Mr. Duane Chapman, Senior Regulatory Advisor

Transcription

1 Scott A. Thomson VP, Finance & Regulatory Affairs and Chief Financial Officer Fraser Highway Surrey, B.C. V4N 0E8 Tel: (604) Fax: (604) Regulatory Affairs Correspondence Ministry of Energy, Mines and Petroleum Resources Oil and Gas Policy Branch Oil and Gas Division 5 th Floor, 1810 Blanshard Street P.O. Box 9323 Stn Prov Govt Victoria, BC V8W 9N3 Attention: Mr. Duane Chapman, Senior Regulatory Advisor Dear Sir: Re: Terasen Gas (Vancouver Island) Inc. ( TGVI ) Application for a Certificate of Public Convenience and Necessity ("CPCN") for the Mt. Hayes LNG Storage Project and TGVI and Terasen Gas Inc. ("TGI") Approval of a Storage and Delivery Services Agreement (collectively the Project ) Project No Response to the Ministry of Energy, Mines and Petroleum Resources ( MEMPR ) Information Request ( IR ) No. 1 In accordance with the British Columbia Utilities Commission Order No. G setting out the Regulatory Timetable for the Project, TGVI and TGVI respectfully submit the attached response to MEMPR IR No. 1. If there are any questions regarding the attached, please contact Mr. Tom Loski, Director, Regulatory Affairs at (604) Yours very truly, TERASEN GAS INC. Original signed: Scott A. Thomson cc: Commission Secretary Registered Parties ( only) Attachment

2 Page Reference Exhibit B-1 Capital Cost Forecast Page Page 30 The updated cost for a 1.0 Bcf facility reflects approximately a 40% increase from 2004, and provides perspective of the overall cost increase of LNG storage facilities due to escalating equipment and construction costs. Page 31 To achieve the best EPC contract pricing in the current high level of industrial construction activity, a key objective will be to minimize the cost uncertainty in key elements of the Project including major equipment items, base materials and labour productivity and cost. 1.1 At what cost level would Terasen consider the project to not be in the best interest of customers? TGVI would consider that the project not to be in the best interest of customers if the costs escalated to the degree that the LNG Storage Portfolio was no longer expected to be the most cost effective solution to meeting the long term requirements. It is difficult to put a dollar value on this cost level, as it depends on a number of assumptions including recognition that there is also equipment and construction cost uncertainty associated with pipe and compression facilities. 1.2 How does Terasen propose to minimize cost uncertainty to protect the consumer? Please refer to the response to BCUC IR No. 1, Questions 15.1 and 64.1 and BCOAPO IR No. 1, Question 11.2.

3 Page If the project were to proceed to construction and in the end project over run costs were incurred who would take that risk and who would pay for such over run costs? TGVI expects that recovery of the final costs of the project, including any cost over runs, would be subject to prudency review by the Commission. However, to the degree that any cost over runs were prudently expended or were beyond the reasonable control of TGVI, these costs would be recovered through customer rates. TGVI is taking many steps to minimize cost uncertainty and balance risks. Please refer to the response to BCUC IR No. 1, Question 60.1 and BCOAPO IR No. 1, Question 11.2.

4 Page Reference Exhibit B-1, Section 5.2 Return on Equity Page Using a 6.2% Discount Rate, what is the net present value of the incremental revenue requirement from the extra 50 basis points on return to customers over 15 and 25 years should TGVI s request for an additional 50 basis points above be approved? The following table summarizes the incremental revenue requirement from the LNG Storage Facility under both 10% and 9.5% ROE. Note that as in the application, the long term TGVI ROE based on the currently approved formula is assumed to be 9.5% in which case the additional 50 bp would result in a corresponding ROE for the LNG Storage Facility i 10%. The results in the table that are based on the 9.5% ROE also assume straight line depreciation is applied. In order to see the impact of the 50 basis points, therefore, the 10% case is shown with and without the adjusted depreciation schedule. The results show the present value of the impact of the 50 basis points over the 25 year evaluation period is $5 million (i.e. $230M less $225M). The present value impact over the shorter evaluation period is approximately $3 million (i.e. $156 less $153). The proposed adjusted depreciation schedule more than offsets the impact of the 50 basis points in the shorter evaluation period, resulting in reduced costs of $5 million (i.e. $148 versus $153). $Millions Evaluation Period PV@6.2% Discount Rate 15 Year 25 Year TGVI ROE = 9.5% with Straight line Depreciation TGVI ROE = 10% with Straight line Depreciation TGVI ROE = 10% with Adjusted Depreciation $Millions Evaluation Period PV@10% Discount Rate 15 Year 25 Year TGVI ROE = 9.5% with Straight line Depreciation TGVI ROE = 10% with Straight line Depreciation TGVI ROE = 10% with Adjusted Depreciation

5 Page The application states that the extra 50 basis points are required to make the return more comparable, although still lower, than those realized by similar investments elsewhere in North America. Are there unique risks to the Utility shareholder in building and operating this LNG project as opposed to any other parts of the regulated business that justifies the extra return requested? The request for an additional 50 basis points is based on what is fair, reasonable, and appropriate, not on unique risks. TGVI is of the view that the risk associated with the LNG rate base would be similar to its current transmission rate base, however the project will result in a step function increase in the investment in the business. The primary difference between this Project and a minor capital expenditure relates directly to the fact that this application addresses a transformative prospective investment versus that of sunk or embedded investment. The alternative to this investment (ie the Pipe and Compression Portfolio) would be more costly to customers but involve a significantly smaller financial commitment from TGVI at this time. 2.3 Is the project still economic if the extra 50 basis points is not approved? Without the 50 basis points, the revenue requirement associated with the project is lower for the customer but the project is less financially viable for the shareholder. In this scenario, the shareholder would have to re-evaluate whether it would still be prepared to proceed with the project. This decision to proceed would depend on an assessment of all of the terms and conditions of the approvals requested in the Application. The Act requires the BCUC to consider the interests of both customers and investors. TGVI believes that its Application supports the requested level of ROE while also being the best option available to customers.

6 Page Reference Exhibit B-1 Section Terms and Conditions page In Figure 5-4 the bar graph shows that TGI has a fixed revenue requirement while the TGVI revenue requirement increases. Why does Terasen propose to fix TGI s revenue requirement and have TGVI revenue requirement variable? The total costs in each year in the bar graph in Figure 5-4 represent TGVI s annual incremental cost of service of the LNG Storage Facility. In the initial 20 years the cost of service of the facility is expected to increase by approximately 1% a year as a result of the proposed adjusted depreciation schedule. As shown in Figure 5-2 the proposed depreciation schedule reduces the cost of service in the initial period relative using straight line depreciation. If straight line depreciation is used, the initial costs would be higher but the cost of service would be expected to decline from year to year. Figure 5-3 shows that customers are indifferent between the two depreciation approaches over the longer term but benefit from the adjusted depreciation schedule over the longer term. The charges paid by TGI to TGVI under the proposed Storage and Delivery Agreement are based on its avoided cost of storage resources and are not directly linked to the revenue requirement of the LNG Storage Facility. For example, if it is determined that straight line depreciation was used such that the cost of service declined from year to year, TGI s charges would continue to remained fixed at the same level. The TGVI costs shown in Figure 5-4 represent TGVI s incremental cost of service of the LNG Storage Facility net of the mitigating revenue TGVI will receive from TGI under the Storage and Delivery Agreement. As proposed in the Application, these costs will be allocated to TGVI s gas portfolio and system capacity and together represents much lower costs for TGVI than it would realize under the Pipe and Compression Portfolio. Please also refer to the responses to BCUC IR No. 1, Questions 23.4, 23.5, 39.3 and If TGI s cost for LNG service is fixed for the first 20 years, how is risk being shared between TGVI and TGI customers during the construction period and then on an ongoing basis for items such as operating and maintenance costs and capital costs over time? Under the proposed structure, by paying a fixed fee TGI s customers are not exposed to risks related to capital and fixed operation costs during construction and operation of the facility. TGI is exposed to variations in the operating cost related to fuel and electricity usage for liquefaction and vapourization. Please refer to the response to BCUC IR No. 1, Question 40.4 for further discussion on this topic.

7 Page Reference Exhibit B-1 Section 6.1.1, Appendix D Core Demand Appendix D of the application assumes that all customer classes on the TGVI system s use per customer remain static from 2007 to The 2006 Resource Plan determined that it was possible that use per customer could decrease over time. For example, residential use per customer decreased from 60 gigajoules/yr to 58 from 2003 to How would appendix D and Figure 7-9 be affected if peak day use per residential customer was 10 % lower starting in 2011? At which point would more capacity be required to cover TGVI, Whistler, Squamish and the JV at their current firm level? The 2006 TGVI Resource Plan (pp. 42) states that (annual) use rates for residential customers are forecasted to remain stable and that (annual) use rates for commercial customers actually experienced an increase in 2005, but are also forecasted to remain stable. TGVI s response to BCUC IR1, question 29.1 explains why TGVI does not expect annual use per customer on Vancouver Island to decrease. The same discussion found in these references also indicates that design day use per customer is also not expected to decrease. Further, a step change such as that suggested in this question is extremely unlikely to occur. Finally, the 2006 TGVI Resource Plan (pp. 37) also explains that because residential customers are forecasted to be the fastest growing segment of customer mix, the growth in peak demand is outpacing the growth in annual demand for the overall TGVI system. For all of these reasons, TGVI believes that any of the scenarios presented in this question are unlikely to occur. With this clarification in mind, a 10 % lower peak day use per TGVI residential customer starting in 2011 would reduce the overall peak day demand from TGVI core customers by 9%. This decrease would defer the first capacity expansion from 2013 to 2017 in order to meet the peak day demands for TGVI, Whistler, Squamish and the VIGJV at its current firm level. See Figure 4.1 below showing the current design day system capacity relative to the design day demand forecast for this scenario..

8 Page 7 Figure Design Day System Capacity TGVI Design Day Forecast Terajoules per Day Year beginning November BC Hydro VJGJV Whistler Squamish TGVI Core minus 10% residential System Capacity 4.2 How would appendix D and Figure 7-9 be affected if peak day use per customer was 10 % lower starting in 2011 for all core customer classes? At which point would more capacity be required to cover TGVI, Whistler, Squamish and the JV at their current firm level? At which point would more capacity be required to cover TGVI, Whistler and Squamish? Again, please refer to the response the Question 4.1 above for reasons why TGVI believes this scenario is unlikely to occur. With this clarification in mind, a 10 % lower peak day use per customer for all TGVI customer classes starting in 2011 would defer the first capacity expansion from 2013 to 2017 in order to meet the peak day demands for TGVI, Whistler, Squamish and the JV at their current firm level. See attached Figure 4.2 showing the current design day system capacity relative to the design day demand forecast for this scenario. Capacity expansion would be required in 2022 to meet the peak day demands for TGVI, Whistler, and Squamish without the VIGJV as a firm transport customer.

9 Page 8 Figure Design Day System Capacity TGVI Design Day Forecast Terajoules per Day BC Hydro VJGJV Whistler Squamish TGVI Core minus 10% System Capacity Year beginning November 4.4 How would appendix D and Figure 7-9 be affected if peak day use per customer was 20 % lower starting in 2011 for all core customer classes? At which point would more capacity be required to cover TGVI, Whistler, Squamish and the JV at their current firm level? At which point would more capacity be required to cover TGVI, Whistler and Squamish? Again, please refer to the response to Question 4.1 above for reasons why TGVI believes this scenario is unlikely to occur. A 20 % lower peak day use per customer for all TGVI core customer classes starting in 2011 would defer the first capacity expansion from 2013 to 2026 in order to meet the peak day demands for TGVI, Whistler, Squamish and the JV at their current firm level. See attached Figure 4.4. Capacity expansion would be required in 2030 to meet the peak day demands for TGVI, Whistler, and Squamish without the VIGJV as a firm transport.

10 Page 9 Figure Design Day System Capacity TGVI Design Day Forecast Terajoules per Day BC Hydro VJGJV Whistler Squamish TGVI Core minus 20% System Capacity Year beginning November 4.5 How would appendix D and Figure 7-9 be affected if peak day use per customer was 10% higher starting in 2011 for all core customer classes? At which point would more capacity be required to cover TGVI, Whistler, Squamish and the JV at their current firm level? What year is more capacity required to cover TGVI, Whistler and Squamish? TGVI also believes that a step increase of this magnitude is highly unlikely for the reasons described in the response to Question 4.1 above. With this clarification in mind, a 10 % higher peak day use per customer for all TGVI customer classes in 2011 would advance the first capacity expansion from 2013 to 2011 in order to meet the peak day demands for TGVI, Whistler, Squamish and the JV at their current firm level. See attached Figure 4.5. Capacity expansion would be required in 2012 to meet the peak day demands for TGVI, Whistler, and Squamish without the VIGJV as a firm transport.

11 Page 10 Figure Design Day System Capacity TGVI Design Day Forecast Terajoules per Day BC Hydro VJGJV Whistler Squamish TGVI Core plus 10% System Capacity Year beginning November

12 Page Reference Exhibit B-1 Section Page 64 The use of underground storage such as JP storage to structure a 10-day LNG service requires an increased capacity allowance to account for differences in withdrawal characteristics To account for this decline in daily withdrawal rate a 15-day storage capacity at JP storage is used to evaluate a 10 day LNG equivalent service. 5.1 Please show a table illustrating the 15 days of daily withdrawals assumed in the JP storage alternative along with the volume required to be stored at the facility prior to 15 days of withdrawals starting. Is the withdrawal rate decline a function of how much gas is in storage at the time of withdrawal? The maximum withdrawal rate for underground storage typically decreases as the inventory decreases due to the drop in pressure. The reference to 15 days of storage capacity is the capacity to withdrawal ratio or a capacity of 15 times the daily maximum withdrawal. Because of the decline in deliverability, 15 days of capacity would take more than 15 days to withdraw from storage. The chart below illustrates the relationship between withdrawal rate and inventory based on a 150MMcfd 15-day underground storage facility. This is based on the decline rate profile provided in Appendix G Attachment 6 of the 2006 TGI Resource Plan. The withdrawal rate starts to decline after seven days at maximum withdrawal rate. At this point, it is necessary to re-inject gas into storage to maintain the maximum withdrawal rate Withdraw al Rate Decline of Underground Storage 15-Day Service Withdrawal MMcfd Days at Maximum Available Withdraw al Rate

13 Page Does the Mist storage facility contract for withdrawal volumes on a declining volume basis or can 10 days be contracted at an even withdrawal rate? The storage agreements at Mist are based on a 26-day service and include a decline in withdrawal rate as inventory reduces. This service provides an even withdrawal rate for 12 days based on the decline rate profile provided in withdrawal Appendix G Attachment 6 of the 2006 TGI Resource Plan. The higher storage capacity associated with Mist makes this a more expensive resource than a 15 day JP storage service. The economic preference for high deliverability, shorter duration market area storage relative to longer duration resources is discussed in section of the Application Withdraw al Rate Decline of Underground Storage 26-Day Service Withdrawal MMcfd Days at Maximum Available Withdraw al Rate 5.3 Does the Unocal storage facility contract for withdrawal volumes on a declining volume basis or can 10 days be contracted at an even withdrawal rate? The storage agreement at Aitken Creek has a flat withdrawal rate that is not subject to decline due to inventory volumes. A 10 day storage service at Aitken Creek may be possible to contract but contracting for firm redelivery transport capacity on Westcoast pipeline would make this option uneconomic. To ensure firm redelivery to Huntingdon, 365 days of capacity on Westcoast pipeline would have to be acquired.

14 Page On average how often over the last 10 years has TGI and TGVI experienced design day temperatures requiring 10 days of peaking supply? The design year temperature pattern for TGI and TGVI is based on the average daily temperatures of the five coldest years since To estimate the historical requirement for a 10-day peaking supply, the average daily temperatures at or below the design year temperature on the 10 th coldest day was examined. The design year temperature on the 10 th coldest day for TGI and TGVI is and -2.7 Degree Celsius respectively. On average over the last 10 years both Vancouver and Victoria has experienced one day per year of daily average temperatures at or below their respective 10 th coldest day design year temperature. The figures below show the number of days in each gas year that historical temperatures at Vancouver and Victoria have been at or below the 10 th coldest day design year temperature for TGI and TGVI respectively. The analysis demonstrates the requirement for peaking supply may vary from year to year but the need can exceed 10 days. Please note, the requirement for peaking supply is based on incremental resource requirements to meet long term demand. As such the use of historical temperature alone does not consider the effects of increasing customer accounts, change in use rates, and change in customer composition. The analysis of historical temperatures demonstrates an LNG Storage facility provides an effective solution to manage the requirements for peaking supply, extended winter periods, and variability in temperature.

15 Page Reference Exhibit B-1 Economic Justification and Customer Impacts, page Has Terasen considered other options to building the LNG facility such as contracting for more volumes at Huntingdon from November to March at a gas daily related price? In this option gas the gas would be sold back into the market on warm days and only kept on peak days. Terasen considers all gas supply options available in the market, including transport, storage, term commodity purchases, and peaking supply. Commodity purchases at Huntingdon are maintained in both TGI and TGVI gas supply portfolios. Please see the response to BCUC IR #66.2. Terasen s purchase of Huntingdon gas for peaking purposes contributes to the volatility at Huntingdon. If Terasen is selling gas on warm days then on peak days when the gas is retained, the market that had formerly been supplied would be short and would likely bid up the price in order to secure supply. This contracting strategy increases the risks of high commodity prices and over reliance on mitigation revenue in the gas supply portfolios. High prices not only impact the cost of the peaking supply but can impact the cost of other resources in the portfolios. In addition to providing peaking supply, the LNG Storage facility reduces volatility at Huntingdon and enhances flexibility in the decision to resell gas. 6.2 Using historical weather records, how many times on average over the last 25 years has TGI seen design day temperatures that would require 10 days of peaking supply? On average over the last 25 years both Vancouver and Victoria has experienced three days per year of daily average temperatures at or below their respective 10th coldest day design year temperature. Please refer to the response to Question 5.4 for an examination of historical temperatures.

16 Page What has been the average spread each year over the last 5 years between published Gas Daily prices and TGI s and TGVI s average selling price at Huntingdon in Canadian dollars per GJ for periods of November to March? When Terasen sells gas on for a day at Huntingdon, it can usually receive a price within a few cents of the Platt s Gas Daily index. It also can realize prices that are different such as in the case of a recallable sale where Terasen sells gas on a daily basis at a monthly index price subject to recall when the weather is cold. For this reason, the average sales price for the day can be different than the Gas Daily average for the day. The table below provides the average spread between the TGI average selling price and the published Gas Daily Sumas price for the last three November to March period. Data prior to 04/05 is difficult to obtain due to a change in Terasen s gas information system. Average Spread Between TGI Winter Sale Price and Platts Gas Daily at Huntingdon $/GJ 06/07 $ /06 $ /05 $ 0.14 TGI s average sale price in winter has been higher than the Gas Daily Sumas price for the last three years. However for the same time period, TGI s average sales price has been below the monthly Sumas index, the primary price index used for Huntingdon purchases, The average sales price does fluctuate and is highly dependent on the makeup of gas portfolio and timing of demand. The results above show that with the current portfolio and the use of storage, gas sales were managed evenly throughout the winter to limit losses. This may not be the case every winter. If there were proportionately more purchases of Huntingdon gas and less storage, the averages sales price would likely be lower because TGI would be selling more gas on warmer days when prices are usually lower. It should also be noted that other major gas utilities in the region as well as Terasen have similar procurement practices and have take steps to limit the need to purchase additional gas and instead rely on storage to meet elevated demand due colder than normal weather. Part of the reason that it has been possible for Terasen to achieve a reasonable mitigation average is because of these practices. TGVI has a different portfolio makeup and therefore a slightly different mitigation experience. Over the past three winters, TGVI sales at Huntingdon have averaged close to the average Gas Daily index (within a half cent per GJ). Unlike a merchant s activity, TGI s and TGVI s participation in commodity resale is limited to mitigating cost of procurement. Terasen can only sell gas when it is not required to meet demand, normally coinciding with lower market demand and resale price.

17 Page 16 Contracting for seasonal gas to meet peaking requirements increases resale volumes consequently introducing both volume and price risk in the gas supply portfolios. The LNG Storage facility provides peaking supply without increasing resale risk and enhances flexibility in the resale decision. 6.4 Is it possible in today s market and markets forward for Terasen to pick up extra supply at Huntingdon during the winter period November to March for TGVI or TGI as its load grows each year? TGI and TGVI s reliance on Huntingdon supply to meet incremental gas supply requirements continues to increase each year. Currently, Terasen s total activity at Huntingdon accounts for approximately 50% of pipeline capacity there on peak day. An increase in commodity purchase or the removal of base load gas by a large participant such as Terasen at Huntingdon, a market characterized by limited buyers and sellers, generates supply uncertainty and leads to greater price volatility. Operationally, larger commodity purchases at Huntingdon limits the ability to redeliver JP and Mist storage gas to TGI service area via displacement of southerly flowing gas The purchase of peaking supply that is not backed with supporting infrastructure is not a long term solution. Such a contracting strategy does not provide appropriate market signals to facilitate development of an efficient market place and jeopardizes long term supply security for the region. 6.5 Would there be a benefit if TGI or TGVI could contract long term for an incremental 5,000, 10,000, 20,000, or 50,000 Gj s of supply at Huntingdon (November-March) at a gas daily price for purposes of only keeping it during peak periods? There is no benefit from long term commodity contracts at Huntingdon to meet incremental winter peaking requirements. Analysis of the gas supply portfolio indicates the economic preference for a high deliverability shorter duration resource to meet long term projected demand. A 100% load factor contract is not an effective long term peaking supply option. It increases exposure to price volatility, introduces resale risk, and limits flexibility in the TGI and TGVI gas supply portfolios.

18 Page 17 From a market structure perspective, the reliance on incremental peaking supply not backed with infrastructure creates a false sense of supply in the regional market place. In the long term, a lack of regional infrastructure would create uncertainty in supply and increase price volatility. Purchasing supply in this market environment would likely result in higher purchase costs for TGI and TGVI. 6.6 Has TGI or TGVI in the past purchased more gas supply at the Huntingdon pool during the November to March period vs April/October period over the last 10 years as one of ways of having some peaking supply available should cold weather happen? Historically, commodity purchases at Huntingdon have being higher in the winter months relative to summer months. The reliance on purchases at Huntington to meet incremental peaking supply has been increasing over time due to the limited availability of infrastructure backed peaking supply. Terasen recommends limited purchases at Huntingdon due to the lack of market liquidity and consequent introduction of supply and price volatility risk in the TGI and TGVI gas supply portfolios. The decision to purchase peaking supply at Huntingdon is made annually and depends on market availability and pricing. Huntingdon gas is a temporary short term supply solution and does not alleviate the need for incremental resources to meet projected demand. 6.7 Appendix E Gas Market Information, page 15 it shows potential LNG Import terminals in the Pacific Northwest. How could LNG import terminals change liquidity to the Huntingdon market in the short term and long term? LNG import terminals would provide additional base supply into the region. LNG terminals typically are designed to operate at a high load factor, that is send out supply each day at a steady rate. For the terminals in the north (Kitimat, Westpac) this would have a similar impact to the region to adding conventional supply at Station 2. As the LNG supply would flow into the Westcoast Pipeline south of Station 2 it would likely partially offset supply flowing from Northeast BC to Station 2. For the terminals in the south around the Columbia River, LNG supply could offset flows through Huntingdon that currently serve the region and this might decrease the ability to receive JPS and Mist storage via displacement.

19 Page 18 In order to have liquidity in a market it takes a combination of buyers and sellers. Absent an expansion of the Westcoast Pipeline system, LNG supply from the North would likely not have much effect on liquidity at Huntingdon as the amount of available supply there would not change. It would likely enhance liquidity at Station 2 because there would be a greater amount of supply and presumably the infrastructure to move it to market. For terminals south of Huntingdon, it is less clear what the impact would be on Huntingdon. All of the Southern import LNG terminals are contemplating new pipeline connections into the PNW as well as California through the TransCanada GTN pipeline or a new direct connection to California. TGI is not aware of any plans for additional pipeline capacity to deliver incremental gas back to Huntingdon. To the degree that import LNG physically supplies markets that had been served by gas sourced at Huntingdon, it could hurt liquidity there by reducing the market available to it (the number of potential buyers). 6.8 Based on the above answers to 6.4 and 6.5 what would need to happen for Huntingdon to be more liquid? Liquidity is created by a combination of buyers and sellers. Liquidity is enhanced by the assurance that the price is established by market fundamentals and all participants have the opportunity to participate in the market. i.e. Market participants are attracted to the pricing point because the have reasonable assurance of participating in the market at a fair price. Huntingdon evolved as a market hub because it was a natural place for US markets to meet Canadian suppliers. As Canadian suppliers have developed more options for their BC production, the need to dedicate supply to the Huntingdon market has diminished and liquidity fallen with it. In turn, PNW utilities have moved to buying more of their supply at Station 2 rather than Huntingdon as they seek suppliers. This has further hurt liquidity at Huntingdon. One buyer cannot create liquidity on its own. Volatility can hurt liquidity in that participants can be driven away from participating in a market that does not reflect fundamentals. If TGI were to rely on purchasing gas at Huntingdon for significant peaking supply, it would create volatility there as the markets that would be relying on that supply would have it withdrawn when TGI required it. As there are limited other sources of supply, the effect would be to create price volatility. Those that were without supply would bid up the price in order to get it. The best way to create liquidity is to grow the size of the market and to create options for supply and demand. It is also beneficial to have no large entities that dominate the market. The Alberta market is an example of an extremely liquid market. Available

20 Page 19 supply is in excess of 15 PJ/d. There has also been a significant amount of storage developed so there are options for incremental supply into the market. As well there are buyers who participate who have other options for supply. For example, US Midwestern markets can source supply from Alberta or US sources. While there are large buyers and sellers, no one party is able to dominate the market. Huntingdon in contrast is a much smaller market at just over 1 PJ/d on average. Even with the development of LNG storage on Vancouver Island TGI/TGVI, core demand will be approximately 50% of the peak day Huntingdon market so Terasen s actions have can have a large impact on the functioning of the market. While the Mt. Hayes LNG facility is a relatively small component of overall supply at Huntingdon on an annual basis, it will contribute to enhancing liquidity there by increasing the overall supply to that market and reducing the impact of Terasen s peaking requirements on it. With reference to Questions 6.4 and 6.5, it would be difficult, given the size of the Huntingdon market, to create the kind of liquidity that would allow Terasen to source a significant portion of its peaking gas on the spot market there. Even in Alberta, 100 MMcfd of incremental demand is significant, particularly when it is cold. It would require a very large injection of new supply into the Huntingdon market with buyers then sourcing gas for outside the region to create the conditions in which supply could be diverted for peaking without adversely affecting the market. This would mean either something several large import LNG terminals located in proximity to Huntingdon or large pipeline expansions into the region to a liquid supply point.

21 Page Reference Exhibit B-1 Section System Cost Allocation Assumptions 7.1 What would be the financial impact to TGVI customers and TGI customers by customer class, year over year as a result of the proposed LNG facility and its incremental cost of service? What would be the financial impact using the base P50 scenario, P10 scenario, P90 scenario and 20% over the P90 scenario? The financial impact to TGVI customers for Approaches 1 and 2 using the base P50 scenario, P10 scenario P90 scenario and P90+20% scenario are included in Attachment 7.1. The net incremental LNG Storage Portfolio revenue requirement and levelized costs are presented on the Capital Cost Comparison worksheet rows and rows respectively. For TGI customers there is no financial impact since under the proposed Storage and Delivery Services Agreement its cost of services from the LNG Storage Facility is fixed. 7.2 What would the values in Figure 8-2 be under the scenario of a P90 capital cost and 20% over the P90 cost estimate? The values in Figure 8-2 represents the forecast of the allocation of costs based on the expected the cost of service of the LNG Storage Facility for the year 2015 based on the P50 capital case. The values for a scenario of a P90 capital cost and 20% over the P90 Cost estimate are summarized in the following table: Cost Allocation Year 2015 Millions $ P50 Capital Cost* P90 Capital Cost P90+20% Capital TGI Storage and Delivery $12.6 $12.6 $12.6 TGVI Gas Portfolio $6.3 $6.3 $6.3 TGVI Net LNG Storage $1.9 $4.1 $6.9 * From Figure 8-2 (Application, page 155)

22 Page How many dollars is the model allocating to the Joint Venture and ICP in Figure 8-2? Figure 8-2 illustrates the revenues recovered from TGI under the Storage and Delivery Agreement, and the allocation to TGVI s gas supply portfolio based on the avoided cost of alternate storage resources. The TGVI Net LNG Storage costs represent the remaining revenue requirement in 2015 after consideration of the revenues from TGI and the value to TGVI s gas supply portfolio. Over the evaluation period it is the difference between these costs and the costs of the facilities that would otherwise be required over the planning period (i.e. pipe and compression) that represent the savings all of TGVI customers will realize. Please see the responses to BCUC for schedules that show illustrative examples on how these net costs may be allocated among TGVI s different customers. 7.4 How much of the $12.6M expenditure on TGI in Figure 8-2 will be allocated to TGI Transportation customers if any? The $12.6 million figure in Figure 8-2 represents the annual revenue paid by TGI to TGVI under the Storage and Delivery Agreement not a $12.6 million expenditure on TGI. TGI will assign its cost of the Mt Hayes storage services to its Midstream Cost Reconciliation Account which is not allocated to TGI Transportation customers. Please refer to BUCU IR# regarding the allocation of cost to TGI customers. Note that TGI Transportation customers do not benefit from the LNG Facility. On the other hand, the Project will allow TGVI to avoid future transmission capacity expansion facilities, and therefore will result in significant lower costs for transmission system benefiting both Core and Transport Customers. 7.5 How much of the $12.6M expenditure on TGI will be allocated between Lower mainland customers and interior customers? The $12.6 million figure in Figure 8-2 represents the annual revenue paid by TGI to TGVI under the Storage and Delivery Agreement not a $12.6 million expenditure on TGI. TGI will assign its cost of the Mt Hayes storage services to its Midstream Cost Reconciliation Account. These midstream costs are allocated amongst all TGI core market customers in the Lower Mainland, Inland and Columbia service areas on an equal distribution based on usage just as pipeline and storage costs are currently allocated.

23 Attachment 7.1