c+ -1/ BRITISH COLUMBIA UTILITIES COMMISSION IN THE MATTER OF the Utilities Commission Act, R.S.B.C. 1996, Chapter 473 (the" Acf') In the matter of BRITISH COLUMBIA HYDRO AND POWER AUTHORITY (Be HYDRO) 2007 Rate Design Application DOCUMENTS REFERRED TO DURING CROSS-EXAMINATION OF BC HYDRO BY TERASEN UTILITIES BOOK 2 (TABS 11~21) July 2007 DM_ VANI240148-00595/6700714.2 09/07/200710:11 AM C7-11
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BRITISH COLUMBIA UTILITIES COMMISSION COLUMBIA UTILITIES COMMISSION ... DM_VANI240148-00595/6700714.2 09/07/200710:11 AM n! I / ... an NCP allocator was used …
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BRITISH COLUMBIA UTILITIES COMMISSION
IN THE MATTER OF the Utilities Commission Act,R.S.B.C. 1996, Chapter 473 (the" Acf')
In the matter ofBRITISH COLUMBIA HYDRO AND POWER AUTHORITY
(Be HYDRO)
2007 Rate Design Application
DOCUMENTS REFERRED TO DURINGCROSS-EXAMINATION OF BC HYDRO BY
TERASEN UTILITIES
BOOK 2(TABS 11~21)
July 2007
DM_ VANI240148-00595/6700714.2 09/07/200710:11 AM
C7-11
bharvey
BCH 2007 Rate Design
!
I/
(1 2.5.7 Classificationof DistributionSystem
BChydro mlUI
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, II
2 BC Hydro has reviewed the Distribution system in order to classify the cost of distribution.
3 The review of the Distribution system consisted of a review of distribution capital assets and
4 the sub-functionalization of the capital assets into the following categories:
5 • distribution wires,
6 • distribution transformers, and
7 • street lighting.
8
9
10
11
12
13~ 14
15
16
17
18
19
20
21
22
23
24
25
26
The distribution wires system includes duct banks, underground cables, switching cubicles,
poles, overhead conductors, switches, fuses and all distribution assets except transformers.
The distribution wires system was allocated to rate classes where customers are connected
to the distribution system (all rate classes except Transmission), and were classified as
75 per cent demand related and 25 per cent customer related. The portion of costs
classified as demand and customer related is based on experience and the practices of
other distribution utilities. The majority of the distribution system is typically designed to meet
the system demand while local facilities are designed to connect the customer and therefore
the majority of costs are classified as demand related.
As discussed in section 2.3.3, an NCP allocator was used to allocate Distribution costs. The
distribution transformer system includes the cost of the step down transformer. Rate classes
that take primary service do not make use of transformers and were not allocated any cost
associated with distribution transformers. The distribution transformer system was classified
as 75 per cent demand related and 25 per cent customer related.
The cost of distribution metering was allocated on the basis of the cost of replacement
meters and the number of services, by meter type. The meter types are linked back to rate
class in order to allocate metering costs to rate classes.
The assets categorized as street lights were assets in service solely to provide street lighting
service.
Be Hydro 2007 Rate Design Application-22-
,.
..
British Columbia Utilities CommissionInformation Request No. 1.21.1 Dated: April 5, 2007British Columbia Hydro & Power AuthorityResponse issued April 30, 2007British Columbia Hydro & Power AuthorityBC Hvdro 2007 Rate Desian Application
Page 1of 1
Exhibit:B-3
21.0 Reference: Exhibit B-1, p. 22, lines 12-14 Distribution System
1.21.1 It is stated that the 75/25 demand/customer split was based onexperience and the practice of other distribution utilities. Pleaseprovide the demand/customer splits for all other utilities on which BeHydro relied.
RESPONSE:
Electric distribution utilities generally classify distribution systems furthest fromthe customer (i.e. the primary distribution systems) as 100 per cent demandrelated. The closer the facilities are to the customer, the larger the customercomponent becomes and the smaller the demand component becomes. At thedistribution meter, the demand/customer split is 0/100 since meter costs areconsidered customer related.
Each electric distribution utility will have its own demand/customer split based onthe composition of its electric distribution system. Electric distribution systemswhere the primary system makes up a large proportion of the total distributionplant will have a higher percentage of demand related costs.
BC Hydro used its own experience and judgment in assessing that a 75/25demand/customer split is appropriate for its distribution system. Other utilitieshave reviewed their own facilities and have adopted various approaches asfollows.
ENMAX Power (an urban electric distribution system) splits its electric distributionsystem into a number of sub functions which have demand/customer splits thatvary from 100/0 for primary feeders to 0/100 for secondary cables and meters,based on various analyses, including minimum system and zero intercept. Theoverall distribution system has a 43/57 demand/customer split.
ATCO Electric splits its distribution system into sub functions and uses a range ofdemand/customer splits. ATCO Electric classifies its primary distribution systemas 100 per cent demand related, its transformers as 42/58 demand/customer andits secondary cables as 26/74. The overall ATCO Electric distribution system has ademand/customer classification of SO/50.
BC Hydro has historically used 75/25 demand customer split for classification ofits distribution system. BC Hydro requires that larger commercial customersprovide their own transformers, which tends to increase the demand componentrelative to utilities that provide such transformation. A detailed study would berequired to update the demand/customer classification for BC Hydro's electricdistribution system.
British Columbia Utilities CommissionInformation Request No. 1.21.2 Dated: April 5, 2007British Columbia Hydro & Power AuthorityResponse issued April 30, 2007British Columbia Hydro & Power AuthorityBC Hvdro 2007 Rate Desian Application
Page 1of 1
Exhibit:B-3
21.0 Reference: Exhibit B-1, p. 22, lines 12-14 Distribution System
1.21.2 Please provide the demand/customer split from each Be Hydro COSAperformed since 1995 and describe the methodology employed (forinstance, was the split determined by survey, minimum system orintercept analysis?)
RESPONSE:
BC Hydro's 1998 Cost of Service Study used a 73/27 demand/customer split forthe classification of the primary distribution system. The classification was basedon a distribution system analysis, which considers individual components similarto minimum system analysis.
I(I!
Terasen Gas Inc.Information Request No. 1.14.4 Dated: April 11, 2007British Columbia Hydro & Power AuthorityResponse issued April 3D, 2007British Columbia Hydro & Power AuthorityBC Hvdro 2007 Rate DesiQn Aoolication
Preamble: The referenced section states "The distribution wires system wasallocated to rate classes where customers are connected to the distributionsystem (all rate classes except Transmission), and were classified as 75 per centdemand related and 25 per cent customer related. The portion of costs classifiedas demand and customer related is based on experience and the practices ofother distribution utilities."
1.14.4 Has Be Hydro performed any studies at a more detailed level of its owndistribution costs which would lend support to 75% demand-related I25% customer-related split of distribution costs? If so, please file thestudies in this proceeding.
RESPONSE:
BC Hydro has not performed any detailed studies to identify demand related andcustomer related costs associated with its electric distribution system.
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JIESCInformation Request No. 4.17.2 Dated: June 4, 2007British Columbia Hydro & Power AuthorityResponse issued June 8, 2007British Columbia Hydro & Power AuthorityBC Hvdro 2007 Rate Desian ADDlication
17.0 Reference: Exhibit 8-7, JIESC IR 2.10.1
Page 1of 1
Exhibit:B-9-2
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Explanation: In Information Request JIESC 2.10.1 the JIESC asked that BCHydro:
"Provide the monthly coincident peak demands of each customer class. with andwithout losses, at the times of the domestic peak loads for the fiscal years2001-2005 in the format used for fiscal year 2006 in the spreadsheet identified asJIESC_1_003_1 Attachment 1."
In its response to this Information Request, found in Ex. 8-7, filed Friday, June 1,2007 BC Hydro stated:
"Data sets for years prior to F2004 are incomplete and therefore not useful torespond to this request. In addition, Irrigation and Street Light load profiles forF2004 were unavailable and F2005 load profiles for these rate classes wereused for F2004. F2004 data is provided in a similar format to the response toJIESC IR 1.3.1. This data is included in the document titled "JIESC IR 2.10.1Attachment". Also included in this attachment are the F2005 and F2006 sheetswhere the titles for Irrigation and Street Lights are corrected."
In order to better understand trends in the Peak Loads over time furtherinformation is required.
4.17.2 Provide System Peak data for domestic load by month for F2001 to2007.
~Ionlh :'\ames of Ranked Peaks56 Greatesl ( ....llDual Peak) December December December January January December :-;ovember57 2-nd Greatest February January January December December l\ovewber January58 3-nd GrealeS! November November November November i'ovember January December59 4-th Greatest January March February FebnlllI)' February February February60 5-rb Greatest March February March March March March March61 6-th Greatest October October OClober October October October October62 7-rh Greatest April April April April April April April63 8-th Greatest May May :>'lay July August September July64 9-th Greatest August Seplember S,,!>lember August July August June6S 10-th Greatest July August Augll.<1 Seplember September July September66 II-th Greatest September June July June June June May67 12-tb Greatest June July June May May May August
Ranks or :\IOhlhs- ~O April 6 (> 6 6 6 II 6RI May 5 5 5 I I,~2 June I 2 1 2 21>3 July J I 2 5 4 J
~ 1'4 .~uguSl 4 3 J 4 5 4~5 September 2 4 4 3Sh OCIObc:-tf;7 :'\ovember 10 10 10 10 10 II 12'8 December 12 i2 12 11 II 12 10~9 January 9 11 II 12 12 10 1190 february II S 9 9 9 9 991 March S 9 8 8 8 8 8
Linx, .. ikr C un'iuhing S('r'\.lCC .... ln~. June 11. :1l(J7
Exhibit _ tJNL-2)Page3 or8
(--, BC H~dro
2007 Rlll~ Design Application
v . Linl"i1er Anal~'sis of Be Hydro's "Ionthly Peak Demands For Fiscal Years 2001-2007
,.-,I. Basic Re\'iew of Historical .\IODlbly Peab (ConliDu~)
16 Maximum 85.82%17 Minimum 79.58%18 Simple Average 82.77%
Off-PeaIL Months in Currenl Y~ar E~ce«lingLo",es! PeaIL Month
19 Lowest Peak Month of Year 8,154.000 7.929.000 8,157.000 8,638.000 8,453,000 8.789.000 8,778,00020 Number Non-Peak Months Greater I 2 I 1 1 I I- 21 Three or More? ~o No :-';0 No No 1'0 1'0
22 Lowest Peak ~lolltb of Prior Year 8,154.000 7,929,000 8,157,000 8,638.000 8.453.000 8.789,00023 l\wnber !'olon-Peak :-tonths Grealer I 2 1 I J 124 Cumulative Number of O«urences 7:!5 Cumulative Greater than 10 :-';0
LiIlX\likr CIln.uhlD£ 5(1'\ Ice,. Inc. Jun_ II. ~I)07
hhibil _ONL-2}l'ag( 8 of 8
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BC H}dro2007 Rare Desillo AppUcatiOD
LiD1"i1u A031ysis of Be H~'dro's :\10ntbly Peak D~mands For Fiscal Years 2001-2007
S. Aoalysis of UP .-\II~arioo :\1~rbod
Line D.. criJ.l.tion 2001 2002 2003 2004 200s 2006 2007
21 Lowest Peak Month of Prior Year 8.154,000 7.929.000 8,157,000 8.638,000 8.453,000 S,7H9,OOO23 l'umber l"on-Peak Months Greater 0 I 0 0 0 024 Cumulative :\wnber ofOccurences )~, Cumulalive Grealer than 10 :"'0
~....
L1I1.\\\ tier C'Jn ..ulring S~I"\·j~(s.luc. JIllU: I '- 20(1':0
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British Columbia Utilities CommissionInformation Request No. 2.111.1 Dated: May 16, 2007British Columbia Hydro & Power AuthorityResponse issued June 8, 2007British Columbia Hydro & Power AuthorityBC Hvdro 2007 Rate Desion ADD!"
2.111.1 In the Attachment Be Hydro states that due to the wet spring they werenot anticipating using the interruption option in the 1990/91 heatingseason. Please explain why it was not used in subsequent years, inparticular the last few years, and why the use of the 30 day mail notice,and penalty billings for failure to comply, could not be used.
RESPONSE:
In the 1980's, BC Hydro had a significant surplus in both energy and capacity.The Pacific Northwest also had a significant surplus, and access to exportmarkets from BC was not sufficiently developed to allow BC Hydro to sell surplusenergy economically, nor were there robust real·time markets. It was in thiscontext that E-Plus rates were developed.
Since that time, load growth has continued and BC Hydro has become a netimporter of energy (with load growth running at approximately 2 percent per year).In addition, there are now robust real-time electricity markets in the PacificNorthwest, and open access transmission tariffs have made those marketsavailable to BC Hydro. Thus, the original premise of the E-Plus rate has beenrendered obsolete by changes in BC Hydro's supply and demand situation andthe industry structure.
Special Conditions of the E-Plus rate allow for the interruption of electricity supplywhen there is lack of surplus hydro energy and the service cannot be providedeconomically from other energy sources. However, the tariff does not clearlydefine 'lack of surplus' hydro energy conditions nor does it define 'economicallyfrom other energy sources'.
As outlined in the response to Rochon IR 1.2.0, lack of surplus hydro energycould arguably mean those periods during which BC Hydro has been a netimporter of electricity. E-Plus customers could arguably now be interruptedcontinuously, which would effectively end the E-Plus service rate.
Be Hydro has considered whether shorter periods of interruption would bepossible and of value in the context of how the system operates, includingdemand patterns and resource options. However, to manage short term systemconstraints Be Hydro currently has several options at its disposal that would bedrawn upon more practicably prior to interrupting E·Plus customers. For example,Be Hydro has the ability to purchase electricity from Powerex (market purchases,
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British ColumbiaUtilities CommissionInformation Request No. 2.111.1 Dated: May 16, 2007British Columbia Hydro & Power AuthorityResponse issued June 8, 2007British Columbia Hydro & Power AuthorityBC Hvdro 2007 Rate Desian Aoplication
Page 2of 5
Exhibit:B~7-1
including eanadian Entitlement), operate the Burrard Thermal generating stationor initiate voluntary customer curtailment. All of these options provide a quickresponse and the high degree of reliability required to address a short termsupply shortage. For reasons described below, curtailment of E-Plus customersinvolves a longer notice and activation period before the beneficial relief isexperienced and therefore would provide no value for short term, real-time needs.
If BC Hydro were to consider implementing an E-Plus rate interruption driven bysupply shortages for serving domestic load, the only plausible interruption periodwould need to be for several months and during the winter season (November toFebruary) when the system experiences its peak demand load and when theE-Plus load is highest (roughly 88GWh for the 2005/2006winter season).
If BC Hydro were to interrupt E-Plus customers over the winter season, it wouldbe necessary, in light of the fact that E-Plus customers have never beeninterrupted, to develop a comprehensive notification process. Notification wouldbe issued to advise customers of the period of interruption; the customer'sresponsibility in regards to the safe operation and adequacy of back-up systems;and an explanation of penalty rates to be billed if the E-Plus service were to beused during the interruption period. Notification would also advise on Schedule1105 Special Conditions 3 and 10 that stipulate interruption non-compliance mayresult in forfeiture of entitlement to this rate schedule until it can be demonstratedthat adequate standby facilities exist. Additionally, customers would be advisedthat they have the option to switch to the standard rate but that such a transferrequires giving 3 months prior notice to Be Hydro.
As per Schedule 1105 Special eondition 3, written notification requires eitherhand delivery or issuance by registered mail. Given the dispersion of E-Pluscustomers throughout the province, registered mail would likely be utilized.eonfirmation of receipt of registered mail would be required to ensure all E-Pluscustomers received notification. Not only is this stipulated in the tariff but it isalso very important to ensure the safety of E-Plus customers given that it hasbeen 20 years without interruption since the inception of the program. This is amanual process matching notifications issued with customer acknowledgements.It is expected that not all customer confirmations would be received on an initialmail-out and that would then precipitate the need for a second registered notice to
. those who have not confirmed receipt. If, after both mailings, customerconfirmation is still not confirmed, hand delivery would then be required andused.
Working to an interruption period starting in November, the initial mail out wouldoccur throughout March. Mail drops would be staggered to better manageexpected incremental enquiries to the eaU eentre and processing ofconfirmations. The second mail out would occur in May and hand delivery, ifrequired, would occur in'June. This notification process would allow customers
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British Columbia Utilities CommissionInformation Request No. 2.111.1 Dated: May 16, 2007British Columbia Hydro & Power AuthorityResponse issued June 8. 2007British Columbia Hydro & Power AuthorityBC Hvdro 2007 Rate DesiQn AD plication
Page 3of 5
Exhibit:8-7-1
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the time to seek clarification and decide on how they could best respond to theinterruption period. Furthermore, if customers elect to move to the standard rate,this time-varied approach allows for BC Hydro to be notified by the end of July forthe 3 month (August to October) time requirement needed to switch the rate.
Given the length of time between initial notification and interruption, billmessages and/or inserts would be used to remind customers of the upcominginterruption period. An additional direct mailing and newspaper ads would also beconsidered.
Confirmation of compliance with an interruption request requires measurement bymeter readings. As E-Plus customers are widely dispersed throughout theprovince, the meter reading and resulting billing cycles vary by customer. As themajority of E-Plus customers are residential customers, meters are typically readevery second month within a two day window.
Assuming existing scheduled meter readings are used to measure compliance,the start of an interruption period would span over two months. Essentially most,if not all, interrupted E·Plus customers would have different absolute periods ofinterruption. Those that are read in the odd month would have an interruptionperiod of November to March and those read in the even month would have aninterruption period of December to April. Scheduled meter readings would need tobe identified for each E-Plus customer and therefore written notification wouldrequire customization to address differing periods of interruption.
Assuming unscheduled meter readings would be used to measure compliance,BC Hydro staff would need to attend each E-Plus premise to obtain a meterreading at the start and the end of the interruption period. It is not reasonable toexpect that all E-Plus unscheduled readings would occur on the same day giventhe varying locations of customers but is more reasonable to expect that thesereadings could be accomplished within a shorter time period such as two weeks.In this case, E-Plus customers would have interruption periods with more uniformstart and finish dates and all would be from November to February.
Regardless of which of the above two methods are used, there would always beissues related to meter access that impact the ability to read. Customers that haveinaccessible meters would need to be contacted and arrangements made to readthe meter would then impact the interruption period and require manualprocessing in the billing system.
Billing system functionality to invoice penalty rates does not currently exist. Itwas not built in the past because E-Plus customers have never been interrupted.It is anticipated that most E-Plus customers would either comply with interruptionor switch to the standard rate leaving relatively few accounts that would incurpenalty charges. From a system perspective this does not change the need to
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British Columbia Utilities CommissionInformation Request No. 2.111.1 Dated: May 16, 2007British Columbia Hydro & Power AuthorityResponse issued June 8, 2007British Columbia Hydro & Power AuthorityBC Hvdro 2007 Rate Desian AODlication
Page 4of 5
Exhibit:8-7-1
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develop and test programming that provides for the accurate invoicing of E-Pluscustomers. Even with this functionality in place, there would almost certainly beaccounts that require manual processing given the coordination required betweenreadings and interruption periods.
Even with extensive customer notification of interruption periods and associateddetails, it is expected that a number of E-Plus customers would not respond untilafter they receive a first penalty billing (which is currently 19.55cents per KWhbased on a rate approximately 6 times greater than the E-Plus rate or 3 timesgreater than the standard Residential rate during a non-interruption period).During a heating season, an average monthly bill of 1500kWh is approximated at$50 during a non·interruptible period. If the same consumption is used during aperiod of interruption, the cost increases to about $290. It is expecte~ thatcustomers experiencing this penalty would inquire about their invoice which,inturn, would cause a requirement to explain their bill and forfeiture of entitlementto this rate schedule (until it can be demonstrated that adequate standby facilitiesexist) once the period of interruption is complete. During the period of interruptioncustomers are not able to switch to the standard rate and face the higher rate forthe duration of the interruption period. Some of these customers could then revertto back-up energy systems for the duration of the interruption.
eustomers that do not curtail would need to be notified of the removal of theE-Plus rate after the interruption period. However, if these customers candemonstrate that adequate back-up systems are in place, Be Hydro may allow thecontinuance of the rate, although this would require review on a customer-by-customer basis that could include site checks to confirm systems. Training offield staff to perform this type of site check would need to be developed anddelivered.
Be Hydro anticipates that the amount of energy realized from an interruptionwould be very small relative to the amount of energy required to address thesupply shortfall. However, winter-season interruption may be of some value toBC Hydro's long-term supply and capacity management planning, providedcustomers actually curtail. BC Hydro believes it is unrealistic to assume that allcustomers would curtail and indeed, as noted, believes that upon notification ofimpending interruption a portion of E·Plus customers would switch to the regularResidential rate because the back-up energy source is no longer convenient,available, economical or operable. As well, it is expected that some E-Pluscustomers would not curtail, or would curtail for only a portion of the interruptionperiod, and continue to use electricity as their energy source, incurring theassociated penalty.
For these reasons, it is difficult to estimate what portion of E-Plus customerswould actually curtail in the event of an interruption. At least one interruptionperiod would be required to observe and establish the responsiveness behavior
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British Columbia Utilities CommissionInformation Request No. 2.111.1 Dated: May 16, 2007British Columbia Hydro & Power AuthorityResponse issued June 8, 2007British Columbia Hydro & Power AuthorityBC Hvdro 2007 Rate DesiQn Aoplication
Page 5of 5
Exhibit:8-7-1
pattern of E-Plus customers before any meaningful and useful data would beavailable for incorporation in BC Hydro's long-term load forecasting, planning,decision and system management operational process.
Be Hydro conservatively estimates the cost of interrupting E·Plus customers tobe roughly $1.4 Million if regular reading schedules were used and $1.8 Million ifspecial reading schedules were used.
For illustration purposes, using the E-Plus 2005/06winter consumption of 88,000MWh as a point of reference, the value of a 25 per cent reduction in energy useresulting from customer curtailment is estimated at $1 Million and the value of a50 per cent energy use reduction is estimated at $2 Million.
Since Be Hydro does have a gap between energy supply and demand,interrupting E-Plus customers for an extended period of time would, in theory,provide some marginal benefit. However, Be Hydro has other options ava1labletomeet the supply shortage that are economic, more practical, less problematic andnot as disruptive to customers. BC Hydro believes it should exercise thoseoptions first and not use extended interruptions of customers to meet supply gapissues.
BChydro '"w
1 Following the determination that a cost is proportional to demand, the next question that
2 must be answered, is when does this demand occur? The answer is based on reviewing
3 how the system is planned and designed. If there is one identifiable large demand that is the \
4 sale focus of planning and design activities, then a single coincident peak or 1 CP method of
5 allocation is appropriate for the classification of the demand related costs. A 1 CP method of
6 classifying demand related costs may be appropriate regardless of whether the peak load
7 occurs in the summer or the winter.
8 When planners determine conditions that cause stress on the system, and develop capital
9 upgrades to alleviate the stress, the planners must consider the ability of the system to
10 deliver the energy in addition to forecasting the load on the system. The thermal capacity of
11 electric systems is diminished in the summer as the result of higher ambient temperatures,
12 and the reduced ability for cooling of equipment. An electric system has a derated capacity
13 in the summer time that may result in stress to the system even if the load is smaller or
14 similar to winter load. When transmission upgrades are completed to alleviate stress at
15 times other than that of the annual peak load, 1 CP is not appropriate.
16 Demand classification may vary for each function. Demand related costs for transmission
17 systems are commonly based on coincident peaks because many diverse customers
18 contribute to a coincident load condition. Demand related costs on distribution systems are
19 commonly based on non coincident peaks because there is less diversity between
20 customers, and each individual customer stresses the system close to the customers'
21 service entrance.
22 Transmission systems are commonly designed for more than one annual peak load. The
23 BC Hydro transmission system spans across the province and must be designed to provide
24 reliable service throughout the yeauparts of BC Hydro's transmission system must serve
25 loads that peak in the summer time such as in the Okanagan area. Transmission lines
26 providing service to the southeast interior experience more congestion in the summer than
27 in the winter. The transmission lines providing service to Vancouver Island experience peak
Mr. Robert J. PellattCommission SecretaryBritish Columbia Utilities CommissionSixth Floor, 900 Howe StreetBox 250Vancouver, BC V6Z 2N3
Dear Mr. Pellatt:
Re: British Columbia Transmission Corporation ("BCrC")Transmission System Capital Plan F2008 to F2017
Pursuant to sections 45(6), 45(6.1) and 45(6.2) of the Utilities Commission Act,BCTC files with the British Columbia Utilities Commission the Transmission SystemCapital Plan F200B to F2017 ("Capital Plan").
In response to Commission Letter L-78-06, BCTC notes that Section 1.6 of the CapitalPlan lists in detail the Orders Sought through this application. BCTC will work withCommission staff during the course of the proceeding to provide electronic copies ofdraft Orders in WORD format, as required.
Sincerely,
Original Signed byGerry Lister for:
Marcel RegheliniDirector, Regulatory Affairs
British Columbia Transmission Corporation.Suite 1100 Four Bentail Centre, 1055 Dunsmuir Street,
4.4.1 Financial. 414.4.2 Reliability 414.4.3 Market Efficiency 414.4.4 Asset Condition 424.4.5 Relationships with Community and First Nations 424.4.6 Environment and Safety .43
4.5 Stakeholder and First .Nations Engagement.. .434.5.1 Consultation Activities 434.5.2 Incorporating Stakeholder and First Nations Feedback .49
5.1 Growth Capital Portfolio Table 765.2 Historical and Trend Explanations 815.3 Changes from Previous Capital Plan 845.4 Prioritization Results 865.5 Growth Capital Portfolio Descriptions 88
5.5.1 Bulk System Reinforcements 885.5.2 Regional System Reinforcements 1015.5.3 Station Expansion & Modification 1145.5.4 Customer-Requested Projects 1275.5.5 Independent Power Producer Interconnections 127
6.0 Sustaining Capital Portfolio 130
6.1 Sustaining Capital Portfolio Table 1306.2 Historical and Trend Explanations 1336.3 Changes from Previous Capital Plan 1356.4 Optimization Results 1386.5 Sustaining Capital Portfolio Descriptions 139
6.5.1 Stations , ,1406.5.2 Lines 175
7.0 BCTCCapital Portfol i0 201
7.1 BCTC Capital Portfolio Table 2017.2 Program Description and Strategy 204
BCTC Capital Plan F200821 December 2006
2
Transm ission Reven ue Requirement Impacts 254
Commiss ion Oi rectives 257
9.1 Order G-91-05 page 4 : 2579.2 Order G-91-05 page 6 Directive 1 2579.3 Order G-91-05 page 7 Directive 2 2589.4 Order G-91-05 page 8 Directive 3 2599.5 Order G-91-05 page 8 Directive 4 2599.6 Order 8-91-05 page 9 Directive 5 2619.7 Order G-91-05 page 11 Directive 6a 2629.8 Order G-91-05 page 11 Directive 6b 2639.9 Order G-91-05 page 11 Directive 7 2639.10 Order G-91-05 pages 15 and 16 2649.11 Order G-91-05 page 16 Directive 8 2659.12 Order G-91-05 page 17 Directive 9 2669.13 Order G-91-05 page 17 2669.14 Order G-91-05 page 19 Directive 10a 2669.15 Order G-91-05 page 20 Directive 10b 2679.16 Order G-91-05 page 26 Directive 11 2679.17 Order G-91-05 page 26 directive 12 2689.18 Order 8-91-05 page 26 Directive 13 2689.19 Order G-91-05 page 27 Directive 14 2699.20 Order G-91-05 page 30 directive 15 2699.21 Order G-91-05 page 37 Directive 19 2709.22 Order G-91-05 page 41 Directive 21 2709.23 Order G-91-05 page 42 directive 22 2709.24 Order G-91-05 page 44 Directive 23 2719.25 Order G-91-05 page 45 Directive 24 2719.26 Order G-91-05 page 45 Directive 25 2719.27 Order G-91-05 page 47 Directive 26 2729.28 Order G-91-05 page 49 Directive 28a 2729.29 Order 8-91-05 page 49 Directive 28b 272
7.2.1 Information Technology 2047.2.2 Control Centre Technologies 2057.2.3 Facilities , 206Historical and Trend Explanations 2067.3.1 Trend for BCTC Capital Portfolio 2067.3.2 Trends for Specific Projects 208Changes from Previous Capital Plan 2097.4.1 Changes to Projects 2097.4.2 Changes to Submission Format... 210Prioritization Results 211BCTC Capital Portfolio Descriptions 2137.6.1 Information Technology Projects for ApprovaL 2137.6.2 Information Technology Future Projects 2487.6.3 Control Centre Technologies Project for Approval. 2497.6.4 Control Centre Technologies Future Project.. 2507.6.5 Facilities Project for Approval 2507.6 .6 Facilities Future Project 253
serc Capital Plan F200821 December 2006
3
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3
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,-. 15{
16
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2.5
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4 - Capital Planning Process Overview
(d) A deferral of system reinforcements by using generation shedding forgoes the
benefits that can occur from reinforcements in one part of the system providing
secondary benefits in another part of the system.
Some exceptions to this general policy are made if the amount of shedding is less
than the largest unit on the transmission system, and the required investment to avoid
the shedding cannot be justified.
BCTC will accept generation shedding for a double contingency and for a single
contingency if one element is already out of service. BCTC has adopted this policy so
that the transmission system is more robust and is able to depend on generation
shedding for less common and more severe events.
4.6.2.5.3 Over Voltage Line Tripping
The transmission system has many expensive pieces of equipment that can be
damaged by excessive voltages. For example, underground cables in Metro
Vancouver and the submarine cables to Vancouver Island can be severely damaged
if exposed to excessively high voltages. Because of this, a staged protection scheme
has been implemented which trips 500 kV lines at specific increasing levels of over
voltage. This system is intended to backup other specific measures that are taken to
control voltages to acceptable levels for well-defined contingencies that may occur on
the system.
Tripping a single line reduces system voltages due to two phenomena. Firstly,
because 500 kV lines have some capacitance which tends to support system
voltages, the removal of a line will reduce a source of capacitive reactive power and
the voltage will fall somewhat. Secondly, tripping one line also increases the reactive
power demand by putting more current onto the remaining lines. The demand for
reactive power is proportional to the square of the current on the remaining lines and
this is a non-linear effect. Consequently, the reactive power required to maintain a
given level of voltage is higher after a line trips than it was before and the sources of
reactive power are lower. The net result of these two phenomena is that the voltage
stabilizes at a lower value than it had before the line tripping occurred. One
alternative to the reliance on line tripping is to install additional reactors on the
system.
BCTC Capital Plan F200821 December 2006
58
C·2~.)
4
5
4 - Capital Planning Process Overview
BCTC's planning policy is that the line over voltage protection scheme shall not be
triggered when the system responds to a single (N-1) or double (N-2) contingency. To
effect this standard, BCTC requires that sufficient voltage control equipment be
installed so that the 500 kV lines do not trip on over voltage protection for N, N-1, or
N-2 contingencies.
6 4.6.3 Key Drivers
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Growth projects are predominantly customer and volume driven. BCTC determines
investments to meet growth in peak demand, OAD requests, and generation
identified and forecast by BCTC's customers. Projects range from minor facility
enhancements to major transmission line projects and can be needed at three
different levels:
(a) Bulk transmission system facilities used to transfer bulk amounts of capacity and
energy between large generating stations and the major load centres. These
include the 500 kV system, parts of the 230 kV system, interconnections to other
utilities, and the circuits to Vancouver Island;
(b) Regional transmission system facilities within specific geographic areas, which
are closer to the loads and are generally 230 kV and below; and
(c) Substations or points of connection for loads or generators.
Consideration of bulk system reinforcements to comply with NERC/WECC Planning
Standards is triggered by growth in the coincident BC Hydro service area system
peak demand load forecast. This includes the Be Hydro domestic peak load plus firm
exports to FortisBC, New Westminster, Alberta, and the US. The system-wide peak is
known as the coincident system peak demand.
Investigation of regional, or area, system transmission requirements is determined
using the coincident regional peak demand forecast; while investigation of local area
or substation reinforcement requirements is determined using non-coincident station
peak demand forecasts.
BCTC Capital Plan F200821 December 2006
59
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4 - Capital Planning Process Overview
The comparison of load forecast to Planning Standards is complemented with
probabilistic analysis to validate reinforcement needs. The methodology to conduct
probabilistic analysis is described in Section 4.6.5 below.
Service Agreements
BCTC is obliged to meet the needs of customers that request service under the terms
of the OAn. This includes customers using the system for NITS to meet loads in
multiple locations from multiple sources, PTP to transfer energy from and to specific
points on the network, and Generator Interconnection services which enable
customers to inject energy into the network at the location of a new generation
source. These service requests must be studied to examine the feasibility and impact
on the existing system for the proposed use.
BCTC conducts planning studies to determine the impacts of the proposed use of the
system to see if system damage or sustained interruptions of service would occur.
The studies also determine any need to reinforce the system to securely
accommodate these requests.
BC Hydro is presently the only NITS customer on the transmission system and is
experiencing significant load growth throughout the province. BC Hydro issued a
2006 Call for Tender which resulted in thirty-eight new Energy Purchase Agreements
with IPPs. The impact of each associated IPP interconnection requires some local
extension of the system to accommodate the energy flow into the system. Customer
requests for long-term Point-to-Point transmission services are also tracked and
considered in BCTC's review of the capability of the system to meet customer needs.
All of these services together can create a need to enhance the system at both the
regional and the bulk levels. The need is identified by power flow and stability studies
of the systems which take into account the forecast load on the system as well as
these three types of service requests. Growth projects are planned when the
aggregated service requirements exceed the capability of the system, and
implemented when BCTC obtains service request commitments.
Demand and Resource Forecasts
The transmission system capacity requirements are dictated primarily by MW transfer
forecasts which are provided by BC Hydro in the form of a system load forecast which
BCTC Capital Plan F200821 December 2006
60
4 - Capital Planning Process Overview
includes peak demand load on the system as well as a generating resource
nomination to meet that load.
The continuing growth of BC Hydro's loads, requests for service from other OA IT
customers, and interconnections of new IPPs requires continuing expansion of the
transmission system. The addition or modification of substation equipment or
upgrading of existing circuits is often sufficient to meet these needs. New bulk
transmission circuits may be required to:
(a) Incorporate new generating stations into the transmission grid; or
(b) Increase the capacity of the grid if line or station upgrading cannot carry the
added transfers.
4.6.3.2.1 Sources of Forecast Inputs
BCTC currently uses a number of inputs to project future requirements for
transmission services:
(a) BC Hydro's 2006 Amended Long-Term Acquisition Plan (the amended LTAP);
(b) Twenty-year demand and forecasts provided by BC Hydro as part of its NITS 10-
year service agreement application. The Be Hydro NITS requirements include BC
Hydro's retail loads and generation resources as well as the following:
i. Service to the City of New Westminster;
ii. Service to FortisBC as required under its Power Purchase Agreement
with BC Hydro;
iii. Transmission service between BC Hydro and the systems of FortisBC,
TeckCominco and Columbia Power Corporation, as specified by the
Canal Plant Agreement between these parties; and
IV. Independent Power Producers (IPPs) with whom BC Hydro has
contracted to purchase the output, and designated by Be Hydro as
Network Resources to supply BC Hydro's loads.
The BC Hydro NITS Service Agreement includes the following information:
Bcrc Capital Plan F200821 December 2006
61
4 - Capital Planning Process Overview
J. Coincident peak-day forecasts for the integrated system are used for
the bulk system studies;
II. Regional coincident peak-day forecasts are used for the regional
transmission system studies; and
III. Non-coincident substation peak-day forecasts are used for the
substation studies.
(c) Identification of transmission service requirements by other customers such as:
i. Transmission capacity specified by FortisBC's resources in the East
Kootenays to its loads in other service areas, such as the Okanagan.
This transmission service is provided under the General Wheeling
Agreement; a grandfathered transmission services agreement which
existed prior to the establishment of the OATT;
ii. Long Term Firm Point-to-Point Transmission Service contracts with
OATT customers under the OA IT tariff; and
iii. Requests by generator owners to interconnect new generators, or to
accommodate changes to existing generators.
4.6.3.2.2 BCTC's Role in Developing Transmission Usage Forecasts
In developing its Growth Capital plan, BCTC does not duplicate the effort that BC
Hydro uses to build its load and resource forecasts. BC Hydro has the data and
detailed knowledge of its residential, commercial and industrial customer base
required to forecast its requirements. Therefore, BCTC believes that it is appropriate
that BC Hydro's load forecasts should form part of BCTC's consolidated view on the
future requirements for transmission. In addition, given that BC Hydro, as the
distribution utility, makes decisions on distribution system reconfigurations that can
impact substation loading, it is BC Hydro's role to develop the forecasts reflecting
those decisions at the substation level, which then become part of BCTC's overall
view on future transmission needs.
As noted, the location, timing and capacity of new generation resources are key
drivers of transmission planning, particularly as they impact the bulk system.
BCTC Capital Plan F200821 December 2006
62
(
Terasen Gas Inc.Information Request No. 1.12.1 Dated: April 11, 2007British Columbia Hydro & Power AuthorityResponse issued April 30, 2007British Columbia Hydro & Power AuthorityBe Hvdro 2007 Rate Desion Application
The paragraph mentions that the southeast interior of BC experiences morecongestion in the summer than in the winter and Vancouver Island experiencesmore congestion in the winter than the summer.
1.12.1 What proportion of the BC Hydro's system overall summer load andsummer peak demand is represented by the area in the southeastinterior where there is more congestion in the summer than in thewinter?
RESPONSE:
The proportion of the total Southern Interior's sales to Be Hydro's overall totalsales in July and August is 12.0 per cent and 12.2 per cent respectively. This isbased on F2006 sales data excluding distribution and transmission losses.
For the same year, the proportion of peak demand of the total Southern Interiorpeak relative to Domestic System peak in July and August is estimated to about12.7 per cent and 12.5 per cent respectively. This estimate involves using metereddata for the Domestic System and simulated hourly data, excluding losses, for theSouthern Interior.
((.....
Terasen Gas Inc.Information Request No. 1.12.5 Dated: April 11, 2007British Columbia Hydro & Power AuthorityResponse issued April 30, 2007British Columbia Hydro & Power AuthorityBe Hvdro 2007 Rate Desian ADDlication
The paragraph mentions that the southeast interior of BC experiences morecongestion in the summer than in the winter and Vancouver Island experiencesmore congestion in the winter than the summer.
1.12.5 In the 2006 IEP/L TAP BC Hydro identified the need in the near futurefor a significant expansion of the Interior to Lower Mainlandtransmission system ("the ILM project"). Is the need for the ILM projectdriven by the requirement to meet winter or summer peak loads?
RESPONSE:
Be Hydro understands that the need for the ILM project is due to the requirementto meet winter peak load.
(
0--4~i6"'f ILT/tP
2006 IEP Report
.;........
BChgdro
Chapter 4
.,.au
.-...i.
,;.:......
Amended Chapter 4 Supply Demand Tables andFigures reflecting the response to BCUC.IR
4.430.5.4
.~~ ( Table of Contents8.1 INTRODUCTION _ _ 1
List of FiguresFIGURE 4 - 9 2006 IEP INTEGRATED SYSTEM FIRM ENERGY LOAD RESOURCE BALANCE
List of TablesTABLE 4 -9 2006 IEP INTEGRATED SYSTEM FIRM ENERGY LOAD RESOURCE BALANCE.4TABLE 4 -10 2006 IEP INTEGRATED SYSTEM DEPENDABLE CAPACITY LOAD RESOURCE
BALANCE 5
iBC Hydro 2006 Integrated Electricity Plan
._ C'1 Introduction
'-'(
2 In the response to BCUC lR 4.430.5.4 (Exhibit B-17), BC Hydro provided an updated
3 energy load and resource balance table reflecting the addition of domestic non-firm
4 supply from the F2006 Call, Alcan and the proposed 2007 Call for the period of fiscal
5 2006 to fiscal 2015. This document provides the updated 20-year energy and capacity
6 load-resource balances that demonstrate Be Hydro's existing supply demand outlook
7 before LTAP directives.
1Be Hydro 2.006 Integrated Electricity Plan
I·._. , j\;. ,~ i ,\ ) 1 ,.. '
,- .'\ f' (. r 1 I"
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Figure 4 - 9 2006 IEP Integrated System Firm Energy Load Resourco Balance(2008 Load Forec.ast)
British ColumbiaUtilities CommissionInformation Request No. 1.5.1 Dated: AprilS, 2007British Columbia Hydro & Power AuthorityResponse issued April 30, 2007British Columbia Hydro & Power AuthorityBCHvdro2007RateDesionAcclication
Page 1of 2
Exhibit:B·3
5.0 Reference: Exhibit B-1, pp. 3-4 Energy Policy
The Application states on page 3 at lines 8-10 that" ... BC Hydro's 2007 RateDesign Application sets the foundation for BC Hydro's future rate designproposals that will address the opportunities to use rate structures to contributeto the implementation of the government's 2007 Energy Plan." At lines 26-27,the Application states that BC Hydro's long term rate strategy will involvesignificant external engagement with customers and stakeholders
1.5.1 In BC Hydro's view are the proposed rates consistent with the 2007Energy Plan?
RESPONSE:
This response addresses a number of questions asked by the BCUC andintervenors with respect to the 2007 Energy Plan and future rate design proposals.The 2007Energy Plan has been filed as an attachment to the response toESVIIR 1.6.1.
BC Hydro prepared its 2007 RDA in 2006, and most recently in January andFebruary 2007 engaged stakeholders through a number of workshops andmeetings to discuss the draft proposals. It was always BC Hydro's intention thatthis RDAwould establish an updated foundation upon which to base further ratedesign proposals that would specifically promote energy conservation and load
.management. Demand-side management has been a key part of BC Hydro'sresource acquisition plans for some time, and as demonstrated by theintroduction of stepped rates for large industrial customers in 2006, rate design isrecognized as an important tool in attempting to change customers' electricityusage behaviour. Going forward, BC Hydro's long term rate strategy will considerrate structures that may be capable of incenting behaviours towards achieving thetargets for demand side management set in the 2007 Energy Plan.
However, given that BC Hydro's rates have not been comprehensively reviewedby the acuc for 15 years it was considered important that some fundamentalaspects be addressed and confirmed before attempting to develop and proposemore significant structural changes to rates. The principle focus of the 2007 RDAis to ensure that BC Hydro's rates and Terms and Conditions are fair, efficient andsimple, and are reflective of the current cost and operating environment. Morespecifically BC Hydro's proposals include a rebalancing of rates as a result of theF2008Cost of Service Study; restructuring of the large General Service rate;phasing out of the E-Plus rate; and simplifying the Terms and Conditions, inparticular the distribution extension policy.
British Columbia Utilities CommissionInformation Request No. 1.5.1 Dated: April 5, 2007British Columbia Hydro & Power AuthorityResponse issued April 30, 2007British Columbia Hydro & Power AuthorityBe Hvdro 2007 Rate Oesion ADclication
Page 2of 2
Exhibit:B-3
The proposed changes to the large general service rate, the phasing out of the E-Plus rate and the redesigned distribution extension test are consistent with prioracuc determinations and reflect the need to amend certain rate structures andterms that are providing inefficient and inappropriate price signals. To that end,these proposals go some way to ensuring that energy conservation and efficiencyare not discouraged.
The 2007 Energy Plan was released on February 27, 2007 by the Provincialgovernment, 16 days prior to BC Hydro filing its 2007 RCA. Accordingly the 2007Energy Plan does not specifically inform any of the proposed changes in theApplication. While it is BC Hydro's view that the proposed rates are notinconsistent with the 2007 Energy Plan, it is neither realistic nor helpful to attemptto link the specific proposals in the 2007 RDA to the policy actions in the 2007Energy Plan. Be Hydro is not claiming that the proposals in the RDA-meet in fullthe requirements of the policy actions of the 2007 Energy Plan. As with many ofthe policy actions in the 2007 Energy Plan BC Hydro, along with other B.C. energyutilities, needs to clearly understand the requirements and implications of thepolicy, engage the relevant stakeholders, develop proposals and take theappropriate steps for implementation.
_r'OTerasen Gas Inc.Information Request No. 1.3.2 Dated: April 11 , 2007British Columbia Hydro & Power AuthorityResponse issued April 30, 2007British Columbia Hydro & Power AuthorityBe Hvdro 2007 Rate Desion Application
Page 1of 1
Exhibit:8·3
3.0 When discussing home heating on BC Hydro's website, BC Hydrorecommends that its customers use energy resources efficiently andstates: "It's important to match your energy source to its best use.Electricity is best suited for lighting and powering our appliances andtelevisions, whereas natural gas is ideal for space and water heating."
1.3.2 If so, how are the approvals sought in the Rate Design Applicationachieving the aims of this policy?
RESPONSE:
None of the approvals sought in the Application are specifically to encourage ordiscourage heating source alternatives. However, BC Hydro's proposed -distribution extension policy does reflect the cost differential between electric andnon-electric heating connections.
Please also refer to the response to Terasen IR 1.19.1.2.