SOllClTORS 16W - Utilities Commission · BARRISTERS & SOllClTORS June 9,2008 ... expanding, mothballing, capital cost forecasts, etc ... Plateau Pipe Line Ltd. Information Request

B A R R I S T E R S & S O l l C l T O R S

June 9,2008

VIA E-MIL

British Columbia Utilities Commission P.O. Box 250 600 - 900 Howe Street Vancouver, BC V6Z 2N3

16W Ulthsdml Place

915 West Geargio Stmat

Voncauver, Brtlish COlumb$a

Canada V6C 3LZ

Telephone 604 685 3456

Focslmlle604 6691620

Attention: Erica M. Hamilton

Dear Sirs and Mesdames:

BCUC Project No. 3698481 Plateau Pipe Line Ltd. ('Tlateau") Application for the Approval of 2007 and 2008 Western System ToUs ("Application")

Please find enclosed the responses of Chevron Canada Limited ("Chevron") to the information requests from Plateau Pipe Line Ltd.

Please note that the writer, Keith Bergner, is out of the country until June 16. Pursuant to Commission Order P-6-08, Chevron will make submissions on June 16 on the proposed date for written argument

Yours very truly,

Keith B. Bergner

Enc (2) cc. Distribution List Project No. 3698481

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Plateau

BRITISH COLUMBIA UTILITIES COMMISSION Plateau Pipe Line Ltd.

Application for the Approval of 2007 and 2008 Western System Tolls Project No. 3698481

Plateau Pipe Line Ltd. Information Request No.1 to Chevron Canada Limited ("Chevron")

Chevron Response Issued June 9,2008

1.1 Reference:

(i) Written evidence of Gordon Engbloom and Grant Graves ("Written Evidence"), Page 9 - 11, Answer 20:

"The primary reason to discriminate among shippers' tolls provided by Plateau appears to be that it is prepared to take volume risk for Husky but not for Kamloops shippers. That is not a satisfactory reason to discriminate by focusing the whole reduction in revenue requirement on one shipper."

(ii) Plateau response to Husky Information Request No.2, question 153 (c), actual throughput for 2002 to 2006, Taylor to Kamloops and Taylor to Prince George.

(iii) 2001 Previous Decision, pages 31 to 32:

"Chevron supported a volume forecast that was close to historical volumes. It thought that a forecast of 6,600 m3ld was reasonable ..."

"The Commission determines that for calculating tolls, deemed normal forecast deliveries to Prince George of 1,600 m3ld commencing September 7, 2000 will be used. The Commission determines that for calculating tolls, relatively conservative deemed normal forecast deliveries to Kamloops of 3,900 m3ld will be used for September 7, 2000 to October 31, 2001, and 5,000 m3ld will be used commencing November 1,2001."

Request:

(a) Please confirm that the following table is correct, and if not confirmed , please explain why:

Forecast Volumes (M3ld) to Prince 1,600 1,600 1,600 1,600 1,600 George in the Previous Decision:

Actual volumes (M3ld) to Prince 1,622 1,642 1,547 1.545 1,426 George:

Forecast volumes (M3ld) to 5.000 5.000 5,000 5,000 5,000 Kamloops in the Previous Decision:

Actual volumes (M3ld) to Kamloops: 1,115 2,734 2,509 2,231 2,182

(b) Please provide a detailed description of Chevron's understanding as to why the throughputs to Kamloops from 2002 to 2006 were materially less than forecast.

(c) Please list and explain all factors that contributed to Chevron's portion of throughput from 2002- 2006 being materially less than the forecast.

(d) Please confirm that under the tolling methodology proposed by Chevron in its Written Evidence, Chevron bears no cost consequences if the volumes to Kamloops are less than forecast.

(e) Please explain why Plateau should bear the volume risk in the event that the volume shipped by Chevron and other shippers to Kamloops is less than forecast.

Response:

(a) Chevron, a shipper on the Western System, cannot confirm the volumes shipped to Prince George or Kamloops on the Western System. Chewon does not have the requested information. Please see Chevron's response to BCUC-Chewon-4.1 for information regarding the volumes shipped by Chevron on the Western System.

(b) Chevron objects to this request on the grounds that it requests Chevron to comment on matters not raised in the evidence filed by Messrs. Engbloom and Graves and is therefore outside the scope of proper Information Requests. Further, given that Chevron is not asking Plateau to assume volume risk (refer to BCUC-Chevron-14.1), questions regarding volume risk (past or prospective) presented by Chevron are not relevant.

(c) Please refer to Plateau-Chewon-l . l (b).

(d) Not confirmed. Please refer to BCUC-Chewon-14.1 and Plateau-Chevron-l.6(h).

(e) Please refer to Plateau-Chevron-l . 1 (d).





1.2 Reference:

Written Evidence, Page 9 - 11, Answer 20:


Request:

(a) Please confirm that the Western System is the only pipeline transportation option for the transmission of crude oil to Husky's Prince George refinery.

(b) Please provide a detailed explanation of the final receipt point(s) for crude oil shipped by Chevron on the Western System (i.e., please provide the locations of Chevron's refineries which are, have been, or are forecast to be supplied by crude oil shipped by Chevron on the Western System).

(c) Please provide the following information for each of the final receipt point(s) listed in response to Question 1.2(b) above:

(i) minimum and maximum inlet capacity;

(ii) the average daily consumption of crude oil for the Test Period and 2008 to date;

(iii) a forecast of the average daily consumption of crude oil for the remainder of the Test Year, 2009,2010,201 1 and 2012;

(iv) the average daily volume of crude oil shipped on the Western System for the Test Period and 2008 to date; and

(v) a forecast of the average daily volume of crude oil shipped on the Western System for the remainder of the Test Year, 2009,2010,201 1 and 2012.

(d) Please provide a detailed description of Chevron's long and short term plans, including any contingencies or issues, with respect to each of the final receipt point(s) listed in response to Question 1.2(b) above. Please further explain how Chevron's long and short term plans will impact its use of the Western System.

(e) For each of the final receipt point(s) listed in response to Question 1.2(b) above, please discuss Chewons plans, or prospects of expansion or future investment that would affect capacity or demand for crude oil. Please further explain how this will impact Chewon's use of the Western System.

(f) Please provide Chevron's 1, 2, 5, and 10 year outlook for the utilization of each of the final receipt point(s) listed in response to Question 1.2@) above.

(g) Please describe and provide a copy of any forecasts, outlooks or studies prepared by Chevron, or its consultants, for each of the final receipt point(s) listed in response to Question 1.2(b) above, including, without limiting the generality of the foregoing, a full discussion of obsolesce, refurbishing, retrofitting, expanding, mothballing, capital cost forecasts, etc.

(h) Please provide Chewon's 1,2, 5, and 10 year outlook for each market served by each of the final receipt point(s) listed in response to Question 1.2(b) above.

(i) Please summarize and provide a copy of any forecasts, outlooks or studies prepared by Chevron, or its consultants, for each market served by each of the final receipt point(s) listed in response to Question 1.2(b) above.

Response:

Preliminary Comment: Chewon objects to these requests on the grounds that they request Chewon to comment on matters not raised in the evidence filed by Messrs. Engbloom and Graves and are therefore outside the scope of proper Information Requests. Further, given that Chevron is not asking Plateau to assume volume risk (refer to BCUC-Chevron-14.1), questions regarding volume risk (past or prospective) presented by Chewon are not relevant. To the extent that any of the information requested may relate to other relevant issues, Chevron provides the following:

(a) Chevron does not own or operate Husky's Prince George refinery and does not have information on all transportation options that may be available to it. It is Chewon's understanding that the only pipeline servicing Husky's Prince George refinery is the Western System.

(b) Chevron Canada Limited owns and operates a refinery located in Bumaby, British Columbia (the Bumaby Refinery) that obtains all of its crude feedstock from the TransMountain pipeline.

(c) See response to BCUC-Chevron-4.1

(d)-(i) See Preliminary Comment above.



Plateau Pipe Line Ltd. Information Request No. 1 to Chevron Canada Limited ("Chevron")


1.3 Reference:



Request:

(a) Please provide a description of the type(s) of crude ("feedstock") used, or that could be used, for each of the final receipt point(s) listed in response to Question 1.2(b) above.

(b) Please describe and provide a map of the source(s) of each respective feedstock used for each final receipt point(s) listed in response to Question 1.3(a) above.

(c) Please explain the likelihood of Chevron changing its feedstock inputs within the next 1, 2, 5, or 10 year period for each of the final receipt point(s) listed in response to Question 1.2(b) above.

(d) For each source listed in response to Question 1.3@) above, please provide an explanation of whether Chevron owns the production or whether it is purchased fiom a third party.

(e) For all feedstock sources owned by Chevron, please provide the pool source, and for each pool, whether production has increased or decreased in recent years and the rates of decline, if any, experienced by Chevron. For each pool where the crude oil produced could be shipped on the Western System, please also provide the rate of replacement and Chevron's exploration and production plans, including capital cost investment forecasts.

(f) For each source listed in response to Question 1.3(b) above, please provide a detailed explanation of how declines in supply may affect Chevron's use of the Western System.

(g) For each of the final receipt point(s) listed in response to Question 1.2(b) above, please provide a detailed explanation of how changes regarding or in any way relating to supply sources may affect Chevron's use of the Western System.

Response:

Preliminary Comment: Chevron objects to these requests on the grounds that they request Chevron to comment on matters are not raised in the evidence filed by Messrs. Engbloom and Graves and are therefore outside the scope of proper Information Requests. Further, given that Chevron is not asking

Plateau to assume volume risk (refer to BCUC-Chevron-14.1), questions regarding volume risk (past or prospective) presented by Chevron are not relevant. To the extent that any of the information requested may relate to other relevant issues, Chevron provides the following:

Chevron does not own any crude oil production in northeast B.C. that accesses the Western System. All crude oil shipped by Chevron on the Western System is purchased from third parties.




Chevron Res~onse Issued June 9.2008

1.4 Reference:

(i) Written Evidence, Page 9 - 11, Answer 20:


(ii) Written Evidence, Page 11, Answer 20:

"Kamloops volumes would directionally be more likely to use the Western System if a lower toll was available."

Request:

(a) Please provide a map and description of all of the transportation options to each of the final receipt point(s) listed in Question 1.2(b) above.

(b) For each transportation option listed in response to Question 1.4(a) above, please provide a table setting out the cost of transportation on each of these routes and compare that cost to shipping on the Western System.

(c) For each transportation option listed in response to Question 1.4(a) above, please provide a detailed explanation as to why Chevron has chosen to ship on this route as opposed to Western System. For each transportation option listed in response to Question 1.4(a) above, please also explain what characteristics or aspects of this alternative route would cause Chevron to use it for transportation (beyond transportation cost).

(d) For each of the final receipt point(s) listed in Question 1.2(b) above, please provide a detailed explanation of all of the types of circumstances, factors or events that in the future could cause a decline or increase in the volumes shipped on the Western System. For each circumstance, factor or event, please provide Chewon's forecast of the likelihood of it occurring, the timeframe in which such a each circumstance, factor or event could arise, and the materiality of it on the volumes shipped by Chevron on the Western System.

Response:

Preliminary Comment: Chevron objects to these requests on the grounds that they request Chewon to comment on matters are not raised in the evidence filed by Messrs. Engbloom and Graves and are therefore outside the scope of proper Information Requests. Further, given that Chevron is not asking

Plateau to assume volume risk (refer to BCUC-Chevron-14.1), questions regarding volume risk (past or prospective) presented by Chevron are not relevant. To the extent that any of the information requested may relate to other relevant issues, Chevron provides the following:

(a) and (b) Please refer to BCUC-Chevron 1.4.

(c)-(d) Chevron, like any shipper, considers a number of factors. Primary among them is transportation cost. Other factors include price and availability of crude supplies and available pipeline capacity.



Plateau Pipe Line Ltd. Information Request No.1 to Chewon Canada Limited ("Chevron")

Chewon Response Issued June 9,2008

I .5 Reference:

(i) Written Evidence, Page 9 - 11, Answer 20:


Request:

(a) Please explain how TransMountain pipeline's apportionment history, both upstream and downstream of Kamloops, has affected Chewon's throughput on the Western System and could affect Chewon's throughput on the Western System for 2008-2012.

(b) Please explain how the expansion of the TransMountain pipeline will affect the apportionment explained in response to Question 1.5(a), and how this could affect Chevron's throughput on the Western System for 2008-201 2.

(c) Please describe and discuss (frequency, impact, mitigation, options, etc.) all types of events and reasons causing volumes Plateau deliveries to Kamloops to not be readily transported downstream by TransMountain and how these events could affect Chevron's throughput on the Western System for 2008-2012.

(d) Please explain how Kinder Morgan's TMX Anchor Loop Project will impact on Chewon's use, or forecast use, of the Western System. Please also explain how any subsequent expansion of the TransMountain pipeline will impact on Chewon's use, or forecast use, of the Western System.

(e) Has Chewon entered into any agreement(s) with Kinder Morgan regarding or in any way relating to the TransMountain pipeline? Please provide a copy of any such agreement. Please also explain how this agreement(s) impact on Chevron's use, or forecast use, of the Western System.

Response:

Preliminary Comment: Chewon objects to these requests on the grounds that they request Chewon to comment on matters are not raised in the evidence filed by Messrs. Engbloom and Graves and are therefore outside the scope of proper Information Requests. Further, given that Chewon is not asking Plateau to assume volume risk (refer to BCUC-Chewon-14.1), questions regarding volume risk (past or prospective) presented by Chewon are not relevant. To the extent that any of the information requested may relate to other relevant issues, Chevron provides the following:

For the past number of years, the TransMountain pipeline has suffered repeated bouts of apportionment between Edmonton and Kamloops. During these times, Chevron is constrained in the volume of crude it can source from Edmonton. Periodic apportionment is generally expected to continue on TransMountain in the coming years.

Although TransMountain has an approved capacity increase under construction (the TXM Anchor Loop Project), this expansion is relatively modest in the context of the TransMountain pipeline. At its start up scheduled for May 2008, TMX Phase 1 is to add 3,980rn3ld (25,000 bpd) of incremental pipeline capacity to TransMountain. TMX Phase 2 is expected to add an additional 2,380m31d (15,000 bpd) of capacity when it is scheduled to come on stream in November 2008. This is in the context of a total capacity of approximately 260,000 bpd the TransMountain system.

The rules and regulations tariff includes procedures for allocating capacity on the TransMountain pipeline. According to the current procedures, capacity is allocated based on delivery destination-Domestic, Export and the Westridge Dock. Chevron's Bumaby Refinery takes deliveries from TransMountain in the Domestic category. The allocation of the additional capacity of the TMX Anchor Loop volumes has not been determined by the NEB. However, Kinder Morgan has proposed (and the NEB has approved on an interim basis) allocating the majority of the additional capacity of TMX Phase 1 to the Westridge Dock category (2,200 m3id) and decreasing the percentage of the remaining capacity available to the Domestic category (including Chevron's Bumaby refinery) to 52% (down from its previous level of 54%).

Kinder Morgan has indicated that it plans to apply to the NEB to combine the Domestic and Export categories into a single "Land" category. If this were to happen, the Chevron Bumaby Refinery would be competing for limited capacity within a much larger (and unpredictable) group of shippers in British Columbia and Washington State. Chevron believes that this would increase the likelihood that the Chevron Bumaby refinery would face future apportionment on the TransMountain system.

When the TransMountain system is constrained between Edmonton and Kamloops, the Chevron Bumaby Refinery can attempt to access additional volumes from the Westem System, which ties into the TransMountain system at Kamloops.

Chevron has not entered into any agreements with Kinder Morgan relating to the TransMountain pipeline. In particular, Chevron has made no minimum (or any other) volume commitments to TransMountain. Chevron nominates its volumes monthly pursuant to the published and approved tariffs of TransMountain.





1.6 Reference:



Request:

(a) Please provide Chevron's actual throughputs on the Western System for the Test Period and 2008 to date.

(b) Please compare the volumes provided in response to Question 1.6(a) to the total volumes forecast in Plateau's application to be shipped to Kamloops.

(c) Please provide Chevron's forecast of the volumes it will ship on the Western System for the remainder of the Test Year, 2009,2010,201 1 and 2012.

(d) Please provide a detailed discussion of the accuracy and reliability of the forecasts provided in response to Question 1.6(c). Please list all factors that would affect the accuracy or reliability of this forecast and provide Chevron's estimation of the likelihood of it occuning and the materiality of its impact.

(e) Please provide a detailed description of all Chevron's markets and market plans and how changes to its markets and market plans will affect its volume forecasts for the Test Year, 2009, 2010, 201 1 and 2012.

(f) Please compare the forecast in Question 1.6(c) to the total volumes forecast by Plateau to be shipped to Kamloops on the Western System.

(g) Please provide any information Chevron has on the forecast volumes to be shipped by other Kamloops shippers. Please provide the source and indicate the reliability of all information provided in response to this question.

(h) Is Chevron willing to enter into take or pay arrangements or otherwise guarantee that it will ship the volumes forecast in response to Question 1.6(c)?

(i) If the answer to Question 1.6(h) is no, please provide a detailed explanation as to why Chevron is not willing to guarantee its throughput.

6) If the answer to Question 1.601) is no, please also explain why Plateau should bear the risk of under-recovery based on chevron's actual throughputs not meeting forecast volumes.

Response:

(a) Please refer to BCUC-Chevron-] .4.

(b)-(g) Chevron objects to these requests on the grounds that they request Chevron to comment on matters are not raised in the evidence filed by Messrs. Engbloom and Graves and are therefore outside the scope of proper Information Requests. Further, given that Chevron is not asking Plateau to assume volume risk (refer to BCUC-Chevron-14.1), questions regarding volume risk (past or prospective) presented by Chevron are not relevant.

(h) Differences between forecast and actual volumes shipped to Prince George and Kamloops are to be reconciled in the RSA and tolls adjusted accordingly to avoid Plateau taking volume risk. Chevron accepts this provision of the RSA. As a result, with the RSA in effect, a take-or-pay provision would be redundant or not necessary.

(i) Plateau is a common carrier pipeline. Its current approved tariff contains no provision for take- or-pay service or guaranteed throughput. Neither the original nor the amended applications contain provisions for take-or-pay service or guaranteed throughput. No other shipper (including Husky) has guaranteed throughput. Indeed, Plateau has shown a willingness to accept Husky's volume risk and, at the same time, give Husky a discounted toll. This is unjustly discriminatory.

fi) Chevron is not proposing that Plateau should bear the risk of under-recovery based on Chevron's actual throughputs not meeting forecast volumes. Please refer to BCUC-Chevronl4.1 and Plateau-Chevron-] .6(h).



Plateau Pipe Line Ltd. Information Request No. 1 to Chevron Canada Limited ("Chevron")


1.7 Reference:

(i) Written Evidence, Page 3, Answer 4:

"The agreed upon tolls for Prince George service are a discount from those that would occur under the applied for cost of service forecast."

(ii) Plateau's response to Commission Information Request No. 3, question 84.4:

2007 (Jul-Dec) 2008 Volume (m3/d) 1710 1600

Tolls ($)

Interim 11.20 Application 9.05 Settlement 11.20

Forecast Revenue from Huskv ($000)

Interim 3,524 Application 2,845 Settlement 3,254

1 1.20 10.50 9 (1 1.20 Jan-Feb)

Total

Request:

(a) Please confirm that for the Test Period and Test Year the revenues forecast to be received by Plateau from Husky under the terms of the Toll Settlement exceed the revenues forecast to be received by Plateau from Husky under the applied for costs of service forecasts.

(b) If not confirmed, please provide a detailed explanation why not, including alternate calculations.

Response:

(a) Confirmed. As shown in the table in the request, the revenue under the settlement is forecast by Plateau to be $12,000 more than the $8,994,000 revenue under the application case, an increase of 0.13%. The closeness of these two revenue streams is noted at QIA 18 of Chevron's Intervenor Evidence. However, in the future period 2009-201 1 the difference in revenues forecast to be received by Plateau with and without the Toll Settlement is $3,6 million lower under the settlement. This amount is the difference between the revenue streams with and without the settlement as shown in BCUC-Plateau-84.1.

(b) Not applicable.





1.8 Reference

Written Evidence, Page 4, Answer 5, Table I:

Annual Revenue Loss from Toll Settlement Prince George Tolll

Annual Original Toll Revenue

Year Estimate Settlement Difference Volume Reduction

Request:

(a) Please confirm that under the applied for tolls to Kamloops, Plateau would not retain the revenue surplus collected from Kamloops shippers under the interim toll, and please further confirm that the Karnloops revenue surplus would be credited back to Kamloops shippers in the Rate Stabilization Account.

(b) Please provide a revised Table 1 that includes the tolls collected by Plateau for the Test Period and January and February of 2008. In preparing this table, please assume that the volume shipped by Husky for the Test Period was 1,710 m31d.

Response:

(a) Please refer to BCUC-Chevron-14.1.

(b) Please refer to BCUC-Chevron-7.1.





1.9 Reference:

(i) Written Evidence, Page 6, Answer 11. (ii) Written Evidence, Page 13, Table 2, Comparison of Income Tax Calculations.

Request:

(a) Does Chevron agree that, by calculating deemed taxes in the manner it describes in its evidence, the toll to Kamloops would no longer be determined as if the Toll Settlement did not exist?

(b) Please confirm that Chevron's calculations of "Income Taxes & Income Based on Revenue Received with the Settlement" in Table 2 does not include the higher revenues received by Plateau by its retention of the Husky interim revenue surplus for the Test Period and January and February of the Test Year.

(c) Does Chevron agree that, with the Rate Stabilization Account mechanism approved, Plateau never recovers more or less tax than what is approved based upon its approved return?

Response:

(a) No. The purpose of the calculation of income tax is to show that actual income tax will be less than used by Plateau to establish tolls for Kamloops shippers, with the result that Plateau's return will be higher than it shows. Under the settlement, Kamloops shippers do not secure a reduced toll for any reason.

(b) The revenues utilized in determining the income taxes in Table 2 are (a) Revenues Received with the Settlement of $1 9,207 and the Rate Stabilization Account of $ 201 8 (in millions) as included in BCUC-Plateau-84.1.

(c) The request is correct but incomplete. The Rate Stabilization Account will only compare approved cost to assumed costs that do not include the impact of the settlement. However, the actual costs incurred under the settlement will be different than the applied-for costs; for example, income and return as noted.





1.10 Reference:

Written Evidence, Page 7, Answer 16:

"The tolls were based on the Commission-approved methodology that sets the Prince George toll equal to 65% of the Kamloops toll."

Request:

(a) Please provide a detailed explanation of Chevron's understanding of the history of the 65:100 relationship between the Prince George and Kamloops tolls, including:

(i) when this 65:100 ratio was first implemented;

(ii) the rate making rationale for this ratio at the time it was first implemented;

(iii) the capacity of the Western System at the time this ratio was first implemented;

(iv) the volumes shipped to Kamloops at the time this ratio was first implemented; and

(v) the volumes shipped to Prince George at the time this ratio was first implemented.

(b) Please provide the source and indicate the reliability of all information provided in response to question 1.10(a) above.

(c) Please confirm that the following is a correct calculation of a truly volumetric toll (volume/distance allocation units) for deliveries to Prince George and Kamloops based on Plateau's applied for revenue requirement for the Test Year. If not confirmed, please explain why and provide an alternate calculation.

Miles M3iMiles Test Year 000

Revenue requirement $000 22.102 Less stabili7ation (2.01 81

20,0R4 Volume M3id Prince George 1,600 Kamloops 2.366

3.966 Volumetric tolls Prince George 232.4 372 $8.17 Kamloops 504.3 1193 $17.73

736.7 1565

Average haul 395 Average toll 13.87 Slope 3.52

(d) Does Chevron agree that, at the 65:100 relationship, deliveries to Prince George provide a toll subsidy on tolls to Kamloops?

(e) If the answerer to Question 1.10(d) is yes, please provide a detailed explanation why this subsidy is not discriminatory.

(f) Is Chevron of the view nothing that affects the appropriateness of continuing the 65:100 relationship has changed on the Western System since 2002?

(g) Is Chevron of the view that the 65:100 relationship should remain intact regardless of any changes in volumes over time? Please provide a detailed explanation.

Response:

(a) In both the original and amended application, Plateau explicitly uses the existing toll design relationship of 65:100 between Prince George and Kamloops tolls. Nowhere does Plateau indicate that the existing toll design is not acceptable. Indeed, the application filed by Plateau did not seek to change this toll design and, to the contrary, explicitly recognized that "the tolls at these relative levels are just, reasonable and not unduly discriminatory." (See Application, page 7, paragraph 40.) On this basis, Chevron has made no assessment of the existing toll design. For a history of the existing toll design, please see Plateau's original application.'

(b) Not applicable.

(c) The arithmetic in the table, which is for 2008, is confirmed. The toll for Kamloops shipments is shown as $17.73 per M3, which is higher than the 2008 toll of $16.15 per M3 shown for Kamloops shipments in BCUC-Plateau-84.1. Directionally, increases in the Kamloops toll erode the economic benefit of Kamloops shippers using Plateau's Western System.

(d) to (g) Please refer to Plateau-Chevron-1 .lO(a).

1 Original Application, Tab 1





1.11 Reference:

Written Evidence, Page 11, Answer 21:

"Of course, to obtain the recommended toll, Kamloops shippers would have to agree to the other elements of the toll settlement except to the extent it is necessary for them to pursue litigation to void the discriminatory allocation of the discounted revenue to Husky."

Request:

(a) Please explain the litigation Kamloops shippers' are contemplating "to void the discriminatory allocation of the discounted revenue to Husky."

(b) Please explain all terms of the Toll Settlement Kamloops shippers would not be willing to agree to.

(c) Please confirm that Chevron is not speaking for other Kamloops shippers.

(d) Please confirm that no other Kamloops shippers expressed any concern to the Commission regarding tolls to Kamloops before or after the Husky Toll Settlement.

Response:

(a) Until the Kamloops shippers settle with Plateau, if at all, the litigation of this case is continuing and associated costs are being incurred.

(b) Please refer to BCUC-Chevron-14.1.

(c) Chevron speaks for itself.

(d) There is no indication of such concern on the public record,





1.12 Reference:

Written Evidence, Page 11, Table 3:

Tolls Under Settlement and Recommended Cases Husky Kamloops Shippers

Year Settlement Recommended Settlement Recommended $lm3 $/m3 $/m3 $im3

2008 9.00 10.04 16.15 15.45 2009 9.36 10.74 17.57 16.52 2010 9.73 10.86 17.70 16.71 201 1 10.12 1 1.49 19.06 17.68

Request:

(a) Please calculate the total revenue received by Plateau from all shippers under Chevron's recommended case for 2008,2009,2010 and 201 I.

(b) Based on the calculations provided in response to Question 1.12(a), please calculate as a percentage the return on common equity Plateau would receive based on Chevron's recommended tolls.

(c) Please compare the return on equity calculated in response to 1.12(b) to the Commission approved retum on equity for a low-risk benchmark utility.

Response:

(a) Plateau may have misinterpreted the purpose of showing recommended tolls. The recommendation proposed in Chevron's Intervenor Evidence is that the revenue reduction that Plateau accepted by cntering the settlement with Husky be allocated to all shippers and not streamed solely to Husky. The "recommended" tolls are illustrative of applying the recommended revenue allocation and are not recommended for approval.

The "recommended" tolls in Chevron's Intervenor Evidence are derived from BCUC-Plateau-84.1, which shows the revenue and return under the original and amended applications.

Please refer to BCUC-Chevron-6.1.

@) Not applicable.

(c) Not applicable.





1.13 Reference:

(i) Written Evidence, Page 2, Answer 1

(ii) Written Evidence, Page 16, Curriculum Vitae of Gordon Engbloom.

(iii) Written Evidence, Page 23, Curriculum Vitae of Grant Graves.

Request:

(a) Please indicate when each of Messrs. Engbloom and Graves were retained and the requests made of each by Chevron. Please produce a copy of all written instructions to Messrs. Engbloom and Graves, whether by letter, e-mail or otherwise, including any communications exchanged to clarify hose instructions.

(b) Did Chevron retain any external consultant(s) beyond Messrs Engbloom and Graves in respect of Plateau's Application? If so please indicate whom, when, details of the mandate(s) and the results.

(c) Please list and describe all experiences of Mr. Engbloom on or in respect of the Western System. Provide copies of all work product, including filed evidence and IR responses in respect of same.

(d) Please list and describe all experiences of Mr. Graves on or in respect of the Western System. Provide copies of all work product, including filed evidence and IR responses in respect of same.

(e) Please list and describe all experiences of Mr. Engbloom on or in respect of assessing whether any oil or liquids pipeline toll designs resulted in unjustly discriminatory tolls. Provide copies of all work product, including filed evidence and IR responses in respect of same and copies of the associated final decision(s) of regulator(s).

(f) Please list and describe all experiences of Mr. Graves on or in respect of assessing whether any oil or liquids pipeline toll designs resulted in unjustly discriminatory tolls. Provide copies of all work product, including filed evidence and IR responses in respect of same and copies of the associated final decision(s) of regulator(s).

Response:

(a) No written instructions have been provided to Mr. Engbloom or Mr. Graves.

Mr. Engbloom was first contacted in early April to review Plateau's amended application dated March 13, 2008. That review occurred from April 18 to 21 and included participation in the

preparation of Chevron's Information Request 2. Subsequent to Plateau's May 5 filing of responses to information requests from the BCUC and Chevron, Mr. Engbloom was asked to review the responses. During the week of May 12, Mr. Engbloom was asked by counsel to prepare written evidence, which commenced on May 16. With consent of counsel, on May 17 Mr. Engbloom requested Mr. Graves to prepare evidence with respect to income tax matters. The joint evidence was filed on May 20.

(c) Mr. Engbloom has no prior experience with the Westem System.

(d) Mr. Graves has no prior experience with the Western System.

(e) Mr. Engbloom filed evidence before the National Energy Board (RH-2-2007) with respect to toll design on Line 9, a crude oil pipeline owned and operated by Enbridge Inc. Line 9 presently transports offshore crude oil from Montreal to Samia. The proceeding was terminated before information requests regarding Mr. Engbloom's evidence were made. The evidence is being filed in a separate file provided with this response.

At the time of the preparation of this response, Mr. Engbloom has prepared evidence related to further issues regarding toll design on Line 9 (NEB proceeding RH-3-2008). The proceeding is in suspension and the evidence has not been filed.

As described in Mr. Engbloom's CV attached to Chevron's Intervenor Evidence, he has long experience assessing toll designs for reasonableness and discrimination.

(f) In the application of accounting and financial practices to regulated pipelines, Mr. Graves has not applied those principles to liquids pipelines.





1.14 References:

Written Evidence, Page 5, Answers 7 and 8.

Request:

(a) Is Chevron opposed to the use of a Rate Stabilization Account mechanism to refund to it the excess revenue that would be collected if throughput exceeded forecasts? If so, why?

(b) Is Chevron opposed to the use of a Rate Stabilization Account mechanism to refund to it the excess revenue that would be collected if integrity costs are less than forecast? If so, why?

(c) Is Chevron opposed to the use of a Rate Stabilization Account mechanism to refund to it the excess revenue that would be collected if O&M costs are less than forecast? If so, why?

(d) Is Chevron opposed to the use of a Rate Stabilization Account mechanism to refund to it the interim revenue surplus? If so, why?

Response:

Chevron is prepared to accept the implementation of a RSA for reconciliation of cost variances that are beyond Platcau's control, as well as variances in volume. On this basis, Chevron believes that RSA can be used to address each matter raised in the requests except for item (c). With respect to that item, variance in O&M costs, Chevron is concerned that the RSA is proposed by Plateau to include reconciliation of all costs, including those, like O&M costs, that Plateau can control.

Please refer to BCUC-Chevron 14.1.



Plateau Pipe Line Ltd. Information Request No.1 to Chewon Canada Limited ("Chewon")


1.15 Reference:

Written Evidence, Page 7-8, Question and Answer 16.

"Q16. Doesn't the toll settlement result in different tolls for service to Kamloops and Prince George?

A16. Yes, but so did the applied-for tolls in the application. In that case, the tolls were based on the Commission-approved methodology that sets the Prince George toll equal to 65% of the Kamloops toll. The problem with the toll settlement is that it takes a reduced revenue requirement and applies it only to the Prince George toll. By so doing it clearly favours the Prince George shipper - Husky - and not the Kamloops shippers, which include Chevron. In other words, the issue is not about whether there should be a difference between the tolls for Prince George and Kamloops but rather whether the difference that arises from the toll settlement is reasonable. or not."

Request:

(a) Is Chewon of the view that deliveries to Prince George have the same supply source alternatives as deliveries to Kamloops? Please explain.

(b) Please confirm that deliveries to Karnloops on the Western System constitute traffic under different circumstances and conditions as deliveries to Prince George? If not confirmed, please provide a detailed explanation why not, including an exhaustive list of all circumstances and conditions that exist, and how all of these circumstances and conditions are the same for deliveries to Prince George and Kamloops.

(c) Please explain how Plateau's proposed toll to Prince George under the Toll Settlement has adversely affected Chewon as a shipper to Kamloops, relative to what the toll to Prince George would have been in the absence of the Settlement, ceteris paribus.

Response:

(a) Yes, under the existing toll economics. Please refer to BCUC-Chewon-13.1 and 13.2.

(b) The toll design issue is not whether there are different circumstances and conditions between deliveries to Prince George and Kamloops. The real issue is whether any such differences warrant that the proposed reduction in Plateau's revenue requirement should be solely directed to shipments to Prince George. The answer is no, there are no such differences.

Please refer to Plateau-Chewon-l . l5(c).

(c) As proposed by Plateau, the toll for shipments to Kamloops is unchanged with or without the settlement. That is a problem. The cause of the problem is Plateau unreasonably streaming a reduction in its revenue requirements solely to shipments to Prince George and excluding shipments to Kamloops fiom any part of that reduction.

As noted in BCUC-Chevron-13.1 and 13.2, the differences in volumes transported to Prince George and Kamloops are related to the declining supply available at Taylor, a risk common to both Prince George and Kamloops shipments. For transmission services, temporary or transitory operating matters are not toll design criteria.' Nor are the characteristics of the ultimate demand for the product transported. For example, if crude oil is transported to a domestic refinery, in and of itself that characteristic does not cause the domestic refiner to be subject to a different toll than crude oil that is delivered nearby and then loaded onto a ship and transported offshore. Further, as noted in Chevron's Intervenor Evidence, the matters that Plateau says it relied upon to stream the reduction in revenue requirements solely to Husky, such as a "...wish to resume discussions around other Western System opportunities.", are not toll design criteria.'

Refer to BCUC-Chevron-5.1 Refer to Chevron Intervenor Evidence, QIA 17, page 8

24





1.16 Reference:

Written Evidence, Page 3, Answer 4.

Request:

(a) Is Chevron suggesting that it had no opportunity to discuss a negotiated resolution to tolling issues with Plateau before the Husky Toll Settlement was filed?

Response:

No. While there were some informal discussions, Chevron was not included in the negotiations that led to the Husky Toll Settlement and has not been offered a similar settlement in the absence of a volume/time commitment fiom Chevron (which Husky was not required to make).



Plateau Pipe Line Ltd. Information Request No.1 to Chewon Canada Limited ("Chewon")


1.17 Reference:

Written Evidence, Page 3, Answer 3.

"It [the Commission reducing the entire Revenue Requirement by the amount of Husky's reduction] would also mean that Kamloops shippers would have to amee to the other elements of the toll settlement ..." (emphases added)

Request:

(a) Please explain the concept of Kamloops shippers having "to agree" if the Commission proceeds Chewon proposes.

Response:

(a) Please refer to BCUC-Chewon-14.1.

In the Matter of an Application to the National Energy Board dated 11 April 2007 for approval pursuant to Part IV of the National Energy Board Act made by Enbridge Pipelines Inc. seeking orders fixing and approving tolls that Enbridge shall charge for transportation services on its Line 9 for the 2006 Test Period (1 April through 31 December 2006) and 2007 Test Year (1 January through 31 December 2007).

National Energy Board Hearing Order RH-2-2007

Written Evidence of:

Gordon M. Engbloom, P. Eng Confer Consulting Ltd.

Calgary, Alberta

Prepared for:

NOVA Chemicals (Canada) Limited

July 30, 2007

Confer Consulting Ltd. 2

Table of Contents

Section Page

1. Introduction and Conclusions 3 2. Toll-Setting Issues 6 3. Scope and Nature of Cost Recovery During the FSA 8 4. Generational Considerations and Equitable Tolls 13 Appendixes


1. Introduction and Conclusions

Q1 Please state your name, business address, education, occupation and work

experience.

A1 My name is Gordon Engbloom. My business address is 2900, 350 – 7 Ave.

S.W., Calgary, Alberta, T2P 3N9. I am President of Confer Consulting Ltd. where

I have been engaged in economic consulting for the past 30 years. My

curriculum vitae is in Appendix A.

Q2 What is the purpose of your evidence?

A2 The purpose of my evidence is to review the toll levels sought by Enbridge

Pipelines Inc. (“Enbridge”) for Line 9 during the applied-for test periods (“Test

Periods”) having regard for sound and recognized toll-setting principles.

Q3 What is your general conclusion?

A3 My general conclusion is that Enbridge has proposed toll levels for Line 9 during

the Test Periods that are not consistent with sound and recognized toll-setting

principles.

Q4 Please summarize the reasons for your conclusions.

A4 Enbridge has requested that the costs of higher equity thickness and accelerated

depreciation be included in the tolls set for the Test Periods, which include the

Third Interim Period.1

With respect to those higher costs for the Third Interim Period, when the FSA

was entered, Enbridge could see a contractual term of eight years when

combining the Primary and Extended Terms. There were no warranties or

guarantees of any service requirements after the end of the FSA. In these

circumstances, Enbridge settled on a depreciation rate consistent with that of the

Older System and agreed to an increase in its equity thickness from 40% to 45%

over the Primary Term. Further, there was no increase in equity thickness or

1 During the Extended Term of the FSA, revenue requirements and effective tolls for the First and Second Interim Periods were established by agreement between Enbridge and the shippers. The Second Interim Period ended March 31, 2006. The remainder of the Extended Term from April 1, 2006 to September 30, 2007 is defined as the Third Interim Period in this evidence.


accelerated depreciation under the arrangements for either the First or Second

Interim Periods.

Enbridge faces the same basic outlook and business environment for the use of

Line 9 in the Third Interim Period as it experienced in the First and Second

Interim Periods. Accordingly, there is no need to change the scope and nature of

the costs included in revenue requirements, and therefore tolls, for the Third

Interim Period.

With respect to depreciation, the systematic and rational inclusion of depreciation

in Line 9 tolls must reflect the economic life of the assets in transportation

service, not simply westbound service. Enbridge states that there are probable

and potential uses for the assets to have economic life beyond its view of the end

of westbound service. It relies on this expectation of economic life of the assets

to assert that no abandonment plan for the assets is needed, yet it applies to

have the assets fully depreciated by 2013. As a result of the applied-for

depreciation, those shippers that could use the line after 2013 would have use of

existing assets but not pay the depreciation expense of those assets in their tolls

and would not pay their share of the assets’ depreciation. Stated differently, a

future generation of shippers after 2013 will benefit from excess depreciation

being charged to a current generation of shippers.

Moreover, Enbridge has asked the Board to saddle westbound shippers with an

incremental $102 million in depreciation expense to accelerate capital recovery

over the period to 2013. In so doing, Enbridge must provide evidence that the toll

impacts of such costs are justified not only in theory, which it has not done given

the expected future life of Line 9 assets after 2013, but also by robust analysis

that demonstrates thorough examination and reasonable conclusions.

Instead of such analysis and demonstration, Enbridge relies on Muse, Stancil &

Co. (“Muse”) and specifically a report dated February 2007 (“Muse”)2 to establish

2013 as the end of westbound service. Muse contains weak and incomplete

analysis that should not be relied upon to set the date of the end of westbound 2 Application, Appendix A-7.1.


service or the prospects for re-reversal and the commencement of eastbound

service. Moreover, Enbridge itself has not undertaken even the most basic

analysis of the costs to reconfigure its system in southwest Ontario to make use

of Line 9. Nor has it undertaken studies or initiatives to best expand the market

for western Canadian crude oil in Ontario, Quebec or adjacent U.S. markets.

Instead, Enbridge appears to have resorted to seeking to pin the cost of fully

depreciating Line 9 on westbound shippers with the result that it will have

available to it a fully depreciated asset likely to be in future use after 2013, a

likelihood that it recognizes by not even contemplating abandonment of Line 9.

Q5 How is your evidence organized?

A5 Section 2 sets out a description of toll-setting, followed by Section 3 that

addresses the scope and nature of costs used in toll-setting during the Third

Interim Period and Section 4 that addresses generational equity and the

treatment of depreciation.


2. Toll-Setting Issues

Q6 What do you mean by toll-setting?

A6 Two features of pipeline tolls should be distinguished. First, ‘toll design’

establishes the design of tolls having regard for the characteristics of the services

offered and the physical movement of products through the pipeline system. For

example, toll designs could be postage stamp or distance-based, they could be

demand charges paid by the shipper whether or not it ships product, or they

could be commodity charges paid by the shipper only on the volume it ships.

In contrast, ‘toll setting’ involves establishing a toll by combining revenue

requirements with a particular toll design. The process establishes the level of

tolls within the context of the particular toll design used by the pipeline.

In this case, toll design is not at issue. Rather, setting tolls is the issue because

Enbridge has chosen to include certain higher costs in the applied-for revenue

requirements for the Test Periods that it has not included in the past for

westbound service on Line 9.

Q7 What are the issues of toll-setting that arise in the Application?

A7 Two primary issues of toll-setting arise in this case. First, although tolls may be

established retrospectively, the Application seeks to expand the scope and

nature of costs recovered in retrospective tolls beyond those costs that are

consistent with the commercial framework and history of the Facilities Support

Agreement (“FSA”). Enbridge’s risks during the Third Interim Period of the FSA

are not different than earlier periods under the FSA and there is no basis to

expand the scope and nature of costs recovered during that period by raising

effective tolls3 due to increases in equity thickness and in depreciation rates.

Second, tolls should be equitable in the sense that shippers taking service in a

test period should pay a toll that is set so as to recover the costs of service

3 The practice under the FSA has been to establish interim tolls for a period and then charge variances between toll revenue and revenue requirements to shippers. “Effective toll” is used in this evidence as the total unit cost (interim toll and share of variance) for a period that a shipper bears for service on Line 9.


applicable to that test period and not to other periods. Since many elements of

the cost of service of a pipeline are recovered over many years, and therefore

many test periods, it is important to ensure that each test period attracts no more

or less than its share of those costs. This feature is sometimes referred to as

generational equity among shippers.

The Application seeks to accelerate depreciation for the Third Interim Period as

well as after the FSA. Enbridge’s position is that the increased depreciation must

occur so as to complete amortization of the assets currently in rate base over the

forecast life of the assets in westbound service. This is inconsistent with

Enbridge’s view that the assets are likely to have economic life beyond the end of

westbound service.


3. Scope and Nature of Cost Recovery During the FSA

Q8 What is the key business issue that relates to cost recovery for Line 9 under the

FSA?

A8 The key business issue is that during the Primary Term Enbridge’s cost recovery

is provided through a combination of revenues from interim tolls for westbound

service on Line 9, and sharing of any revenue shortfalls by shippers on the Older

System and by Line 9 shippers. There appears to be no dispute that during the

Primary Term the arrangement provided Enbridge with its actual revenue

requirement.

In the Extended Term, the FSA states that there will be no reliance on Older

System shippers in terms of recovering revenue requirements for Line 9, and in

that way, the shippers on Line 9 stand alone for payment of the revenue

requirements.

Q9 How have the parties addressed recovery of revenue requirements in the

Extended Term?

A9 Through March 31, 2006, the parties entered two sets of agreements to cover the

First Interim Period from October 1, 2004 to March 31, 2005 and the Second

Interim Period from April 1, 2005 to March 31, 3006. Under these agreements

interim tolls were established and subsequent toll revenue was reconciled with

the actual revenue requirement to take account of variances between forecast

and actual volumes shipped and forecast and actual costs. The record of these

arrangements for the First and Second Interim Periods is extensive4 since in

each of the Periods initial agreements were for short periods followed by

extensions that ultimately extended the term of each Period to the dates noted

above. There appears to be no dispute that during the First and Second Interim

Periods the arrangements provided Enbridge with its actual revenue requirement.

Q10 What were the equity thickness and depreciation rates during the Primary Term

and the First and Second Interim Periods?

4 NCX-Enbridge-3(c).


A10 The FSA provides for the equity thickness to increase over the Primary Term

from 40% to 45%, and the 45% level was maintained for the First and Second

Interim Periods. The depreciations rates for the Primary Period were confirmed

by agreement to equal those of the Older System. The same basis for

depreciation rates applied to the First and Second Interim Periods. These rates

are in the order of 3% per year.

Q11 What has happened with respect to the remainder of the Extended Term from

April 1, 2006 to September 30, 2007, or the Third Interim Period?

A11 It is the evidence of Enbridge5 and NOVA Chemicals that negotiations failed to

settle long-term arrangements. NOVA Chemicals believed that without a long-

term arrangement, the established precedents from the First and Second Interim

Periods would apply to the Third Interim Period.6

Q12 Please explain how the Application proposes to deal with the Third Interim

Period.

A12 The 2006 Test Period is from April 1 to December 31, 2006, which is the portion

of the Third Interim Period that falls in 2006. The 2007 Test Period is from

January 1 to December 31, 2007, where the first nine months fall within the Third

Interim Period and the last 3 months fall outside both the Third Interim Period and

the Extended Term of the FSA since it terminates on September 30, 2007.

The result is that the Application subsumes the entire Third Interim Period into

the Test Periods, even though it is wholly within the Extended Term of the FSA.

Q13 Is this important from a toll-setting perspective?

A13 Yes, it is.

Q14 Please explain why.

A14 It is important because through the Application Enbridge is seeking cost

treatment for the Third Interim Period that unilaterally alters the precedent

business arrangements setting out the risks and remedies between the shippers

5 Enbridge, for example, in NCX-Enbridge-7(b). 6 NCX in its corporate evidence at Sections 2.5 and 2.6.


and Enbridge that have prevailed under the FSA. The Application ignores those

previous arrangements insofar as the Third Interim Period is concerned and in so

doing includes costs that reflect a fundamental change in the scope and nature of

the business arrangements within the commercial context of the FSA when no

such change is warranted. From a toll-setting perspective, the Application has

the effect of denying the shippers on Line 9 a reasonable level of certainty in the

toll-setting methodology that they had come to rely upon.

The fact is that within the commercial context of the FSA and arrangements for

previous interim periods, there is no reason to change the equity thickness or

increase depreciation in the Third Interim Period. Stated differently, Enbridge’s

risks have not changed in the Third Interim Period compared to the earlier

periods.

Q15 Please explain.

A15 When the FSA was entered, Enbridge could see a contractual term of eight years

when combining the Primary and Extended Terms. There were no warranties or

guarantees of any service requirements after the end of the FSA. In these

circumstances, Enbridge settled on a depreciation rate consistent with that of the

Older System and agreed to an increase in its equity thickness from 40% to 45%

over the Primary Term.

There was no increase in equity thickness or accelerated depreciation under the

arrangements for either the First or Second Interim Periods. Enbridge faces the

same basic outlook for the use of Line 9 in the Third Interim Period as it

experienced in the First and Second Interim Periods.

Q16 How do you know that?

A16 In a presentation to shippers dated September 20067, a page title “Status

Update” itemizes the following factors shown in quotes:

(a) “closure of the Petro-Canada refinery”. The closure was announced in

September 2003 as was an early-2005 closure date.8 The closure of the 7 Attachment 1 to IOL-Enbridge-14(1).


refinery was known to Enbridge well before the commencement of the

Extended Term and the closure itself occurred at the time the First Interim

Period was ending and the Second Interim Period was beginning;

(b) “reduced volumes”. Line 9 throughput peaked in 2004 and declined in 2005

and thereafter9, which is during the Extended Term when Enbridge agreed to

the business arrangements for the First and Second Interim Periods;

(c) “FSA winding down”. The same can be said for any period after the

Commencement Date of the FSA, and especially after the end of the Primary

Term;

(d) “uncertain future use”. The same can be said for the period before the FSA

and, since the FSA, after the Extended Term;

(e) “declining economic life”. If there is “uncertain future use”, it is not clear that

there is declining economic life since a future use could extend the economic

life. Moreover, as will be discussed later in this evidence, the evidence

provided by Enbridge to support a decline in economic life is weak and

incomplete, and even Enbridge states that it believes “…that portions of Line

9, and potentially the entire pipeline, could have economic use beyond its

current use in westbound service.”10 More of the same types of statements

regarding economic life beyond 2013 are made by Enbridge in Application

Appendix A-10, Terminal Negative Salvage.

The point here is that none of these factors is new to the Third Interim Period.

They were known for various lengths of time when Enbridge agreed to earlier

business arrangements for then-future periods. In the result, it would be

inconsistent to increase equity thickness and accelerate depreciation during the

Third Interim Period, with the consequent increase in effective tolls, when neither

8 CCNMatthews - Sept. 3, 2003 “Oakville Refinery Operations to be Shut Down and Oakville Terminal Facility Expanded”. The refinery closure was effective April 11, 2005 (NCX-Enbridge-23(b)). 9 IOL-Enbridge 24.2(ii) and (iii). 10 NCX-Enbridge 5(a) & (b).


of those was changed in previous periods during the Extended Term, even

though all periods have similar circumstances.

Q17 Is there another matter that should cause caution to impose retrospective tolls

that change the scope and nature of costs to be recovered?

A17 Yes. In its March 17, 2006 letter to the Board seeking interim tolls for the Third

Interim Period, Enbridge stated it:

“…is preparing and intends to file a comprehensive tolls Application for the establishment of longer-term tolls to be effective for the period commencing April 1, 2006. Enbridge expects that Application to be filed during the second quarter of this year [2006].”

The Application was not filed until the second quarter of 2007, about one year

after Enbridge’s stated intention. While Enbridge undertook consultations with

shippers and others and negotiations with shippers, those cannot be used to

excuse the late filing of an application that fundamentally changes the scope and

nature of costs to be recovered in the business environment of the Third Interim

Period. Such changes destabilize the certainty of toll methodology shippers have

come to rely upon. If higher equity thickness and accelerated depreciation for the

Third Interim Period were high priorities for Enbridge, then the application

seeking approval of such changes should not have been delayed by a year and

occur over 12 months into the 18-month term of the Third Interim Period.

The point is that there was no known prohibition on Enbridge filing the application

and still negotiating a longer-term deal. An application in the second quarter of

2006 would have put shippers on notice that new uncertainty of the toll-setting

methodology was being sought by Enbridge applying for higher equity thickness

and accelerated depreciation for the Third Interim Period. Rather than taking that

course, Enbridge delayed filing the Application for a year and it now appears that

with failure of the negotiations Enbridge is using the Application to drag the Third

Interim Period out of the precedent and unchanged business environment

established in the FSA, and particularly the First and Second Interim Periods,

and putting it into the post-FSA business environment.


4. Generational Considerations and Equitable Tolls

Q18 What is the focus of this issue with respect to the Application?

A18 The focus of this issue is the acceleration of depreciation. The Application seeks

the acceleration to be effective April 1, 2006, which is the beginning of the Third

Interim Period. While the Application only deals with Test Periods covering the

last three quarters of 2006 and all of 2007, acceleration of depreciation is sought

for the period through to 2013.

Q19 What is the impact of the applied-for acceleration of depreciation?

A19 The impact is to increase the composite depreciation rate from 3.05% to

10.60%.11 The latter rate, when applied to the original plant in service, is

intended to fully amortize the assets currently in Line 9 service over 7.75 years

from April 1, 2006 to the end of 2013.

The financial impact is shown on Figure 1, which compares depreciation expense

under the accelerated rates applied for in the Application and under the existing

rates.

11 Application, Appendix A-4, paragraph 12, pages 4 and 5.


Figure 1

Line 9 Depreciation Expense at:Accelerated Rate and Existing Rate

-

4,000

8,000

12,000

16,000

20,000

24,000

2006 2007 2008 2009 2010 2011 2012 2013

000s

$ Accelerated

Existing

The 2006 values are for the 9-month test period ending December 31, 2006.

Over the 2006 to 2013 period, the cumulated depreciation expense is $130.1

million in the applied-for case and $28.4 million for the existing case, an increase

of $101.8 million.12

Q20 Is this the only financial impact of the Application?

A20 No. NOVA Chemicals requested Enbridge to provide financial forecasts for the

2006 to 2013 period under the applied-for case, with higher equity thickness and

accelerated deprecation and the existing equity thickness and depreciation

(NCX-Enbridge 24). Comparing the two cases, Enbridge forecasts no change in

the operating and maintenance costs of Line 9, the applied-for case has a lower

cumulative cost for return, an increase in cumulative income taxes, and the

above-referenced increase in cumulative depreciation expense. In total, the

applied-for case seeks cumulative revenue requirements of $413.4 million, or

$121.8 million higher than the $291.6 million that would occur under the existing

case over the 2006-2013 period.

12 Numbers may not add due to rounding.


Appendix B shows a comparison of plant and revenue requirements for the

Application case and the FSA case, which uses 45% equity thickness and

existing depreciation rates. The appendix also shows the difference in the two

cases for key financial streams

4.1 Inconsistency of Enbridge’s Positions on Life of Line 9 Assets

Q21 What is the role of depreciation in setting tolls?

A21 Depreciation is one of the costs included in the revenue requirements of a utility,

and tolls are set by applying billing determinants to revenue requirements. As a

result, when all else is equal, an increase in depreciation expense increases tolls.

There are many definitions of depreciation, but one referenced by a well-

recognized academic textbook dealing with utility rates is:

Depreciation accounting is a system of accounting which aims to distribute the cost or other basic value of tangible capital assets, less salvage (if any), over the estimated useful life of the unit (which may be a group of assets) in a systematic and rational manner. It is a process of allocation, not of valuation. Depreciation for the year is the portion of the total charge under such a system that is allocated to the year. Although the allocation may properly take into account occurrences during the year, it is not intended to be a measurement of the effect of all such occurrences.13

With respect to toll-setting and depreciation, the task is to allocate the “cost of

…tangible capital assets…” in a “…systematic and rational manner.”

Q22 Has Enbridge accomplished this task with its proposed depreciation expense for

toll-setting purposes on Line 9?

A22 No.

Q23 Why not?

A23 There are several reasons, which are discussed below.

13 Bonbright, James C.; Danielsen, Albert L.; Kamerschen, David R.; “Principles of Pubic Utility Rates”, Public Utilities Reports, Inc. 1988, page 273 reference to Committee on Terminology of the American Institute of Accounting (1953).


The first reason is that Enbridge has adopted an inconsistent view of the future of

Line 9 assets after 2013. On one hand it refuses to propose Terminal Negative

Salvage (“TNS”) for Line 9, which would be consistent with an expectation that

Line 9 should be fully depreciated by 2013 since it would have no economic life

after that date and should be abandoned. Enbridge’s refusal to propose TNS is

stated in plain terms:

Enbridge recognizes that, ultimately, there may be such a final abandonment of Line 9 assets; however, at this point Enbridge simply cannot reliably forecast the nature or the timing, or both, of such a final abandonment. Enbridge has not formulated, therefore, an abandonment strategy for the Line 9 assets.14

When asked if Line 9 assets could only be used in future westbound service,

Enbridge responded:

No. Enbridge believes that Line 9’s economic life in westbound service will expire by or during 2013. Enbridge also believes that portions of Line 9, and potentially the entire pipeline, could have economic use beyond its current use in westbound service.”15

When asked if it is Enbridge’s position that Montreal refiners would never make

long-term commitments for eastbound service on Line 9, Enbridge’s response

was “No.”16

On the other hand, notwithstanding Enbridge’s position that Line 9 should not be

abandoned in the foreseeable future, it asserts that Line 9 assets must be fully

depreciated over the period to 2013 since that is the forecast end of westbound

service, and generational equity requires that shippers taking westbound service

must pay for the assets in westbound service so as to avoid post-2013 shippers,

likely taking eastbound service in Enbridge’s view, from being charged for

depreciation expense of assets in westbound service. To use Enbridge’s words:

14 Application, Appendix A-10, paragraph 9, page 3 of 6. 15 NCX-Enbridge-5(a) & (b). 16 NCX-Enbridge-8.


Therefore, in order to preserve generational equity and fairness, [westbound] shippers should pay for the capital spent for their benefit and not burden either a future generation of shippers that may use the pipeline in a re-reversed mode or potentially leave the pipeline owners with a stranded asset that is not fully depreciated.17

and

…the “user-pay” principle …calls for the recovery of the capital costs of the original reversal of Line 9 by those shippers using westbound service. This principle is designed to ensure generational equity by placing the burden of recovery of capital costs on the westbound shippers and, if Line 9 is re-reversed, removing the burden from the eastbound shippers.18

Q24 What causes the inconsistency of these positions?

A24 The primary inconsistency arises because Enbridge confuses westbound service

and transportation service. It appears to do so by relying on the words “…in

current operation…”, which Enbridge emphasizes in a definition of depreciation it

puts forward.19 It appears Enbridge is equating “in current operation” with

westbound service and not taking a more systematic and rational view that the

current operation of Line 9 is providing a transportation service.

Like any pipeline, Line 9 should be depreciated over its economic or physical life

in transportation service, whether that service is westbound, eastbound, or both.

The economic life of a pipeline does not depend on flow in one direction or

another; rather, it depends on either its physical capability to provide

transportation service or a demand for transportation service. Enbridge’s own

view is that the prospects for both of those conditions are sufficiently high after

2013 that it has not turned its attention to and is not prepared to advance

abandonment of Line 9.

Contrary to Enbridge’s assertions, the principles of “user-pay” and generational

equity do not support acceleration of depreciation rates for the Test Periods.

This is because there is probable and potential use of Line 9 assets after

westbound service ends. Put simply, Enbridge’s applied-for depreciation

17 NEB-Enbridge-22, first paragraph. 18 IOL-Enbridge-14.4, page 23. 19 NEB-Enbridge-16.


treatment will cause westbound users to pay more than their share of

depreciation and permit future eastbound users to not pay depreciation at all on

Line 9 assets they use.

As shown in Figure 2, the original cost of Line 9 assets shows that at the time of

reversal, $58.5 million or 73% of the assets were for Line 9 pipe, pump and

maintenance stations on Line 9, and various Westover and Sarnia facilities.

Since then, an additional $43.8 million has been expended on these facilities, or

99% of the net additions. As a result, these facilities now comprise some 82% of

the total original cost of Line 9 assets.

Figure 2 Amounts and Shares of Line 9 Assets

Total TotalOriginal Total Transportation Original Total Transportation

Transportation Additions & Plant at Transportation Additions & Plant atPlant Retirements 31-Dec-07 Plant Retirements 31-Dec-07000s$ 000s$ 000s$

Line 9 Pipe 29,745 29,954 59,699 37.0% 67.5% 47.8%Pump & Maintenance Stations 13,758 8,939 22,697 17.1% 20.1% 18.2%North Westover to Westover Pipeline 533 - 533 0.7% 0.0% 0.4%Westover Terminal Connections 9,722 969 10,691 12.1% 2.2% 8.6%Sarnia Terminal Connections 4,781 3,959 8,740 5.9% 8.9% 7.0%Subtotal 58,539 43,821 102,360 72.7% 98.8% 82.0%Line 9C 10,429 - 10,429 13.0% 0.0% 8.4%Line 22 5,299 (42) 5,257 6.6% -0.1% 4.2%Clarkson Terminal 6,139 588 6,727 7.6% 1.3% 5.4%Line 12 86 - 86 0.1% 0.0% 0.1%Total 80,492 44,367 124,859 100.0% 100.0% 100.0%

Source: Attachment 1 to IOL-Enbridge 2.1 and 2.2

It is obvious that any eastbound service will require pipe and pumping facilities as

well as terminal facilities at Westover and Sarnia. Shippers that use those

facilities in west or east bound service should pay for them; that is what user pay

means. Yet Enbridge’s proposal is that only westbound shippers should pay for

the same facilities that will be used by eastbound shippers.

Q25 What is your next reason that shows Enbridge has not proposed toll-setting that

reflects a systematic and rational approach to depreciation?

A25 Another reason is Enbridge’s incomplete analysis of Line 9 assets. Instead of

detailing the assets to determine which are solely related to westbound service,


which are related to transportation service in westbound or eastbound service,

and which have no use in either westbound or eastbound service, Enbridge has

lumped them all into westbound service.

The problem with this approach is that there are capital assets that can be used

in eastbound transportation service; for example, costs associated with

capitalized pipeline integrity expenditures. Those expenditures provide integrity

of the Line 9 in transportation service, not only service in one direction. Thus,

with future transportation service post-2013 on Line 9, Enbridge’s applied-for

treatment of depreciation creates generational inequity and unfairness among

shippers by proposing to fully depreciate those assets over westbound shippers

during the period to 2013.

Simply put, Enbridge has failed to provide any analysis of the assets so as to

distinguish those that are solely in westbound service and would have no

economic life after westbound service ends, and those that would have economic

life after westbound service ends.

Q26 Is there an example that shows Enbridge has not proposed toll-setting that

reflects a systematic and rational approach to depreciation? If so, please

explain.

A26 There is an example. Suppose that Enbridge develops a configuration where

Line 9 is reversed from Sarnia to Westover and provides eastbound service at

volumes higher than can be shipped on the existing Line 7. The remainder of

Line 9 would continue in westbound service with oil transported on that portion of

Line 9 being transferred to Line 7, which is reversed and would deliver oil to the

Sarnia area.

If such a configuration were to be implemented, then according to Enbridge’s

view of the link between “in current operation” and depreciation life, presumably

the following events would occur: a) fully depreciate the portion of Line 9 from

Sarnia to Westover before eastbound service commences; b) maintain existing

depreciation for the portion of Line 9 in westbound service from Montreal to

Westover; and c) fully depreciate the portion of Line 7 that is reversed from


Westover to Sarnia. The effect would be to cause the existing shippers on Line 7

and on Line 9 between Sarnia and Westover to pay for all the capital assets over

the period those assets will provide service in their current direction so that future

shippers taking transportation service in the opposite direction would have no

burden of those costs. This is not “user-pay”. It is not generational equity. It is

not a systematic or rational result.

Q27 What do you say about Enbridge’s example of the Montreal Extension being fully

depreciated before it was converted to westbound service in 1999?

A27 When requested to provide regulatory examples of assets being fully depreciated

at a time when probable and potential uses are forecast beyond the depreciation

period, Enbridge’s response was to reference the Montreal Extension.20 This is

not useful because the Montreal Extension was built to satisfy government

energy policy and the terms of the financial arrangements, including revenue

backstopping by the Government of Canada, as well as the depreciation period,

do not represent standard commercial practices or terms. For example, the

original pipeline was depreciated over 20 years, when Enbridge acknowledges

pipeline assets normally have a longer life.

Q28 Can you provide a more useful example of other pipeline assets that have

changed service but have not been fully depreciated before that change?

A28 Yes. A recent example occurred when TransCanada PipeLines Limited

(“TransCanada”) applied to transfer a portion of Line 1 of its Mainline gas

transportation system from transporting gas to transporting oil,21 an obvious and

clear change in service. By Enbridge’s view of “in current operation” and

generational equity and fairness, gas shippers would apparently pay through tolls

to fully depreciate Line 1 assets before the transfer in order to avoid future oil

shippers paying for assets that were used to provide gas transportation service.

Q29 Is that what happened?

20 NEB-Enbridge-1.16(b). 21 TransCanada PipeLines Limited and TransCanada Keystone Pipeline GP Limited, “Transfer Application”, June 2006.


A29 No. TransCanada sought, and received conditional approval22 from the Board, to

transfer Line 1 assets in gas service to the proposed new oil pipeline at the

assets’ net book value at the time of transfer. In the result, assets previously

used in gas service would be used in oil service and the transfer value would be

paid through tolls of oil shippers after the assets enter oil transportation service

and not through tolls of gas shippers before the transfer.

In other words, TransCanada, and the Board, recognized that the economic life

of Line 1 assets extends beyond a particular service or a particular generation of

shippers to the broader context of the economic life of the assets operating in

transportation service.

Q30 Please summarize this portion of your evidence.

A30 The systematic and rational inclusion of depreciation in Line 9 tolls must reflect

the economic life of the assets in transportation service, not simply westbound

service. Enbridge states that there are probable and potential uses for the assets

to have economic life beyond its view of the end of westbound service. It relies

on this expectation of economic life of the assets to assert that no abandonment

plan for the assets is needed, yet it applies to have the assets fully depreciated

by 2013. As a result of the applied-for depreciation, those shippers that could

use the line after 2013 would have use of existing assets but not pay the

depreciation expense of those assets in their tolls and would not pay their share

of the assets’ depreciation. Stated differently, a future generation of shippers

after 2013 will benefit from excess depreciation being charged to a current

generation of shippers.

4.2 Weak and Incomplete Analysis

Q31 Returning to your conclusion that Enbridge relied on weak and incomplete

analysis, what is the basis for date 2013 as the end of westbound service on Line

9?

22 Reasons for Decision, MH-1-2006. The key condition is that the transfer is subject to the Board’s decision with respect to an application to construct and operate the Keystone oil pipeline project.


A31 The Muse report, which concludes “…that by 2013 the Ontario refiners will no

longer find the use of Line 9 economically attractive and, accordingly, the

remaining economic life of Line 9 in westbound service is approximately 7

years.”23

Q32 For the purposes of justifying increased tolls due to accelerated depreciation, are

there weaknesses and limitations in Muse’s analysis?

A32 Yes, there are several, such as:

(a) Muse focussed its evidence on assessments of costs of Brent crude oil

delivered to Montreal and Ontario refiners. While it did provide some

comments on west African crude oil, it did not account for supply from other

Atlantic sources of crude oil, even though they have increased their share of

Line 9 shipments24 and production of crude oils available to Atlantic markets

is forecast to increase.25 Muse attempted to refute the increased share and

supply of other crude oils by saying their transportation costs will be higher to

Portland than Brent transportation26, and therefore make these alternatives

less economic to Ontario refineries. This ignores the obvious fact that the

same higher transport costs will not only make those alternatives less

attractive to Ontario refineries but also to Montreal refineries. Moreover,

while Muse shows the distances from west Africa to Portland are about 5,000

nautical miles compared to 2,800 nautical miles from the North Sea, the

distance from other Atlantic sources, for example Algeria to Portland, is more

comparable to that from the North Sea.27 Further, and more to the point,

there is no analysis of the landed cost of crude oils available to Portland

which would show price variances for crude quality in addition to

transportation costs. All of this means that Muse’s analysis of other sources

of crude oil to Atlantic markets is weak and incomplete.

23 Muse Study, page 2. 24 IOL-Enbridge-25(20), Attachment 1. 25 IOL-Enbridge-25(2). 26 IOL-Enbridge-25(4). 27 Muse Study, Figure 4, page 9. The distances from Algiers, Algeria to Portland, Maine is less than 3,300 nautical miles. One nautical mile equals 1.85 km.


(b) With respect to Muse’s estimates of the “Brent Advantage”, when Muse was

asked to detail the increase in Portland and Montreal pipeline tolls in the

event that Line 9 volumes no longer flow on those pipelines, it indicated that

no such increase was made in it analysis.28 It is the evidence of NOVA

Chemicals that the toll levels have recently increased. It is also NOVA

Chemicals’ evidence that those tolls could rise significantly with the loss of

Line 9 volumes.29 Given that Muse estimates that the Brent Advantage at

Montreal has been US$0.88 per barrel30 without adjusting for increased tolls

and the loss of volume on the Portland and Montreal pipelines, it is a serious

analytical weakness not take account of these factors in assessing the long-

term outlook for Line 9.

Moreover, Muse shows in its report that the Brent Advantage at Montreal has

disappeared and become negative in recent periods during 2006 and up to

January 2007. When asked to update that information, Muse responded by

showing monthly details of the Brent Advantage at Montreal from January

1995 to May 2007.31 An examination of those data shows that until 2006

there were very few months of negative Brent advantage, and there had

never been more than two consecutive months of a negative Brent

advantage. In contrast, since December 2005 all but four months show

negative Brent advantage at Montreal.

(c) Muse was requested to explain its views as to why the change in Brent

advantage occurred and in so doing provide its views with respect to the fact

that prices for WTI, the present benchmark crude oil for North America, have

recently lost their historical premium to Brent. Muse stated that it has not

studied factors that explain the change in comparative daily cash prices at

Brent and WTI. On the face of it, it is difficult to rationalize not undertaking

such an analysis when the Brent Advantage at Montreal has turned negative,

and western Canadian crude oil is penetrating further south, even entering

28 NCX-Enbridge 15(b). 29 NOVA Chemicals Evidence, Appendix C. 30 Muse Report, page 22. 31 IOL-Enbridge-25(3), Attachment 4.


the Cushing market where WTI prices are established, as well as points

further south at the U.S. Gulf Coast.

(d) Muse states that as western Canadian crude oils penetrate further into new

markets, the parity pricing point moves further from western Canada and

results in lower netback price in western Canada.32 Muse noted that the

price parity point will vary by type of crude oil, but could not provide an

analysis that shows how the price parity points would shift as western

Canadian crude oil expands its market area in the timeframe through 2013.33

Moreover, Muse describes its understanding that recent pipeline shipments

of western Canadian crude oil to the U.S. Gulf Coast have been sour heavy

crude34, but when asked to show western Canadian netback prices for heavy

crude delivered to the U.S. Gulf Coast and to Montreal, Muse stated that it

had not undertaken such an analysis.35

(e) When Muse was requested to describe its views of the impact of incentives

for western Canadian crude oil to access the Spearhead pipeline to Cushing

and a reversed Mobil pipeline to the U.S Gulf Coast, Muse simply provided

reference to the Board and FERC websites. There is no discussion by Muse

of the role of transportation incentives to develop new markets for western

Canadian crude oil, including markets in Canada.

These weaknesses and limitations are inconsistent with due diligence that would

normally be expected to be undertaken to justify toll setting where the scope and

nature of costs included in tolls is materially changed, as it is in this case through

more equity thickness and accelerated depreciation that add a cumulative

increase in toll revenue of well over $100 million through 2013.

Q33 Is it only Muse’s evidence that is weak and incomplete?

A33 No. Enbridge’s own evidence is also weak and incomplete.

32 Muse Report, page 23. 33 NCX-Enbridge-18(e). 34 NCX-Enbridge-18(b). 35 NCX-Enbridge-18(f).


Q34 Please explain.

A34 The main difficulty is that Enbridge has not undertaken the analysis and

evaluation of Line 9 in future services necessary to justify fully depreciating Line

9 assets over the period to 2013. While Enbridge has a history of pursuing

initiatives, such as the Spearhead and reversed Mobil pipeline, to expand the

scope of markets for western Canadian crude oil transportation, it has done little

to assess the prospects for future Line 9 uses. There are several examples of

weak and incomplete analysis:

(a) Enbridge has no current cost estimates for re-reversing Line 9 to provide

eastbound service.36 In Decision OH-2-97, Enbridge stated it could re-reverse

Line 9 in 2 weeks under emergency conditions and six weeks under non-

emergency conditions. At the time, Enbridge stated that it would cost about $0.5

million to re-reverse line 9.37

(b) Enbridge is not able to provide cost estimates for expanding Line 7 to deliver

more western Canadian crude oil in southwest Ontario.38 While it has

considered a “swap” in direction of service for Lines 7 and 9 between Sarnia and

Westover, which would avoid expansion of Line 7 to supply higher eastbound

deliveries, it has not prepared any cost or toll impacts of this possibility.39

Enbridge excuses this omission by stating that it does not currently see Imperial’s

Nanticoke or United’s refineries requiring sufficient western Canadian crude oil to

cause new capacity.40 Yet, Enbridge, and Muse, state that neither has done any

kind of assessment of the specific refinery economics of using more western

Canadian crude oil.41

Further, these responses appear to be inconsistent with Enbridge’s statement

that:

36 NCX-Enbridge-1(a) to (c). 37 Reasons for Decision, OH-2-97, page 74. 38 IOL-Enbridge-11.2. 39 IOL-Enbridge-11.3 & 11.4. 40 IOL-Enbridge-11.6. 41 For example, for Enbridge see IOL-Enbridge-16.2 & 16.3, and for Muse see NCX-Enbridge-10.


Line 9 would be re-reversed from Sarnia Terminal to the North Westover Terminal and Line 7 would be shut down. It is the best overall configuration – considering capital and operating costs, tolls impacts and quality concerns – to replace Line 7 with a re-reversed Line 9 …” for onward transportation to supply Imperial’s Nanticoke refinery and United’s refinery.42 (emphasis added)

This lack of substantive analysis is difficult to rationalize given that both parties

assert that offshore crude oil supply for Ontario refineries will become

uneconomic over the period to 2013 and that the Canadian market for western

Canadian crude oil “…will likely expand in all directions.”43

(c) Enbridge has shown that it has an interest in expanding the market for western

Canadian crude oil. Its arrangements with respect to initiatives regarding

Spearhead and the reversed Mobil pipeline involve making payments to support

western Canadian crude oil transported on those systems. In the cases of

Spearhead and the Mobil line, the costs of incentives are charged to Enbridge’s

shippers. Enbridge has also proposed numerous pipeline projects to transport

western Canadian crude oil to new markets, including, in some cases, all-new

pipelines with their attendant expense and new rights of way.

Moreover, Enbridge recognizes that Line 9 has probable and potential future

uses. In part, this is almost certainly because the pipeline exists – it is a real

operating asset. With this background, it is curious that there is little or no

analysis and a virtual lack of initiatives to take advantage of Line 9’s existence to

develop its future use. All of which is to say that accelerating depreciation on

Line 9, with a cumulative cost of $102 million through 2013, is premature and not

warranted on basis of the evidence provided by Enbridge.

Q35 Please summarize this portion of your evidence.

A35 Enbridge has asked the Board to saddle westbound shippers with an incremental

$102 million in depreciation expense to accelerate capital recovery over the

period to 2013. In so doing it must provide evidence that the toll impacts of such

42 Application, Appendix A-10, paragraph 10, first bullet. 43 Application, Appendix A-4, paragraph 10, last bullet, page 4.


costs are justified not only in theory, which it has not done given the expected

future life of Line 9 assets after 2013, but also by robust analysis that

demonstrates thorough examination and reasonable conclusions.

Instead of such analysis and demonstration, Enbridge relies on Muse to establish

the 2013 date for the end of westbound service when Muse contains weak and

incomplete analysis that should not be relied upon to set the date of the end of

westbound service or the prospects for re-reversal and the commencement of

eastbound service. Moreover, Enbridge itself has not undertaken even the most

basic analysis of the costs to reconfigure its system in southwest Ontario to make

use of Line 9, as well as studies or initiatives to best to expand the market for

western Canadian crude oil in Ontario, Quebec or adjacent U.S. markets.

Instead, Enbridge appears to have resorted to seeking to pin the cost of fully

depreciating Line 9 on westbound shippers with the result that it will have

available to it a fully depreciated asset likely to be in future use after 2013, a

likelihood that it recognizes by not even contemplating abandonment of Line 9.

Q36 Does this conclude your evidence?

A36 Yes, at this time.


Appendix A

Curriculum Vitae

Gordon Engbloom

Confer Consulting Ltd.


Curriculum Vitae Name: Gordon M. Engbloom, P.Eng Education: M.A. (Economics) Queen’s University at Kingston, Ontario, 1976 B.Sc. in Chemical Engineering University of Alberta Edmonton, 1970 Professional Affiliations: Association of Professional Engineers, Geologists and Geophysicists of Alberta International Association for Energy Economics Length of Service with Current Employer: 30 years Gordon Engbloom has 33 years of energy sector experience, the last 30 years as sole consultant with his firm, Confer Consulting Ltd. (Confer). Mr. Engbloom has worked for a wide variety of clients, including natural gas aggregators; electric and natural gas utilities; crude oil, natural gas and natural gas liquids producers; independent power producers; regulatory agencies; and governments. Mr. Engbloom has appeared before regulatory boards and gas price arbitration panels as an expert witness. Consulting experience includes commercial analysis and strategy for sale, purchase, pricing and arbitration under natural gas contracts; advisor for natural gas pricing and royalty regimes; natural gas deregulation analysis, including issues regarding gas contracting and transportation access; electric energy deregulation, including issues of power pool structure and mitigation of market power; forecasts of natural gas prices; forecasts of total energy, natural gas and electric energy demand using end-use analysis within a top-down model of economic and demographic variables; and cost benefit and economic impact analyses of resource developments and natural gas exports. Confer has extensive experience in natural gas matters, including estimating natural gas supply and demand, deregulation, contracting, pricing and pipeline costs and tariffs. Mr. Engbloom has consulted with natural gas aggregators, producers, marketers, policy makers and pipeline and distribution utilities. Confer also has extensive experience in the electric energy matters, including analysis of market design and industry structure, deregulation, transmission access, generation procurement options and strategies, market demand and forecasts, independent power contracts and natural gas supply to electric generation plants. Mr. Engbloom has consulted with electric utilities, independent power producers, and government departments and agencies.


G. M. Engbloom Appearances Before Regulatory Boards

Alberta Energy Resources Conservation Board In a 1979 proceeding regarding an application to construct and operate a mining oil sands plant, jointly provided evidence of the project’s economic impact and net benefits. Client was Alsands Oil Sands Project. In a 1981 proceeding regarding future energy requirements for Alberta, provided evidence on long-term forecasts of Alberta economic activity and energy demand. Clients were the Electric Utility Planning Council, Canadian Western Natural Gas Company Limited and Northwestern Utilities Limited. In a 1981 proceeding regarding an application for industrial development permit to construct and operate an ethylene oxide/glycol plant, provided evidence of the project’s economic impact and net benefit. Client was Union Carbide Canada Limited. In proceedings during the mid-1980s up to October 1987 regarding applications for and an inquiry into the removal of ethane at field locations in Alberta, provided evidence of the economic impact and net benefits. Clients were various individual oil and gas producers for the applications and the Ethane Owners Group for the inquiry. In 1991 and 1993 proceedings regarding an application to convert a heavy oil pipeline to natural gas service, provided evidence on the net benefits. Client was Northwestern Utilities Limited. Ontario Energy Board In a 1981 proceeding regarding an application for flexible utility retail rates to serve large commercial and industrial consumers, provided evidence of the competitive fuel market at various locations within the utility’s service area. Client was Union Gas Limited. National Energy Board In a 1990 proceeding regarding applications to construct natural gas pipeline facilities and authorize natural gas exports, provided evidence of the net benefits of a proposed natural gas export. Client was Canadian Occidental Petroleum Ltd. In a 1995 proceeding regarding natural gas export applications, prepared evidence to address the Export Impact Assessment. The evidence was on behalf of several applicants. The evidence was filed, but no appearance at the hearing was necessary. In a 1997 proceeding regarding applications to develop Sable Island natural gas and construct and operate an interprovincial gas pipeline, provided evidence regarding economic pipeline toll design and regulations for export of Sable Island natural gas. Client was Nova Scotia Power Inc. In a 1998 proceeding regarding an application by Alliance Pipeline L.P. to construct and operate a natural gas pipeline system from northeast B.C. and northwest Alberta to Chicago, provided evidence regarding the role of competitive forces within a regulated


environment and specifically in respect of the Alliance Pipeline Project. The client was the applicant. In a 1999 proceeding regarding an application for a long-term licence to export natural gas from the Sable Island offshore field to the northeast U.S., provided evidence on the export impact assessment of the proposed exports. Clients were Boston Gas and Imperial Oil. In a 2003 proceeding regarding an application to construct and operate a high-pressure natural gas pipeline to Vancouver Island, provided evidence on gas supply, economic evaluation of alternatives, and tolls and tariffs. Client was the applicant, GSX Canada Limited Partnership (Canada). In a 2006 proceeding regarding a Section 74 application to transfer a gas pipeline to crude oil service, provided evidence on economic aspects of the public interest in approving the transfer. Client was TransCanada PipeLines Limited. In a proceeding that involved a hearing appearance in late 2006, provided evidence on the toll design and investment policy applied for by the Mackenzie Valley Pipeline. Client was the Yukon Government. British Columbia Utilities Commission In a 1991 proceeding (G-92-91) regarding utility gas cost recovery, provided evidence on gas commodity costs, gas price adjustments for load factor, interruptible gas supply and competitive pricing. Client was BC Gas Inc. In a 2003 proceeding regarding cost of service allocation and toll design for firm and interruptible service, provided evidence related to cost allocation factors, firm toll design, interruptible toll design, allocation of interruptible revenue, and recovery of cumulative revenue deficiency related to Centra Gas British Columbia. Client was BC Hydro, a transmission shipper on the pipeline. In a 2003 proceeding regarding an application to construct and operate a gas-fired electric generation plant on Vancouver Island, provided evidence in support of gas prices forecasts. Client was BC Hydro, the applicant. California Public Utilities Commission In a 1992 proceeding (A.91-04-003) regarding an application by Pacific Gas & Electric for a finding that costs arising from its gas and electric operations were reasonable during the period 1988 to 1990, including the costs of its purchases of Canadian natural gas, provided evidence of the market structure and price for natural gas in Canada. Client was the Independent Petroleum Association of Canada. Alberta Public Utilities Board In proceedings during 1993 and 1994 regarding Phase II applications by Canadian Western Natural Gas Company Limited and by Northwestern Utilities Limited, respectively, provided evidence on the role of competition and competitive pricing in the context of regulated utility service, including the extent of competition in the utilities’


marketplace. The evidence also quantified and compared the utilities’ transportation rates to the average and incremental operating costs for several industrial sectors. Clients were the applicants. Public Utilities Board of the Northwest Territories In a 1994 proceeding regarding the extent of regulation necessary to ensure fair and reasonable rates under competitive circumstances, provided evidence on competition in the western Canadian propane market and in the retail heating market in Hay River, NWT. Client was Stittco Utilities NWT Ltd., a propane distribution utility. Alberta Natural Resources Conservation Board In a 1994 proceeding regarding the importation of hazardous waste to Alberta from other Canadian jurisdictions, provided evidence on the economic benefit from importation. An existing hazardous waste treatment facility, partially owned by the government of Alberta, had excess treatment capacity and sought to increase capacity utilization and reduce subsidies by importation of waste from outside Alberta. Client was the facility owner. Alberta Energy and Utilities Board This Board, which was formed in early 1995, is the amalgamation the Alberta Energy Resources Conservation Board and the Alberta Public Utilities Board. In a 1995 proceeding regarding the Phase 1 of a General Rate Application by NOVA Gas Transmission Ltd. (NGTL), provided evidence on the use of Transportation by Others with respect to transportation to markets off NGTL for natural gas located behind the systems of gas distribution utilities in Alberta. Clients were the distribution utilities. In a 1996 proceeding regarding an application to extract natural gas liquids from a sidestream of NOVA Gas Transmission Ltd. at Strachan, provided evidence on a study of the benefits and costs of such extraction. Client was the applicant, Gulf Canada Resources Limited. In a 1997 proceeding regarding an applications to construct NGL pipeline facilities in northwest Alberta, provided evidence on the contestability of the market for new pipeline facilities and the ability of the Board to rely upon such competition. Client was Federated Pipe Lines Ltd., one of three applicants. In a 1999 proceeding regarding an application to introduce new products and pricing by NOVA Gas Transmission, provided evidence on the applied-for toll design and on an alternative toll design. Client was ATCO Gas. In a 2001 proceeding regarding the disposition of gas producing properties by a regulated gas distribution utility, provided evidence on the discount rate that should be employed to estimate the net present value of costs and benefits arising from the sale. Client was ATCO Gas. In a 2002 proceeding regarding investment policy and levels by a utility in customer-related facilities, provided evidence on a comparison of investment policies among


utilities, on the discount rate for calculating investment levels and on the overall investment policy issues. Client was ATCO Electric. In a 2003 proceeding regarding an application to process a gas stream on the NOVA Gas Transmission Ltd. System to extract natural gas liquids, provided evidence related to economic issues. Client was Solex Gas Processing Corp., the applicant. In a 2004 proceeding regarding a toll design application by NOVA Gas Transmission Ltd., provided evidence related to alternative cost allocation methods and toll designs for intra-Alberta gas deliveries. Client was ATCO Pipelines. In a 2005 proceeding regarding a toll design application by NOVA Gas Transmission Ltd., provided evidence related to alternative cost allocation methods and toll designs for intra-Alberta gas deliveries. Client was ATCO Pipelines. In a 2006 proceeding regarding the provision of retail gas services to core market customers, provided evidence with respect to customer balancing mechanisms in other jurisdiction and compared those with the Alberta market characteristics. Client with ATCO Gas.

Confer Consulting Ltd. - Client ListUtilities:Alberta Natural Gas Company Limited Centra Ontario Gas Inc. SaskEnergy LimitedATCO Gas and ATCO Pipelines Edmonton Power Stittco Utilities NWT LtdATCO Electric Enbridge Inc. The Yukon Electrical Company Ltd.Alliance Pipeline Ltd. GSX Canada Limited Partnership TransCanada PipeLines LimitedBC Gas Utility Ltd. New Brunswick Power TransAlta CorporationBC Hydro and Power Authority Nova Scotia Power Inc. Vector Pipeline LPBoston Gas Company Union Gas Limited

Oil and Gas Producers:Amerada Hess Corp. Dome Petroleum Limited Rigel Energy Ltd Anderson Exploration Ltd. Elan Energy Inc. Shell Canada LimitedAPL Oil & Gas Ltd. Imperial Oil Limited Sceptre Resources LimitedApache Corporation Gulf Canada Resources Limited Suncor Energy Inc.ATCOR Resources Limited Home Oil Company Limited Summit Resources LimitedBow Valley Energy Inc. Morrison Petroleums Ltd. Talisman Energy Inc.Canada Southern Petroleum Ltd. North Canadian Oils Limited Texaco Canada Petroleum Inc.Canadian Hunter Exploration Ltd. OMV (Canada) Inc. Unocal Canada Limited.Canadian Natural Resources Limited Paramount Resources Ltd. Wainoco Oil Corporation CanadaCanadian Occidental Petroleum Ltd. Penn West Petroleum Ltd. Westcoast Petroleum Ltd.Devon Canada Corporation Petro-Canada Inc.

Governments and Agencies Government of British Columbia, Energy Mines and Petroleum Resources Natural Gas Aggregators:Government of Alberta, Manpower and Training Alberta & Southern Gas Company Ltd.Government of Saskatchewan, Energy and Mines CanWest Gas Supply Inc.Government of Canada, Energy, Mines and Resources KannGaz Producers Ltd.Government of Yukon Pan-Alberta Ltd.Alberta Energy Resources Conservation Board ProGas LimitedLodgepole Well Blowout Inquiry TransCanada Gas Services LimitedGovernment of New Brunswick, Natural Resources and EnergyGovernment of Thailand, National Energy Policy Office

Others:Agrium Inc. Chem-Security (Alberta) Ltd. Independent Petroleum Association of CanadaAlberta Electric Utility Planning Council Chicken Farmers of Ontario Pacific GenerationAltamont Pipeline Study Group Direct Energy Marketing Limited Pacific International TerminalsATCO Power Emera Inc. Power Pool of AlbertaBalancing Pool of Alberta Enserco Energy Inc. Proprietary IndustriesBord Gais of Ireland Ethane Owners Group Solex Energy Inc.Brascan Corporation Mackenzie Explorers Group Tenaska Washington Partners II, L.P.Calgary Exhibition and Stampede Mitsui & Co. (Canada) Ltd. TransAlta Energy Inc.Canadian Gas Association Monenco AGRA Inc. Union Carbide Canada LimitedCanadian Market Opportunities Program National Energy Board Westmoreland CoalCanadian Utilities Limited NOVA Chemicals

Privileged and Confidential - Solicitor Client Privilege

Confer Consulting Ltd. Draft, July 18, 2007

35

5

Appendix B

Analysis of Revenue Requirements,

Plant, Depreciation and Rate Base 10

(from NCX-Enbridge-24)

Comparison of Application Case (52.5% equity and accelerated depreciation) and FSA Case (45% equity and existing depreciation rates)2006-13

2005 2006 2007 2008 2009 2010 2011 2012 2013 Cum000s$ 000s$ 000s$ 000s$ 000s$ 000s$ 000s$ 000s$ 000s$ 000s$

Application Case (NCX-Enbridge 24)Cost of ServiceO&M - Operating and Administrative 12,047 12,156 15,035 12,700 12,400 13,800 13,900 13,400 12,400 105,791 - Fuel & Power 2,968 2,151 2,590 1,900 1,800 1,600 1,900 1,400 - 13,341 - Property Tax 7,026 7,044 7,308 7,700 8,000 8,300 8,600 9,000 9,300 65,252 Subtotal 22,041 21,351 24,933 22,300 22,200 23,700 24,400 23,800 21,700 184,384

Amortization of Line 9 Deficiency 1,185 1,195 1,159 1,100 500 - - - - 3,954 Income Tax 2,340 5,631 5,705 6,091 6,256 6,167 6,629 7,634 9,413 53,526 Depreciation 3,016 10,940 12,206 14,531 15,313 16,095 17,808 20,582 25,402 130,142 Cost of Service (Calculated) 28,582 39,117 44,003 44,022 44,269 45,962 48,837 52,016 56,516 374,742

Return - Equity 3,674 3,925 3,815 3,735 3,294 2,802 2,265 1,574 613 22,023 - Debt 3,476 2,928 2,988 2,877 2,480 2,056 1,658 1,152 449 16,588 Subtotal 7,150 6,854 6,803 6,612 5,774 4,858 3,923 2,726 1,062 38,612

Revenue Requirement 35,732 45,971 50,806 50,634 50,043 50,820 52,760 54,742 57,578 413,354

FSA Case (NCX-Enbridge 24)Cost of ServiceO&M - Operating and Administrative 12,047 12,156 15,035 12,700 12,400 13,800 13,900 13,400 12,400 105,791 - Fuel & Power 2,968 2,151 2,590 1,900 1,800 1,600 1,900 1,400 - 13,341 - Property Tax 7,026 7,044 7,308 7,700 8,000 8,300 8,600 9,000 9,300 65,252 Subtotal 22,041 21,351 24,933 22,300 22,200 23,700 24,400 23,800 21,700 184,384

Amortization of Line 9 Deficiency 1,185 1,195 1,159 1,100 500 - - - - 3,954 Income Tax 2,340 1,092 968 960 1,207 1,301 1,339 1,515 1,611 9,993 Depreciation 3,016 2,879 3,173 3,445 3,553 3,635 3,767 3,922 4,000 28,374 Cost of Service (Calculated) 28,582 26,517 30,233 27,805 27,460 28,636 29,506 29,237 27,311 226,705

Return - Equity 3,674 3,484 3,671 3,999 4,092 4,196 4,279 4,312 4,264 32,297 - Debt 3,476 3,512 3,884 4,162 4,162 4,159 4,232 4,265 4,217 32,593 Subtotal 7,150 6,996 7,555 8,161 8,254 8,355 8,511 8,577 8,481 64,890

Revenue Requirement 35,732 33,513 37,788 35,966 35,714 36,991 38,017 37,814 35,792 291,595



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2006-132005 2006 2007 2008 2009 2010 2011 2012 2013 Cum

Application Case (NCX-Enbridge 24) 000s$ 000s$ 000s$ 000s$ 000s$ 000s$ 000s$ 000s$ 000s$ 000s$Gross Plant - Opening Balance 101,856 106,050 124,859 129,259 131,859 136,059 142,759 145,459 - Additions 4,194 18,884 4,400 2,600 4,200 6,700 2,700 3,200 46,878 - Retirements - (75) - - - - - - - Closing Balance 106,050 124,859 129,259 131,859 136,059 142,759 145,459 148,659

Accumulated Depreciation - Opening Balance 18,570 26,797 38,928 53,459 68,772 84,867 102,675 123,257 - Depreciation Expense 8,205 12,206 14,531 15,313 16,095 17,808 20,582 25,402 130,142 - Retirements 22 (75) - - - - - - (53) - Closing Balance 26,797 38,928 53,459 68,772 84,867 102,675 123,257 148,659

Net Plant 79,253 85,931 75,800 63,087 51,192 40,084 22,202 -

Average Net Plant (Calculated) 81,270 82,592 80,866 69,444 57,140 45,638 31,143 11,101

Average Net Plant (per ENB) 82,414 83,819 80,865 69,443 57,139 45,637 31,142 11,101

Working Capital Allowance 1,779 2,078 1,858 1,850 1,975 2,033 1,983 1,808

Rate Base 84,193 85,897 82,723 71,293 59,114 47,670 33,125 12,909

FSA Case (NCX-Enbridge 24)Gross Plant - Opening Balance 101,856 106,050 124,859 129,259 131,859 136,059 142,759 145,459 - Additions 4,194 18,884 4,400 2,600 4,200 6,700 2,700 3,200 46,878 - Retirements - (75) - - - - - - - Closing Balance 106,050 124,859 129,259 131,859 136,059 142,759 145,459 148,659

Accumulated Depreciation - Opening Balance 18,570 20,751 23,849 27,294 30,847 34,482 38,249 42,171 - Depreciation Expense 2,159 3,173 3,445 3,553 3,635 3,767 3,922 4,000 27,654 - Retirements 22 (75) - - - - - - (53) - Closing Balance 20,751 23,849 27,294 30,847 34,482 38,249 42,171 46,171

Net Plant 85,299 101,010 101,965 101,012 101,577 104,510 103,288 102,488

Average Net Plant (Calculated) 84,293 93,155 101,488 101,489 101,295 103,044 103,899 102,888

Average Net Plant (per ENB) 84,419 94,359 101,486 101,488 101,294 103,044 103,899 102,888

Working Capital Allowance 1,779 2,078 1,858 1,850 1,975 2,033 1,983 1,808

Rate Base 86,198 96,437 103,344 103,338 103,269 105,077 105,882 104,696



38

Comparison of Application Case (52.5% equity and accelerated depreciation) and FSA Case (45% equity and existing depreciation rates)2006-13

2006 2007 2008 2009 2010 2011 2012 2013 CumDifference: Application Case less FSA Case: 000s$ 000s$ 000s$ 000s$ 000s$ 000s$ 000s$ 000s$ 000s$O&M - - - - - - - - - Amortization of Line 9 Deficiency - - - - - - - - - Income Tax 4,539 4,737 5,131 5,049 4,866 5,290 6,119 7,802 43,533 Depreciation 8,061 9,033 11,086 11,760 12,460 14,041 16,660 21,402 101,768 Cost of Service (Calculated) 12,600 13,770 16,217 16,809 17,326 19,331 22,779 29,205 148,037

Return - - - - - - - - - - Equity 441 144 (264) (798) (1,394) (2,014) (2,738) (3,651) (10,274) - Debt (584) (896) (1,285) (1,682) (2,103) (2,574) (3,113) (3,768) (16,005) Subtotal (142) (752) (1,549) (2,480) (3,497) (4,588) (5,851) (7,419) (26,278)

Revenue Requirement 12,458 13,018 14,668 14,329 13,829 14,743 16,928 21,786 121,759

Documents

SOllClTORS 16W - Utilities Commission · BARRISTERS & SOllClTORS June 9,2008 ... expanding, mothballing, capital cost forecasts, etc ... Plateau Pipe Line Ltd. Information Request