National Energy Board
Hearing Order RH-1-2010
Enbridge Pipelines Inc.
Line 9 Application – Tolls and Tariff
Responses of Enbridge to
Information Requests of
Imperial Oil Limited
May 18, 2010
RH-1-2010 Responses of Enbridge to Imperial IRs Page 2 of 323
IOL-Enbridge 1
Reference: Written evidence of Enbridge (Adobe Number A1R0U9), Appendix A-1, page 9, paragraph 21.
Preamble: Enbridge refers to the reversal project and indicates that modifications would need to be completed if Line 9B and Line 9A were to be re- reversed to provide eastbound service.
Requests: (a) Provide details, including expected locations, of the modifications referred to and the current estimate of the cost of those modifications and the expected year that they would be incurred.
(b) How quickly could Line 9 be re-reversed? That is, how long would a Line 9 re-reversal project take?
Responses: (a) Enbridge Pipelines considered the possibility of re-reversing Line 9 in the context of the Eastern Access/Trailbreaker Project.1 Based on the parameters of that Project, Enbridge would expect that re-reversing Line 9 would entail, at a minimum, the following facility modifications or additions:
(i) installation, relocation or re-configuration of pumping units at Sarnia Terminal to inject into Line 9;
(ii) piping modifications at Sarnia Terminal associated with (i) above;
(iii) piping changes at each Line 9 station to re-configure the suction/discharge lines for the reversed flow operation;
(iv) piping reconfigurations at Montreal Terminal to permit the reversed flow operation;
(v) SCADA and control system changes to permit the reversed flow operation; and
(vi) terminal reconfiguration to allow access to all tanks, if required.
If the assumptions regarding crude slate, flow rate, delivery location, and other variables are not the same as those used for the Eastern Access/Trailbreaker Project, then the foregoing facilities
1 See Prologue to response to NOVA Chemicals 1.2. RH-1-2010 Responses of Enbridge to Imperial IRs Page 3 of 323
would have to be revised accordingly. See Attachment 9 to NOVA Chemicals 1.2(b) for information respecting the estimated costs of the Eastern Access/Trailbreaker Project.
(b) The time required to bring a re-reversed Line 9 into service would depend upon many factors including requirements related to crude slate, flow rate, delivery location and other variables. It would also depend upon securing sufficient shipper support and, thereafter, the time required to complete related modifications to upstream or downstream facilities in addition to factors such as: long lead item procurement; land acquisitions; environmental and regulatory applications; power infrastructure requirements; and construction timelines. A typical timeframe for such projects, after securing sufficient shipper support, would be at least 18 months. It could be possible to complete a re-reversal in less time in a crisis situation.
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IOL-Enbridge 2
Reference: Written evidence of Enbridge (Adobe Number A1R0U9), Appendix A-1, pages 13 to 14, paragraphs 33 to 38.
Written evidence of Enbridge (Adobe Number A1R0W5), Statements C-2.1.9 and C-2.5
Preamble: Enbridge refers to $1.974 million of deferred regulatory costs with respect to the RH-2-2007 proceeding.
Requests: (a) Provide a detailed explanation of the regulatory principles, and citations to NEB or other regulatory authority, relied upon to recover 2007 costs from future customers over a five year period and explain why they should not have been collected from 2007 customers.
Response: (a) Enbridge is not relying on regulatory principles to justify its proposal to recover, as an administrative expense, the cost of the regulatory costs over a five-year period commencing on January 1, 2008. The rationale for the proposal is provided in paragraph 35 of Appendix A-1.
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IOL-Enbridge 3
Reference: Written evidence of Enbridge (Adobe Number A1R0U9), Appendix A-1, page 15, paragraphs 39 to 42.
Written evidence of Enbridge (Adobe Number A1R0V0), Appendix A-2, page 3, paragraph 9.
Preamble: Enbridge refers to operating Line 9 in a Start-Stop fashion and the risks and the changes to the integrity and maintenance programs.
Requests: (a) Provide a detailed explanation of changes to the integrity and maintenance programs as a result of the stop-start operation of Line 9 together with cost of such programs by year.
(b) Provide details of the “increased mechanical maintenance” and indicate the estimated cost by year.
(c) Indicate the nature and the expected cost of the “post-2010 integrity programs”.
(d) Please confirm that pipeline integrity and maintenance programs are directed at maintaining the integrity of a pipeline for both current pipeline operation and future pipeline operation. If not confirmed, why not?
Responses: (a) Though Line 9 has experienced some level of stop-start operation since the line was put into east-west operation in 1999, average daily throughputs until 2005 generally allowed for continuous flow. During the period from 2005 to date, Line 9 has been subject to more significant levels of start-stop operation.
Line 9 integrity data for the period of 1999 to 2005 identified medium to high stress levels on the pipeline due to required pumping pressures. While the pressure cycling frequency was not high, the severity resulting from start-stop occurrences suggested the potential for crack growth. As a result, a crack inspection program was initiated in 2004.
The crack tool inspection runs identified a number of crack indications along Line 9. Follow-up digs were performed to allow for evaluation of the indications and rehabilitation and mitigation work.
Stop-start operation also increases the potential for internal RH-1-2010 Responses of Enbridge to Imperial IRs Page 6 of 323
corrosion due to water and sediment settling in the pipeline. This may give rise to a requirement for additional cleaning tool runs in future. See response to IOL-Enbridge 3(b).
See Attachments 1 and 2 to NOVA Chemicals 1.25(a).
(b) The low flow rates that Line 9 has been experiencing for the past number of years have required the mechanical equipment to operate below its most efficient flow rate in an effort to maximize the periods of continuous flow. This prolonged operation at less than ideal conditions has increased the maintenance requirements for pumps and other equipment. The maintenance costs for mechanical equipment have been summarized in the table below. These costs are included in the costs shown on line 4 of Statement C-1.2.
Mechanical Maintenance Costs ($000) 2007 2008 2009 2010 140 146 249 349
(c) The information requested is not relevant to any of 2008, 2009 or 2010 tolls. Enbridge therefore objects to filing the information requested and declines to so.
(d) The pipeline integrity and maintenance programs are directed at maintaining the integrity of Line 9 for both current and future pipeline operation.
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IOL-Enbridge 4
Reference: Written evidence of Enbridge (Adobe Number A1R0V0), Appendix A-2, pages 2 to 3, paragraphs 5 to 7.
Preamble: Enbridge refers to Consultations.
Requests: (a) Please provide the materials used in the slide presentation referred to in paragraphs 6 and 7.
(b) Please provide the information distributed to stakeholders on November 16, 2009 and referred to in paragraph 6.
Responses: (a) See Attachment 1 to IOL-Enbridge 4(a).
(b) See Attachment 1 to IOL-Enbridge 4(b).
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IOL-Enbridge 5
Reference: Written evidence of Enbridge (Adobe Number A1R0V1), Appendix A-3, page 9, paragraph 28.
Written evidence of Enbridge (Adobe Number A1R0V4), Appendix A-6, pages 2 to 8.
Preamble: Enbridge refers to risk of not recovering its revenue requirement and its revenue requirement is no longer guaranteed.
Requests: (a) If the NEB approves all of the deferral accounts and toll adjustment mechanisms it has requested, please explain what risks Enbridge will incur with respect to the recovery of Line 9 test period revenue requirements.
Response: (a) The proposed deferral accounts would mitigate the risk of variances between forecast and actual revenue requirements for Enbridge only to the extent that oil losses, throughput and costs for regulatory proceedings contribute to such variances. However, neither the deferral accounts nor the toll adjustment mechanism address the risk of Line 9 becoming idle, in which case Enbridge would not recover its revenue requirement.
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IOL-Enbridge 6
Reference: Written evidence of Enbridge (Adobe Number A1R0V8), Appendix A-8, pages 2 to 4, paragraphs 1 to 7.
Preamble: Enbridge seeks exemption from recording its system of accounts according to the OPUAR and from compiling with Guide P and BB of the Board’s Filing Manual.
Requests: (a) Confirm that with respect to Line 9, Enbridge can provide details and balances for each of the applicable accounts in the OPUAR if requested by the Board or intervenors.
(b) If not, explain why the exemption should be granted.
Responses: (a) Confirmed.
The Board’s final report of the financial regulatory audit referenced at page 2 of Appendix A-8 can be found at the following link:
https://www.neb-one.gc.ca/ll- eng/livelink.exe?func=ll&objId=587117&objAction=browse
(b) Not applicable.
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IOL-Enbridge 7
Reference: Written evidence of Enbridge (Adobe Number A1R0V8), Appendix A-8, page 3, paragraph 4.
Written evidence of Enbridge (Adobe Number A1R0Y0), Filing Manual Guide P.
Written evidence of Enbridge (Adobe Number A1R0W4), Statement C-1.
Preamble: Enbridge has sought exemption from and has not filed some of the details required in the Filing Manual Guide P.
Requests: (a) For each deferral account and for each year including 2007 to 2010 “provide schedules showing the derivation and monthly accumulation of the deferral account balances and the calculation of any carrying charges, indicating which amounts are actual and which are estimated.”
Response: (a) Final 2008 and 2009 tolls will be based on actuals (plus the return of, and on, capital resulting from the proposals in the Application) and therefore there are no variances upon which to calculate carrying charges for those years. As 2010 variances, if any, have yet to be determined, the information requested in respect of 2010 cannot be provided.
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IOL-Enbridge 8
Reference: Written evidence of Enbridge (Adobe Number A1R0V8), Appendix A-8, page 3, paragraph 4.
Written evidence of Enbridge (Adobe Number A1R0Y0), Filing Manual Guide P.
Written evidence of Enbridge (Adobe Number A1R0W4), Statement C-1 and Statement C-1.2, line 8,
Written evidence of Enbridge (Adobe Number A1R0W5), Statement C- 2.1.4.
Preamble: Enbridge has sought exemption from and has not filed some of the details required in the Filing Manual Guide P.
Requests: (a) For each year including 2007 to 2010 for salaries and wages (Statement C-1.2 line 8), “provide cost schedules for the base, current and test years, with explanations of changes from year to year, detailing the following:
(i) general salary increases;
(ii) merit increases;
(iii) promotions and progressions;
(iv) management incentive compensation;
(v) severance payments;
(vi) staffing levels (full time equivalents, if appropriate);
(vii) any allocation methodology; and
(viii) other relevant factors.
Support the cost schedules with schedules showing the number of permanent and temporary employees (or full time equivalents) for each period.
To the extent that any amounts have been capitalized to arrive at the net salaries and wages shown as expense provide the amounts capitalized and indicate to which accounts the salaries and wages have been capitalized and the amount, if any, of benefits, RH-1-2010 Responses of Enbridge to Imperial IRs Page 12 of 323
overheads or other uplifts or burdens that may have been applied to the salaries and wages for purposes of determining the amount capitalized and together with the basis of determining the benefits, overheads or other uplifts or burdens.
Response: (a) (i)-(v) Line 8 on Statement C-1.2 reflects 19 employees (including, for example, one employee who is eligible for management compensation and one former employee to whom severance was paid). Therefore, to maintain confidentiality, Enbridge objects to filing the information requested and declines to do so.
(vi) See Attachment 1 to NOVA Chemicals 1.24(b) for an explanation of the changes from year to year.
(vii) There are no allocations reflected in Statement C-1.2 line 8 (Statement C-2.1.4).
(viii) There are no other factors. There are no capitalized charges included in salaries and wages as shown in Statement C-2.1.4. The amounts provided are not net of capitalized charges.
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IOL-Enbridge 9
Reference: Written evidence of Enbridge (Adobe Number A1R0V8), Appendix A-8, page 3, paragraph 4.
Written evidence of Enbridge (Adobe Number A1R0Y0), Filing Manual Guide P.
Written evidence of Enbridge (Adobe Number A1R0W4), Statement C-1, Statements C-1.1 and C-1.2.
Written evidence of Enbridge (Adobe Number A1R0W5), Statement C- 2.1.5.
Preamble: Enbridge has sought exemption from and has not filed some of the details required in the Filing Manual Guide P. The Filing Manual under Guidance indicates “Where contracted services are either from or to an affiliate, provide the details of the transactions, including evidence that the cost of the contracted services is reasonable.”
Requests: (a) For each amount for each year 2007 to 2010 shown on statement C-1.2 and on C-1.1 other than line 2, provide:
(i) the amounts charged to or included in the Line 9 cost of service from an affiliate or Enbridge Pipeline Inc.(“EPI”);
(ii) the manner of determining the charge, such as time sheets, from an affiliate or EPI;
(iii) the amount of the burden included and the method of determining that burden; and
(iv) why the affiliate was used as compared to an arms-length third party.
Response: (a) For Statement C-1.1:
With one exception, no amounts are charged to Enbridge by an affiliate or by Enbridge Pipelines. The deferred regulatory costs include a burden amount that is applied to the labour costs. Refer to the item labelled “D” in Attachment 1 to NOVA Chemicals 1.27(a) for further detail on the internal labour charges. Refer to section (iii) under “For Statement C-1.2” below for an explanation of the method of determining the burden amount. RH-1-2010 Responses of Enbridge to Imperial IRs Page 14 of 323
For Statement C-1.2:
(i) All affiliate and allocated charges are captured in Lines 10 and 16 of Statement C-1.2. See Attachment 1 to IOL- Enbridge 9(a) for detail on affiliate charges within Support Services and to the items labeled “F” and “G” in Attachment 1 to NOVA Chemicals 1.27(a) for further detail on affiliate charges within Regulatory Costs.
(ii) See Attachment 1 to IOL-Enbridge 9(a).
(iii) See Attachment 1 to IOL-Enbridge 9(a) for the amount of the burden and the response to IOL- Enbridge 22(a) for the method of determining the burden. (iv) It is more economic to use Enbridge Pipelines’ resources than a third party due to economies of scale. In addition, Enbridge Pipelines’ employees may be able to provide better expertise than an arms-length third party.
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IOL-Enbridge 10
Reference: Written evidence of Enbridge (Adobe Number A1R0V8), Appendix A-8, page 4, paragraph 7.
Preamble: Enbridge seeks exemption from Filing Manual Guide BB
Requests: (a) Please confirm that the exemption for the Older System was part of the negotiation of the Older System tolls.
(b) Please explain why in Enbridge’s view throughput and payroll statistics are not useful information to allow the Board and other parties to monitor the results of Enbridge.
Responses: (a) Shipper support for the exemption for the Older System from the Guide BB filing requirements was an element of the 2005 ITS and 2010 ITS.
(b) The request item does not accurately reflect the view of Enbridge. See paragraphs 5 through 7 of Appendix A-8.
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IOL-Enbridge 11
Reference: Written evidence of Enbridge (Adobe Number A1R0V9), Statement B-1.3.1, pages 6 to 9; Statement B-1.4, page 10.
Preamble: Enbridge has provided debt costs for each of the years 2007 to 2010.
Requests: (a) For each year 2007 to 2010 provide details, including the issues, on how Enbridge determined the cost rate for debt attributed to Line 9. (b) For 2007 through 2009 indicate the specific debt issues used in determining cost rate for debt with reference to the EPI consolidated financial statements. Responses: (a) See response to NEB 1.38 for information respecting 2007.
The rates and specific debt issues used for 2008 and 2009 are identified in the response to IOL-Enbridge 11(b).
(b) The specific debt issues used to determine Enbridge Pipelines’ Weighted Average Cost of Term Debt are summarized below. The last issue in the table is the one from which $45 million was assigned to Enbridge (in that regard see response to NEB 1.38).
Year End Year End 2008 2009 $200 million Debenture Series K @ 8.2% - issued 200.0 200.0 December 22, 1993; Maturing February 15, 2024 $65 million MTN @ 6.05% - Issued February 12, 65.0 65.0 1999; Maturing February 12, 2029 $109.6 million MTN @ 6.50% - Issued June 11, 109.6 109.6 1999; Maturing June 11, 2029 $300 million MTN @ 6.62% - Issued November 19, 300.0 300.0 2008; Maturing November 18, 2018 $300 million MTN @ 4.49% - Issued November 10, - 300.0 2009; Maturing November 12, 2019 1 $100 million MTN @ 6.35% - Issued November 17, 100.0 100.0 1998; Maturing November 17, 2023 $50 million MTN @ 6.55% - Issued November 17, 50.0 50.0 1997; Maturing November 17, 2027 $200 million MTN @ 5.35% - Issued November 10, - 200.0 2009; Maturing November 10, 2039 1 $150 million MTN @ 5.08% - Issued December 21, 150.0 150.0 2006; Maturing December 19, 2036 $250 million MTN @ 4.46% - Issued December 16, 250.0 250.0 2005; Maturing December 17, 2012 $100 million MTN @ 6.85% - Issued October 26, 100.0 - 1999; Maturing October 29, 2009 1 1 Included in the calculation for the proportionate period outstanding RH-1-2010 Responses of Enbridge to Imperial IRs Page 17 of 323
IOL-Enbridge 12
Reference: Written evidence of Enbridge (Adobe Number A1R0W0), Statements B- 2.1, B.2.2, B-2.3 and B-2.4.
Written evidence of Enbridge (Adobe Number A1R0W2), Statement B- 4.1.
Written evidence of Enbridge (Adobe Number A1R0W3), Statements B- 5.1, B-5.2, B-5.3 and B-5.4.
Preamble: Enbridge provides some information regarding the income tax allowance however, further information is required.
Requests: (a) For each year 2007 to 2010 shown on statement B-4.1 provide the derivation of the income tax rate and indicate if it is EPI’s income tax rate or a stand-alone rate for Line 9.
(b) On Statement B-4.1 a deduction is taken for AIDC Capitalized, however, it is not apparent from the Adjustments for AFUDC capitalized on Statements B-5.1, B-5.2, B-5.3 and B-5.4, how the AIDC is determined. For each of 2007 to 2010 provide the calculation of the AIDC capitalized deduction on Statement B- 4.1, line 10 and reconcile those amounts to the AFUDC capitalized on Statements B-5.1, B-5.2, B-5.3 and B-5.4.
(c) On Statement B-4.1 a deduction is taken for Capitalized General & Administrative Expenses, however, it is not apparent from the Adjustments for G&A Capitalized on Statements B-5.1, B-5.2, B- 5.3 and B-5.4, how the Capitalized General & Administrative Expenses deduction is determined. For each of 2007 to 2010 provide the calculation of the Capitalized General & Administrative Expenses deduction on Statement B-4.1, line 18 and reconcile those amount to the G&A Capitalized on Statements B-5.1, B-5.2, B-5.3 and B-5.4.
(d) Please reconcile the additions per Statements B-2.1, B.2.2, B-2.3 and B-2.4 to the additions on the CCA schedules Statements B- 5.1, B-5.2, B-5.3 and B-5.4.
(e) Please provide a detailed explanation and the calculations of the amounts shown as book to tax file adjustment shown on Statement B-4.1, line 16. RH-1-2010 Responses of Enbridge to Imperial IRs Page 18 of 323
Responses: (a) The income tax rate shown on Statement B-4.1 is based on Enbridge Pipelines’ income tax rate. See Attachment 1 to IOL- Enbridge 12(a).
(b) The capitalized AIDC amount taken as a deduction on statement B-4.1 for each year consists of AIDC incurred, not AIDC transferred to completed plant. Therefore the comparison to Statements B-5.1, B-5.2, B-5.3 and B-5.4 is not relevant. See Attachment 1 to IOL-Enbridge 12(b).
(c) The deduction taken for capital General and Administrative Expenses on statement B-4.1 for each year is the product of a calculated percentage applied to incurred capital project labour and burden. The calculated percentage is determined each year to reflect the amount of deductible costs charged to capital projects through internal labour and burdens. Therefore it is not comparable to Statements B-5.1, B-5.2, B-5.3 and B-5.4.
(d) See Attachment 1 to IOL-Enbridge 12(d).
(e) 2008: The book to tax file adjustment of $30,000 (grossed up to $43,000 on line 16) relates primarily to a CCA adjustment between the year-end provision and the tax return. The remaining amount relates to a tax rate adjustment to true up the provision rate to the actual tax rate. Enbridge Pipelines received updated information on the salary and pipeline allocation per province after closing the financial records for 2007 but prior to filing the 2007 tax return.
2009: The book to tax file adjustment of ($810,000) relates to the reversal of a regulatory deferred credit for $1.8 million in a prior year which was reversed in 2008. As the establishment of the deferral was not taxable, neither is the reversal of the deferral in 2008. However, while the regulatory deferred credit was reversed the corresponding tax entry was not made. The appropriate tax entry is recorded with the 2009 book to tax filing.
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IOL-Enbridge 13
Reference: Written evidence of Enbridge (Adobe Number A1R0W0), Explanatory B- 2 and Statements B-2.1, B.2.2, B-2.3 and B-2.4.
Preamble: Enbridge has provided an analysis of Project Components to be transferred from Construction Work in Progress to Completed Plant.
Requests: (a) For each year and each month in 2008 to 2010 provide details on how Enbridge calculated the amounts shown for each of AFUDC Incurred and AFUDC Transfers to Completed Plant.
(b) For each year and each month in 2008 to 2010 provide details on how Enbridge calculated the amounts shown for each of G&A Incurred and G&A Transfers to Completed Plant.
(c) For 2007 provide a statement equivalent to B-2.9 and provide:
(i) how Enbridge calculated the amounts shown for each of AFUDC Incurred and AFUDC Transfers to Completed Plant; and
(ii) how Enbridge calculated the amounts shown for each of G&A Incurred and G&A Transfers to Completed Plant.
Responses: (a) Enbridge applies the AFUDC rates to capital projects not yet in service at the end of each month. The AFUDC rates are applied to a project’s Construction Work in Progress (CWIP) balance – adjusted for project accruals and hold-backs – at each month end. Effective as at the in-service date of a capital project, AFUDC is no longer charged to the project and the accumulated AFUDC, along with the other project costs, is transferred to completed plant See Attachment 1 to IOL-Enbridge 13(a).
(b) Each month the accounting system applies the General and Administrative (G&A) burden to all project labour charges, both operating and capital. The operating project costs are charged as appropriate each month. G&A charged to capital projects accumulates in CWIP and is transferred to completed plant upon the completion of the project. See Attachment 1 to IOL-Enbridge 13(b).
(c) See responses to IOL-Enbridge 13(a) and 13(b). See Attachment 1 to IOL-Enbridge 13(c). RH-1-2010 Responses of Enbridge to Imperial IRs Page 20 of 323
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Reference: Written evidence of Enbridge (Adobe Number A1R0W4), Statement C- 1.2.
Written evidence of Enbridge (Adobe Number A1R0W5), Statements C- 2.1.1 to C-2.1.9.
Preamble: Enbridge has provided some explanations of the costs and variances however further information is required to understand the estimates.
Requests: (a) For each year 2007 to 2010 provide further details on the Repairs and Maintenance (C-2.1.1) indicating the amount of:
(i) each recurring costs and a description of those costs; and
(ii) each periodic cost including those listed indicating when they were last incurred and why they are necessary in the year forecast in this application.
(b) For each year 2007 to 2010 provide further details on Internal Inspections (C-2.1.2) including the internal inspection plans, the cost of each of corrosion and crack inspections, the location(s) and pipelines to be inspected.
(c) For each year 2007 to 2010 provide further details on Outside Services (C-2.1.3) and in particular the reason for the use of more consultants for these internal inspections in some years than others, their costs, and details on any other consultant costs included in the amounts shown.
(d) For each year 2007 to 2010 provide further details on salaries and wages (C-2.1.4) and, to the extent not provided above, indicate:
(i) the increase in the number of full time equivalents and the justification for them in light of declining throughputs; and
(ii) the number of full time equivalents for each of the activities listed and if there are additional activities those activities and the number of full time equivalents.
(e) For each year 2007 to 2010 provide further details on Support Services (C-2.1.5) indicating each of the services provided, the cost each year and the reason for the increase showing separately inflationary impacts and other impacts and an explanation of those RH-1-2010 Responses of Enbridge to Imperial IRs Page 21 of 323
impacts.
(f) On statement C-2.1.5 Enbridge refers to its operating budgets. Please provide the 2009 and 2010 operating budgets referred to.
(g) For each year 2007 to 2010 provide further details on Capital Taxes (C-2.1.6) including the capital on which each of the Capital Taxes are calculated and the rates used and the allocation showing both the Line 9 kilometres and the total kilometres.
(h) For each year 2007 to 2010 provide the manner in which Enbridge determined its estimate of the NEB Cost Recovery Charges (C- 2.1.7) including the total estimated for EPI and the method and units used to determine the Line 9 allocation.
(i) For each year 2007 to 2010 provide further information on Oil losses (C-2.1.8) indicating the detailed calculations for:
(i) physical oil loss/(gain);
(ii) degradation Oil Loss;
(iii) evaluation Oil loss/(gain); and
(iv) where historical information is used provide the details of those percentages and how they were calculated.
Responses: (a) See response to NOVA Chemicals 1.22(b).
(b) See response to NOVA Chemicals 1.25(c). In order to respect the confidentiality of the pricing arrangements for in-line inspections, Enbridge objects to filing additional details relating to the costs of internal inspections that are shown on Statement C-2.1.2 and declines to do so.
(c) Not all of the outside service costs reported on Statement C-2.1.3 relate to in-line inspections. In 2007, $101,000 of the reported $321,000 related to in-line inspections. $40,000 relates to a contractor back-filling for an employee on long-term disability. The remaining cost in 2007, and the outside service costs, in years 2008 through 2010, relate to other Line 9 operations. Enbridge utilizes outside contractors for each year in which there are inspections, but in years other than 2007 these outside service costs were charged to the in-line inspection account.
(d) See response to NOVA Chemicals 1.24(b) and (c). RH-1-2010 Responses of Enbridge to Imperial IRs Page 22 of 323
(e) See response to NOVA Chemicals 1.23.
(f) Enbridge did not refer to operating budgets in Statement C-2.1.5.
(g) See Attachment 1 to IOL-Enbridge 14(g).
(h) See Attachment 1 to IOL-Enbridge 14(h).
(i) See Attachment 1 to IOL-Enbridge 14(i).
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IOL-Enbridge 15
Reference: Written evidence of Enbridge (Adobe Number A1R0W6), D-1.
Written evidence of Enbridge (Adobe Number A1R0W7), D-2.
Written evidence of Enbridge (Adobe Number A1R0W8), D-3.
Preamble: Enbridge has provided EPI financial statements for 2007 and 2008 and the 2008 MD&A.
Requests: (a) Please provide the 2009 consolidated financial statements of EPI and the 2009 MD&A or confirm that the versions on SEDAR are part of this record.
Response: (a) The 2009 consolidated financial statements and 2009 Management Discussion & Analysis of Enbridge Pipelines that are available on SEDAR are part of the record of this proceeding.
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Reference: Written evidence of Enbridge (Adobe Number A1R0V4), Appendix A-6, pages 4 to 5, paragraphs 12 to 13
Written evidence of Enbridge (Adobe Number A1R0W5), Statements C- 2.1.9 and C-2.5.
Preamble: Enbridge has provided detail in the Appendix on types of regulatory costs and the Statement provides amounts by year.
Requests: (a) For each of the years 2008 to 2010 please provide the amounts forecast for each of the bullet items on pages 4 and 5 of Appendix A-6, paragraphs 12 to 13.
(b) For each of the years 2008 to 2010 provide the calculations that results in the carrying charges shown on line 3 of Statement C-2.5.
Responses: (a) For the information requested in reference to paragraph 12 of Appendix A-6, see Attachment 1 to NOVA Chemicals 1.27(a).
Enbridge does not break down nor track costs in a manner that would enable it to provide the information requested in reference to paragraph 13 of Appendix A-6. Enbridge therefore declines to do so.
(b) The interest on the unamortized balance of Deferred Regulatory Costs is calculated using the weighted average cost of debt of Enbridge Pipelines for the year multiplied by 0.75 and applied to the average monthly balance of unamortized Deferred Regulatory Costs. The following tables show these calculations for 2008, 2009 and 2010.
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2008 Interest Net days Deferred Open Closing Deferred in Regulatory Accum Accum Reg. mth Costs Amort Amort Amort Costs Rate Interest 1,974,071 0.75 January 2008 31 1,974,071 - 32,901 32,901 1,941,170 6.749% 8,416 February 29 1,974,071 32,901 32,901 65,802 1,908,269 6.749% 7,741 March 31 1,974,071 65,802 32,901 98,704 1,875,368 6.749% 8,133 April 30 1,974,071 98,704 32,901 131,605 1,842,466 6.749% 7,734 May 31 1,974,071 131,605 32,901 164,506 1,809,565 6.749% 7,850 June 30 1,974,071 164,506 32,901 197,407 1,776,664 6.749% 7,460 July 31 1,974,071 197,407 32,901 230,308 1,743,763 6.749% 7,567 August 31 1,974,071 230,308 32,901 263,209 1,710,862 6.749% 7,426 September 30 1,974,071 263,209 32,901 296,111 1,677,960 6.749% 7,049 October 31 1,974,071 296,111 32,901 329,012 1,645,059 6.749% 7,143 November 30 1,974,071 329,012 32,901 361,913 1,612,158 6.749% 6,776 December 31 1,974,071 361,913 32,901 394,814 1,579,257 6.749% 6,860
394,814 395 90,155
Total Amort & Interest 484,969
2009 Interest Net days Deferred Open Closing Deferred in Regulatory Accum Accum Reg. mth Costs Amort Amort Amort Costs Rate Interest 1,579,257 0.75 January 2009 31 1,579,257 - 2,901 32,901 1,546,356 6.591% 6,561 February 28 1,579,257 32,901 32,901 65,802 1,513,455 6.591% 5,802 March 31 1,579,257 5,802 32,901 98,704 1,480,553 6.591% 6,285 April 30 1,579,257 98,704 32,901 31,605 1,447,652 6.591% 5,949 May 31 1,579,257 131,605 32,901 64,506 1,414,751 6.591% 6,009 June 30 1,579,257 164,506 32,901 97,407 1,381,850 6.591% 5,681 July 31 1,579,257 197,407 32,901 30,308 1,348,949 6.591% 5,732 August 31 1,579,257 230,308 32,901 63,209 1,316,047 6.591% 5,594 September 30 1,579,257 263,209 32,901 96,111 1,283,146 6.591% 5,280 October 31 1,579,257 296,111 32,901 29,012 1,250,245 6.591% 5,318 November 30 1,579,257 329,012 32,901 61,913 1,217,344 6.591% 5,013 December 31 1,579,257 361,913 32,901 94,814 1,184,443 6.591% 5,042
394,814 395 68,266
Total Amort & Interest 463,080
RH-1-2010 Responses of Enbridge to Imperial IRs Page 26 of 323
2010 Interest Net days Deferred Open Closing Deferred in Regulatory Accum Accum Reg. mth Costs Amort Amort Amort Costs Rate Interest 1,184,443 0.75 January 2010 31 1,184,443 - 32,901 32,901 1,151,542 6.176% 4,595 February 28 1,184,443 32,901 32,901 65,802 1,118,640 6.176% 4,033 March 31 1,184,443 65,802 32,901 98,704 1,085,739 6.176% 4,336 April 30 1,184,443 98,704 32,901 131,605 1,052,838 6.176% 4,071 May 31 1,184,443 131,605 32,901 164,506 1,019,937 6.176% 4,077 June 30 1,184,443 164,506 32,901 197,407 987,036 6.176% 3,820 July 31 1,184,443 197,407 32,901 230,308 954,135 6.176% 3,818 August 31 1,184,443 230,308 32,901 263,209 921,233 6.176% 3,689 September 30 1,184,443 263,209 32,901 296,111 888,332 6.176% 3,445 October 31 1,184,443 296,111 32,901 329,012 855,431 6.176% 3,430 November 30 1,184,443 329,012 32,901 361,913 822,530 6.176% 3,194 December 31 1,184,443 361,913 32,901 394,814 789,629 6.176% 3,171
394,814 395 45,679
Total Amort & Interest 440,493
RH-1-2010 Responses of Enbridge to Imperial IRs Page 27 of 323
IOL-Enbridge 17
Reference: Written evidence of Enbridge (Adobe Number A1R0W5), Statement C-2.2.
Preamble: Enbridge has provided summary information on fuel and power costs.
Requests: (a) Please provide for each of the years 2007 to 2010 by each pump station the estimated power to be used by that station in each year and the costs estimated for that consumption. If there is a two or three part rate provide details of the calculated costs for each station based upon the multi-part rate, if applicable.
Response: (a) Power consumption and costs are detailed by station below. 2007, 2008 and 2009 values are actual. 2010 values are estimated. The information provided below does not precisely match to that provided in Statement C-2.2. The values in Statement C-2.2 are annual power costs as reported in the General Ledger and reflect billing delays and monthly accrual reconciliation.
Detailed rate information is publically available on the following websites:
• Bluewater Power - http://www.bluewaterpower.com/ • Hydro One - http://www.hydroone.com/ • Independent Electricity System Operator - http://www.ieso.ca/ • Hydro Quebec - http://www.hydroquebec.com/
Power Cost North Sarnia Hilton Cardinal Clarkson Terrebonne Montreal Total Westover 2007 $249,087 $217,287 $539,959 $400,507 $25,136 $621,205 $209,611 $2,262,792 2008 $202,807 $168,407 $379,159 $291,656 $3,319 $606,056 $201,016 $1,852,420 2009 $122,735 $83,733 $292,579 $258,616 $901 $371,527 $167,951 $1,298,042 2010 $124,499 $93,857 $325,376 $286,987 $0 $284,405 $149,875 $1,264,999
Energy Consumption (MWh) North Sarnia Hilton Cardinal Clarkson Terrebonne Montreal Total Westover
2007 2,985 3,035 7,559 5,609 113 8,602 2,743 30,646 2008 2,437 2,302 5,196 4,047 0 7,536 2,367 23,885 2009 1,383 1,042 3,613 3,187 0 3,158 1,664 14,047 2010 1,383 1,043 3,615 3,189 0 3,160 1,665 14,055
RH-1-2010 Responses of Enbridge to Imperial IRs Page 28 of 323
IOL-Enbridge 18
Reference: Written evidence of Enbridge (Adobe Number A1R0W5), Statement C- 2.3.
Preamble: Enbridge has provided amounts for property taxes in each of the years 2007 to 2010.
Requests: (a) For 2007 provide the actual assessed values by municipality and/or province and the mill rates charged.
(b) For each of the years 2008 to 2010 please provide by municipality and/or province the assessed values used, the basis of the inflation factor, if any, assumed and the mill rate and the basis for forecasting that rate.
Responses: (a) See Attachment 1 to IOL-Enbridge 18(a).
(b) See Attachment 1 to IOL-Enbridge 18(b).
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IOL-Enbridge 19
Reference: Written evidence of Enbridge (Adobe Number A1R0W4), Statement C-1.
Preamble: The 2009 test period is indicated to be a combination of estimated and actual costs.
Requests: (a) Provide 2009 actual amounts.
Response: (a) See response to NOVA Chemicals 1.21(a).
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IOL-Enbridge 20
Reference: Written evidence of Enbridge (Adobe Number A1R0V8), Appendix A-8, pages 2 to 4, paragraphs 1 to 7.
Preamble: Enbridge seeks exemption from recording its system of accounts according to the OPUAR and from compiling with Guide P of the Board’s Filing Manual.
Requests: (a) Please confirm that prior to the applied for test years (2008, 2009 and 2010) that Line 9 tolls were subject to a settlement that was approved by the NEB. If not confirmed, why not?
(b) Please confirm that Enbridge is a Group 1 pipeline company as defined by the NEB and that Line 9 is not regulated on a complaint basis. If not confirmed, why not?
(c) Please confirm that Enbridge has not applied for Group 2 status for Line 9. If not confirmed, why not?
(d) Please confirm that Enbridge has not reached a negotiated settlement with Line 9 shippers with respect to the applied for test years. If not confirmed, why not?
(e) Please confirm that the application seeks a cost of service toll for Line 9. If not confirmed, why not?
(f) Please confirm that Guide P requires all Group 1 pipeline companies: not regulated on complaint basis; not subject to a negotiated settlement with its interested parties; and that is regulated on a cost of service basis to comply with certain filing requirements. If not confirmed, why not?
(g) Please confirm the date and the NEB proceeding in which all aspects of revenue requirement on Line 9 in westbound service, were fully litigated (i.e. not subject to any form of settlement) and tested before the NEB.
(h) Please confirm the date and the NEB proceeding in which all aspects of revenue requirement on Line 9 in eastbound service, were fully litigated (i.e. not subject to any form of settlement) and tested before the NEB.
Responses: (a) Confirmed. RH-1-2010 Responses of Enbridge to Imperial IRs Page 31 of 323
(b) Enbridge Pipelines is a Group 1 company as defined by the Board. Group 1 or Group 2 status applies to legal entities, rather than physical assets such as Line 9.
(c) The Application speaks for itself.
(d) Notwithstanding numerous attempts to reach a settlement that would be satisfactory to all shippers, Enbridge has not reached a negotiated settlement with Line 9 shippers concerning 2008, 2009 or 2010.
(e) Not confirmed. The proposed tolls for 2008, 2009 and 2010 are intended to afford Enbridge with a reasonable opportunity to recover its revenue requirement.
(f) Confirmed. However, Guide P provides that the level of detail will generally vary with the complexity of issues and the degree of change from previously approved applications.
(g) Board proceeding OH-2-97.
(h) Board proceeding RH-2-91.
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IOL-Enbridge 21
Reference: Written evidence of Enbridge (Adobe Number A1R0V8), Appendix A-8, pages 2 to 4, paragraphs 1 to 7.
Preamble: Enbridge seeks exemption from recording its system of accounts according to the OPUAR and from compiling with Guide P of the Board’s Filing Manual.
Requests: (a) Enbridge states that the grounds for its request for an exemption from complying with Guide P are, in part, “that the Line 9 shippers are familiar with the format of Enbridge’s supporting material.” Is Enbridge willing to comply with the filing requirements of Guide P if requested to do so by Line 9 shippers?
(b) If the response to request (a) is affirmative, please provide revenue requirement and tolling information in the form prescribed in Guide P.
(c) If the response to request (a) is negative, please explain why Enbridge will not provide the information requested by Line 9 shippers.
Responses: (a) No. Enbridge would continue to seek exemption from complying with the requirements of Guide P as Enbridge believes that it has, in all material respects, complied with the Guide P requirements. Enbridge would view the incremental work as excessive in the context of Line 9. Little value would be added for the incremental cost involved.
(b) See response to IOL-Enbridge 21(a).
(c) See response to IOL-Enbridge 21(a).
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IOL-Enbridge 22
Reference: Written evidence of Enbridge (Adobe Number A1R0W4), Statement C-1, page 1, paragraphs 1 to 3.
Preamble: Enbridge states that “[t]o the extent that Enbridge utilizes other resources of Enbridge Pipelines, Enbridge is charged a fully burdened cost for the service using appropriate allocation factors.”
Requests: (a) Please define “fully burdened cost”.
(b) Please confirm the “allocation factors” used by Enbridge and provide a detailed explanation of how they have been applied to allocate costs incurred by Enbridge Pipelines to Line 9.
(c) For each Line No. in Statement C-1.2 that contains a cost that was determined using an allocation factor, please provide an accounting of what the total Enbridge Pipelines’ cost was, how it was allocated to Line 9, and the amount that was ultimately allocated to Line 9.
(d) Please confirm that those costs incurred by Enbridge Pipelines and allocated to Line 9 on the basis of the allocation factors were allocated “at cost” and not inflated or marked-up. If not confirmed, please explain.
Responses: (a) A fully-burdened cost has two components. Neither component includes a mark-up for profit or return on investment.
One component is comprised of all direct employee costs at a department level. Enbridge Pipelines uses departmental charge- out rates to allocate costs when an employee does work for others outside of her/his department; for example, work for a capital or operating project or for a business unit such as Enbridge (i.e., Line 9). These rates recover the employee’s salary, training, travel, supplies, etc.
The other component is the General and Administrative (G&A) burden. It is applied to the departmental charge-out rates for time- sheeted capital and operating projects and fixed fee allocations. This component is held in a separate pool of costs and is comprised of items benefitting the entire organization. The G&A burden pool includes:
- Employee benefits (including incentive compensation) RH-1-2010 Responses of Enbridge to Imperial IRs Page 34 of 323
- Corporate rent and office services - IT network, telecom, desktop and mail support services - Enbridge Pipelines executive and related administrative costs - Enbridge Inc. support costs
(b) See Attachment 1 to NOVA Chemicals 1.23(a).
(c) See Attachment 1 to NOVA Chemicals 1.23(a).
(d) Confirmed. See response to IOL-Enbridge 22(a).
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IOL-Enbridge 23
Reference: Written evidence of Enbridge (Adobe Number A1R0U9), Appendix A-1, page 2, paragraphs 1 to 4 and footnote 1.
Preamble: In footnote 1 Enbridge refers to Line 7 and states that the portion downstream of Westover was deactivated in 2005.
Requests: (a) Indicate whether the portion of Line 7 downstream of Westover is included in the rate base for Line 9 in this application.
(b) If the cost is included in the rate base for Line 9 in this application please provide for each of the test years and for 2007:
(i) the gross plant;
(ii) the accumulated depreciation;
(iii) the average plant in service;
(iv) the depreciation recorded;
(v) the operating costs associated with maintaining the line in a deactivated state; and
(vi) any other costs such as property or capital taxes of maintaining the line in a deactivated state.
Responses: (a) See paragraph 6 and footnote 6 of Appendix A-1.
(b) (i)-(iv) See Attachment 1 to IOL-Enbridge 23(b).
(v) Enbridge does not break down nor track costs in a manner or at a level of detail that would enable it to provide the information requested and therefore declines to do so.
(vi) Property tax costs are: $42,798 for 2007, $43,568 for 2008 and $44,124 for 2009. Enbridge does not break down nor track other costs, such as capital taxes, in a manner or at a level of detail that would enable it to provide the information requested and therefore declines to do so.
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IOL-Enbridge 24
Reference: Written evidence of Enbridge (Adobe Number A1R0W0), Statements B- 2.1, B-2.4, B-2.7, B-2.10, B-2.15, B-2.16, B-2.17, and B-2.18.
Preamble: In the above references Enbridge provides some information on rate base additions.
Requests: (a) With respect to the amounts for the pipeline repair program, for each year indicate the location of the repair and the number of kilometres repaired or forecast to be repaired.
(b) Please indicate for each of the costs (AFEs) listed in each of Statements B-2.15, B-2.16, B-2.17, and B-2.18 which of the lines (prime accounts) of Column (e) on Statements B-2.1, B-2.4, B-2.7, B-2.10 the costs that have been recorded, if allocations have been made provide details indicating the amounts to each account/line and the basis for such allocation.
(c) In each of B-2.1, B-2.4, B-2.7, and B-2.10 amounts are shown as additions to buildings, please indicate for each year which building(s) have been added to, indicating the location and the primary work done.
(d) On B-2.15 it is indicated that a purchase was made from Quebec Hydro. Please provide the nature of the purchase, the rights acquired and the purpose for the acquisition of these rights.
Responses: (a) See response to NOVA Chemicals 1.25(c). The work at the 142 locations referenced in that response breakdown, by year, as follows:
2007: 35 locations 2008: 42 locations 2009: 65 locations
Significant time and effort would be required in order to provide the highly detailed information requested. Enbridge therefore objects to filing the information and declines to do so.
(b) See Attachment 1 IOL-Enbridge 24(b). Internal labour charged to capital projects is burdened with a G&A charge to allow for a fully burdened cost to be charged for each hour of Enbridge Pipelines labour. The G&A burden reflects overhead costs such as benefits, Human Resources, Information Technology, etc. Enbridge RH-1-2010 Responses of Enbridge to Imperial IRs Page 37 of 323
Pipelines’ Fixed Asset system does not allow for the extraction of this information as requested.
(c) The costs recorded in the Prime Account Buildings include costs of: buildings; leasehold improvements; roads and parking; and fences. See Attachment 1 to IOL-Enbridge 24(c) for the information requested. A materiality threshold of $100,000 per project has been applied.
(d) An easement was obtained from Hydro Quebec for the original construction of Line 9. That easement was five feet wide and was contained within a 100 foot wide parcel of land owned by Hydro Quebec on which it maintained electric transmission facilities. By 2007 Hydro Quebec had removed its facilities and was selling the property. Given those circumstances, Enbridge considered it necessary to obtain an additional (i.e., wider) easement in order to ensure adequate access and working space for maintenance and protection from third party damage. Hydro Quebec refused to grant the additional easement. In the circumstances, Enbridge determined that the best course of action was to purchase the entire parcel of land from Hydro Quebec.
RH-1-2010 Responses of Enbridge to Imperial IRs Page 38 of 323
IOL-Enbridge 25
Reference: Written evidence of Enbridge (Adobe Number A1R0V7), Appendix A- 7.3, pages 5, 6 and 8.
2006 Technical Update to the 1999 Depreciation Study; 2003 Technical Update to the 1999 Depreciation Study; 1999 Enbridge Depreciation Study.
Preamble: In the reference, Gannett Fleming, Inc. refers to various technical updates.
Imperial wishes to understand Appendix A-7.3 and Enbridge's current approach to depreciation in the context of the historical approach to depreciation on the Enbridge system. For purposes of this information request, “Enbridge” is intended to include “Interprovincial Pipelines” if the time frame of the information sought so requires.
Requests: (a) Please provide an electronic copy or a paper copy, if an electronic copy is not available, of all work papers used or created to prepare the depreciation study provided by Gannett Fleming in the Enbridge application dated December 9, 2009 as Appendix A-7.3. (b) Please provide an electronic copy of the model or models used to prepare the depreciation study provided by Gannett Fleming in the Enbridge application dated December 9, 2009 as Appendix A-7.3. If unable to comply with this request, please: (i) provide a full and detailed explanation of how all numbers in Tables 1A and 1B and pages 14 through 37 of Appendix A-7.3 were calculated; (ii) provide model runs providing the same information that Gannet Fleming reported in Table 1A and pages 14 through 23 of Appendix A-7.3 for assumed truncation dates 31 December 2030, 31 December 2035, and 31 December 2039; (iii) provide model runs providing the same information that Gannet Fleming reported in Table 1B and pages 24 through 37 of Appendix A-7.3 for assumed truncation dates of 31 December 2035 and 31 December 2039; and (iv) provide model runs providing the same information that Gannet Fleming reported in Tables 1A and 1B and pages 14 through 37 of Appendix A-7.3 for assumed truncation dates of 31 December 2030, 31 December 2035, and 31 RH-1-2010 Responses of Enbridge to Imperial IRs Page 39 of 323
December 2039 with all Line 9 assets aggregated into a single category (i.e., with the “Original Reversal Costs” combined with the “Bi-Directional Costs”). (c) Please provide an electronic copy or paper copy, if an electronic copy is not available, of all work papers and models used to prepare the depreciation study filed on 10 November 2006 by Enbridge that is titled "2006 Technical Update to the 1999 Depreciation Study that excludes Line 9 Assets." (d) Please provide an electronic copy or a paper copy, if an electronic copy is not available, of all work papers and models used to prepare the depreciation study filed on 24 November 2003 by Enbridge that is titled “2003 Technical Update to the 1999 Depreciation Study.” (e) Please provide an electronic copy or a paper copy, if an electronic copy is not available, of the depreciation study and all the associated work papers and models used to prepare the 1999 Enbridge depreciation study that was updated by Enbridge and is the basis for the 24 November 2003 filing that is titled “2003 Technical Update to the 1999 Depreciation Study.” (f) Please provide an electronic copy or a paper copy, if an electronic copy is not available, of all information requests to Enbridge since 1 January 2005 on the subject of depreciation and the response that Enbridge provided to these information requests. (g) For all depreciation studies for pipelines that transport crude oil or petroleum products filed by Enbridge with the National Energy Board or any other regulatory body, please provide a list of the depreciation studies filed since 1 January 2005 including the Hearing Order or Board file number, the date filed, and the title of the filed study.
(h) Please provide an electronic copy or a paper copy, if an electronic copy is not available, of all depreciation studies and associated testimony (e.g., reports and exhibits) since 1 January 2005 for pipelines that transport crude oil or petroleum products filed by Enbridge with the National Energy Board or any other regulatory body, and the associated underlying work papers and models.
Responses: (a) Appendix A-7.3 calculates the annual depreciation accrual rate for the Original Reversal Costs and the Bi-Directional Costs based on the average service life and net salvage percentages as used for the Older System assets and as originally developed in the 1999 Depreciation Study for Enbridge Pipelines. As such, there are no detailed working papers to support the average service life and net RH-1-2010 Responses of Enbridge to Imperial IRs Page 40 of 323
salvage percentage parameters. The depreciation rates are calculated in the detailed depreciation calculations as presented at pages 10 though 33 of Appendix A-7.3 and are based on the aged account balances for the Line 9 assets as at March 31, 2007. No further work papers exist in support of the calculations.
(b) (i) The values in Tables 1A and 1B are derived, in a summary format, from the values in the tables on pages 14 through 37 of Appendix A-7.3. The following explains how such tables were constructed:
• Year - This is the year in which a capital asset was placed in service. • Original Cost - This is the original cost of the asset net of the value of retired assets from the same vintage. • Calculated Accrued - This is the value of accumulated depreciation of the asset category, based on its vintage, original cost, Iowa curve for that asset category, and truncation date. • Allocated Book Reserve - This is the value of the accumulated depreciation recorded for the vintage of the asset category. • Future Book Accruals - This is the value of the depreciation expense to be recorded in future periods; namely, the difference between original cost, adjusted for any salvage value, and Allocated Book Reserve. • Remaining Life - This is average remaining life of each vintage to the truncation date recognizing the fact that some plant will retire between the date of study (April 1, 2006) and the truncation date. • Annual Accrual - This is the amount of the Future Book Accruals to be recognized in each period of Remaining Life; namely, the dividend of the Future Book Accruals and Remaining Life.
(ii) See Attachment 1 to IOL-Enbridge 25(b)(ii) for the results of the December 31, 2030 case.
See Attachment 2 to IOL-Enbridge 25(b)(ii) for the results of the December 31, 2035 case.
See Attachment 3 to IOL-Enbridge 25(b)(ii) for the results of the December 31, 2039 case.
(iii) See Attachment 1 to IOL-Enbridge 25(b)(iii) for the results RH-1-2010 Responses of Enbridge to Imperial IRs Page 41 of 323
of the December 31, 2035 case.
See Attachment 2 to IOL-Enbridge 25(b)(iii) for the results of the December 31, 2039 case.
(iv) See Attachment 1 to IOL-Enbridge 25(b)(iv) for the results of the December 31, 2030 aggregated case.
See Attachment 2 to IOL-Enbridge 25(b)(iv) for the results of the December 31, 2035 aggregated case.
See Attachment 3 to IOL-Enbridge 25(b)(iv) for the results of the December 31, 2039 aggregated case.
(c) See response to IOL-Enbridge 20(2) in the RH-2-2007 proceeding (Board filing receipt number A15918), which can be located at the following link; however, only the response to IOL-Enbridge 20(2) is part of the record of this proceeding: https://www.neb-one.gc.ca/ll- eng/livelink.exe?func=ll&objId=469039&objAction=browse.
(d) See response to IOL-Enbridge 20(3) in the RH-2-2007 proceeding (Board filing receipt number A15918), which can be located at the following link; however, only the response to IOL-Enbridge 20(3) is part of the record of this proceeding: https://www.neb-one.gc.ca/ll- eng/livelink.exe?func=ll&objId=469039&objAction=browse.
(e) See response to IOL-Enbridge 20(4) in the RH-2-2007 proceeding (Board filing receipt number A15918), which can be located at the following link; however, only the response to IOL-Enbridge 20(4) is part of the record of this proceeding: https://www.neb-one.gc.ca/ll- eng/livelink.exe?func=ll&objId=469039&objAction=browse.
(f) Since January 1, 2005, Enbridge Pipelines has responded to the following information requests on the subject of depreciation:
(i) RH-2-2007 Board Information Requests 1.15 and 1.16 (Board filing receipt number A15916);
(ii) RH-2-2007 NOVA Chemicals Information Requests 2, 3, 5, 20, 22, 23, 24(a), 27, and 30 (A15956);
(iii) RH-2-2007 Imperial Information Requests 5.3, 5.5, 7, 14.3, 14.4, 14.5, 20, 21, 22, 34, 40, 63, 71, 78, 81 and 94 RH-1-2010 Responses of Enbridge to Imperial IRs Page 42 of 323
(A15918);
(iv) RH-2-2007 Imperial Supplemental Information Request 1 (A16068);
(v) RH-2-2007 CAPLA and OPLA Information Requests 1, 2(1), 2(2), 6, 11, 17 and 18 (A16079);
(vi) RH-2-2008 Board Information Request 1.10 (A20164); and
(vii) RH-2-2008 Board Information Request 2.2 (A20633).
The responses referred to above can be located at the following link; however, only the responses on the subject of depreciation as specifically referred to above are part of the record for this proceeding: https://www.neb-one.gc.ca/ll-eng/livelink.exe.
(g) Since January 1, 2005, Enbridge Pipelines has filed the following depreciation studies with the Board:
(i) November 10, 2006 – Technical Update to the 1999 Depreciation Study (File OF-Tolls-Group1-E101-2006-06 01) (Board filing receipt number A13997);
(ii) April 11, 2007 – Line 9 Assets (RH-2-2007) (A0Y4Y4); and
(iii) March 31, 2010 – Technical Update to the 1999 Depreciation Study (File OF-Tolls-Group1-E101-2010-04 01) (A1S4A5).
These documents can be located at the following link: https://www.neb-one.gc.ca/ll-eng/livelink.exe.
(h) See responses to IOL-Enbridge 25 (a) through (g).
Gannett Fleming has declined to provide Enbridge with a copy− either electronic or paper − of the requested models for filing with the Board on the ground that the requested models are proprietary in nature and, as a result, the disclosure of them could reasonably be expected to prejudice Gannett Fleming's competitive position. As a result, Enbridge is not able to provide the models.
RH-1-2010 Responses of Enbridge to Imperial IRs Page 43 of 323
IOL-Enbridge 26
Reference: Written evidence of Enbridge (Adobe Number A1R0V7), Appendix A- 7.3.
Preamble: Imperial wishes to understand Appendix A-7.3 and Gannett Fleming's current approach to depreciation in the context of Gannett Fleming's approach to depreciation in other situations involving pipeline assets.
Requests: (a) For all depreciation studies prepared by Gannett Fleming on behalf of pipelines that transport crude oil or petroleum products that were filed with the National Energy Board or any other regulatory body, please provide a list of all depreciation studies filed including the Hearing Order or Board file number, the date filed, and the title of the filed study.
(b) Please provide an electronic copy or a paper copy, if an electronic copy is not available, of all depreciation studies and associated testimony (e.g., reports and exhibits) prepared by Gannett Fleming on behalf of pipelines that transport crude oil or petroleum products that were filed since 1 January 2005 with the National Energy Board or any other regulatory body, and the associated underlying work papers and models.
(c) For the witness who is sponsoring the deprecation study on behalf of Enbridge in this proceeding, for all depreciation studies and testimony regarding depreciation prepared by the witness on behalf of pipelines that transport crude oil or petroleum products that were filed with the National Energy Board or any other regulatory body, please provide a list of the depreciation studies and testimony filed including the Hearing Order or Board file number, the date filed, and the title of the filed study.
(d) For the witness who is sponsoring the deprecation study on behalf of Enbridge in this proceeding, please provide an electronic copy or a paper copy, if an electronic copy is not available, of all depreciation studies and testimony regarding depreciation prepared by the witness on behalf of pipelines that transport crude oil or petroleum products that were filed since 1 January 2005 with the National Energy Board or any other regulatory body, and the associated underlying work papers and models.
(e) Please provide an electronic copy or a paper copy, if an electronic copy is not available, of the 2010 report titled Technical Update to the 1999 Depreciation Study that was prepared by Gannet Fleming RH-1-2010 Responses of Enbridge to Imperial IRs Page 44 of 323
and of all the associated work papers and models used to prepare this study.
Responses: (a) See response to IOL-Enbridge 21(1) in the RH-2-2007 proceeding (Board filing receipt number A15918), which can be located at the following link; however, only the response to IOL-Enbridge 21(1) is part of the record of this proceeding: https://www.neb-one.gc.ca/ll- eng/livelink.exe?func=ll&objId=469039&objAction=browse
(b) Since 2005, Gannett Fleming has not filed any reports or evidence before the Board or other regulatory bodies other than as described in response to IOL-Enbridge 26(a).
(c) See Attachment 1 to IOL-Enbridge 26(c).
(d) See response to NOVA Chemicals 1.15(a) for Larry E. Kennedy in the RH-2-2007 proceeding. See Attachment 1 to IOL-Enbridge 26(d) for Mr. Kenney in connection with Kinder Morgan Canada, Burnaby/YVR Jet Fuel Pipeline. See Appendix A-7.3 for Mr. Kennedy in this proceeding.
(e) See response to IOL-Enbridge 25(g)(iii).
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IOL-Enbridge 27
Reference: Written evidence of Enbridge (Adobe Number A1R0V2), Appendix A-4.
Written evidence of Enbridge (Adobe Number A1R0V7), Appendix A- 7.3.
Preamble: Imperial wishes to understand the placement of Line 9 assets into the “Original Reversal Costs” and “Bi-directional Costs” categories.
Requests: (a) What criteria or methodology was used to assign assets to or apportion them across the “Original Reversal Costs” and “Bi- directional Costs” categories?
(b) Did Enbridge assign assets to or apportion them across the “Original Reversal Costs” and “Bi-directional Costs” categories and communicate the assignment/apportionment to Gannett Fleming? If not, and alternatively, did Gannet Fleming or another party perform this assignment/apportionment? If another party was involved, who was this other party? If the assignment/apportionment was performed jointly by more than one party, list the parties and describe the manner in which they participated in the assignment/apportionment? If the assignment/apportionment was performed in some other manner other than the alternatives identified immediately above, describe the process and the parties involved?
(c) Provide all communications between Enbridge, Gannett Fleming, and any other parties related to assigning Line 9 assets to or apportioning them across the “Original Reversal Costs” and “Bi- directional Costs” categories.
(d) Provide all work papers or documents relied upon to assign assets to or apportion them across the “Original Reversal Costs” and “Bi- directional Costs” categories.
(e) List and describe, including location by either kilometre post, valve or pump station, the Line 9 assets, and, for each asset and the “Original Reversal Costs” and “Bi-directional Costs” categories, indicate the category to which it was assigned or the manner it was apportioned across the categories, and describe the criteria or methodology that was used in its assignment/apportionment. Please note that Imperial requires this information in much greater detail than aggregated into the broad cost accounts as shown in RH-1-2010 Responses of Enbridge to Imperial IRs Page 46 of 323
Tables 1A and 1B of Appendix A-7.3.
Prologue: Depreciation, as used in accounting, is a method of distributing fixed capital costs over a period of time by allocating annual amounts to expense. Regulated entities commonly aggregate similar assets into groups and then depreciate the capital costs of those groups rather than the capital costs of the individual assets. Enbridge is required by the OPUAR to follow this approach.
Enbridge has subdivided its undepreciated capital costs – but not the related assets – into two categories, Original Reversal Costs and Bi- directional Costs. As a result, capital costs from a particular group of assets may appear in each category. See response to NOVA Chemicals 1.17(d) for an explanation of the costs that are included in each category.
Responses: (a) See response to NOVA Chemicals 1.17(d).
(b) See response to NOVA Chemicals 1.17(d). The categorization and subdivision of costs was completed by Enbridge alone.
(c) There was no such communication. Enbridge provided the cost data to Gannett Fleming after the categorization and subdivision was completed.
(d) See Attachments 1 and 2 to NOVA Chemicals 1.16(a). See Attachment 1 to IOL-Enbridge 27(d) for the calculation of accumulated depreciation allocable to Original Reversal Costs.
(e) See response to NOVA Chemicals 1.17(d). See Attachments 1 and 2 to NOVA Chemicals 1.16(a).
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IOL-Enbridge 28
Reference: Written evidence of Enbridge (Adobe Number A1R0V7), Appendix A- 7.3.
Preamble: Imperial wishes to understand from Enbridge how the deployment and use of Line 9 assets would change upon re-reversal of Line 9.
Requests: (a) Assuming re-reversal of Line 9, would any of the Line 9 assets be removed from service? If so, indicate whether those assets would be decommissioned, abandoned or idled. For each asset that would be decommissioned, abandoned or idled, please indicate which assets and the reason why they would be removed from service. Provide the cost, and related accumulated depreciation for each asset decommissioned, abandoned or idled.
(b) Assuming re-reversal of Line 9, would any of the Line 9 assets be moved, repositioned, or reconfigured? If so, indicate each such asset’s previous and new location, the manner in which it would be repositioned or reconfigured, and the reason for the repositioning or reconfiguration.
(c) What maintenance, upgrades, or improvements are planned or forecast for Line 9?
Responses: (a) See response to NEB 1.6(b).
Enbridge declines to speculate as to the costs, and related accumulated depreciation, for any Line 9 asset that might be idled, deactivated, decommissioned or abandoned upon re-reversal of Line 9.
(b) See response to IOL-Enbridge 28(a).
(c) See Attachment 1 to NOVA Chemicals 1.22(b) and Statement B- 2.15.
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IOL-Enbridge 29
Reference: Written evidence of Enbridge (Adobe Number A1R0V2), Appendix A-4.
Written evidence of Enbridge (Adobe Number A1R0V5), Appendix A- 7.1.
Written evidence of Enbridge (Adobe Number A1R0V7), Appendix A-7.3
Enbridge’s 31 March 2010 Application for Approval of the Incentive Toll Principles of Settlement for the Year 2010 and For Approval of 2010 Final Tolls and Tariffs for the Enbridge Mainline System.
Preamble: Imperial wishes to understand the appropriateness of the proposed truncation dates and how they were determined.
Requests: (a) What party(ies) (Enbridge, Gannett Fleming, or other party(ies)) determined that the appropriate truncation date for the “Original Reversal Costs” is 31 December 2017?
(b) What party(ies) (Enbridge, Gannett Fleming, or other party(ies)) determined that the appropriate truncation date for the “Bi- Directional Costs” is 31 December 2030?
(c) Other than the reasons discussed in the Muse Stancil report (Appendix A-7.1), are there any reasons that Enbridge, Gannett Fleming, Muse Stancil, or other relevant parties believe that Line 9 will cease providing westbound service on or before 31 December 2017 and/or that the appropriate truncation date for the “Original Reversal Costs” is 31 December 2017? If so, provide those reasons.
(d) Why does Enbridge believe that the appropriate truncation date for the “Bi-Directional Costs” is 31 December 2030?
(e) Does Enbridge believe that a 30 year depreciable life would be appropriate for its “Mainline System” as proposed in its 31 March 2010 Mainline filing? If “yes,” explain why it would be appropriate. If “no” explain why it would be inappropriate.
(f) Does Enbridge believe that a 30 year depreciable life would be appropriate for its “Bi-Directional [Line 9] Costs?” If “yes,” explain why it would be appropriate. If “no” explain why it would be inappropriate. RH-1-2010 Responses of Enbridge to Imperial IRs Page 49 of 323
(g) Does Enbridge believe it would be appropriate to use the same depreciable life for both its “Bi-Directional [Line 9] Costs” and also its “Mainline System?” If “yes,” explain why it would be appropriate. If “no” explain why it would be inappropriate.
(h) Why does Gannett Fleming believe that the appropriate truncation date for the “Bi-Directional Costs” is 31 December 2030?
(i) Does Gannett Fleming believe that a 30 year depreciable life would be appropriate for Enbridge’s “Mainline System” as proposed in Enbridge’s 31 March 2010 filing? If “yes,” explain why it would be appropriate. If “no” explain why it would be inappropriate.
(j) Does Gannett Fleming believe that a 30 year depreciable life would be appropriate for the “Bi-Directional [Line 9] Costs?” If “yes,” explain why it would be appropriate. If “no” explain why it would be inappropriate.
(k) Does Gannett Fleming believe it would be appropriate to use the same depreciable life for both the “Bi-Directional [Line 9] Costs” and also Enbridge’s “Mainline System?” If “yes,” explain why it would be appropriate. If “no” explain why it would be inappropriate.
Responses: (a) Enbridge.
(b) Enbridge.
(c) Enbridge also provided reasons of its own in paragraphs 17 and 18 of Appendix A-3 and paragraphs 19 to 21 of Appendix A-5.
Since the date of the Muse Report, the trade press has indicated that the Imperial Sarnia Refinery will discontinue lubricant production in 2011. Muse regards this as a negative development for westbound throughput on Line 9. In addition, Muse regards NOVA Chemicals’ commercial efforts to obtain NGL supply from the Marcellus Shale as a negative development for westbound service on Line 9. Finally, the closure of the Shell Montreal Refinery is a negative development. See responses to NEB 1.18 and IOL-Enbridge 86(g) and Attachment 1 to IOL-Enbridge 29(c).
(d) Enbridge’s best estimate is that Line 9 will cease providing westbound service by, or before, December 31, 2017. It is expected, however, that Line 9 will be re-reversed to provide eastbound service at some future time. December 31, 2030 matches the currently estimated end of the depreciable life of the RH-1-2010 Responses of Enbridge to Imperial IRs Page 50 of 323
Older System. At present it is expected that, if and when Line 9 were to be operating in eastbound service, it would be subject to the same or similar supply and market parameters as would the Older System.
(e) The depreciable life of the Older System is not the subject of this proceeding. The March 31, 2010 filing referenced in the request item speaks for itself.
(f) It is appropriate that the depreciable life for the Bi-Directional Costs were to match that of the Older System. See response to IOL-Enbridge 29(d).
(g) See response to IOL-Enbridge 29(f).
(h) Gannett Fleming believes that the Bi-Directional Costs should be depreciated over the estimated depreciable life of the investment. It is a long-standing construct of regulatory depreciation applications that the users of utility investment should bear the full cost of the facilities available for their use over the estimated depreciable life of the investment. Given that Enbridge has advised that, if and when Line 9 were to be operating in eastbound service, it would be subject to the same or similar supply and market parameters as would the Older System, the use of a truncation date similar to that applied in respect of the Older System is appropriate.
(i) The depreciable life of the Older System is not the subject of this proceeding. See response to IOL-Enbridge 29(h).
(j) See response to IOL-Enbridge 29(h).
(k) See response to IOL-Enbridge 29(h).
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IOL-Enbridge 30
Reference: Canadian Association of Petroleum Producers (CAPP), Crude Oil Forecast, Markets & Pipeline Expansions, June 2009 (“CAPP Report”)2
Preamble: Imperial wishes to understand the status of other current and potential pipeline projects announced or proposed by Enbridge.
Requests: (a) Please provide a description of the Enbridge Line 6B Debottleneck and Expansion project, discussed in the CAPP Report (p. 24), and outline the status of this project.
(b) Please provide a description of the Trailbreaker project, discussed in the CAPP Report (p. 24), and outline the status of this project?
(c) Could Enbridge’s existing Terrebonne pumping station, Montreal facilities and/or other Line 9 assets be used to initiate flow into a reversed Portland-Montreal pipe? Has this possibility been evaluated by Enbridge in conjunction with Portland Pipeline? If so, describe the conclusions and provide all supporting documents and work papers.
Responses: (a) The Enbridge Line 6B Debottleneck and Expansion Project referenced in the request item was a component of the Eastern Access/Trailbreaker Project. The expansion of Line 6B capacity from Griffith Terminal to Sarnia Terminal (from 290,000 to 425,000 b/d) included seven new pump stations, and modifications to six existing stations. The Eastern Access/Trailbreaker Project is currently on hold.
(b) See Attachment 9 to NOVA Chemicals 1.2(b). The Eastern Access/Trailbreaker Project is currently on hold.
(c) Enbridge Pipelines has not evaluated the possibility of using the Terrebonne pumping station to initiate flow into one reversed pipeline owned by Portland-Montreal Pipe Line.
2 Available at http://www.capp.ca/GetDoc.aspx?DocId=152951. RH-1-2010 Responses of Enbridge to Imperial IRs Page 52 of 323
IOL-Enbridge 31
Reference: Written evidence of Enbridge (Adobe Number A1R0U9), Appendix A-1, page 9, paragraph 21.
Written evidence of Enbridge (Adobe Number A1R0V1), Appendix A-3, page 7, paragraph 18.
Preamble: Enbridge discusses re-reversing Line 9 and uncertainty surrounding re- reversal. Imperial wishes to understand the cost of re-reversing Enbridge’s Line 9.
Requests: (a) What does Enbridge believe it would cost to re-reverse Line 9? Provide a detailed breakdown and description of these re-reversal costs, and provide any supporting documents, presentations, and work papers.
Response: (a) See response to IOL-Enbridge 1(a).
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IOL-Enbridge 32
Reference: Written evidence of Enbridge (Adobe Number A1R0W4), Statement C-1, page 1, paragraphs 1 to 5; Statement C-1.2.
Preamble: Enbridge outlines in Statement C-1.2 the cost of insuring Line 9 in each of 2008, 2009 and 2010.
Requests: (a) Please confirm the scope of liability coverage maintained (i.e. type and nature of claims, losses and damages covered) on Line 9 under the insurance policies Enbridge has in place.
(b) To the extent that the insurance policies require Enbridge to pay deductibles or requires Enbridge to self insure for a portion of any claim, loss or damage, please provide details as to what type of claim, loss or damage require a deductible or self insurance and the amount of deductible or self insurance.
Responses: (a) The commercial general liability program that is in place insures against legal liability for personal injury and damage to property of others arising out of operations including: sudden and accidental pollution; products and completed operations; fire fighting expense; employee benefits liability; non-owned automobile; tenants legal liability; contingent employers liability. An umbrella legal liability program sits excess of the commercial general liability, automobile liability, garage liability, aircraft liability programs.
Key Exclusions: data; employment practices liability; failure to supply; gradual pollution; hazardous waste, pcb; nuclear hazards liability; professional liability; terrorism.
(b) With the exception of sudden and accidental pollution events, the self-insured retention/deductible for legal liability losses described above is $100,000. With regard to damage suffered by third parties caused by a sudden and accidental pollution event, the insured retention/deductible is $5,000,000.
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IOL-Enbridge 33
Reference: (i) Written evidence of Enbridge (Adobe Number A1R0V1), Appendix A-3, pages 2 to 3, paragraphs 1 to 6.
(ii) Written evidence of Enbridge (Adobe Number A1R0V6), Appendix 7.2, pages 8 to 12, lines 110 to 244.
(iii) NEB RH-1-2008 Decision at page 85 where the NEB stated:
“The Board's policy is to approve or reject settlements as a whole, recognizing that there are unknown tradeoffs made in arriving at what ultimately comes to the Board as a package deal. When the Board finds that the resulting tolls would be just and reasonable, the Board does not approve each component as just and reasonable on a standalone basis. The Board is of the view that the evidence in this proceeding has highlighted the fact that negotiated tradeoffs cannot be observed or deduced by outside parties, and that any one aspect of a settlement, including the allowed return, cannot be presumed to have been independently acceptable to parties.
The Board is not persuaded that looking at a number of settlements in aggregate alleviates this fundamental problem. The Board finds that the uncertainty related to the tradeoffs is a great barrier to the informative value of settlement returns. Therefore, the Board has placed no weight on the returns derived from Canadian negotiated settlements”
Preamble: In reference (i), Enbridge confirms its views are compatible with Ms. McShane (Foster Associates, Inc.). In reference (ii), Ms. McShane (Foster Associates, Inc.) discusses the fair return standard enunciated by the NEB in the RH-1-2008 proceeding.
Requests: (a) Does Ms. McShane agree that negotiated settlements contain unknown tradeoffs? If not, why not?
(b) Does Ms. McShane agree that negotiated tradeoffs contained in settlement agreements cannot be observed or deduced by outside parties? If not, why not?
(c) Does Ms. McShane agree that any one aspect of a settlement, cannot be presumed to have been independently acceptable to the parties to the settlement? If not, why not?
(d) Does Enbridge agree that negotiated settlements contain unknown RH-1-2010 Responses of Enbridge to Imperial IRs Page 55 of 323
tradeoffs? If not, why not?
(e) Does Enbridge agree that negotiated tradeoffs contained in settlement agreements cannot be observed or deduced by outside parties? If not, why not?
(f) Does Enbridge agree that any one aspect of a settlement, cannot be presumed to have been independently acceptable to the parties to the settlement? If not, why not?
Responses: (a) Ms. McShane agrees. See response to NEB 1.12.
(b) Ms. McShane agrees. See response to NEB 1.12.
(c) Ms. McShane agrees. See response to NEB 1.12.
(d) Enbridge agrees.
(e) Enbridge agrees.
(f) Enbridge agrees.
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IOL-Enbridge 34
Reference: Written evidence of Enbridge (Adobe Number A1R0V6), Appendix 7.2, page 24, Table 2.
Preamble: In the reference, Ms. McShane (Foster Associates, Inc.) states that the actual equity thickness of Enbridge Pipelines Inc. is 46%.
Requests: (a) Please confirm the actual equity thickness of Enbridge Pipelines Inc.
Response: (a) The 46% equity ratio cited in Table 2 is the 2006-2008 average actual common equity ratio for the Mainline as shown in the column titled “Other.” The corresponding average equity ratio for the consolidated Enbridge Pipelines was 45%.
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IOL-Enbridge 35
Reference: Written evidence of Enbridge (Adobe Number A1R0W4), Statement C-1.
Written evidence of Enbridge (Adobe Number A1R0W5), Statements C- 2.1.1 to C-2.5.
Preamble: Enbridge seeks NEB approval of its cost of service for Line 9.
Requests: (a) Does Enbridge agree that in providing transportation service on Line 9 it is only entitled to recover its prudently incurred costs? If not, why not.
(b) Does Enbridge agree that on a cost of service pipeline like Line 9, the NEB determines what costs are prudently incurred and hence permitted to be included in revenue requirement? If not, why not?
Responses: (a) Enbridge is permitted to charge just and reasonable tolls which, among other things, are designed to recover the revenue requirement approved by the Board. The approved revenue requirement includes more than “prudently incurred costs” or, for a forward test year, more than forecast costs not yet incurred but deemed prudent; for example, the cost of capital.
(b) See response to IOL-Enbridge 35(a).
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IOL-Enbridge 36
Reference: Written evidence of Enbridge (Adobe Number A1R0V6), Appendix 7.2, pages 31 to 37, lines 778 to 930.
Preamble: In the reference Ms. McShane (Foster Associates, Inc.) outlines that the RH-2-94 ROE formula produces incongruous results.
Requests: (a) Based on Ms. McShane’s analysis, in her view when did the RH-2- 94 ROE Formula start to produce incongruous results? (b) Based on Ms. McShane’s analysis, in her view when did the RH-2- 94 ROE Formula start providing an ROE that failed to meet the fair return standard? Please explain. (c) Based on the Line 9 capital structure and cost of debt during the 1999 to 2007 test years, when did the incongruous results of the RH-2-94 Formula contribute to Line 9 failing to receive an overall fair return? Please explain. Responses: (a) By incongruous, Ms. McShane meant that the results of the formula went in the opposite direction of the cost of capital. In most years, based on the comparison of the revised formula and the RH-2-94 formula, the results were not incongruous. As noted at page 30, lines 844-846, “The November 2008 application of the multi-pipeline formula for 2009 clearly demonstrated that the existing formula also could produce incongruous results, that is, a decline in the multi-pipeline ROE at a time when the cost of capital was increasing.” The only other year in which the proposed revised formula went in the opposite direction of the RH- 2-94 formula was 2001.
(b) Since the fair return falls within a range, it is difficult to pinpoint the precise point in time when the formula no longer met the fair return standard. However, given the large differential between the Canadian and U.S. allowed returns that appeared in 1998 and has persisted since that time, and the significant deviations between the results of the RH-2-94 formula and the proposed revised formula from 1999 forward, Ms. McShane would consider that the formula was producing returns that were too low in that time frame.
(c) As the ROEs for Enbridge for 1999-2007 were tied to the RH-2-94 formula, Ms. McShane would conclude that they were too low as well. RH-1-2010 Responses of Enbridge to Imperial IRs Page 59 of 323
IOL-Enbridge 37
Reference: Written evidence of Enbridge (Adobe Number A1R0U8), Application, pages 4 to 7, paragraphs 6 to 13.
Preamble: Enbridge outlines interim and final tolls on Line 9 for each applied for test year and states it intends to invoice shippers for the difference between interim and approved final tolls.
Requests: (a) Please confirm that the final applied for tolls for 2008 contained in the application reflect the actual costs, versus forecast costs, incurred by Enbridge. If not confirmed, why not.
(b) Please confirm that Enbridge is seeking NEB approval of final tolls on Line 9 for the 2009 and 2010 test years, based on forecast costs and not actual costs incurred by Enbridge for those test years. If not confirmed, why not.
Responses: (a) For 2008, Enbridge is seeking approval of final tolls that reflect actual costs plus the return of, and on, capital resulting from the proposals in the Application.
(b) Confirmed for 2010.
For 2009, Enbridge is seeking approval of final tolls that reflect actual costs plus the return of, and on, capital resulting from the proposals in the Application.
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IOL-Enbridge 38
Reference: Written evidence of Enbridge (Adobe Number A1R0U9), Appendix A-1, pages 13 to 14, paragraphs 33 to 38.
Written evidence of Enbridge (Adobe Number A1R0W5), Statements C- 2.1.9 and C-2.5.
Preamble: Enbridge refers to $1.974 million of deferred regulatory costs with respect to the RH-2-2007 proceeding and its decision to recover these costs in tolls contemplated by the TSA.
Requests: (a) Please confirm for each of 2007, 2008, 2009 and 2010, which shippers shipped on Line 9.
(b) Did Enbridge consult with Line 9 shippers regarding the treatment of the deferred regulatory costs? If so, provide details of the consultations including the names of shippers consulted.
(c) Enbridge refers to a letter agreement among Enbridge, Imperial, NOVA Chemicals and Shell in relation to the Third Interim Period, please provide a copy of the letter agreement.
Responses: (a) 2007: Imperial, NOVA Chemicals and Shell. 2008: Imperial, NOVA Chemicals and Shell. 2009: Imperial and NOVA Chemicals. 2010: Imperial and NOVA Chemicals.
(b) Various issues were discussed during negotiations with shippers in the period prior to the TSA. Enbridge cannot disclose the contents of the discussions without the consent of the negotiating parties.
(c) See Schedule B to the following link:
https://www.neb-one.gc.ca/ll- eng/livelink.exe?func=ll&objId=504927&objAction=browse
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IOL-Enbridge 39
Reference: Written evidence of Enbridge (Adobe Number A1R0U9), Appendix A-1, page 15, paragraphs 39 to 42.
Preamble: Enbridge refers to operating Line 9 as a Start-Stop fashion and the risks and the changes to the integrity and maintenance programs.
Requests: (a) Please provide a detailed break down of actual and forecast, as applicable, pipeline integrity program costs for each of 2008, 2009 and 2010.
(b) Please provide a detailed break down of actual and forecast, as applicable, pipeline maintenance program costs for each of 2008, 2009 and 2010.
(c) Please provide a detailed accounting of the costs in requests (b) and (c) that Enbridge intends to capitalize and a further accounting as to how these capitalized costs have been divided between “Original Reversal Costs” and “Bi-directional Costs”.
Responses: (a) See Attachment 1 to IOL-Enbridge 39(a) for capital costs and Attachment 2 to IOL-Enbridge 39(a) for operating costs.
(b) All operating costs associated with pipeline maintenance are captured in Statement C-2.1.1. See Attachment 1 to NOVA Chemicals 1.22(b).
(c) See Attachment 1 to IOL-Enbridge 39(a). All capital costs associated with pipeline integrity programs are capitalized as Bi- directional Costs.
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IOL-Enbridge 40
Reference: Written evidence of Enbridge (Adobe Number A1R0U9), Appendix A-1, pages 10 to 11, paragraphs 23 to 26.
Preamble: Enbridge discusses the Facilities Support Agreement (FSA).
Requests: (a) Please provide a copy of the FSA.
(b) Please confirm the depreciation rate(s) and truncation date used for Line 9 to calculate the Line 9 tolls contemplated by the FSA.
(c) Please confirm how the rate(s) and truncation date in request (b) compared to the Enbridge Mainline and Older System at the time that the FSA was entered into as well as currently.
Responses: (a) The FSA is available at the following link:
https://www.neb-one.gc.ca/ll- eng/livelink.exe/fetch/2000/90465/92835/155829/544980/459963/ 460989/458861/B-1n_-__Appendix_A-8_- _Facilities_Support_Agreement_(consolidated)_- _A0Y4Y5.pdf?nodeid=458868&vernum=0
(b) See the following table.
Depreciation Depreciation Depreciation Rates Effective Rates Effective Rates Effective October 1, January 1, January 1, 1999 2000 2003
Truncation Date 2017 2024 2027
Asset Category
Rights of Way 1.39% 2.43% 2.91% Pipelines 2.86% 2.76% 2.56%
Brick Buildings 2.50% 2.95% 3.30% Steel Buildings 2.50% 3.56% 3.27% Other Buildings 2.86% 3.62% 3.23%
Main Pumping Equipment 4.00% 4.35% 3.99% Booster Pumps 5.00% 2.50% 2.34%
Station Oil Lines 3.33% 3.49% 3.41% Other Station Equipment 4.00% 4.00% 3.70% Oil Storage Tanks 2.86% 3.23% 3.06% RH-1-2010 Responses of Enbridge to Imperial IRs Page 63 of 323
Communications Equipment 5.00% 4.25% 3.89%
General – Furniture and Equipment 5.50% 2.99% 3.19% Computers 5.50% 14.43% 13.36%
Automotive Units 15.00% 15.00% 15.00% Heavy Vehicles n/a 7.00% 7.00% Mobile equipment 0.00% 5.00% 5.00% Non-Mobile Equipment 5.00% 5.00% 5.00%
Main Frame – Computer Equipment 9.00% 10.98% 8.20%
(c) The same depreciation rates were applied in respect of Line 9 and the Older System at the time that the FSA was executed. Until December 31, 2007, the depreciation rates that were applied in respect of Line 9 were the same as those that had been applied in respect of the Older System until December 31, 2005.
The Application proposes the application of different depreciation rates in respect of Original Reversal Costs and Bi-directional Costs for 2008, 2009 and 2010.
Enbridge Pipelines filed depreciation studies with the Board in respect of the Older System in 2006 (25-year depreciable life) and again in 2010 (30-year depreciable life) and those studies did not address Line 9.
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IOL-Enbridge 41
Reference: Written evidence of Enbridge (Adobe Number A1R0U9), Appendix A-1, page 9, paragraph 21.
Written evidence of Enbridge (Adobe Number A1R0V1), Appendix A-3, page 7, paragraph 18.
Preamble: Enbridge discusses re-reversing Line 9 and uncertainty surrounding re- reversal. Imperial wishes to understand what analysis Enbridge has conducted in relation to future uses of Line 9.
Requests: (a) Other than the current configuration that Line 9 is operating under (i.e. westbound service), has Enbridge contemplated any other service configuration for Line 9? If not, why not? If so, please outline what service configurations have been contemplated and provide a description of these configurations.
(b) To the extent that Enbridge has contemplated any other service configurations for Line 9 as described in response to request (a), please provide any analysis, reports or studies prepared with respect to these configurations.
(c) Given Enbridge’s evidence relating to the uncertainty surrounding re-reversing Line 9, has Enbridge contemplated integrating Line 9 with the Older System, or altering its current Older System operation, so as to optimize the operation of either or both Line 9 or the Older System? If not, why not? If so, please outline what service configurations have been contemplated by Enbridge to optimize or integrate the operation of either or both of Line 9 and the Older System.
(d) To the extent that Enbridge has contemplated any other service configurations to optimize or integrate the operation of either or both of Line 9 and the Older System as described in response to request (c), please provide any analysis, reports or studies prepared with respect to these configurations or optimizations.
Responses: (a) Enbridge Pipelines has contemplated numerous other service configurations for Line 9 with various levels of integration with the Older System including: refined products service, natural gas liquids service, gas service, and eastbound crude service under the Eastern Access/Trailbreaker Project.
Enbridge Pipelines evaluated those configurations referenced in RH-1-2010 Responses of Enbridge to Imperial IRs Page 65 of 323
IOL-Enbridge 41(a); however, no commercial agreements with potential shippers have been reached for reasons including: unfavourable market conditions, insufficient commercial support, insufficient volumes, or prohibitive costs.
(b) See response to IOL-Enbridge 41(a).
(c) In 2009 Enbridge Pipelines contemplated a project that would deliver additional western Canadian crude into Line 11 (Nanticoke) and Line 10 (Warren) by re-reversing Line 9A (Sarnia to Westover) and reversing Line 7 (Westover to Sarnia). Based on the shipper feedback Enbridge received on the cost and scope, the project was not pursued.
(d) See response to IOL-Enbridge 41(c).
RH-1-2010 Responses of Enbridge to Imperial IRs Page 66 of 323
IOL-Enbridge 42
Reference: Written evidence of Enbridge (Adobe Number A1R0V7), Appendix A- 7.3, pages 8 to 9.
Preamble: Gannett Fleming, Inc. discusses different vintaging of Line 9 assets and “intergenerational inequity”.
Requests: (a) Please provide a definition for “intergenerational inequity” that applies in the context in which Gannett Fleming is using the term.
(b) Please provide citations for NEB, or other regulatory authority, that supports the definition and context of “intergenerational inequity” provided in request (a).
(c) Please provide NEB, or other regulatory authority, that permits or supports the different vintaging of assets on a stand alone pipeline such as Line 9.
Responses: (a) The term “intergenerational inequity” is defined by the Board to mean the “[i]nequity occurring when a generation of customers does not pay, at the expense of another generation, its fair share of the costs incurred by the utility in providing service.” See Pipeline Tolls and Tariffs: A Compendium of Terms published by the Board (as modified December 29, 2009).
(b) See response to IOL-Enbridge 42(a).
(c) TransCanada PipeLines Limited (“TCPL”) filed an application with the Board on March 14, 2007 seeking approval of its 2007 Mainline Tolls Settlement. The Settlement provided for the allocation of the Mainline’s annual depreciation expense of the transmission plant assets on a segmented basis during each year of the term of the Settlement (i.e., 2007 through 2011). The segmentation reflected the differing economic lives of the Mainline’s three main segments: the Prairies Line, the Northern Ontario Line, and the Eastern Triangle. The depreciation rates for the same asset groups (e.g., mains) varied from segment to segment.
The Board approved the settlement in its letter decision dated May 31, 2007 and Order TG-06-2007. Neither the letter decision nor the Order referred to the segmentation.
RH-1-2010 Responses of Enbridge to Imperial IRs Page 67 of 323
IOL-Enbridge 43
Reference: Written evidence of Enbridge (Adobe Number A1R0V1), Appendix A-3, pages 8 to 9, paragraphs 23 to 26.
Written evidence of Enbridge (Adobe Number A1R0V6), Appendix A- 7.2, page 22, lines 555 to 562.
Written evidence of Enbridge (Adobe Number A1R0V7), Appendix A- 7.3, pages 8 to 9.
Preamble: In each of the references there is discussion of depreciation and business risk or the uncertainty in selecting truncation dates for depreciation purposes.
In the RH-2-2004 Phase II Decision, at page 62, the NEB stated:
The Board is of the view that there are two distinct aspects to risk as it relates to business risk and depreciation rates. The first is that the current best estimate of economic life, which is reflected in the depreciation rates, may ultimately prove to be wrong. Various business factors, including changes to supply or competitive forces, could alter the economic life of the Mainline. This possibility cannot be fully mitigated and therefore should be compensated through cost of capital.
The second aspect of depreciation-related risk is that the depreciation rates in use may not actually reflect the estimates of economic life that would be selected if assessed at that point in time. A company can mitigate the risk that the estimates in use are not current by bringing forward an application to reconsider its deprecation rates. The part of this risk that is mitigable should not be compensated through the cost of capital. Should it become apparent that depreciation rates do not adequately reflect current estimates of economic life, it is incumbent on the management of the company to seek to change depreciation rates, not to expect incremental compensation through the cost of capital. RH-1-2010 Responses of Enbridge to Imperial IRs Page 68 of 323
Requests: (a) Does Enbridge agree with the quoted NEB statement and principles enunciated? If not, why not?
(b) Does Ms. McShane (Foster Associates, Inc.) agree with the quoted NEB statement and principles enunciated? If not, why not?
(c) Does Gannett Fleming, Inc. agree with the quoted NEB statement and principles enunciated? If not, why not?
Responses: (a) Yes.
(b) Yes. The conclusion of the Board is consistent with the statement in lines 555 through 560 of Appendix A-7.2, “While the proposed depreciation rates represent Enbridge’s best estimates of the remaining depreciable life of Line 9, there remains a significant risk that the actual remaining service life in either direction will be shorter than currently anticipated. With respect to the reversal project capital costs, the estimated remaining depreciable life may be shorter than anticipated and the throughput necessary to recover the invested capital may not materialize.”
(c) Yes.
RH-1-2010 Responses of Enbridge to Imperial IRs Page 69 of 323
IOL-Enbridge 44
Reference: Written evidence of Enbridge in RH-2-2007, pages 5 and 6 (as numbered in the application).
Preamble: In the RH-2-2007 proceeding Enbridge sought approval of final tolls on Line 9 for the 2006 Test Period and the 2007 Test Year.
Requests: (a) Please confirm that Enbridge sought approval of final tolls on Line 9 for the 2007 Test Year in the RH-2-2007 proceeding based on the following:
(i) ROE was to be determined using the NEB’s multi-pipeline rate of return on equity, based on the ROE formula established in the RH-2-94 proceeding and that no additional adjustment to ROE to account for business or financial risk, was proposed. If not confirmed, why not.
(ii) The Line 9 common equity ratio was to be increased from 45% to 52.5% to account for a perceived increase in business risk. If not confirmed, why not.
(iii) The truncation date used for depreciation purposes on Line 9 was to be changed so as to recover all of the remaining Line 9 depreciation costs by December 31, 2013. If not confirmed, why not.
Response: (a) Confirmed.
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IOL-Enbridge 45
Reference: Written evidence of Enbridge (Adobe Number A1R0V9), Statement B-1, page 1, paragraph 8.
Preamble: In the reference, Enbridge states that the debt component of Line 9 is provided by a “deemed” allocation of debt issued by Enbridge Pipelines.
Requests: (a) Please confirm the total amount of debt Enbridge Pipelines Inc. has outstanding for each of 2008, 2009 and 2010.
(b) Please confirm what pipelines, facilities, affiliates or subsidiaries Enbridge Pipelines Inc. uses this debt to finance.
(c) Please confirm the methodology and reasoning for how the debt in request (a) is allocated across the pipelines, facilities, affiliates and subsidiaries identified in request (b).
(d) Please also confirm how the debt in request (a) is actually allocated (i.e. percentage of total debt or amount) across each of the pipelines, facilities, affiliates and subsidiaries in request (b).
Responses: (a) The following summarizes the total long term debt of Enbridge Pipelines (excluding debt for Southern Lights) outstanding for the years ended December 31, 2008 and 2009, and for the quarter ended March, 31 2010:
Long Term Debt
Outstanding ($ millions) 2008 1,815 2009 2,566 Q1 2010 2,775
(b) The long term debt referenced in the response to IOL-Enbridge 45(a) is used to finance all of the following pipeline assets: Enbridge Mainline System (including SEP I, SEP II, Terrace Expansions, Southern Access Expansion, Line 4 Extension and Alberta Clipper), Line 8 and Line 9. However, to satisfy specific financing requirements, from time to time, all or a portion of individual debt instruments are allocated to finance one or more specific assets listed above. In this regard see the response to NEB 1.38 for information regarding Line 9.
(c) The long term debt identified in the response to IOL-Enbridge RH-1-2010 Responses of Enbridge to Imperial IRs Page 71 of 323
45(a) is allocated in accordance with the tolling arrangements for the assets or projects identified in the response to IOL-Enbridge 45(b).
(d) See response to IOL-Enbridge 45(b).
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IOL-Enbridge 46
Reference: Written evidence of Enbridge (Adobe Number A1R0V1), Appendix A-3, pages 2 to 3, paragraphs 1 to 6.
Written evidence of Enbridge (Adobe Number A1R0V6), Appendix A- 7.2, pages 16 to 23.
Preamble: Enbridge states that it is providing its own assessment of its business risk. Ms. McShane (Foster Associates, Inc.) provides her own assessment of business risk.
Requests: (a) Please confirm which business risk assessment, Enbridge or Ms. McShane’s, was prepared first.
(b) If there is an inconsistency between the Enbridge business risk assessment and Ms. McShane’s, which assessment takes precedent for the purposes of the Application?
Responses: (a) Enbridge’s assessment of business risk was prepared first. Enbridge then asked Ms. McShane to confirm the reasonableness of its assessment. She conducted her assessment for that purpose.
(b) Enbridge does not see any inconsistencies between the two assessments.
RH-1-2010 Responses of Enbridge to Imperial IRs Page 73 of 323
IOL-Enbridge 47
Reference: Written evidence of Enbridge (Adobe Number A1R0U9) Appendix A-1, pages 8, 11 to 12, paragraphs 19, 27 to 29.
Preamble: Enbridge seeks to add a total of $1.636 million to Line 9 rate base.
Requests: (a) Please confirm that this $1.636 million relates to an original amount of $500,000, which represents the difference between Enbridge’s (IPL’s) actual deficiency amount incurred and the “Line 9 Deficiency Amount” defined and set under the FSA. If not confirmed, why not?
(b) Please confirm the $1.636 million sought to be added to Line 9 rate base is made up of the $500,000 difference between the actual deficiency amount and the “Line 9 Deficiency Amount” in the FSA, plus carrying charges since 1996. If not confirmed, why not?
(c) Please confirm that Enbridge (IPL) negotiated with FSA shippers the quantum of the “Line 9 Deficiency Amount” to be included under the FSA prior to knowing what the actual deficiency amount was. If not confirmed, why not?
(d) Please confirm that Enbridge (IPL), in negotiating the FSA and the Line 9 Deficiency Amount to be included under the FSA, took the risk that the actual or final deficiency amount would be higher or lower than the Line 9 Deficiency Amount. If not confirmed, why not?
(e) Enbridge states that the cost of retaining ownership of Line 9 is analogous to the cost of acquiring or constructing a transportation plant. Please provide an explanation of the regulatory principles, and citations to NEB or other regulatory authority, relied upon to make this statement.
Responses: (a) Not confirmed. See the discussion at paragraphs 27 to 29 of Appendix A-1. The $1.636 million relates to both of the original amount of $10.5 million – the “Line 9 Deficiency Amount” as defined in the FSA – and the $500,000 difference between that amount and the actual deficiency amount.
(b) See response to IOL-Enbridge 47(a). RH-1-2010 Responses of Enbridge to Imperial IRs Page 74 of 323
(c) Confirmed.
(d) Confirmed. Enbridge took this risk under the FSA.
(e) Enbridge is not relying upon regulatory principles to justify this statement. The logic behind Enbridge’s statement is self-evident. The cost of retaining ownership of the Montreal Extension was incurred in order to enable Enbridge to reverse it, as Line 9, and to provide westbound service to its shippers.
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IOL-Enbridge 48
Reference: (i) Written evidence of Enbridge (Adobe Number A1R0V1), Appendix A-3, pages 4 to 9, paragraphs 11 to 26.
(ii) Written evidence of Enbridge (Adobe Number A1R0V6), Appendix 7.2, pages 16 to 23, lines 379 to 570.
Preamble: In reference (i), Enbridge provides the broad definitions of the various forms of risk that make up business risk and then provides conclusions of its assessment of these forms of risk in relation to Line 9. In reference (ii), Ms. McShane (Foster Associates, Inc.) outlines “Conceptual Considerations” and the “Trend in Business Risks” with respect to Line 9. Imperial wants to understand the changes in the various forms of risk facing Line 9 since the last NEB proceeding in which the NEB had an opportunity to consider the Line 9 deemed equity component.
Requests: (a) In reference (ii), Ms. McShane (Foster Associates, Inc.) makes reference to “physical risks”. Please confirm that physical risks are encompassed in “operating risk”. If not confirmed, please explain the differences between operating risk and physical risks.
(b) For each of the following: supply risk; market risk; regulatory risk; competitive risk; operating risk; physical risk; and depreciated- related business risk, please provide:
(i) a detailed description and analysis of the risk facing Line 9 in 1997 at the time of the OH-2-97 proceeding; and
(ii) a detailed description and analysis, versus the “conceptual considerations” and “trends” provided, of the risk facing Line 9 in January 2008.
Responses: (a) Physical risks are synonymous with operating risks. See response to IOL-Enbridge 148.
(b) (i) The description and analysis of the risk facing Line 9 in 1997 was provided by Dr. Robert E. Evans in his response to the Board’s Information Request No. 1 dated 13 June 1997, Question No. 1.50 (Attachment 1 to IOL-Enbridge 48(b)(i)) and in his testimony on August 19, 1997 as recorded in Volume 8 of the transcript at pages 971 through 1024 (Attachment 2 to IOL-Enbridge 48(b)(i)).
(ii) Enbridge provided its description and analysis of the risk RH-1-2010 Responses of Enbridge to Imperial IRs Page 76 of 323 facing Line 9 in January 2008 in Appendix A-3 as the basis for its proposed capital structure. As the Board recognized at page 81 of its RH-1-2008 Reasons for Decision (TQM), “The freedom for a company to choose its optimal capital structure is consistent with the Board's philosophy of regulating pipeline companies on a goal-oriented basis.” Ms. McShane was retained to assess the reasonableness of Enbridge’s proposed capital structure and to recommend a rate of return on equity. Ms. McShane’s analysis is contained in Appendix A-7.2. Ms. McShane’s analysis, encompassing conceptual considerations and trends, is sufficiently detailed to make an assessment of reasonableness.
RH-1-2010 Responses of Enbridge to Imperial IRs Page 77 of 323
IOL-Enbridge 49
Reference: (i) Written evidence of Enbridge (Adobe Number A1R0V1), Appendix A-3, pages 5 to 8, paragraphs 13 to 22.
(ii) Written evidence of Enbridge, (Adobe Number A1R0V6), Appendix 7.2, pages 16 to 23, lines 379 to 570.
Preamble: In reference (i), Enbridge defines “operating risk” as “the risk to Enbridge’s income-earning capability that arises from technical and operational factors” and states that it manages this risk through extensive integrity and maintenance programs.
In reference (ii), Ms. McShane (Foster Associates, Inc.) states that the risk of supply interruption is linked to operational risk and that a factor in operational risk is whether a pipeline is looped.
Requests: (a) Please confirm whether the risk of supply interruption due to a pipeline rupture/leak or other equipment failure is a “supply risk” or “operational risk”. If not confirmed as either, why not?
(b) Please provide a complete listing of “technical factors” that form or contribute to Enbridge’s operational risk on Line 9.
(c) Please provide a complete listing of “operational factors” that form or contribute to Enbridge’s operational risk on Line 9.
(d) Please provide a complete listing of potential events or outcomes that, in Enbridge’s view, would represent the materialization of operational risk.
Responses: (a) Enbridge confirms that the risk of supply interruption due to a pipeline rupture/leak or other equipment failure is an operational risk.
(b) Such technical factors include: the size of pipe; pipe material strength and wall thickness; depth of cover; and soil conditions.
(c) Operational factors include: the nature of products shipped; pressure, temperature and flow rate; climate conditions; activity near the right of way; and operator error.
(d) Operational risk could materialize as, for example among other things, a pipeline rupture or leak leading to interruption of service, pipeline rehabilitation and environmental clean-up. RH-1-2010 Responses of Enbridge to Imperial IRs Page 78 of 323
IOL-Enbridge 50
Reference: National Energy Board OH-2-97 Decision at: (i) page 27, Section 3.1; and (ii) page 31, Section 3.2.1.2.
Preamble: Reference (i) states in part:
“The Line 9 Reversal Project would provide IPL with the ability to re- reverse Line 9 to a west-to-east mode in the future. As the current configuration of Line 9 provides for west-to-east flow, minimal additional facilities would be required to accommodate re-reversal. The cost of the re-reversal facilities, estimated at $500,000, is included in the scope of the Line 9 Reversal Project.”
Reference (ii) states in part:
“With respect to timing, IPL indicated that the intent of the station design is to allow for re-reversal of the complete Line 9 system within six weeks. However, Line 9A would be capable of re-reversal within two weeks, primarily because it would require fewer facility modifications than the longer Line 9B segment.”
Requests: (a) Please confirm that at the time the Line 9 reversal project was constructed in accordance with the IPL application filed in the OH-2-97 proceeding. If not confirmed, why not?
(b) Please confirm that at the time the Line 9 reversal project was commissioned it was constructed so as to include “re-reversal facilities” that would permit the Line to be re-reversed from east- west flow to west-east flow. If not confirmed, why not?
(c) Please confirm that the “re-reversal facilities” referred to in reference (i) are still in place and operational. If not confirmed, why not?
(d) Please confirm that the cost of the “re-reversal facilities” referred to in reference (i) is included in the current Line 9 rate base. If not confirmed, why not? If confirmed, please provide a detailed listing of these facilities and an accounting of the book value and depreciated value.
(e) Please confirm that Line 9 can still be re-reversed within six weeks, as stated in reference (ii). If not confirmed, why not? RH-1-2010 Responses of Enbridge to Imperial IRs Page 79 of 323
Responses: (a) In Schedule “A” to a letter from Enbridge to the National Energy Board dated July 28, 1999, Mr. Neil Rausch, a Professional Engineer responsible for matters concerning the construction of the Line 9 Reversal Project, stated the following:
I can confirm that all facilities referred to in this document [the application] have been designed, constructed and tested to the standards, specifications and procedures as set forth in Enbridge's Application to the National Energy Board dated May 1997 and approved pursuant to the Board Order XO-J1-34-97.
(b) Confirmed.
(c) Flanged suction and discharge pipe segments (spools) were fabricated for possible installation at North Westover, Hilton and Cardinal Stations. These spools are still available for installation.
(d) Confirmed.
These assets are not tracked as distinct assets for accounting purposes. Consequently it is not possible to provide the detailed information requested.
(e) See response to IOL-Enbridge 1(b).
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IOL-Enbridge 51
Reference: National Energy Board OH-2-97 Decision at: (i) page 90, Section 9.1; and (ii) page 91, Section 9.2.
Preamble: Reference (i) states in part:
“IPL submitted that re-reversal capability would permit a timely response to supplying Montreal refineries in the event of a supply disruption on the Portland-Montreal system. However, IPL could not foresee all potential circumstances or events that would necessitate Line 9 re-reversal. As an example, re-reversal may be appropriate if the volumes of offshore crude oil on the reversed Line 9 were to fall below 8750 m3/d (55,000 b/d).”
Reference (ii) states in part:
“IPL stated that there is no agreement on what the tolls would be if Line 9 were re-reversed. Board approval would be needed, but not the approval of the Refiners. It was noted that as Line 9 would be in west-to-east service, the expectation would be that integrated tolls would apply.”
Requests: (a) Please outline why, at the time of the OH-2-97 proceeding, IPL could not “foresee all potential circumstances or events” that would necessitate a re-reversal of Line 9.
(b) Please provide a listing of “potential circumstances or events” that were foreseen by IPL as necessitating a re-reversal of Line 9.
(c) Is Enbridge still of the view that re-reversal may be appropriate if Line 9 volumes in reversed flow were to fall below 55,000 b/d? If not, why not?
(d) Please confirm that at the 55,000 b/d threshold cited in reference (i), Line 9 would have to operate in a start-stop fashion. If not confirmed, why not?
(e) Please confirm whether it is still Enbridge’s expectation that if Line 9 were re-reversed so as to operate in west-to-east service, integrated tolls would apply. If not confirmed, why not?
Responses: (a) It was not possible to foresee all potential circumstances or events then nor is it now.
(b) See response to IOl-Enbridge 51(a).
(c) A decision to re-reverse Line 9 would not depend solely on any RH-1-2010 Responses of Enbridge to Imperial IRs Page 81 of 323
threshold throughput level but also on several other factors including shipper requirements for eastbound service.
(d) Confirmed. See response to IOL-Enbridge 60(a).
(e) Not confirmed. See response to NOVA Chemicals 1.1(b).
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IOL-Enbridge 52
Reference: (i) Written evidence of Enbridge (Adobe Number A1R0V1), Appendix A-3, pages 2 to 3, paragraphs 1 to 6.
(ii) Written evidence Enbridge (Adobe Number A1R0V6), Appendix 7.2, page 24, Table 2.
(iii) Enbridge Inc. May 25, 2009 submission to the NEB in the RH-R- 2-94 proceeding (Review of RH-2-94 Cost of Capital) titled: “Submissions Related to Whether the Board Should Review the Multi-Pipeline Cost of Capital Decision (RH-2-94)”.
(iv) Enbridge Inc. September 18, 2009 submission to the NEB in the RH-R-2-94 proceeding (Review of RH-2-94 Cost of Capital) titled: “Review of the Multi-Pipeline Cost of Capital Decision (RH-2-94)”.
Preamble: In reference (i), Enbridge confirms its views are compatible with Ms. McShane (Foster Associates, Inc.). In reference (ii), Ms. McShane (Foster Associates, Inc.) provides information related to common equity ratios for various pipelines using third party public information (e.g. DBRS Reports). In reference (iii) Enbridge Inc. states that a review of the RH-2- 94 ROE formula should be undertaken. In reference (iv) Enbridge Inc. outlines the benefits of a generic formula approach.
Requests: (a) Please provide a copy of reference (iii) and (iv).
(b) In reference (iv) Enbridge Inc. indicates that it has entered into 9 settlement agreements since the RH-2-94 Decision and has over a half dozen existing settlement agreements that specifically reference the NEB Multi-Pipeline rate of return and use it as the basis for determining return on equity. Please provide the following:
(i) A listing of all pipeline/utility toll settlements that Enbridge Inc., and its affiliates, have entered into since the RH-2-94 proceeding. This listing should be comprehensive and should include all Greenfield and existing NEB regulated Enbridge owned or affiliated pipelines as well as any other pipelines/utilities regulated by a Canadian regulator.
RH-1-2010 Responses of Enbridge to Imperial IRs Page 83 of 323
(ii) Using the listing in (i), please confirm which of these settlements specifically reference the NEB Multi-Pipeline rate of return and either used or use it as the basis for determining return on equity.
(iii) Using the listings in (i), please confirm: the date of each settlement; the term of the settlement; the pipeline/utility facilities it applies to; the settlement capital structure (i.e. debt and equity components); the ROE; and debt costs.
(iv) To the extent that any of the pipeline toll settlements in (i) prevent Enbridge from disclosing the information requested in (iii), please provide, either via Enbridge or Ms. McShane, the same or similar information sourced from third party public information (e.g. DBRS reports) as Ms. McShane has done in reference (ii).
Responses: (a) The documents referred to in references (iii) and (iv) can be found at the following links:
https://www.neb-one.gc.ca/ll- eng/livelink.exe?func=ll&objId=557933&objAction=browse
https://www.neb-one.gc.ca/ll- eng/livelink.exe?func=ll&objId=570735&objAction=browse
(b) Enbridge objects to filing the information in the requested detail and declines to do so. Paragraph 12 of Appendix A-2 provides a list, in effect, of the settlements reached by Enbridge Pipelines and an affiliate other than two that involve Imperial as the only shipper (Line 8) and the primary shipper (Norman Wells Pipeline). Enbridge Pipelines subsequently reached an Incentive Toll Settlement with CAPP for 2010 (Mainline System). These settlements are on the public record.
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IOL-Enbridge 53
Reference: Written evidence of Enbridge (Adobe Number A1R0V6), Appendix 7.2, pages 23 to 27, lines 572 to 686.
Preamble: In the reference, Ms. McShane (Foster Associates, Inc.) discusses seven pipelines as comparables to Line 9: Enbridge Pipelines Mainline; Enbridge Pipelines (N.W.) Inc.; the Express System; the Milk River Pipeline; the Plateau Pipe Line; the TransMountain Pipeline; and Trans-Northern Pipelines Inc.
Requests: (a) In Table 2 of the reference (page 24), Ms. McShane appears to be citing information and data with respect to the Enbridge Pipelines Mainline and Express System in both Canada and the United States. Please confirm if this is the case and if so, please provide an updated Table 2 reflecting only information and data for Canada.
(b) In Table 2 of the reference (page 24), Ms. McShane identifies, both the “Equity Ratio Approved for Regulatory Purposes” and the “Actual Common Equity Ratio” for each of the comparable pipelines. For each of the pipelines, please confirm whether the “Equity Ratio Approved for Regulatory Purposes” was arrived at by way of a litigated rate case before the applicable Canadian regulator or by way of negotiated settlement that was approved by the applicable Canadian regulator.
(c) For those pipelines identified in request (b) as having their “Equity Ratio Approved for Regulatory Purposes” set by negotiated settlement, please confirm if the equity ratio formed only one aspect of a larger “package deal” settlement. If not confirmed, why not?
Responses: (a) Table 2 contains only two pieces of data for Enbridge Pipelines. One is the actual common equity ratio, which is (as noted in the table) the average as calculated by DBRS for the Mainline. The November 2009 DBRS report (see Attachment 1 to IOL-Enbridge 131(a)) from which the Enbridge Pipelines data were obtained defines the Mainline (at page 4) as “Operations of the Canadian oil pipeline system (Edmonton to the Manitoba-U.S border), including Line 9 (Montréal to the Ontario-U.S. border), referred to as the Enbridge System.” The other piece of data is the debt rating. There is only one debt rating; that is, for the debt issued by Enbridge Pipelines.
Express Pipeline Limited Partnership (Canada) and Express Pipeline LLC (U.S.) issue debt jointly and severally; Platte Pipe Line RH-1-2010 Responses of Enbridge to Imperial IRs Page 85 of 323
Company guarantees the debt. In assessing their financial statements, of the Express system DBRS states: “The Express Pipeline System financial statements, which are a combination of the financial statements of Express Canada, Express U.S. and Platte, form the basis of the financial analysis in this report due to the joint nature of the debt obligations as a result of the guarantee of Platte.” There are no separate publicly available data of which Ms. McShane is aware for Canada.
(b) The requested information is presented below.
Equity Ratio Approved for Negotiated Settlement Pipeline Regulatory Purposes or Litigated Enbridge Pipelines N/A N/A Enbridge Pipelines (N.W.) Inc. 55% Negotiated Express System N/A N/A Milk River Pipeline 50% Litigated Plateau Pipe Line Ltd. (Western System) 50% Litigated Trans Mountain Pipeline ULC 45% Negotiated Settlement Trans-Northern Pipelines Inc. 50%-55% Negotiated Settlement
(c) As stated in response to NEB 1.12, negotiated settlements are the result of arms-length negotiations and reflect a “give and take” process. The end results, particularly when a number of settlements are considered as a group, are an indicator of comparable returns available on investment of similar (though not identical) risk. The results of negotiated settlements are not intended to, nor should they, on a stand-alone basis, be determinative of returns that meet the three requirements of the Fair Return Standard, that is, the comparable investment, financial integrity and capital attraction requirements.
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IOL-Enbridge 54
Reference: Written evidence of Enbridge (Adobe Number A1R0V6), Appendix 7.2, page 15, lines 342 to 356.
Preamble: In the reference, Ms. McShane (Foster Associates, Inc.) discusses the mirroring down of Enbridge Pipelines’ debt to Line 9 and states that this is “consistent with regulatory practice”.
Requests: (a) Please provide authority for the “regulatory practice” cited. In doing so please provide a comprehensive listing of NEB or other Canadian utility regulator decisions that reference the practice.
Response: (a) The Alberta Utilities Commission (formerly the Alberta Energy and Utilities Board or “EUB”), the Public Utilities Board of the Northwest Territories and the Yukon Utilities Board all rely on the cost of debt that is raised by CU Inc. on behalf of CU Inc.’s various regulated utilities that operate in those jurisdictions, rather than the stand-alone cost of debt that each utility would individually incur on a stand-alone basis. For example, in Decision EUB 2003-100 (December 2003), the EUB noted that “ATCO Pipelines argued that its financing costs, which reflected the long established practice of combining debt and preferred share financings through CUL, should be approved as filed.” The EUB considered these costs reasonable and approved ATCO Pipelines’ proposed embedded costs of debt and preferred shares as set out in the Application. In Decision 24-2008 (10/2008), the Public Utilities Board of the Northwest Territories accepted a cost of debt for Northland Utilities (Yellowknife) and Northland Utilities (NWT) which reflected the cost of debt as raised by CU Inc. In its Reasons for Decision for Yukon Electrical Company, the Yukon Utilities Board accepted the cost of debt proposed by the Company, which reflects mirroring down of debt issued by CU Inc.
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IOL-Enbridge 55
Reference: (i) Written evidence of Enbridge (Adobe Number A1R0V1), Appendix A-3, pages 2 to 3, paragraphs 1 to 6;
(ii) Written evidence of Enbridge (Adobe Number A1R0V6), Appendix 7.2, page 37, lines 932 to 939; and pages 43 to 45, lines 1083 to 1172;
(iii) Written evidence of Enbridge (Adobe Number A1R0V6), Appendix 7.2, page 24, Table 2.
(iv) NEB RH-2-94 Decision, pages 13, 15, 16 and 19.
Preamble: In reference (i), Enbridge confirms it relies on the evidence of its experts and that its views are compatible with the opinions and methodologies employed by each expert.
In reference (ii), Ms. McShane (Foster Associates, Inc.) states that she preserved the initial RH-2-94 benchmark pipeline ROE of 12.25% established in the RH-2-94 proceeding and used it as the point of departure to revise the RH-2-94 adjustment formula to produce the ROEs for each of 2008, 2009 and 2010 and applied for by Enbridge for Line 9. Additionally, Ms. McShane adds an equity risk premium for Enbridge’s Line 9.
In reference (iii), Ms. McShane (Foster Associates, Inc.) relies on Enbridge Pipelines Inc.’s mainline system as a comparable to Enbridge’s Line 9.
In reference (iv), the NEB determined the ROE and capital structure for a “benchmark pipeline”.
Requests: (a) Please confirm that in setting the 12.25% ROE in the RH-2-94 proceeding, the NEB’s goal was to set an appropriate ROE for a “low-risk”, “high-grade” regulated pipeline and use that ROE as the standard for determining the ROE for all other pipelines participating in the proceeding. If not confirmed, why not?
(b) Please confirm that in the RH-2-94 proceeding the NEB determined that it was appropriate for all pipelines in the proceeding to be subject to the benchmark pipeline ROE of 12.25% and that all risk differentials between pipelines are best accounted for through differences in common equity ratios. If not RH-1-2010 Responses of Enbridge to Imperial IRs Page 88 of 323
confirmed, why not?
(c) Please confirm that Enbridge (then IPL) was discharged from the RH-2-94 proceeding as it had reached a settlement and as such its ROE and capital structure were not considered or determined by the NEB. If not confirmed, why not?
(d) Is it Ms. McShane’s view that when using a benchmark ROE formula it is best that any risk differentials between pipelines be accounted for through adjustments to the common equity ratios of the pipelines? If not, why not?
(e) In Ms. McShane’s view, at the time of the RH-2-94 proceeding, what should Enbridge’s mainline system ROE have been relative to the NEB’s benchmark pipeline? Similarly, what should Enbridge’s mainline system common equity ratio have been relative to the gas and oil pipelines common equity ratios established by the NEB in the RH-2-94 proceeding?
(f) In Ms. McShane’s view, if Line 9 had been a participant in the RH-2-94 proceeding on a stand alone basis, at the time of the RH- 2-94 proceeding, what should Line 9’s ROE have been relative to the NEB’s benchmark pipeline? Similarly, what should Line 9’s common equity ratio have been relative to the gas and oil pipelines common equity ratios established by the NEB in the RH-2-94 proceeding?
(g) Is it Enbridge’s view that when using a benchmark ROE formula it is best that any risk differentials between pipelines be accounted for through adjustments to the common equity ratios of the pipelines? If not, why not?
(h) In Enbridge’s view, at the time of the RH-2-94 proceeding, what should Enbridge’s mainline system ROE have been relative to the NEB’s benchmark pipeline? Similarly, what should Enbridge’s mainline system common equity ratio have been relative to the gas and oil pipelines common equity ratios established by the NEB in the RH-2-94 proceeding?
(i) In Enbridge’s view, if Line 9 had been a participant in the RH-2- 94 proceeding on a stand alone basis, at the time of the RH-2-94 proceeding, what should Line 9’s ROE have been relative to the NEB’s benchmark pipeline? Similarly, what should Line 9’s common equity ratio have been relative to the gas and oil pipelines common equity ratios established by the NEB in the RH-2-94 proceeding? RH-1-2010 Responses of Enbridge to Imperial IRs Page 89 of 323
Responses: (a) At page 3 of the Board’s RH-2-94 Reasons for Decision it states: “In the context of this proceeding, a benchmark pipeline refers to a hypothetical utility whose overall investment risks are characteristic of a low-risk, high-grade regulated pipeline. The Board’s objective was to determine an appropriate rate of return on common equity for a benchmark pipeline and use this as the standard for determining the rate of return on common equity for all of the pipelines subject to this proceeding.”
(b) At page 6 of the Board’s RH-2-94 Reasons for Decision it states: “The Board is cognizant of the linkage between the rate of return on common equity and the pipelines’ capital structures and has determined that any risk differentials between the pipelines can best be accounted for through adjustments to the common equity ratios rather than by making company-specific adjustments to the benchmark pipeline’s rate of return on common equity.”
(c) Confirmed. See page 2 of the Board’s RH-2-94 Reasons for Decision.
(d) No. Ms. McShane does not believe it is best that any risk differentials between pipelines be accounted for through adjustments to the common equity ratios of the pipelines. Ms. McShane believes management is in the best position to understand its risks and financing requirements and thus, within reason, choose its own capital structure. As the Board noted in the RH-1-2008 proceeding, “The freedom for a company to choose its optimal capital structure is consistent with the Board's philosophy of regulating pipeline companies on a goal-oriented basis. Exercise of that freedom does not, in the Board’s view result in a wealth transfer, and is supported by the longstanding stand-alone principle.” See responses to NOVA Chemicals 1.6 and IOL- Enbridge 187(d).
(e) Ms. McShane did not represent IPL in the 1994 proceeding nor any of the oil pipelines. However, given that IPL had previously been allowed a common equity ratio of 45%, had applied in the RH-2-94 proceeding for an equity ratio in the 45-50% range, and Trans Mountain was allowed a common equity ratio of 45%, it could reasonably be inferred that IPL would have been allowed 45% as well, and the benchmark pipeline ROE.
(f) Ms. McShane has not analyzed Enbridge (Line 9) as of the vantage point of 1994 and is not in a position to respond to the question.
(g) No. See response to IOL-Enbridge 55(d). RH-1-2010 Responses of Enbridge to Imperial IRs Page 90 of 323
(h) Enbridge has no view in this regard.
(i) Since Enbridge Pipelines was discharged from the RH-2-94 proceeding, Enbridge does not possess all of the information necessary to respond to this request.
RH-1-2010 Responses of Enbridge to Imperial IRs Page 91 of 323
IOL-Enbridge 56
Reference: Written evidence of Enbridge (Adobe Number A1R0U9), Appendix A-1, pages 4 to 6, paragraphs 5 to 8.
Preamble: In paragraph 5, Enbridge states: “three storage tanks within Sarnia Terminal, which are used only for Line 9, and connecting facilities to those tanks and from those tanks to Sarnia Station and onward to a point proximate to the end point of Line 9A within Sarnia Terminal;”
Footnote 4 states, regarding these facilities: “Enbridge has the flexibility to change any or all of the specific tanks that are used only for Line 9 as necessary to achieve operational efficiency.”
Imperial would like to understand what flexibility exists regarding these specific tanks, and what operational efficiency can be achieved through any such changes.
Requests: (a) Provide a description of any previous operational changes regarding these tanks over the life of the Line 9 assets.
(b) Provide a summary of the options available to Enbridge regarding the use of the subject tanks.
(c) Provide a description of any studies that have been done to quantify operational efficiency improvements that may be achieved through alternative uses of the subject tanks.
Responses: (a) There are no such operational changes.
(b) Enbridge has the ability to change the use of Sarnia tankage in Line 9 service. Capital expenditures may be required to effect such changes.
(c) Terminal facilities are reviewed annually. Commodities are allocated to tanks based on forecast throughputs, crude segregation requirements and connectivity constraints with a view to improving operational efficiency.
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IOL-Enbridge 57
Reference: Written evidence of Enbridge (Adobe Number A1R0U9), Appendix A-1, pages 4 to 6, paragraphs 5 to 8.
Preamble: Imperial would like to understand how the Enbridge facilities are operated, and any flexibility that might exist within the system.
Requests: (a) What tank capacity does Enbridge have for crude storage at Sarnia, Westover and Montreal? (b) What tank capacity is available to shippers on Line 9 in addition to the Enbridge capacity that might provide flexibility to those shippers and assist in the operation of Line 9? (c) Please provide a schematic diagram of the Line 9 facilities, including tankage, pipelines and interconnections, at Sarnia, Westover and Montreal. (d) For the tanks identified in request (c), please provide capacity and service information.
Responses: (a) The tables below provide working tankage volumes:
Sarnia Tankage Tank Working Volume m3 SA-TK-212 24,552 SA-TK-213 25,112 SA-TK-215 51,704
Westover Tankage Tank Working Volume m3 WS-TK-224 11,661 WS-TK-227 18,708
Enbridge has no tanks at Montreal Terminal.
(b) None.
(c) See page 3 of Appendix A-1.
(d) See response to IOL-Enbridge 57(a). The tanks are operated in Line 9 delivery service.
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IOL-Enbridge 58
Reference: Written evidence of Enbridge (Adobe Number A1R0U9), Appendix A-1, page 7, paragraphs 14 to 15.
Preamble: In paragraph 14, Enbridge states: “As a result of dwindling demand and a forecasted decline in light crude oil production in Western Canada, the Montreal Extension was purged with nitrogen and deactivated on July 6, 1991.”
Paragraph 15 states: “The Montreal Extension was reactivated in 1992 to accommodate a request to IPL by the Alberta Petroleum Marketing Commission (the “APMC”), on behalf of Alberta, to provide eastbound service to Montreal for 3,180 to 4,770 m3/d (20,000 to 30,000 b/d).”
Imperial would like to understand how Enbridge views the situation in 1991-1992 compared to the current situation.
Requests: (a) When Enbridge purged the Montreal Extension in 1991, what did it anticipate to be the outlook for future use of the facilities?
(b) Did Enbridge have any knowledge of the potential use of the facilities by the APMC at the time it purged the line?
(c) If the answer to request (b) is no, please explain how the current situation differs from the situation in 1991-1992.
Responses: (a) The request is not relevant to the matters that are before the Board in this proceeding since, at the time in question, the Montreal Extension was operated under the Deficiency Agreement with the Government of Canada.
(b) See response to IOL-Enbridge 58(a).
(c) See response to IOL-Enbridge 58(a).
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IOL-Enbridge 59
Reference: Written evidence of Enbridge (Adobe Number A1R0V5), Appendix A- 7.1, pages 27 and 28, “Line 9 Shipper Interdependencies”
Preamble: Muse identifies the line fill requirement for Line 9 as “approximately 366,800 m3 (2,307 kb).”
In Figure 11, Muse presents what is described as a simple example of the implications of Line 9 throughput on the tolls and the transit time in the pipeline.
Imperial would like to confirm that it fully understands the information presented in the Muse Report.
Requests: (a) Please provide supporting data for the indicated line fill requirement.
(b) Please provide all assumptions and calculations supporting Figure 11 of the Muse Report.
Responses: (a) The indicated line fill requirement is Enbridge’s standard line fill estimate. This number may be checked by calculating the line fill for the 762 mm (NPS-30) pipe that comprises the preponderance of the Line 9 assets.
A NPS-30 pipe with 0.25-inch wall thickness has a cross-sectional area of 0.4410 m2. Therefore, the line fill is: (832 km)(0.4410 m2)(1000 m/km) = 366,912 m3 (2,308,000 barrels). No additional allowance has been added for miscellaneous connections at the terminals and pumping stations or tank inventory.
(b) The transit time is simply the Line 9 line fill (discussed in the response to IOL-Enbridge 59(a)) divided by the indicated Line 9 throughput.
The toll calculation is estimated from the May 1, 2009 Line 9 toll filing (Tariff NEB No. 289). The Line 9 Light Toll of CA$10.645/m3 was understood by Muse to have been developed for 16,000 m3/d of Line 9 throughput. A toll at a different Line 9 throughput is simply the ratio of the throughputs times the CA$10.645/m3. The Older System Light Delivery Terminalling Toll (from Tariff NEB No. 286) (also shown in Tariff NEB No. 289)) of CA$0.560/m3 is then added to finish the calculation. RH-1-2010 Responses of Enbridge to Imperial IRs Page 95 of 323
IOL-Enbridge 60
Reference: Written evidence of Enbridge (Adobe Number A1R0U9), Appendix A-1, page 15, paragraph 39.
Preamble: In paragraph 39, Enbridge states: “Enbridge operates Line 9 in batch mode with turbulent flow. The minimum flow rate is 1,000 m3/hour (6,290 b/hour) to maintain batch mode. The average daily throughput on Line 9, when divided by 24 hours, is now well below the minimum hourly flow rate. Enbridge accordingly operates Line 9 in a start-stop fashion.”
Imperial would like to understand the start-stop operation and what options Enbridge has to optimize the operation of Line 9.
Requests: (a) When did the start-stop operation commence?
(b) Has Line 9 ever operated in start-stop mode at any time in the past?
(c) If the answer to (b) is “yes”, please provide a summary outlining the time periods, the crude slates, volumes shipped and any other operating history for this mode of operation.
(d) Did Enbridge advise the Line 9 shippers of the requirement to commence start-stop operation? Please provide a summary of all communications to shippers on this matter.
(e) Provide all documentation describing the physical integrity impact of start-stop operation on the pipeline.
(f) Provide documentation for the increase in mechanical maintenance work that is required on Line 9.
(g) Provide documentation for integrity and maintenance programs accordingly with corresponding cost increases.
Responses: (a) See response to IOL-Enbridge 3(a).
(b) See response to IOL-Enbridge 3(a).
(c) Attachment 1 to IOL-Enbridge 66(a) provides the average monthly throughput since 2005. For each month in which the average throughput was less than 24,000 m3/d (150,955 b/d), Line 9 was in start-stop operation. RH-1-2010 Responses of Enbridge to Imperial IRs Page 96 of 323
(d) There has been no formal communication.
(e) See response to NEB 1.9(a).
(f) See response to IOL-Enbridge 3(b).
(g) See responses to IOL-Enbridge 3(a) and (b).
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IOL-Enbridge 61
Reference: Written evidence of Enbridge (Adobe Number A1R0V1), Appendix A-3, page 2, paragraph 3.
Preamble: In paragraph 3, Enbridge states: “Enbridge is also sponsoring the report prepared by Muse, Stancil & Co. (“Muse”) entitled “Medium-Term Prospects for Line 9 Westbound Service” and dated December 2009 (“Muse Report”). It was prepared under the supervision of Mr. Neil Earnest, Vice President of Muse; a copy is provided in Appendix A-7.1. Ms. McShane relies, in part, on the Muse Report.”
Imperial would like to understand the terms of Muse’s engagement and the staffing of the assignment by Muse.
Requests: (a) When was Muse engaged for the preparation of the Muse Report?
(b) Please provide the scope of work of the engagement.
(c) What does “medium term”, used in the title of the Muse, Stancil & Co. report, mean in this context?
(d) Who else besides Mr. Neil Earnest worked on the engagement?
(e) Please provide the CV for all individuals named in (d), and identify the specific aspects of the analysis that were prepared by these individuals.
Responses: (a) Muse was engaged for the preparation of the Muse Report on April 1, 2009.
(b) Muse’s work scope was to provide an analysis of the prospects for Line 9 in westbound service. A formal scope of work document does not exist.
(c) Three to 10 years.
(d) Brad Stults, Kevin Giles, Kirk Moser, and Sharon Keeler.
(e) See Attachment 1 to IOL-Enbridge 61(e). Messrs. Stults and Moser and Ms. Keeler assisted with aspects of the pricing calculations and generation of various charts. Mr. Giles assisted with researching the capabilities of the Ontario refineries.
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IOL-Enbridge 62
Reference: Written evidence of Enbridge (Adobe Number A1R0V1), Appendix A-3, page 2, paragraph 5.
Written evidence of Enbridge (Adobe Number A1R0V3), Appendix A-5.
Preamble: In paragraph 5, Enbridge states: “Enbridge prepared a throughput analysis for Line 9 in westbound service; a copy is provided in Appendix A-5. Enbridge’s analysis and expectation that Western Canadian crude oil will continue to increase its penetration into the Ontario market, essentially replacing declining offshore crude supplies, is consistent with the Muse Report.”
Imperial would like to understand the relationship between Muse’s engagement and conclusions, and the work completed by Enbridge in relation to its throughput analysis for Line 9.
Requests: (a) Please provide a specific (paragraph) reference to the location of the throughput analysis which is referred to in Appendix A-5.
(b) When did Enbridge prepare its throughput analysis?
(c) What future time period does Enbridge’s throughput analysis cover?
(d) Did Enbridge rely on any analysis other than Muse’s work, to support its statement that Western Canadian crude oil will continue to increase its penetration into the Ontario market? If so, please provide such analysis.
Responses: (a) Paragraphs 9 through 12 of Appendix A-5.
(b) Enbridge prepared its throughput analysis in Q4 2009.
(c) 2009 and 2010.
(d) No.
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IOL-Enbridge 63
Reference: (i) Written evidence of Enbridge (Adobe Number A1R0V1), Appendix A-3, pages 5 to 6, paragraphs 13 to 15.
(ii) Written evidence of Enbridge (Adobe Number A1R0V5), Appendix A-7.1.
Preamble: In reference (i), Enbridge defines categories of risk in paragraph 13 to include (among others) “supply risk”, “market risk” and “competitive risk”.
In reference (i), Enbridge dismisses supply risk in paragraph 14, because “The supply of crude oil that would be physically available to the Line 9 shippers is accordingly vast.”
In reference (i), Enbridge suggests in paragraph 15, that “the Ontario refiners’ demand for offshore crude oil is expected to continue to decline as supply availability from those regions decreases and prices likely increase, making it less attractive compared to, for example, Western Canadian crude oil.”
Imperial would like to understand Enbridge’s views on crude oil supply.
Requests: (a) Which supply regions did Enbridge consider when dismissing supply risk due to the vast physical availability of crude oil?
(b) Which, if any, of the regions identified in (a) were not included in the scope of work for the Muse analysis? Why not?
(c) Which regions are referred to in reference (i), paragraph 15, as “those regions”?
(d) Are any crude oil production regions experiencing increasing supply? If so, please explain the apparent contradiction with the statement in reference (i), paragraph 15.
Responses: (a) The Atlantic Basin, including supplies available from the Mediterranean, Central Asia, and Russia.
(b) None.
(c) See response to IOL-Enbridge 63(a).
(d) Yes. Paragraph 15 of reference (i) requires clarification. The North Sea crude production is decreasing and the supply orbit for RH-1-2010 Responses of Enbridge to Imperial IRs Page 100 of 323 the North Sea crudes is expected to generally retract to Western Europe over time. Consequently, the price for the North Sea crudes is expected to increase relative to other crudes grades available in the Atlantic Basin, making the North Sea crudes less attractive to the Ontario refiners. However, the increasing supply volume of Western Canadian crude is expected to act to lower their prices relative to the conventional crudes available in the Atlantic Basin for which prices are not changing. Consequently, Muse expects an increased penetration of Western Canadian crude supply into the Ontario market.
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IOL-Enbridge 64
Reference: (i) Written evidence of Enbridge (Adobe Number A1R0V1), Appendix A-3, page 7, paragraph 18.
(ii) Written evidence of Enbridge (Adobe Number A1R0V5), Appendix A-7.1.
Preamble: In reference (i), paragraph 18, Enbridge states: “There is also uncertainty related to the ultimate scope and timing of the re-reversal of Line 9. The entire pipeline, or at least a segment of it (i.e., Line 9B in whole or in part), could remain idle for a time after westbound service ceases. It is possible, moreover, that such a segment may never be re-reversed and thus remain idle.”
Imperial would like to understand Enbridge’s views on the risk and probabilities of Line 9 remaining idle or being re-reversed.
Requests: (a) Does Enbridge consider the re-reversal of Line 9 to be a possible outcome at some point in time?
(b) If the answer to (a) is “yes”, what does Enbridge consider to be an acceptable period of time for Line 9 to remain idle? What does Enbridge consider to be an unacceptable period of time for Line 9 to remain idle? Why?
(c) If the answer to (a) is “yes”, why did Enbridge not include analysis of this outcome in the scope of Muse’s engagement?
Responses: (a) Yes.
(b) Enbridge does not consider any period of time for Line 9 to remain idle to be acceptable. Enbridge’s preference is that Line 9 continue in service in order to generate a return of, and on, its capital for as long as possible. Assuming funds are available to cover the costs of doing so, mechanical integrity of the pipeline can be maintained indefinitely.
(c) It was unnecessary to do so.
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IOL-Enbridge 65
Reference: (i) Written evidence of Enbridge (Adobe Number A1R0V1), Appendix A-3, page 9, paragraph 28.
(ii) Written evidence of Enbridge (Adobe Number A1R0V5), Appendix A-7.1.
Preamble: In reference (i), paragraph 28, Enbridge states: “The time when Line 9 ceases to provide westbound service is uncertain now and, moreover, Line 9 in its entirety or Line 9B (in whole or in part) could remain idle for an extended period after westbound service ceases. Line 9B (in whole or in part) could remain idle indefinitely.”
Imperial would like to understand the relationship between Enbridge’s views on Line 9’s future operation and those presented in the Muse Report.
Requests: (a) Can Enbridge confirm that it considers the time for Line 9 to cease providing westbound service to be uncertain?
(b) If Enbridge sponsored, and concurs with, the Muse Report, does Enbridge agree with the conclusion of the Muse Report, specifically that the probability that Line 9 will be in westbound service by 2016 is very low?
(c) If the answers to (a) and (b) are “yes”, please explain the apparent discrepancy.
(d) What is meant by “extended period” in this context?
(e) If Enbridge is concerned about Line 9 in its entirety or parts thereof becoming or remaining idle, why did it not request Muse to investigate other potential opportunities for use of the pipeline?
(f) Has Enbridge conducted any internal studies or commissioned others to conduct any studies to investigate other potential opportunities for use of the pipeline?
(g) If the answer to (f) is “yes”, please provide all such studies.
Responses: (a) Yes.
(b) Yes. RH-1-2010 Responses of Enbridge to Imperial IRs Page 103 of 323
(c) There is no discrepancy.
(d) In this context an extended period is longer than one year and can be indefinite.
(e) It was not necessary to do so. Enbridge is capable of considering potential opportunities without the assistance of Muse.
(f) See response to IOL-Enbridge 41(a) and (d).
(g) See response to IOL-Enbridge 41(a) and (d).
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IOL-Enbridge 66
Reference: Written evidence of Enbridge (Adobe Number A1R0V3), Appendix A-5, page 2, paragraphs 1 and 3.
Preamble: In paragraph 1, Enbridge provides average daily throughput on Line 9 in westbound service for the period 1999 to 2009.
In paragraph 3, Enbridge states: “Average daily throughput has continued to decline since 2005 and, on a monthly basis, it has become more volatile.”
Imperial would like to have additional detail regarding the Line 9 throughput and operation over this historical period, details of crude deliveries to Ontario, and Enbridge’s outlook for the future.
Requests: (a) Please provide monthly throughput history for the period 1999 to 2009, in m3/d and b/d.
(b) Please provide a definition for each category of crude oil shipped on Line 9.
(c) Please provide monthly shipment information by crude type, for each category of crude oil shipped on Line 9 (Line 9 basket), for the period 1999 to 2009, in m3/d and b/d.
(d) Please provide a list of crude oils accepted into each category of crude oil shipped on Line 9 (Line 9 basket).
(e) Please provide a description of operating constraints that may apply to the delivery of each category of crude oil shipped on Line 9 (Line 9 basket). Include discussion of batch sequencing protocol.
(f) Please provide actual historical crude oil deliveries to Ontario by month from 1999 to 2009, in m3/d and b/d. Include the following categories:
• Line 9 deliveries, by each category of crude shipped; • U.S. crude imports; • U.S. condensate/natural gasoline imports; • Imports via US Gulf Coast, including light sweet, light sour, condensate and any other streams; • Western Canadian crude, including conventional light sweet, conventional light sour, conventional heavy blends, bitumen blends, light sweet synthetic, light sour synthetic, heavy RH-1-2010 Responses of Enbridge to Imperial IRs Page 105 of 323
synthetic and condensate and any other streams.
(g) Please provide a forecast of crude oil supplies to Ontario by year from 2010 to 2025, in m3/d and b/d. Include the following categories:
• Line 9 deliveries, by each category of crude shipped; • U.S. crude imports; • U.S. condensate/natural gasoline imports; • Imports via US Gulf Coast, including light sweet, light sour, condensate and any other streams; • Western Canadian crude, including conventional light sweet, conventional light sour, conventional heavy blends, bitumen blends, light sweet synthetic, light sour synthetic, heavy synthetic, condensate and any other streams.
Responses: (a) See Attachment 1 to IOL-Enbridge 66(a).
(b) Enbridge currently ships crude categorized in four baskets on Line 9: FHP – foreign lube (Sweet) type crudes; FSP – foreign (Sour) high-pour type crudes; FOP – foreign sour type crudes; and FCP – foreign condensate type crudes.
(c) The requested information is commercially sensitive and Enbridge treats this information as confidential. Enbridge therefore objects to filing the information and declines to so.
(d) See Attachment 1 to IOL-Enbridge 66(d).
(e) The following approved Line 9 commodities have seasonal restrictions and can only be transported from May 15 to October 31: Terra Nova; Volve; Azeri Light; Hamaca Blend; and Hibernia. There are no batch sequencing constraints on Line 9. For all other operational constraints, see Tariff NEB No. 290 (http://www.enbridge.com/pipelines/about/pdf/line-9-neb- 290.pdf).
(f) Information concerning historical crude oil deliveries to Ontario is available from Statistics Canada (Catalogue No. 45-004).
(g) The requested information is commercially sensitive and Enbridge treats this information as confidential. Enbridge therefore objects to filing the information and declines to do so.
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IOL-Enbridge 67
Reference: Written evidence of Enbridge (Adobe Number A1R0V3 ), Appendix A-5, pages 2 to 3, paragraphs 3, 4 and 6.
Preamble: Enbridge provides several references to volatility of Line 9 throughput.
In paragraph 3, Enbridge states: “Average daily throughput has continued to decline since 2005 and, on a monthly basis, it has become more volatile.”
In paragraph 4, Enbridge states: “The average daily throughput on Line 9 in 2008 was only 11,000 b/d (1,700 m3/d) greater than Imperial’s committed volume. It follows, in Enbridge’s view, that throughput levels on Line 9 are likely to be less robust and more volatile in the post-TSA era.”
In paragraph 6, Enbridge quotes variances regarding month-to-month deliveries.
Imperial would like to have additional detail regarding the impact of Line 9 throughput variances.
Requests: (a) What, if any, are the negative consequences of volatility in pipeline delivery volumes?
(b) Have any of Enbridge’s other pipelines experienced similar volatility over the period since 2005? If so, please provide details of the variances, on a monthly basis, citing increases and/or decreases.
(c) Please provide current examples of contractual arrangements on any of Enbridge’s other pipelines that include provisions to reduce volatility in throughput.
(d) For the reference from paragraph 4, why does it follow, and what is the basis for Enbridge concluding that it would follow, that throughput levels on Line 9 are likely to be less robust and more volatile in the post-TSA era?
(e) Does Enbridge consider it possible that other factors, such as the broader economic downturn that affected demand for refined products in 2008 and 2009, may have contributed to the cited reduction in throughput over this period? RH-1-2010 Responses of Enbridge to Imperial IRs Page 107 of 323
Responses: (a) As discussed in the responses to NEB 1.9(a) and IOL-Enbridge 3(a), low flow rates can require start-stop operation which, in turn, can have adverse consequences for pipeline operation and integrity. These problems are exacerbated by throughput volatility, which limits Enbridge’s opportunities to optimize its facilities and their operation.
(b) No other pipeline operated by Enbridge Pipelines has experienced similar volatility.
(c) Enbridge has no pipelines other than Line 9. Enbridge Pipelines and affiliates have entered agreements, such as facilities support agreements, that oblige shippers to pay tolls irrespective of whether they ship volumes. Such agreements may reduce throughput volatility on the relevant pipelines.
(d) Enbridge’s view is supported by its experience both before and after the TSA was terminated in April, 2009.
(e) Yes.
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IOL-Enbridge 68
Reference: Written evidence of Enbridge (Adobe Number A1R0V3), Appendix A-5, page 4, paragraph 12.
Preamble: In paragraph 12, Enbridge states: “Enbridge’s forecast for 2010 is based on the 10-month actual average daily throughput in 2009. The volatility of throughput on Line 9 historically and particularly in 2009 has made it too difficult to forecast throughput for 2010 with any confidence. In addition to changes in supply markets, lower refinery utilization in Ontario has had a bearing on deliveries by Line 9.” Enbridge has developed its 2010 forecast for Line 9 throughput based on 2009 actual data. Imperial would like to understand Enbridge’s approach to forecasting, and its resulting outlook for Line 9 throughput. Requests: (a) Are there any factors that may contribute to higher refinery utilization in Ontario in 2010? Include consideration of any announcements regarding refinery rationalization within the last year.
(b) If any factors identified in (a) were not considered when formulating the 2010 throughput forecast, please explain why.
(c) Does Enbridge’s approach to throughput forecasting for Line 9 differ from its approach to throughput forecasting on other parts of its system? Please explain.
Responses: (a) Yes. An improvement in general economic conditions could lead to higher refinery utilization in Ontario in 2010.
(b) See the response to IOL-Enbridge 69(a).
(c) Enbridge, as defined for purposes of the Application, has no pipelines other than Line 9. A quantitative forecasting methodology for Line 9 would require Enbridge to predict the actions or inactions of just two shippers, one of which operates a petrochemical facility. Accordingly, Enbridge regards a quantitative analysis as neither practical nor possible. Recent historical throughput information is instead used to develop a forecast. Enbridge Pipelines does not face this situation elsewhere across its system and, thus, its approach to throughput forecasting differs from Enbridge’s approach to forecasting in respect of its facilities.
RH-1-2010 Responses of Enbridge to Imperial IRs Page 109 of 323
IOL-Enbridge 69
Reference: Written evidence of Enbridge (Adobe Number A1R0V3 ), Appendix A-5, page 4, paragraphs 13 to 15.
Preamble: In paragraph 13, Enbridge states: “Enbridge Pipelines’ supply and demand forecasts for Western Canadian crude oil (including condensate) take into consideration the Ontario refiners’ historical runs of offshore crude oil after adjusting for Petro-Canada’s closure of its Oakville refinery in April 2005.”
Paragraphs 14 and 15 include statements regarding Enbridge’s expectations for an increase in the penetration of Western Canadian crude oil into the Ontario market, and that a portion of this increase will flow to Ontario refiners via the mainline system.
Imperial would like to have more information about Enbridge’s forecasts, and its methodology for preparing its forecasts.
Requests: (a) What other factors beside Ontario refiners’ historical runs of offshore crude, if any, does Enbridge consider when preparing its throughput forecasts for Ontario refiners? Please explain.
(b) What quantitative analysis has Enbridge undertaken to support its view that penetration of Western Canadian crude oil into Ontario will occur? Please provide any such analysis.
(c) Describe Enbridge’s methodology for throughput forecasting, with particular reference to Line 9 throughput forecasting.
Responses: (a) Enbridge Pipelines does not attempt to use a quantitative analytical approach to predict Ontario crude receipts because of the small number of refiners involved. Instead, Enbridge Pipelines primarily relies upon historical demand data to develop its forecast for Ontario. See response to IOL-Enbridge 68(c).
(b) Enbridge engaged Muse to provide such quantitative analysis. Muse did so in the form of the Muse Report.
(c) Enbridge has no pipelines other than Line 9. See response to IOL- Enbridge 68(c).
RH-1-2010 Responses of Enbridge to Imperial IRs Page 110 of 323
IOL-Enbridge 70
Reference: Written evidence of Enbridge (Adobe Number A1R0V3), Appendix A-5, page 5, paragraphs 17 to 18.
Preamble: In paragraph 17, Enbridge implies that significant growth in Western Canadian supply, and in particular, light synthetic crude, will result in the need for increased penetration in traditional markets, such as Ontario.
In paragraph 18, Enbridge states: “Muse notes that the impact of this price pressure has been demonstrated in the last few years where the price of crude oil delivered via Line 9 have been at a disadvantage in Ontario compared to Western Canadian crude oil. Muse does not foresee this pricing dynamic changing. This view is supported by the ongoing declines in North Sea crude production, which historically has been an important source of supply for the Ontario refiners.”
Imperial would like to have more information about the scope of Muse’s analysis, and the breadth of Enbridge’s forecast preparation.
Requests: (a) Does Enbridge or Muse prepare its own forecast of light synthetic crude oil supply? If so, please provide same.
(b) Does Enbridge or Muse prepare its own forecast of North Sea crude oil supply? If so, please provide same.
(c) Does Enbridge or Muse prepare its own forecast of crude oil supply from other Atlantic Basin sources? If so, please provide same.
(d) Has a competitive analysis for Line 9 deliveries versus Western Canadian deliveries been completed for the forecast period to 2016? If so, did the competitive analysis take into account anticipated Enbridge tolls on its mainline over that period?
(e) How much North Sea crude oil has been supplied to Ontario refiners since 2005? Please provide details on a monthly basis.
(f) If the answer to (d) is “no”, please provide a competitive analysis for Line 9 deliveries versus Western Canadian deliveries for the forecast period. In doing so, please take into account anticipated Enbridge tolls on its mainline over that period.
(g) What is meant by “the impact of this price pressure”? RH-1-2010 Responses of Enbridge to Imperial IRs Page 111 of 323
(h) What factors, other than the decline of North Sea production, did Muse consider when determining that the pricing dynamic is not likely to change?
Responses: (a) No.
(b) No.
(c) No.
(d) Other than to the extent that the Muse study addresses this issue, Enbridge has not prepared such an analysis and declines to do so.
(e) Annual information regarding Ontario crude deliveries from the United Kingdom and Norway is provided in Attachment 1 to IOL- Enbridge 163. Monthly information regarding supplies to Ontario from these suppliers is available from Statistics Canada (Catalogue No. 45-004).
(f) Other than to the extent that the Muse study addresses this issue, Enbridge has not prepared such an analysis and declines to do so.
In the RH-2-2007 proceeding, Imperial commissioned Purvin & Gertz, Inc. to prepare the report entitled “Outlook for Enbridge Line 9 Viability”, which provides a competitive analysis for Line 9 deliveries versus Western Canadian deliveries through 2025. The report is available at the following link: https://www.neb-one.gc.ca/ll- eng/livelink.exe/fetch/2000/90465/92835/155829/544980/459963/ 460904/463563/473390/C-6-6e_-_P- G_Report__A0Z8X3.pdf?nodeid=473288&vernum=0
(g) The impact of increasing supply pressure from Western Canada, which is reflected in lower Western Canadian crude prices (price pressure), is discussed at pages 18 through 21 of Appendix A-7.1. Both of Figures 9 and 10 in Appendix A-7.1 illustrate that crude delivered via Line 9 has generally been at a price disadvantage relative to Western Canadian supply for the last several years.
(h) A key aspect of the current crude pricing dynamics is that Western Canadian crude supply exceeds inland demand, shifting the price parity point south and lowering Canadian crude prices. This shift has, among other things, prompted Canadian crude producers to support the construction of a new pipeline to the U.S. Gulf Coast (Keystone XL) to better access a broader market. Western Canadian crude supply is expected to continue to increase, and there is very low probability that new refineries will be constructed RH-1-2010 Responses of Enbridge to Imperial IRs Page 112 of 323 in the inland markets that will create additional inland demand. Consequently, the pricing dynamic is not expected to change. RH-1-2010 Responses of Enbridge to Imperial IRs Page 113 of 323
IOL-Enbridge 71
Reference: (i) Written evidence of Enbridge (Adobe Number A1R0V1), Appendix A-3, page 2, paragraph 5.
(ii) Written evidence of Enbridge (Adobe Number A1R0V3), Appendix A-5, page 4, paragraph 12.
Preamble: In paragraph 5 of reference (i), Enbridge states: “Enbridge prepared a throughput analysis for Line 9 in westbound service; a copy is provided in Appendix A-5.”
In paragraph 12 of reference (ii), Enbridge states: “Enbridge’s forecast for 2010 is based on the 10-month actual average daily throughput in 2009.”
Imperial would like to understand Enbridge’s forecast preparation.
Requests: (a) Is it typical for Enbridge to prepare its throughput forecasts based only on historical average daily throughput?
(b) If the answer to (a) is “no”, please provide an explanation of its typical methodology for forecast preparation.
(c) Did Enbridge follow its typical methodology in preparing the Line 9 forecast?
(d) If the answer to (c) is “no”, please explain.
(e) Please provide details of the methodology used by Enbridge to prepare the throughput analysis, the parties contacted in relation to the analysis, and any work products prepared during the analysis that support Enbridge’s view about throughput.
Responses: (a) Enbridge has always relied upon the historical throughput data to develop its forecasts for Ontario.
(b) Not applicable.
(c) Yes.
(d) Not applicable.
(e) See paragraph 12 of Appendix A-5,.
RH-1-2010 Responses of Enbridge to Imperial IRs Page 114 of 323
IOL-Enbridge 72
Reference: Written evidence of Enbridge (Adobe Number A1R0V3 ), Appendix A-5, page 6, paragraph 20.
Preamble: In paragraph 20, Enbridge states: “Muse expects that, by 2015, the Nabiye phase of the Cold Lake project will be operational. Imperial is also proceeding with the first phase of its Kearl Oil Sands project (“Kearl”), with production to begin in 2012. Muse considers that it is entirely possible that production from Kearl’s second phase – starting in 2016 – will be processed in Ontario. If Imperial were to modify its Ontario refineries to process incremental heavy crudes, then Enbridge considers that Kearl and Cold Lake production would likely displace Imperial’s volumes on Line 9.”
Imperial would like to understand Enbridge’s statements regarding the potential supply and disposition of crude oil from Imperial projects.
Requests: (a) What probability does Enbridge assign to the outcome that Ontario refiners will process Kearl production?
(b) What probability does Enbridge assign to the outcome that Ontario refiners will process incremental Cold Lake production?
(c) How were probability figures in (a) and (b) arrived at?
(d) What disposition does Muse expect for Kearl’s first production phase?
(e) Does Muse consider it entirely possible that production from Kearl’s second phase could be processed in any other refineries besides those in Ontario? If so, please provide a complete list of such refineries that are accessible by pipelines from Western Canada.
(f) Highlight any refineries listed in (e) that would be capable of processing Kearl production without modification.
(g) What modifications would be required in Imperial’s Ontario refineries to allow the processing of incremental heavy crude?
(h) Is Enbridge or Muse aware of any firm plans by Imperial to modify its Ontario refineries to process incremental heavy crudes? If so, please provide details. RH-1-2010 Responses of Enbridge to Imperial IRs Page 115 of 323
Responses: (a) Enbridge has not assigned a probability to the outcome that Ontario refiners will process Kearl production.
(b) Enbridge has not assigned a probability to the outcome that Ontario refiners will process incremental Cold Lake production.
(c) Not applicable.
(d) The blended production from the first phase of the Kearl Oil Sands project will likely flow to all of the current markets for Canadian heavy crude oil.
(e) Yes. See Attachment 1 to IOL-Enbridge 72. The listed refineries are those that are estimated by Muse to be capable of processing more than approximately 5%, of their total crude slate, of heavy sour crude.
(f) All of the refineries listed in Attachment 1 to IOL-Enbridge 72 are estimated by Muse to be capable of processing some amount of Kearl blended bitumen.
(g) The required modifications will be influenced by the desired amount of incremental heavy crude runs. Small increases in heavy crude runs are likely possible via the re-optimization of the overall refinery crude slate, possibly combined with increased asphalt production. More substantive increases in heavy crude runs will require the modification or construction of refinery process units and supporting infrastructure.
(h) No.
RH-1-2010 Responses of Enbridge to Imperial IRs Page 116 of 323
IOL-Enbridge 73
Reference: Written evidence of Enbridge (Adobe Number A1R0V5), Appendix A- 7.1, pages 4 to 5.
Preamble: In the last paragraph of page 4, Muse states: “evaluates the probability that the two key shippers on Line 9 will continue to ship.”
On page 5, Muse characterizes the two key shippers based on their motivation to continue using Line 9 or consider alternatives.
Imperial would like to understand Muse’s probability estimates, and to understand how the same approach may be applied to other refiners or group of refiners.
Requests: (a) Are there any other potential shippers on Line 9? If so, please identify those potential shippers, and the destination of their deliveries.
(b) Does Muse consider any of the other potential shippers to be likely candidates for processing crude delivered by Line 9? Please explain.
(c) In westbound operation, would Shell or Suncor be potential shippers on Line 9? If not, please explain.
(d) In eastbound service, would the following refiners or groups of refiners potentially be shippers on Line 9:
• East Coast Canada refiners (Imperial Dartmouth, NS; Irving Saint John, NB; Harvest Energy Come-by-Chance, NL); • Quebec refiners (Suncor Montreal, Ultramar St. Romuald); • U.S. Atlantic Coast (PADD I) refiners; • European refiners.
(e) For the refiners or groups of refiners identified above, please provide an explanation of processing or market constraints, or the opportunities that may be realized by processing Western Canadian crude oil.
Responses: (a) Yes. Shell and Suncor for delivery to their Sarnia area refineries. United Refining for delivery to its Warren, Pennsylvania refinery.
(b) No. Based upon a review of EIA import data, the United Warren refinery has never used Line 9 in westbound service. The Shell RH-1-2010 Responses of Enbridge to Imperial IRs Page 117 of 323
and Suncor Sarnia refineries have processed Line 9 crude in the past, and remain capable of processing Line 9 crude. The crude pricing relationships present for the last several years have made supply from Western Canada more attractive than Line 9 supply for these refiners.
(c) Yes.
(d) Of those refiners or groups of refiners listed in the request item, Line 9 in eastbound service can access only the Suncor Montreal refinery, assuming that the Shell Montreal refinery is closed. Practical access to all other refiners or groups of refiners would also require the reversal of one or both of the pipelines operated by the Portland-Montreal Pipe Line. Subject to such a reversal, the identified refiners are potential shippers.
(e) All of the identified refiners are capable of processing Western Canadian light sweet conventional crudes, most are capable of processing some volume of conventional medium sour and light synthetic grades, and some will be capable of processing heavy sour grades. The processing constraints include desulfurization capability, residuum conversion capacity, asphalt and heavy fuel oil production capacity, and various finished product specifications.
RH-1-2010 Responses of Enbridge to Imperial IRs Page 118 of 323
IOL-Enbridge 74
Reference: Written evidence of Enbridge (Adobe Number A1R0V5), Appendix A- 7.1, page 6.
Preamble: Muse states, in relation to Imperial’s Nanticoke Refinery: “The refinery’s preferred crude slate can also shift away from the crude types delivered by Line 9 via a refinery upgrading project to process more Western Canadian heavy sour, by a substitution of Western Canadian synthetic for conventional light crude, by increased runs of Western Canadian heavy sour for asphalt production, or from some combination of all three.”
Muse has relied on comparisons of Western Canadian and competitive crudes delivered via Line 9 for its analysis of Nanticoke refinery supply economics.
Imperial would like to understand Muse’s statement regarding Imperial Nanticoke.
Requests: (a) What would the capital cost be for an Imperial Nanticoke refinery upgrading project to allow processing of more Western Canadian heavy sour crude oil?
(b) What would the capital cost be for an Imperial Nanticoke refinery project to allow substitution of Western Canadian synthetic crude for conventional light crude?
(c) What would the capital cost be for an Imperial Nanticoke refinery project to allow increased runs of Western Canadian heavy sour for asphalt production?
(d) If Imperial Nanticoke were to process additional runs of Western Canadian heavy sour for asphalt production, what would be the effect on the existing markets for asphalt served by Imperial’s Ontario refineries?
(e) For any of the crude slate changes (or combinations thereof) identified in the preamble, please provide supporting comparative analysis of refinery supply economics after completion of the project(s). Include fixed and variable cost impacts.
Responses: (a) The capital cost will be a function of how much more Western Canadian heavy sour crude Imperial desires to process at the Nanticoke refinery. A sizable increase in heavy sour crude runs RH-1-2010 Responses of Enbridge to Imperial IRs Page 119 of 323
would require an expensive capital project.
(b) The Nanticoke refinery is a conventional cracking configuration that does not produce lubricants or other specialty products. It can almost certainly process some volume of Western Canadian synthetic crude today.
(c) Unknown. The capital cost, if any for modest or moderate run increases, will be a function of the amount of heavy sour crude that Imperial desires to process.
(d) The market impact will be influenced by a number of factors, including the incremental asphalt volume Imperial seeks to produce, the rate of change in asphalt demand in Ontario, the degree of difficulty in displacing asphalt imports or inter- provincial transfers, and the asphalt export and inter-provincial transfer opportunities. Once Marathon completes the construction of a coker at its Detroit refinery, Marathon may be reducing its asphalt production at Detroit. This may reduce asphalt imports into the Ontario market or increase Imperial’s export opportunities. In addition, the closure of the Shell Montreal refinery, which produces asphalt, may provide an asphalt marketing opportunity for Imperial.
(e) The request is understood to speak to the comparative economics of supplying Nanticoke from Western Canada versus the Atlantic Basin. The Nanticoke refinery is not regarded as being sufficiently large such that an upgrading project (or increased heavy runs for asphalt production) would significantly influence the price of Canadian heavy sour at Hardisty or Edmonton. Thus, the supply economics remain unchanged relative to Line 9 deliveries.
RH-1-2010 Responses of Enbridge to Imperial IRs Page 120 of 323
IOL-Enbridge 75
Reference: Written evidence of Enbridge (Adobe Number A1R0V5), Appendix A- 7.1, pages 6 to 7.
Preamble: Muse quotes Mr. Bruce March from the Imperial Oil Ltd. Investor Day Q&A session, May 26, 20093, in relation to potential disposition of production from Imperial’s Kearl Oil Sands project.
Imperial would like to confirm that the quote provided in the Muse Report is not taken out of context.
Requests: (a) Please provide the full content of Mr. March’s reply on pages 5-7 of the referenced Q&A session.
(b) Please confirm that Mr. March’s comments also include mention of other possible dispositions for Imperial’s Kearl production, including (i) marketing Kearl to other upgraders in the Alberta area, and (ii) other third party opportunities in the upper Midwest and eventually, the Gulf Coast.
(c) Please confirm that Mr. March’s comments also suggest that third party opportunities for Kearl might allow the crude to reach the Gulf Coast shortly after 2012.
(d) Please confirm that Mr. March’s comments also suggest that its partner in Kearl (i.e. ExxonMobil) has “some very good conversion facilities in the upper Midwest and on the Gulf Coast both”.
(e) In the event that Kearl production serves any of the other market opportunities mentioned above, what would the implications be for the crude supply and economics for Imperial Nanticoke refinery? Please provide a detailed explanation.
Responses: (a) See Attachment 1 to IOL-Enbridge 75.
(b) Confirmed.
(c) Confirmed.
(d) Confirmed.
3 http://www.imperialoil.ca/Canada-English/Files/News/N_S_QA_090526_27.pdf. RH-1-2010 Responses of Enbridge to Imperial IRs Page 121 of 323
(e) Imperial will likely market its Kearl production in all of the market opportunities discussed by Mr. March. However, the crude supply economics for the Nanticoke refinery are essentially unchanged. It is Muse’s expectation that the purchase of Kearl production by Imperial’s downstream division would be made on an arms-length basis and, therefore, the Nanticoke refinery would be paying no more or less at Edmonton than any other buyer. It is not Muse’s expectation that the Nanticoke refinery will have access to discounted supply from the Kearl Oil Sands project. Nonetheless, it is Muse’s experience that integrated oil companies generally maximize throughput of their equity production in their own refining assets as long as there are no other buyers prepared to pay more for the equity production than its internal value.
It is Muse’s view that Imperial will look first to run Kearl at its own refining assets, as Mr. March has clearly indicated. And if the market price for Kearl is such that it provides attractive refinery upgrading economics, then it is Muse’s expectation that Imperial will carefully consider the merits of further upgrading its Ontario refineries to capture the upgrading economics. For example, Marathon is currently upgrading its Detroit refinery to process Canadian heavy production. Attachment 2 to IOL-Enbridge 75 provides further details regarding the cost of the upgrading project, the expected feedstock cost savings, and the location advantage available to a refinery in Detroit versus the U.S. Gulf Coast.
RH-1-2010 Responses of Enbridge to Imperial IRs Page 122 of 323
IOL-Enbridge 76
Reference: Written evidence of Enbridge (Adobe Number A1R0V5), Appendix A- 7.1, pages 6 to 8.
Preamble: (i) Muse states that “by about 2016, Imperial is expected by Muse to have commissioned the second phase of its massive Kearl Oil Sands project” and “it is Muse’s assessment that by 2016, when the second phase of the Kearl Oil Sands project is commissioned, there is a very low probability that Imperial will be a westbound shipper on Line 9. Indeed, it is entirely possible that in the next several years Imperial will shift solely to crudes from Western Canada, …”
(ii) Muse goes on to conclude that “The termination of westbound shipments is entirely possible, even likely, in the next several years. By 2016, it is Muse’s assessment that the probability that Line 9 will be in westbound service is very low.”
Imperial would like to understand the basis for Muse’s expectations regarding the Kearl Oil Sands project, and the conclusion regarding Line 9.
Requests: (a) Please provide supporting documentation upon which Muse bases its expectations for the timing of the second phase and third phases of the Kearl Oil Sands project.
(b) Is Muse’s conclusion regarding the probability of Line 9 operating in westbound service by 2016 related to its expectation of timing for the second phase of the Kearl Oil Sands project?
(c) If the answer to (b) is “no”, please explain how Muse arrived at its conclusion regarding the probability of Line 9 operating in westbound service by 2016?
(d) If the answer to (b) is “yes”, please explain how Muse’s conclusions regarding the probability of Line 9 operating in westbound service would change if the second phase of the Kearl Oil Sands project were delayed by two years? Five years?
(e) What is meant by “entirely possible” in the context of (i)? In the context of (ii)?
Responses: (a) The rationale for Muse’s expectations regarding the timing of the second and third phase of the Kearl Oil Sands project is based upon the Imperial 2009 investor meeting presentation, page 36, RH-1-2010 Responses of Enbridge to Imperial IRs Page 123 of 323
which indicated that Imperial “...will use our “design one, build many” strategy to develop Kearl in three phases with initial production in late 2012 followed by subsequent phases later in the decade.”
(b) Yes, it is related to the expected timing, but not exclusively.
(c) Not applicable.
(d) The probability of Line 9 operating in westbound service in 2016 would increase slightly if phase two of the Kearl Oil Sands project were delayed by two or five years.
(e) Imperial is free to immediately discontinue Line 9 shipments if it desires. The termination of westbound shipments by Imperial is regarded as likely in the next several years.
RH-1-2010 Responses of Enbridge to Imperial IRs Page 124 of 323
IOL-Enbridge 77
Reference: Written evidence of Enbridge (Adobe Number A1R0V5), Appendix A- 7.1, pages 9 to 14.
Preamble: Muse discusses crude processing capabilities of individual refineries, including the requirements to process sour and heavy crude.
Imperial would like to understand how Muse arrives at its conclusions regarding capabilities of Ontario refineries in this regard.
Requests: (a) For each Ontario refinery, provide details of the refinery configuration and Muse’s analysis that led to the determination of crudes processed by each refinery.
(b) With reference to Figure 2, it is not clear in the case of the Ontario refineries that the following statement on page 10 (Adobe page number) applies: “Consequently, Canadian refiners have been steadily modifying their refineries to process more of the Western Canadian synthetic and heavy crudes.” Please explain.
Responses: (a) The refinery configuration details are provided in Attachment 1 IOL-Enbridge 77. These details are obtained from the Oil & Gas Journal 2009 Worldwide Refining Survey.
Neither the Shell nor Suncor Sarnia refineries have significant capability to convert the heaviest portion of the crude barrel (residuum) to light transportation fuels. Nor do these refineries produce asphalt. Consequently, this type of refinery configuration typically limits its crude slate to the lighter grades that do not contain much residuum. Moreover, Suncor’s 2009 Annual Information Form (dated March 5, 2010) indicates that 74% of its Sarnia refinery’s crude slate was synthetic crude, with the balance being conventional crudes obtained primarily from Western Canada.
Statistics Canada data indicates that, in 2009, approximately 9,530 m3/d (59,800 b/d) of conventional heavy and blended bitumen were processed somewhere in Ontario. The Imperial Sarnia refinery is the only refinery in Ontario that operates a coker (which converts residuum into light transportation fuels), and the Nanticoke refinery is the only Ontario refinery that currently produces asphalt. Accordingly, these two refineries are estimated to be the primary consumers of heavy sour crude in Ontario. Moreover, this estimation is supported by the Imperial Oil 2005 RH-1-2010 Responses of Enbridge to Imperial IRs Page 125 of 323
Information for Investors booklet, dated May 2005, which indicates that Imperial Sarnia processes “conventional heavy, medium and light Cold Lake blend.” The Imperial 2006 Annual Report comments that “the Nanticoke refinery continued to increase its capability to process Cold Lake blend to manufacture asphalt.”
(b) The statement was not intended to be specific to the Ontario refiners.
RH-1-2010 Responses of Enbridge to Imperial IRs Page 126 of 323
IOL-Enbridge 78
Reference: Written evidence of Enbridge (Adobe Number A1R0V5), Appendix A- 7.1, page 21.
Preamble: Muse states: “Muse uses the Platts Oilgram Price Report (Platts) as its source of crude prices.”
Imperial would like to understand whether the Muse analysis took into account the availability of other price assessments, company postings, and the impact, if any, on the results of the analysis.
Requests: (a) Is Muse aware of any other sources for Canadian crude price assessments?
(b) Can Muse confirm that Natural Gas Exchange Inc. (“NGX”) provides a range of price indices for Canadian crude oil, including Alberta sweet crude and Light Sour Blend?
(c) How would the results of Muse’s analysis for Brent-MSW and Urals-LSB change using a different price assessment?
(d) Please provide an indication of how representative the Platts price assessment is for the Mixed Sweet price, including a monthly historical comparison to company postings and the NGX price index for the period 2000 to 2009?
(e) Please provide an indication of how representative the Platts price assessment is for the Light Sour Blend price, including a monthly historical comparison to company postings and the NGX price index for the period 2000 to 2009.
Responses: (a) Argus and Platts provide assessments of Canadian crude prices. Natural Gas Exchange Inc. (“NGX”) provides various volume- weighted price indexes of Canadian crudes.
(b) Confirmed.
(c) Unknown. Muse has not conducted an analysis with a different price assessment.
(d) Platts describes its Mixed Sweet assessment as reflecting a market- on-close value at 3:15 PM Eastern Time for injection at Edmonton on the first forward month. To the best of Muse’s knowledge, Platts regards its Mixed Sweet assessment as being entirely RH-1-2010 Responses of Enbridge to Imperial IRs Page 127 of 323
representative of a market-on-close value for Mixed Sweet at 3:15 PM Eastern Time for injection at Edmonton on the first forward month. Muse does not maintain records of individual company postings. Attachment 1 to IOL-Enbridge 78 provides a comparison of the Platts Par Crude postings assessment to the Platts Mixed Sweet spot assessment. The Par Crude is described by Platts as a 40.02°API, 0.3 wt% sulphur crude, whereas the Mixed Sweet is described as a 38.8°API, 0.47 wt% sulphur crude. Muse does not have access to the NGX price indexes.
A review of Attachment 1 to IOL-Enbridge 78 indicates that over the period January 2004 to March 2010 the Platts Mixed Sweet spot price averaged US$0.51/bbl higher than the Platts Par 40 posted price (the spot price series only began in August 2003). Consequently, had the posted price been used for Mixed Sweet in Figure 9 of the Muse report, the “Brent Advantage” would have been US$0.51/bbl lower on average since 2004. Similarly, for Figure 10 of the Muse report, had the Light Sour posted price been used instead of the Light Sour spot price, the Urals advantage would have been US$1.43/bbl lower since 2004. Accordingly, the use of posted prices, rather than spot, would have widened the supply advantage for the Western Canadian crudes relative to the Atlantic Basin competition.
(e) Platts describes its Light Sour Blend assessment as reflecting a market-on-close value at 3:15 PM Eastern Time for injection at Cromer on the first forward month. To the best of Muse’s knowledge, Platts regards its Light Sour Blend assessment as being entirely representative of a market-on-close value for Light Sour Blend at 3:15 PM Eastern Time for injection at Cromer on the first forward month. Attachment 1 to IOL-Enbridge 78 provides a comparison of the Platts Cromer Light Sour postings assessment to the Platts Light Sour Blend spot assessment. The Cromer Light Sour is described by Platts as having an average posted gravity of 35.05°API, and an average sulphur content of 1.2 wt%, whereas the Light Sour Blend is described as a 34-36°API, 1.2-1.4 wt% sulphur crude. Muse does not have access to the NGX price indexes.
RH-1-2010 Responses of Enbridge to Imperial IRs Page 128 of 323
IOL-Enbridge 79
Reference: Written evidence of Enbridge (Adobe Number A1R0V5), Appendix A- 7.1, page 22.
Preamble: Muse discusses crude quality corrections for Brent and (Alberta) Mixed Sweet. Muse states: “This crude quality correction is based upon a cracking refinery yield and product pricing on the U.S. Gulf Coast and, thus, the quality correction is not specific to the Imperial Nanticoke refinery.”
Imperial would like to understand how applicable the quality correction is to the Nanticoke situation.
Requests: (a) Provide a detailed description of the cracking refinery used for this analysis, the yields for Brent and Alberta Mixed Sweet used to determine the quality correction, and the product pricing used.
(b) Provide all calculations done to determine quality corrections for the historical period shown in the report.
(c) Would Muse expect quality corrections at the U.S. Gulf Coast to be applicable to Imperial Nanticoke? Explain.
(d) Would Muse expect quality corrections for Brent and Alberta Mixed Sweet to apply to other delivered crudes? Explain.
(e) Please provide an indication of how the quality correction at Imperial Nanticoke might differ from the U.S. Gulf Coast.
(f) What factors might contribute to making the approach taken by Muse an inappropriate basis of comparison for Nanticoke? Consider differences in product pricing fundamentals.
Responses: (a) The yields from the cracking refinery representation used by Muse can be found in Attachment 1 to IOL-Enbridge 79. The cracking refinery is intended to represent a generic U.S. Gulf Coast refinery that utilizes a fluidized catalytic cracking unit as its primary heavy oil conversion unit and produces heavy fuel oil. The U.S. Gulf Coast product prices found in the attachment are from Platts.
(b) See Attachment 1 to IOL-Enbridge 79.
(c) Muse would expect Nanticoke-specific quality corrections to generally track U.S. Gulf Coast quality corrections. RH-1-2010 Responses of Enbridge to Imperial IRs Page 129 of 323
(d) No. Other delivered crudes would have a different quality correction relative to Mixed Sweet or Brent.
(e) The product yield set for Imperial Nanticoke while processing Mixed Sweet and Brent will not be identical to the yield sets generated by Muse for a U.S. Gulf Coast cracking configuration. Product pricing relationships will also differ between Ontario and the U.S. Gulf Coast.
Ontario bulk spot finished petroleum product prices are not available to compare to U.S. Gulf Coast prices; however, bulk spot prices are available for Chicago. Since 2000, Chicago unleaded regular gasoline prices have averaged 2.60 ¢/gal over the U.S. Gulf Coast price, and low sulphur diesel (500 ppm) has averaged 3.75 ¢/gal over the U.S. Gulf Coast. Consequently, a northern refiner has had a slightly greater incentive (of 1.15 ¢/gal) to produce diesel versus gasoline since 2000. In Muse’s cracking refinery configuration, Brent produces about 3% more distillate (jet + diesel) than Mixed Sweet, and about 3% less gasoline. The approximate impact upon the quality adjustment between Brent and Mixed Sweet would be equal to: (1.15 ¢/gal)(42 b/gal)(0.03)/(100 ¢/$) = US$0.015/bbl. This is an immaterial impact upon the overall quality adjustment.
Regarding the applicability of Chicago prices to Ontario, Imperial’s 2010 Management Discussion and Analysis document comments on page A6 that: “Canadian wholesale [product] prices in particular are largely determined by wholesale prices in adjacent U.S. regions.” The Chicago and Detroit markets are connected by a high-capacity finished product pipeline, and prices in these two areas track each other.
(f) See response to IOL-Enbridge 79(e). RH-1-2010 Responses of Enbridge to Imperial IRs Page 130 of 323
IOL-Enbridge 80
Reference: Written evidence of Enbridge (Adobe Number A1R0V5), Appendix A- 7.1, page 22.
Preamble: Muse discusses delivered crude price comparisons at Nanticoke.
Imperial would like to understand how Muse interprets the results of the delivered crude price analysis.
Requests: (a) What defines “extremely attractive” opportunity for the Ontario refiners, versus, for example, “attractive”, “unattractive” or “extremely unattractive” opportunities for crude selection?
(b) In Muse’s experience, what decision process might be considered typical for a refiner when facing crude selection opportunities that are “extremely attractive”?
(c) How applicable is the decision process outlined in (b) to the case of Imperial Oil for Nanticoke?
(d) In Muse’s experience, how might the above process change if crude selection opportunities were merely “attractive”?
Responses: (a) The differences between the various adverbs and adjectives cited cannot be quantified.
(b) The refiner will investigate means to exploit the market opportunity presented.
(c) It is Muse’s expectation that Nanticoke, like almost all refineries, will seek to exploit attractive market opportunities.
(d) The general process will remain unchanged, but the urgency may change.
RH-1-2010 Responses of Enbridge to Imperial IRs Page 131 of 323
IOL-Enbridge 81
Reference: Written evidence of Enbridge (Adobe Number A1R0V5), Appendix A- 7.1, page 23.
Preamble: Muse discusses the process through which refiners evaluate crude pricing “discrepancies”, and take advantage of these opportunities through their buying and selling actions. Muse states: “Consequently, if Brent is not attractive in Nanticoke, no other grade of light sweet crude in the Atlantic Basin will be attractive due to a lower delivered price (adjusted for crude quality differences).”
Imperial would like to understand Muse’s conclusion regarding the available alternatives to Brent.
Requests: (a) Has Muse considered every possible light sweet crude in the Atlantic Basin in its analysis?
(b) If the answer to (a) is “no”, please indicate how Muse is able to conclude that no other grade of light sweet crude in the Atlantic Basin will be attractive?
(c) Is Muse aware of any prospective light sweet or light sour crude oil developments in the Atlantic Basin that may potentially provide crude oil for Line 9 delivery within the timeframe of the analysis (i.e. before 2017)? If so, please identify same.
(d) Have crude quality differences been determined for any other sweet crudes in the Atlantic Basin, delivered to Nanticoke? If so, please provide complete details.
Responses: (a) In effect, yes. Most of the light sweet crudes available in the Atlantic Basin are delivered by water and their market dispositions are not limited to the pipeline delivery points. Consequently, refiners are free to seek out the light sweet crude grade that, on a delivered basis, provides the most value (quality adjusted). Brent Blend is a readily available and widely traded crude. If there had been light sweet crudes in the Atlantic Basin that were consistently more attractively priced than Brent, then refiners would have stopped buying Brent and purchased the alternative. Consequently, the price of Brent and the light sweet alternative would quickly come into equilibrium.
(b) Not applicable. RH-1-2010 Responses of Enbridge to Imperial IRs Page 132 of 323
(c) See Attachment 1 to IOL-Enbridge 81.
(d) No.
RH-1-2010 Responses of Enbridge to Imperial IRs Page 133 of 323
IOL-Enbridge 82
Reference: Written evidence of Enbridge (Adobe Number A1R0V5), Appendix A- 7.1.
Preamble: The Muse Report includes comparison of the following crude oils at Sarnia:
• Brent vs. MSW • Urals vs. LSB • Saharan Blend via Line 9 vs. Capline-Chicap-Line 6B
Imperial would like to understand how Muse’s results would change for other crude oils or any other premise.
Requests: (a) Why was Brent selected as a representative crude when there is very little North Sea sweet currently shipped via Line 9? (b) What other sources of light crude are available within the Atlantic Basin for delivery via Line 9? Consider all major supply regions including offshore Eastern Canada, West Africa, Caspian (via Mediterranean) and Latin America. (c) Are there any recent or pending industry developments, such as pipeline infrastructure projects, that might change the results presented in the Muse Report by making Western Canada less attractive in Ontario? Please explain. Responses: (a) Brent was selected because the United Kingdom remains one of the most important crude sources for Line 9 shipments, generally second only to Algeria. The Algerian crudes are believed to be primarily delivered to the NOVA Chemicals Corunna facility. NOVA Chemicals specifically identified Saharan Blend (which is produced in Algeria) as a feedstock for its Corunna facility in its direct evidence filed in the RH-2-2007 proceeding. Moreover, Brent is the key benchmark light sweet crude in the Atlantic Basin and pricing is readily available. Muse does not limit its analysis to just light sweet crude, but also considers the competitiveness of light sour crude at Nanticoke.
(b) There are a number of light crude grades available from the North Sea, West Africa, South America, Atlantic Canada, North Africa, Russia, and Central Asia.
(c) See response to NEB 1.17. RH-1-2010 Responses of Enbridge to Imperial IRs Page 134 of 323
IOL-Enbridge 83
Reference: Written evidence of Enbridge (Adobe Number A1R0V5), Appendix A- 7.1, page 25.
Preamble: Muse discusses other incentives for Imperial to process more Oil Sands crude at its Ontario refineries.
Muse states: “All of the large Oil Sands producers are under pressure from government and labor organizations to maximize the value added in Canada, and it would certainly be helpful to address these desires if Imperial acted to further upgrade its Ontario refineries to process more Oil Sands crude.”
Imperial would like to understand Muse’s comments, in relation to the topic of comparative crude supply economics to Nanticoke.
Requests: (a) Does Muse consider Imperial to be included in the group of “large Oil Sands producers”?
(b) If the answer to (a) is “yes”, please provide details of the pressure being applied by government and labor organizations for Imperial to maximize the value added in Canada.
(c) Are there other ways that Imperial may add value in Canada without further upgrading its Ontario refineries? Explain.
(d) Was it within Muse’s mandate to quantify the costs and benefits to governments, labor organizations, Imperial, or any other stakeholder, associated with upgrading of Imperial’s Ontario refineries? Explain.
Responses: (a) Yes.
(b) The following link provides a representative overview of governmental interest in value-adding activities in Canada:
http://www.energy.alberta.ca/Petrochemical/844.asp.
Moreover, the role of the Alberta Energy Minister is defined, in part, to “continue to implement strategies to increase upgrading and refining capacity in Alberta, including the implementation of Bitumen Royalty In-kind.” See Attachment 1 to IOL-Enbridge 83. The interest of labour unions in the subject has been demonstrated by their consistent opposition to new crude oil export pipeline RH-1-2010 Responses of Enbridge to Imperial IRs Page 135 of 323
projects over the last several years.
(c) Yes. In addition to further upgrading its Ontario refineries, Imperial can upgrade its Strathcona refinery and construct upgraders to produce synthetic crude oil.
(d) No. However Muse has observed that Imperial’s chairman and CEO has stated that “Kearl is a heavy, low API gravity crude and I think you’ll see us concentrate most of that upgrading at our two Ontario sites rather than our Strathcona site which is less leveraged towards conversion capability.” The views of Mr. March appear to be germane to the issue of Imperial’s future use of Line 9 in westbound service. Muse has not attempted to quantify the benefits that would flow to Imperial, governments, labour organizations, or any other stakeholder from upgrading Canadian heavy crude at the Ontario refineries.
RH-1-2010 Responses of Enbridge to Imperial IRs Page 136 of 323
IOL-Enbridge 84
Reference: Written evidence of Enbridge (Adobe Number A1R0V5), Appendix A- 7.1, pages 23, 24 and 29, Figures 9, 10 and 12.
Preamble: Imperial would like to ensure that it has the latest available information regarding Muse’s analysis.
Imperial would like to understand the calculation of economic advantage as presented in the Muse Report.
Requests: (a) Please update Figures 9, 10 and 12 for 2009 complete and 2010 year-to-date.
(b) For each referenced figure, and the additional months added for (a), provide all supporting assumptions and calculations. Identify all data sources and calculation steps, including marine shipping calculations, pipeline tolls, quality adjustments and any other relevant data.
Responses: (a) See Attachment 1 to IOL-Enbridge 84.
(b) See Attachments 2 through 4 to IOL-Enbridge 84 for the supporting calculations for Figures 9, 10, and 12 respectively. The sources of various items are identified on the attachments. Details of the quality adjustments are found on Attachment 1 to IOL- Enbridge 79.
RH-1-2010 Responses of Enbridge to Imperial IRs Page 137 of 323
IOL-Enbridge 85
Reference: Written evidence of Enbridge (Adobe Number A1R0V5), Appendix A- 7.1, pages 6 and 15.
Preamble: Muse states on page 6, in relation to Imperial’s Nanticoke Refinery,: “The refinery’s preferred crude slate can also shift away from the crude types delivered by Line 9 via a refinery upgrading project to process more Western Canadian heavy sour, … [or] by increased runs of Western Canadian heavy sour for asphalt production ... .”
Muse states on page 15: “The most near-term prospect is the Hebron field that is expected to be in production by 2017. However, Hebron is a heavy crude, which has not been the preferred crude type for Line 9 deliveries into Ontario.”
Imperial would like to understand Muse’s position regarding heavy crude processing in Ontario, and whether Hebron might be shipped by Line 9.
Requests: (a) Why has heavy crude not been the preferred crude type for Line 9 deliveries?
(b) How does Hebron quality compare to the typical heavy crude blends available from Western Canada, and in particular, to Cold Lake Blend?
(c) Please confirm that ExxonMobil Canada is an equity owner of Hebron.
(d) Please explain whether Imperial, if it were to consider processing of its Western Canada equity heavy crude in Ontario, might not also consider processing of its Eastern Canada equity heavy crude in Ontario?
(e) Please confirm what modifications would be required to transport Hebron crude through Line 9.
(f) Please confirm what constraints would be applicable to the transportation of Hebron crude or any other heavy crude through Line 9, and discuss how these constraints might be alleviated.
(g) Please confirm what constraints would be applicable to the processing of Hebron crude at Nanticoke, discuss how these constraints differ from processing of Cold Lake Blend, and how RH-1-2010 Responses of Enbridge to Imperial IRs Page 138 of 323
they might be alleviated.
Responses: (a) Heavy crude from Western Canada has been consistently more attractively priced than heavy waterborne grades available in the Atlantic Basin. See also page 36 of the report referenced in the response to IOL-Enbridge 70(f).
(b) Muse does not have access to a Hebron assay. A project description filed by ExxonMobil Canada with the Newfoundland and Labrador Petroleum Board, dated March 2009, indicates that the primary reservoir that comprises the Hebron Project has an oil gravity of 20°API. This is approximately the same gravity as Cold Lake Blend. Additional Hebron properties were not provided.
(c) Confirmed.
(d) Imperial does not appear to have equity heavy crude production in Eastern Canada currently and is not one of the owners of the Herbron Project or of ExxonMobil Canada. Nonetheless, Muse would expect that any sales of Hebron crude by ExxonMobil to Imperial would be made on an arms-length basis, and that Imperial would evaluate the economics of processing Hebron crude on the same basis that it uses for other crudes. Furthermore, Mr. March in the Imperial Oil Ltd. Investor Day Q&A session, May 26, 2009, indicated that crude sales between Imperial and Exxon Mobil are made on an arms-length basis. See pages 33-34 of Attachment 1 to IOL-Enbridge 75.
(e) Enbridge has not conducted an analysis to determine the required modifications to Line 9 or related terminal facilities to transport Hebron crude. A number of key variables such as expected throughputs, project timing and crude characteristics are unknown.
(f) Enbridge has not conducted this analysis. See response to IOL- Enbridge 85(e).
(g) Unknown. Muse would require additional information regarding Hebron crude.
RH-1-2010 Responses of Enbridge to Imperial IRs Page 139 of 323
IOL-Enbridge 86
Reference: (i) Written evidence of Enbridge (Adobe Number A1R0V5), Appendix A-7.1, page 7.
(ii) Written evidence of Enbridge (Adobe Number A1R0V5), Appendix A-7.2, pages 25 and 26.
(iii) NOVA Fourth Quarter 2008 News Release and Conference Call.
Preamble: Muse states in (i): “NOVA Chemicals has not indicated that it is contemplating the closure of the Corunna Olefins facility, but the recent economic performance of the facility suggests that this possibility cannot be absolutely ruled out. Moreover, it is possible that NOVA Chemicals may elect to just discontinue the use of light crude and condensate as a feedstock, by either closing the portion of the plant that consumes light crude and condensate or by switching to other feedstocks.”
Muse states in (ii): “A second possibility is that consumption of light crude and condensate drops to the volumes readily available elsewhere, …”
Imperial would like to understand Muse’s analysis and conclusions regarding NOVA’s Corunna Olefins facility.
Requests: (a) Has Muse evaluated the financial performance of NOVA’s Corunna Olefins facility in comparison to other petrochemical producers in North America over the period?
(b) How does the 2008 and 2009 performance cited as the basis for a possible closure of the NOVA Corunna Olefins facility compare with other olefins producers in North America?
(c) According to reference (3), did NOVA’s 2008 adjusted EBITDA includes any extraordinary items? Please explain.
(d) Absent any extraordinary items identified in (c), would the cumulative pre-tax free cash flow for the period shown in Table 1 have changed? Please explain.
(e) With reference to (d), how would Muse’s conclusions regarding NOVA Chemicals operation of the Corunna Olefins facility change?
(f) How would the closure of the portion of NOVA’s Corunna Olefins RH-1-2010 Responses of Enbridge to Imperial IRs Page 140 of 323
plant that consumes light crude and condensate affect the overall capacity of the facility?
(g) What other possibilities may exist for NOVA (other than closure of the Corunna Olefins plant or closure of the portion of the plant that consumes light crude and condensate) among the options considered by Muse in preparing its analysis?
(h) What volume of “other feedstocks” can be accommodated in the NOVA Corunna Olefins facility?
(i) What volumes of light crude and condensate are “readily available elsewhere”?
Responses: (a) No.
(b) The free cash flow over the 2004 to Q2 2009 period was cited as a basis for a possible closure of the NOVA Corunna Olefins facility.
(c) No. The news release does not discuss any “extraordinary items.” The document does indicate that Adjusted EBITDA, which Muse used to develop its free cash flow estimate, “assists investors in determining NOVA Chemicals’ ability to generate cash from operations.”
(d) Not applicable.
(e) Not applicable.
(f) Unknown.
(g) Pages 25 through 26 of the Muse Report discuss the possibility of NOVA Chemicals replacing its Line 9 shipments with deliveries via the U.S. Gulf Coast.
Subsequent to the completion of the Muse Report, NOVA Chemicals and Buckeye Partners, L.P. (Buckeye) announced that they had signed a memorandum of understanding regarding the evaluation and development of a mixed natural gas liquids (NGL) pipeline from the Marcellus Basin in Pennsylvania to the refining and petrochemical complex in the Sarnia-Lambton area of Ontario. In March 2010, Buckeye conducted a non-binding open season for the proposed pipeline. The open season document indicated that the expected capacity of the pipeline to delivery Y-grade NGLs was 90,000 to 170,000 b/d (14,300 to 27,000 m3/d), and the NOVA Corunna facility was identified as one of the delivery points. On April 6, 2010, Buckeye announced that it had received RH-1-2010 Responses of Enbridge to Imperial IRs Page 141 of 323
favourable responses from potential customers to transport NGLs from the Marcellus Basin to Sarnia, Ontario. Buckeye further indicated that the expressions of interest supported continued development of engineering designs for the proposed pipeline. Attachments 1, 2 and 3 to IOL-Enbridge 86 provide the initial press release, the open season document, and the second press release announcing the results of the open season, respectively.
On April 20, 2010, Kinder Morgan Energy Partners, L.P. (Kinder Morgan) announced plans to connect the Marcellus Basin with a new pipeline to its Cochin Pipeline system at Riga, Michigan. Kinder Morgan indicated that it anticipates that NGL would be transported from Riga via the Cochin Pipeline to Windsor, Ontario, and then through the Windsor-Sarnia Pipeline to Sarnia. The pipeline will be designed to transport Y-grade NGLs as well as purity NGLs, and will have an initial capacity of 175,000 b/d (27,800 m3/d). Kinder Morgan indicated that it planned to move forward with an open season in the second quarter of 2010. Attachment 4 to IOL-Enbridge 86 provides the press release.
See response to IOL-Enbridge 88.
(h) Unknown.
(i) The “readily available” volume equals the volume of light crude and condensate that NOVA Chemicals has acquired from delivery routes other than Line 9 over the last several years.
RH-1-2010 Responses of Enbridge to Imperial IRs Page 142 of 323
IOL-Enbridge 87
Reference: Written evidence of Enbridge (Adobe Number A1R0V5), Appendix A- 7.1, page 29, footnote 31.
Preamble: At footnote 31, page 29, Muse states: “NOVA Chemicals will likely incur greater contamination of the light sweet crudes that it purchases on the U.S. Gulf Coast supply route versus Line 9. However, the recent modifications to the Capline and Chicap pipelines to facilitate condensate supply to Chicago may reduce the contamination from the historical levels that NOVA Chemicals has experienced.”
Imperial would like to understand Muse’s conclusions regarding contamination.
Requests: (a) How much contamination is typically acceptable in light sweet crude and condensate for processing in olefins plant feedstock?
(b) How much contamination has historically been experienced in sweet crude and condensate deliveries via Line 9 to Sarnia? Please provide historical results for the period since Line 9 has been operating in westbound operation.
(c) Describe the recent modifications to the Capline and Chicap pipelines.
(d) How much contamination has historically been experienced in condensate deliveries via Capline and Chicap to Sarnia?
(e) Confirm what historical levels of contamination are being referred to; Line 9 or Capline-Chicap deliveries.
(f) How much contamination is historically experienced in Enbridge Line 6B?
(g) Could Line 6B contamination potentially be significant enough to offset any benefits of the Capline-Chicap pipeline modifications? Explain.
Responses: (a) The acceptable level of contamination is a function of the specific design of the olefins plant and the feedstock and product pricing relationships applicable to the olefins plant.
(b) See section 2.3 of the Written Direct Evidence of NOVA RH-1-2010 Responses of Enbridge to Imperial IRs Page 143 of 323
Chemicals in the RH-2007 proceeding (Exh. C-8-4b).
(c) The modifications are not described by Capline and Chicap pipelines. However, the objective of the modifications is described in a news release dated April 21, 2008 as follows: “The modifications will allow the two systems [Capline and Chicap] to carry light hydrocarbons measuring up to 85 API gravity and 13.5 RVP. These light hydrocarbons, such as condensates and light naphthas, could be used as refinery feedstocks or to dilute bitumen...”
(d) See section 2.2 of the Written Direct Evidence of NOVA Chemicals in the RH-2007 proceeding (Exh. C-8-4b).
(e) Capline-Chicap-Enbridge Line 6B.
(f) Enbridge does not have access to NOVA Chemicals’ internal information regarding contamination. See the response to IOL- Enbridge 87(d) for information regarding contamination on the Capline/Chicap/Line 6B delivery route.
(g) Enbridge would expect that any improvements in contamination levels on Capline and Chicap would result in a net improvement in contamination to Sarnia.
RH-1-2010 Responses of Enbridge to Imperial IRs Page 144 of 323
IOL-Enbridge 88
Reference: Enbridge website: http://cnrp.ccnmatthews.com/client/enbridge/releaseen.jsp?actionFor=113 5345
“Enbridge Announces Plans to Hold Open Season for Proposed Natural Gas Liquids Pipeline from Marcellus Shale to Chicago”, March 22, 2010.
Preamble: Enbridge states: “Enbridge will develop, construct, own and operate the planned NGL pipeline. The Company is currently evaluating various routing and market alternatives and anticipates moving forward with an open season in the second quarter 2010.” and “The Chicago area has substantial markets to accommodate the large volumes of NGLs that are expected to be associated with future Marcellus production. Other NGL markets, including Ontario, can also be accessed from Chicago utilizing existing infrastructure.”
Imperial would like to know more about Enbridge’s plans to deliver natural gas liquids from the Eastern U.S. to the Midwest.
Requests: (a) What is the earliest date that the proposed NGL pipeline could be in service?
(b) Please describe the potential costs for the proposed Marcellus shale NGL pipeline.
(c) Since Ontario is named by Enbridge as a potential market for NGL from the proposed pipeline, and since the use of existing infrastructure for this operation is of interest, has Enbridge considered, or be willing to consider, the option of using Line 9 for the delivery of Marcellus shale NGL production to Sarnia?
(d) If the answer to (c) is “no”, please explain why not.
(e) If the potential use of Line 9 described in (c) would require pipeline modifications or construction of new facilities, please describe such modifications and construction, and their estimated costs.
Responses: (a) Enbridge Pipelines expects, assuming normal development and permitting processes, that the earliest in-service date would be in Q3 2013.
(b) Enbridge Pipelines is still in the process of developing the route, RH-1-2010 Responses of Enbridge to Imperial IRs Page 145 of 323
pipe size, and design for the proposed pipeline and does not have a cost estimate at this time.
(c) No, because the routing of Line 9 makes it an impractical option for moving Marcellus NGL’s into Ontario.
(d) Line 9 does not access SW Pennsylvania, which is the area from which the NGLs are expected to be produced. Marcellus gas to the north of this area does not contain significant NGL. To utilize Line 9 for NGL service, additional pipelines would have to be constructed from SW Pennsylvania into Ontario to connect with Line 9. Enbridge Pipelines does not contemplate doing so and, as a result, it has made no cost estimates of the cost to modify Line 9 or to construct the additional pipeline(s).
(e) See response to IOL-Enbridge 88(d).
RH-1-2010 Responses of Enbridge to Imperial IRs Page 146 of 323
IOL-Enbridge 89
Reference: (i) Written evidence of Enbridge (Adobe Number A1R0V5), Appendix A-7.1, pages 30 to 31.
(ii) RH-3-2007 Enbridge response to IOL-Enbridge 24(12).
Preamble: In reference (i), Muse states: “Absent Imperial, the Line 9 toll more than doubles for NOVA Chemicals, assuming that NOVA Chemicals doesn’t increase its Line 9 shipments above its historical volumes. Due to the higher Line 9 toll, the economics to switch to a U.S. Gulf Coast supply route and/or switching to just Western Canadian and U.S. light crude supply would become compelling for NOVA Chemicals. Consequently, Line 9 is not seen a viable transportation route for NOVA Chemicals absent Imperial.”
In reference (ii), Enbridge states “It is Enbridge’s understanding that NOVA has less optionality that other Line 9 shippers, such that they would be the last shipper in the line before becoming idle.”
Imperial wishes to understand the analysis presented by Enbridge in relation to the interdependencies of shippers on Line 9.
Requests: (a) Can Enbridge confirm that NOVA has requested its Line 9 linefill back and intends to stop shipping on Line 9?
(b) If the answer to (a) is “yes”, please explain why, despite Muse and Enbridge expectations, it appears that NOVA and not Imperial has stopped shipments on Line 9.
(c) If the answer to (a) is “yes”, please explain whether the economics to switch to the alternative sources mentioned in (1) are equally compelling for Imperial, and by how much.
Responses: (a) The information requested is commercial information relating to a competitor of Imperial which Enbridge has consistently treated as confidential. Enbridge objects to filing such information and declines to do so.
(b) Not applicable.
(c) Not applicable.
RH-1-2010 Responses of Enbridge to Imperial IRs Page 147 of 323
IOL-Enbridge 90
Reference: (i) Enbridge website, Investor Community Presentation, March 2010, page 18
(ii) Enbridge website, Investor Community Presentation, March 2010, page 31
(iii) Muse Stancil presentation, TD Securities, London Oil Sands Forum 2009, January 19, 2009, page 19
Preamble: Imperial wishes to understand Enbridge’s current plans in relation to system expansions, and Muse’s outlook for these plans.
Requests: (a) In reference (i), New Market Access projects are listed for the 2012+ period. “PADD I – Eastern Access” and “Eastern PADD II” are shown as high probability projects. Please explain what high probability means in this context.
(b) In reference (ii), Enbridge diagrams a group of projects labelled as Eastern Access, including deliveries to Portland (for marine delivery to Philadelphia, Eastern Canada or other Atlantic Basin markets), Philadelphia (via Buffalo or Chicago) and Eastern PADD II. What is the current status of each of these Eastern Access projects?
(c) For each of the projects in (a) and (b), how does Enbridge envision the project coming to physical fruition – what new facilities would be required and what existing facilities may be used for the project?
(d) In reference (iii), Muse states, “A crude pipeline reversal to the Atlantic Coast is entirely possible”. Please confirm the reversal referred to includes Line 9.
(e) What is meant by “entirely possible” in the context of (d)?
Responses: (a) As WCSB production comes online, new markets will be needed, which may include PADD I and Eastern PADD II, and likely beyond 2012.
(b) Based on market conditions over the past 18 months, the Eastern Access/Trailbreaker Project, which would provide deliveries to Portland (for marine delivery to Philadelphia, Atlantic Canada, or RH-1-2010 Responses of Enbridge to Imperial IRs Page 148 of 323
other Atlantic Basin markets) is currently on hold.
With respect to deliveries to Philadelpia (via Buffalo or Chicago) and Eastern PADD II, see response to IOL-Enbridge 90(a).
(c) The specific facilities that may be used for the projects referred to in the responses to IOL-Enbridge 90(a) and (b) is dependent on the commercial terms agreed upon by Enbridge Pipelines and its shippers. In the absence of specific commercial agreements, considerations include: flow rate, direction of flow, commodity types, quality considerations, and shipper connectivity. Enbridge Pipelines has none of this information, at this point, and so it cannot speculate on what new or existing facilities may be required for each of those projects.
(d) Confirmed.
(e) It means that such a reversal is achievable.
RH-1-2010 Responses of Enbridge to Imperial IRs Page 149 of 323
IOL-Enbridge 91
Reference: Written evidence of Enbridge (Adobe Number A1R0V5), Appendix A- 7.1, page 6 and 20.
Preamble: Muse makes references on pages 6 and 20 to western crude delivery. Muse states: “In the case of Imperial, the decision is …, influenced in the short-term by the physical capability of the pipeline systems to supply the desired crude volumes from the west”.
Imperial would like to understand the physical capability and limitations of western supply and how this influences Imperial supply decisions.
Requests: (a) What is the definition of “short-term” in this context?
(b) What is the definition of “the west” in this context?
(c) Please outline the physical capability of western supply into the Ontario based refineries.
(d) Are there restrictions with respect to crude deliveries from the west into Ontario refineries, specifically Nanticoke?
(e) If the answer to (d) is “no”, please explain how Imperial’s decisions are influenced by the pipeline systems.
(f) If the answer to (d) is “yes”, are plans in place to remedy these limitations?
(g) If the answer to (f) is “no”, why not?
(h) If the answer to (f) is “yes”, what is the timeframe for these plans to be completed?
Responses: (a) Less than two years.
(b) Crude deliveries that transit the St. Clair River, irrespective of their ultimate origin.
(c) The statements from the Muse Report that are cited in the Preamble relate to Line 7. The physical capacity of Line 7 is approximately 23,850 m3/d (150,000 b/d). See the response to NEB 1.16.
(d) Yes. RH-1-2010 Responses of Enbridge to Imperial IRs Page 150 of 323
(e) Not applicable.
(f) No, since shippers have not requested that Enbridge remedy the constraints on Line 7 on a priority basis. See the response to NEB 1.16.
(g) See the response to IOL-Enbridge 91(f).
(h) Not applicable.
RH-1-2010 Responses of Enbridge to Imperial IRs Page 151 of 323
IOL-Enbridge 92
Reference: Written evidence of Enbridge (Adobe Number A1R0V6), Appendix A- 7.2.
Preamble: Throughout Ms. McShane’s evidence there are a number of calculations provided by the author.
Requests: (a) Please provide all work papers which support the calculations presented in Appendix A-7.2, including spreadsheets. Formula information used to derive any spreadsheet results should also be provided in a manner which allows the electronic spreadsheet information to be accurately reproduced.
Response: (a) All work papers supporting the calculations in Appendix A-7.2 are provided in Attachment 1 to IOL-Enbridge 92(a). This zip file includes “Enbridge Line 9 Workpaper Mapping.doc” that shows how each work paper refers to the evidence. The Excel version of the schedules is also included in the zip file. A correction has been made to Schedule 3 cell D22, so that it pulls from cells B7 and D7, not B8 and D8. This has no impact on the final results. The FortisBC spread was incorrectly reported as 325 basis points at page 12, line 330, of Appendix A-7.2. The actual spread is approximately 275 basis points.
RH-1-2010 Responses of Enbridge to Imperial IRs Page 152 of 323
IOL-Enbridge 93
Reference: Written evidence of Enbridge (Adobe Number A1R0V6), Appendix A- 7.2, page 9, lines 165 to 167.
Preamble: Ms. McShane states that “the stand alone principle has been respected by virtually every Canadian regulator, including the NEB, in setting both regulated capital structures and allowed ROEs.”
Requests: (a) Please explain the use of “respected” in this context. In what way is it analogous to “applied”?
(b) Please provide specific examples of regulatory cases, NEB and other regulators, where the stand-alone principle has been applied.
(c) Is Ms. McShane aware of instances where the stand-alone principle was considered, but not applied? If so, please identify the cases and regulator.
(d) Ms. McShane specifies that Canadian regulators often apply the stand-alone principle. Does Ms. McShane know whether U.S. regulators do likewise? If so, please provide examples.
Responses: (a) In this context, “respected” means “applied.”
(b) The following are examples of regulatory cases where the stand- alone principle has been applied:
National Energy Board • Interprovincial (Enbridge today) 1. RH-2-76, Part I (December 1976), pp. 5-4 to 5-6 2. RH-2-76, Part II (December 1977), pp. 3-1 to 3-5, 4-1 to 4-5, 6-1 to 6-3, and 7-1 3. RH-2-75, Part III (May 1978), pp. 4-1 to 4-6 4. RH-3-80 (June 1980), pp. 3-1, 4-1 and 4-2, 5-8, 6-1, and 7-6 5. RH-2-91 (June 1992), at pp. 6-7, 33, 35, 46-47, and 68-73 6. OH-2-97 (December 1997), at p. 59
• TransCanada 7. RH-2-80 (Aug. 80), pp. 3-1 to 3-8, 4-17 to 4-22 8. RH-4-81, Phase I (Aug. 81), pp. 3-8 to 3-9, 4-1 to 4-5, 5-9 to 5-13 9. RH-3-82 (July 82), pp. 3-1 to 3-9, 4-1 to 4-11 RH-1-2010 Responses of Enbridge to Imperial IRs Page 153 of 323
10. RH-1-91 (Sept. 91), pp. 19-21 11. RH-R-1-2002 (Feb. 03), pp. 25-27
• Trans Quebec & Maritimes 12. RH-4-83 (Mar. 84), pp. 23-25 13. RH-2-90 (Feb. 91), pp. 16-18 14. RH-1-2008 (Mar. 09), pp. 80-81
• Alberta Natural Gas 15. RH-1-80 (May 80), pp. 6-1 to 6-3 16. RH-1-82 (Apr. 82), pp. 3-6, 11-14
• Westcoast Transmission 17. RH-4-80 (Nov. 80), pp. 3-1 to 3-6, 4-1 to 4-5 18. RH-1-83 (Aug. 83), pp. 31-36
Ontario Energy Board • Consumers Gas/Enbridge Gas Distribution 19. EBRO 376-I &II (Jan. 30/81), pp. 57-59, 61-70 20. EBRO 381 (Jan. 27/82), pp. 59-62 21. EBRO 386-I (Jan. 26/83), pp. 115-120 22. EBRO 395 (Nov. 1/83), pp. 95-96 23. EBRO 485 (Dec. 23/93), pp. 67-70 24. RP-2002-0158 (Jan. 16/04), paras. 113-148
• Union Gas 25. EBRO 380 (Sept. 14/81), pp. 51-59 26. EBRO 382 (Apr. 8/82), pp. 51-59 27. EBRO 397 (Apr. 24/84), p. 19 28. EBRO 456 (Sept. 26/89), pp. 98-100 29. RP-2002-0158 (Jan. 16/04), paras. 113-148
• Centra Gas Ontario 30. EBRO 467 (May 22/91), pp. 85-87
• Natural Resource Gas 31. EBRO 496 (Aug. 20/98), pp. 38-41
Public Utilities Board/Energy & Utilities Board/Alberta Utilities Commission • Nova Gas Transmission 32. PUB Decision C78221 (Dec. 21/78), pp. 19-27 33. PUB Decision E92086 (Oct. 6/92), pp. 25-36, 41-42 34. PUB Decision E93060 (Aug. 20/93), pp. 14-16
RH-1-2010 Responses of Enbridge to Imperial IRs Page 154 of 323
• Alberta Power 35. PUB Decision E82194 (Aug. 18/22), pp. 40-45, 50-51
• GENCO and DISCO 36. EUB Decision 2001-92 (Dec. 12/01), pp. 19-29
• AltaLink 37. EUB Decision 2003-061 (Aug. 3/03), pp. 77-92 38. EUB Decision 2004-007 (Jan. 27/04), pp. 22-25
• Generic Cost of Capital 39. EUB Decision 2009-216 (Nov. 12/09), pp. 18
(c) See the response to IOL-Enbridge 104(c).
(d) Yes. U.S. regulators apply the stand-alone principle, although the term may not be used specifically. In determining a rate of return, U.S. rate of return experts utilize samples of companies that are deemed to be of similar risk to the regulated operations in question in developing their cost of capital recommendations.
The term stand-alone in a U.S. context has more frequently been used to refer to the determination of income taxes, where the regulated entity’s allowed taxes are estimated on the basis of its own operation’s not the parent’s, in order to avoid cross- subsidization. For example, the FERC stated in 23 FERC ¶61,396, Columbia Gulf Transmission Company, Docket No. RP75-105- 002, Columbia Gas Transmission Corporation, Docket No. RP75- 106-006 (Consolidated Taxes), (June 22, 1983), “The method the pipelines have used, and the method the Commission has followed since 1972, is one in which "a utility [is] considered as nearly as possible on its own merits and not on those of its affiliates." [footnote excluded] This method is called the stand-alone method, for "a stand-alone income tax allowance is one that takes into account the revenues and costs entering into the regulated cost of service without increase or decrease for tax gains or losses related to other activities . . .”
In El Paso Electric Company v. Federal Energy Regulatory Commission Decision of the United States Court of Appeals, Fifth Circuit, May 2008, the Court stated, “The Stand-alone” principle is formulated to protect one class of customers from paying the costs attributable to another class. Its purpose is to avoid cross- subsidization and its focus is upon who pays (para. 22). RH-1-2010 Responses of Enbridge to Imperial IRs Page 155 of 323
IOL-Enbridge 94
Reference: Written evidence of Enbridge (Adobe Number A1R0V6), Appendix A- 7.2, page 9, lines 167 to 170.
Preamble: Ms. McShane states that “For the Extended Term under the now terminated FSA, the stand-alone principle was explicitly applied to Enbridge in the determination of tolls. The stand-alone principle is equally applicable to periods subsequent to the termination of the FSA.”
Requests: (a) On what basis does Ms. McShane make the determination that the stand-alone principle remains applicable after the termination of the FSA?
Response: (a) Ms. McShane made that determination based on her conclusions that the stand-alone principle is the appropriate means to determine the cost of capital for Enbridge, based on its history, financial theory, and confirmed by the virtual universal reliance on the stand-alone principle by Canadian regulators. See response to IOL-Enbridge 141.
RH-1-2010 Responses of Enbridge to Imperial IRs Page 156 of 323
IOL-Enbridge 95
Reference: Written evidence of Enbridge (Adobe Number A1R0V6), Appendix A- 7.2, schedule 4, page 65.
Preamble: Ms. McShane presents average investment betas for the time period June 30, 2002 to June 30, 2009, as well as common equity ratios for the time period 2002-2008.
Requests: (a) Please provide source data for figures listed in the schedule.
(b) Please provide investment betas and common equity ratios for companies and time periods that Ms. McShane may possess but excluded from the sample.
(c) What is the significance of the time periods selected for these data?
(d) What market index is used in the determination of the betas?
(e) Did Ms. McShane determine/calculate the betas herself, or were the betas directly obtained from source documents? If Ms. McShane made the calculations, please provide the underlying data used for such calculations, and the calculations themselves, in an excel spreadsheet. If Ms. McShane obtained the betas from another source, please provide the source documents.
(f) What is Ms. McShane’s purpose for adjusting the betas? Please provide the formulas that inform or provide the basis for Ms. McShane’s adjustment formula.
Responses: (a) See Attachment 1 to IOL-Enbridge 92.
(b) Additional betas that were calculated for the two samples are provided in Attachment 1 to IOL-Enbridge 92.
(c) See response to NEB 1.25.
(d) The S&P 500 Index was used in the determination of the betas.
(e) See Attachment 1 to IOL-Enbridge 92.
(f) The use of adjusted betas recognizes that the raw beta for utilities does not accurately reflect the empirical risk/return relationship. A number of empirical studies on CAPM have shown that the return requirement is higher (lower) for a low (high) beta stock than the RH-1-2010 Responses of Enbridge to Imperial IRs Page 157 of 323
CAPM would predict. The deficiencies in “raw” beta can be mitigated by using adjusted betas. As noted below Table 5 in Appendix A-7.2 (lines 1133 to 1137), adjusting betas entails moving betas above and below the market mean of 1.0 toward the market mean. The result of adjusting the betas for this purpose reduces the estimate of the incremental risk premium.
RH-1-2010 Responses of Enbridge to Imperial IRs Page 158 of 323
IOL-Enbridge 96
Reference: Written evidence of Enbridge (Adobe Number A1R0V6), Appendix A- 7.2.
Preamble: Through her prepared testimony, Ms. McShane refers to a Facilities Support Agreement between Enbridge and the principal Line 9 shippers.
Requests: (a) Please provide a copy of the FSA (as amended).
Response: (a) See response to IOL-Enbridge 40(a).
RH-1-2010 Responses of Enbridge to Imperial IRs Page 159 of 323
IOL-Enbridge 97
Reference: Written evidence of Enbridge (Adobe Number A1R0V6), Appendix A- 7.2, page 10, lines 194 to 195.
Preamble: Ms. McShane states that “There are effectively two approaches that can be used to determine a fair rate of return on rate base.”
Requests: (a) Is Ms. McShane aware of other approaches? If so, why were they excluded? Have they been used by energy regulators? If so, in what cases?
Response: (a) A third approach is to use the After-tax Weighted Average Cost of Capital (ATWACC) Method. This approach estimates the cost of equity and then combines it with the after-tax market cost of debt and the market value capital structures to arrive at a single cost of capital, rather than specifying the capital structure and ROE values separately. Ms. McShane’s main concern with this methodology is that, in its “pure” application, it is not compatible with simultaneously allowing the recovery of a utility’s embedded cost of debt. Transitioning from the traditional rate base/rate of return approach would, for many utilities, require some interim solution so that utilities with relatively high or low embedded costs of debt relative to the market cost are not disadvantaged or advantaged. In addition, it is not as transparent to investors as the “traditional” rate base/rate of return approach. She is aware that the Board approved the methodology for TQM Pipeline in its RH-1-2008 proceeding. It has also been employed by regulators in the United Kingdom, Australia and New Zealand in establishing the rate of return for utilities under their jurisdiction.
RH-1-2010 Responses of Enbridge to Imperial IRs Page 160 of 323
IOL-Enbridge 98
Reference: Written evidence of Enbridge (Adobe Number A1R0V6), Appendix A- 7.2, pages 10, 11 and 13.
Preamble: Ms. McShane describes two approaches that can be used to determine a fair rate of return on rate base. On line 196, Ms. McShane states that the first approach seeks to establish a capital structure that, inter alia, permits the pipeline to achieve a stand alone investment grade debt rating. On lines 236 to 237, Ms. McShane states that she has adopted the second approach. On line 298, Ms. McShane states that on a stand-alone basis, Line 9 would be unable to achieve an investment grade debt rating (A or higher).
Requests: (a) Is the fact that Ms. McShane states that Line 9 would be unable to achieve an investment grade debt rating the reason why she decided against using the first approach? If not, assuming one was to use the first approach, how would this be reconciled?
(b) Please specifically explain the reasoning behind the choice to use the “second approach”.
Responses: (a) The principal reason that Ms. McShane relied on the second approach is because, as stated at lines 230-234 of Appendix A-7.2, it is “compatible with the philosophy that the capital structure, within a reasonable range, is appropriately a decision for management, because management is in the best position to assess its business risks, financing requirements and access to debt and equity capital.” In addition, the first approach is more suitable for regulated companies whose business risks are such that they could achieve, on a stand-alone basis, debt ratings similar to those of a benchmark regulated company without an unduly high equity ratio. For smaller regulated companies with relatively high business risks that would find it difficult to achieve a comparable level of risk to a benchmark irrespective of the equity ratio, it would be more cost effective to adopt the second approach. This is the approach that the BCUC relies upon for the utilities that it regulates.
(b) See response to IOL-Enbridge 98(a).
RH-1-2010 Responses of Enbridge to Imperial IRs Page 161 of 323
IOL-Enbridge 99
Reference: Written evidence of Enbridge (Adobe Number A1R0V6), Appendix A- 7.2, page 10, lines 183 to 192.
Preamble: In discussing the cost of capital, Ms. McShane states that “financial risk refers to the additional risk that is borne by the equity shareholder because the firm uses debt to finance a portion of its assets.” “Thus, as the debt ratio rises, the cost of equity rises.” She also states that “the capital structure, comprised of debt and common equity, can be viewed as a summary measure of the financial risk of the firm.”
Requests: (a) With these statements, is Ms. McShane speaking generally, or just with respect to Enbridge Line 9 on a stand-alone basis?
(b) Would Ms. McShane disagree that financial risk can also result from other financial obligations, such as lease payments?
(c) If Ms. McShane concurs that financial risk can be acquired from firm activities other than debt financing, please explain how the capital structure of a firm can be viewed as a summary measure of the financial risk of a firm.
Responses: (a) This was a general statement, not specific to Enbridge.
(b) Ms. McShane agrees that firms incur financial obligations that are not included in the capital structure, and which are not directly attributable to the financing of assets that are recorded on the companies’ balance sheet. Consequently they are not reflected in the capital structure of the firm. Firms incur financial obligations which allow them to carry out its day to day operations, including the obligation to pay salaries and wages, to provide for post retirement benefits, to pay for equipment that might be subject to operating leases, etc. While such obligations are financial in nature, they reflect the operating, maintenance, administrative and general expenses of the firm, and thus relate primarily to business risk. The capital structure, which includes capital leases, reflects the financing of the firm’s fixed assets.
(c) The capital structure can be viewed as a summary measure of the financial risk of the firm inasmuch as it reflects the proportions of debt (including capital leases) and equity, and indirectly the related costs, to finance the fixed assets of the firm.
RH-1-2010 Responses of Enbridge to Imperial IRs Page 162 of 323
IOL-Enbridge 100
Reference: Written evidence of Enbridge (Adobe Number A1R0V6), Appendix A- 7.2, pages 10 to 11, lines 194 to 195 and 228 to 234.
Preamble: Ms. McShane asserts that there are two “approaches that can be used to determine a fair rate of return on rate base.” Further, in touting the second approach, she states that the “advantage of the second approach is that it is, in principle, compatible with the philosophy that the capital structure, within a reasonable range, is appropriately a decision for management, because management is in the best position to assess its business risks, financing requirements and access to debt and equity capital.”
Requests: (a) Please explain what is meant by a “reasonable range.”
(b) What does Ms. McShane believe to be the basis for determining a “reasonable range”?
Responses: (a) A reasonable range is one which would allow the utility to access capital markets on reasonable terms and conditions, taking into account the business risks that it faces, which allows it to maintain its creditworthiness and which is consistent with the goal of minimizing the cost of capital.
(b) The determination of whether a capital structure falls within a reasonable range for the purpose of setting tolls does not lend itself to precise rules. Whether or not a regulated company’s capital structure falls within a reasonable range can be assessed by reference to factors including industry practice, rating agency guidelines, the relative business risks of the regulated company, the external financing requirements of the company, and the impact of the capital structure, in conjunction with the ROE, on the debt ratings of the company, if the company is rated.
RH-1-2010 Responses of Enbridge to Imperial IRs Page 163 of 323
IOL-Enbridge 101
Reference: Written evidence of Enbridge (Adobe Number A1R0V6), Appendix A-7.2., page 13, lines 294 to 296.
Preamble: Ms. McShane states that “even regulated issuers with BBB ratings can be closed out of the market at times, particularly at the longer end (20-30 year term) of the debt market.”
Requests: (a) Please explain what Ms. McShane means by “closed out of the market”.
(b) Please provide examples to support this assertion.
(c) Have the instances in which regulated BBB issuers were closed out of the market been regularly occurring events? Please explain.
(d) Please provide a comparison over time (1990 to present) of regulated BBB issuers who did not have access to the market versus those who were closed out of the market.
Responses: (a) The term “closed out of the market” refers to a number of ways in which a company’s ability to issue debt is affected by market conditions. However, unless one is privy to the ongoing discussions between the companies and their underwriters and the underwriters and potential investors, which Ms. McShane is not, it is virtually impossible to know whether a company tried to issue a longer-term issue than it was able to, whether the company wanted to issue at a particular time or had to wait, whether it had to agree to a spread concession to issue, whether it wanted to issue more debt than it ultimately could, or whether it had to agree to more stringent terms and conditions in order to issue.
(b) The clearest example of a utility which experienced difficulty issuing and for which there is publically available information is Pacific Northern Gas. Details are provided in the BCUC decision “In the Matter of Pacific Northern Gas Ltd. Application for Approval to Recapitalize Under an Income Trust Ownership Structure”, Decision, September 9, 2005.[http://www.bcuc.com/Documents/Decisions/2005/DOC_8464_DOC_8 464_G-84-05_Income_Trust_Decision.pdf] In the BCUC decision In the Matter of FortisBC Inc., 2005 Revenue Requirements Application, 2005-2024 System Development Plan, 2005 Resource Plan, Decision, May 31, 2005, the BCUC notes FortisBC’s statement that it could not raise 30-year debt in 2004, a period of relatively easy credit market conditions. [http://www.bcuc.com/Documents/Proceedings/2005/DOC_7645_G-52- 05%20FortisBC%202005RR-SDP-RP%20and%20Decision.pdf] RH-1-2010 Responses of Enbridge to Imperial IRs Page 164 of 323
Nova Scotia Power Inc. raised five-year debt in December 2008 at a 400 basis point spread over the five-year benchmark Canada bond; the treasurer of Emera Inc. (NPSI’s parent) told Ms. McShane that, at the time, NSPI could not have raised debt with a term of 10 years or more. That being said, in the then current market conditions, even A rated utilities were facing financing difficulties. AltaLink informed the AUC in mid-December 2008 that it did not expect to be able to successfully market its previously approved long-term debt issue until first quarter 2009.
It is also important to recognize that the market for BBB rated debt in Canada is relatively small. As reported in “Back to Basics” by Marlene K. Puffer, Canadian Investment Review, Fall 2006, the BBB corporate debt market is only 4% of the total market and it is mainly limited to issues with terms under 10 years. Many institutional investors such as pension funds face limits on the proportion of BBB rated debt they are allowed to hold in their portfolios or cannot invest in BBB rated debt at all.
From January 2006 to March 2009, RBC Capital Markets, Credit Weekly, recorded $164 billion (452 issues) of corporate debt financing in Canada. Of that amount, companies all of whose ratings were in the BBB category or below accounted for approximately 6% and 9% of the total dollar value and number of issues respectively. Even including companies with one rating in the A category (i.e., split-rated A/BBB category or lower) are included, those issues account for only 13% and 17% of the total value and number of issues respectively. From mid-2007 to March 2009, during which the credit markets were experiencing various degrees of turmoil, of 189 reported issues, only seven were by companies with all ratings in the BBB category or lower, none of which was for a term in excess of 10 years.
(c) See response to IOL-Enbridge 101(a).
(d) Unknown. Ms. McShane does not have the requested information. See response to IOL-Enbridge 101(a).
RH-1-2010 Responses of Enbridge to Imperial IRs Page 165 of 323
IOL-Enbridge 102
Reference: Written evidence of Enbridge (Adobe Number A1R0V6), Appendix A- 7.2, pages 13 to 14, lines 298 to 312.
Preamble: As one of the principles to be respected in assessing capital structure, Ms. McShane asserts that a reasonable capital structure should provide the basis for stand-alone investment grade debt ratings. She also maintains that “the fundamental business risks and small size of Enbridge Line 9 would not likely permit it to achieve debt ratings in the A category on a stand-alone basis, irrespective of the level of equity in the capital structure and allowed ROE.” As a result, “Enbridge is proposing to use Enbridge Pipelines’ company-wide weighted average cost of long-term debt.”
Requests: (a) Please elaborate on the reasoning for why Line 9 would be unlikely to achieve A debt ratings on a stand-alone basis. Please provide cases, regulatory decisions, and established economic and financial theories relied upon.
(b) Is McShane aware of any Canadian regulatory decisions which have affirmed the use of company-wide cost of debt for capital structure assessment, when the rest of the pipeline is evaluated on a stand-alone basis? If so, please identify them. Are there other justifications for doing so?
Responses: (a) The preamble of the question erroneously suggests that Enbridge is proposing to use Enbridge Pipelines’ company-wide weighted average cost of long-term debt because Enbridge would not be able to achieve ratings in the A category if it were a legal entity raising debt in its own name on the basis of its unique business and financial risks. Enbridge’s proposal is independent of Ms. McShane’s conclusion that Enbridge would not be able to achieve debt ratings in the A category on a stand-alone basis, i.e., absent happenstance of ownership. Ms. McShane’s conclusion that Enbridge would not be able to achieve debt ratings in the A category was based on her assessment of the business risks and size of Enbridge and of the debt ratings that have been assigned to other Canadian utilities of relatively small size. In particular, she had reference to the ratings for Pacific Northern Gas (BBB(low) by DBRS), Maritime Electric (BBB+ corporate credit rating by S&P), FortisBC (BBB(high) by DBRS and Baa2 by Moody’s), and the BBB+ rating by S&P of TQM.
(b) See response to IOL-Enbridge 54. RH-1-2010 Responses of Enbridge to Imperial IRs Page 166 of 323
IOL-Enbridge 103
Reference: Written evidence of Enbridge (Adobe Number A1R0V6), Appendix A- 7.2, pages 13 to 14, lines 322 to 332.
Preamble: The author cites several figures that illustrate differences in cost of debt for firms with various debt ratings.
Requests: (a) Please provide source data for these figures, including any calculations that may have been used to generate said figures.
Response: (a) RBC Capital Markets provided the source data to its utility clients on the condition that the source data were proprietary and could not be disclosed with certain exceptions; for example, to a client's economic consultants – such as Foster Associates – but on the same condition. Foster Associates has accordingly declined to provide the source data to Enbridge and, as a result, Enbridge is not able to provide the source data in response to this request item.
RH-1-2010 Responses of Enbridge to Imperial IRs Page 167 of 323
IOL-Enbridge 104
Reference: Written evidence of Enbridge (Adobe Number A1R0V6), Appendix A- 7.2, page 14, footnote 6.
Preamble: The author notes the method for determining cost of debt under the now expired FSA. “The cost of debt was determined for Enbridge as the sum of the benchmark 10-year Government of Canada bond yield, a generic utility spread for 10-year term A rated corporate bonds, and a fixed component of 0.65%.”
Requests: (a) Does Ms. McShane have an opinion on whether this was an appropriate method to use for calculating cost of debt?
(b) Is Ms. McShane aware of whether the NEB or other energy regulators that have applied this method? If so, please identify cases and the regulator.
(c) Is Ms. McShane aware of cases where energy regulators have considered, via evidence placed before them, this method but rejected it? If so, please identify the cases and the regulator.
(d) Does Ms. McShane recommend the continued use of this method subsequent to the expiration of the FSA?
Responses: (a) Yes. Ms. McShane believes this is an appropriate way to determine the cost of debt as it is consistent with the stand-alone principle.
(b) Regulators that have approved a similar method for calculating the cost of debt include the Régie de l’énergie for Gazifère, the Nova Scotia Utilities and Review Board for Heritage Gas and the Alberta Energy and Utilities Board (predecessor of the Alberta Utilities Commission) for EPCOR Transmission and Distribution. The Public Utilities Board of Alberta (predecessor of the Alberta Energy and Utilities Board) (“PUB”) applied the stand-alone principle in respect of certain debt issues of NOVA Corporation amounts of which had been allocated to the former Alberta Gas Trunk Line (now NOVA Gas Transmission). In Decision E92086, the PUB concluded that the pipeline could have raised the debt more cheaply on a stand-alone basis. The PUB adjusted downward debt rates that it concluded were inconsistent with Alberta Gas Trunk Line’s stand-alone debt rating.
(c) The New Brunswick Energy and Utilities Board (“N.B. Board”) RH-1-2010 Responses of Enbridge to Imperial IRs Page 168 of 323
concluded in respect to Enbridge Gas New Brunswick (EGNB), “the Board is unable to accept the argument that EGNB should be considered as a “stand-alone” entity for purposes of establishing its cost of debt.” The N.B. Board considered that allowing a cost of debt equal to EGNB’s stand-alone debt cost would provide a benefit to Enbridge Inc., from whom EGNB borrows, a benefit that is excessive in the circumstances. The N.B. Board ordered that the cost of debt of EGNB be limited to the actual borrowing rate of the parent company plus 1%.
(d) See response to NEB 1.37(c).
RH-1-2010 Responses of Enbridge to Imperial IRs Page 169 of 323
IOL-Enbridge 105
Reference: Written evidence of Enbridge (Adobe Number A1R0V6), Appendix A- 7.2, page 15, lines 337 to 340 and lines 354 to 356.
Preamble: Ms. McShane states that “The determination of a reasonable capital structure for Enbridge needs to recognize the magnitude of the cost benefits conferred upon tollpayers through the proposed assignment of the company-wide weighted cost of long-term debt rather than an estimated stand-alone cost.” She later repeats her assertion: “the combination of the capital structure adopted for toll-making purposes and ROE for Enbridge needs to recognize the significant cost benefits that tollpayers are receiving.”
Requests: (a) How does Ms. McShane propose that the capital structure and/or ROE recognize the cost benefits to tollpayers?
(b) Please confirm that a “reasonable” capital structure is one that respects the five principles listed in lines 254 to 258.
Responses: (a) Ms. McShane has recommended that the lower cost of debt represented by Enbridge Pipelines’ company-wide weighted average cost of debt that Enbridge has proposed for toll setting purposes, as opposed to the stand-alone cost that Enbridge would incur, be reflected in the equity risk premium. See lines 1173 through 1183 of Appendix A-7.2.
(b) Confirmed.
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IOL-Enbridge 106
Reference: Written evidence of Enbridge (Adobe Number A1R0V6), Appendix A- 7.2, page 15, lines 342 to 354.
Preamble: Ms. McShane asserts that applying to Enbridge both the actual costs of debt that Enbridge would be able to obtain on its own and the capital structure that would be required by lenders to provide this debt would “ensure that the other operations of Enbridge Pipelines are not subsidizing Enbridge.” She goes on to say that assigning Enbridge Pipelines’ weighted average cost of long-term debt “implicitly recognizes that each of Enbridge Pipelines’ operations (and by extension, toll payers) benefit by way of a lower cost of debt from the size and diversity of the company’s operations.” “However, given the small size of Enbridge relative to the total operations of Enbridge Pipelines’ the latter’s cost of debt would not be impacted in any measurable way by the financing requirements of Line 9.”
Requests: (a) Please explain the meaning of the term subsidization as Ms. McShane uses it in the referenced evidence. Is Ms. McShane suggesting that the referenced subsidization involves a transfer from other Enbridge Pipelines’ operations to Line 9? If affirmative, please explain.
(b) Please explain how recognizing that each of Enbridge Pipelines’ operations benefit from the firm’s size and diversity results in a subsidization of Line 9.
(c) On what basis does Ms. McShane claim that the financing requirements of Line 9 will have no measurable impact on Enbridge Pipelines’ cost of debt? Please provide any data or calculations used to arrive at this conclusion.
Responses: (a) The term subsidization in the context of the referenced section of Appendix A-7.2 refers to the bearing of costs or the receipt of benefits by an entity which properly are caused by or belong to a different entity. If the cost of debt to Enbridge Pipelines was measurably higher due to the existence of Enbridge, and each stand-alone pipeline operation were using the company-wide weighted average cost of debt, there would be a transfer of costs to the other pipeline operations.
(b) The fact that the diversity and size of the entity that raises capital may lead to an overall cost of debt that is lower than would be the case if each operation were a stand-alone operation does not mean RH-1-2010 Responses of Enbridge to Imperial IRs Page 171 of 323
that each of the individual operations is of similar risk and thus has a cost of capital equal to the parent’s cost of capital. Assume, for example, the corporate entity that raises debt is comprised of a pipeline and oil and gas exploration and development operations. The cost of debt would be lower to the diversified entity than the combined costs of debt of each of the operations as a stand-alone operation. However, if the pipeline were to be charged (and pass on to toll payers) the company-wide cost of debt, the pipeline operations would be subsidizing the oil and gas exploration and development operations.
(c) The total external long-term debt of Enbridge Pipelines at the end of 2008 was $1.93 billion, compared to the debt of Enbridge of approximately $100 million based on a 50% debt component. Even if Enbridge’s stand-alone cost of debt were 100 basis points higher than the cost of debt of the other pipeline operations, the company-wide cost of debt would be only be five basis points higher than it would be in the absence of Enbridge.
RH-1-2010 Responses of Enbridge to Imperial IRs Page 172 of 323
IOL-Enbridge 107
Reference: Written evidence of Enbridge (Adobe Number A1R0V6), Appendix A- 7.2, page 15, lines 348 to 352.
Preamble: The author discusses the exception to the stand-alone principle when it comes to cost of debt. Ms. McShane states that “While the assignment of Enbridge Pipelines’ weighted average cost of long-term debt is a departure from the pure application of the stand-alone principle, it is consistent with regulatory practice...”
Requests: (a) Please provide examples of this “regulatory practice”.
(b) Is Ms. McShane aware of instances where the stand-alone principle was applied with respect to cost of debt? If so, please provide examples.
(c) Is the departure from the stand-alone principle when it comes to cost of debt a result of Enbridge’s Line 9 inability to achieve investment grade ratings on a stand-alone basis? If Enbridge Line 9 were able to achieve A (or higher) debt ratings, is Ms. McShane of the opinion that this deviation from a pure application of the stand-alone principle is still appropriate?
Responses: (a) See response to IOL-Enbridge 54.
(b) See response to IOL-Enbridge 104(b).
(c) No. The conclusion that Enbridge would not be able to achieve debt ratings in the A category, similar to those of Enbridge Pipelines, the entity that raises the debt, supports either reliance on a stand-alone cost of debt or recognition of the higher cost of capital in the ROE if the company-wide cost of debt is used. If Enbridge were able to achieve debt ratings in the A category, it would be reasonable to conclude that its stand-alone cost of debt would be equal to the company-wide cost of debt. In those circumstances, reliance on the company-wide cost of debt for Enbridge for toll setting purposes would be consistent with the stand-alone principle. See response to IOL-Enbridge 102(a).
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IOL-Enbridge 108
Reference: Written evidence of Enbridge (Adobe Number A1R0V6), Appendix A- 7.2, page 16, lines 385 to 388.
Preamble: In discussing business risk, Ms. McShane states that “[t]he capital structure in particular needs to compensate for longer-term risks, as the financing of a pipeline is premised on the longer-term risks as perceived by investors when committing capital to the enterprise.”
Requests: (a) Please explain in more detail the way in which the capital structure should be adjusted to compensate for long-terms risks.
Response: (a) The referenced statement was simply intended to recognize that the choice of capital structure needs to take into account the longer-term risk that the invested capital will earn a fair and reasonable return and not be fully recovered, not solely the ability of a regulated firm to earn the allowed return from year to year due to the prevailing regulatory framework. The higher the longer- term business risks, the higher the equity ratio that would be expected supporting the assets. A capital structure that recognizes the longer-term risks provides a measure of financing flexibility, or a cushion, in circumstances where the longer-term risks are experienced.
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IOL-Enbridge 109
Reference: Written evidence of Enbridge (Adobe Number A1R0V6), Appendix A- 7.2, page 17, lines 392 to 395.
Preamble: Ms. McShane argues that the premise that the “regulatory framework provides the regulator an opportunity to compensate the shareholder for the longer-term risks when they are experienced” may not hold. To support this, she states that “shipper resistance may forestall higher return awards when the risk materializes,” and that “no regulator can bind his or her colleagues or successors and thus guarantee that investors will be compensated for longer-term risks when they are incurred in the future.”
Requests: (a) Please explain what is meant by “shipper resistance”.
(b) Please explain what is meant by “return awards”.
(c) In what way are “return awards” forestalled by “shipper resistance”?
(d) Is Ms. McShane suggesting that the regulatory framework or future regulators are ineffective in addressing the business risks, and therefore the appropriate capital structure, cost of capital, and ROE of a pipeline? Please explain.
(e) Does Ms. McShane mean that the current policy of the NEB has been systematically inconsistent with the recovery of business risks? Please explain.
(f) How does Ms. McShane take into account the reliance of the Board on precedent when stating that regulators cannot bind future regulators? If Ms. McShane maintains that regulators cannot bind future regulators, does she concur that current regulators can at least influence future regulators because of the Board’s reliance on past rulings?
(g) Is Ms. McShane indicating that the fact that current regulators cannot bind future regulators is a new risk not faced by the pipeline before now? If so, please explain.
(h) Does Ms. McShane think that the NEB’s determination of a generic rate of return is inaccurate in some way? Please explain.
Prologue: IOL-Enbridge 109(f) refers to "the reliance of the NEB on precedent" and to "the Board's reliance on past rulings." The Board has made it clear in at RH-1-2010 Responses of Enbridge to Imperial IRs Page 175 of 323
least five decisions that it is not strictly bound by its prior decisions, as precedents or otherwise, or by the principle of stare decisis. The Board has indicated that it strives for consistency in its decisions, however, and that it may decide to consider and apply principles articulated in its earlier decisions. The following are the five decisions:
(i) OH-2-97 Reasons for Decision, Interprovincial Pipe Line Inc., December 1997 at p. 56;
(ii) RH-2-98 Reasons for Decision, B.C. Gas Utility Ltd., March 1999 at p.14;
(iii) RH-1-2000 Reasons for Decision, Maritimes & Northeast Pipeline Management Ltd., August 2000 at p. 39;
(iv) RH-1-2005 Reasons for Decision, Enbridge Pipelines Inc., June 2005, at p. 21; and
(v) Mackenzie Gas Project -- Hearing Order GH-1-2004 -- Ruling #16 dated 10 July 2006 at p. 13.
Responses: (a) “Shipper resistance” refers to the unwillingness or inability of shippers (due to competitive constraints) to pay higher tolls.
(b) “Return awards” refers to the allowed return granted a utility by a regulatory panel.
(c) See response to IOL-Enbridge 109(a).
(d) No. Ms. McShane was simply stating that there is no guarantee that the shareholder will be compensated when long-term risks are experienced. The conclusion follows logically from the fact that no regulatory panel can bind successor panels. The ability (or inclination) of successor panels to compensate utilities when risks are experienced is dependent on the utility's circumstances at the time; for example, the regulatory framework in place or the shippers’ ability to bear the costs of the experienced risk.
(e) No. See response to IOL-Enbridge 109(d).
(f) Reliance on precedents is not assured. The Board has the power to review, vary, or rescind any decision it issues. The approach to regulation essentially reflects a combination of political views and philosophy (e.g., what stakeholders should bear the risks), economic conditions, and energy policy. Based on current policies and practices, Ms. McShane has no reason to believe that Enbridge, similar to other utilities in North America, will not be RH-1-2010 Responses of Enbridge to Imperial IRs Page 176 of 323
provided a reasonable opportunity to recover its invested capital in Line 9. However, political views and regulatory philosophy can change; economic and competitive conditions can change and energy policies can change.
(g) No.
(h) No. Although Ms. McShane believes the recent multi-pipeline ROEs have been too low, the referenced sentence was not addressing that issue.
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IOL-Enbridge 110
Reference: Written evidence of Enbridge (Adobe Number A1R0V6), Appendix A- 7.2, page 18, lines 429 to 434.
Preamble: Ms. McShane discusses factors key to the business risk profile at the time Line 9 was reversed. She states that “There was an acknowledged risk that Line 9 could be underutilized in the early years of reversal because the reversed Line 9 would be accessing world supplies that had multiple outlets... and shippers on Line 9 had alternative sources of supply.”
Requests: (a) Please define “early years.”
(b) Please elaborate and explain the degree to which risk was “acknowledged” at the time of the Line 9 reversal.
(c) Was the possibility of underutilization acknowledged only to be present only “in the early years?” If so, why? What would have changed in the long-term that would have mitigated the risk?
(d) Was there an acknowledgment of long-term underutilization? If so, please explain the manner in which this occurred.
Responses: (a) The reference to early years was taken from the OH-2-97 Reasons for Decision, page 42, in the matter of the reversal project. A review of the transcripts from the OH-2-97 proceeding indicates that “early years” refers to the term of the FSA. The oral argument of IPL, Volume 20 of the transcripts, stated that “utilization of a reversed Line 9 in the early years, for which the FSA assures cost recovery, is required because, in IPL's view we are – and I quote – “on the cusp", unquote, of a scenario where inland production is falling and offshore crude is becoming more attractive.”
(b) The reference is from page 2 of the OH-2-97 Reasons for Decision, which states that “IPL acknowledged that the pipeline has some risk of underutilization, especially in the early years, because it accesses world sources rather than an inland supply with few outlets and serves a limited market with alternate supply sources.” See response to IOL-Enbridge 110(a).
(c) No, as indicated in the responses to IOL-Enbridge 110(a) and (b). A review of the transcripts (e.g., Vol. 9, pages 114-115, and Vol. 12, pages 83-84) in the OH-2-97 proceeding indicates that both IPL and the Refiners foresaw a future in which inland crude production (e.g., from Western Canada) would be falling. At page RH-1-2010 Responses of Enbridge to Imperial IRs Page 178 of 323
38 of the OH-2-97 Reasons for Decision, the Board concluded that it “is satisfied that the economic interest of the Refiners will result in high utilization of the reversed facilities during the Primary Term. The Board is also satisfied that future market conditions will result in high utilization rates beyond the Extended Term.” This has not come to pass; Western Canadian crude production is now steadily rising. The long-term changes in the marketplace have not mitigated the risk of underutilization, but have increased the risk of underutilization. Consequently, a key premise for the original Line 9 Reversal Project has been undermined, so that Enbridge is exposed to significant risk that the pipeline will not only be underutilized but idled.
(d) Yes. See response to IOL-Enbridge 110(c).
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IOL-Enbridge 111
Reference: Written evidence of Enbridge (Adobe Number A1R0V6), Appendix A- 7.2, page 23, Table 2.
Preamble: In Table 2, Ms. McShane lists several comparison pipelines, for purposes of evaluating relative business risks.
Requests: (a) Are the pipelines listed single lines or pipeline systems?
(b) Please explain how it is appropriate to compare a single pipeline, evaluated on a stand-alone basis, with pipeline systems that are composed of multiple lines.
(c) All other factors equal, would Ms. McShane agree that a pipeline system would be exposed to lower business risk relative to an individual line (as a result of diversification)? If not, why not?
Responses: (a) Except for Plateau-Western System and Enbridge Pipelines (N.W.), the pipelines listed on Table 2 are pipeline systems.
(b) There are no comparable pipelines that are configured exactly the same as Line 9 or face precisely the same risks. Therefore, it is necessary to rely on information for the most comparable companies. In the RH-2-94 proceeding, the Board noted that TQM was a single pipeline which exposed it to relatively higher risk than pipelines with multiple lines. The fact that TQM was a single pipeline did not preclude comparing it on a relative risk basis to other pipelines with multiple lines.
(c) Yes.
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IOL-Enbridge 112
Reference: Written evidence of Enbridge (Adobe Number A1R0V6), Appendix A-7.2, page 25, lines 607 to 613.
Preamble: Ms. McShane discusses the relative risks of Enbridge Pipelines, Trans Mountain Pipeline ULC, and Enbridge Line 9.
Requests: (a) When Ms. McShane refers to “Enbridge Pipelines,” is this inclusive of Line 9? Please discuss the reasoning behind and impact of including/excluding Line 9 from “Enbridge Pipelines”.
(b) Has Ms. McShane reviewed the Incentive Toll Settlements that Enbridge Pipelines and Trans Mountain operate under? If so, please provide copies of each.
Responses: (a) Ms. McShane was not including Line 9 in the assessment of the relative business risks of Enbridge Pipelines and Enbridge (i.e., Line 9 on a stand-alone basis). The discussion of Enbridge Pipelines was related to the segment of the Enbridge System referred to as the Older System; see response to NEB 1.10 for definition of “Older System”. The purpose was to compare the risks of the Older System to those of Line 9, each on a stand-alone basis. Even if Line 9 were to have been included, since it accounts for only approximately 0.5% of the Enbridge Pipelines’ net income, the impact would have been minimal.
(b) Yes. The settlements are on the Board’s website. The links are as follows:
Enbridge 2010 Canadian Mainline Interim Tolls Application: https://www.neb-one.gc.ca/ll- eng/livelink.exe/fetch/2000/90465/92835/155829/601435/602560/602555/A1R9Y5_- _2010_Canadian_Mainline_Interim_Tolls_Application.pdf?nodeid=602501&vernum=0
Trans Mountain: https://www.neb-one.gc.ca/ll- eng/livelink.exe/fetch/2000/90465/92835/267614/438200/437719/A0W5C2_- _Application.pdf?nodeid=437726&vernum=0
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IOL-Enbridge 113
Reference: Written evidence of Enbridge (Adobe Number A1R0V6), Appendix A- 7.2, page 27, lines 660 to 664.
Preamble: Ms. McShane opines that “With respect to relative business risk, I would judge that the inherent business risks of the Milk River Pipeline and Enbridge are not dissimilar.”
Requests: (a) Can Ms. McShane please elaborate on and provide explanation for this statement, including any data and calculations?
(b) As Ms. McShane has concluded that they are not dissimilar, would she also conclude that the “inherent business risks of the Milk River Pipeline and Enbridge” are similar? If no, why not?
Responses: (a) Ms. McShane’s assessment was based on the conclusions of the Board in the Reasons for Decision for the Milk River Pipeline quoted at lines 637 to 654. In that decision, the Board concluded that the business risks of Milk River may be somewhat higher than that of Trans Mountain because it is smaller with more limited supply and markets, but also referred to its limited competitive market and its ability to exercise market power. Enbridge is also a relatively small pipeline (compared to the Older System, as defined in response to NEB 1.10, and to Trans Mountain) with more limited markets, and while it may have access to vast offshore supplies, it has little if any ability to exercise market power.
(b) They would be similar in terms of level of inherent business risks faced, but, as noted at lines 662-664, she would judge the short- term risks of the Milk River Pipeline to be higher than those of Enbridge as the Milk River Pipeline does not have the short-term risk mitigation which will be provided for Enbridge by its proposed toll adjustment mechanism and deferral accounts and because of the relatively smaller size of the Milk River Pipeline.
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IOL-Enbridge 114
Reference: Written evidence of Enbridge (Adobe Number A1R0V6), Appendix A- 7.2, pages 28 to 29, footnotes 24, 25 and 26.
Preamble: Moody’s Rating Methodology reports.
Requests: (a) Please provide cited reports.
Response: (a) See Attachments 1 and 2 to NEB 1.13.
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IOL-Enbridge 115
Reference: Written evidence of Enbridge (Adobe Number A1R0V6), Appendix A- 7.2, pages 29 to 30, lines 724 to 729 and 745 to 747, and footnote 27.
Preamble: In discussing business risk profiles, Ms. McShane determines that Enbridge is likely to be assigned a “Satisfactory” rating, based on the fact that Pembina Pipeline Corp. and InterPipeline Fund are in the “Satisfactory” category. Using an S&P business and financial risk matrix, Ms. McShane further states that “in isolation, for a “Satisfactory” business risk profile rating, a debt ratio in the range of 35%-45% (equity ratio of 55%-65%) is indicated for a BBB rating.”
Requests: (a) Can Ms. McShane explain why these two firms were chosen as proxies for Enbridge? What similarities and/or differences are there?
(b) How does Ms. McShane determine that Enbridge would receive an “Intermediate” financial risk assessment?
(c) Does Ms. McShane interpret the S&P financial risk matrix starting from the assumption that Enbridge would achieve a BBB debt rating?
(d) Ms. McShane states (on lines 724 to 725) that the financial risk assessment includes the consideration of three quantitative metrics (one of which is the debt/capital ratio). Does this mean that the assessment follows from the metrics, or, that the metrics follow from the assessment?
Responses: (a) Ms. McShane concluded that “Given the business risk profiles assigned to the various Canadian utilities it rates, Enbridge would be assigned a business risk category of ‘Satisfactory’” as stated at lines 745-746. Ms. McShane did not mean to suggest that the specific risks of the Pembina Pipeline Corporation and the Inter Pipeline Fund were the same risks that Enbridge faces, only that there are oil pipelines in Canada assigned a business risk category of “Satisfactory.” Ms. McShane reviewed the entire slate of business risk ratings that had been assigned by S&P, from which she concluded that, on a stand-alone basis, Enbridge would be assigned a business risk ranking no higher than “Satisfactory.” This conclusion was based on her assessment of where Enbridge would fit relative to all of the Canadian regulated companies that S&P ranked. Ms. McShane judged that Enbridge faces higher risks than Union Gas or Westcoast Energy, both ranked “Strong,” RH-1-2010 Responses of Enbridge to Imperial IRs Page 184 of 323
and higher risks than Nova Scotia Power and Maritime Electric, both ranked “Satisfactory.”
(b) Ms. McShane’s evidence does not state that Enbridge would receive an “Intermediate” financial risk assessment. The referenced sentence was intended to be an explanation of how the S&P matrix is to be interpreted. The sentence states, “In isolation, for a “Satisfactory” business risk profile ranking, a debt ratio in the range of 35%-45% (equity ratio of 55%-65%) is indicated for a BBB rating.”
(c) No. See response to IOL-Enbridge 115(b).
(d) The assessment of the financial risk ranking follows from the metrics.
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IOL-Enbridge 116
Reference: Written evidence of Enbridge (Adobe Number A1R0V6), Appendix A- 7.2, page 32, lines 804 to 808.
Preamble: Ms. McShane discusses factors that affect the yield of long term Government of Canada bonds. She states that “The secular decline in long-term Canada bond yields reflects three factors: a reduction in the expected rate of inflation over the long-term, the waning of investors’ fear that inflation would reignite to levels experienced in the 1980s decade, and a declining supply of long-term government debt relative to demand.”
Requests: (a) Please clarify the difference between “a reduction in the expected rate of inflation” and “the waning of investors’ fear that inflation would reignite.”
(b) Did Ms. McShane rely on indicators other than bond yields to determine that these factors were indeed occurring? If so, what indicators?
Responses: (a) By the expected rate of inflation, Ms. McShane means the long- term forecasts of inflation. By “the waning of investors’ fear that inflation would reignite,” Ms. McShane means the reduction of the premium in long-term Government bonds that investors required for the risk that inflation would reignite. The premium required for fear of higher future inflation can be estimated by comparing the yield on “conventional” long-term Government bonds to the yield on real return bonds. The difference is a measure of the premium that investors require for inflation, both expected and unexpected. The larger is the difference between the forecast rate of inflation and the total premium for inflation imbedded in the inflation premium, the higher is the component of the inflation premium that is required for the fear that inflation will reignite.
(b) Ms. McShane relied on yields on “conventional” bonds, yields on real return bonds, long-term forecasts of inflation, and the trends in the level of the outstanding long-term government debt in relation to GDP, in addition to having followed closely what was occurring in the economy and capital markets during this period.
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IOL-Enbridge 117
Reference: Written evidence of Enbridge (Adobe Number A1R0V6), Appendix A- 7.2, page 35, Figure 2 and page 60, Schedule 1.
Preamble: To illustrate how the formula-based NEB benchmark multi-pipeline ROE can cause incongruous results, Ms. McShane compares allowed ROEs for NEB-regulated pipelines to allowed ROEs for U.S. gas and electric utilities.
Requests: (a) Please provide source data for Schedule 1. Please provide the underlying data and/or calculations used in determining the allowed ROEs for U.S. utilities”, U.S. gas utilities and U.S. electric utilities. How do “U.S. utilities” differ from “U.S. gas utilities” and “U.S. electric utilities”?
(b) Please detail which pipelines are included in “NEB-regulated pipelines.” Are both oil and gas pipelines included?
(c) Please detail which U.S. utilities, U.S. gas utilities and U.S. electric utilities are included, and their respective allowed ROEs.
Responses: (a) The source data and underlying calculations are provided in Attachment 1 to IOL-Enbridge 92. “U.S. utilities” represents a weighted (by the number of decisions released) average of the ROEs for the U.S. gas utilities and U.S. electric utilities. In other words, Column 5 of Schedule 1 is a weighted average of Columns 8 and 11 of Schedule 1.
(b) The pipelines that were included in “NEB-regulated pipelines” are TransCanada PipeLines and Westcoast Energy, both gas pipelines, because each had allowed ROEs set annually from 1990-1994, prior to the release of the Board’s RH-2-94 Reasons for Decision. The allowed ROEs for the NEB-regulated pipelines from 1995- 2009 represent the ROEs determined by the RH-2-94 automatic adjustment formula.
(c) The data are provided by Regulatory Research Associates Inc. (“RRA”) which is owned by SNL Financial LC (“SNL”). RRA provided the data in composite form on a quarterly basis by industry (gas and electric) in a quarterly publication, subject to copyright protection, entitled Major Rate Case Decisions. RRA compiles the ROEs and common equity ratios from the decisions that are released each quarter by the various state regulators. The total number of cases for each of the electric and gas utility RH-1-2010 Responses of Enbridge to Imperial IRs Page 187 of 323 industries that were included in the 1995-2009 regression analysis was provided in response to NEB 1.34. The quarterly averages used to estimate the regressions were provided in an Excel workbook in response to IOL-Enbridge 92. For the entire 1990- 2009 period included on Schedule 1, there were 443 gas utility decisions and 541 electric utility decisions. Foster Associates has access to the names of the individual utilities and their respective allowed ROEs via its subscription to SNL's proprietary data base. The SNL Master Subscription Agreement precludes Foster Associates from distributing this information "in a quantity or in a manner that serves as a substitute for purchase of Licensed Materials from SNL." The term "Licensed Materials" includes the requested information. Foster Associates has accordingly declined to provide this information to Enbridge and, as a result, Enbridge is not able to provide the information in response to this request item.
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IOL-Enbridge 118 Reference: Written evidence of Enbridge (Adobe Number A1R0V6), Appendix A- 7.2, pages 33 and 35, lines 844 to 854 and 879 to 882. Preamble: Ms. McShane argues that reliance on the NEB multi-pipeline formula led to incongruous results during 2009 when the formula indicated lower costs of capital for pipelines, while other indicators showed higher costs. As a result, Ms. McShane turns to a comparison between allowed ROEs for NEB-regulated pipelines to allowed ROEs for U.S. gas and electric utilities as a means of indicating the degree to which multi-pipeline formula ROE “diverged off course”. Requests: (a) Given that Schedule 1 of Ms. McShane’s prepared testimony indicates that the allowed ROE for U.S. utilities, U.S. gas utilities and U.S. electric utilities all declined during 2009, as did the allowed Canadian ROE, in what way does a comparison of U.S allowed ROE’s provide an indication of the “divergence”? (b) Does Ms. McShane have an opinion about the way allowed ROEs are determined for U.S. gas and electric utilities, considering that they too “incongruously” adopted lower allowed ROEs in 2009 than 2008? Responses: (a) The divergence refers to the large differential between the Canadian and U.S. allowed returns that appeared in 1998, not simply the results of a single year. See response to IOL-Enbridge 36. (b) The decisions will lag the actual data that was used to perform the cost of equity tests on which the regulators relied in arriving at their decisions. The table below presents the allowed ROEs on a quarterly basis from the beginning of 2008 as updated through the first quarter of 2010. The quarterly averages of allowed ROEs, when the lag between market data and decision date is recognized, indicate that allowed returns rose from third quarter 2009 through first quarter 2010. Weighted Gas Electric Average 2008 Q1 10.38 10.45 10.42 Q2 10.17 10.57 10.46 Q3 10.49 10.47 10.48 Q4 10.34 10.33 10.34 2009 Q1 10.24 10.29 10.27 Q2 10.11 10.55 10.35 Q3 9.88 10.46 10.23 Q4 10.27 10.54 10.41 2010 Q1 10.24 10.66 10.51 RH-1-2010 Responses of Enbridge to Imperial IRs Page 189 of 323
Source: Regulatory Research Associates RH-1-2010 Responses of Enbridge to Imperial IRs Page 190 of 323
IOL-Enbridge 119
Reference: Written evidence of Enbridge (Adobe Number A1R0V6), Appendix A- 7.2, page 37, lines 941 to 945.
Preamble: Ms. McShane lists three criteria that should govern any ROE formula.
Requests: (a) Please indicate any material (publications, decisions, evidence of established economic or financial theory or practice) that Ms. McShane relied upon in formulating these criteria.
Response: (a) That an ROE formula satisfy the criteria of simplicity, accuracy and transparency follows from regulatory decisions, including RH- 2-94. The Board indicated, in Hearing Order RH-2-94, that amongst the issues to be considered was “what simplified procedure should be implemented to effect an annual adjustment to the rate of return applicable to the pipelines between cost of capital proceedings?” Further, in the RH-2-94 Reasons for Decision, the Board stated at page 1 that “it was the Board’s intention to put in place means of improving the efficacy of the toll setting process for the year 1995 and beyond….[and] to avoid annual hearings on the cost of capital and was of the view that some automatic mechanism to adjust the return on common equity could be the most appropriate way to ensure that this return continued to be fair to all parties, while avoiding the expense of litigating annual or biennial changes in the rate of return.”
Similar goals of simplifying and improving the regulatory process as well as reflecting major changes in the capital markets were set forth by the Ontario Energy Board in its March 1997 Compendium to Draft Guidelines on a Formula-Based Return on Common Equity for Regulated Utilities (Draft Guidelines), at page 6:
The primary advantage of a formula-based rate of return is the simplification of the hearing process. Based upon a numerical equation, formulaic ROEs have the advantage of being relatively free from conflicting interpretation and being readily understood by all participants. Returns based on generic formulas also reduce the need for complex, annual risk assessments, while still reflecting major changes in the capital markets
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IOL-Enbridge 120
Reference: Written evidence of Enbridge (Adobe Number A1R0V6), Appendix A- 7.2, page 40, lines 1009 to 1016.
Preamble: Based on two regression analyses, Ms. McShane proposes a new benchmark pipeline ROE that proposes that the ROE should be adjusted by 50% of the change in long-term government bond yields and by 50% of the change in corporate bond yield spreads. The regression coefficients for the independent variables for long-term government bond yields were 0.47 and 0.40; for corporate bond yield spreads they were 0.27 and 1.15.
Requests: (a) Considering the wide variability of the coefficients, on what basis does Ms. McShane conclude that 50% is the appropriate adjustment measure (for both independent variables)?
Response: (a) See response to NEB 1.28(c).
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IOL-Enbridge 121
Reference: Written evidence of Enbridge (Adobe Number A1R0V6), Appendix A- 7.2, page 40, lines 1023 to 1026, footnote 38.
Preamble: Ms. McShane reinforces her proposal of a revised benchmark ROE by stating that it is analogous to the one adopted by the State of California PUC. In footnote 38, she notes that the PUC automatic adjustment mechanism is used only during interim years between triennial cost of equity reviews by the Commission. In addition, the PUC formula will not be adjusted unless the relevant long-term utility bond yields change by more than 100 basis points. Ms. McShane’s proposed formula does not include these conditions.
Requests: (a) Does Ms. McShane have an opinion as to whether the lack of periodic reviews will affect the suitability of her proposed formula over the long-term?
(b) Please explain any reasoning that Ms. McShane used in deciding not to include a trigger threshold (as the PUC did) in her benchmark pipeline ROE.
Responses: (a) Although Appendix A-7.2 does not propose a periodic review of the formula, Ms. McShane is of the view that a periodic review of any formula is appropriate, to ensure that the formula results have not gone off track.
(b) With the trigger as implemented by the CPUC, the ROE will not change unless there is a fairly substantial change in the cost of equity. However, since the CPUC will also be conducting a triennial cost of capital proceeding, the cost of equity will be reviewed and reset fairly frequently. While Ms. McShane is of the view that a periodic review is appropriate, she does not believe that it is necessary to review the cost of capital every three years. With less frequent reviews, Ms. McShane sees no reason not to adjust the allowed ROE annually as indicated by the formula.
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IOL-Enbridge 122
Reference: Written evidence of Enbridge (Adobe Number A1R0V6), Appendix A- 7.2, page 41, lines 1038 to 1049; page 63, Schedule 3.
Preamble: Ms. McShane discusses calculations made in Schedule 3.
Requests: (a) Please provide data, including Schedule 3, and formulas underlying calculations, sufficient such that analysis can be independently reproduced. In particular, please provide the data in an excel spreadsheet, including the formulas embedded in any cell calculations.
Response: (a) See Attachment 1 to IOL-Enbridge 92. The formula in cell D22 was corrected with no impact on the final results.
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IOL-Enbridge 123
Reference: Written evidence of Enbridge (Adobe Number A1R0V6), Appendix A- 7.2, page 43, lines 1096 to 1109.
Preamble: In creating both the “Benchmark Utility Sample” and the “MLP Sample,” Ms. McShane uses U.S. companies.
Requests: (a) Does Ms. McShane have an opinion as to what impact choosing U.S. utilities instead of Canadian utilities might have on the outcome of the average investment betas?
Response: (a) No. The objective of the analysis was to estimate an incremental risk premium for Enbridge. Consequently, the focus was on differentials in betas, not absolute betas, for which two samples were required. Since there are only six publicly-traded companies in Canada with significant regulated operations (Canadian Utilities, Emera, Enbridge, Fortis, Pacific Northern Gas, and TransCanada), the universe of available comparators is not large enough to be able to develop two samples of companies of differing levels of risk. Consequently, Ms. McShane could not perform the incremental analysis using Canadian companies.
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IOL-Enbridge 124
Reference: Written evidence of Enbridge (Adobe Number A1R0V6), Appendix A- 7.2, page 44, lines 1124 to 1126.
Preamble: Ms. McShane “compares investment risk betas of the benchmark utility sample and the MLP sample with their corresponding book value common equity ratios measured over the same period as the betas.”
Requests: (a) Please explain why the common equity ratios are measured using book value instead of market value.
Response: (a) Ms. McShane relied on book value capital structures because they represent the capital structures on which allowed ROEs for regulated companies are conventionally established, which form the basis for debt rating agency guidelines, and which are reported by equity analysts and by the companies themselves. See response to NEB 1.11.
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IOL-Enbridge 125
Reference: Written evidence of Enbridge (Adobe Number A1R0V6), Appendix A- 7.2, page 46, lines 1176 to 1180.
Preamble: Ms. McShane states that the “long term average difference in the yield on long-term A and BBB rated utility debt has been approximately 35 basis points, or approximately 25 points on an after-tax basis...”
Requests: (a) Please provide documentation, source data and calculations supporting the claim of a 35 basis point difference between these debt ratings.
(b) Please provide the corporate tax schedule relied upon for this calculation.
Responses: (a) See Attachment 1 to IOL-Enbridge 92.
(b) No corporate tax rate schedule was used in this calculation.
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IOL-Enbridge 126
Reference: Written evidence of Enbridge (Adobe Number A1R0V6), Appendix A- 7.2, pages 53 to 59, appendices B and C.
Preamble: Ms. McShane provides tables showing information for Canadian liquid pipelines.
Requests: (a) Please provide source documents and data, as well as any calculations used, for all information found in appendices B and C.
Response: (a) See the links provided in response to IOL-Enbridge 112 for information regarding Appendix B. Additional information is provided in the following:
(i) Attachment 1 to IOL-Enbridge 126(a): Enbridge (NW), Order TO-4-99;
(ii) Attachment 2 to IOL-Enbridge 126(a): Enbridge Pipelines Annual Information Form for 2008;
(iii) Attachment 3 to IOL-Enbridge 126(a): Express Pipeline, 76 FERC ¶ 61245 (Sept. 11, 1996);
(iv) Attachment 4 to IOL-Enbridge 126(a): the Board’s Reasons for Decision Concerning Tolls for the Milk River Pipeline, August 2001, Toll Complaint;
(v) Attachment 5 to IOL-Enbridge 126(a): the Board’s Pipeline Services Survey Results, May 2009;
(vi) Attachment 6 to IOL-Enbridge 126(a): the BCUC’s Decision, Plateau Pipe Line Ltd., Western System Application for Permanent Tolls, June 26, 2001;
(vii) Attachment 7 to IOL-Enbridge 126(a): the Board’s Reasons for Decision, Trans-Northern Pipelines Inc., RHW-3-96, June 1996, Toll Settlement; and
(viii) Attachment 8 to IOL-Enbridge 126(a): the Board’s Order TO-3-95, 8 June 1995, Trans-Northern Pipelines Inc.
See Attachment 1 to IOL-Enbridge 92 for information regarding Appendix C.
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IOL-Enbridge 127
Reference: Written evidence of Enbridge (Adobe Number A1R0V6), Appendix A- 7.2, pages 15 and 52, lines 334 to 336 and 1176 to 1178.
Preamble: Discussion of cost of debt differentials between differently rated bonds.
Requests: (a) Please explain and reconcile the following statements: “the significant differentials (up to 250 basis points) between the potential costs of long-term debt of BBB rated companies and of Enbridge Pipelines [noted to be A rated, line 305] provides a perspective on the potential magnitude of the cost of debt benefits which accrue to the Line 9 tollpayers” and “The long-term difference in the yield on long-term A and BBB rated utility debt has been approximately 35 basis points...”
Response: (a) The 35 basis points represents the long-term average difference between the cost of long-term A rated and BBB rated utility debt. The specific company spreads referenced relate to the indicated spreads for new long-term debt issues that were estimated by RBC (based on the prevailing yields) during the financial crisis.
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IOL-Enbridge 128
Reference: Written evidence of Enbridge (Adobe Number A1R0V6), Appendix A- 7.2, page 46, lines 1185 to 1187.
Preamble: Ms. McShane states that “With Enbridge Pipelines’ lower cost of debt assigned to Enbridge, the ROE need to be correspondingly higher (by 25 basis points) to equate to a stand-alone overall cost of capital for Enbridge compatible with its business risk”.
Requests: (a) Please explain this statement, with respect to the earlier assertion that tollpayers benefit by way of a lower cost of debt from the size and diversity of Enbridge Pipelines’ operations. Why does the ROE need to be higher to equate for the lower cost of debt? Wouldn’t this eliminate the benefit tollpayers receive from “the size and diversity of the company’s operations”?
(b) Is the author proposing an exemption from the stand-alone principle for the cost of debt, but not for the overall cost of capital?
Responses: (a) The objective was to ensure that the overall cost of capital for Enbridge adhered to the stand-alone principle. See response to NEB 1.37.
At page 43 of Appendix A-7.2, Ms. McShane states that “At a minimum, the difference would be the difference between the cost to a BBB rated issuer and an A rated issuer.” For a small entity like Enbridge, on a pure stand-alone basis, the true cost could be materially higher because (1) the small size of debt issues would likely require Enbridge to access private, rather than public, financing which would attract a private placement premium; (2) the outlook for the utilization of Line 9 would likely lead potential investors to either require a higher premium than available to BBB issuers or to attach covenants to loans (e.g., minimum debt service coverage). They may require as well the annual amortization of the outstanding principal. Thus, by attaching either a premium of 35 basis points to the company-wide average cost of long-term debt, to reflect the long-term difference in spread between A and BBB rated utility debt yields, or 25 basis points to the ROE, tollpayers continue to receive benefits from the size and diversity of Enbridge Pipelines’ company-wide operations.
(b) No. See response to IOL-Enbridge 128(a).
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IOL-Enbridge 129
Reference: Written evidence of Enbridge (Adobe Number A1R0V6), Appendix A- 7.2, page 22, lines 555 to 557.
Preamble: Ms. McShane states that “While the proposed depreciation rates represent Enbridge’s best estimates of the remaining depreciable life of Line 9, there remains a significant risk that the actual remaining service life in either direction will be shorter than currently anticipated.”
Requests: (a) How does an increase in the depreciation rate affect the choice of an equity portion?
(b) Please confirm that Ms. McShane makes her recommendation about common equity ratio and ROE based on the depreciation rates given in Appendix A-4.
Responses: (a) As the Board recognized in the RH-2-2004 proceeding, cited in response to IOL-Enbridge 177(b), “the depreciation rates in use may not actually reflect the estimates of economic life that would be selected if assessed at that point in time. A company can mitigate the risk that the estimates in use are not current by bringing forward an application to reconsider its depreciation rates. The part of this risk that is mitigable should not be compensated through the cost of capital. Should it become apparent that depreciation rates do not adequately reflect current estimates of economic life, it is incumbent on the management of the company to seek to change depreciation rates, not to expect incremental compensation through the cost of capital.” However, as stated in response to IOL-Enbridge 143, if depreciation rates are set at levels designed to allow the recovery of capital over a shorter period than the economic life of a pipeline, they can be used as an offset to business risk or, alternatively, they can increase business risk if recovery of capital is deferred in order to make rates more competitive. While, as also indicated in that response, Ms. McShane is not aware of any circumstances in which depreciation rates were either increased as an offset to business risk or reduced to make rates more competitive, theoretically, in such circumstances, a lower or higher common equity ratio and/or a higher or lower ROE would be warranted.
(b) Not confirmed. Ms. McShane did not recommend a common equity ratio; rather, she assessed the reasonableness of Enbridge’s common equity ratio. She made her assessment in this regard, and her recommendation on ROE, based on the depreciation rates set RH-1-2010 Responses of Enbridge to Imperial IRs Page 201 of 323 out in Appendix A-4. Ms. McShane is now aware that Enbridge is revising Appendix A-4, including the proposed depreciation rates, and she has no reason to change her assessment on her recommendation.
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IOL-Enbridge 130
Reference: Written evidence of Enbridge (Adobe Number A1R0V6), Appendix A- 7.2, page 9, lines 167 to 169.
Preamble: Ms. McShane indicates that for the Extended Term under the FSA, the stand-alone principal was “explicitly applied to Enbridge in the determination of tolls” for Line 9.
Requests: (a) Please provide documentation that shows that the NEB “explicitly applied” the stand-alone principal to Line 9.
(b) Is Ms. McShane aware of any other instances where the NEB has applied the stand alone principal to business divisions as opposed to separate businesses? If so, please provide documentation that indicates as such.
Responses: (a) Clauses 7.3 and 7.7 of the FSA provide for stand-alone tolls during the Extended Term; see response to IOL-Enbridge 40(a) at pages 25 and 26 of the consolidated version of the FSA. The Board stated the following at page 59 in its OH-2-97 Reasons for Decision (December 1997):
In the RH-2-91 Decision, the Board stated its belief that stand-alone tolls would be the most appropriate methodology for a reversed Line 9. The Board notes that, in the current proceeding, no party opposed the principle of stand-alone tolls. It is recognized, however, that the applied-for methodology, which is the result of negotiations between CAPP, the Refiners and Sunoco, is a compromise which would allow for a transition from fully integrated to fully stand-alone tolls. The Board is of the view that it is reasonable, in this case, to have such a transition period in order that participants have adequate time to adjust to changes in oil markets which may result from the reversal. The Board therefore approves the applied-for toll methodology which allows for a transition from a fully integrated to a fully stand-alone toll methodology.
(b) The Board has applied the stand-alone principle to both the Enbridge Mainline System and Line 8 (Oil Products Transportation System) as well as Line 9. All of them are not only RH-1-2010 Responses of Enbridge to Imperial IRs Page 203 of 323 separate businesses, but also business divisions of a single legal entity; namely Enbridge Pipelines. The following is the “documentation:”
• the Board’s approval of the 2010 Incentive Toll Settlement for the Core System by its letter decision dated May 12, 2010; and
• the Board’s approval of the Financial Support and Service Agreement dated as of October 2, 1995 between Enbridge (under its former corporate name) and Imperial Oil by Order TO-5-96 issued on August 29, 1996.
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IOL-Enbridge 131
Reference: Written evidence of Enbridge (Adobe Number A1R0V6), Appendix A- 7.2.
Preamble: In Ms. McShane’s written evidence, she refers to credit ratings of pipelines similar to Enbridge, authored by DBRS and other rating entities.
Requests: (a) Please provide copies of all rating reports referred to in Ms. McShane's testimony, from which information regarding pipelines similar to Enbridge was obtained.
(b) To the extent that the pipelines similar to Enbridge have had their credit ratings discontinued, please provide the most recent ratings report of the pipeline. To the extent that the pipelines similar to Enbridge have never had a credit rating, please provide the credit rating report of the pipeline’s parent, if available.
Responses: (a) See Attachments 1 through 19 to NEB 1.15. Additional reports are included as:
(i) Attachment 1 to IOL-Enbridge 131(a): DBRS, Enbridge Pipelines Inc. (Nov. 27, 2009);
(ii) Attachment 2 to IOL-Enbridge 131(a): DBRS, Express Pipeline Limited Partnership and Express Pipeline LLC (Oct. 16, 2009);
(iii) Attachment 3 to IOL-Enbridge 131(a): DBRS, Trans- Northern Pipelines Inc. (Apr. 28, 2009);
(iv) Attachment 4 to IOL-Enbridge 131(a): S&P, Enbridge Pipelines Inc. (Nov. 9, 2009); and
(v) Attachment 5 to IOL-Enbridge 131(a): S&P, Express Pipeline Partnership (Dec. 28, 2009).
(b) To Ms. McShane’s knowledge, only Trans Mountain has had its credit ratings discontinued. The most recent S&P and DBRS ratings reports are included as:
(i) Attachment 1 to IOL-Enbridge 131(b): S&P, Teresen Pipelines (Trans Mountain) Inc. (Dec. 17, 2004); and
(ii) Attachment 2 to IOL-Enbridge 131(b): DBRS, Teresen Pipelines (Trans Mountain) Inc. (August. 30, 2005). RH-1-2010 Responses of Enbridge to Imperial IRs Page 205 of 323
IOL-Enbridge 132
Reference: Written evidence of Enbridge (Adobe Number A1R0V6), Appendix A- 7.2, page 57, Schedule B.
Preamble: The Trans-Northern table specifies that it has “operated under settlements since 1996.”
Requests: (a) Has Ms. McShane reviewed the 1996 agreement herself? If so, please provide a copy.
Response: (a) Ms. McShane has reviewed the 1996 agreement. A copy is provided in Attachment 7 to IOL-Enbridge 126(a).
RH-1-2010 Responses of Enbridge to Imperial IRs Page 206 of 323
IOL-Enbridge 133
Reference: Written evidence of Enbridge (Adobe Number A1R0V6), Appendix A- 7.2, page 24, Table 2.
Preamble: Table 2 shows information for various comparison oil pipelines.
Requests: (a) Does Ms. McShane have any information on the relationship between actual equity ratios of the comparison pipelines in contrast to the equity ratios approved for regulatory purposes?
(b) If so, please provide this information.
Responses: (a) See Table 2 of Appendix A-7.2 and Appendix B. Both the actual and approved ratios are provided as publicly available.
(b) See response to IOL-Enbridge 133(a).
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IOL-Enbridge 134
Reference: Written evidence of Enbridge (Adobe Number A1R0V6), Appendix A- 7.2, page 9, lines 159 to 170.
Preamble: In her written evidence, Ms. McShane outlines what she believes to be the “stand-alone principal”.
Requests: (a) In applying the stand alone principal, is Ms. McShane aware of any instances in which the NEB has articulated or explained how to determine the appropriate business unit for which the stand alone principal should be applied? If so, please provide references.
Response: (a) The stand-alone principle means, in Ms. McShane’s view, that a legal entity that has non-utility as well as utility operations or discrete utility operations – such as Enbridge Pipelines has (i.e., Enbridge for Line 9) – is treated as if its only business were owning and operating its utility operations, or each discrete utility operation, for toll-making purposes. This treatment ensures that utility operations do not cross-subsidize non-utility operations or, in Enbridge Pipelines’ case, that discrete utility operations do not cross-subsidize one another. It also ensures that the utility operations have a suitable capital structure or, in Enbridge Pipelines’ case, that its discrete utility operations each have suitable capital structures.
Ms. McShane disagrees with the view that “a utility should only be allowed to recover the costs incurred by an equivalent competitive firm providing the same service.” Her view is that the stand-alone principle means that a legal entity should only be allowed to recover the costs, including the cost of capital, that it incurs in providing utility service. The return available from the application of invested capital to other enterprises of like risk – rather than enterprises “providing the same service” – is one requirement of the fair return standard. This standard is used to determine the cost of capital for a utility.
The Board has used utility operations, as the appropriate business unit, when a legal entity has non-utility as well as utility operations; see the response to IOL-Enbridge 93 (items 1-2, 4-9 and 15-18). The Board has also used business units per se when a legal entity has two or more utility operations as is the case with Enbridge Pipelines (i.e., Enbridge for Line 9); see the response to IOL-Enbridge 93 (items 1-6). RH-1-2010 Responses of Enbridge to Imperial IRs Page 208 of 323
IOL-Enbridge 135
Reference: Written evidence of Enbridge (Adobe Number A1R0V6), Appendix A- 7.2. page 23, lines 574 to 584.
Preamble: In her written evidence, Ms. McShane stated that “oil pipelines which raise debt in the public markets have capital structures that have been ‘tested’ by the capital markets.”
Requests: (a) Please explain the relationship between the capital structures that have been “tested” by capital markets and the capital structure that a regulatory body, such as the NEB, decides for ratemaking purposes. Are they necessarily the same? Does Ms. McShane have any evidence indicating whether they are the same and if not the degree to which they differ? If so, please provide.
Response: (a) They are not necessarily the same for several reasons: (1) the entity that is rated may have businesses other than the regulated oil pipeline; (2) there may have been external debt or equity raised for major capital expenditures that temporarily changed the ratios; (3) the specific terms of the debt financing (amortizing debt) in the circumstances of limited or no growth that may result in an actual capital structure that does not match the allowed capital structure; and (4) the pipeline may conclude that it requires more equity than the regulated level for purposes of maintaining its creditworthiness. For information on the actual versus allowed ratios for the oil pipelines, see pages 20-24 of Appendix A-7.2.
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IOL-Enbridge 136
Reference: Written evidence of Enbridge (Adobe Number A1R0V6), Appendix A- 7.2, page 65, Schedule 4.
Preamble: In the table “Betas and Common Equity Ratios for Benchmark Utility and MLP Samples,” a column gives percentages for Common Equity Ratio Average 2002-2008.
Requests: (a) Was the equity ratio determined by Ms. McShane or S&P? How is the equity ratio measured? Is it based on book value or market value?
Response: (a) The equity ratios were measured by Ms. McShane using the Standard & Poor’s Research Insight data base. The equity ratios are measured as a percentage of total debt (long-term and short- term), including capital leases, preferred stock, and common equity. They are book value capital structures.
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IOL-Enbridge 137
Reference: Written evidence of Enbridge (Adobe Number A1R0V6), Appendix A- 7.2.
Preamble: Throughout her written evidence, Ms. McShane refers to the “cost of long-term debt”.
Requests: (a) By cost of long-term debt, does Ms. McShane mean the yield? If yes, does she mean the market yield?
Response: (a) Yes. When Ms. McShane refers to the cost of debt, unless she specifically refers to embedded cost of debt, she means the market yield.
RH-1-2010 Responses of Enbridge to Imperial IRs Page 211 of 323
IOL-Enbridge 138
Reference: Written evidence of Enbridge (Adobe Number A1R0V6), Appendix A- 7.2, page 4, lines 18 to 21.
Preamble: In her written evidence, Ms. McShane states that she has “been asked by Enbridge Pipelines to assess the reasonableness of its proposed capital structure and recommend a rate of return on equity (“ROE”) for its Line 9 operations on a stand-alone basis; that is, as if Enbridge Pipelines’ only business were owning and operating Line 9.”
Requests: (a) Does Ms. McShane have any opinion on the capital structure and ROE for Line 9 if it were not considered as separate from the rest of Enbridge’s Canadian oil pipeline system? If so, please elaborate. If not, why not?
Response: (a) Ms. McShane does not understand the question. If Enbridge (Line 9) was not considered as separate from the rest of Enbridge Pipelines’ Canadian oil pipeline system, it would not have its own ROE and capital structure.
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IOL-Enbridge 139
Reference: Written evidence of Enbridge (Adobe Number A1R0V6), Appendix A- 7.2, page 6, lines 55 to 58.
Preamble: In her written evidence, Ms. McShane indicates that “Line 9 was originally built in 1976 with Government of Canada financial support to transport Western Canadian crude oil to Montréal refineries in order to provide additional security of supply, as well as to Levis (opposite Québec City) and Atlantic Canada refineries via ship from Montréal.”
Requests: (a) Please provide the names, locations, and capacities of refineries in and around Levis, Québec City, Montréal, and Atlantic Canada when Line 9 was originally built.
(b) Please provide the same information as of today.
Responses: (a) See Attachment 1 to IOL-Enbridge 139.
(b) See Attachment 1 to IOL-Enbridge 139. Since the date of Ms. McShane’s source, Shell has announced that it is closing its Montreal refinery.
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IOL-Enbridge 140
Reference: Written evidence of Enbridge (Adobe Number A1R0V6), Appendix A- 7.2, page 6, lines 78 to 79.
Preamble: In her written evidence, Ms. McShane explains that the FSA specifies that FSA Shippers “will have unapportioned access and rights to transportation based on their historical shipments …”
Requests: (a) Please define and explain “unapportioned access and rights to transportation based on their historical shipments” as opposed to “apportioned access and rights to transportation based on their historical shipments”.
(b) Wouldn’t rights to transportation based on historical shipments be considered a type of apportionment?
Responses: (a) Ms. McShane is describing the outcome of the formula set out in Clause 6.1(c) of the FSA; see the link in response to IOL-Enbridge 40(a). The terms Available Capacity, FSA Shipper’s Contract Volume, and Unapportioned Access, which are used in Clause 6.1(c), are defined in Clause 1.1 of the FSA. The parties to the FSA apparently did not consider, as an alternative or otherwise, “apportioned access and rights to transportation based on their historical shipments.”
(b) No. It would confer a right of priority access to apportioned capacity based on historical shipments.
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IOL-Enbridge 141
Reference: Written evidence of Enbridge (Adobe Number A1R0V6), Appendix A- 7.2, page 9, lines 159 to 170.
Preamble: In her written evidence, Ms. McShane gives her views on the stand-alone principle.
Requests: (a) Please explain whether there are any theoretical inconsistencies with the application of the stand-alone principal to all of Enbridge’s Canadian Oil pipelines versus treating each segment as a stand-alone pipeline.
(b) Is Ms. McShane aware of any Canadian regulators that do not use or recognize the stand-alone principal in regulating the participants in industries which they oversee? If so, please provide examples of instances in which this is the case.
Responses: (a) Yes. There could be inconsistencies if the specified segments actually operate as an integrated system and the risks of the individual segments are not independent of the risks of the integrated system. Ms. McShane does not view this to be the case with Enbridge Pipelines.
(b) Except for cases of Crown-owned electric utilities whose debt is guaranteed by the province(s) in which they operate, Ms. McShane is not aware of any regulatory jurisdictions in Canada where the stand-alone principle is not followed with respect to capital structure and ROE.
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IOL-Enbridge 142
Reference: Written evidence of Enbridge (Adobe Number A1R0V6), Appendix A- 7.2, pages 9 to 10, lines 159 to 161 and 194 to 195.
Preamble: In her written evidence, Ms. McShane refers to the “fair return” to which Enbridge is entitled.
Requests: (a) Are the terms “fair” and “reasonable” returns used interchangeably? If so, what is their definition? If not, what is the distinction between the terms “fair return,” “reasonable return,” and “fair and reasonable return”?
Response: (a) Ms McShane views the term “fair return” as synonymous with the term “fair and reasonable return” and defines that as the overall return on capital that meets the fair return standard which, in turn, has the following three requirements:
(i) Comparable investment requirement – overall return should be comparable to the return available from the application of invested capital to other enterprises of like risk;
(ii) Financial integrity requirement – overall return should enable the financial integrity of the regulated enterprise to be maintained; and
(iii) Capital attraction requirement – overall return should permit incremental capital to be attracted to the enterprise.
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IOL-Enbridge 143
Reference: Written evidence of Enbridge (Adobe Number A1R0V6), Appendix A- 7.2, page 10, lines 207 to 209.
Preamble: In her written evidence, Ms. McShane summarizes her opinion of the approaches used by Canadian regulators in determining a “fair rate of return on rate base”. In particular, she states that if “the total risk of the benchmark sample is higher or lower than that of the subject pipeline, an adjustment to their cost of equity would be required when setting the subject pipeline’s allowed ROE.”
Requests: (a) Is it Ms. McShane’s opinion that depreciation rates can be used as an offset to business risk? Is she aware of any instances where depreciation rates are used as an offset to business risk with the Canadian regulatory structure? If so, please explain.
Response: (a) Yes. If depreciation rates are set at levels designed to allow the recovery of capital over a shorter period than the economic life of a pipeline or, alternatively, they can increase business risk if recovery of capital is deferred in order to make rates more competitive. Ms. McShane is not aware of any situations where depreciation rates were used as an offset to business risk.
RH-1-2010 Responses of Enbridge to Imperial IRs Page 217 of 323
IOL-Enbridge 144
Reference: Written evidence of Enbridge (Adobe Number A1R0V6), Appendix A- 7.2, pages 12 to 13, lines 267 to 275.
Preamble: In her written evidence, Ms. McShane states that the “stand-alone principle encompasses the notion that the cost of capital incurred by the shippers should be equivalent to that which would be faced if Line 9 were Enbridge’s only business, raising capital in the public markets on the strength of its own business and financial parameters; in other words, as if it were operating as an independent entity. The cost of capital for the pipeline should reflect neither subsidies given to, nor taken from, other activities of Enbridge Pipelines Inc. – the legal entity – or Enbridge Inc. Respect for the stand-alone principle is intended to promote efficient allocation of capital resources among the various activities of the firm.”
Requests: (a) Can the entire Enbridge crude oil pipeline system also be evaluated on a stand-alone basis as a single, independent entity?
(b) Is Ms. McShane aware of any crude oil pipeline in Canada (comparable to Enbridge Pipelines Inc. or not) where rates of returns are determined using this more comprehensive measure? If so, please provide NEB or other regulatory decisions pertaining to these instances.
Responses: (a) No. Enbridge Pipelines’ regulated business is characterized by significant asset segregation, different regulatory frameworks (e.g., the ITSs for the Older System) and/or different contractual arrangements (e.g., the Financial Support and Service Agreement for Line 8).
(b) Ms. McShane is aware that the same rate of return applies to the entire Trans Mountain system. However, Ms. McShane is not aware of any other crude oil pipeline comparable to Enbridge Pipelines in terms of asset segregation, that applies the stand-alone principle to the entire system for rate of return determination purposes.
RH-1-2010 Responses of Enbridge to Imperial IRs Page 218 of 323
IOL-Enbridge 145
Reference: Written evidence of Enbridge (Adobe Number A1R0V6), Appendix A- 7.2, page 13, lines 279 to 283.
Preamble: In her written evidence, Ms. McShane refers to the possibility of a failure to recover “a compensatory return on, and/or the return of, the capital investment itself.”
Requests: (a) Please explain how the term “compensatory” return compares to a “fair return,” a “reasonable return,” and a “fair and reasonable return”?
Responses: (a) Ms. McShane considers the terms to be synonymous. See response to IOL-Enbridge 142.
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IOL-Enbridge 146
Reference: Written evidence of Enbridge (Adobe Number A1R0V6), Appendix A- 7.2, page 13, lines 290 to 296.
Preamble: In her written evidence, Ms. McShane opines that investment grade debt ratings “assure that the regulated company would be able to access the capital markets on reasonable terms and conditions during both robust and difficult, or weak, capital market conditions.”
Requests: (a) Please explain the meaning of the terms “robust capital market conditions,” and “difficult or weak capital market conditions”.
Response: (a) Robust capital markets would be characterized by investors, whether in debt or equity markets, exhibiting less risk aversion and more willingness to commit capital at lower rates of return without (in the case of debt markets) stringent protective covenants. In difficult markets, terms on debt may be limited (e.g., no access to the 30-year market), increased financial requirements (limitations on dividends or interest coverage tests), and higher credit spreads or more market pressure on stock prices in the case of an equity issue.
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IOL-Enbridge 147
Reference: Written evidence of Enbridge (Adobe Number A1R0V6), Appendix A- 7.2, page 17, lines 397 to 399.
Preamble: In her written evidence, Ms. McShane indicates that business risk exposes shareholders to the risk of the under-recovery of the “required return on and/or the return of, their capital investment.”
Requests: (a) Please explain what is meant by the term “required return.” How does the term compare to: (i) “compensatory return”; (ii) “fair return”; (iii) “reasonable return”; and (iv) “fair and reasonable return”?
Response: (a) The required return means the minimum return necessary to induce the investor to commit capital. A fair and reasonable return is a broader concept, defined by the fair return standard and its three requirements as listed in response to IOL-Enbridge 142.
RH-1-2010 Responses of Enbridge to Imperial IRs Page 221 of 323
IOL-Enbridge 148
Reference: Written evidence of Enbridge (Adobe Number A1R0V6), Appendix A- 7.2, page 17, lines 400 to 401.
Preamble: In her written evidence, Ms. McShane indicates that the regulatory framework “is typically designed around the inherent market and supply/physical risks.”
Requests: (a) Please explain what is meant by the term “physical risks”.
(b) Please distinguish between “physical risks” and “operating risk” as discussed in Appendix A-3.
Responses: (a) “Physical risks” encompass the risks associated with the actual operation of a pipeline that can interrupt delivery of product and cause loss of revenue.
(b) “Physical risks” are synonymous with “operating risks.”
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IOL-Enbridge 149
Reference: Written evidence of Enbridge (Adobe Number A1R0V6), Appendix A- 7.2, page 18, lines 424 to 425.
Preamble: In her written evidence, Ms. McShane indicates that “the economic life of the reversed Line 9 was expected to be similar to that of the ‘Older System.’”
Requests: (a) Is “economic life” a generic concept which can be applied for ratemaking purposes to evaluate the use of the pipe in either direction? Is it Ms. McShane’s suggestion that the pipeline will have no more economic life after it has performed the last of its east-to-west service and, as a result, be abandoned? If not, does the pipeline begin a “new” economic life?
Response: (a) There are three parts to the request item. This response is segregated accordingly.
(i) Ms. McShane views the term “economic life” as related to the particular service that the pipeline provides in its current configuration.
(ii) No, the physical assets may be used to offer a different service.
(iii) If so, the pipeline would have a different economic life. It is likely that at least a portion of the line will be used for a different service (e.g., west to east) in the future.
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IOL-Enbridge 150
Reference: Written evidence of Enbridge (Adobe Number A1R0V6), Appendix A- 7.2, page 19, lines 464 to 465.
Preamble: Ms. McShane states that “Shell Canada has effectively stopped shipping on Line 9, receiving virtually all of its requirements from Western Canada.”
Requests: (a) At what date did Shell Canada stop shipping on Line 9?
(b) What is the capacity of Shell Canada’s Ontario refinery? What oil slates is it capable of processing?
(c) What percentage of Line 9 throughput was Shell Canada shipping?
Responses: (a) See response to IOL-Enbridge 38(a).
(b) See page 8 of Appendix A-7.1.
(c) The information requested is commercial information that relates to a competitor of Imperial that Enbridge has consistently treated as confidential. Enbridge therefore objects to filing such information and declines to do so.
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IOL-Enbridge 151
Reference: Written evidence of Enbridge (Adobe Number A1R0V6), Appendix A- 7.2, page 22, lines 549 to 551.
Preamble: In her written evidence, Ms. McShane refers to the anticipations by Muse Stancil that by 2016 that “Line 9 will likely no longer be operating in westbound service.”
Requests: (a) Is Ms. McShane or Enbridge aware of any study regarding the economic attractiveness of Line 9 for use in eastbound service, either before or after 2016? If so, please provide.
Responses: (a) Neither Enbridge nor Ms. McShane is aware of any study regarding the economic attractiveness of Line 9 for use in eastbound service either before or after 2016.
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IOL-Enbridge 152
Reference: Written evidence of Enbridge (Adobe Number A1R0V6), Appendix A- 7.2, page 22, lines 556 to 560.
Preamble: In her written evidence, Ms. McShane states that “there remains a significant risk that the actual remaining service life in either direction will be shorter than currently anticipated. With respect to the reversal project costs, the estimated remaining depreciable life may be shorter than anticipated and the throughput necessary to recover the invested capital may not materialize.”
Requests: (a) Please explain what is meant by the term “significant risk”? Has Ms. McShane conducted any study to measure the degree of risk she believes exists? If so, please provide.
(b) Please explain to what measurable extent the risk of non-recovery remains, if depreciation were accelerated as requested by Enbridge.
Responses: (a) The term “significant” means that the risk that the remaining economic life of Enbridge is less than projected is non-trivial, given the possibility that current shippers may before 2016 no longer find Enbridge economically attractive. Ms. McShane has not conducted a study; her conclusions were based on discussions with Enbridge regarding the potential for alternative transportation operations for shippers prior to the end of Enbridge’s estimated economic life.
(b) The ability to recover the remaining capital is dependent on sufficient volumes being nominated for delivery through Enbridge over the estimated remaining economic life. Insufficient volumes and/or tolls would increase the risk of failure to recover the remaining capital investment.
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IOL-Enbridge 153
Reference: Written evidence of Enbridge (Adobe Number A1R0V6), Appendix A- 7.2, page 24, Table 2.
Preamble: In Table 2, it is specified that DBRS calculates the average actual common equity ratios for the Mainline for Enbridge Pipelines.
Requests: (a) Please confirm that Line 9 is included in the Mainline and thus in DBRS calculations for Enbridge Pipelines. If not confirmed, why not?
Response: (a) Confirmed. DBRS includes Line 9 in the “Enbridge System or Mainline.”
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IOL-Enbridge 154
Reference: Written evidence of Enbridge (Adobe Number A1R0V6), Appendix A- 7.2, page 26, lines 647 to 654.
Preamble: In her written evidence, Ms. McShane quotes a portion of the Reasons for Decision with respect to tolls for the Milk River Pipeline.
Requests: (a) Is either Ms. McShane or Enbridge aware of the depreciation rates assigned to the Milk River Pipeline? If so, please explain what they are.
Response: (a) Based on the information contained in the Board's Reasons for Decision, the depreciation rate for Milk River Pipeline can be estimated at approximately 3.7% (depreciation expense divided by gross plant).
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IOL-Enbridge 155
Reference: Written evidence of Enbridge (Adobe Number A1R0V6), Appendix A- 7.2, page 22, lines 546 to 547.
Preamble: Ms. McShane states, “Enbridge’s rate base includes the capital costs of the reversal project and of the subsequent maintenance of the line in westbound service.”
Requests: (a) Can Ms. McShane or Enbridge please explain the basis for the belief that only the capital costs of reversal and maintenance of Line 9 in westbound service are included in the Line 9 rate base.
(b) What were the capital costs of the pipeline reversal? Please provide documentation.
Responses: (a) Ms. McShane was so informed by Enbridge.
(b) See Attachment 1 to IOL-Enbridge 155(b).
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IOL-Enbridge 156
Reference: Written evidence of Enbridge (Adobe Number A1R0V6), Appendix A- 7.2, page 6, lines 68 to 70, footnote 3.
Preamble: In her written evidence, Ms. McShane states that “[t]he first five years of the FSA was a transition period during which the tolls on Line 9 were charged largely on a stand-alone basis, but with some aspects of integration with the ‘Older System.’“ She elaborates in a footnote that the “purpose of the integration was to have the benefits and risks of reversal shared between the Older System shippers and the FSA Shippers, while Enbridge was kept whole in respect to its Line 9 costs.”
Requests: (a) Please explain in what way and the extent to which the Line 9 tolls were integrated with the “Older System”.
(b) Please provide shipment data for both FSA and “Older System” shippers during the Primary Term of the FSA and from the expiration of the Primary Term to the present.
Responses: (a) See response to NOVA Chemicals 1.5(a).
(b) The information requested is commercial information that Enbridge has consistently treated as confidential. Enbridge therefore objects to filing such information and declines to do so.
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IOL-Enbridge 157
Reference: Written evidence of Enbridge (Adobe Number A1R0V6), Appendix A- 7.2, page 19, lines 457 to 471.
Preamble: In her written evidence, Ms. McShane discusses the status of one of the shippers on Line 9. She states: “Petro-Canada permanently closed its Oakville, Ontario refinery, announced in 2005. In light of new sulphur specifications for producing gasoline , Petro-Canada opted to expand its Montréal facilities rather than incur the costs necessary to meet the environmental rules at what Petro-Canada referred to as the “small disadvantaged” Ontario facility. Petro-Canada had accounted for approximately 25% of the Line 9 deliveries from the date of reversal in 1999 through 2004.” “Throughput on Line 9, which has a capacity of 240,000 barrels per day (“bbls/day”), has declined from an average of 215,200 bbls/day in 2000-2004 to 110,700 bbls/day in 2008. Deliveries in 200 are expected to decline further, to approximately 70,340 bbls/day.”
Requests: (a) What was the old capacity of the Petro-Canada Montréal refinery? What is the new capacity of Petro-Canada’s Montréal facility?
(b) Ms. McShane indicates that Petro-Canada accounted for about 25% of Line 9 deliveries. Please provide an electronic spreadsheet (Excel) with monthly throughput on Line 9 from 1999 through the present, for each of the shippers.
(c) Ms. McShane indicates that 2009 deliveries are expected to decline further. What is the basis for Ms. McShane’s prediction that deliveries were estimated to decline further? Did Ms. McShane conduct any studies or analysis of estimated flows on Line 9? Has Ms. McShane developed any forecasts for deliveries in 2009 and later? If so, please provide. If not, please explain the basis for expecting a decline in deliveries from 2008 to 2009.
(d) Has Enbridge developed any forecasts for deliveries in 2009 and later? If so, please provide. If Enbridge relied on other forecasts for this information, please identify these sources and provide these forecasts.
Responses: (a) As of January 1, 2005, the crude capacity of the Petro-Canada Montreal refinery was 16,690 m3/d (105,000 b/d). As of January 1, 2010, the crude capacity of the Suncor Montreal refinery was 20,640 m3/d (129,800 b/d).
(b) The information requested is commercial information that RH-1-2010 Responses of Enbridge to Imperial IRs Page 231 of 323
Enbridge has consistently treated as confidential. Enbridge therefore objects to filing such information and declines to do so.
(c) Ms. McShane relied entirely on Enbridge’s forecasts. See paragraphs 1, 7, 8 and 9 of Appendix A-5.
(d) See Appendix A-5 for Enbridge’s 2009 actual/forecast and 2010 forecast of deliveries.
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IOL-Enbridge 158
Reference: Written evidence of Enbridge (Adobe Number A1R0V5), Appendix A- 7.1, page 11.
Preamble: The report states that “[i]n two NEB proceedings in 2007, 2008, and 2009, information became public that identified the Imperial Nanticoke refinery and the NOVA Chemicals Corunna Olefins facilities as the primary recipients of Line 9 shipments.”
Requests: (a) Please specifically indicate which NEB documents support this assertion, including line, paragraph, or page numbers.
Response: (a) During the RH-2-2007 proceeding, in response to Enbridge Information Request 11(2), Imperial stated: “There are four potential shippers on Line 9 – Imperial Oil, NOVA Chemicals, Suncor and Shell. Imperial Oil understands that Suncor and Shell ship insignificant amounts on Line 9.”
During the RH-3-2008 proceeding, in response to Enbridge Information Request 2 to NOVA Chemicals, NOVA provided Appendix B that detailed the Corunna facility’s monthly Line 9 receipts through September 2008. The average delivery rate to NOVA Chemicals through September was approximately 5,700 m3/d (36,000 b/d).
Tariff NEB No. 292, filed June 15, 2009, provides the 2008 actual throughput to Nanticoke and Sarnia (Appendix 1). Appendix 1 indicates that Nanticoke received 49% of total Line 9 deliveries in 2008, for an average delivery rate of 8,670 m3/d (54,500 b/d). Total Line 9 deliveries in 2008 were 17,580 m3/d (110,600 b/d). Thus, the 2008 delivery information indicates that the Nanticoke refinery and the Corunna facility were receiving approximately 80% of Line 9 deliveries.
Tariff NEB No. 289, filed April 20, 2009, provides the Q1 2009 actual throughput to Nanticoke and Sarnia (Appendix 1). This tariff indicates that Nanticoke received 63% of total Line 9 deliveries in Q1 2009.
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IOL-Enbridge 159
Reference: Written evidence of Enbridge (Adobe Number A1R0V5), Appendix A- 7.1, page 12.
Preamble: The report states that “up to a certain Line 9 toll, the transportation route from the U.S. Gulf Coast to Corunna is also more expensive.”
Requests: (a) Do the authors have data to support this assertion? If so, please provide.
(b) What are the costs of acquiring oil from the Gulf Coast for the NOVA facility? At what level of Line 9 toll do the costs become equivalent?
Responses: (a) Yes. See page 12, Figure 12 of Appendix A-7.1.
(b) See response to IOL-Enbridge 84.
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IOL-Enbridge 160
Reference: Written evidence of Enbridge (Adobe Number A1R0V5), Appendix A- 7.1, page 13.
Preamble: The report states that “...most of the Algerian receipts are believed to have been delivered to the NOVA Chemicals Corunna Olefins facility.”
Requests: (a) On what basis does the author make this statement? Are there supporting data? If so, please provide.
Response: (a) Low sulphur, paraffinic feedstocks are the most suitable heavy liquid feedstocks for olefins plants. Saharan Blend from Algeria is a low sulphur, paraffinic light crude. Moreover, NOVA Chemicals identified Saharan Blend as a feedstock in its Written Direct Evidence in the RH-2-2007 proceeding (Exh. C-8-4b).
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IOL-Enbridge 161
Reference: Written evidence of Enbridge (Adobe Number A1R0V5), Appendix A- 7.1, page 14.
Preamble: The report states that “[a]s light crude production grows in Western Canada, the pricing of light crude will move down relative to conventional light crudes elsewhere in the world.”
Requests: (a) Please explain the economics underlying this assertion.
(b) Please explain how changing volumes of production from a given source necessarily translate into changes in price. Do the authors disagree that arbitrage will eliminate any price advantages that a crude may temporarily enjoy relative to a fungible crude?
(c) Do the authors rely on historical data in making this claim? If so, please provide.
Responses: (a) As the supply of light crude, particularly light synthetic, increases, the Canadian crude producers will have to transport their production farther afield to find the last buyer. The shift in the price-parity point farther from Western Canada will act to lower the price at Edmonton, due to the combination of higher transportation costs from Edmonton and lower transportation costs for the competitive alternative.
(b) See response to IOL-Enbridge 161(a).
The price advantage of a specific crude to a specific refinery is mostly a function of the location of the crude production relative to the location of the refinery. Arbitrage clearly doesn’t eliminate crude pricing differences, as few crudes in the world have the same price to one another at their point of origin. Long-term crude pricing differentials between similar crude grades exist because of fundamental differences in the applicable supply-demand dynamics and transportation options available to each grade.
(c) There was no need to rely upon historical data, as the economic principles that the assertion is based upon are straightforward.
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IOL-Enbridge 162
Reference: Written evidence of Enbridge (Adobe Number A1R0V5), Appendix A- 7.1, pages 21 to 24.
Preamble: The report provides a comparative price analysis to assess the relative competitiveness of Line 9 crudes delivered to Imperial’s Nanticoke refinery. A comparison is made between North Sea Brent Blend and Western Canadian Mixed Sweet, and between Russian Urals and Western Canadian Light Sour Blend.
Requests: (a) Please provide the data underlying this analysis (including Figures 9 and 10). This should include figures for freight fees, tariffs, pump-over charges, crude prices, and any other data used in the calculations. If available, please also provide data for time periods beginning when Line 9 was reversed.
Response: (a) See Attachments 1 and 2 to IOL-Enbridge 84 and Attachment 1 to IOL-Enbridge 79.
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IOL-Enbridge 163
Reference: Written evidence of Enbridge (Adobe Number A1R0V5), Appendix A- 7.1.
Preamble: Through the report, the authors present several figures.
Requests: (a) Please provide underlying data, source documents, reports, and calculations for each of the figures. For Figures 2, 3, 9, 10 and 12, please provide data up to the most recent time period available.
(b) For Figure 3, what is the meaning of “Estimated” in the title? In other words, are the data not precise?
(c) For Figure 11, please include data illustrating the relationship between volumes shipped and transit time, and the relationship between volume shipped and tariff.
(d) For Figures 9, 10 and 12, please provide data for previous time periods beginning when Line 9 was reversed.
Responses: (a) See Attachments 2 through 4 to IOL-Enbridge 84 for Figures 9, 10, and 12. See Attachment 1 to IOL-Enbridge 163 for Figures 2 and 3 and for the supporting data.
(b) The data are obtained from Statistics Canada. Muse cannot comment upon the data precision. The estimate of Line 9 deliveries is developed entirely from public information. All crude sources shown in Figure 3 are assumed to have been transported on Line 9. The Line 9 delivery estimate is overstated to the extent that any crudes from these sources was delivered into Ontario via the U.S. Gulf Coast. Delivery volumes into Ontario via the U.S. Gulf Coast are not publicly available. Thus, the “estimated” in the figure title.
Nonetheless, the estimated Line 9 deliveries derived from public data can be compared to actual Line 9 throughput for the years 2003 to 2007. During the RH-3-2008 proceeding, Enbridge disclosed the actual Line 9 throughput in response to NOVA Chemicals 1.12(a). At least over this time period, the estimated and actual Line 9 throughput agreed closely.
(c) See response to IOL-Enbridge 59(b).
(d) See Attachments 2 through 4 to IOL-Enbridge 84. RH-1-2010 Responses of Enbridge to Imperial IRs Page 238 of 323
IOL-Enbridge 164
Reference: Written evidence of Enbridge (Adobe Number A1R0V5), Appendix A- 7.1, page 4.
Preamble: The report states that “Line 9 currently accommodates the shipment of four crude baskets: conventional light sweet; conventional light sour; condensate; and lube”.
Requests: (a) Enbridge indicates in the Line 9 Application, among other places, that Line 9 accommodates light and medium crudes. Does either condensate or lube fall into the “medium” category?
Response: (a) See Tariff NEB No. 297 (Statement E-8).
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IOL-Enbridge 165
Reference: Written evidence of Enbridge (Adobe Number A1R0V5), Appendix A- 7.1, page 11.
Preamble: The report states that “[o]f the total crude receipts [of Ontario refineries], 42,300 m3/d (266 kb/d), which is 72% of the total, was received from the west”.
Requests: (a) Please indicate the source of this information, and provide percentages for other regions that ship oil to Ontario.
(b) Of the receipts from the west, do the authors know what percentage comes from Western Canada (as opposed to the U.S.)?
Responses: (a) The first two sentences of page 8 of the Muse Report should read as follows: In 2008, Ontario refineries received 58,400 m3/d (367,000 b/d) of crude. Of the total crude receipts, 40,400 m3/d (254,000 b/d), which is 69 percent of the total, was received from the west.
The data source is Statistics Canada. In 2008, the percentages for other regions were 8% (Algeria), 1% (Norway), 2% (Russia), 9% (United Kingdom), 2% (Venezuela), and 5% (Eastern Canada).
(b) In 2008, 63% of the total Ontario crude receipts were from Western Canada.
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IOL-Enbridge 166
Reference: Written evidence of Enbridge (Adobe Number A1R0V5), Appendix A-7.1, page 14.
Preamble: The report indicates that “there are several export pipeline projects in various stages of commercial development that seek to connect Western Canada with markets in the U.S. Gulf Coast, the U.S. West Coast, and Northeast Asia.”
Requests: (a) Please provide specifics regarding the indicated pipeline projects in development.
(b) Please provide details regarding planned expansions of pipeline facilities from Western Canada to the U.S. Midwest and Ontario over the next ten years.
Responses: (a) See response to NEB 1.17. In addition to the projects discussed in that response, details regarding the Enbridge Northern Gateway Project can be found at: http://www.northerngateway.ca/. Details regarding a possible Kinder Morgan project to the West Coast can be found at: http://www.kne.com/business/canada/TMX_Documentation/TMX_FuturePl ans.cfm.
(b) Enbridge Pipelines has completed or is in the process of completing large expansions of its Mainline System together with the Southern Lights Pipeline. The expansions of the Mainline System will deliver Western Canadian crudes to the U.S. Midwest and, from there, those crudes could eventually flow to Ontario.
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IOL-Enbridge 167
Reference: Written evidence of Enbridge (Adobe Number A1R0V5), Appendix A- 7.1.
Preamble: The report discusses the increasing attractiveness of Western Canadian crude to Ontario refiners.
Requests: (a) Can the authors please comment on the Ontario refiners’ current bitumen processing capacity?
(b) Assuming completion of currently announced facility upgrades, can the authors comment on the Ontario refiners’ bitumen capacity in 5 years?
(c) Please answer questions (a) and (b) with respect to synthetic crudes.
Responses: (a) For 2009, Statistics Canada reported that Ontario refiners processed 4,846 m3/d (30,500 b/d) of bitumen blend.
(b) The Ontario refiners’ bitumen blend capacity in five years will be a function of changes in refinery operating procedures and facilities, and the amount of synthetic crude and conventional light, medium, and heavy crude processed.
(c) For 2009, Statistics Canada reported that Ontario refiners processed 12,879 m3/d (81,000 b/d) of synthetic crude. The Ontario refiners’ synthetic crude capacity in five years will be a function of changes in refinery operating procedures and facilities, and the amount of bitumen blend and conventional light, medium, and heavy crude processed.
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IOL-Enbridge 168
Reference: Written evidence of Enbridge (Adobe Number A1R0V5), Appendix A- 7.1, page 11.
Preamble: The report identifies “the Imperial Nanticoke refinery and the NOVA Chemicals Corunna Olefins facilities as the primary recipients of Line 9 shipments.”
Requests: (a) Are there other current recipients of Line 9 shipments?
(b) If so, please provide shipment volumes since 2008.
Responses: (a) Yes.
(b) The information requested is commercial information that Enbridge has consistently treated as confidential. Enbridge therefore objects to filing such information and declines to do so.
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IOL-Enbridge 169
Reference: Written evidence of Enbridge (Adobe Number A1R0V5), Appendix A- 7.1, page 18.
Preamble: The report discusses North Sea crude production and its attractiveness to Ontario refiners.
Requests: (a) The authors state that “the North Sea is the closest source of light sweet or light sour crude for an Ontario refiner.” Relative to what? Are they excluding Atlantic Canada production from this assertion? Are they just referring to imported oil?
(b) In reference to “[t]he market size of the North Sea crude production has contracted as production as dropped…”, how is the market size determined?
Responses: (a) The North Sea is the closest major supply source for Ontario refiners, relative to such sources as Africa, Russia, or Central Asia. Atlantic Canada crude production is modest relative to the North Sea. Moreover, Atlantic Canada’s current and forecast crude production is considerably less than existing refining capacity in Atlantic Canada.
(b) The market size is determined by the geographical extent of North Sea crude shipments.
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IOL-Enbridge 170
Reference: Written evidence of Enbridge (Adobe Number A1R0V5), Appendix A- 7.1.
Preamble: Throughout the report, the authors refer to the relative prices of oil from various regions, as well as price changes of various crudes.
Requests: (a) Please provide all oil pricing data that the authors have relied upon in making their assertions. Please include prices of all crude grades that are available to Ontario refiners from various regions, i.e. the North Sea, Algeria, Nigeria, Western Canada, Atlantic Canada, U.S. Gulf Coast, Williston Basin, etc.
(b) Please provide data specified in question (a) from 1997 to present, if available.
Responses: (a) See Attachment 1 to IOL-Enbridge 170 for the crude prices used by Muse for its analysis. Prices for other crude grades can be purchased from such sources as Platts and Argus.
(b) See response to IOL-Enbridge 170(a).
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IOL-Enbridge 171
Reference: Written evidence of Enbridge (Adobe Number A1R0V5), Appendix A- 7.1, page 25.
Preamble: The authors state that “[s]ince about 2006, crude supply from the west has been more attractive to the Ontario refineries, and this situation is not expected to change.”
Requests: (a) Please provide data and calculations underlying this assertion. In addition, please provide any underlying assumptions used in making this assessment.
(b) Please specify which crude supply sources are used in comparison to supply from the west.
(c) Please elaborate as to which supply sources are being referred to as “the west”.
Responses: (a) See the section titled “Comparative Crude Supply Economics to Nanticoke” (page 18 of Appendix A-7.1) for a detailed discussion of the analytical basis and conclusions that support the statement. See Attachments 2 through 4 to IOL-Enbridge 84 for supporting calculations.
(b) See response to IOL-Enbridge 171(a).
(c) The expression “west” as it appears in the excerpt from the Muse Report cited in the Preamble was intended to mean Western Canadian and Williston Basin crudes.
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IOL-Enbridge 172
Reference: Written evidence of Enbridge (Adobe Number A1R0V1), Appendix A-3, page 3, paragraph 6.
Preamble: Paragraph 6 indicates that “[t]his written evidence provides Enbridge’s own assessment of its business risk and, based on its assessment, its conclusion that the proposed deemed common equity ratio effective January 1, 2008 and the proposed ROE for each test year are required in order to appropriately reflect its business risk. Both are required, as well as the proposed cost of debt, for the Board to comply with the fair return standard.”
Requests: (a) Please indicate what is meant by “own assessment”.
(b) Does Enbridge have a different assessment of business risk than that being provided by Ms. McShane in her testimony? If so, please list the differences between the assessment of business risk as provided by Ms. McShane and Enbridge. For this purpose, please address each of the categories of business risk that Enbridge indicates at Paragraph 13 should considered by the NEB including supply risk, market risk, regulatory risk, competitive risk, and operating risk.
(c) Please indicate whether Enbridge is requesting the specific change in equity portion and proposed ROE based on the testimony of Ms. McShane or its own policy assessment.
(d) Has Enbridge undertaken a separate assessment of business risk as it relates to the requested change in equity portion and/or ROE than that prepared by Ms McShane? If so, please provide all work papers and underlying reference documents which support this separate assessment.
(e) Is it Enbridge’s opinion that an increase in deemed common equity ratio and/or ROE is the only manner in which to reflect an increase in business risk? If not, why in Enbridge’s own assessment, is such an increase “required”?
Responses: (a) Enbridge independently assessed the risks relative to Line 9 as well as relying on the analysis performed by Muse.
(b) No.
(c) Enbridge made its own assessment of business risk. Enbridge RH-1-2010 Responses of Enbridge to Imperial IRs Page 247 of 323
concluded that there have been significant changes in its business risk. Enbridge then determined an appropriate capital structure.
Ms. McShane was retained to assess the reasonableness of Enbridge’s capital structure and to recommend a rate of return on equity for Enbridge. Ms. McShane then conducted her own assessment of business risk, in order to assess the reasonableness of Enbridge’s capital structure.
Ms. McShane recommended rates of return on equity of 12.00%, 12.60%, and 12.18% for the 2008, 2009, and 2010 Test Years respectively. Enbridge accepted her recommendation and framed the Application accordingly.
(d) See Appendix A-3 and the response to IOL-Enbridge 172(a). There are no work papers; Enbridge’s assessment of business risk was qualitative rather than quantitative.
(e) Enbridge’s opinion (within a cost of service regime) is set out in paragraph 8 of Appendix A-3. An alternative approach to addressing an increase in business risk is a long-term agreement which ensures Enbridge will earn a return of and on the capital invested in Line 9.
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IOL-Enbridge 173
Reference: Written evidence of Enbridge (Adobe Number A1R0V1), Appendix A-3, page 4, paragraph 10.
Preamble: Paragraph 10 indicates that “[t]here have been significant changes in Enbridge’s business risk, for the reasons described below, and Enbridge’s proposed common equity ratio and its proposed ROEs are together an appropriate measure of a fair return in light of its business risk.”
Requests: (a) In this paragraph, is Enbridge referring to the common equity ratio and ROEs to Enbridge’s regulated oil pipeline enterprise? Is Enbridge aware of any other manner in which to account for business risk?
Response: (a) Enbridge is referring to its own common equity ratio and ROEs (i.e., Line 9 operating as a stand-alone pipeline). The dollar amount is a function of the common equity ratio in Enbridge's capital structure as well as its ROE.
Enbridge is seeking an increase in the common equity ratio and ROEs in order to reflect the increase in its business risk. See response to IOL-Enbridge 172(e).
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IOL-Enbridge 174
Reference: Written evidence of Enbridge (Adobe Number A1R0V1), Appendix A-3, pages 7 to 8, paragraphs 20 to 21.
Preamble: Paragraph 20 indicates that “Enbridge is now at risk for variances between its forecast and revenue requirement...” Paragraph 21 indicates that “Enbridge is proposing a throughput deferral account and a toll adjustment mechanism to mitigate short-term variations in throughput…”
Requests: (a) To what extent will the adoption of such accounting treatment mitigate the short-term business risk of variances between forecast and revenue requirements on Line 9?
(b) What short-term risk factors that might cause variances between forecast and revenue requirements wouldn’t be mitigated by the existence of these accounting treatments?
Responses: (a) The adoption of the deferral accounts mitigates the risk of variances between forecast and actual revenue requirements for Line 9 only to the extent oil losses, throughput and costs for regulatory proceedings contribute to such variances.
(b) Not all variances between forecast and actual costs would be captured in the proposed deferral accounts. Moreover, a deferral account does not guarantee recovery of the deferred amounts.
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IOL-Enbridge 175
Reference: Written evidence of Enbridge (Adobe Number A1R0V1), Appendix A-3, page 7, paragraph 19.
Preamble: Paragraph 19 indicates that the FSA provided a true-up mechanism that kept Enbridge whole with regard to its annual revenue requirement, and that “[l]etter agreements with the Line 9 shippers did likewise thereafter until December 31, 2007.”
Requests: (a) Please indicate whether the Letter Agreements with Line 9 Shippers were an explicit factor in Board approval of final tolls during the period from October 1, 2004 through March 31, 2006. If so, please provide a copy of the Board approval in this regard.
Response: (a) They were not an explicit factor. However, Line 9 shippers had agreed to the letter agreements and the relevant applications were unopposed.
The letter agreement for the interim period from April 1, 2006 through December 31, 2007 was filed with Enbridge’s application for final tolls, which is available at the following link:
https://www.neb-one.gc.ca/ll- eng/livelink.exe?func=ll&objId=504845&objAction=browse&sort=- name
RH-1-2010 Responses of Enbridge to Imperial IRs Page 251 of 323
IOL-Enbridge 176
Reference: Written evidence of Enbridge (Adobe Number A1R0V1), Appendix A-3, pages 6 to 7, paragraph 17.
Preamble: Paragraph 17 discusses “the mutual dependence of the two Line 9 shippers; that is, that likelihood that there are either at least two shippers or no shippers at all in westbound service.”
Requests: (a) Please confirm that the assumption underlying this statement is that if one shipper stops nominating volumes, the remaining shipper will be responsible for the entire revenue requirement, thus costs will be allocated over a smaller throughput, causing tolls to rise.
(b) Can Enbridge supply an example of when this has occurred in the past?
Responses: (a) Confirmed.
(b) The last paragraph of page 3 of the document entitled “The Sarnia- Montreal Pipeline, A Review & Report” (National Energy Board, April 1991 – cited in reference (ii) to NOVA Chemicals 1.1) includes the following discussion (in relation to an analogous circumstance in 1990):
Beginning in September 1990, three shippers – Esso Petroleum Canada (“Esso”), Petro-Canada and the Alberta Petroleum Marketing Commission – ceased nominating for delivery on the Montreal extension. Shell, the only remaining shipper, was left to carry the cost of the 368 000 cubic metres (2.3 million barrels) of linefill. Shell, in March 1991, requested of IPL that this volume be delivered to it; in late April 1991, IPL began displacing the linefill with nitrogen.
RH-1-2010 Responses of Enbridge to Imperial IRs Page 252 of 323
IOL-Enbridge 177
Reference: Written evidence of Enbridge (Adobe Number A1R0V1), Appendix A-3, pages 8 to 9, paragraph 25.
Preamble: Paragraph 25 links business risk to depreciation and indicates that depreciation rates reflect a “best estimate” of remaining economic life.
Requests: (a) Has Enbridge changed the manner in which it determines its “best estimate” of remaining life since the Board last approved its tolls? If so, please describe specifically these changes in calculation methodology. (b) If the “best estimate” of remaining economic life of Line 9 in westbound service is overly conservative, will the equity portion or ROE being requested by Enbridge be unfairly high? Responses: (a) No. Enbridge has not changed the manner in which it estimated the remaining depreciable life of the relevant costs. (b) No. If the depreciation rates had been designed to allow the recovery of capital over a shorter period than the remaining depreciable life of Line 9, then the business risk associated with estimating the depreciable life would be lower and thus Enbridge’s requested cost of capital would be too high. This is not the case for Enbridge. The proposed depreciation rates represent Enbridge’s best estimate of the remaining depreciable life of Line 9. The remaining life can be re-estimated if circumstances change and depreciation charges changed accordingly. As the Board recognized in the RH-2-2004 Phase II Reasons for Decision (page 46): . . . the depreciation rates in use may not actually reflect the estimates of economic life that would be selected if assessed at that point in time. A company can mitigate the risk that the estimates in use are not current by bringing forward an application to reconsider its depreciation rates. The part of this risk that is mitigable should not be compensated through the cost of capital. Should it become apparent that depreciation rates do not adequately reflect current estimates of economic life, it is incumbent on the management of the company to seek to change depreciation rates, not to expect incremental compensation through the cost of capital.
This is what Enbridge has done.
RH-1-2010 Responses of Enbridge to Imperial IRs Page 253 of 323
IOL-Enbridge 178
Reference: Written evidence of Enbridge (Adobe Number A1R0V1), Appendix A-3, page 8, paragraph 22.
Preamble: Paragraph 22 discusses integrity and maintenance cost increases that have resulted from decreased throughput and increased volatility.
Requests: (a) Please provide said cost figures from time of reversal to present.
(b) Please explain how decreased throughput and increased volatility result in higher maintenance costs.
Responses: (a) See Attachment 1 to IOL-Enbridge 178(a).
(b) See responses to IOL-Enbridge 3(a) and (b).
RH-1-2010 Responses of Enbridge to Imperial IRs Page 254 of 323
IOL-Enbridge 179
Reference: Written evidence of Enbridge (Adobe Number A1R0V1), Appendix A-3, page 7, paragraph 19.
Preamble: Enbridge states that it’s “regulatory risk also increased significantly at the start of 2008. Enbridge was then no longer kept whole in respect of its actual revenue requirement.”
Requests: (a) Does Enbridge consider the FSA and subsequent letter agreements with Line 9 shippers to be part of its regulatory framework (when they were in effect)? If so, why? Did regulators (the NEB) have input as to the terms and conditions of the agreements? Please explain the statement that regulatory risk increased subsequent to the expiration of these agreements.
Response: (a) The FSA and the letter agreements formed part of the regulatory framework under which Enbridge operated during the relevant periods.
The FSA and the letter agreements were negotiated among the parties and, in that sense, the Board had no advance input as to their terms. The Board did, however, disallow the unapportioned access provisions of the original FSA which was subsequently amended by the parties. The toll-making provisions of the FSA were unaffected.
The regulatory risk increased at the start of 2008 due to the absence of any agreement with shippers under which Enbridge was kept whole in respect of its actual revenue requirement.
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IOL-Enbridge 180
Reference: Written evidence of Enbridge (Adobe Number A1R0V3), Appendix A-5, page 4, paragraph 13.
Preamble: Enbridge asserts that “[a]ccording to information from Statistics Canada, Ontario sourced approximately 75% to 80% of its imports from the North Sea prior to 2005. Over the last five years, however, these imports declined and have averaged around 35%.”
Requests: (a) Please indicate how many years prior to 2005 the calculation of “75% to 80%” was based on.
(b) Please provide information from Statistics Canada that Enbridge used for this calculation.
Responses: (a) The calculation was based on 2003 and 2004.
(b) See Attachment 1 to IOL-Enbridge 180(b).
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IOL- Enbridge 181
Reference: Written evidence of Enbridge (Adobe Number A1R0V4), Appendix A-6, page 2, paragraph 1.
Preamble: Enbridge seeks to establish deferral accounts to record the variances in the costs/revenues attributable to oil losses/(gains), throughput, and regulatory proceedings in the 2009 and 2010 Test Years.
Requests: (a) Please explain why Enbridge is not seeking a deferral account for the 2008 Test Year as well.
Response: (a) Enbridge is not seeking deferral accounts for costs/revenues attributable to oil losses/(gains), throughput, and regulatory proceedings for the 2008 Test Year since all relevant amounts are now known.
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IOL-Enbridge 182
Reference: Written evidence of Enbridge (Adobe Number A1R0V6), Appendix A- 7.2, page 31, lines 788 to 791.
Preamble: Ms. McShane states that “[t]he NEB’s formula operated for 15 years. In the intervening period, with the benefit of hindsight, it became increasingly clear that the required ROE did not track long-term Government of Canada bond yields in the manner indicated by the automatic adjustment mechanism.”
Requests: (a) Could Ms. McShane please elaborate on what she meant when she indicated that “the required ROE did not track long-term Government of Canada bond yields in the manner indicated by the automatic adjustment mechanism.”
(b) Please explain how the required ROE was supposed to track long- term Government of Canada bond yields. In what manner did it not track long-term Government of Canada bond yields?
(c) In what manner was the automatic adjustment mechanism supposed to provide for the ROE to track long-term Government of Canada bond yields?
(d) Please provide any references or authorities that support your answers to the above.
Responses: (a) The automatic adjustment formula is based on the proposition that the cost of equity changes by 75% of the change in long-term Canada bond yields. The empirical evidence that has been presented in Appendix A-7.2 indicates that the sensitivity of the cost of equity to long-term government bond yields is closer to 0.50 than to 0.75, and that the cost of equity is also positively related to the movements in utility bond spreads.
(b) See response to IOL-Enbridge 182(a). The evidence indicates that the required ROE changed by approximately 50% of the change in long-term government bond yields as discussed in lines 911 through 999 of Appendix A-7.2, and also increased or decreased with increases and decreases in utility bond spreads.
(c) See response to IOL-Enbridge 182(a). The automatic adjustment mechanism was supposed to provide for the allowed ROE to track long-term government bond yields in a manner that measures the RH-1-2010 Responses of Enbridge to Imperial IRs Page 258 of 323
change in the cost of equity as it occurs in the capital markets.
(d) The Ontario Energy Board, in its December 2009 Report of the Board on the Cost of Capital for Ontario’s Regulated Utilities, after hearing submissions by multiple experts, concluded as follows:
The formula also needs to be refined to reduce its sensitivity to changes in government bond yields due to monetary and fiscal conditions that do not reflect changes in the utility cost of equity. First, the Board views the determination of the LCBF [Long Canada bond forecast] adjustment factor to be an empirical exercise, and as such, based on the empirical analysis provided by participants in conjunction with the consultation, the Board is of the view that the LCBF adjustment factor should be set at 0.5. Second, based on the analysis provided by participants to the consultation, the Board concludes that there is a statistically significant relationship between corporate bond yields and the cost of equity, and that a corporate bond yield variable should be incorporated in the return on equity formula.
The Board has determined that it will use a utility bond spread based on the difference between the Bloomberg Fair Value Canada 30-Year A-rated Utility Bond index yield and the long Canada bond yield and that the utility bond spread reflected will be subject to a 0.50 adjustment factor, consistent with the empirical analyses provided by participants to the consultation.
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IOL-Enbridge 183
Reference: Written evidence of Enbridge (Adobe Number A1R0V6), Appendix A- 7.2, page 27, lines 666 to 667 and 678 to 679.
Preamble: Ms. McShane opines that “[w]ith respect to Plateau Pipe Line Ltd. (“Plateau”), whose Western System accesses British Columbia crude, its circumstances are not dissimilar to those of Enbridge.” She further states that “[o]n balance, I would judge Plateau to face somewhat higher business risks than Enbridge.”
Requests: (a) As Ms. McShane has concluded that they are not dissimilar, would she also conclude that circumstances are similar? If no, why not?
(b) What does Ms. McShane mean by “somewhat higher”? How much of a change in the: (1) equity ratio; and (2) ROE, would make the business risks of Plateau and Enbridge the same?
Responses: (a) The circumstances would be similar in terms of level of fundamental business risks faced, with Enbridge facing lower short-term risk due to risk mitigation which will be provided for Enbridge by its proposed toll adjustment mechanism and deferral accounts.
(b) Ms. McShane means that the difference is significant enough (i.e., non-trivial) to warrant the difference in equity risk premium that was inherent in the equity risk premium adopted for Plateau compared to the risk premium that Ms. McShane has recommended for Enbridge. The premise of the question (i.e., what changes in the ROE and capital structure would make the business risks the same) is flawed. The business risks are not changed by a change in the ROE and capital structure. The ROE and capital structure should be commensurate with the business risks - hence different capital structures and ROEs are warranted for different levels of business risk. At lines 681-683 of Appendix A-7.2, Ms. McShane noted that Plateau’s common equity ratio and equity risk premium were 50% and 300 basis points above the benchmark utility ROE. Given the higher business risk of Plateau relative to Enbridge, Ms. McShane judged her recommended capital structure and risk premium for Enbridge to be reasonable relative to the parameters adopted for Plateau.
RH-1-2010 Responses of Enbridge to Imperial IRs Page 260 of 323
IOL-Enbridge 184
Reference: Written evidence of Enbridge (Adobe Number A1R0V6), Appendix A- 7.2, page 35, lines 879 to 887.
Preamble: Ms. McShane asserts that “[t]he extent to which the multi-pipeline formula ROEs diverged off course due to their dependence on the level of forecast long-term Canada bond yields can be assessed by a comparison of allowed returns for NEB-regulated pipelines to the returns adopted for U.S. gas and electric utilities during the corresponding year.”
She further states: “[t]his comparison is germane given (1) the significant integration of the Canadian and U.S. capital markets, (2) the similarity in the business (or operating environments) for regulated companies in Canada and the U.S., and (3) the similarity in the regulatory models in the two countries.”
Requests: (a) Please explain why meaningfulness of the divergence between allowed ROEs for U.S. gas and electric utilities diverged and allowed NEB returns is dependent on a significant integration of Canadian and U.S. capital markets.
(b) Does Ms. McShane believe that there are any differences in the regulatory models between the U.S. and Canada that would explain any divergence between U.S. and Canadian allowed returns?
(c) Despite Ms. McShane’s assertion that capital markets of the two countries are significantly integrated, does she necessarily believe that there are no differences between the economies of the two countries that might be reflected in a difference between the allowed ROE’s for utilities in the two countries? Please explain.
Responses: (a) More precisely, the comparison is germane given the similar costs of capital in the two countries since long-term government bond yields converged in approximately 1997. From 1998 to 2009, the difference between 10-year government bond yields in the two countries averaged eight basis points; the difference between 30- year government bond yields in the two countries averaged nine basis points. Inflation as measured by the GDP deflator was virtually identical. A 2007 study by the Bank of Canada found that since government bond yields have converged in the two countries, the difference in the cost of equity financing between the two countries is statistically insignificant (Lorie Zorn, Estimating the Cost of Equity for Canadian and U.S. Firms, Bank RH-1-2010 Responses of Enbridge to Imperial IRs Page 261 of 323
of Canada, Autumn 2007).
(b) Yes, there are some differences in the application of the regulatory model, as discussed in response to NEB 1.10. However, the differences in the regulatory model do not explain the differences in the allowed ROEs. It is clear from Figure 2 that the divergence relates to the closer tracking of government bond yields by Canadian allowed returns, which is a function of the construct of the discontinued RH-2-94 formula. A comparison of the allowed returns for U.S. gas distribution utilities to those of Canadian utilities, as both generally have debt ratings in the A category, suggest that the observed 140 basis point differential in allowed ROEs is not explained by risk differences. To the extent that U.S. gas utilities have higher business risk than Canadian utilities, the higher business risk is offset by more conservative capital structures. The allowed common equity ratios of the gas utilities in the U.S. have been close to 50% since 1998, compared to a range of 35%-40% in Canada.
(c) Ms. McShane is not aware of any differences between the two economies that would explain the degree of divergence between the allowed returns of the utilities.
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IOL-Enbridge 185
Reference: Written evidence of Enbridge (Adobe Number A1R0V6), Appendix A- 7.2, pages 38 to 39.
Preamble: Ms. McShane reports the results of two different regression analyses that attempt to test the relationship “between the equity risk premium, long- term government bond yields and corporate bond yield spreads for regulated companies.”
Requests: (a) Please provide the complete data set used to establish the estimated regression equations.
(b) What program did Ms. McShane use in estimating her regressions?
(c) Did Ms. McShane conduct any additional statistical tests to determine the reliability of her regression results? If so, please provide an explanation of the tests conducted and their results.
Responses: (a) See Attachments to IOL-Enbridge 92.
(b) Ms. McShane used Microsoft Excel’s regression function in estimating her regressions.
(c) See response to NEB 1.28(b).
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IOL-Enbridge 186
Reference: Written evidence of Enbridge (Adobe Number A1R0V6), Appendix A- 7.2, page 44, Table 5.
Preamble: Ms. McShane reports investment risk betas, in both a “raw” and “adjusted” form. Further, she cites Value Line, Bloomberg, and Merrill Lynch as seemingly authorities for the use of adjusted betas.
Requests: (a) Is indeed Ms. McShane relying on the fact that Value Line, Bloomberg, and Merril Lynch all publish adjusted betas as the rationale for its use in her analysis?
(b) If no, can Ms. McShane cite any academic sources for the use of adjusted betas? If so, please provide.
Responses: (a) No.
(b) As stated in the response to IOL-Enbridge 95(f), the use of adjusted betas recognizes that the raw beta for utilities does not accurately reflect the empirical risk/return relationship. The objective in the application of the CAPM is to arrive at a cost of equity that represents the return investors do require, not the return investors should require as predicted by the CAPM under its restrictive assumptions. Studies on CAPM which have shown that the return requirement is higher (lower) for a low (high) beta stock than the CAPM would predict are set out below:
Fisher Black, Michael C. Jensen, and Myron S. Scholes, "The Capital Asset Pricing Model: Some Empirical Tests," Studies in the Theory of Capital Markets, edited by Michael Jensen. (New York: Praeger, 1972), pp. 79-121.
Marshall E. Blume and Irwin Friend, "A New Look at the Capital Asset Pricing Model," Journal of Finance, Vol. XXVIII (March 1973), pp. 19-33.
Eugene F. Fama, and James D. MacBeth, "Risk, Return and Equilibrium: Empirical Tests." Unpublished Working Paper No. 7237, University of Chicago, Graduate School of Business, August 1972.
Nancy Jacob, "The Measurement of Systematic Risk for Securities and Portfolios: Some Empirical Results," Journal of Financial and Quantitative Analysis, Vol. VI RH-1-2010 Responses of Enbridge to Imperial IRs Page 264 of 323
(March 1971), pp. 815-834.
The experience of Canadian utilities is illustrative; the “raw” equity betas of the S&P/TSX utility index explain a relatively small percentage of the actual achieved market returns over time. A regression of the monthly returns on the TSX Utilities Index against the returns on the TSX Composite, for example, over the period 1970-2009 shows the following:
Monthly TSX = 0.0055 + 0.49 { Monthly TSE } Utilities Index Composite Return Return t-statistic = 14.6 R2 = 31%
The relationship quantified in the above equation suggests a long- term beta of approximately 0.50. However, the R2, which measures how much of the variability in utility stock prices is explained by volatility in the equity market as a whole, is only 31%. That means 69% of the monthly volatility in share prices remains unexplained. To provide some perspective, the average actual annual return for the TSX utility index from 1970-2009 was 12.25%. Of this average annual return, almost seven percentage points was not explained by price movements in the equity market. The use of betas that are adjusted toward the equity market beta of 1.0, rather than the calculated “raw” betas, takes account of the observed tendency of low beta stocks such as utilities to achieve higher returns than predicted by the simple CAPM.
RH-1-2010 Responses of Enbridge to Imperial IRs Page 265 of 323
IOL-Enbridge 187
Reference: Written evidence of Enbridge (Adobe Number A1R0V6), Appendix A- 7.2, page 4, lines 18 to 21.
Preamble: Ms. McShane indicates that she was asked by Enbridge Pipelines Inc. to assess the reasonableness of its proposed capital structure and recommend a fair ROE for its Line 9 operations.
Requests: (a) Please provide copies of all presentations to security analysts, credit agencies and regulators since 2007, where the business risk of Line 9 and other pipeline assets of Enbridge have been discussed in any significant detail.
(b) Please provide copies of any prospectus filings by which Enbridge Pipelines Inc. or Enbridge Pipelines has raised capital since 2007.
(c) Please indicate all evidence Ms. McShane has filed on behalf of Enbridge affiliated companies since 1995. For each provide her recommended common equity ratio and ROE along with her associated forecast long Canada bond yield at the time of the recommendation.
(d) Please confirm that in preparing her written evidence in this proceeding, Ms. McShane did not recommend a capital structure to Enbridge, but was simply asked to confirm the reasonableness of Enbridge’s request.
(e) Further to request (d), what would Ms. McShane regard as a range of reasonableness for Enbridge’s capital structure? That is, if Enbridge had asked Ms. McShane to comment on a requested common equity ratio of 30%, 35%, 40%, 45%, 50%, 55% and 60%, which would she have regarded as unreasonable?
(f) Please confirm that Ms. McShane was asked to recommend a fair ROE rather than confirm Enbridge’s requested ROE.
(g) Further to request (f), did Ms. McShane communicate her recommended ROE to Enbridge prior to finalizing her report and was the recommendation changed at any time prior to submitting her final report? If yes, please indicate how the recommended ROE changed.
Responses: (a) Enbridge does not make presentations to security analysts and credit agencies regarding the business risks of Line 9. The only RH-1-2010 Responses of Enbridge to Imperial IRs Page 266 of 323
such “presentations” made to regulators – the Board – since 2007 are those in this Application; namely, Appendix A-3 and, on its behalf, Appendix A-7.2.
Enbridge’s assets (i.e., Line 9) comprise a very small portion of the assets of Enbridge Pipelines. It is highly unlikely, therefore, that any such presentation made by Enbridge Pipelines would have discussed the business risk of Line 9 “in any significant detail”. This is particularly so in light of Enbridge Pipelines’ major projects since 2007.
(b) Enbridge has never issued a prospectus to raise capital for Line 9. A copy of each prospectus issued by Enbridge Inc. and Enbridge Pipelines Inc. to raise capital since 2007 is available at www.sedar.com.
(c) See Attachment 1 to IOL-Enbridge 187(c).
(d) Confirmed.
(e) Ms. McShane would, for Enbridge on a stand-alone basis, view a range of 45% to 60% as reasonable.
(f) Confirmed.
(g) Yes, Ms. McShane communicated her recommended ROEs to Enbridge prior to finalizing her report. Ms. McShane had discussions with Enbridge about approaches that could be taken to estimate the fair return for Enbridge but, once she communicated her recommended ROEs to Enbridge, the only change was to update the 2010 recommended ROE for more recent Consensus Forecasts and corporate bond spreads.
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IOL-Enbridge 188
Reference: Written evidence of Enbridge (Adobe Number A1R0V6), Appendix A- 7.2, page 4.
Preamble: Ms. McShane discusses the Enbridge System.
Requests: (a) Please provide the earned ROE for Line 9 and the other two segments of the Enbridge System (the older system and Line 8) for each year since 2000. (b) Please provide the common equity ratio for the older system and Line 8 since 2000. (c) Please provide the net rate base for all three parts of the Enbridge System since 2000. (d) Please describe in detail the reason for any significant differences in the annual earned ROE (+/-2%) across the three segments of the Enbridge System.
Responses: (a) See Attachment 1 to IOL-Enbridge 195(d) for the information requested related to Line 9. See Attachment 1 to IOL-Enbridge 188 for the information requested related to Line 8. Enbridge objects to filing the requested information in respect of the Older System and declines to do so. The Older System revenue requirement was subject to the 2000 ITS from 2000 to 2004 and the 2005 ITS from 2005 to 2009. It is also subject to the 2010 ITS for 2010. The annual revenue requirement for toll- making purposes is not necessarily the sum of the cost of service plus the return on rate base. The filing and reporting requirements under the ITSs, moreover, do not include the requested information. (b) See response to IOL-Enbridge 188(a). (c) See response to IOL-Enbridge 188(a). (d) Line 9 is not comparable to either of Line 8 or the Older System; for example, both are subject to an ITS or the equivalent for toll- making purposes.4 The differences in their individual annual earned ROE, whether significant or otherwise, are accordingly not relevant to the Board’s determination of Enbridge’s allowable ROE for 2008, 2009, and 2010. Enbridge therefore declines to
4 “Older System” in this context means Lines 1, 2, 3, 4, and 65 (in western Canada) and Lines 5, 6B, 7, 10, and 11 (in Ontario). RH-1-2010 Responses of Enbridge to Imperial IRs Page 268 of 323 provide the requested description.
RH-1-2010 Responses of Enbridge to Imperial IRs Page 269 of 323
IOL-Enbridge 189
Reference: Written evidence of Enbridge (Adobe Number A1R0V6), Appendix A- 7.2, page 6.
Preamble: Ms. McShane discusses Line 9’s original 40% common equity ratio.
Requests: (a) Can Ms. McShane outline her involvement in the 1994 multi- pipeline hearing before the NEB?
(b) As a result of the 1994 multi-pipeline hearing would Ms. McShane agree that the “standard” common equity ratio for an oil pipeline was 45%, whereas it was 30% for a gas pipeline?
(c) Can Ms. McShane elaborate on all the risk differences that existed in 1994 to justify a difference of 15% in the common equity ratios between oil and gas pipelines and for each indicate whether such risk differences still exist?
(d) When the Line 9 common equity ratio was set at 40% increasing by 1.25% a year to reach 45%, can Ms. McShane elaborate on all the risk differences between Line 9 and a standard oil pipeline that justified the lower common equity ratio than that awarded in the RH-2-94 multi-pipeline proceeding?
(e) Can Ms. McShane discuss whether in her judgment it is common for an oil pipeline to have a tariff where shippers agree to “full recovery of all deviations between forecast and actual costs” as happened for Line 9 from 2004-2006?
Responses: (a) Ms. McShane, along with Dr. Stephen Sherwin, were sponsored by Alberta Natural Gas, Foothills Pipe Lines, TransCanada PipeLines, and Westcoast Energy. Her primary responsibility was the development of the cost of equity estimates for a benchmark pipeline. Dr. Sherwin had responsibility for assessments of relative business risk.
(b) Ms. McShane accepts that the Board adopted a 45% common equity ratio for the only oil pipeline that was governed by the RH- 2-94 formula, Trans Mountain, and that, in the tolls proceeding for IPL immediately preceding the RH-2-94 proceeding (RH-2-91), the Board adopted a 45% equity ratio. In the RH-2-94 proceeding, the Board adopted 30% equity ratios for each of the gas pipelines except Westcoast, for which it adopted a common equity ratio of RH-1-2010 Responses of Enbridge to Imperial IRs Page 270 of 323
35%.
(c) The risks that justified the difference in the equity ratios in RH-2- 94 from the Board’s perspective were summarized in its Reasons for Decision as follows:
Gas Pipelines
(i) With respect to operating risks, the Board concluded that the operation of a single high pressure line and the presence of sour gas gathering pipelines and processing plants as important risk factors.
(ii) With respect to market risks, the extent to which a pipeline’s markets are diversified, the quality and competitiveness of those markets, and the average length of shippers’ contracts were judged to be the most significant factors in the Board’s evaluation of market risks.
(iii) The Board had regard to the political risk associated with export markets.
(iv) The method of regulation and adequacy of supply had, at that time, only a marginal impact on the overall risk of pipelines.
Oil Pipelines
(i) The quality and the competitiveness of the markets served by a pipeline are the two most significant factors.
(ii) With respect to supply risks, the Board concluded that the resource base, in terms of both the remaining established reserves as well as discovered and undiscovered resources, is sufficiently large and diversified to support the existing pipelines beyond their current truncation dates under most circumstances. The Board anticipated that a future decline in conventional oil supply from the WCSB will tend to be offset by an increased supply of unconventional oil.
While each of the major NEB-regulated pipelines is unique, on an industry-wide basis, the difference in the risks of the oil and gas pipelines exiting the Western Canadian Sedimentary Basin (WCSB) may be somewhat smaller than at the time of the RH-2- 94 proceeding. TransCanada PipeLines, for example, faces higher pipe-on-pipe competition and higher supply risk than at the time of the RH-2-94 proceeding, as was recognized by the Board in both RH-1-2010 Responses of Enbridge to Imperial IRs Page 271 of 323
the RH-4-2001 and RH-2-2004 Phase II proceedings.
As regards oil pipelines, with the development of the oil sands, the supply risks arising from the physical supply of oil from Western Canada are lower since the RH-2-94 proceeding. However, the long-term outlook for the development of the oil sands is dependent on the interplay among a number of factors, including world oil prices and the impact of climate change policies on the costs of both producers and refiners. Further, the competitive risks faced by the individual oil pipelines for delivery of the available supply have increased with the development of the Keystone Project.
(d) No. Ms. McShane cannot elaborate on all the risk differences between Line 9 and a “standard” oil pipeline that justified the lower common equity ratio than the 45% awarded Trans Mountain in the RH-2-94 proceeding and IPL in the RH-2-91 proceeding. Clause 9.3(b) of the FSA prescribed a yearly increase in the common equity ratio from 40% in the first year to 45% in the fifth (and last) year of the Primary Term. The FSA was the result of negotiations between Enbridge, on the one hand, and the initial four Line 9 shippers on the other. Clause 9.3(b) is but one provision in a complex agreement. Thus it is not possible to know what the trade-offs might have been. However, the OH-2-97 decision makes clear that IPL required an FSA to proceed with the reversal of the Montreal Extension, because it was not willing to accept the level of commodity risk to which Line 9 would be exposed. The cost of capital expert for IPL in the OH-2-97 proceeding, Dr. Evans, testified that the existence of the FSA was the factor that allowed the equity ratio of Enbridge to be set at the levels that were agreed to in the FSA and that, without the FSA, the appropriate equity ratio would have been higher than the 45% that had been adopted for the Older System in the RH-2-91 proceeding and for Trans Mountain in the RH-2-94 proceeding.
(e) Ms. McShane is aware of several full cost of service oil pipelines, that are covered by long-term agreements with shippers, including Enbridge (NW), the Syncrude Pipeline (formerly the Alberta Oil Sands Pipeline), Corridor Pipeline, and the Horizon Pipeline.
RH-1-2010 Responses of Enbridge to Imperial IRs Page 272 of 323
IOL-Enbridge 190
Reference: Written evidence of Enbridge (Adobe Number A1R0V6), Appendix A- 7.2, pages 8 to 9.
Preamble: Ms. McShane discusses the fair return standard.
Requests: (a) Please indicate why Ms. McShane thinks the NEB decision supports the three “requirements” as being separate and distinct, rather than simply three aspects of the same requirement?
(b) Please confirm that the phrase “cost of capital” as referred to on page 5 normally means a “market based cost” also commonly known as the investor’s required rate of return as adjusted for issue costs etc. If not, why not?
Responses: (a) At page 7, footnote 14, in its RH-1-2008 Reasons for Decision the Board stated: In previous decisions the Board used the word “standard” for each of the elements of the Fair Return Standard. The Board has changed the description to “requirement” to clarify that there are three requirements which should be met under the Fair Return Standard. In this decision, the Board separately assessed whether the return allowed would meet the comparable investment, the capital attraction, and the financial integrity requirements (as the Board renamed them).
(b) The term “cost of capital” is normally used to mean a market- based cost. The cost of capital is an opportunity cost; that is, the return foregone by investors by not investing in an alternative investment. In other words, in order to commit funds to an enterprise, investors require a return on those funds equal to what they could earn in an alternative investment of comparable risk; that is, the investors’ required return.
RH-1-2010 Responses of Enbridge to Imperial IRs Page 273 of 323
IOL-Enbridge 191
Reference: Written evidence of Enbridge (Adobe Number A1R0V6), Appendix A- 7.2, pages 12 to 13, lines 267 to 275.
Preamble: Ms. McShane discusses the stand alone principle.
Requests: (a) On page 1 Ms. McShane notes that the Enbridge System is comprised of three parts one of which is Line 9, whereas on page 9 she states the stand alone principle means that financial parameters should be determined as if it were Enbridge’s only business. Please reconcile these two statements.
(b) Would Ms. McShane agree that many regulated businesses could sub divide their operations into smaller stand alone businesses so the idea of a unique “stand alone” business has little substance? For example would Ms. McShane regard Union Gas’s northern assets (the old Centra Gas Ontario) as a stand alone business separate from Union Gas’ southern Ontario assets?
(c) Would Ms. McShane also agree that in its TQM decision the NEB regarded TQM as substantively part of the TransCanada Mainline, so despite being a separate company with it own rate base (and 6 employees) the fact its tolls are rolled into the Mainline meant that effectively it was not a stand alone pipeline?
(d) Would Ms. McShane agree that competition would force small utilities with uneconomic financial costs to merge to generate the scale required to access the capital market?
(e) Would Ms. McShane agree that regulation should not allow the uneconomic financial costs of small utilities to be passed through as higher tolls when regulation is supposed to be a surrogate for competition? If not why not?
Responses: (a) There is nothing to reconcile. As stated in response to IOL-Enbridge 144, Enbridge Pipelines’ regulated business is characterized by significant asset segregation, different regulatory frameworks (e.g., the ITSs for the Older System), and/or different contractual arrangements (e.g., the Financial Support and Service Agreement for Line 8). Adherence to the stand-alone principle through capital structure, ROE, or a combination thereof, for the segregated portions of the Enbridge System is a means of ensuring that it is the cost of capital related to the risk of the specific investment that is being estimated, not the overall cost of capital of Enbridge RH-1-2010 Responses of Enbridge to Imperial IRs Page 274 of 323
Pipelines.
(b) It is perhaps obvious that one could take the stand-alone principle to a nonsensical extreme. This is not the case for Enbridge; see IOL-Enbridge 191(a). Ms. McShane would not regard Union Gas’ Northern and Southern Ontario gas distribution operations as stand-alone entities.
(c) No. In setting the allowed return for TQM in the RH-1-2008 proceeding, the Board stated its decision was “supported by the longstanding stand-alone principle” (page 80). In determining the return for TQM, the Board assessed TQM’s risks, not those of TransCanada PipeLines.
(d) Small utilities with no access to capital might well be acquired by a larger firm. The price the acquiring firm would pay would be a function of the fundamental business risks that the acquired utility faces.
(e) Ms. McShane’s view is that regulation should allow a regulated company a reasonable opportunity to recover its revenue requirement – which includes more elements than simply “prudently incurred costs” or, for a forward test year, more than forecast costs not yet incurred but deemed prudent; for example, the cost of capital. The return available from the application of invested capital to other enterprises of like risk is one requirement of the fair return standard. This standard is used to determine the cost of capital for a utility.
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IOL-Enbridge 192
Reference: Written evidence of Enbridge (Adobe Number A1R0V6), Appendix A- 7.2, pages 13 to 14, lines 287 to 312.
Preamble: Ms. McShane discusses credit worthiness.
Requests: (a) Please confirm that the median debt rating of U.S. utilities is BBB and not A. If Ms. McShane can not confirm, please provide copies of tables and exhibits of all U.S. utilities she has referenced in testimony since 2007.
(b) In Ms. McShane’s judgment, do a DBRS, S&P and Moody’s “A” rating all indicate the same thing? That is, do the ratings generally agree and do they estimate the same thing? Please discuss in detail.
(c) Please provide any and all support for the notion that a regulated utility needs to be able to access long term debt on “reasonable” terms at all times during the business cycle, rather than simply access capital on reasonable terms.
(d) Would Ms. McShane agree that most Canadian utilities maintain back-up lines of credit to ensure that if the long term debt market is closed, or costs regarded as unreasonable, they can raise capital through shorter term debt maturities until capital market conditions improve? Would Ms. McShane regard such actions as prudent or imprudent?
(e) Would Ms. McShane agree that even during the credit crunch of September 2008-March 2009 no Canadian utility was shut out of the capital market? If she can not agree please provide details of any Canadian utility with public debt outstanding that was forced to withdraw a public offering due to poor investor “appetite”.
(f) On page 14, Ms McShane alleges that shippers gain from lower debt costs that result from Line 9 being a part of Enbridge. Please provide all analyses that Ms. McShane has performed to indicate that Line 9 could exist as an independent operation and that it would not disappear by way of an acquisition, like most of the other small utilities in Canada, such as Maritime Electric, Island Telephone etc. That is, please provide support for the proposition that Line 9 being a part of a larger entity is not the normal result of competition. RH-1-2010 Responses of Enbridge to Imperial IRs Page 276 of 323
Responses: (a) Confirmed.
(b) In all cases, the rating agencies mentioned state that their ratings are opinions as to the creditworthiness of an issuer, a security, or an obligation. Further, the agencies state that, by their very nature, opinions are subjective based on both quantitative and qualitative analyses of data. Therefore, in Ms. McShane’s judgment, ratings, all aim to assess the same thing despite a situation in which there may not always be agreement among rating agencies.
(c) Appendix A-7.2 states that “Debt ratings in the A category assure that the regulated company would be able to access the capital markets on reasonable terms and conditions during both robust and difficult, or weak, capital market conditions.” It does not state that a regulated utility needs to be able to access long term debt on “reasonable” terms at all times during the business cycle. Ms. McShane recognizes that, under certain market conditions, such as during the recent financial crisis, access to long-term debt markets on reasonable terms and conditions may not be feasible even for highly rated companies.
(d) Ms. McShane agrees that most Canadian utilities have back-up lines of credit that they use for working capital purposes and for bridge financing until such time as long-term debt financing is required. Utilities with ratings in the A category will have access to a broader range of short-term financing instruments, such as commercial paper, at lower cost and less restrictive conditions on terms of trade. Maintaining back-up credit facilities is prudent financial management.
(e) Ms. McShane is not aware of any Canadian utilities that were not able to obtain some kind of financing during the recent credit crunch. Those utilities that needed to access additional financing, including renewing or expanding available lines of credit, did so at a higher cost. See the responses to IOL-Enbridge 101(a) and (b).
(f) Ms. McShane has not performed any analysis to determine if Enbridge could exist as an independent operation. Based on her knowledge of the utility industry in Canada, Ms. McShane recognizes that it is more likely that an operation like Enbridge would be owned by a larger company and benefit from its affiliation with the larger company than to be an independent operation. That conclusion does not invalidate the proposition that Enbridge’s cost of capital should be determined on a stand-alone basis. RH-1-2010 Responses of Enbridge to Imperial IRs Page 277 of 323
IOL-Enbridge 193
Reference: Written evidence of Enbridge (Adobe Number A1R0V6), Appendix A- 7.2, pages 14 and 15.
Preamble: Ms. McShane discusses spreads on utility debt.
Requests: (a) Please update the spread estimates and indicate whether, in Ms. McShane’s judgment, debt market conditions are back to normal?
(b) Is Ms. McShane aware of the recent Dallas Fed article that is referenced below in the April 8, 2010 issue of the Canadian Investment Review that indicates that U.S. spreads are back to their mid-2008 levels, that is, prior to the credit crunch and stock market crash? If so, can she comment on whether in her view the markets are back to near normal levels and if not where the Dallas Fed article is deficient?
Canadian Investment Review
Bond Spreads Point to Normalizing Economy
But no wage gains and cautious consumer confidence.
April 8, 2010
Bad news for investors might be good news for the economy – but no news for workers. The Dallas Fed reports that the spreads between junk bonds and Treasuries and between corporate bonds and Treasuries are now at levels last seen in mid-2008.
But the Dallas Fed isn’t overly optimistic in its latest National Economic Update, released March 31. Says David Luttrell, a Dallas Fed research assistant: “Recent data point to a mild firming of the underlying pace of final demand growth. However, questions remain as to the sustainability of growth as conventional monetary and fiscal policy stimulus efforts fade over the course of this year. Improving trends in production and employment suggest that job losses might soon give way to modest gains. In light of continued debt deleveraging and tight credit conditions, persistent economic slack will likely continue to constrain inflationary RH-1-2010 Responses of Enbridge to Imperial IRs Page 278 of 323
pressures and expectations.”
Still, the normalization of bond spreads is startling to view as the chart shows.
Junk spreads soared to almost 21% and are now at about 5%; corporates went to 6% and are now around 2.5%. They’re approaching rates typical of a growing economy rather than a contracting one. So the capital gains turkey shoot is over; now it’s back to finding forgotten easter eggs.
Bond investors are clearly more confident about getting their money back, and corporations have access to money. The question, as always, is how will they use it – especially with far-from-ebullient consumer confidence, and record wage disinflation.
Responses: (a) As stated in footnote 7 of Appendix A-7.2, RBC stopped distributing the indicated spreads at the end of May 2009 and, therefore, the requested updates cannot be provided. In Ms. McShane’s judgement, the debt market conditions in the U.S., as measured by spreads are largely back to normal. In Canada, bond spreads were, at the end of March 2010, higher than pre-crisis. The spread between long-term A rated corporate bonds and the long-term Canada bond yield at month end March 2010 was 1.5%, compared to 1.15% during 2007.
(b) Yes. Ms. McShane is aware of the Federal Reserve Bank of Dallas article. Ms. McShane does not take issue with the comments made in the article as regards the current state of the U.S. bond market.
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IOL-Enbridge 194
Reference: Written evidence of Enbridge (Adobe Number A1R0V6), Appendix A- 7.2, pages 16 to 17.
Preamble: Ms. McShane discusses shorter vs. longer term risks.
Requests: (a) Ms. McShane observes that the idea that the regulator may compensate the utility for risk as it arises may not hold since current regulators can not bind future regulators and the costs may not be recoverable. Would Ms. McShane also agree that compensating the utility now for risks that may occur in the future can lead to double counting, as the utility can claim “again” when and if the risks actually do materialise?
(b) In terms of Line 9 would Ms. McShane agree that it was only built with financial support from the Government of Canada and the existence of this support indicates that it was regarded as risky from day one?
(c) Would Ms. McShane agree that Enbridge (and predecessor companies) as the operator of Line 9 has since 1976 been compensated for the riskiness of Line 9 by a higher deemed common equity component than other Canadian pipelines as well as higher depreciation rates and various deferral accounts and cost true ups? If not, why not?
Responses: (a) It is possible that the return and capital structure adopted for toll- setting purposes may compensate for risks that the pipeline faces, actually incurs, and subsequently is able to mitigate through the regulatory process. Prudent management would make all reasonable efforts to mitigate the risks that are actually experienced. If there are indeed regulatory solutions available, it is ultimately within the purview of the regulator to determine how the experienced risks can or should be allocated between tollpayers and shareholders.
(b) Ms. McShane agrees that the Montréal Extension was only built with the financial support of the Government of Canada and was viewed as a risky venture.
(c) No. First, Ms. McShane considers Enbridge (Line 9) to be a different entity from the Montréal Extension. Second, from its inception until the end of September 2007, Enbridge (Line 9) was governed by the negotiated terms of the FSA during its Primary RH-1-2010 Responses of Enbridge to Imperial IRs Page 280 of 323 and Extended Terms, which specified the ROE, cost of debt, capital structure, depreciation rates, etc., specific to Enbridge (Line 9) during this discrete period. Over the same time period, Incentive Toll Settlements and the Financial Support and Service Agreement applied to the Older System and Line 8 respectively. The terms and conditions of the settlements and agreements were specific to those two segments of the Enbridge System. Ms. McShane fails to see how Enbridge “as the operator of Line 9” could or would have been compensated for the risks of Line 9 through the terms of tolling arrangements which either applied to other segments of the Enbridge System or which were applicable to Enbridge (Line 9) under the now-expired FSA.
RH-1-2010 Responses of Enbridge to Imperial IRs Page 281 of 323
IOL-Enbridge 195
Reference: Written evidence of Enbridge (Adobe Number A1R0V6), Appendix A- 7.2, pages 19 to 22.
Preamble: Ms. McShane discusses Line 9’s business risks.
Requests: (a) Ms McShane indicates that throughput on Line 9 has dropped from 240,000 bd to 70,340, please indicate: (1) the $ impact of the throughput drop on the toll; and (2) express this impact as a % of the current price of a barrel of crude oil.
(b) Can Ms. McShane also please indicate the current throughput on the TransCanada Mainline, and: (1) express that relative to the Mainline’s notional capacity; (2) indicate the current toll to Ontario and Quebec in $ and as a% of the current price of natural gas; and (3) indicate what the impact on the Mainline’s toll would be if it were running at full capacity.
(c) Ms. McShane indicates that the credit risk of the shippers has declined due to Shell and Petro Canada no longer shipping oil. Please indicate what if any additional support Enbridge requires of non investment grade shippers like NOVA? Also please indicate what the marginal cost of serving a non-investment grade shipper like NOVA is?
(d) Please provide the net rate base, annual earned ROE, and common equity ratio for Line 9 since inception indicating any significant capital cost additions.
Responses: (a) Enbridge assumes that the question is related to 2009 which was forecast to have throughput of 70,341 b/d and a revenue requirement of $46.878 million. For purposes of this example Enbridge also assumes that there is no power cost impact and that there is only one delivery point on Line 9. Using the forecast amounts a toll can be derived as follows: $46,878,000 / (70,341 b/d X 365 days/year) = $ 1.826. Following the same approach, 240,000 b/d yields a toll of $0.535.
As of May 13, 2010 the Brent Spot Price was CA$81.26 (source: Bloomberg). The impact of the difference in tolls calculated above expressed as a % of the current price of a barrel of oil can be calculated as follows: (1.826 - .535) / 81.26 = 1.6%.
(b) Ms. McShane was retained to assess the reasonableness of RH-1-2010 Responses of Enbridge to Imperial IRs Page 282 of 323
Enbridge’s proposed capital structure and to recommend a rate of return on equity. The scope of her retainer does not include preparation of the requested information.
(c) Non-investment grade shippers may be required to provide Financial Assurances. See Tariff NEB No. 297 at Rule 19.
The marginal cost of serving a non-investment grade shipper, if any, has not been determined.
(d) See Attachment 1 to IOL-Enbridge 195(d). RH-1-2010 Responses of Enbridge to Imperial IRs Page 283 of 323
IOL-Enbridge 196
Reference: Written evidence of Enbridge (Adobe Number A1R0V6), Appendix A- 7.2, page 24, Table 2.
Preamble: Ms. McShane discusses comparable common equity ratios for 7 pipelines.
Requests: (a) For each comparable pipeline cited, please indicate the book value of: (1) the entire rate base; (2) the common equity; and (3) the debt.
(b) For each issuer in Table 2 (except Enbridge) please provide the major forms of debt that have been issued and the amounts categorized according to maturity and type of debt, for example, bank debt, inter-corporate debt, public market debt etc.
(c) For each issuer in Table 2, please indicate the terms of the last debt issue, that is, date, maturity, all in cost, equivalent Canada yield and type of debt.
(d) Where there are no debt ratings provided, please explain why.
Responses: (a) The information available to Ms. McShane is presented in the table below:
Rate Base Equity Debt
$million $million $million Enbridge Pipelines $1510.2 $1,850 (Mainline) 1/ n/a (2008) (2008) Enbridge Pipelines (NW)2/ $109 (2010F) $59.95 $49.05 $250.5 $346.2 Express System3/ n/a (6/2009) (6/2009) Milk River Pipeline 4/ $10.0 (2001) $5 $5 Plateau Pipe Line (Western System) 5/ $14.9 (2002) $7.45 $7.45 Trans Mountain Pipeline6/ $209 (2008) $94 $115 Trans-Northern Pipelines 1/ n/a $61 (2009) $110 (2009)
1/ DBRS, Rating Report Enbridge Pipelines Inc. (November 27, 2009), and Rating Report TransNorthern Pipelines Inc. (March 3, 2010). 2/Enbridge Pipelines (NW) Inc., Estimate of Full Cost of Service for Operating Year 2010. 3/ DBRS, Rating Report Express Pipeline Limited Partnership & Express Pipeline LLC (October 16, 2009). The financial data presented in the DBRS report are for the Express System as defined by DBRS, which includes Express Canada, Express U.S. and Platte. 4/NEB, Reasons for Decision Murphy Oil Company Ltd. (now Plains Marketing Canada, L.P.) Concerning Tolls for the Milk River Pipelines (Order TO-4- RH-1-2010 Responses of Enbridge to Imperial IRs Page 284 of 323
2001), August 2001. 5/BCUC, Plateau Pipe Line Ltd. Taylor to Kamloops Pipeline Application for Permanent Tolls Decision (Decision P-3-01). 6/NEB, Trans Mountain Pipeline Inc. Methodology for Calculation of 2009 Tolls Pursuant to the 2006 to 2010 Incentive Toll Settlement, May 2009. Note: n/a = not available
(b) Ms. McShane does not have the information in the format requested. From DBRS, which rates the two pipelines other than Enbridge that issue debt in their own name, the following information is available:
Rating Issue Date Coupon Principle Express Pipeline Limited Partnership & Express Pipeline LLC Senior Secured Notes due 2013 A (low) 2/1998 6.47% $150million Subordinated Secured BBB Notes due 2019 (low) 6/2005 6.09% $110million Senior Secured Notes due 2020 A (low) 2/1998 7.39% $250million Trans-Northern Pipelines Inc. Senior Unsecured Notes due March 2015 A(low) 12/2005 4.742% $135million
(c) The requested information for Enbridge Pipelines is presented below. Ms. McShane does not have the requested information for the Express and Trans-Northern issues listed in part (b) above.
Company Size Coupon Maturity Spread Benchmark Date of ($million) (%) (bps) Issue Enbridge 350 4.45 April-20 78 CAN 3.5 4/2010 Pipelines June-20 Inc. Enbridge 300 5.33 April-40 125 CAN 5 4/2010 Pipelines June-40 Inc.
(d) In the case of Trans-Northern Pipelines, the company is not rated by Standard and Poor’s. In all other cases, the pipelines do not issue debt in their own name. Trans Mountain was previously rated by DBRS, but the debt rating was discontinued in 2005 when the rated issue was repaid.
RH-1-2010 Responses of Enbridge to Imperial IRs Page 285 of 323
IOL-Enbridge 197
Reference: Written evidence of Enbridge (Adobe Number A1R0V6), Appendix A-7.2, pages 28 to 30; footnotes 23 to 25.
Preamble: Ms. McShane discusses rating agency guidelines.
Requests: (a) Please provide copies of the documents referenced in footnotes 23, 24 and 25.
(b) Ms. McShane refers to Moody’s methodology for gas transmission companies as providing a perspective on the reasonableness of Enbridge’s requested 50%. Please explain what Ms. McShane means by perspective given that Canadian oil pipelines have traditionally operated with more common equity than natural gas pipelines.
(c) Please indicate what Moody’s rating for TransCanada was while the Mainline was operating on 30% common equity.
(d) Ms. McShane refers (at Adobe page 29) to S&P placing most Canadian regulated utilities in the highest rating of “Excellent”. Please provide a histogram of S&P’s rating of U.S. utilities’ business risk based on the number of utilities in each rating classification from excellent down to weak.
(e) Ms. McShane’s judgement, based on S&P’s guidelines, indicates a BBB rating for Line 9. For each Canadian utility rated by S&P, please perform a similar analysis indicating what Ms. McShane believes the S&P guidelines imply about their rating versus S&P’s actual rating.
Responses: (a) See Attachments 1 through 4 to NEB 1.13.
(b) Appendix A-7.2 states that “Enbridge’s proposed 50% equity ratio is below the lower end of the A range and in the middle of the Baa range for a gas pipeline. Although these guideline ranges are for gas, not crude oil, pipelines, Moody’s considers that gas pipelines face lower business risk than crude oil pipelines. While the actual ratings will take into account multiple factors, in isolation, they suggest Enbridge’s proposed 50% equity ratio is conservative.” The referenced sentence recognizes that Moody’s regards gas pipelines as less risky and concludes that, based on the guidelines for gas pipelines, Enbridge’s common equity ratio would be RH-1-2010 Responses of Enbridge to Imperial IRs Page 286 of 323
conservative.
(c) The Moody’s rating for TransCanada was A2 at the time the Canadian Mainline was operating with 30% common equity.
(d) The requested histogram for U.S. regulated electrics and gas utilities is presented below:
(e) As stated at page 27, lines 742 through 745 of Appendix A-7.2, while “S&P does not apply their guidelines mechanically, and the guidelines apply broadly across corporate sectors (not solely to regulated companies), the guidelines do provide direction as to ranges that are considered reasonable for ratings in the different rating categories.” The actual ratings for the Canadian gas and electric utility companies rated by S&P as Attachment 1 to IOL- Enbridge 197(e).
RH-1-2010 Responses of Enbridge to Imperial IRs Page 287 of 323
IOL-Enbridge 198
Reference: Written evidence of Enbridge (Adobe Number A1R0V6), Appendix A- 7.2, pages 30 to 31.
Preamble: Ms. McShane discusses the RH-2-94 formula ROE.
Requests: (a) Please indicate the basis for the comment that “it became increasingly clear” on page 31, line 789, by citing examples of any utility failing to make investments at a formula ROE, whether that of the NEB or any other formula, or any downgrades of utility debt that occurred during the operation of the formula where the rating agency cited the ROE formula as the primary reason.
(b) When Ms. McShane states that as the long Canada yield fell by 490 basis points the allowed ROE fell by 370 basis points, please confirm that this means the utility risk premium increased by 120 basis points. Please provide all empirical support for the notion that the risk of a typical Canadian utility subject to a formula ROE like that of the NEB’s increased over the period 1995-2009.
(c) Further to request (b), if we assume the typical utility has a relative risk assessment of 0.5, please confirm that the increase in the utility risk premium of 120 bps means the market risk premium increased by 240 bps. Please provide any and all justification for an increase in the market risk premium of 240 bps from 1995 to 2009.
(d) On page 32, Ms. McShane refers to the reduced supply of long Canada bonds coming to the capital market due to greater fiscal responsibility on the part of Canadian governments. Would Ms. McShane agree that this implies that funds were allocated elsewhere than the Canadian bond market, since “crowding out” was reduced? If not, why not?
(e) Would Ms. McShane agree that greater investment in “non-Canada bonds” drives up their prices and reduces their expected rates of return? If not, why not?
(f) Would Ms. McShane agree that all conventional (non-derivative) classes of securities are “gross substitutes” in the sense that their expected rates of return tend to move together? If not, why not?
Responses: (a) The basis for the comment at page 28, lines 789-791 of A-7.2, that “it became increasingly clear that the required ROE did not track RH-1-2010 Responses of Enbridge to Imperial IRs Page 288 of 323
long-term Government of Canada bond yields in the manner indicated by the automatic adjustment mechanism” is presented in lines 793-900 and lines 971-1007 of A-7.2.
As long ago as December 2001, CIBC World Markets Report entitled “Pipelines and Utilities: Time to Lighten Up”, stated, in reference to the then recent formulaic reduction in Newfoundland Power’s allowed return (from 9.59% to 9.05% year over year):
The magnitude of the reduction in the case of Newfoundland Power illustrates the flaw in using a brief snapshot of existing rates rather than a forecast of rates that are expected to persist during the upcoming year. More importantly, however, it shows the shortcoming of the formula approach itself. Mechanically tying allowed returns on equity to long bond yields is an approach that is simple for regulators to apply; however, in recent years, with a steady decline in bond yields, it has produced- allowed returns that are out of sync with the cost of capital, and returns that are being achieved with comparable non- regulated companies or regulated returns that are achievable in the U.S.
In its June 2006 Canadian Hydrocarbon Transportation System Report, the Board reported that a number of analysts felt that the ROE generated by the Board’s formula and by other Canadian regulators’ formulas “were a little too low” and not supportive of dividend growth or credit metrics. A number of analysts commented that where they had “Buy” recommendations on utility stocks, the recommendations tended to reflect the prospects of the unregulated operations. Analysts also commented that companies had reduced costs and taken other steps to improve profitability and dividend growth for several years, and wondered how long that could continue. The Board’s 2007 Report expressed similar views. Some market participants expressed concern that the stand-alone pipelines might have difficulty attracting capital given low ROEs. Others felt the regulated entities would be able to attract capital, but that the terms under which they did so would be more costly than for the consolidated entity. In addition, the Board’s 2007 Report stated that:
Many analysts expressed support for a formulaic approach to determining ROEs because of the transparency, stability and predictability that this method provides. However, a number expressed the view that the ROE resulting from the formula was too low, and contend that they are much lower RH-1-2010 Responses of Enbridge to Imperial IRs Page 289 of 323
than regulated ROEs in the U.S. and U.K. While views ranged widely on this issue, some felt that the typically lower ROEs in Canada were not justified by the differences in risk for Canadian companies compared to FERC- regulated pipelines. Some parties suggested it was time for the Board to revisit the ROE Formula.
In Pipelines/Gas & Electric Utilities, dated December 7, 2006, Karen Taylor, then equity analyst for BMO Capital Markets, concluded, “We believe on a collective basis, that the allowed returns as established by the formulas highlighted above [referring to the NEB, EUB, BCUC and OEB formulas] are confiscatory and likely violate the Fair Return Standard.”
In October 2008, RBC recommended that investors focus on Enbridge and TransCanada as “the majority of both companies’ capital” was being allocated to projects with expected ROE above the formula return, “mostly oil pipelines, contracted power generation and U.S. gas pipelines” (RBC Capital Markets, ROE Outlook for 2009: Is the Formula Broken? ROEs Set to Decline, October 24, 2008). In early 2009 (RBC Capital Markets, Industry Comment, Allowed ROEs: The Formula Is Broken, but Will Regulators Fix It?, January 16, 2009), RBC reaffirmed their position, recommending that investors focus on regulated companies with “the least exposure to the Formula.”
A February 23, 2009 report by Macquarie Research entitled ROE Formula May Finally Bite the Dust concluded that government bond yields bear little resemblance to any private company’s cost of capital. The report also concluded that:
Lack of comparability between allowed utility ROEs and returns on similar investments is driving the emerging capital access problem. In support of the argument the comparability criterion is not being met, utility customers and their expert witnesses like to point out that allowed returns for U.S. utilities are considerably higher than allowed returns in Canada. No matter how we slice the data, we concur with this opinion.
BMO Capital Markets analyst George Lazarevski in Pipelines and Utilities (March 30, 2009) stated,
We applaud the NEB for acknowledging that the RH-2-94 formula is no longer applicable given the changes in business risk, financial markets and economic conditions. RH-1-2010 Responses of Enbridge to Imperial IRs Page 290 of 323
In particular, the globalization of financial markets made it difficult for Canadian operators to compete for capital with such low ROE.
On April 24, 2009, Scotia Capital commented (Stephen Dafoe, Falling Canada Yields and Utility ROEs, Capital Points):
The turmoil in financial markets over the last 18 months has had a material knock-on effect on a sector typically seen as a safe haven from adverse equity market volatility and valuations. Energy utilities across Canada have seen their regulated returns on equity squeezed by falling Government of Canada bond yields, even as the real-world cost of equity capital has risen dramatically.
Beginning with the National Energy Board in early 1995, Canadian energy regulators have largely adopted formula- based annual adjustments to utilities’ allowed return on equity. These formula have been based on the capital asset pricing model. A base “risk-free” rate, represented by long Canada bond yields, is augmented by an equity risk premium, chosen to represent the business and financial risk of the utilities. The NEB’s formula was created in 1994 and 1995, when Canada long bond yields reached over 9% at times, due to a range of factors, including ratings downgrades, large public sector deficits, and bearish domestic and international market sentiment towards Canadian government debt.
As Canada’s public sector reformed its finances, long Canada yields have come down, gradually but steadily, since early 1995. This led to a gradual decline in utility allowed ROEs, which has been a challenge for equity holders, and a challenge for utility management to offset by trying to “over-earn” the regulatory target, which is used to set rates.
The onset of economic and financial market turmoil in late 2007 led to a further, more rapid decline in Canada yields, mimicking the global flight to the safety of top-quality sovereign debt, and reflecting widespread investor aversion to risk of all kinds. This triggered a decrease in Canadian utility regulators’ formula-driven ROEs, to unprecedented low levels. However, utility bond spreads, and their cost of equity capital, were rising.
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Very recently, the NEB recognized these adverse and undesirable results, in what we view as a very significant Decision in the case of Trans Québec & Maritimes Pipeline. The NEB varied from its formula, which it had applied virtually universally to utilities in its jurisdiction since 1995. The ROE relief was material, lifting TQM’s ROE from the formula-set 8.46% and 8.71% in 2007 and 2008 (on the NEB’s deemed equity capitalization of 30%) to roughly 11.6% to 11.8%, based on the same capital structure and the embedded cost of debt.
To Ms. McShane’s knowledge, no downgrades of utilities occurred during the operation of the formulas where the formula was specifically cited as the reason for the downgrade. Terasen Gas Inc. was downgraded by Moody’s in 2005 due to its weak financial profile relative to its global peers; the financial profile results from the combination of deemed capital structure and ROE, the latter having been set by formula. DBRS noted in its February 2010 Industry Study: Recent Regulatory Developments for Canadian Pipeline and Utility Companies: “From the mid-1990s to early 2009, regulated ROE levels were directly linked to government of Canada long bond yields. In recent years as long- term interest rates dropped significantly, allowed ROEs followed suit, resulting in weakening credit ratios and lower returns on equity capital compared with other investment alternatives. Additionally, with the increase in corporate credit spreads, which peaked in early 2009, the long-term cost of debt for regulated entities was fast approaching approved ROE levels, implying that the ROE levels were too low to justify incremental equity investment in the entity. Although this pressure has recently subsided somewhat, it was another signal that the adjustment mechanisms for determining allowed ROE needed to be reviewed within the context of an evolving financial market.” DBRS stated that “deteriorating ROE levels have not had a direct negative effect on DBRS ratings of pure pipeline and utility companies” and that “recent increases in approved ROE levels or equity thickness should not, in themselves, result in positive rating actions unless the improvement is significant enough to be viewed as a material reduction in financial risk.” However, the debt rating agencies’ concerns are focused on the interests of creditors, who are concerned with the ability of the firm to meet their fixed rather than the interests of equity investors.
With respect to utilities failing to make investments at the formula ROE, the only example of a utility which has publically announced an investment that it did not make, of which Ms. McShane is RH-1-2010 Responses of Enbridge to Imperial IRs Page 292 of 323
aware, is that of Union Gas. Union Gas commented in its April 2009 letter to the Ontario Energy Board in the recent cost of capital consultation (The Cost of Capital in Current Economic and Financial Market Conditions: EB-2009-0084) that:
In a global capital market, where utility ROEs are already considerably lower relative to US jurisdictions, a spread of 39 basis points between the regulated ROE and the long- term debt rate makes attracting investment capital to Ontario utilities even more difficult. For Union Gas, this has manifested itself in a deferral of the next expansion of its Dawn-Trafalgar transmission system despite having adequate market demand for service, as the company’s cost of capital is not competitive with other investment alternatives available to its owner.
Utilities have continued to make regulated investments at formula- based ROEs due, where relevant, to the obligation to serve, in order to preserve the value of their franchises or service areas, to meet their obligations to provide safe and reliable service, and because they continue to have an expectation that regulators will award returns on invested capital that are fair and reasonable.
(b) It is confirmed mathematically that a decline of 490 basis points in the long Canada yield and a 390 basis points decline in the allowed ROE results in an increase of 120 basis points in the implicit risk premium. Ms. McShane’s evidence does not claim that there has been an increase in the investment risk of the typical Canadian utility over the 1995-2009 period. In the RH-2-94 proceeding, the evidence of Dr. Sherwin and Ms. McShane relied upon a relative risk adjustment of 0.70 for a high grade Canadian utility applied to an estimated market premium. Ms. McShane currently estimates the relative risk adjustment for a high grade Canadian utility to be in the range of 0.65-0.70 applied to a market risk premium of 6.75%. See response to IOL-Enbridge 198(c).
(c) Ms. McShane does not accept the premise of the question: that the required risk premium for the typical Canadian utility is 50% of the market risk premium. As stated in response to IOL-Enbridge 198(b), Ms. McShane’s current estimate of the relative risk adjustment for a high grade utility is in the range of 0.65-0.70. In the express context of the CAPM, at a 0.70 relative risk adjustment for a high grade utility, the increase in the market risk premium implied by the application of the discontinued RH-2-94 formula would be approximately 1.7 percentage points (increase of 1.2 percentage points in the RH-2-94 formula risk premium for a RH-1-2010 Responses of Enbridge to Imperial IRs Page 293 of 323 benchmark pipeline divided by a relative risk adjustment of 0.70).
An increase in the market risk premium of that magnitude is supported by the decline in the risk of long-term Canada bonds relative to equities since 1995 combined with relatively stable long-term average equity market returns. With respect to the relative risk of long-term Canada bonds, as the expected rate of inflation rises, investors perceive increasing uncertainty that the future inflation rate will be different from the expected rate. Since investors in bonds are adversely affected by rising inflation, greater uncertainty regarding the future course of inflation may lead to a perceived increase in the riskiness of bonds relative to stocks, and hence an incremental risk premium on bonds for the uncertainty of inflationary expectations. That premium has been referred to as a "lock-in" premium. Equity investments are generally viewed as providing at least a partial inflation (and sometimes a complete) inflation hedge, and do not require a purchasing power premium of the same magnitude as bond investors.
At the time of the RH-2-94 proceeding, the premium built into long-term Canada bond yields for the fear of inflation (the lock-in premium) was as high as 2.5 percentage points. During the fourth quarter of 1994, the yield on conventional (nominal) long-term Canada bonds was approximately 9.25%. The yield on inflation indexed bonds was approximately 4.75%. The differential between the two yields of 4.5% is an estimate of the premium that bond investors required for both anticipated inflation and the fear of unanticipated inflation. In the fourth quarter of 1994, the consensus of economists’ forecasts of inflation over the next 10 years was just over 2% (Consensus Economics, Consensus Forecasts, October 1994). Consequently, the premium that bond investors were demanding for unanticipated inflation may have been as high as 2.5% (4.5% total inflation premium minus a consensus 10-year forecast inflation rate of 2%). At prevailing levels of long-term Canada bonds (4% and 1.5% for conventional and inflation-indexed long-term Government of Canada bonds, respectively) and a consensus forecast for inflation of 2% (Consensus Economics, Consensus Forecasts, April 2010), the corresponding prevailing lock-in premium would be 0.5%, a reduction of 2.0 percentage points compared to late 1994. The significantly lower lock-in premium in long-term Canada bond yields, ceteris paribus, points to a materially higher equity risk premium today than at the time of the RH-2-94 proceeding.
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With respect to equity market returns, the long-term average (arithmetic) returns in Canada at the time of the RH-2-94 proceeding were in the approximate range of 11.5% to 12.0%. The long-term averages through 2009 are at similar levels. The absence of any material upward or downward trend in the nominal historical equity market returns supports the conclusion that a reasonable expected value of the future equity market return is a range of 11.5%-12.0%. Long-term Canada bond yields are expected to be in the approximate range of 4.75% (near-term) to 5.25% (longer-term) based on the April 2010 Consensus Forecasts, the indicated market risk premium is approximately 6.75%, compared to the market risk premium of 4.5%-5.0% determined by the Board in the RH-2-94 proceeding, an increase of approximately 2.0 percentage points.
See also response to NEB 122(c).
(d) Ms. McShane agrees that, if there is a decreased supply of Government of Canada bonds, and no offsetting decrease in the supply of savings to be invested, then the funds must be allocated elsewhere.
(e) Ms. McShane agrees that increased demand for a particular type of security without an offsetting increase in supply would tend to increase the price and lower the expected rate of return.
(f) Ceteris paribus, the expected rates of return on different classes of securities would tend to move in a similar direction over the longer-term, reflecting the overall cost of capital environment. The extent to which individual types of securities move together or in different directions at specific points in time depends on various factors, including the prevailing degree of risk aversion, the perceived risks associated with different types of securities and the demand for and supply of different types of securities.
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IOL-Enbridge 199
Reference: Written evidence of Enbridge (Adobe Number A1R0V6), Appendix A- 7.2, page 33.
Preamble: Ms. McShane discusses some broad measures of market behaviour.
Requests: (a) Ms. McShane notes that the yield on Enbridge Pipeline bonds increased from 5.4% in November 2007 to 7.0% in November 2008 at the height of the financial crisis. Please confirm that as the yield on Enbridge’s bonds increased their market price falls, that is yield and prices move inversely, so bond holders lost money on their investment in Enbridge‘s bonds.
(b) Please confirm that during those two periods Enbridge’s daily closing stock price was as follows:
28-Nov-08 38.1 30-Nov-07 37.11 27-Nov-08 36.49 29-Nov-07 36.85 26-Nov-08 36.58 28-Nov-07 37.26 25-Nov-08 36.6 27-Nov-07 36.63 24-Nov-08 36.29 26-Nov-07 36.33 21-Nov-08 36.27 23-Nov-07 37.01 20-Nov-08 34.55 22-Nov-07 36.56 19-Nov-08 35.7 21-Nov-07 36.24 18-Nov-08 37.5 20-Nov-07 36.22 17-Nov-08 39.15 19-Nov-07 36.08 14-Nov-08 39.68 16-Nov-07 36.61 13-Nov-08 39.35 15-Nov-07 37.01 12-Nov-08 39.29 14-Nov-07 37.49 12-Nov-08 13-Nov-07 37.59 11-Nov-08 40.86 13-Nov-07 10-Nov-08 40.85 12-Nov-07 38.7 7-Nov-08 40.48 9-Nov-07 38.9 6-Nov-08 41.19 8-Nov-07 39.32 5-Nov-08 42 7-Nov-07 39.28 4-Nov-08 42.3 6-Nov-07 40.76 3-Nov-08 41.22 5-Nov-07 40.4 2-Nov-07 40.41 1-Nov-07 40.96 (c) Please confirm that Enbridge’s average stock price in November 2007 was $38 whereas during November 2008 it increased to $39, but there is no discernible pattern in Enbridge’s stock price between these two periods. If Ms. McShane discerns a pattern and disagrees please indicate what she believes the pattern to be and provide justification. RH-1-2010 Responses of Enbridge to Imperial IRs Page 296 of 323
(d) Please confirm that all else constant a declining ROE due to the ROE formula combined with an increase in the cost of equity implies that Enbridge’s stock price should have fallen, exactly the same as its bond prices fell. If not, why not?
(e) Is it Ms. McShane’s judgement that equity and bond investors react identically to the same information and economic events? If so, please provide all support for this idea.
(f) Please confirm that the increase in Enbridge’s stock price at a time of a declining formula ROE is consistent with Enbridge being a “defensive” stock and investors requiring a lower fair return for investing in such stocks during a time of flight to quality? If not, please explain why not?
Responses: (a) Confirmed.
(b) Confirmed for Enbridge Inc.
(c) Confirmed that the average prices of Enbridge Inc.’s stock in November 2007 and November 2008 were approximately $38 and $39, respectively. Not confirmed that there was no pattern discernable in Enbridge Inc.’s stock price between those two months. During the referenced period, Enbridge Inc.’s share price movements generally tracked those of the equity market composite.
(d) All else constant, confirmed. However, all else is not constant. The consolidated operations of Enbridge Inc. do not have as much exposure to the formula ROE as some of the other publicly-traded Canadian companies with regulated operations. For example, Robert Kwan, an energy analyst with RBC Capital Markets, in his January 16, 2009 Industry Comment, Allowed ROEs: The Formula Is Broken, but Will Regulators Fix It? recommended that investors focus on regulated companies with least exposure to the formula. The two companies that he highlighted were Enbridge Inc. and Emera.
(e) No. Bond and stock investors do not react identically to the same information and economic events. For example, bond prices are likely to react more negatively to rising inflation than equity prices.
(f) Ms. McShane is not certain to what period the question is referring. A review of all of the Enbridge Inc. stock price changes between November 1, 2007 and November 30, 2008 indicates that Enbridge Inc.’s stock price generally rose beginning in early RH-1-2010 Responses of Enbridge to Imperial IRs Page 297 of 323
February 2008, peaking in mid-June 2008, and then trended downward through mid-October 2008, before rising again towards the end of November 2008. The S&P/TSX Composite followed a similar pattern. The rise in Enbridge Inc.’s stock price during the Q4 of 2008 may have been more related to the fact that the company announced that it expected to be able to achieve 10% annual growth in operating earnings between 2007 and 2012 than because it is a defensive stock.
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IOL-Enbridge 200
Reference: Written evidence of Enbridge (Adobe Number A1R0V6), Appendix A- 7.2, page 35; figure 2.
Preamble: Ms. McShane discusses U.S. awards relative to those of Canadian utilities.
Requests: (a) From the presentation of Figure 2, it seems to be Ms. McShane’s view that Canadian allowed ROEs should be the same as those awarded in the U.S. Is this in fact Ms. McShane’s view?
(b) Canadian allowed ROEs dropped below those in the US about 1997 when the aggregate government deficit in Canada turned into a surplus. Is it Ms. McShane’s view that deficit financing by the national government has no impact on the level of fair rates of return in the capital market? If so, please provide all evidence to support this notion.
(c) Can Ms. McShane briefly describe why the capital markets are currently fixated on the problems facing Greece and confirm that it is because their deficit is predicted to be 120% of GDP and as a result Greece’s sovereign borrowing costs, that of its major banks and other institutions, are hitting all time highs in terms of spreads over equivalent bonds issued by the German government?
(d) If capital markets exhibit “significant integration” as described by Ms McShane, does this means that nominal rates of return have to be the same?
(e) If Ms. McShane’s answer to request (d) above is yes, please provide all theoretical support for the notion that in an integrated market nominal rates of return have to be identical for two otherwise identical securities.
(f) Please provide the latest available estimates of the following instruments: US and Canadian prime, the real yield on US and Canadian real return bonds (TIPS in the US) and the yield on 30 day U.S. and Canadian commercial paper.
Responses: (a) It is not Ms. McShane’s view that the Canadian allowed ROEs should be identical to those awarded in the U.S. However, she does believe that the returns available to investments of similar risk undertaken in similar cost of capital environments should be comparable. Over the period since cross-over, 1998-2009, the difference in long-term government bond yields in Canada and the RH-1-2010 Responses of Enbridge to Imperial IRs Page 299 of 323
U.S. has been approximately nine basis points. In isolation, on this basis, the average difference in ROEs should have been less than 10 basis points. The actual difference between the allowed returns in Canada and the allowed returns in the U.S. over that period was approximately 140 basis points. See also response to IOL- Enbridge 184.
(b) Not confirmed. The deficit financing by the government has an impact on inflation and on long-term government bond yields, which in turn have an impact on the costs of other forms of capital. The improvement in Canada’s fiscal position over the period since 1997 impacted the level of government bond yields, reducing them to levels that were similar to those prevailing in the U.S. As noted in response to IOL-Enbridge 184, a recent study by the Bank of Canada found that since government bond yields have converged in the two countries, the difference in cost of equity financing between the two countries is statistically insignificant (Lorie Zorn, Estimating the Cost of Equity for Canadian and US. Firms, Bank of Canada, Autumn 2007). However, due to the construct of the automatic adjustment formulas and the degree of sensitivity of the allowed ROEs in Canada to the change in long-term Canada bond yields incorporated within them, allowed returns in Canada diverged sharply from U.S. allowed returns, whose sensitivity to changes in long-term government bond yields has been less extreme.
(c) Ms. McShane is aware that the ratio of general government debt to GDP in Greece is forecast at 120% in 2010. She does not know whether current spreads of Greek bond yields relative to other country’s bonds are at all time highs but agrees that the current fiscal situation has pushed the premiums on sovereign debt to levels well in excess of those of other European Union countries.
Concerns regarding Greece’s sovereign credit risk have been expressed by capital market participants for some time. The concerns are based on recognition of the country’s extremely high level of public debt and deficits. In 2007, S&P stated that the fiscal measures implemented by the Greek government were “unlikely to bring about sustainable fiscal adjustment over the medium to long term.” Over the period 2004 to 2008, the ratio of general government debt to GDP averaged 98%; in 2009, the level was 112% and it is forecast to increase sharply in 2010 to 120%. (Source: Moody’s Credit Opinion Greece, December 2009) Both S&P and Moody’s downgraded the country’s debt in late April 2010. S&P downgraded the debt to junk status (BB+) while Moody’s indicated that a multi-notch downgrade from the current RH-1-2010 Responses of Enbridge to Imperial IRs Page 300 of 323
A3 rating (issued April 23, 2010) is “likely” (April 29, 2010). The downgrades reflect increasingly unfavourable debt dynamics such as “increased credit risk discrimination by investors (that would raise the cost of borrowing relative to other sovereign issuers) and lower trend nominal growth” which make current debt levels unsustainable. (Moody’s April 29, 2010) In announcing the possibility of a further downgrade, Moody’s stated that the “current debt and macro-economic dynamics in Greece” make an upgrade in the government’s ratings “unrealistic in the foreseeable future.” Further, if the “structural weaknesses of the economy (low competitiveness) and of public finances (widespread tax evasion, high structural expenditure) persist and maintain debt metrics on an unfavourable trajectory.” (Moody’s April 29, 2010 report.
(d) No. The nominal rates of return on different securities would be a function of multiple factors including the rates of inflation, monetary policy, and taxes in the two countries. However, significant integration would result in prices of securities in the two countries being impacted by the same events and moving more closely in tandem. See response to IOL-Enbridge 200(a).
(e) Not applicable.
(f) U.S. data is available at the following link: http://www.federalreserve.gov/releases/h15/update
Canadian data is available at the following link: http://www.bankofcanada.ca/en/bond-look.htm and Canadian interest rates- Interest rates- Rates and Statistics- Bank of Canada
April 19, Prime Long-Term 30-day Commercial 2010 Rate Inflation Paper Indexed 0.18% (non-financial) U.S. 3.25% 2.00% 0.23%(financial) Canada 2.25% 1.55% .38%
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IOL-Enbridge 201
Reference: Written evidence of Enbridge (Adobe Number A1R0V6), Appendix A- 7.2, page 36.
Preamble: Ms. McShane discusses the NEB’s TQM decision.
Requests: (a) Ms. McShane refers to the NEB’s statement about significant changes in financial markets and economic conditions since 1994, please confirm that the NEB conducted a full review of the multi- pipeline ROE formula in 2001 (RH-4-2001) and stated:
Is it Ms. McShane’s judgement that in 2001 the NEB did not consider changes in economic conditions and financial markets since 1994 or that no such testimony was entered into evidence? If the answer is yes please provide support.
(b) Can Ms. McShane please confirm that in RH-2-2004 the NEB removed the appropriate rate of return on common equity for the Mainline from the issues list and the Mainline was allowed the multi-pipeline formula ROE? Is it Ms. McShane’s judgement that the allowed ROE at that time was unfair or unreasonable? If so, please explain in detail.
(c) Can Ms. McShane confirm that the TQM hearing commenced on September 23, 2008 in Montreal and finished on October 22, 2008 in Calgary and that during this period the TSX composite dropped from 12,599.88 to 9,236.88 or a drop of 27%?
(d) Can Ms. McShane confirm that the TQM decision was released approximately March 23, 2009 when the TSX Composite touched a low of 8,506.35 representing a decline of 33% since the start of the TQM hearing about six months before?
Responses: (a) Ms. McShane confirms that the Board did review the multi- pipeline formula in 2001 and considered changes in economic conditions and financial markets since 1994, concluding that the results of the formula continued to be reasonable. The RH-1-2010 Responses of Enbridge to Imperial IRs Page 302 of 323
determination in the RH-4-2001 Reasons for Decision that the results of the RH-2-94 formula continued to be reasonable was largely based on the application of the Capital Asset Pricing Model, a test which does not easily lend itself to estimating the relationship between interest rates and the cost of equity over time. The empirical evidence presented in Appendix A-7.2 indicates that the cost of equity for regulated companies since the time of the RH-2-94 Reasons for Decision has not been as sensitive to long- term government bond yields as the RH-2-94 formula implied.
(b) Confirmed. See responses to IOL-Enbridge 201(a), IOL-Enbridge 36, and NEB 1.21(b).
(c) Confirmed. Ms. McShane notes that the purpose of the referenced TQM proceeding was to determine the cost of capital for 2007 and 2008. A review of the RH-1-2008 Reasons for Decision does not indicate that the weighted average cost of capital awarded TQM was impacted by the financial crisis.
(d) Confirmed. See response to IOL-Enbridge 201(c).
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IOL-Enbridge 202
Reference: Written evidence of Enbridge (Adobe Number A1R0V6), Appendix A-7.2, pages 37 to 42.
Preamble: Ms. McShane discusses the use of corporate bond yields.
Requests: (a) Can Ms. McShane confirm that in the 2004 Alberta generic ROE hearing the Board stated:
The Board does not consider that ENMAX’s proposal to adjust the ROE by the sum of the change in the long-Canada bond yield and the change in the utility bond spread to be appropriate due to the difficulty of determining and tracking bond yields for a representative sample of corporate bonds.
(b) Can Ms. McShane indicate how she has addressed the then AEUB’s concerns over: (a) the difficulty in getting a sample of utility bond yields; and (b) generating a forecast of those bond yields (note that footnote 39 does not refer to utility yields).
(c) If Ms. McShane is comfortable with using non-utility A bond yields in her ROE formula, please provide all evidence that utility and non-utility bond yields for the same rating grade move in unison throughout the business cycle.
(d) Further to request (c), is Ms. McShane aware of any Canadian evidence that during recessions Canadian utility bonds have traded on lower yields than equivalently rated non-utility debt?
(e) Can Ms. McShane confirm that the yields on default risky corporate debt are not expected, but instead are promised rates of return? If so, can she please explain the difference between the two types of yield?
(f) Further to request (e), can Ms. McShane confirm that promised yields exaggerate any movement in underlying expected rates of return since small changes in the default probability can have a huge impact on the promised yield even if the expected rate of return is unchanged? If not, please explain by example why not.
Responses: (a) Confirmed.
(b) The Alberta Energy and Utilities Board cited the difficulty in determining and tracking bond yields for a representative sample of RH-1-2010 Responses of Enbridge to Imperial IRs Page 304 of 323
corporate bonds as the impediment to using the ENMAX proposal. By using an independently constructed and maintained index of A rated corporate bond yields, there is no difficulty in determining and tracking bond yields for a representative sample of corporate bonds. The choice of an A rated corporate bond yield index rather than a utility bond index is explained in detail in response to NEB 1.28(d). The corporate spread used in the proposed formula is not a forecast spread; rather, it represents the change in actual spread from one year to the next.
(c) Figure 1 below shows the yields on the now discontinued CBRS A Rated utility bond index and the DEX A rated corporate bond index from January 1981 to December 1996, which encompasses the recessions of 1981-82 and 1990-92. Figure 2 shows the yields on a sample of A rated Canadian utility bonds maintained by Foster Associates since the discontinuation of the CBRS index in September 2000 and the A rated DEX Corporate Index. Figure 2 includes yields from the economic slowdown in 2001 and the most recent recession. Both figures indicate that A rated utility bonds and the DEX A rated corporate bond index (which includes utility bonds) have moved in unison over the business cycle.
Figure 1
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Figure 2
(d) Yes. Ms. McShane is aware that the now discontinued CBRS corporate bond index series showed higher yields during recessionary periods than the corresponding utility series. As indicated in response to IOL-Enbride 202(c), that has not been the case with the DEX long-term A rated corporate index.
(e) The promised yield is the yield to maturity of the bond, which reflects the return the investor will receive by holding the bond to maturity and reinvest all of the coupon payments at the yield to maturity. An expected rate of return is the anticipated rate as, theoretically, determined by a probability distribution of the possible outcomes. The promised yield on a bond is equal to its expected rate of return when the bond has no default risk.
(f) Yes. The higher the default risk, the bigger the gap between the promised yield and the expected rate of return on the bond. For bonds with low default risk, such as A rated bonds, the smaller the gap between the promised yield and the expected return.
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IOL-Enbridge 203
Reference: Written evidence of Enbridge (Adobe Number A1R0V6), Appendix A-7.2, pages 36, 38 to 40; page 63, Schedule 3.
Preamble: Ms. McShane discusses her empirical test.
Requests: (a) Please provide the underlying data used for the test results reported on pages 38 and 39 for U.S. utilities. For the DCF tests, please provide the components of the DCF fair rate of return separately, that is, the dividend yield and the forecast growth yield and explain fully how this estimate was derived for each utility.
(b) Please confirm that 100% of Ms. McShane’s recommended formula ROE results are based on tests using U.S. utility data, and as such, measures either: (a) the response of U.S. regulators to the applicants requested ROE; or (b) the capital market’s valuation of the utility through the dividend yield and the analysis through a forecast growth rate.
(c) On page 40, Ms. McShane applies her ROE formula to the benchmark pipeline using the starting point of 12.25% set in RH-2-94, please confirm that the only Canadian data Ms. McShane has used in the formula is the 12.25%.
(d) In its TQM decision, cited by Ms. McShane on page 36, the NEB notes a number of significant changes in economic conditions and capital markets that have occurred in Canada since 1994. Can Ms. McShane please explain in detail how her ROE formula has taken into account these changes when it is entirely derived from U.S. data?
(e) In Schedule 3, Ms. McShane backdates her ROE formula to 1994. Please do a similar analysis starting after RH-4-2001 when the NEB fully reviewed and reconfirmed its ROE formula.
(f) In Schedule 3, Ms. McShane backdates her ROE formula to 1994. Please do a similar analysis started after RH-3-2004 when the NEB refused to hear ROE evidence.
(g) Please provide a table of the actual NEB allowed ROE, Ms. McShane’s formula ROE from her backdating to 1994 and the results from requests (e) and (f) for the three years 2008, 2009 and 2010.
Responses: (a) See Attachment 1 to IOL-Enbridge 92, which contain calculations that show how estimates were derived for each utility. Appendix C of Appendix A-7.2 provides an explanation of the construct of the DCF RH-1-2010 Responses of Enbridge to Imperial IRs Page 307 of 323
estimates.
(b) The formula is based on tests using U.S. utility data. Ms. McShane addressed the reasons for using U.S. data in the development of the formula in the response to NEB 1.28(e). The analysis based on allowed returns is based on regulators’ assessments of the various cost of equity test results presented by both applicants and intervenors. The DCF-based risk premium test results reflect the relationship between the cost of equity measured using a dividend yield (which reflects the market’s valuation of the security through the price) and a forecast of growth.
(c) Not confirmed. All bond yield and spread data in Schedule 3 are Canadian data.
(d) As explained in response to IOL-Enbridge 203(b), the reasons for using U.S. data in the development of the formula were addressed in response to NEB 1.28(e). However, the proposed formula was applied to Canadian data using as the starting point the 12.25% set in the RH-2-94 proceeding; see response to IOL-Enbridge 203(c). As a result, changes in economic conditions and capital markets that have occurred in Canada since 1995 are captured in the development of the benchmark ROE.
(e) See response to NEB 1.21(b). The results of the requested analysis are presented in response to NEB 1.21(g).
(f) The analyses requested in IOL-Enbridge 202 (e) and (f) were conducted using as the starting points the 2001 and 2004 multi-pipeline ROE of 9.61% and 9.56%, respectively, and the data set out in Schedule 3 of Appendix A-7.2. The resulting indicated benchmark pipeline ROEs for 2008, 2009 and 2010 are as follows:
Indicated Benchmark ROE NEB Proposed Formula Proposed Formula Allowed Starting with 2001 Starting with 2004 ROE per Proposed NEB Allowed NEB Allowed RH-2-94 Formula ROE ROE 2008 8.71% 10.13% 8.83% 9.10% 2009 8.57% 10.73% 9.43% 9.70% 2010 8.45% 10.30% 9.00% 9.27%
The indicated benchmark pipeline ROE, as updated using the forecast long-term Canada bond yield of 4.3% underpinning the published 2010 Rate of Return on Common Equity (ROE) per Discontinued RH-2-94 Formula and the September/October average A corporate bond/long-term Canada bond yield spread of 1.84% would be, respectively, 10.34%, 9.04% and 9.30%. RH-1-2010 Responses of Enbridge to Imperial IRs Page 308 of 323
IOL-Enbridge 204
Reference: Written evidence of Enbridge (Adobe Number A1R0V6), Appendix A- 7.2, page 42.
Preamble: Ms. McShane discusses her new formula ROE.
Requests: (a) Ms. McShane recommends a benchmark ROE for 2010 of 10.30%, please confirm that this represents a utility risk premium over the forecast long Canada bond yield of 6.11%.
(b) Please indicate whether Ms. McShane believes that the benchmark utility is of below average risk, average risk or above average risk in terms of the Canadian market as a whole.
(c) Please indicate what Ms. McShane’s current estimate of the historic Canadian market risk premium is using her normal data base of equity and bond returns since 1947.
(d) Please indicate the market risk premium estimate consistent with Ms. McShane’s utility risk premium of 6.11%?
(e) In footnote 42, page 45, Ms. McShane makes a risk adjustment based on U.S. master limited partnerships. Please indicate what Canadian jurisdiction has ever based a fair ROE solely on evidence from U.S. master limited partnerships.
(f) Please indicate any Canadian jurisdiction that has based an ROE award solely on U.S. data without any corroborating Canadian data.
(g) Please indicate any Canadian jurisdiction that has based an ROE award on a sample of U.S. utilities with a median bond rating of BBB.
Responses: (a) Confirmed as of December 16, 2009; however, in response to NEB 1.21(c), the updated 2010 forecast Long Canada yield is 4.3% and the updated spread is 1.84%. The resulting benchmark ROE for 2010 is 10.34% and the implicit benchmark risk premium is 6.04%.
(b) The benchmark pipeline is below average risk relative to the market as a whole.
(c) As per the response to NEB 1.23, in a pure CAPM context, Ms. RH-1-2010 Responses of Enbridge to Imperial IRs Page 309 of 323
McShane would estimate the market risk premium at approximately 6.75%.
(d) See response to NEB 1.22(c).
(e) Ms. McShane is not aware of a Canadian jurisdiction that has ever based a fair return solely on evidence from U.S. Master Limited Partnerships. Ms. McShane’s evidence on the fair return for Enbridge is not based solely on U.S. MLPs. She uses the sample of MLPs to estimate a risk premium specific to Enbridge.
(f) Ms. McShane is not aware of a Canadian jurisdiction that has based an ROE award solely on U.S. data without any corroborating Canadian data. See response to NEB 1.28 for an explanation of the use of U.S. data for the establishment of the relationship between interest rates, corporate yield spreads, and the cost of equity and for the estimation of the risk premium specific to Enbridge. The relationship between interest rates and the cost of equity was applied to a Canadian-allowed ROE as the point of departure; Canadian long-term government bond yields and corporate yield spreads were used to implement the proposed formula.
(g) The BBB rated sample to which IOL-Enbridge 204(g) refers is presumably the same sample referred to in IOL-Enbridge 204(a). Ms. McShane has not researched Canadian decisions to determine if Canadian regulators have made ROE awards, including the estimation of incremental equity risk premiums for a specific higher risk regulated company, based on a sample of U.S. utilities with a median bond rating of BBB. Enbridge accordingly declines to provide the requested information.
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IOL-Enbridge 205
Reference: Written evidence of Enbridge (Adobe Number A1R0V1), Appendix A-3, page 7, paragraph 18.
Written evidence of Enbridge (Adobe Number A1R0V5), Appendix 7.1.
Preamble: Enbridge outlines that there is uncertainty surrounding the ultimate scope and timing of re-reversal of Line 9 and has retained Muse, Stancil & Co. to opine on supply and markets for Line 9.
Requests: (a) Since 1999, has Enbridge considered how it might deliver Western Canadian crude to PADD I? If so, please provide any internal documents, analysis, reports or studies with respect to Enbridge supplying Western Canadian crude to PADD I.
(b) Since 1999, has Enbridge considered any new pipeline projects that would involve the use of Line 9 to deliver Western Canadian crude to PADD I? If not, why not? If so, please provide details of the project, its timing and status.
Responses: (a) Since 1999 Enbridge has examined several projects that would provide Western Canadian crude to PADD I including the following:
(i) Construction of Greenfield facilities from the U.S. Midwest to the Philadelphia area; for example, see slide 18 of Attachment 1 to NOVA Chemicals 1.2(b).
(ii) Utilization of existing pipeline facilities, expanded as required, from Sarnia via Lines 7 and 10 to Buffalo, N.Y. and from there, for example, via Sunoco Logistics Partners’ pipeline to Philadelphia in PADD I.
(iii) See response to IOL-Enbridge 205(b).
(b) Enbridge Pipelines has proposed the Eastern Access/Trailbreaker Project, which contemplated the expansion and reversal of existing facilities, including Line 9, to create a pipeline route to Portland, Maine to provide waterborne access for Western Canadian crude to PADD I and other markets. See response to NOVA Chemicals 1.2.
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IOL-Enbridge 206
Reference: (i) Written evidence of Enbridge (Adobe Number A1R0V1), Appendix A-3, page 7, paragraph 18.
(ii) Enbridge Inc. 2008 Annual Report, page 33.
Preamble: In reference (i), Enbridge outlines that there is uncertainty surrounding the ultimate scope and timing of re-reversal of Line 9.
In reference (ii), Enbridge describes the Trailbreaker Project as follows:
“…The Company initiated plans to provide access for western Canadian crude oil to refineries along the U.S. eastern seaboard and the U.S. Gulf Coast via the marine terminal at Portland, Maine. The Trailbreaker project contemplates the expansion and reversal of existing facilities to create a pipeline route to Portland. An open season process held by a third-party owned Portland-Montreal Pipe Line did not receive sufficient commercial support for the reversal of one of its pipelines to transport crude oil from Montreal, Quebec to Portland. As a result, CAPP has exercised its right to withdraw support from the project at this time. Enbridge continues to engage in discussions with customers to determine timing and conditions for proceeding with this project.”
Requests: (a) Please confirm that an integral element of the Trailbreaker Project was the re-reversal of Line 9 (i.e. to eastbound service). If not confirmed, why not?
(b) Please provide a detailed description of the Trailbreaker Project. In doing so, please describe the facilities that were to be included, the expansion of those facilities and the capacities forecast. Please also describe the costs of the project and how it was to be tolled.
(c) Please outline the reasons why the Portland-Montreal Pipe Line open season did not receive sufficient commercial support. In doing so, please comment on whether the timing and uncertainty in estimated tolls on a re-reversed Line 9 may have had an impact.
(d) Please confirm that CAPP supported the re-reversal of Line 9. If not confirmed, why not?
(e) Please provide copies of CAPP’s correspondence to Enbridge outlining its support for Trailbreaker or its support for the re- reversal of Line 9 and the expansion of the facilities referenced. RH-1-2010 Responses of Enbridge to Imperial IRs Page 312 of 323
(f) In reference (ii), Enbridge states that “CAPP has exercised its right to withdraw support for this project at this time.” Please provide a copy of any correspondence from CAPP in which it withdrew its support. Please also provide a copy of any document (e.g. memorandum of understanding, agreement or term sheet) that outlined CAPP’s right to withdraw support.
(g) Did CAPP and Enbridge enter into any form of memorandum of understanding, term sheet, or agreement with respect to the re- reversal of Line 9? If so, please provide a copy of the document.
(h) Please confirm the number of shippers that demonstrated an interest in the Trailbreaker Project or any re-reversal of Line 9.
(i) In reference (ii), Enbridge states that it continues to engage in discussions with customers to determine the timing and conditions for proceeding with the Trailbreaker project. Please provide a summary of discussions Enbridge has had with customers relating to the re-reversal of Line 9. In doing so, outline the scope and nature/content of the discussions and who has been involved. Also provide copies of all reports and presentations and responses to inquiries that Enbridge has produced and provided to its customers.
Responses: (a) Confirmed.
(b) See response to NOVA Chemicals 1.2(b).
(c) Enbridge Pipelines was informed by Portland-Montreal Pipe Line, of which an affiliate of Imperial has a substantial interest in, that it did not receive sufficient support for its open season. The threshold for sufficient support is within the purview of Portland- Montreal Pipe Line.
(d) Confirmed.
(e) See Attachments 1 and 2 to IOL-Enbridge 206(e).
(f) See Attachments 1 and 2 to IOL-Enbridge 206(f) for CAPP’s withdrawal of support.
See Attachments 3 through 10 to IOL-Enbridge 206(f) for the term sheets (and three amendments) that provided CAPP with withdrawal and termination rights.
(g) Yes. See response to IOL-Enbridge 206(f). RH-1-2010 Responses of Enbridge to Imperial IRs Page 313 of 323
(h) The number of shippers that demonstrated an interest in the Eastern Access/Trailbreaker Project was contingent on the number of shippers that responded to, or expressed an interest in, Portland- Montreal Pipe Line’s open season. Enbridge Pipelines does not know the number of shippers; it was not involved in the PMPL’s open season process.
(i) Reference (ii) was issued early in March 2009 by Enbridge Inc. See response to NOVA 1.2(a) for the dates of, and the participants in, the meetings held thereafter. The discussions were general in nature. Enbridge Pipelines provided no reports and made no presentations; there were no inquires for which written responses were required.
Enbridge notes that Enbridge Inc.’s 2009 Annual Report makes no reference to the Eastern Access/Trailbreaker Project. Nor does Enbridge Pipelines’ Management Discussion and Analysis for 2009.
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IOL-Enbridge 207
Reference: Written evidence of Enbridge (Adobe Number A1R0V6), Appendix A-7.2, page 42, Table 4
Preamble: Table 4 reflects bond yields and pipeline ROE.
Requests: (a) Please provide the equity risk premium over Forecast Long- term Canada Bond Yields embedded in the Benchmark Pipeline ROE for each of 1995, 2008, 2009 and 2010.
Response: (a) The requested implicit benchmark pipeline equity risk premiums are presented below.
ROE Incorporating Forecast Long Change in Both Canada Long Canadas and Implicit Equity Underlying Corporate Bond Risk Premium NEB ROE Yields Proposed Formula
(1) (8) 1995 9.25 3.00 2008 4.55 10.13 5.58 2009 4.35 10.73 6.38
2010F 4.30 10.34 6.04
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IOL-Enbridge 208
Reference: Written evidence of Enbridge (Adobe Number A1R0V4), Appendix A-6, page 6, paragraph 15.
Preamble: Enbridge states the monthly carrying charges are equal to one-twelfth of the proposed pre-tax rate of return on rate base for 2008, 2009 and 2010.
Requests: (a) Please confirm that Enbridge equates the proposed rate of return with the proposed return on equity sought in this application. If not, please explain why not.
(b) Please provide the total dollar amount of carrying costs for each of 2008, 2009 and 2010 using the monthly rate of one- twelfth of the proposed rate of return 2008, 2009 and 2010.
(c) Please provide the total dollar amount of carrying costs for each of 2008, 2009 and 2010 using the monthly rate of one- twelfth of Enbridge's proposed cost of debt for 2008, 2009 and 2010.
(d) Please provide a list of NEB regulated pipelines that currently use the monthly rate of return on equity for calculating carrying charges. Assume currently means the last 10 years.
(e) Please provide what rate Enbridge has used for calculating carrying charges for its core Mainline ITS for the period 1995 to 2010.
Responses: (a) No. Enbridge equates the proposed carrying charges to the pre- tax debt rates and the pre-tax returns on equity weighted according to the proposed capital structure.
(b) Enbridge has not proposed deferral accounts for 2008 and therefore there will be no carrying charges for that year. Due to effluxion of time, the 2009 final tolls will not include carrying charges. Carrying charges for 2010 cannot be determined until the deferral account balances are known.
(c) See response to IOL-Enbridge 208(b).
(d) Enbridge does not have such a list nor the information that it would require to prepare such a list. Enbridge understands that the requisite information for Group 1 companies, but not RH-1-2010 Responses of Enbridge to Imperial IRs Page 316 of 323
necessarily for Group 2 companies, is available in the Board’s electronic document repository. Enbridge has no better access to the repository than Imperial and, accordingly, declines to prepare the requested list.
(e) Enbridge’s only pipeline asset is Line 9. Enbridge Pipelines has applied the following carrying charges under the ITS’s:
1995: 7.76% 1996: 5.05% 1997: 3.67% 1998: 5.73% 1999: 5.42% 2000: 6.23% 2001: 4.81% 2002: 3.21% 2003: 3.69% 2004: 3.00% 2005: 2.92% 2006: 4.31% 2007: 4.60% 2008: 3.21% 2009: 0.65%
Enbridge Pipelines will only be able to calculate the carrying charge rate for 2010 after December 31, 2010 and the average of the 12 monthly Bank Rates published by the Bank of Canada for 2010 are known. The ITS carrying charges are an element of a negotiated settlement and should only be considered in that context.
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IOL-Enbridge 209
Reference: Written evidence of Enbridge (Adobe Number A1R0W0), Statement B-2.1.
Preamble: Imperial would like to better understand the Plant in Service in lines 1 through 15 Original Reversal.
Requests: (a) Please describe in detail, the plant in service for each of lines 3 through 14 and whether Enbridge considers each of them to be capable of bi-directional usage. If Enbridge does not consider them capable of bi-directional usage, please explain why.
Response: (a) See Attachments 1 and 2 to NOVA Chemicals 1.16(a) and see also response to NOVA Chemicals 1.17(d).
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IOL-Enbridge 210
Reference: Written evidence of Enbridge (Adobe Number A1R0U9), paragraph 6, page 5.
Preamble: Imperial wishes to understand the current disposition of the Clarkson Facilities.
Requests: (a) Confirm that “Clarkson Facilities” collectively refers to Line 22, Clarkson Station, Clarkson Terminal, connecting facilities in Mississuaga, and Line 12. Does “Clarkson Facilities” refer to any other assets?
(b) What is the current physical status (e.g. operating, idled, abandoned in place) of the Clarkson Facilities? Provide more detail than given in the referenced paragraph which states that, “The Clarkson facilities were deactivated in 2005.”
(c) What is the current financial status of the Clarkson Facilities? For example: do all or some of them remain in the Line 9 rate base?
(d) Have the Clarkson Facilities been fully depreciated? If not, list the individual assets and provide their current book value.
Responses: (a) “Clarkson Facilities” collectively refers to Line 22, Clarkson Station, Clarkson Terminal, their connecting facilities in Mississauga, and Line 12. “Clarkson Facilities” does not refer to any other assets.
(b) The Clarkson Facilities were drained, purged with nitrogen and rendered deactivated in 2005. Enbridge Pipelines applied for and received approval for the deactivation in Board Order MO- 11-2-6. The facilities are currently maintained in a deactivated state as defined in CSA Z662.
(c) All Clarkson Facilities remain in Enbridge’s rate base.
(d) See response to NOVA Chemicals 1.18(a).
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IOL-Enbridge 211
Reference: Written Evidence of Enbridge (Adobe Number A1R0V6), Appendix A- 7.2, Schedule 2.
Preamble: Ms. McShane provides the results of her DCF Cost of Equity Study for Benchmark U.S. Utility Sample in Schedule 2, which she states in calculated as an annual average of monthly data.
Requests: (a) Please provide the monthly data underlying Schedule 2.
(b) In addition, please provide the names of each utility used and the monthly data specific to each of these utilities.
(c) Please explain how the Dividend Yield was adjusted for I/B/E/S growth.
Responses: (a) See Attachments to IOL-Enbridge 92.
(b) See Attachments to IOL-Enbridge 92.
(c) The formula is shown in Appendix A-7.2, Appendix C, page C-2 as DY * (1 + g).
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IOL-Enbridge 212
Reference: (i) Written Evidence of Enbridge, various references, including (Adobe Number A1R0V3), Appendix A-5, pages 4 and 5, “Supply and Market Fundamentals”.
(ii) Written Evidence of Enbridge (Adobe Number A1R0V5), Appendix 7.1, several references.
(iii) CAPP, “Crude Oil Forecast, Markets & Pipeline Expansions, June 2009”.
Preamble: In (i), paragraph 13, Enbridge states: “Enbridge Pipelines’ supply and demand forecasts for western Canadian crude oil (including condensate) take into consideration the Ontario refiners’ historical runs of offshore crude oil after adjusting for Petro-Canada’s closure of its Oakville refinery in April 2005.”
In (iii), CAPP states: “While CAPP has included a forecast of production from Atlantic Canada in this report, the primary focus will be on production from Western Canada since most of the growth in oil production is expected to be derived from the oil sands areas located primarily in the western province of Alberta.”
Imperial would like to confirm that it understands the definitions used in the referenced documents, and the outlook for East Coast offshore production.
Requests: (a) Please confirm that references to “offshore” in (1) are for all crudes received for delivery to Line 9, including East Coast Canadian and foreign imports.
(b) Please confirm that the references to “offshore” in (2) are for Eastern Canada domestic production, as distinct from foreign imports.
(c) Does Enbridge agree that the outlook for Atlantic Canada crude production is a material factor in the analysis of Line 9 throughput?
(d) Did Enbridge discuss with Muse the need for alternative forecasts of Atlantic Canada crude production as part of its mandate, in light of the fact that CAPP does not have this source of supply as its primary focus? RH-1-2010 Responses of Enbridge to Imperial IRs Page 321 of 323
(e) Did Enbridge or Muse prepare its own forecasts of Atlantic Canada crude production within the scope of the Line 9 application? If so, please provide same.
(f) Did Enbridge or Muse consider any other forecasts of Atlantic Canada crude production besides the CAPP forecast? Please explain.
Responses: (a) Confirmed.
(b) Confirmed.
(c) No. Atlantic Canada is a small, high-cost supply basin for which there is little prospect for a significant increase in production until perhaps 2017. Current Atlantic Canada crude production is approximately 45,300 m3/d (285,000 b/d), as compared to Atlantic Canada refining capacity of approximately 71,100 m3/d (447,000 b/d). If the Valero Levis refinery is included, Atlantic Canada refining capacity increases to 112,400 m3/d (707,000 b/d). Thus, Atlantic Canada is net short crude.
(d) No.
(e) No.
(f) Yes. See paragraph 14 of Appendix A-5.
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IOL-Enbridge 213
Reference: Written Evidence of Enbridge (Adobe Number A1R0V5), Appendix 7.1, pages 11 and 12, “Imperial Sarnia Refinery”.
Preamble: Muse states: “Total crude capacity is 19,200 m3/d (121 kb/d), and the refinery processes a mix of conventional light, medium, and heavy crudes, plus Cold Lake Blend. The Sarnia refinery is a coking configuration and, as such, is comparatively well-suited to process heavy crudes from Western Canada. With the closure of the Petro-Canada Oakville refinery in April 2005 with its sizable asphalt production, it appears that the Imperial Sarnia refinery is now responsible for much of the heavy crude throughput in Ontario. It appears likely that Imperial will continue to seek to further increase its receipts of Western Canadian crude.”
Imperial would like to better understand Muse’s analysis of Imperial Sarnia, and Ontario heavy crude markets in general.
Requests: (a) Please provide a monthly summary of crude types processed by Imperial Sarnia for the last three years.
(b) Provide details for other refineries being compared to Imperial Sarnia, and supporting analysis regarding comparative suitability of these refineries and Imperial Sarnia to process heavy crudes from Western Canada.
(c) Provide supporting analysis for the statement regarding Imperial Sarnia being responsible for much of the heavy crude throughput in Ontario.
(d) Provide a monthly summary of asphalt markets in Ontario for the period 2004 to present, including demand, production by refinery, any interprovincial transfers in/out, any imports/exports, and any supply adjustments.
(e) See Attachment 1 to IOL-Enbridge 163 for the annual Ontario crude slate. Monthly information is available from Statistics Canada. Crude runs by each refiner are unknown.
(f) Please fully explain the rationale for the statement: “It appears likely that Imperial will continue to seek to further increase its receipts of Western Canadian crude.”
Responses: (a) Unknown. RH-1-2010 Responses of Enbridge to Imperial IRs Page 323 of 323
(b) See the response to IOL-Enbridge 77.
(c) See the response to IOL-Enbridge 77.
(d) See Attachment 1 to IOL-Enbridge 213.
(e) See Attachment 2 to IOL-Enbridge 213. Crude runs of each blend by each refiner are unknown.
(f) See Appendix A-7.1. The section titled “Comparative Crude Supply Economics to Nanticoke” provides a detailed assessment of the recent economics of Western Canadian crude supply, versus waterborne supply via Portland, to Nanticoke. The Western Canadian supply advantage since 2006 is even greater for Sarnia because the toll from Portland is higher and the toll from Western Canada is lower (relative to the tolls to Nanticoke).