TGVl's Resource Planning/CPCN Environment: Then and Now … · 01249.88645.JCK.2511319.1. 2 End Notes 1 Exhibit B-2, CPCN Application, p. 66. 2 Exhibit B-8, TGVI Response to BC Hydro

TGVl's Resource Planning/CPCN Environment: Then and Now

RP/CPCNItem

VIGJV FirmDemand

BC Hydro FirmDemand (ICP)

ICP FuelSwitchingCapability

CFT Outcome

Dependenceof LNG Facilityon CFTOutcome

BC Hydro FirmDemand for2007 (ICP &DPP)

Design Pricefor LNGFacility

r' I I;:ieilt1>I'1lJff.'August 13, 2004(Prehearing Conference)

37.6 TJ/day, declining to33.6 TJ/day in 2006.1

38 TJ/day (ICP), to expireOctober 31,2004 and continuewith IT service and assignedcapacity from JV.

Unconfirmed.

Unknown.

Base +0 Case assumed theaddition of either LNG orcompression in all portfolios in2007. 6

45 TJ/day (ICP).

"The Commission notes thatTGVI expects to enter into asole source contractualarrangement ... [to] coveractivities to mid November2004 and which will includesufficient detailed engineeringto provide a firm project price... at that time." 9

November 17, 2004(Commencement of Hearing)

20 TJ/day for January 2005; 12.5 TJ/day for2006 to 2012; JV may reduce by 4.5 TJ/dayon 12 months' notice, beginning 2007, subjectto a minimum Contract Demand of 8 TJ/day.2

38 TJ/day (ICP), to expire December 31,2004;3 no assigned capacity from JV.

Confirmed October 1,2004. BC Hydroexamining whether storage capacity will limit240-hour/year peaking service to TGVI andlooking at ways to remove any suchlimitations.4

Winning bid is Duke Point Power LP (DPP)-252 MW; 44.6 TJ/day; no fuel switchingcapability in current configuration.5 AwaitingCommission process related to CFT outcomeafter EPA is filed.

Revised Base +0 Case shows that no newfacilities are required in 2007 if existing ICPfuel switching capacity is used.?

Total peak day demand of 44.6 TJ/day withfCP fuel switching; 89.6 TJ/day without;additionallCP curtailment available after 2016if less than 4500 TJ used between 2007 and2016.8 Negotiations between BC Hydro andTGVI on long-term agreements are ongoing.

"The current schedule now anticipates the firmEPC (engineering, procurement andconstruction) price to be obtained ... byJanuary 27,2005 .... at which time TGVIwould have a control estimate with aconfidence level within +/-10%." 10

01249.88645.JCK.2511319.1

2

End Notes

1 Exhibit B-2, CPCN Application, p. 66.

2 Exhibit B-8, TGVI Response to BC Hydro IR 48.0(a) and (b).

3 BCUC Order G-97-04, October 29,2004.

4 Exhibit C7-4, BC Hydro Response to BCUC IR 1.1.

5 Exhibit C7-4, BC Hydro Responses to BCUC IR 3.4, 3.5.

6 Exhibit B-1, Resource Plan, Appendix E, p. 1.

7 Exhibit B-8, TGVI Response to BCUC IR 48.1, Attachment 3, p. 15 (see PC&C portfolios).

8 Exhibit C7-4, BC Hydro Response to BCUC IR 3.8.

9 Exhibit A-2.

10 Exhibit B-3, TGVI Responses to BCUC IR 28.5, 28.8.

01249.B8645.JCK2511319.1

ITera~n 0 1

Gas

Design Day Base Forecast Scenario

Year Core Customers Joint Venture BC Hydro Squamish

2005 100.4 37.6 38.0 4.82006 103.9 33.6 38.0 5.02007 107.3 33.6 45.0 5.12008 110.5 33.6 45.0 5.32009 113.6 33.6 45.0 5.52010 116.4 33.6 45.0 5.72011 119.0 33.6 45.0 5.92012 121.5 33.6 45.0 6.12013 123.9 33.6 45.0 6.32014 126.4 33.6 45.0 6.42015 129.0 33.6 45.0 6.62016 131.5 33.6 45.0 6.82017 134.2 33.6 45.0 7.02018 136.9 33.6 45.0 7.12019 139.6 33.6 45.0 7.32020 142.4 33.6 45.0 7.52021 145.2 33.6 45.0 7.72022 148.1 33.6 45.0 7.82023 151.1 33.6 45.0 8.02024 154.1 33.6 45.0 8.22025 157.2 33.6 45.0 8.42026 160.4 33.6 45.0 8.5

The design-day demand is highly correlated to the coldness of weather conditions experiencedand is highly price inelastic, meaning that during the design-day, the demand is insensitive toprice, driven primarily by the weather. For TGVI, since Core customers' demand is primarilyweather dependent, design-day demand is forecast based upon the coldest weather observedin the last 25 years, which over the last 25 years has been minus 10.4 degrees Celsius or 28.4heating degree days (HOD).

A design year load duration curve is provided for reference below using the results of theregression analysis extrapolated against the HDD for each day of 1989, the coldest year in thelast 25 years. The duration curve provided is sorted from the coldest to warmest day.

Page 66

TERASEN GAS (VANCOUVER ISLAND) INC.

RESOURCE PLAN REPORT DATED JULY 8, 2004 ("RESOURCE PLAN")CERTIFICATE OF PUBLIC CONVENIENCE AND NECESSITY APPLICATION

DATED AUGUST 4,2004 ("CPCN APPLICATION")

RESPONSE TO BC HYDRO INFORMATION REQUEST NO.2

48.0 Reference: Stakeholder Workshop - October 22, 2004

In TGVl's presentation material distributed at the above-referenced StakeholderWorkshop, TGVI provided a revised assumption of 10-15 TJ/day for the long-termoutlook for the firm contract demand requirements of the JV (presentation entitled'Transport Customer Forecast," first slide after title slide).

(a) Please provide an update on any recent discussions between TGVI and the JV inrespect of changes to the contract demand under the JV TSA.

Response

Terasen Gas (Vancouver Island) Inc. ("TGVI") and the VIGJV have entered into anagreement to amend (the "Amending Agreement") the JV TSA and the PGMA, effectiveJanuary 1, 2005. Set out below is a description of the Amending Agreement and thebackground with respect to how the two parties arrived at the agreement.

Backqround

The VIGJV and Pacific Coast Energy Corporation [now TGVI] entered into the JV TSAand the PGMA effective December 14, 1995, in conjunction with the re-structuring of thearrangements for the delivery of natural gas to Vancouver Island and the SunshineCoast and the signing of the Vancouver Island Natural Gas pipeline Agreement. TheSpecial Direction to the British Columbia Utilities Commission (the "Special Direction")that was issued by the Lieutenant Governor in Council through Order in Council 1510was part of that restructuring. It directed the Commission to approve the JV TSA. TheJV TSA was approved in Commission Order G-105-95/G-1 08-95 and Order G-4-96.

The mills operated by the members of the VIGJV operate in a competitive internationalmarket that imposes continuous demands for improved cost efficiencies. Prompted inpart by rising commodity prices for natural gas and other fossil fuels, the mills haveimplemented changes to reduce overall energy consumption and to make more effectiveuse of alternative fuels. This has resulted in a marked reduction in natural gas use froman average of greater than 40 TJ/day in the 1990's to approximately 23 TJ/d over thelast year. The VIGJV has advised that this trend will continue with capital investmentsover the next year to further reduce the VIGJV firm requirements to 12.5 TJ/d.

In response to the reduced fuel requirements, the VIGJV was investigating ways toreduce its obligations for firm capacity on the TGVI system. Under the current JV TSAthe VIGJV has the option of terminating (not extending) the agreement at the end of2005. The VIGJV has the right to extend the current JV TSA for five years with notice byDecember 31,2004. The contract allows a reduction in Contract Demand of up to 3

02





TJ/d with 6 months notice and down to 30 TJ/d with 12 months notice. It also gives theVIGJV the right to turn back capacity in response, and coincident with, a TGVI systemexpansion. TGVI understand from the VIGJV that the VIGJV was pursuing anagreement with BC Hydro for the assignment of up to the full amount of its ContractDemand effective November 1,2004. TGVI disputed the VIGJV's right to effect such anassignment and that dispute was to be the subject of litigation pursuant to a Petition filedin the Supreme Court of British Columbia. The VIGJV informed TGVI that it was alsoinvestigating other avenues in the contract to reduce the burden of its firm commitment.

TGVI is currently unable to meet peak demands on its system without having to relyupon curtailment rights with both BC Hydro and VIGJV. With respect to VIGJV, therewas the potential for a further dispute and litigation as the VIGJV took the position thatthe PGMA did not permit TGVI to exercise curtailment rights based on constraints intransmission capacity.

At the same time, BC Hydro requires firm capacity, which, as a result of the outcome ofits Call for Tender process, is expected to be 90 TJ/d by 2007. BC Hydro had previouslymade a commitment for 30 years to the Georgia Strait Crossing (GSX) project for 90TJ/d. TGVI has been working on a lower cost alternative to the GSX that includes theLNG storage facility on Vancouver Island that is the subject of this CPCN. Settling theVIGJV's long term requirements at this time allows a better determination of actual long-term demand, which in turn allows a better assessment of the facilities required to meetthat demand.

The Amendinq Aqreement

As a result of the factors described under the previous section, TGVI entereddiscussions with the VIGJV with the goal of negotiating a new long term arrangement.The Amending Agreement (consisting of the Letter Agreement with the Principal TermSheet appended thereto) is the result of those negotiations. The key elements of theAmending Agreement are as follows:

The agreement amends and extends the current VIGJV agreements (JV TSA andPGMA)

Term: January 1, 2005 to December 31,2012 (8 years)

Contract Demand: 20 TJ/d for 2005 and 12.5 TJ/d for 2006 to 2012

Toll:Firm - Current firm demand formula escalating at ~ CPIInterruptible - Three tier formulaFirm rate - IT between firm CD quantity and 20 TJ/dCurrent IT rate - Quantities of gas between 20 TJ/d and 30 TJ/d1X Firm rate - Quantities of gas in excess of 30 TJ/d

-2-

03





Contract Demand Reductions:Right to reduce contract demand by up to 4.5 TJ/d with 12 months notice beginningin 2007.Right to reduce contract demand in response to a system expansion in the last twoyears of the contract (2011, 2012)

Contract Demand Reinstatement:The VIGJV may request a permanent reinstatement of contract demand oncereduced up to 12 TJ/d depending of availability. Any quantity above 12 TJ/d wouldbe renewed from year to year dependent on availability. Should the VIGJV requirecapacity that would trigger the need for a system expansion, the VIGJV requestwould be the subject of an economic test which would require that the VIGJV coverthe cost of the expansion.

Peaking Gas (PGMA)Consistent with the reduction in firm demand, the VIGJV mills will utilize theiralternative fuel capabilities in the ordinary course of operations. Accordingly, theywill have very little, if any, ability to provide additional fuel switching capability. ThePGMA will remain in place with the reduced CD for 2005 (up to 10 TJ/d of peakinggas). After 2005, Standard curtailment units are no longer available but the VIGJVwill provide peaking gas in the case of a mechanical failure on the TGVI system atthe Supplemental gas price. The provision for Emergency Gas is also retained.

Interruptible Offset GasThe current limit of 1 PJ on interruptible offset gas will be reduced to 25 times thethen current CD. This is in line with the original formula for the 1 PJ (25 X 40 TJ).

AssignmentThe right to assign the JV TSA is removed except in the case of a change inownership of the VIGJV mills. Legal processes and claims currently under wayrelated to the assignment of Contract Demand will be adjourned pending approval ofthe Amending Agreement and will be discontinued when the Amending Agreement isapproved.

Current CPCNThe VIGJV has agreed to not oppose TGVl's pending CPCN application.

-3-

04



DATED AUGUST 4, 2004 ("CPCN APPLICATION")


(b) Have these discussions resulted in any agreement that modifies the contractdemand under the JV TSA or the quantity of peaking gas available to TGVI underthe PGMA? If so, please provide a copy of any such agreement. If theagreement has not been put into written form, please describe the essentialterms of the agreement and provide a copy of the agreement when it is in writtenform.

Response

Please see the agreements attached in Attachment 1 and 2.

(c) For each year of the TGVI planning period, please identify the appropriatequantity of JV contract demand and peaking gas that TGVI will now be using inits load forecast and resource planning analysis to justify the proposed LNGstorage facility.

Response

TGVI is now using a load forecast of 12.5 TJ/d for the VIGJV for each year in theplanning period with the exception of 2005 which is 20 TJ/d.

-4-

05

BRITISH COLUMBIAUTILITIES COMMISSION 06

TELEPHONE: (604) 660-4700BC TOLL FREE: ]-800-663-1385

FACSIMILE: (604) 660-1102

SIXTH FLOOR, 900 HOWE STREET, BOX 250VANCOUVER, B.C. V6Z 2N3 CANADA

web site: http://www.belle.eom

ORDERNUMBER G-97 -04

IN THE MATTER OFthe Utilities Commission Act, R.S.B.C. 1996, Chapter 473

and

An Application by Terasen Gas (Vancouver Island) Inc.for Approval of an Amending Agreement that amends the Transportation Service Agreement,Peaking Agreement, Capacity Assignment Agreement and the Compressor Facility Agreement

BEFORE: L.A. Boychuk, CommissionerL.F. Kelsey, Commissioner

)) October 29,2004

WHEREAS:ORDER

A. On October 28, 2004, Terasen Gas (Vancouver Island) Inc. ("TGVI") applied for approval of an Amending

Agreement to the Transportation Service Agreement, Peaking Agreement, Capacity Assignment Agreement

and Compressor Facility Agreement ("the Amending Agreement") dated October 28, 2004 that amends the

Transportation Service Agreement ("TSA") dated March 7, 2001 as amended September 1, 2001, October 17,

2002 and September 30,2003; the Peaking Agreement ("PA") dated March 7, 2001 as amended October 17,

2002 and September 30, 2003; the Capacity Assignment Agreement ("CAA") dated March 7, 2001 as

amended September 1, 2001, October 17, 2002 and September 30, 2003, and the Compressor Facility

Agreement ("CFA") dated May 18,2001 and amended September 30,2003; and

B. The TSA, PA, and CFA are between British Columbia Hydro and Power Authority ("BC Hydro") and TGVI

for the transportation of natural gas on the TGVI high pressure natural gas transmission system ("HPTS") to

the Island Cogeneration Plant at Elk Falls, and for the supply of peaking gas by BC Hydro to TGVI; and

C. The CAA is between Terasen Gas Inc. ("Teras en Gas"), BC Hydro and TGVI. The CAA provides capacity

on the Terasen Gas system for the wheeling of gas to the TGVI system; and

D. The Amending Agreement extends the TSA, PA, CFA and CAA fTom October 31, 2004 to December 31,

2004; and

.. ./2

BRITISH COLUMBIAUTILITIES COMMISSION 07

2

ORDERNUMBER G-97 -04

E. The Commission has considered the application and the finds that the extension of the contracts should be

approved.

NOW THEREFORE the Commission approves for TGVI the Amending Agreement dated October 28, 2004,

subject to TGVI filing the fully executed agreement in a timely fashion.

DATED at the City of Vancouver, in the Province of British Columbia, this 29th

BY ORDER

Original signed by:

Lori Ann BoychuckCommissioner

OrderrrGVI/BCH ICP 2004 Amending Agrmts

day of October 2004.

British Columbia Utilities Corporation Information Request No. 1.1.1 PageDated: November 3, 2004 1British Columbia Hydro & Power AuthorityResponse issued November 10, 2004Terasen Gas (Vancouver Island) Inc. 2004 Resource Plan Application July8, 2004 andTerasen Gas (Vancouver Island) Inc. LNG CPCN Applicationdated August 4, 2004

1.0 Reference: TGVI Resource Plan, p. 51; Exhibit No. B-3, Response toBCUC IR 34.1,34.13 BC Hydro letter dated September 7,2004;Exhibit No. B-6, Response to BCUC Hydro IR 4.0(i)

1.1.1 BC Hydro's letter dated September 7, 2004 indicates that thefocus of its intervention includes "the need/timing for the proposedLNG storage facility, its cost-effectiveness in relation to otheroptions, including peaking curtailment arrangements withindustrial customers, and the allocation of costs and impacts onshipper tolls to be charged by TGVI."

TGVl's response to BCUC IR 34.13 reproduces the VancouverIsland Energy Corporation ("VIEC") response to an InformationRequest regarding the ability of the Island Cogeneration Plan("ICP") to curtail gas usage and operate on distillate. Pleaseprovide an updated response to the Information Request thatVIEC was responding to.

RESPONSE:

At the time of the VIEC response, ICP's ability to fuel switch to distillate was notconfirmed. ICP has now been retrofitted with distillate back-up firing capability.Commissioning of the distillate system took place in June 2004. On October 1,2004, BC Hydro received a letter from Calpine confirming that it has completed thedistillate system commissioning and testing for ICP and the system is capable foruse as defined in the Electricity Purchase Agreement between BC Hydro andCalpine (EPA) and within the requirements set out in the air permit under the EPA.(See attached letter from Calpine and air permit.) BC Hydro is investigatingwhether the current on-site distillate storage will be a limitation in providing a 240-hour per year peaking service to TGVI. If so, BC Hydro will examine possibleoptions and costs to remove restrictions imposed by the limited on-site storagecapacity.

03

AlII • CALPINE CANADA[.••••••October 1,2004

Nick ChopraBC HydroPower Supply I Resource Management6911 Southpoint DriveBumaby, BCV3N 4X8

Dear Mr. Chopra

Subiect: Distillate Completion and Fuel Transfer.

1'0 IIOXH7

HOO ORANGE POINT IUMD

CAMPHElllllVER, 8C

V9W 581

TELEPHONE (250) 8:10-21120

fAX (2511) IISO-1I189

As discussed in the Operational Committee meeting, Calpine hereby confirms that it hascompleted the distillate system commissioning and testing for the Island Cogeneration Facilityand the system is capable for use as described in the ESA and within the air permit requirementsissued by MWLAP.

The fuel remaining (approximately 982,000 liters) in the tank has been tested and is within thespecifications outlined in the ESA and also meets the requirement of the OEM for usage in thecombustion processes for the Gas Turbine. The original acquisition cost of this fuel is confirmedto be $614,270.05 GST included, based on the cost of the fuel as confirmed by the purchaseagreement with (supplier), a copy of which is attached to this letter.

In accordance with section 7.3(a) of the ESA, Calpine hereby requests that it be reimbursed forthe acquisition cost of such fuel, as set out above.

Curtis oneyPlant ManagerIsland Cogeneration

Enclosures: InvoiceChevron Distillate ReceiptsDiesel Fuel Purchase Agreement

07/tt/tOO: 11:58 FAX 804S41S4~O CALPINE CANJJ>! YVR

MINISrRYOFWATER, lANDAND AIR PROTECTION

PERMITPA-16080

.•ICP PUNT

Under the ProvisJons of the Wasto Management Act

CalpiDe IsbDd Co~tion partnersb.lp do

CaIpbae IsJad CogeoentJoD Project In<!.17~ -1040 Wed Geo,;p Shut

VancouVtl'. nrlt1sh Columbia, VilE 4B1fa authodsed to di$cl1ar80 air cont3U1inmta froln a rogcncntion power facility Jocattd inCampbd1 ItiVta'. British Columbia. tUbjcct to tho cmditions listed be1aw. Contravention of any ofthese cooditiOOl is. viobtion of the Waste MarJa8mu:nt Act and may ~ in pcwccuIioo.

'J:'Im permit is effective on md from J4t)\W)' 1, 2001.

1. AlJ'tHORISJID DISCHARGES

1.1 This subsection applies (0 Ihe discharge of air contaoJi~ts from a NATURALGAS AND OIL.FIRED TVRBINE"GENERATORAND A BEATRECOVERY S'I'B.AM GENERATOR UNIT idc:n1ific:dass 1 on the awdIedSite:Plan A. The site rcfcrm<:e number roc this dlscbargo la EZ41424.

1.1.1 The fue1Jauthorlsod for use are natlIraI t88 and oil (subject toSUbscctioos 2..4 and 26).

1.1.1 The maximum authotised nlO of discharge is 334 m'/s..1.1.3 The autbori:scd discharge period i3 7 dJw. 365 dlL

1.1.4 &cqJt asauthmisal by Subsmioo 2.1, the cbatacteriSdcs of thediechargc sba11not cxceed;Nitrogell Oxides (as NOV

-when fired with na11Ual gas 48 mg/m' .•.-~CD fired with oiJ 80 mglm3 •

Ctrlx>n Monoxidtl 58 mglm' .•.

.•.Hourlyavcragc cOnGC:ntratJons t:OttYXted to 15% Dl.

IbI8 ~ ·Detemba 1.2000Da~ 2(11I04I -> J U L 6 ZDDZp~ 10(6

~--".-..,;r;C- ~';> ••~'~.rcr _

D. P. BrowaRcDOCIOIIW""",,-&t:f

Pt!1I.MIT: PA-I6080

----- ...--

07/2~j2002 11:5& FAl 8048815~~O CALPINE CANADA YVR ~ ICP PLANT r.b 005

1 1

1.1.5 The authorised wow arc a turoinc genCT3lor equipped with dty, lowN01 COJltrol$ when fmd with natun)) ~ and water injection faci1itiC$when fired with oil, a beat reCovery steam gcnaator, &tACk. ducts, andrelated appnrtonance.! approximately JOC3fed as shown on attached SitePlan A-

1.1.6 The authorised woU:s must be complete and in opctation 00 and fromthe effecti ve date of this pmDit.

1.1.7 The: ~on ot~ facilities from which the ~ originates and meiocatiQn of the point of disclmge is Di5trict Lot 109, except Pam:1 A(DD285472-1) and ~ ptrts in Plana 1313-R. 16956. 19311, 50636,V1PS4479..oo VIP64.521 SaywardLandDUtrict.

1.2 This sobsection appliee to the diecharge of lir contaminants from anEMKKGltNCY BACKUPDJESEL 'POWERED GENERATOR andDIFSRJ. roWERED FIRE PUMP idc:mificd as 2 on the attached Site Plan A.'The site rcfete:nCC number fox this dischq& aB2429 14.

u..1 The IIWdm1Ixn authOrlsed rate of ~ iJ 100m'/mm.

J.1.1 The J.UtboriJed ditchargc period js intermittent (UDU.gt::rq pawct'backup and fire fighting).

1..2.3 Tbcchatacterlstics of tho discharge shall beequivaknt to, or bettcrthan,typiC3.1 emiS$iOllS from dfdeJ powered caglnes (St1b~ to Subsection2.5).

1.2.4 The authorised WOJ:b are a dleael poweted generator and a dieselpowered fire pump. stacks and rclated appurtenances appmximatclylocmd as d10wn on attded Sitc Plan A.

1.25 The autbodsed worlcJmust be in pl~ and in operation on and from thedfec:tive date of thh pennit.

1.2.6 The location of the facilitit.S 1Iom which the dUch3rge od~ .wi thelocation of1he point of di~ Js tho same l~OD as Jet out inS~on 1.1.7•.

1.3 ThiJ ~ applies to the 0i3cl1argc ot air·confilmin< ••~• from aMECHANICAL DRAFT COOLING TOWER identified as 3 on the attachedSilO Plan A. ~ sile tderencc number for WI di8Cba(ge ia B:24:291S.

1.3.1 • The ~mum au2horiStd ~ or discharge is unspc:cificd.

1.3.2 The authoriso!i discharge period is 7 dIw,365 dlL

1.3.3 The characteristics of the dIacharge 3hall be equivalent to, ()( bottcr than,typical cmWions from a mcc:hanlcal dtatt cooling towa.

I)Q&c1uucd: ~ I, 2000

~~ JUl 2 6 1002Pao= 20(6

• h".' • ." ,.~ •~~ _ .' __ '.,' •• ',-,_

~-.D. P.1!n7wD..

~WMU~

PEJUtU: PA-l6OiO

CALPINE CAlillIA YVR .• ICP Pl.A.~ iiflDoe

1~

1.3A 11.K:audtOtised wad:! 8tC a m.c:cbtnlcal draft cooling tower, ~U&t ventand related ~ 1pP1t)ximate]y loc4lted as shown on attachedSire P1aD A

1.3.5 The authoriscd worb must be in place and in. operation on and from theetfectiYO date of this pc:m1it.

1.3.6 The location of 1M facilitiC6 from which the discharge originates fIXld !helocation of the point ot discharge is the same JOCI.UOl1I$ sot out inSubUCtion 1.1.7.

2. GENERAJ..~O~

1.1 StAbtW'c! CondIttons

For the administration of this peD'Dit aD ~ volumes shaIl be converted tostandard cooditlOns of 293.15 K. and 101.325 kPa with zero~ moisture.

:u ~~ Pro<:tdure8

In the evc:ntof an ~ which prevents compliaoo:: with a rcquiremeat of thispronit. that ~t may be suspended for such time 1$ the emergency cmta oruntil 0tbenviJc ~ by tbe RcgiOlUl Waste MmAger provided that:

a) Due diligence wu exercised in ftI1atioo to the ~ opemion Q(" oventwbicl1 caused 1he ~y and that the cmctgeI1cy occumd notWithstanding thisexercise of due .mi~:b) The ~giooa1 WumManageru im~lynoti6ed oftbe ~y; andc) The: ~y is beiJi~ tomcted with due diIl~•

Notwidutanding It. b, and c above. the Regional Waste Manap may require the~OD to be smpMded to protect ~ environment wbiJe die sitUatioG is com:cted.

2.3 ~

The peonittee shalt ensure that DO waste ill disc.batged without being proteSiedthrough tba authorlscd weds unlru plOt"wriU= apptOval.b ~ from theRislonal Waste Manag«.

2A ~ht,p' Content of Fntl (enwom lI\ttborlsed in Su~n ),I}

Tho pCrmittee £hall not U$Oany fuel as a backup to naIutal gas that has & sulpbllroontent in ~xceu of 0.05%.

DorcIUDCd: ~ 1. 2000=:r~ a: JUl 20 Z002~3oC6

d?'" ~;:.._0.1'."10'1I"II..

~oaaI WUIC~

I'EJUdIT: PA·J6OIO

01/%'/%00% 11:SD FAX 60l6S154DO CALPINE CANADA YYR .• ICP PI..ANT !jf)007

content of each shipment of fuel ttaived.

2.! Sulphur Co~~nt of Fu~l ([or works autborlsed in SubIoection 1.2}

In accoWance with !.he Su1phUl: Qrntc::nt of Pud Regula.tion. the' pennil.tcc sballllotU$C fuel rb.tt baa a sulphur content in excess of 1h~ specified lJU;timum content(cwrcntly 1.1~).

2.6 UseI)f Oil

2.6.l Oil slWl be used as a backup fuel ooIy during perioch wbed the natural gas". supply is curtai.1cd. 1'hosa periods aball not ex.Ct\td 8 total of 10 days in any

calendar year.

1..6.Z Id the c:a$C of an ~• the Regional Waste Manager may allow thebIJInIn. of on in cxccu of the ~lowablc 10 da~ provided fO(' in Sub&edioo2.6.1.

2.7 OPeration durlw!'Low 'f'..oad·ClrcumsfJmces

As a nsult of law Joad ~ includiDl but not limited to~uiDg.testing. planned.maintmance acdv:ltf6S.or during 1WtIra183$ inlenUption" thotuibine p,i:nI:C8ll1r~y be shut down or operated Udder 10w Joad. 11i3 ~that undct low load conditions (e.g., immedialdy prior to shut-down and for alonger period fo11owlng start-up). the di..sch.atgc may not meet 1M cblll1llCtMatiCSspocified in Subsection 1.1.4. In this ~gard:

2.7.1 Uu1css oth«wiso authorised by tho Re;i<>na1 Wastc Managct, an allowanceis provided wbiclJ au1horiscs the permiuI:e to dis.chugc cadJoq JDOIIOJUdoupto a muimwn hourly avezagc concentration of 116S mgJm3~ed to15~ Oz. du1:in3 tho foDowlngpcriods: .

:a.)when the nominal inputenergyfiring~'51e&$ than 1411 GJ/h;b) for 3 booB fo11owing a twbIne ~ ItMt-up; and. .c) roc 1.5 bouu iInm:diatcly pnx:cdiag the tmbine genuator 0Ut down.

2.7:J. Written permission of the Regional Waste Mmaget' ia required during low)qad ciJ:cumIt2nce& in which the nt)PIinal input ~ firipg fi1to is leu than733 G!/boor (40% load).

Based on tho msu]ts of the monitoring program ~fied in Section 3 and/or other1n1'ormatlon obtai.ot:d in connection with the discharge aUthoristd in Sub8ection 1.1,tbc: pc:nnitt<:c tnay be Jaluircd to take ~ andr'or provide addJtiooa1 ~

Dare~~1.1OOO

~~ JUl 2 62002h;c:4oC6

D. F. &owL.P..cPmaI Wuu: Maoupr

J'!!J\MIT.: rA-16O&O

01It~/!OO% 11:Si FAl $04$815480

facilities.

CALPJN1! CANADA l'VR .• I CP PLANT IilJOO&

1 4

3. JdONITORJNG AN})REPORTING .REO~NTS

3.1 DJscbarr.e Mon1t()rlDl~

3.LZ Nitrogen Oxides (as ~Catboa Monoxide~hrtJcu1ato MattaSulpbUt Dioxi&Rate ofDischargcDischargc't~

SmauIiD~ Fn411&C{

ContinuoWlyContinuouslyeamp1c stack oaccIannum(Note 1)(Nota 2)(Note 2)

Note 1; lX;tc:rmine the &U1pbureontent of each shipment of oil.Note 2: Tb& !tcquency and method of J.1lOIIitoring shall be: approved by theRegional Waste Managtr.

Based 011 tbe reaalts of the discharge monitoring mdlO1' the data obWnedfrom the ambient rooaitoring apccificd in Sub8tlction 3.2 the manltodngnquircmcnts maybe C'Jltendedoc:alttmJ by 1bc: llcgiODal Wane Manager.

3.1.3 COOU02 Tower

~ VisU211rionitoring of ~ cooling tower dlacharge will be cani&d OUtbyPollution Preventioo $faff a$ part of a monitoring progrAm for the mti1ecogcncotion power facility opcntion. lJased on tbece mooitoring resultsthe petmittcc o»y be JeqUitcd to provide and imp1cma1t additional cootroI.athat arc considered~•

:u Ambient AIr MonJfDrlnl!

At a site or utes approved by Ibc 1tegI0C31Waste Maoaser Ihe pcnnlttee shancont:inJJously measure nitropl oxides and oz:ono, and RiCOl'd the ~ in ppb(voJuroe) avenged OVes'ODe hour periods.

'~~ru-D. P. &vwa...

~W~~

~r!orl6080

._--'------_ ..-~ .•---. ---~._-------

---------~~~~~~~~~~~~~~~~~--

1507/t~/200% 12:00 FAl $04881S4PO CALPINE CANADA¥\'l! .• ICP PUNT .

3.3 M~t0rb12 ~UhS

3.3.1 SampUnSl': Locations and TecbnfQ1.JCS

AU sampling localions, teChniques and equipment require the consent of the~!iooal Wute Mm~priOtto use. Sampling and monitoling data,which also should include rate of di:scharge DX8Jurcment:s or calculationsand diBcbArgetemperature IneUlIremaltB. 8baUbe accompanied by p~sdata re]cvmt to the opention of the SODI'CC of the emission and theperf~ of the pollution abatement equipment involved in the UlSling.

3.3.2 S9mptln2 and An.ITtt~ J>roadtU'e$

$nopJing and rate of di5chargc ~ 8Ial1 be canied OUt in. acoonJance wilh the proce4\ma dcIaibcd in 1bc -Briti$b Columbia :FieldSampling Manual for CoDlinUOU$ Monitorinl Plus tho CoI1ectioa of Air.Aifl-EmissiOl1, W:ata, Wastewater, Soil. ScdimcDt. and Bio1ogical Samples.1996 Edition {Petmittcc)". or by suitabJo a1~ve ptOCedure$ asauthodsed bY the llegiOllal Waste Managtt.

Copies of the abovo roanuaJs may be pmcba.ced from the Queen', PrinterPublications Centm, P. O. Box 9452, Stn. Prov. Gov't. Victoria.Brltlsb Columbia, ViW 9V7 (1-800-663-0105 or (250) 387~), IIId arealso available rodnspc:ctioo at.aU Pollution Pt&vtJntion offices.

3.3.3 Reportin~

Unlcu ~ o<heJ:wj$C by tnc RegitJ~ Wastr: Man:agcr the ~$hall $Ubmit,once eacb quartu. the results ot the monitoring programspeci&d in Subsccti0l13.I. The data fornitrogeD oxides and carbonmonoxide shall be rcpontJd in tr:rms ofhoudy a~ The PM2.S ~(sshall be reponed in the quaruny rcpott 1oDowiDgthe q11al1CriD which tMumpllng was CODductcd. The Regional Waste Managt::rmay request thatdata be submiucd in a machine readablo fOODat suitable for entry into theMini&tlJ of Environment. Lands 8J:¥i Parks ~lcrdal.a ~ The

. lnt'ODDation &hall be ~miUed within 30 da)'$ fo11owi11g the qUArtet' inwhich the data was collecttd

In addition, the pcnnittee shaJrsubmit on or before Jun~ 30 of e.ch year •• com~ve mview and analysis of the ambient air monitoring data

obtained during the previOU& calendar year.

.'._-'-_.'-'-'-'-~-_._------_._-

D. P. eXOWD..

R~WJl:lta~

PERMIT: P A-16D80

~--------~--_.- ..

07/2~/200% 1%:00 PAl 60t8315480 CALPINE CAHAbA YVR .• I CP PlANT ijJ OJ 0

16

JUL 2 I) ZOOZ

AN·

SITE PLAN A

ScaJc: 1: 1.470

Permit: PA.l6080

Date:

D. F. BrownRegional Waste ManagerVaocouvuIsland •on

British Columbia Utilities Commission Information Request No. 1.3.4 PageDated: November 3, 2004 1British Columbia Hydro & Power AuthorityRespOnse issued November 10,2004Terasen Gas (Vancouver Island) Inc. 2004 Resource Plan Application Juty8, 2004 andTerasen Gas (Vancouver Island) Inc. LNG CPCN Applicationdated August 4, 2004

3.0 Reference: Exhibit B-3. Response to BCUC IR 10. 34.10

1.3.4 At the time of drafting this Information Request, BC Hydro had notannounced the result of its Vancouver Island Call for Tenders("CFT"). What is the amount of fuel gas that will be required tooperate at normal full capacity the gas-fired generation onVancouver Island that BC Hydro expects will result from the CFT(the "CFT Generation")?

RESPONSE:

The firm natural gas requirement for the Duke Point Power Project is 44.6 TJ/dayto meet a dependable capacity of 252 MW. The actual volume of gas consumedwould depend on how BC Hydro dispatches the plant.

17

British Columbia Utilities Commission Infonnation Request No. 1.3.5 PageDated: November 3, 2004 1British Columbia Hydro & Power AuthorityResoonse issued November 10 2004Terasen Gas (Vancouver Island) Inc. 2004 Resource Plan Application July8, 2004 andTerasen Gas (Vancouver Island) Inc. LNG CPCN Applicationdated August 4, 2004

3.0 Reference: Exhibit B·3, Response to BCUC IR 10, 34.10

1.3.5 For the CFT Generation, please explain any ability that thegeneration will have to operate on a fuel other than natural gas,the amount of curtailment of gas deliveries that would be possibleon a day and the maximum amount of curtailment over a year.

RESPONSE:

Under the awarded EPA, the Duke Point Power Project, as currently configured,will not have dual fuel capability. However, the option exists to considerinstallation of dual fuel capability subject to justification and agreement with theproject proponents. Also, additional permits would be required for the dual fueloption.

18

Terasen Gas Vancouver Island Inc. 2004 Resource Plan Re ort

~TeraSenGas

APPENDIX E

1 9

Capital Spending Schedules for all Portfolios

Page 77

Incremental TGVI Facility Requirements for the Base + 0 TJ/day Forecast

200820092010201.12012201,32014201520162017201820192020202.12022202;3202420252026

LegendCFT MSdlskmLNGPMsparesV1U4V1 U4 (Mars)

2.3%

2.4%:::~;~<J:9

2.5%

CFT Meter Station'downstream of'kilometre'Mt Hayes LNG Storage Facility'Port Mellon'Spare Engines4th unit to VI - Coquitlam Compressor Station4th unit (Mars) to VI - Coquitlam Compressor Station

- 1 -

V1U5V2V3bV4V5WFWS

5th unit to VI - Coquitlam Compressor StationV2 - Squamish Compressor StationV3b - Secret Cove Compressor StationV4 - Texada Compressor Station (retention and upgrades)V5 - Dunsmuir Compressor Station'Woodfibre''Watershed'

No




RESPONSE TO COMMISSION INFORMATION REQUEST NO.2

BCUC IR 48.2

ATTACHMENT 3

Capital Plans for Revised Demand Scenarios

- 13 -

2 1

2004200S2006209720082009201220132014261s20162017201820192020202120222023

2026

Legend

TERAS EN GAS (VANCOUVER ISLAND) INC.

RESOURCE PLAN REPORT DATED JULY 8,2004 ("RESOURCE PLAN")CERTIFICATE OF PUBLIC CONVENIENCE AND NECESSITY APPLICATION



Revised Base +0 Forecast· Incremental Facilit Re uirements

CFT MSdlskmLNGPMsparesV1U4

CFT Meter Station'downstream of'kilometre'Mt Hayes LNG Storage Facility'Port Mellon'Spare Compressor Engines4th unit to VI - Coquitlam Compressor Station

-15 -

V1USV2V3bV4VSWFWS

Sth unit to VI - Coquitlam Compressor StationV2 - Squamish Compressor StationV3b - Secret Cove Compressor StationV4 - Texada Compressor Station (retention and upgrades)VS - Dunsmuir Compressor Station'Woodfibre''Watershed'

NN

British Columbia Utilities Commission Information Request No. 1.3.8 PageDated: November 3, 2004 1British Columbia Hydro & Power AuthorityResponse Issued November 10, 2004Terasen Gas (Vancouver Island) Inc. 2004 Resource Plan Application July8, 2004 andTerasen Gas (Vancouver Island) Inc. LNG CPCN Applicationdated Auaust 4, 2004

3.0 Reference: Exhibit B-3, Response to BCUC IR 10, 34.10

1.3.8 Further to the foregoing responses, please provide BC Hydro'stotal firm gas demand by year for ICP and the CFT Generation(both before and after possible curtailments) from 2007 through2026. Please also identify the total firm gas transportationcontract demand by year that BC Hydro expects will be needed forgas-fired generation on Vancouver Island. Please explain how theresponse is consistent with the 2004 Integrated Electricity Planthat BC Hydro filed on March 31,2004.

RESPONSE:

Please see BC Hydro's responses to BCUC IR 1.3.3 and 1.3.7 for schedules of thefirm gas demands and curtailments for ICP and the CFT Generation. The CFTGeneration is a combined cycle gas turbine at Duke Point and is similar to thepreviously proposed VlGP. The Duke Point Power Project, as currently planned,does not have fuel switching, thus no curtailments are assumed for this plant. Forthe two projects, the year-over-year total firm gas demand (before and afterpossible curtailments) and the total firm gas transportation contract demands areshown in the table below.

The information is consistent with BC Hydro's 2004 Integrated Electricity Plan,which assumed a firm contract demand of 45 TJ/day for ICP. The IEP showed afirm gas demand for the CFT of 25 TJ/day based on a 150 MW gas-fired project.The firm demand of 44.6 TJ/day for the Duke Point Power Project is slightly lessthan the 45 TJ/day firm demand for VIGP filed at the 2003 VIGP hearing.

The 45 TJ/day firm demand for ICP can be more properly described as "curtailablefirm" given that the project may be fuel-switched to distillate oil for up to 240hours per year without reducing electrical output. The table below assumes thatthe aggregate maximum amount of ICP curtailment for fuel switching over theterm of the EPA is 4,500 TJ. This volume is equivalent to 45 TJ/day for 100 daysand is assumed to be used up In the 10-year period 2007 to 2016. If less than the4.500 TJ of curtailment allowed under the EPA were used in this period, additionalcurtailment would be available after 2016.

23

British Columbia Utilities Commission Information Request No. 1.3.8 PageDated: November 3, 2004 2British Columbia Hydro & Power AuthorityResponse issued November 10, 2004Terasen Gas (Vancouver Island) Ine. 2004 Resource Plan Application July8, 2004 andTerasen Gas (Vancouver Island) Inc. LNG CPCN Applicationdated Auaust 4, 2004

Vancouver Island Gas-Fired Generation- Daily Gas Demands by Year for ICP & Duke Point Project (TJ/day)

Year 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016Firm Demand 89.6 89.6 89.6 89.6 89.6 89.6 89.6 89.6 89.6 89.6(No fuelswitching atICP)Firm Demand 44.6 44.6 44.6 44.6 44.6 44.6 44.6 44.6 44.6 44.6(With fuelswitching atICP)Contract 89.6 89.6 89.6 89.6 89.6 89.6 89.6 89.6 89.6 89.6Demand

Year 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026Firm Demand 89.6 89.6 89.6 89.6 89.6 89.6 44.6 44.6 44.6 44.6(No fuelswitching atICP)Firm Demand 89.6 89.6 89.6 89.6 89.6 89.6 44.6 44.6 44.6 44.6(With fuelswitching atICP)Contract 89.6 89.6 89.6 89.6 89.6 89.6 44.6 44.6 44.6 44.6Demand

24

ROBERT J. PELLA TTCOMMISSION SECRETARY

[email protected] site: http://www.beuc.com

VIA [email protected] August 23, 2004

25SIXTH FLOOR, 900 HOWE STREET, BOX 250

VANCOUVER, RC. CANADA Voz. 2N3TELEPHONE: (604) 660-4700

BC TOLL FREE: 1·800-{i63·1385FACSIMILE: (604) 660-1102

Log No. 7098

Mr. Scott ThomsonVice President, Finance and Regulatory AffairsTerasen Gas Inc.16705 Fraser HighwaySurrey, B.c. V3S 2X7

Dear Mr. Thomson:

Re: Terasen Gas (Vancouver Island) Inc. ("TGVI")Deferral Account for Preliminary Expenditures

for a Liquefied Natural Gas Project on Vancouver IslandJuly 2004 Update Report

This is to acknowledge TGVl's August 16,2004 letter which provided the July 2004 Update Report on thedeferral account that was approved by Order No. G-69-03 for preliminary expenditures for a Liquefied NaturalGas ("LNG") project on Vancouver Island.

The Commission notes that TGVI expects to enter into a sole source contractual arrangement for the LNGProject that will cover activities to mid November 2004 and which will include sufficient detailed engineering toprovide a firm project price from the contractor to TGVI at that time. TGVI will be expected to justify that itssole sourcing approach for the LNG project and any funding allowance for the contractor are in the best interestsofTGVI customers.

Yours truly,

JBW/rtcc: Registered Intervenors

TGVI/Cor/July Update Report_LNG Project



DA TED AUGUST 4, 2004 ("CPCN APPLICATION")


28.4 What is the estimated total capital cost in as-spent dollars, for each year of theproject and for the entire project?

Response

$MillionAs Spent $ 2004$

LNG Total $96.5 $94.4

SpendingProfile

2003 $0.42004 $1.62005 $22.82006 $26.62007 $45.1

Total (exclafudc) $96.5

afudc $9.5 $9.3

Total (inclafudc) $106.0 $103.7

28.5 In its July 2004 Update Report dated August 16, 2004 on the deferral account forpreliminary expenditures on the LNG Project, TGVI stated that it intended toenter into a sale source contractual arrangement with an EPC contractor inAugust and that it expected to receive a firm EPC price approximately November15, 2004. Is this schedule still current?

Response

TGVI entered into a designlprice determination contractual arrangement with onecontractor in late September following a sole source selection process. The currentschedule now anticipates the firm EPC price to be obtained from the contractor byJanuary 27, 2005.

- 149 -

26





any bid and these negotiations would result in schedule delays and increased costs. Itis TGVl's view that a sole source EPe contact negotiation is in our customer's bestinterest as it is the best method of getting an EPe price at the least development cost fora facility design that is acceptable to TGVI and at terms and conditions acceptable toTGVI.

Also refer to response to Question 28.9 below.

28.7 Although the cost of the pipeline connections and many site costs are likely to besite-specific, what information can TGVI provide about the actual costs of similarLNG facilities that have been built recently that confirms the cost estimate for theLNG storage, liquefier and vapourizer?

ResponseSee the table provided in response to Question 28.1 above. The two projects Williams(Pine Needle) and Memphis Gas (Memphis) are the most recent peak shaving facilitiesbuilt in North America.

28.8 What is TGVl's level of confidence in the $94.4 million estimate? Is this a P50estimate (i.e. 50 percent probability that the actual cost will be this amount orless)? Please identify the P50 and P90 (90 percent probability that the actualcost will be the amount or less) estimates for the project.

ResponseThe current cost estimate for the LNG project is based on previous project costinformation as shown in response to IR 28.1 above. The current project estimate of$94.4 ($2004) million has a confidence level in the order of +1-15%. This estimate isreasonable based on the information available, but cannot be confirmed without thedevelopment of a detailed design specific to the facility conditions. TGVI has engagedan EPe contractor to do this design and price development work leading to a firm EPecontract price and detailed scope of work by Jan. 27, 2005 at which time TGVI wouldhave a control estimate with a confidence level within +1-10%.

28.9 Under a firm EPC price contract, please describe the cost and schedule risks thatwould be assumed by the contractor.

ResponseThe EPe contract firm price will be based on a detailed design, preliminary bids formajor materials, equipment and subcontracts and detailed construction and project

- 151 -

27

ROBERT J. PELLATTCOMMISSION SECRETARY

[email protected] site: http://www.bcuc.com

VIA FACSIMILE / E-MAIL«Email Fax»

«Gendem «FirstName» «LastName»«Title»«Company»«Company2»«Address 1»«Address2»«City», «Province» «PostalCode»

Dear «Name2»:

March 31, 2004

LETTER No. L-18-04

SIXTH FLOOR, 900 HOWE STREET, BOX 250VANCOUVER, B.C CANADA V6Z 2N3

TELEPHONE: (604) 660-4700BC TOLL FREE: J -800-663-1385

FACSJMJLE: (604) 660-1 J 02

Re: British Columbia Utilities CommissionCertificate of Public Convenience and Necessity ("CPCN") Application Guidelines

Please find enclosed the British Columbia Utilities Commission's CPCN Application Guidelines, and OrderNo. G-28-04 which cancels Commission Order No. G-133-99 and the CPCN Application Requirements thatpreviously were in effect.

Draft CPCN Application Guidelines were distributed to public utilities and other interested parties for commentby Letter No. L-4-04 dated January 28, 2004. The Commission appreciates the helpful comments that wereprovided by a number of parties, and has revised the CPCN Application Guidelines in response to thesecomments.

The purpose of the CPCN Application Guidelines is to assist public utilities and other parties wishing to constructutility facilities in their preparation of CPCN applications so that the review of the applications can proceed asefficiently as possible. Future CPCN applications should be prepared in accordance with the Guidelines.

Yours truly,

Original signed by:

Robert J. PellattJEW/emsEnclosure

MisCor/CPCN Application Guidelines-Final

LETTER No. L-18-04Page 5 of?

CPCN APPLICATION GUIDELINES

A CPCN application under Sections 45 and 46 of the DCA should contain the following infonnation:

1. Applicant

(i) the name, address and nature of business of the Applicant and all other persons having adirect interest in the ownership or management of the project;

(ii) evidence ofthe financial and technical capacity of the Applicant and other personsinvolved, if any, to undertake and operate the project;

(iii) the name, title and address of the person with whom communication should be maderespecting the Application; and

(iv) the name and address of legal counsel for the Applicant, if any.

2. Project Description

(i) a description of the project, its purpose and cost, including engineering design, capacity,

location options and preference, as well as all ancillary or related facilities that are

proposed to be constructed, owned or operated by the Applicant;

(ii) an outline of the anticipated timetable for construction and operation, together with dates

by which critical events, including approvals required from other agencies, must take

place to ensure continued economic viability;

(iii) a description of any new or expanded public works, undertakings or infrastructure that

will be entailed by the project, together with an estimate of the costs and necessary

completion dates;

Issued: March 2004

LETTER No. L-18-04Page 6 of7

(iv) identification and preliminary assessment of any impacts by the project on the physical,

biological and social environments or on the pubhc, including First Nations; proposals

for reducing negative impacts and obtaining the maximum benefits from positive

impacts; and the cost to the project of implementing the proposals; and

(v) identification ofthe customers to be served by the project; and, where the project would

expand the area served by the Applicant, a geographical description of the expanded

servIce area.

3. Proiect Justification

(i) studies or summary statements identifying the need for the project and confirming the

technical, economic and financial feasibility of the project, identifying assumptions,

sources of data, and alternatives considered (if applicable);

(ii) a study comparing the costs, benefits and associated risks of the project and alternatives,

which estimates the value of all of the costs and benefits of each option or, where not

quantifiable, identifies the cost or benefit and states that it cannot be quantified;

(iii) a statement identifying any significant risks to successful completion of the project; and

(iv) a statement of the revenue requirement impact of the project and the resulting effect on

the rates of customers; and

(v) information relating the project to the Applicant's approved resource plan and action plan

filed pursuant to Section 45(6.1) of the DCA, which may address some or all of the

Project Justification requirements.

Issued: March 2004

LETTER No. L-18-04Page 70f7

4. Public Consultation

(i) a description of the Applicant's public infonnation and consultation program, including

the names of groups, agencies or individuals consulted, as well as a summary of the

issues and concerns discussed, mitigation proposals explored, decisions taken, and items

to be resolved.

5. Additional Requirements for New Service Areas

(i) the telephone number or other means by which customers will be able to contact the

utility, particularly regarding an emergency;

(ii) the facilities and trained personnel that will provide emergency response;

(iii) the tariff including tenns and conditions of service, rate schedules and initial rates that

the Applicant proposes for customers in the new service area; and

(iv) information confirming that the proposed rates will be competitive with other service

options that are available to customers in the new service area.

6. Other Applications and Approvals

(i) a list of all approvals, permits, licences or authorizations required under federal,

provincial and municipal law; and

(ii) a summary of the material conditions that are anticipated in the approvals and

confinnation that the costs of complying with these conditions are included in the cost

estimate in the Application.

Issued: March 2004

IN THE MATTER OF

West Kootenay Power Ltd.

CERTIFICA TE OF PUBLIC CONVENIENCE AND NECESSITY

Kootenay 230 kV System DevelopmentProject

DECISION

June 5, 2000

Before:

Peter Ostergaard, ChairKenneth L. Hall, P.Eng., Commissioner

Paul G. Bradley, CommissionerBarbara L. Clemenhagen, Commissioner

TABLE OF CONTENTS

Page No.

EXECUTIVE SUMMARY1.0 INTRODUCTION

1.1 Background1.2 Related Reports, Meetings and Workshops1.3 Generation and Transmission Providers

1.3.1 West Kootenay Power Ltd.1.3.2 Cominco Ltd.1.3.3 CPC/CBT1.3.4 1996 Facilities Sharing Agreement1.3.5 British Columbia Hydro and Power Authority

112345789

2.0 WKP APPLICATION FOR SYSTEM DEVELOPMENT 112.1 The 20 Year Transmission and Distribution Master Plan 112.2 System Impact Studies for Transmission System Expansion 112.3 Feasibility Study for Transmission System Expansion 122.4 Public Consultation 122.5 The Application 132.6 WKP Requests for Commission Directions 15

3.0 WKP PLAN AND INTEGRATION OF SYSTEM 153.1 Evaluation of Present WKP / Cominco System 15

3.1.1 Physical Condition and Safety 153.1.2 System Stability, Reliability and Power Quality 16

3.2 Minimum System Planning Criteria 173.3 Voltage of Transmission System 183.4 System Configurations to Address System Deficiencies 183.5 Comparison of System Planning Options 20

3.5.1 Qualitative Comparisons 203.5.2 Economic Comparisons 21

3.6 Other Planning Options from a Single System Viewpoint 223.6.1 The Current Status of System Integration 223.6.2 Alternative System Configurations and Possible Redundancies 23

3.7 Commission Findings 25

4.0 TRANSMISSION LINES 264.1 South Slocan to BrilJiant 26

4.1.1 West Route 274.1.2 Low Elevation Route 274.1.3 High Elevation Route 294.1.4 Economic Impacts 294.1.5 Commission Findings 30

4.2 BrilJiant to Warfield 314.2.1 The K3 Route 314.2.2 The K5 Route 324.2.3 The Crossover Route 334.2.4 Economic Impacts 334.2.5 Commission Findings 34

4.3 Warfield to Waneta 354.3.1 Connection to Waneta 354.3.2 Selkirk and Nelway Alternatives 364.3.3 Warfield to Waneta Alternatives 374.3.4 Cominco Exemption Order Considerations 384.3.5 Commission Findings 40

TABLE OF CONTENTS(Cont'd.)

Page No.

4.44.5

Communication SystemElectric and Magnetic Fields, Radio Interference and Noise Levels4.5.1 Commission Findings

414243

5.0 SUBSTATIONS AND INTERCONNECTIONS 435.1 South Siocan to Kootenay Canal Plant 445.2 Connection at Brilliant 44

5.2.1 CPC/CBT Exemption Order 455.2.2 CPC/CBT Position 455.2.3 Commission Findings 46

5.3 Warfield Substation 475.3.1 Cominco Position 485.3.2 Commission Findings 48

5.4 Waneta Substation 495.4.1 Commission Findings 49

5.5 Connection of Line No. 71 to Nelway 505.5.1 Cominco Position 505.5.2 B.C. Hydro Position 515.5.3 Commission Findings 51

5.6 Rate Schedule 110 - Long-Term Alternate Path Transmission Service 525.6.1 Commission Finding 53

6.0 FINANCIAL CONSIDERATIONS AND RATEPAYER IMPACTS 536.1 Cost Estimates and Potential Variances 536.2 Cost Sharing 55

6.2.1 Commission Findings 586.3 Financing and Funding Alternatives 606.4 Revenue Requirements and Ratepayer Impacts 616.5 Cost Collar Incentive Mechanism 61

6.5.1 Commission Findings 63

7.0 FUTURE INTEGRATION ISSUES 637.1 Emergence of a Regional Transmission Organization 637.2 Impacts of a RTO on Transmission Pricing and Access 647.3 Participation in an Integrated System: Regulatory Concerns 657.4 Commission Findings 66

COMMISSION ORDER NO. C-I0-00

APPENDIX AAPPENDIX BAPPENDIX C

FIGURE 1FIGURE 1.1FIGURE 1.2FIGURE 4.1FIGURE 4.2FIGURE 4.3FIGURE 4.4FIGURE 4.5FIGURE 4.6FIGURE 4.7

AppearancesIndex of Sworn WitnessesExhibits

Last page of Executive Summaryfollows page 4follows page 4follows page 27follows page 27follows page 28follows page 31follows page 31follows page 31follows page 31

EXECUTIVE SUMMARY

West Kootenay Power Ltd. is an investor-owned electric utility providing wholesale and retail service in thewest Kootenay and south Okanagan regions of British Columbia. It is a public utility regulated by theBritish Columbia Utilities Commission in accordance with the Utilities Commission Act. Annual peakloads on the WKP system are in the order of 600 to 650 MW. The Utility owns four small hydroelectricplants on the Kootenay River with a combined rated capacity of 214 MW. Remaining needs are metthrough power purchase contracts.

The WKP transmission system in the Kootenay and Columbia valleys consists of a series of 63 kV linesmounted on wooden poles. Much of the system was built in the 1930's and has deteriorated to the pointwhere safety, reliability and quality of service are compromised. Also, the system is somewhat isolatedfrom 230 kV systems developed more recently in the area. This isolation can cause outages and relateddifficulties. In April 1999, following a series of studies, WKP filed with the Commission a 20-yearTransmission and Distribution Master Plan. In November 1999, WKP applied to the Commission for aCertificate of Public Convenience and Necessity to develop a fully-integrated, 230 kV system to upgrade itstransmission and substation system in the Kootenay region.

The generation and transmission infrastructure in the Kootenay/Lower Columbia region is unusuallycomplex. Four companies own electrical generation and transmission facilities in the area. Generationtotals 2,100 MW and is likely to increase to 2,500 MW or more in the near future. In contrast, themaximum Kootenay area load is only 450 MW, comprised of WKP's customer load of 200 MW andCominco's 250 MW industrial load. Cominco has its own aging generation and transmission system,which it views as a strategic asset to ensure its regional economic viability. In the 1960's and 1970's, B.c.Hydro superimposed a new 230 and 500 kV system to connect its large generation plants with loadsoutside the region, and to meet Columbia River Treaty obligations. More recently, the Columbia BasinTrust was established with a mandate to invest in and develop power projects, using some of the Province'sproceeds from the sale of the Columbia River downstream benefits. In 1996, a joint venture of theColumbia Power Corporation and the CBT Power Corporation ("CPC/CBT") purchased from Comincothe Brilliant Dam and Powerhouse and expansion rights to Cominco's Waneta plant.

WKP's Application for a 230 kV system development describes proposed new transmission lines, and newor rehabilitated substations and switchyards, that WKP states it needs to upgrade and expand itstransmission system in the Kootenay region. It includes proposed additional connections to adjoining230 kV systems for additional reliability and system security. There has been a long history of mutualsupport and co-operation between WKP and Cominco in the joint use of facilities. The WKP proposaldepends upon agreements with Cominco at the Warfield and Waneta facilities, with CPC/CBT at Brilliantand with B.C. Hydro for connections at the Kootenay Canal plant and at the Nelway substation.

EXECUTIVE SUMMARY

There are a number of agreements among the four owners of generation and transmission facilities in theKootenay region. All parties were involved in the preliminary studies and negotiations were undertaken toseek amendments to agreements where necessary to accommodate the WKP system development proposal.In its Application, WKP stated that it expected to have all the agreements in place prior to the opening ofthe public hearing; however, the negotiations were not completed successfully. As a result, WKP requestedthat the Commission issue directions to the other parties to meet WKP's requirements. This, as explainedin the Reasons for Decision, the Commission declined to do. In its Decision the Commission directedWKP to resume negotiations and urged all parties to work together to find solutions for their mutualbenefit.

By Order No. G-125-99, the Commission established the Regulatory Agenda and Timetable to review theApplication. A public workshop and pre-hearing conference was held in Castlegar on January 14,2000. Apublic hearing was held in Castlegar and Brilliant from February 21 to 24, and from March 13 to 16, 2000.Evening sessions were held on February 22 and 23 and on March 13 to ensure that concerned residentscould participate in the hearing. The Application, as amended, requested approval of option K3 of theFeasibility Study Report.

The Application requested approval for construction of the fo1Jowingfacilities:

• South Slocan switchyard modifications and an additional 63 kV tie to the B.C. Hydro KootenayCanal plant, and Kootenay Canal substation modifications

• Kootenay Canal to Brilliant 230 kV line via the East High Elevation route• New Brilliant substation• Brilliant to Warfield 230 kV line via existing river line route• Warfield substation replacement• Warfield to Waneta 230 kV line along existing route• Waneta switchyard expansion• Connection from Cominco's 230 kV Line No. 71 to B.c. Hydro's Nelway substation• Breakers and improved protection at WKP generation stations• Communications system

The transmission assets in the region are identified on Figure 1, attached.

Participants in the hearing generally agreed that WKP's transmission assets in the Kootenay region werereaching the end of their physical life and that a major refurbishment was required. However, severalparticipant groups opposed specific routings or the sizing and ownership of specific assets.

11

EXECUTIVE SUMMARY

Residents of Glade and nearby settlements expressed their opposition to routing the transmission linebetween South Slocan and Brilliant nearby their communities. This group supported a new route east ofthe present B.C. Hydro right-of-way, and WKP adopted this "East High Elevation" route as its preferredoption during the hearing.

Atco Lumber Ltd. and others concerned about forest, wildlife and wilderness values, opposed the routing ofnew transmission corridors through forest and umoaded lands.

CPClCBT expressed numerous concerns about the Project, primarily with respect to the ownership, costsharing and implications for regulation of the proposed new Brilliant substation. CPC/CBT was alsoconcerned that the proposed new transmission line between Warfield and Waneta could jeopardize theirrights in future to the use of Cominco' s Line No. 71.

Cominco's concerns related to maintaining the viability of its operations at Trail and minimizing itstransmission and substation costs, along with maintaining low cost access to export its surplus power to theUnited States. If Cominco is able to renegotiate the delivery point of its power under the Canal PlantAgreement, it would not require capacity on the proposed Kootenay Canal to Warfield 230 kV line.Cominco proposed a more modest 230 kV upgrading and opposed WKP's planned expansions atWarfield along with the proposed cost sharing. Cominco also opposed the construction of the new 230 kVline from Warfield to Waneta and any proposed changes to the Waneta switchyard or firm access by WKPto Cominco's Line No. 71.

B.C. Hydro asked that the new WKP facilities not be energized until Line No. 71 was connected to theNelway substation, to avoid worsening loop flows on its system. B.c. Hydro also took the position thatany discussion of a modified rate under its Wholesale Transmission Service should not be determined inthis Decision.

The Regional Districts of Kootenay Boundary and Central Kootenay supported the construction of atransmission link between Keenleyside and Warfield so as to allow removal of most of the eighttransmission lines in the corridor between Brilliant and Trail.

WKP applied for approval of Rate Schedule 110 - Long-Term Alternate Path Transmission Service("APTS"). WKP indicated that if it were unable to reach an agreement for facilities sharing with any ofthe third parties, the third parties would take service under the APTS. Cominco stated that the APTS tariffwas not required at this time and that it would not take service under that tariff. The Commission hasdetermined that approval of the APTS tariff is premature, since agreement on cost sharing with Cominco isstill likely.

ill

EXECUTIVES~ARY

In this Decision, the Commission has detenmned that a major rebuilding of the Kootenay transmissionsystem is required to maintain reliable and safe electricity service to ratepayers. The cost of these upgradesis substantial, but the Commission finds that reliable, safe, high quality service to customers cannot beprovided without them. The Commission's detenmnations with respect to the major segments of the newtransmission line and the substations are as follows:

1.0 Transmission Lines

1.1 South Slocan to BriHiant

Construction of a 230 kV transmission line is required between South Slocan and Brilliant along the EastHigh Elevation route, subject to filing of final line alignment, right-of-way acquisition plans and updatedcost estimates. WKP is to pursue rnitigation measures such as consolidating its routing with that of theCPc/CBT line, the use of large spans to reduce dearing and coordination of the timing and sequencing oflogging.

1.2 Brilliant to Warfield

Construction of a 230 kV transmission line is required between BriHiant and Warfield along the generalTOutingof the existing lines (K3), subject to the filing of final line alignment, right-of-way acquisition plansand updated cost estimate. The K3 routing not only has the lowest cost for all ratepayers but also theproposed line, with diversions around most populated areas, will greatly reduce the impact on the publiccompared to the existing lines. This route also minimizes the impact on wildlife and forest resources.

1.3 Warfield to Waneta

The Application to build a 230 kV transmission line from Warfield to Waneta is denied, at this time. WKPhas historically been able to obtain access to Line No. 71 by agreement with Corninco. Corninco andWKP have acted pragmatically and cooperatively in the past and the Commission encourages them to assisteach other. If the transmission owners in the Kootenays cannot cooperate then a Regional TransmissionOrganization will be required, as soon as possible.

IV

EXECUTIVE SUMMARY

2.0 Substations and Interconnections

2.1 South Slocan to Kootenay Canal Plant

Construction of a second 63 kV intertie with the Kootenay Canal Plant and a second transfonner at theKootenay Canal Plant is required, subject to the filing of an updated cost estimate. The Commission alsofinds that the rebuild of the South Slocan switchyard and the Breaker Upgrades at the Kootenay llivergenerating plants and at Rosemont substation are required.

2.2 Connection at BriHiant

The need to deliver power generated at BriHiant to the WKP system and the construction of a 230 kVtransmission line to Warfield will require a substation at Bri1Jiant. There appear to be considerableadvantages to the construction of one common substation, and benefits to all parties from interconnectionof the WKP and CPC/CBT systems. To date, WKP has not been able to negotiate an agreement for theconnection, and for sharing the costs of the connection.

The Commission considers that at this time it does not have authority to direct CPc/CBT to connect itsKeenleyside to Selkirk line to the WKP system at the Brilliant substation or at Keenleyside, even thoughinterconnection could be beneficial to both parties. Without integration WKP ratepayers may face higherutility rates. In the absence of an agreement with CPC/CBT, which benefits WKP ratepayers, it seemsappropriate for WKP to construct and own the substation. As the substation will be a critical part of theKootenay transmission system, the public interest is likely to require Commission oversight of the facility.

The Commission directs WKP to resume negotiations with CPC/CBT to determine the design and theownership arrangements of a larger Brilliant substation to accommodate the needs of both parties at areasonable cost to WKP ratepayers. If a negotiated settlement cannot be reached by September 15, 2000,the Commission authorizes WKP to construct and own a substation at Brilliant that is designed to meet therequirements ofWKP and its ratepayers.

2.3 Warfield Substation

The proposed Warfield substation is an integral part of the WKP transmission system. Interconnection ofthe WKP and Cominco systems at the Warfield substation is essential so that the systems can be operatedtogether, as required by the Cominco Exemption Order. Construction of a new 230 kV and 63 kVsubstation at Warfield is required. WKP is directed to resume negotiations with Cominco on the design,construction and cost sharing of a new substation at Warfield. The Commission declines to issue specific

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directions to Corninco, since the Commission believes that Cominco and WKP will be able to design andcost-share the mutua]]y dependent facilities.

2.4 Waneta Substation

The Commission dedines to approve construction of the requested works at Waneta, and decJines to makedirections to Corninco regarding the requested works. However, the Commission recognizes that with itsdenial of the 230 kV ]ine from Warfield to Waneta a system constraint is again an issue. WKP needs tofind an aJtemative solution: a prefeued solution would incJude interconnection with CPC/CBT'sKeenleyside to Selkirk line.

2.5 Connection of Line No. 71 to Nelway

The Commission accepts that connection of Line No. 71 to Nelway is necessary and in the public interest.Due to the lack of direct WKP involvement in the intertie facilities, it is not appropriate to include suchfacilities in a CPCN to WKP. Moreover, the Commission believes that the connection between Line No.n and Nelway will proceed under the guidance of B.c. Hydro and Corninco without the need forCommission intervention.

3.0 Capital Costs and Impact on Rates

The capital cost estimates of the Project varied significantly during the course of the hearing and thepotential for cost sharing with other parties was not resolved. The Commission estimates that the capitalcosts of the facilities approved in this Decision are likely to range between $93 and $100 million withWKP's share of the capital costs likely to be between $73 and $80 rnillion. The Commission deteuninesthat the Project should be financed with traditional utility equity and debt financing. In keeping with thedebate during the hearing on aJtemative financing methods, the Commission expects WKP to secure theleast cost debt funding possible, which may be from 10caJgovernments or a Crown Corporation.

Over the next six years, the cumulative impact on customer rates is expected to range between 5.6% and6.4%. The revenue requirement impact will be influenced by sharing auangements with CPC/CBT andCorninco.

VI

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Warfield 63 kV Modifications Including Retiring Tadanac

In its application, WKP assumed a cost of modifications to Warfield, including retiring the Tadanacswitchyard, of $10.537 million with Cominco paying all of the capital cost and WKP renting a 35 percentshare of the asset (Exhibit 1, Tab 3, Table 3.1; Exhibit 3, Tab 1, p. 17). Subsequently, the WKP costsincreased to $5.197 million due to Cominco's requirement to establish two distinct switchyards at Warfield(Exhibit 14, p. 2). This cost is shown in Table 6.1.

Cominco stated during the hearing that Cominco and WKP should each pay for their own portions of theswitchyard, but that Cominco was not insisting on two physically separate switchyards. Consequently,Cominco thought that the cost estimate might be different (T8: 1388). For the low capital cost scenario inTable 6.2, the original cost of $10.5 million is assumed with WKP assuming a 35 percent share of the costor 3.7 million.

The Warfield Line Diversions

WKP stated in its Application that diversions of Cominco-owned 63 kV lines into the expanded Warfield63 kV switchyard would be the responsibility of Cominco. WKP's involvement in the switchyard wouldbe a function of the number of its line terminations at the station. On this basis, WKP has indicated that itwould be responsible for $44,000 related to the Warfield line diversions, while Cominco would beresponsible for $540,000. Cominco stated in its evidence that it had agreed with WKP that there is a needto replace the Tadanac/Warfield switchyards and that the two parties had agreed what the total range of costmight be (Exhibit 96, p. 1). As the WKP proposal also appears consistent with Cominco's position thateach party should be responsible for its own facilities, this sharing of costs does not appear to be indispute.

Miscellaneous Improvements

In its Application, WKP has proposed to accept all of these costs without any cost sharing.

6.2.1 Commission Findings

Based on the analysis above, the Commission has concluded that a likely range of costs, based on WKP'scapital cost estimates for the approved components, but allowing for some uncertainty regarding costsharing, is in the range of $73.1 million to $80.4 million. The basis of this estimate is shown in Table 6.2.However, as discussed in Sections 6.1 and 6.2, if WKP were unable to interconnect at Brilliant, a largertransformer could be required at Waneta at an additional cost of $10.3 million. Until WKP provides final

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Table 6.2

West Kootenay Power Ltd., 230 kV Capital Cost and Cost Sharing Amounts

Low Capital Sharing High Capital Sharing WKPComponents with Sharing Uncertainty _C_os_t Estimate WKP Share _C_os_t Estimate _Sh_ar_e

Kootenay Canal plant modifications 6,934 0 6,934 6,934 532 6,401230 kV line -K3 Kootenay Canal to Warfield 21,430 0 2] ,430 23,430 7,803 15,627Brilliant new 230/63 kV Switchyard 13,263 0 13,263 16,463 1,098 15,365Warfield Switchyard, new 230/63 kV substation ] 1,540 0 11,540 ]2,040 5,057 6,983Tadanac/Warfield 63 kV reconstruction 10,537 6,849 3,688 12,596 7,399 5,197N. Kootenay Generation Dropping RAS 1,000 0 ],000 1,000 0 1,000ComincoIWKP Load Dropping RAS 1,000 0 1,000 1,000 0 1,000Subtotal - Shared Components & Adjustments 65,704 6,849 58,855 73,463 21,889 51,573

SharingComponents with Sharing Certainty Capital Cost Estimate WKP Share

South Slocan Modification 9,716 0 9,716Tie to Kootenay Canal 229 0 229Warfield Line Diversions 540 496 44Waneta-Warfield 230 kV line nla nla nlaWaneta 230 kV modifications nla nla nlaTie Line No. 71 to Nelway 636 636 0Nelway Modifications 1,748 1,748 0Miscellaneous Improvements 8,480 0 8,480Kootenay Communications 4,097 1,381 2,716Feasibility Study 431 112 319Subtotal 25,877 4,373 21,504

Low Capital Sharing High Capital Sharing WKP_C_os_t Estimate WKP Share _C_os_t Estimate _Sh_are_

TOTALS 91,581 11,222 80,359 99,340 26,262 73,077

Notes:1. The costs estimates of the Warfield Switchyard include the adjustments for a larger transformer and reduced line

terminations.2. For both low and high cases, the estimates are based on the assumption that no Warfield to Waneta line is constructed.3. As noted in Section 6.2 the WKP share could increase by an additional $10.3 million for a transformer at Waneta to

approximately $91 million if WKP was unable to connect with CPC/CBT at Brilliant.4. The potential scenario under which Cominco requires no capacity on the WKP system is included in the Table under the

low capital costilow sharing scenario.

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cost estimates for all components of the final configuration of its system upgrade, additional uncertaintyexists in the base estimates as we]].

Although these estimates are based on preliminary data and contain a relatively high level ofuncertainty, the Commission has determined that the items which it has approved are necessaryfor safe and reliable service to residents of the Kootenays. This Project is a necessaryrefurbishment of a transmission system that has reached the end of its physical life, and,therefore, approval cannot be delayed until final costs and cost sharing arrangements arecomplete.

6.3 Financing and Funding Alternatives

During the hearing, several financing alternatives were explored. These induded traditional funding byWKP through a mixture of debt and equity. Other alternatives proposed included the use of a mixture ofdebt or equity financing, or both, by third parties.

Except for the common facilities at Warfield, WKP proposed to own all of the facilities proposed in itsApplication. WKP proposed to finance the Project through its normal ratio of Utility debt and equityfinancing. WKP calculated its revenue requirement and rate impacts based on the assumptions of aweighted average cost of debt of7.5% and a return on equity of 10%.

In their initial evidence, the Regional Districts proposed to take an ownership role of the Project facilities(Exhibit 9H, pp. 4-8). The Regional Districts suggested that, by participating in the Project, they couldreduce the cost of the Project sufficiently that their preferred option, K5, would become comparable to thatof WKP's preferred option, K3. Subsequent to the condusion of the evidentiary portion of the hearing,the Regional Districts indicated that they were no longer pursuing an ownership position.

During the hearing, the Regional Districts stated that, while an alternative would be for them to act as afinancier alone, this would likely not be a realistic or viable option as there are express prohibitions againstlocal governments acting as financing institutions (Exhibit 9H, pp. 8 and 9). The Regional Districtsindicated that they did not see their role as necessarily providing debt financing for 100% of the Project, butrather that they could finance a portion of the project through debt, with another partner possibly taking anequity portion (T3: 455).

Documents

TGVl's Resource Planning/CPCN Environment: Then and Now … · 01249.88645.JCK.2511319.1. 2 End Notes 1 Exhibit B-2, CPCN Application, p. 66. 2 Exhibit B-8, TGVI Response to BC Hydro