re: terasen gas (vancouver island) inc. (“tgvi”) … · november 17, 2004 british columbia...

November 17, 2004 British Columbia Utilities Commission Sixth Floor - 900 Howe Street Vancouver, B.C. V6Z 2N3 Attention: Mr. Robert J. Pellatt, Commission Secretary Dear Sir: RE: Terasen Gas (Vancouver Island) Inc. (“TGVI”)

2004 Annual Review TGVI Response to British Columbia Hydro & Power Authority (“BC Hydro”) Information Request No. 1

TGVI respectfully submits the attached responses to BC Hydro Information Request No. 1. Please note that these responses have been made in consideration of revisions to the allowed return on equity and cost of service allocations as described in the TGVI submission of November 17th, 2004, which is attached for your reference and labeled as Appendix A. Twenty copies will be sent to the Commission office, Thursday November 18th, 2004. Yours very truly, TERASEN GAS (VANCOUVER ISLAND) INC. Original signed by Tom Loski

For: Scott A. Thomson Attachment cc: Registered Intervenors

Scott A. ThomsonVice President, Finance & Regulatory Affairs 16705 Fraser Highway Surrey, B.C. V3S 2X7 Tel: (604) 592-7784 Fax: (604) 592-7890 Email: [email protected] www.terasengas.com

TERASEN GAS (VANCOUVER ISLAND) INC.

2003 – 2005 SETTLEMENT AGREEMENT 2004 ANNUAL REVIEW OF ITS 2005 REVENUE REQUIREMENT

RESPONSE TO BC HYDRO AND POWER AUTHORITY

INFORMATION REQUEST NO. 1

1.0 Reference: TGVI Advance Information for the 2004 Annual Review

Transportation Revenues Table 4.1, Page 4.1 Page 4.8

Preamble: Transportation Revenue under the “2003 Test Year” is $20.8 million and

the source is referenced as the 2003/05 Revenue Requirements Application. Appendix F of that application, dated September 26, 2002, shows total transportation revenue of $25.3 million for 2003, and Exhibit 12 of that proceeding shows Transportation Revenue for 2003 as $27.96 million (Sheet 14 of 15, revised March 3, 2003).

Request: (a) Please reconcile the differences in Transportation Revenue for 2003 as

described in the Preamble. Response As stated in the Annual Review, 2003 Test Year Transportation Revenue of $20.8 Million is sourced from Commission Order G-02-03 page 13 (January 9, 2004). The same figure can be referenced to in the 2003 Annual Review (November 2003) Tab 4, pages 4.1 and 4.8; as well as the 2003 Revenue Requirements Application (July 2002) Tab 19, schedules 2, 96, and 101. Rolling Forecast is a snap shot of the company’s year end projection based on prevailing market conditions and corporate objectives. Hence, it is not unusual to have variations over a 9-month period (July 2002 to March 2003) in these “liquid” forecasting exercises. Transportation Revenue forecasted in July’s Application was based on actual approved rates when the Revenue Requirements Application was prepared. The subsequent $25.3 Million forecast from September’s Rate Design Application was based on proposed rates. Please see table below for detail. The Exhibit 12 document is not readily available.





- 2 -

TERASEN GAS (VANCOUVER ISLAND) INC.2003 Transportation Revenue Schedule

2003/05 Application Rate Design Application2002 Jul 2002 Sep

Energy (GJ's) 23,561,749 25,383,578 Revenue ($'000) $20,775 $25,287

Average Rate per GJ $0.88 $1.00

(b) With respect to the statements under the heading Transportation Revenue on Page 4.8, please allocate the 2003 Actual Revenue shown on Table 4.1 to firm and interruptible services.

Response TERASEN GAS (VANCOUVER ISLAND) INC.Transportation Revenue Schedule($ million)

2003

Firm $25.9Interruptible 2.4

Total T-Service Revenue $28.3





- 3 -

2.0 Reference: TGVI Advance Information for the 2004 Annual Review 2004 Energy Sales, Table 5.4, Page 5.6

Preamble: The projected energy sales are below the Test Year estimate.

Request:

(a) How much of the reduced energy sales forecast for 2004 does TGVI attribute to

weather and how much is due to conservation resulting from higher gas prices? Response The 2004 Projected energy volume is expected to be 414.0 TJs less than forecast for the 2004 Test Year. A significant portion of this relatively minor 3.6% variance appears to be caused by warmer than normal weather. A final estimate of the degree to which weather is responsible for this variance will not be known until final actual weather data is available in early 2005 and normalized use rates calculated. At this time, no trend is detectable for a movement of average annual use rates given the presence of such offsetting factors as load building incentives and the adoption of higher efficiency furnaces. (b) Does TGVI anticipate a similar pattern toward conservation in 2005? Response No. The 2005 forecast does not assume significantly different use rates from those expected for 2004. (c) If so, how is this reflected in the 2005 forecast? Response See response to IR 2.0 (b) above. (d) How does TGVI anticipate it will make up for conservation related revenue

shortfalls of its energy sales? Response TGVI will continue to identify opportunities to increase the penetration of natural gas use amongst consumers. In the past, TGVI has employed marketing programs to attract new residential customers to improve the utilization of the gas delivery system. These





- 4 -

programs provide incentive to builders, developers and existing customers to install more natural gas fueled equipment. TGVI intends to continue with these existing load building programs and will also seek to identify further opportunities, particularly electricity to gas fuel substitution.





- 5 -

3.0 Reference: TGVI Advance Information for the 2004 Annual Review Energy Sales and Proposed Rates Table 5.4, page 5.6 Table 6.1, page 6.1 Appendix C

Preamble: The references lack detail.

Request:

(a) Table 6.1 shows an Annual Revenue Surplus of $14.4 million forecast for 2005.

The first table of Appendix C shows a revenue deficit of $1.7 million for 2005. Please provide a revised table of the Appendix C summary revenue proof showing the $14.4 million surplus.

Response Please see MEM IR 17.1. The revenue requirement surplus includes $5.9MM in RDDA financing costs and $7.8MM of after tax RDDA drawdown. (b) Using the format requested in (a) above, please provide similar tables for each of

the 2003 Test Year, 2003 Actual, 2004 Test Year and 2004 Projected cases. Please provide the weighted average “Effective Rate” for 2004 having regard for the changes in rates that were approved in BCUC Order No. G-87-04. Please include in the response the estimates for each year of interruptible (“IT”) service at each IT toll and the associated revenue.

Response Revenue proof schedules, similar to the table included in Appendix C, showing previous year forecast data were filed as part of TGVI’s Rate Design Application and TGVI’s 2003 Annual Review. Compliance with the above request would require a “reverse-engineering” of actual results back through the COSA model. Time does not permit the production of this information by the filing deadline and TGVI does not understand what if any benefit would be derived from this commitment of resource in evaluating toll proposals for 2005 at this time. (c) For RGS, the Effective Rate on the first table of Appendix C is $15.286, but the

detailed revenue proof shows an average rate equal to (67,486,825/4,411,575 =) $15.2977. Please clarify which rate is correct and provide revised tables.

Response





- 6 -

Please refer to Appendix A.

(d) For SGS-2, the Effective Rate on the first table of Appendix C is $14.473, but the

detailed revenue proof shows an average rate equal to (7,840,361/538,237 =) $14.567. Please clarify which rate is correct and provide revised tables.

Response Please refer to Appendix A. (e) For LGS-3, as shown in the detailed revenue proof in Appendix C, please explain

the reference to CRxx and the associated revenue of $1,349,465. Response The CRxx rate class is closed. This rate class is not allocated costs and for presentation purposes this revenue was included in the LCS3 rate class.





- 7 -

4.0 Reference: TGVI Advance Information for the 2004 Annual Review Royalty Adjusted Gas Cost, Page 5.5, Line 11

Request: (a) As of what date was the “snapshot” of gas prices taken and what has happened

to gas prices since? Response The gas prices were based on the October 26th, 2004 market forecasted prices, and prices have fallen somewhat since. Please refer to response to BCUC IR 29.5 for a revised Cost of Gas budget, which is based on the November 15, 2004 forward strip and one-year forward exchange rate. (b) What was the CAD/US exchange rate on the date of the snapshot, and what was

the one-year forward exchange rate on that date? Response The CAD/US spot rate on that date was $1.226 CAN/USD and the one-year forward exchange rate was approximately $1.23 CAN/USD. The one-year forward exchange rate as at November 15, 2004 was $1.205 CAN/USD.





- 8 -

5.0 Reference: TGVI Advance Information for the 2004 Annual Review Allocation of Cost of Service and Allocation Factors Table 6.1, Page 6.1 and Appendix A, Schedule 2

Preamble: The cost of service is not subdivided between the HPTS and CDS.

Request: (a) In its presentation of information for the 2004 Annual Review, how has TGVI

attempted to show the separation of records for the HPTS and the CDS in accordance with Section 4.5 of the Special Direction?

Response Please see response to IR 5.0 (b) below. (b) Using the line items in Appendix A, Schedule 2, for each year please provide a

subdivision of lines 1 to 20 showing the costs allocated to the HPTS and to the CDS. The aggregate of costs allocated to the HPTS should equal the total cost of service for that function.

Response Please see the 2005 Forecast COSA Results table below.





- 9 -

Total Other HPTS CDS 1 Gross O&M Expenses 32,622,000 10,612,096 9,856,618 12,153,286 2 O&M Capitalization (4,626,815) (417,829) (1,278,351) (2,930,635)3 Direct Charges & Allocations to Affiliates (224,700) (70,797) (68,707) (85,195)4 B.C. Gas Wheeling Charge 4,388,976 0 4,388,976 0 5 Lease Payments for Equip. & System Asset 2,153,923 0 2,153,923 0 6 Depreciation 15,492,442 1,251 7,450,647 8,040,545 7 Reamortization/(Amortization) - CIAC 701,232 0 701,232 0 8 Municipal Taxes 6,355,073 1,163,176 2,434,060 2,757,838 9 Amortization of Deferreds 0 0 0

Financing Costs 204,175 102 96,439 107,634 Unamortized Manufactured Gas Plant 354,261 354,261 0 0 NGV Conversion Expense 0 0 0 0 Generic Utility Systems Extension Hearing Costs 0 0 0 PCEC Start Up Costs 43,900 0 43,900 0 Integrated Resource Plan Expenses 0 0 0 Customer Grants and Incentives 151,515 151,515 0 0 CIS Implementation 115,799 115,799 0 0 2000-2002 Regulatory Expenses 0 0 0 Gas Cost Variance Account 1,976,201 1,976,201 0 0 Cost Allocation & Rate Design 241,747 149 113,674 127,925 Incremental CIS Operating Costs 0 0 0 Texada Compressor Operating Costs 46,071 0 46,071 0 ICP Cogen Project Commissioning 0 0 0 0 T-Service for ICP 0 0 0 0 Insurance Variance 75,941 75,941 0 0 Pension Expense (515,973) (515,973) 0 0 Regulatory Expense 2003-2005 65,617 40 30,854 34,722 Compressor Fired Hours 10 Large Corporations Tax 925,780 23,564 425,417 476,799 11 British Columbia Capital Tax 0 0 0 0 12 Motor Fuel Tax 568,614 568,614 0 0 13 Provincial Sales Tax on Meter Station Fuel 94,163 94,163 0 0 14 Proposed Return on Rate Base 32,437,977 943,642 12,320,468 19,173,866 15 Less Special Direction Provision (1,867,000) 0 (1,867,000) 0 16 Equity Portion of AFUDC 0 0 0 17 Income Tax Expense 8,137,568 3,600,701 2,602,356 1,934,511 18 Cost of Service 99,918,486 18,676,615 39,450,577 41,791,294 19 Cost of Sales 102,740,107 102,740,107 0 0 20 Total Revenue Requirement 202,658,593 121,416,722 39,450,577 41,791,294





- 10 -

(c) Using the results from (b) above, please provide a brief explanation of the annual

change in costs by line number for the HPTS. Response All of the items represent normal, negotiated, or formulaic changes with the exception of the Cost of Sales (gas costs). The gas cost forecast included in the 2004 annual review for 2005 shows a significant increase over 2004. (d) Using the results of (b) above, please show the allocation of HPTS costs for the

CDS, BC Hydro, the VIGJV and Terasen Gas Squamish, including any costs allocated directly to individual shippers.

Response Please refer to Appendix B. (e) With respect to (d) above please provide the details of the allocation factors,

showing the CDS peak demand before peaking arrangements, peaking arrangements, CDS secondary peak, and the Contract Demands for each other HPTS shipper. Please provide this information through 2015 as shown in TGVI’s response to BC Hydro IR 1 from the 2003 Annual Review.

Response Due to the current uncertainty of firm requirements and the varied results that are possible it would not be meaningful to provide any results. Once firm requirements are known, TGVI would be in a position to provide a meaningful response to this question. (f) For each year, please subdivide Line 21 of Appendix A, Schedule 2 into sales

revenue, T-service revenue for firm service and T-service revenue by rate level for interruptible service.

Response Sales $147,600,403 T-Service $ 22,473,971 No interruptible revenue is included.





- 11 -

(g) Please provide a table showing the minimum daily and annual on-system peaking gas requirements for the 2004/05 and 2005/06 winters assuming the full capacity of the HPTS is used on the design peak day and the Amending Agreement for the VIGJV is implemented. In preparing this table, include identification of load among shippers and if the system capacity is not 155 TJ/d, please fully explain why.

Response Please see response to (e) above. (h) Using the results of (g) above, please provide a table showing the cost allocation

for each HPTS shipper for 2005. Response Please refer to the response to MEM IR 17.1, which provides allocated cost data by HPTS shipper.





- 12 -

6.0 Reference: TGVI Advance Information for the 2004 Annual Review Amortization of GCVA Page 6.6

Preamble: TGVI indicates that the 2004 GCVA deficit amount of $2.0 million (after

tax) would be amortized into cost of service for 2005 and that the amortization has not been allocated to Transportation Customers.

Request: (a) How will TGVI track the recovery of the GCVA included in the revenue

requirement to ensure it is recovered from core customers and that any under recovery is not added to the RDDA? Please fully explain.

Response TGVI will not track the recovery of the GCVA component included in the revenue requirement. Actual consumption versus forecast consumption by core customers may result in an insignificant over or under recovery of the GCVA amount which would ultimately form part of the Annual Revenue Surplus/Deficit. This treatment of the year end GCVA imbalance is consistent with the amortization of the 2003 GCVA surplus into cost of service for 2004. Further, past practice, prior to the establishment of the GCVA in 2003, meant that gas cost variances flowed directly to the RDDA.





- 13 -

7.0 Reference: TGVI Advance Information for the 2004 Annual Review Sales Revenue Page 6.6

“For 2005, TGVI is proposing that for core rate classes whose current rates are at or above their cost of service and below their cap, or who are at their cap, rates will be held at current levels.”

Request: (a) Please explain the rationale for proposing that the rates of core rate classes

whose current rates are at or above their cost of service but below their cap be held at current levels when TGVI has already established a precedent of setting rates in excess of cost of service recovery.

Response This statement is no longer necessarily valid. Please see updated revenue to cost results provided in response to MEM IR 17.1. (b) Please provide a table that shows the difference by rate class in unit rates and

total annual revenue for 2005 comparing TGVI’s proposed rates for 2005 with those that would result from using TGVI’s proposed, and accepted, discounts from competitive fuels set out in Section 5, Rate Proposal of the 2003/05 Rate Design Application dated September 20, 2002.

Response Please see tables below.





- 14 -

TOTAL Firm

Transportation VIGJV Squamish

Gas Total

Distribution Present Rates Effective Unit Rate $1.122 $0.895 $1.050 $12.558 Revenues from Present Rates $170,074,374 $15,561,686 $6,533,500 $378,785 $147,600,403 Revenue to Cost Ratio 125% 106% 27% 98%

Total Distribution RGS AGS SC1 SC2 LC1 LC2 LC3 HLF ILF

$12.558 $15.286 $10.507 $17.200 $14.473 $11.666 $10.283 $9.944 $9.233 $7.585

$147,600,403 $67,398,120 $11,023,308 $4,546,610 $7,798,767 $15,268,194 $13,739,971 $24,610,633 $2,183,605 $1,031,196

98% 91% 105% 101% 109% 105% 103% 105% 125% 129% These rates are consistent with the approved rate design principles of TGVI and take in to account competitive fuel price alternatives and their respective discounts as approved





- 15 -

8.0 Reference: TGVI Advance Information for the 2004 Annual Review Sales Gas Forecast Table 6.4, Page 6.7 and first table of Appendix C

Preamble: Reconciliation of forecasts.

Request:

(a) Table 6.4 shows total forecast sales for 2005 of 11,964.8 TJ. The first table in

Appendix C shows total sales for 2005 of 11,740,098 GJ. Please reconcile the difference and provide revised tables as necessary.

Response Please see IR submission cover letter and/or MEM IR 17.1 for the correct values.





- 16 -

9.0 Reference: TGVI Advance Information for the 2004 Annual Review Contributions, Page 6.9

Preamble: TGVI states that it is forecasting repayment of Federal/Provincial

contributions. TGVI further states the potential repayment is partially dependent on refinancing with an investment-grade debt rating, which itself depends on the demand for transportation capacity to serve gas-fired generation.

Request: (a) Please describe the level of demand and term for transportation capacity

associated with gas-fired generation that will provide an investment-grade rating.

Response Obtaining an investment-grade credit rating is dependent on a variety of factors that are considered by credit rating agencies. Financial strength is a consideration, and although TGVI’s deemed capital structure supporting rate base is somewhat more leveraged than other Canadian gas distribution utilities, the primary focus for credit rating agencies will be the RDDA, the likelihood that it will be recovered prior to the expiry of the royalty revenue contributions in 2012, and the ability of TGVI to competitively recover its revenue requirement after the expiry of the royalty revenue contributions. This assessment will depend on a variety of business factors such as competitiveness with alternative energy sources, exposure to large-volume customers and the regulatory environment. Based on TGVI’s present circumstances absent additional gas-fired generation load, it is uncertain whether TGVI could obtain an investment-grade credit rating. Additional transportation demand associated with the Duke Point Power Project announced by BC Hydro on November 3, 2004 would likely provide credit rating agencies with sufficient confidence in the likely recovery of the RDDA and the ongoing ability of TGVI to recover its revenue requirement after 2011 to assign an investment-grade credit rating, provided that a long-term contract with BC Hydro is in place to support gas-fired generation load. It is impossible to say with precision how long the credit rating agencies would expect a long-term contract to be in place, but it is likely that they would expect such a contract to be in place for at least five to ten years after the expiry of the royalty revenues in 2012.





- 17 -

(b) Is it TGVI’s position that only demand for gas-fired generation affects an investment-grade rating? If so, please fully explain. If not, please identify and discuss any other factors that influence an investment-grade rating.

Response Please refer to the response to IR 9(a). (c) Does the proposed de-contracting of firm capacity by the VIGJV affect an

investment grade rating? Please fully explain.

Response The existing contract with the VIGJV could have been terminated by the joint venture at the end of 2005, and any renewal would have been for a further five years to 2010. Therefore, the “de-contracting” by the VIGJV applies only to 2005 volumes. The proposed contract renewal with the VIGJV provides for a seven-year extension to 2012, and reduces uncertainty as to the VIGJV’s intentions, both factors that would positively affect a credit rating agency’s assessment of TGVI. In addition, the proposed reduction in revenues in 2005 is more than offset by the additional revenues that are expected to arise from incremental transportation demand from the Duke Point Power Project. (d) Has TGVI included the cost of $3.8 million for repayment of the government’s

contribution in 2005? If so, please provide or reference a table showing how it was included.

Response Please refer to the 2004 Annual Review submission, Section 9, Tab A, Schedule 7, line 2.





- 18 -

10.0 Reference: TGVI Advance Information for the 2004 Annual Review VIGJV Section 7.1.1.1. – Pages 7.2 to 7.4

Preamble: TGVI describes the proposed Amending Agreement with the VIGJV. Request: (a) TGVI states that the VIGJV had the option to terminate the JV TSA at the end of

2005. Please describe what transportation services would have been offered to the VIGJV had it terminated the JV TSA. Please describe the toll or toll design for each such service; for example, would firm service have been offered at the firm transportation toll?

Response The VIGJV and TGVI have entered into an agreement to amend and extend the existing JV TSA. TGVI does not wish to speculate on the discussions that may have occurred under this hypothetical situation. (b) Please confirm that the proposed IT tolls for the VIGJV under the Amending

Agreement at all times during 2005 will be less than the IT tolls for BC Hydro. Response The firm and interruptible rates included in the Amending Agreement are based on the rates that are in the JV TSA. The firm rates have not changed. The Interruptible rate has been expanded to include 3 tiers. The Tier 1 IT rate is set at the same as the Firm rate, the Tier 3 IT rate is 110% of the Firm rate and the Tier 2 rate is the same as the IT rate set out in the JV TSA. The Interruptible rate proposed for BC Hydro in 2005 was determined consistent with rate design principles approved by the Commission in its 2003 rate design decision. The Interruptible rates paid by the VIGJV under the current JV TSA and the Amending Agreement, are lower than the Interruptible rates paid by BC Hydro in 2004 and those proposed for BC Hydro in 2005.





- 19 -

(c) Please confirm that under the proposed IT tolls in the Amending Agreement for 2005, the VIGJV will pay $0.895/GJ for the first tranche of service, $0.69 for the second tranche and $0.985 for the third tranche. If these are not correct, please provide the correct values.

Response Confirmed.

(d) Please fully explain the rationale for the variance in proposed IT toll levels.

Response The tiered structure of the Interruptible rates was agreed to as a means to ensure that the VIGJV was contracting for the required level of Contract Demand to meet their operating requirements, and that Firm demand is not met through the use of Interruptible service.

(e) Please fully explain the rationale for not using the IT tolls associated with

transportation service, which TGVI forecasts will be $1.177 per GJ in summer and $1.703 per GJ in winter, and in particular, the rationale for not using the annual system load factor to establish a variance in proposed IT tolls for the VIGJV.

Response The rates that the VIGJV and TGVI have agreed to in the Amending Agreement are consistent with the rates set out in the existing JV TSA.

(f) Please confirm that the IT tolls proposed for the VIGJV in the Amending Agreement are not seasonal; that is, they do not vary by season.

Response Confirmed.





- 20 -

(g) Is TGVI prepared to propose that IT service be allocated on the basis of maximizing revenue or will it continue to allocate IT service on the basis of nominations? If the latter, please explain fully why the VIGJV should be relieved of much of its firm transportation costs and all of its peaking requirements, but still retain economically preferential access to IT service.

Response TGVI would continue to allocate Interruptible service based on matching up service requests with available capacity on the system for the each Day, consistent with the terms of the Tariff. TGVI is not proposing changes to the Terms and Conditions in the Tariff. (h) Considering the historical gas use of the VIGJV and the proposed reduction in

Contract Demand, does TGVI still consider it prudent to completely exclude IT revenue from its forecast? If so, please support the rationale. Under what conditions would TGVI consider it prudent to include IT revenue?

Response Please refer to response to Commission IR 13.3. (i) Is the proposed right to reduce Contract Demand by up to 4.5 TJ/d beginning in

2007 an annual right or is it a one-time right? Please fully explain. Response Under this right the VIGJV can reduce demand by an aggregate amount of 4.5 TJ. This aggregate 4.5 TJ reduction could be accomplished in 1 year or over 3 years, for example. Contract demand cannot be reduced below 8 TJ (ie 12.5 TJ less 4.5 TJ) with the exception of the final two years of this extended agreement if there is an expansion project.

(j) Please fully explain the proposed right to reduce the Contract Demand of the

VIGJV in response to a system expansion in 2011 or 2012. Response The right to reduce Contract Demand as a result of Expansion projects will remain in the Amending Agreement, but will be suspended for any expansion Projects that, when announced, are projected to have in-service dates prior to November 1, 2010. For





- 21 -

clarity, this means that the VIGJV will not be able to reduce its Contract demand for any Expansion Projects put in service prior to November 1, 2010.

(k) At line 28, page 7.3, TGVI states: “The VIGJV may request reinstatement of

contract demand once reduced up to 12 TJ/d.” Please fully explain what is meant by this sentence.

Response In the event that the VIGJV has reduced its contract demand below 12 TJ per day, it can request that the Contract Demand be increased back to 12 TJ per day on a permanent basis if capacity is available. Additionally the VIGJV can request Contract Demand to be increased greater than 12 TJ per day on an annual renewable basis, effective November 1 of each year, subject to capacity availability. For clarity, nothing in this amendment would compel TGVI to add facilities to meet the VIGJV request for reinstatement of Contract Demand.





- 22 -

11.0 Reference: Joint Venture Transportation Service Agreement TGVI Advance Information for the 2004 Annual Review Pages 3.2 and 7.2

“In October 2004, Vancouver Island Gas Joint Ventures (“VIGJV”) and TGVI entered into an Amending Agreement to the JV TSA and the JV PGMA, subject to approval, to be effective January 1, 2005 (the “Amending Agreement”). TGVI states that the Amending Agreement is described in more detail under section 7 of this submission and the terms of which have been included in the determination of the 2005 Revenue Requirements and Rate Proposal” (page 3.2). “Under the JV TSA, the VIGJV has the option of terminating the agreement at the end of 2005. The VIGJV has the right to extend the JV TSA for five years with notice by December 31, 2004”. (page 7.2)

Request: (a) Please produce a copy of the Amending Agreement. Response Please refer to response to BCUC IR 13.1. (b) Please describe all necessary approvals and the party or parties that must grant

such approvals. Response Please refer to response to BCUC IR 28.1.

(c) Please provide TGVI’s present expectation of the processes and timing of those

processes to obtain each approval necessary. Response Please refer to response to BCUC IR 28.1.





- 23 -

(d) Did the VIGJV advise TGVI of its intent to terminate the JV TSA? If so, when? Response The VIGJV advised TGVI that it was considering all its options, which TGVI understood to include termination of the JV TSA.

(e) Did the VIGJV give notice of its intent to extend the JV TSA for five years? If so,

when? Response If the Amending Agreement is approved then the contractual arrangements are extended to 2012, and there is not a requirement for a notice.

(f) Please provide any documentation relating to the intent to terminate or extend. Response Please refer to response to IR 11 (d) and 11 (e). (g) If VIGJV has not given notice of its intent to extend the JV TSA, has TGVI

received any information that the VIGJV intends to extend the current JV TSA for five years and to give notice to TGVI by December 31, 2004? If so, provide such information.

Response Please refer to response to IR 11 (d). (h) As the Special Direction provides a regulating framework under which the TGVI

must operate, what is the authority upon which the TGVI relies in purporting to amend and extend the JV TSA beyond the original term of the JV TSA?

Response Please refer to response to BCUC IR 28.1.





- 24 -

12.0 Reference: Joint Venture Transportation Service Agreement TGVI Advance Information for the 2004 Annual Review Page 7.2

“The contract allows a reduction in Contract Demand of up to 3 TJ/d with six months notice and down to 30 TJ/d with twelve months notice. It gives the VIGJV the right to turn back capacity in response, and coincidence with, a TGVI system expansion.”

Request: (a) What section or sections of the JV TSA does TGVI refer to in stating that the

contract allows a reduction in Contract Demand of up to 3 TJ/d with six months notice?

Response Section 3.06 of the JV TSA. (b) Has the VIGJV given TGVI a six month notice of a reduction in Contract Demand

of up to 3 TJ/d? Response No. (c) If so, when was the six months notice given? Response Not applicable. Please refer to response to IR 12 (b). (d) If so, what was the extent of the Contract Demand reduction under the notice? Response Not applicable. Please refer to response to IR 12 (b).





- 25 -

(e) If the six month notice was given, please provide a copy. Response Not applicable. Please refer to response to IR 12 (b).

(f) Has VIGJV given TGVI a twelve month notice of a reduction in the Contract

Demand? Response No.

(g) If so, when was the twelve month notice given? Response Not applicable. Please refer to response to IR 12 (f). (h) If so, what was the extent of the Contract Demand reduction under the twelve

month notice. Response Not applicable. Please refer to response to IR 12 (f). (i) If the twelve month notice was given, please provide a copy. Response Not applicable. Please refer to response to IR 12 (f). (j) In permitting the VIGJV to reduce its Contract Demand in the Amending

Agreement, is TGVI purporting to rely upon a particular section or sections in the JV TSA permitting the reduction?

Response

The VIGJV could have allowed the TV TSA to expire thereby reducing the Contract Demand to zero, and subsequently negotiate a new Contract Demand and agreement.





- 26 -

(k) If so, specify the section or sections in the JV TSA relied upon. Response Not applicable. Please refer to response to IR 12 (j).





- 27 -

13.0 Reference: Joint Venture Transportation Service Agreement TGVI Advance Information for the 2004 Annual Review Page 7.2 “[The JV TSA] gives the VIGJV the right to turn back capacity in response, and coincident with, a TGVI system expansion.”

Request:

(a) Has the VIGJV turned back capacity in response, and coincident with, a TGVI

system expansion? Response No.

(b) If so, when did this occur? Response Not applicable. Please refer to response to IR 13 (a). (c) Provide details including the amount of capacity turn back. Response Not applicable. Please refer to response to IR 13 (a). (d) Please produce any documentation with respect to the turn back in capacity. Response Not applicable. Please refer to response to IR 13 (a).





- 28 -

(e) If such a turn back in capacity has not occurred, has the VIGJV advised TGVI that it intends to turn back capacity?

Response TGVI has not served notice on the VIGJV under Section 3.08 of the JV TSA that it proposes to proceed with an Expansion project. As a result the VIGJV is not in a position to give notice to TGVI. (f) If so, provide details and a copy of any documents evidencing such intent. Response Not applicable. Please refer to response to IR 13 (e).





- 29 -

14.0 Reference: Joint Venture Transportation Service Agreement TGVI Advance Information for the 2004 Annual Review Pages 7.2 and 7.3

“TGVI is currently unable to meet peak demands on its system without having to rely upon curtailment rights with both BC Hydro and VIGJV. To address the requirement for increased system capacity, TGVI has filed an application for a CPCN related to the construction and operation of an LNG storage facility on Vancouver Island

As a result of the factors described under the previous section, TGVI entered discussions with VIGJV with the goal of negotiating a long term agreement. The Amending Agreement is the result of those negotiations.”

Request: (a) Has the VIGJV advised TGVI of any position it intends to take with respect to the

TGVI CPCN application? If so, please provide details. Response TGVI is aware that the VIGJV has registered as an Intervenor in the LNG CPCN proceeding. The VIGJV has indicated it will not be opposing the LNG CPCN Application proceeding.

(b) Does anything in the Amending Agreement assist TGVI in being able to better

meet peak demands on the system? If so, explain fully. Response To the extent that the Amending Agreement results in a reduction of the VIGJV’s net demand (i.e. Contract Demand less Peaking Gas), it reduces the need for facilities required to meet future system loads.

(c) What compensation has TGVI received for providing the VIGJV the right to

reduce its firm service commitment? Response TGVI has not received monetary compensation from the VIGJV as a result of entering into the Amending Agreement. The Amending Agreement evidences compensation that is passing between the parties.





- 30 -

(d) What compensation has TGVI received for providing the VIGJV the future right to unilaterally reduce its firm service by an additional 4.5 TJ/day?

Response Please refer to the response to IR 14 (c).

(e) What compensation has TGVI received for releasing the VIGJV from the

obligations to provide peaking under the PGMA? Response Please refer to the response to IR 14 (c). (f) How will this compensation in (d) to (f), if any, be dealt with in terms of rates or

tolls to other customers? Response Not applicable. Please refer to responses to IR 14 (d) to (f).





- 31 -

15.0 References: Joint Venture Transportation Service Agreement TGVI Advance Information for the 2004 Annual Review Page 7.3 “Contract Demand: 20 TJ/d for 2005 and 12.5 TJ/d for 2006 on Toll: Firm-Current Firm Demand Formula escalating at ½ CPI Interruptible: Three Tier Formula Firm Rate – IT between CD quantity and 20 TJ/d Current IT rate – Quantities of gas between 20 TJ/d and 30 TJ/d 1.1 X Firm rate – Quantities of gas in excess of 30 TJ/d”

S. 3.6 OF THE SPECIAL DIRECTION:

“3.6. The BCUC shall not amend, change, alter or vary the transportation service agreement referred to in Section 3.2 (the “JV TSA”) or the General Terms and Conditions referred to in Section 3.5, if such amendment, change, alteration, or variation would have the effect of either:

(a) varying the transportation tolls or other amounts payable to PCEC for the services provided to the Joint Venture pursuant to that Transportation Service Agreement; or

(b) increasing or decreasing the Contract Demand for Firm Transportation Service determined in accordance with that Transportation Service Agreement, or the quantities of Interruptible Offset Gas which the Joint Venture is entitled to receive pursuant to that Transportation Service Agreement.”

Request:

(a) As section 3.6 of the Special Direction prohibits the BCUC from either:

(i) amending, changing, altering or varying the JV TSA with the effect of

varying the transportation tolls; or

(ii) decreasing the Contract Demand for Firm Transportation Service determined in accordance with the JV TSA,

on what authority will TGVI rely to approve the proposed IT tolls and the reduction of the Contract Demand of the VIGJV?






- 32 -

(b) Do TGVI and VIGJV rely upon any Contract Demand reduction provisions within the VIGJV TSA for this reduction of the Contract Demand?

Response Please refer to response to IR 12 (j). (c) If so, which provision or provisions? Response Not applicable. Please refer to response to IR 15(b). (d) If so, has the VIGJV given notice to the TGVI of its intention to rely upon any

particular provision or provisions for any such reduction? Response Not applicable. Please refer to response to IR 15(b). (e) If so, provide details. Response Not applicable. Please refer to response to IR 15(b). (f) If so, please provide a copy of any documentation evidencing such intention. Response Not applicable. Please refer to response to IR 15(b).





- 33 -

16.0 Reference: Joint Venture Transportation Service Agreement TGVI Advance Information for the 2004 Annual Review Page 7.3

“Contract Demand Reductions

• Right to reduce contract demand by up to 4.5 TJ/d with 12 months notice beginning in 2007.

• Right to reduce contract demand in response to a system expansion in the last two years of the contract (2011, 2012)”

Request:

(a) What authority does TGVI rely upon for the right to reduce Contract Demand by up to 4.5 TJ/day with twelve months notice beginning in 2007?

Response Please refer to response to BCUC IR 28.1. (b) How was the 4.5 TJ/day determined? Response It is TGVI’s understanding that the VIGJV’s long term Firm requirements are for a Contract Demand of 12.5 TJ per day. The VIGJV have indicated that with potential further investment they may be able to reduce their Firm requirements to 8 TJ per day.

(c) Has the VIGJV indicated its intention to reduce Contract Demand by up to 4.5

TJ/day pursuant to that provision? Response Please refer to response to IR 16 (a).

(d) If so, provide details. Response Not applicable. Please refer to response to IR 16 (a).





- 34 -

(e) If so, please provide a copy of any documentation evidencing such intention. Response Not applicable. Please refer to response to IR 16(a).





- 35 -

17.0 Reference: TGVI Advance Information for the 2004 Annual Review Special Direction – Section 3.6 (quoted in I.R. No. 20.0 above) Pages 7.2 to 7.4

Preamble: Pages 7.2 to 7.4 provide details of the Amending Agreement between TGVI and the VIGJV for the JV TSA and JV PGMA. Depending on the nature of the amendments, section 3.6 of the Special Direction prohibits the BCUC from making certain changes to the JV TSA. It appears that some of the proposed amendments may have extended beyond the jurisdiction of the BCUC.

Request:

(a) Has TGVI, or the VIGJV to the knowledge of TGVI, sought approval from the Province of British Columbia to amend the Special Direction?

Response The VIGJV and TGVI are currently in discussions with representatives of the Provincial Government regarding the Special Direction, and the terms included in the Amending Agreement.

(b) If so, please provide the amendments that have been sought. Response TGVI and the VIGJV are seeking a Special Direction that provides for approval of the Amending Agreement.

(c) If amendments to the Special Direction have been sought, have they been

approved? Response As of November 15, 2004 approval has not been given. (d) If so, please provide a copy of the approved amendments. Response Not applicable. Please refer to response to IR 17 (c).





- 36 -

18.0 Reference: TGVI Advance Information for the 2004 Annual Review Page 7.2 “The VIGJV and TGVI have entered into an Amending Agreement, subject to approval as necessary, for the JV TSA and JV PGMA that terminate at the end of 2012.”

Request:

(a) What contingency plan does TGVI have in the event that the Amending Agreement is not approved? Please provide a full explanation.


(b) In the event that approval of the Amending Agreement was denied, please

provide tables for 2005 showing the revised HPTS cost allocation factors and the information provided in the first table of Appendix C of the 2004 Annual Review.

Response Please refer to response to MEM IR 20.1.

(c) In such circumstances, if in the response to (b) above, the Contract Demand of

the VIGJV is other than 37.6 TJ/day for 2005, please provide a full explanation of reasons that Contract Demand value is used.

Response Not applicable. Please refer to response to IR 18 (b).





- 37 -

19.0 Reference: TGVI Advance Information for the 2004 Annual Review Page 7.7 Appendix G

Preamble: On Page 7.7 TGVI quotes the use of an exchange rate of 1.32 CAD/USD

in determining competitive oil prices and in Appendix G TGVI uses an exchange rate of 1.26 in determining gas costs for 2005.

Request: (a) Please reconcile the use of two different exchange rates. Response The exchange rate quoted on page 7.7 and used in the Competitive Market Position analysis is the exchange rate based on the 50th percentile of the Bank of Canada noon daily average exchange rate during the period November 2003 to October 2004. The exchange rate used in Appendix G is a forward exchange rate and is used in estimating the forecast gas costs for the remainder of 2004 and calendar 2005. Note that the exchange rate line item on the gas attachment in Appendix G should read 1.23 CAN/USD, not 1.26 CAN/USD. Due to an oversight, this line item was not updated but the correct exchange rate was used in calculating the prices shown on this schedule. TGVI has recalculated the cost of gas budget based on the November 15th, 2004 forward strip and used a 1.205 Can / USD exchange rate. Please refer to the response to BCUC IR 29.5. Additionally, the competitive market position analysis was revised based on the lower exchange rate and more recent future oil prices. Please refer to response to ROMA IR 3 (d).

(b) What effect is the improving Canadian dollar (relative to the USD) having on

TGVI’s forecast cost of gas? Please quantify. Response All else being equal, with the Canadian dollar increasing relative to the USD from 1.23 CAD/USD to 1.205 CAD/USD the royalty adjusted gas cost is reduced by approximately Cdn$0.14/GJ.





- 38 -

(c) Is a 1.26 CAD/USD exchange rate still appropriate? If so, why? Response Please refer to response to 4 (a).





- 39 -

20.0 Reference: TGVI Advance Information for the 2004 Annual Review Depreciation Appendix A, Schedule 2

Preamble: Depreciation increases by about $1.2 million from 2004 to 2005.

Request: (a) Please provide a schedule showing details of the determinants and the

calculation of the increase in depreciation from 2004 to 2005. Response The schedule below provides the detailed depreciation computations as requested. SAP software depreciation to commence in 2005 and it accounts for $0.8 Million of the total $1.2 Million unfavorable variance.

TERASEN GAS (VANCOUVER ISLAND) INC.Depreciation Expense Schedule($ million) 2004 2004 variance

12/31/03 Additions Retirem'ts 12/31/04 2004 2005 inc / (dec)(1) (2)

ASSET CLASS:Intangible Plant $1.4 $0.0 $0.0 $1.4 -$0.1 -$0.1 $0.0Transmission - High Pressure 272.3 6.9 -0.6 278.6 -6.1 -6.2 0.1Distribution 305.3 10.9 -0.3 315.9 -6.8 -7.0 0.2General Plant 24.3 4.9 -0.5 28.7 -1.4 -2.2 0.8

Total Gas Plant $603.2 $22.7 -$1.4 $624.6 -$14.3 -$15.5 $1.2

Depreciation Exp





- 40 -

21.0 Reference: TGVI Advance Information for the 2004 Annual Review Plant Additions Appendix A, Schedule 4

Preamble: High Pressure Transmission plant and General plant details are required.

Request: (a) For each year, please provide a detailed description of the plant and costs for the

plant additions shown for High Pressure Transmission and General. Response The schedule below provides the detailed plant additions as requested.

TERASEN GAS (VANCOUVER ISLAND) INC.Fixed Assets Addition Schedule($ million)

Description 2004 2005

Transmission - High PressureTP Land Rights $0.1 $0.2TP Transmission Pipeline 4.0 6.2TP Compressor Equipment 0.7 1.2TP Meas/Reg Equipment 0.1 0.2Transmission - High Pressure $5.0 $7.7

General PlantGP (Frame) Structures $0.2 $0.2GP Computer Hardware 0.0 0.1GP Computer Software 3.9 5.6GP Office Equipment 0.1 0.2GP Vehicles 0.5 0.2GP Small Tools/Equipment 0.3 0.9General Plant $4.9 $7.1

ADDITIONS





- 41 -

(b) For each plant addition noted in (a) above for 2005, has a business case been developed to justify the expenditure? If it has, please provide the business case. If no business case has been developed, please explain why not?

Response Transmission – High Pressure Haslam River Directional Drilling Based upon a hydro-technical survey by Northwest hydraulics of the TGVI transmission system, migration and erosion at the transmission pipeline between Nanaimo and Ladysmith at the Haslam River crossing poses a risk to the pipeline. It is proposed to replace the existing transmission pipeline using horizontal directional drilling. The estimated cost of this project is approximately $1.0 million (excluding AFUDC). Relocate Coquitlam Dam Pipeline Crossing The TGVI Transmission mainline crosses the Coquitlam Dam owned by BC Hydro. BC Hydro has indicated that to comply with stricter earthquake ratings geotechnical upgrades will be required. This upgrade will require the TGVI transmission pipeline to be relocated or be bypassed. This work has been delayed since 2003 pending notification from BC Hydro. The estimated cost of this project is approximately $1.0 million (excluding AFUDC). Englishman River Directional Drilling Based upon a hydro-technical survey by Northwest hydraulics of the TGVI transmission system, migration and erosion at the transmission pipeline between Parksville and Nanaimo at the Englishman River crossing poses a risk to the pipeline. It is proposed to replace the existing transmission pipeline using horizontal directional drilling. The estimated cost of this project is approximately $1.0 million (excluding AFUDC). Population Encroachment and Pipe Replacement The pipelines of TGVI must meet codes and regulations in effect for the areas of operation and the nature of the application. Pipeline upgrades are necessary in 2005-2009 as expanding populations on Vancouver Island and the Sunshine Coast continue to encroach on the transmission mainline. The existing wall thickness of pipe in certain locations will not be permissible for road crossings under pipeline code (CSA Z662). The following areas are being addressed to ensure code compliance:





- 42 -

Nanaimo/Ladysmith This project is currently planned to be constructed in 2005. It consists of approximately 3.0 km of the TGVI transmission mainline. The estimated cost of this project is $2.8 million (excluding AFUDC). V1 Coquitlam Compressor Unit 1 Upgrade (Nox emissions) To comply with the GVRD emission reduction targets V1 Coquitlam Compressor Unit 1 requires an upgrade. The estimated cost of this project is approximately $1.0 million (excluding AFUDC). General Plant TGVI Business Integration The integration initiative transitions TGVI to the standard business processes and systems that are in place for TGI to enable common management practices and realize synergies. Capital costs for a series of systems projects totaling approximately $8.0 million (excluding AFUDC) will be incurred for to integrate to various systems at TGI The Integration initiative began in 2004 and is expected to be completed in 2005 and the business case is captured in the advance materials under Appendix J. Banner to Energy Customer Information System Conversion Currently TGVI is preparing a business case to support the conversion of TGVI customer information and billing process to the same platform used by TGI. Should the business case prove that conversion from the existing outsourced Banner CIS to the outsourced Energy CIS used by TGI is the least cost alternative; a CPCN Application will be submitted to the Commission. The current estimated cost of this conversion project is approximately $6.0 million (excluding AFUDC). The conversion would be expected to be completed in 2005.





- 43 -

22.0 Reference: TGVI Advance Information for the 2004 Annual Review Appendix A, Schedule 23

Preamble: A major variance from forecast royalty revenue occurred in 2004.

Request:

(a) How were estimates of the 2005 royalty revenues developed? Response Consistent with previous years, the royalty estimates are regularly updated utilizing a regression analysis based on the historical relationship between royalty credits and actual AECO prices, Sumas prices and exchange rates.

(b) Has the process used to develop royalty revenue estimates for 2005 remained

the same as that used when the 2004 Outlook was originally prepared? Response Yes.

(c) If not, what has changed? Response Please refer to response to question IR 22 (c)

(d) If it is the same, why has TGVI not made adjustments to the estimating process

to account for the understatement of these revenues? Response

TGVI does not believe these revenues are understated.





- 44 -

(e) At this time, what percentage of TGVI’s forecast gas requirements does it have financially hedged for the 2005 calendar year? What percentage does TGVI plan to hedge for 2005?

Response Approximately 20% of TGVI’s forecast gas requirements are financially hedged for calendar 2005. TGVI financially hedges up to approximately 30% of its forecasted gas requirements.





- 45 -

23.0 Reference: TGVI Advance Information for the 2004 Annual Review Appendix A - Schedule 24 – Line 20

Request:

(a) What services does TGVI now provide to Terasen Gas Whistler? Response The services provided by TGVI to Terasen Gas Whistler have not changed from those provided in previous years. TGI and TGVI have entered into a shared services agreement whereby the majority of general management and support functions will be provided by TGI to TGVI. Subsequently these services will be provided through TGVI to Terasen Gas Whistler, leaving the service agreement between TGVI and Terasen Gas Whistler unchanged. The services provided by TGVI to Terasen Gas Whistler were included and approved as part of a shared services survey, which was part of the 1995/1996 Application, approved by Order G-41-95.

(b) Please explain the charges of Terasen Gas Whistler in Schedule 24 at Line 20.

Response

The charges of Terasen Gas Whistler in Schedule 24 at Line 20 are the charges associated with the Shared services agreement between TGVI and TGI as described in the response to IR 23 (a). The shared services expense incorporated into the 2004 allowed amounts were based on a Shared Service Study, completed and filed by Terasen Gas (Vancouver Island) Inc. (formerly Centra Gas BC Inc.). The study was done using an objective and consistent methodology that results in a fair and reasonable allocation of its shared service costs. The survey was approved, as part of the 1995/1996 Application, by Order G-41-95. Terasen Gas Whistler has included shared service costs of $220,500 and $224,700 in the 2004 and 2005 forecast revenue requirements respectively. This amount represents the approved level of shared service costs escalated by a CPI factor.





- 46 -

24.0 Reference: TGVI Advance Information for the 2004 Annual Review Appendix G - Cost of Gas Table

Request:

(a) How were management fees and departmental costs derived and how do they

compare with previous years? Response Appendix G had been incorrectly updated with core market admin costs based on old methodologies. It has since been updated to reflect the allocation of Gas Supply Department costs as presented in Terasen Gas Inc.’s (TGI) annual review materials. In TGI's annual review, the TGVI portion of Core Administration costs amounts to $449,474 and Terasen Gas (Whistler) Inc.’s (TGW) amounts to $24,100. Since TGW's amount comes back to TGVI as a credit, the line item in Appendix G for TGVI's share is grossed up to $473,574. Gas Control costs are a separate charge item from TGI to TGVI's core costs as per agreement. Please refer to the response to BCUC IR 29.5 for a revised Cost of Gas Budget schedule which includes the above mentioned corrections and is based on the November 15, 2004 forward strip. (b) Please reconcile Appendix G charges for management fees and departmental

costs against the charges identified in Schedule B of Appendix J. Response There is no relationship between the fees shown on the Cost of Gas Budget schedule included in Appendix G, with the charges in Schedule B of Appendix J. The charges to cost of gas of approx $200K relate to providing the Gas Control function to TGVI, this amount and the agreement around this was put in place and transferred from Duke Energy when Centra Gas was sold to BC Gas Inc. During the full integration for 2004, and as part of Utilities Strategies Project, the need for a shared services agreement between TGI and TGVI was identified. Existing contracts between TGI and TGVI were considered out of scope and therefore not altered. The amounts in Schedule B of Appendix J relate to the integration of the general management and back office functions.





- 47 -

25.0 Reference: TGVI Advance Information for the 2004 Annual Review Cost of Service

Preamble: The 2004 Annual Review does not provide COSA Results, although the

2003 Annual Review did provide those results in Appendix B and in response to BCH-TGVI-3.

Request:

(a) Please provide Tables 1 to 6 of COSA results for 2005. Response Please see response to MEM IR 17.1.

Appendix A

November 17, 2004 British Columbia Utilities Commission 6th Floor - 900 Howe Street Vancouver, B.C. V6Z 2N3 Attention: Mr. R.J. Pellatt, Commission Secretary Dear Sir: RE: Terasen Gas (Vancouver Island) Inc. (“TGVI” or “the Company”)

2003 – 2005 Settlement Agreement 2004 Annual Review - November 19, 2004 Revised Materials

By BCUC Order No. G-95-04, the British Columbia Utilities Commission (“the Commission”) set November 19, 2004 as the date for the 2004 TGVI Annual Review. This is required under the Company’s 2003 – 2005 Settlement Agreement (“the Settlement”). The Settlement was approved by BCUC Order No. G-2-03 dated January 14, 2003. TGVI submitted its Advance Materials to the Commission and Interested Parties on Friday, November 5, 2004. On Friday, November 12, 2004 TGVI received Information Requests from the Commission, Ministry of Energy & Mines, British Columbia Hydro and Power Authority, BC Old Age Pensioners Organization, and the Rental Owners and Managers Association of BC. Subsequent to the filing and during preparation of the responses to the Information Requests, TGVI became aware that the allowed Return on Equity (“ROE”) for 2005, as calculated by the Commission approved mechanism is expected to change to 9.53% for TGVI. TGVI understands that the Commission will render a Decision with respect to the allowed ROE on Thursday, November 18, 2004. As a result, in the preparation of these information responses, TGVI thought it appropriate to revise the allowed ROE that it had included in the original submission, from 9.75% to 9.53%, which results in an overall reduction in revenue requirement. In addition, while TGVI was preparing the responses to the Information Requests, and in particular the request to provide detailed Cost of Service Allocation (“COSA”) results, the Company discovered a small number of incorrect items in the COSA model, which resulted in inaccurate cost allocations. This has been corrected and the result is a decrease in the costs allocated to Firm transportation customers and an increase to Distribution customers. As a result of these changes, TGVI is proposing a change to rates for Firm Transportation service, however, the rates proposed for all other rate classes remains unchanged from the original proposal of November 5, 2004. Attached to this letter are

Scott A. ThomsonVice President, Finance & Regulatory Affairs 16705 Fraser Highway Surrey, B.C. V3S 2X7 Tel: (604) 592-7784 Fax: (604) 592-7890 Email: [email protected] www.terasengas.com

- 2 -

revisions to the following Tables, which were included in the November 5, 2004 submission, reflecting the revisions noted. Specifically, the following revised tables are attached:

• Tables 1 and 8.1 Proposed 2005 Rates.

• Table 6.1 Summary of Revenue Requirements And Annual Revenue Deficiency/ (Surplus) 2003/2005 Application vs. Forecast ($000’s)

• Table 6.2 Summary of Revenue Deficiency Deferral Account 2003/2005 Application vs. Forecast ($000’s)

• Table 6.3 Summary of Mid-Year Rate Base 2003/2005 Application vs. Forecast ($000’s).

• Appendix C Revenue Proof. The information responses to the Information Requests noted above have been completed based on the revisions made to the COSA and the ROE. These information requests will be submitted under separate transmittal letters in order to minimize file size. TGVI respectfully requests that the rates as set out in the revised Table 8.1 as attached, be approved effective, January 1, 2005. Enclosed are twenty (20) copies of the advance information for the 2004 Annual Review. This includes information on financial projections and forecasts necessary for achieving the annual review objectives. TGVI will present information at the Annual Review on the matters addressed in the advance materials. We trust the enclosed is satisfactory. Yours very truly, TERASEN GAS (VANCOUVER ISLAND) INC. Original signed by: Scott A. Thomson cc: 2003 – 2005 NSP Participants

2004 Annual Review Registered Intervenors

Table 1

Proposed 2005 Rates Revision Dated: November 17, 2004

Change

FMCCommodity

ChargeDemand Charge

Effective Unit Price

Proposed 2004 R/C

Proposed 2005 R/C

RGS $10.50 13.220 15.286 0.0% 0.95 0.91 AGS $40.00 10.170 10.507 10.5% 1.07 1.05 SCS-1 $9.45 15.459 17.200 6.7% 1.06 1.01 SCS-2 $33.53 13.192 14.473 0.0% 1.22 1.09 LCS-1 $61.00 10.844 11.666 9.2% 1.07 1.05 LCS-2 $97.82 9.798 10.283 1.6% 1.15 1.03 LCS-3 $201.51 9.809 9.944 3.9% 1.16 1.05 HLF $250.00 6.601 47.18 9.233 0.0% 1.60 1.25 ILF $250.00 7.386 7.585 0.0% 1.88 1.29

FT 1.122 1.122 10.3%Summer IT 1.122 1.122 10.3%Winter IT 1.626 1.626 17.0%R/C = Revenue to Cost Ratio

2005 Rates

Table 8.1

Proposed 2005 Rates Revision Dated: November 17, 2004

Change

FMCCommodity

ChargeDemand Charge

Effective Unit Price

Proposed 2004 R/C

Proposed 2005 R/C

RGS $10.50 13.220 15.286 0.0% 0.95 0.91 AGS $40.00 10.170 10.507 10.5% 1.07 1.05 SCS-1 $9.45 15.459 17.200 6.7% 1.06 1.01 SCS-2 $33.53 13.192 14.473 0.0% 1.22 1.09 LCS-1 $61.00 10.844 11.666 9.2% 1.07 1.05 LCS-2 $97.82 9.798 10.283 1.6% 1.15 1.03 LCS-3 $201.51 9.809 9.944 3.9% 1.16 1.05 HLF $250.00 6.601 47.18 9.233 0.0% 1.60 1.25 ILF $250.00 7.386 7.585 0.0% 1.88 1.29

FT 1.122 1.122 10.3%Summer IT 1.122 1.122 10.3%Winter IT 1.626 1.626 17.0%R/C = Revenue to Cost Ratio

2005 Rates

Table 6.1

Summary of Revenue Requirements and Annual Revenue Deficiency/ (Surplus) 2003/2005 Application vs. Forecast ($000’s)

Revision Dated: November 17, 2004

Revenue Requirement

2005 2003/2005

Application

2005 Forecast

Variance

Royalty Adjusted Cost of Gas $51,681 $57,250 $5,569Net OM&A (Adj for Sooke) 27,122 27,771 649 Depreciation 14,789 15,492 703Municipal and Other Taxes 9,443 7,944 (1,499)Income Tax 13,442 8,136 (5,306)Wheeling Charges 4,297 4,389 92 Return on Rate Base 28,963 30,571 1,608Amortization of GCVA - 1,976 1,976Other 3,452 3,641 189Total Revenue Requirement $153,189 $157,170 $3,981

Revenues

Sales Revenue $140,578 $147,600 $7,022Transportation Revenue 22,402 22,894 492Other Revenue 470 389 (81)Total Revenue $163,450 $170,883 $7,433

Annual Revenue Deficiency/(Surplus) $(10,261)

$(13,713) $(3,452)

Table 6.2 Summary of Revenue Deficiency Deferral Account

2003/2005 Application vs. Forecast ($000’s) Revision Dated: November 17, 2004

Calculation of RDDA

2005 2003/2005

Application

2005 Forecast

Variance

Opening Balance $81,878 $60,025 ($21,853) Current Year Def/(Surplus) (9,891) (13,713) (3,822)Preferred Share Financing 4,780 - (4,780)Subordinated Debt Financing - 5,946 5,946

Closing Balance $76,767 $52,258 ($24,509)

Table 6.3 Summary of Mid-Year Rate Base

2003/2005 Application vs. Forecast ($000’s) Revision Dated: November 17, 2004

Rate Base

2005 2003/2005

Application

2005 Forecast

Variance

GPIS – Opening (Adj for Sooke) $622,876 $624,566 $1,690 GPIS – Closing (Adj for Sooke) 639,864 650,641 10,777

GPIS – Mid-Year (Adj for Sooke) 631,370 637,646 6,276 Accumulated Depreciation – Opening $(123,397) $(122,619) 778 Accumulated Depreciation – Closing (137,288) (137,161) 127

Accumulated Depreciation - Mid-Year (130,343) (129,890) 453

Allocated Common Plant – Mid-Year (104) (235) (131) Contributions – Mid-Year (66,964) (67,378) (414) Working Capital – Mid-Year 16,264 15,772 (492)

Total Mid-Year Rate Base $450,223 $455,915 $5,692

Appendix C Revenue Proof

Revision Dated: November 17, 2004

Rate Class Volume GJProposed Revenues

Effective Rate

Allocated Cost of Service

Surplus / (Deficiency) R/C

Advance Material R/C 2004 R/C

RGS 4,409,140 $67,398,120 $15.286 $74,074,778 -$6,676,659 0.91 0.91 0.95AGS 1,049,139 $11,023,308 $10.507 $10,544,550 $478,758 1.05 1.00 1.07SCS1 264,338 $4,546,610 $17.200 $4,491,887 $54,724 1.01 0.96 1.06SCS2 538,849 $7,798,767 $14.473 $7,141,143 $657,624 1.09 1.04 1.22LCS1 1,308,777 $15,268,194 $11.666 $14,525,229 $742,965 1.05 1.00 1.07LCS2 1,336,183 $13,739,971 $10.283 $13,346,017 $393,954 1.03 1.00 1.15LCS3 2,474,923 $24,610,633 $9.944 $23,380,948 $1,229,685 1.05 1.00 1.16HLF 236,500 $2,183,605 $9.233 $1,745,060 $438,545 1.25 1.35 1.6ILF 135,952 $1,031,196 $7.585 $801,914 $229,282 1.29 1.23 1.88

Total Core 11,753,802 147,600,403 $12.558 $150,051,526 -$2,451,122 0.98

BC Hydro 13,870,000 $15,561,686 1.122 $12,449,349 $3,112,337 1.25Other Trans 7,300,000 $6,533,500 0.895 $6,175,856 $357,644 1.06Squamish 360,748 $378,785 1.050 $1,397,644 -$1,018,859 0.27

Firm Service 21,530,748 $22,473,971 $20,022,849 $2,451,122 1.12

Winter Interruptible $1.626Summer Interruptible $1.122Interuptible

Total System 33,284,550 $170,074,374 $170,074,375 -$1 1.00

Appendix B

Total Direct Assignment CDS

Firm Tranportation VIGJV

Squamish Gas

Gross Operating and Maintenance Expenses 8,125 0 8,125 0 0Operating and Maintenance Capitalization (1,351) 0 (1,351) 0 0Direct Charges and Allocations to Affiliates (72) 0 (72) 0 0B.C. Gas Wheeling Charge 0 0 0 0 0

Lease Payments for Equipment and System Asset 0 0 0 0 0

Depreciation 1,251 0 1,251 0 0

Reamortization/(Amortization) - CIAC 0 0 0 0 0

Municipal Taxes 2,580 0 2,580 0 0

Amortization of DeferredsFinancing Costs 102 0 102 0 0Unamortized Manufactured Gas Plant 0 0 0 0 0NGV Conversion Expense 0 0 0 0 0Generic Utility Systems Extension Hearing Costs 0PCEC Start Up Costs 0 0 0 0 0Intergrated Resource Plan Expenses 0Customer Grants and Incentives 0 0 0 0 0CIS Implementation 0 0 0 0 02000-2002 Regulatory Expenses 0Gas Cost Variance Account 0 0 0 0 0Cost Allocation & Rate Design 149 0 149 0 0Incremental CIS Operating Costs 0Texada Compressor Operating Costs 0 0 0 0 0ICP Cogen Project Commissioning 0 0 0 0 0T-Service for ICP 0 0 0 0 0Insurance Variance 0 0 0 0 0Pension Expense 0 0 0 0 0Regulatory Expense 2003-2005 40 0 40 0 0Compressor Fired Hours 0

Large Corporations Tax 531 0 548 (18) 0British Columbia Capital Tax 0 0 0 0 0Motor Fuel Tax 568,614 202,137 236,083 124,254 6,140Provincial Sales Tax on Meter Station Fuel 94,163 33,474 39,096 20,577 1,017

Proposed Return on Rate Base 21,344 3 22,046 (705) 0Less Special Direction Provision 0 0 0 0 0

Equity Portion of AFUDCIncome Tax Expense 19,451 6,915 8,076 4,250 210

Cost of Service 714,927 242,528 316,673 148,358 7,367

Cost of Sales 295,655 0 62,905 232,750 0Total Revenue Requirement 1,010,583 242,528 379,579 381,108 7,367

Total CDSFirm

Tranportation VIGJV Squamish Gas1 Gross Operating and Maintenance Expenses 32,622,000 28,029,486 2,785,663 1,462,458 344,3932 Operating and Maintenance Capitalization (4,626,815) (4,027,824) (363,403) (190,673) (44,915)3 Direct Charges and Allocations to Affiliates (224,700) (192,699) (19,411) (10,190) (2,400)4 B.C. Gas Wheeling Charge 4,388,976 2,330,802 1,246,959 656,539 154,677

5 Lease Payments for Equipment and System Asset 2,153,923 1,143,858 611,955 322,201 75,909

6 Depreciation 15,492,442 11,997,271 2,118,066 1,114,528 262,576

7 Reamortization/(Amortization) - CIAC 701,232 372,395 199,228 104,896 24,713

8 Municipal Taxes 6,355,073 5,051,168 801,602 413,682 88,621

9 Amortization of DeferredsFinancing Costs 204,175 158,849 27,502 14,426 3,399Unamortized Manufactured Gas Plant 354,261 354,261 0 0 0NGV Conversion Expense 0 0 0 0 0Generic Utility Systems Extension Hearing Costs 0PCEC Start Up Costs 43,900 23,313 12,473 6,567 1,547Intergrated Resource Plan Expenses 0Customer Grants and Incentives 151,515 151,515 0 0 0CIS Implementation 115,799 115,799 0 0 02000-2002 Regulatory Expenses 0Gas Cost Variance Account 1,976,201 1,976,201 0 0 0Cost Allocation & Rate Design 241,747 188,292 32,445 17,004 4,006Incremental CIS Operating Costs 0Texada Compressor Operating Costs 46,071 24,466 13,089 6,892 1,624ICP Cogen Project Commissioning 0 0 0 0 0T-Service for ICP 0 0 0 0 0Insurance Variance 75,941 75,941 0 0 0Pension Expense (515,973) (515,973) 0 0 0Regulatory Expense 2003-2005 65,617 51,108 8,806 4,615 1,087Compressor Fired Hours 0

10 Large Corporations Tax 925,780 725,722 121,435 63,629 14,99311 British Columbia Capital Tax 0 0 0 0 012 Motor Fuel Tax 568,614 202,137 236,083 124,254 6,14013 Provincial Sales Tax on Meter Station Fuel 94,163 33,474 39,096 20,577 1,017

14 Proposed Return on Rate Base 32,437,977 26,637,800 3,523,279 1,842,677 434,22115 Less Special Direction Provision (1,867,000) (991,486) (530,436) (279,281) (65,797)16 Equity Portion of AFUDC17 Income Tax Expense 8,137,568 6,906,002 746,597 393,135 91,834

018 Cost of Service 99,918,486 80,821,878 11,611,026 6,087,937 1,397,644

19 Cost of Sales 102,740,107 102,444,451 62,905 232,750 020 Total Revenue Requirement 202,658,593 1,823,927,335 202,658,593 202,658,593 202,658,593

re: terasen gas (vancouver island) inc. (“tgvi”) … · november 17, 2004 british columbia...

Documents