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November 10, 2004 British Columbia Utilities Commission Sixth Floor - 900 Howe Street Vancouver, B.C. V6Z 2N3 Attention: Mr. Robert J. Pellatt, Commission Secretary Dear Sir: RE: Terasen Gas (Vancouver Island) Inc. (“TGVI”)
Review of Resource Plan and an Application for a Certificate of Public Convenience and Necessity (“CPCN”) for a Liquefied Natural Gas Storage Project Hearing Exhibits
Terasen Gas (Vancouver Island) Inc. respectfully submits the following exhibits for the hearing:
• List of Panel Members and Panel Issues • Witness Data • Stakeholder Workshop Presentation for October 22, 2004
Twenty hard copies of the attached will be sent to the Commission office by Friday, November 12, 2004. Yours very truly, TERASEN GAS (VANCOUVER ISLAND) INC. Original signed by Tom Loski
For: Scott A. Thomson Attachment cc. Registered Intervenors
Scott A. ThomsonVice President, Finance & Regulatory Affairs 16705 Fraser Highway Surrey, B.C. V3S 2X7 Tel: (604) 592-7784 Fax: (604) 592-7890 Email: [email protected] www.terasengas.com
TERASEN GAS (VANCOUVER ISLAND) INC.
RESOURCE PLAN FOR VANCOUVER ISLAND AND SUNSHINE COAST
APPLICATION FOR A CERTIFICATE OF PUBLIC CONVENIENCE AND NECESSITY FOR A LIQUEFIED NATURAL GAS STORAGE PROJECT
WITNESS PANEL MEMBERS
Panel Panel Name Witness Title
Cynthia Des Brisay Director, Business Development
David Bennett Director, Energy Management Services
1 Resource Plan
James Wong Manager, Forecasting
Bill Manery Director,
Project Assessment
Guy Wassick Project Manager, LNG
Gareth Jones Manager, Project Assessment
2 Technical
Mike Davies Manager, Business Development
Douglas Stout Vice President,
Gas Supply and Transmission
Cynthia Des Brisay Director, Business Development
Mike Davies Manager, Business Development
David Bennett Director, Energy Management Services
3 Project Justification
Tom Loski Director, Regulatory Affairs
TERASEN GAS (VANCOUVER ISLAND) INC.
RESOURCE PLAN FOR VANCOUVER ISLAND AND SUNSHINE COAST APPLICATION FOR A CERTIFICATE OF PUBLIC CONVENIENCE AND NECESSITY
FOR A LIQUEFIED NATURAL GAS STORAGE PROJECT
WITNESS PANEL ISSUES
Panel Panel Name Issue
1 Resource Plan
RP1. TGVI Resource Planning Process RP2. Resource Plan Objectives and Measures RP3. Design Day, Design Year and Normal Year Demands for Core Market RP4. Core Market Annual Demand Forecast RP5. Load Forecasts for Other Customers RP7. DSM Programs RP8. Pipeline to Whistler
2 Technical
LNG1. LNG Site Selection LNG2. LNG Facility LNG3. LNG Project LNG6. Development of Resource Addition Portfolios
3 Project Justification
RP6. Industrial Curtailment and Peaking Supply LNG4. System Balancing & Other Benefits LNG5. Contractual Commitments LNG7. Analysis of Resource Addition Portfolios LNG8. Rate Impacts
TERASEN GAS (VANCOUVER ISLAND) INC.
RESOURCE PLAN FOR VANCOUVER ISLAND AND SUNSHINE COAST APPLICATION FOR A CERTIFICATE OF PUBLIC CONVENIENCE AND NECESSITY
FOR A LIQUEFIED NATURAL GAS STORAGE PROJECT
NOVEMBER 17 – 26, 2004 HEARING NANAIMO, BC
Witness Data
NAME: Cynthia Des Brisay
TITLE: Director, Business Development; Gas Supply & Transmission
PANEL # 1 and 3
EDUCATION / WORK BACKGROUND B. Engineering in Chemistry, Queen’s University MBA, University of B.C. Employed with Terasen Gas over the past 5 years, with prior experience in the energy sector.
TERASEN GAS (VANCOUVER ISLAND) INC.
RESOURCE PLAN FOR VANCOUVER ISLAND AND SUNSHINE COAST APPLICATION FOR A CERTIFICATE OF PUBLIC CONVENIENCE AND NECESSITY
FOR A LIQUEFIED NATURAL GAS STORAGE PROJECT
NOVEMBER 17 – 26, 2004 HEARING NANAIMO, BC
Witness Data
NAME: David Bennett
TITLE: Director, Energy Management Services; Gas Supply & Transmission
PANEL # 1 and 3
EDUCATION / WORK BACKGROUND B. Sc. in Economics and Computer Science, University of Victoria Employed with Terasen Gas and predecessor companies, and held previous positions in Marketing, Planning, and Gas Supply. Previously testified before the British Columbia Utilities Commission.
TERASEN GAS (VANCOUVER ISLAND) INC.
RESOURCE PLAN FOR VANCOUVER ISLAND AND SUNSHINE COAST APPLICATION FOR A CERTIFICATE OF PUBLIC CONVENIENCE AND NECESSITY
FOR A LIQUEFIED NATURAL GAS STORAGE PROJECT
NOVEMBER 17 – 26, 2004 HEARING NANAIMO, BC
Witness Data
NAME: James Wong
TITLE: Manager, Forecasting; Marketing
PANEL # 1
EDUCATION / WORK BACKGROUND MBA, Simon Fraser University B. Comm., University of British Columbia Certified General Accountant Employed with Terasen Gas and predecessor companies for 13 years, and held previous positions in Finance, Gas Supply and Marketing.
TERASEN GAS (VANCOUVER ISLAND) INC.
RESOURCE PLAN FOR VANCOUVER ISLAND AND SUNSHINE COAST APPLICATION FOR A CERTIFICATE OF PUBLIC CONVENIENCE AND NECESSITY
FOR A LIQUEFIED NATURAL GAS STORAGE PROJECT
NOVEMBER 17 – 26, 2004 HEARING NANAIMO, BC
Witness Data
NAME: Bill Manery
TITLE: Director, Project Assessment; Gas Supply & Transmission
PANEL # 2
EDUCATION / WORK BACKGROUND B. Sc. in Mechanical Engineering, University of Calgary, 1969 Professional Engineer, Association of Professional Engineers and Geoscientists of B.C. Employed with Terasen Gas and predecessor companies, and held previous positions in Operations and Engineering. Project Director for the Southern Crossing Pipeline Project completed in 2000. Previously testified before the British Columbia Utilities Commission.
TERASEN GAS (VANCOUVER ISLAND) INC.
RESOURCE PLAN FOR VANCOUVER ISLAND AND SUNSHINE COAST APPLICATION FOR A CERTIFICATE OF PUBLIC CONVENIENCE AND NECESSITY
FOR A LIQUEFIED NATURAL GAS STORAGE PROJECT
NOVEMBER 17 – 26, 2004 HEARING NANAIMO, BC
Witness Data
NAME: Guy Wassick
TITLE: Project Manager, LNG; Gas Supply & Transmission
PANEL # 2
EDUCATION / WORK BACKGROUND B.A.Sc. in Mechanical Engineering, University of B.C., 1976 Professional Engineer, Association of Professional Engineers and Geoscientists of B.C. Employed with Terasen Gas and predecessor companies, and held previous positions in Operations and Engineering. Project Manager for the compressor installations for the Southern Crossing Pipeline Project and Langley Compressor, both completed in 2000.
TERASEN GAS (VANCOUVER ISLAND) INC.
RESOURCE PLAN FOR VANCOUVER ISLAND AND SUNSHINE COAST APPLICATION FOR A CERTIFICATE OF PUBLIC CONVENIENCE AND NECESSITY
FOR A LIQUEFIED NATURAL GAS STORAGE PROJECT
NOVEMBER 17 – 26, 2004 HEARING NANAIMO, BC
Witness Data
NAME: Gareth Jones
TITLE: Manager, Project Assessment; Gas Supply & Transmission
PANEL # 2
EDUCATION / WORK BACKGROUND B. Sc. in Mechanical Engineering, University of Alberta, 1981 Queen’s Executive program, Queen’s University, 1998 Professional Engineer, Association of Professional Engineers and Geoscientists of B.C. Professional Engineer, Association of Professional Engineers, Geologists and Geophysicists of Alberta Employed with Terasen Gas and predecessor companies for 14 years, and held previous positions in Operations and Engineering. Previously testified before the British Columbia Utilities Commission.
TERASEN GAS (VANCOUVER ISLAND) INC.
RESOURCE PLAN FOR VANCOUVER ISLAND AND SUNSHINE COAST APPLICATION FOR A CERTIFICATE OF PUBLIC CONVENIENCE AND NECESSITY
FOR A LIQUEFIED NATURAL GAS STORAGE PROJECT
NOVEMBER 17 – 26, 2004 HEARING NANAIMO, BC
Witness Data
NAME: Michael Davies
TITLE: Manager Business Development
PANEL # 2 and 3
EDUCATION / WORK BACKGROUND MBA, Simon Fraser University B. A. Sc. in Mechanical Engineering, University of B.C. Professional Engineer, Association of Professional Engineers and Geoscientists of B.C. Employed with Terasen Gas and predecessor companies for 14 years.
TERASEN GAS (VANCOUVER ISLAND) INC.
RESOURCE PLAN FOR VANCOUVER ISLAND AND SUNSHINE COAST APPLICATION FOR A CERTIFICATE OF PUBLIC CONVENIENCE AND NECESSITY
FOR A LIQUEFIED NATURAL GAS STORAGE PROJECT
NOVEMBER 17 – 26, 2004 HEARING NANAIMO, BC
Witness Data
NAME: Douglas Stout
TITLE: Vice President, Gas Supply & Transmission
PANEL # 3
EDUCATION / WORK BACKGROUND MBA, University of Alberta B.Sc. in Civil Engineering, University of Alberta Employed with Terasen Gas over the past 3 years, with prior experience in the energy sector. Previously testified before the British Columbia Utilities Commission.
TERASEN GAS (VANCOUVER ISLAND) INC.
RESOURCE PLAN FOR VANCOUVER ISLAND AND SUNSHINE COAST APPLICATION FOR A CERTIFICATE OF PUBLIC CONVENIENCE AND NECESSITY
FOR A LIQUEFIED NATURAL GAS STORAGE PROJECT
NOVEMBER 17 – 26, 2004 HEARING NANAIMO, BC
Witness Data
NAME: Tom Loski
TITLE: Director, Regulatory Affairs
PANEL # 3
EDUCATION / WORK BACKGROUND
Certified Management Accountant, 1985 Diploma of Technology – Finance Option, BCIT, 1980 Employed with Terasen Gas and predecessor companies for 22 years, and held previous positions in Gas Supply, Finance and Marketing. Previously testified before the British Columbia Utilities Commission.
Contact Information Tom LoskiDirector,Regulatory Affairs
Tel: (604) 592-7464Fax: (604) 592-7890E-mail: [email protected]
Terasen Gas (Vancouver Island) Inc. Resource Plan and LNG Storage
Project CPCN Application
Stakeholder WorkshopFriday, October 22, 2004
Vancouver, B.C.
2
Workshop Agenda Introduction Tom Loski 5 minsOverview Doug Stout 15 minsLNG Plant Bill Manery/Guy Wassick 25 minsQuestions 15 minsResource Planning Process James Wong 10 minsCore Demand Forecast James Wong 20 minsTransport Customer Forecast David Bennett 15 minsQuestions 15 minsResource Portfolios Mike Davies 20 minsGas Supply Benefits & LNG Services David Bennett 20 minsFinancial Justification Cynthia Des Brisay 20 minsQuestions 15 minsNext Steps Tom Loski 10 mins
Guy WassickProject Manager, LNG
Bill ManeryProject Director, LNG
Terasen Gas(Vancouver Island) Inc.
LNG Project
2
Agenda
• LNG Industry in General• Site Selection and Public Consultation• Environmental Assessment• LNG Process and Design• Project Schedule• Project Cost• Project Contracting
3
What Is LNG?
• LNG (liquefied natural gas) is natural gas cooled until it condenses into a clear liquid.
• LNG is stored at -162o Celsius (-260o F) at atmospheric pressure in a “thermos” like storage container.
• LNG takes up far less space – about 1/600th of its original volume as a gas.
• LNG (the liquid itself) is not flammable or explosive.
• When LNG is warmed it evaporates and becomes a lighter-than-air gas and is flammable only when it occurs in a 5% to 15% concentration in air.
4
Types of LNG Storage
• Peak ShavingSmall storage capacity, send out only on peak days, connected to a pipeline with liquefaction and vaporization capability
• Base Load, Import/Export TerminalLarge storage capacity, liquefaction or send out every day, supplied to/by marine tanker with either liquefaction or vaporization capability
• Satellite PlantsFor peaking or smaller base load send out, supplied by truck transport, with vaporization capability only
• Transportation FuelCars, trucks, buses
5
The LNG Industry
• There are over 240 LNG storage facilities operating in the world.
• In North America there are approximately 110 peak shaving facilities (3 located in Canada) and 4 import/export terminals.
• LNG storage tanks are insulated tanks, operating at atmospheric pressure and constructed of 9% nickel steel; no tank of this design has failed in service anywhere in the world.
6
LNG Plants – North America
7
Tilbury Island (Delta, B. C.)“Peak shaving” LNG Plant (1970) - 0.6 bcf
8
Site Selection Process
• Terasen Gas examined a strip of land 5 km on either side of the main natural gas transmission pipeline from the Courtenay area down to the Langford area to locate a storage facility of up to 1.5 bcf.
• Based on this analysis, 25 potential sites were identified.
• Further analysis of slope, geotechnical characteristics, view sheds and pipeline system hydraulics reduced potential sites to seven, then to three.
9
7 - Short Listed Sites
10
Final Site – Near Ladysmith
LNG Storage
• Proposed facility– Storage 1bcf– Send-out 100
mmcf/d– Liquefaction
5mmcf/d
• 6km NW of Ladysmith, West of Mt. Hayes
• Located near load center on Southern Vancouver Island
11
Storage Plant Location
12
Consultation Process
TGVI undertook a comprehensive public consultation process over a period of 12 months which included the following key elements.
• Letters to stakeholders• Meetings with and presentations to stakeholders• 2 focus groups • 3 Open Houses• CVRD sponsored Public Meeting • Environmental and Social Review (ESR)• CVRD Public Hearing
Site re-zoning approved by CVRD May 26/04
13
Storage Plant Site Details
New zone is U-1, LNG Storage Utility
• 42.7 ha rezoned• 12 ha plant site• 20 ha, western and eastern buffers, beyond
rezoned area will be retained in forestry operations
• Total 82 ha owned or controlled by TGVI
Zoning allows up to 2 – 1.5 bcf tanks; future expansion could occur on the site
14
Private Property Purchased
Property to be purchased
142 ha
15
Rezoned Area
42 ha
Rezoned
Area
16
Proposed Storage Plant Area
Plant area
12 ha
17
Total Land Owned or Controlled
Exclusion Zone
Total area 82 ha
18
Environmental Assessment:Key Human Impact Findings
Location of the site in an isolated area mitigates most human and safety impacts
• 3 km from facility to nearest dwelling• Traffic effects on existing roads limited to
construction period• Little impact on forestry or recreation• Aesthetics and noise impacts minimal
-3 kms to nearest dwelling-Landscape is already heavily disturbed
• Domestic water supplies unaffected-Outside of aquifer recharge areas
19
Environmental Assessment:Key Biophysical Findings
The site is privately owned and has already been disturbed, reducing impacts on physical and biological environment
• Site is mostly clearcut• Site is geologically stable• Aquatic and vegetation impacts can be mitigated• Intermittent streams (non fish bearing) will be
channelized, a pond created, replacing the present bog
• No effect on fish• Little effect on wildlife
20
Economic Impacts
LNG facility will positively impact and help to diversify the existing economy.
Total construction expenditures $94.4 Million• $28.7 M of local expenditures, $41.7 in British
Columbia • 240 local jobs (100 direct, 140 indirect, induced)
Facility operation provides 9 full-time jobs• $150,000/year in goods and services expenditures• $300,000/year in property taxes
21
Site PhotographMt. Hayes in background - view to east
Tank Location
22
Artist Rendering
23
Tilbury Island (Delta, B. C.)“Peak shaving” LNG Plant – 0.6 bcf
24
Major Components OfPeakshaving LNG
• Liquefaction(freezer)
• Storage(thermos)
• Vaporization(hot water tank)
Preheater
Boil-off Compressor
LNG Vaporizers
LNG Tank
LNG TankerUnloading &Loading
to TransmissionPipeline System
LNG Pumps
Feed Gas
Tail Gas
DessicationLiquefaction
25
Design/Safety Features
• Insulated, non pressurized, 9% nickel steel inner tank (like a thermos)
• 100% secondary containment around tank• Controlled buffer zone around facility • Safeguard systems (eg: fire/smoke/gas
detection, automatic/remote control, manned full time) designed for isolation/containment and shut-down
• Fire water system, water deluge and dry chemical extinguishers
LNG facilities are designed to isolate, contain and shut down.
26
Typical 9% Nickel Steel Tank Design
27
Artist Rendering
28
TGVI Project “Pre-approval” Schedule
ID Task Name Duration
1 LNG STORAGE FACILITY 21.82 mons2 GENERAL ENG. & SPEC. DEVELOPMENT 8 mons3 SITE SELECTION incl. ENVIR'N ASSESSMENT 9 mons4 SITING AND ZONING APPROVAL 4.7 mons5 SITE ACQUISITION (Option & Purchase) 2.7 mons6 CONTRACTOR SELECTION 4.8 mons7 CONTRACTOR DESIGN & PRICE 4 mons8 CPCN PROCESS 5.5 mons9 BCUC APPROVAL 0 mons
Qtr 2 Qtr 3 Qtr 4 Qtr 1 Qtr 2 Qtr 3 Qtr 4 Qtr 12004 2005
29
Comparable LNG Storage Project Schedules
Actual peak shaving projects– Memphis Gas – 1996 1.0 bcf 29 mth– Williams (Pine Needle) – 1998 2 X 2.0 bcf 29 mth
Proposed peak shaving projects– BC Gas – 1996 2.0 bcf 25 – 30 mth– PGT – 1996 2.0 bcf 24 – 30 mth– WGSI – 1997 3.0 bcf 28 mth– Williams – 1997 3.0 bcf 24 mth
Other– Contractors 2003 Estimates 28 – 29 mth.– CBI 2004 Negotiated 28 mth.
30
TGVI Project Construction Schedule
ID Task Name Duration
1 LNG STORAGE FACILITY 33.97 mons2 BCUC APPROVAL 0 mons3 AWARD EPC CONTRACT 0.2 mons4 DETAIL DESIGN - TANK 8 mons5 DETAIL DESIGN - PROCESS & CONTROLS 20 mons6 PURCHASE TANK MATERIALS 12 mons7 PURCHASE PROCESS EQUIPMENT 16 mons8 SITE & ROAD PREPARATION 3 mons9 CONSTRUCTION - TANK 22 mons10 CONSTRUCTION - PROCESS & CONTROLS 19 mons11 EPC CONSTRUCTION CONTINGENCY 2 mons12 CONSTRUCTION - POWER LINE 3 mons13 CONSTRUCTION - PIPELINES 3 mons14 COMMISSIONING 2.7 mons15 COMMERCIAL OPERATION 0 mons16 PERFORMANCE TESTING 2 mons17 OPERATION & PARTIAL FILL 3 mons18 RESTORATION 4 mons
Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q12005 2006 2007 2008
31
Outstanding Approvals
• OGC Notice to Construct• OGC license of occupation and license to cut• MWLAP Approval to construct pond• MWLAP Air emissions permit • Other minor permits (building, highway access,
etc)
32
TGVI Project Capital Cost – 2004$
Capital Cost, $000
EPC Total $73,800Land $1,600
Interconnects $9,300Proj. Services $7,900
Contingency $1,800CDN$ $94,400
33
Comparable LNG Project Costs
Actual peak shaving projects 2004$million• Memphis Gas–1996 1.0 bcf 81• Williams (Pine Needle)–1998 2 X 2.0 bcf 178
Proposed peak shaving projects• BC Gas – 1996 2.0 bcf 110• PGT – 1996 2.0 bcf 110• WGSI – 1997 3.0 bcf 147• Williams – 1997 3.0 bcf 99
TGVI – 2004 1.0 bcf 94.4
34
EPC Contracting Process
EPC contracting is the norm for process facilities where the construction contractor is also the designer
• 2003 – Contact with 8 potential LNG Contractors• Mar 2004 – Request for Expression of Interest • May 2004 – Evaluation
– 4 teams of interest• Corporate and Financial Strength• Organization• Experience and Performance
– 2 “qualified” contractor teams identified
35
EPC Contracting Process
Decision to Negotiate
EPC Bidding difficult due to;• lack of bidders • high bidders costs• detailed scope and contract leads to non-
compliance, no bids and/or high bids• significant negotiation on scope, price and
contract after bidding
36
EPC Contracting Process
Negotiated contract allows owner to;• Negotiate assignment of project risks (e.g.
insurance, exchange, etc.)• Negotiate pricing fixed elements (e.g. profit,
administration, etc.)• Be part of the scoping and design• View open book bids for equipment/components
and subcontracts• Minimize contractor contingencies
37
EPC Contracting Process
Jun to Aug 2004 – Negotiation– Contract terms– Price development method– Contractor team & execution strategy– Selection of “Chicago Bridge & Iron”
Sep 2004 to Jan 2005 – Design & price development– Document scope and guarantees– Receive EPC price
January 2005 – CPCN Approval– Award EPC Contract
38
EPC Contractor:Chicago Bridge & Iron
One of the worlds leading Low-Temp/LNG design/builders with over 50 years experience. Currently doing US$1.2 billion/yr
• Over 40 LNG Terminals and Peak shaving plants
• Over 120 LNG Tanks• Built last 2 N.A. LNG Peak shaving plants• Awarded Yankee Gas (Oct. 2004 1.2 bcf p/s)• Full Scope of EPC Services In-House• HortonCBI – Canadian Subsidiary
Contact Information James WongManager, Forecasting
Tel: (604) 592-7871E-mail: [email protected]
TGVI Resource Planning Process
2
Evaluating the Portfolio Alternatives
Objective Attribute Measure Ensure reliable and secure supply.
System reliability Security of supply
Risk of outages Gas supply diversity
Provide service to customers at least delivered cost.
Financial evaluation of supply side and demand side resources
Net Present Value Total Resource Cost (TRC) Ratepayer Impact (RIM)
Reduce rate volatility. Expected rates Risk trade-offs Balance socio-economic and environmental impacts.
Social costs / benefits including: Local emissions Greenhouse gas Land use impacts Employment/local
economic impacts Stakeholder consultation
Air pollutants Quantity of CO2 equivalent Area impacted Jobs created
Stakeholder input
3
LNG is the Preferred Resource
• Demand growth presents opportunity to improve energy infrastructure
• LNG Storage is the preferred portfolioImproves security of supplyLowest cost for expected range of demandPart of a phased solution that will support economic growth
TGVI LNG Pipe PipePlanning Storage Compression CompressionObjective Curtailment
Ensure reliable secure supplyLowest delivered costReduce long-term volatilityBalanced impacts
Contact Information James WongManager, Forecasting
Tel: (604) 592-7871E-mail: [email protected]
TGVI Core Market –Peak Demand Forecast
5
Definitions, inputs and drivers
Core Market – residential, commercial and small industrial customers that have gas purchased and delivered to their home or business. Design Year – The year which experienced the coldest day in the last 25 years.Design Day – The coldest day in the last 25 years – i.e. February 2, 1989
Gross Squamish Demand High Base Low High Base Low ICP + 0 ICP + 20 ICP + 45 Yes Yes NoHigh-High ● ● ● ● ●Base + 45 ● ● ● ● ●Base + 20 ● ● ● ● ●Base + 0 ● ● ● ● ●Low-Low ● ● ● ● ●
Core Customers Joint Venture Generation (ICP + CFT) Whistler
Gross Demand Scenarios – Base, High, and Low
6
Definitions, inputs and drivers
Inputs and DriversCustomers• Annual Additions – Customer Growth
• New versus Conversion Customers• Total Number of Customers in a Year
Peak Use Rate per Customer– the maximum demand for natural gas from a customer on a
single day
7
Forecasting Methodology –Customer Growth
-
20,000
40,000
60,000
80,000
100,000
120,000
140,000
160,000
1991 1996 2001 2006 2011 2016 2021 2026
Cus
tom
ers
(Lin
e C
hart
)
0
2,000
4,000
6,000
8,000
10,000
12,000
14,000
16,000
Cus
tom
er A
dditi
ons
(Bar
Cha
rt)
Transition
Base - Maintain competitive position and economic growth is stable
High - Competitive position inproves and economy grows
Low - Competitive position worsens and economic growth is poor
ForecastActual
3.1% CAGR
3.8% CAGR
2.4% CAGR
33.4% CAGR
CAGR - Compound Annual Growth Rate
4.7% CAGR
Implementation Maturity
2.0% CAGR
Base – 98,000 cust; 119 TJ/dayHigh – 103,000 cust; 139 TJ/dayLow – 94,000 cust; 107 TJ/day
Base – 132,000 cust; 160 TJ/dayHigh – 140,000 cust; 187 TJ/dayLow – 126,000 cust; 144 TJ/day
Resource Plan reference, page 19 - Figure 3-5. Core Customer New Account Growth in Three Market Phases
8
Forecasting Methodology –Customer Growth
Look at recent years growth experience ~ 3,000 per year
Customer Additions2000 - 2004
-
500
1,000
1,500
2,000
2,500
3,000
3,500
2000 2001 2002 2003 2004
# of
Cus
tom
ers
Forecast ~ 2,400/year
OR
55,000 total
FROM
2004-2026
9
Market Segments - Conversions
Conversion Activity – Last Five Years
-
500
1,000
1,500
2,000
2,500
3,000
3,500
4,000
1999 2000 2001 2002 2003
# of
Con
vers
ions
10
Market Segments - Conversions
Conversion Potential"On-Main"
Remaining Conversion
Potential27,000
Forecasted Conversions
28,0002004 - 2026
~ 55,000 On-Main Potential Customers
11
Market Segments –New Construction
New Construction Installations to Housing Starts
-
1,000
2,000
3,000
4,000
5,000
6,000
7,000
8,000
1992 1995 1998 2001 2004 2007 2010 2013 2016 2019 2022 2025
New Construction Housing Starts
12
Market Segments –New Construction
Natural Gas Market Capture of New Housing Starts
30.0%
40.0%
50.0%
60.0%
70.0%
80.0%
90.0%
100.0%
110.0%
1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003
New
Con
stru
ctio
n C
usto
mer
s pe
r New
Hou
sing
Sta
rt
Increased Market capture for forecast horizon
Market capture for forecast horizon
13
Peak Use Rate per Customer
Statistical method –Regression Analysis used
* 1997 to 2001 data used
Scatter(Oct 97 through Dec 01)
y = 0.0377x + 0.1421R2 = 0.9149
0.00.10.20.30.40.50.60.70.80.91.01.11.21.3
0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30
HDD
UPC
(GJ)
14
Peak Use Rate per Customer
Updated recently –
similar results
* 1997 to 2003 data used
Scatter(Oct 97 through Dec 2003)
y = 0.0362x + 0.144R2 = 0.9109
0.00.10.20.30.40.50.60.70.80.91.01.11.21.3
0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30
HDD
UPC
(GJ)
Design
15
Peak Use Rate per Customer
Is it a “reasonable” model?
Recent results……. say “Yes”
Regression EquationCore Market Y intercept Slope Heating Forecast Difference Act vs Fcst
Day of Deliveries Non temp sensitive load Temp sensitive load Deg Days Core Market Core Load Act vs Fcst DifferenceDate Week (gigajoules) (UPC) (UPC / DDD) (HDD) (Customers) (gigajoules) (gigajoules) (%)
3-Jan-04 Saturday 76,238 0.1421 0.0377 19.3 76,533 66,488 9,750 14.7%4-Jan-04 Sunday 77,695 0.1421 0.0377 24.0 76,533 79,981 (2,286) -2.9%5-Jan-04 Monday 76,760 0.1421 0.0377 22.9 76,533 77,045 (285) -0.4%6-Jan-04 Tuesday 69,704 0.1421 0.0377 21.2 76,533 72,132 (2,428) -3.4%
Total 4,750
* HDD based on weighted average HDD of three regions; Victoria, Nanaimo, Comox
* BCUC IR #1, 8.5.2
16
Design Day Demand Forecast
Design Day Demand ForecastCore Market
50,000
70,000
90,000
110,000
130,000
150,000
170,000
190,000
210,000
2004 2007 2010 2013 2016 2019 2022 2025
GJs
/ da
y
Low Base High Base + Higher Mkt Capture
Transport Customer Forecast
David A. Bennett
Joint Venture
• Resource Plan Forecast(Based on consultation in the spring)
High – 40 TJ/dMid – 33.6 TJ/dLow – 20 TJ/d
• Current Indications Gas prices are higherHave seen a downward trend in usageTGVI expects energy efficiency initiatives will be more economic10-15 TJ/d longer term
BC Hydro
• ICP45 TJ/d in 2007
• CFT requirements150 MW – 300 MW RequirementBid projects mostly gas firedAnnouncement Tues October 26
• Firm Tenders
Expected Gas Demand Outcome (20 to 45 TJ/d)
BC Hydro
Bidder Name Primary Fuel Location Calpine Island Cogeneration Limited Partnership
Natural Gas Campbell River
Duke Point Power LP Natural Gas Nanaimo ENCO Power Company Natural Gas Nanaimo EPCOR Power Development Corporation Natural Gas Ladysmith EPCOR Power Development Corporation and Calpine Canada Power Ltd.
Natural Gas Nanaimo
Green Island Energy Ltd. Biomass Gold River
Contact Michael DaviesManager, Business DevelopmentTerasen Gas
Tel: (604) 592-7836E-mail: [email protected]
Gross Demand ForecastsSupply Portfolios
RP/CPCN Workshop – October 22, 2004
Summary
• Gross Demand Forecasts• Planning Criteria• Portfolio Description and Comparison Measures
Gross Demand Forecast
• How might VIGJV changes and CFT expectation effect demand?– VIGJV 10 – 15 TJ/d– CFT 20 – 45 TJ/d
• Range of expected demand narrows• New demand forecast comparable to Base+0 to Base+20
Resource PlanForecasts VIGJV BC Hydro TotalTJ/d 2007+
Base +0 34 45 79Base +20 34 65 99Base +45 34 90 124
Base +20 (JV@10) 10 65 75Base +45 (JV@10) 10 90 100
Gross Demand Forecasts
-
50,000
100,000
150,000
200,000
250,000
300,000
350,000
400,000
1992 1994 1996 1998 2000 2002 2004 2006 2008 2010 2012 2014 2016 2018 2020 2022 2024 2026
Year
Dem
and
(GJ)
pipeline capacitydemand history
high forecast
base forecast low forecast
Dem
and
GJ/
d
Year
Portfolios – Transmission Planning Criteria
• 20 year planning period beginning 2007 when facilities addedPresent Value of Cost of Service is the main quantitative measureReflects the revenue required to be recovered in customer rates
• Design Day and Normal Peak Day consideredDesign Day – coldest day in 25 years, with curtailmentNormal Peak Day – average coldest day, without curtailment
• Planning based on daily rather than hourly requirementsGeographic/weather diversity, ability to ‘pack’ the transmission lineTransport customers are limited to maximum 5% of daily nomination in one hour
• Construction and operating logistics are also consideredLength and phases of looping for example
Portfolios – Capital Spending Profile
LNGStorage
Base Case + 20millions 2004$
14 26 19 14
94
2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026
LNGCompressionPipe
14
78
1424 4418 8
34
2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026
1459
19 22 13 24 44
2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026
PipeCompression
PipeCompressionCurtailment
Comparison of incremental costs
Table 6.5.1LNG Pipe LNG Pipe
Storage Compression Storage Compression (PV 2004-2026 @ 6%, $M) Incremental Facilities 165 162 250 277 Transport Fuel Differential 4 - 22 - Gas Supply Differential (58) - (58) - LNG Mitigation (36) - (34) - Total (PV@6%) 74 162 180 277
Base +0 TJ/d Base +45 TJ/d
Table 6.5.3LNG Pipe LNG Pipe
Storage Compression Storage Compression (PV 2004-2026 @ 6%, $M) Curtailment Curtailment Incremental Facilities 163 88 245 214 Transport Fuel Differential 4 7 22 8 Gas Supply Differential (58) (35) (58) (28) LNG Mitigation (36) - (34) - Peaking Gas Mitigation (16) - (16) - Total (PV@6%) 56 60 159 195
Base +0 TJ/d Base +45 TJ/d
Gas Supply Benefits and LNG Storage Services
David A. Bennett
Electric Generation
Industrial
Residential and Commercial
1 40 81 120 161 200 241 280 365321
Coldest to Warmest Days of the Year
Nat
ural
Gas
Con
sum
ptio
n
Potential New Electric Generation
Residential and Commercial Growth
Future Requirements
TGVI Annual Load Profile
0
10,000
20,000
30,000
40,000
50,000
60,000
70,000
80,000
90,000
100,000
1-Nov
1-Dec
1-Jan
1-Feb
1-Mar
1-Apr
1-May
1-Jun
1-Jul
1-Aug
1-Sep
1-Oct
GJ/
day
Baseload Supply Seasonal Capacity Storage
Curtailment/ Interruption Design Year Demand Gas purchases
Pipeline
StorageStorage
0
10
20
30
40
50
60
70
80
90
100
110
120
1 51 101 151 201 251 301 351Days of the Year
Dem
and
(TJ/
d)
StoragePipeline
Peaking Supply
`
Average Forecast Load Requirements vs Resource Availability
Normal Demand
For illustrative purposes only
Gas Supply Portfolio Planning
Peak Day Demand
TGVI Annual Contracting Plan
2004/05 2005/06 2006/07 2007/08 Stn2 Baseload 20 20 20 20 Stn 2 Winter 5
month9 9 9 9
Hunt 5 month 8 8 10 15 Hunt 3 month 8 8 10 15 Aitken Creek 14 14 14 14 Mist/Peaking 25 30 33
LNG - - - 40 BCHydro Peaking - - - -
VIJV Peaking 18.8 18.8 16.8 -
Peak Day incl fuel 102.8 107.8 112.8 113 Peak Day net of
fuel97.7 100.4 103.9 107.3
TGVI Annual Portfolio(TJ/d)
BCUC IR 23.5
SENDOUT Optimization Model…
• Model OverviewNew Energy Associates - a wholly owned subsidiary of Siemens Westinghouse Power Corporation www.newenergyassoc.com
A Natural Gas Supply Planning Optimization System– Economic model– Optimization types: variable costs only or fixed and variable costs
Linear Programming Network Optimization Algorithm– Minimize total system cost, (the objective function), of flows along a network
subject to physical and contractual constraints (including reliability requirements)– Total System Cost = Fixed + Variable + Un-served Demand Penalty – Revenue– CPLEX Solver Engine – www.ilog.com
Deterministic Model– Optimal solution generated by looking at complete problem all at once– Assumes perfect knowledge…no uncertainty modeling– Optimal solution found via iterative process
Over 100 SENDOUT Clients (90% customers regulated)
SENDOUT Optimization Model…
Graphical Solution of a Two Variable LP
TGVI gas supply model:– 270,000 constraints, 220,000 variables, and 100,000 iterations– Setup time (including input data collection) - 3 to 4 weeks initial setup – Solution time - 15 minutes initial run, 90seconds consequent runs
-8-6-4-202468
10121416
0 2 4 6 8 10 12 14 16 18 20 22 24 26 28 30 32 34
control variable 1
cont
rol v
aria
ble
2
Points at w hich constrains are boundedObjective Function ValuesConstraint Equations 1 & 2Feasible Region
Direction of improvement
TGVI Gas Supply Model…
• SENDOUT Network Structure
* Daily time steps in Chronological order
* Annual resource sizing decisions
* 20 year optimization period
Off System Sales
Storage ContractsSupply Contracts
Term/Day/Peaking
Transport Contracts/
Pipe Segments
Core Load & Temperature
TGVI Gas Supply Model…
• Scenario Structure
Pipe and Compression– Unconstrained pipe capacity to TGVI– Incremental transport (Duke) and/or storage (ACR, Mist)
LNG– Constrained pipe capacity to TGVI– LNG on TGVI (minimum take and optional)
Pipe, Compression, and Curtailment– Constrained pipe capacity to TGVI– Curtailment on TGVI (existing and optional)
TGVI Gas Supply Model…
• Summary of Portfolio Costs – Normal Year Requirements
Total Cost = Variable + Fixed – Resale Revenue – Release RevenueNormal Cost = Variable * Normal Load/Design Load + Fixed
+ (Design Load – Normal Load) * US$0.25/MMBtu
TOTAL COST (BASE + 0) - NORMAL YEAR ($Millions)
PIPE,COMPRESSION LNG
PIPE,COMPRESSION,CURTAILMENT
Fixed 145.77$ 90.32$ 106.26$ Variable 893.73$ 892.01$ 898.88$ Total 1,039.50$ 982.34$ 1,005.12$
Third Party RevenuePotential Customers
• Shippers on TGVIBC Hydro for electrical peakingOthers
• TGI• Others in Region
LDCs, electric producers
Highest value will be to those at Huntingdon or upstream because they avoid pipeline redelivery costsTGI is willing to take all capacity that TGVI does not require
TGI Supply Stack
0
200
400
600
800
1000
1200
1400
1 6 11 16 21 26 31 36 41 46 51 56 61 66 71 76 81 86 91 96 101
106
111
116
121
126
131
136
141
146
151
TJ/d
LNG/Curtailment
Peaking
Stn 2/Alberta Spot / JPS/Mist
Seasonal Storage
Baseload/Seasonal
Design
Normal
Market ValuationAnnual Carrying Costs(1 GJ of Sendout)
Pipeline– 365 days X $0.40 / GJ = $150 per year
Downstream Storage– $3.50 / GJ X 30 days = $115 per year
LNG– $8 / GJ X 10 days = $80 per year
(For illustrative purposes)
Required(days) Pipeline
DSStorage LNG
10 15.00 11.50 8.0030 5.00 3.50 -
150 1.00 - -365 0.40 - -
Costs By Load Duration($/GJ)
Service Comparison Downstream Storage vs. TGVI LNG
Service Downstream Storage TGVI LNG
Reliability Dependent on pipeline grid On-system source of supply
Nomination Notice 4 GISB Cycles over two days 2 hours or less
Nomination Flexibility Subject to intraday proration Infinitely VariableLoad Following
Delivery/Redelivery Dependent on delivery/redelivery by others Firm On-system
Deliverability Declines after 50% No Decline
Injection Up to Max Withdrawal 5% of Max Withdrawal
Cost Certainty Length of contract Yes
Cycling Costs $0.40 /GJ Dependent on IT
~2 X Downstream StorageFirm
• LNG offers unique balancing and storage advantages because of its location
Contact Cynthia Des BrisayDirector, Business DevelopmentTerasen Gas
Tel: (604) 592-7837E-mail: [email protected]
TGVI LNG Storage ProjectCustomer Impacts
October 22, 2004
Introduction
• CPCN Approval sought for LNG Storage Project LNG Storage Portfolio determined to be preferred resource portfolio across range of likely demandMost cost effective portfolio which will support lowest delivered costs to customers
• Cost Allocation of LNG facility to be determined in future rate reviews
• Evaluation of Indicative burnertip and transport costs demonstrates LNG project can supports rate design objectives
Least Cost PortfolioNet Incremental Cost of ServiceBase + 45
0
5
10
15
20
25
30
35
40
2008 2010 2012 2014 2016 2018 2020 2022 2024 2026Calendar Year
Mill
ion
$
Pipe,Compression& Curtailment
LNG Storage
Pipe &Compresion
Least Cost Portfolio
Net Incremental Cost of ServiceBase + 0
0
5
10
15
20
25
30
35
40
2008 2010 2012 2014 2016 2018 2020 2022 2024 2026Calendar Year
Mill
ion
$
Pipe, Compression& Curtailment
LNG Storage
Pipe & Compression
Customer Impacts
• TGVI Rate Design ObjectivesCompetitive Pricing versus alternate energiesLong term financial sustainability
• Centra (TGVI) Rate Design DecisionSoft Cap MechanismRDDA Amortization and Allocation
• Indicative Burner tip costs and Transport CostsBased on current rate design principlesBased on Allocation of LNG Storage Facility in similar fashion as transmission assets
LNG Facility Benefits
➼➼Reliability & Security
➼➼Gas Supply Benefits
➼➼Avoided Facility Costs
➼➼Efficient Use of Existing Transmission System
TransportCoreBenefits
➼ Direct ➼ In-Direct
Indicative Burner Tip Rates
Demand Scenario - Base +0 LNG
$-
$5.00
$10.00
$15.00
$20.00
$25.00
2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026
$ pe
r GJ
Del
iver
ed
Average Cost of GasAverage Delivery MarginHeating Oil Equivalent90% Residential Electric
Residential Customer (RGS)Allocated Cost $ per GJ
BCUC IR 47.7
Indicative Transport CostsDemand Scenario - Base + 0 LNG
$-
$0.20
$0.40
$0.60
$0.80
$1.00
$1.20
$1.40
2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026
Dem
and
Cha
rge
$ pe
r GJ/
d
Allocated Unit Cost / GJ
Allocated Unit Cost x 1.25 R/C
Firm TransportationAllocated Cost $ per GJ/d Capacity
BCUC IR 47.7
Indicative Burner Tip Rates
Demand Scenario - Base + 45 LNG
$-
$5.00
$10.00
$15.00
$20.00
$25.00
2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026
$ pe
r GJ
Del
iver
ed
Average Cost of Gas
Average Delivery Margin
Heating Oil Equivalent
90% Residential Electric
Residential Customer (RGS)Allocated $ per GJ
BCUC IR 47.8
Indicative Transport Costs
Demand Scenario - Base + 45 LNG
$-
$0.20
$0.40
$0.60
$0.80
$1.00
$1.20
$1.40
2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026
Dem
and
Cha
rge
$ pe
r GJ/
d
Allocated Unit Cost / GJAllocated Unit Cost x 1.25 R/C
Firm TransportationAllocated Cost $ per GJ/d Capacity
BCUC IR 47.8
Conclusions
• Given a minimum level of Firm Transport demand as defined in the CPCN as Base + 0, the LNG resource portfolio drives rates that:1. Core service rates that are competitive to
alternative fuels to 2011 2. Provide Core service rates that remain competitive
to alternative fuels in 2012 when royalty relief is lost3. Recover the RDDA by 20114. Transport Rates comparable or less than current
levels
FINANCIAL ANALYSIS UPDATE
• Revised Financial Analysis to be provided before November Hearing
Transport Demand to reflect BC Hydro CFT OutcomeEconomic Parameters – Updated Oil and Gas prices Forecast– BC Hydro Electricity Price forecast – US$/CDN Exchange Rate (from 0.71 to 0.75)
Financial Assumptions– Depreciation Rates– Fed./Prov. Contribution Repayment
Operational– Gas Supply Cost Forecast (Sendout)– Incremental Wheeling Costs
Contact Information Tom LoskiDirector,Regulatory Affairs
Tel: (604) 592-7464Fax: (604) 592-7890E-mail: [email protected]
Review and Approval Process
Next Steps
2
Regulatory Agenda
Workshop Fri, Oct 22
Budget Estimates for Participant Assistance Mon, Oct 25
BC Hydro CFT results made public Tues, Oct 26
Intervenors file Evidence Wed, Oct 27
Information Requests to Intervenors and TGVI Wed, Nov 3
Intervenors & TGVI respond to IR's Wed, Nov 10
Hearing Commences Wed, Nov 17
3
Proposed TGVI Panels for Hearing• Key Considerations in Panel determination
• Primary: Resource Plan and CPCN – subject areas and issues not discrete between the two
• Secondary: Logistics – TGVI personnel involved with Annual Review presentation
• Panel 1• Overview, History, Regional Planning, Resource Planning Process,
Core & Industrial Demand Forecasts, DSM
• Panel 2• LNG Project; Siting, Facility Design, Capital & Operating Costs,
Contracting Practice, Operations, Safety
• Panel 3• Resource Alternatives, Project Justification, Financial Evaluation,
Industrial Curtailment, Customer Rate Impacts, Gas Supply benefits