement of Qualifications

Project: Bioko Island LNG Facility Client: Marathon Oil Company Date: 2002 to Present Scope: Evaluated liquefaction technologies and Owner’s Engineer during the FEED of this greenfield 3.7 mmtpa baseload LNG export project.

Project: LNG Facility – Regulatory Oversight Client: State of Connecticut DPUC Date: 2002 - Present Scope: Providing regulatory oversight for a new LNG peakshaving facility to be built by Yankee Gas in Waterbury, Connecticut. The work will include RFP, engineering FEED and detailed design review; on-sight construction inspection oversight services and various engineering inspection services.

Project: Tijuana Regional Energy Center Client: Marathon Oil Company Date: 2002 to 2003 Scope: Defining and reviewing engineering studies and system design by FEED engineering contractor in the contractor’s offices, including facility integration alternatives, systems/equipment definition, environmental issues and site layout. CH·IV is providing valuable input to owner to assure the best possible design to meet project objectives. Currently awaiting kick-off of post-permit work.

Project: Lake Charles LNG Terminal Expansion – Owner’s Engineer Client: CMS Energy Date: 2002 - Present Scope: Reviewing engineering design by engineering contractor, including PFD and P&IDs. Provided cost-saving alternatives on vapor handling systems and LNG piping. Evaluated major equipment vendor proposals. Working very closely with Terminal operations to staff to assure plant operability and reliability.

Project: Cove Point LNG terminal Client: Dominion Resources Date: 2003 Scope: Prepared/presented 3-week “LNG Basics” Technician training for reactivation of the Cove Point LNG Terminal. Training included 2-binder supporting textbook. Prepared and supported 2-week “Operations” training. Prepared 130-page “Pre-Cool Procedure” for testing integrity of LNG transfer system. Prepared 150-page “Reactivation/Start-Up Manual” which led to the first unloading of an LNG tanker at Cove Point in over 20 years.

Project: Dahej LNG Import Facility Client: SBI Banking Consortia Date: 2003 Scope: Provided Lender’s Engineering and technical support to an assessment and evaluation of the Petronet LNG import terminal and regasification facilities project under construction in Dahej, Gujarat, India. The 5.0 mmtpa capacity plant is scheduled to start up in December 2003.

August 2004 Page 6 of 9 H H C H H CH·IV International Statement of Qualifications

Project: EcoElectrica LNG Import/Power Facility (Puerto Rico) – RAM Study Client: North Ridge Resources Date: 2003 Scope: Provided reliability, availability and maintainability (RAM) study in association with parent company (MPR Associates). CH·IV was responsible for the LNG systems in the facility.

Project: EcoElectrica Power Facility (Puerto Rico) – Due Diligence Client: Confidential Date: 2002 Scope: Provided due diligence on purchase of the first dedicated LNG-powered independent power producer.

Project: Hackberry, LA Import Terminal Project – Due Diligence Investigation Client: Sempra Energy International Date: 2002 Scope: Reviewed project design and permitting status, determined validity of current FEED package including: process design, site layout, equipment selection, contract issues, cost and schedule. CH·IV subsequently advised client of the impact to the project of the investigation results.

Project: Baja Mexico LNG Import Terminal – Owner’s Engineer Client: Gas Natural Baja California, S. de R.L. de C.V. Date: 2001-2003 Scope: Prepared Design Basis and Operating Philosophy documents and assisted in preparation of Request for Quotation to provide Front-End Engineering Design (FEED) package.

Project: Enron LNG-Related Assets - Due Diligence Client: Confidential Date: 2002 Scope: Provided due diligence of various Enron-owned LNG-related assets under control of bankruptcy court. Responsibilities included 1) reviewing EPC bid and cost estimate for construction of the Bahamas LNG import terminal project; 2) Technical evaluation of the LPG extraction process proposed for the Bahamas; 3) Evaluation of the Bahamas to Florida high pressure submarine pipeline; and 4) Preliminary reliability, availability and maintainability of Elba Island LNG facility.

Project: Lake Charles LNG Terminal Expansion – Conceptual Engineering Design Client: CMS Energy Date: 2001 Scope: Prepare conceptual design package for second expansion of the Terminal. The expansion scope includes a new full containment LNG storage tank, sendout pumps, high pressure sendout pumps and vaporizers.

August 2004 Page 7 of 9 H H C H H CH·IV International Statement of Qualifications

Project: Cove Point LNG Terminal Reactivation – Owner’s Engineer Client: Williams Energy Date: 2000 - 2002 Scope: Reviewed engineering design by engineering contractor. Provided conceptual design of revised vapor handling system, vaporizer pH control system, alternative nitrogen production facilities, and LNG blending concept. Provided studies on vaporizer replacement options, second-stage pump enhancements, and unloading system pressure drop. Followed permit development. Reviewed cost estimates for construction and plant operation.

Project: LNG Import Terminal – Altamira, Mexico – Design Review Client: Confidential Date: 2001 Scope: Reviewed third-party produced conceptual design package. Included in the review were: Design basis, technical and process description, PFD, plot plan and exclusion zone drawing and budgetary costs.

Project: Lake Charles LNG Terminal Expansion FERC Filing – Owner’s Engineer Client: CMS Energy Date: 2001 Scope: Reviewed engineering design by engineering contractor. Assisted in preparation of data for FERC filing. Provided conceptual design and cost estimate of gas turbine generator waste heat recovery. Reviewed most plant systems for adequacy in supporting plant expansion. Provided studies on alternatives for waste heat utilization and optimization of existing gas recondensing system. Provided alternative PFD.

Project: LNG Terminal – Mexico – Regulatory Support Client: Gas Natural Baja California, S. de R.L. de C.V. Date: 2001 Scope: Assisted in preparation of documents for submission to the Comisión Reguladora de Energía (CRE), Mexico’s equivalent of the FERC. The documents included: drafts of operations and maintenance manuals, documentation of safety procedures, plant contingencies and civil protection, recommendations on which international LNG standards should be implemented and justification on the choice of LNG tank design.

Project: LNG Peakshaving Facility Retrofit - Conceptual Engineering Design Client: Confidential Date: 2001 Scope: Provided conceptual design for converting an existing LNG peakshaving facility to accept marine cargoes of LNG.

Project: Sacramento LNG Production Facility - Engineering Design Client: PG&E Date: 2001 Scope: Provided LNG facility design and permitting assistance for new LNG production facility.

August 2004 Page 8 of 9 H H C H H CH·IV International Statement of Qualifications

Project: Lynn (MA) LNG Facility – Lender’s Engineer Client: Fleet Bank Date: 1998 - 1999 Scope: As Lender’s Engineer, provided an 80-page evaluation of the condition of the Lynn, Massachusetts peakshaving facility.

A few older projects of particular note:

Project: Milford (CT) LNG Peakshaving Facility – Due Diligence Client: Panhandle Energy Corporation Date: 1996 - 1997 Scope: Provided equipment condition study and due diligence evaluation for Panhandle. Provided environmental risk assessment study. Provided liquefaction process evaluation and recommended alternatives to increase performance. As-built and upgraded P&IDs and electrical drawings to AutoCad. Helped draft Resource Report No. 13 and responded to FERC data requests.

Project: GLZ2 Liquefaction Complex (Arzew, Algeria) – Owner’s Engineer Client: Sonatrach, as subcontractor to Tractebel Industries Date: 1993 - 1995 Scope: Provided owner’s mechanical, electrical and instrumentation engineer in the re-design of the 1,000 mmscfd GLZ2 liquefaction facility.

Project: Cove Point LNG Terminal – Due Diligence Client: PEPCO Date: 1993 Scope: Provided due diligence for client on purchase of 50% of the facility. Provided equipment condition study.

August 2004 Page 9 of 9 Safety History of International LNG Operations

January 2005

H | H — C — H | H

LNG

LNG

Prepared by ~ H H C H H CH·IV International The LNG Specialists 1120C Benfield Boulevard Millersville, MD 21108

Phone: 410-729-4255 Web Site: CH-IV.com

Technical Document TD-02109 H H C H H CH·IV International

Safety History of International LNG Operations

INTRODUCTION:

LNG has been safely handled for many years. The industry is not without its incidents and accidents, but it maintains an enviable “modern-day”1 safety record. The process of natural gas liquefaction, storage and vaporization is not a new technology. Earliest patents involving cryogenic liquids date back into the mid- 1800s. The first patent directly for LNG was awarded in 1914. In 1939, the first commercial LNG peak-shaving plant was built in West Virginia. There are over 120 peakshaving and LNG storage facilities2 worldwide, some operating since the mid 1960s. In addition, there are over 18 base-load liquefaction (LNG export) facilities in Abu Dhabi, Alaska, Algeria, Australia, Brunei, Indonesia, Libya, Malaysia, Oman, Nigeria, Qatar and Trinidad currently in operation. LNG is transported by a fleet of over 130 LNG tankers of varying sizes from 18,500 M3 (cubic meter) to 140,000 M3 . This fleet of LNG ships delivers to receiving terminals in the Belgium, Dominican Republic, France, Greece, Italy, Japan, Korea, Spain, Taiwan, Turkey, the U.K. and, of course, the U.S., including Puerto Rico.

The LNG storage tanks at these facilities are constructed of an interior cryogenic wall, usually made of 9% nickel steel, aluminum or other cryogenic alloy. The outside wall is usually made of carbon steel or reinforced concrete. A thick layer of an insulating material such as Perlite separates the two walls.

For land-based facilities, an earthen or concrete spill containment having a minimum capacity exceeding the capacity of the LNG tank(s) surrounds the LNG tank(s). In some applications a tall concrete wall having an internal diameter slightly greater than the outside wall of the LNG tank, is used to double the integrity of the LNG tank. In others, the tanks are buried below ground level. In both cases, the objective is to minimize the exposed area between the LNG and the secondary containment based on a catastrophic tank failure3 scenario. Many tanks are equipped with top tank penetrations only, i.e., no bottom or side wall penetrations, thus, even in the unlikely event of a piping failure, tank contents remain in place.

With a few exceptions, LNG handling facilities have revealed an exceptionally superior safety record when compared to refineries and other petrochemical plants. With the exception of the 1944 “Cleveland Disaster,” all LNG-related injuries and/or fatalities, however devastating, have been limited to plant or contractor personnel. There have been no LNG shipboard deaths. There has not been a member of the public injured by an incident involving LNG since the failure of the ill-conceived Cleveland facility. Small LNG vapor releases and minor fires have also been reported, but impact was limited to the plant and the hazard was promptly handled by

1 Modern Day – Post mid-1950s - Cryogenic technologies came of age during the late 1950s and early 1960s with the development of the U.S. space program where cryogenic fuels such as liquid hydrogen and liquid oxygen had to be routinely and safely handled. 2 This does not include dozens of small LNG vehicle fueling stations and industrial LNG fuel facilities. 3 There has never been a catastrophic tank failure with any LNG, or similarly designed, storage tank.

TD-02109 Page 1 of 20 Revision 7 – January 2005 H H C H H CH·IV International

Safety History of International LNG Operations

plant personnel. Other accidents have occurred during the construction and repair of LNG facilities. Some of these accidents have been used to tarnish the exceptional safety record of LNG, but as no LNG was directly involved in the incident these accidents can only truly be called “construction” accidents. Damage has always been limited to the plant proper.

The following three sections discuss land-based, LNG ship and over-the-road LNG transport incidents respectively. Each section references an appendix listing the various incidents.

SAFETY RECORD OF LAND-BASED LNG FACILITIES

The first commercial facility for producing or utilizing LNG was a peakshaving plant that began operations in 1941 in Cleveland, Ohio. (A peakshaving plant liquefies natural gas when customer demand for gas is low and then vaporizes the LNG when demand is high, thus handling periods of peak demand that cannot be met by existing gas pipelines.) Since then, more than 150 other peakshaving plants have been constructed worldwide (approximately one-half of these are satellite facilities that have no liquefaction capability). In addition, 18 large natural gas liquefaction plants (export facilities) and about 30 large LNG import terminals have been constructed.

There have been four incidents in operating LNG facilities directly attributable to LNG that resulted in one or more fatalities – Skikda, Algeria – 2004; P. T. Badak (Bontang, Indonesia), 1983; Cove Point Maryland, 1979; Arzew, Algeria, 1977; and Cleveland, Ohio, 1944. There were two other “LNG” incidents (Portland 1968 and Staten Island 1973) involving death, but these correctly should be classified as construction accidents since no LNG was present. See Appendix A for more details on these incidents and a complete listing of land-based LNG facility incidents.

The accident at East Ohio Gas Company’s peakshaving plant in Cleveland, Ohio, is the only incident that involved injuries or fatalities to persons not employed by the LNG facility or by one of its contractors. This accident is often used as an example of the danger or risk involved in the LNG industry. However, the industry has changed dramatically since 1944. Modern LNG plants are designed and constructed in accordance with strict codes and standards that would not have been met by the Cleveland plant. For example, the alloy used in Cleveland for the inner vessel of the LNG storage tank is now forbidden and each LNG tank must now be located within a dike capable of containing at least 100% of the tank’s capacity.

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Although Appendix A is intended to be a comprehensive listing of incidents that have occurred in land-based LNG facilities; it does not include all of the minor, but reportable incidents. For example, the outer roofs or domes of a few conventional double-wall LNG tanks have suffered small cracks as a result of low temperature embrittlement initiated by leaks of LNG from over-the-top piping. These cracks allowed LNG vapor (i.e., natural gas) to escape from the tanks. In each case, the tanks were safely repaired without being taken out of service. Similarly, the inner tanks of several conventional LNG storage tanks (i.e., cryogenic metal inner tank and carbon steel outer tank) have been cracked as a result of frost heave brought on by inadequate or inoperative below-tank heaters. These tanks have been safely entered, repaired, and put back into service.

SAFETY RECORD OF LNG SHIPS

The first transportation of LNG by ship took place early in 1959 when the Methane Pioneer (an ex-Liberty ship that had been extensively modified) carried 5,000 M3 (cubic meters) of LNG from Lake Charles, Louisiana, to Canvey Island, near London, England. Commercial transportation of LNG by ship began in 1964 when LNG was transported from Arzew, Algeria to Canvey Island in two purpose-built ships—the Methane Princess and the Methane Progress.

The overall safety record compiled by LNG ships during the thirty-nine year period 1964 - 2002 has been remarkably good. During this period, the LNG tank ship fleet has delivered more than 30,000 shiploads of LNG, and traveled more than 100 million kilometers while loaded (and a similar distance on ballast voyages).

In all of these voyages and associated cargo transfer operations (loading/unloading), no fatality has ever been recorded for a member of any LNG ship’s crew or member of the general public as a result of hazardous incidents in which the LNG was involved. In fact, there is no record of any fire occurring on the deck or in the cargo hold or cargo tanks of any operating LNG ship.

Among LNG import and export terminal personnel, only one death can be even remotely linked to the loading or unloading of LNG ships. (In 1977, a worker in the LNG Export Facility at Arzew was killed during a ship-loading operation when a large-diameter valve ruptured and the worker was sprayed with LNG. His death was the result of contact with the very cold LNG liquid; the spilled LNG did not ignite. See Item 6 in Appendix A.)

Appendix B summarizes the historical record of LNG ship incidents. Although a major effort was made to ensure the record presented is complete, it is possible that some incidents have been missed. However, it is very unlikely that a major incident has been omitted. Firstly, nearly every shipping incident that results in an insurance claim will be published in “Lloyd’s List.” Secondly, even if the ship owners are self- insured, news of major incidents travels quickly through the LNG industry because it is composed of a relatively small number of ship and terminal operators that often

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share experiences through industry associations such as SIGTTO (the Society of International Gas Tanker and Terminal Operators).

Also included at the end of Appendix B is a description of a marine incident involving a liquid petroleum gas (LPG) tanker which is of similar design to many LNG ships. The incident provides some insight into the integrity of the product storage systems on these ships.

OVER-THE ROAD LNG TRANSPORT ACCIDENTS

Appendix C provides a partial compilation of over-the-road incidents. It is not intended to be comprehensive as reports of these incidents are maintained in different ways from state to state. However, much as with LNG ships, it is very unlikely that a major incident has been omitted. The lists do provide examples of the wide range of potential vehicle accidents that can occur. Most notable, not a single person outside the driver of the transport was injured and rarely did product spill and far more rarely did it ignite. The last occurrence listed is the best testimony to the safety of these over-the-road transports.

SUMMARY

The various incidents discussed, when taken on a case-by-case basis, attests to LNG’s safety record. The fact that most LNG opponents cite Cleveland and Staten Island as examples of the dangers of LNG, clearly indicate that there is little else to make their point. As devastating as both Cleveland and Staten Island were, they have no relevance when discussing the design and operation of today’s LNG facilities.

LNG is cryogenic; it is a liquid; and its vapors are flammable. It is not without its safety concerns – it, however, can be produced, transported and revaporized as safely, and in most cases, more safely, than other liquid energies.

For more information on LNG safety, please see CH·IV’s website, particularly: http://www.CH-IV.com/lng/lngsafty.htm

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1. October, 1944 Cleveland, Ohio, USA ~ “The Cleveland Disaster” LNG Peakshaving Facility Any time the topic of LNG is introduced to a new audience the “Cleveland Disaster” is bound to surface. It was indeed tragic, but an unbiased review will show just how far the industry has come from that horrific incident. The East Ohio Gas Company built the first “commercial” LNG peakshaving facility in Cleveland in 1941. The facility was run without incident until 1944, when a larger new tank was added. As stainless steel alloys were scarce because of World War II, the new tank was built with a low-nickel content (3.5%) alloy steel. Shortly after going into service, the tank failed. LNG spilled into the street and storm sewer system. The resultant fire killed 128 people, setting back the embryonic LNG industry substantially. The following information is extracted from the U.S. Bureau of Mines report4 on the incident:

On October 20, 1944, the tanks had been filled to capacity in readiness for the coming winter months. About 2:15 PM, the cylindrical tank suddenly failed releasing all of its contents into the nearby streets and sewers of Cleveland. The cloud promptly ignited and a fire ensued which engulfed the nearby tanks, residences and commercial establishments. After about 20 minutes, when the initial fire had nearly died down, the sphere nearest to the cylindrical tank toppled over and released its contents. 9,400 gallons of LNG immediately evaporated and ignited. In all, 128 people were killed and 225 injured. The area directly involved was about three-quarters of a square mile (475 acres) of which an area of about 30 acres was completely devastated.

The Bureau of Mines investigation showed that the accident was due to the low temperature embrittlement of the inner shell of the cylindrical tank. The inner tank was made of 3.5% nickel steel, a material now known to be susceptible to brittle fracture at LNG storage temperature (minus 260°F). In addition, the tanks were located close to a heavily traveled railroad station and a bombshell stamping plant. Excessive vibration from the railroad engines and stamping presses probably accelerated crack propagation in the inner shell. Once the inner shell ruptured, the outer carbon steel wall would have easily fractured upon contact with LNG. The accident was aggravated by the absence of adequate diking around the tanks, and the proximity of the facility to the residential area. The cause of the second release from the spherical tank was the fact that the legs of the sphere were not insulated against fire so that they eventually buckled after being exposed to direct flame contact.

4 “Report on the Investigation of the Fire at the Liquefaction, Storage, and Regasification Plant of the East Ohio Gas Co., Cleveland, Ohio, October 20, 1944,” U.S. Bureau of Mines, February, 1946.

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Further, it should be noted that the ignition of the two unconfined vapor clouds of LNG in Cleveland did not result in explosions. There was no evidence of any explosion overpressures after the ignition of the spill from either the cylindrical tank or the sphere. The only explosions that took place in Cleveland were limited to the sewers where LNG ran and vaporized before the vapor-air mixture ignited in a relatively confined volume. The U.S. Bureau of Mines, concluded that the concept of liquefying and storing LNG was valid if “proper precautions are observed.”

The Cleveland Disaster put an end to any further LNG development in the United States for many years. It was not until the early sixties that LNG began to be taken seriously through construction of LNG peakshaving facilities. A number of elements came together to bring LNG back; these included: • The advent of the space program and its associated cryogenic technologies • Successful large-scale fire and vapor cloud dispersion demonstrations • Extensive cryogenic material compatibility studies • Construction and operation of liquefaction plants in Algeria and receiving terminals in France and England.

2. May, 1965 Canvey Island, Essex, United Kingdom LNG Import Terminal A small amount of LNG spilled from a tank during maintenance. The spill ignited and one worker was seriously burned. No other details have been made available.

3. March, 1968 Portland, Oregon, USA LNG Peakshaving Facility - Construction Accident, no LNG present Four workers inside an unfinished LNG storage tank were killed when natural gas from a pipeline being pressure tested inadvertently entered the tank as a result of improper isolation, and then ignited causing an explosion. The LNG tank was 120 feet in diameter with a 100-foot shell height and a capacity of 176,000 barrels and damaged beyond repair. Neither the tank nor the process facility had been commissioned at the time the accident occurred. The LNG tank involved in this accident had never been commissioned; thus, it had never contained any LNG.

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4. 1971 La Spezia, Italy LNG Import Terminal - First documented LNG Rollover incident The LNG carrier Esso Brega had been in the harbor for about a month before unloading its cargo of “heavy” LNG into the storage tank. Eighteen hours after the tank was filled, the tank developed a sudden increase in pressure causing LNG vapor to discharge from the tank safety valves and vents over a period of a few hours. The roof of the tank was also slightly damaged. It is estimated that about 100 mmscf of LNG vapor (natural gas) flowed out of the tank. No ignition took place. This accident was caused by a phenomenon called “rollover,”5 where two layers of LNG having different densities and heat content are allowed to form. The sudden mixing of these two layers results in the release of large volumes of vapor.

5. January, 1972 Montreal, Canada LNG Peakshaving Facility - Although an LNG facility, LNG was not involved On January 27, 1972 an explosion occurred in the LNG liquefaction and peak shaving plant of Gaz Métropolitain in Montreal East, Quebec. The accident occurred in the control room due to a back flow of natural gas from the compressor to the nitrogen line. Nitrogen was supplied to the recycle compressor as a seal gas during defrosting operations. The valves on the nitrogen line that were kept open during defrosting operation were not closed after completing the operation. This resulted in the over-pressurization of the compressor with up to 250 - 350 psig of natural gas. Natural gas entered the nitrogen header, which was at 75 psig. The pneumatically controlled instruments were being operated with nitrogen due to the failure of the instrument-air compressor. The instruments vented their contents into the atmosphere at the control panel. Natural gas entered the control room through the nitrogen header and accumulated in the control room, where operators were allowed to smoke. The explosion occurred while an operator was trying to light a cigarette.

6. February, 1973 Staten Island, New York, USA LNG Peakshaving Facility - Construction Accident, no LNG present Proper precautions have been common place in all of the LNG facilities built and placed in service ever since Cleveland. Between the mid-1960s and mid- 1970s more than 60 LNG facilities were built in the United States. These peak-shaving plants have had an excellent safety record. This construction accident has consistently been used by opponents of LNG as a case-in-point to depict the danger of LNG, after all, “40 persons lost their lives at an LNG facility.”

5 See Section 3.1 of CH·IV’s “Introduction to LNG Safety,” Short Course on LNG Rollover.

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Here’s the story – One of Texas Eastern Transmission Corporation’s (TETCO) LNG storage tanks on Staten Island had been in service for over three years when it was taken out of service for internal repairs. The tank was warmed, purged of the remaining combustible gases with inert nitrogen, and then filled with fresh recirculating air. A construction crew entered the tank to begin repair work in April of 1972. Ten months later, in February of 1973, an unknown cause ignited the Mylar liner and polyurethane foam insulation inside the tank. Initial standard operating procedures called for the use of explosion-proof equipment within the tank, however non-explosion proof irons and vacuum cleaners were being used for sealing the liner and cleaning insulation debris. It is assumed that an electrical spark in one of the irons or vacuum cleaners ignited the Mylar liner. The rapid rise in temperature caused a corresponding rise in pressure inside the tank. The pressure increase lifted the tank’s concrete dome. The dome then collapsed killing the 40 construction workers inside.

The subsequent New York City Fire Department investigation6 concluded that the accident was clearly a construction accident and not an LNG accident. This has not prevented LNG’s opponents from claiming that since there may have been latent vapors from the heavy components of the LNG that was stored in the tank, then it was in fact an LNG incident.

7. March, 1977 Algeria LNG Export Facility A worker at the Camel plant was frozen to death when he was sprayed with LNG, which was escaping from a ruptured valve body on top of an in-ground storage tank. Approximately 1,500 to 2,000 m3 of LNG were released, but the resulting vapor cloud did not ignite. The valve body that ruptured was constructed of cast aluminum. The current practice is to provide valves in LNG service that are made with stainless steel.

8. March, 1978 Das Island, United Arab Emirates LNG Export Facility A bottom pipe connection of an LNG tank failed resulting in an LNG spill inside the LNG tank containment. The liquid flow was stopped by closing the internal valve designed for just such service. A large vapor cloud resulted and dissipated without ignition. No injuries or fatalities were reported.

6 "Report of Texas Eastern LNG Tank Fatal Fire and Roof Collapse, February 10, 1973," Fire Department of the City of New York, July, 1973

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9. October, 1979 Cove Point, Maryland, USA LNG Import Terminal The Cove Point LNG Receiving Terminal in Maryland began operations in the spring of 1978. By the fall of 1979, Cove Point had unloaded over 80 LNG ships. In 1979, a tragic accident occurred at Cove Point that took the life of one operator and seriously burned another. Around 3:00 AM on October 6, 1979, an explosion occurred within an electrical substation at Cove Point. LNG had leaked through an inadequately tightened LNG pump electrical penetration seal, vaporized, passed through 200 feet of underground electrical conduit, and entered the substation. Since natural gas was never expected in this substation, no gas detectors had been installed in the building. The natural gas-air mixture was ignited by the normal arcing contacts of a circuit breaker, resulting in an explosion. The explosion killed one operator in the building, seriously injured a second and caused about $3 million in damages. The National Transportation Safety Board (NTSB) found7 that the Cove Point Terminal was designed and constructed in conformance with all appropriate regulations and codes. It further concluded that this was an isolated incident, not likely to recur elsewhere. The NTSB concluded that it is unlikely that any pump seal, regardless of the liquid being pumped, could be designed, fabricated, or installed to completely preclude the possibility of leakage. With that conclusion in mind, building codes pertaining to the equipment and systems downstream of the pump seal were changed. Before the Cove Point Terminal was restarted, all pump seal systems were modified to meet the new codes and gas detection systems were added to all buildings.

10. April, 1983 Bontang, Indonesia LNG Export Facility - Maintenance Accident, no LNG present A major incident occurred on April 14, 1983 in Bontang, Indonesia. The main liquefaction column (large vertical shell-and-tube heat exchanger) in Train B ruptured due to overpressurization of the heat exchanger caused by a blind8 left in a flare line during start-up. All the pressure relief systems were connected to this line. The exchanger was designed to operate at 60 psig on the shell side. The gas pressure reached 180 psig causing the failure of the exchanger. Debris and coil sections were projected some 50 meters away. Shrapnel from the column killed three workers. The ensuing fire was extinguished in about 30 minutes. This incident occurred during dry-out and purging of the exchanger with warm natural gas prior to introducing any LNG into the system, so no LNG was actually involved or released.

7 “Columbia LNG Corporation Explosion and Fire; Cove Point, MD; October 6, 1979" National Transportation Safety Board Report NTSB-PAR-80-2, April 16, 1980 8 A flat plate temporarily installed between flanges during construction and/or maintenance to isolate equipment.

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11. 1987 Mercury, Nevada, USA Department of Energy Test Facility An accidental ignition of an LNG vapor cloud occurred at the DOE, Nevada Test Site on August 29, 1987. The large-scale tests involving spills of LNG on water were sponsored by the Department of Energy and Gas Research Institute to study the effectiveness of vapor fences in reducing the extent of downwind dispersion of LNG vapor clouds. The cloud accidentally ignited during Test #5 just after a sequence of relatively strong rapid phase transitions (RPTs) which damaged and propelled polyurethane pipe insulation outside the fence.

The official explanation was that a spark generated by static electricity approximately 76 seconds after the spill was the most likely source of ignition. An independent investigation on behalf of Gas Research Institute showed that a more likely source of ignition was oxygen enrichment between the surface of the LNG pipe and the combustible polyurethane foam insulation. Oxygen enrichment occurred during the long cool-down period with liquid nitrogen that preceded the LNG test. Such enrichment had been previously observed during tests carried out by an LNG tank design and manufacturing company. Impacts during the RPTs may have ignited the insulation but not the nearby fuel-rich vapor cloud. However, when a smoldering insulation fragment was propelled outside the fence by an RPT, it ignited the portion of the cloud that was within the flammable limits. The duration of the fire was 30 seconds. The flame length was about 20 feet above the ground.

There have been other accidental ignitions involving LNG during large-scale tests. • One occurred in England during large-scale fire tests being carried out by British Gas Corporation. Stray currents from a nearby radar station were blamed for prematurely igniting the primer that was eventually to be used to ignite the LNG cloud. • Another occurred in Japan during similar large-scale tests carried out by Japan Gas Association. The ignition mechanism was not explained. • During a test at a research facility near San Clemente, California, a sudden change in wind direction caused the vapor cloud to encounter a tractor that was moving some of the test equipment. The tractor ignited the vapor cloud, badly burning the driver. A researcher was also in the vapor cloud at the time of ignition. He was able to get out of the vapor cloud before the flame front reached him by running crosswind and was not injured.

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12. August, 1985 Pinson, Alabama, USA LNG Peakshaving Facility The welds on an 8 1/ 4-inch by 12-inch “patch plate” on a small aluminum vessel (3 ft in diameter by 7 ft tall) failed as the vessel was receiving LNG which was being drained from the liquefaction cold box. The plate was propelled into a building that contained the control room, boiler room, and offices. Some of the windows in the control room were blown inward and natural gas escaping from the failed vessel entered the building and ignited. Six employees were injured.

13. 1988 Everett, Massachusetts, USA LNG Import Terminal Approximately 30,000 gallons of LNG were spilled through “blown” flange gaskets during an interruption in LNG transfer at Distrigas. The cause was later determined to be “condensation induced water hammer.”9 The spill was contained in a small area, as designed. The still night prevented the movement of the vapor cloud from the immediate area. No one was injured and no damage occurred beyond the blown gasket. Operating procedures, both manual and automatic, were modified as a result.

14. 1989 Thurley, United Kingdom LNG Peakshaving Facility While cooling down the vaporizers in preparation for sending out natural gas, low-point drain valves were opened on each vaporizer. One of these drain valves had not been closed when the pumps were started and LNG entered the vaporizers. As a result, LNG was released into the atmosphere as a high- pressure jet. The resulting vapor cloud ignited about thirty seconds after the release began. The flash fire covered an area approximately 40 by 25 m. Two operators received burns to their hands and faces. The source of ignition was believed to be the pilot light on one of the other submerged combustion vaporizers.

15. 1993 Bontang, Indonesia LNG Export Facility An LNG leak occurred in the open run-down line during a pipe modification project. LNG entered an underground concrete oily-water sewer system and underwent a rapid vapor expansion that overpressured and ruptured the sewer pipes. No ignition of the vapor occurred, but the sewer system was substantially damaged.

9 See description in Section 3.1 of CH·IV’s “Introduction to LNG Safety”

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16. September, 2000 Savannah, Georgia, USA LNG Import Terminal In September 2000, a 580-foot ship, the Sun Sapphire, lost control in the Savannah River and crashed into the LNG unloading pier at Elba Island. The Elba Island facility was undergoing reactivation but had no LNG in the plant. The Sun Sapphire, carrying almost 20,000 tons of palm and coconut oil, suffered a 40-foot gash in her hull. The point of impact at the terminal was the LNG unloading platform. Although the LNG facility experienced significant damage, including the need to replace five 16" unloading arms, there was no indication that had LNG been present in the piping that there would have been a release. Given the geometry of the Savannah River at Elba Island, it is doubtful that had an LNG ship been present that a similar ramming could have penetrated the double hull and released any LNG.

17. January 19, 2004 Skikda, Algeria LNG Export Facility A leak in the hydrocarbon refrigerant system formed a vapor cloud that was drawn into the inlet of a steam boiler. The increased fuel to the boiler caused rapidly rising pressure within a steam drum. The rapidly rising pressure exceeded the capacity of the boiler's safety valve and the steam drum ruptured. The boiler rupture was close enough to the gas leak area to ignite the vapor cloud and produce an explosion and fireball. The fire took eight hours to extinguish. The explosions and fire destroyed a portion of the LNG plant and caused 27 deaths and injury to 72 more. No one outside the plant was injured nor were the LNG storage tanks damaged by the explosions. A joint report issued by the U.S. Federal Energy Regulatory Commission (FERC) and the U.S. Department of Energy (DOE) was issued in April 2004 under the title of “Report of the U.S. Government Team Site Inspection of the Sonatrach Skikda LNG Pant in Skikda, Algeria.” The primary findings in the report indicate that there were local ignition sources, a lack of “typical” automatic equipment shutdown devices and a lack of hazard detection devices.

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1. 1964/1965 25,500 M3 Jules Verne While loading LNG in Arzew, Algeria, lightning struck the forward vent riser of the ship and ignited vapor, which was being routinely vented through the ship venting system. Loading had been stopped when a thunderstorm broke out near the terminal but the vapor generated by the loading process was being released to the atmosphere. The shore return piping had not yet been in operation. The flame was quickly extinguished by purging with nitrogen through a connection to the riser.

A similar event happened early in 1965 while the vessel was at sea shortly after leaving Arzew. The fire was again extinguished using the nitrogen purge connection. In this case, vapor was being vented into the atmosphere during ship transit, as was the normal practice at that time.

2. May, 1965 27,400 M3 Methane Princess The LNG loading arms were disconnected before the liquid lines had been completely drained, causing LNG to pass through a leaking closed valve and into a stainless steel drip pan placed underneath the arms. Seawater was applied to the area. Eventually, a star-shaped fracture appeared in the deck plating in spite of the application of the seawater.

3. May, 1965 25,500 M3 Jules Verne On the fourth loading of Jules Verne at Arzew in May 1965 an LNG spill, caused by overflowing of Cargo Tank No.1, resulted in the fracture of the cover plating of the tank and of the adjacent deck plating. The cause of the overfill has never been adequately explained, but it was associated with the failure of liquid level instrumentation and unfamiliarity with equipment on the part of the cargo handling watch officer.

4. April 11, 1966 27,400 M3 Methane Progress Cargo leakage reported. No details.

5. September, 1968 5,000 M3 Aristotle Ran aground off the coast of Mexico. Bottom damaged. Believed to be in LPG service when this occurred. No LNG released.

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6. November 17, 1969 71,500 M3 Polar Alaska Sloshing of the LNG heel in No. 1 tank caused part of the supports for the cargo pump electric cable tray to break loose, resulting in several perforations of the primary barrier. LNG leaked into the interbarrier space. No LNG released.

7. September 2, 1970 71,500 M3 Arctic Tokyo Sloshing of the LNG heel in No. 1 tank during bad weather caused local deformation of the primary barrier and supporting insulation boxes. LNG leaked into the interbarrier space at one location. No LNG released.

8. Late 1971 50,000 M3 Descartes A minor fault in the connection between the primary barrier and the tank dome allowed gas into the interbarrier space. No LNG released.

9. June, 1974 27,400 M3 Methane Princess On June 12, 1974 the Methane Princess was rammed by the freighter Tower Princess while moored at Canvey Island LNG Terminal. Created a 3- foot gash in the outer hull. No LNG released.

10. July, 1974 5,000 M3 Barge Massachusetts LNG was being loaded on the barge on July 16, 1974. After a power failure and the automatic closure of the main liquid line valves, a small amount of LNG leaked from a 1-inch nitrogen-purge globe valve on the vessel’s liquid header. The subsequent investigation by the US. Coast Guard found that a pressure surge caused by the valve closure induced the leakage of LNG through the bonnet and gland of the 1-inch valve. The valve had not leaked during the previous seven or more hours of loading. Several fractures occurred in the deck plates. They extended over an area that measured about one by two meters. The amount of LNG involved in the leakage was reported to be about 40 gallons. As a result of this incident, The U.S. Coast Guard banned the Barge Massachusetts from LNG service within the U.S. It is believed that the Barge Massachusetts is now working in liquid ethylene service.

11. August, 1974 4,000 M3 Euclides Minor damage due to contact with another vessel. No LNG released.

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12. November, 1974 4,000 M3 Euclides Ran aground at La Havre, France. Damaged bottom and propeller. No LNG released.

13. 1974 27,400 M3 Methane Progress Ran aground at Arzew, Algeria. Damaged rudder. No LNG released.

14. September, 1977 125,000 M3 LNG Aquarius During the filling of Cargo Tank No. 1 at Bontang on September 16, 1977, LNG overflowed through the vent mast serving that tank. The incident may have been caused by difficulties in the liquid level gauge system. The high- level alarm had been placed in the override mode to eliminate nuisance alarms. Surprisingly, the mild steel plate of which the cargo tank cover was made did not fracture as a result of this spill.

15. August 14, 1978 124,890 M3 Khannur Collision with cargo ship Hong Hwa in the Strait of Singapore. Minor damage. No LNG released.

16. April, 1979 125,000 M3 Mostefa Ben Boulaid While discharging cargo at Cove Point, Maryland on April 8, 1979, a check valve in the piping system of the vessel failed releasing a small quantity of LNG. This resulted in minor fractures of the deck plating. This spill was caused by the escape of LNG from a swing-check valve in the liquid line. In this valve, the hinge pin is retained by a head bolt, which penetrates the wall of the valve body. In the course of operating the ship and cargo pumping system, it appears that the vibration caused the bolt to back out, releasing a shower of LNG onto the deck. The vessel was taken out of service after the incident and the structural work renewed. All of the check valves in the ship’s liquid system were modified to prevent a recurrence of the failure. A light stainless steel keeper was fashioned and installed at each bolt head. Shortly after the ship returned to service, LNG was noticed leaking from around one bolt head, the keeper for which had been stripped, again probably because of vibration. More substantial keepers were installed and the valves have been free from trouble since that time.

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17. April, 1979 87,600 M3 Pollenger While the Pollenger was discharging LNG at the Distrigas terminal at Everett, Massachusetts on April 25, 1979, LNG leaking from a valve gland apparently fractured the tank cover plating at Cargo Tank No. 1. The quantity of LNG that spilled was probably only a few liters, but the fractures in the cover plating covered an area of about two square meters.

18. June 29, 1979 125,000 M3 El Paso Paul Kayser Ran aground at 14 knots while maneuvering to avoid another vessel in the Strait of Gibraltar. Bottom damaged extensively. Vessel refloated and cargo transferred to sister ship, the El Paso Sonatrach. No LNG released.

19. December 12, 1980 125,000 M3 LNG Taurus Ran aground in heavy weather at Mutsure Anchorage off Tobata, Japan. Bottom damaged extensively. Vessel refloated, proceeded under its own power to the Kita Kyushu LNG Terminal, and cargo discharged. No LNG released.

20. Early 1980s 125,000 M3 El Paso Consolidated Minor release of LNG from a flange. Deck plating fractured due to low temperature embrittlement.

21. Early 1980s 129,500 M3 Larbi Ben M’Hidi Vapor released during transfer arm disconnection. No LNG released.

22. December, 1983 87,600 M3 Norman Lady During cooldown of the cargo transfer arms, prior to unloading at Sodegaura, Japan, the ship suddenly moved astern under its own power. All cargo transfer arms sheared and LNG spilled. No ignition.

23. 1985 35,500 M3 Isabella LNG released as a result of overfilling a tank. Deck fractured due to low temperature embrittlement.

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24. 1985 35,500 M3 Annabella Reported as “pressurized cargo tank.” Presumably, some LNG released from the tank or piping. No other details are available.

25. 1985 126,000 M3 Ramdane Abane Collision while loaded. Port bow affected. No LNG released.

26. February, 1989 40,000 M3 Tellier Wind blew ship from its berth at Skikda, Algeria. Cargo transfer arms sheared. Piping on ship heavily damaged. Cargo transfer had been stopped. According to some verbal accounts of this incident, LNG was released from the cargo transfer arms.

27. Early 1990 125,000 M3 Bachir Chihani A fracture occurred at a part of the ship structure, which is prone to the high stresses that may accompany the complex deflections that the hull encounters on the high seas. Fracture of the inner hull plating led to the ingress of seawater into the space behind the cargo hold insulation while the vessel was in ballast. No LNG released.

28. May 21, 1997 125,000 M3 Northwest Swift Collided with a fishing vessel about 400 km from Japan. Some damage to hull, but no ingress of water. No LNG released.

29. October 31, 1997 126,300 M3 LNG Capricorn Struck a mooring dolphin at a pier near the Senboku LNG Terminal in Japan. Some damage to hull, but no ingress of water. No LNG released.

30. September 6, 1999 71,500 M3 Methane Polar Engine failure during approach to Atlantic LNG jetty (Trinidad and Tobago). Struck and damaged Petrotrin pier. No injuries. No LNG released. 31. December 2002 87,000 M3 Norman Lady A U.S. nuclear submarine, the U.S.S. Oklahoma City, raised its periscope into the ship necessitating her withdrawal briefly from service for repairs due to penetration of outer hull allowing leakage of seawater. No LNG released

TD-02109 Page 17 of 20 Revision 7 – January 2005 H H C H H CH·IV International Safety History of International LNG Operations APPENDIX B Chronological Summary of Incidents Involving LNG Ships

Yuyo Maru No. 10 The following information pertains to a liquid petroleum gas tanker (LPG) which has a similar construction to an LNG tanker. The information was obtained from a Japanese marine registry record. The annotations [text] were added by the authors for clarity. This incident is included in this document to help illustrate the integrity of LNG tanks onboard LNG ships. There is much discussion today around the impact of a terrorist attack perpetrated on an LNG tanker.

The Motorship “Yuyo Maru No. 10” (gross tonnage of 43,723), laden with 20,831 MT of light naphtha, 20,202 MT of propane and 6,443 MT of butane, left Ras Tanura, in the Kingdom of Saudi Arabia, for Kawasaki, and the port of Keihin on October 22, 1974. While the vessel was sailing northward along the Naka-no Se Traffic Route in Tokyo Bay on November 9, she collided with the Motorship “Pacific Ares” (gross tonnage of 10,874), manned with a Taiwanese Master and 28 crew members, laden with 14,835 MT of steel products, en route from Kisarazu for Los Angeles, USA. The collision occurred about 13:37 hours on the same day slightly northward of the boundary line of the Naka-no Se Traffic Route.

As a result of the collision, the “Yuyo Maru No. 10” suffered a large hole at the point of collision, with her cargo naphtha [The naphtha was carried in its outer ballast tank (between the insulated LPG tanks and the hull of the ship). This is effectively what makes up the “double hull” with LNG ships. The LPG cargo tank was not penetrated. LNG tankers never carry any thing other than air or ballast (water) in these tanks.] instantly igniting into flames. As a result of the outflow of naphtha overboard, the sea surface on her starboard side literally turned into a sea of fire. The “Pacific Ares” showered with fire burst into flames in the forecastle and on the bridge. While explosions occurred one after another [naphtha, not propane], attempts were made to tow the “Yuyo Maru No 10”, outside the bay, but she ran aground in the vicinity of Daini Kaiho. She was successfully towed out of Tokyo Bay and sunk south of Nojima Saki on the afternoon of November 27 [Thirty-six days after the original collision.] by cannon, air bomb and torpedo attacks staged by the Maritime Self-Defense Force. [Please note “cannon, air bomb and torpedo attacks” were required to sink the ship. Other reports indicate that these attacks lasted one and a half days. The author has seen a black and white film of these attacks. It appeared that the LPG tanks were for the most part fully in tact prior to the attacks. The ship’s LPG vent stacks were melted down to just above the decks and on fire indicating that LPG remained within the storage tanks.]

On board the “Yuyo Maru No. 10”, five crew members were killed and seven others injured by this accident. The “Pacific Ares”, whose forward section was completely crushed and superstructures burned down, was later repaired. Her crew members were all killed except one person, who was injured but rescued.

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Safety History of International LNG Operations APPENDIX C Chronological Summary of LNG Tanker Truck Incidents

Date Location LNG Carrier 1. June 1971 Waterbury, VT Capitol Blowout, hit rocks by road, tore hole in tank, 20% spilled, no fire, remainder dumped. Single wall tanker? 2. August 1971 Warner, NH Gas, Inc. Driver fatigue, drove off road, rollover cracked fittings, small gas leak, no fire. 3. October 1971 N. Whitehall, WI Indianhead Head-on collision with truck. Gasoline and tire fire, no cargo lost. 4. October 1973 Raynham, MA Andrews & Pierce Truck side swiped parked car; brakes locked and trailer overturned. No cargo on- board, no fire 5. 1973 Rt. 80 & 95 JCT, NJ Chemical Leaman Driver couldn’t negotiate turn off. Rollover demolished tractor and severe damage to trailer. No fire. $40,000 damage to trailer. 6. February 1974 New Jersey Turnpike Gas, Inc. Faulty brakes caused wheel fire. Check valve cracked 5% leaked out. No fire. 7. February 1974 McKee City, NJ Gas, Inc. Loose valve leaked LNG during transfer operation. 8. January 1976 Chattanooga, TN LP Transport Rollover, no fire, caused by oil spill on exit ramp. Truck righted and continued delivery of cargo. 9. November 1975 Dalton, GA LP Transport Rollover, no fire. Driver swerved to avoid pedestrian, hit guardrail and rolled over and down an 80 foot bank. $18,000 damage to trailer. 10. September 1976 Pawtucket, RI Andrews & Pierce Car hit trailer at landing wheels, rollover, no LNG loss or fire. 11. April 1977 Connecticut Turnpike Chemical Leaman Truck parked (with blowout) hit by a tow truck in rear. No leak or fire. 12. July 1977 Waterbury, CT LP Transport “Single Wall” Lubbock hit in rear by tractor-trailer, axle knocked off. Rollover. No loss of cargo. 13. December 1977 I5 & I10, Los Angeles Western Gillet/SDG Rollover with little product loss, no vacuum loss, no fire. Driver had 3 broken ribs.

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Safety History of International LNG Operations APPENDIX C Chronological Summary of LNG Tanker Truck Incidents

Date Location LNG Carrier 14. February 1981 Barnagat, NJ LP Transport Driver failed to negotiate turn due to excessive speed on country road. Driver not hurt seriously. Loss of some product through relief valve resulted in serious damage to transport. 15. September 1981 Lexington, MA Andrews & Pierce Rollover, no fire, no product loss (empty), driver not seriously hurt. Extensive damage to transport. Cause: rain and poor road conditions. 16. October, 1993 Everett, MA TransGas Trailer slide off third wheel just before entering highway. No fire, no product loss 17. May 1994 Revere, MA TransGas Trailer over turned when trying to negotiate a traffic circle at too high of speed. No product loss, no fire. Trailer emptied into second trailer without incident. 18. October 1998 Woburn, Ma TransGas Trailer traveling at high speed is sideswiped by car then careens into guardrail ripping open diesel fuel tanks. Ensuing diesel fuel fire traps driver in cab where he perishes. Fire engulfs LNG trailer until extinguished. No loss of product experienced. LNG partially transferred to second trailer. Trailer then uprighted and sent to transport yard to complete the transfer of product. 19. September 2003 Woburn, Ma TransGas Trailer traveling too fast on a highway exit ramp overturned. There was no leakage of cargo from the overturned truck. The truck driver was slightly injured and received a speeding citation.

Note: The last four incidents were reported on television and/or presented in the local Boston print media. In every case the media attempted to create a disaster scenario using meaningless phases such as “blast zone” and “police cruisers turned off lights to prevent explosions.” In one case a totally misinformed fire chief stated that the situation was “potentially a giant bomb. . . . An explosion would devastate a half- mile in all directions.” One of the worst “facts” reported was that “water was hosed onto the tanker to keep the LNG cool”!

TD-02109 Page 20 of 20 Revision 7 – January 2005 Siting LNG Terminals in the Californias - What is a Good Project from Safety and Environmental Viewpoint?

Bill Powers, P.E. Border Power Plant Working Group www.borderpowerplants.org

1 What is California’s History with Onshore LNG Terminals? • California LNG Terminal Act of 1977 (later rescinded): • Transfers authority to permit one LNG terminal from CA Coastal Commission (CCC) to CPUC • CCC directed to survey and rank terminal sites • Maximum population density 10 people per sq. mi to one mile from fenceline, 60 people per sq. mi to four miles from fenceline • Same density standard for LNG shipping lanes • Power of eminent domain granted to terminal operator to maintain low population densities 2 What was Rationale for Population Density Restrictions?

“The Legislature’s 4-mile restriction was apparently based on estimates of the skin burn radiation limits from a major fire resulting from a large LNG spill at the terminal. This 4-mile criterion does not specifically address the possible travel of an unignited LNG vapor cloud beyond four miles.” Spills of 25,000 m3 and 125,000 m3 of LNG were evaluated.

Source: CCC, Final Report Ranking LNG Terminal Sites, May 24, 1978, p. 68. 3 Have Proposed California LNG Terminal Sites Been Considered Before? • 1978 California Coastal Commission report, “Final Ranking of LNG Terminal Sites,” 82 sites evaluated, all but 4 sites rejected. • Evaluation criteria: population density, land and water site characteristics, maritime conditions, seismic activity, and coastal resources • L.A. Harbor site was rejected, due to population density and siesmic concerns • Humbolt Bay site rejected due to populaton

density 4 Have Offshore LNG Terminals Been Considered Before? • CCC Resolution - WHEREAS, it is possible that one or more offshore sites and terminal types could prove more appropriate than the best onshore site and terminal type, considering safety, cost, timing and the policies of the (1976) Coastal Act . . . . • Most appropriate offshore site - international waters (Ventura Flats) off the coast of Ventura County. • Minimal adverse impacts on sensitive marine resources and public recreation along the coast. • Offshore Long Beach identified as good potential site. CCC, Final Report Evaluating and Ranking LNG Terminal Sites, May 24, 1978, p. 57. CCC, Offshore LNG Terminal Study, September 15, 1978 5 Is There a Cost Difference Between Onshore and Offshore LNG Terminals? Project Sendout Capital Cost (bcfd) ($ millions) Shell/Sempra 1.3 600 ChevronTex (offshore) 1.0 650 Marathon/Golar 0.75 550 Mitsubishi 0.75 400 BHP Billiton (offshore) 1.5 600

6 How Does U.S. Law Address LNG Terminal Safety?

• Pipeline Safety Act Amendments of 1979: • Government Accounting Office (GAO), investigative arm of Congress, states before Senate “We believe remote siting is the primary factor in safety” (for LNG and LPG terminals) • GAO recommendation incorporated in 1979 Act

Source: Mobile Register article, Nov. 16, 2003

7 Is Remote Siting of LNG Terminals Required by Law? • Pipeline Safety Act Amendments of 1979: • Final bill states “Secretary of Transportation shall prescribe minimum safety standards for deciding on the location of a new LNG facility • The law lists six factors the Secretary must consider in setting these minimum standards • Factor No. 6 states “the need to encourage remote siting” • Factor No. 6 not incorporated into implementing regulations, according to author of legislation

Source: Mobile Register article, Nov. 16, 2003 8 What is Intent of Legislation Regarding Terminal Safety?

Federal officials appear to be ignoring a congressional mandate designed to discourage construction of liquefied natural gas terminals in populated areas, according to U.S. Rep. Ed Markey, D-Mass., author of the 1979 House bill outlining minimum safety standards for such facilities.

Source: Mobile Register article, Nov. 16, 2003

9 How Does FERC Define Worst Case Accident Scenario? • A break in one LNG transfer arm that last for 10 minutes. Total spill is ~550,000 gallons. This represents less than 1.5% of the capacity of one LNG storage tank. • The LNG tanker, often considered the most vulnerable element at the terminal, is not included in the risk analysis. • The LNG terminal owner must demonstrate via approved model that the distance to significant radiation impact is within the terminal property line.

10 What is a Worst Case LNG Tanker Accident Scenario?

• Scientific consensus is that rupture of a single 25,000 m3 LNG tanker sphere would create a fire at least 1/2 mile wide, with significant radiation impact another 1/2 mile out from the fire’s edge. • There are five 25,000 m3 LNG spheres on a typical LNG tanker- a fire involving all five tanks would be considerably larger than the single sphere example.

Source: Union of Atomic Scientists Bulletin article, LNG: Safety in Science, Jan/Feb 2004, pg. 30.

11 Test of LNG Spill

12 Combustion of 40 m3 of LNG

13 Form of LNG Vapor Cloud/Fire

14 What is Vulnerability of Sites with LNG Storage Tanks and Propane/Ethane Spheres? • “A moderately sized commercial aircraft would penetrate the three-foot thick concrete secondary LNG storage tank containm could also be vulnerable to attack from land- or ship-borne weapons.” • “Two 12-million gallon propane tanks near ent shell. The tanks Sacramento where identified for attack in 1998. The perpetrators were caught in the planning stages.” Source: City of Vallejo, LNG in Vallejo: Health and Safety Issues, Draft 6 Final Report, Jan. 8, 2003, pg. 45. 15 What is Homeland Security’s View on LNG Terminal Vulnerability? Dept. of Homeland Security Nov. 21, 2003 warning of increased risk of terrorist attacks: Of particular concern is “al-Queda’s continued interest in aviation, including other hazardous materials facilities,” using cargo jets” to attack infrastructure such as bridges and dams “as well as , chemical and targeting liquid natural gas the Department said in a statement.

16 Are FERC LNG Accident Modeling Scenarios Conservative? • “The author of a study (Quest) used by federal officials to demonstrate that LNG facilities pose few hazards for cities like Mobile has now written those officials to warn that his study cannot be used in that way.” • “Federal officials have used the Quest study in public hearings, federal documents and in letters to members of Congress to suggest that fires stemming from an LNG tanker accident would endanger only a small area around the ship.” Source: Mobile Register article, December 4, 2003 17 Recent Federal Developments - LNG Terminal Risk Evaluation • December 2003 - DOE Sec. Abraham instructs DOE’s Sandia National Laboratory (SNL) to conduct review of LNG safety studies amid controversy that federal officials had misused several LNG studies to open LNG import the side of inclusion rather than speed.” terminals in populated areas. Original SNL study narrowly focused. • January 23, 2004 - DOE announces the SNL LNG safety study will be greatly expanded, “to err on

18 Source: Mobile Register article, January 24, 2004 Recent State and International Siting Developments • Jan. 14, 2004 - Gov. Bob Riley (AL) states intention to block sale of Mobile Bay port site to ExxonMobil untilscenario.” independent safety study conducted. Urges FERC to consider “most credible worst case [Alternative - offshore]. • Jan. 20, 2004 - Explosion/fire at LNG complex in Algeria, three liquefaction trains destroyed • Jan. 27, 2004 - Incident will generate misinformed perceptions, doubts incident will influence FERC actions (Oil & Gas Journal). Sources: Mobile Register article, January 15, 2004; Oil & Gas Journal article, January 27, 2004. 19 How are LNG Projects in the Region Being Designed? Project Location Regas Distance to method pop. density > 60 sq. mi. Shell/Bechtel onshore SCV 1 -withdrawn- Calpine onshore unknown 1 Humbolt Bay -controversial- BHP Billiton floating SCV 20+ 20 mi. off Oxnard offshore Mitsubishi onshore process <2 Long Beach Harbor water -controversial-

20 How are LNG Projects in the Region Being Designed? Project Miles to Location Distance to border pop. density > 60 sq. mi. Sempra 40 onshore 2.5 -permit on hold- Shell 40 onshore 3 -permit on hold- Conoco/El Paso 15 onshore <1 -permit denied- ChevronTexaco 10 offshore 6 -sanctuary issue- Marathon/Golar 3 onshore <1 -controversial-21 Have There Been Any LNG Storage Accidents?

Source: Vallejo LNG Safety Study (draft), January 8, 2003 Date Place Description 1988 Boston ~30,000 gallons of LNG spilled during interruption in LNG tranfer. Blown flange gaskets caused by “water hammer,” spill contained. Still air conditions prevented movement of vapor cloud. 1978 Das Is., Failed bottom connection, LNG drains UAE into containment. Vapor cloud, no fire. 1944 Cleveland LNG tank rupture, no containment, fire. 128 dead, hundreds injured. Tank metallurgy problem caused rupture. 22 Have There Been Any LNG Shipping Accidents? Date Place Description 2000 Elba Cargo ship loses control and hits LNG Island, GA unloading pier. Not operational at time. Five 16-inch unloading arms replaced. 1999 Trinidad/ Engine failure during approach to LNG Tobago jetty. Ship struck and damaged pier. 1989 Algeria Wind blows ship from pier. All transfer arms sheared, piping on ship heavily damaged. LNG released, no fire. 1983 Japan Prior to unloading, ship suddenly moves astern under own power. All transfer arms sheared and LNG spilled, no fire. 23 Are Double-Hulled LNG Tankers Impregnable? A double-hulled french oil tanker was attacked off Yemen in late 2002: • Explosion rips large hole in French crude oil supertanker Limburg • Small boat loaded with explosives caused damage • Both hulls breached, vessel set on fire

Source: BBC News Online article, Oct. 6, 2002

24 Long Beach Harbor Site: Supply Flexibility vs. Increased Hazard Potential at Terminal Site • Processing plant included onsite to remove “hot gas” components, propane and ethane, so LNG can meet SoCalGas, ARB CNG specs. • Hazard - propane (explosive) and ethane stored onsite in 85-foot diameter spheres near LNG storage tanks. • Hazard - up to 140 tractor-trailer trucks required to move propane/ethane offsite.

25 Source: Sound Energy Solutions, Resource Report 9, Long Beach LNG Import Project What is “Hot” (High Btu) LNG?

O Characteristics of available Pacific Rim LNG - high Btu (>1,100 Btu/ft3), high ethane.

O Far Eastern LNG customers want high Btu content, these customers drive LNG business. 3 O SoCal Rule 30: heat content < 1,150 Btu/ft

O ARB CNG fuel spec: ethane < 6 percent

O Investment risk issue - Who will pay to “cool” the hot gas to meet CA specs? Liquefaction plant? Receiving terminal?

26 What is Air Emissions Impact of “Hot” Natural Gas?

O Millions of space heaters, hot water heaters, stoves with no controls to adjust for increase in natural gas Btu content.

O For these units, NOx increase roughly proportionate to Btu content increase.

O SCAQMD test program - increased Btu content 3 from 1,000 to 1,150 Btu/ft , NOx increased 20%. O Not a major issue for combustion systems with adjustable controls (GTs, boilers, engines).

27 Possible Upstream Source(s) of LNG and Environmental Issues

Project LNG Environmental Issues Source Shell or Sakhalin 600 km. long pipeline along length of Mitsubishi (Russia) or Sakhalin, offshore gas field in area considered key habitat for critically Australia endangered Pacific Gray Whale Sempra Peru or Ex-Im Bank denied loan guarantee Bolivia request (8/29/03) citing damage to Peruvian rainforest, Bolivia opposes Chile as LNG shipping point – War of Pacific Marathon/ Sulawesi, MOU with Pertamina to receive LNG Golar Indonesia from new plant on Sulawesi

28 Gaseous Fuel Accidents and Mexico - Population Sensitized to Fuel Storage Site Hazards Site Year Fuel Dead Injured Mexico City 1984 LPG 650 6,400 Fire/explosion (same site) 1996 LPG 4 unknown Guadalajara 1992 mixed 170 500 Tank leakage – fire Chiapas 1996 natural 630 Cactus gas plant - gas gas leakage – explosion/fire

29 Use of Large Amounts of Seawater for Regas Controversial

O All 4 existing continental U.S. regas terminals use portion of LNG for regas (1 - 1.5% of throughput)

O New coastal/river power plants prohibited from using once-through cooling. EPA 316(b) rule. Oil/gas production facilities, including LNG terminals, will be brought into program.

O SEMARNAT denied license to proposed 450 MW power plant at Baja Shell/Sempra LNG site in 2000 - impacts of seawater cooling on marine life cited.

O ChevronTexaco and Shell/Sempra proposing

seawater regas in Baja. 30 California Natural Gas Demand Issues

O SoCalGas/SDGE Dec. 2003 projection: decline through ~2010, rebound to 2002 level in 2016.

O Backbone of California power generation is fleet of aging, inefficient utility boilers. Accelerated replacement with combined-cycle plants could reduce demand by 400 to 500 mmcfd in short- and mid-term.

O Policy question: Spend $4 billion for one LNG supply chain or $4 billion to repower fleet, and potentially eliminate need for terminal? 31 LNG - Bridge to Renewable Energy Future? Do We Need the Bridge?

O California renewables generation target of 20% by 2017.

O Interest in accelerating 20% target to 2010.

O Little short- or mid-term potential demand for greenfield (other than replacement) gas- fired power plants if state chooses ambitious renewables track.

32 Conclusions

O Major ongoing controversy over appropriate worst case accident/event to use for siting onshore LNG regas terminals.

O All onshore regas projects encountering resistance in the Californias

O Offshore terminal with no seawater regas minimizes safety and marine impact concerns.

O Significant distance from coast (> 10 miles)

minimizes visual impact concerns. 33